ML20148K944
| ML20148K944 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 03/09/1988 |
| From: | NRC COMMISSION (OCM) |
| To: | |
| Shared Package | |
| ML20148K935 | List: |
| References | |
| NUDOCS 8804010078 | |
| Download: ML20148K944 (173) | |
Text
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UNITED STATES NUCLEAR REGULATORY COMMISSION In the !!atter of:
!!EETING:
NRC & TVA re:
Part 50, Appendix R Issues Pages:
1 through 120 Place:
Rockville, Maryland Date:
Ilarch 9, 1988
..............................................u............
F HERITAGE REPORTING CORPORATION ories.i n. porter 1220 L Street, N.W., Suke 644 Washington, D.C. 20005 (202) 628-4884 8804010070 880309 PDR ALdCK 05000327 F
3 1
1 UNITED STATES NUCLEAR' REGULATORY COMMISSION l
2 l
In the Matter of:
3 MEETING:
NRC & TVA 4
re:
10 C.I.a. Tart 50, Appendix R Issues 5
Wednesday, 6
March 9, 1988 7
Room 8-B-11 11555 Rockville Pike 8
Rockvil:e, Maryland 9
The above-entitled matter care on.for hearing, pursuant to notice.
10 MEETING ATTENDANCE:
11 From the NRC 12 T.P. Gwynn 13 C.L. Miller George Hubbard 14 David Notley Dennis Kubicki 15 B.D.
Liaw E.C.
Marinos 16 Charles Ader George Felgate 17 E.C. Gilbert C.E. Mullins 18 S.D.
Ebneter Pete Hearn 19 Jack Scarborough Steven West 20 R. Aulnek Steven Richardson 21 Rex G. Wescott Robert C. Pierson 22 Thomas S.
Rotella Barry Zalaman 23 Hukam Gary Jane Axelrad 1
24 25 1
Heritage Reporting Corporation (202) 628-4888
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MEETING ATTENDANCE (Continued):
2 From TVA:
3 R.P. Levi 4
N.D. Black R. Gridley 5
R.N.
Bass R.J. Hansen 6
H. George T.A.
Keys 7
Nick Fioravante Robert C. Williams 8
Jimmy J.
Pierce Edward A. Connell 9
R.H.
Bryan James T.
Springfield 10 P.J.
Polk C.H.
Fox 11-John Hosmer John Henry Sullivan 12 Frank A.
Koontz, Jr.
13 From Knoxville News-Sentinel 14 Richard Powelson 15 From Bishop, Cook:
16 Dan Stenger 17 From Impellt 18 Steven Whitsert 19 From House Interior Committee 20 Richard H. King 21 Others:
22 Andrew Bartlik 23 Lynne Bernabei j
M. McGarry 24 Kevin Elle 25 Heritage Reporting Corporation (202) :?.8-4888
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PROCEEDI NGS 2
MR. RICHARDSON:
Good afternoon, I apologize for 3
the crowded conditions of the meeting room here.
4 This is a meeting between the NRC and TVA to 5
discuss various issues related to fire protection compliance 6
at the Sequoyah facility.
It is a public meeting.
A 7
transcript is being taken.
I would ask that speakers other 8
than those at the table when you speak or give a comment give 9
a name and get close to a microphone so the conversation can 10 be picked up and transcribed.
11 There is an agenda for the meeting that has been 12 put together which lists the various technical issues that 13 the staff feels there are still some questions on.
The 14 protocol of the meeting is that the staff is going to go 15 through the TVA responses, each of the individual 26 16 questions that were sent out on February 26th and the 17 answers to those.
We are going.to go through those in 18 sequential order.
There will be a frequent break 19 periodically for members of the public to interact with the 20 staff, any additional questions that they think need to be 21 answered.
At the end of the technical discussion there will 22 be a 20 minute period that members of the public will be able 23 to address various concerns for the record.
24 Any additional comments or questions we need t.
25 cover?
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MR. ROTELLA:
There is attendance list going 2
around.
3 MR. RICHARDSON:
There is an attendance list coming 4
around and everybody needs to sign that.
5 With that, I'd like the members at the table to 6
introduce themselves.
7 MS. AXELROD:
He essentially just laid out the 8
ground rules with regard to public participation, that this 9
is a meeting between the staff and TVA.
Members of the i
10 public will have an opportunity, a 20 minute period at the 11 end of the meeting to voice their comments or questions, 12 Questions should be directed to the staff.
i 13 MR. RICHARDSON:
I'd like to take a minute and go 14 around the room and introduce everybody.
I am Steve Richardson, Director of the TVA Project Division.
15 16 MR. WESCOTT:
I'm Rex Wescott, Office of Special 17
- Projects, l
18 MR. PIERSON:
I'm Bob Pierson, Plant Systems Branch I
19 Chief.
20 MS. RANSEN:
Rebecca Hansen, TVA Manager Staff.
21 MR. FOX:
Charles Fox, TVA Office of Nuclear Power.
22 MR. HOSMER:
I'm John Hosmer, Project Engineer, TVA 23 Sequoyah.
24 MS. AXELROD:
Jane Axelrod, Deputy Director, Of fice j
25 of Special Projects.
i Heritage Reporting Corporation (202) 628-4888
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MR. GARG:
-- Garg, Office of the Special Project.
2 MR. ROTELLA:
Tom Rotella, Sequoyah Project Manager 3
for Unit 2.
4 MR. MARIIOS:
Angelo Marinos, Chief of Reactor 5
Operations Branch, TVA Projects.
6 (Whereupon, others in the room gave their name and 7
affiliation) 8 MR. RICHARDSON:
Thank you.
I'd like to turn the meeting over to Bob Pierson who will start through the 9
10 questions and TVA responses.
11 MR. PIERSON:
The agenda we would like to follow 12 today is to work through question by question the request 13 for additional information which we sent to TVA on 14 February 26, 1988.
TVA replied on March 2nd.
It is not my intention to cover every question, but only those questions 15 16 which the staff has questions about.
17 What I would like to do is start with number one, 18 which discussed providing calcu)ations for the reactor 19 coolant system, water and containment.
I don't want to 20 discuss that question now. I want to come back to it later, 21 depending on what your answers are to subsequent questions.
22 Question number two, which is the question 23 concerning the task group's conclusion of boiling of the 24 spent fuel pool is not a technical concern.
I don't have 25 any questions for that.
i Heritage Ropot: ting Corporation (202) 628-4888 i
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Mr. Wescott, do you have any questions concerning 2
this issue?
3 (No response.)
4 MR. PIERSON:
The next question is question number 5
three.
Question number three concerns procedure review.
And i
6 again, I don't have any questions for that.
I would like for i
7 you to understand that we are reserving the right to come 8
back to some of these questions because it really depends on 9
subsequent answers.
10 The first question I would like to discuss in 11 detail is question number four, which describes the standard 12 operating instruction 26.3, revision one, and provides 13 adequate boron concentration for cold shutdown condition 14 after a worst case appendix R fire.
15 Our ledger talked about a concept called 16 pressurizer level fluctuation as a methodology for 17 depressurizing.
TVA replied in their responst that 18 pressurizer level fluctuation was not used in 110I 26.3 19 Region 1.
However, the response that I am looking for more 20 than that is do yon use a concept of pressurizer level 21 fluctuation?
Is there such a concept?
What is it?
Do you 22 use it in your procedures?
23 Who in TVA addresses question number four?
24 MR. FOX:
Our speaker on that question is John 25 Henry Sullivan.
John Henry is the Supervisor of the Plant Heritage Reporting Corporation (202) 628-4888 i
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Operations Review Staff at Sequoyah.
He is our former 2
Appendix R project manager at Sequoyah also.
3 MR. PIERSON:
The first thing is this concept of 4
pressurizer level fluctuation. Then hcv does that work, and 5
how do you accomplish the depressurization sequence to get on 6
RRR?
7 The point that we're trying to bring out here is 8
that you need to have your Appendix R protected 9
depressurization mechanism.
I am not quite sure by your 10 answer that that is addressed.
11 KR. SULLIVAN:
To directly address the question on 12 pressurizer level fluctuations, it is not taken credit for in j
13 any of the procedures or analysis for depressurization of the 14 RCS.
15 MR. PIEASON:
What does that mean?
16 MR. SULLIVAN:
I am assuming what is meant by 17 pressurizer level fluctuations is you somehow try to cool the 18 vapor space in the pressurizer to decrease pressure.
19 MR. PIERSON:
But you don't use that as a 20 depressurization method?
21 MR. SULLIVAN:
That is not a proceduralized method 22 and there is no credit taken for that.
23 MR. PIERSON:
Do you take credit for one trail of 24 RHR to cool the plant to less than 200 degrees fahrenheit?
25 MR. SULLIVAN:
Yes.
Heritage Reporting Corporation (202) 628-4888
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1 MR. PIERSON:
Your response indicates that you've 2
requested an update on an analysis tnat Westinghouse 3
performed on July 21, 1975, and you will provide those 4
results as soon as possible.
Could you discuss why you feel 5
it's appropriate to use one train of RHR cooldown if you 6
don't, what information do you use to substantiate that?
Why 7
do you think it's a viable method of cooldown?
What I'm 8
reading here says to me that it doesn't look like you have an 9
analysis to support that.
10 MR. PIERSON:
We do have an analysis from 11 Westinghouse that supports shutdown in the plant, cold 12 shutdown using one train.
If you back up into the old single 13 failure criteria and get out of the R space, you're 14 guaranteed to be able to shut the plant down with one train 15 of RH:.
It just takes a little longer than the normal two 16 trains do.
17 We have an updated Westinghouse analysis which I 18 believe has been supplied to you.
I don't know if you 19 received it and had a chance to review it.
20 MR. FOX:
TVA provided at your request a list of 21 all pertinent documents and calculations and so on that were 22 germane to this issue that were referenced in our response.
23 You should have gotten that earlier this week.
l 24 MR. PIERSON:
We got two binders this morning and 25 we got some last week.
We haven't complated our review of
\\
1 Heritage Reporting Corporation (202) 628-4888
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9 i
1 that.
2 MR. FOX:
John Henry, why don't you give them the 3
reference.
It is in your package.
I'll confirm that.
4 MR. ROTELLA:
That's the March 8th submittal er the 5
earlier submittal?
6 MR. FOX:
There were three submittals.
1 think 7
this package should have come to you yesterday.
3 MR. PIERSON:
It was delivered this morning.
We 9
have just completed a preliminary review of the package 10 delivered this morning.
11 MR. SULLIVAN:
There is a Westinghouse letter to 12 TVA dated March 4th, TVA-88-561, and it deals with the one 13 RRR pump to two RCS co-legs at a tech spec minimum required 14 flow rate of 2500 GPM and gives us performance curves on RHR 15 cooldown to cold shutdown.
16 MR. PIERSON:
The last statement in the response on 17 the March 2nd says that pressurizer heaters, auxiliary spray, 18 and normal spray are not required to support safe shutdown.
19 Could you describe how you accomplish safe shutdown without 20 pressurizer heaters, auxiliary spray, and normal spray?
21 MR. SULLIVAN:
Pressurizer heaters is really 22 addressed in a different question.
Basically there is, who 23 has the question on pressurizar heaters?
24 MR. PIERSON:
The question is an operational 25 concern.
You have the statement, pressurizer heaters, Heritage Reporting Corporation (202) 628-4885
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auxiliary spray, and normal spray are not required to support 2
safe shutdown, so presumably you have some shutdown scenario 3
whereby you can accomplish it without those three items, and 4
I would just be interested in your discussing that.
5 MR. SULLIVAN:
The safe shutdown logic does not 6
require pressurizer heaters.
It was in the original analysis 7
and there were I believe three locations, two locations, 8
where you lost pressurizer heaters.
We based our response to 9
the question I believe in the Task Force Resolution Report 10 that loss of the pressurizer heaters does not mean you have 11 lost your bubble.
You still have a bubble in the top of the 12 pressurizer.
There are special tests that were run during 13 the startup phase of Sequoyah.
There are other St. Lucie 14 vents that Westinghouse Owners Group I believe has documented 15 that shows the relationship, RCS pressure and decay of 16 pressure versus time and loss of heaters.
17 MR. PIERSON:
That assumes that you don't have a 18 spurious actuation of the pressurizer port, is that correct?
l' MR. SULLIVAN:
Yes.
I think all the analynis did 20 not assume any sort of transient going on at the samn time.
21 MR. PIERSON:
I'd like to have it noted, we'll have 22 to come back to that because we do have some questions 23 concerning spurious actuation of your pressurizer port which 24 may impact on the response that you gave to question number j
i 25
- four, Heritago Reporting Co:tporation (202) 628-4888 l
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Does anyone from the staff have anything to say?
2 MR. MARINOS:
I have a question, clarification on 3
these three items.
You said you don't need the heaters, you 4
don't need the emergency spray, and you don't need the normal 5
spray for the pressurizer.
How do you maintain pressure 6
control?
The pressurizer is not utilized at all for pressure 7
control?
8 MR. SULLIVAN:
Yes. The vapor space in the 9
pressurizer is still utilized for pressure control. It has a 10 certain amount of internal energy and will be there for a 11 certain finite period of time.
12 MR. MARINOS:
But you are using no sprays and no 13 heaters to maintain that control. How are you going to do 14 that?
Are you going to pop the PORV?
15 MR. SULLIVAN:
We prefer not to pop PORVs, safety 16 valves, or do anything like that to challenge the system.
17 Charging pumps are used for charging.
The steam is steam j
18 from the generator to maintain a cartain cooldown rate.
19 Without going into a lot of detall on it, you make up to the 20 plant, you maintain your pressurizer leve.la, you can bring 21 the pressurizer level up to help collapse, help compress your 22 bubble a little bit more.
I think it was something like a 23 ten percent increase in level gave you 100 PSI.
Don't quote 24 me on that one but I believe that is about a correlation 25 where you can increase the level to help get pressure back up Heritage Reporting Corporation (202) 628-4888
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i 12 1
should you lose precsure.
That was all documented in our 2
resolution of the issue of the interactions where we lost 3
pressurizar heaters.
4 MR. ROTELLA:
In other words, you use CBCS?
5 MR. SULLIVAN:
Yes.
Charging pumps.
6 MR. ROTELLA:
Charging pumps and letdown.
7 MR. MARINOS:
It is not clear to me how you are 8
going to maintain the bubble in the prer,surizer without any 9
of the control systems associated with the pressurizer.
10 MR. ROTELLA:
What he is saying is he's going to 11 lower the level by increasing letdown.
12 MR. SULLIVAN:
We'll lower level by cooling the 13 plant down and shrinking the plant.
Adding water through a 14 CBCS.
15 MR. BARTLIK:
You mean not using letdown, just to 16 correct that statement.
17 MR. ROTELLA:
You mean it's not necessary to use 18 letdown.
19 MR. BARTLIK:
I didn't say that.
20 MR. PIERSON:
One point here.
The staff is allowed 21 to ask the questions.
We are not set up to allow the public 22 to address questions.
The public can address questions of 23 the staf f at the intermissions oc following the meeting.
We 24 will address them at that point.
25 The next question is question number five, and the j
Heritage Reporting Corporation (202) 628-4883 i
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question, to paraphrase, asks you about taking credit for 2
pneumatic systems for control during Appendix R events.
You 3
reply that you don't take credit for pneumatic systems except 4
for one key.
We asked for clarification on that and you 5
stated that you took manual control of some HVAC dampers.
6 My question with respect to that is, if you're 7
taking manual control of these HVAC dampers, are they covered 8
in precedures, are they accessible?
9 MR. FOX:
Bob Bryan is the Staff Specialist, 10 Accident Evaluation as it deals with containment systems in 11 the Nuclear Technology Branch, in the Division of Nuclear 12 Engineering.
13 MR. BRYAN:
The answer is yes, specifically in our 14 procedure SOI 26.2.
These dampers are provided and discussed 15 and the operator is informed that if he loses automatic 16 control of them he can go out and manually take control of 17 them.
j 18 MR. PIERSON:
And you substantiated that as opposed 19 to some plants I've seen that they are in fact accessible and i
20 he doesn't have to carry a step ladder with him?
)
21 MR. SULLIVAN:
The main control room KVAC dampers 22 are all located in the mechanical equipment room adjacent to 23 the control room and they are accessible.
24 MR. PIERSON:
Thank you.
25 To continue on with question five, this touches on Heritage Reporting Corporation (202) 628-4888
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another issue.
You stated that a preliminary separation 2
analysis on Unit 2 indicates that either a head vent or 3
pressurizer port letdown path is available for all scenar'os 4
that may require water solid operations.
5 We have done a preliminary review of the submittal 6
this morning and wt are going to take some issue with that 7
statement.
I'll be coming back to that later.
8 But the question I have with respect to this, is 9
TVA taking credit for using pressurizer 4 where a reactor 10 event, as a means of recovering from an Appendix R event?
11 KR. RYAN:
At the current time, no.
12 KR. PIERSON :
The answer to that question is no?
13 KR. RYAN:
That is correct.
14 KR. PIERSON:
Thank you.
15 Then I think we can go on to question six.
I have 16 some subsequent questions with respect to that answer.
17 Does anybody on the staff have a question about 18 number five?
19 KR. RUBBARD: George Hubbard, OSP.
I guess if that 20 preliminary separation analysis you are not taking credit for 21 then, we wouldn't be expecting to see a final analysis on 22 that?
23 KR. RYAN:
Not at the present time, no.
24 KR. PIERSON:
Okay, we'll move on to question six.
25 Question number six concerned why the primary plant will not Heritage Reporting Corporation (202) 628-4888 I
15 1
lose a pressurizer bubble in a fire scenario such that 19 2
hours is the conservative value for requiring the 3
availability of RHR.
4 We in the staff have discussed this, and we 5
understand how you came up with 19 hours2.199074e-4 days <br />0.00528 hours <br />3.141534e-5 weeks <br />7.2295e-6 months <br /> and why you consider 6
it a conservative value.
We don't have any argument with 7
that per se.
But we do question whether you will be able to 8
maintain primary plant pressure in light of the fact that 9
it's not clear to us that the pressurizer PORVs are 10 protected.
I don't need to address it under this question 11 because it's going to be addressed in other questions later, 12 but we do have some questions concerning whether you are 13 going to end up in a solid plant condition and what you're 14 going to do, and why you can take 19 hours2.199074e-4 days <br />0.00528 hours <br />3.141534e-5 weeks <br />7.2295e-6 months <br /> credit for that.
15 So with respect to that I'd like to move on to 16 number seven.
17 Number seven, TVA states that, we asked TVA to 18 provide justification for repair times of flow control valve 19 74-1 and 74-2.
Those are the series valves for your RHR.
We 20 asked why these valves are considered operable for fires 21 inside containment, and TVA replied they consider them 22 operable because they can utilize 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to go in and 23 repair these valves.
24 I don't have a question per se based on that, 25 however, I do have a concern that if you stated earlier you Heritage Reporting Corporation (202) 628-4888
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didn't use the pressurizer PORVs or the reactor head vent 2
valves as a cooldown mechanism, which seems to me 3
contradictory to some of the replies you made later.
Maybe 4
they were questions that you used that as a possible means 5
but you didn't take credit for it.
But if you do use reactor 6
head vents or pressurizer PORVs and you do end up in a 7
situation where you are blowing down RCS into the i
8 containment, we are concerned as to how you could access the 9
containment.
What calculations are used to justify that the 10 containment is accessible to repair, among other things, 11 these valves, or else show to us that these valves, it's not j
12 credible to have a fire in those areas where you could have a 13 blowdown, say if a pressurize PORV reactor head vant valve, 14 and as such the one event excludes the possibility of the 15 other.
16 It's not clear to me, going back to your first 17 question, as to how you could justify access to the 18 containment if you took credit for that.
Since you didn't j
19 take credit for it I'll move on, but I think there are other 20 statements where it implies to me, at any rate, that you did 21 take credit for it.
22 MR. ROTELLA:
During a phone call.a couple of days 23 arjo, we had understood TVA Licensing and Enginacring to tell 24 us that indeed you do protect PORVs and block valves.
You 25 separate where necessary, you vrap where necessary.
Why Heritage Reporting Corporation (202).628-4888
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would you do that if you don't need them for fire?
Why isn't 2
that inconsistent with the submittal we got today?
3 MR. FOX:
I'm not sure what the conversation was.
4 Who was the conversation with, Tom?
5 MR. ROTELLA-Licensing was Mark Burzynski, and 6
Enginwering was, was it Frank?
7 KR. KOONTZ:
This is Frank Koontz.
I think I can 8
address that.
9 MR. FOX:
Frank Koontz is our Assistant Branch 10 Chief in Nuclear Technology Branch.
He's also our Safe 11 Shutdown Specialist.
12 MR. KOCNTZ:
We were doing a preliminary analysis 13 to see if we did have the availability of the reactor head 14 vents or the pressurizer PORVs.
That analysis at the time we 15 were discussing it was still in its preliminary stage and it 16 was being finalized.
Since that time the analysis has been 17 finalized and it's been documented. We do not have a problem 18 that I'm aware of, providing that analysis to the staff if 19 they would like to review it.
However, our position today is 20 we still do not take credit for the use of the head vents or 21 the PORVs to cool down the plant.
I need to emphasize that.
22 MR. ROTELLA:
Is that a change in the design basis 23 then?
24 MR. KOONTZ:
No, we did not credit the use of the 25 head vents or the PORVs before.
Heritage Reporting Corporation (202) 628-4888
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MR. ROTELLA:
So Rev 6 of the calculation doesn't 2
have PORVs?
3 MR. KOONTZ:
Right.
4 MR. ROTELLA:
Rev 8 does not either?
)
5 MR. KOONTZ:
That's correct.
It does not, i
6 KR. PIERSON:
If I could interject, Jane Axelrod 7
has come up with a very good suggestion.
She says we have a 8
bigger room.
I want to break and move.
I suggest that's'a 9
good idea.
The question is, where is the room.
10 (Whereupon, a brief recess is taken) 11 MR. PIERSON:
The meeting will continue.
12 We were on question seven and I'd like to continue 13 with question seven.
14 We were discussing the RHR valves, FCV 74-1 and 25 74-2, and their accessibility with respect to a fire inside 16 containment.
17 The question I have is are the RHR valves 18 protected?
Are they considered Appendix R equipment?
Do 19 they have separation, a one hour barrier, detectors, or 20 whatever?
21 MR. SULLIVAN:
Please ask your questions one at a 22 tim'e.
23 MR. PIERSON:
Are the RHR valves Appendix R 24 protected equipment?
That's 74-1 and 74-27 25 MR. SULLIVAN:
Yes.
They are cold shutdown Heritage Reporting Corporation (202) 628-4888
19 1
required equipment.
2 MR. PIERSON:
How is that Appendix R protection 3
provided?
4 MR. SULLIVAN:
It's provided by using the 3G 5
requirements for cold shutdown.
Basically for a fire outside 6
containment we have a couching procedure that vill repair the 7
valve and can get 74-1 and 74-2 open without entering 8
containment.
9 For a fire inside containment there is no 10 significant fire loading around the valves.
One of the 11 valves is located in accumulator room four, and one is under 12 steam generator four.
Fire hazard analysis has been done.
