ML20198Q889
| ML20198Q889 | |
| Person / Time | |
|---|---|
| Issue date: | 06/03/1986 |
| From: | Advisory Committee on Reactor Safeguards |
| To: | |
| References | |
| ACRS-T-1518, NUDOCS 8606090408 | |
| Download: ML20198Q889 (231) | |
Text
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O UNITED STATES NUCLEAR REGULATORY COMMISSION IN THE MATTER OF: "
DOCKET NO:
ADVISORY COMMITTEE ON REACTOR SAf'EGUARDS SUBCOMMITTEE ON REACTOR OPERATIONS O
LOCATION: WASHINGTON, D. C. PAGES: 1 - 147 DATE: TUESDAY, JUNE 3, 1986 g';060;, X .c a T-ists , nv
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t-1 j UNITED STATES OF AMERICA O 2 NUCLEAR REGULATORY COMMISSION 3 ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 4 SUBCOMMITTEE ON REACTOR OPERATIONS 5
Nuclear Regulatory Commission 6 Room 1046 1717 H Street, N.W. ;
7 Washington, D. C.
8 Tuesday, June 3, 1986 .
9 The subcommittee on Reactor Operations convened at 10 8:30 a.m., Jesse C. Ebersole presiding.
11 12 ACRS MEMBERS PRESENT:
MR. JESSE C. EBERSOLE 14 MR. CARLYLE MECHELSON 15 MR. GLENN A. REED 16 MR. CHARLES J. WYLIE 17 ja ACRS CONSULTANTS PRESENT:
19 HERMAN ALDERMAN 1
20 ,
21 22 1
23 1 l
24
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Aarkdat Reporters, Inc.
25 1
() PUBLIC NOTICE BY THE UNITED STATES NUCLEAR REGULATORY COMMISSIONERS' ADVISORY COMMITTEE ON REACTOR SAFEGUARDS TUESDAY, JUN E 3, - 19 86 The contents of this stenographic transcript of the proceedings of the United States Nuclear Regulatory Commission's Advisory Committee on Reactor Safeguards 4 (ACRS), as reported herein, is an uncorrected record of the discussions recorded at the meeting held on the above I
date.
No member of the ACRS Staff and no participant at
() this meeting accepts any responsibility for errors or inaccuracies of statement or data contained in this transcript.
1
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1 P,R O C E E D I,N_ G_ S l 2 MR. EBERSOLE: The meeting will now. come to
- 3 order. This is a meeting of the ACRS Subcommittee on i
4 Reactor Operations. I am J. Ebersole , chairman of the 5 Subcommittee on Reactor Operations. The other ACRS members 6 in attendance today are Glenn Reed and Chuck Wylie and
- 7 later I expect Mr. Michelson.
8 The Subcommittee will review recent events at
- 9 operating plants. To the extent practical, the meeting j 10 will be open to the public. However, a portion of the
- 11 meeting will be closed to discuss elements of the Palo i
12 Verde security plan. ,
E 13 Herman Alderman is the ACRS Staff member for 14 this meeting.
4 15 The rules for participation in today's meeting l-
! 16 have been announced as part of the notice of this meeting i
- 17 published in the Federal Register, May 16, 1986, with a i
18 revision to this notice sent out on May 28, 1986.
19 It is requested that each speaker first identify 20 himself or herself and speak with sufficient clarity and l
21 volume so that he or she can be readily heard. i l 22 We have received no written comments or requests t
23 for time to make oral statements from members of the 'public.
24 In our past meetings, sometimes we have 25 discussed items that never did get to the tull Committee
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, .27026.0 3 BRT 1 for some presumed resolution at that stage , and ye t we had 2 observations and comments and Staf f statements of intent 4
3 and so forth. I would like to make it a practice at this 4 meeting and then following on all others that as we get to
. 5 the end of each of these events, we make what I'd call sort
'6 of an underlined statement of the intent of the Staf f and 7 also on the part of ACRS to make a statement pertinen t to 8 each incident as to what action, if any -- which may be 9 very informal; maybe no more than comments, hope f ully on 10 which Staff will react -- that will be taken. In short, 11 I'd like to have a closure on each item, since evidently 12 lots of people think they are important enough to have some 13 sort of closure on it.
14 We will now proceed with the meeting. Do any 15 Subcommittee members have any comments or additions to s
16 these comments?
1 17 If not, I would like to call on M. Wegner.
I 18 MR. ALLISON: Mr. Ebersole , my name is Dennis 19 Allison. I would like to tell you about somebody before l 20 Ms. Wegner goes on. I have with me Bob Baer. Ron Hernan
- 21 is expected.
22 This was an interesting event at LaSalle on
- 23 Sunday, and we are just beginning to look into it. We
. 24 don' t really know what happened, but plant experienced a 25 feedwater transient while performing some surveillance , got 1 ()
i i
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\ 1 a high reactor water- level and tripped the operating 4
2 steam-driven main feed pumps.
3 The level then went to a low level, to about the 4 scram set point, the operator was recovering by starting an i
5 electric-driven main feed pump. The plant has four level
, 6 switches that initiate a scram, 1.5 inches. One of those
! ~
i
] 7 switches tripped, the other three did not. And this gave l
l 8 the -- gave a half scram. The operators recovered and ;
i 9 continued to ope ra te . A little later on Commonwealth 10 personnel started looking at it, wondering if there had 11 been a problem like an ATWS, that the other three switches 1
1 12 should have tripped, and this was one system that was i 13 indicating the level was substantially below the scram set '
(:) 14 point. So we have a team who got there last night. The
}
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! 15 licensee is studying the event. I just wanted to let you j 16 know about that.
J
I 18 This is a old boiler, isn't it?
j 19 MR. BAER: A new one.
20 MR. EBERSOLE: Wait a minute -- LaSalle. I'm 1
! 21 out of -- yes.
4 ,
! 22 MR. MICHELSON: Are they continuing to operate? !
i j- 23 MR. BAER: No, they are shut down now and will l
- 24 be shut down until they continue operating.
t I 25 MR.-MICHELSON: I have given Herman a couple of 1
i (:) !
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27026.0 5 BRT 1 things I wanted to hear about briefly. It may be a good 1
, 2 time now. One was the scratch scram discharge volume at
! 3 Perry filling up to the point because of leaky insert or
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4 scram valve; I don't remember which. It filled up to the 5 48 gallon level on the trip, and of course that's the final 6 last-ditch defense that it tripped on short of filling it.
7 I just wondered if you had any information on it.
8 MR. BAER: Ms. Wegner remembers the event.
9 MS. WEGNER: It was leaky scram valves. I don't 10 know anything more about it, though.
f 11 MR. MICHELSON: That one you better follow up 1
12 pretty caref ully, because that's a very serious event, if i
gg 13 this is happening, particularly on a brand new. We, a long
- V 14 time ago, Kind of wondered about those valves at the time i .
15 the Browns Ferry problem happened, and at that time this 16 was one of the predicted modes of an ATWS, was to have '
l 17 those leaky scram valves and failed to detect the 18 accumula tion of water. Of course, that was one of the 19 reasons for concentrating on real good instrumentation,
, 20 which in this case worked, but when you start looking at 21 other LERs lately, you see some other people have a little 22 trouble on the level instrumentation on the scran discharge 1
23 volumes. When you couple the two together, you have ,
24 another potential loss of ability to scram.
i 25 MR. EBERSOLE: Le t me follow that up a little i C:)
i i
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27026.0 6 BRT 1 bit. Again, this is one of these underlined follow-ups I 1
2 think we should pursue. These level switches are the last
! 3 lines of defense. You know we had found .them early on !
4 battered to pieces at Palo Verde because of the hydraulic l 5 knock and so forth; I think the whole BWR scram system is j 6 an absolutely lousy design that should be ripped out and 7 replaced and I have maintained that position for years.
8 Looking at this, at the time the level detector 9 switches do in fact intercept -- pick up a scram, I presume 10 there's quite a bit lef t of available margin in which to i
11 take the discharge of all the individual drives. You know, '
12 it has to have room enough to do this with some margin lef t i
i 13 over, and I wonder if there are any rates of leakage which 1
- 14 are so high, combined leakage rates which precede this, to I
! 15 interfere with this margin of volume. Do you understand?
i 16 You have an influx of water so great that before you even
! 17 get a scram you have encroached on the necessary available 18 volume to execute the scram.
19 MR. BAER: I remember the event, probably less 20 clearly than she , but if you have a point on the design it 21 ought to be addressed to NRR rather than IE.
i l 22 MR. MICHELSON: It the -instruments that fail to i
23 scram are the ones telling you how much water is there and 24 if you have lost those instruments, you have no reason to 1
i 25 believe there's water in the discharge volume until -- well,
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1 until it's full, you don't know it's there. You have lost 2 your indication.
3 MR. BAER: Well, at the time they required -- as 4 far as I know, they still require -- redundant switches and ,
i 5 some diversity. I think it was -- it is only difterent 6 manufacturers. I think they finally decided on different 7 manufacturers, which I'm not sure is very diverse.
8 MR. MICHELSON: Right. It wasn't redundancy in 9 principle, only manufacturers. But they really need l
10 redundancy in principle.
11 MR. EBERSOLE: At one time they had hollow float 12 balls. Thank you for this. We would be much interested in
- 13 a follow-up on that.
! 14 MR. MICHELSON: Maybe for the next meeting you J
15 could talk about the Browns Ferry event -- or the Perry j 16 event, which was tairly recent. It was minor, but I would 1
i 17 like to feel comfortable that it is tollowed up.
18 MR. BAER: The Perry event?
19 MR. MICHELSON: Yes. I gave it to Herman in one 20 of the morning reports.
21 MR. EBERSOLE: I might comment, we have a very 22 tight schedule so we'll be watching these allotted times l
23 quite closely. Okay.
l 24 MS. WEGNER: I'm Mary Wegner f rom I&E.
l 25 On April lith and 12th, in 1986, Pilgrim had a 1
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1 series of problems starting with concurrent leakage of all 2 three valves which isola te the higher-pressure RCS from the
- 3 low-pressure B-RHR/LPCI line.
l 4 (Slide.)
1 5 While they were shutting down from this event,
[ 6 when they reached 880 psig on the steam lines with the mode
! 7 switch in start-up, the primary containment isolation, in i
i 8 that, the MSIVs were closed, although they were not 9 supposed to in this condition.
l 10 While they were recovering from all of this they 1
11 could not open the MSIVs, the outboard MSIVs.
J 12 The safety significance of this was that there
' - 13 was a potential for che intersystem LOCA outside of
! 14 containment due to leaking. There was inadequate 15 corrective action taken for precursor events in each ot I 16 these areas, and they were all unnecessary challenges to i 17 sa fe ty systems, that's PCIS and RPS.
18 (Slide.)
19 A precursor event tor the LPCI leaking occurred l
- 20 on February 12, 1986. The inboard testable check valve ,
21 688, was leaking. The outboard, normally closed isolation s
22 valve, 28B, began to leak. They were receiving 23 liigh-pressure alarms in the low-pressure system. This was i 24 reported by the resident inspector as having been occurring 25 over a period ot several weeks.
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27026.0 9 BRT O 1 The corrective action at tha t time , among othe r 2 things, was to close this normally opened valve and to open 3 this normally closed one and to continue plant operation.
4 On April 4th, the modo switch con' tact problems ,
5 which apparently caused the MSIVs to close, was experienced 6 during a plant shutdown for another reason. At that time 7 they also failed to open the outboard MSIVs for about an 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> and a halt into the recovery. They found debris in 9 the ports of the control valves for the MSIVs, and they 10 thought they had found the problem.
11 On April lith, the outboard, normally opened 12 isolation valvo, which at that time was closed, began to 13 leak. Among other things, they closed both of these valves.
14 Still, even af ter venting this line, they were getting 15 High-pressure alarms within a space of about two hours.
16 MR. EBERSOLE: Don't they have a fairly high 17 relief valve capacity? They were actually raising pressure 18 with it open?
19 MS. WEGNER: They have a relief valve in this 20 line, but I believe it's something like 3/4s of an inch or 21 1 inch.
22 MR. EBERSOLE: Okay.
23 MS. WEGNER: Something like that.
24 MR. EBERSOLE: It was going full blast?
25 MS. WEGNER: The relief valve was lifting and O
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i 1 they were getting the High-pressure alarms both times.
l 2 MR. EBERSOLE: You keep mentioning the fact they 3 couldn' t open the main steam isolation valves. They always i
j 4 have the option of blowdown if they wanted, don't the y? l i
j 5 MS. WEGNER: That wasn't -- I don't think they l 1
j 6 were blowing down. I don't think they lifted --
j 7 MR. BAER: At that point the main steam i
j 8 isolation valve was still open.
j 9 MR. EBERSOLE: Wha t I got was an impression that ,
! t 10 they wished they could reduce pressure but they couldn' t i 11 get the valve open?
12 MS. WEGNER: This was during scram recovery, j 13 when it's always preferable to blow down to the condenser.
14 MR. EBERSOLE: I know they are so atraid of J
a 15 those PRVs or SRVs not closing that they don't touch them.
i f
! 16 THE WITNESS: Yes. They have had a little !
1 i
17 problem. j j
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18 MR. EHERSOLE: Sounds like we have a combined l
?
19 maintenance quality problem all over the place. Go ahead.
20 MS. WEGNER: It was. With these three valves
- 21 closed they were getting High-pressure alarms and they i
j 22 began their shutdown. While they were shutting down, when i
23 they got to the 880 psig on the steam line with the mode 24 switch, again, in start-up, they got an isolation and later
- 25 on, they were eventually able to open the MSIVs, but not at f I l I l I ACE. FEDERAL REPORTERS. INC.
I 202 347 3700 Nationwide Coverage 800 1 4 6646 1
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('h s) I first.
2 At this time the Region and I&E and everybody 3 else was presented in it, and IIT was sent to the site on 4 the 12th. Confirmatory action letter was issued, requiring 5 the plant to maintain the equipment and their records for 6 the IIT to investigate.
7 You have a copy of the -- I'm sorry, it's AIT, 8 not IIT.
9 The team report is a part of your package there.
10 The causes of the problems, the mode switch, PCIS 11 initiation problems, they did quite a tow dif terent 12 diagnostics and didn't find out anything.
13 This problem had been experienced in 1983 at
,)
14 Pilgrim. I believe it has been experienced at a number of 15 other plants, including Dresden. I don't think anyone has 16 over found exactly what caused it.
17 The MSIV tailure to open was due to 18 disengagement of a pilot poppet due to an installation 19 error.
20 (Slide.)
21 This is the basic MSIV, to utilize the lift oft 22 the seat here, allowing flow through this orifice, and so 23 torth.
24 (Indicating.)
25 (Slide.)
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j 1 MR. MICHELSON: I thought you first ind ica ted j 2 dirt in the air system. Was that later changed?
3 MS. WEGNER: It may have contributed to their b
i 4 problem, but that wasn't the entire problem.
~J 5 MR. MICHELSON: Was it a part ot the problem?
6 MS. WEGNER: It might have been the first time.
l l 7 MR. BAER: This is Bob Baer of the Staff. There 1
8 was the precursor event that you mentioned, the ir 9 troubleshooting, they found material in the pilot solenoid,
, 10 so they cleaned that out and thought they resolved the i 11 problem. When the second event occurred again they I
j 12 couldn't -- the main steam isolation valves again closed 1
1 13 when they shouldn' t have and they had dif ficulty reopening t r
! i 14 it. What Mary is talking about now is the troubleshooting l.
15 they did the second time.
- 16 MR. EBERSOLE
- What's the action of the pilot, I
l 17 other than to build steam pressure? What does it do?
t 18 Provides an assist to the opening tunction?
j 19 MS. WEGNER: That I hadn't looked at. I suppose 20 it does.
21 MR. EBERSOLE: I was wondering if it just j 22 equalized the prosauro.
i 23 MS. WEGNER: This has to be lett out at here --
24 you can't soo it on this -- tor air to como in -- for steam, i !
l 25 air, whatevor to como in here to equalize prosauro across i i
I i i
> I j ACE. FEDERAL REPORTERS, INC, ;
002 347 37(u) Nation.Ide Coverage Na>34M 46 '
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i k- 1 the disk so that you can open the disk.
2 The original design, the pilot poppet was one 3 p ie ce . Two plants, Pilgrim and Hatch Unit 1, had modified 4 their pilot poppet because they were having leakago 5 problems and this was supposed to correct the leakage
, 6 problems, which I understand it has done a pretty good job i
7 of doing. However, this piece is connected to this pilot 8 poppet nut by a set sc re w , which is supposed to be -- which 9 is supposed to engage and deform the threads ot this pilot 10 poppet nut and the set screw is suppoced to be stakod.
11 Approximately six pilot poppets which were found 12 to be disengaged did not have the set scrows properly 13 attached. e 14 We checked with Atwood Morrill and also with i
15 Plant Hatch and tound in all cases where the set screw was 16 properly engaged and staked, the problem was not the pilot 17 poppet disengaging, but getting it to disengage. So that 18 problem was -- the MSIV tailure to reopen was due to the 19 pilot poppet disengaging.
20 The RHR valvo leakage problems, the problems
- 21 were caused by the licensoon over concerns with meeting the 22 technical specifications without adoquatoly addressing the 23 reasons tor the requitomonts. The ovorprossure protection 24 ot the low-pressure piping, 1 gallon por minuto, which is 25 allowed by toch specs, amounts to 1440 gallons a day, or O
ACE FEDERAt. REPORTERS, INC, 202 347 37(x) Nationside Co$erage mrk33MM4
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1 over 10,000 in a week, and a system which is full of water 1
i 2 is not going to take much of that.
I j 3 Corrective actions, the mode switch problem 4 remains to be addressed by the licensee. I feel they will 1
i 5 probably take the same route others have taken in the past, ;
6 and that is to replace it.
1 I 7 The proper installation ot the so t screws should l
] 8 elimina te the problem of the tailure to open of the MSIVs. !
i !
9 Atwood Morrill has also stated that they are going to 1
( t l
l 10 modify the design somewhat to make the arrangemont even 1
11 harder for the pilot poppet to fall otf or hardor tor it to
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1 i 12 be installed wrong and easier for it to be removed when
- 13 doing maintenance.
O L
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{ 14 MR. EBERSOLE: Will you throw that cut ot tho ,
I 15 main steam isolation valvo up there again, I just want to l' 16 ask a question about it.
{i 1 17 (Slide.) l 18 I invite the Statt to shoot mo down here. I'm j
' J I
19 looking at the pilot poppet and steam flow path and the 5
! 20 tunction of the pilot poppet which takes steam through the j 21 balancing oritico , and then it the pilot -- it pressure is i
22 raised on the back sido, the pilot poppet will opon, and *
. [
23 I'm trying to got at the basic tunction of the valvo. On ;
- i. f j 24 the downstream sido ot this valvo is there a presumption 1 f
- 25 that thoro is a valve closed or opon? Can anyone toll mo? I i
' i L
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j ACE FuonnAL REPORTERS. INC. !
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j v 1 Is that valve qualified in the same context tha t this valve 1
l 2 is?
t
! 3 MR. ALLISON: This is Dennis Allison.
4 Downstream you'll have to have a closed valve somewhere. I !
! 5 don' t think you'll ever equalize and get it open.
) i
, 6 MR. EBERSOLE: That's what I am getting at. It J
- 7 I have a closed valve downstream, then that valve in turn e 4
8 should have the same quality characteristics of this valve, s I
! 9 but it does not. i
)
i 10 MR. ALLISON: You only need the closed valvo, I e I
f 11 think, to open it. If you want to get it open and you dump 12 to the condenser, for instance, I don't think you'll ever l
j .
13 got it open.
i j 14 MR. EBERSOLE: So it is in fact inherently J
] 15 locked closed if the downstream valve is locked closod?
16 MR. ALLISON: 1 think so.
h 17 MR. EBERSOLE: So no matter what you do, if the l l
18 downstream valve is locked closed, you have had it? You l I 19 can't open it?
4 20 MR. ALLISON: No. I'm sorry. I'm mixed up here.
-l 21 It you open the condenser dump valvo so that you
\
q 22 never got more than about, oh, 100 psi downstream of the !
23 valvo, I don't believe that the actuator is strong enough i
j 24 to opon it.
j! 25 MR. EDERSOLE: I'm saying, you are in a modo ;
t l ($)
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1 which is not very nice, to have this valve, by the function 1
] 2 of some nonqualified item, the downstream dump valve, 1
l 3 remain locked up, no matter what you do to the bypass. And 4 that throws you inevitably on the SIVs --
i l 5 MS. WEGNER: This is the condenser side valve
. 6 arrangement. .
i
) 7 (Slide.)
i l 8 MR. LANIK: This is George Lanik in IE. First -
i 9 ot all, you don't want to open up the MSIVs unless the ;
l 10 valves are open, unless you have the condenser available.
1 j 11 MR. EBERSOLE: It my steam dump system i
j 12 downstream is shut -- well, at course, I can't get steam 13 tiow anyway.
(:) 14 MR. LANIK Then you can open the valve , and it 15 your steam dump system is working --
j 16 MR. EBERSOLE: It won't do me any good anyway.
i L i
17 So the essence of this is that this system, in the opening i i
18 mode, is unqualified. You can' t open it if you want to
{
j 19 unless you have a line, unqualified item.
20 j MR. MICHELSON: But there's no safety 21 requirement to open the talvo.
22 MR. EBERSOLE: Well, Carl, that's always the 1 23 que stion . Do you remember the Browns Ferry fire when they !
l +
i 24 were doing everything --
i
] 25 MR. MICHELSON: I understand, but there's no I
i i
i i Acc FunERAt. REPORTERS, INC.
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i 1 safety requirement to open the valve.
I 2 MR. EBERSOLE: There is a safety requirement to 1
3 find a home for the steam.
4 MR. MICHELSON: There's a safety requirement to 1
l 5 remove decay heat.
t
! 6 MR. EBERSOLE: In this case , in a boiler, that
) 7 means finding a home f or the steam.
I j 8 MR. MICHELSON: That's RHR it you are low enough,
{ 9 or if you are not low enough --
1 j 10 MR. EBERSOLE: I go back to the tire; they were i 11 fighting desperately to get a bypass to the condenser and l
i 12 they couldn' t.
i 13 MR. MICHELSON: There is, to my knowledge, no i
14 safety requirement to open these valves; is that correct?
1
- 15 MR. EBERSOLE
- That's always been, however, a j 16 philosophical issue , and I invite you to think about it.
4 17 You want a home for the stream somewhere. You don't like 18 to put it in the suppression pool. There's no way to get i
{ 19 it, like a hend valve, like a hand equalizer or a 4-inch I
! 20 line that you can open.
j 21 MS. WEGNER: You don't have a vacuum in the l
- 22 condenser, you are not going to want to blow down --
i j 23 MR. EBERSOLE: You could -- but you wouldn't 1
- 24 want to blow the diaphragm. '
i 25 MR. ALLISON: We understand the point you are f () -
i l
l ACE. FEDERAL REPORTERS, INC.
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2 MR. EBERSOLE: So what is to do?
3 MS. WEGNER: The written responses per the 4 confirmatory action letter have not been received yet.
5 MR. EBERSOLE: Will the Subcommittee share with 6 me we'd like to see the eventual closure of this item? I 7 think I would. It's kind of a generic, BWR problem.
8 With that, I guess we have to move on.
9 MR. MICHELSON: What's the potential closure ,
10 Jesse? What do you want to hear about? They told you what 11 they are going to do so the poppet won' t come loose again.
12 That's all the closure there is, isn't there , basically?
g- 13 MR. EBERSOLE: Is that all that's intended?
b 14 Just do some adjustments?
15 MR. BAER: I guess I think the more signiticant 16 problem is the low pressure /high pressure leakage. We have 17 been talking to Region 1 about that and they are waiting 18 for the licensee's response and we are going to be 19 discussing that with them.
20 MR. EBERSOLE: By the way, the 1-inch line --
21 that's lots at water isn't it?
22 t1R. ALLISON: They were testing the reliet valve, 23 but in Pilgrim were they lif ting the reliet valve or just 24 venting off.
25 MS. WEGNER: It it had a relief valve they were ace FEDERAL REPORTERS, INC.
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27026.0 19
, BRT 1 lifting it.
2 MR. EBERSOLE: If they had a relief valve? They 1
i j 3 better have one.
4 MR. MICHELSON: This is one of the interesting i 5 areas in the Code where , if you read the Code very l
6 care f ully, ' Section 3 -- this is all Section 3 piping, you l
j 7 will find that the Code only under very special i
I 8 circumstances allows you to use isolation valves as 1
1 4
9 barriers to remove the need for relief capacity equal to l
l 10 the valve wide-open position. So you don' t have a relie f f
11 capacity here equal to valve wide open. In fact, you only 12 have a thermal relief capacity that's put in, generally a
l 13 about a 3/4, 1-inch relief valve.
14 And you really -- the Code always thought tha t
} 15 these valves were going to be tight. If you want to talk -
I 16 about anything more than minuscule leakage -- now we are 17 talking about gallons a minute.
! 18 MR. BAER: Well, I think the bigger concern is l 19 the massive failure of the high pressure / low pressure l
j 20 interf ace and you're exposing a low pressure system to high 21 pressures. This has occurred at a couple of plants, not on l 22 a mass basis, and NRR -- IE referred that over to NRR as a 1
j 23 high-priority generic issue.
j 24 MR. MICHELSON: I think the later design is a i
! 25 600-pound design rather than 450. Pilgrim was earlier.
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27026.0 20 BRT 1 MR. BAER: That helps. The problem isn't 2 potentially as severe as it is on a PWR.
3 MR. MICHELSON: But you have a far more serious 4 problem if you have these valves open and get back to the 5 suction side of the RHR pump which is not designed for 600
) 6 pounds. Discharge side is but not the suction side.
t j 7 Depending on the vendor, it's designed to about 100, 150 8 pound. So if you overpressurize with this valve 16-B open
! 9 and you have a leaky check valve, you have the potential 10 now, depending on the valving alignment, of blowing out the
! 11 pump.
1 12 MR. EBERSOLE: This brings into view a couple of
, 13 other things, too. What is the circuitry that keeps the l 14 valves opening? An interlocked system, the two valves in I 15 serie s? Does it keep you f rom opening in high pressure in l 16 an individual high pressure / low pressure system?
i 17 Those imply some interties between two valves to j 18 ensure if one is open the other is shut.
~i 19 MR. BAER: On the suction side there is a series 1
- 20 of interlocks, but this is the ECCS injection line. Maybe i
21 Eric can help me, but it has an automatic opening signal on I' 1 i 22 an ECCS signal, but once the pressure is down --
23 MS. WEGNER: There's a permission first and then 24 there's an open.
I 25 MR. REED: I believe you said something about I
i I
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27026.0 21 BRT 1 Dresden had had a problem, similar problem on this valve 2 leakage before?
3 MS. WEGNER: No, sir. That was the mode switch.
, 4 MR. REED: .Oh, not the valve leakage. Valve
- , 5 leakage, is that going to be corrected? It seems to me i
6 that's a seat and disk maintenance issue, such as on the i 7 check valve 28B and 29B. Are they having a problem of 8 accession because of radioactivity, or lack of tools to lap 9 the faces or what's the problem?
10 MS. WEGNER: The licensee has not addressed that j 11 corrective action ye t. It will have to be addressed per t
! 12 the confinmatory action letter, and I can assure you we 13 will review it. The overpressurization caused by the 14 leakage will have to be addressed. Not just meeting tech 1 .
! 15 s pe c s .
l 16 MR. EBERSOLE: One other little facet, we are i
17 just running over time a little bit. I suggest and request l 18 you look at that mode switch again which was part of this i
{ 19 problem. I always envision a mode switch with something a
j 20 like 1630 --
l 21 MS. WEGNER: Ye s , sir , there 's a picture .
22 MR. EBERSOLE: In hypothesizing a local l 23 contlagration I've never quite satisfied myselt as to what 24 sort of hot shorts and so forth could degenerate that. I j 25 remember one time GE tried to get rid of the modo switch 4
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\ 1 function of executing the main steam line closure and it l l
2 meant a rise in pressure -- loss of pressure on the l 1
3 secondary side , which is hypothesized as a steam line break 4 if they were in the other than run mode -- start up. And 5 that presented a problem which they eventually corrected.
6 They did not get rid of that. But the mode ' switch is a 7 beautiful focal point for trouble and I'm not quite certain 8 as to what sort of potentialities there are in it if you 9 try to extrapolate.
10 MS. WEGNER: I don't think anyone has ever found 11 the problem that -- whatever it was that caused the 12 iniations in the past, I think it went away when they 13 installed the new modo switch, which I presume Pilgrim is 14 going to do since they already have one.
15 MR. EBERSOLE: The mode switch is a sa fety-grade 16 switch, isn't it?
17 MS. WEGNER: I wouldn't think so.
18 MR. EBERSOLE: On the other hand, how can it be 19 when it's only one switch with one panel that can come of f, 20 like --
21 Well, let's move on or we'll never get through.
22 MR. LANIK The event I'm talking about is an 23 event of of t-site power disturbance at Pt. St. Vrain.
24 (Slide.)
25 This is an April 3 date. If you recall, they O
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! 27026.0 23 j BRT I had this huge snowstorm out West. They are speculating i
2 this was the worst snowstorm ever, if not the worst one in 3 30 years. In fact, they had something like 240 faults on j 4 their distribution system.
- 5 The significance of this event is that it's an 6 event where, at Ft. St. Vrain, they had a loss of forced 7 circulation. This is equivalent to something on a PWR, for 8 example, like loss of all feedwater. However , because the i
1 9 Ft. St. Vrain reactor has a lot of thermal mass and the l
j 10 responses are a lot slower, you usually don't have the time i
11 concern that you do on PWR.
l 12 The other aspect of this event was there was a 13 very small release of noble gas, xenon 135.
't 14 Just to put that in perspective , they typically 15 release , during 100 percent power operation, they would 16 typically release about 100 millicuries a day. So this was j 17 just a puff in a short time equivalent to what they would i
j 18 normally release in a day.
I 19 (Slide.)
l!
20 This is a diagram of the power systems, down at 21 the -- basically the 480 volt region. At Ft. St. Vrain i
22 they have 5 outside power lines which feed in. There's a 23 switchyard up here somewhere and they feed in through these 24 480 volt -- through transformers to the 480 volts.
- 25 Well, during this event they had 15 separate
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27026.0 24 BRT O 1 incidents where they lost one of those 5 of f-site power 2 lines. The worst situation they were in they still would 3 have two available. Wha t was happening is they'd lose a 4 line and restore it, lose a line and restore it.
5 One thing that came out of this event was they 6 found that the way these things affected the controls of 7 some of -- like the bearing water pumps for their 8 circulatings, they need bearing water to keep running these 9 helium recirculators , similar to the way you need seal 10 inspection on a PWR pump. They had disturbances in these 11 due to the of f-site power disturbances.
12 One of the ways that happened is they would --
13 they were losing single phases of these of f-site power 14 lines and the circuitry that monitors for undervoltage on a f
15 three-phase system usually takes a two out of three logic.
16 In other words, you have to lose two out of three phases in 17 your three-pnase power system to drop out the undervoltage 18 really. Also, there is -- usually those relays have timers 19 on them. Some of them are set for 120 seconds, some for 30 20 seconds, so you can lose a phase , you can lose two phases 21 and get them back, as long as you get them back within a 22 certain amount of time.
23 MR. EBERSOLE: You say this was during this 24 storm they were in. Did the operators anticipate this and 25 get on with starting the emergency generators and O
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- 1 stabilizing on it --
1 2 MR. LANIK: No. They always had two out of rive 3 outside power lines.
4 MR. EBERSOLE: The problem is they didn't know .
l i
5 how close they were to trip.
, 6 MR. LANIK: There are two aspects of this event.
7 One thing is, first of all, they are operating -- they are 8 at limited power at Ft. St. Vrain; they are being kept below l 9 35 percent power.
3 10 MR. EBERSOLE: But they still have those 11 critical seals, don't they? And by the way, that's not i
12 sealed lube water, tha t ' s the wa te r -- it is a purging
- 13 water.
14 MR. LANIK: They have bearing water and the 1
15 bearing water is really the purge water. It's the same i
- 16 thing.
I j 17 MR. EBERSOLE: If you lose the water you lose i
, 18 both the gas retention capability and the bearing function 19
)) itself, don't you? .
20 MR. LANIK Right.
21 MR. EBERSOLE: I remember, that came out of an ,
i 22 incident, believe it or not, in 1954. Carry on.
l 4 23 MR. LANIK: Okay. Like I say, one thing about 24 this event -- first they are restricted to operation below l
j 25 35 percent power, although loss of circulators is a problem I
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- 27026.0 26 j BRT 1 at 100 power af ter 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> -- well, the problem at that 2 plant is if you lose circulator flow, forced circulation, 3 for five hours, you can' t restart it because - they cause a 4 thermal transient on the steam generators. So, therefore,
! 5 if they ever get to five hours they just don' t restart them.
1 6 On the other hand, the plant can withstand loss 7 of the circulators and loss of the cooling for the concrete 8 reactor vessel for up to, like 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />, be fore they have l 9 to get that back.
I 10 MR. EBERSOLE: If you lose this water which
- 11 pe r f orms the f unction of helium ceiling as well as bearing 12 cooling, what is the interval of time before which, if you #
a 13 continue to run the pumps, that they are gone forever? Is 14 there an automatic cutout instantly?
I a
15 MR. LANIK: It's called a loop shutdown. Tha t 's 16 one of the trips that shuts down a loop.
17 MR. EBERSOLE: At that time isn't there a i
18 hea t-up of the local area around the seals due to helium i
- 19 outleakage and a horrendous transient possible when you try i
20 to restart the pumps? You lose the helium seal function, i
21 don't you?
22 MR. LANIK: I'll have a drawing of the i
23 circulator up there in a second. If I could just make my 24 point here.
l 25 MR. EBERSOLE: Sure. Sure. Go ahead.
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k/ 1 MR. LANIK: Anyway, you have two out of three 2 logic on your three phases and off of here --
3 MR. WYLIE: Excuse me, you said two out of three.
4 At what level?
5 MR. LANIK: Some of them are at 80 percent, some 6 at --
7 MR. WYLIE: No, I mean what voltage level? Are
- 8 you talking about down on the auxiliary system? That's not 9 line?
i 10 MR. LANIK: No. I believe it's on the 4160; is j
l 11 that true, Vince? I believe it's on the 4160. j 4
1 12 Actually, it's probably in the 480 volt. '
^w 13 Probably on the 40 volt too, because that's the thing that 14 starts tne diesels.
i 15 MR. WYLIE: That's where you separate --
16 MR. LANIK: That's where you separate. You want 17 to get on emergency power if you have actually lost the 18 feeders.
19 MR. WYLIE: Actually what you are looking at 20 here --
21 MR. LANIK: These are the 4160s, and these two 22 buses are on the diesels. So you'd want to disconnect here, 23 here , and here and connect here with the diesel.
