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,/ NUCLEAR REGULATORY GOMMISSION DISCUSSION OF GRAND GULF DIESEL GENERATOR INSPECTION ORDER i
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PUBLIC MEETING l
4 ZY Thursday, May g, ]984 I
l Pages 1-58 Prepared by:
ANN TIPTON 0506150000 050205 9
LLO4 459 PDR I
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UNITED STATES OF AMERICA r~'N 2
NUCLEAR REGULATORY COMMISSION ll
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DISCUSSION OF GRAND GULF 6
DIESEL GENERATOR INSPECTION ORDER 7
g PUBLIC MEETING 9
10 II Room 1130 1717 H Street, N. W.
Washington, D. C.
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Thursday, May 24, 1984 I4 The Cc= mission convened in open session at 10:05 7
o' clock, a.m.
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CCMMISSIONERS PRESENT 16 NUNZIO PALLADINO, Chairman of the Commission 17 THOMAS ROBERTS, Commissioner JAMES ASSELSTINE, Ccmmissioner 18 FREDERICK BERNTHAL', Commissioner i
19 STAFF AND PRESENTERES SEATED AT COMMISSION TABLE:
20 S. CHILK H. PLAINE 21 W. DIRCKS H. DENTON 22 D. EISENHUT G. CtMNINGHAM 23 J. ZE SE 24 AUDIENCE SPEAKERS:
25 M. HODGES T. NOVAK M. SRINIVASAN G. WHITE O
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DISCLAIMER
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This is an unofficial transcript of a meeting of the United states Nuclea Regulatory Cc==ission held on 5
6 Thursday, May 24, 1984, in the Cc==ission's offices at 1717 H Street, N. W., Washington, D. C.
The =eeting was 7
8 open to public attendance and observation.
This transcript has not' been reviewed, corrected or edited and it =ay g
Contain inaccuracies.
g The transcript is intended solely fer general y;
inf r=ati n p rp ses.
s pr vided by 10 C:TR 9.103, it is 12
.not part of the for=al or infor=al record of decision of the matters discussed.
Expressions of opinien in this transcript do not necess'arily reflect final determinations U
cr beliefs.
No pleading or other paper =ay be filed with 16 the cc==ission in any proceeding as the result of or addressed to any statement or argn=ent contained herein, P-except as the Cc==ission may authori::e.
19 20 21 22 23 24 25 O(O
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CHAIRMAN PALLADINO:
Good morning, ladies and 3
gentlemen.
Before we hold this meeting this morning, we need 4
to vote to hold it on short notice and the meeting has to do 5
with discussion of a diesel generator order issued by the 6
staff on Grand Gulf.
May I have a vote to hold this. meeting 7
on less than one week's notice?
8 COMMISSIONER ASSELSTINE:
Aye.
9 CHAIRMAN PALLADINO:
Aye.
10 COMMISSIONER BERNTHAL:
Aye.
I1 COMMISSIONER ROBERTS:
No.
12 CHAIRMAN PALLADINO:
Okay.
We have three votes 13 saying "aye."
14 The purpose of,today's meeting is to discuss with (p) 15 the staff the rationale for the order issued on May 22, 1984, v
16 regarding diesel generator inspection at the Grand Gulf plant.
37 Specifically, I believe the Commission is interested 18 in understanding the basis for allowing the plant to continue 39 operation at power levels up to five percent while one diesel 20 generator is undergoing inspection and, therefore, is in-21 operable.
I recognize the meeting was called on short notice.
22 This was as a result of conversation late yesterday afternoon 23 between me and other Commissioners.
While the staff has not g
had a chance to prepare formal written material, perhaps they
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I The second area has to do with the relaxation of the
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2 limiting conditions for operation of the plant by means of 3
this order.
It is not clear to me what the public health, 4
safety, or interest benefit is of relaxing the limiting 5
conditions of operation and I also have a questlon about 6
relaxing those conditions by order rather than by requiring 7
the licensee to submit a license amendment and reviewing that 8
in accordance with our regulations governing license amend-9 ments, which would include an analysis of whether those 10 amendments, in themselves, involve significant ha::ards con-11 siderations.
I guess I question the propriety of that ap-12 proach by the staff as well.
13 Those are the two areas of questions that I have n'
14 identified based on a fairly quick reading of the material.
(d 15 CHAIRMAN PALLADINO:
I think there is a related 16 question and that has to do with what the procedural options j7 the staff has with regard to an operating plant as opposed to 18 ne that doesn't have a license, and I guess -- well, ma'ybe jg that's far enough for the question.
Other questions or comments?
20 (No response.)
21 CHAIRMAN PALLADINO:
All right.
Can I turn the 22 meeting over to Mr. Denton.
MR. DENTON:
Let me just summarize the staff's activities on this application during the past month and I f~)
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I will try to answer Commissioner Asselstine's questions and, if 7
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not, we have OELD here and the technical sta'ff that can do so.
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Our activities have been driven by the need to 4
protect public health and safety.
I would like to start with 5
calling your attention to an order I issued on April 18.
I 6
would like the Secretary to just pass these out.
7 This was an order that amended immediately their low 8
power license.
9 CHAIRMAN PALLADINO:
This is an order dated when?
10 MR. DENTON:
April 18.
It is restricted conditions 11 for operation.
12 As we have discussed with the Ccmmission on many 13 occasions, we found errors in the licensee's tech specs and we p
have a program underway to identify those.
When we had
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15 identified those that I thought were required.to make the low 16 power license whole, I issued this order on April 18, to be j7 effective immediately, and said the plant shall not operate yg unless this operation is conformance with required tech s'pecs.
[g All these changes were to make the license more restrictive and they were intended to Correct the inadequacies that had found to be in the license.
I say that just by way g
of background to get into the issue.
Now, while we were reviewing the toch specs and even before that, the staff had concerns about the Transamerica Delaval diesels and we had had dealings with the industry.
We
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have indicated that our confidence in those was not as high as s
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program.
We had a number of meetings with the Grand Gulf 4
people on their diesel, we had our consultants from Battelle 5
Northwest and their consultants meeting meeting with Missis-6 sippi Power and Light over the adequacy of their diesels and, 7
on April 25, we sent the company a. staff evaluation of the TDI 8
diesel generator reliability for powe: operation at Grand 9
Gulf.