13 So a fire inside containment will not damage the valve unless 14 the fire is in the valve or the control circuitry to the 15 valve, in which case that fire will be limit 6d to within that 16 valve and will not damage other equipment.
Containment 17 access, normal letdown, everything else would be available.
18 No spurious PORV or head vent operation is considered.
19 The conclusion is cold shutdown is achievable for 20 our shutdown logic with those valves protected the way we 21 have.
22 MR. PIERSON:
So you base that on a fire hazards 23 analysis then?
24 MR. SULLIVAN:
Yes sir.
25 KR. PIERSON:
We have that fire hazards analysis?
Heritage Reporting Corporation (202) 628-4888
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MR. SULLIVAN:
Yes sir.
I should also point out j
2 that the valves, thtre was I believe a question at one point 3
on the EQ qualification of these valves.
4 MR. PIERSON:
Yes.
5 MR. SULLIVAN:
The valves are qualified on a 6
temperature profile that peaks at about 300 and then i
7 maintains about 200 for 30 days.
8 MR. PIERSON:
So the valves are essentially i
9 qualified ~for end containment local conditions?
10 MR. SULLIVAN:
Yes.
I 11 KR. PIERSON:
Thank you.
l 1
12 Does anyone from the staff have any further i
l 13 questions on question number seven?
14 (No response) l 15 KR. PIERSON:
Now I'd like to discuss quickly 16 number eight, which discusses the possibility of lubrication 17 oil from the main coolant system pumps being thrown beyond 18 the oil collection system.
l l
19 I don't have any questions concerning this.
Does i
20 anyone from the staff have any questions?
l 21 (No response) l 22 MR. PIERSON:
We'll move on to question nine.
23 Describe the protection and provide a copy of the fire hazard 24 analysis for steam generator PORV controls.
25 From the response from March 2nd it appears that Heritage Reporting Corporation (202) 628-4888 I
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you have done what you need to do.
I don't have any 2
questions on number nine.
Does anyone from the staff have s 3
question on nine?
4 (No response) 5 MR. PIERSON:
We'll move on to question number ten.
6 Describe the effects of a main steamline break and the 7
resulting steam generator PORV opening spuriously.
Describe 8
the environmental qualification of PORV including seismic.
9 Is the PORV single failure proof?
Discuss whether Appendix R 10 functional criteria specifically call for no bore down of any 11 steam generator.
12 I'd like for TVA to stsrt with describing what your 13 single failure criteria is.
14 MR. BRYAN:
Bob Bryan.
In addressing what our 15 single failure criteria is, basically we feel we follow 16 standard industry practice.
Specifically for seismic events, 17 our safety-related equipment is designed to be seismic so we 18 don't expect it to fail in seismic events.
We also do not 19 consider multiple failures of non-seismic components during a 20 seismic event.
21 Specifically for the case of the main steamline 22 break that we were talking about in question sen, we consider 23 that an independent initiating event.
We take a loss of off-24 site power if that is the worst assumption.
We take a single 25 failure, either one active failure immediately or a passive Heritage Reporting Corporation (202) 628-4888
22 i
1 failure 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> later, and for this event we do not couple a 2
seismic event with the MSLV since we consider those 3
independent events.
4 MR. PIERSON:
I see.
So what you're saying then is 5
from your response, that the actuating circuit, the closing 6
solenoid is environmentally and seismically qualified, and 7
the valve is not seismically qualified and it's not a problem f
i 8
in your single failure criteria?
9 Mr. BRYAN:
The actuating circuit is not l
10 environmentally qualified.
A pot"ton of the controller's i
11 circuit has been moved out of the vault, but the closing 12 circuits have been environmentally and seismically qualified, 13 and they are provided for remote manual actuation from the 14 control room.
The operator can override all the automatic l
15 control functions and can run that valve closed if it should i
16 spuriously open.
17 MR. PIERSON:
I don't have any more questions on l
18 number ten.
Does anyone from the staff have questions on 19 number ten?
i 20 MR. FOX:
Was that answer satisfactory?
Do you 21 have a question about standard industry practice? I have 22 consultants lined up to speak to that if there is a further 23 question.
24 MR. PIERSON:
No, I don't.
25 The next question, number 11 was very straight Heritage Reporting Corporation l
t (202) 628-4888 l
23 1
forward.
Provide assurance of the pressurizer block valve 2
when closed against full reactor coolant system pressure.
I 3
think Mr. Hubbard requested a completed maintenance 4
instruction.
Did you get that complete instruction?
5 MR. HUBBARD:
Yes, I did, Bob.
6 MR. PIERSON:
Then I have no questions about number 7
11.
j 8
MR. FOX:
Have you had an opportunity to review 9
that instruction, and do you find it satisfactory?
10 MR. HUBBARD:
I briefly looked at it and it appears 11 that it will be satisfactory.
12 MR. PIERSON:
Now we come to really what I consider 13 the crux of the meeting which is question 12, which is 14 provide an explanation of how Appendix R related cables are 15 provided protection from spurious actuations, and 16 particularly define the grounding mechanisms of these cables; 17 do cables of a train for various required components share a I
18 common ground?
If so, is spurious actuation from a wire to 19 wire short between different cables prevented?
Were credible 20 faults considered between individual conductors within a 21 cable, or cable to cable?
22 You have since revised your response on this.
We 23 have conducted a preliminary review on it this morning.
We 24 got the response this morning.
I think the staff has several 25 questions regarding that submittal.
Heritage Reporting Corporation (202) 628-4888
24 1
I think what I'd like to do is let Mr. Garg ask 2
some questions if he has some, and then I have some 3
additional questions following his.
4 MR. GARG:
The question I have is how do you 5
justify not considering the cable to cable fire?
I think you 6
did an industrial study and I think most of the utility 7
outlets have been this.
I don't see what basis you have for 8
not considering a cable to cable fire.
9 MR. PIERSON:
Would TVA like to make a presentation 10 on this question and then let us respond to it?
11 KR. FOX:
We would like to present our response to 12 this entire question, if we could, since it is the principal 13 point of contention.
Thank you.
14 Our speaker on this subject is John Henry Sullivan.
15 MR. SULLIVAN:
Thank you, Charlie.
16 Spurious actuation of type two associated circuits 17 is the concern here.
These circuits required for safe 18 shutdown and those not allowed to spuriously operate ware all 19 analyzad as required circuits.
In general, required circuits 20 and these type two associated circuits were protected by 21 separation or fire barriers in accordance with G-2.
Where 22 separation did not exist, interactions were identified, we 23 analyzed those interactions, and provided dispositions to 24 each one of them.
)
l 25 Alternate shutdown capability is provided for areas Heritage Reporting Corporation (202) 628-4888
25 1
where we considered cable to cable faults credible, namely 2
the main control room, the cable spring room, and the 3
auxiliary instrument room.
These areas have a large 4
congestion of cables and cable to cable faults.
Maybe 5
credible.
6 Sequoyah utilizes an ungtounded DC control --
7 MR. MARINOS:
Are you going to be able to explain 8
to us later what you call credible and not credible faults?
9 You just indicated whenever you decided that a cable to cable 10 fault may be credible, or however you phrased it. Could you 11 tell us how you made that judgment?
12 KR. SULLIVAN:
Yes, I will try to get into that 13 right now.
14 We utilized an underground DC control system.
We 15 also have an ungrounded AC control system off control 16 transmitters on the 480 volt grounded AC system.
This is 17 unique in some respects that our AC control power system or 18 essentially all of our motor operated valves and MoV boards 19 are off controlled transformers and is ungrounded.
)
20 This means that spurious actuation from any device 21 not fed from a common power source, would take multiple 22 faults.
23 Additionally, we did a separate look back at the 24 high/ low pressure interfaces based upon the criteria in 531 25 of Generic Letter 86-10.
We relooked that reactor vessel Heritage Reporting Corporation (202) 628-4888
26 1
head vents, the RHR letdown path, the OCS normal and excess 2
letdown, and also pressurizer relief pacts.
In only three 3
cases in th'.s look back did we find that the cable to cable 4
fault, had it been considered, would have resulted in a 5
problem and therefore, we did not meet that. The literal 6
guidance given is such in 531.
7 MS. AXELROD:
When did you do this look back?
8 MR. SULLIVAN:
This look back was completed over 9
the weekend.
These three cases deals with the pressurizer 10 PORV, cable to cable fault, multiple faults such that you hot 11 up on a separate cable.
This assumes upurious operation.
12 MR. GARG:
There are two issues here.
One is the 13 high/ low interface, and the other is for any other subject.
14 But high/ low interface, you have to consider the multiple 15 chart.
For any of the separates, you have to consider if 16 there is any --
17 MR. SULLIVAN:
I point out here that we identified 18 these interactions and our disposition of cable to cable 19 shorts was submitted to the NRC.
I thir.k we brought that out in the submittal that you got this morning.
This was 20 21 reviewed by tha NRC at the time of our reevaluation.
NRC 22 stated that we had taken appropriate corrective actions for 23 these interactions.
However, we did go back and reevaluate 24 due to your additional request with respect to the high/ low 25 interfaces, and provided the results of that review this i
Heritage Reporting Corporation (202) 628-4888
27 1
morning.
2 MR. PIERSON:
If I could interject, it sounds to me 3
like you are saying that you have three cases where you have 4
a cable to cable interaction problem. One is the pressurizer 5
PORVs; one is the reactor head vent valves; and one is with 6
respect to the RCS letdown path.
Is that a correct 7
statement?
8 KR. SULLIVAN:
Would you repeat the first sentence 9
of that question?
10 KR. PIERSON:
I said it appears to me that.you have 11 three places in your containment where you apparently haven 12 to considered where you have a problem with cable to cable 13 faults.
14 KR. SULLIVAN:
No.
The three problems that I point 15 out here in meeting the literal requirements of 531, all 16 three of them deal with pressurizer PORVs in three separate 17 locations.
18 KR. PIERSON:
All three deal with pressurizer PORVs 19 in three separate locations.
20' MR. SULLIVAN:
Yes.
21 MR. PIERSON:
I'd like you to turn to Attachment 5, 22 a March 8, 1988 submittal.
Could you elaborate on statement 23 number four.
"The reactor head vent valves are obviously not 24 separated because they are physically located together near 25 the reactor vessel head to satisfy reactor pressure vessel Heritage Reporting Corporation (202) 628-4888
28 1
boundary considerations."
What have you done to prevent 2
spurious actuation to reactor head vent valves?
3 MR. FOX:
You're going to need to rephrase your 4
question.
5 MR. PIERSON:
Have you found Attachment 5?
6 MR. SULLIVAN:
I've got it now.
Will you repeat 7
your question?
8 MR. PIERSON:
On question four you said that the 9
"reactor head vent valves are obviously not separated because 10 they are physically located together near the reactor vessel 11 head to satisfy reactor pressure vessel boundary 12 considerations."
13 What does that mean? Does that mean that you 14 provided the cable wrapping?
You provided the separation 15 criteria?
Obviously it didn't meet the sepe. ration criteria, 16 so what have you done?
17 MR. SULLIVAN:
There is another attachment in here 18 if you give me just a minute.,
Roman Numeral I i
19 readdresses in a very similar fash' ion how we initially i
20 addressed this issue in December 2, 1982, which I believe 21 that letter was provided as enclosure Attachment 1.
22 MR. PIERSON:
Okay, now there is a problem with 23 that response based on what you said earlier in the meeting, i
24 because you said you didn't take credit for reactor head vent 25 valves operating spuriously or operating in a fire for.
l Heritage Reporting Corporation (202) 628-4888
29 1
pressure control.
Yet in the second paragraph here you say 2
"Even if spurious operation did occur, it will not result in 3
depressurization of the RCS because a shutdown logic 4
separation analysis ensures a CCP is available for makeup.
5 Because two valves are in series, a single set of two on this 6
ungrounded DC circuit from an external cable will not result 7
in a loss of the high pressure interface."
8 So whet it's telling me, if I'm reading this 9
correctly, is you're saying we don't care if the valve is 10 open.
We've got the centrifugal charging pump to provide 11 makeup.
Is that what you're saying there?
12 MR. SULLIVAN:
What we're saying, to address the 13 earlier response that we gave you, is that we do not take 14 credit for reactor head vent system as a letdown path or a 15 depressurization path.
16 MR. KOONTZ:
This is Frank Koontz.
I think there 17 is a confusion about whether we worry about the thing 18 spuriously opening when we don't want it to be open verLus
)
19 whether we take credit for it as a letdown path so that we 20 can open it and can close it when we want to.
21 MR. PIERSON:
I guess I am confused then, because 22 Appendix R says that essentially if something can spuriously 23 actuate, you've got to provide some sort of protection 24 against it.
That's what a high/ low pressure interface is all 25 about.
That's what generic letter 8610 considers.
So if J
Heritage Reporting Corporation (202) 628-4888
30 1
you're telling me in one place that you don't consider it and 2
then the other place you're saying if it happens we can 3
provide makeup, there is a problem.
4 MR. FIORAVANTE:
Nick Fioravante.
He's saying that 5
they don't utilize the head vents for the PORV as letdown 6
path.
That doesn't mean they don't consider it.
They don't 7
utilize it as part of their shutdown equipment.
They have 8
reviewed it as part of the spurious actuation parts, part of 9
the associated circuits.
10 MR. ROTELLA:
So it is protected against.
11 MR. FIORAVANTE:
It is addressed, but it's not 12 utilized.
13 MR. PIERSON:
You're saying it's addressed but it's 14 not protected.
You don't take credit for it in your 15 analysis, is that right?
If you take credit for it it has to 16 be protected.
17 MR. SULLIVAN:
We do not take credit for head vents 18 as a required circuit.
19 MR. FIORAVANTE:
Protection is beyond just cable 20 right.
Protection can be provided that you looked at it and 21 it doesn't spuriously actuate.
Protection can be defined as 22 you looked at it, it spuriously actuates, it opens, but it's 23 not a problem.
Try to separate in your mind something that 24 needs to open and close and the type of protection you 25 provide for that and something you are only worried about if Heritage Reporting Corporation (202) 628-4888
I 31 1
it spuriously actuates.
2 MS. AXELROD:
What kind of protection did you 3
provide here, I think, is the other part of Bob's question.
4 What did you do to prevent a spurious actuation?
5 MR. SULLIVAN:
To summarize what we've said in i
6 here, there are fuses that can be pulled by the 7
operator should the thing spuriously operate and the valves 8
will go closed.
That is from an internal cable fault.
9 External cable faults were dispositioned here as not being 10 credible, well the hot /short being credible from an external 11 cable, but since it had to happen to two valves it would take 12 multiple combinations of the two hot / shorts and therefore 13 that was not credible.
14 MR. GARG:
That's what I have a problem with.
If 15 we look at 8610 for high/ low interfaces, you have to consider 16 the short for all the high/ low defenses.
But anything beyond 17 the high/ low defense you have to consider a single short.
18 MR. WILLIAMS:
This is Bob Williams, TVA.
We 19 looked at those valves and the basis for our conclusion was 20 if you pull those fuses, it takes multiple shorts on two 21 different valves.
It will take at least four shorts of the 22 proper polarity to actuate two valves and give you a path.
23 With the random laying cable, we considered that to be an 24 incredible event.
You've got to get four off the same 25 instrument bus or transformer together in the same tray and Heritage Reporting Corporation (202) 628-4888
\\
32 1
' short them with the proper polarity to have that event occur.
2 MR. GARG:
I'm not sure why you would need four.
3 MR. WILLIAMS:
You have to have the positive and 4
negative of two different circuits together to actuate two 5
vessels.
6 MR. GARG:
That's the two shorts.
7 MR. WILLIAMS:
That's four conductor shorts of the 8
proper polarity.
9 MR. GARG:
Yes, but that is considered --
10 MR. WESCOTT:
But that is in addition to the one 11 we've already mitigated.
12 MR. MARINOS:
Do you know how many shorts or faults 13 are required for low to high pressure interface?
Is there 14 more than one, less than four, what is the number?
15 MR. WILLIAMS:
In this particular case we're 16 discussing, the original short can be, it would take a short 17 to the positive side which is a single event.
We can 18 mitigate that by pulling the fuses.
In addition to that, we 19 would have to short additionally two more cables, both 20 positive to positive and negative to negative, to initiate 21 that event.
So there is a minimum, it would take a minimum 22 of three.
23 MA. MARINOS:
If you have two or leds it will be 24 unacceptable.
25 MR. WILLIAMS:
No.
Heritage Reporting Corporation (202) 628-4888 I
l I
33 1
MR. GARG:
Your comment about three, that's j
2 considered for the high/ low defense.
My question is, -- I'm 3
not sure how you can operate this.
t 4
MR. WILLIAMS:
No, we did not remove the fuses.
5 What we said was that if it does spuriously actuate we can 6
pull the fuses and mitigate that event.
If we pull the 7
fuses, then it takes two additional shorts on two valves to 8
cause them to spuriously open again.
What we said in the 9
analysis was that having those valves spuriously actuate is 10 within the design basis of the plant.
11 MR. GARG:
So you indicated that three is a 12 credible, three independent faults you are talking about,
{
or 13 more.
You say four.
If fou pull the fuses it would take 15 four conductor to conductor shorts with proper polarity.
It 16 could be two cables to cables.
17 MR. GARG:
Pulling the, fuse is in your procedure?
18 MR. SULLIVAN:
The form on the fuses is in the 19 procedure for the backup control room, abandonment of the 20 main control room, single procedure for the plant fires 21 outside the control room at this time.
22 MR. PIERSON:
I'm sorry.
I missed something there.
23 Can you repeat that please?
24 MR. FOX:
Repeat the question, please.
25 MR. PIERSON:
I heard something about something Heritage Reporting Corporation (202) 628-4888
34 1
wasn't in a procedure, and I'm not sure what that referred 2
to.
3 MR. FOX:
What was your question?
4 MR. GARG:
My question is pulling the fuses out in 5
the procedure, the norm, and he is supposed to take out the 6
fuses.
I mean if you take the credit for that.
7 MR. SULLIVAN:
We'll put in that in SOI 26.2 right 8
now is currently in AOI 27 on abandonment of main control 9
room.
10 MR. PIERSON:
So in effect you're saying that's a 11 fix as a result of what you've done in the past few days?
12 KR. SULLIVAN:
No, it's an enhancement based upon a 13 relook at what we told you December 2, 1982, based upon our j
14 relook.
Our disposition in December 2, 1982 basically said, i
15 and I'd like to put this on the record, is that there is a 16 three-eighths inch flow restrictor during this line, that 17 charging pump can maintain RCS pressure with that flow 18 restrictor, and it's not defined as a loca in accordance with 19 10 CFR 50 because we can provide the makeup and do a normal 20 shutdown in accordance with --
21 MR. PIERSON:
And you can assure me that since it 22 has nothing to do with your flow control valves for your RHR 23 system, the RHR system is independent of this so you can 24 always access your RHR valves even if you did have some 25 leakage?
lieritage Reporting Corporation (202) 628-4888
35 1
MR. SULLIVAN:
We think that appropriate mitigative 2
action would have been taken to stop this spurious actuation 3
of the valves once the operator had found it, and there would 4
never have been any adverse effect on 74-1 or 74-2.
5 MR. PIERSON:
I'd like to talk more, are we 6
finished with this question now?
7 MR. GARG:
No, I have some more questions.
8 MR. SULLIVAN:
We had an open question I believe 9
that you said we were to get back to on number, dealing with 10 the RHR valves.
We didn't address that at the time.
You 11 said we would discuss it later in the presentation.
Would 12 you like to discuss that?
13 MR. KOONTZ:
I believe that was question seven, 14 Bob.
15 MR. SULLIVAN:
Were you satisfied with our response 16 on seven?
17 MR. PIERSON:
Let's go ahead and talk more about 18 spurious actuates.
We've still got pressurizer PORVs to talk 19 about and we've still got RCS letdown.
When we finish that 20 then we can come back to that.
21 MR. GARG:
Okay.
I think the question I still have 22 is that you pull the fuses for all the high/ low interfaces?
23 Is that what you are doing?
1 24 MR. WILLIAMS:
We're only pulling the fuses if that 25 valve spuriously actuates.
Heritage Reporting Corporation (202) 628-4888
d i
36 1
MR. GARG:
That has to be that.
2 MR. WILLIAMS:
What I want to make clear is we're 3
not pulling the fuses in advance of the event.
They are not 4
being pulled now.
5 MR. GARG:
No, but ycu have a procedure before --
6 You will have the instructions for the operator that if he 7
detects -- that he will pull the fuse, for all high/ low 8
differences.
9 MR. WILLIAMS:
For the reactor head vent.
10 MR. GARG:
No, I'm talking about all high/ low 11 differences.
There are four or five identified, right?
12 MR. SULLIVAN:
Only on the reactor head vents.
The 13 internal letdown, if you go through Attachment 2 in the 14 submittal that you received this morning, it goes through in 15 detail all four of those and what we've done.
The reactor 16 vessel head vents we stated in Attachment 2 that the operator 17 could pull the fuses, and that is what, we ciready had an 18 AOI, abnormal operating procedure for the operator to verify 19 the valves closed.
We'll go on and enhance that one step 20 further and tell them if it doesn't close we'll pull the 21 fuses.
We'll go ahead and put in an SOI 26.2 and identify 22 that those fuses need to be pulled in the event of a 23 confirmed fire to protect the plant and equipment.
24 MR. PIERSON:
How long does it take for the 25 operator to do that?
Heritage Reporting Corporation (202) 628-4888
s 37 1
MR. SULLIVAN:
The fuses are two doors away from 2
the control room, about 100 feet.
When he knows they're 3
spuriously opened and he has pulled out his procedure and is 4
ready to go, ten minutes would be a very conservative 5
estimate.
6 MR. GARG:
If you look at it, two shorts are 7
incredible.
- Again, I have a problem there.
8 MR. MARINOS:
Are you modifying the statement to 9
say by applying the removal of fuses you will increase the 10 need for failures to cause you the inadvertent actuation?
11 The statements say two shorts are incredible.
But what I 12 have heard here, it will require more than two shorts in 13 order to cause the inadvertent situation.
14 MR. WILLIAMS:
No sir.
It takes one short to 15 inadvertently actuate.
Pulling the fuses causes at least two 16 more.
17 MR. MARINOS:
That makes it three.
16 MR. WILLIAMS:
Right.
But it only takes one to 19 initially make it actuate, and then it takes two more to 20 bring it back open again.
21 MR. PIERSON:
If I could interject here, you're 22 saying then that it takes one short to spuriously actuate the 23 reactor head vent valves?
24 MR. SULLIVAN:
That's due to an internal cable 25 fault.
The same power force.
You pull the fuses in that i
Heritage Reporting Corporation (202) 628-4888
e 38 1
event.
2 MR. PIERSON:
How does that meet generic letter 3
8610?
J 4
MR. SULLIVAN:
We performed the further evaluation 5
and documented that evaluation to you that said that that 6
line being restricted by a three-eights inch orifice which i
7 separates reactor coolant system piping from non-reactor t
a coolant system piping, was not a loca, was within the makeup 9
capability of the centrifugal charging pump, so we could 10 proceed with a normal --
i 1
11 KR. PIERSON:
So I can infer from that that your 12 centrifugal charging pump is in your Appendix R safe shutdown 13 evaluation, and all the control circuitry, and you've 14 established that that is going to be operable in the event i
l 15 you have this spurious actuation?
l 16 MR. SULLIVAN:
We will always have a centrifugal 17 charging pump that satisfies the shutdown logic requirements.