24 (Indicating.)
~
25 MR. WYLIE: These lines come from the of f-site w
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1 power?
2 MR. LANIK: The ones up above come from the 3 of f-s ite .
4 MR. WYLIE: Correct. They don' t tie to the 5 generators?
J 6 MR. LANIK: Right. The diesel generators are 7 down here.
8 MR. WYLIE: I mean the main generators.
9 MR. LANIK: The generators are out there 10 somewhere. Actually one of these comes out of a unit 11 transformer --
12 MR. EBERSOLE: Wha t he 's saying is the input 13 power for the criticality functions is derived from the 14 main generator or the orf-site incoming lines?
15 MR. LANIK: Typically, like a BWR, they have a 16 unit transformer and start-up transformer.
I 17 MR. EBERSOLE: In the normal operations is the 18 station power drawn from the generator?
19 MR. LANIK: From the generator.
20 MR. EBERSOLE: And it's transferred --
21 MR. LANIK: There's nothing unusual about this 22 system, really.
23 MR. EBERSOLE: They are making the new ones 24 different because they don' t depend on the generator ' output.
25 MR. WYLIE: If those two outside lines are l
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l 27026.0 29
) BRT 1 coming from the aux transformers, on the main generator in 2 this' normal supply, then I'm having a hard time figuring 3 out the inputs of the transmission lines tlashing on a 4 phase is going to give you this problem.
5 MR. EBERSOLE: Because the generator would be 6 rolling, wouldn't it?
l 7 MR. WYLIE: Unless they are supplying directly t
j 8 f rom the of f-site power, which is the a preferred mode. I
! 9 don't know, maybe that's the way they are doing it. I 10 don't know.
11 MR. LANIK: These voltage drops were not for 12 long durations, in some cases. The voltage drop was very g 13 short duration.
14 MR. EBERSOLE: Normally they ride on the i
15 generator output you are telling me. If the generator 7
l 16 output trips because of some reactor function or whatever, 17 they transfer to incoming lines.
18 MR. LANIK: I doubt in this event they got -- I 19 could probably read the LER. I haven't looked into that to 20 see whether they stayed on that, how long they stayed on 1
4 21 the of f-site power.
! 22 MR. EBERSOLE: New designs recognize the fact 23 that to be on the output of the turbine generator, which is 24 sure to fail, is not good practice, so they design the new 25 plants to ride on incoming of f-site power as a standing C)
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27026.0 30 BRT 1 mode of operation, but this is an old plant and I expect it 2 rides on the output of the unit generator, unit transformer 3 and then has a transfer to keep the critical functions 4 running if that fails.
5 MR. HERNAN: Jesse, I'm Ron Hernan from the 6 Staff. Le t me ma ke it a little easier for you. The NRR 7 Staff is scheduled for a subcommittee meeting , the Ft. St.
8 Vrain subcommittee in about two or three weeks. We'll be 9 glad to get into depth on that.
10 MR. EBERSOLE: Why don' t we proceed on that 11 basis. Just go ahead here.
12 MR. LANIK: The problem was off of the 40-volt 13 buses you have an instrument bus which is a single phase of 14 that three-phase input. Apparently this phase was being 15 af fected and there's no protection on that. There was no 16 relays in there that had timers. They were instantaneous.
17 One of the things you want to do on this plant, 18 if you interrupt that bearing flow, you don't want to 19 restart all three bearing water pumps at the same time 20 because you'll overpressurize the cavity, the bearing 21 cavity. So what they do is protect relaying, but as soon 22 as you trip the pumps to prevent them from restarting, the y 23 have this protective relay which prevents restart 24 automatically. So that was dropping out whatever they got 25 at low voltage on that single phase.
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27026.0 31 BRT j 1 MR. EBERSOLE: So, I think we are eyeballing the a
2 bearing seal and lubrication f unction as the Achilles' heel 3 of this design?
4 MR. LANIK: The point I was going to make was 5 that the, perhaps the control logic for this -- and that's 6 one of the things that NRR is going to follow up on, the y 7 are looking at this to see whether the control logic for 8 these pumps should be on uninterruptible power.
j 9 MR. EBERSOLE: My comment, I made a mistake --
10 it was in '64-65 that these very same pumps, as I recall, 11 were trying to be put in Oak Ridge. If there was going to 12 be anything te sted in that year it was going to be the 13 helium system, including this one. It was never tested 14 Decause they didn' t spend the money to crank it up. But it 4
} 15 was known at that time that these water-buf fered seals and 16 their associated cooling functions on the journals were 17 probably the Achilles' heel on the whole design and yet 18 they were reproduced through here and they continue all 19 these years to be the Achilles' heel of the whole. I would 4
t 20 like to see this looked at as a focal point of the whole 21 project out there , maybe the one that is going to be --
22 eventually kill it. Right where you are talking, the seal I
23 function.
l 4
24 Carry on.
25 (Slide.)
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- 1 MR. EBERSOLE: Wha t's the clearance? About 7/10 2 of a mill? Same thing.
3 MR. LANIK: Basically, the pump -- wha t happened
- 4 before the release was eventually up here , you have your 5 reactor coolant system, and because of the disruption in 6 the auxiliaries that operate the pump seal and the pump 7 bearing, you had flow down the shaft, all the way down here 8 to the -- the pump is driven by steam from the secondary 9 steam side of the plant. So basically you have a flow path 10 down the shaft, out into the steam system and then 11 evsntually out the air ejectors.
12 MR. EBERSOLE: W'e are looking at the death knell 13 of Ft. St. Vrain, right he re in this cut, probably. It was 14 permitted to stand that way against all sorts of objections 15 to it: one, it being a static cooling system in which the 16 motor was a high frequency motor driven straight through 17 with pressure equalization on a frequency changer, Charlie.
I 18 What they did , they got a turbine drive to get the speed up.
t 19 That necessitates this mechanical seal, which is a i 20 water-buffered seal and the water does more than buffer the 21 helium flow outward, it also cools the journal.
l 22 Does this thing happen to have a shear pin in it, f
23 if you recall? The seal locks on the shaft it will shear 24 and rotate? The original design -- if you lock on the 4
l 25 sleeve because you lost the water, one of the original
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n 27026.0 33 BRT 1 designs was to shear it and permit the motor to turn anyway 2 and maintain a cooling function in the depressurized mode.
3 It turned out, however, that the -- that that was 4 impossible, eventually, because of oil heat up on the 5 journal.
! 6 MR. LANIK: This doesn't have any oil in it.
7 MR. EBERSOLE: It's interesting to call out the 8 focal point of the failure on Ft. St. Vrain --
9 MR. LANIK: They have some ideas on how to fix 10 it.
11 MR. EBERSOLE: Pull it out and flow it away.
12 MR. LANIK: They are not going to do that, I 13 don't suppose.
14 What happened here is they lost the sealed 15 bearing water which comes in here. You have the seal water 16 coming in here , you have steam down here and helium up here 17 and then you have a separate helium supply into the seals 18 also.
19 The way it is designed to work is the helium 20 pre ssure here is such that there will always be a net flow 21 of helfum up the shaft. This is purified helium, not 22 primary system helium from an auxiliary supply here, it
- 23 gocc up ' qe shaf t into the reactor and part of it also,goes i
24- down the shaf t where it meets up with the water, the water 25 coming up the bearing, going down the bearing, the water
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1 and helium come together and go out a helium-water drain 2 where it is recirculated and -- af ter being separated.
3 MR. EBERSOLE: I heard you say "always."
4 MR. LANIK: I didn't say "always." During 5 normal opera tion , I said. That's true during normal 6 operation. Here part of it goes up the seal, part of it 7 goes down, and you have the steam down here which is 8 driving the turbine, and part of that would come up to the 9 seal and the pressure should be such that it goes out the 10 steam-water drain.
11 MR. EBERSOLE: Wha t has been the fraction of 12 shutdowns due to the invasion of the helium system by water?
e3 13 Almost 30, 40 percent of them?
)
14 MR. LANIK: Could be . I don't know.
15 The other thing that is involved here, when you 16 get a looped shutdown or a circulator trip, there are 17 accumulators for the water, bearing water which was 18 maintained -- this bearing water flow, for about 30 seconds, 19 which is time to shut down the pump. There's a brake on 20 here. It's a helium-operated brake shoe that pushes down 21 like a disk brake on the shaft, and then there's a static 22 seal which is supposed to come here, pre ssurize the bellows, 23 push this down to the ceiling surface.
24 What happened in this case, and the only reason 25 you had the release was, even though they had all these O
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27026.0 35 BRT i 1 disturbances -- they were without forced circulation for 2 four different times in a two-day period, and the maximum i
l 3 time was up to 27 minutes, which indicates to me , first of 4 all, they got good at getting the se things back on line.
5 They didn't have really that much problem getting it back.
6 The other thing I didn't mention earlier was 7 they did choose to trip the plant manually once they i
8 started seeing -- be tore they ever had force -- loss of
, 9 forced circulation, they did trip the plant manually and 10 shut it down, so I think they took prudent action in this 11 case.
12 MR. EBERSOLE: Just a question --
- 13 MR. LANIK: Like I'm saying, let me finish.this --
! 14 MR. EBERSOLE: Sure.
j 15 MR. LANIK: The only reason they had the release j
16 is not only did they have loss of all auxiliaries
- 17 associated with maintaining dif ferent pressures on a
18 different parts of the seals, but also this was a leak on g a
- 19 one of the static seals because , perhaps again, debris on 1
s 20 the ceiling surfaces.
i 21 So even though they lost all these system 22 auxiliaries, if it hadn' t been for the fact that they had
] 23 the leak on that one static seal out of the four
, 24 circulators, they wouldn' t have had their release.
25- MR. EBERSOLE: You mention if they keep steam
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\- 1 generators out of service for five hours, I think, they get 2 so hot they can't get them started again; is that right?
3 MR. LANIK: I mentioned if you are without 4 forced circulation, using at least 1 circulator out of four 5 and you have been operating at 100 percent power -- some is 6 on a gradation between 35 percent power and 100 percent 7 power, that time would be different -- but the condition 8 they were in here, they were below 35 percent power, so 9 they could have lost circulation forever and not had a 10 problem.
11 MR. EBERSOLE: But the circulators are 12 turbine-driven.
-, 13 MR. LANIK: Turbine-driven. They have about 14 five different supplies for steam and water for these 15 things?
16 MR. EBERSOLE: Are' they treated as safety 17 systems?
18 MR. LANIK: And they are safety-related.
19 MR. EBERSOLE: And they count them just like aux 20 feedwaters on the PWRs; they want that. The y don ' t wa n t to 21 get into that business of the steam generator overheating.
22 MR. LANIK: If they lost forced circulation at
?.3 this plant for a long period of time and lost operation at 24 more than 35 percent, at 100 percent power they probably 25 l would never be able to start this up again.
A
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1 MR. EBERSOLE: They do have heat removal inside 2 the concrete reactor vessel. Could they not hold the j 3 temperature steady at that point and at some point retain
- 4 the operation level of the steam generators?
5 MR. LANIK: That's why they were being held at j 6 35 percent power for this period of time. The calculations 7 apparently show if you stay below 35 percent power on total 8- loss of forced circulation for a lengthy period of time, 9 you will not have --
, 10 MR. EBERSOLE: So this plant is restrained in 11 that context?
12 MR. LANIK: Right now they are restrained by
. 13 environmental qualification of some components.
, 14 MR. EBERSOLE: Thank you.
15 MR. REED: I like to keep a running track of how 16 you categorize these. Are you categorizing this incident i
17 as a design-related incident or a maintenance or operator 18 incident?
- 19 MR. LANIK
- I think it's a design-related event.
20 At this point there has been no decision made on whether
- 21 anything has to be done to correct it.
1 22 MR. EBERSOLE: I had heard that Palo Verde was 23 in the balance a little bit, you know, as to whether it 3 24 would be continued to run over the long haul, and wondered i
j 25 whe ther or not -- I don' t mean that. Palo Verde is on my i O 4
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O 1 mind. Pt. St. Vrain, I wondered if due regard had been 2 given to the fact that the focal point of all their a 3 problems has been what you are looking at here?
4 MR. LANIK: Right now the focal point, as they 5 see it, is getting the environmental qualifications.
j 6 MR. EBERSOLE: Is it really that? Even after 7 all that is done I don' t see any improvement in 8 availability coming up.
9 MR. LANIK: That's a regulatory requirement.
10 MR. EBERSOLE: Okay. Any questions? Any items 11 of closure on this that any Subcommittee members want? By 12 the way, you remember we have a function of identifying the 13 items here to which we take the full Committee. Any 14 observations about this?
15 MR. WYLIE: Le t 's see . I believe Ron said he'll
- 16 report this at another meeting --
17 MR. HERNAN: That's a Subcommittee meeting on I
18 the 26th, and the design issues should be further pursued 19 at that point in time.
20 MR. EBERSOLE: I agree with you. That covers 21 that. We can take that out and we won' t take this to the 22 full Committee.
23 Now, then, the earlier one where we failed to 24 i sola te , I don't see any particular point in taking that so 25 we'll quit -- we are clear on 1 and 2. Le t ' s go to O
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27026.0 39 BRT O 1 unexpected criticality and reactor trip. Mr. H. Bailey, I s
2 have here.
3 Mr. Bailey, we have lost five minutes. Maybe 4 you can pick it up.
5 MR. BAILEY: I think this will be rather short.
6 (Slide.)
7 This event occurred at San Onofre 3 back on 8 April 13th. They were in the process of doing a start-up.
9 That was only their third start-up since they had refueled j 10 on cycle 3 -- excuse me, cycle 2. It was the first start 4
i 11 up they had really done on cycle 2 in which they hcd 12 significant xenon present. That turned out to be -- have a
]
13 large factor here. Of course, the reactor became critical I
O 14 prematurely.
j 15 The significance of the event was it there was
! 16 inadequate control of the procedures the xenon tables for 17 cycle 1 was used, rather than cycle 2. It was a failure to 18 follow the approach to critical procedures in that the y 19 didn't really monitor closely to expect criticality at any 20 time.
i 21
~
And, finally, the criticality occurred below the 1
22 zero power dependent insertion limits. Approach to 23 criticality was after shutdown after 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />. Under these
! 24 conditions, xenon was changing rapidly. They had hoped to 25 go critical at 1100 hours0.0127 days <br />0.306 hours <br />0.00182 weeks <br />4.1855e-4 months <br />, because that was what it wa s se t i
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27026.0 40 BRT l l
) 1 for and if they missed that significantly they would have l
l 2 to start over again. They were already behind schedule.
i 3 They became critical at about 11:16.
j 4 They had a trainee on the panel, manipulating i 4 -
j 5 the control rods. This, you might recall, is very similar !
l l 6 to an event that occurred at Summer in '85.
i 7 As I mentioned earlier, due to inadequate 8 administrative control, the xenon tables for cycle 1 were 9 being used instead of cycle 2. Start-up rate was the main 10 parameter being monitored. They have a count rate and 11 power level recorders, but those were very slow-speed
- 12 recorders and they are tairly small.
13 So, as a result, the start-up rate was what was i
O. 14 l being monitored.
The procedure called for having no more
- 15 than a 1.0 sustained start-up rate, 1.0 per minute , and an
, 16 instantaneous of 1.5.
i 17 MR. EBERSOLE: Is there a rate enunciator of any i
18 kind?
t
{ 19 MR. BAILEY: I'm not aware of one.
1
! 20 There was no problem through this start-up that >
- 21 was exceeding any kind of rate. The rate was at about 1.5, 22 I believe, in any case.
j 23 The control room supervisor was on a four-hour 4
24 holdover f rom the previous shif t. This was about the j 25 middle of the day, and he had been on the previous shif t
! (:)
1 a
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l 1 and was on overtime , and he was in the process of being i
, 2 relieved, which is also in violation of their procedures.
3 Of course, the procedures called it -- you won't have any l 4 turnover or other special operations going on while you are
- 5 trying to go critical.
6 The shift superintendent was present, but he wa s 7 tied up on an operation being performed on Unit 2.
8 They pulled the shutdown and reliet valves out
- 9 and they were pulling their -- there are six regulating 10 banks and they were pulling the regulating banks in j 11 sequence. There was a slight misalignment on the full-out j 12 control rods. When they got them f ull out, this slight i i
13 misalignment, it turns out, generates penalty points in
- 14 their calculator. These penalty points can be fairly l 15 substantial, even at this low power level. Core protection i
j 16 calculators cut in at 10 to the minus 4 percent power, but j 17 actually as soon as it cuts in, for its purposes, it
! 18 assumes the reactor is at 20 percent. This is a i
] 19 conservatism in the core protection calculator, and it from j 20 time to time does create an operational problem, I might
- 21 say.
} 22 MR. EBERSOLE: What does the core protection 1
1 23 calculator trip at?
i 24 MR. BAILEY: 10 to the minus 4.
! 25 MR. EBERSOLE: That low down?
i i
()
t i
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27026.0 42 BRT O 1 MR. BAILEY: Ye s . If it gets the right penalty l
- 2 points it will. That's its trip set point and that's what j 3 happened here.
4 MR. EBERSOLE: It's saturation proof, isn't it?
5 You can't go through it fast?
l 6 MR. BAILEY: No, not that I'm aware of. The l 7 estimated critical position was 60 inches out on group 6.
1 8 Apparently it went critical at 80 to 100 inches on group 4.
]
j 9 This was not immediately recognized by either the trainee 10 or the licensed operator who was supervising. They 11 continued to pull the rods to about 110 inches and they 12 were on a stable 1.0 decayed ramp, and at this time the
{
- 13 control room supervisor recognized that they were critical 14 and he recognized that the criticality had occurred below 1
l 15 the insertion limits.
i f 16 MR. EBERSOLE: How does he discern between 17 critical and just a g adual rise in power?
i 18 MR. BAILEY: The procedure calls for you to pull 1
- 19 it and wait. When you pull it, you get a jump in your 4
20 start-up rate and then --
21 MR. EBERSOLE: He didn't do that?
22 MR. BAILEY: Apparently didn't do it well enough.
23 MR. EBERSOLE: They do it ste pwise instead of f 24 continuously?
j 25 MR. BAILEY: They were doing it stepwise , but ACE-FEDERAL REPORTERS, INC.
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i I
27026.0 43 BRT O 1 the indications are they didn' t wait long enough to see if 2 the start-up rate came back down.
j 3 MR. EBERSOLE: Did anybody investigate the ,
i 4 operator's training background?
j 5 MR. BAILEY: The control room? Well, there's no l 6 -- I'm not aware, yet, of any results of any investigation i t
] 7 on their background. Region 5 is still actually 8 investigating this event. Of course, the guy on the I 9 control rods was a trainee.
s
- 10 MR. EBERSOLE
- Did he know how to discern f i
} 11 between a critical case and uncritical case?
)
- 12 MR. BAILEY
- He had been through some i
j 13 preliminary training. I couldn't really address anything
. O- I 14 further than that.
l j 15 MR. EBEltSOLE: Okay. ;
i 16 MR. BAILEY: Of course , when the control room t
j 17 supervisor recognized they were critical at below the 18 limits, he directed the control rods be inserted. When l 19 they started inserting the group 4 control rods, they got 20 them in to a 98-inch level. This created more penalty
) 21 factors which the core protection calculator saw. At thio 1
22 point they were already above .the 10 to the minus 4 percent 23 power at which it cuts in and, therefore, they got a trip 1
2 24 f rom .the core protection calculator.
2 l
25 MR. EBERSOLE: Which worked normally?
i I ACE-FEDERAL REPORTERS, INC.
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i 27026.0 44 BRT 1 MR. BAILEY: Yes. The peak power that they
)
2 actually got to -- actually, it cut in at 10 to ' the minus 4
! 3 but then when they were peaking, their rod position gave
{ 4 them enough penalty points. At about 10 to the minus 2 is
} 5 where they actually got the trip.
6 MR. EBERSOLE: They got virtually no heat in the 7 rods at all? ,
f j 8 MR. BAILEY: No. The indication is the core was
! 9 nowhere near any actual limits at this time. It's just a l
} 10 feature of the core protection calculator and the rod I
l 11 misalignments they have at the time.
! 12 MR. EBERSOLE: It's a theoretical safety trip.
4 13 MR. BAILEY: Yes.
14 ( Sl ide . )
i i
15 As I mentioned earlier, the Region is continuing i
16 to investigate this event. However, in the meanwhile, the 17 licensee has made some changes since the event as follows: !
18 The start-up procedures will now be modified to require an ;
19 inverse count ra te , that's 1 over M plot, with a count rate i
I 20 prediction of criticality. They weren' t doing this.
I 21 MR. EBERSOLE: It would not be hard to create an 22 instrument that would tell you whether you are critical or l j
l 23 not critical on start-up, but I guess nobody thinks that's
, (
24 worth it.
! 25 MR. BAILEY: Well, no one has one, anyway, that i
l '
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i 27026.0 45 BRT i
- CE) 1 I know of.
i 2 MR. REED: You know, I have a problem with the 1
j 3 ovaremphasis of, we'll call it premature criticality, or j 4 the overemphasis on failure to meet the prediction. I wish 5 we would put the same kind of emphasis on decay heat j 6 removal, which is really the issue with respect to reactor i
i 7 safety.
l 8 Criticality on water reactors, particularly i
j 9 negative temperature coef ficient and negative coef ficient I
10 reactors, is not a big deal. In the early days of the l 11 reactor business, you didn't even have a prediction, you
- 12 just went ahead and said: Okay, hold a period or start-up 13 ra te of so much, and when you get to that, let us know.
i
- 14 Why -- this to me is not a big deal.
15 MR. EBERSOLE: It's for the same reason, Glenn, 16 we still call the instrument panel in an automobile a 17 dashboard. It was originally to keep something between you 18 and the horse . What this is is a fallout from the early i
! 19 days --
j 20 MR. REED: Of the academics.
21 MR. EBERSOLE: Of the academics. Sure.
22 MR. REED: In fact, in the third plant that I l
l 23 commissioned, I would not have a party on initial 24 criticality, because I thought it was a watt-less event, a 25 nonevent. Criticality is not a big deal. Quite frankly, i
i
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1 O 1 what I hear is the start-up meters were functioning. There 2 are, I assume, at least two. They were watching the 3 start-up' rate, that's the most importan t thing, and not i l
4 exceeding a sustained rate of over 1. l i
j 5 So, the trips were working. So they missed the 6 prediction and a lot of things were going on. But I don't l
7 find it a big event.
! 8 MR. BAILEY: I think it's more an indication of i
j 9 sloppy operation in general.
2 4
10 MR. EBERSOLE: It's a yardstick of operational i 11 discipline and that's about all it is.
- 12 MR. BAILEY
- That and the sloppiness of getting 13 the xenon tables mixed up. I think it's an indication of i
O 14 other problems, though.
I 15 MR. EBERSOLE: In that de fense , though --
l 16 MR. BAILEY: They did go critical below the zero i
{ 17 insertion limits.
i j 18 MR. REED: That's one problem I would pick out.
j i 19 The other thing is it would indicate lack of procedural i
- 20 rigorousness, but as far as what people get out of it --
t 21 there was a trainee on the board. I think also you'll find i
l 22 you have requirements that trainees must be involved in 23 making certain approaches to criticality per year. Is 10
- 24 per year still required?
)
25 MR. BAILEY: I'm not sure.
i
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1 27026.0 47 BRT 1 MR. REED: I think it is. You have to get it
- 2 into your record of so many approaches to criticality per
] 3 year, so this is the time when trainees have to function.
4 MR. EBERSOLE: It is true now that the se level 5 trips have all been fixed against saturation, so it doesn't 4
6 matter how hot the pe r iod is. They have been examined; 7 they will pick up a transient no matter how f ast?
J 8 MR. BAILEY: The core protection calculator? I 9 think it will, yes.
10 But you mentioned the monitoring charts -- there i
11 are some at zero and --
! 12 MR. EBERSOLE: The thing that stops the fast 13 transie.t is the Doppler in the fuel, the 238. Some of the 14 research reactors the professors had didn' t have any 238 15 and they had a real problem; they would get the fuel t I 16 without heating the water at all. ' There was no transfer to i
1 17 the water. There wasn' t time enough, Glenn. ,
i l 18 MR. REED: You are thinking of EBR 1, I think.
i j 19 MR. EBERSOLE: You could virtually detonate i
20 those thin foil fuel elements. Not now, but --
) 21 MR. BAILEY: We feel if they are not going to be 22 alert when they are starting up, they are not ever going to i
23 be alert.
1 24 MR. EBERSOLE: I think, operator discipline ,
i
, 25 it's a revelation of whether they have it or not.
l l CE) 4 i
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27026.0 48 BRT O 1 MR. REED: It's like automobile drivers. You 2 keep putting up 10 mile-an-hour signs on every highway and 3 pretty soon, have you accomplished your purpose?
4 MR. EBERSOLE: Yes. They ignore them. Anyway, 5 we won't carry this to the f ull Committee . It's still a 6 classical matter of significance because of history, I 7 think.
8 MR. BAILEY: There have been a couple of reports 9 put out by industry on this, that you would think you would 10 see less of this, 11 MR. EBERSOLE: This is the minimum flow logic 12 problems on Pilgrim? The sequence doesn't matter here. We 13 are one minute ahead of schedule. Not bad.
14 MR. WEISS: Good morning. On May 19, Pilgrim 15 called us on the Emergency Notification System, the red 16 phone, told us that they had identified a problem with 17 their miniflow logic, a potential single failure that could 18 disable all redundant RHR pumps during a small or 19 in te rmedia t i size break LOCA.
20 (Slide.)
21 The significance is twofold. First, they 22 identified a single f a ilure that causes losses of multiple 23 safety systems, not single but multiple safety systems.
24 The second significance is that there is really no 25 safety-related way for long-term cooling should this single O
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l 27026.0 49 BRT t
1 failure occur.
2 MR. EBERSOLE: It can't be fixed -- following j 3 the failure, can it be manually fixed?
4 MR. WEISS: Ye s . If you destroy the RHR pumps i 1 1 5 you are in a bind.
- 6 MR. EBERSOLE
- You mean it invokes destruction
) 7 of the pumps?
! 8 MR. WEISS: Tha t's right.
9 MR. MICHELSON: No flow.
. 10 MR. WEISS: If you destroy the RHR pumps, you 11 are in a real bind. There are some safety equf ) ment and 12 some of f-the-wall alternatives, but really you are in a 13 bind if you destroy all your RHR pumps in a boiling water i
1 O 14 reactor.
15 The licensee found this problem as a result of a i
j 16 review prompted by Information Notice 8584 that discussed
! 17 related problems.
! 18 MR. EBERSOLE: Pardon me. One thing, that would 19 be true except on the new plants like Limerick. They could i
20 still cool by the evaporate process with makeup, but that's 21 a rather floating matter at this time. Do you follow me?
22 MR. WEISS: Yes.
j 23 MR. EBERSOLE: Carry on. l 1
j 24 MR. WEISS: I will show you what we are talking !
i 25 about.
.i
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27026.0 50 BRT (5
U 1 (Slide.)
2 It's a plant that looks something like this. We 3 have four RHR pumps. They are aligned to the torus 4 ordinary to take a suction on the torus, and they are 5 multi-function pumps. They serve a number of modes. The y 6 can discharge to the recirc loops, via LPCI injection 7 valves, low-pressure coolant injection. They also provide 8 for containment spray, they provide for head spray and not 9 least significant, they provide for shutdown cooling.
10 (Slide.)
11 If we consider a particular design aspect of 12 this, the problem becomes more interesting. The se g3 13 particular vintage plants have something called loop select O
14 logic, which permits you to crosstie the two RHR loops 15 automatically and feed the good loop. By that I mean if we 16 postulate a break in the recirc loop, this Loop selection 17 logic is designed to close the LPCI injecti)n valve on the 18 bad loop, on the loop that has the break in it, and inject 19 all the flow over into the good recirc loop.
20 f1R. EBERSOLE: I thought all of those had been 21 invalidated as being unsafe , one reason being that the 22 method of determination of choice is a series -- a very 23 fast transient measurement of pressure gradient in the 24 system, to tell you which line is gone. Pretty close to 15, 25 18 years ago it was found the impulse lines that drove the i
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27026.0 51 BRT 1 pressure detection systems were wrapped around the very I 2 lines it was supposed to break.
l l
3 MR. WEISS: Mr. Ebersole, it's my understanding 4 that a number of plants out there have loop selection 5 limits.
6 MR. MICHELSON: It's a little more serious j 7 problem than that and I thought GE had eliminated this on 8 all boiling waters. The real problem is you are depending i
9 on a differential pressure measurement to de termine which
, L i 10 side is broken, and if you just send one of your inspectors l 11 up to watch the gauges near there, there's installed 12 instrumentation on all BWRs that show you that ditferential (
4
! 13 pressure, and just ask him if he thinks he can ever use 14 that tor detection of a break. It's under such severe i
j 15 hydraulic perturbation at all times it's a useless measure, ,
16 absolutely useless.
] ,.
17 MR. WEISS: There's a number of plants out there l 18 that have the loop select logic and I want to point out how j 19 a single failure in this minitlow line may cause you to I
! 20 lose all RHR pumps permanently. .
j 21 MR. MICHELSON: I'm trying to reach a little
) 22 deeper point, I ho pe , that is, when difficulties of this 23 sort are found and if the vendor, for some reason, isn't
) 24 feeding this back, why doesn't the staf f feed it back or is 25 the staff unaware of these problems? And they really
()
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. 1 shouldn't be, because there's long documentation on why 2 that crosstie had to be kept closed and eliminated on a 3 number of plants.
4 MR. EBERSOLE: This is certainly going to be an l 5 item taken to the full Committee and boiled out in its most 1
l 6 furious fashion.
7 MR. MICHELSON: I think the serious question is 8 why are there still plants out there with this arrangement, 9 unless you can clearly show this arrangement can even work?
10 In fact, the real danger is it picks the wrong side , very i 11 possible, and you don' t get any water to the vessel. It 12 all goes out the break.
s 13 MR. WEISS: We'll do our best to answer your
} 14 questions before the full Committee. It's my understanding, 15 having spoken to General Electric recently, that in a large 16 break LOCA they do not have to take credit ~ior the LPCI,
- 17 and that surprised me very much because I asked them about j 18 the temperature rise as a result of this f ailure in ' the i 19 large break LOCA, and I was told it was zero degrees t
l 20 beca use they assumed a single failure would close the LPCI i
1 21 injection valve.
l 22 So you don't have the LPCI system available on a 23 large break LOCA, which personally surprised me. But 24 that's a whole different ball game than saying all of the i
j 25 RHR pumps are lost, beca use the RHR pumps serve multiple t
I i
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27026.0 53 BRT 1 functions, including torus cooling, suppression pool 2 cooling, shutdown cooling. If you lose those functions, 1
3 it's an entirely dif ferent ball game. But let me get back 4 to the point here.
5 We are injecting into the good loop and we are 6 looking at flow sensors. The flow sensors are used to 7 close the miniflow bypass lines which are used for- pump 8 protection. Now, since all of the flow is going through 9 this sensor, when the loop selection logic was retrofitted 10 into the plant or sometime subsequent to that, a logic 11 change was made that crossed divisions. So now we have 12 this "or" gate, which really consist of two contacts in '
13 se r ie s .
i O 14 It says, if I have got flow, then I close my E
15 miniflow valves. The problem here is, obviously, that a 16 failure of this sensor or anything in this logic, a single 17 f ailure , will close all the miniflow lines. Then the pumps 18 are sitting there deadheaded in a small or intermediate t
19 size break LOCA or even an inadvertent actuation. Or it 20 could have a failure over here of this insert or something 21 in this logic and it would do the same thing.
i 22 MR. EBERSOLE: The plant is presumed now to be 4
23 at low pressure, so it could receive water if it had it?
24 MR. WEISS: In an intermediate or small break 25 LOCA, the reactor vessel pressure remains high.
()
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27026.0 54 BRT 1 MR. EBERSOLE: That's what I mean. But you 2 pre sume the pressure has been decayed for whatever reason, 3 by blowdown or leakage, and it's now receiving water from 4 these pumps?
5 MR. WEISS: If I had a large break LOCA that 6 would be correct, but I'm talking about a small or 7 intermediate break LOCA. I'm also talking about an 8 inadvertent pump actuation in which the reactor pressure 9 remains high. The pumps remain deadheaded. The pump 10 manufacturers do not warrant the pumps longer than a minute; 11 however, GE tells me there has been actual operating 12 experience where several pumps have survived a long period 13 of time: I believe Fe rmi , two hours; Brunswick, a half v
14 hour, and they have run af ter being deadheaded for that 15 period of time.
16 MR. MICHELSON: The real key point -- and those 17 experiences were that they were able to run a while -- the 18 real key point is they were able to drive the water out of 19 the casing fast enough so they were running on steam or 20 emptying, and once you do that, then the worst that happens 21 is eventual bearing damage. The real problem is if you are 22 in a situation like this and you have voided the casing and 23 then you open the valves, the water slug will just 24 literally destroy the pumps. No matter whe ther they 25 survived a few minutes, if the operator isn't smart, if he n
( )
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27026.0 55
-BRT. ,
) 1 opens the valves now, he's in trouble. Once the pumps are 2 voided and you send a water slug in, that's the end of the 3 business and that's the real danger, not the fact that --
4 they can, survive for long periods of time if they are 5 caref ully vciding 'them and then don' t refill them.
6 MR. EBERSOLE: I think this is a trigger event, 7 to go into the whole show of these pNmps and for that 8 matter, generic pump performance on close , discharge. -- you 9 know, zero flow, what they do -- and for that matter, on 10 full LOCA tlow.
11 MR. WEISS: The preliminary safety analysis I i 12 looked at --
i 13 (Slide.)
i ,
'14 -- said, in effect, at least we've got 15 low-pre ssure coolant injection. That will handle the small '
16 ' 'or intermediate break LOCA. Low-pressure core spray, '
17 ekcuse me. The low-pressure core spray is a. separat$-
18 system with its own pumps. It draws a section from the
- 19 suppressionepool and sprays ihto the vessel.
20 - -
The problem is they come from the suppression 2h . pool. The suppression pool would heat up, and you wouldn't 22' have suppression pool choling so you'd lose net positive 23 suction head. In- this vintage plant they are not committed -
24 to Reg Guide 1.1, so they need the suppression pcol cooling [
25 in order to prevent loss of not positive suction head or O -
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27026.0 56 BRT O 1 they have to take cre" it for pressure in the conta inment , NPSH.