That package has been passed out.
10 In there, this says, "As previously discussed at the 11 April 13 meeting and in several previous discussions, the 12 staff has been unable to conclude that the proposed MP&L y
program for ensuring adequate diesel generator reliability is sufficient to support operation of Grand Gulf at power levels
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15 in excess of five percent power.
We have concluded that your 16 submittals to date do not adequately address existing techni-g7 cal concerns without further inspection for defective compo-18 nents in at least one diesel engine," and so forth.
39 So, when I sent that letter, I had already received the views of the Division of Safety Integration that operation g
at low power did not pose an unduel health and safety risk.
g We had looked at, from the moment the diesel concern had arisen, whether or not we should allow Grand Gulf to continue operation with these questions about their diesels and I had a written analysis from that group saying that there was no p
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unreasonable health and safety risk associated with operation
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2 at low power without reliance on these diesels.
That was v
3 based on a preliminary look at the specific design of the 4
plant and what was required at low power by the various 5
accidents that could happen.
6 COMMISSIONER ASSELSTINE:
IIarold, that was the April 7
12 analysis from Roger Mattson to Darrell?
8 MR. DENTON:
Yes.
9 COMMISSIONER ASSELSTINE:
Okay.
10 MR. DENTON:
The Company, in response to our April 11 25 memo, came back in several weeks later, still objecting to 12 the staff's view.
They had, in their response, said that the 13 diesel is reliable to the first fuel cycle, that they should g
be allowed to operate at 100 percent power, that the first (3
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15 inspection could be deferred until the end of the first v
16 refueling cycle, and, if we were still concerned, they would j7 make the alternative that they might do this inspection and gg repair scmewhere in the start-up program.
39 We had their answer to our April 25 submittal 20 reviewed by the staff and by our consultants.
We disagreed 21 with their view and we told them, in a mee. ting on May 18, the f 11 wing:
that our view was still the same; that these 22 g
diesels must be inspected prior to exceeding five percent g
power; that their submittal did not demonstrate adequate reliability to meet General Design Criteria No. 17; nor
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justify operation above five percent power.
2 We told them, at that =eeting, that we had deter-3 mined that the plant was safe for operation up to five percent 4
power for sc=e period but that period at five percent, that we 5
were relying on the turbine generators and on the offsite 6
pcwer, not on the diesels and that the issue of the diesels 7
needed to be resolved premptly.
8 This ccmpany keeps talking abcut =eeting with the 9
Ccemission for full power in the near future and I felt the 10 need to resolve this diesel concern.
I told them, one ti=e, 11 that it required an inspecticn and disassembly.
They dis-12 agreed with =e.
I told that, consistent with the Shoreham 13 decision, an exemptien was required to be submitted.
They p
indicated that they would submit an exe=ption request for iV; 15 operation at icw power within abcut a week.
16 Because the Cc==ission has always taken the view 37 that a violation of a regulation does not, in and of itself, jg i= pose a require =ent that the license be suspended, and since 39 I had an analysis that indicated that safety of cperation at 20 1cw power and the risk to public health was not a question 21 here, I thought that I could give them the 3ime to request an exemptien.
So, on the 22nd, I issued an crder that required 22 them to inspect and repair one diesel generator and ordered ccmpensatory actions on the remaining onsite and offsite power 3
sources.
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their exe=ption request because there is =cre := an exe=ptien l
7 request than us: the safety analysis part.
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require =ents := he 'ceked at and we have act prejudged these.
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- thcught : vas being censistent with the Sh::eha= decisien in la telling the= tha: they needed :: request an exe=ptic: fer
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to the public, and health and safety, :: get an '- ediate 13 inspecticn cf these diesels befcre :L e -- in ether v:rds, if e~,
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sufficient ecnfidence in these generaters.
gg The way I chcse te de that was by crder which did I
h relax cne LOC, because the LOO -- the license n::: ally re.
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quired tvc diesel genera:crs and if either ene is cut cf
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serrice icnger than 72 hccrs, the plant veuld have :: shut i.
dcwn.
That was a requirenent that is standard f:: full pever but, based en wha: I knew abcut this, I felt it was =cre in 3
the public interest :: require ene be taken devn t: rescive i
this uncertainty while : inpesed addi:1:nal require =ents c 5
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2 In a nutshell, that is the history of the staff's f
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CHAIRMAN PALLADINO:
Harold, I think you still say 5
-- if I understand this order correctly -- two separate and 6
independent diesel generators have got to be available or 7
8 MR. DENTON:
Before I would recomunend the Cossaission l
3 vote on this plant for full power, I would expect to have this i
to issue fully resolved, i
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11 CEAIRMAN PALLADINO:
But what I don't understand is 12 you said there are some conditions for operating during this 13 period of time and maybe you should refer me to them, because 14 I thought they were included in Attachment 3, I believe it is.
15 MR. DENTON:
They are a little bit different than i
16 the Shoreham situation in that they have two TDI diesels and j
- 7 one non-TDI diesel.
So, in this license, we only permit one
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g, diesel be available as well as the TDI.
20 The period of time required for this inspection is 21 arguably between two weeks and nine weeks.,,The staff thinks j
it can be done very promptly, the licensee thinks it will take 22 a longer period of time.
So that's the period of time that we think is required to execute this.
We would plan to have our
- 3 consultants there during the tear-down and the license also 25 i
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has requirements for watching for tornadoes during this period 2
and other external hazards that might affect the availability 3
of offsite power sources.
4 CHAIRMAN PALLADINO:
I still don't know what the 5
conditions is wi.th regard to diosel generators.
6 MR. DENTON:
Let me ask Darrell to explain the 7
specifics.
8 MR. EISENHUT:
Mr. Chairman, I think you are refer-9 ring to one of the tech specs that is attached --
10 CHAIRFAN PALLADINO:
348-1 -- 3/48-1.
11 MR. EISENHUT:
There is a limited condition of 12 operation Item B which states, now, in the new tech specs, 13 that two separate, independent diesel generators shall be g
operable, etc.
It used to say three.