18 MR. GARG:
I think I'm still looking for an answer j
i 19 on Item 3, RCS is nominal and accessibly done.
1 20 MR. SULLIVAN:
In Attachment 2?
21 MR. GARG:
Yes.
Here you make a statement that it 22 would take two shorts of the proper polarity without 23 grounding, and each of these --
24 MR. SULLIVAN:
Let me explain this.
There are two 25 pipe and flow paths--normal and excess letdown.
In similar Heritage Reporting Corporation (202) 628-4888
39 1
ways, head vents, you have two flow paths, an A train and a B 2
train.
Head vents have two valves in s'eries.
We just went 3
through all that.
That's why it takes the four hot / shorts of 4
the proper polarity to get those things open.
In this line 5
you have three valves in series in each of the two paths.
So 6
it would take three hot / shorts, two hot / shorts of the proper 7
polarity, to get all three of those valves open.
8 MR. GARG:
Is it three, or three paths?
9 MR. SULLIVAN:
There are two paths, three boundary 10 valves in each path.
11 MR. GARG:
Three in each path.
And they have no 12 problem.
13 MR. SULLIVAN:
Right.
They are normally fail close 14 valves, and you would have to hot them up and have air 15 supplied to them at the same time to get all three valves up.
16 MR. PIERSON:
You're talking about the RCS letdown 17 path?
i 18 MR. SULLIVAN:
And excess letdown.
19 MR. PIERSON:
One other question I've got is in 20 terms of availability of RCS letdown.
Have you considered 21 all your spurious actuation circuits to verify that in all 22 conditions you're going to have RCS letdown available?
23 MR. SULLIVAN:
RCS letdown availability is not 24 guaranteed by the shutdown logic and Appendix R analysis.
25 MR. PIERSON:
We talked earlier about the Heritage Reporting Corporation (202) 628-4888
1 l
l 40 1
pressurizer PORV and these interactions that you consider on 2
the pressurizer PORV.
Could you elaborate on where they are 3
and what they are?
4 MR. SULLIVAN:
This is from memory.
Two locations 5
in the annulus of Unit 2, Unit 1 has not been looked at; two 6
locations in the Unit 1 annulus, one involves each of the 7
A PORV may spuriously open there, considering the 8
hot / shorts from the cable.
No internal cable hot / shorts 9
would cause the valve to open.
10 MR. PIERSON:
Cable to cable fault you're talking 11 about?
12 MR. SULLIVAN:
Yes, it has to be a cable to cable 13 fault.
14 MR. BLACK:
Norman Black, Electrical Group at 15 Sequoyah.
That's correct.
The three interactions or 16 identified concerns, two of them are in the reactor building 17 Unit 2 annulus, and one is in the emergency gas treatment 18 area where we have a situation where the PORV cable is tray i
19 routed in close proximity to a block valve which we have 20 identified.
It happens to be the train B block valve 21 associated with that train A PORV valve.
22 MR. PIERSON:
Do you consider this cable to cable 23 interaction a problem?
24 MR. BLACK:
On that particular circuit?
25 MR. PIERSON:
Are you planning on doing anything i
Heritage Reporting Corporation l
(202) 628-4888
41 1
about it, or are you just telling us it exists?
What is your 2
answer with respect to that?
3 MR. SULLIVAN:
Let me try to address that.
4 We're currently relooking at both the spurious 5
cable to cable concern and also the letdown concern.
We have 6
not decided what to do about them or made any decisions.
In 7
this particular case Norm's talking about, it's emergency 8
power supplying the block valve that's in question.
If 9
you're sending the cable to cable fault, the emergency power 10 from the diesels to that valve may not be available.
If off-11 site power was available the block valve would be available 12 to close.
That was our problem.
13 MR. PIERSON:
It sounds to me like there's a 14 problem there that we need some additional information before 15 we can resolve.
Is that a correct assumption on my part?
16 MR. FOX:
Can we take a five minute caucus?
I'm 17 not sure, we've got too many people speaking to the issue.
18 Could we take a few minutes to caucus and then give you a 19 coherent answer to your question?
j 20 MR. PIERSON:
Yes.
Make it ten minutes.
21 (Whereupon, a brief recess was taken) 20 MR. HOSMER:
Let me answer the question by first 23 starting with a little bit of history.
24 The majority of the Appendix R work on Sequoyah we 25 reconvened a team and did our, well let me go back even Heritage Reporting Corporation (202) 628-4888
e 42 1
further.
2 The NRC confirmation letter was sent to us in 8/84 3
saying "confira you meet Appendix R 3GJLL."
We formed a 4
team, we completed our work, and we completed that work with 5
the submittal to NRC in December 1984.
So the history is we 6
had completed our work and submitted that to you the end of 7
December 1984.
Generic letter 8610 obviously was issued 8
after that.
9 I would like to read from the cover letter of the 10 generic letter a couple of sentences.
"This package 11 represents recent staff assessments of these questions and 12 provides guidance as to acceptable methods of satisfying 13 commission regulatory requirements. "
Attention to the next 14 sentence.
"other methods proposed by a licensee for 15 complying with commission regulations may also be satisfied 16 and will be considered on their own merits."
We proposed, 17 and we feel you have accepted, other methods.
18 our basis that we presented to you for other 19 methods of compliance with 8610 and particularly this issue 20 of cable to cable interaction, were low probability of 21 interaction for ungrounded DC systems, and the fact that we 22 had ungrounded AC systems and had low probability of l
23 interaction.
That was our basis and that is what we believe 24 you have accepted.
It is documented in a December 21, 1984 25 letter to the commission.
Your acceptance enclosure of that Heritage Reporting Corporation (202) 628-4888
1 i
43 1
is documented by at least three inspection reports; at least 2
two that I have access to today, 8741 and 8640.
3 In conclusion, we meet 8610.
We meet it by 4
approved alternate exceptions.
5 MR. PIERSON:
I've looked at the inspection reports 6
and I'm not sure that I can agree with what you say.
This is 7
probably the wrong forum to take that up.
What we'll do is 8
we will understand what you have done with respect to 9
spurious actuation cable to cable.
I think we can understand 10 that you essentially have not done it in accordance with 8610 1
11 literally, but you feel like the exceptions that you do have 12 have been evaluated by the NRC and accepted by the NRC.
Is 13 that a correct synopsis?
14 MR. FOX:
Again, I want to make the statement that 15 8610 is not a set of requirements.
It is merely guidelines 16 and it allows alternate means.
17 MR. PIERSON:
I understand that.
18 MR. FOX:
We feel like we meet it per the alternate 19 means.
20 MR. PIERSON:
I understand what you're saying, but 21 I am not telling you that I am accepting what you're saying.
22 Are there any more questions with respect to 23 spurious actuation?
24 MR. GARG:
Just for the record, I want to know, we 25 have talked about high/ low interface, and we haven't talked Heritage Reporting Corporation (202) 628-4888
l 44 l
1 about any other subjects.
Have you considered any other 2
subjects besides high/ low interface for this?
3 MR. WILLIAMS:
Let me try to address that.
4 Specifically to address cable to cable, the answer is no.
i 5
But much of the analysis that we did with Appendix R and our 6
calculations bounded the cable to cable case.
7 For instance, in the main control room, the 8
spreading room, the auxiliary instrument room, we looked to 9
see if we had an alternate path for any device that faulted.
10 We didn't consider the mechanical means for the basis for 11 that fault, we just said that we had a faulty device and do 12 we have an alternate.
13 If you look at things like the short circuit 14 calculation and some of the coordination studies, basically 15 they did the same thing.
They considered like a three phase 16 fault, regardless of how they got it, whether it was 17 conductor to conductor or cable to cable.
So there is much 18 in the analysis we feel is bounded the cable to cable case, 19 aven though specifically we did not address it that way.
20 MR. PIERSON:
Could you discuss the RCS letdown 21 path in terms of reactor coolant system letdown in the event 22 of an Appendix R event?
It says on your Attachment 5, 23 "Purther analysis being performed that will result in an RCS 24 letdown path."
Can you amplify on that statement and explain 25 what you mean by that?
i j
Heritage Reporting Corporation l
(202) 628-4888
45 1
KR. SULLIVAN:
You're referring to the preliminary 2
work that had been done?
3 MR. PIERSON:
On Attachment 5 of your submittal 4
today.
5 MR. FOX:
Give us just a minute. ?
6 MR. PIERSON: to the submittal you 7
gave us. It's on the same page that we talked about with 8
respect to pressurizer PORVs and also the reactor head vent 9
valves.
He said, "Further analysis is being performed that 10 vill result in an RCS letdown path."
11 MR. SULLIVAN:
That analysis is in its preliminary 12 stage right now.
I think it's being reviewed and checked, is 13 that right Norm?
14 MR. KOONTZ:
No, we have the analysis right here.
15 MR. PIERSON:
May I ask what does that mean?
What 16 is that analysis to accomplish?
17 MR. SULLIVAN:
That analysis ensures that a 18 pressurizar PORV or a head vent path is available for letdown i
19 from the RCS.
20 MR. PIERSON:
I'm confused then.
Is that strictly 21 for a fire, or is that --
22 MR. SULLIVAN:
This was done for a fire.
It's not 23 a current requirement of our shutdown logic or safe shutdown 24 to have a letdown path.
This evaluation was done to see if 25 the plant in its physical layout had any problems in it where Heritage Reporting Corporation (202) 628-4888 I
i
46 1
you would not have a letdown path.
2 MR. PIERSON:
What does that mean with respect to 3
the statement you said earlier that you didn't take Appendix 4
R approved path for letdown then for vent valves or PORVs?
5 KR. SULLIVAN:
As I stated, in the current shutdown 6
logic for safe shutdown, letdown is not identified and we do 7
not take credit for it.
8 MR. PIERSON:
Then why are you doing this letdown 9
analysis?
10 MR. SULLIVAN:
A question was asked to us 11 concerning letdown and we went off and looked at the cables 12 that we already had plotted because we had to ensure letdown 13 would isolate.
This was sort of the flip question, now can 14 you ensure a letdown path is available.
So we had all the 15 cables plotted-We just went out and looked at what they 16 were.
17 MR. PIERSON:
So you're telling me that in all 18 cases you've got an RCS letdown path available?
19 MR. SULLIVAN:
No, I'm not telling you that.
20 MR. PIERSON:
Okay.
You're telling me as a result 21 of that that you've done an analysis to show that your 22 pressurizar PORV and your reactor coolant systen vents can be 23 used as a letdown, is that correc*?
24 MR. SULLIVAN:
No.
We're saying we've done an 25 analysis to see if they can be used as a letdown path.
Heritage Reporting Corporation (202) 628-4888 i
47
)
1 MR. PIERSON:
So what is the conclusion?
Do you
]
2 have a letdown path?
3 MR. SULLIVAN:
In all but two locations which are 4
in the annulus area for Unit 2.
I don't know about Unit 1.
l 5
We could have a letdown path.
6 MR. PIERSON:
And you're going to address those two 7
locations to provide to us with this analysis y '1've got 8
here?
Is that what you're doing?
9 MR. FOX:
Yes, we will.
10 MR. PIERSON:
Are there any other questions with 11 respect to question number 12?
12 (No response) 13 MR. PIERSON:
I'm going to move on then, to 14 question 13.
I don't have eny questions abcut question 15 number 13. Does anyone in the staff have a question about 16 number 13?
17 (No response) i 18 MR. PIERSON:
Question number 14.
19 MR. GARG:
I want to ask one question on question 20 number 12 again.
You have not considered the internal 21 circuits for the cable to cable interaction?
22 MR. WILLIAMS:
Yes, we have considered internal.
23 MR. GARG:
I mean the two cables.
I mean the 24 circuits connected to the common bus could be shorted bp one 25 single short.
Have you considered that?
]
Heritage Reporting Corporation (202) 628-4888
46 1
MR. MARINOS:
This is in connection with your 2
statement earlier about the ungrounded AC and DC which is a 3
legitimate electrical engineering argument, but if you had, 4
that is true perhaps, for circuits that come from independent 5
sources.
If they are ungrounded, yes, it is a legitimate 6
argument.
But if the circuits are coming from the same 7
common bus, have you addressed t It will not be.
8 MR. WILLIAMS:
In the sinal analysis, the cable 9
to cable short was not considered.
The basis for not 10 considering the cable '.o cable short was the fact with the 11 ungrounded system and the kind of the random arrangemer*
12 we've got in cables and trays, the fact that it does take 13 something on a common bus or a common transformer to cause 14 that short, that we considered that a much less likely event 15 to happen than having conductor to conductor shorts within a 16 cable.
Foq the case that you brought up for the high/ low 17 pressure interfaces, we did in fact go back and evaluate 18 those four cable to cable shorts.
19 MR. GARG:
No, but for the circuits besides 20 high/ low, you have to consider single short and if it can 21 cause a spurious acuations.
22 MR. WILLIAMS:
The way the analysi,s was done within 23 the main control room, the spreading room, and the aaxiliary 24 instrument room, we bounded that analysis by making sure we 25 always had an alternate path, outside the high/ low pressure
)
Heritage Reporting Corporation (202) 62W-4888
49 1
interfaces and outside those three areas we have not 2
specifically looked at cable to cable shorts.
But we do not 3
think from the basis of our system that that's really a 4
credible event.
5 MR. GARG:
Well, you are not in compliance with 6
8610.
j 7
MR. ROTELLA:
Have you responded to 8610?
8 MR. HOSMER:
We have never been asked to.
9 MR. GARG:
Aren't you supposed to respond to j
l 10 generic letter?
11 MR. FIORAVANTE:
Could you just please explain why 12 you are interpreting them as not in compliance with 8610?
13 MR. GARG:
Because 8610 requires that for any, --
14 high/ low interface you have to consider if a single short can 15 croate those --
16 MR. FIORAVAh"'. :
Isn't it also in 8610 that it says 17 for ungrounded DC you dc
't have to consider --
18 MR. GARG:
If you are a common bus then there is a 19 case.
If you are ungrounded, separate circuit then you 20 don't. Then you don't have a scenario.
21 MR. FIORAVANTE:
I guess I'm a little confused.
22 Where in 8610 does it say anything about a common bus?
23 MR. GARG:
In 8610, I think that was referenced to 24 the separato circuit.
25 MR. MARINOS:
You can only take credit for Heritage Reporting Corporation (202) 628-4888
1 50 l
l 1
ungrounded system if it will'be two separate sources.
If it 2
is the same one it doesn't matter whether it's grounded or 3
ungrounded, if it is the same circuit.
4 MR. PIERSON:
We will discuss this lawar.
5 MR. McGARRY:
This is Mike McGarry.
I just want to 6
make one comment.
7 8610, so there is no confusion, did not require 8
that a utility respond to 8610.
It was put on the street to 9
assist utilities and provide guidance.
In this situation 10 Sequoyah had already formed its fire hazards analysis in 11 advance, prior to the issuance of 8610.
12 MR. PIERSON:
I understand that.
13 Has everyone signed the attendance sheet?
If you 14 haven't I'll pass it down.
15 I'd like to continue on with question 14 if that 16 takes care of the questions on number 12.
17 KR. WESCOTT:
I would like to spe'ak to someone on 18 question 14 if they would be willing to address it.
19 MR. PIERSON:
What is your question?
20 MR. WESCOTT:
I spoke on the phone with Jimmy 21 Pierce and we discussed the various situati
's where you 22 actually have a non-ducted damper between wall, and there 23 was one item here that I can't remember us talking about and 24 that was where you had fire detection on both sides and 25 automatic suppression on only one side.
That may have been Heritage Reporting Corporation (202) 628-4888
i 51 1
mentioned, but I didn't hear it at the time.
2 I'm a little bit concerned about this particular 3
situation and I'd like to ask two questions about areas where 4
you have this particular type of setup.
5 First of all is the manual suppression.
Can one 6
get to that without going through the room where the fire is 7
in all cases?
8 KR. PIERCE:
Yes.
Tre manual suppression is in 9
some auxiliary instrument rooms, I believe, aux shutdown 10 boards, and the actuation of those circuits are in another 11 room.
12 MR. WESCOTT:
The room where the major fuel load 13 is, the significant fuel load, that has an automatic 14 suppression I assume in all cases?
15 MR. PIERCE:
Yes.
16 MR. WESCOTT:
And the rooms that do not have 17 automatic suppression have very limited fuel load.
18 MR. PIERCE:
The only fuel load in there is the 19 insulation on the cables in the trays, and those trays are 20 coated with pneunastic.
We've got ionization smoke detection 21 in that room and manually actuated suppression.
22 MR. WESCOTT:
Thank you.
23 MR. PIERSON:
Any other questions with respect to 24 14?
25 (No response)
Heritage Reporting Corporation (202) 628-4888
52 1
KR. PIERSON:
Let's go on to question 15.
Provide 2
the fire interaction study for a fire in the immediate 3
vicinity of the pressurizar.
That comes back to the 4
questions we discussed earlier in question 12, and I think 5
we're going to have to address that in some other format.
We 6
understand what your position is, and we'll have to come 7
back to you later.
8 So I'd like to go on to question 16.
TVA has 9
provided us this list which is requested in question number 10 16.
I'll go on to question 17.
11 Question number 17 is with respect to passing of 12 liquid through a pressurized or code safety valve and the 13 resultant erosion and subsequent ability of the valve to 14 reseat.
This question and many of the questions that we've 15 covered seem at face value to be outside the context of 16 Appendix R, but the way some of these questions were 17 developed was on the assumption that some of the scenarios 18 would be applicable, and in that event these questions 19 necessarily would follow through.
This is, of course, coming 20 from where the pressurizer, your system becomes solid and you 21 use a code safety valve as a pressure control mechanism.
It 22 wasn't clear to us, and may not still be clear to us, that 23 that doesn't occur.
24 You've provided a list here that talks about the 25 EPRI test, and I understand that code safeties are not Heritage Reporting Corporation (202) 628-4888 l
1 53 1
necessarily designed to pass water, although some of them 2
will up to a point.
But I don't think there is anything more 3
to be gained by asking you any more questions with respect to 4
that one, so I'd like to go on to question 18.
l 5
MR. HOSMER:
Can I ask a question?
6 MR. PIERSON:
Sure.
7 MR. HOSMER:
Would it help if we explain to you why 8
we do not believe it will go solid?
9 MR. PIERSON:
Yes, but let's wait until we go 10 through the questions.
I think there is another question 11 that addresses that specifically.
12 Number 18 is provide rationale for protection of 13 centrifugal charging pump cavitation from a spurious 14 actuation in the volume control tank isolation va.lyc.
15 I'd like to talk to you a little bit about that.
16 I'm not quite sure from talking to Mr. Koontz and Mr.
17 Burzynski, it's my understanding that if you do have a 18 spurious actuation of that isolation valve, that you still 19 have the ultimate charging pump available, is that correct?
20 MR. SULLIVAN:
The approach to the charging pump 21 suction is to either remove power by opening the breaker on 22 the board, transferring suction to the'RWST and removing 23 power from its breaker so you don't have the same problem 24 again, or stopping the pump by the operator in the control 25 room.
This is all proceduralized in the SOI 26.2 to be done.
Heritage Reporting Corporation (202) 628-4888
54 1
MR. PIERSON:
Do you have any sense of how long 2
you've got before the charging pump cavitation results in 3
inoperability of the charging pump?
4 MR. SULLIVAN:
I'd like to address that question by 5
making the statement that we have done an evaluation and 6
determined that for a fire in the area we should have at 7
least ten minutes to perform these actions before the valves 8
go closed.
9 MR. PIERSON:
Ten minutes before the VCT isolation 10 valve goes closed
- 11 MR. SULLIVAN:
Yes.
12 MR. PIERSON:
How would the operator know that a
~
13 fire started?
Why would he know there was a fire in that 14 area?
i 15 MR. SULLIVAN:
Fire detection, fire suppression i
l 16 actuation, the fire alarm system.
17 MR. PIERSON:
So when a fire occurs in that area he 18 secures that charging pump and volume control tank and shifts 19 the suction to the RWST tank?
20 MR. SULLIVAN:
Yes.
21 MR. PIERSON:
Is there any credibility or any 22 possibility that the same fire that would affect that volume 23 control tank isolation valve could also affect the standby 24 charging pump?
25 MR. SULLIVAN:
I believe when you get to some of Heritage Reporting Corporation (202) 628-4888 l
E
55 1
your end devices such as your MOV boards where power to the 2
valves comes from, that's a possibility.
Down locally at the 3
valves and throughout most of the plant, no, that is not 4
credible because the valves are in a room by themselves, 5
charging pump cables don't go in that room, and to address a 6
little further about the MOV boards. for the valves to go 7
closed, it would almost have to be a fire internal to those 8
boards.
9 MR. PIERSON:
Which wouldn't affect the power to 10 the charging pump?
11 MR. SULLIVAN:
Which wouldn't affect the cable 12 trays in the area.
That's not the approach we took.
We 33 looked at that.
We took the approach of getting the operator 14 to get power off the' valves which was consistent with what 15 the rest of the industry has done to address this generic 16 Westinghouse type question.
17 MR. PIERSON :
Did you provide that analysis to us j
18 in one of your submittals?
19 MR. SULLIVAN:
Which analysis?
20 MR. PIERSON:
What you're talking about, this 21 approach you're talking about here.
22 MR. SULLIVAN:
I think you've got a copy in SOI 23 26.2.
24 MR. PIERSON:
All right.
25 MR. WESCOTT:
What type of fire detection do you Heritage Reporting Corporation (202) 628-4888
1 56 1
have in that area, do you know?
2 MR. SULLIVAN:
Just ionization alone.
3 MR. PIERSON:
One other question.
The tripping 4
mechanism of the centrifugal charging pump, is that protected 5
so the sr.me fire couldn't wipe out the volume control tank isolation valve and the tripping mechanism to the pump?
6 7
Would it be a case where you couldn't isolate the pump?
8 MR. SULLIVAN:
There are three alternates involved.
9 He can move power from the VCT outlet valve, such that they 10 will not go closed.
He can transfer suction, or basically 11 open the RWST valves and remove power from them so they will 12 not go closed.
Or he can trip the pump.
So there are two 13 backups in case he cannot trip the pump.
I cannot address 14 that.
I'm sure you can build a fire in a certain place and 15 you couldn't trip a pump, but I cannot address if that's the 16 same fire that would cause a problem with these valves, 17 MR. PIERSON:
But you're sure that you still have 18 at least one remaining pump operable, the standby pump?
19 MR. SULLIVAN:
What I'm trying to say is we have 20 two other methods that the operator has in a situation that 21 should he not be able to stop the pump he can remove power 22 from the VCT outlet valves or he can go ahead and open an 23 RWST supply valve and remove power from her.
24 MR. PIERSON:
Any more questions about question 25 number 18?
Heritage Reporting Corporation (202) 628-4888
57 1
MR. NOTLEY :
This is Dave Notley.
2 A couple of weeks ago we had a fire protection 3
engineers meeting in Atlanta.
One of the questions that came 4
up was sending out a fire brigade immediately upon receipt of 5
fire alarms.