2 But then you've lost containment spray. You have lost your 3 ability to cool the containment. So presumably, you must 4 purge. Then you lose NPSH.
5 Initially, the high coolant injection and 6 reactor core isolation systems take condensation -- but in 7 the latter station they draw from the suppression pool. So 8 we have lost anything that takes suppression -- anything 9 that can inject from the suppression pool has NPSH. We 10 have lost --
11 MR. EBERSOLE: You have, bottom line, lost 12 containment heat injection.
~
13 MR. WEISS: This doesn't mean, necessarily, we 14 have lost the condenser over --
15 MR. EBERSOLE: No, but we can't count on it.
16 MR. WEISS: And a number of plants have a standby 17 system where they can take RHR service water af ter having 18 moved a few spool pieces and valves and so forth and inject 19 that directly to the vessel.
20 MR. EBERSOLE: I understand at Browns Ferry they 21 were contemplating eliminating that connection.
22 MR. WEISS: There's also at multiple-unit sites 23 often an ability to crosstie between units; again, moving 24 spool pieces and valves and so forth. But the point I'm 25 making is we have - single failure that wipes out a variety O
t i
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(~%
1 of safety systems and af fects the long-term course of the 2 accident. It doesn't affect the initial stages but affects 3 the latter stages.
4 MR. EBERSOLE: I'm glad now we have a tocal 5 point on which to address this problem as well as the more 6 generic ones.
7 What about at large? Pumps are not designed to 8 operate with closed discharge very long, so far as I know.
9 Do they have miniflow bypass lines? And if they lose the 10 main bypass and those don't function, the pump has had it.
11 I think there are many pumps, also, if they go to an open 12 discharge, unimpeded discharge -- what's the magic word --
r- 13 runout flow.
L)g 14 MR. WEISS: Runout.
15 MR. EBERSOLE: In a somewhat equivalent fashion, 16 they can' t carry that load because of horsepower problems 17 and so forth, and they stop for other reasons. I have ye t 18 to see a more or less generic consideration of the se 19 problems across the board.
20 MR. WEISS: Well, I'd say this: When I looked 21 at those problems brie fly on other plants, it's usually 22 been a case of a single failure causing loss of a single 23 train. I don't usually run across a single failure wiping 24 out a system entirely, much less multiple systems.
25 MR. EBERSOLE: Like this.
(~h t)
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27026.0 58 BRT 1 MR. WEISS: That's what makes this unique.
2 MR. EBERSOLE: Is there any inquiry now being l.
3 made as to how many plants are subject to this?
4 MR. WEISS: Yes. We have issued a bulletin, a i
5 compliance bulletin, 8601, and that is requiring all I
6 boiling water reactors, even though we don't think all
! 7 boiling water reactors have this problem, to respond and i
j 8 tell us if they have the problem and what their fixes are.
9 MR. REED: Could you flash the drawing back 10 there for a moment? I'm wondering if there isn't another 11 single component failure to the piping.
I 12 That crosstie line, I have never seen one in my 13 experience with only one crosstie valve.
, 14 (Slide.)
i i 15 I believe there's more. I simplified this
! 16 greatly. I didn't stick a lot of the valves in. I have a 17 detailed drawing I could give you.
- 18 MR. REED
- All right. Because most of the time 19 they always have two; in case one valve bonnet blows off,
)
j 20 you have killed both sides.
21 MR. WEISS: In any case, this system is subject i 22 to a single failure in the LPCI injection mode. A single l 23 failure of this valve would defeat all LPCI. But that's 24 not the point. The point is you don' t destroy the pumps in j 25 that case and you can get suppression pool cooling and i 3 ACE-FEDERAL REPORTERS, lNC.
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, 1 containment cooling because you have the miniflow --
l 2 MR. REED: This is a very key issue. There have 3 been people , even commissioners, who have said there are no 4 design problems. It's all operations and maintenance. But 5 I would like to get in this point.
6 Here again, we should keep thinking back, the i 7 I&E folks should keep thinking back to the need tor J
8 redundancy in principle for decayed heat removal in some of r 9 these functions. This certainly is not redundancy in 10 principle.
I 11 MR. EBERSOLE: I believe this plant here -- if 12 it's like the old Browns Ferry plant, you can close the 13 crosstie and what happened was you can invoke the total O-14 loss of train A or train B from the core cooling viewpoint, 15 and of course you still have the function of -- if you 1
16 didn't lose the pump, you'd still have torus cooling, and 17 invoke the core spray pump as -- not as a spray function,
- 18 but as a makeup f unction to cool the water along with the 19 two -- therefore, a large break -- and you had it made.
20 And I'm astounded to find that this crosstie hasn' t been 21 closed in all plants and all that bric-a-brac, that junk 22 that was supposed to make it run, been stripped.
t l 23 MR. MICHELSON: I think it was done at all the 24 later ones. Pilgrim, apparently, slipped by. There are a
- 25 lot of deficiencies in this arrangement.
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27026.0 60 BRT 1 MR. EBERSOLE: What we have is an operational 2 problem is, Pilgrim hasn' t gotten the word.
3 MR. MICHELSON: That's the disturbing thing.
4 How come the utilities didn' t get all -- didn' t all get the 5 word? This is 15 years ago.
6 MR. EBERSOLE: This is INPO,,EPRI, the whole 7 caboodle. We don' t have a communication system.
8 MR. WEISS: It's my understanding that a number 9 of the BWR-3s have the loop selection logic and a couple --
10 one BWR-4.
11 MR. MICHELSON: Doe sn ' t the Staf f wonder why the 12 logic was changed on the earlier ones, and go back and look gS 13 and make a decision, and that ought to be a documented, G
14 well-thougnt-out decision? So you should go back in your 15 records and find such documenta tion. If you don't, I'm 16 also very surprised.
17 MR. EBERSOLE: I think it's important that you 18 found this. It's really lifting a rock and finding lots of 19 worms under it.
20 MR. MICHELSON: I thought this was gone long ago, l l
21 long, long ago.
l 22 MR. EBERSOLE: Well, tha t's it. We'll take this l l
23 to the full Committee; is that agreed?
24 MR. MICHELSON: Just one small question, the "or" 25 ga te they used. Did they use that on a one-on-two twice g_
(s '
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\ 1 logic?
2 MR. WEISS: No, it's my understanding it was 3 simply two relay contacts in series. I have the 4 elementaries, which I ' d be glad to share with you.
5 MR. MICHELSON: They really went simplistic on 6 the "or" ga te , then.
7 MR. EBERSOLE: I think we should allot --
8 MR. BAER: Carl, when you go through the log ic 9 -- I haven't tried to do it in detail, but if you start 10 thinking about single failures, you get into -- if you say 11 I want an AM gate you get problems, too, because if you 12 lose a loop and then you are diverting 10 percent of your 13 flow from your remaining loop --
14 MR. MICHELSON: That crosstie, as long as it's 15 open there tras a lot of problems in this system and that's 16 what happened. The crosstie closed forever in the later 17 BWRs; in fact, they talked about cutting the pipe out and 18 getting rid of the valves.
19 MR. EBERSOLE: I expect in the full Committee 20 meeting we should allot an especially long time for this 21 topic. Any f urther questions?
22 MR. MICHELSON: It might be interesting if maybe 23 somebody from NRR can come and explain to us the licensing 24 implications, how this happened, why Pilgrim is allowed to 25 ope ra te this way and the later PWRs made the change?
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! 1 MR. EBERSOLE: That would make a valuable issue 2 on this topic.
3 MR. MICHELSON: And then , of course , also if 4 they did review it, what document I can read to see what
! 5 was done?
i 6 MR. ALLISON: We understand. We'll get that in.
l 7 MR. EBERSOLE: I understand Mr. Clark is not 8 here ye t , so why don' t we call a 10-minute break.
I 9 MR. MICHELSON: One more question. Did Pilgrim 10 have a PRA?
4 11 MR. WEISS: I don't know.
j 12 MR. MICHELSON: Do you know? That would be I
13 another question, did they have a PRA and why didn' t the PRA l 14 pick this up? PRAs are supposed to do all these good
) 15 things. How did these get by the PRA? Apparently a very i
) 16 simplistic "or" gate , and got by the PRA. 1 4 '
I 17 MR. EBERSOLE: For tha t matter , if not merely i 18 Pilgrim, any other plant in this configuration, did it have I 19 a PRA and did it pick this up?
4 i 20 MR. MICHELSON: That's right. They won' t know I 21 that, I guess, until they get their responses.
22 MR. LANIK This is an example of -- I think the 23 regulatory process worked fairly good because it originated 24 as an engineering report from AEOD. We issued an
! 25 information notice; neither of those two things addressed 1
I 1
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27026.0 63 i BRT j 1 the particular single tailure problem here. But in i 2 follow-up at the Pilgrim site , the Pilgrim people picked it
- 3 up on their own and reported it to us, and that's how it i
1 4 went on.
I J
5 MR. EBERSOLE: It came out of an LER?
6 MR. LANIK: Reported into the operations center, i 7 originally.
8 MR. MICHELSON: Did you say there was an AEOD
,l q 9 re port?
1 1 10 MR. LANIK: Yes, that addressed multi-function 11 valves but that did not address a single tailure wiping out 12 both systems. We wrote an information notice relating to 13 the multi-f unction valves, and at that point when Pilgrim f 14 read that, they looked more dooply into their system. The y
- 15 tound they had a single f a ilure , which is a completely j 16 dif ferent problem than the thing started out. It showed j 17 how the thing progressed through the NRC.
18 MR. MICilELSON: The real deep issue is that this i
19 is a long-standing question on boiling water reactors and I
i 20 it was tixed on some and not on others, and the question is, 21 why wasn't it fixed on some, like Pilgrim, long ago, like i 22 15 years ago? That's the question I would like answered.
23 MR. EBERSOLE: Well, it illustrates a more i r 24 generic thing. If you lift these rocks at the detail level 25 and not f rom the cosmic view that ACRS is supposed to view l () ,
i 1 ACE. FEDERAL REPORTERS, INC.
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('s 1 things, you find snakes under the rocks. I wonder how many 2 other snakes.
3 Let's have a break and come back at 10 af ter 4 10:00.
5 (Recess.)
6 MR. EBERSOLE: I would like to resume this 7 meeting. If Mr. Clark is here, we 'll take him.
8 MR. CLARK: Thank you.
9 (Slide.)
, 10 My name is Dick Clark. I'm the Browns Ferry 11 project manager and we are here to talk about an 12 inadvertent systems actuation, or undesirable systems f-' 13 interaction that occurred at Browns Ferry Unit 1 back on 5
14 May 3rd.
15 This series of events all started on April 30th, 16 actually, when they were replacing a fire hydrant out in 17 the cooling tower yard. I hate to mention it, but it was 18 just a few days thereaf ter when we had a cooling tower fire 19 in cooling tower 4. They were replacing the tire hydrant 20 out there and it resulted in a depressurization of the fire 21 header. As a result of depressurization in the tire header ,
22 some leaking check valves, which we'll get into later on, 23 some of the deluge valves opened up on the 593-foot 24 elevation and sprayed down some of the cable trays and some 25 of the panels there, including the RPS instrumentation ACE FEDERAL REPORTERS, INC.
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27026.0 65 BRT 1 panel for Unit 1.
2 MR. MICHELSON: Just on that point, you can 3 confirm it or not. We have chatted with TVA from time to 4 time about tire protection and fire protection problems.
5 In fact, the last time we chatted with them was on Watts 6 Bar in Knoxville a couple -- year and a halt or so ago. I 7 was led to believe that at least for that plant, they 8 didn't have any deluge systems and I thought I was led to 9 believe TVA doesn't use deluge systems except in a few 10 instances such as the llPCI room. I gather now, though, 11 that they do indeed have deluge systems and apparently in 12 areas where it can spray vital equipment.
13 That means there are no thermal linkages on the 14 individual nozzles; it means one valve charges the system 15 and sprays a fairly large area. That's generally what a 16 deluge means.
17 MR. CLARK You don't have this slide in your 18 particular handout.
j
, 19 (Slide.) l 20 This is what caused these leaking check valves 21 here but they actually do refer to them as deluge valves or 22 tixed spray systems.
23 MR. MICilE LSON : They feed 20 spray nozzles and 1
24 there are no thermal links in the nozzles; is that right?
25 MR. CLARK: No. It depends on pressure in these l
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l j 1 check valves keeping this deluge valve, the pressure in the 2 header keeping it closed. If, as it ha ppe ned , these check
- 3 valves leak, letting the pressure of f that valve, as you 4 could see up here on the clapper, then unfortunately it j 5 opens up. ,
I 6 One of the corrective actions we'll get into l
7 later on is replacing any of the se that are suspect, and 8 checking and doing a lot ot maintenance on the others.
9 MR. MICHELSON: Replacing, you mean replacing '
10 the deluge valve?
11 MR. CLARK: No. They are replacing the check l
j 12 valves. It was the check valves at fault.
i >
13 MR. MICHELSON: They are still keeping the i
14 deluge system? Now, keeping in mind this is not a 15 seismically qualified system and so torth, and keeping in
?
).
16 mind GDC-3, which requices if there is inadvertent 1
- 17 actuation that the equipment be survivable, have you looked
- 18 at the equipment qualification in these areas where they i ,
19 are deluging to see that they have qualified it for water i 20 spray?
I j 21 MR. CLARK: That's one of the things that the
{' 22 corrective actions -- one of the most important corrective 1 23 actions they are taking, checking all the seals. The j 24 cabinets and whatnot were supposed to be sealed and in i
25 their own write-up -- you'll have a copy of the LER in a i
J :
i l ACE FEDERAL REPORTERS, INC.
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1 few days and I can give you copies of that. That was just i 2 issued the other day. They are not in the system yet, but l r i 3 as they themselves pointed out, one of the major
! 4 implications to them is the e f fect on the ir environmental 3
i 5 qualification program, j 6 MR. MICilELSON : Was there any direct spraying ot :
i 7 the system or all indirect through the conduits?
8 MR. CLARK: Direct spray, in three zones, in 9 fact, in the first situation. Then it reoccurred on May lith, 10 actually, i
j 11 MR. MICliELSON : Does this mean if I had had a I
12 big fire somewhere in the plant and I began to use a lot of i 13 water, at what pressure do I tinally get these inadver tent j 14 actuations and start a lot more water drain and kind of i
15 even lose my fire suppression capability? Because these
] 16 systems aren't designed for fires at all points 17 instantaneously.
l l
t 18 MR. CLARK: No, you can drain down the he ade r .
19 MR. MICilELSON: liow much pressure drop does it i
20 take before these things actuate?
i 21 MR. CLARK: In this case, in both cases, April l
22 30 and May 11, the pressure went essentially to zero. In
- 23 the first case it did actually go to zero.
l 24 MR. MICilELSON: Assuming we have a usage that 25 causes the pressure to drop, what is th9 actuation point at O
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27026.0 68 BRT 1 which these deluges will start at other locations?
2 MR. CLARK: If things are working right and the .
I 3 check valves are holding, I don' t think, to my
! 4 understanding, it should have occurred at all, even if the
]
5 pressure had dropped down.
) 6 MR. MICilELSON: Clearly, if you drop to zero, it f 7 happens.
j 8 HR. CLARK: The normal pressure in that system 9 is about 170 pounds.
10 MR. MICilELSON : I thought it was a little lower 1 i l 11 than that, but okay.
i
! 12 MR. CLARK: In the fire header. ;
j 13 MR. MICilE LSON: You are saying, almost to zero, 14 it will not actuate?
?
15 MR. CLARK: That I can't answer. I really don't 16 know. It's a good question and I'll find out the answer l 17 tor you, but I don't know.
18 The way they explain it in cheir analysis, if 19 the check valves had held it wouldn't have occurred.
20 MR. MICllELSON: Doesn't it really disturb you 21 that a nonseismically qualified system like this, which 22 there's always a chance at putting a nonsoismic pipe during 23 a seismic event -- I don't think anybody can discredit that 24 -- that you start to actuate fire protection around the '
25 building? I don' t know how much more could be actuated
- O
}
i
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27026.0 69 BRT 1 besides the particular ones that were actuated. Isn't this 2 kind of -- I would think this warrants an AIT-type 3 investigation, as opposed to just a regional look at it.
4 Apparently none was appointed for this.
5 MR. EBERSOLE: As long as the line was 6 pressurized, everything was stable. Then something 7 happened and they lost pressure. When they reestablished 8 pressure --
9 MR. CLARK: The clapper was --
10 MR. EBERSOLE: It was held, then it didn't 11 rescat. So its dependence on sealing is the standing 4
12 pressure in the header, and once you relieve that it may 13 not reseat, as s typical of lots or valves.
14 Notmally it's opened by some sort of a sensor I
15 and diaphragm actuation?
16 MR. CLARK: Yes. Heat.
17 MR. EBERSOLE: This, of course, didn't occur.
18 It just happened to swing back. There's no spring action 19 to keep it seated?
20 MR. CLARK: No. It we look at the design --
l 21 (Slide.)
22 MR. REED: What about the installation? Is it 23 installed in vertical lines, upside down nr right sido up?
24 MR. EBERSOLE: It may have a gravity logic.
25 MR. REED: That's what I am wondering about.
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O 1 MR. CLARK: I don't know.
i I
- 2 MR. EBERSOLE: Unless that little spring has an !
j 3 assist function, which I don't think it has, then it is I j 4 gravity dependent to close.
5 MR. REED: I would look very closely at whether 6 these valves are installed properly, because you've got to i
7 realize that check valves in this kind of system are not ;
8 very likely, in a totally hydro-filled, no air bubble 9 system, not very likely to do anything other than leak ott 10 the pressure in the first millisecond. So I'm wondering it i i
- 11 the valves are not physically ranged -- located properly. t I
12 MR. CLARK: Check on the installation. !
i l 13 MR. MICHELSON: You might also ask them if they 1 O 14 have in the Asiatic clams in those valves. That's not 15 tacetious at all. They have had a vast amount of i
16 dif ficulty with Asiatic clams over the years.
17 MR. CLARK: And corrosion inside of three yeats.
18 It is disheartening. L l
19 MR. MICHELSON:
I would think this kind of event, f
j 20 as of ten as it happened -- on two or three occasions at l '
21 least, I didn't go back in history -- I'm surprised the )
7 J 22 Agency hasn't taken a much more serious view of it. At l 1
! 23 least an AIT-type investigation. Is there some reason why 24 the agency doesn't view this as a particularly serious l 25 problem? !
i
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j BRT O 1 MR. EBERSOLE: Incidentally, Glenn's question 2 about installation, if it's a valve like that just trom i
3 visual inspection it is a gravity-dependent valve and ought i
] 4 to be installed in the position you show it. It will be I '
j 5 impor tan t to see whether the design drawings so stated and 6 showed and made explicit that is the case and then, as 7 typical practice, the construction people didn' t pay any l
?
8 a t ten tion to it, which is one ot the focal points of TVA's 9 problems, it's an open-ended, nonclosure process.
10 MR. CLARK: They have a major program going in 11 design control and contiguration management and walkdown of 1
l 12 the systems, as you are well aware.
- 1 )
i 13 MR. EBERSOLE: Yes.
- l 14 MR. MICHELSON: Apparently other people not too l i
15 tong ago had a problem wheroin the water pressure reduced Il i' i 16 for a while and they got an inadvertent actuation of firo i
f 17 protection at another plant. So apparently this kind of .
j 18 design is not something unique to TVA, by any means, and
} 19 there may be a serious outlier in this whole program, due l 20 to such arrangements as this. It -- certainly you ought to i
( 21 look at this closoly.
1 J 22 MR. EBERSOLE: Seismic actuation of the entire f 23 complex.
i l 24 HR. CLARK: Has anybody over talkod about an AIT?
l 25 That would come out of It.E, wouldn't it?
i O i
! ACE FEDERAL REPORTERS, INC. !
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27026.0 72 BRT 1 MR. BAER: It would come out of the Region ,
2 really. Since half the statt is already on TVA plants, 3 that might be a contributing tactor.
4 MR. MICHELSON: This is not a TVA-unique problem.
5 MR. CLARK: We don't need any more attention, 6 really.
7 MR. WYLIE: I assume the system is arranged 8 normally so that -- in zones, so that one safety channel is 9 not attected by one spray system.
10 MR. CLARK: You are correct in assuming that.
11 MR. MICHELSON: But the redundant one is the 12 same valvo, same arrangement, and it also actuated. Soo?
13 MR. WYLIE: In this caso here , they were all 14 depressurized.
15 MR. MICHELSON: I don't know it they got cross 16 trains or not with this particular deluge that ha ppened . I 17 haven' t heard yet.
18 MR. CLARK: This just happened on one lovel, the j 19 593 foot olevation. But it happened -- the first incident, 1
20 April 30, occurred both in Units 1 and 3, coincidentally on 21 the same olovation , 593. On the second actuation on May 11, 22 it actually only occurred in Unit 3.
i 23 MR. MICilELSON: Did it spray more than ono 24 division of equipment in the process?
25 MR. CLARK: Yes, it did.
1 O
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27026.0 73 BRT O- 1 MR. MICHELSON: Got both divisions?
2 MR. CLARK: Yes.
3 MR. MICHELSON: So, that's the whole proDlom 4 with the fire protection.
5 MR. REED: You said the 593 level. Is that a 6 high level or low lovel in the tacility?
7 MR. CLARK: Fairly high. You start at 519.
8 MR. REED: That supports my fooling the thing 9 may be installed incorrectly. The lower the level, the 10 loss likely in olevation --
11 MR. CLARK: More hydrostatic head.
12 MR. REED: The loss likely to havo the clapper 13 tlap open because --
14 MR. CLARK: What actually happened in the system --
15 (Slido.)
16 -- on May 3, they had an inadvertent actuation 17 l of the ECCS systems that was caused by water that had 18 gotton into two of the tunction boxes for two of the 19 pressure switches for dry wall high pressure. Which -- the 20 unit has been defueled and down tor over a year, so that it 21 wouldn't actuate the HPCI. It it would have boon in 22 pressure, it .would have actuated the HPCI system. The 23 pumps were racked out. The RHR injection valves, isolation 24 valvos were also racked out. Unfortunately, the motor --
25 two motor-operated valvos, injection valves, outboard O
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27026.0 74 BRT O 1 isolation valves on the core spray had not been racked out i 2 and they opened up. ,
3 The operator didn' t think too much ot it, 4 knowing that the pumps were racked out, and he got no 5 indication of any flow on the testablo check valve over 6 here that you may remember f rom another incident where we 7 had, back in August ot '84, an overpressurization of the 8 core spray system. j 9 It took about an hour before they finally found 10 what was happening, that they were tilling the reactor 11 through the koop-fill system over hero. These lines were l
12 open. This, as you remember from your design, is up on the i 13 root of the building to provido a head to it and they have 14 the pumps. It pumps in at about 1000 gpm. It went on for i
15 about an hour. They put about 60,000 gallons in, filled 16 the reactor vessel.
17 MR. MICHELSON: 1000 gallons a minuto sounds 18 awfully largo to go through just the core spray line. The 19 individual koop-till for the core spray is a relatively 20 small line. It'n a 1-inch line, probably. [
21 MR. CLARK: No, I think it's a 4-inch lino.
22 MR. MICHELSON: Not to the individual lines. It [
23 branches down to very small diamotor as it tills the e 24 individual lines. 1000 a minute means you are dumping the [
25 equivalent of that head overy three minutos. I'm surprised O
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27026.0 75 BRT 1 that the keep-fill pumps are that high a rating to begin 2 with. I don't recollect, but I didn't think it was that 3 high. You also get alarms when both ot those pumps are 4 running. You also got alarms when you get low lovel l, the 5 head tank. Were all these alarms ignored?
i 6 MR. CLARK: Apparently they didn' t got the 7 alarms. At least I have no indication of that until -- the 8 first indication was when they got a high level in the 9 spe n t fuel pool surge tank, and they sont an operator up to 10 check on it and he found out that they had tilled the 11 reactor cavity up. Remembe r , those little rectangular vont 12 openings into the ventilation system in tho top of the 13 reactor cavity, it was overflowing into thero.
14 The vont system does have a drain to the 15 oquipment tloor drawn outsido, but this was way too much 16 volume for that to handle and it finally wound up with 17 about 28, 30,000 gallons in the basement.
18 MR. MICHELSON: It scoms impossible to me that 19 you got 1000 gallons a minuto through the koop-fill lines i
20 of the coro spray system. You ought to check that 21 carotully as to line sizo. Also, check carotully the pump, 22 those makeup pumps to the head tank.
23 MR. CBERSOLC In the evolution of this ovont, I 24 guess the gist ot the question in, why wasn't it 25 intorcepted early on through appropriato visualization on Act! Fl!!'!!RAL Rt!PonTt!Rs, INC, 202 347 37m Nulonwide Coverage En)3MM6
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, I the instruments it they were there? It sounds like there's 2 room here to find some sloppy operation.
, 3 MR. CLARK: There's no question. In their 4 write-up on the LER, they say that it was due to the tact 5 that it was an unlicensed operator up there. When the 1
6 plant is down in a cold shutdown this long, they are not
! 7 required to man it with a licensed opera tor.
i 8 MR. EBERSOLE: There's no nuclear hazard. Ic's 9 just an example on the transient on reactor activity, it's 10 operator disciplino tha t wo a re soo ing .
11 MR. CLARK: They have a problem with operator d
12 requalitication and training. Wo have allowed them to put 13 the maximum number ot operators into requalitication 14 training programs at the prosent timo.
15 Well, thank you very much for letting me have 16 the opportunity to como down today. I dotinitely will 17 tollow up on these.
18 MR. MICilELSON: Can you explain, onco the water i
19 ontered the ventilation ducts inside of containment, which 20 I guess in the mechanism --
l 21 MR. CLARK: It did.
. 22 MR. MICilELSON: It ran down to the isolation l
l 23 valvos in thoso dumps, I guess; is that right? Whore did 24 the water go?
1 25 MR. CLARK: I'm not aware ot any isolation thore.
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! BRT O' 1 You know the design probably as good as I do.
2 MR. MICHELSON: You have primary containment l
l 3 isolation of all lines penetrating containment and that 4 ventilation line ultimately has to go to the outside.
l 5 MR. BAER: But this isn't the pool. This is l 6 outside the primary.
l 7 MR. MICHELSON: I thought this was at the top ot I 8 the reactor vessel.
9 MR. CLARK: The head was of f , up on top of the 10 cavity abovo -- up above, way above the pool level, you 11 have those rectangular oponings to draw air out, koop down 12 activity.
13 HR. MICHELSON: You wore tilling the cavity and 14 overtilled the cavity.
15 MR. CLARK: More than overtilled the cavity.
16 MR. EBERSOLE: You montioned the fact that water 17 got into a box of some sort.
18 MR. CLARK: Junction boxos.
19 MR. EBERSOLE: It wasn' t clear to me whether the 20 junction boxes should have boon environmental qualified to 21 cosist that --
22 MR. CLARK They should have boon.
23 MR. EBERSOLE: Or was thoro a logic that said 24 thoro would bo intrusion ot water to the outsido ot thoso 25 boxos and they simply didn't have the closuros?
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1 l 27026.0 78 BRT 1
1 MR. CLARK: The seals were degraded. That's why I
j 2 I say --
i 3 MR. EBERSOLE: Were the seals elastomers that
- 4 were depreciated or was it not tightened? See, years ago l 5 -- I remember Browns Ferry. I insisted that they go around 6 with a high-pressure hot water hose and f tre it at
) 7 everything in sight. I couldn' t get any cooperation, like
)
8 on many other things, to try to reveal these spurious lack 9 of closures in a comprehensive way and there was total 10 resistance to this concept of testing these systems.
11 MR. MICllELSON: This is outside of containment, 4 12 Jesse?
l l 13 MR. EBERSOLE: Nevertheless, it's subject to i
1 14 sprays.
i 15 MR. MICllCLSON: I don't know. You want to spray j 16 outside?
f j 17 MR. EBERSOLE: This is outside ot containment i 18 and what I'm trying to get at is was there a hypothesis i
! 19 that the spray would occur and therefore a resistance i
! 20 closure put there?
j 21 MR. CLARK: It is supposed to have been sealed 1
l 22 and resisted, and one of the things they are chocking, all I 23 these cabinets and things are supposed to be watertight and i
24 it's part at the environmental qualification program.
i
\
25 MR. EBERSOLE: Against a spurious water spray lO i
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x- 1 outside of containment?
2 MR. CLARK: After this happened, because this is 3 river water, the corrective action they took immediately 4 was to wash down all the cable trays. So the water that i
i 5 got in there could actually have come from washing down to
! 6 got rid ot the --
J 7 MR. EBERSOLE: That's one of the hypothetical 8 flooding events, is washing down or a fireman coming in 9 with his hoso.
i 10 MR. MICllE LSON t When the cavity was overtilled, 11 and the water ontored the ventilation ducts, whero did the 12 water go f rom thoro?
13 MR. CLARK: Some of it wont to the equipment O 14 drain outsido where it was supposed -- a small amount ot 15 water --
16 MR. MICilELSON: You said it got so high it went 17 into the ventilation duct. Then whora did it go?
18 MR. CLARK: 28- to 30,000 gallons in the 19 basoment in the corner room. If you remomber Browns 20 Forry --
21 MR. MICl!ELSON : What I'm trying to trace though 22 is what other branchos are thoro in the ventilation duct, 23 whoro o100 might it havo ontored bosidos just going into 24 the basomont area? llave you looked to soo what other areas 25 there are on the vontilation system or what other boards it
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l 1 went down? TVA, presumably, told you. All things 2 ultimately end up at the lowest point. Gravity tends to do 3 that eventually. But where did it go elsewhere in the 4 processes of overfilling. I never thought about those 5 ventilation ducts. They are also the way, it you ever drop 6 a heavy weight into that pool while you are refueling, that 7 water will also enter ventilation ducts.
8 MR. EBERSOLE: You mean like a cask?
9 MR. MICHELSON: If you drop your tuel plug into 10 the pool -- I never thought about the water entering the 11 ventilation ducts.
12 MR. EBERSOLE: I don't think anybody ever looks
! 13 at the deluge that would occur over the water line.
14 MR. MICHELSON: That's a huge overfill, sudden 15 rise in the water level, and that will, of course, overflow 16 to all these ducts, too.
17 MR. EBERSOLE: They are taken care of the 18 structural nature, wherever it hits, but not in my long 19 memory can I think ot anybody that would look at what would 20 occur in the hydraulic reservoir.
i 21 MR. MICHELSON: I have never soon it discussed 22 in the heavy issues. It's one ot the things to watch for.
23 MR. CLARK: We try to prevent it by upgrading 24 the cranes.
25 MR. EBERSOLEt It's one of those logic anakes we O
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- I never really picked up. What happens to the seiche?
f 2 MR. CLARK: Did they check if it went to other
)
3 parts of the ventilation system?
l 4 MR. CLARK: I don't know, but I'll find out.
- 5 MR. MICHELSON
- Another question. In your j 6 details, you indicated the water entered the pressure 7 switches for the dry wall.
8 MR. CLARK: Yes. It's two junction boxes.
a 9 MR. MICHELSON: Those are on a panel not far
! 10 f rom the outside shield wall of the dry wall. So, I
I 11 apparently, that area was among the areas that was sprayed i
- 12 by the water? Or at least water got into conduits that j 13 eventually reached that point?
I I 14 MR. CLARK: It could have either flowed down
- 15 through the cable tray, one possibility, or else the actual 16 spray, washing them down or initial spray, somehow it got
! 17 in through the panel and into the junction boxes.
l j 18 MR. MICHELSON: Another funny thing Browns Ferry
] 19 has and a tow of the other plants have, worries me a little l 20 bit. It used to be all open cable trays before the Browns 1
21 Ferry tire, in which if you spray the area locally the i 22 water kind of gets out of the cable tray again. It can't
! 23 run down a cable tray when there's no bottom on it, open 24 lattice cable tray. But at that point TVA cocooned up the 25 cable trays, so now the water can run all the way down the
! (:)
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O k/ 1 cocoon quite a long distance. So eventually TVA went to a 2 totally closed cable tray, so to s pe a k , with a potential 3 for conducting water inside. ,
4 MR. CLARK: I don't think that's unique --
5 MR. MICHELSON: There's a few other plants that 6 have done this because it's a worrisome thing, beca use ih 7 becomes another environmental conductor from point A to 8 point B, which is a little worrisome.
9 MR. EBERSOLE: Also, have the loading 10 considerations been taken into account when the licensees 11 make boats out of their cable trays, which are potentially 12 fillable with water?
13 MR. CLARK : Well, the seismic of overfilling and 14 then overloading on the cable trays is one of my major 15 seismic issues.
16 MR. EBERSOLE: I'm talking about a seismic 17 overload.
18 MR. MICHELSON: Pilling them up with water.
19 MR. EBERSOLE: If they truly made boats on them, 20 you may find a cable tray overloading problem.
21 By t he wa y , there were no failures of this old 22 cable, per se, as a result of getting wet, were there?
23 MR. CLARK: No.
24 MR. EBERSOLE: That's comforting. I - think they 25 are 20 years old, some of the cables.
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l MR. WYLIE: 'The water spray was not the original
~
2 design. It was added later; right? -
3 MR.' CLARK: Right. Following the ~ large '75 ' fire.
4 MR. WYLIE: I suspect they had to go back, if 5 they did have them qualified at all. Those cabinets were
'6 apparently or originally not designed for that.
7 MF. CBERSOLE: And they were probably patched up 8 with rubber seals. '
9 r1R. MICHELSON: Caps over the top.
10 MIR. CLARK: I have the question, what is the 11 type of seal? I don't know.
12 MR. EBERSOLE: TVA -used to have a design basis t
13 of not using elastomers. They had elaborately designed 14 seals, but I don't know what they did in this case.
15 MR. MICHELSON: They went back and presumably 16 sealed all the conduits, hope f ully at both ends, but I 17 ! don't know. What you;want to look at, tMough, if they have 18 cocooned the cable trays, did they seal where the vertical 19 drops into where the cabinets are? '
i 20 ,
MR. WYLIS: What did they do, spray plastic over o
21 it?
22 MR. MICHELSON: In a lot of cases they wrapped 23 it with fiberglass or something.
\
24 ,
, MR. WY' LIE: Why do that when you have sprays on L
25 [ them?
0 s
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\2 1 MR. MICHELSON: You know, ste pwise . The first 2 reaction was to cocoon it and then they realized it wasn't 3 good enough.
4 MR. EBERSOLE: The old issue of validating the 5 frequency of their sealing process, ask them when they are 6 done , how do they know they are through? And, with that, 7 we've got to move.