This plant, remember, 15 has two TDI diesels and one other diesel, not by Transamerica 16 Delaval.
g7 The tech necs used to be three and it has been 18 changed to two.
So that is the basis of the two here,now.
It is one TDI and one non-TDI.
COMMISSIONER ASSELSTINE:
The non-TDI is just hooked 20 t
21 MR. EISENHUT:
That is correct.
22 CHAIRMAN PALLADINO:
And it is going to remain that g
w"Y7 24 MR. EISENHUT:
It would remain this way during the CN V
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2 CHAIRMAN PALLADINO:
But it would remain tied to the 3
MR. EISENHUT:
One would remain tied to the high 5
pressure core spray.
The one TDI must be operable and, 6'
elsewhere in this package, it requires that there be an onsite 7
gas turbine that now has conditions put on it to declare it 8
operable and I told that that gas turbine, as of today or S
yesterday, was declared operable by the utility, and I am told to that, in accordance with this. condition, the one TDI diesel, 11 they are now in the process of draining the diesel and will be 12 starting disassembly today.
13 So this would be the condition that would remain in 14 effect through the inspe,ction period for ene TDI diesel.
15 CHAIRMAN PALLADINO:
This gas turbine, is that an, 16 approved gas turbine or does it --
3 17 MR. DENTON:
No, it is not an approved gas turbine.
jg CHAIRMAN PALLADINO:
Well, actually, General Design 39 Criteria 17 doesn't say it has to be approved.
It says you 20 have got to have onsite and offsite power to meet certain conditions but then, of course,'if you had,,GDC-1, then it 21 speaks to quality.
22 MR. DENTON:
It doesn't necessarily have protection 23 3
against tornadoes and earthquakes to the same quality that the diesels would have.
So that's why we laid on some additional
..a 13 m,
I requirements to watch for these external phenomenon.
2 CHAIEMAN PALLADINO:
Why did you say GDC-17 isn't 3
complied with?
k MR. DENTON:
Because they rely on these two TDI 5
diesels to fully meet the Commission's criteria and we don't 6
think they have been demonstrated to be sufficiently reliable 1
7 to do that.
l 8
The gas turbine is not a reviewed, claimed source.of 9
onsite power.
It's an extra that they happened to have -- I 10 think they brought it in during the dispute over the TDI 11 diesels to augment their onsite power capability.
12 CHAIRMAN PALLADINO:
I don't want to get involved in 13 words, but the General Design Criteria for design and they 14 designed it right, that',s why I kept coming back, because I s
15 think we need operating criteria as well.
16 MR. EISENHUT:
That is certainly a point the staff j7 considered and looked at and there was that debate whether it
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jg was a design criteria or an operating criteria.
I.think we jg tried to take a simple interpretation that I can understand, 20 and that was that this plant came in with at application that 21 assumed two diesels with a certain level of reliability to meet the onsite requirements of GDC-17.
That clearly, by 22 application, was two Transamerica Delaval diesels which were 23 24 pedigreed, which were reliable, which were environmentally qualified.
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Now that they fall below that threshold, we took the 2
view, we thought consistent with the Commission's order, that 3
you have to declare that they don't meet GDC-17 in the letter 4
of what they applied for.
5 We, on.the other hand, however, took the view, as 6
Harold said, that we believed that the plant was safe.
We 7
believed the plant was adequately safe because, in the bottom 8
line, you really, from a systems standpoint, don't need any 3
kind of diesels for five percent power.
You don't need any 10 power source for a long period of time following all events at 11 five percent power.
12 So it put us in this situation where -- I think 13 there is another important ingredient.
Even up to the May 6
- 4 submittal and the May 18 meeting with MP&L, MP&L really 1
15 believes the diesels, today, are qualified.
They believe the 16 diesels adequately satisfy GDC-17.
We had considerable
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37 debate, last week, with our consultants, coming to the bottom i
18 line that', in the staff's view, we didn't have enough confi-gg dence in the reliability of the diesels.
S we, in effe t, n last Friday, took the view with 20 g
the utility that, notwithstanding the fact,that they have submitted evaluations arguing they are reliable, notwith-standing that they have done inspections, notwithstanding that the industry has done inspections at Catawba and argued that the Catawba inspections are applicable to Grand Gulf, we took J
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the view that we just aren't quite there in terms of relia-l 2
bil,ity.
So, therefore, we will, for the sake of going forth 3
in the discussion, assume that the diesels are not what they 4
were originally meant be in terms of reliability to go forth.
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So we, in effect., declared them not to meet present require-6 ments.
7 COMMISSIONER BERNTHAL:
Darrell, you say they are j
8 not what you would like them to be in terms of reliability..
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9 You really mean in being able to -- what you are talking about l
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10 is quality assurance in a sense.
You don't know that they j
11 aren't reliable.
You're just not sure that there isn't l
12 something wrong with them.
- 3 MR. EISENHUT
I think that is an important point l
g and I keep reminding everyone, on my staff, too, that is not s.
l 15 that we have concluded that they are unreliable.
It is just
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that it has not been demonstrated that they are reliable.
16 MR. DENTON:
We want to be sure that some of these 97 gg critical components, which have been found to be broken and cracked in other examinations, are not actually present here.
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We have found at least one similar diesel that we were very g
pleased with at Catawba, but the conditions.under which that g
diesel was manufactured and the quality assurance is quite 22 4
!I different than at Grand Gulf.
23
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2 So we think the only way to get that level of 24 3
confidence at Grand Gulf is to examine these components with
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experts and we have spelled out in this order the type of 2
examination and components we think need to be looked at.
3 COMMISSIONER BERNTHAL:
But I wanted to make clear k
that, at this point, you are looking for a problem.
You 5
haven't found a problem, yet.
~ 6 MR. DENTON:
Right.
7 COMMISSIONER ASSELSTINE:
At this plant.
8 COMMISSIONER BERNTHAL:
At this plant, that's right.
9 MR. EISENHUT:
And even in thi area that Harold i'
i 10 pointed out, we don't know that the components on Catawba were 11 manufactured differently than at Grand Gulf.