The response was that most plants send a runner 6
down to establish that there is a fire before they call the 7
fire brigade and dispatch them.
8 Do you do the same thing, and what you were just 9
talking about?
You have ten minutes to take action and 10 prevent damage to the pump, and you were asked does the 11 operator perforr this action immediately upon receipt of the 12 f f.'Je al a rm.
I think I heard you say yes, but I want to make 13 sure you don't send a runner down to establish that there is 14 a fire before you start this kind of action.
15 MR. ROTELLA:
If there's a fire you're going to 16 shut the plant down with boron coming from the RWST.
17 MR. SULLIVAN:
The way we normally do it is if 18 someone calls in on 6299 which is the plant fire alarm, all 19 the fire brigade will respond.
I know that for a fact.
The
~ 20 fire brigade leader is the man responsible for notifying the 21 control room when there is a fire affecting plant equipment.
22 If it's a cigarette smoldering in a corner in a turbine 23 building somewhere and the fire alarm comes in, we're not 24 going to go through this scenario.
The fire brigade leader 25 is responsible for notifying the shift supervisor in the Heritage Reporting Corporation (202) 628-4888
58 1
control room who is in the command function when there is u 2
fire affecting plant equipment, he knows the location of the 3
fire, we go to our fire interaction manual, you open it up 4
for that location, and it will tell you for that location 5
what might happen and what action he needs to take.
6 MR. NOTLEY :
I think your answer is yes, that you 7
do send someone down on receipt of automatic fire alarm to 8
establish that there is a fire.
9 KR. SULLIVAN:
True.
10 MR. PIERSON:
You need all the ten minutes, right.
11 MR. SULLIVAN:
I'd like to add a concluding 12 comment.
Our response to this condition which is generic to 13 a lot of other Westinghouse PWR's is consistent with what 14 they're doing, and we think we've taken the appropriate 15 action in this area consistent with other safety requirements 16 to protect the charging pump from loss of suction.
17 MR. PIERSON:
And youre sure that you have the 18 remaining charging pump.
There is nothing in your procedure 19 that tells the guy to secure the one charging pump and then 20 turn on the B charging pump on the same suction and destroy t
21 it as well, is that correct?
22 MR. SULLIVAN:
There is nothing in the instruction 23 for that.
24 MR. PIERSON:
Good.
25 The next question is question number 19.
The basis Heritage Reporting Corporation (202) 628-4888
59 1
for fire protection of Appendix R shutdown systems inside the 2
containment.
We addressed most of the questions with respect 3
to this in question number 12, spurious actuation.
I don't 4
have anything else to add to this.
Does anyone else have 5
something they want to talk about with respect to question 6
19?
7 (No response) 8 MR. PIERSON:
If not, I'll go on to question number 9
20.
Question 20 discusses the possibility of two low 10 pressure signals causing an actuation of the safety injection 11 system.
Sequoyah says safety injection is not required for 12 safe shutdown at Sequoyah.
I don't have any questions with 13 respect to your response here.
Does anyone on the staff have 14 anything they want to address?
15 MR. ROTELLA:
I have a question back on 19.
for 16 the RER valves that we talked earlier, on 74-2, you stated 17 that you've done a review of the area and have determined 18 that you can't have a fire that is going to propagate from 19 the motor on that valve, and that there are no surrounding or 20 intervening combustibles.
I guess I need to ask the question 21 then, do you intend to submit a deviation for that condition?
22 MR. PIERCE:
No, we had not planned on submitting a 23 deviation on that.
What we were looking at is the guidance 24 you had given in 8610 said we could do a fire hazard 25 evaluation in the area as long as it's done by appropriate Heritage Reporting Corporation (202) 628-4888
f 60 1
- people, i.e.,
fire protection engineer and systems engineer, 2
and provide that information to you for review.
If you 3
agree, and it's intuitively obvious that conditions we 4
describe are as they state so we don't have to submit a 5
deviation.
6 MR. ROTELLA:
I'd like to ask the staff, Dennis 7
Kubicki, if he could respond to that.
Is that true?
8 MR. KUBICKI:
This is Dennis Kubicki.
Do I 9
understand your question that you're asking me whether they 10 have to submit a deviation for this condition?
If 8610, the 11 premise that I'm going to be basing my answer on is that if 12 8610 establishes means for satisfying 3GJ LNO of Appendix R, 13 and if they don't conform with that guidance, then a 14 deviation is appropriate. I think in this particular case we 15 should avoid the semantical distinction and say that if 16 they've got a condition that doesn't literally conform with 17 the explicit guidance in 8610, then they should provide the 18 justification to us and we should review it without really 19 calling it a deviation or whatever.
20
'MR.~ GEORGE:
This is Hank George.
The condition 21 we're talking about here is one where what was evaluated was 22 whether these are components that would be susceptible to 23 fire damage.
Where the evaluation says that, basically 24 concluding that you can still get in there and manually 25 operate these valves, it's not an engineering evaluation to Heritage Reportiing Corporation (202) 628-4888
.r-
l 61 1
justify adequacy of separation which is the 3G item that 2
Dennis is referring to.
So this engineering evaluation is 3
not one that relates to a demonstration of meeting 3G.
It's 4
just whether these components could be damaged by a fire.
5 Since they couldn't, these are valves that have manual 6
operators on them.
Even though they are motor operated, 7
there are still hand wheels on them.
That function is what 8
was cencluded as still being operable for fires in that area.
9 So under that, I think our interpretation would be 10 that that is not an item requiring an engineering evaluation 11 per 8610, or a deviation request.
12 KR. McGARRY:
I want to agree with Dennis Kubicki 13 in that let's put the semantics aside and get down to what is 14 really the substantive issue.
But 8610 does state in page 14 15 the question, if a utility determines that a deviation from a 16 guidance document exists, then an exemption request needs to 17 be filed.
If so, what is the legal basis for this 18 requirement?
The response is no.
In other words, you can 19 have a deviation from 8610 and you don't have to file an 20 exemption.
21 MR. PIERCE:
Let me just say, we have provided you 22 with that evaluation.
If you've got any questions concerning 23 that evaluation we'll be glad to talk to you.
24 MR. ROTELLA:
That was the March 8th submittal, the 25 one we just got?
Heritage Reporting Corporation (202) 628-4888
62 1
MR. PIERCE:
Yes.
2 MR. ROTELLA:
Thank you.
3 MR. PIERSON:
Okay, we'll go on.
I think we're on 4
question 20.
I don't have any questions on question 20.
5 Does anyone in the staff wish to address question number 20?
6 (No response) 7 KR. PIERSON:
Question number 21, has TVA evaluated 8
effects of fire on instrument sense lines?
Provide the 9
results of the evaluation on the functional analysis report.
10 We have some information from TVA with respect to 11 fire effects on instrument sense lines, and I think we still 12 have a few remaining questions.
Mr. Garg, do you have 13 questions still with respect to instrument sense lines?
14 MR. GARG:
- Yes, I have a couple of questions.
One 15 is I think on your document QYR SQP SQN 38, on Item 4 and 5, 16 there is a statement that -- nothing inside --
I think we 17 talked to somebody in here to explain why it wasn't done.
I 18 would like that information to be put in the record.
19 MR. PIERCE:
I'd like for Ed Connell, one of our 20 fire protection engineers to address that for you.
21 MR. CONNELL:
The basis of the question was 22 regarding whether or not a fire inside containment would make 23 the containment untenable for manual operation of the valve.
24 The evaluation in the areas of these penetration boxes 25 concluded that a fire inside the penetration box could damage Heritage Reporting Corporation (202) 628-4888
1 63 1
the cables inside that box and therefore we would not be able 2
to operate the valve outside containment.
A fire in this box 3
would certainly be a small fire, would not cause the spurious 4
operation or release of any kind of RCS volume into the 5
containment, and the manual operation of the valve could 6
still be achieved.
7 MR. GARG:
Okay.
Another question I have is, I 8
think the analysis you gave on the document SQN 00D052 EPM 9
ESC 011888 did address only the pressurizer and --
10 instruments.
My question is, have you considered all other i
l 11 instruments for which you take a credit in the Appendix R?
j 12 MR. CONNELL:
This particular analysis dealt only l
13 with steam generator and pressurizer level instrumentation.
14 MR. PIERCE:
Let me interrupt right here and give 15 you a little background on that.
We wrote a CAQ back in 16 early 1987 that said instrumentation sense lines had not been 17 adequately reviewed for fire fix.
As a result of that CAQ we 18 did an Appendix R separation analysis on instrumentation 19 sense lines.
The result of that CAQ was another condition 20 adverse to quality that identified four areas where we had 21 interactions in which the sense lines did not meet Appendix R 22 separation criteria.
The fire hazard analysis evaluation was 23 done to address those four areas where adequate Appendix R 24 separation did not exist for those sense line instruments 25 that were identified in that CAQ.
Heritage Reporting Corporation (202) 628-4888
i t
64 1
MR. CONNELL:
The conclusion regarding the level 2
indication for pressurizar and steam generator concluded that 3
we would have at least one level indicator for each steam i
4 generator and we would retain one level instrument for the 5
pressurizer, for any fire inside the containment.
6 MR. GARG:
My question is not with your analysis on 7
this.
My question is do you have any document that you don't 8
have any of that problem with the instrument lines?
9 MR. PIERCE:
We documented where we had problems.
10 I don't think we have to document where we don't have 1
11 problems.
We did an evaluation and found out where we did 12 have problems, and then addressed them.
13 MR. GARG:
You are saying, where you have addressed 14 your evaluation, where can I find your evaluation on the 15 instrument lines?
16 MR. PIERSON:
What Mr. Garg is asking for is where 17 do you have the evaluation that says the only point in 18 containment where you have a problem is with respect to the 19 steam generator level and the pressurizer levels?
20 MR. PIERCE:
The corrective action 01QEASQP 870857.
j 21 MR. PIERSON:
Do we have a copy of that?
22 MR. PIERCE:
We gave you that CAQ.
Then CAQR 23 870151 identified where we had interaction specifically.
24 MR. PIERSON:
We'll look at that.
I have one other 25 question.
Did you discuss pressurizer or steam generator Heritage Reporting Corporation (202) 628-4888
65 1
pressures?
I heard levels.
Is a pressure required?
2 MR. SULLIVAN:
Steam generator pressure is outside 3
containment.
It was provided separation by the original --
4 saw a reevaluation of the 84-85 time frame.
5 RCS pressure was your second part of that, is that 6
correct?
7 MR. PIERSON:
Yes.
8 MR. SULLIVAN:
There are three RCS pressure 9
channels, two of them are pan instrucantation that are routed 10 outside to the auxiliary building, and the other one is off 11 which is wide range RCS, the other one is off the 12 pressurizer.
13 MR. PIERSON:
So you have three instruments, is 14 what you're saying?
15 MR. GULLIVAN:
Three instruments.
16 MR. PIERSON:
You're confident that --
17 MR. SULLIVAN:
We're confident we have separation 18 between the two pans and the one over on the pressurizer.
19 MR. PIERSON:
I'm sorry, I missed something there.
20 MR. SULLIVAN:
The requirement being a 20 foot 21 separation inside containment.
22 MR. PIERSON:
So you met that 20 foot separation is 23 what you're saying?
24 MR. SULLIVAN:
Yes.
25 MR. GARG:
How about instrument line outside the Heritage Reporting Corporation (202) 628-4888
f l
l 66 1
containment?
Did you consider those?
2 MR. SULLIVAN:
Yes, by the electrical engineering branch, and I am not sure we submitted that calculation, but 3
4 we will give you that information.
We don't have it with us 5
right now.
6 MR. LIAW:
This is B. D. Liaw.
7 With regard to what you said, Mr. Sullivan, about 8
CAQR and another, have they been closed for restart?
9 MR. PIERCE:
Yes, they were determined to be 10 restart, and they are already complete.
Corrective action of t
11 those has been complete.
i 12 MR. PIERSON:
Do we have any other questions on 13 number 21?
14 MR. HUBBARD:
George Hubbard.
I have one quick 15 question on that.
He referenced a CAQR 870151.
In looking 16 through the documentation this morning, I didn't find that 17 particular CAQR.
18 MR. FOX:
We'll get it to you.
19 MR. PIERCE:
I apologize for that.
I thought we 20 had sent that to you.
21 MR. PIERSON:
Any other questions on sense lines, 22 number 21?
23 MR. GARG:
No, I don't have any.
24 KR. PIERSON:
The next question I'd like to talk 25 about is question 22.
I'd like to point out something.
Heritage Reporting Corporation (202) 628-4888
67 Within the response with the exception of number 12, 1
the 2
response to number 22 is very difficult.
It dances around 3
the issue, and I think I understand what you're trying to i
4 say, but it's misleading.
Explain why the' fire in 5
containment would not affect the instrumentation as discussed in the task group deposition of issues in B2 used by the 6
7 operator.
Distinguish between a fire and c loca.
You talk 8
about what you take credit for here, and then you go into a list of instruments there without differentiating which of 9
10 those instruments are Appendix R instruments, which of them 11 are safety grade instruments, it's just a list of 12 instruments.
It's difficult to make any sense of that.
But j
13 I talked to your staff and I think I understand where I can 14 i
expect an answer from you with respect to that question.
So 15 I don't have anything to address on that, but I did want to 16 make a comment there.
17 Would you like to say anything?
18 MR. HOSMER:
We apologize for confusing you.
19 i
MR. SULLIVAN:
Do we owe you something on this one?
20 MR. PIERSON:
You told me you were going to take 21 this list of instruments and tell me which were EQ and which i
22 were safety related and which were fire protection 23 instruments.
24 MR. SULLIVAN:
Okay.
We have a list of those that 25 are EQ.
As far as addressing the safety related and Heritage Reporting Corporation (202) 628-4888
i 68 i
i distinguishing between a fire and a loca, we can explain that 2
to you also.
3 MR. PIERSON:
We'll listen.
4 MR. SULLIVAN:
This question is tied into 20 and 26 5
as well.
It is possible for two low pressure signals to 6
cause a spurious SI in this plant, we believe, but SI is not 7
required for safe shutdown.
8 Narrow range RCS pressure is also not required by 9
our analysis.
The fire that's inside containment, we have 10 wide range RCS pressure which is located in the auxiliary 11 building, elevation 690; and some outside containment 12 radiation monitors, 9106 and 112 which sample inside 13 containment.
Also containment pressure differential 14 transmitters which measure containment pressure that are 15 located in the annulus.
All these things are principally 16 outside the reactor building itself where we believe they 17 would be available post-fire.
18 Additionally, as we have mentioned earlier, we'll 19 have pressurizer level available and we'll have steam 20 generator level, one for each of the steam generators.
Thus 21 the SI termination criteria that's specified for the operator 22 to use which states that sub-coolant has to,be greater than 23 40 degrees since he has RCS pressure and since he has 24 temperature in two of the four loops, he can satisfy that 25 point of the four point termination criteria.
Heritage Reporting Corporation (202) 628-4ssa i
I
69 i
1 The second point being RCS pressure stable and 1
2 increasing.
He can satisfy that for his spurious SI.
And with steam generator level greater than a 10 percent narrow 3
i 4
range in at least one steam generator, he can verify that as 5
well.
6 The last item is pressurizer level being greater 7
than 20 percent.
Since pressurizer level is guaranteed, he 8
can check that.
I 9
The operators have the appropriate training to know 10 and apply this SI termination criteria.
Additionally, j
11 simulator exercises are planned to start I believe next week.
12 That's going to address fire scenarios.
We're going to take 13 this fire interaction manual that I've talked about, and 14 we're going to start failing instruments for a fire in a 15 given area and see if the operator can respond to it i
16 properly.
17 MR. PIERSON:
That's a good idea.
18 MR SULLIVAN:
In conclusion, the operator's got 19 sufficient information to check the SI termination criteria.
20 He'll be able to distinguish between a loca and a fire, 21 identify spurious SI, and terminate the spurious SI and proceed with mitigating the effects of the fire.
22 23 MR. PIERSON:
Thank you.
I don't think you need to 24 say anything more on that particular question.
25 I'm ready to move on to question number 23 unless Heritage Reporting Corporation (202) 628-4888
70 1
seneone has other comments.
2 On question 23, discuss how steam generator 3
overfill from the main feedwater system is protected against 4
fire in the control building.
In particular, address 5
response times for feeder line isolation following loss of 6
control building.
7 The question that we're really asking here is in 8
the event that you have a, how do you guarantee that you can 9
complete this response here?
You say that AoI 27 provides 10 that before the main control room is abandoned the reactor is 11 tripped and the MSIV's are closed.
Have you provided some 12 evaluation of your control power to MSIV's to state that they 13 can or cannot be operated?
Could you elaborate on that?
14 MR. SULLIVAN:
Yes, I can.
15 For a fire in the control building that affects 16 plant equipment and that requires control room abandonment, 17 operators are going to be automatically dispatched out to the 18 auxiliary control room to c, tart their process.
AOI 27 is the 19 plant procedure for abandonment of the main control room and 20 it requires the operator to do these two things before he 21 abandons the control room.
22 MR PIERSON:
Are you sure the circuits would be 23 available to accomplish that?
24 MR. SULLIVAN:
Let me get to that, please.
25 He's going to trip the reactor and close the MSIV's Heritage Reporting Corporation (202) 628-4888
71 1
prior to leaving the main control room.
Note that closing 2
the MSIV's isolates steam flow to the main feed pump turbine 3
which is going to terminate your feed water flow and avoid 4
steam generator overfill.
5 Normally there is a manning overlap between the au'x 6
control room and the main control room, and when we get to 7
the aux control room which is only two doors away, about 150 8
feet, so it's less th4n two minutes we think he's going to 9
get there, once the aux control room is manned, the operator 10 places a transfer switch in auxiliary which removes the 11 damaged circuits in the control building complex and ensures 12 the MSIV is closed.
13 MR. PIERSON:
Could you repeat the last please?
14 MR. SULLIVAN:
Once the operator is in the 15 auxiliary control room and he takes the transfer switches and 16 puts them in auxiliary, the damaged circuits that are in the 17 control building complex are then removed from the circuit.
18 Should there have been a spurious signal over there, the 19 MSIV, that will be isolated from the circuit and the MSIV 20 will close.
21 MR. PIERSON:
You're saying that's accomplished in 22 two minutes?
23 MR. SULLIVAN:
Less than two minutes.
24 MR. PIERSON:
You've actually tested that two 25 minutes?
Heritage Reporting Corporation (202) 628-4888
72 1
MR. SULLIVAN:
No sir.
I'd like to add a little 2
bit more to this.
3 The MSIV's are fail close valve.
They have dual 4
train solenoids. They have an A train solenoid and a B train i
5 solenoid.
There is diverse isolation mechanisms provided in 6
the safe shutdown logic for fires outside the control 7
building.
That diverse mechanism is basically steam load 8
isolation in the turbine building, i.e.,
the trip valves, 9
throttle valves from the main turbine, the reheat valves.
10 The trip valves on the turbines to the main feed pumps.
11 On the feedwater isolation signal it's 60 percent 12 steam generator leveled.
Feedwater reg valves are going to 13 go closed.
There would have to also be some sort of spurious i
14 signal that causes the feedwater reg valve to stay open.
In 15 addition to the spurious signal that you've already assumed i
16 that keeps the MSIV open with dual trained solenoids.
17 Additionally, when a steam generator level gets to i
18 75 percent, you get the engineering safety feature actuation i
19 which closes all four steam generator feedwater isolation 20 valvss and trips the main feed pump circuit.
21 One third signal that could come in, since we've 22 already tripped the reactor, if you get the low TI, which you 23 will because you're steaming the power to the main feed pump 24 to feed the steam generators at 554 degrees, you'll pick up 25 another feedwater isolation signal.
Heritage Repo ing Corporation (202) 628-4888
73 1
MR. PIERSON:
Thank you.
I don't have any more 2
questions about that issue.
3 MR. FOX:
We have the CAQR with us, 870151.
We'll 4
be happy to provide this to you now and follev it with 5
official docketing, if you so choose.
)
6 MR. PIERSON:
I would appreciate that.
We received 7
a copy of this document that Mr. Fox just mentioned.
8 The next issue is question 24 which talks about 9
reactor coolant pump seal integrity.
The concern here was 10 that during a fire you couldn't maintain your reactor coolant 11 pump seal integrity and you could possibly end up with a loss 12 of coolant accident to your reactor coolant pump seals.
13 You implied that you had talked to Westinghouse 14 personnel and they indicated that a one hour value applies to 15 both qualified and non-qualified elastomers within your 16 reactor coolant pumps, and that you have in your procedure i
17 that you' isolate that in an event that it's lost.
18 I'd like you to comment on that.
In particular 19 with respect to this qualified and non-qualified elastomers.
20 I'm not sure I understand.
It's my understanding from 21 looking at that that it talks about high temperature 22 elastomers.
I'm not sure whether that's a qualified or 23 whether that's a qualified and a non-qualified elastomer.
24 MR. KOONTZ:
We have really reviewed the WCAP in 25 question and also talked to Westinghouse personnel.
There Heritage Reporting Corporation (202) 628-4888
i l
74
)
1 are two basic types of elastomers that are discussed in that 2
document and they are both called high temperature 3
elastomers.
One is called a qualified high temperature 4
elastomer, and the other one is called an unqualified high 5
temperature elastomer.
Basically they are different 6
manufacturer model numbers.
7 What we have at Sequoyah is equivalent to or better 8
than the Parker E515-80 elastomer which is called a high 9
temperature unqualified elastomer.
Both cases in the WCAP, 10 and this was confirmed by talking to Westinghouse personnel, 11 both of those type of elastomers, both whether they're 12 qualified or unqualified, will last for the first hour.
They 13 do degrade diff>trently later on, though, if seal cooling is 14 not available.
15 KR. PIERSON:
Do you have something you're willing 16 to provide to us to substantiate that?
A letter or something 17 like that?
18 MR. KOONTZ:
I think what we provided was a 19 reference to the WCAP.
Would you like us to provide a 20 letter?
We can get Westinghouse to write a letter to TVA 21 which we could provide to you if that would help.
22 MR. PIERSON:
That would be better than what we've 23 got here, because we've got something that's confusing to me 24 with respect to what's a high temperature and what isn't a 25 high temperature elastomer.
f i
Heritage Reporting Corporation (202) 628-4888 I
75 1
MR. KOONTZ:
We'll take that as an action item.
j 1
2 HR. PIERSON:
So your contention then is that your 3
procedure tells you to isolate the reactor coolant pump?
Are 4
you assured that the circuits that are available to isolate 5
thct, you can do that in these fire scenarios?
6 MR. KOONTZ:
I'm sorry, could you repeat that?
7 MR. PIERSON:
This one hour time frame that you've 8
got for your reactor coolant pumps, you say that's a 9
windmilling pump as I understand it, is that correct?
The 10 pump is de-energized, is that correct?
11 KR. KOONTZ:
The pump is de-energized for one hour, 12 a one hour interval, yes.
13 MR. PIERSON:
From your procedure you say that 14 you're going to secure the pump.
My question is, are you 15 assured that the power that's required to secure the pump, to 16 operate the control circuits or whataver, is available?