8 MR. CLARK: Thank you very much.
9 MR. MICHELSON: I assume this is on our list, 10 Jesse, tor full Committee?
11 MR. ESERSOLE: I didn't mention that. Is this a 12 Committee position? We should take this to the full 13 Committee? Do you think we shouldt 14 MR. MICHELSON: My vote is yes.
15 MR. EBERSOLE: Glenn? Charlie?
- 16 MR. REED: It seems to me there's some details
~
17 lacking. I don't know-if we can get those before the full 18 Committee. .
19 MR. EBERSOLE: I think I would not bother with .
20 this, Carl.
21 MR. MICHELSON: There's a prime example of where 22 we can have some sleeping dogs.
23 MR. EBERSOLE: Let's have a short one on this.
24 In the context it reveals Carl's point that you can have a 25 short-term event that will have great effects all over the O
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2 27026.0 85 BRT l O 1 plant.
2 MR. REED: Maybe we can delay it to a future 1 3 full Committee mee ting.
1 4 MR. EBERSOLE: Le t's hold it until then.
5 MR. MICHELSON: Why don't we -- for our next 6
Subcommittee meetingg gan we ask that you have TVA send you 7 a package of design details on these valves, more than even 8 this one drawing? This came out of a manual, I'm sure.
9 Can you send us more details on the design arrangement, i 10 including the flow sheets and so forth, and the indication 11 from TVA as to how extensively they have used this type of i
12 arrangement at Browns Ferry, for instance?
1 13 MR. HERNAN: You have an auxiliary systems 14 scheduled on June 26.
15 MR. MICHELSON: This would be another place 16 where we could do it.- That was to address miscellaneous 17 fire protection issues. We can do it there. Jesse will be i
18 there. I think Glenn --
19 MR. EB'ERSOLE: Why don' t we pick it up there.
20 MR. MICHELSON: Why don' t we pick it up on the 21 26th, then , and see if they can't send tus more details.
22 In fact, what I _ would like to have them do is 23 come and tell us about it, beca use it's not quite historic 24 with Watts Bar. The Watts Bar story was kind of comforting.
25 It's a little discouraging to find the philosophy didn' t O
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('- ') 1 reflect at Browns Ferry.
2 MR. EBERSOLE: I have lost 10 minutes.
3 Loss of main feedwater pump. Mr. Jones?
4 Ordinarily the loss of the main feedwater pump 5 is sort at routine, isn't it? This must be something 6 extraordinarily different.
7 MR. JONES: I believe the cause is a little 3 different. It's basically the loss of both main feedwater 9 pumps.
10 (Slide.)
11 I ' ll be talking about a reactor trip from 95 12 percent power that happened on May 12, at about 7:05 in the g-) 13 evening. That was as a result of a nylon cord being used V
14 to hold the limit switch shut on a manually controlled 15 valve.
16 MR. EBERSOLE: What was the function of that 17 limit switch, which the nylon cord prevented?
18 MR. JONES: That's a pretty good question, 19 pretty timely question.
20 (Slide.)
21 The condenser wire boxes are over here.
22 Condensate pumps over here , low pressure heaters. The main 23 feed pumps -- at Salem they are referred to as steam 24 generator feed pumps, high-pressure heaters and a 25 combination flow cleanup line that goes back to the hot.
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1 MR. EBERSOLE: Are there any booster pumps?
2 MR. JONES: Back hece. I have this up here so 3 you can see the valve of in te re s t.
4 The normal long cycle cleanup is to use the set 5 of pumps up here, from the hot well, through low-pressure
- 6 heaters, bypassing these feed pumps, bypassing the main 7 feed pumps through the high pressure. In other words, to 8 clean the system up at th'e beginning of a start-up, through 9 this valve , back to hot well.
10 Originally there were some components in this r 11 line which were not rated for full steam generator feed 12 pump discharge pressure.
13 MR. EBERSOLE: That's pretty high pressure?
., 14 MR. JONES: Yes, about 850 to 1200. Those 15 components were not rated above 600.
16 MR. MICHELSON: What code, traditionally -- what 17 code is designed in the design of the support of that 18 system?
19 MR. JONES: I don't know, other than to say 20 secondary side.
21 MR. MICHELSON: Even B31-1 requires that you 22 design pressure rating of discharging pumps. .
23 MR. ALLISON: There's a further story. The 24 valve is designed to prevent overpressurizing.
25 MR. JONES: The manually controlled valve has a
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-27026.0 88 BRT 1 contact switch on it, a limit switch, which indicates to 2 the feedwater system when the valve is closed. That's the 3 purpose of the switch. Okay?
4 MR. MICHELSON: That's a single track 5 configuration, though? That valve? There's just one of 6 them? One control?
7 MR. JONES: That's right.
8 MR. MICHELSON: Its failure , again, can lead to 9 overpressurization?
10 MR. JONES: If the valve were open , the 11 components down here could see full feed pump discharge 12 pressure if the teed pumps are running. That's true.
f- 13 MR. MICHELSON: The hot welds can never be D 14 overpressurized by this arrangement because they'd blow out 15 the ir diaphragms. -
16 MR. EBERSOLE: Are these motor-driven feed pumps?
17 MR. JONES: They 'are turbine-driven feed pumps.
18 MR. EBERSOLE: Where are the : aux feed incoming 19 lines located? Are they on downstream? Protected by flow 20 checks which don' t show here?
21 -
MR. JONES: I presume they are.
22 MR. EBERSOLE: So presumably, we are going to 23 have wa ter to the boilers no matter what happens.
24 MR. JONES: Ye s . That's not the problem. The 25 only purpose of this limit switch that I'm talking about is l
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27026.0 89 BRT 1 to prevent pressurization -- is to prevent components 2 downstream of this valve seeing full feed pump discharge 3 pressure.
4 MR. EBERSOLE: This is a challenge to the 5 nonsafety grade main feed pump system?
) 6 MR. JONES: That is true.
7 MR. EBERSOLE: Okay.
8 MR. JONES: The nylon cord was used to hold the 9 limit switch on the manually controlled valve in the closed 10 position. Closed contacts indicate to the feedwater system 11 that the valve was closed. If those contacts come open,
- 12 you cannot latch the feed pump turbines, and if it comes i
,- 13 open, it will trip the feed pumps.
14 MR. EBERSOLE: So they closed it to maintain 15 pump function?
16 MR. JONES: In order to start up about May 6, 17 they tied the contact switch shut in order to latch the 18 turbines"to perform the start-up.
I 19 MR. EBERSOLE: Normally they would have just put 20 them in there to hold it during start-up phase?
I 21 MR. JONES: The valve is actually locked shut. j 1
22 It's a manual valve that's locked shut. The contact switch j 23 has had a prcblem, a long history of making -- it's l
24 normally locked shut under administrative control. It's i 25 shut during the start-up process by administrative O
l i
1 i
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t 27026.0 90 BRT O 1 procedure, locked shut.
2 MR. EBERSOLE: They had this little switch that
- 3 kept the pump from starting if it was open?
4 MR. JONES: That's right.
5 MR. EBERSOLE: Okay.
6 MR. JONES: The significance is it's an 7 indication of a past maintenance practice.
8 MR. EBERSOLE: This is Salem, isn't it?
9 MR. JONES: I'm going to talk'about at lea st two 10 aspects of wha t this sentence or phrase means down toward 1
11 the end .
12 They were operating at 95 percent Monday the 12th, 1,3 and the line on this valve broke; indicated to the 14 feedwater system that the pumps should be tripped to 15 protect the downstream line. Bear in mind, the valve is 16 locked shut.
17 MR. MICHELSON: By "line" do you mean the spring
~
18 broke?
19 MR. JONES: It is a nylon cord. The cord broke.
, 20 MR. MICHELSON: Okay.
21 MR. JONES: They lost both feedwater pumps.
22 1 hey went out on a combination low feed- flow and high . steam-23 generator signal; they had trippedL both feed pumps' because -
24 that cord broke, and I've discussed the single valve 25 protects the line , components in the line. It monitors.the O
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27026.0 91 BRT 1 valve position and indicates that the valve is open when in 2 fact it's not. The valve was locked shut.
3 Back on 12/85 they had also found a cord on this 4 limit switch tying it shut had been removed, so in order to 5 perform the tie-up on the 6th of May, apparently, the 6 contact switch was tied shut again, tied closed.
7 MR. EBERSOLE: I thought Salem was our banner 8 plant about operational discipline, since they are the only l 9 one that's had a PWR ATWS.
10 MR. JONES: I'm going to be addressing a couple 11 of aspects of that as I get toward the end.
12 MR. EBERSOLE: Okay.
13 MR. JONES: There had been , since 1980 -- since 14 1979 and '80, a long-standing change request to de fea t the 15 interlock to trip the pumps and cause the turbines not to 16 be able to be latched, and to remove the limit switches.
17 MR. EBERSOLE: How are they going to protect the 18 low-pressure system against inadvertent blowout?
19 MR. JONES: Okay. The details are in fact the 20 components are not in the line anymore.
21 MR. EBERSOLE: Okay. But can you blow out the 22 relief disk on the hot well?
23 MR. JONES: No. It's my understanding that 24 that's not the problem. The problem is that there were 25 some strainers in this line, subsequently removed.
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%) 1 MR. EBERSOLE: I see.
2 MR. JONES: The design request was to defeat the 3 interlock and remove the limit switches. I say switches, I 4 mean Unit 1 Salem, Unit 2 Salem.
5 It had become a low-priority work i te m . However, 6 a f ter the trip on the 12th and prior to restart, the 7 interlock was disabled by lif ting the leads. That was done 8 via a planned procedure for administratively controlling 9 leads. Then a removal of leads was accomplished for Unit 2.
10 MR. EBERSOLE: What bothers me he re is you say 11 " lifting of leads." Tha t ha s a transient connotation that 12 I lift them, but I'm going to put them back some day. I'd gS 13 rather you tell me you had cut them off, and there was a 14 record of that.
15 MR. JONES: My understanding is that the leads 4 16 were removed and they were removed via an existing plant 17 procedure which maintains the control of such things. ..
18 MR. EBERSOLE: So they are not merely lif ted, 19 they are permanently disconnected, is that right?
20 MR. JONES: Permanently disconnected in the fact 21 that they have been disconnected and that has been recorded l 22 in the proper place.
l 23 MR. EBERSOLE: Is the switch still left?
24 MR. JONES: The switch is still there, is my I
25 understanding.
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27026.0 93 BRT O 1 MR. EBERSOLE: Why don't they knock it off to 2 prevent future confusion?
3 MR. JONES: That was part of the original design 4 request and I'm assuming that's something down the road.
5 MR. EBERSOLE: I see. Fine. I got the picture .
6 Any questions? Okay. No questions.
- 7 I don't think we'll take this to the full 8 Comm i ttee . Thank you very much.
9 MR. JONES: I'll just go through the 10 follow-through. I think this will be relatively quick.
11 The two aspects of this are, one, there was an 12 existing problem which the operators continually had to i -
13 face: how to latch these feed pump turbines to do the 14 start-up. They were aware that an existing plant design 15 had been around for a long time. So two things have ta ken 16 place: The process by which this was accomplished, using 17 the cord, has been well publicized throughout the plant.
18 Everybody is aware of it and , understands that that practice 19 is not to be used because it violates procedure. The 20 second thing is there 's a more ef fective means -- a new 21 group has been created to accomplish in a more rapid and 22 effective manner, a more timely manner so the operators 23 won't continually be irr i ta ted , for making a minor design 24 change -- this is referred to as a minor design change.
25 MR. EBERSOLE: Okay. So they are going to get O
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l rid of this informality, running around with cords tying 2 things?
3 MR. JONES: Yes. That's to be accomplished 4 through operator training, publicizing this event to all 5 operators, and the irritation factors to be removed by 6 accomplishing the design changes in a more timely manner.
7 MR. REED: Is this a totally in-house 8 modification or did it have to go outside for verification, 9 validation, or was there some regulatory roadblock to 10 accomplishing this modification in a reasonable fashion?
11 MR. JONES: There was no regulatory roedblock.
12 My belief -- I'm not 100 percent certain -- my belief is 13 this was an internal public gas and electric corporation --
14 MR. REED: Their internal modification 15 procedures and timeliness getting them done was not up to 16 snuff? Is that what you are saying?
17 MR. EBERSOLE: This is balance of plant. It's 18 not a regulatory matter, since it's not become a formalized 19 process.
20 MR. REED: I never know what's a regulatory 21 matter anymore.
22 MR. JONES: My understanding is this is not.
23 MR. EBERSOLE: I expect there will be more and 24 more attention to challenges to aux feedwater systems as 25 time goes on. This is a representation of part of that.
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27026.0 95 BRT 1 MR. REED: I don't think this challenges aux 2 feed, necessarily.
3 MR. EBERSOLE: Sure it does. If you lose main 4 feed, you have to have aux feed.
5 MR. REED: It's a challenging event whenever 6 anything goes wrong because it might call into service, 7 safety systems.
1
) 8 MR. EBERSOLE: Right.
9 MR. REED: That's the way we learn.
10 MR. EBERSOLE: It's nice to learn when you don't 11 really need them.
I 12 Any further questions?
i 13 Okay. We picked up five minutes. Not bad.
14 Repeated snubber failures at Trojan. Mr. Chan?
15 Mr. Chan, as usual we gave you 20 minutes. If you can make
{
16 it 15, that will be great.
17 MR. CHAN: I would like to make it about five.
18 MR. EBERSOLE: Feel free.
19 ( Sl ide . )
20 MR. EBERSOLE: This is the most dangerous form 21 of failure. They locked up.
22 MR. CHAN: What I'm going to talk about today is, 23 I guess, a condition at. Trojan, that is, the failure of 24 snubbers, in particular the -- we are talking about the 25 lockup of steam generator snubbers which resulted in the
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27026.0 96 BRT O' 1 overstress of a portion of the RCS hot leg piping.
2 During the 1985 retueling outage, Trojan 3 inspected all 16 of their steam generator snubbers, two of 4 which f a iled the surveillance te s t , and thus all 16 were 5 declared inoperable.
6 MR. EBERSOLE: Will you give us a review? First 7 of all, what's the nature of the design of the snubbers as 8 , to whether they are dry or hydraulics?
9 MR. CHAN: Hydraulic snubbers manufactured by 10 Anchor Hall. They are 900 KIPS snubbers.
11 This was the first time Trojan was required to 12 inspec t their snubbers for the life of the plant , since 13 1975. They were j ust issued a tech spec, early 1985, to 14 inspect them.
15 MR. EBERSOLE: So whatever has happened has been 16 goir.g on somewhere be tween 1975 and now.
17 MR. CHAN: That is what was assumed.-
18 MR, EBERDOLE: ' That's going to include, I gue ss, 19 a fatigue investigation on certain piping?
20 MR. CHAN: Yes, it has.
21 MR. EBERSOLE: Go a he ad .
22 MR. CHAN: During this 1985 refueling outage it 23 was also discovered that a lateral member of a vertical hot 24 leg pipe whip restraint had been pulled out about 5/8 of an 25- inch f rom the wall. Now, all of the snubbers were rebuilt,
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1 27026.0 97 BRT 1 retested, met the acceptance criteria , were re-installed !
! 2 and the plant was then started up.
F 3 MR. EBERSOLE: Question. By what valid right 4 did they start up the plant without first doing a fatigue l 5 analysis of when the snubber failed and how many cycles it
)
6 had gone through?
7 MR. CHAN: Because at that time they had not --
i 8 they did not have information that they thought would i 9 indica te that the piping was overstressed.
+
10 MR. EBERSOLE: Did they look hard? I belong, 11 you know, to the field of thought that if it looks bad I ,
12 won't look at it too much. Did they really --
- 13 MR. CHAN: I think that can be addressed in a l 14 couple of steps as I go down.
l 15 MR. EBERSOLE: Okay. Go ahead.
1 16 MR. CHAN: The snubbers were rebuilt, re te s te'd ,-
17 the plant came back up to oper.ation. And during the time l
18 period between 1985 and their 1986 outage, Trojan had been 1
19 working on what seemed to be two independent occurrences at 20 the plant. One is how the horizontal member of the pipe 21 whip restraint was pulled out, .the reason for thati and, 22 also, unexplained pressurizer surge line movement.
23 Now, in 1985, when Trojan asked their 4
24 consultants to postulate the lockup of the steam generator l
l- 25 snubbers from a cold condition to a hot condition, it was
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27026.0 98 BRT 1 found that that lockup, during the thermal growth, during 2 heat up, would account for both the pressurizer surge line 3 movement and/or the damage to the pipe whip restraint.
4 MR. EBERSOLE: That occurred at what point in 5 time and for how many years past the hypothe tical lockup?
6 MR. CHAN: In 1985 there was no damage found on 7 the pipe whip restraint.
8 MR. EBERSOLE: Do they periodically reexamine 9 the linearity of the pipe and the positions, hot and cold, 10 to determine whe ther the snubbers are locked up?
11 M R. CHAN: No, they had not in the past.
12 MR. EBERSOLE: How do you ever know when a 13 snubber is locked up, then?
14 MR. CHAN: I can't answer that.
15 MR. EBERSOLE: Seems like we don' t know when a 16 snubber is locked up until something happens.
17 MR. CHAN: I think --
18 MR. HERNAN: Jesse, most of the tech cpecs have 19 requirements for periodic surve illance .
20 MR. EBERSOLE: Is that in the field or cycles of 21 thermal distortion and overloading that's acceptable in a 22 peak context?
23 MR. HERNAN: Usually in a fixed-number context.
24 MR. ALLISON: It's a requirement to test the 25 snubber.
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'- 1 MR. EBERSOLE: But is that consistent with the 2 motion --
3 FROM THE FLOOR: If one postulates the snubbers 4 are going to fail, then you are right. On the other hand, j 5 you have to expect the requirement for testing snubbers and 6 you don't expect the snubbers are in failure.
7 MR. EBERSOLE: How many cycles of movement of 8 snubbers do you hypothesize before failure? Heat up and 9 cool down? What I'm trying to find out is the basis.
10 FROM THE FLOOR: You have 28 cycles; is that 11 right? Te c h s pe c --
12 MR. EBERSOLE: They really don't have a basis 13 based on the procedures, on fatigue loading?
14 FROM THE FLOOR: Operational records, they have 15 determined how many cycles it has gone through. Dave?
16 MR. ALLISON: You are talking about two things.
17 The tech spec is simply pull the snubber out and te st it.
18 If it doesn't work, fix it.
I 19 MR. EBERSOLE: There's no estimate to get the ;
20 potential stress cycles. I'm talking about the point where 21 there was complete failure --
22 MR. ALLISON: On the snubbers --
23 MR. EBERSOLE: There's no intertie between a e 24 potential cyclic damage and the figures you expect in the '
25 hydraulics snubbers in the locked up mode? It's not
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('T s/ 1 important if they fail in the other mode because we are 2 waiting for an earthquake for the e f fect?
3 MR. ALLISON: That's what they are there to 4 handle.
5 MR. EBERSOLE: I think it's far more important 6 they don' t fail in the locked-up mode.
7 Le t ' s no te there is no placing of the locked-up 8 snubbers in terms of finding the potential cycles before 9 te s ting it. I'm sure we are going to take this to the full i
10 Commi t tee .
11 MR. MICHELSON: For clarification, you talk j
12 about movement of the pressurizer surge line. Can you tell gg 13 me what you mean by " movement"? Is this permanent
%.)
14 displacement?
15 MR. CHAN: This was periodic displacement. This I
16 was periodic displacement that was observed during the 17 hea t-up process. Back in 1982 the utility had performed 18 some modifications to the thermal sleeve for the ;
1
! 19 pressurizer surge line. According to analyses done at that '
! 20 time, certain types of movement was expected. However, the l 21 system, the piping did not settle out as it was expected, 4
22 and so they continued to monitor the movement up through
- 23 1985.
24 MR. MICHELSON: Is this a permanent displacement?
25 Memory distortion of the surge line? Or is this just --
O i
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27026.0 101 BRT O' 1 it's growing more than you anticipated, but returned to 2 zero position?
3 MR. CHAN: It returns back to another condition.
4 MR. MICHELSON: It does return to a zero 5 position when it's cold again? Or not totally? There's 6 some permanent growth of some sort or permanent distortion?
7 MR. BAGCHI: There 's a creep phenomenon , that 8 sort of thing.
9 MR. EBERSOLE: How much did it eat into the 10 f a tigue life?
11 MR. BAGCHI: My name is Goutam Bagchi, with the 12 engineering branch. You said in this particular instance, t
13 for this plant, they have monitoring instrumen ta tion . They 14 are going to look at it f rom the cold condition up to the 15 hot, nonnuclear heating , looking at-the movement and 16 comparing that against prediction. Then when it's on the 17 line they are going to monitor the movement, plot it, and 18 if there is any unexpected movsment,' that will be reflected.
19 MR. EBERSOLE: You say,at this plant? .
4 20 MR. BAGCHI: Well, monitoring this kind of 21 condition, there has been -- the best answer as far as I 22 know, for this particular plant, they have also made other 23 improvements like changing the - snubber -- fluid reservoir 24 valving system.
25 MR. EBERSOLE: In an engineering context, is it O)
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1 true there's a dimension to protect the snubbers for 2 lockup conditions? There's no real knowledge of-how many 3 operating cycles you went through --
4 MR. BAGCHI: Yes, there is. You can look at the 5 log.
6 MR. EBERSOLE: You can look at it af ter the fact 7 but are th' re any hypothesized numbers?
8 MR. BAGCHI: No. The Section 11 requirement 9 --
that can be done for some reasons, for instance, by 10 radiation area --
11 MR. EBERSOLE: Couldn't you argue it's necessary 12 to hypothesize a number of cyclic functions to validate?
13 In any case, I'm sure we'll discuss this at the 14 f ull Committee mee ting.
15 MR. BAGCHI: I'm wondering it it shouldn't be 16 considered as a generic question rather than this plant.
17 MR. EBERSOLE: I agree with you. That's the 18 plant..
19 MR. HERNAN: Jesse, from a' practical standpoint, 20 the plant has to be in a shutdown condition to do most of 21 these snubber inspe c tions . The 18 months -- or refueling -- ,
l 22 is based somewnat on a realistic standpoint of the schedule 23 of the plant. In other words, we have not suf ficient data 24 to cause the plant to go into a nonscheduled shutdown for 25 the purpose of inspecting snubbers.
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1 MR. EBERSOLE: My thought is very simple. I 2 would hypothesize some sort of statistical distribution of 3 failures of snubbers and examine the plant for the 4 compe tence to withstand that cycle, whatever hypothetical 5 number of tra n s ie n ts .
t 6 MR. HERNAN: Generally a plant would only 1
- 7 experience the cycle during a refueling.
8 FROM THE FLOOR: That would be a very severe 9 transient-driven philosophy. If you use that kind of 10 philosophy, you would almost have to say completely locked 11 up and overstressing it would be unacceptable in main 12 conditions.
13 MR. EBERSOLE: I think we need to discuss it on 14 a broader basis than here .
15 By the way, I don't know why you think the plant 16 will run continuously for 18 months. I have yet to hear of 17 anyone that does. ,
18 MR. REED: I think it's more likely the average 19 number of thermal cycles might be on the order of three per 20 core life , for some plants 'go through the whole core life --
21 MR. EBERSOLE: Is that cycles of heat-up and 22 cooldown per core life?
23 MR. REED: Ye s . Per core life. Many plants run l 24 the whole cycle without a cool down. PWR -- I don't know 25 about your BWRs, Gary, but two or three.
i
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1 ACE-FEDERAL REPORTERS, INC.
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l 27026.0 104 BRT O 1 MR. EBERSOLE: Anyway, whatever the number is, 2 it's the basis of consideration when you look at the lockup 3 conditions, whatever it is.
- 4 Let's carry on.
4 5 MR. CHAN: Getting back to the discussion, where i 6 the analysis accounted for the pressurizer surge line
, 7 movement and the damage to the pipe whip restraint, when 1 8 this evaluation was carried out to evaluate stress on the I
9 reactor coolant hot leg piping and specifically near the 10 elbow that's indicated by the arrow on-this diagram --
11 MR. EBERSOLE: Is there any root logic that says 12 when I put in a snubber or restraint or hanger or whatever 13 and I get a condition like this, I must always say that the f-) ,
! (/ h i 14 pipe is going to be so strong that it will destroy the
'i n 15 ll thing that's getting in its way? Do you follow me?
16 MR. CHAN: In this case --
17 MR. EBERSOLE: The preservation of the pipe is f
18 what I'm after.
l 19 h MR. CHAN: It did fail.
8 ?
20 i MR. EBEESOLE: Is it a mandatory design l
, 21 philosophy when I put in romething like this, that says i 22 q when I'm looking at one restraint I'll pull it up by the i 23 roots without any real serious damage to the plant?
i ~
24 MR. TERAO: This is David Terao from engineering i
i 25 branch. No, this is no weak pipe built into the system.
1
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27026.0 105 '
BRT 1 MR. MICHELSON: There's a GDC that says that no 2 single failure of equipment shall cause a loss of coolant.
3 The snubber locks up is the single failure, and it breaks 4 the pipe. A LOCA has been caused by a single component 5 failure. I don't think we are supposed to get LOCAs off of l 6 single failures, other than the pressure boundary failure 1
7 itself.
8 MR. EBERSOLE: That's true of the hanger --
9 MR. MICHELSON: When one locks up, you tell me 10 it breaks the pipe. I 11 MR. HERNAN: Jesse, I think you'll hear an 12 example of what you are asking when we get down to talk i !.
t 13 ! about one of the other items here, Palo Verde.
3 14 MR. EBERSOLE: I'm sure we'll have an i
15 enlargement of this discussion at . full Committee by some 16 l structural experts. Carry on.
i 4 I
[ 17 MR. CHAN: In conclusion, then, the elbow did
]
18 exceed the ASME stress allowables. A plastic analysis was
- 19 permanent formed, but those results -- it was found that 20 I they were within the 1 percent strain limits.
21 MR. MICHELSON: Which elbow?
22 MR. CHAN: This. This elbow right here.
i 23 MR. EBERSOLE: 1 percent strain for how many 24 cycles?
25 MR. CHAN: I don't believe it addresses cycles.
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1 MR. TERAO: This is David Terao. The utility ,
2 postulated 30 cycles at 1 percent strain.
3 MR. EBERSOLE: Okay. So they had some margins ,
j 4 didn't they? Or did they? ;
, 5 MR. CHAN: They evaluated the 28 cycles, which
} 6 was from 1975 to date.
i 7 MR. EBERSOLE: They figured they could take how l
l 8 many? ;
d 9 MR. CHAN: I don' t think they extrapolated out 10 as to how many they could take.
I
- 11 MR. EBERSOLE
- Didn't I hear a 30 number?
! 12 MR. REED: Divide-it by 10 and got 3, Jesse.
i 13 MR. TERAO: Well, there's several margins.
[ l 14 There's two margins that we are asking them to address.
15 One is margin to the 1 percent strain acceptance criteria j 16 { '
for the one event, and the other is the margin for the i
17 ! total usage fatigue factor for the life of the plant.
18 ; MR. EBERSOLE: Where do they stand on the latter
~
f i f 19 one?
\
- l 20- MR. TERAO: It turns out the hot leg elbow is
! 21 no't the highest fatigue point in the system. It turns out l 22 the vessel was. So it's below the 1.0 Code fatigue I
! 23 allowable. I don't know exactly what the margin is at this i
24 point. We are still waiting for the t'inal results.
l 25 MR. EBERSOLE: Okay. Thank you.
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27026.0 107 BRT bi V 1 MR. CHAN: Because Trojan plans to come out of 2 its refueling this Friday and they plan to start up nuclear 3l heating around Saturday, they have undergone an extensive l
4l program to -- utilizing ultrasonic testing, rad iog ra phic l
5 testing, and monitoring program, to ensure that the piping 6 integrity is, in fact, sound; and that the postulation of 7! the failed snubbers, which caused their problem, has in l
8 fact been remedied through the -- through the change of the 9 control valve assembly on the snubbers.
10 3 MR. EBERSOLE: All these nondestructive testing l
11 f techniques do not reveal the state of fatigue?
1 i
12 l MR. CHAN: That is correct. But it does --
y 13 ) would indicate --
O 14 3 f1R. EBERSOLE: If you've already damaged it in a i
15 l visual context.
I 16 :! !!R. CHAN: That's correct.
18 less out of the picture for PWRs, and since this is a
' i 19 ;l snubber issue, which restraints and snubbers can be taken a
1 20 g? off, decouple for large break reasons,? Are these snubbers 21 large break snubbers or seismic or what?
22 MR. CHAN: These are not large break snubbers.
23 MR. REED: They are seismic snubbers.
24 MR. CHAN: They are seismic snubbers. They are 25 lateral. The snubbers in question attach in the upper O !
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l portion of the steam generator.
- 3 and for seismic, i 4 MR. CHAN
- I stand corrected.
5 MR. REED: Is there any activity on the i
6 licensee's part to ask for relief from having to use them?
i 7 MR. TERAO: Yes. They are pursuing it. At this
- 8 time they are not part of the Westinghouse owners' group
- 9 but they are performing analysis necessary to submit for an j 10 exemption from GEC-4 under the limited scope rule. '
11 MR. EBERSOLE: Is the Staff always as i
12 enthusiastic about risk cost -- benefit evaluations, where i
13 i you balance out the work versus the price you pay? I think i O i it would be interesting to find out whether the snubbers j\ 14 3 -
t;
]
15 A aren't a decrease in safety rather than an increase, just 1 i j 16 their physical presence. I rather think they are a net l- 17 decrease in safety and they cost money to boot, and they 7 18 are a maintenance problem.'-
4 i
j 19 l Let's be sure we have this at the full Committee, 20 is that agreed, as a more or less generic matter and let's i l 21 go on to the Texas topic. I'm only five minutes behind.
f 22 MR. HERNAN: Jesse, I might point out on this, 23 on the handout there are some diagrams, hydraulic diagrams 24 of the snubbers. I'm not sure if you are interested in the 25 mechanics --
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[m
'- 1 MR. EBERSOLE: I begin to think snub --
2 FROM THE FLOOR: There was a walkdown on the 3 reactor coolant loop, and Staff went out with the utility 4 experts and consultants and we are pretty satisfied that 5 the examination was reasonably thorough.
6 MR. EBERSOLE: How do you feel about it in a 7 generic context?
8 FROM THE FLOOR: In a generic context, I don' t 9 think one can get away by postulating a complete lockup of fl 10 l the snubber.
I 11 j MR. EBERSOLE: Well, I mean statistical lockup k
0 12 ila of some sort.
13 0] MR. BAGCHI: Actual lockup one could consider in
(.
(^)3 j 14 9 a design consideration.
)
15 MR. MICHELSON: A small question on snubbers'
]
o 16 principles. If you lose the oil from the snubbers, do they 2
17 f lock up? That's the question. Do they lock up if you lose i
18 l the oil?
19 MR. TERAO: Terao. No, they do not lock up.
20 I MR. MICHELSON: In that circumstance they would 21 l just become compl'etely loose and they only lock up when the 22 orificing arrangement gets clogged somehow; is that it?
23 MR. TERAO: Or if the control valve is too l
24 sensitive, it locks up. l 25 MR. EBERSOLE: In the course of thermal growth, l l
l ACE-FEDERAL REPORTERS, INC. {
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\
l then friction would lock up the system? Then it locks up 2 and stays locked up? Do you mean that vulnerability is i
3 still in it? This is an ancient, ancient form. They 4 better not recognize the sudden release of stasis
! 5 pressure --
6 MR. BAGCHI: They have not replaced that control
]
7 valve totally.
8 MR. EBERSOLE: Well, we'll take up that, too.
I 9 MR. WAMBACH: I'm Tom Hambach, the project 10 manager for the Palisades plant. I'm here to discuss the
..l 11 reactor trip of May 19, 1986. I would like to point out to 12 the Committee that there are some representatives from the I 13 L utility here if the Committee wants to ask them any a
il 14 g questions.
ii 4
15 l The problem was multiple failures following the
! :i 16 reactor trip.
) The turbine bypass valve failed to open, one ,
j 17 l steam dump valve failed to open, backpressure regulator int d
i 18 lI the letdown line failed to close, pressurizer' spray valve
, 19 failed to fully close and the variable speed charging pdmp j 20 ! tripped five times.
21 (Slide.)
1 4 22 The significance of the event and our concern i
23 about it was the-unnecessary challenges to safety equipment 24 -- the reactor tripped on high pressurizer pressure; the 25 increased burden on operators to compensate for failed or
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s.
I
( 1- deficient equipment; and the implications concerning the
_ 2 quality of maintenance and post-maintenance testing.
i 3 MR. EBERSOLE: Do you see in this a basic 4 maintenance deficiency o'r design deficiency or composite of
- 5 both or what do you'see?
6 MR. WAMBACH': The main thing I think we have.
7l discovered is what we feel is a deficiency in the i8 maintenance performance at the plant. There has been some
,9
>l
- history on this. 'They did get a 3 rating on maintenance.
l 10 . ) There have been'some inspection teams to the site, 11 concentrating on maintenance. Prior-to the last refueling 1 12 outage a confirmatory, action letter was issued, requiring
- 13 them to decrease t' heir backlog of' maintenance and clear up j
6 14 g l) the number of tag's they had on equipment in the control 15 k t, room.
H 16 MR. EBERSOLE: So you see this in the
! 17 I reevaluatrion of a preexisting condition? As you - -you 18 ; might have anticipated this sort of thing?
) 19 . MR.-WAMBACH: Yes, because most of the equipment 20 involved here had a history of malfunctioning.
21 MR. FBERSOLE: Sounds like-Davis-Besse:
- 22 MR. WAMBACH
- The sequence is as follows.
23 Maintenance was being performed on the turbine cabinet l 3
3 24 control fans, the fans are located'on the front and back of 1 . n
- 25 the panel on the turbine deck; instrument tech was out ;
i <
i i '
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- ' 1 there in order to do the preventative maintenance on the 2 fans. He has to unplug the fan so it will stop running and 3 he can clean the dirt off the filter, replace the filter, 4 clean the blades and so on.
5l Sometime after he started into tnis maintenance, 6g at 1415 and 14 seconds, the turbine valves closed.
7 The reactor tripped about a minute later on high 8
f pressurizer pressure. The turbine then got a trip from the 9 reactor trip.
10 l MR. EBERSOLE: Let me ask you this, did the a
11 U operator, if they stopped the fans already -- previously I
12 3 had he recognized the resulting high temperatures or 13 whatever occurred invited a turbine trip?
~)
s- g 14 j MR. HAMBACH: It wasn't the high temperatures.
15 i What happened is these fans -- the power plug to these fans 16 j is plugged into the same power supply as the 120 volt AC i
17 j that provides the power for both the primary and secondary 5
18 [ power supplies for the electrohydraulic control system for 19 the turbine valves.