All we know is 1
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12 that, because of the problem with QA records, et ceteri, you 13 can't demonstrate that the Catawba experience is applicable to 14 what you would expect at Grand Gulf.
it i-15 CHAIRMAN PALLADINO:
Is there not another point that 16 this diesels are different from the ones in which they had at 17 least the major flaws?
18 MR. DENTON: -They are a different design than the cne at Shoreham, that's right.
They are more like the one at jg Catawba.
20 21 CHAIRMAN PALLADINO:
Have there been flaws found in diesels of this kind?
22 i
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MR. EISENHUT:
I think so, yes, on some of the 23
!i Principal components.
24
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MR. DENTON:
The Comanch'e Peak turbine is torn down 5
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I this week and is being exa *.ed and, if ycu read the attach-
=ents to the letter cf April 25, it has cur censultant repcrts 3
j and they spell cut, in these reports, their views en certain 4
components in the diesel and why they think it needs to be 5
locked at.
6 COMMISSICNER ASSE,STINE:
Has the staff basically 7
endorsed the cwners' grcup program, at this point, and it is 8
caly a question of doing an inspection to make sure that the
' cwners' group program is met, or are there still fundamental S
10 questiens abcut the adequacy of the cwners' grcup prcgram, i
11 itself?
12
~
MR. DENTON:
We have not fer: sally endorsed the 13 cwners' grcup program, yet.
I think we have in hand, new, cur p
censultants views en the pregram and we hepe to have a staff 15 pcsition en that very shortly.
i 16 CC80CSSIONER ASSEI.STINE:
I read the P&. letter and a
i 17 it seemed to raise both kinds of questions. ' Clearly, it said
- g that, for this particular plant, in their view, an. inspection l
was essential.
But it also seemed to raise sc=e questiens j
39 at went
- ader dan eat, that went to scme of 9.e elements 20 i
in the owners' group pregram itself.
Is that a fair charac-21 i
teri:ation?
22 MR. EISENEUT:
I think ti=e has evertaken a little l
23 bit the April 22 letter.
24 i
1 CCMMISSIGNER ASSE:.ST2TE:
I was talking ahcut the 25 v
,g,..O paM NW4mW 4
h*
.OUh N *' "
i 18 1
j 1
j.
May 21 letter.
4 2
MR. EISENRUT:.The most recent?
3 COMMISSIONER ASSELST'INE:
Yes.
i l
N MR. NOVAK:
This is Tom Novak.
I think the way I 4
3 5
would characterise it, I think our consultants believe that we l
6 are not convinced that the arguments the owners' group are i
7 proposing are necessarily convincing to resolve the problem.
4 8
COMMISSIONER ASSELSTINE:
The one that stuck out in j
9 my mind'were cracks in the block, for instance.
10 MR. NOVAK:
Right.
11 MR. DENTON:
We have to taken a position on that.
i l
12 All of our experts in this area are being deposed, today, and l
1 13 those that aren't are off on the road.
i I
l 14 COMMISSIONER A,SSELSTINE:
The only question I had l
1 l
15 about the inspection program, and let me say right up front 16 that as far as that part of the order was concerned, I think t
l you are right.
I don't have any major problem with that part j7 1:
i l-gg in terms of providing some enhanced assurance of reliability I
39 at low power and also the k'inds of things that we would be 20 looking for before any full power decision.
i l
21 The only question I had, though, was, by pushing
~
them to do the inspection right now, in essence, are you 22 j
1ockin,yourse1f in in ee=ms of the owners. group pro, ram,
,3 4
4 because there are some elements of the inspection that seem to i
j go towards, well, you inspect, if you find certain things, you i
25 2
i
)
t c
I
. -. -.. ~
l
^
19 i
i l
I have to repair them and, by implication, if you do that, 2
that's going to satisfy us.
j 3
To what extent do you think you are hemming yourself I
i I
4 in by ordering them to do an inspection along these lines, 5
now, in terms of your reviewability, your flexibility, along 6
with the advice of your consultants,,in reviewing th's owners'
[
7 view program and the results that are submitted by --
8 MR. DENTON:
It would be preferable to have the f
9 program clearly reviewed and resolved before you went to 1
10 individual plants.
I think the original owners' group program l
11 intended to do that.
But they fell behind schedule.
So what
]
12 we have got, now, are one or two utilities who are trying to l
13 get out in front of the total program and our protection in I
p that area is that review of the program is being done by the I
]
15 same people who are doing the review of the individual diesels.
1 16 So, we have not taken.a position on the adequacy of 37 the program but we are willing to review diesels which are 18 torn down, like Comanche Peak's is down and they are car $(ing 1
i 39 out the owners' group program.
COMMISSIONER ASSELSTINE:
Except they are doing -- I 20 21 gather they are doing much more.
At least, that's what I was f
j told when I was at Comanche Peak.
They said, "Well, you know, we are going beyond the owners' group.
Anytime there is any l
23 i
question at all, we're putting in new material.
We have 24 j
independent people redesign components and we are doing a lot i
25 j
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more than they are doing at other plants, but this one.
2 MR. DENTON:
So they are taking some risk that we 3
may not approve exactly what they find but they are doing it a
under their own and I think, here, we are trying to tre'at this J
j 5
plant as a specific plant, while still looking at the total 6
owners' grcup program.
l 7
MR. EISENHUT:
Also, we face this question with the l
8 consultants and I think'another bottom line was we think that 9
we will have a position on the overall program while the 10 diesel is torn down.
We have looked at the window of' time.
I 11 You have to remember this is the second time Grand Gulf has i
i 12 gone through a diesel inspection, also.
13 MR. DENTON:
We told the owners' group that within 1
e 14 thirty days or so after,their last report to us, we would have 3
15 a position on their program and they had a program in which l
l.
16 they were going to submit like, 16, separate reports and I
]
17 think at last count --
4 13 COMMISSIONER ASSELSTINE:
Only about half of those i
gg are in, aren't they, or something like that?
f 20 MR. DENTON:
They have been coming in here of late 1
21 but I think there may still be one or two outstand.
J.
CHAIRMAN PALLADINO:
Can I ask you a different 22 question.
While this inspection is going on, why did you feel tha't they could continue operation up
'.o i;.sa percent power?