17 MR. SULLIVAN:
The trip breakers for the reactor 18 coolant pumps are located in the turbine building in a
{
19 separate environment and a different direction from where the 20 fire is that takes out the charging pumps.
21 MR. PIERSON:
How long would it take you to operate 22 the trip breaker there?
How long would it take you to do 23 that?
24 MR. SULLIVAN:
An ASE is stationed in the turbine 25 building and he's called our turbine building ASE and he's Heritage Reporting Corporation (202) 628-4888
76 1
about 50 feet from the pump, fro. +.e breaxer, from the 2
board.
A couple of minutes.
3 MR. PIERSON:
That's to rack out the breaker or 4
trip the breaker?
What are you talking about doing there?
5 MR. SULLIVAN:
Trip the breaker locally at the 6900 6
volt board.
7 MR. PIERSON:
That's just a switch to operate.
You 8
don't have to rack it out is what you're saying.
9 MR. SULLIVAN:
It's a switch on the board, on the 10 compartment.
11 MR. PIERSON:
Does anyone else have any questions 12 about this issue?
13 Number 25.
This considers spurious opening of the 14 pressurizer PORV and that's the same thing we talked about 15 earlier.
We really probably are not going to get anything e
16 additional from this question.
It's just essentially with a f
i 17 different nuance.
I don't have anything with respect to this 18 question I need to ask.
Does anyone have anything they want 19 to talk about?
l 20 (No response) 21 MR. PIERSON:
We'll go on to question 26.
Question
)
l 22 26 is a narrow range reactor coolant system pressure sensors, l
23 all the narrow range reactor coolant pressure systems are 24 included in the Appendix R analysis.
I think you've already 25 addressed that earlier.
We'd ask additional questions about Heritage Reporting Corporation (202) 628-4888
77 1
spurious actuation possibly causing an operator.to think a 2
loca was in progress. We talked about that earlier.
RCS 3
depressurization from a fire, spurious failures, and that's 4
been addressed in question 12.
5 I don't have any direct questions with respect to 6
that.
Does anyone have any items they want to address with 7
respect to question 26 from the staff?
8 (No response) 9 MR. PIERSON:
In that case, why don't.wo take a 10 short break, say a ten minute break, and then we'll come back 11 for public comments or TVA comments or both.
12 (Whereupon, a brief recess was taken.)
13 MR. PIERSON:
We have a few issues we want to talk 14 about, and then we'd like for TVA to talk, and then we're 15 going to let the public have a comment.
16 Mr. Kubicki has indicated that he'd like to clarify 17 one statement that he made earlier in the meeting, and I'll 18 let him start out with that.
19 MR. KUBICKI:
I'd like to preface my statement by 20 saying that the issue concerns wh9n TVA would have to request 21 approval for a deviation from the criteria of GJ&o.
What I 22 was trying to say earlier is that when it comes to a 23 particular condition in the plant, if that condition is not 24 in conformance with 3GJ&O as identified in the supplemental 25 guidance document of 8610, then that condition should be II Heritage Reporting Corporation (202) 628-4888 l
l l
1 78 1
identified as a deviation and a request for approval sought.
2 For example, if you have a situation within 3
containment where you have certain cables that you're claiming 4
are not going to be fire damaged, if the basis for claiming 5
that no damage is going to exist is not in conformance with 6
the separation criteria of 3G, then that's a deviation from 3G 7
and should be so identified.
8 What we have here is we have a couple of situations 9
where you aro taking credit for an internal analysis that 10 purports to demonstrate that certain components were not going 11 to be damaged by fire, and yet the basis for such is not the 12 separation criteria of 3G, so therefore that is a deviation 13-and you should be proposing a deviation for that.
14 Is that clear?
There are certain conditions that 15 represent deviations and should be so identified.
16 KR. PIERSON:
Would TVA like to comment on that now?
17 I don't think that is consistent with what we were talking 18 earlier.
19 MR. EBNETER:
We don't need to comment on it.
20 That's staff's interpretation right now, and we'll get back 21 with you on it.
22 MR. P7.ERSON :
I'd like to move on then.
23 We skipped over a couple of issues in the questions.
24 One concerned solid plant operations; one was letdown; and one 25 was this question number one which has to do with the Heritage Reporting Corporation (202) 628-4888
79 1
contamination in containment.
What I'd like to do is talk a 2
little bit about SOI 26.3 which allows, is your shutdown 3
procedure.
It says there that you need to be within 200 4
degrees of, is it 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br />?
T=15 hours?
Is there someone 5
that can comment on that?
6 I have this document that was given to me earlier by 7
Mr. Fox that says 200 degrees in 21 hours2.430556e-4 days <br />0.00583 hours <br />3.472222e-5 weeks <br />7.9905e-6 months <br />.
I'm just a little 8
bit confused about what the situation is.
9 MR. SULLIVAN:
Is that the Westinghouse motor?
10 MR. PIERSON:
Yes it is.
11 MR. SULLIVAN:
Your question again?
12 MR. PIERSON:
It's got a graph and it shows about 13 200 degrees in 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br />, 21 hours2.430556e-4 days <br />0.00583 hours <br />3.472222e-5 weeks <br />7.9905e-6 months <br />.
I remember earlier that 14 you took credit for 19 hours2.199074e-4 days <br />0.00528 hours <br />3.141534e-5 weeks <br />7.2295e-6 months <br /> and some place it's 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />.
15 I'm confused about your cooldown sequence for SOI 26.3.
How 16 long is it going to take you to get to that point?
And how 17 are you going to accomplish letdown to do that if you possibly 18 don't have pressurizer heaters or sprays?
In other words, to 19 provide boration to the core.
20 MR. SULLIVAN:
There are three or four questions 21 embedded in that, I believe.
I'll try to sort them out.
22 I would like to go through a little bit about 23 depressurization first, and how we would expect to 24 depressurize the system, and then get to the second part of 25 the question.
Heritage Reporting Corporation (202) 628-4888 i
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When we're cooling down the plant, feeding off the 2
feedwater to the steam generators and steaming, steam from the 3
steam generators, the primary side energy is being removed and 4
the primary side is shrinking.
RCS temperature obviously 5
decreases and cold RWST water is provided as makeup.
There is 6
going to be a certain amount of thermal losses from the 7
pressurizer during this period of time.
Thermal losses from 8
the pressurizer vapor space would be expected.
9 Should pressure not come down, the SDA can determine 10 that if with the current RCS temperature and boron 11 concentrations, 11 sufficient boron is in the core to just sit 12 there until pressure decays on down.
A realistic approach, 13 tnere are many ways to remove that excessive amount of energy, 14 pressure in the core.
Obviously the technical support center 15 and operational support center is going to be manned post-16 fire.
It's affected the plant in this way.
We made some real 17 unlikely assumptions through all of this that the boric acid 18 transfer system, the letdown system, is all not available; 19 that we've not been able to supply the 20,000 PPM boron from 20 the boric acid tanks; that the only water supplied is the 21 25,000 gallons that you normally make up when the RCS shrinks 22 to a normal cold shutdown condition.
23 only it all those cases are required and also the 24 worst case conditions for the reactivity analysis that we've 25 done, and I'd like to go through some of those worst case Heritage Reporting Corporation (202) 628-4888 1
61 1
reactivity assumptions.
I think this was quoted as the worst 2
case Appendix R fire.
It has done all the things I have just 3
mentioned, plus it assumes this scenario.
4 The plant had been at 100 percent power.
There is a 5
There is a post-trip review conducted and a 6
fast restart decision made.
Maximum delusion is started in 7
order to try to fast restart the plant, at the same time Xenon 8
is peaking.
Xenon peaks somewhere between nine and ten hours 9
after a 100 percent trip.
This analysis assumes we're 10 reaching 100 percent power with boron reaching its peak, which 11 is obviously not possible.
This gives you the minimum boron 12 concentration in the core, and that will give you the initial 13 condition for the worst case Appendix R fire.
14 In reality, in today's world, if you have a trip and 15 you go through and do a post-trip review, you're not going to 16 get it done and get the plant restart decision made prior to 17 xenon peaking.
You're not going to be reaching, even if you 18 tried to go back into core, you're sure not going to be 19 getting significant power levels up to get to 100 percent 20 power with xenon peaking.
21 Additionally, should all of that happen, in four 22 hourn you've brought xenon out.
Your reactor flux has already 23 burned that xenon out and you're back down to equilibrium 24 xenon.
So we're only talking about a four hour period after 25 all these initial conditions have occurred on all this matter Heritage Reporting Corporation (202) 628-4888
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that we don't consider to be a realistic assumption for a --
2 which I think quite in the beginning of -- you're supposed to 3
look at the probability and consequences of the fire.
We've 4
taken such an improbable initial condition and then tried to 5
design a plant for it after a fire that it's just not 6
consistent with other safety requirements.
We've gone beyond 7
what we do for other Chapter 15 -- accidents.
We don't go 8
into that amount of depth.
9 This was also done for the worst point in the fuel 10 cycle.
In other words, for different cycles BOL, EOL, or 11 whatever point in between, you had to be at that point in the 12 fuel cycle, that one point in the fuel cycle.
13 Again to summarize, boric acid makeup and boric acid 14 tanks are unavailable, normal RCS letdown is unavailable, 15 excess RCS letdown is unavailable, reactor head vents are 16 unavailable and didn't spuriously open or anything, 17 pressurizar PORVs are unavailable, and boric acid makeup and 18 the refueling water storage tank is your only boration source.
19 We're relooking at that scenario to see if it's appropriate to 20 be part of the design of the worst case Appendix P fire.
21 MR. PIERSON:
So can I infer from that that you 22 assure letdown?
23 MR. SULLIVAN:
No. Letdown, again, is not a 24 requirement in the current shutdown logic.
25 MR. PIERSON:
The reason it's not is because you Heritage Reporting Corporation (202) 628-4888
l 83 1
feel you still envelope whatever consideration you'd be in 2
because of what you just said.
3 MR. SULLIVAN:
Right.
4 To address the second point about depressurization a 5
little bit more, there are lots of ways to get that energy out 6
of the core.
Like I said, the technical support center and 7
the operational support center is staffed.
We've gone through i
8 various drills at Sequoyah.
An accident never happens, 9
especially a fire, the way you predict and think it's going to 10 happen, so we're going to take credit for the people, the 11 staff that's there, and we're going to assess the consequences 12 and make the best decision at that time.
13 For example, with portable nitrogen bottles we could 14 go in and get auxiliary spray reestablished to the pressurizer 15 if that method is the most desirable.
16 Another example, a pressurizer PORV could be opened 17 by wiring in a temporary 125 volt DC power source at the 18 containment penetration such that you could open the PORV with 19 that method for a short period of time to depressurize, to get 20 RHR cut on.
21 MR. PIERSON:
Does anyone have any more comments 22 from the staff about this matter?
23 (No response) i 24 MR. PIERSON:
I'd like to go on and ask a couple of i
25 other things.
Heritage Reporting Corporation (202) 628-4888
84 j
1 You don't need to address it right now, but in your 2
water solid condition I do want you to talk about the 3
likelihood of a pressurized PORV opening and putting it in a 4
solid plant condition and how you plan to respond to that 5
solid plant condition when you come to your discussion.
6 MR. KOONTZ:
I can address that a little bit.
I 7
can't address it from the operating procedures standpoint.
8 But if you were to spuriously open a pressurizer PORV, what 9
would happen to the reactor coolant system is you'd lose mass 10 and inventory through that PORV.
11 MR. PIERSON:
Right.
12 MR. KOONTZ:
Once the operator took action, and I 13 think you had us consider two cases in here.
One was if you 14 took action in the control room, then that action would take 15 place fairly quickly and he would move to close the block 16 valve and terminate the event.
17 There was a second case that was questioned, and 18 that was if the fire was in the control room, what would the 19 operator do?
And for that event, the operator would have to 20 go down to the auxiliary control room and/or the MOV boards 21 and cause the block valve to be closed.
22 In both of those events, though, what you and up 23 with is an RCS that has somewhat less inventory in it once the 24 vent is closed.
25 As you continue to cool the system down on the steam Heritage Reporting Corporation (202) 628-4888
}
85 1
generator, and you use natural circulation or whatever means j
l 2
of cooldown, the bubble in the pressurizer should reform 1
3 because the RCS is connected to itself in the staam 4
generators.
The pressurizar is over there essentially at a 5
dead end leg at that point, so the bubble should reform.
)
6 MR. PIERSON:
Do you have an engineering evaluation 7
of this, or is this just engineering judgment?
8 MR. KOONTZ:
No, that's engineering reasoning, 9
analysis.
10 The second thing, the only way we could determine 11 that you might lose a pressurizer bubble was if you had a 12 spurious safety injection which would then fill the 13 pressurizer up with water.
14 What we looked at there was the charging flow rate, 15 because our safety injection pumps don't pump in at 2250 psi 16 which is normal RCS conditions.
So you'd have charging flow 17 at approximately 100 to say if both trains were on maybe 300 18 GPN, and you'd have approximately 10-20 minutes before you'd 19 eliminate the pressurizer bubble.
So the operator would have 20 time to go take action and terminate that spurious safety 21 injection.
22 MR. PIERSON:
What sort of actions would he take?
23 MR. KOONTZ:
He would just have to go down and 24 secure the charging pumps and turn them off temporarily.
4 25 We've got that in, have we got some operating procedures?
Heritage Reporting Corporation (202) 628-4888 w
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MR. SULLIVAN:
E-0 contains, or one of the emergency 2
procedures, I think E-0 refers you to it, contains the SI 3
termination criteria and also the steps the operator goes 4
through to terminate the SI.
It tells them vist to do if the 5
response is not obtained.
6 MR. BRYAN:
This is Bob Bryan.
The other thing that 7
is important is we have assured the instrumentation necessary 8
for him to know that he has a spurious SI and terminate the 9
event quickly.
10 MR. KOONTZ:
As a minimum, remember that we assured 11 pressurizer level so that would be available.
12 MR. PIERSON:
Okay.
Rick Wescott has got a question 13 about your HVAC systems and some of the performed calculations 14 he'd like to ask.
15 MR. WESCOTT:
When we asked you question 14, at the 16 time basically our concerns were regarding heat transfer due I
17 to a fire through open dampers, walls, and th'at type of thing 1
18 and possibly affecting required equipment in adjacent rooms.
19 We have expanded the concern to include equipment that would 20 require for a safe shutdown any place in the plant.
21 In other words, could a fire take out the HVAC in 22 such a manner that you would have equipment required for safe
{
23 shutdown exceeding their qualified temperatures and therefore, 24 would be inoperable?
25 MR. PIERCE:
I want to make sure I understand what Heritage Reporting Corporation (202) 628-4888
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you're saying.
We've got a fire in say room 8, and circuits 2
for the room coolers, for room B are in there.
Will the equipment that we veri; relying on in room B continue to 3
4 operate?
5 MR. SULLIVAN:
That's correct.
That would be one 6
scenario, yes.
7 MR. PIERCE:
Okay, and correct me if I'm wrong, John 8
Henry, but we have gone through and any place we required room 9
cooling we made sure that that room cooler was available.
10 MR. SULLIVAN:
The shutdown logic already contains 11 the HVAC that is currently necessary and has provided a 12 separation for that HVAC.
13 MR. WESCOTT:
Okay, and I assume when you say room 14 coolers you're talking about area coolers as well, cooling a 15 large area like I think in the vicinity of the auxiliary 16 feedwater pumps as I recall, that's one place that's area 17 cooled, I believe.
18 MR. SULLIVAN:
I'm not sure what the HVAC 19 requirements are in that area, but right now the current 20 shutdown logic does not include HVAC for that area as being 21 qualified.
It's not in the current shutdown logic.
22 MR. WESCOTT:
So does this imply that you made 23 calculations that show that even under worst case cond.itions 24 you do not need those coolers?
Is that what you mean when 25 you're saying your HVAC system is not qualified for that area?
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MR. KOONTZ:
Generally what we do is they take a 2
look ut the electrical heat loads in a given area, and if it 3
turns out that you can fail the HVAC in that area due to a fire and still not exceed reasonable qualifiable temperatures, 4
5 again we don't EQ qualify for fires, but if you look at the 6
temperatures that that room goes to and it stays within 7
reason, then we assume that the cooling is not necessary for 8
that room.
9 If the temperature goes on up and continues past a 10 reasonable temperature for equipment in that room, what that 11 indicates is that the cooling must be available in that room 12 and we have to provide HVAC separated cooling or some other 13 alternate means of getting cooling into that room.
Maybe 14 portable fans, whatever.
15 MR. ROTELLA:
Did you document that analysis?
16 MR. KOONTZ:
Yes.
That's documented and it goes into the safe shutdown logic calculation as an input.
17 18 MR. WESCOTT:
Could we get a calculation number for 19 that?
20 MR. KOONTZ:
I think it's 195.
I'm not sure.
I'd 21 have to get back with you on the number.
22 MR. FOX:
Has that information been provided to 23 them in this package we sent?
24
'Pm. KOONTZ:
No, that is a separate package.
25 MR. FOX:
Are you also asking us to provide this Heritage Reporting Corporation (202) 628-4888
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calculation?
2 MR. PIERSON:
Do you need that, Rex?
3 MR. WESCOTT:
Yes, if we could have it we'd like to 4
have it.
5 MR. KOONTZ:
We'll take that as an action item, 6
MR. PIERSON:
Is that all ycu have on that, Rex?
7 (Pause) 8 MR. PIERSON:
Mr. Wescott wants to continue on with 9
questions on the HVAC.
10 MR. KOONTZ:
Let me clarify one thing too, Rex.
Let 11 me tie up a loose end.
As you're probably aware if you read 12 the previous final report from the task team, the HVAC issue 13 related to the calculations was one of the open issues that we 14 were dealing with as a free restart issue.
That is still 15 ongoing.
What we will provide for you is the current version 16 of the calculation that goes with Rev 6 and then as soon as 17 the new one is out we'll provide that one also for you to look 18 at.
19 What may come out of.the new calculation is some 20 portable blowers may be required in certain areas, and that 21 will be incorporated at that time into SOI 26.2.
22 MR. WESCOTT:
I do have a question.
23 Have you in fact found, using the existing 24 calculations, that some of the room coolers as presently 25 designed, failure of these would in fact result in Heritage Reporting Corporati.on (202) 628-4888
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temperatures exceeding the qualification limits of required 2
equipment?
3 MR. KOONTZ:
There are several room areas and I 4
didn't bring the calculation with me today, but I remember one 5
room area went to approximately 118 degrees, I believe, after 6
a fire, which was above the previous temperature for that f
7 room.
It was an aux instrument room, I believe.
8 For that area we've asked the electricals to go back 9
and look at the equipment in the area and see what temperature 10 the equipment was qualified to or purchased to to see if it i
11 could be reasonably expected to survive that event.
We found 12 that the temperature was something like 120 degrees, I 13 believe, in that area, so we would expect the instrumentation 14 and the components in there to survive.
15 Now some areas would exceed the room temperature 16 after 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, so what we've got to do is we've got to go in 17 for those areas and put in somewhere in the operating 18 procedure, specifically the fire procedure, for the operators 19 to take action to assure that those rooms stay in a reasonable 20 temperature range after 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
21 MR. WESCOTT:
This would be equipment then that was 22 required to bring the plant into shutdown, but not required 23 for fire chart cooling.
24 MR. KOONTZ:
Yes.
25 MR. WESCOTT:
When you're saying heated up, you mean Heritage Reporting Corporation (202) 628-4888
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actually exceeded the qualification temperatures on the 2
equipment, is that what you're saying?
3 MR. KOONTZ:
It would have heated up in some areas 4
above say 130 degrees after 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, which we would consider 5
unacce. table and we would need to go in and do something.
6 Beyond that, I don't have enough knowledge of the 7
calculation with me here today to go into the specifics, but I 8
can provide it to you and I can provide the new calculation 9
and you can review those.
10 MR. WESCOTT:
Will we be notified as to the findings 11 of your review and the calculations?
12 MR. KOONTZ:
Yes.
13 MR. WESCOTT:
Thank you.
14 KR. PIERSON:
I'd like to go on and talk about one 15 other thing.
I'm a little bit confused about SOI 26.2 and I'd 1
16 like you to reiterate I think what you've already said, that j
1 17 in the event that you have a situation that you lose one 18 centrifugal charging pump, say from a VCP isolation valve 19 shutting spuriously, do you have the other pump available?
Is 20 the additional pump there available?
Do you know that for a 21 fact?
Have you looked at the interaction study or whatever to 22 say that?
23 MR. SULLIVAN:
We have not looked at the interaction 24 study with the objective of making sure the ot'her pump was not 25 damaged in the fire area.
We went through the interaction Heritage R' porting Corporation e
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study with the intent of ensuring that the existing pump that 2
was sitting there operating at the time did not get damaged.
3 MR. PIERSON:
If you essentially say that the existing pump was not damaged, then you're telling me that if 4
5 the bond control tank isolation valve shuts the pump can sit 6
there and spin?
7 MR. SULLIVAN:
No sir, I'm not.
The operating 8
charging pump will not be damaged by spurious closure of the 9
VCT outlet valves because we will take appropriate action 10 before those valves close.
11 MR. PIERSON:
I'm afraid I'm having a hard time 12 agreeing with that for the simple reason that you told us 13 earlier that you don't consider the fire to exist until you 14 send a runner down to identify the fire.
So we could have the 15 valves shut during the time a man gr;s down, looks, verifies 16 the fire, and comes back.
I don't think that a charging pump 17 will operate without a suction.
18 MR. SULLIVAN:
I hear you.
The charging pump will 19 not operate with the suction valve closed.
We know that, the 20 vendor has told us that.
Our whole' intent is to ensure that 21 the appropriate action is taken prior to spurious closure of 22 these valves.
It takes a finite amount of time to get cable 23 damage.
24 We have an analysis of that.
25 MR. PIERSON:
Have you provided an analysis to us?
4 Heritage Reporting Corporation (202) 628-4888
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MR. SULLIVAN:
We will, if we have not provided it.
2 MR. PIERSON:
I'd like to look at that because I'm 3
concerned about that.
4 MR. SULLIVAN:
I'd like to emphasize again, in case 5
I wasn't clear before, there are three things the operator can 6
do.
He can open the AC breakers on the DCT outlet valves, so 7
they won't spuriously close.
He can open the RWST supply 8
valve and open its breaker so it doesn't spuriously close, a
9 similar problem to the one that had ben previously identified 10 on the VCT.
He can trip the centrifugal charging pump until 11 one of the above is completed.
So he has three things in 12 there he can do to ensure that the operating pump is not 13 damaged.
14 MR. PIERSON:
I understand what you're saying.
I'd 15 like to see the analysis or calculations vou've got that shows 16 the expected amount of time before the fire is detected and 17 the action is taken to isolate that pump.
18 Does anyone else on the staff have any questions we 19 want to ask?
We still need to talk about solid pressure, 20 solid plant ops.
21 George Hubbard?
22 MR. HUBBARD:
I've got just one point for 23 clarification'was earlier they had mentioned the CAQR 8700857.
24 I looked at the data which they listed out the information 25 they provided us, and that CAQR has not been provided, so that Heritage Reporting Corporation (202) 628-4888 l
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would need to be provided to us.
That was relative tc 2
question 21, CAQR 870857.
That along with the 870151 which 3
you have given us now.