L 20 r MR. EBERSOLE: So we have, then -- what kind of I
21 load? It's a load on a critical system? A fan load on a 22 critical system?
23 MR. WAMBACH: Right. They found in 24 troubleshooting after the event, they found that when they 25 unplug the front fan that it would cause an overvoltage !
/^%
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- 1 trip on the power supply for the electrohydraulic 2 controllers.
3 MR. EBERSOLE: That's a typical common generic
- 4 thing you come into when you put deep loads on critical 5 systems. Is that going to be corrected in design concept?
l 6 MR. WAMBACH: They are correcting that as part 7 of the inmediate corrective action.
l 5
8 MR. EBERSOLE: I wonder whatever loads they have 9 plugged into DC systems and so forth that have the same 10 potential?
11 MR. WAMBACH: As a result of this event, you'll 12 , find when we get to the follow-up, I have a dask force that I
,q 13 l is investigating this type of thing generally. The scope kJ 14 of that is going to be explained to us on Friday at a 4
i 15 ; meeting at the Region.
3 16 MR. EBERSOLE: Thank you. I have already
!]
17 decided, at least for me, this will go to the full I
18 Committee, so go ahead.
19 l MR. HAMBACH: The fan on the back of the cabinet, l 20 they found when they unplugged it, it would result not only 21 in a trip of the primary power supply but also the backup 22 power supply, which is a permanent magnet generator driven 23 by the turbine. This is because the plug was routed in the 24 same cable bundle with the 420 hertz power supply going to l
25 the EHC.
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1 MR. WYLIE: Are these DC fans?
2 MR. WAMBACH: No. 120 volts AC.
3 MR. MICHELSON: What else did that back up? Did 4 the backup also trip -- what other loads are on that level i i 5 of board?
6 MR. WAMBACH: Well, the only thing we 7 investigated on that particular -- you mean on the 120 volt 8 AC?
9 MR. MICHELSON: You said they picked up not only 10 that but the backup trip.
11 MR. WAMBACH: The backup power supply powers the 12 EHC.
A \
14 i MR. WAMBACH: Yes.
k 15 j I got as far as the turbine trip, I guess. Then I!
16 the dump valves opened. Three of the four dump valves 17 opened.
P 18 MR. MICHELSON: Is that an effect of losing the l
19 voltage to the EHC?
20 MR. WAMBACH: No. That's independent of the 21 dump valves.
1 22 MR. MICHELSON: You'll tell us in a minute why, 23 then?
24 MR. WAMBACH: I don't know as I can. They are 25 still troubleshooting that on the fourth dump valve. It C)
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O 27026.0 115 BRT 1 had been having a history of some problems with control.
j 2 The charging pump, P55-A, the variable speed i
3 charging pump had been placed out of service because of a 4 cracked head, but in this event, when the pressurizer water 5 level started dropping down fairly low, they decided to go 6 ahead and start it anyway. They considered that it could 7 perform its function. They started it and 30 seconds later, 8 it tripped, and then this was repeated five times but by 9 the time the fifth time had occurred, the water level in 10 the pressurizer had turned around and was recovering back I
11 to normal.
]
I 12 MR. EBERSOLE: I'm trying to figure out why had
, g 13 it fallen? Did it fall on some unprogrammed basis?
4
) 14 MR. WAMBACH: No. In response to the trip.
3 15 MR. EBERSOLE: Okay.
4ll 5
16 MR. WAMBACH: The parameters, you'll see when I ,
17 get to the next slide, the parameters for the reactor trip j 18 were pretty much normal.
19 MR. EBERSOLE: Are you telling me they were not-20 ready to hold pressurizer level no matter what had happened i
4 21 because they had a cracked pump?
22 MR. WAMBACH: They did have the other two 23 charging pumps in service.
24 MR. EBERSOLE: But they couldn't hold the level?
. 25 MR. WAMBACH: Not in a rapid ^cooldown from a 1
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27026.0 116' BRT O 1 reactor trip.
2 MR. EBERSOLE: So they are always under the 3 begun for maintaining level unless they've got all three 4 pumps?
5 MR. WAMBACH: Hell, again, this pump didn' t help 6 all that much and they did return.
~
7 MR. REED: You have shrinkage.
8 MR. EBERSOLE: I'm just asking do I need every 9 pump I've got to keep up with the fast shrink?
10 MR. WAMBACH: I wouldn't think so.
11 MR. REED: You wouldn't think so if they are 12 allowed to have one out of service.
13 MR. EBERSOLE: Right. But they had to invoke 14 the third one?
15 N MR. WAMBACH: It was there and they used it because it was available.
16 l 17 MR. EBERSOLE: Does it mean that the.first two 18 pumps -- it could have been broken, period, couldn't it?
19 Then what would have happened?
20 MR. WAMBACH: Well, again, this pump, only 30 21 seconds times 5 -- 150 seconds of operation is all they got 22 out of it.
23 MR. EBERSOLE: So in essence, it doesn't work
~
24 anyway, much. So they are prepared for a two-pump shutdown?
l 25 MR. HAMBACH: Right. I O l
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\~# 1 MR. EBERSOLE: Okay. Now I've got a disabled 2 pump. It's gone. What does the tech spec say?
3 MR. WAMBACH: The tech spec requires them to 4 have two operable charging pumps.
5 MR. EBERSOLE: If, then, if I experience a 6 transient like this one or any nuaber of others and I start 7 to shrink, and one of the charging pumps doesn't respond to j
8 the charging pump, where am I with the one that's left?
9 What's going to happen to me then?
10 MR. WAMBACH: I presume the water pressure in a
11 n the pressurizer would drop lower than what it did on this 1
12 l event.
rs <
13 MR. EBERSOLE: How low? And would that be a t
\_)
v j
14 3 problem?
4 15 ] MR. WAMBACH: In this event I think it dropped 4
16 II to about 20 percent indication, which, as I recall --
h 17 ) MR. EBERSOLE: Would it go blind?
li 18 MR. WAMBACH: It would probably go off the level 19 l indicator.
20 th MR. EBERSOLE: Then where's my recognition of l
21 residual inventory?
22 f MR. WAMBACH: Just in the amount of volume --
23 i see this level indicator does not cover the entire height 24 of the pressurizer.
25 MR. EBERSOLE: I want to know when I go blind, O
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j C:) 1 and if I do so as a result of our common transient with I 7
2 only one makeup. I want to'know when I go blind, is all.
3 MR. WAMBACH: Let me ask the licensee if there's 4 any other indication on the pressurizer, other than this 5 channel that we are looking at on the data logger?
, 6 MR. BERRY: There's a total of about seven or 7 eight indicators.
8 MR. WAMBACH: All the same span?
9 MR. EBERSOLE: So when do I go blind?
10 MR. BERRY: You can recover with only one -- you 11 i won't go out of pressure.
j I 12 MR. EBERSOLE: Do you maintain a visible index 1
13 of where the level is in the pressurizer, too? Or do you 14 go blind?
15 MR. BERRY: You stay within the range of the
- 16 pressurizer.
17 MR. EBERSOLE:
i f The visual level with one pump?
t i 19 l; MR. MICHELSON: Does your answer include the i-20 fact that some of the atmospheric dump valves are open?
21 MR. EBERSOLE: What if you compound this by i
22 additional shrinkage due to overcooling?
I 23 MR. MICHELSON: Which was this case? Apparently 24 two atmospheric dump valves --
25 MR. WAMBACH: Three.
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27026.0 119 BRT O 1 MR. BERRY: Three functioned correctly. One 2 failed to open. It did not overcool.
3 MR. EBERSOLE: Right. The others functioned. l 4 MR. MICHELSON: What does it mean, second 5 atmospheric dump valve opened, three atmospheric dump valve 6 opened, first one opened --
7 MR. WAMBACH: There's 4.3 opened.
8 MR. MICHELSON: That was part of the transient 9 of course, for them to open. That causes a further rapid 10 cooling and that is the transient that you say one charging 11 pump will handle?
12 MR. BERRY: I'm Ken Berry with Consumers Power 13 i /PHUBL.
i 14 j The plant responded pretty much normally, as far I 15 l as the shrink and swell.
16 MR. EBERSOLE: Because you always saw where the 17 level was?
18 MR. MICHELSON: Do you normally open atmospheric 19 d ump , though, in a trip?
20 MR. BERRY: No. Normally don' t.
21 MR. MICHELSON: You don't normally open them.
22 Yet in this transient they did open? And for this 23 particular transient where they did open, you are saying 24 one charging pump will still handle the transient without 25 emptying into the surge line?
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'- 1 MR. BERRY: Right.
2 MR. MICHELSON: Thank you.
3 MR. EBERSOLE: All I'm asking, when did the 4 operator go blind and doesn' t know where the inventory is?
5 What kind of plant is this, Westinghouse?
I 6 MR. WAMBACH: Combustion.
7 MR. EBERSOLE: For many years the argument was I 8 don't need a level indicator in the pressurizer -- I mean, I
9 in the main vessel; on the other hand, the grounds, you'd 10 never see any level or any indication. But what I'm 11 hearing is apparently there are circumstances in which, if 12 you've got a full shrink and loss of makeup pump, you will s 13 id go blind.
-] 14 L MR. BERRY: I don't believe that's true.
15 MR. EBERSOLE: Okay. Let's go ahead.
16 MR. WAMBACH: As I said, the pressure low level 9
17 was turned around at 26 percent and returned to the normal a
18 E low level for the shutdown condition.
I!
19 ) It is noted here that the last letdown isolated il 20 f on low pressurizer level. This will come up, then , when 21 the isolation valves for letdown had isolated, then the 22 ,
backpressure regulator, which is downstream of that, trying 23 f to control a fixed pressure with no steam input, would 24 probably have closed. Then, later in the event when the 25 level gets back to normal, the letdown isolation valve re (v~
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! 27026.0 121 BRT i
- 1 opens and the backpressure regulator does not respond and i 2 the relief valve lifts.
i t
3 At 1422:15 is when the pressurizer level 4 returned to normal, and the event, as far as the challenge l 5 or response to the reactor system, was completed.
6 (Slide.) ,
i
, 7 Reactor tripped at 2245 psia, then, during the j 8 cooldown, 689 psia. You can see the hot temperature rose; 9 I think at the time of the event it was about 588 degrees, 10 minimum 535 is where it stabilized; that's where they i
j 11 controlled opening with the atmospheric dumps. And T cold 12 rose 537 -- I think thai was about 20 degrees above what I 13 i that was at, steady state. Steam generator pressure peaked i
14 la at 1025 psia; that was the opening point of the safety 15 ) 1 valves. Steam generator level dropped from 70 to 12 1
- 16 percent and then recovered back to its set. point. '
3 17 MR. REED: I assume that 70 to 12 is on the i
18 narrow range, it's not the real level, just a narrow range l l 19 band?
t 20 MR. EBERSOLE: Percent of what, normal level?
I !
i 21 MR. WAMBACH: It's a 180-inch span on the l 22 instrument and runs from the feedwater sparger level up.
I 23 MR. MICHELSON: Zero ire.still well above the top
! 24 of the U bends.
i 25 MR. EBERSOLE: What's 100 percent?
1 O
ACE-FEDERAL REPORTERS, INC.
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i 27026.0 122 BRT 1 MR. WAMBACH: 100 percent is 180 inches above 2 that point.
3 MR. EBERSOLE: Okny.
4 MR. WAMBACH: As a result of our concerns, again
, 5 the maintenance -- most of these things were worked on as 6 part of the accelerated or aggressive recovery of the 7 backlog on maintenance. Some of them were worked on during 8 the February, March, April, May time frame, and yet they 9 failed.
10 So Region 3 issued a confirmatory action letter 11 requiring Region 3 approval prior to restart.
12 The action letter requires a thorough 13 investigation of the causes and implications of the May 19, 14 f 1986 trip; thorough investigation of plant safety systems t
15 h and balance of plant systems important to safety with 0
r 16 l regard to operability and required maintenance; and then 17 h the regional administrator must be briefed of the results 18 and the corrective actions taken or planned and give his b
19 approval prior to restart.
20 ! Region 3 also formed an augmented inspection j
21 team with headquarters people, and we visited the site May
}
22- 22 through May 25th. At the site we -- two of the team 23 members held discussions and interviews and so on with the 24 operations people, mainly regarding that concern on the 25 increased workload for the operators during these events ACE-FEDERAL REPORTERS, INC.
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1
- 27026.0 123 BRT I with deficient equipment. Three of us worked with the 2 maintenance people and the systems engineers to determine 3 if they had any precursors that would identify that these
, 4 failures would occur and what the maintenance history was ,.
i 5 and so on.
j j 6 Following all these discussions, then they also i
! 7 gave us work packages'for each of these components-that I
8 gave us a history of what had been done in the past.
2 9 MR. MICHELSON: On this point, help me a little i 10 bit. I was thinking that an augmented inspection team is 11 the next step below an IIT, and it indicates an event of 12 significance from a safety viewpoint, but maybe not quite i 13 big enough to make it a full-blown affair.
] -
14 It escapes me in this case, the safety 15 !i significance of this whole event, sufficient to initiate an h
j 16 l AIT; yet in the case of Browns Ferry where they had the i
j 17 . water all over the place and had a number of electrical i
, 18 actuations and a lot of strange things happening, there was
, i 19 no AIT for that. So I'm trying to get a feel for.the level 20 and the reasons why you have AIT in one case and you don't 4
21 f in another?
1
) 22 MR. EBERSOLE: This is part of the a'
23 regionalization problem.
24 flR. MICHELSON: What's the safety significance j 25 of this event, first of all? Maybe it escapes me.
(
i i
ACE-FEDERAL REPORTERS, INC, j 202-347-3700 Nationwide Coverage 800-33MM6
.27026.0 124 BRT 1 Warranting an AIT? Or is it just that they really wanted j 2 to do some inspection of the maintenance?
3 MR. WAMBACH: No, the safety significance, we i
I 4 believe -- whereas these items, especially with the i
i 5 background that we knew they were having maintenance
$ 6 problems over the last cycle and.they supposedly were on a 7 program that satisfied the confirmatory action letter to 8 better their maintenance and reduce the backlog, and yet
] 9 this equipment which they worked on --
! 10 MR. MICHELSON: It would seem to me that what 1
11 you listed under significance indicates that - they are not
~
12 l quite doing what you thought they were doing, and, i
i 13 j therefore, you ought to crack down a little more with t l 14 another inspection. But an AIT to me meant that there was
- 15 something of potential real safety significance that might 16 fbegenerictotheindustryandsomethingthathastobe '
17 jumped on right away and worked out, but not quite big
- 20 I HR. EBERSOLE
- What I saw in this is something i
! 21 that's always bothered me. It seems that you are about to
] 22 go blind on reactivating inventory -- i 4 i
) 23 l MR. REED: Jesse, I don't agree on your i i j 24 theorizing here. There are a lot of multiple failures here, i
i 25 but what has happened here is the turbine bypass valve
)
O i
i i
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27026.0 125 BRT i 1 failed to open and one steam dump failed to open. That 2 sets you up for atmospheric dumps opening, but it doesn't 3 really affect the surge of the transient on the pressurizer i
4 very much because the atmospheric dumps and other pumps 5 took care of it and kept your pressure temperature 6 secondary.
7 MR. EBERSOLE: In effect, what I heard, it
! 8 wasn't a pressurizer surge, it was a subsequent depression.
9 MR. REED: Sure. That will happen.
10 MR. EBERSOLE: Then I heard they had three pumps, l 11 one with a cracked head -- they had three pumps, one that 12 worked 150 seconds or something. What I drew out of it.is s
13 J if these makeup pumps don't work, I am in apparent close i 14 proximity to loss of visual references to where the reactor
- 15 coolant inventory is.
16 h] MR. REED: That's true if your charging pumps 17 f don't work, but the design has looked at the size of the i
l 18 l pressure, water level, span of the monitoring --
19 MR. EBERSOLE: What does it say when I go blind?
l l 20 i Do I go blind on one pump?
I l 21 l MR. REED: The gentleman, I think, said in a i
l 22 normal transient or near normal transient on this PWR, one i
23 charging pump is sufficient.
l 24 MR. EBERSOLE: Is that the design basis in a f 25 generic context?
l; ()
1 l ACE-FEDERAL REPORTERS, INC.
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. . . . - . .. - . =. . - - .
- 27026.0 126 BRT 1 MR. REED: I believe these must be combination 2 chargers and injection pumps. These are centrifugals; i 3 right? They are positive?
i 4 MR. WAMBACH: No. Positives.
l 5 MR. REED: Well, he said one. That's generally
- l l 6l the case on PWRs, that I'm familiar with, for a near normal 7 transient or removal of decay heat through the steam 8 generator. One will take care of-it.
9 MR. WAMBACH: Let me also mention that as part 10 of the automatic response also on the water level is the 11 isolation of the letdown system, so then the water level i
! 12 that has been dropping, you know, will stop if you don't l 13 l have any charging pumps.
1 0
1 14 q MR. EBERSOLE: Except for shrink.
J 15 MR. MICHELSON: So really I'm at a loss to
- l l 16 l support what all the fuss is about. It's an interesting 17 event, but I don't find a fuss big enough to warrant I
- 18 forming an AIT.
- 19 MR. WAMBACH: Mr. Hale, from Region 3, I think I
i 20 I can address that.
l 21 MR. HALE: I'll Bill Hale, Region 3. The l 22 thought process that went into the formation of the AIT was 23 considering the history of problems that had existed at
{
i l
24 Palisades during the last cycle, and experienced subsequent j 25 to the refueling outage, ' created great concern with regard i
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(~)
1 to reliance on operator action above and beyond what is 2 normally expected. The main concern here was with trying 3 to determine what effect these multiple equipment failures 4 had upon the operating organization, operators' controls, 5 . what kind of distraction would these cause that would i
- 6) distract their primary attention from recovery of plant.
I 7 Because of the differences in the reports received both j
i 8l through the headquarters duty officer and the report coming i
9 j out of the resident inspector of the plant, we weren't 10 quite sure what exactly the extent of the equipment 11 p i
failures were at the time that we initiated the AIT effort.
12 l MR. MICHELSON: Just have to see, then.
(~ 13 MR. EBERSOLE: I would endorse taking in to the
\m)g 14 i full Coamittee on the grounds that any transient like this 15 l that has a number of failures is indicative of a 16 h maintenance deficiency that has to be looked at.
17 MR. MICHELSON: Many of these were in the d
18 j nonsafety portion. It escapes me what real safety problem 9
19 j developed that we ought to be concerned about.
20 MR. EBERSOLE: It's the first stages of a 21 l Davis-Besse-type sequence.
22 MR. MICHELSON: So are a lot of other events 23 that we don't form AITs for.
24 MR. EBERSOLE: Let's take a vote here. My vote 25 is only worth the same as all the rest of you. I'd take it O)
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J 27026.0 128 BRT 1 to the full Committee. What would you do?
2 MR. REED: I don't think I would. I think this 3 is indicative of backlog and poor maintenance and perhaps 4 some poor design valves and equipment. But you've got to 5 do the maintenance first to find out, and it looks to me 6 I like the maintenance is not up to snuff.
7 MR. EBERSOLE: Okay. You wouldn't take it. How l 8 about you, Charlie?
9 MR. WYLIE: I wouldn't take it.
1 J
10 MR. EBERSOLE: Okay. We won't take it.
11 MR. BAER: Mr. Ebersole, this is Bob Baer of the 12 Staff. I would like to try and address Carl's question in 13 ! a little different manner, because you were concerned about O 14 i
Browns Ferry.
l I
15 E MR. MICHELSON: As an example.
l
~
17 l plant. You might come up with generic issues after you 18 have done the in-depth inspection, but it's aimed at the I
- 19 health and safety of that plant and whether it should be 20 - restarted and looking, thoroughly understanding the event I
21 and making sure the licensee is taking the appropriate i
22 I action.
23 I think in the case of all the Browns Ferry 24 plants, one, there's not an immediate health and safety 25 problem and I think the general feeling is they are getting i
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1 plenty of Staff attention so that's how I would contrast it j 2 in that case. ,
?
- 3 MR. MICHELSON
- I think if you go back and look i
4 at the definition of what constitutes the need for an AIT, 5 it's more than the need for a little more in-depth 6 inspection. The nature of the event is such that there are 4
7 implications of serious, potentially even generic safety 8 issues at that or even several plants and that's the reason 9 you put together the special team. Not just to enhance an 10 inspection process that's supposed to be going on.
11 ,
MR. BAER: I think for an AIT, it is enhance'the 12 Region's capability. It's not an IIT, which is, I think, a 13 little more.
O 14 MR. MICHELSON: I'd be very surprised to have an l
15 g l4 l IIT because your maintenance isn't too good, but it's not i
16 at all surprising when an event occurs at a plant which j 17 l indicates that a plant is in a potentially unsafe state. <
l l
18 lt If you have sloppy maintenance, it's a problem for the '
! I 19 Region to take care of without an AIT, because the AIT 20 draws in beyond the Region now.
21 MR. ALLISON: I don't think you should be 22 surprised if the Staff initiates events like this.
23 MR. MICHELSON: Several events in the last few 24 months which I would have put down for candidates, such as j 25 Browns Ferry, were not candidates for AIT.
i ()
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27026.0 130 BRT 1 MR. EBERSOLE: Browns Ferry is already under the 2 gun.
3 MR. MICHELSON: I'm trying to rationalize where 4 AITs are being formed, so I look at the cases where they 5 are formed and I look at all the cases where they are j 6 formed and I have the problem as to why. Here, in this one 7 here, really I scratched my head. '
i i 8 MR. EBERSOLE: Let's get this out of this: Why I
9 don't we derive from this particular topic a statement of 10 requirements to initiate an AIT and a generic context that l 11 crosses the Regions? Where are the guidelines for issuing j 12 an AIT, and why don't we get an expression of those?
i 13 MR. ALLISON: There's a procedure.
14 MR. MICHELSON: I have seen the procedure. I l 3 15 ! have read it. I'm quite interested in the AITs.
l 16 I MR. EBERSOLE: Do you agree with the procedure?
! 17 i MR. MICHELSON: Yes. I i l 18 MR. EBERSOLE: It's the Implementation.
f 19 MR. MICHELSON: And the fact that other examples 20 which I think were more safety significant didn't seem to i
l 21 make the list.
22 -,
MR. EBERSOLE: Why don't we get a copy of the AIT,
- 23 whoever is coming to the meeting.
24 MR. ALLISON: We'll bring it to you on Friday.
25 MR. EBERSOLE: We have to move on. We'll run l
. ACE FEDERAL REPORTERS, INC.
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27026.0 131 BRT 1 out.
2 Are there any further questions?
3 The next is a cracked main steam line header, at 4 Palo Verde. That makes it even more so.
5 MR. HARTZMAN: My name is Mark Hartzman, talking 6 on behalf of John Fair. The event is not a main steam line 7 cracked header but a broken strut-type pipe support.
8 MR. EBERSOLE: How did this get in here?
9 MR. HARTZMAN: I was asked to come down and talk 10 to you.
11 MR. EBERSOLE: No, what I'm getting at, is there 12 a cracked main steam line header at Palo Verde?
13 MR. ALLISON: No. It's the support that's 14 cracked.
15 MR. HARTZMAN: On March 13, 1986, a broken 16 strut-type pipe support was found on the 24-inch main 17 feedwater line to the steam generator number 2 of Palo 18 Verde Unit 1. The characteristics of this failure were 19 that the welds between two members had broken completely 20 and there was a significant deformation of the flanges.
21 PR. EBERSOLE: Were these supports coordinated 22 so that each carried their shared portion of the loads?
23 MR. HARTZMAN: Yes.
24 MR. EBERSOLE: In spite of that this one broke?
25 MR. HARr2 MAN: That's correct. A diagram of the O
i l
l ACE. FEDERAL REPORTERS, INC.
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s 1 support is shown to your left. .
2 (Slide.)
3 The failure occurred at the weld between these
! 4 two members, which are labeled item A and item E.
I 5 The pipe or the support ^c6nsists of a 6 cantilevered type I-beam and has a diagonal restraint. At 7 the end there is a cross member from which there are two 8 struts hanging. The struts are, in turn, attached by other 9 members to the pipe. Basically, the way this works, on the 10 thermal expansion, the pipe will be able to translate i 11 biaxially and transversely without putting any undue loads 12 on the support itself. Due to thermal expansion.
, 13 Other than wha t I would call normal thermal 14 expansion loads.
15 MR. EBERSOLE: Is there an increase in loads 16 when you have a thermal expansion? Transient?
17 MR. HARTZMAN: I'd like to come to that. Yes, 1
18 there is.
- 19 MR. EBERSOLE
- Okay.
20 MR. HARTZMAN: The safety significance of this 21 event is that in the first place, the support failed under 22 operating conditions. In other words, it failed during --
23 simply during dead weight, under dead weight and thermal 24 expansion loads.
I 25 The other supports have to carry additional i
O 1
ACE-FEDERAL REPORTERS, INC.
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27026.0 133 BRT 1 loading and the load carrying capacity of the other 2 supports may be exceeded under seismic or other dynamic 3 loading.
4 MR. EBERSOLE: I think there's a coamon question, 5 i now popular, about steam generator overfill, in which case 6 you would carry not merely the dead weight of the pipe but 7 carry a full load of liquid.
8 f MR. REED: This is a feed line.
1 :i 9
f MR. EBERSOLE: I'm sorry, this is a feed line, 10 isn't it?
l 11 MR. HARTZMAN: It's a feedwater line; yes.
e 12 t MR. EBERSOLE: Forget it. I'm off base.
4l p 13 ; MR. HARTZMAN: Now --
V a 14 !' MR. EBERSOLE: What is the failure logic of the l
15 j supports? Obviously if one fails, it's still hung up.
16 j MR. HARTZMAN: In this case there was total J
17 f separation of the pipe from the support -- from this.
18 These two members totally separated.
1 19 0 MR. EBERSOLE: What stress conditions did that 20 g result in in the pipe? Anything in particular?
a 21 MR. HARTZMAN: We believe there was no 22 l1 additional or no excessive stress in the pipe. The pipe 23 remained integral and did not appear to be deformed in any 24 manner.
25 MR. EBERSOLE: What residual stress did it O
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~
27026.0 134 1
BRT 1 result in, in the remaining three hangers?
i 2 MR. HARTZMAN: Residual stress?
} 3 MR. EBERSOLE: What stress loading took place?
1 j 4 Obviously they stood up.
I l
5 MR. HARTZMAN: The other hangers also stood up.
MR. EBERSOLE:
l 6 ! What was the margin to failure, 7
of a cascade failure?
8 MR. HARTZMAN: I can't tell you. Of the other
- 9 hangers in the line, there are five or six or seven other 10 hangers in the line.
l
- 11 MR. EBERSOLE
- If I had one hanger which was J
j 12 mal-loaded as a result of deformation of this, could it l 13 have a tearing effect?
14 MR. HARTZMAN: There might have been a tearing l
- 15 effect on the dynamic loading; yes. This is this concern, i 16 the safety significance.
i l 17 MR. EBERSOLE: It's a cascade potential, here?
I
- 18 MR. HARTZMAN
- That's correct.
I j 19 MR. EBERSOLE: If they all come down, what
- 20 happens?
?
i 21 MR. HARTZMAN: The line, presumably would deform i
I 22 quite substantially. It might even f ail, might crack and I
! 23 break.
4 l 24 MR. EBERSOLE: If it were to fall, would it i
j 25 preserve the entry of the critical need for aux feedwater?
l l ACE FEDERAL REPORTERS, INC.
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a i.
. 27026.0 135 BRT f
1 MR. HART 2 MAN: It would not. I don't believe so.
2 MR. EBERSOLE: This gets into an interesting
- 3 safety-significant problem because Palo Verde of all plants i
- 4 rides on the preservation of aux feedwater. It has got no l 5 other way of cooling. It doesn't have PORVs. So le t 's go .
i 6 i MR. REED: I'm not sure I caught what he replied. -
7 You are saying failure of this main feed line would not I l .
8 jeopardize aux feed? Is that what you said?
9 MR. EBERSOLE: He said it would.
I 4 l 10 ! MR. HART 2 MAN: No. I said it might. Frankly, I l 11 don't really know, but I said it might.
4 !
)
a 12 l MR. REED: Someone, perhaps, should look at the l 13 location of the check valves in the main feed line and i
j h
14jl their reliability and whether or not aux feed would be 15 j jeopardized, would have been jeopardized.
t !
i 16 l; I might point out something about main feed 17 0 lines. They vibrate, they shake. This weld doesn't look i
! 18 very rugged and substantial, and I'm wondering with the
?
l 19 offsetting that you get from cold to hot, I'm wondering if 20 the weld with the vibrational loading, should have been --
i j 21 that perhaps was here and perhaps worst at this point -- I 22 wonder if their vibrational loading was reason for the i
23 failure?
24 MR. EBERSOLE: You are saying there's a dynamic s 25 loading component?
(
i I
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! 1 MR. MICHELSON: Those are spring hangers,
- 2 weren't they?
i j 3 MR. BAER: It was just a misdesign.
)
4 MR. ALLISON: One thing, we are going to tell l 5 you it was underdesigned. Second, the aux feed goes in a 3
. 6 separate line. This goes to the main feedwater header.
.i 1, 7 MR. EBERSOLE: It's isolated from the main
! 8 feedwater header by check valves?
) 9 MR. ALLISON: I think it goes right into the j 10 main.
l .
11 MR. EBERSOLE: If you lose the main header
] ,
12 you've got to close up.
I 13 MR. ALLISON: It just goes in in a separate
{
I 14 j penetration. It's not connected with the main feeder line t
4 15 system.
I !
l i
16 l' MR. EBERSOLE: If I lose the main feedwater l
17 header, and in the course of doing that, I disable the 18 reverse flow checks, then do I not look on a common
! 19 manifold system to both steam generators?
i j 20 MR. HARTZMAN: I can't answer your question. I
! 21 don't know.
j 22 HR. EBERSOLE: I'm trying to find the
! 23 implications.
)
j 24 Okay. We'll leave that one hanging as a 25 question.
1 l i l 1 i j ACE-FEDERAL REPORTERS, INC. l 202-347 3700 Nationwide Coverage 800-33 & 6646 l
. I 1 -1
\
27026.0 137 f BRT i i I 1 MR. HARTZMAN: The root causes, when we first t
)
i 2 spoke with the licensee, we hypothesized that there were !
l 1 4
3 some unknown loads, possibly due to water hammer or some 4 other source which had not been taken into account in the 5 design of these supports, and, indeed, when the licensee i
6 came back after his investigation, he found that the system 7 experienced lateral and axial translation, such that there s
] 8 were certain lateral loads induced, due to the dead weight j 9 on this member (indicating) such that there were additional I l 10 moments, shears and moments induced. There were additional i 11 shears and moments which induced considerable additional i !
1 12 stresses on the welds which led to this failure.
i 13 Furthermore, the flanges, where, because there i 14 l were only welds between the lower flange and the upper I. !
l 15 j flange, not all around, but only along two edges, this j 16 ! induced certain additional prying effects which are not i I
17 pl i
usually accountable in the standard weld design methodology. .
1 j 18 But which do play -- which do play quite significant effect,
.] 19 particularly when combined with with certain stress i
j 20 concentration effects which also are known to exist in i
- 21 welds.
) 22 Usual weld design methodology accounts for --
r 23 doesn't explicitly account for these effects, but there is
\; <
{ 24 enough conservatism that it takes care of this, in ordinary
?
l 25 design. However, when you have -- but, when you have this i
l ACE. FEDERAL REPORTERS, INC.
l 202 347 3700 Nationwide Coverage 800 336 M46 i
T 27026.0 138 BRT (3
kl 1 additional flexibility of the flanges and you have these 2 induced moments, then the welds obviously cannot take these 3 loads.
4 To give you an idea of the deflections of the 5 line during thermal heatup or thermal expansion, the pipe 6 under dead weight loading hung -- this was the cold 7 position.
8 (Slide.)
9 The dead weight plus thermal expansion, the line 10 l experienced a lateral rotation of 5.93 degrees and an axial i
11 g rotation of 1.76 degrees. This, coupled -- this induced a 12 lateral lowering at this point, which, coupled with the 13 ,
distance from the support or the junction of this point iO 14 with the depth of the cross member, caused the large
]
15 I increase in stress in the weld which had not been accounted
)
16 for in the original design.
l 17 MR. EBERSOLE: Why wasn't it on a pivot or a
- 18 f chain?
19 f MR. HARTZMAN: Because this is a strut, and 20 i struts are always pinned members, i
21 i 1
So, this was the main reason but not the only 22 reason. The other reasons were insufficient weld size.
23 There is something called a cover plate and prying effect, 24 l due to the flexibility of the bottom flange.
25 MR. EBERSOLE: Is it generally true in a hanger ACE. FEDERAL REPORTERS, INC.
202-347 3700 Nationwide Cmcrage 800-33 4 % 46
t
'27026.0 139 BRT like this you are obligated to carry $oment loads due to 1
2 lateral movement?
3 I MR. HARTZMAN: No. Not usually accounted for.
4 MR. MICHELSON: I thought the seismic motion
,5 would have brought in a few degrees of lateral load?
- 6. MR. HARTZMAN: It's still not accounted for.
7 MR. MICHELSON: I'm sure it is accounted for in 8 the seismic design. If there's movement it has to be.
9 MR. HARTZMAN: There's induced additional i
10 loading but this effect is not accounted for.
- 12 of course, but I don't know how much lateral motion you get 13 ,
in the seismic load in this case but it's not at all 14 uncommon to see a few inches on a big steam line or 15 . feedwater line.
16 g MR. EBERSOLE: What I'm trying to find out is
- o ,
17 ! why is this a rigid system rather than pure hanging?
18 MR. HARTZMAN: In what sense do you mean " rigid 19l system"? ,
20 MR. EBERSOLE: In that left-hand diagram, why 21 did they ever put a moment on the weld?
22 MR. HARTZMAN: Because of the dead weight plus 23 thermal load, which~is assumed to act in a downward 24 direction, when you have a lateral displacement,aa' lateral 25 displacement due to the pipe moving outwards, induces a O -
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i i
27026.0 140 BRT 1 load. This is a strut, which is a one-direction 2 member-type load.
3 MR. EBERSOLE: Those are pin joints. They are 4 free to move? That's enough. I just wanted to know that 5 it was free hanging.
6 MR. HARTZMAN: Ye s , it is free hanging.
7 There was also a small computational error that 8 was made in the very initial design and -- but they found 9 that the water hammer loads -- they did calculate water i
10 hammer loads and they were found to be not significant.