24 f-MR. DENTON:
Because the analysis that is attached 25 j
1 i
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I to the order that we had looked at the types of accidents that h
2 present a risk at low power and looked at the need for elec-f 3
trical power during that period and came to the conclusion 4
{.
that you do not need to rely on diesels at these power levels.
1 1
5 COMISSIONER BERNTRAL:
I think it would be useful l
{
j
{
6 if you -- I know you have done this before, it seems to me, in 7
another meeting not so long ago, but it would be useful, for 8
me, at least, if you would go through and summarize -- and I t
S think the public needs to have a good summarf as well.
)
10 As I understand the way you have represented things 11 now, Harold, we would have one TDI generator that'is not torn i
12 down while this one is being torn down.
13 COMMISSIONER ASSELSTINE:
Of questionable relia--
14 bility.
a I
15 COMMISSIONER BERNTRAL:
Of questionable reliability.
16 We do have another diesel generator.
37 COMMISSIONER ROBERTS:
Of unknown reliability.
4 33 COMMISSIONER BERNTRAL: ~ Let's spare the editorials I
39 for a moment, here.
1 i
20 CHAIRMAN PALLADINO:
Well, no.
The editorial has i
2!
inserted and I think it should --
22 COMMISSIONER ASSEL3 TINE:
I will accept " unknown."
COMMISSIONER BERNTRAL:
Let me start over.- We have l
l 23 i
4 one diesel generator not torn down.
We have'another one of a j
3 i
different brand, if you wish, that is available and we have 1
t 25 l
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f i
4 i
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i s
. -. --..,.,,__,_,..,._.,_a_,.._;._.___.;__,._.._..__.____..__,__.',-.
22 I
some other onsite gas turbine power generators, and I would 2
like to hear how those fit into your overall calculations, if 3
at all.
I think it would be useful to give us a summary of 4
the kind of logic that you used to determine that the safety 5
hazard to the public is minimal.
6 MR. DENTON:
Let me.ask Mr. Hodges of the Reactor 7
Safety Branch to describe how we approach'that question and 8
how we answer it for ourselves.
9 MR. HODGES:
I am Wayne Hodges in the Reactor 10 Systems Branch.
There are several things to bear in mind.
li One is, at the low power level -- five percent power level --
12 the heat flux from the fuel is low enough that you don't worry
~
13 about possibilities like critical power ratio.
You are well 14 removed from a problem in that.
You don't worry about over-15 Pressurization transients because, again, the energy input 16 compared to relieving capabilities is very low.
So the normal 17 Chapter 15-type of transients that you would look at would 33 become 'irisignificant at five percent power level.
j9 So, now, you look at what are the real safety 20 e neerns and that is, if you had no TDI diesels available at 21 all, either one of them, and you lost all your offsite power, y u had no power at all, what could happen.
For Grand Gulf, 22 you can go through a transient.
You have isolation.
You can get int a situation where you are boiling the water level 24 down in the core and you say, "How long does it take to expose I
-- ~.~ - -.
e-o 23 I
the cere?"
Chvicusly, c e you scra= the reacter a:d the fuel.
1 is ecvered with water and ycu had ne prehless due to boiling 3
transitics or critical power ratic cr everpressurizatics during the initial part of the transient, the c=1y thing *2at 5
you really have ec worry about is the fuel heating up acd, as 6
1cag as it is ecvered with water, that wen't happen.
7 rcr Grand Gcif, it takes c= the crder of two er =cre days just to get down to the tcp cf the ccre with bcil off..
3 CCtetISSICNER 3E W AL:
what if ycu have a less of.
10 cociant -
11 MR. ECDGES:
I will get to that.
I'm as trf ng to i
12 go for the sc= ' m first, te ctver the full spectrum.
13 So ycu have c= the crder of two days te get dcwn n
just te the sep of the fuel.
Teu started no heat up.
ne water and the fuel are essential at saturated ccnditic=s at 16 this point - less than 600 degrees.. Sc to preblen.
37 Even beyc=d that point, ycu conid bcil well dcwn
~
gg isto the core regics befcre ycu started te get significa t 39 heat up.
So there is lots of time available to restere pcwer i
for the sc -less cf ecclast accident situatics.
[
.40
(
For the Icss of ecciant accident,,the ene that gets t
I to be a preblen is the large grade LCCA, just as.we talked abcut for Shereham a few weeks age.
Grand Gulf is a little
[
.3 1
differest frce Shcreham in that they have a high pressure cere spray system that is driven by a separate diesel.
It dees =ct
,5 6
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a 24 O
I rely upon steam power as the high pressure injection system V
2 does at Shoreham.
If that operates, then there is no question i
3 that you could sit there indefinitely or for a very long 4
period of time without restoring other sources of AC power.
5 If that fails to operate, then the kinds of numbers 6
we talked about at Shoreham, which says you have got on the 7
order of an hour to an hour-and-a-half, using evaluation-type 8
analysis, or three hours, if you use realistic analysis, in 9
order.to restore power if there is a problem.
So, from a 10 safety standpoint, there is lots of time available to get 11 alternate AC power sources going.
12 COMMISSIONER BERNTHAL:
Are these onsite gas tur-13 bines designed to be hooked into that core spray system, then, 14 assuming the dedicated diesel didn't work under those circum-v 15 stances.
4 16 MR. HODGES:
The answer is, yes.
37 CHAIRMAN PALLADINO:
Can we get an oral answer to 18 that, because the record won't show nodding heads.
MR. DENTON:
I think the onsite diesel would supply gg i
20 AC power and, therefore, would restore power to all the safety systems if they operate.
21 MR. HODGES:
Mr. Srinivasan from the Power Systems i
22 i
Branch tells me that it could, plus they can also be hooked 23 into the other core spray system and the low pressure coolant injection systems, all of the other ECC systems that are-l J
I i
I j
i
......,x.
25 I
there.
2 COMMISSIONER BERNTHAL:
These are these extra gas 1
3 turbines that they brought in onsite?
k MR. HODGES:
Yes.
l 5
MR. DENTON:
Let me ask Mr. Srinivasan, Chief of the 6
Power Branch, if he would like to elaborate.
l 7
MR. SRINIVASAN:
Srinivasan, from the Power Systems l
8 Branch.
Grand Gulf has three onsite gas turbine generators.