4 MR. FOX:
Yes.
5 MR. HUBBARD:
The one other question with regard to 6
question 22, in your responsa you indicated that for 7
information notice 8409 that you were in compliance or had 8
approved deviations.
I think in telephone conversations we 9
asked that you identify the specific equipment which you 10 utilized to be in compliance with the 8409, and also to 11 identify what the approved deviations are.
I think there are 12 a couple on there, I've run across a few.
Also, which of the 13 equipment was environmentally qualified.
14 MR. FOX:
Okay.
We have taken a copy of the 15 appendix to the shutdown logic calculations, and we have 16 checked those items which are 5049 EQ'd and I'll provide that 17 to you now for information, and we'll put it on the docket of 18 forms coming back.
j i
19 MR. KOONTZ:
George, I think the approved deviations 20 are in an NRC letter, and we can provide the reference for 21 that.
22 MR. KUBBARD:
I do have one letter on approval of l
23 deviations.
I have a May 29, 1986 which gives some 24 deviations.
25 MR. PIERCE:
There was another one I believe in Heritage Reporting Corporation (202) 628-4888
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October of '86 that was on lack of TEco instrumentation in the 2
auxiliary control room.
3 MR. FOX:
October of '86?
4 MR. PIERCE:
I believe that was the date.
5 MR. FOX:
We will confirm that.
6 MR. KOONTZ:
I believe those two constitute the 7
approved deviations for instrumentation.
8 MR. HUBBARD:
So any deviation that would have been 9
approved by the NRC.
10 MR. KOONTZ:
Yes.
11 MR. PIERSON:
Is that all?
12 I'd like you to speak about solid plant operations 13 for a minute as we discussed earlier.
14 MR. FOX:
Okay, I would like to review the bidding 15 right now because there are several things we want to do to 16 close out our part of this presentation today.
We will cover 17 depressurization, we'll cover the water solid, we also want to 18 run through the action items to make sure we have a clear 19 understanding of everything you've asked for here today.
I've 20 tried to keep up with it, but I'd like at some point before we 21 turn the meeting over to public comment to run through those.
22 MR. PIERSON:
That's fine.
23 MR. FOX:
We'd now like to have John Henry Sullivan 24 talk about depressurization.
25 MR. HOSMER:
Before we do, I'd like to add a comment Heritage Reporting Corporation (202) 628-4888
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on the charging pump question we brought up.
I asked for 2
this, as project engineer in Sequoyah I asked for this task 3
force to be formed to look at these issues.
One of the things 4
I asked be done was an industry survey in particular on the 5
charging pump issue because this is a Westinghouse plant with 6
charging pumps of the type provided by Westinghouse.
7 What we found on this issue is what sequoyah is the 8
doing is the norm for Westinghouse plants.
It is in NTOL's as 9
well as oldor vintage plants.
Our approach is consistent with 10 what they are doing, and more conservative than some.
11 MR. PIERSON:
Could you supply, we need something, 12 that's not in the submittal that you gave us.
13 MR. HOSMER:
I don't know how to name plants, give 14 you a list of plants.
15 MR. GARG:
I think it's in Appendix A.
16 MR. HOSMER:
I believe it's in an attachment.
I 17 MR. KOONTZ:
The industry survey on issue A-15 in 18 the testing report.
19 MR. PIERSON:
Thank you.
20 MR. FOX:
Okay.
We'll go ahead and cover water 21 solid now then.
22 MR. KOONTZ:
I think we've covered water solid from 23 the standpoint of spurious safety injection being one cla'tse; 24 opening of the PORV being another clause; and I think we've 25 gone into the depressurization a little bit.
If you've got Heritage Reporting Corporation (202) 628-4888
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some further questions for example, on issue Al on the dose e
2 or any of that, we can cover that.
3 MR. PIERSON:
It appeared to me from your earlier 4
submittals that you were taking credit for pressurizer PORV 5
operation for reactor head vent valves in event of a solid 6
plant operation, and as such I was interested in what would 7
happen in terms of contamination inside the containment and 8
how that would affect your accessibility to operate the RHR 9
valves.
10 You told me in the meeting that you don't take 11 credit for pressurizer PORV valves opening or reactor head 12 vent valves opening, and presumably you've got the flow 13 control valve or the RHR valve adequately protected such that 14 a fire isn't going to destroy it such that you can't repair it 15 within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
I don't see access to the containment as a 16 problem per se, provided that you're not going to be leaking 17 reactor coolant system coolant into the containment.
If 18 that's true, I think we can probably get around question 19 number one.
20 I need some response rather than shaking your heads 21 here.
22 MR. BRYAN:
That's correct.
We do not need access 23 to the containment when we would have a release from the RCS.
24 MR. PIERSON:
So what you're saying is when you have 25 a release from the RCS you're in a loca and your hot shutdown Heritage Reporting Corporation (202) 628-4888
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sense?
2 MR. KOONTZ:
No, remember the reason that we veuld 3
need access to the containment was to go in and repair, to 4
manually open the valve door to repair the wiring or the motor 5
on the valve.
A study was done to show that there was not a 6
fire loading in there that would cause those valves to be 7
damaged other than the viring or the motor itself.
If the 8
wiring or the motor to that valve was damaged, then we would 9
not have had a spurious SI and we would not have had 10 contamination inside the containment.
That's the argument.
11 MR. BRYAN:
And normal letdown would be available.
12 MR. PIERSON :
We think you're going to have to 13 supply us a deviation on that analysis for those flow control 14 valves, because you're not taking the normal 20 foot 15 separation on that.
16 MR. KOONTZ:
We provided the drawings on those 17 valves I think in the last submittal.
18 MR. PIERSON:
Is there a 20 foot separation?
19 MR. KOONTZ:
That I don't recall.
One is inside the 20 crane wall on the floor and the other is up in an accumulator 21 room.
22 MR. PIERSON:
We can address that later.
23 MR. PIERCE:
Can I get a clarification?
Are you 24 saying the separation between the 74-1 and 74-2?
25 MR. PIERSON:
Yes.
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MR. PIERCE:
Are you saying the separation between 2
740-1 and 74-2 and --
3 MR. PIERSON:
What I'm talking about is you're 4
saying that the only fire there in terms of 74-1 and 74-211s 5
going to affect the motor operator of the valve as well asLI 6
remember, so it can only affect that valve.
But I thought I 7
understood from that that as a result of that fire hazard 8
analysis you did, that you didn't meet some of the separation 9
criteria that you would normally have to meet for Appendix R.
10 If that's the case, then we need to have some sort of a 11 deviation or something on that. I may have misunderstood that, 12 but that was my understanding earlier in the meeting.
13 MR. HOSMER:
We'd like a couple of minutes here just 14 to caucus on that a second.
15 (Pause) 16 MR. BRYAN:
What we want to clarify is, we don't 17 see, it appears that you're asking us for a deviation request 18 because you say we don't have 20 foot separation.
19 MR. EBNETER:
Let me cut that off.
We'll tell you 20
' formally whether we want a deviation on anything at all, but I 21 don't want to debate it in this meeting.
22 MR. PIERSON:
Is that acceptable?
We'll take it up j
23 in a later issue.
t 24 MR. BRYAN:
Okay, that's acceptable.
25 MR. PIERSON:
Any other questions?
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(No response) 2 MR. PIERSON:
Does TVA have anything else to say in 3
their response with respect to some of the other issues?
4 MR. KOONTZ:
Let me ask if you had any further 5
gaestions on number one, the off-site dose calculwrion?
6 MR. PIERSON:
Possibly.
It depends on something to 7
do Wi.th the RHR valve, but I think we can work around that 8.
- later, 2 dor't think that's worth discussing now.
9 I'm ready to close t'..e NRC's portion of this 10 meeting.
11 MR.,
FDX:
I would like to run through the action 17.
itemts.am'I have them identified, and if NRC staff has one 13 that'.m Wet on the list, please call it out.
14 The first one is the docket CAQ 870151.
Also we've 15 been asked to docket CAQ 0857 in reference to question 21.
16 870151 was, I guess, one of the others.
17 We've also been asked to docket the list of Appendix 18 R equipment that's 5049 AQ'd.
I handed George Hubbard a 19 marked up appendix to the calc that was provided opposite 20 question 22.
We will formally docket that.
21 Also we need to provide you with, relative to 22 question 24, the reactor coolant pump seal, we'll get a letter 23 from Westinghouse and we'll provide that to you.
It has to do 24 with elastomer seal integrity.
25 We also will provida you the revised procedure to Heritage Reporting Corporation (202) 628-4888
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pull fuses.
That's SOI 26.2.
2 We will also provide you the KVAC calculation, both 3
the old calculation and the new calculation when it's finished 4
and we'll advise you of any actions we feel are appropriate to 5
take with regard to providing localized cooling.
6 We also need to provida you an analysis assuring the 7
operating charging pumps integrity, survivability.
8 Are there any other items?
9 Instrument lines outside the tank.
10 MR. PIERSON:
Wa may have some other requests with 11 respect to the pressurizer PORVs, the assured letdown, and the 12 protection for your flow control valves, your RHR flow control 13 valves.
14 MR. FOX:
Okay.
You haven't made your mind up on 15 those yet?
16 MR. PIERSON:
Well, I have to look at the transcript 17 and discuss it with the staff.
la MR. FOX:
Okay.
19 MR. PIERSON:
The second thing we need to reiterate 20 is, I was a little bit remiss, and I wasn't keeping track of 21 the items and there may be other items in the transcript and 22 we'll ask for them.
23 MR. FOX:
We'll scan the transcript.
These were 24 things that, with one exception, that we felt like you wanted 25 fairly quickly and we're going to go ahead and initiate action Heritage Reporting Corporation (202) 628-4888
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immediately to get those in and get them on the docket.
2 KR. PIERSON:
We appreciate that.
3 KR. EBNETER:
Before we close I'd like to make one 4
comment.
I'm somewhat concerned in looking at the chronology 5
of events that TVA identified a problem with these 6
calculations some time ago and the NRC wasn't aware of it 7
until December.
Is that true?
In looking at your chronology, 8
DNE calculation programs, identification documentation in 9
December of
'86.
Should we have been notified?
10 KR. FOX:
You're referring to the second --
11 KR. EBNETER:
Part of your presentation.
12 KR. FOX:
Well part of the handout we gave you.
13 KR. EBNETER:
Right.
14 (Pause) 15 KR. HOSMER:
Are you referring to the 12-86 date?
16 KR. EBNEIER:
Yes.
17 KR. HOSKER:
That came out of the cale regeneration 18 effort, a concern about unverified assumptions.
I think we 19 made it visible and apparent to you in Knoxville as part of 20 audits.
Can you help me, Mr. Koontz?
21 KR. KOONTZ:
Yes. That whole program was audited by 22 the KRC.
23 KR. EBNETER:
Who was that, do you recall?
24 KR. KOONTZ:
Gene Embro was in charge of that audit 25 on calculations, and I believe the NRC reviewers took a copy Heritage Reporting Corporation (202) 628-4888
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with them of the CAQR that reported that calculation was in 2
error.
3 MR. EBNETER:
Okay.
I'll retract my remark.
4 That must have been one of Gene's first DVBP inspections, is 5
that right?
6 MR. FOX:
I think part of the problem is that 86 7
should be 87.
8 MR. KOONTZ:
Maybe that's part of the problem.
9 There's a typo in there.
10 MR. FOX:
No, that's out of sequence again.
11 MS. AXELROD:
Are you talking about a recent 12 inspection by Gene Embro?
13 MR. KOONTZ:
This is the whole calculation 14 verification program where they came in and they audited the 15 civil, electrical, mechanical, nuclear calculations and they 16 closed out the issues on the nuclear and mechanical 17 calculations.
The review team consisted of Embro, Ron 18 Parkhill, and others.
19 MR. EBNETER:
That slide is in sequence and it says 20 12-86.
21 MR. KOONTZ:
That's correct.
22 MS. AXELROD:
When did Mr. Embro do his inspection?
23 MR. FOX:
I guess the best thing for us to do is to 24 get with the people that were involved and we will take that 25 as an action item to provide an explanation.
Heritage Reporting Corporation (202) 628-4888 l
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HR. EBNETER:
If that is the case when it was 2
identified, and particularly an Appendix R error, that thing 3
should have been reportable, I believe.
If
',t was not, dad we 4
didn't discover it until a year later, whether through an 5
inspection or through an alleger, I still have some concerns 6
about it.
That's all I want to comment about it.
But I will 7
check back with you on that.
8 MR. HOSMER:
Let me provide one piece of 9
information.
I think you're aware as part of a very massive 10 calculation regeneration effort one of the things that TVA 11 identified were numerous unverified assumptions.
This was one 12 of hundreds of unverified assumptions that were being 13 monitored, tracked to closure.
It was viewed as not a 14 technical issue or a safety issue.
It was viewed as needing 15 to establish as built documentation.
It was tracked and 16 monitored as part of a program to close all of those issues 17 prior to restart.
10 MR. EBNETER:
Okay.
I just wanted to let you know I 19 have a concern about it.
20 MR. FOX:
We'll get you the explanation of the 21 events.
22 MS. AXELROD:
I'd like to ask one question.
What is 23 the status of Rev 9 of the calculation?
I've heard you might i
24 be working on a Rev 9, is that true?
25 MR. PIERSON:
We have Rev 8.
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MS. AXELROD:
Are you working on a Rev 9?
2 MR. KOC NTZ :
Yes.
Revision 9 will be out, I don't 3
know what the date scheduled for it is, and it will 4
incorporate the new results of the HVAC analysis and these 5
other issues.
6 MS. AXELROD:
Can you give me an approximate date, 7
when you expect it to be out?
8 MR. KOONTZ:
I can't at this time, but we can get 9
the date for you.
10 MS. AXELROD:
Do you expect it to be out prior to 11 restart?
12 MR. KOONTZ:
I would expect the HVAC issue and the 13 new revision out prior to restart, yes.
14 MR. PIERSON:
Unless someone on the staff has some 15 additional comments, I'm going to turn the meeting back over 16 to Mr. Richardson, and Mr. Richardson will close it out to 17 public comment.
18 Any questions?
19 MR. RICHARDSON:
This is the portion of the meeting 20 on the agenda that has been reserved for public comment 21 period.
Are there any members of the public that wish to make 22 a statement?s 23 MS. BERNABEI:
My name is Lynn Bernabei.
I'm 24 attorney for Andrew Bartlik who has raised many of the 25 concerns that are being discussed here today.
Heritage Reporting Corporation (202) 628-4888 l
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I'd like to make two comments that I think are integrally related to the technical issues that have been 2
3 discussed.
One has to do with Mr. Bartlik's charges of 4
harassment and intimidation.
Essentially he has charged that his contract was terminated because he identified these safety 5
issues which cite management and upper level TVA management 6
7 attempted to suppress.
I think the NRC staff has to address 8
that issue because the Commission has stated in no uncertain 9
terms that if there has been intimidation of engineers and 10 employees it is a very serious bar to the flow of safety 11 information to upper TVA management and to the NRC.
12 The second issue that I think the staff should 13 address is why we're all here today on the eve of restart days 14 or weeks before the Commission is about to vote on restart, 15 debating very serious safety issues.
I think the only 16 conclusion you can come to is that basically these problems 17 which have been identified in internal memoranda in August of 18 this year were withheld from the NRC so the staff could noc 19 complete a complete review at that time.
20 I think the reason people are scrambling right now 21 is because that information was withheld.
And given the 22 seriousness of the problems and the likely reportability under i
23 NRC regulations, I think the staff should explore what 3
24 happened that these issues were reported to you not by TVA but 25 by a former TVA engineer.
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Mr. Bartlik has a number of concerns that he wanted 2
to talk about in terms of the technical issues, but I would 3
urge the staff to review those two things before coming to any 4
recommendation on the technical issues or on restart.
5 MR. RIORARDSON:
Thank you.
6 MR. BARTLIK:
My name is David Bartlik.
I'd like to 7
talk about a few things.
8 First I'd like to read a statement.
I think the 9
discussions here have shown that there are many unresolved 10 problems pertaining to Appendix R of TVA's program.
I would 11 like to focus on a few of the areas.
I believe it's clear 12 that TVA does not meet NRC Appendix R requirements, and this 13 has not been discussed in sufficient detail in all the areas I 14 am concerned with, although the staff has made a reasonable 15 attempt to do so.
16 First I'd like to talk about SOI 26.3.
Mr. Sullivan 17 today was alluding to all the excess conservatism they have 18 used in this calculation.
I wish to point out that that SOI 19 26.3 is TVA's basis for establishing long term reactivity 20 control, and that is what their calculations for ensuring the 21 core will be maintained in some critical conditions is based 22 on.
It is based on the establishment of a letdown path 23 through the RHR system at T=15 hours or 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />.
If TVA 24 intends to use this procedure, it also requires the RCS be 25 cooled to 200 degrees F.
If they intend to have the RCS Heritage Reporting Corporation (202) 628-4888
l 108 1
cooled to 200 degrees at T=15 hours, I would suspect the RHR j
2 valves would have to be opened well before eight hours.
3 TVA is relying on repair procedures, but by their 4
own admission it takes up to 19 hours2.199074e-4 days <br />0.00528 hours <br />3.141534e-5 weeks <br />7.2295e-6 months <br /> to get the valves fixed.
1 5
Clearly these valves have to be fixed for periods as early as 6
eight hours.
7 In addition to that, TVA has had previously not had 8
any information from Westinghouse regarding how long it would 9
take to cool the plant with a single train of RHR coolers 10 available.
11 As it turns out, when this analysis came in from 12 Westinghouse, they have determined that it takes over 20 f
13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br />, I think it was 25 hours2.893519e-4 days <br />0.00694 hours <br />4.133598e-5 weeks <br />9.5125e-6 months <br /> if we look at that graph, to j
14 cool the plant from hot standby conditions to 200 degrees.
So 15 it's essentially that calculation from Westinghouse that shows 16 that TVA is not able to cool the plant down to 200 degrees 17 within the allotted time.
Therefore, they cannot meet the 18 reactivity control requirements as specified in SOI 26.3.
l 19 In addition to that, TVA is relying on seal j
20 integrity for, it's relying on seal injection for seal 21 integrity in a large number of fire areas.
As a matter of 22 fact, according to their safety position statements there is 23 only one plant area in which they're relying on CCW to the 24 thermal barriers as a means of maintaining seal integrity.
25 Ultimately seal injection will result in the overfill of the Heritage Reporting Corporation (202) 628-4888
109 1
RCS and you must establish a letdown path.
TVA's own 2
calculations have shown that this establishment of letdown 3
path for providing control is required at T=19 hours.
That's 4
where the original 19 hours2.199074e-4 days <br />0.00528 hours <br />3.141534e-5 weeks <br />7.2295e-6 months <br /> came from.
Again, they have not 5
ensured this ability.
6 Again, at T=19 hours, they are not able to have j
7 opened up the RHR valves and cooled it down sufficiently to 8
use TVA's own designated method of letdown.
9 In addition, there has been some debate whether 10 these part 100 limits are accurate., or part 20 limits.
I wish 11 to point out that this Appendix R is not an accident and part 12 100 limits are only applicable to accident scenarios.
TVA 13 submitted calculations showing they are within their part 100 14 limits, as opposed to part 20.
15 TVA's letdown scenarios also dump water either to 16 the floor, to the reactor building floor, or sometimes the 17 auxiliary building floor.
It is not clear to me that the part i
18 20 limits can be maintained with dumping water to the floor as 19 they are currently planning, especially considering that the 20 necesse.ry HVAC systems that normally clean up such radioactive 21 spills are not included in the analysis.
22 TVA also makes an interesting statement regarding 23 water solid operations.
They say that under water solid 24 operations they will slow their cooldown rate.
I guess they 25 don't have to minimize any transients.
It's interesting to Heritage Reporting Corporation
~
(202) 628-4888
l 1
110 1
note that if you're cooling slowly that is clearly not in 2
accordance with SOI 26 which requires a prompt cooldown.
3 Also TVA used the justification for not training l
4 operators on water solid operations that it's a low 5
probability event.
It is not necessarily such a low 6
probability event.
Also, loca, steam generator tube ruptures 7
are also low probability events, and we certainly train 8
operators on these.
It's been noted that one of the most 9
likely current concerns for core melt accidents is a fire-10 initiated event, so that they don't train to ensure they don't 11 do something to endanger the public is beyond me.
12 It's also interesting to note, Bob Bryant, I know I 13 talked to Bob many times about the issue concerning the steam 14 generator PORV and blowdown of multiple generators.
I was 15 essentially the author of the CAQR that TVA references 16 allegedly resolving the problem, they distributed the CAQR and 17 said therefore, we don't have a problem.
18 It turns out that before I issued that CAQR, TVA's, 19 I guess what I consider TVA's leading expert on single failure 20 criteria, Harry O'Brien, had been fully consulted on that 21 matter and was in full concurrence with me.
Harry O'Brien is 22 documented, saying that in a memo.
Also I feel Doug Wilson 23 considers him as expert because when I raised the CAQR, TVA, 24 the first thing is Doug Wilson disagreed with my 25 interpretation of the rules and the first person Doug Wilson Heritage Reporting Corporation (202) 628-4888
111 1
ran to was Harry O'Brien.
He advised me that I should talk to 2
Harry because I obviously don't know what I'm talking about.
3 I responded I had fully coordinated with Harry O'Brien, and it 4
has been supported.
5 I kind of wonder why TVA hasn't brought Harry 6
O'Brien to discuss this matter, because I know he has a little 7
bit different opinion that Mr. Bryant.
8 One interest:ng point, I don't want to get into all 9
the technical details contained within that CAQR because it 10 would really take more than 20 minutes to adequately discuss 11 it, but I understand TVA has made some statements that they 12 could always close that pressurizer PORV.
I want to point out 13 that if you have a steam generator tube rupture and that PORV 14 is open and you take the failure of that closing solenoid as 15 your single active failure, that PORV will not close.
That 16 will most clearly increase the significance of a steam 17 generator tube rupture because TVA's current analysis assumes 18 that that PORV is promptly closed.
They will not be able to 19 do that and it will delay operator action, and therefore, it 20 vill increase the amount of RCS that gets into the steam 21 generator because it will be lower, steam generator pressures.
22 It will also increase the amount of release because the valve 23 will be open longer.
24 Again, it just shows how the failure of the PORV 25 creates a beyond design basis event.
A failure of this Heritage Reporting Corporation (202) 628-4888
112 1
control circuitry the way they have these non-qualified 2
circuits influencing the position of the PORV.
3 I also wish to point out that from my understanding 4
from John Henry Sullivan's discussion is that they are relying 5
on a factor, they're saying that a VCT isolation valve will 6
not closo before ten minutes and give the operators time to do 7
things like rack out the breakers so the valve will not close, 8
or open the RWST.
There is one other thing he was relying on.
l 9
None of these methods being assured available from a fire.
10 I also wish to point out that an analysis of that 11 nature is not currently allowed by Appendix R and would 12 require a deviation request in my estimation.
I understand 13 TVA has not submitted the same, also.
14 Another concern that was not really thoroughly 15 touched on is if we have a spurious safety injection signal as 16 TVA has admitted may occur, that will start both charging 17 pumps.