11 MR. MICHELSON: How did they calculate water 12 hammer loads? You'd have to postulate water hammers first fs 13 of some sort. You'd have to model this thing.
N) n 14 MR. HARTZMAN: This support is located near 15 certain valves, and I assume they simply -- I presume they 16 assumed that the valves simply closed and they were able to 17 calcula te the loads acting on the elbows near the support.
18 MR. MICHELSON: This is water hammers due to 19 fast valve closure and that sort and not to steam 20 condensation and that sort of thing?
21 MR. HARTZMAN: As far as I know it's a water 22 line.
23 MR. MICHELSON: Yes, but it's a hot water line, 24 and when you depressurize it during an accident, it starts 25 to void, and when you start the pumps again or whatever,
() '
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27026.0 141 BRT l 1 you get some very nice water hammers.
2 MR. EBERSOLE: We are running fast out of time 3 and there's another meeting that comes in at 1:00, and if 4 you want anything to eat we are going to have to move it.
5 I heard some statement to the ef fect that this 6 sort of hanger melf unction might precipita te into a tearing 7 or cascade failure event which in turn might jeopardize 8 that critical aux feedwater f unction because of the 9 potential failure of reverse flow checks. In Palo Verde in 10 particular, which is supposed to be a banner plant in the 11 eyes of the commercials, which doesn't have PORVs, I think 12 anything even faintly threatening the continuity of aux 13 feedwater is a matter of some importance. It would only be 14 for that basis that I would carry this to the full 15 Committee . I would like to have the Subcoramittee members 16 comment and agree or disagree on this.
17 Is this an incipient matter here leading to loss 18 of aux feedwater, for.which Palo Verde has no recourse?
19 MR. MICHELSON: How could it lead to a loss of 20 the auxiliary feedwater? It's directly into the- steam i
21 generator --
22 MR. EBERSOLE: Water car come out through the 23 feedwater lines --
24 MR. MICHELSON:
~
Only if the check valves fail 25 also, in addition to the line failure?
to
- ( '
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27026.0 142 BRT
(~)
5/ 1 MR. EBERSOLE: But they may be loadings on the 2 check valves --
3 MR. MICHELSON: There may be. There's nothing 4 saying that's even the case here, because upstream and 5 downstream of this point I assume there were no failures of 6 supports?'
7 MR. HARTZMAN: These supports are designed to 8 take seismic loading. So, presumably this is an isolated 9 incident.
10 MR. EBERSOLE: You said you didn't know the 11 margin of strength in the residual hanger structures, ,
12 didn' t you? You didn't know the margins of strength left 13 with the residual hangers. ,
14 MR. HARTZMAN: No. I didn't.
15 MR. EBERSOLE: We argued then, if they peel, 16 you'd lose all the supports, and if you lost all of them, 17 this would imply a degree, nonunderstood degree of 3'
18 potential failure on the reverse flow checks.
19 MR. REED: Je sse , I think our Palo Verde concern 20 is very important, but I don't think this is a good case to 21 promote it with, because obviously the other supports 22 didn't fail. This one was failed.
23 MR. EBERSOLE: But we don't know with what 24 margin they didn't.
25 MR. REED: Well, they didn' t. It's probably a O
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! 27026.0 143 BRT I
separa te injection line on auxiliary feed, which means that 1
2 checks valves on the main' lines, the only thing that would 3 come out would be steam anyway, and again, steam would ,
4 affect cooling. You'd get transfer decay heat anyway.
- 5 I doubt if this is a good case.
4 6 MR. EBERSOLE: You mean you'd get an injection 7 of aux feed even if it was evaporative cooling to this 8 region because you wouldn' t drain the steam generators anyway.
i 9 MR. REED: Yes.
i 10 MR. EBERSOLE: Do I have any reaction, then, 11 toward not taking this to the f ull Committee?
12 MR. REED: I don't think I'd take it to the full 13 Committee.
14 MR. EBERSOLE: What about you, George?
! 15 MR. WYLIE: I don't think I would.
i 16 MR. MICHELSON: How many candidates do we have l
- 17 for the full Committee?
} 18 MR. EBERSOLE: Two so far.
4 19 MR. REED: I do note again this is a design 20 problem which,' supposedly we've covered all those.
- 21 MR. MICHELSON
- I would like to make one i
i 22 observation. We decided in a previous case not to take it 23 to t he full Committee by a vote of the Subcommittee. '
It 24 bothers me a wee bit, though, that here is an event that 25 warranted the formation of an AIT but wasn't sufficiently l
($)
l ACE-FEDERAL REPORTERS, INC.
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27026.0 144 BRT l
l'} l important even to bring to the attention of the full l f
2 Committee.
3 MR. REED: This one didn't get an AIT.
4 MR. MICHELSON: No. I'm talking about the i 5 previous one.
6 MR. MICHELSON: I would think almost 7 automatically any event that caused the formation of an AIT, d we automatically went to the full Committee. '
9 MR. EBERSOLE: For that reason, would you take 10 it to the full Committee?
11 MR. MICHELSON: If we have the time and continue 12 to have many candidates, and I think we do -- in any case, 13 I would bring it there to raise the question and present 14 the opportunity for the staf f so explain a little bit why 15
~
an AIT was formed in this case and so forth, to get an idea.
16 Because this whole AIT/IIT is in a formative stages , yet 17 and it's feeling along. I have been watching the examples 18 of when they are formed, and when they aren't formed and I 19 was just thinking automatically --
20 MR. WYLIE: Are we going to hear the conclusion 21 of this one?
22 MR. EBERSOLE: Did you have anything else? Is 23 that it?
24 MR. HARTZMAN: Well, I have -- I can say a few 25 more words about this.
t b%
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27026.0 145 BRT 1 (Slide.)
2 The licensee has taken corrective actioris as 3 follows. They have performed calculations to confirm the 4 deficiency of the hanger as originally designed.
5 Then stress calculations for this hanger were 6 revised to account for the additional loading at the weld 7 in all three units.
8 Metallurgical studies were also performed on the 9 broken welds and the results ind ica te f ailure which 10 occurred from ductile overload and not fatigue.
11 MR. EBERSOLE: I would like to see you add to 12 that, if you can, that the studies ' even in the original 13 considerations, anticipated failure of single hangers is 14 always with us. And the residual loads that occur after 15 that on the remaining hangers need to be confirmed with 16 appropriate margins.
17 MR. HARTZMAN: Do you mean additional loads?
18 MR. EBERSOLE: Due to the failure of a single 19 hanger I want to know what the margin of safety is to hold 20 up the rest of the pipes. It seems that would just be a 21 common logic design basis. I'm always going to fail one 22 hanger because somebody forgot to weld it or something.
23 MR. HARTZ: We would assume such things don't
- 24 happen.
25 MR. EBERSOLE: It's a single failure logic, bs 1
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27026.0 146 BRT s' 1 that's all. Then I must show the residual hangers must 2 work.
3 MR. WYLIE: Obviously they haven't considered 4 all the loadings on this particular hanger in the design.
5 MR. HARTZMAN: This was an unusual case, in the 6 sense that the reason that these additional loads were not 7 considered -- they are ordinarily not considered in hanger 8 design.
9 MR. EBERSOLE: We do have in place a single 10 failure criteria, don't we? So we temporarily say at any 11 point in this structure , pass or otherwise , unless we have 12 a little in the pass structure or otherwise -- you know, 13 the superreliability concept: We argue if something 14 singular fails, the rest of the system will hold together 15 with appropriate margins.
16 Isn't this followed in a ritual way in hanger 17 design?
18 MR. HARTZMAN: This would be followed in the 19 pipe design, in the piping analysis. But I am not familiar 20 with the piping analysis that was done in this case.
21 The issue here was a broken hanger and, 22 therefore, the only place where the piping analysis came in 23 was in providing the loading which acted on the hanger.
24 The question here was: Why did this hanger fail under all 25 operating conditions?
A V
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l l
27026.0 147 j BRT 1 MR. EBERSOLE: My question, of course , pertains-2 to the pipes.
3 MR. HARTZMAN: Of course. I realize that.
4 MR. EBERSOLE: That's the only item of interest 5 anyway.
6 MR. HARTZMAN: To conclude, the hangers , the 7 hangers -- hanger was modified by stiffening flanges and 8 adding required weldment. The flanges were stiffened by.
l 9 placing additional plates.
10 MR. EBERSOLE: I think we can forego further 11 details of the fix and move on to the next item because of
{
12 the lack of time. ,
13 (Discussion off the record. )
O 14 (Whereupon, at 12:10 p.m., the hearing was i 15 concluded.)
16 17 i
18 19 20
! 21
. 22 i
23 1 1
24 l 25 ]
O-J i
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I CERTIFICATE OF OFFICIAL REPORTER O
This is to certify that the attached proceedings before the UNITED STATES NUCLEAR REGULATORY COMMISSION in the matter of:
NAME OF PROCEEDING: ADVISORY COMMITTEE ON REACTOR SAFEGUARDS SUBCOMMITTEE ON REACTOR OPERATIONS 4
DOCKET NO.:
PLACE: Washington, D. C.
DATE: Tuesday, Ju'ne 3, 1986 were held as herein appears, and that this is the original transcript thereof for the file of the United States Nuclear Regulatory Commission.
,}
(sigt)
/
, (TYPED),
JOE BREITNER Official Reporter ACE-FEDERAL REPORTERS INC.
Reporter's Affiliation, O
f
\
O Agenda for ACRS d Meeting on June 3,1986 8:30 a.m.
Room 1046, H Street RECENT SIGNIFICANT EVENTS Presenter / Office Date Plant Event telephone Py 4/11/86 Pilgrim Failure to Isolate RCS from RHR M. Wegner, IE A 492-4511 Ft. St. Vrain Loss of Control Power Following G. Lanik, IE Y 4/3/86 Grid Disturbances 492-9007 4/13/86 San Onofre 3 Premature Criticality H. Bailey, IE 7 492-9006 4/30/86 Browns Ferry Undesirable Systems Interaction R. Clark, NRR y as a Result of Fire Suppression 492-8298 Systems Spurious Actuation 5/19/86 Pilgrim Single Failure Could Disable E. Weiss, IE /d All Redundant RHR Pumps 492-9005 Q Loss of Main Feedwater Pump W. Jones, IE /Af i 5/12/86 Salen 1 492-7613 Repeated Snubber Failure T. Chan, NRR /7 6/85 Trojan 492-7136 5/19/86 Palisades Reactor Scram T. Wambach, NRR 21 AIT on site as of 5/22/86 492-8049 Palo Verde Broken Pipe Support on Main. M. Hartzman, NRR 2.3 ;
3/13/86 492-9429 Feedwater Line CLOSED SESSION
- 't #
5/14/86 Palo Verde Disruption of Offsite Power Lines E. Licitra, NRR M 1&2 492-8599 l
l O !
I 1
4
($) PILGRIM . FAILURE TO ISOLATE RCS FROM RHR (M. WEGNER, IE)
APRIL 11-12,'1986 PROBLEM:
CONCURRENT LEAKAGE OF ALL THREE VALVES WHICH ISOLATE RCS THE LOW PRESSURE B-RHR/LPCI LINE PRIMARY CONTAINMENT ISOLATION ACTUATION AND REACTOR SCRAM WITH THE MODE SWITCH IN STARTUP AT 880 PSIG FAILURE OF MSIVS TO RE-0 PEN SAFETY SIGNIFICANCE:
POTENTIAL FOR INTER-SYSTEM LOCA OUTSIDE OF CONTAINMENT INADEQUATE CORRECTIVE ACTION FOR PRECURSOR EVENTS IN EACH PROBLEM AREA
DISCUSSION:
()
- PRECURSOR EVENT (FEBRUARY 12, 1986) PROBLEMS:
INBOARD TESTABLE CHECK VALVE (M0-1001-68B) LEAKING OUTBOARD NORMALLY-CLOSED ISOLATION VALVE (M0-1001-28B)
LEAKING '
HIGH PRESSURE ALARMS CORRECTIVE ACTIONS:
CLOSE NORMALLY-0 PEN ISOLATION VALVE (M0-1001-29B)
CONTINUE PLANT OPERATION
- APRIL 4, 1986 MODE SWITCH CONTACT PROBLEMS (REF IN 83-42)
- ISOLATION, SCRAM FAILURE TO REOPEN OF MSIVS
- APRIL 11, 1986 PROBLEMS:
OUTBOARD NORMALLY-0 PEN ISOLATION VALVE (M0-1001-29B)
LEAKING HIGH PRESSURE ALARMS ( GT. 400 PSIG) ON RHR SYSTEM
- CLOSED OTHER ISOLATION VALVE (M0-1001-28B); STARTED BLEEDING 0FF LINE
() -
GOT REPEAT HIGH PRESSURE ALARM 2 HOURS LATER STARTED PLANT SHUTDOWN 2
([) PILGRIM - FAILURE TO ISOLATE RCS FROM RHR A GROUP I PCIS ACTUATION AND A SCRAM OCCURRED AT 880 PSIG WITH THE MODE SWITCH IN STARTUP DIFFICULTIES IN RE0PENING THE OUTB0ARD MSIVS OCCURRED DURING RECOVERY CAUSES:
THE MODE SWITCH /PCIS INITIATION PROBLEM IS STILL BEING INVESTIGATED MSIV FAILURE TO REOPEN WAS DUE TO DISENGAGEMENT OF THE PILOT POPPET DUE TO INSTALLATION ERROR RHR VALVE LEAKAGE PROBLEMS WERE CAUSED BY THE LICENSEE'S CONCERN WITH MEETING THE TECHNICAL SPECIFICATIONS FOR LEAKAGE WITHOUT ADEQUATELY ADDRESSING THE REASONS FOR THE REQUIRE-MENTS: OVER-PRESSURE PROTECTION OF THE LOW PRESSURE PIPING O
CORRECTIVE ACTIONS:
THE MODE SWITCH PROBLEMS REMAIN TO BE ADDRESSED BY THE LICENSEE '
THE PROPER INSTALLATION OF THE SET SCREWS SHOULD ELIMINATE THE PROBLEM 0F THE FAILURE TO OPEN OF THE MSIVS DUE TO THE PILOT POPPET FALLING OFF CORRECTIVE ACTIONS ON RHR VALVE LEAKAGE MUST ADDRESS THE OVER-PRESSURIZATION OF THE LOW PRESSURE RHR LINE THE WRITTEN RESPONSES PER CAL 86-10 HAVE NOT BEEN RECEIVED FROM THE LICENSEE YET. THEY MUST BE RECEIVED BEFORE RESTART.
()
- 11
1 b) FORT ST . VRAIN - LOSS OF CONTR01. F0WER FOLLOWING GRID DISTURBANCES APRIL 3 1986 (GEDf6E F. [MIK,_ID_
PROBLEM: LOSS OF CERTAIN CLASS 1E EQUIPMENT DUE T S IGNIF ICANCF,:
CIRCULATORS TRIPPED BRIEF LOSS OF ALL FORCED CIRCULATION:
ON LOSS OF BEARING WATER VIA SMALL RELEASE (96 MILLICURIES) 0F NOBLE GAS (XE-1 CONDENSER AIR EJECTORS (PRIMARY COOLANT T OFFSITE DOSES INSIGNIFICANT DISCUSSION:
REPEATED LOSS (AND RESTORATION) 0F OFFSITE (J -
SEVERE SPRING SNOWSTORM (REACTOR MANUALLY SHUT FLUCTUATIONS ON ONE PHASE OF 480VAC POWER CA LOSS OF VOLTAGE (CLASS 1E) ON INDIVIDUAL 120V INTERLOCK CIRCUITS -
TEMPORARY LOSS OF HELIUM PURIFICATION TRAIN (
CLOSED DUE TO CONTROL POWER PROBLEM)
TEMPORARY LOSS OF CIRCULATORS BEARING WAT POWER PROBLEM)
_F0l10',l-UP:
NRR REVIEW 0F ELECTRICAL SYSTEMS CONTINUING ELECTRICAL POWER ANALYSIS OF LER MAY BE R 8 .,/
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SAN ONOFRE UNIT 3 - PREMATURE CRITICALITY APRIL 13, 1986 (H. BAILEY, IE)
()
PROBLEM: REACTOR BECAME CRITICAL PREMATURELY SIGNIFICANCE:
INADEQUATE CONTROL OF PROCEDURES (XENON TABLES).
- FAILURE TO FOLLOW APPROACH-TO-CRITICAL PROCEDURES.
INSERTION
- CRITICALITY OCCURRED BELOW ZERO POWER DEPENDENT LIMITS (60 INCHES ON GROUP 5).
DISCUSSION: 16 HOURS; APPROACH TO CRITICALITY AFTER BEING SHUTDOWN FOR ONLY XENON CHANGING RAPIDLY; BEHIND SCHEDULE ON REACHING CRITICALITY; TRAINEE ON CONTROL RODS.
- DUE TO INADEQUATE ADMINISTRATIVE CONTROL, THE XENON TABLES FOR CYCLE 1 WERE BEING USED INSTEAD OF CYCLE 2.
COUNT START-UP RATE WAS THE MAIN PARAMETER BEING MONITORED.
( ')
RATE AND LOG POWER WERE RECORDED ON SLOW SPEED STRIP CHART RECORDERS.
THE CONTROL ROOM SUPERVISOR (CRS) WAS ON A 4 HOUR HOLDOVER FROM THE PREVIOUS SHIFT AND WAS IN PROCESS OF BEING RELIEVED
- SLIGHT MISALIGNMENT OF FULL-OUT CONTROL RODS GENERATED CPC PENALTY POINTS.
- ECP WAS 60 INCHES OUT ON GROUP 6; WENT CRITICAL AT 80-100
'5 INCHES OUT ON GROUP 4; NOT IMMEDIATELY RECOGNIZED BY TRAINEE OR LICENSED OPERATOR.
- RODS PULLED FURTHER TO 110 INCHES OUT (STABLE PERIOD OF 1.0 DPM). CRS RECOGNIZED CRITICALITY HAD OCCURRED BELOW ZERO '
POWER INSERTION LIMIT; STARTED INSERTING RODS PER TECH SPECS.
PERCENT POWER; AUTO TRIP; PEAK POWER
- CPC ACTIVATED AT 10
-2 WAS 10 PERCENT.
O
$7 l
_2-O FOLLOWUP:
- INVESTIGATION BY REGION IN PROGRESS.
- REACTOR STARTUP PROCEDURES WILL BE MODIFIED TO r
INVERSE COUNT RATE RATIO PLOT AND A PREDICTION OF COUNT RATE DURING ROD WITHDRAWAL.
f
- ENGINEERING PROCEDURES FOR CONTROL OF NUCLEAR D BOOK (XENON TABLES) HAS BEEN STRENGTHENED.
+
- THE STRIP CHART RECORDERS VILL BE MODIFIED FOR TW THE FAST SPEED WILL BE MONITORED WHEN WITHDRAWIN
- THE EVENT WAS REVIEWED WITH ALL OPERATORS.
i O
.l 9
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O BROWNS FERRY UNIT 1 -UNDESIRABLE SYSTEMS INTERACTION AS A RESULT OF FIRE SUPPRESSION SYSTEM SPURIOUS ACTUATION APRIL 30, 1986 (R, CLARK, NRR 492-8298)
PROBLEM:
FIRE SUPPRESSION SYSTEM ACTUATION RESULTS IN ECCS ACTUA FLOODING 0F BASEMENT SIGNIFICANCE:
UNDESIRABLE SYSTEMS INTERACTION (GDC 3)
LACK 0F COMPLETE F0LLOWUP SUBSEQUENT TO FIRE SUPPRESSION SYSTEM ACTUATION DESIGN INADEQUACY OF SAFETY-RELATED CABINET CABLE SEALING DISCUSSION:
UNIT 1 HAS BEEN DEFUELED FOR OVER A YEAR WITH REACTOR VE O AND DRYWELL OPEN,
REPLACEMENT OF FIRE HYDRANT IN COOLING ,
TOWER AREA RESULTED IN DEPRESSURIZATION OF FIRE HEADER, WHEN PRESSURE IN HEADER WAS RESTORED, DELUGE VALVES TO THREE CABLE TRAY FIXED SPRAY ZONES IN UNITS 1 AND 3 ACTUATED, SPRAY SYSTEM SHOULD HAVE REMAINED INACTIVE, ,
- SPRAYS WET DOWN CABLE TRAYS, PUMPS AND PANELS, INCLUDING RPS l
INSTRUMENTATION PANEL IN UNIT 1.
l MAY 3, 1986 -
INADVERTENT ACTUATION OF ENGINEERED SAFETY FEATURES (ESF) ON UNIT 1 AT 1:24 A.M. DUE TO FALSE HIGH DRYWELL PRESSURE SIGNAL CAUSED BY ELECTRICAL SHORT IN T PRESSURE SWITCHES, SAME ACTUATION OF ESF RE0CCURRED AT 3:54 A.M. AND EARLY NEXT SHIFT.
VALVES HAD BEEN TAGGED CLOSED BUT CONTROL POWER REMA Q OUTBOARD ISOLATION VALVES 75-25 AND 75-53 WHICH OPENED, KEEP-FILL SYSTEM VALVES WERE OPEN, k
l l
O
- KEEP-FILL SYSTEM PUMPED 60,000 GALLONS AT 1,000 G)M TO VESSE VESSEL OVERFLOWED CAUSING HIGH LEVEL ALARM IN '
AREA AND SPILL OF 28,000 GALLONS INTO VENTILATION SYSTEM:
BASEMENT CORNER ROOMS FLOODED,
TESTABLE CHECK VALVES INDICATED CLOSED SINCE CHARGING LOW INSUFFICIENT TO RAISE LIMIT SWITCH POSITION.
CAUSE OF FALSE PRESSURE INDICATION DETERMINED IN PRESSURE SWITCH JUNCTION B0XES DUE TO INADEQUATE SEALS,
! ALL OTHER JUNCTION B0XES IN UNITS 1 AND 3 SPRAY AFF AREAS WERE INSPECTED AND NO WATER FOUND, TWO SPRAY SYSTEM ACTUATION CAUSED BY LEAKING CHECK VA CHECK VALVES IN WATER SUPPLY WHICH HOLDS THE DE CLOSED LEAKED ALLOWING DELUGE VALVE TO OPEN, WHICH SPRAYED l Q- TRAYS WHEN PRESSURE IN HEADER WAS RESTORED, SIMILAR INCIDENT ON MAY 11, 1986 WHEN TWO MORE DELUGE VALVES ACTUA AFTER FIRE HEADER PRESSURE DROPPED AND WAS RESTORED, FOLLOWUP:
~
LICENSEE TO REVIEW IMPLICATIONS OF THIS EVENT ON PROGRAM,
- LICENSEE REPLACING AFFECTED CHARGING WATER CHECK VALVES, OVERHAUL AND INSPECTION OF OTHER LIKE MODEL VALVES,
~
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DILGRIM - SINGLE FAILURE COULD DISABLE ALL REDUNDANT R
(]) MAY 19, 1986 (ERIC WEISS, IE)
PROBLEM:
SINGLE FAILURE OF MINIFLOW LOGIC COULD DISABLE A PUMPS DURING SMALL OR INTERMEDIATE SIZE BREAK LOCA SIGNIFICANCE:
POTENTIAL SINGLE FAILURE CAUSES LOSS OF MUL POTENTIAL FOR NO LONG TERM COOLING FROM SAFETY CIRCUMSTANCES:
LICENSEE REVIEW (PROMPTED BY INF0 NOTICE 85-SINGLE FAILURE OF EITHER MINIFLOW SWITCH COULD AUTOMATIC LOW FLOW PROTECTION FOR ALL RHR PUMPS; PUMPS C BURN UP IF MANUAL ACTION NOT TAKEN IMMEDIATELY
- DURING SOME ACCIDENTS OR SPURIOUS ACTUATIONS, RHR PUMPS WOULD BECOME DEAD HEADED FOR EXTENDED PERIOD CURRENT MINIFLOW LOGIC DESIGNED TO BE CONSIST SELECT LOGIC FOR LPCI
(])
- WHEN FLOW DETECTORS IN EITHER LOOP SENSE ADEQUATE FLOW, 1
RHR MINIFLOW LINE VALVES CLOSE CONSEQUENCE OF RHR PUMP LOSS IS LOSS OF LO HEAT EXCHANGERS, AND OTHER FUNCTIONS INCLUDING: ,
-SHUTDOWN COOLING MODE
-LOW PRESSURE COOLANT INJECTION
-HEAD SPRAY (REMOVED FROM PILGRIM)
-CONTAINMENT SPRAY
-TORUS SPRAY
-SUPPRESSION P0OL COOLING WHICH EVENTUALLY W
-LOW PRESSURE CORE SPRAY f
-HIGH PRESSURE COOLANT INJECTION
-REACTOR CORE ISOLATION COOLING
- GE FIX IS TO ELIMINATE "CLOSE" SIGNAL TO MINIFLOW VALVES; COULD INCREASE PEAK CLAD TEMP 50*F IN SOME BREAK SIZES; NI CONSIDERS THIS TO BE INTERIM ACTION
([) FOLLOW-UP l
IE BULLETIN 86-01 ISSUED 5/23/86 IE AND GE ARE DETERMINING GENERIC SIGNIFICANCE -- l
- NRR WILL REVIEW RESOLUTION FOR PLANTS WITH PROBLEM, INC TECHNICAL SPECIFICATION ISSUES /2~
O l SIMPLIFIED DIAGRAM OF PILGRIM MINIMUM FLOW FOR RHR na VM I I E
A ..
.. VM VM RX PRESS. V LPCI LPCI VESSEL AINJECT INJECT
- 4
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- RHR RHR -
HX " A" HX "B" XEITHER SENSOR DETECTING FLOW WILL CAUSE MINIMUM FLOW VA O
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N O
SALEM UNIT 1 - LOSS OF BOTH MAIN FEEDWATER PUMPS MAY 12,1986 (W R. JONES, IE)
PROBLEM:
NYLON CORD WAS USED TO HOLD LIMIT SWITCH CONTACTS CLOSED, SIGNIFICANCE:
INDICATION OF PAST MAINTENANCE PRACTICES.
CIRCUMSTANCES:
- PLANT AT 95% POWER; REACTOR TRIP DUE TO LOW FEED FLOW 8 LOW S/G LEVEL; BOTH MAIN FEEDWATER PUMPS HAD TRIPPED.
SINGLE VALVE PROTECTS CLEANUP LINE BACK TO HOT WELL IF CONTACT IS OPEN, '
- LIMIT SWITCH MONITORS VALVE POSITION, '
4 IT INDICATES VALVE IS OPEN, AND FEED PUMP INTERLOCK CAUSES BOTH MAIN FEED PUMPS TO TRIP, THE VALVE ITSELF WAS ADMINISTRATIVELY CONTROLLED ,
LOCKED CLOSED PREVIOUS HISTORY (12/85) 0F CONTACT SWITCH NOT MAK .
CONSEQUENTLY A NYLON CORD WAS INSTALLED 5/6/86 T!
CONTACTS CLOSED, LONG-STANDING DESIGN CHANGE REQUEST.TO REMOVE FEE INTERLOCK AND LIMIT SWITCHES, ER 6 RE C R RIP (PRIOR TO RESTART) UNIT 1 INTERLOCK SUSE00ENTLY i
DISABLED VIA PROCEDURE BY REMOVING LEADS.
ACCOMPLISHED FOR UNIT 2. ,
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- FOLLOW-UP:
REGION I HAS REVIEWED LICENSEE ACTIONS AND FEELS LICENSEE IS ADEQUATELY CONCERNED ABOUT EVENT. EVENT IS RESULT OF HOLD OVER FROM PREVIOUS PRACTICES.
FULL LICENSEE EVALUATION OF POSSIBLE SIMILAR PROBLEMS IN PROGRESS.
- MORE EFFECTIVE MEANS OF MAKING MINOR DESIGN CHANGES, LICENSEE HAS A PROGRAM IN PLACE TO ADDRESS POSSIBLE CHALLENGES TO SAFETY SYSTEMS, WHICH INCLUDES SINGLE-CHANNEL B0P INPUTS, O
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CONDENSER A l i
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LOW PRESSURE W CONDENSATE HEATERS l PUMPS O
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4 HIGH PRESSURE I
HEATERS I
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TROJAN - REPEATED SNUBBER FAILURES O JUNE.198s < r cuas . NRR)
PROBLEM:
STEAM GENERATOR HYDRAULIC SNUBBERS LOCKING UP DUE TO DESIG INADEQUACY.
SIGNIFICANCE:
DAMAGE TO HOT LEG PIPE WHIP RESTRAINT (1985)
OVERSTRESSING OF HOT LEG ELB0WS PREVIOUSLY UNACCOUNTED FOR MOVEMENT IN THE PRESSURIZER LINE (1982-1985)
CIRCUMSTANCES:
NRC RECENTLY LEARNED THAT RCS HOT LEG PIPE RESTRAINT HAD
- PULLED FROM WALL IN 1985
- DYE PENETRANT TEST PERFORMED ON "B" SG ELBOW.
INDICATIONS FOUND.
H PERFORMED UT ON ALL 4 HOT LEG ELBOWS AND FOUND NO INDICATIONS
+
CRUSHED GRAPHITE SHIMS FOUND ON 3 0F 4 HOT LEG PIPE WHIP RESTRAINTS INDICATING HOT LEG TO RESTRAINT BINDING 11 0F 16 SG SNUBBERS FOUND TO HAVE FAILED AGAIN IN SAME WA 1
BACKGROUND:
1982 - LICENSEE REMOVED THE THERMAL SLEEVE ON THE PRESSURIZER SURGE LINE; HOWEVER, SURGE LINE DID NOT l SETTLE OVER NEXT FEW CYCLES, AS HAD BEEN EXPECTED IN H ANALYSES; MOVEMENT CONTINUED l 1985 - LICENSEE HIRED IMPELL TO REVIEW THE SURGE LINE MOVEMENT; UNABLE TO ACCOUNT FOR CONTINUED MOVEMENT 1985 - A HOT LEG (T0 SG "B") PIPE WHIP RESTRAINT H0RIZONTAL SUPPORT WAS FOUND PULLED FROM THE WALL 17 1
- .- - - _: 1
TROJAN - REPEATED SNUBBER FAILURES
'([) JUNE, 1985 (K. JOHNSTON, NRR), (CON'T.)
1 BACKGROUND,-(CON'T.)
1985 - SNUBBERS TESTED PER NEW TS REQUIREMENTS !
- 2 0F 16 SG HYDRAULIC SNUBBERS WOULD NOT RES. POND TO 100 KIP LOAD; SHOULD HAVE RESPONDED AT dC 10 KIP; ;
ALL 16 WERE DECLARED IN0PERABLE AND REBUILT i
- SNUBBER FAILURE ATTRIBUTED TO CLOGGED HYDRAULIC LINES; CLEANED WHEN ASSUMED THAT ALL SG SNUBBERS WERE INOPERABLE,,IMPELL ANALYSES WAS ABLE TO ACCOUNT FOR THE SURGE LINE MOVEMENT AND THE DAMAGE TO THE PIPE WHIP RESTRAINT THE LICENSEE CLAIMED (1985) THAT ALTHOUGH HOT LEG STRESSES EXCEEDED ASME SECTION III ALLOWABLES, STRAIN IS WITHIN 1%
.- LIMIT, WHICH WAS NRC-APPROVED LIMIT FOR SONGS-1 ON SEISMIC i CRITERIA AND METHODOLOGY i
O FOLLOW-UP:
SNUBBER CONTROL VALVES TO BE REPLACED WITH NEW DESIGN LICENSEE TO PERFORM PRE-STARTUP WALKDOWN OF RCS IN A HOT CONDITION NRR TO REVIEW RCS PIPING STRESSES AND APPLICABILITY AND l
ACCEPTABILITY OF LICENSEE'S ANALYSIS i
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> 900K SUPPRESSOR Page 12.
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Page 12a.
PALISADES - REACTOR TRIP O MAY 19, 1986 (T. WAMBACH, NRR)
PROBLEM: MULTIPLE FAILURES TURBINE BY-PASS VALVE FAILED TO OPEN 1 STEAM DUMP VALVE FAILED TO OPEN BACKPRESSURE REGULATOR IN LET-DOWN LINE FAILED CLOSED PRESSURIZER SPRAY VALVE FAILED TO FULLY CLOSE VARIABLE SPEED CHARGING PUMP TRIPPED 5 TIMES SIGNIFICANCE:_
UNNECESSARY CHALLENGES TO SAFETY EQUIPMENT INCREASED BURDEN ON OPERATORS TO COMPENSATE FOR FAILED OR DEFICIENT EQUIPMEN1 IMPLICATIONS CONCERNING THE QUALITY OF MAINTENANCE AND POST-MAINTENANCE TESTING SEQUENCE OF EVENTS:
PM ON TURBINE VALVE CONTROL CABINET FANS TURBINE VALVES CLOSED O
- REACTOR TRIP ON HIGH PRESSURIZER PRESSURE TURBINE TRIP FIRST ATMOSPHERIC DUMP VALVE OPENED, AFW PUMP P-8A STARTED 2ND ATMOSPHERIC DUMP VALVE OPENED '
3RD ATMOSPHERIC DUMP VALVE OPENED CHARGING PUMP P-55A STARTED (55B & C ALREADY RUNNING)
PRESSURIZER LEVEL LOW ~
LAST LETDOWN ISOLATED CHARGING PUMP 55A TRIPPED THIS PUMP WAS RESTARTED 4 MORE TIMES TRIPPING 30 SECONDS LATER AFTER EACH START 14:22:15 PRESSURIZER LEVEL NORMAL PLANT PARAMETERS:
PRESSURIZER PRESSURE MAX 2245 PSIA, MIN 1689 PSIA T/ HOT MAX 594*F, MIN 535'F T/ COLD MAX 557'F, MIN 535*F S/G PRESSURE MAX 1025 PSIA S/G LEVEL DROPPED FROM 70 TO 12 PERCENT O FOLLOWUP:
I REGION III ISSUED A CONFIRMATORY ACTION LETTER REQUIRING REGION III APPROVAL PRIOR TO RESTART J2 REGION III FORMED AN AIT WITH HQ, SITE VISIT MAY 22 THRU 25
! LICENSEE FORMED TASK FORCE TO STUDY IMPLICATIONS ON PLANT M ;
4 U rJ g 7 [ 6doscgd fi (6 S,j pg , E T PA t$ vs/2.o G -
o rd H Wr d PGGD al ate & Lt dC M A r7_ v_ 14 A (4 T 2_. P-1 AeJ , rJ /2 e EVENT:
- ON MARCH 13, 1986 A BROKEN STRUT-TYPE PIPE SUPPORT WAS FOUND ON THE 24-INCH MAIN FEEDWATER LINE TO STEAM GENERATOR NO. 2 0F PALO VERDE UNIT 1.