9 They operate in parallel.
They could provide power to any one i
10 of the class 1-e buses.
There is a flexibility, the way they 11 are arranged.
So, in the event you lose any one of the I
12 qualified onsite power supplies, these gas turbines could 13 supply power.
j 14 It has to be started manually.
It doesn't start 15 automatically.
It takes about -- the analysis indicated it t
16 would take about 25 minutes or so to establish power to the 4
37 buses.
We have a particular specification laid on these gas 18 turbines to be tested periodically the same way we.would' test i
39 the TDI diese1s -- once in every 31 days.
20 CHAIRMAN PALLADINO:
Other points?
COMMISSIONER ASSELSTINE:
I had one other question
- y gy n the analysis that was done.
There is Mr. Hodges, there.
22
. hen 1.as 1ooxing through th. ana1ysis, it seemed to he in l>
24 two parts.
The first part was an ana1ysis of LaSalle, which l*
l's, as I understand it, a BWR/5 Mark II and you said, in your 1
i
26 O
1 analysis, and I quote, "It is very important to recognize that 2
this report is based on some very rough estimates.
A detailed 3
review of each event tree was not possible in the time allot-4 ted.
Also, computer analyses of'the important events (hTWS 5
and LocA) were not possible.
Therefore only estimates and 6
inferences from previous work were used.
For these reasons, 7
the risk reduction numbers have larger uncertainties than they 8
otherwise might."
9 Now, as I understand what you have done, you have 10 taken that rough analysis for LaSalle.
You have looked at it 11 in terms of Grand Gulf, which is a different plant -- there is 12 not another one in this country -- and, third, you have, in 13 essence, a new licensee and a licensee who has not, so far, p
demonstrated a high degr,ee of performance.
O 15 I guess my question is, to what extent do those 16 three levels add significant uncertainties to the analysis 37 that you have done.
18 MR. DENTCN Let me give you my perception and then i
gg ask Wayne to elaborate.
We have not approached this on the basis of risk reduction.
I have quoted numbers to the Commis-20 si n, n many ceasions, as to what the relative risk is and 21 there is a lot of uncertainty when you get to PRA and risk, 3
but the kinds of numbers and details that you have heard, 23 g
today, are deterministic calculations of how long it takes water to boil off and how long you can go before various O
l
27 I
things would occur.
They are not PRA estimates.
Wayne, maybe 2
you would like to elaborate.
3 MR. HODGES:
Well, we have done two different types 4
of analyses.
The memorandum that is attached to the order --
5 that's the one you are reading from?
6 COMMISSIONER ASSE,~.STINE:
Yes.
7 MR. HODGES:
We have done an additional analysis, 8
since that time, that looked at the deterministic approach,.
3 and that is what I've talked about tcday.
So we have got two 10 separate analyses.
One that says the prob' ability you are 11 going to have this situation is very low and then, the risk or 12 the consequences, once you.get there, are very minimal.
So 13 that combines the low number.
And then I've talked a little 14 bit this morning about the deterministic analysis that you 15 could use to show, yes, indeed, the consequences are low.
16 MR. DENTON:
I thought the question, this morning, g7 would be, why didn't we suspend the license in view of the gg Commission's action on Shoreham.
CHAIRMAN PALLADINO:
Suspend the license?
gg MR. DENTON:
Yes, in view of your decision on 20 Shoreham and after consulting with OELD and others, and the 21 fact that we had a view about the adequate safety of opera-22 tion, and the fact that the Commission's practico and de-cisions over the years have not required automatic suspension g
when you find a GDC is not but rather look to see what the V) a S-m m
m
I.
28 1
safe limitations are, that's why I decided that I could let 2
them continue to operate, require that they request an examp-3 tion to square with your decision, and, at the same time, 4
order this examination in order to put this issue to be'd, 5
because I think the licensee was trying to defer consideration 6
of an inspection and then try to push through a full power 7
license without this issue being adequately addressed.
g COMMISSIONER ASSELSTINE:
I gusss I would agree with you up to one point, Harold, and that is the question of.'
9 relaxing the tech spec -- the LCO.
I don't see anything 10 improper with issuing them an order saying you have to do this g,
inspe tion program.
But it seems to me, then, the burden is 12 on the licensee to come back, if it wants a relaxation of the
,3 toch spec limitation, and submit a license amendment, and the g
v burden is on them to justify approving that -- provide the 15 justification for approving that relaxation of the tech spec 16 limit.
17 It is not a question of issuing an immediately' effective show cause order to revoke or suspend the license.
19 I think it is a question of whether the licensee can provide 20 the justification for showing that he ought to be able to 21
~
operate the plant with cnly one diesel generator of unknown 22 reliability as opposed to the tech spec requirements for 23 having at least two diesel generatorn available.
24 Mh. DENTON:
I think, by requiring ccmpensatory 25 bd 4
l.
j l
1
-cl t
ew I
i t
I I
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e
'l e l
s 1
N t
l 1
1e'
- .sastres f:r ce eder sti Ts, 12: we have
- 01arged :le i
l b
l 1
level Of safety.
!= c cer v::ds, I have s:ts:1 ::ei ::e 1
1 I
3 die:ei heing cc: f::.tese c:xpensatery seasvres :: tie citer 4
thim;s.
5: it is
- , ville ve have rein ed -- ! -M -k, if 5
y:= 1:ck as the.ticarse as a pachage, safety is a-least eere
(
6
- , ins bef::e.
I will ask Cr:0 ::
- mment.
r l
j i
y MP.. Cn N*MZAM:
- : darstand the a 7.. 4 : 7 are s
j i
s
=Aki:5 that, viile 1: vas appre; iate pcssely, 's 7::: viev, I
i I
f:: :s := crder :le inspec 10:, the b : des st: *.d be :: the l
l I
g" (
licensee :: ask f:: reinatie: Of le te:1 spec.
30: le var l
l 1,, l we a;;::ae.d is was we c:21d=': crder et usre::1 =, v-i e r.
d venid fly is le face Of le sect a;e=, witt::: sir:1usects17i l e.
i 1
t tid:essic; the te:t sye: gesti::.