TVA has not ensured that the RWST will be properly 18 aligned and this may result in the charging pumps being left 19 drawing suction from the VCT.
That will promptly deplete it 20 and this will result in the charging pump sucking on hydrogen 21 which will also promptly destroy both charging pumps as well 22 as the SI pumps which are also aligned at that time.
23 In addition, TVA has not ensured the prompt 24 availability of RHR.
They rely on repair procedures.
This 25 will also mean that it may very well be that the RHR pumps are Heritage Reporting Corporation (202) 628-4888
=
113 1
disabled. They may be left with absolutely no way to get water 2
in the core in this event.
I think we should examine this a 3
little bit more closely, 4
I'm also pointing out, it was demonstrated in 5
discussion today that there is no method assured by TVA to l
6 terminate feedwater flow, main feedwater flow to the steam 7
generators in a control building fire and they are ultimately 8
relying on action in the auxiliary control room.
I am unaware 9
of any calculations to determine how much or whether these 10 generators won't back to overfill before they get down there.
11 Also, I understand TVA is taking credit for very 12 short operator responses.
Normally speaking, the NRC allows 13 ten minute operator response for actions within the control 14 room.
I think a two minute operator responses currently 15 called for might be over-stretching the operator's 16 capabilities, especially considering he may not exactly 17 appreciate what if anything is happening.
I'll get into that 18 a little more with regard to spurious SI~a little later.
19 Also similar problems with the pressurizer PORV in 20 the aux control building fire.
Obvicusly, if-you made your 21 mind up and you say to the control room "Go, close that 22 valve "
You can get there in two minutes.
I think that's 23 about the extent of the analysis.
However, you've got to keep 24 in mind the operator may not really know what he has.
I'm 25 going to ask these things in question form because that's how Heritage Reporting Corporation (202) 628-4888 l
114 1
they're written to save time, but I'm really not expecting a 2
response at this time.
3 How does TVA know in fact that the PORV is open?
Do 4
they have any position indications assured that they're going 5
to receive that the PORV is in fact open?
Any pressure 6
indication that they know they're going to receive. hat the 7
RCS pressure is dropping?
8 If the operator receives indication that the RCS is 9
depressurizing and it receives a fire alarm, doe'3 he use his l
10 EOIs and follow them until he reaches the appropriate exit 11 point?
Or does he go to an AOI for control room abandonment?
12 How are these procedures coordinated?
13 Will it take longer than two minutes to exit the 14 EOI?
How could they close the block valve before this time?
15 If it takes ten minutes to close the block valve, what will 16 the RCS conditions be?
Is the situation currently analyzed?
17 Obviously if the PORV is only open for two minutes, 18 the RCS conditions are not going to degrade that much.
19 Normally safety injection comes on in a minute or thereabouts.
20 Two minutes, I will acknowledge that there won't be much 21 change in the RCS conditions, and I agree with Frank Koontz if 22 they get there in two minutes it's not too much of a problem.
23 Unfortunately, I believe it may take 10 minutes or 15 minutes 24 to really figure out what happened.
Ten or 15 minutes, you've 25 lost substantial inventory and you are beyond your design Heritage Reporting Corporation (202) 628-4888
115 1
basis.
You've gone into degrading of steam generator loops.
2 I believe this is unanalyzed at this time.
I think 3
the KRC staff should be very careful before they allow TVA to 4
take credit for two minute operator response on an event of 5
this nature.
6 In an actual loca if the operator receives a fire 7
signal, this is not a real fire, by the way, just something 8
caused as a consequential failure that occurred due to the 9
loca.
Maybe the diesels didn't start properly, maybe it was a 10 voltage spike like we were talking about.
I understand some 11 people have raised that concern.
That might have done 12 something funny to the fire detection system that a false 13 alarm comes in.
Does the operator go into his loca procedures 14 or does he go to his ALI's?
Obviously, fire protection takes 15 lower priority and the operator is going te stick with his 16 EOIs first until he's absolutely positive he does not have a 17 loca before he starts thinking about fires.
18 TVA also made statements today that they don't care 19 if safety injection signals actuate.
I want to point out that 20 this is different than their 1984 position where they say it 21 will not occur.
I refer staff to the safety position 22 statements.
I can't put my finger on it exactly, but Mr.
23 Pierce, I'm sure, could confirm that.
We discussed that item 24 at one point or another.
25 I've got questions with this spurious SI again.
If Heritage Reporting Corporation (202) 628-4888 l
l f
116 1
the operator really isn't sure what he's got, I believe the 2
prudent thing would be to keep that SI flow going, and it may 3
take all of 20 minutes to figure out that he doesn't have a 4
loca and has a fire.
Keep in mind, although TVA has said they 5
have ensured a pressurizer level sensor available, the failure 6
mechanisms of these pressurizer level sensors could be that l
7 you would have some of them failing on scale in intermediate 8
values.
The operator may bv faced with two pressurizer level 9
sensors, off scale load, the majority of his pressure sensors 10 including his narrow range and some of his wide range 11 indicating low pressures, pressurizer level indicating low, 12 and then he sees one lone pressurizer level set lifting up 13 kind of slow looking like it might be failing.
What's he 14 going to listen to?
The weight of the indication that may 15 indicate a loca and it may take him substantially longer than 16 20 minutes, i
17 I also want to point out that TVA responded in the 18 recent correspondence to the NRC that an analysis on Bellafont 19 was done and showed that the operators would in fact respond.
20 I wish to just for the record state that I performed that 21 analysis and I realize what the flaws are, not that they're 22 flaws, but what the limitations are, I should add.
That 23 analysis also showed that in some areas it would be likely for 24 the reactor to be driven more to solid.
In those particular 25 scenarios around Bellafont, we assured that we didn't have to Heritage Reporting Corporation (202) 628-4888
1 I
i 117 l
1 go into containment, that we didn't mess up the environment.
2 I don't think we've done that at Sequoyah.
3 l
Also, TVA makes statements that they believe there 4
will be sufficient indication available.
Again, before we 5
made those statements on Bellafont, we made specific looks at 6
What instrumentation were lost, we made judgments as to 7
whether it would be sufficient indication left over, and then 8
we tested the operators.
Per discussions with Ed Sheehy at j
9 TVA, we went over some scenarios where we lost tremendous l
l l
10 amount of indication with a 20 foot Appendix R fire.
With 11 that indication in our opinion, it may be survivable, but it l
12 would certainly require some special operator training which is contrary to what TVA is currently considering to do.
13 14 (Pause) 15 Also I would like to talk about the main steam 16 isolation valves.
I know we talked about so much redundancy 4
17 in separation.
I'm not sure abcut TVA's specific design, but 18 all the other plants I worked on, the main steam isolation 19 valves, this is pro-Westinghouse, generally requires power to trip those valves although they are fail-close valves.
20 The 21 closing solenoids are usually, generally, this could be 22 verified with Mr. Hosmer shaking his head no, but my 23 understanding is the circuits that actually close the 24 solenoid, that actually bleed the air require power.
There 25 are multiple solenoids, granted, but they do require power.
Heritage Reporting Corporation (202) 628-4888 f
118 1
Again, I may be incorrect at TVA because I have not reviewed 2
those specific circuits.
3 MR. RICHARDSON:
You have a couple of minutes left 4
in your allotted time.
5 MR. BARTLIK:
Yes sir.
6 TVA mentioned they will trip the breakers, they 7
would just hit a switch at the local control center. I wonder, 8
hitting that switch, is that possible that the control pow.*
9 has been disabled?
Has TVA shown that control power is 10 available to trip the RCP breakers, or is TVA going to have to 11 rely on winding up those breakers with the reach rods?
I'm 12 not sure what exactly TVA has to do to trip those RCP motor 13 control centers.
14 I'd like to talk a little bit to RCS 15 depressurization.
John Henry Sullivan mentioned a lot of 16 methods in which to depressurize the RCS. I wish to point out 17 none of them are currently in the Appendix R shutdown logic.
18 That was originally one of my concerns in that it wasn't there 19 and it was unclear if the RCS would be able to be 20 depressurized in a reasonable time frame, in the time frame I
21 required for SOI 26.3.
22 Although we may be able to get in,there and put air 23 bottles and do a number of different things, those are 24 currently not reflected in procedures as required by the law.
25 MR. RICHARDSON:
Do you have any closing comments, Heritage Reporting Corporation (202) 628-4888
119 1
Mr. Bartlik?
You've come to the end of the allotted time.
2 MR. BARTLIK:
You said you might give me a little 3
more time.
If you can give me about two more minutes --
4 MR. RICHARDSON:
Please wrap up within that time.
5 MR. BARTLIK:
Yes sir.
6 AOI 27 which deals with pulling control fuses for 7
the pressurizer head vents, I mean the RCS head vents, the 8
head vents may open for numerous other fire areas and AOI 27 I 9
believe pertains strictly to the control room, so this i
10 procedure currently does not reflect the need to disable power 11 to these valves.
12 I have no further comments.
Thank you.
13 KR. RICHARDSON:
Thank you very much.
14 MR. BARTLIK:
I would like to say if any of the
]
15 staff needs my help to discuss any of these items, for further 16 clarification, I will be available.
17 MR. RICHARDSON:
Thank you.
Does TVA have any brief 18 comments?
19 MR. FOX:
Yes. TVA does not agree with a lot of the 20 statements that were made by Mr. Bartlik.
We'll be happy to 21 address any of the questions that NRC staff feels are 22 appropriate and need to be addressed after reviewing the 23 transcript.
24 MR. RICHARDSON:
Thank you, we appreciate that.
25 MR. PIERSON:
Thank you for your participation.
Heritage Reporting Corporation (202) 628-4888
120 1
(Whereupon, at 5:16 p.m. the meeting was adjourned.)
Heritage Reporting Corporation (202) 628-4888
b REPCRTER'S CERTIFICATI J
i i
2 3
4 CASE TITLE:
MEETING:
NRC & TVA re: 10 C.F.R. Part 50, Appendix R Issues 5
HEARING DATE:
March 9, 1988 6
LCCATION:
Rockville, Maryland 7
I hereby certify that the proceedings and evidence 8
are contained fully and accurately on the tapes and notes 9
reported by me at the hearing in the above case before the 10 ADVISORY CO!C1ITTEE ON REACTOR SAFEGUARDS.
Il 12 13 Date:
3/9/89 14 IJ
$b8N Of fic14(1 Ruporteir' 37 HERITAGE REPORTING CORPORATION 18 1220 L Street, N.W.
Washington, D.C.
20005 l
i 19 1
20 21 22 23 :
i I
24 25 Heritoge Reporting Corporation
= = =.
4 0
HARCH 9, 1988 MEETING AGENDA FOR APPENDIX R DISCUSSION BETWEEN NRC AND TVA FOR SEQUOYAH UNIT 2 OPENING REMARKS (MEETING FORMAT)
- 5. Richardson /S Ebneter BACKGROUND R. Pierson DISCUSSION Staff /TVA TVA vill be asked to address staff questions on various Appendix R issues including the following:
Spurious actuation HI/LO pressure interface Associated circuits Ungrounded DC circuits Effect of fire on instrument sense lines RHR cooldown with one train Spurious actuation of specific components (PORV's, Reactor Head Vents,etc.)
Solid plant operations Single failure criteria instrumentation requirements of IN 84-09 PUBLIC COMMENT 20 Minutes CLOSING REMARKS S. Richardson
e,s;. r., ;
ss..~
tw c.w cn.a 615 632 6194 p.32 e**
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"w EQUIPHtWT RRgtJ1 RED FOR SAFE GNIJTDOW Prepared hy/cagefd/// - g/f '
OUR1WG A OESICH 8ASI3 FIRE Checked by/04to M/ 6L/ J//a//,
APPtNDIX 3 APPENDIX 0 - TMTRUMEWTATION f.TST FOR MAIN CCNTROL MCOM Inditaler I
Descristles
- LI-68-339 Pressuriser Water Levet v1.I-68-320 or,e of these Pressurisur Watet Levet h $
A I-68-335A (a s - 13f) fressuriser Water Level k
lPI-68-J62A -
SC8 WR Pressure d'
/PI-68-66A one of three ICS WR Pressure
/ PR-66-69 l}CS WE Pressure
/P1-1-2A Rtther one
}
40-1 stees Press l
- P!-1-38 i
M-18 teep Press i
' PI-1-9A tither one
$0-2 Steet Press y in F1-1-95 30-2 staas Press j
e fr' Pr 1-20x sith.e on.
r 3 ste.. Press l 71-1-J05 j
Loops 40-3 8 tees Press
{
g Requtrad PI-1-27A Rtther enn 30-4 stosa Press j/PI-1-2 78 i
30-4 Steet Press l
/ LR 3-43
- LI-3-114 w1,1-3-14 4
{
/ L1-3-J8* = Either eno I
89-1 WR Level
/L1 3-39 80-1 Wa L4 vel 4
"~~ N j.
./"' l LR 3&,6
~.3-1 e LI-3-113 i
/ !.1-3 'J 18 - tither one 1
80 2 NR Level 4 1-3-52 sg-2 wt Levet i
i v1.1-3-90' I
- dtt-3-172 i
V LI-3-148 V L1-2-93=
- Wither one 34 3 NR Leal
/LI-3-94 36-3 WR Level
't.R 9 8 54.!-3-125 A l-3-111
/ 1-J-1068 - WLthor one g4 4 gg g,y,g L
/Lt-3-107
$$-4WRLeket
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i e
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3Q IPHtNT EkOUIRkD TOR SAft 3 UTDOWW Propered by/04ge % c2 ou,t!WC A OtsICW IASIS FIRE
~
4 l
Checked by/Date_ # / 4 > yf pf son.sgsa-0121
' APPtH0!1 0 APPtWDIX D - IMSTRWFWTATION LIST FOR MAfW CONTRel ROOM
)
Indleator Descristiet
' TR-68-1 (Pen 1)
V TR 68-1 (Pen 2)
%CS Loop 1 Hot Les
$C8 Loop 1 Cold Leg i
R-44-24-(Pat 1)
DCS Loop 8 Hot Leg T1-44-24 (Pen 2) f,3
,Twe loops
$C8 Loep 8 Cold Leg j
f tB-64-43 (Pen.1) rettvitied 448 Loop 8 Mot Les
, TR.44-43 (Pen 2)
(CsLoop3ColdLes
)
[i TR-6 8-4 5 (Pen. D-j l
4C8 Loop 4 Not Let ft-60-65_(Pen 2)
SC8 Loop 6 Cold Let seuraa>tanna.rtum,Mantter,
y*..
.t.....
i s. ;
@ f,33-92 323
\\ [g^ i
'W!-92-313 titherjone
')
+- -
Candonante starsma Tanir teel i
t, 1.
L!-2-230A titherjene for Tank A (Weta 1)
T g
2.
L1.2-2300 i
'^g' t
l 1
3.
L1-2-233A titherlene for Tank n (Note 1) g.-
,; 4 L1-2-2330 i
I j
i
' Chaminal and' Yei-Centeel
)
r 9,
p
{
'gy o
U LT-62-121 (Tank LeveloVCT)
Note 2 i
j 2.
FI-42-93A (Charting F ow)
Wete 3 Noth 1:
If MCS LndLeatten le det evallable. Local, monitoring of tank level or AW eustien pressure is acceptable I
Wot6 2:
Refer to her 4 for as(lone Lf this level Ludkastion is not eveliable.
m 9as stuost Note 3:
This indicator le only required if theApal,h ::a OT!.2 00 Le chosen in her 2.
eOettotes eteam Generator level!tranenttters whose pense 1Lnes have boon p' s4 veeltted as u..y w::: :; e....'... <
kap 4%Uttttd g a. M insida swMwd (gM $80110 001),
s w... li u,,. Am.4= R egie~d (;.J) 4L. iing - ~*
oM ave) T.J).
'l 2
i 356cF/JM8 i
l i
pe'e,gtgg yta sts ese a v isa
a:,c9,;335
- ;i 9 c N3 58-ex 6.5i255.
- .05 i
{
I
/.
l e
(
I
(
)
l 1
l 1
e i
4 I
i 8
l I
I*
I.
"ll!.':C.'t.h t ta. % h)4.f.i.tu N- !
ArygNDIX g i
.3, 6
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+'
v'.
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1 t
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4 i
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e...
e3,cv : :s n : 17 M r.Nr o - v 6:3 su 2 w n.26
((k"15thk5bAP
E"d D N "I'
- 84 Mr./n 3,.,,,Jo 1,,
Cneeae. = m aie o,e,
,,,,,7 l
ffPENDIX E Appendix E - Instrumentation List for Au,xillary Control Acom:
Pressurisse Pressure and Level j
IJ111 net #l1 L: 68-325C Either onq ia tiR d* [ 8.
L1-68-326C Pressure y
L.
P! 48-336C
.O 2.
FI-48-131C One of thnee in gra. g' I 3.
PI-68-342C
~
Reactor Coolant Rot Lee Temeerats e d.
T!-48-lc (Loop 1)
All (w leen
/.. T!-69-26C (Loop 2)
..fr, 2
-eske-- h,j gg
.~.-- n...
v 3.
T!-68-43C (Loop 3)
V%
TI-68-6SC (Loop 4)
Steam Cenerator Freasure end Level Pressure i
1.
PI-t-10 (Loop L)
All four lea p yh 2
?!-t-8C (Loop 2)
-im, i^ r 3.
71-1-19C (Loop 3)
... w wr.
.; :.....e'.4.-. h',f,,
f g t0,
6 P!-t-16C (Loop 4) 8 Y
d.
LI-3-1640 (Loop 1)
Al l f,, t o.,3 d.
Lt=3 L56C (Loop 2)
...,I.-.
.'.:e.,;;: M m '_ d;x f***
v 3..
Lt-3-168C (Loop 3)
A.
LI-3-111C (Loop 4)
Sourea kanse Pluat Monitor f
jq [1..
RI-90-2to gm.
_Le ve ! !4dication for Tanks Voluee Control Tank N #!l.
LI-62-129C eam E2 353kr/JMS ea.a
,,.... f.i.'.# 5NL e. w p.,
g ga p.c<
615 622 6'N
- 8. M run sara, 3MVfDO W '
PER ICCFR$0 APPEND!X A Prepared by/Date N4.M U./t.
r
-- ~
~
Ch*ckeG by/Date A l O' l a ssett APP:N0!X t Appendix 8 - Instruttentation List for Auxttiary Control t oom:
Diornostic fnetru entation for Shutdown Sysh Auxiliary Feedvater SYetem
- d. F!-3-163C (Loop 1)
All fou, l Vf. Ft-3-155c (Leop 2)
' ;- n ' ;e p.
..ea ps v3, FI-3-147C (Loop 3)
.:.,m'.;.
A EM v(. F1-3-170C (Loop 4)
Mcrr a f 5. T!=3-142C (Aux FFT Disch)
O Chemical
- and Volume cont'rol' Tank
- 1. TI.62-40C (Ltdn Mt Exch outkat)
(*^
- 2. II-62-92C (Chg Ndr Press)
- 3. F1-42-93C (Chg Ndr Flow)
- 4. ?!-62-137C (Emet Scration)- -
RAfaty PM'iettietr $Vatwe
'e nob L. F161-910 (RRA Pmp M
- 2. Tb43-920 (AHR Pep, A-A to RCW 263 CL)Either one
'3W 8 8 to RCS L&4 CL)
Essehtf al Raw Cooline Water i*
n,g f 1. TI-67-61C (ERCV Supply Nde A)
- 2. FZ-61-62C (ERCW Supply Ndr 8)
Either ong
- Residual Neat Removal
^*
1.IA4-34C(RNRMtxACutlethosp)
'^
- 2. 73-74-400 (AMR titz ! cettet flamp)
E ther une e
e f
4 9
e f
Ye3 333AF/JMA 40'e
$12$ 9/A 4to
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CON TR ACT N O. __.
ASM E 7 YES @ NO O aEFERENCES R EQUIR EM EN T vlOL ATE D ha of ht9tL_ han N Swms FE0% "T 'Je hn av 7.g _
MW "T
- l ND SOURCE OF REOutREuENT vtOL ATED DESCRIPTION OF CONDITION kotGWT1~. StJWtWiM os s.a m um piTkTios.3 T,h o niAw Tb SAFC. SuaT M gg tyg, t'OT of patJii, uh,<3 us-f SC,w Au ef u s ew b. E<, uta s t$
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RECOMMENDED CORRECTIVE ACTION (OPTION AL)
A90/en. PttoTf. CIT
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'*' *5 su tm co w s m = -rut v m s w w u n e.R.,A ts % g o bND TEL.NO. M X* M L OATE A A'T M CAQR INITI ATED BY D
1 OATEITlu AO Di COVERED INITI ATOR'S ORG ANIZ ATION M 5 % bFY)
Eb,4 M/MM OATE TITLE M ANAGEuENT REVIEWER
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RESPONSIBLE ORG AN(Z ATION Z*,
oc-,
POTENTIAL AFFECT ON DPIKABIOTY~ ~~
8FN 102030 CouuCNO SON 10 23 COuwoNO OPER ABILITY OF NUCLE AR UNIT IS &lS NOTO AFFECTED. W8N 50 20 CouuCN O eLN t o 2 0 CouuCN O IF 'YES'. INolCATE AFFECTED UNITS.
ICAO COORDINATORf *L /- F 7 O ATE RECEIVED PROCESSED BY N.
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TRENDING CODES PLANT i s.1 i
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RiuS ACCESSION NUMBER TVA 19584 (ONP 1-87)
j (gggjp0A Record CAOR
" 22 5 a r v.
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ms accessiua Nuvee= 40'5
'97 0 8 T2 3 0 3CAOR'NO.'!SojF18!7l Oil 15lll !i PART A DESCRIPTION OF THE CAO PL AN T / PR CU E CT
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UNIT 2.
VENDOR N/A SYSTEM _ (e B S VENDOR'S ADDRESS ll./A CouPONEN T I A. u w AT'N h W'N T**Ef5A00 D CON TR ACT NO.
4 /A ASME? YES@ N00 REFERENCES %" MM R E QUI R E M E N T v10L AT E D hf a2AT.O O o' t %CM'~ s At-buT h.)M SWT'EP% F ILOm
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\\0GR vame 50 DESCRIPTION OF CONDITION bT. Q N) ATL '5I.iA W 50tQ OF M%v MENT ATg0f4 1 % T.N inAt- "TO % TT. % "7* O w M t ra TRt. ENEtcT OF F M k % 4 "7 6t.Lu A M Mf%%37D. N 5 u dtfAO 6 DE7ARCI) 69 'TV5 D A( hQ $gy,,gg RECOMMENDED CORRECTIVE ACTION lOPTIONAL) k'5S%QTub ddb OATE NNM TEL.NO.U M 'M M CAQR INITIATED BY INifl ATOR'S ORG ANIZ ATION SN DATE/ flu C 0 OlSCOVERED b0 uANAGEukNT REVIEWER J O ME 9MM/
OATE bN TITLEM"-@ M}
RES90NSI8LE ORG AHlZ ATION W = 6$WS5 m gyy-f s g,gy, w,pf,g/py POTENTIAL AFFECT ON OPERABILITY eFN 10 20 30 CouuoN O son 10 25 CouvoNO oPER A81UTY OF NUCLE AR UNIT is B l$ NOTO AFFECTED.
ir vES. IN0iCATE ArrECTED uNifs.
wsN 50 20 CouuoN O eLN 10 20 CouwoN O CAO COORDINATOM.