CHARACTERISTICS WELDS BETWEEN TWO MEMBERS BROKEN COMPLETELY.
SIGNIFICANT DEFORMATION OF THE FLANGES.
O .
SAFETY SIGNIFICANCE
+
SUPPORT FAILED UNDER OPERATING CONDIT10hS.
OTHER SUPPORTS HAVE TO CARRY ADDITI0 MAL LOADING.
LOAD CARRYING CAPACITY OF OTHER SUPPORTS MAY BE EXCEEDED UNDER SEISMIC OR OTHER DYNAMIC LOADING.
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4 ROOT CAUSES STAFF HYPOTHESIS: POSSIBLE UNKNOWN LOADS DUE TO WATERHAMMER OR OTHER SOURCE.
LICENSEE FINDING: EXCLUSION OF LATERAL LOADS DUE TO INTERACTION OF DEAD WEIGHT AND GE0 METRIC CHANGES RESULTING FROM PIPING THERMAL EXPANSION,
- INSUFFICIENT WELD SIZE
" COVER PLATE" EFFECT ON WELDS DUE TO FLEXIBILITY
(])
- BOTTOM FLANGE OF THE CANTILEVER MEMBER,
- COMPUTATIONAL ERROR, ,
POSSIBLE STRESS CONCENTRATION EFFECT WITHIN W
- WATERHAMMER LOADS NOT SIGNIFICANT, 1
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CORRECTIVE ACTIONS CALCULATIONS TO CONFIRM THE DEFICIENCY OF AS ORIGINALLY DESIGNED, i
STRESS CALCULATIONS FOR THIS HANGER WERE R f ACCOUNT FOR THE ADDITIONAL LOADING AT THE WELD, IN
> ALL UNITS, METALLURGICAL STUDIES WERE PERFORMED ON RESULTS INDICATE FAILURE OCCURRED FROM DU AND NOT FATIGUE, O
- HANGERS HAVE BEEN MODIFIED BY STIFFENING FL i .
ADDING REQUIRED WELDMENT, l:
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O ADDITIONAL CORRECTIVE ACTIONS REVIEW 0F 819 SAFETY-RELATED LARGE-BORE SUPPORT FIVE SUPPORTS FOUND, PER UNIT, ACCOMMODATE PIPE SWAYING.
WHICH REQUIRE MODIFICATION.
WRITTEN INSTRUCTIONS DOCUMENTING ADDITIONAL DESIGN REQUIREMENTS CONCERNING LATERAL LOADS INDUCED BY INTERACTION OF DEAD WEIGHT AND PIPING THERMAL EXP l ISSUED TO ALL PIPING SUPPORT DESIGN PERSONNEL.
(2)
S 4
3 P
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ip PILG8IM - FAILURE TO ISOLATE RCS FROM RHR O .
APRIL 11-12, 1986 PROBLEM:
CONCURRENT LEAKAGE OF ALL THREE VALVES WHICH ISOLATE RCS THE LOW PRESSURE B-RHR/LPCI LINE l
- PRIMARY CONTAINMENT ISOLATION ACTUATION AND REACTOR SCRAM
, WITH THE MODE SWITCH IN STARTUP AT 880 PSIG i FAILURE OF MSIVS TO'RE-0 PEN i
! SAFETY SIGNIFICANCE:
P0TENTIAL FOR INTER-SYSTEM LOCA OUTSIDE OF CONTAINMENT INADEQUATE CORRECTIVE ACTION FOR PRECURSOR EVENTS IN EACH PROBLEM AREA UNNECESSARY CHALLENGES TO SAFETY SYSTEMS (PCIS, RPS) l l
DISCUSSION:
1 PRECURSOR EVENT (FEBRUARY 12, 1986) PROBLEMS:
!O -
INB ARD TESTABLE CHECK VALVE (M0-1001-68B) LEAKING OUTBOARD NORMALLY-CLOSED ISOLATION VALVE (M0-1001-28B) 1 LEAKING l
HIGH PRESSURE ALARMS l CORRECTIVE ACTIONS:
CLOSE NORMALLY-0 PEN ISOLATION VALVE (M0-1001-29B)
) -
CONTINUE PLANT OPERATION j
APRIL 4, 1986 MODE SWITCH CONTACT PROBLEMS (REF IN 83-42)
- ISOLATION, SCRAM FAILURE TO RE0 PEN OF MSIVS APRIL 11, 1986 PROBLEMS:
OUTBOARD NORMALLY-0 PEN ISOLATION VALVE (M0-1001-29B)
LEAKING HIGH PRESSURE ALARMS (.GT 400 PSIG) ON RHR SYSTEM
! - CLOSED OTHER ISOLATION VALVE (M0-1001-28B); STARTED BLEEDING 0FF LINE GOT REPEAT HIGH PRESSURE ALARM 2 HOURS LATER O STARTED PLANT SHUTDOWN
PILGRIM - FAILURE TO ISOLATE RCS FROM RHR O
i A GROUP I PCIS ACTUATION AND A SCRAM OCCURRED AT 880 PSIG WITH THE MODE SWITCH IN STARTUP l
DIFFICULTIES IN RE0PENING THE OUTBOARD MSIVS OCCURRED DURING RECOVERY CAUSES:
THE MODE SWITCH /PCIS INITIATION PROBLEM IS STILL BEING INVESTIGATED MSIV FAILURE TO REOPEN WAS DUE TO DISENGAGEMENT OF THE PILOT POPPET DUE TO INSTALLATION ERROR i RHR VALVE LEAKAGE PROBLEMS WERE CAUSED BY THE LICENSEE'S CONCERN WITH MEETING THE TECHNICAL SPECIFICATIONS FOR LEAKAGE WITHOUT ADEQUATELY ADDRESSING THE REASONS FOR THE REQUIRE-MENTS: OVER-PRESSURE PROTECTION OF THE LOW PRESSURE PIPING Q CORRECTIVE ACTIONS:
THE MODE SWITCH PROBLEMS REMAIN TO BE ADDRESSED BY THE LICENSEE THE PROPER INSTALLATION OF THE SET SCREWS SHOULD ELIMINATE THE PROBLEM OF THE FAILURE TO OPEN OF THE MSIVS DUE TO THE i PILOT POPPET FALLING 0FF CORRECTIVE ACTIONS ON RHR VALVE LEAKAGE MUST ADDRESS THE OVER-PRESSURIZATION OF THE LOW PRESSURE RHR LINE THE WRITTEN RESPONSES PER CAL 86-10 HAVE NOT BEEN RECEIVED FROM THE LICENSEE YET. THEY MUST BE RECEIVED BEFORE RESTART.
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UNITED STATES
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- REGION I
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l 631 PARK AVENUE MING oF PRUSSIA, PENNSYLVANIA 19406
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' NAY 161985 Docket No. 50-293 Boston Edison Company M/C Nuclear ATTN: Mr. William D. Harrington Senior Vice President, Nuclear 800 Boylston Street Boston, Massachusetts 02199 Gentlemen:
Subject:
Inspection Report No. 50-293/86-17 During the period April 12 through April 25, 1986, an Augmented Inspection Team (AIT) conducted a special safety inspection of recent operational events at the Pilgrim Nuclear Power Plant. These events included 1) the spurious group-one primary containment isolations (and associated reactor scrams) that occurred on April 4 and 12, 1986, 2) the failure of the main steam line isolation valves to promptly reopen after the containment isolations, and 3) recurring pressuriza-tions of the residual heat removal system. The inspection results are docu-mented in the enclosed report and-were summarized at the conclusion of the in-spection in a meeting with your staf f. This report identifies several areas for improvement that warrant yocr consideration ~.
Although your evaluations following the April 12, 1986 containment isolation' (and scram) were carefully structured and apoeared thorough, the underlying
) reasons for some of the problem are not yet ully understood. In particular, the reasons for the spurious containment isolations have not been determined.
Similarly, although we understand the technical reason for failure of the Main Steam Isolation Valves (MSIV) to reopen af ter closure, we need to better under-stand the design review and implementation process associated with the modifi-cation in 1983 that resulted in the MSIV problem. In accordance with Confirma-tory Action letter No. 86-10, we await submittal of your report documenting the results of the efforts taken to identify the root cause of the subject events and proposed corrective actions. Af ter receipt of your report, we will review it and schedule a meeting, if necessary, to discuss any questions or concerns that we may have.
Your cooperation with us is ap'reciated.
Sincerely.
O. n Richard Starostecki, Director Division of Reactor Projects
Enclosures:
O- Augmented Incident Response Team Report I
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'O U. S. NUCLEAR REGULATORY COMMISSION AUGMENTED INCIDENT RESPONSE TEAM Report No. 50-293/86-17 Docket No. 50-293 Licensee: Boston Edison Company M/C Nuclear ATTN: Mr. William D. Harrington Senior Vice President, Nuclear 800 Boylston Street Boston, Massachusetts 02199 Facility Name: Pilgrim Nuclear Power Station Inspection At: Plymouth, MA O Inspection Conducted: April 12, 1986 through April 25, 1986 7
Team Leader: J. Strosnider, Chief, Section 18, DRP, RI Team Members: L. Doerflein, Martin McBride, Senior Project Engineer,RI Resident Inspector, Pilgrim K. Murphy, R. Fuhrmeister Technical Assistant, DRS,RI Reactor Engineer, RI M. Chiramal, Section Chief, AE00 S. Pullani Fire Protection Engineer, DRS, RI Reviewed By
/J/ Strosnider, Chief Vroj cts Section IB, DRP Appr'oved By: ob fi. Kistdfi Chief Protects Branch No. 1, DRP C)
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TABLE OF CONTENTS Page 4
1.0 Introduction . . .. . . .. ...... ....... .........
5 2.0 Summary of Events . ... . .... ................ .....
5 2.1 April 4, 1986 Reactor Scram...... . .... . . .....
6 2.2 April 12, 1986 Reactor Scram.........................
7 3.0 Evaluation of Inadvertent Closure of the MSIVs . . ..
7 3.1 Background . . . .......... . ......... .... .
3.2 PCIS Trip Logic Circuit and MSIV Centrol Circuit 8
Designs ... ... .... .. ... ... ..... .... ....
3.3 Investigation .. ..... .. ... .... .... . 9 Root Cause and Safety Significance 12 3.4 ... ... .
0 12 3.5 Conclusions and Recommendations .... .. . .....
3 14 4.0 Esaicaticr. of MSIV Prcbiers .. . . . .
Chronology of Events 14 4.1 .. .... .......... ... ...
Valse Design and Operation .. 15 4.2 . ........ .. . . ..
4.3 Investigation ....... ........... ............... 16 Root Cause and Safety Significance .... .... ... .. 18 4.4 19 4.5 Conclusions and Recommendations.....................
5.0 Evaluation of LPCI Ir.jectier, Valve Leakage . ....... .... 20 5.1 Chronology of Events ............................... 20 5.2 RHR Isolation Valve Descriptions .................. 21 5.3 Past System Leakage Experience ..................... 22 0
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- I 3 i 5.4 History of RHR Valve" Refurbishment and Leak Testing... 22 5.5 As-Found RHR Walkdown and Valve Leakage Measurements.. 24 l 5.6 Root Cause and Safety Significance ................... 25 I I
5.7 Conclusions and Recommendations ...................... 25 !
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6.0 Overall Summary and Conclusions ........................... 27 Figures / Pictures Attachments O
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- 1. INTRODUCTION On April 4 and 12, 1986, the Pilgrim reactor scrammed from low power during routine reactor shutdowns. Both scrams were caused by unexpected group I primary containment isolations. In both cases, the isolation signal was promptly reset, but the four outboard main steam line isolation valves (MSIVs) could not be promptly reopened. As a result, the main condenser was not available as a heat sink during a portion of the reactor cooldown. The shutdown on April lith was initiated because the residual heat removal (RHR) system had been pressurized by leakage of reactor coolant past a check valve and two closed injection valves in the "B" RHR loop. An Unusual Event was declared because of the RHR valve leakage.
NRC management discussed concerns about the recurring isolation and RHR valve leakage problems with senior licensee management and issued Con-firmatory Action Letter (CAL) No. 86-10 on April 12, 1986. This letter required that all affected equipment be maintained in its as-found condi-tion (except as necessary to maintain the plant in a safe shutdown con-dition) until an NRC Augmented Inspection Team (AIT) was onsite to inspect and reconstruct the events. The letter also required that the licensee provide a written evaluation to the NRC cf 1) intersystem leakage through RHR injection valves in the RHR system, 2) the spurious primary containment isolation that occurred on April 12, and 3) the failure of the outboard llh MSIVs to reopen after the isolation. Ihe licensee agreed to seek authori-a zation for restart of the reactor from the Regional Administrator of NRC Recion I. The CAL is included in this report as Attachment 1. An Ali was dispatched to the site on April 12, 1986.
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2.0
SUMMARY
OF EVENTS 2.1 April 4. 1986 Reactor Scram At 1:00 p.m. on April 4,1986, a reactor shutdown was initiated after oil leakage was detected in the main turbine control oil system. The low pressure coolant injection (LPCI) system was considered inoper-able at that time due to an unrelated problem, water leakage past a block valve, MO-1001-36A, in the residual heat removal system torus cooling line.
At 8:15 p.m. on April 4, a group I primary containment isolation (resulting in a reactor scram) occurred as reactor pressure decreased to 898 psig in the shutdown sequence. The two low main steam line pressure alarms (set to approximately 880 psig) were received at the time of the isolation. The reactor mode switch had been moved from the "run" to the "startup" position 45 minutes prior to the isolation.
The low steam line pressure containment isolation function is active in the run mode but is bypassed when the mode switch is placed in the startup mode.
The containment isolation signal was promptly reset following the scram, however, the outboard MSIV's could not be reopened for approximately one and a half hours. The inboard MSIV's were opened
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'- during that time period. As a result of the closed MSIVs, most of the subsequent reactor cooldown was controlled by directing reactor steam to the high pressure coolant injection (HPCI) turbine. The HPCI system was operated in the test mode and did nct inject water into the reactor.
During the review of this even.t the licensee concluded that all the contacts in the reactor mode switch did not close properly when the switch was transferred from the run to the startup mode during the shutdown. As a result, the low pressure containment isolation func-tion was still active when steam line pressure dropped below the trip setpoint (about 880 psig). The licensee determined that proper positioning of the mode switch required removing the Key from the switch each time it was moved to a different mode. Training for all control room operators on proper mode switch operation was conducted prior to the subsequent reactor startup. Additional details of the licensee's evaluation of the inadvertent closure of the MSIVS are discussed in Section 3.0 of this report.
The licensee also concluded that an air leak in the "A" outboard .
MSIV, A0-203-2A, (coupled with repeated attempts to open the valves) probably lowered air pressure to the four outboard valves, preventing them from fully opening. The air leak was attributed to foreign materials in the MSIV pneumatic control valve. Additional details of the licensee's evaluation of the problem with the MSIVs failing to 73 open upon demand and corrective actions are discussed in Section 4.0
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of this report.
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O The evaluations of the Mode Switch and MSIV problems were reviewed by the Operational Review Committee (ORC) on April 8,1986. The reactor was restarted at 2:46 a.m. on April 10, 1986.
2.2 April 12, 1986 Reactor Scram Periodic RHR system high pressure alarms (400 psig) were received on April 10 and 11, indicating that the RHR system was being pressurized by reactor coolant leakage. The~RHR piping in the "B" loop was warm, indicating the leakage was coming through the normally closed injec-tion valve, MD-1001-298, and an inline check valve, 1001-688. At 2:16 p.m. on April 11, a second "B" loop injection valve, M0-1001-288, was closed in the RHR system in an attempt to stop the leakage. The low pressure coolant injection (LPCI) subsystem of the RHR system was declared inoperable at that time. However, leakage continued into the RHR system causing a high pressure alarm two and a half hours later. At 4:53 p.m. on April 11, 1986, a reactor shutdown was initiated f rom about 92*. power and an unusual event was declared due to the leaking valves.
At 1:56 a.m. on April 12, a group-one primary containment isolation (with an associated reactor scram) occurred during the shutdown se-quence. Reactor pressu-e was 908 psig at the time of the isolation.
The mode switch had been mrved from the "run" to the "startup" posi-g
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tion and the key removed from the mode switch twenty minutes earlier, at 1:36 a.m. The isolation and scram occurred about 30 seconds after
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the two main steam line low pressure alarms annunciated in the con-trol room.
As before, the outboard MSIVs could not be opened for approximately one and a half hours after the isolation signal was reset and the HPCI system (in the test mode) was used to cool the reactor. The reactor was placed in cold shutdown and the unusual event terminated at 9:00 a.m. on April 12, 1986.
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.O 3.0 Evaluation of Inadvertent Closure of the Main Steam Isolation Valves Following the scram on April 12, 1986, the licensee promptly organized a team consisting of approximately 14 technical and support personnel to investigate potential failures of the reactor mode switch (RMS), other potential problems in the PCIS circuitry, and operator errors which could have contributed to this event. The scope of the investigation included a thorough analysis of previous events and included trouble shooting plans, procedures and special tests. Members of the NRC Augmented Inspec-tion Team (AIT) monitored the activities of the licensee team and assessed the operational anomalies that occurred in the PCIS circuitry.
3.1 Background
On April 4 and April 12, 1986, while shutting down the reactor, the Pilgrim unit experienced a reactor trip due to inadvertent closure of all eight main steam isolation valves (MSIVs). On both occasions the reactor mode switch was in the "Startup/Het Standby" position and the inadvertent closure of the MSIVs occurred after the operators received alarms indicating iain steam line pressure was less than 880 psig. During the April 4th event, the reactor scram due to MSIV closure occurred almost immediately following the alarm; while on Aprii 12, the scram apparently occurred 30 to 40 seconds after the alarms came in.
Following investigation and analysis of the April 4th event, the licensee has concluded that the cause of inadvertent closure of the MSIVs and subsequent reactor scram was due to failure of some contacts of the reactor mode switch. The contacts in question are in the primary containment isolation system (PCIS) logic channel circuits and are designed to inhibit the actuation of the trip circuits on a low steam line pr' essure condition. That is, the mode switch contacts, when the mode switch is in any position other than "Run", bypass the low steam line pressure trip of the PCIS.
Based on testing of a spare mode switch the licensee also determined that, as a means of assuring that the mode switch contacts function properly, the operators should remove the key from the mode switch handle after the switch is operated. The mode switch key can be re-moved from the handle only if the switch is aligned fully in one of the four required positions, .i.e., the key cannot be removed if the switch is in an intermediate position. All operators were trained on proper mode switch operation, using the spare mode switch, prior to the reactor startup on April 10, 1986.
On April 12, 1986, while shutting down, the mode switch was moved l fr'om the "Run" position to the "Startup/ Hot Standby" position and the key was removed from the handle. However, 30 to 40 seconds following the expected alarms indicating steam line low pressure,
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the reactor scrammed due to the unexpected cicsure of the MSIVs.
Once again the reactor mode switch contacts in the PCIS trip logic channel circuits associated with the MSIVs, were suspected to have caused the inadvertent closure of the MSIVs.
3.2 PCIS Trip Logic Circuit and MSIV Control Circuit Designs 3.2.1 PCIS Trip Logic Circuit The PCIS trip logic scheme consists of four trip logic
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channels (designated A1, A2, B1, and 82) arranged in a one-out-of-two taken twice logic (i.e. , Al or A2 and B1 or B2) to cause a trip. Figure 3.1 is an elementary diagram showing the trip logic channel Al of the PCIS for the MSIVs, main steam line drain valves and reactor water sample valves. When the reactor mode switch is in the "Run" mode, the following conditions will cause the actuation of the PCIS trip logic channels (i.e., deenergizatior, cf relay 16A-K7A, E, C, and D):
(1) Main steam line low pressure (<880 psig)
(2) Low low reactor water level (3) Main steam line high radiation h 0 (4) Main steam line high flow (5) Main steam tunnel high temperature These are referred to as isolation conditions 1, 2, 3, 4, or S in the discussion that follows.
When the mode switch is in other than the "Run" mode (i.e.,
shutdown, refuel or Startup/ Hot Standby), a main steam line low pressure condition will not cause the actuation of the PCIS trip logic channels. This feature enables'the MSIVs to remain open while the reactor pressure is less than 880 psig during a normal reactor startup. However, a high reactor water level condition during these modes (i.e., other than "Run") will cause the actuation of the PCIS trip logic channels.
As stated before, the actuation of the PCIS trip logic means deenergization of relays 16A-K7A, B, C and D.
Contacts of these relays, arranged in a one-out-of-two taken twice logic, actuate the MSIV control circuits discussed below and close the MSIVs.
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3.3 Investication Investigation revealed that the reactor scrams which occurred on April 4 and 12, 1986 were initiated by the actuation of the Reactor Protection System (RPS) due to closure of the Main Steam Isolation Valves (MSIVs). The closure of the MSIVs was initiated by the PCIS trip logic circuitry discussed in Section 3.2.1.
(~') On both the April 4 and 12, 1986 events, it was 1.11tially determined
\> that the only PCIS signal present at the time of the isolation was main steam line low pressure. On both occasions, the reactor mode g switch was in the "Startup/ Hot Standby" position and the reactor pressure was being reduced below 880 psig during the controlled cool down of the reactor. The PCIS trip signal from the four main steam line low pressure switches (261-30A through 0) should have been inhibited by the previously performed operator action of transferring the mcde switch from the "Run" position to the "Startup/ Hot Standby" position.
The reactor mode switch is a pistol grip, key locked, four position control switch. The four positions are: " Shutdown", " Refuel",
"Startup/ Hot Standby", and "Run" (see Figure 3.2). The switch is made up of four banks of General Electric Model SB-1 rotary control switches (see Figure 3.3), having 8 stages per bank (i.e.,16 sets of cam operated contacts per bank). The banks are coupled together by gears. The pistol grip handle is attached to the second bank from the left hand side of the switch.
Reactor mode switch malfunctions causing problems of a similar nature have, occurred at several other nuclear plants and were the subject of IE Information Notice 83-43. Pilgrim had experienced a problem with the mode switch in 1983 (Reference ORC Meeting Hinutes84-104 and Failure & Malfunction Repo~rt 83-133). General Electric Information 73 Letters (SIL) Number 155 and its supplements 1 & 2; and SIL 397 dis-
!, ,) cuss instances of failure of "SB" model switches and recommend actions to be taken.
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Previously, in accordance with SIL 397, during Refuel Outage VI, an SB-9 modei mode switch was bought and tested. The SB-9 mode switch was a used unit rebuilt by GE. Testing was also performed on a SB-1 model switch. Both switches functioned properly and each had a definite ' feel' during a transfer operation. The 58-1 required a specific technique be used to ensure proper alignment of contacts while the SB-9 operated in a stiff and hard manner.
Following this testing, Operations personnel visited the test site and familiarized themselves with the feel and technique used to properly transfer the existing SB-1 switch. This familiarization reduced the concern for the proper operation of the SB-1 Mode Switch.
- This experience coupled with the knowledge that the new SB-9 switch operated in a stiff and hard manner and the extensive time required to change out and post-work test the replacement switch contributed to a subsequent licensee decision to continue operation with the existing SB-1 Mode Switch.
3.3.1 Analysis and Eval'uation of the April 4, 1986 Event During the shutdown on April 4th, the mode switch was trans-ferred by an operator-in-training under direct supervision of the Nuclear Watch Er.gineer. The watch engineer " wiggled" the mode switch to " feel" that it was in the right position.
The mode switch key was not removed from the switch handle following the transfer.
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The operator who had transferred the mode switch ir. the control room prior to the April 4, 1956 scram, had not been trained on the 58-1 Model Switch at Pilgrim and had no previous experierice with it. Even though the watch engineer checked the position of the mode switch, it is n
possible that the switch was not actually in the correct position because the key was not removed (as a positive verification of proper pcsitioning) af ter this transfer.
In retrospect, inadequate training of the operator could have contributed to the event.
Following this event and in accordance with the recommenda-tions in SIL 155, an inspection of the Reactor Mode Switch was conducted at Pilgrim on April 5, 1986. No indication of cracking or broken contacts or of any other adverse con-dition was observed. Examination did indicate that proper preloading of the switch contacts existed.
In summary, the licensee concluded that the most probable root cause of this event was that at least two of the mode switch contacts (10, 26, 42 & 58) did not close or remain closed after the mode switch was transferred from "Run" to "Startup/ Hot Standby". Corrective actions taken as a result O
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11 of this event included development of a prescribed technique for transferring the mode switch and training of Operations personnel in its application.
- 3.3.2 Analysis and Evaluation of the April 12, 1986 Event As discussed earlier in this report, the containment isola-tion and reactor' scram on April 12, 1986 were similar to the April 4th event. However, on April 12, the scram oc-curred 30 to 40 seconds after the main steam line low pressure alarms came in. Also, on April 12, the transfer was performed by an experienced operator and the mode switch key was removed.
The licensee investigation team's evaluation of possible means by which the MSIVs could close was comprehensive. It considered loss of instrument air, failure of the MSIV's AC and DC solenoid valves, loss of AC and DC control power, strultaneous actuation of MSIV test switches or associated circuits, operation of MSIV hand switches, failure of reiays associated with the MSIV close circuit, and the PCIS logic circuits. The team analyzed available event data, s interviewed plant operators, reviewec past histcry for I I similar events, performed additional functional tests and calibration tests, conducteo special tests and conducted walk-downs of the associated systems.
Tne NRC inspectors reviewed test documents to assess their technical adecuacy, evaluated the safety consequences of these activities, and analyzed the test results to ascer-tain that the components functioned as intended. No signi-ficant problems were identified. Attachment 3 lists the tests reviewed and performed as of April 26,19E6.
During the performance of one test, surveillance test E.M.1-19, an unanticipated closure of the MSIVs occurred.
After the initial round of tests and analyses the licensee decided that the inadvertent closure of the MSIVs was due to actuation of the PCIS trip logic circuits. Based on the results of the tests conducted, it was further concluded that testing of the reactor mode switch was necessary. On April 19, 1986, a special test of the switch was conducted.
The test involved monitoring of the mode switch contacts in the suspect PCIS trip logic circuits and multiple operations of the mode switch in its various positions. To consider the human factors aspect of the mode switch operation, several operators were used in the manipulation of the switch. The switch was moved from the "Run" to "Startup"
/"'N position approximately thirty times during this test.
During this testing the contacts in the mode switch were instrumented in order to determine if they were opening and closing properly.
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Review of the mode switch special test data showed that the mode switch contacts in the PCIS trip circuits functioned -
consistently as designed. It could also be concluded that, discounting. random failures, the mode switch was not the root cause of the events of April 4 and April 12, 1986.
Following the mode switc'h test, the licensee's team con-centrated in identifying and testing for other potential failures affecting at least two channels of the PCIS trip logic circuits. Possible causes such as loose wires and terminations, voltage surges on circuit neutrals, ground circuit anomalies, and wiring errors during the recent replacement of RPS and PCIS relays were assessed through testing and inspection. Tnis testing and inspection did not confirm the cause of the unanticipated containment isolations.
3.4 Root Cause and Safety'Sionificance The~ licensee and its special teams are continuing their jnvestigation into the root cause of the inadvertent' closures of the MSIVs that occu. red on Ar,ril 4 and April 12, 1966.4 No root cause for the un-expected cor.tainment isolations had been identified at the conclusion of this inspection, although a mode switch failure was suspected. g Until a root cause is established, the possibility that these inad- W vertent closures could occur in any mooe of reactor operation cannot
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be ruled out. The safety function of the main steam isolation valves is to close when needed to isolate the reactor primary system.
Although inadvertent closure of tne MSIVs aligns the valves in their safe configuration, such closures are of concern for the following reasons:
- 1. Inadvertent closure can lead to a reactor trip, a turbine trip, an'd a loss of the normal heat sink;and normal pressure control of the reactor. l
- 2. Closure could cause challenges to safety-related systems such ,
as the main steam line safety and relief valves, the RPS, HPCI, l and RCIC. i i
.3. Closure could result in increasing the stress level of the opera-tors, as a result of the potential transients identified in !
l items 1 and 2 above.
3.5 Conclusions and Recommendations The licenses has worked hard to determine the root cause of inadver-tent closures of the MSIVs. However, the root cause or-causes of
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the proble'm have not been established as yet. Due to the concerns raised by the inadvertent closures of MSIVs, the root cause,should g e.
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'O be determined prior to restart of the unit or prior to operation under conditions where an unanticipated containment isolation could significantly challenge reactor safety systems or operators. i In addition, considering the important safety functions the mode switch performs, its operation should not be subject to an operator's
" feel", or a prescribed technique for its transfer operation. The !
licensee should continue to~ work on resolving these noted problems.
Licensee activities in this area will be evaluated in future inspections (86-17-01).
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14 4.0 EVALUATION OF MAIN STEAM ISOLATION VALVE (MSIV) PROBLEMS This section discusses the failure of the outboard Primary Containment Main. Steam Isolation Valves (MSIVs) to open upon demand following the reactor trips on April 4 and 12, 1986. For reference, a simplified drawing of an MSIV and an enlarged drawing of the valve pilot poppet assembly are inc.luded as figures 4.1 and 4.2 respectively. A list of procedures and other documents reviewed is included in attachment 4.
4.1 Chronology of Events On April 4,1986 at 8:15 p.m. , during a planned reactor shutdown, the reactor tripped due to all eight MSIVs closing (Group I Isolation). Following the trip, the operators reset the Group I Isolation signal and attempted to open the outboard MSIVs. The MSIV control switches were left in the open position for approximately one minute. During this time, the operators observed both red (open) and green (closed) position indication on the outboard MSIVs, however, the valves did not go full open. When the operators placec the con-trol switches to the closed position, they observed the valve indica-tion went green (full closed) in less than one secona. The inboard MSIVs were then successfully cycled open and closed. The High Pres-sure Coolant Injection (HPCI) system was used in the full flow test lineup to control reactor pressure which is the normal method of pressure control if the MSIVs can't be opened. Approximately one and g a half hours af ter the MSIV isolation was received the outboard MSIVs 3 opened upon demand.
The licensee considered four possible causes for the failure of the outboard MSIV's to reopen: 1) simultaneous mechanical binding of the four outboard MSIV's, 2) exce.ssive differential pressure acro >s the valves, 3) low instrument air pressure, and 4) loss of electrical control power. During the followup investigation, the licensee dis-covered a large air leak on the control system for the "A" outboard MSIV which continuously ported the under piston area of the MSIV air cylinder. During the repair of the air leak, debris (paper and yellow plastic) was found lodged in the pneumatic four way valve.
Some of the pieces of paper were folded, indicating that they wera manually placed in the controller rather than blown in from the in-strument air system. The entire air distribution manifold on the "A" outboard MSIV (last disassembled during the 1984 outage) was removed for cleaning. Inspections for debris were also performed on the "A",
the air distribution manifolds ofinboard "B" and "C" outboard MSIVs MSIVs with negative results.
as well as the "A", "C" and "D" The "D" outboard and "B" inboard MSIVs were not inspected as they had recently been worked'on. The licensee's evaluation of the source of i the debris was ongoirg during the AIT and will be examined during a i future inspection (8C-17-02).
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Following the inspections of the MSIV air system, testing was perform-ed to determine if reduced air pressure would preclude the MSIVs from achieving full stroke. The test results indicated that approxi-mately 40 psig supply pressure would open the MSIV one half inch, resulting in both red and green valve position indication and that full valve stroke could not be achieved when normal supply pressure was introduced slowly to the air cylinder. As no other problems were identified during the followup investigation, the licensee concluded that the failure of the oatboard MSIVs to open-upon demand was most likely caused by a lowered cylinder air supply pressure due to the leak on the "A" outboard MSIV. The reactor was restarted on April 10, 1986.
On April 12, 1986 at 1:56 am, during another planned shutdown, the reactor tripped due to all MSIVs closing. Approximately four and a half minutes after the MSIV closure, the operators reset the Group I Isolation signal and attempted to open the outboard MSIVs. As during the previous event, the MS.IV control switches were left in the open position for approximately one minute, operators observed both red and green valve position indication, and the MSIVs failed to open.
The control switches for the outboard MSIVs were placed in the closed position. Then with personnel stationed in the steam tunnel to ob-serve MSIV stem movement, operators made severa'l attempts to open only the "A" and "C" outboard MSIVs. In one case the MSIV control switch was left in the open position for approximately five minutes.
Personnel in the steam tunnel reported that, during the attempts to open the "A" and "C" outboard MSIVs, the, valve stem would travel ap-proximately one half inch and then stop. There was nc sound of steam flow wher the MSIVs stroked the one half inch. It was also observed that MSIV air cylinder supply pressure was normal.
Again, as during the April 4,'1986 event, the operators were able to ocen the inboard MSIVs (which were left open) and HPCI was used to control reactor pressure. Approximately one and a half hours after the Group I Isolation, the outboard MSIVs opened upon demand. The operators noted that the differential pressure across the outboard MSIVs was 30 psi when the valves were opened. Reactor pressure at that time was approximately 310 psig.
4.2 Valve Desien and Operation Valve Design The Main Steam Isolation valves, manufactured by Atwood and Morrill Company Inc., are 20 inch globe valves having a "Y" pattern body. The valves have 'a cylindrical main disc (poppet) moving in a centerline 45 degrees upward from the axis of the hori:cntal main steam inlet line.' An air cylinder is utilized p to operate the isolation valve. Air for the outboard valves -
C and air or nitrogen for the inboard valves is used to opers the
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valve while springs and/or air (nitrogen) close the valve. The air cylinder is capable of opening the MSIV with the design differential pressure of 200 psi across the main poppet. The MSIV also contains an internal pilot valve whose seat is in the middle of the main poppet. The pilot valve provides a means of i balancing the pressure across the main poppet, just before the l main poppet is lifted and while it is off its seat. The first i three quarters of an inch stem travel only opens the pilot poppet after which the main poppet is lifted off its seat. The total MSIV stem travel from full close to full open is nine and one half inches.
Due to a history of problems with leak tighi. ness and two valve stem failures in 1978 and 1982, the licensee modified all eight MSIVs during the sixth refueling outage, which ended in December 1983. These modifications included: new main poppets with an elongated peppet nose to position the poppet in a proper seating position; increasing stem diameter and fillet radius on the backseat surface; addition of main poppet anti-rotation devices; and addition of self-aligning pilot poppets.
Valve Operation Opening MSIVs with the reactor pressurized, such as following a Group I Isolation, is described by procedure.
sequence requires that all the outboards MSIVs be opened first Basically the lll
] to allow trapped condensation to drain. The outboard valves should open after the pilot poppet reduces the differential pressure across the main poppet to within 200 psi. The steam line drain valves (numbers MOV 220-1, MOV 220-2 and MOV 220-3)
.are then opened to equali.ze pressure across the inboard MSIVs.