We saw is all as pt:: ef i
(v)
Ia l!
the same package.
i g-s
, g" cc m:ss::x n Asst:.s :stt : :a
- dersued ee
- tli
- heal
- 1, safety, and i: eres: is repirisy the immediate 16 4
e I,, ; [
iss;+::i::.
I 7:ess des' see, anyvtere is 70s: ;ack25e, i
e i
e
' is, l
- e analysis cf vaa view as a separate gestic:.
tat l.a i.
L the reinatic: ef the sed s;e: limit.
1: fact, V..a i:
I,a 4
appears :: =e is lis is a way
- get at:::2 :le regire===:
i
.e e.
3
- reviev 11: esse asend===:s fr:: As a;;iier :.
i i
11 L
i I
M?.. CO3:M IAM:
Well, yet asked a gesti:
at ite ee begin.ing Of the secti ? as :: v:y ve didn't req; ire the
\\
43 r
l applicant :: sch=it a reg est f:: as a==edsent.
ne ansver, l
e l
l think, is clear f :n vta: Ear:Id said tais =c:.ing.
ney i
l e
V) 1 j
F 1
i l
30 (A) 1 disagreed with us on the need for this approach.
v 2
If we had just said, "Give us en amendment asking 3
- for relaxation and permission to'do an inspection," they would l
4 have said, "We don't want that amendment."
5 COMMISSIONER ASSELSTINE:
Well, but you coulo have 6
ordered the inspection and simply be silent on the tech specs,
(
7 and then the burden is on the applicant, if it wants to g
continue operation, to come in and say, "Well, all right, you 3
have ordered us to do the inspection,.
Here is our justifica-ti n f r why we should be allowed to operate this plant in 10 violation of the current tech specs for the plant."
y, MR. CUNNINGHAM:
I think you are right.
It could have been done that way.
I think it would have been incumbent 13 m
[O
)
upon us, at a minimum, f,or us to address the question of whether or not they have to shut down.
15 To simply order an inspection when ws knew that they 16 couldn't do that without shutting down, I think we would have l
to say, either shut down or tell us why you are not goincj to I
18*
shut down.
19 We chose, instead, to put it as a package to do the 20 inspection that we wanted done and authorize the relaxations 21 with compensating measures, as Harold has described, which we
.2 l
thought were appropriate.
l 23 To put it another way, our think our view of the l
24 l
public interest here, underlying this order, was that the l
25 h
l G 1
c 31 1.
l-j 1
public interest is not served by ordering the shutdown of a l
2 reactor when your own analysis shows there is no safety reason 3
to do that.- -
4 MR. EISENHUT:
And we didn't want to rely on our 5
analysis too long and that's why we asked the utility to come l,-
6 in and address -- submit an exemption request, provide a 7
justification for staying at five percent power, safety bases, g
and address the other aspects of the Commission's Shoreham.
order.
We asked him how soon he could do that and he said in j
9 I
about seven days.
So we looked at it as our bases we were riding on was not a -- I r.ean, it is going to be documented in y;
I more thorough detail from the licensee, put the burden on the 12 licensee in sort neder.
13 MR. DENTON:
I,think rather than argue,'all we can do is describe what we did and our rationale for it and, if 15 that's not the objective the Commi sion desires, now is the 16 l
time to let us know and we will remedy it.
COMMISSIONER ASSELSTINE:
As I understand it, you had basically told the licensee that they weren't to restart 19 for a period of time, right?
20 MR. DENTON:
(Nodding.)
21 COMMISSIONER ASSELSTINE:
Was that based only on the 22 tech spec problem?
Was it based on the combination of the 23 tech spec problem and the diesel problems and how was that 24 handled?
Was that just'an oral agreement by the licensee that 25 t
w/
4.
e-y, e s - e e+
s e~ - a..
.._._ _ _ ~ _.
o.
l
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l I
they wouldn't operate or was it a direction from you or what 2
was that?
3 MR.- DENTON :
We didn't have a formal hold on them.
g I think I mentioned that to the Commission at the time.' In my l
5 view, I didn't went them to resume operation until I at least 6
knew that the tech specs that applied to low power were the 7
correct set and so I deliberately resisted their efforts to 8
get us to approve restart until I had, from my own staff, an analysis of all the potential problems in the tech specs.
9 l
Which ones should we have in place more restrictive at low g
power and that's why, as I montioned earlier, it was only g
after our issuing this April 19 order that immediately modi-fled the tech specs and made it more restrictive did we permit
/
the licensee to resume low power operation.
'~
. (/
14 CHAIRMAN PALLADINO:
Let me rephrase some of these 15 same questions'a little differently.
Why should not the plant 16 l'
remain shut down until the exemption is received and acted 17 l
upon?
l 18 l
MR. DENTON:
Only because your own orders and l
19 l
policies for 20 years have said that it is not required unless 20 it has a public safety implication.
21 CHAIRMAN PALLADINO:
But you directed them to 22 commence with their exemption request.
l 23 MR. DENTON:
Yes.
24 CHAIRMAN PALLADINO:
And I am not sure I capture all 25
,O, 1%J
l as l
i 33 l
1 the implications of that.
2 MR. DENTON:
Because, in the Shoreham decision, you 3
said that exemptions were required.
We have required that g
they come in here -- I don't want to appear argumentative, Mr.
5 Chairman, all I can say is that is my rationale and if, in the 6
Shoreham order, you intended us to suspend the license, I 4
didn't read that in Shoreham.
7 8
But y u can g back and I have, here, a commission decision of 1978 which says the Commission agrees with the 9
staff that a violation of a regulation does not, in and of g
itself, result in a requirement that a license be suspended.
g It gces on to say that, if health and safety is threatened as a result of the violation, proper remedial r.ction must be 13 taken.
l Well, here, public health and safety is not 15 l
threatened, in the staff's eyes, by this violation, and that I
16 was the rationale.
I 17 CHAIRMAN PALLADINO:
The reason I asked the question 18 is I believe there is a difference between an operating plant 19 and one which has not yet received a license.
l MR. DIRCKS:
But this has received a license.
21 l
CHAIRMAN PALLADINO:
I say there is a difference 22 l
between an operating plant, one that has a liconne,.from a i
23 plant that doesn't have a license yet, so far as your proca-24 dural options are concerned.