DATE RECEIVED
~/ 2 ~ '7 PROCESSED SY [4d d [$'f F~/tP7 OATE TRENDING CODES OlSTRIBUTION u....w
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CAQR aivs Accessolsiuvesa 405
'87 1109 307) CAOR NO3blFei7lc[thsif; ii PARTB EVALUATION AFFECT ON OPER ABILITY DCES Twi$ CAO luPACT UNIT OPER ABILITY 7 YES O NO O IF 'YES' NOTIFIED PLT. WGR. AND/OR OPER ATIONS AT ON TIME DATE SIGNIFICANCC/REPORTABILITY 5:0NIFICANT CAO R E P OR TA81LITY REVIEWED EY O AT E l
YES O NO O 90 O PORS YES k NO 3 %,,,e YES O mE S*0N SIBLE ORG ANIZ ATION YESO NO 7 h 4? &A_
we ??
IF REPORTA81LITY BLOCK IS CHECKED 'YES' IN ITEM 38. GIVE A COPY TO THE ORG ANiz ATION RISPONSIBLE FOR DETERMINING RE* ORT 481LITY IMME0l ATELY: SENT TO D AT E -
flug GENERIC REVIEW A REVIEW POR POTENT' AL GENERIC IMPLICATIONS IS GI 15 NOT C REOulRED.
EVALUATED BY
( ALWAYS REQUIRED FOR SIGNIFICANT CAJS AND CAO'S AFFECTING OPER ASIUTY) g e
j
}NnTo-bf5ft 7 COPY OF CAOR SENT TO ON POR Naut oat t eERFORW ANCE OF A GENERIC REVIEW.
pgef. gg g ROOT CAUSE AN ALYSIS! RECURRENCE CONTROL ORG AN'Z ATION ROOT CAUSE ANALYSIS REQUIRED? YES Y NO O APPROVED Sr RECURRENCE CONTROL REQUIRED? YESW NO O 0 8 6 M gud i
( ALwAYS REQUIRED FOR SIGNIFICANT CAO'S NRC VIOLATIONS. AUDIT FINDINGS. CAO'S NAME DATE AF F ECTING OPER A81UTY. I A m e[,y / M'. e It ElVMER ARE REQUIRED. FILL OUT DART C OF THIS CAOR.
TITLE -
PART C REMEDI AL CORRECTIVE ACTION DISPOSITION METHOD DESCRIPTION OF PF;OPOSED DISPOSITION mETURN TO V E N DOR O REwCA< O RE#AIA O d Ni/ U ACCE pT-AS -it O-SCR AW O OTHER IDESCRISE) 7<si UA
[ee. JtN2ClimeMY OTHE A INFORM ATION NO TAGS PLACEO - %d REPAIR /REgpg PROCEDURE NO.
was ENmNEEmiNG REOu T ED JES O NOE ORGAN RESPONSISLE FOR CI A DA> 6'- 3S EF - @ 3 ciisoc St E N N[NO SCHEDULED COMPLETION DATE 2 -so t y O
VE RIFIC ATION RtTEST Ol Rein 8eECT Ol avoiroM FOLLOW-up O lor Review O j SuPv. Review a R E QUIR E M E N TS OTHER IDESCRIBElO APPROVALS NAME DATE NAME DATE APPROVAL PROPOSEO BY M J Ars s'II' E hf SUPV. APPROVAL IfMfM jr.r., ge PORc REvaEW DATE ONEIONS APPROVAL [ f /)d l/es!(7 f)/d. AI A ACCEPTANCE f$fUNAGER14 001 OATE n rj n OA A s.. Ov AL uw OTwfR APPROVAL j mluS ACCESSION NO. VERIPlC ATION OF REMEDIAL C/ A av a u f O'M ] APPROVED CORRECTIVE ACTION MAS SEEN COMPLETED ANO IS RE ADY FOR VERIFICATION VEmiFICATION ;OuPLE TE ALL TAGS REMOVED CAOp SMEET 2 CLOSED ~ AlWS ACCESSION NUM8ER TVA 18584 (ONP-1-87)
B29 '88 0114 0 01 CAOR, 3^F-670151 PART
- O*
DESCR!?T 03 0F PROPCSED DI3posI;;os A fire nszard; analysis walkdown haJ been pOrformed by a fire protect:1n engancer to determanc if the minimum required number of anotrument sense 11noa required for appendix R wil; survivo sny credicable fire without adverse effects on instrument indicationJ. The sen.se lines involved are far t r.o atoam generator level indicators and for the pressurizer level indicators. It has been detormined that at least one
- team generator level indicator per steam generator locp will Jurvive any creditable fire.
Those are level indicator loops 0-LT-3-38,51,93, and 106. These instruments are to be added to the NEB calculation SON-SOS 4-0127 on revision 8 which la to be issued by 2-5-88. At least one of the three sense lines for the pressurizer level indicators will survive any creditable fire. This will be documented in a formal fire hazardJ analyuls calculation and in a Safety Function pecitlen Statement qcheduled to se issued by 1-20-88. No field work is hequired and tho sense lines are acceptable for use 'as is". palculation 30N-5034-0127 revision 8 is not required for
- estart, i
o b M RC w o FM N a 2 tv ~ c o 0 5 z, D M - E A C - c p r p - s i (h l i e e
- 7 N,. **
OnEEI 3 C.c 3 CAQR =t u RIMS ACCESSION NUMaga 31> ROOT CAUSE ANALYSIS / RECURRENCE CONTROL PARTO ROOT CAUSC OF THE CAO Design criteria and appendix R documentation did not sense lines consider to vulnerable to fire damage because they are essentially noncombustible tubing or pipe. The effects of a fire on the fluid inside the sense lines was not considered, and thus is the root cause of this CAQR. i PROPOSED RECURRENCE CONTROL ACTIONS ? NEB calculation SCN-SCS4-0127 revision 8 is being prepared for issue by 2-5-88 and includes a requirement that all sense lines be evaluated for fire effects. ORGANIZ ATION RESPON8tBLE FOR RECURRENCE CONTROLNF8 SCHEDULE 0 COMPLET10N DAff 2 * /0
- I 9 VERIFICATION ISUPERvisoa mEvirw Woc LNs*ECTioN OITEST OI Avoitom Pottowup O 104 mEviEw Q R EQUIREMENTS lofwEm totsCal0E)
] APPROVALS NAWE DATE NAME OAfg APPRQvAL _ omonostoor D=e d. no.<1D i n sr (J svPV. APMcVAL t, A C _ /udB PORC RE E DATE. DNEIONS APPROVAL k. T Ud fift( W OA APPROVAL =.. 8B"*0M 4 0 (F1 OTHER APPROVAL nes VERIFICATION OF RECURRENCE CONTROL 4tM S ACCE ssaON No NAME APPROVED RECURRENCE CONTROL DATE COMPLETE-READY FOR VERIPICATION VEntPICATION CAOR SMEET 3 CLCSED RiWS ACCESSION NVM8ER TVA 19584 (ONP-1-87) y
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SEQUOYE NUCII!.R PIEI FIREPROIECTION NRCMI!IING F).RCH9,1988 i
e MEETING ACESTA I. INTRODUCTION C. H. Fox II. SQN TIRE PROTECTION HISTORY J. B. Hosmer III. RESPONSE TO QUESTIONS 1, 17, 24, 6, 25 F. Koontz i 2, 5, 10 B. Bryan 8, 9, 13, 14, 15, 21 J. Pierce 3, a, 16, 7, 11, 12, IS, J. H. Sullivan 19, 20, 22, 23, and 26 ) IV. SD?d.ARY 4200F
i FIRE PROTECTION HISTORY 2/80 - 9/S1 Operating license j SRP, APCSB 9.5-1 L' nit 2 condition Appendix R I III G. J. L, and 0 l 6/84 - 7/84 Watts Bar Appendix R f inspection 1 8/84 NRC confirmation letter 8/S4 - 1/85 Operations and DNE team - Industry issue plus Watts Bar Team used evolving guidelines generic letter 83-33 and IEN 84-09 Generic letters 85-01 and 86-10 not issued 121 interactions 21 deviation requests l 4200F
NRC audits of corrective 1/85 7/37 actions' Last audit action closed 7/87 12/86 DNE calculation program identifies documentation concern with R6 (shutdown logic) 7/87 DNE assumes long-term compliance role RT issued with no operations review 10/87 DNE concludes R8 required 12/87 Review team formed to address all known concerns 1/88 Team issues final report and meets with NRC 2/88 NRC identifies 26 questions 3/2/88 TVA response to 26 questions 3/8/88 Question 12 amplification r a 1 L200F
~ ) mer 6 2 t i 0 m t ' 0 i s L 1 o 0 eL 0 s 1 ot R t Dn s F a o C yo) l 0 L 0 1 r 8 on ( d t nCo n i a t uf a l o or B e oo sp C et 0 nO t 6 f i Suoa o l Nmm e g oar SsN a o t n r u( uo 0 e 4 c i r or Ha r e - V P 2r o F 0 2 ) m e r ( e s o D O 5 0 5 0 5 0 5 0 3 3 2 2 1 1 0 0 1 0 0 0 0 0 0 0 0 o ru Fig l;
2-Hour SON Site Boundry Dose For Various Amounts of Coolant Lost (Normal Operation) oose (rem) 25 20 ~ ~ -~~ ~ 1 33 inhalation Dose -. +. - -u-.-.--< .. -.. +....... - -. - --+--..-=a-e* = '-=<+=66.----.as..--*.s4m,-. 0 O 20 40 60 80 10 0 Percentage of Coolant Lost (10 CFR 100 Limit - 300 rem) Figuro 2 J ~
QUES!!ON 1 ISSUE: Containment integrity following a fire
RESPONSE
Calculation shows offsite dose within 10CFR100 guidelines 0-100% RCS release ANSI 18.1 - 1984 activity 0.28 REM gamma site boundary (25 limit) 18 REM thyroid site boundary (300 limit) Ce f ense-in-depth Only practical release path via containment purge l Ognnects containment to environment Infrequently used at power
- Exhaust line has three fait close valves in series HEPA filters and charcoal beds in exhaust line Supply line has three fail close valves Additional four fail closed dampers in supply line Valves and dampers close automatically on radiation signal Appendix R, Section III.L. does not require containment integrity CCNCLUS;0N:
Highly improbable Dese within 10CTR100 limits i Not Appendix R required 4 ] s' 4191y ) 1
em QUESTION 2 ISSUE: Fuel pool boiling ef f ects on auxiliary building
RESPONSE
No saf e shutdown equipment in area except for cables and surge tank Cable type qualified to MSLB temperature and humidity Nine hours for pool to boil (worst fuel load) Boiloff rate - 48 spm Refuel floor volume - 1.000.000 ft.3 Refuel floor exhaust flow - 28,000 cfm l General building exhaust - 80,000 efs Auxiliary building general spaces volume - 2,000.000 ft.3 No fuel failures result - radiation effects from pool boiling not a saf e shutdown concern i CONCLUSIONS: Significant time for pool to boil Minimal impact on environment 1 Not Appendix R issue 4191i
QUISTION 3 ISSUE: Procedure coordination
RESPONSE
Utilize all plant equipment Operator trained and experienced Procedure hierarchy Emerged procedure Fire-specific procedures Operation and training to review procedures Not Appendix R requirement CONCLUSION: No significant conflicts identified Operator will handle most important event e i i l i 4115F 4 l 1 1 _ j
e i 1 QUESTIONS 4 AND 16 l ISSUE: Adequate Boron concentration l
RESPONSE
Reactivity calculations Attempt normal boration (BAT / letdown) RER letdown to floor drain collection tank with makeup f rem charging pumps from the RWST Equipment list in safe shutdown logic Pressurizer level fluctuations not used l Westinghouse calculation shows single RER heat exchanger cooldown in 26 hours Credit for pressuriser spray, auxiliary spray, letdown and excess letdown not taken CONCLUSION: The STA will perform reactivity calculations and operators will take appropriate actions to maintain suberiticality 1 l l 1 l l l k195 1
4 4 l QUESTION 5 ISSUE: Is control air required? i
RESPONSE
Control air is not required to reach safe shutdown Control air used if available Manual actions used as backup specified in Procedure SOI 26.2 Vater solid operation unlikely s Procedures and assured instrumentation prevent water solid operation Takes over 10 hours to go solid without letdown and no RCS cooling CONC:.USION: Y Plant can be shut down without control air Manual actions are supported by procedures 4 e P f a b 4191T 4 4 h 6
r QUES!!ON 6 ISSUE: Water solid operation RESPONSE: Unlikely event - loss of bubble does not make plant unsafe Pressuriser level assured Operator would terminate spurious charging Time available for action (10-20 minutes) Water solid backup 19 Hours earliest KHR needed (exception Question 4) Casualty procedure assures valves ready in 15 hours Cold shutdown not NRC requirement before 72 hours Safety valve available if PORV/ head vent not available Procedures and training not needed CONCLUSION: 1
- Low likelihood for need l
-1 Means of assuring inventory if necessary 1 l i 1 i 1 a 4191T I J'
i QUESTION 7 ISSUE: Ability to put RER system into operation Valves (TCV-74-1,2) in question can be repaired
RESPONSE
Not needed for hot standby Fire outside containment casualty procedure ensures availability within 15 hours without containment entry No significant in situ fire load around valves Tire inside containment will not damage valve For fire in valve will not damage other equipment No spurious PORV, head vent, etc. Normal access to containment 1 Cold shutdown condition is achievable CONCLUSION: j i i i O 4195T 1 i
a QUESTION 8 ISSUE: Reactor coolant pump oil collection system RESPONSE: Appendix R. Section !!!.0, requires an cil collection system for reactor coolant pumps to collect oil leaks from the lubricating systes Reviewed and accepted by NRC Recently reviewed by fire protection engineer and determined to be adequate Postulated low probability events such as broken shaf ts are not required by Sectica III.0 of Appendix R Sleeve around shaf t would contain oil on the shaf t CONCLUSION: Reactor coolant pump oil collection system meets the requirements of Appendix R w l I 4191F
a QUESTION 9 ISSUE: Tire damage to SG atmosphere power-operated relief valve controls
RESPONSE
Modification associated with SGs 1 and 4 ensure that no fire in the area of the PORV solenoids and controller can cause spurious opening of the PCRVs. Tire hazards evaluation perfarmed for the area containing the solenoids for PORVs 2 and 3 determined there is insufficient fuel load to cause damage to the solenoids. For a fire in the auxiliary control roca cabinet, s purious action esn be mitigated. One PORV opening is within the design basis of the plant. Boron injection tank and pump and safety injection pumps are not required nor assured f or Appendix R saf a shutdown. Charging pump operability is assured with manual control. CONCLUSION: Met Appendix R requirements and stayed within the design basis events of the plant. m i 4191T f I l
' QUESTION 10 ISSUE: Multiple steam generator blowdown
RESPONSE
Not Appendix R - MSLB separate initiating event. CAQR issued to document and track. Bounded by TSAR analysis - 4.6 f t.2 break Flow limiter - 1.4 ft.2 2 ADVs - 0.4 ft.2 Valve vault break and 2 ADVs - 1.8 ft.2 Vestinghouse analysis of unisolated blowdown of 2 SG with 2 PORVs open (Catawba. Seabrook) bounds SQN. Physical modifications have been made. Moved controllers and solenoid out of valve vault. Replaced mechanical positioner with more reliable model. Operator can,-aanually close ADVs. ADVs and closing solenoid are environmentally and seismically qualified. ADVs control design consistent with design for all Westinghouse PVRs. CAQR postrestart. AppendLx R criteria do not exclude SG blowdown. CONCLUSION: Plant is saf e. CAQR postrestart. Long-ters corrective actions to resolve CAQR being evaluated. Not Appendix R issue 4191F i
_~ 1 4 i QUESTION 10 (Continued) { ISSUE: Single failure criteria Standard industry practice
RESPONSE
Seismic event Safety-related equipment designed Do not consider multiple failures of nonseismic componer.ts [ .ain steam line break 3 Independent initiating event i Loss of offsite power r Single failure 1 Active immediately or 1 Passive at 24 hours i Do not combine with 6eismic event t I i j 1 r i 1 } i i e I I 4191T i i h i
Y e QUESTION 11 ISSUE: Closure of pressuriser block valve Closure at 2500 psid specified Tested using MOVATS system per MI 10.43 Thrust meets or exceeds requirements CONCLUSION: PRI blocks closure verified Y' j 1
QUESTION 12 ISSUE: Spurious actuation RESPONSE: Circuits required for safe shutdown and those not allowed to spuriously operate were analyzed as required circuits In general, required circuf.ts protected by separation or fire barriers Where separation did not exist, interactions were identified, analyzed, and dispositioned Alternate shutdown provided for cable-to-cable areas Main control room Cable spreading room Auxiliary instrument room Ungrounded DC control system Ungrounded AC off-control transformers O s Separate look bacx at high/ low pressure interfaces Reactor vessel head vents RER letdown path RCS normal and excess letdown Pressuriter relief paths In 3 cases only is GL 86-10 Sectica 5.3.1 not met CONCLUSION: Met Licensing basis for Appendix R Position submitted to NRC Reevaluated CL 86-10 5.3.1 March 8, 1988 submittal 6195F
QUESTION 13 \\ ISSUE: Baseline data - SQN-SQS4-127 RESPONSE: Baseline data provided ARSK drawings, block diagrams, interaction studies, safety function position statements, approved deviation requests, fire hazards evaluations, engineering change notices Task force performed review of selected issues and this was submitted to NRC Nu=erous audits on electrical calculations CONCLUSICN: R6 was the revision that reflected plant configuration 1 Baseline data exists Suf ficient number of audits have been performed and determined appropriate calculation methodology used 4191F
QUESTION 14 ISSUE: Fire effects on equipment in rooms adjacent to a fire RESPCNSE: Fire dampers ensure physical separation Fusible links ensure damper will close in a timely manner Contain fire and products of combustion Equipment qualifications not required for Appendix R or 50.49 requirements Containment Outside - Access not required Inside - For fires inside containment there are no credible fires that create an adverse environment that requires containment entry to ensure saf e shutdown CONCL SIONS: EVAC calculations are not required to demonstrate Appendix R compliance 9 9 4193F 3 c -< ,w v.
_ m l t I QUESTION 15 i ISSUE: Fire near pressuri:er
RESPONSE
Fire Ha:ards Analysis o FdA determined that at least one train of pressurizer level and stean generator level will be available. Insufficient fire load or adequate separation exist for the required instrunentation. CONCLUSION: Fire in vicinity of pressuri:er will not ptavent safe shutdown. i i I s 7 ~ y----. ,i..- .uc.. w 3- =,,v-,.==,gw--<
4 QUESTION 17 ISSUE: Validity of passing liquid through safety valve RESPONSE: Short-term operability has been demonstrated EPRI test data supplied Crosby 6M6 valve Water test Some chattering / galling of surfaces Summary noted valve closed Needed only if pressurizer bubble lost PCRV unavailable head vent unavailable normal letdown unavailable excess letdown unavailable Pressurizer level instrumentation assured for fire Operator secures charging Few challenges anticipated CONCLUSION: Valve will perform as intended 4 Not Appendix R required i o 6191T
5 i QUESTION 18 ISSUE: Assuring adequate suction to charging pumps Analyzed fire sones Identify VCT spurious isolation areas Procedurally controlled expediticusly Open 400 Vac breakers or Open RWST supply and open its breaker or Trip CCP until above is completed Isolate VCT on VCT level observation CONCLUSION: Our response to this condition is consistent with what other utilities have done and we have taken appropriate action, consistent with other saf ety requirements, to protect the CCP from less of suction. E 9 0 4195F
t QUESTION 19 ISSUE: Basis for fire protection of shutdown systems inside containment RESPONSE: Apperdix R. Section III.G.2.a-f, is the basis Shutdown logic review Equipment identification Plant cables Evaluate separation Documentation CONCLUSION: Inside containment has been evaluated consistent with our Licensing position on Appendix R. r i i e j f 4195F t P
.- -.-.......- -. -...-. -. - - _..__. - ~ ~... .. -... - _ _.. -. ~.... -. _ o ^ s i I l l 4 I e QUESTIONS 20, 22, 26 l Spurious saf ety injection, distinguish between LOCA and fire 1 ISSUE: Spurious safety injection not prevented and instrumentation provided
RESPONSE
Safety injecticn not required for safe shutdown 1 SI terminated criteria CONCLUSIbN: Operator can diagnose event and terminate SI. i l i E e .,e , _.. _. ~... _ _,.
e a QUESTION 21 ISSUE: Fire effects on instrument sense lines
RESPONSE
Effects have been evaluated Fire Hazards Analysis done for Appendix R instrumentation Adequate separacion exists or fire effects will not adversely affect both trains of Appendix R instrumentation CONCLUSION: Adequate instrumentation available to the operator e 4 0 9 41937 l ,_m_.. _..,,--
~ QUESTION 24 ISSUE: Reactor coolant pump seal integrity RESPONSE: Seal integrity assured SOI 68.2 operating procedure requires pump trip for loss-of-seal ~ cooling (less than 2 minutes) WCAP applies to qualified high te,mperature and nonqualified high-temperature elastomers l Sequoyah uses Parker E515-80 or better elastomers Immediate seal heatup not expected Westinghous>2 tests indicate two-hour survival (one hour needed) Worst case is if seals fail 21 gpm/ pump leak CONCLUSION: Procedure requires pump trip Seals will survive h 6191T
o' e 1 QUESTION 25 ISSUE: Spurious pressurizer PORV opening - block valve closure
RESPONSE
Operator action will mitigate event Fire in control building Operators dispatched to auxilie.ry control room Staf f overlap between main / auxiliary control room AOI-27 checks hi/ low interfaces Isolation as needed A01-18 requires block valve closure if PORV open Attempt from main control room, MOV board 2-5 minute action time Terminate SI per criteria Similar to stuck open PORV analysis WCAP-9600 SI initiated if available Only charging would inject Additional 700 gallon loss (90,000 gallons RCS) Opsrators trained on AOIs CONCLUSION: Operator mitigates event Similar RCS response to analyzed event L191F
DISTRIBUTION FOR MEETING SUPRARY DATED: March 22, 1988 Facility: Sequoyah Nuclear Plant, Units 1 and 2* IbocketFile~~ NRC PDR Local PDR Projects Reading S. Ebneter J. Axelrad S. Richardson G. Zech J. Clifford T. Rotella C. Jamerson 0GC J. Rutberg F. Miraglia E. Jordan J. Partlow G. Hubbard D. Notley D. Kubicki B. D. Liaw E. Marinos G. Felgate i E. Gilbert C. Mullins P. Hearn S. West R. Auluck R. Wescott R. Pierson B. Zalcman H. Garg ACRS (10) Hon. M. Lloyd Hon. J. Cooper Hon. D. Sundquist Hon. A. Gore Dr. Henry Myers Mr. R. King, GA0 P. Gwynn J. Scarborough G. Marcus C. Miller T. Elsasser C. Ader TVA-Rockville SQN Reading File
- Copies sent to those persons on facility service list
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