When the differential pressure across the inboard MSIVs is within 50 psi (administrative limit), as measured between reactor pressure and main steam pressure upstream of the turbine stop valves, the inboard MSIVs are opened and the drain valves are shut.
4.3 Investigation Following the MSIV isolation and reactor trip on April 12, 1986, the licensee formed a multi-disciplined team to investigate and determine the cause of the outboard MSIV failure to open upon demand. Activi-ties of the team were observed by the NRC inspectors who found that the evaluation team performed a detailed review and analysis of the MSIV problem. Actions taken by the team included: bringing a valve vendor representative onsite to review valve characteristics; operator interviews; review of surveillance test data; review of all previous s trip reports for similar events; system walkdowns; identification and l discussions of potential causes; and contact with the Institute of Nuclear Power Operations and other utilities to identify similar occurrences at other facilities.
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-The evaluation tear identified the following seven possible causes for the failure of the MSIVs to reopen: electrical failure; air supply problems; all pilot poppets broken off; insufficient time allowed by operator for area above main poppet to bleed off; inboard MSIVs leaking so that the differential pressure across outboard M5IVs could not be reduced to less than 200 psi; mechanical binding of main poppet; and mechanical binding of pilot poppet. Based on system walkdowns, functional tests, etc., the team concluded that the most probable cause of the outboard MSIVs failure to open upon demand was the pilot poppet becoming detached from the valve stem.
Prior to the sixth refueling outage, during which the MSIVs were modified, the pilot valve was an integral part of the MSIV stem. No cases were found, prior to this outage, where the MSIVs could not be opened following an isolation with the reactor pressurized. Follow-ing the modifications and plant start:up in December 1983, only three MSIV isolations occurred with the reactor pressurized. Two of the three were the events of April 4 and 12, 1986 during which the out-board MSIVs would not open upon demand. The third event occurred during a planned shutdown on June 15, 1985. However, in this case no attempt was made to reopen the MSIVs.
The modification to the MSIV pilot valve involved installation of a O "fleatin9" niiet nennet. 18e de isn wes intended to previde a laterally floating pilot poppet to improve leakage characteristics and reduce MSIV stem bending stresses. As seen in Figure 4.2, the 4 pilot poppet is attached to the stem by threading the poppet onto the pilot poppet nut which is held on the stem by the split retaining ring installed in the stem groove. A set screw is installed and staked into the pilot poppet to prevent the poppet from unscrewing itse.lf fron. the pilot poppet nut.
The evaluation team developed a test to verify their conclusion that the pilot peppet had become disconnected from the stem. The test consisted of pressurizing the volume between a pair of MSIVs to 23 psig and then slowly increasing the air supply pressure to the out-board MSIV air cylinder to slowly open the valve. Expected results would be that within the first three quarters of an inch stem travel the pilot poppet should lift and depressurize the volume between the '
MSIVs. After three quarters of an inch stem travel (the limit of pilot poppet travel) the main poppet would open to depressurize the volume between the MSIVs. The inspector reviewed the test procedure to verify it was technically adequate and approved by the Operations Review Committee. In addition, the inspector observed the test per- -
- formed on the "A" outboard MSIV. The results of this test clearly indicated that the pilot poppet was not attached to the valve stem.
Similar tests were run on the remaining outboard MSIVs and, although the results were not as definitive, there were indications the pilot poppets were not opening as soon as expected.
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Based on the test results, the licensee disassembled all eight MSIVs for inspection. The results of these inspections were: on two MSIVs
("A" outboard and "C" inboard) the pilot poppets were detached from the valve stem; on the "0" outboard MSIV the pilot poppet became de-tached during MSIV disassembly; three other pilot poppets ("D" inboard, "B" and "C" outboard) had started to unscrew themselves from the pilot poppet nut and exhibited 3/8 to 5/16 of an inch axial play; and the remaining two MSIVs' ("A" and "B" inboards) had the pilot l
poppet fully engaged to the pilot poppet nut. In those cases where the pilot poppet had started to unscrew itself, the threads on the poppet and nut were damaged.
Prior to disassembly the licensee also performed Local Leak Rate Testing (LLRT) of all MSIVs. The results of the LLRT are included in the following table. Leakage rates are in standard liters per minute (sim).
MSIV .
Leakage "A" inboard (IA) 44.5 slm "A" outboard (2A) 5.5 slm "B' inboard (18) 23.2 slm "B" outboard (28) 2.8 slm "C" inboard (IC) 4.03 slm "C" outboard (2C)
"D" inboard (1D) 0.47 slm 33.5 sim ll) g "D" outboard (20) 8.5 slm The inspector noted that the Technical Specification limit for valve leakage is 5.43 sim. However, the inspector also noted that the measured leak rates were significantly lower than those from the two previous LLRTs.
4.4 Root Cause and Safety Significance The cause of the outboard MSIV failure to open upon demand was the pilot poppets becoming detached from the valve stem or inhibited from fully opening so that the differential pressure across the main poppet would prevent the MSIV air cylinder from opening the valve.
At the end of the AIT inspection the cause for the pilot poppets becoming unscrewed and/or detached from the pilot poppet nut was still under analysis by the licensee to determine if it was due to an installation error or design error. However, it was clear that the set screw did not prevent the pilot poppets from unscrewing from the pilot poppet nut.
Subsequent to the AIT inspection the licensee concluded that the lack of positive set screw engagement was due to an inadequate installation procedure coupled with the absence of a torque requirement between the pilot poppet and poppet nut allowing imposed rotational / vibrational forces to unscrew these assemblies.
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Analysis by the licensee is ongoing to ensure that, with the problems identified, the MSIVs met the safety. design basis as stated in the Final Safety Analysis Report. However, the safety objectives of the MSIVs are to close to limit the loss of reactor coolant and limit the release of radioactive materials. The design of the valve is such that apparently even a detached pilot poppet cannot become dis-lodged and prevent the MSIV from fulfilling the safety objective.
This was reinforced by the tLRT results. Nonetheless, failure of the valves to reopen did result in using a safety system to control reactor pressure and temperature and presented additional challenges to the reactor operators. In addition, based on this event and on reports from other facilities, there may be generic safety implica-tions with regard to the use of set screws.
4.5 Conclusions and Recommendations The MSIV evaluation team did a thorough job in identifying the cause for the MSIVs failing to open on demand. Based on the observations and testing performed during the first event of April 4,1986, the inspector could not fault the licensee for not identifying the prob-lem then. Also, based on the LLRT results, it appears that the MSIV modifications have significantly reduced the valve leakage problems noted previously.
The licensee should continue the root cause analysis, to identify why the set screws did not prevent the MSIV pilot poppets from unscrewing off the poppet nut in order that a permanent fix can be implemented.
The corrective actions including proposed design changes will be evaluated when they are available (86-17-03).
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5.0 EVALUATION OF LpCI INJECTION VALVE LEAKAGE 5.1 Chronology of Events Tables 5.1, 5.2, and 5.3 summarize the chronology of events signifi-cant to the RHR valve leakage question. The events begin with the pulling of control rods on April 10, 1986 and end with the securir.;
from the Unusual Event (declared as a result of RHR valve leakage) on April 12, 1986.
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At about 10:00 a.m. on April 10 after reactor pressure was increased to about 500 psig, the "B" RHR Rosemount flow transmitter indicated an increase in pressure was occurring in the RHR system. Normal system pressure is 105 psig controlled by the keepfill system via a connection from the condensate transfer system. Though no pressure indicator exists for the segment of piping in question, the flow transmitter was determined to be pressure sensitive; as pressure in-creases the "B" RHR flow indicator is driven negative. This anomaly was substantiated by the inspector by observation, discussion with I
control room operators, and by a contact made with the meter manufac-turer, Rosemount, Inc. The flow transmitter reading is charted in the control room and thus a permanent record exists that records all of the pressurization events that have occurred. At approximately 11:00 a.m. th? "RHR Discharge or Shutdown Cooling Suction High Pressure" alarm (hereafter referred to as RHR Hi alarms) sounded, indicating pressure of about 400 psig. This alarm had been frequent-ly received in the past. The alarm response procedure requires the operator to diaonose the source of the leakage and to depressurize the system by opening valves that lead to the torus. A number of closely spaced RHR Hi alarms were subsequently received, approximately once every fifteen minutes. In the afternoon the alarms continued to be received, approximately once every half hour. During this time the unit was placed on the line as the normal startup continued.
During the afternoon and into the night maintenance personnel at-tempted to control the RHR leakage by increasing the closing torque on Valve 29B, this valve was diagnosed as the leaky valve because the outboard piping was hot to the touch. The valve torque was increased three or four times, each time the second MOV (288) was closed and 29B opened then torqued closed, after which 28B was reopened. Ad-justing the closure torque to its highest allowable design value had no affect on valve leakage.
At 2:15 p.m. on Friday, April 11, a decision was made by the operating staff to close valve 28B in an attempt to stop the leakage. This required that the plant enter a seven day LCO. Several hours after the closure of 28B the RHR Hi alarm.again sounded indicating that the leakage continued. As both the MOV's appeared to leak the possibility of violating containment integrity forced the operating ~ staf f to de-clare an Unusual Event and start a slow, controlled shutdown of the g plant. The shutdown was subsequently speeded up after discussions w with NRC and by the next morning the reactor was in cold shutdown.
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. -s 5.2 RHR Isolation Valve Descriptions Three valves form the isolation barrier between the high pressure reactor coolant and the low pressure piping of each of the two RHR loops. Figure 5.1 shows a schematic of the RHR loop B isolation valves. The three isolation valves are:
Valve 68B A Rockwell, 900 lb.,18" testable, tilting disc, 316ss, check valve. The valve has been modified by the removal of the posi-tion indication and air cylinder that provided the testability feature. Thus, the valve is now a simple check valve. The valve was once required to undergo containment leak testing but was taken off the Appendix J list via an exemption granted by NRC in 1977.
Valve 29B A 600 lb.,18" x 14", 316ss, gate valve rated for 1250 psig at 586 degree F. The valve is operated by a limitorque motor opera-tor controlled from the control room. The valve will automati-cally open in the event of a LOCA in combination with a reactor pressure less than 400 psig. The valve is interlocked with
~3 valve 28B preventing the inadvertent opening of both valves when (d reactor pressure is greater than 400 psig. The valve is required to undergo local leak rate testing as part of the containment 2
integrity program.
Valve 28B A 600 lb., 18", 316ss, globe valve with a plug type disc, rated for 1250 psig at 58.6 degrees F. This valve is operated by a limitorque motor operator controlled from the control roca. As with 298, it is sent an automatic open signal in the event of a LOCA in combination with a reactor pressure of less than 400 psig. The valve can be throttled by manual control room operation for flow control purposes. The valve is required to undergo local leak rate testing as part of the containment integrity program (it has replaced valve 688 as the second iso-lation valve for the purpose of containment integrity).
Design requires one of the two motor operated valves be closed during normal standby. Valves 28A and 288 of the two loops were the original valves to be kept closed. In early 1986, leakage past 288 began causing RHR Hi alarms. At that time, the valve was judged to have, remained within LLRT leakage limits by trending of past leak tests, but to eliminate the RHR Hi alarms it was decided to operate with 298 as the closed valve. This change took place on February 26, 1986. The A loop valves were left as is'with 28A being the closed MOV in that loop.
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5.3 Past Syste: Leakace Exoerience The RHR Hi alarm indicative of RHR isolation valve leakage has been received in the past. The most recent period in which RHR Hi alarms were received prior to April 10 began on January 10, 1986 and con-tinued through February 26, 1986 (the day that Valve 298 replaced valve 28B as the normally closed valve). During this period the average time between RHR Hi* alarms was about 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br />. From February 27, 1986 through March 8, 1986 no alarms were received.
Th? reactor was then shutdown until April 10 as a result of leaks found in the Head Spray and Reactor Level Instrumentation systems.
I The inspector made a bounding calculation in attempt to estimate a conservative value of the amount of leakage from the valves by ob-taining the time and quantity of torus water that had been trans-ferred to the rad waste tanks for processing. B Ncen January 10
- and February 27 a total of 81,500 gallons of tor us water had been pumped. Since the reactor was at pressure for 47 days during this period the estimated leak rate of between one and two gpm is calcu-lated. As there are other sources of water draining to the torus, e.g., HPCI turbine pump exhaust, this estimate should be considered as a high bound for the leak
- ate. Also this calculation assumes I that torus level at the beginning and end of the period was the same. Though there is a chance of error in this calculatirn, it provides some evidence that the isolation valve leak rate was not substantial during the January 10 - February 27 time period.
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5.4 History of RHR Vaive Refurbishment ar.d Leak Testing 5.4.1 Check Valve 68B Valve 655 was disassembled and rebuilt in May-June 1984.
The inspector reviewed the rebuilding documentation and interviewed the engineer and technicians that worked on the valve. In addition, the valve design was reviewed to judge if the internal components provided reliable support of the disc. The visual inspections upon disassembly in-dicated that the valve internals were acceptable, other than a light lapping of the valve seating surfaces no component degradation was noted. T_he cover nuts and bolts were found not to be acceptable and were replaced. As the valve is no longer on the Appendix J valve list no leak test was performed. Only a visual bluing technique was used to assure that the seating surfaces were in full contact. The fact that the valves as-found condition was generally acceptable and that the design of the valve disc and hinge is substantial, with little chance of misposition-ing of the disc, provided evidence to the inspector the Valve 68B would reliably perform its closure function. As will be discussed in Section 5.5, a significant pressure g differential, which forces the seating surfaces together, w
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is required to tightly seat the valve. However, without a pressure differential, as is the normal case with one of the MOVs closed, the check valve is likely to provide no additional resistance to leakage flow.
5.4.2 Globe Valve 288 In early 1986, this valve was diagnosed as leaking. At that time it was predicted that the valve leak rate was still within the 7.89 standard liters per minute (sim)
- ~~
Appendix J limit for a single penetration., The iocal leak rate testing of Valve 28B is as follows:
1980 - As found 0.1 sim, as left 0.2 sim 1982 - As found 0.5 sim, as left 0.5 slm 1984 - As found 1.9 sim, as' left 1.9 slm Utility staff ca.lculated that (assuming an exponential trend) a valve leak of 4.8 slm would be predicted for early 1986. It was then concluded that the valve, though leaking, was still acceptable. No other mechanical problem with the valve was identified with one exception; electrical main-tenance personnel had found that the closing amperages of O the valve were not initially repeatable. This led to the disassembly and inspection of the motor operator, no abnormalities were found. .
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5.4.3 Gate Vaive 29B This valve has a history of failing the local leak rate testing (LLRT). Th,e valve failed its LLRT on January 7, 1984 and again on October 11, 1984. Based on an interview with the valve maintenance contractor representative, the valve has a design deficiency that makes it difficult to maintain low leakage over a long period of use. The distance between the bottom of the valve wedge and the bottom of the valve housing is only 3/16 inch. As the !
seating surfaces wear the wedge must drop lower and with enough wear will bottom out on the housing. During last November the wedge was removed and the seating surfaces built-up and ground smooth. The post maintenance LLRT done on November 29, 1984 resulted in zero leakage, so at that time the valve was leaktight. As indicated previously this valve replaced valve 28B as the normally closed valve on February 26, 1986. The valve has been considered for replacement, but no hard schedule exists.
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5.5 As-Found RHR Walkdown and Valve Leak Measurements During the period between April 13 and April 19 extensive RHR system walkdowns and isolation valve leak measurements were conducted. NRC
! inspectors observed these activities. The following summarize the findings of these efforts.
5.5.1 System Walkdowns An as-found visual inspection of the RHR "B" loop system piping, components, and structural supports was planned.
The inspection was to determine if any adverse effects had resulted from the isolation valve leakage or possible water hammer events associated with depressurizing the piping after the RHR Hi alarm annunciated or as a result of recent events involving water hammer events of the head spray piping. Evidence of overheating, overpressurization, or piping / component movement was of most interest. The utility sttff's planning and conduct of the walkdown was careful and detailed. Grywell, "B" RHR quadrant, and torus room entries were made and potential defects for each pipe segment, component, and support was documented. No defects were identified which could be associated with thermal, overpressurization, or component movement, thus it was determined that no visual evidence existed suggesting any adverse conditions as a result of the isolation valve h
] leakage.
5.5.2 Water Leak Measurements A special water leak rate test was designed that would simulate reactor water pressure on the reactor side of valve 688. The test was conducted to determine the amount of water leakage associated with the as-found valve condi-tion. Thus the leak rate of the check valve 688, the closed gate valve 29B, and the closed globe valve 288, in series with one another, was to be determined. In addi-tion, the test continued until pressurization of the RHR piping was achieved and the RHR Hi alarm sounded in the control room. Each segment of piping between the isolation valves and between valve 288 and the RHR pump check valve was monitored for pressure.
The test was conducted on April 17, 1986. The normally locked open manual valve, 338, near the reactor was closed and water pumped between it and valve 688. Table 5.4 sum-marizes the test results'as recorded by the NRC inspector.
The pressure between valves 33B and 6SB was increased to 300 psig. The technician found it difficult to hold pres-sure constant. At one point the pumping was stopped com-pletely for several minutes and then varied between 10 and
_ _ _ ~
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't 25 (3
V 20 ' strokes / minute. An air operated positive displacement water pump was used. It became apparent to the inspector that as the technician increased pressure, valve 688 became an effective barrier until such time as the pressure dif-ference across the valve equalized, after which the valve had no affect. The pressure was increased to 600 psig and then to 950 psig. It was held at 950 psig for 95 minutes at which time the'RHR Hi alarm sounded in the control room.
DuH ng this period the pump flow rate, on average, was about 1/2 gpm.
5.5.3 Appendix J Measurements After the water test was concluded, the RHR piping was drainec and the air testing was conducted on April 18, 1986 for each of the three valves. Even though an LLRT is not required for 68B an informational test was conducted. The following are the.LLRT results of the as-found valves:
68B - 76 standard liters per minute 29B - 1.0 standard liters per minute 28B - 1.5 standard liters per minute 5.6 Roct Cause and Safety Significance
( ])
The root cause of the RHR Hi pressure alarms was an approximate 1/2 gpm water leak past the loop "B" RHR isolation valves in conjunction witn apparently relatively leak tight RHR pump discharge check valves. This condition caused a build up in pressure in the inter-vening pipe segments to about 390 psig resulting in the alarm. There was no indication that the potential for sudden failure of all three isolation valves and resultant sudden overpressurization of the RHR piping existed.
Prior to the decision to shutdown, the operating staff could not know the extent of isolation valve leakage and their decision to shutdown was a good one. Though the low leak rate of the isolation valves poses no safety problem, the inability of the operating staff to determine significance due to instrument and procedural inadequacies should be addressed. In addition greater utility attention should be focused on the isolation function of valves that protect low pressure ECCS systems from the high pressure reactor coolant.
5.7 Conclusions and Recommendations The licensee did a thorough job in evaluating the LPCI injection valve leakage and recurring RHR pressurization events. The low leak rates which were measured'do not pose a safety problem. However, continued e- ~ power operation with the recurring pressurization of the RHR piping
(_,3) and the resultant RHR High Pressure Alarm is unsatisfactory because
- 1) the operator's attention is frequently drawn to an alarm.that has.
3 26 h
uncertain and undefined operational / safety significance, and 2) the excessive cycling of the two safety related isolation MOVs (valves 34B and 368) used to vent the pressure to the suppression pool contri-butes to premature wearout of these valves. The licensee should eliminate the cause of the recurring pressurization of the RHR piping.
In addition, several areas were identified where improvements are needed to ensure the significance of similar events in the future can
~
be determined and/or minimized. These include: periodically verify-ing that the LPCI injection check valve properly seats with a dif-ferential pressure across the valve; installation of pressure monitor-ing equipment on the RHR piping; and development of a method to ouan-titatively measure the LPCI injection valve leakage during reactor operation. Licensee activities in this area will be reviewed in future inspections (86-17-04).
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6.0 OVERALL
SUMMARY
AND CONCLUSIONS The AIT reviewed three recent operational problems at Pilgrim: 1) the
.sputi ous.. group-one primary containment isolation on April 4 and 12,1986,
- 2) ths failure of the main steam line isolation valves to open after the isolations, and 3) recurring pressurization events in the residual heat removal (RHR) system.
The team noted that the licensee's problem solving approaches were carefully structured and appeared thorough. In addition, the team drew the following conclusions for the three areas of concern:
-- No root causes for the spurious primary containment isolations on April 4 and 12, 1986 were identified during the inspection period, despite considerable licensee. effort. The team did not identify any weaknesses in the licensee's problem solving approach.
The failure of the outboard main steam line isolation valves (MSIV) to re-open following the containment isolations on April 4 and 12 was caused by partial or complete mechanical separation of the valve pilot poppets from the MSIV valve stem assemblies. Pilot poppet set screws did not prevent the poppets from unscrewing from the stem assemblies.
' -- The RHR pressurization events reflect slow leakage (about 0.5 gpm) past a check valve and two motor operated injection valves in the h "B" RHR loop. Lack of RHR pressure instrumentation and the lack of periodic tests of the RHR injection check valves inhibit a more thorough diagnosis. No apparent RHR valve failure mechanism has been identified as the reason for this leakage.
-- The licensee's conduct of the reactor shutdown on April 11 and 12, 1986, was prudent in light of the recurring RHR pressurization ~
events.
The licensee's root cause evaluations were not completed and corrective actions were not finalized during the AIT inspection. NRC review of these actions should be conducted prior to startup from this outage.
Based on the AIT review, the first four items in CAL No. 86-10 have been completed. The fifth and final item will be closed when the licensee submits a written report on the three areas of concern to the Regional Administrator and the Administrator authorizes reactor restart.
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TABLE 5.1 - EVENTS OF THURSDAY APRIL 10, 1986 Plant RHR System Time Conditions Conditions Comments 0246 Started pulling RHR in standby with Reactor rods cross connect open startup between A & B loops. begins Pressure at 105 psig provided by keepfull system.
0345 Critical 0700 300 psig s
11% steam flow 1000 500 psig RHR flow cnart in-12% stear flow dication showing pressure rise in RHR piping.
1100 660 psig RHR Hi alarm; 6 alarms First alarm llh 12% steam flow once every 15 mins. indicated on RHR f
flow chart, no log entry.
1200 >900 psig Reactor at 12% steam flow . pressore.
1300 Turbine Rolling RHR Hi alarm; 4 alarms, once every 30 mins.
1336 Unit on Line l
1500 STA log -
indicates look-ing into valve 29B leakage i 1600 NWE Log (1600 to l 2400) -
maintenance is l
torquing up valve 29B 1800 RHR Hi alarm; 4 alarms, once every 30 mins.
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Plart RHR System Time Conditions Conditions Comments 2200 No RHR Hi alarms between 2200 and 0200 2400 Reactor near 100*. steam flow O
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TABLE 5,2 - EVENTS OF FRIDAY APRIL 11, 1986 Plant RHR System Time Conditions Conditions Comments 0200 RHR flow test Checks opera-bility of all four RHR pumps 0219 RHR Hi alarm First notation of RHR Hi alarm found in control room log 0315 RHR Hi alarm 0336 "B" RHR loop in torus Pressurization cooline mode of RHR ore-vented when loop open to torus 1115 t.HR secured from torus cooling 1158 RHR Hi alarm 1
1415 RHR Hi alarm; valve Declared LPCI 28E closed, both loop "B" inoperative MOVs (28B & 248) no closed 1653 RHR Hi alarm 1710 Initiated a con- Declared an trolled shutdown Unusual Event, steam flow decrease notified NRC rate of 5% per hour 2000 960 psig, steam flow decrease rate increased to 30% .
per hour l I
2200 930 psig, 33% (
steam flow 2215 pj RHR Hi alarm Notified NRC O
. _ _ _ _ . _ _ _ _ _ . _ l
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31
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l TABLE 5.3 - EVENTS OF SATURDAY, April 12, 1986
.a Plant RHR System Time Conditions Conditions Comments 0030 Turbine off line 0136 Out of run mode I
0200 HPCI in recir- Initiate torus cooling culation mode mode of RHR for reactor pressure control 0215 Significant pressure -
reductice begins 0400 <100 psig 0645 Out of torus cooling RHR loop A placed in shutdown cooling mode 1 0908 Reactor Secured from
<212 degrees F Unusual Event l
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Table.5.4 Summary of Water Leak Test Data Recorded By Inspector April 17, 1986 Approximate Pump Strokes Pressure Between Valves, PSIG
-- T i me Per Minute 338/688 68B/298 298/28B 28B/ Pumps Comments
~ 1500 0 22 25 65 104
- 1510 0-20 300-500 290 100 104 5 min after reaching 300
- 1520 0-20 600-700 575 330 145 10 min after reaching 600 1540 0-20 950 - - -
1606 4-8 950 950 700 185 1715 4.75 975 975 725 375 to 380 RHR Hi Alarra received lll a Note: 4.75 pump strokes per minute is equivalent to ~h gpm.
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34 FIGURE 3.2 REACTOR MODE SWITCH
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NUCLI AH RFGUL ATORY COMMISSION ATIACFXCII 1 REGION I
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CAL No.: 86-10 Docket Number: 50-293 Boston Edison Company M/C Nuclear ATTH: Mr. William D. Harrington Senior Vice President, Nuclear 800 Boylston Street Boston, Massachusetts 02199 Gentlemen:
Subject:
Confireation of Actions to be Taken with Regard to the Pilgrim Plant Events Which Occurred on April 11-12, 1986 Pursuant to our telephone conversation on April 12, 1986 with Mr. Oxsen it is our understanding that you have' taken or will take the following actions:
- 1. Maintaia all affected equipment related to the events which occurred on April 11-12, 1986 in its as-found condition (except as noressary to maintain the plant in a safe :,leutdown condition) in p order to preserve any evidence which would be needed to inspect d or reconstruct the events.
- 2. Develop troubleshcoting plans and procedures and provide those to
) the NRC Augmented Inspection Team (AIT) for their review and comment prior to initiating any troubleshooting of the af fected equipment.
- 3. Advise tne AIT leader prior to the conduct of any troubleshooting activities.
- 4. Make available to the NRC AIT relevant written material related to previous problems with the af fected equipment.
- 5. Provide a written report to the Regional Administrator prior to restart that contains your evaluation of the following:
- a. Intersystem leakage through the motor-operated injection valves (including the check valve) of the residual heat removal system;
- b. The ' primary containment isolation which occurred during ' _"
shutdown after the reactor mode switch was repositioned from the run mode to the startup mode; .
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- c. The failure of the outboard main steam isolation valves to reopen af ter resetting the primary containment isolation signal.
lll lhis report should include the underlying causes for the -above noted events, an assessment of their relationship to previous events including the events of April 4,1986, corrective actions taken and your basis for restart, including the criteria used and your analyses associated with these criteria.
Further we understand that restart will not occur until you receive authoriza-tion from the Regional. Administrator.
If your understanding of the actions to be taken are different thyn those described above, please contact this of fice within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of the receipt of this letter.
Thank you for your cooperation.
Sincerely, I
8 Thomas E. Marley( "-
Regional Administrator cc: L. Oxsen, Vice President, Nuclear Operations llh
, C. J. Mathis.eStation Manager Joanne Shotwell, Assistant Attorney General Paul Levy, Chairman, Department of Public ' Utilities Plymouth Bcard of Selectmen Plvmouth Civil Defense Director Se'nator' Edward P. Kirby Public Document Roorg (PDR) local Public Document Ruom (tPDR)
Nuclear Safety .information Center (MSIC)
NRC Resident Inspector Commonwealth of Massachtsetts (2) r P
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m ATTACHMENT 2 PERSONS CONTACTED The following is a partial listing of the licensee personnel that were contacted during the inspection.
W. Harrington, Senior Vice President, Nuclear L. Oxsen, Vice President, Nuclear Operations (Senior Licensee Manager Present at the Exit Interview)
C. Mathis, Nuclear Operations Manager P. Mastrangelo, Chief Operating Engineer K. Roberts, Director Outage Management N. Brosee, Maintenance Section Head .
T. Sowdor., Radiological Section Head J. Seery, Technical Section Head E. Ziemianski Management Services Section Head S. Wollman, On-Site Safety and Performance Group Leader R. Sherry, Chief Maintenance Engineer 79 E. Graham, Compliance and Administrative Group Leader
\s./ P. Smith, Chief Technical Engineer W. Clancy, Nuclear Engineer, FS and MC Group Leader
- T. McLoughlin, Nuclear Operations Sr. Electrical Engineer A. Morisi, Operations Assistant to Director of Outage Management b
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ATTACHMENT 3 Tests / Checks Performed During Mode Switch /PCIS Investigation The licensee perfo~rmed the following tests / checks of tne PCIS components, including the reactor mode switch. The mode switch testing was performed in all four mode positions under various human factor scenarios i.e.,
with and without key removed, pulling up or pushing down while turning the mode switch, etc.
- Surveillance Test Procedure 8.M.2-1.5.3.1, 2, 3, and 4 Primary Con-tainment Isolation Logic Channel Test - Channels A-1, A-2, A-3, A-4, respectively Revision 6; performed on April 14, 1986.
Inspection of contacts of the PCIS relays in Channels A-2, A-2, B-1 anc B-2, ir, accordance with Procedure 3.M.3-8, inspection / Trouble Shooting - Electrical Circu.its, Revision 6, performed on April 14, 1986, along with the above 4 PCIS Logic Tests.
- Surveillance Test Procedure 8.M.1-19, Reactor Water Level (RPS/PCIS), ,
Revision 13; performed on April 15, 1986. (While performing this l test, an inadvertent closure of the MSIVs and steam line drain valve MO-220-2 occurred)
Trouble Shooting Procedure for the investigation of inadvertent O g
closure of MSIVs and MO-220-2 during performance of the above Sur-veillance Test Procedure (8.M.1-19) on April 15, 1986; performed in accordance with procedure 3.M.3-8 on April 15, 1986.
Surveillance Test Procedure 8.M.2-1.4.4, Main Steam Line Low Pressure, Revision 5, performed on April'16, 1986.
Trouble Shooting Procedure to check out the AC and DC solenoid circuits of the MSIVs, performed on April 17, 1986.
Temporary Procedure TP86-59, Mode Switch Test for Steam Line Low Pressure Bypass, Revision 0; performed on April 19, 1986.
Trouble shooting procedure 3.M.3-8 to check out the effect of vibra-tion on reactor vessel level Yarway level indicating switches;
. performed on April 21, 1986.
Trouble shooting procedure 3.M.3-8 to confirm the vibration effect observed during the above test; performed on April 21, 1986.
Trouble shooting procedure 8.M.1-19 to investigate the cross channel interaction of relays suspected during the performance of the above two tests; performed on April 21, 1986.
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Trouble shooting procedure 3.M.3-8 to investigate the vibration / cross channel interaction observed as the April 21, 1986 testing; performed on April 23, 1986. -
- Trouble shooting procedure 3.M.3-8 to check out the contact resis-tances of the relays in the PCIS trip circuitry, performed on April 23, 1986.
< - Surveillance test procedure 8.M.2-1.4.3, Main Steam Line High Flow, l Revision 1; performed on April 24, 1986.
- Surveillance Test Procedure 8.M.1-12, Main Steam Line High Radiation, l Revision 11; performed on April 24, 1986.
Temporary Procedure TP 86-68, Mode Switch Resistance, Revision 0; performed on April 24, 1986.
Trouble shoottig procedure,3.M.3-8 to check out loose wire in the PCIS circuitry and the RPS grounding connection; performed on April 24, 1986.
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ATTACliMENT 4
- I5k DOCUMENTS REVIEWED Plant Design Change Request No. 83-48, "MSIV Refurbishment", dated October 5, 1983 Atwood and Morrill Co. Inc. , " Instruction Manual for 20" Main Steam
~~
~~ Isolation Valves".
Procedurt No. TP 86-61, "MSIV Plot disassociation Test", Revision 0, dated April 17, 1986 Procedure No. 2.2.92, " Main Steam Line Isolation and Turbine Bypass Valves", Revision 15, dated May 8, 1985 Procedure No. 8.7.4.4, "MSIV Trip", Revision 12, dated January 30, 1986 O
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',(J3 NAY 1 6 1985 Docket No. 50-293 Boston Edison Company M/C Nuclear ATTN: Mr. William D. Harrington Senior Vice President, Nuclear 800 Boylston Street Boston, Massachusetts 02199 Gentlemen:
Subject:
Inspection Report No. 50-293/86-17 During the period April 12 through April 25, 1986, an Augmented Inspection Team (AIT) conducted a special safety inspection of recent operational events at the Pilgrim Nuclear Power Plant. These events included 1) the spurious group-one primary containment isolations (and associated reactor scrams) that occurred on April 4 and 12, 1986, 2) the failure r of the main steam line isolation valves to promptly reopen after the containment isolations, and 3) recurring pressuriza-tions of the residual heat removal system. The inspection results are docu-mented in the enclosed report and.were summarized at the conclusion of the in-spection in a meeting with your staff. This report identifies several areas for improvement that warrant your consideration.
d Although your evaluations following the April 12, 1986 containment isolation (and scram) were carefully structured and appeared thorough, the underlying. -
- reasons for some of the problem are not yet fully understood. In particular, the reasons for the spurious containment isolations have not been determined.
Similarly, although we understand the technical reason for failure of the Main Steam Isolation Valves (MSIV) to reopen after closure, we need to better under-stand the design review and implementation process associated with the modifi-cation in 1983 that resulted in the MSIV problem. In accordance with Confirma-tory Action Letter No. 86-10, we await', submittal of your report documenting the results of the efforts taken to identify the root cause of the subject events and proposed corrective actions. After receipt of your report, we will review it and schedule a meeting, if necessary, to discuss any questions or concerns that we may have.
Your cooperation with us is appreciated.
Sincerely, n
l M- L Richard Starostecki, Director 1l-Division of Reactor Projects -
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Enclosures:
Augmented Incident Response Team Report i
+
1 Boston Edison Company M/C Nuclear 2 cc w/ encl:
L. Oxsen, Vice President, Nuclear Operations C. J. Mathis, Station Manager Joanne Shotwell, Assistant Attorney General Paul Levy, Chairman, Department of Public Utilities Plymouth Board of Selectmen Plymouth Civil Defense Director Senator Edward P. Kirby Public Document Room (PDR) local Public Document Room (LPDR)
Nuclear Safety Information Cent ~er (NSIC)
NRC Resident Inspector Commonwealth of Massachusetts (2) bec w/ encl:
Region I Docket Room (with concurrences)
Management Assistant, DRMA (w/o encis)
" T. Murley, RI J. laylor, OE R. Bernero, NRR J. Heltemes, AEOD W. Kane, RI .
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