25 1
V
o e
s 34 1
MR. CUNNINGHAM:
In fact, I think it is important to
\\
2 Point out that it is at least questionable whether we could 3-have made a finding"that the public health, safety, 'or in -
g terest requires an insnediate shutdown.
Once they have the 5
liC'"**'
the Presumption is they are entitled to operate it.
6 our analysis shows there was no safety problem with continuing to operate here, so it would have been hard to 7
g justify a shutdown order.
CHAIRMAN PALLADINO:
Let me ask you, is there a new 9
Proposal on the part of any Comunissioner to do something or to just --
g COMMISSIONER ASSELSTINE:
I had a couple of more questions, first.
Let me ask a couple more first.
The accident assumptions that were made'in the analysis, did those take into account the kinds of different 15 valve line-ups and things that might exist either at low power 16 levels or in hot shutdown conditions for the plant and what 17 the impact of loss of offsite power would be in terms of
- changing valve line-ups and positions?
Is that something that 19 you'all looked at?
20 I guess what I am wondering is, is the loss of 21 offsite power and the loss of onsite power the kind of acci-22 dent situation that the staff has really looked at in great 23 detail.
For example, how would you compare it to the kinds of 24 analyses that you did on the pipe crack issues where it 25
4 l
[
l 35 l (A l
appeared to me you were talking about the kinds of accident 2
situations that have been much more the routine kinds analyzed l --
3
-in our safety-evaluations.-
4 MR. HODGES:
Well, we looked at each Chapter 15 5
transient accident and tried to say, with no Ac power avail-6 able, is there a problem.
As far as valve line-upo -- the 7
major thing concerned here, when you are starting from a five 8
percent power case is you don't have the turbine on line, you 9
may not have the feedwater system running.
You may be using, 10 f r example, a control rod drive system in order to provide gg the make-up rather than the feudwater system.
Or, if you have 12 g t the feedwater system on, it is just operating at a very low capacity and you dcn't have feedwater heating.
y/
14 Those types of, considerations were put fn there but, as far as emergency equipment, we_didn't consider any changes.
What we are saying is, for those lo'ng periods of times, you 16 don't even need it.
17 MR. DENTON:
I think we are assuming that the p'lant was operating within the limiting conditions of a low power 19 license.
20 MR. HODGES:
Yes.
21 MR. DENTON:
That's where we started from.
Basical-22 ly, we don't see, as we have discussed before, that low power 23 has the same kinds of risk for this accident for not having 24 diesels because you have very few fission products generated, 25 l V o
t 34 1
the fission products tend to still be in the uranium oxide I
pellet matrix, they have not migrated to the space between the 3
--pellet--and--eladding, there is-less potential to get out.
so 4
it's all those kinds of arguments that just lead us in* general 5
"h*" "h*Y *** * '**Y l'" *i'" "
h*'1" "i"h ^^d' *" if Y'"
6 go and begin to heat up the fuel, the amount of fission products that are actually available for release are nowhere 7
g like they are at high power.
COMMISSIONER BERNTNAL:
Jim, if I could just pick up 9
on your question, though, maybe I am not understanding but, when we spoke earlier of the large great loss-of-coolant scenario, I assumed that we were covering the worst case scenario.
Are you suggesting that there is another case scenario that could be worse or -- I mean, I can't see, from my limited perspective, what is y rse than essentially than 15 immediately losing water on the core and then you are in a 16 situation where you have got sone 4here between one and three 17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br /> --
18 COMMISSIONER ASSELSTINE:
I guess what I as talking 15 about is that situation and what I am wondering is, do we 20 really have a good understanding of how the operator's ability 21 to deal with that situation is affected by what would happen 12 to instrumentation and equipment in the plant if you lose all 23 your power.
I mean 21s valves and switches and instruments are going to do different 25 1
....... ~.
u
37 (Ov)
I things, I think, if you lose all your power than would nor-2 mally be the case in that accident situation.
.....3 What-I-am trying to understand 'is to what extent do
.. ~.
4 we really understand that complicating factor.
If you lose 5
all the power, what happens to your instruments in the control 6
room when the power comes right back on or if you get power back on.
What kinds of changes occur and what does that do to 7
l g
the operator's ability to deal with the worse case kind of,
accident.
9 MR. DENTON:
I think pushed to the extreme, we are g
in the severe accident space but to start with the idea it is g
unlikely to lose offsite power because of conditions we put on
-- you have got gas turbines that supply the equipment and then you've got at least,one diesel there that maf or may not l
work but, once you degrade down to_ that, let me ask Wayne to 15 see of he could, or Srinivasan who 'might like to answer it, 16 l
how we approach that, but that's a problem in all plants, 17 l
including ones that we are letting operate at full power
- 1 18 l
today, if they suddenly lose offsite power and lose onsite 19 I
power.
We worry with that problem as a USI for plants at full to power.
l 21 s
l MR. !!ODGES:
Mr. Srinivasan will talk about the 22 l
power, to some extent, but mostly the instrumentation is 23 coming of f of batteries -- the vital instrumentations.
24 MR. SRINIVASAN:
When you lose all AC power, both 25 O)
L l
6
r l
l
~
l 38 l
offsite and onsite, you are getting into an event that is V
2 l
beyond the design basis normally analyzed by the staff.
The 3
very point of it is a safety issue, station blackout, USI-44.
4 With regard to the availability of critical instru-5 ments in the plant, when you lose all AC power, the instrvment buses will be autematically fed from the station batteries, 7
the Class 1-E batteries.
So, normally you will have a random I
chain of information in the plant ccming from different I
batteries.
So, even if you have a single failure on top of 10 all the failures you had in the plant, you allow one set of II critical instruments available to know where the plant is and 12
,'certain critical components, like aux feedwater system, I3 usually mean one chain of the system is made AC independent, Ik so you allow CC power av,ailable for them, like turbines to run l,
15 the FW system.
\\.
16
.What we have done now, in the current licensing 17 review, is to make sure there are adequate procedures in the 18 plant to, cope with this station blackout event, even though 19 such an event is going to be low probability event for the 20 majority of the plants.
21 CCMMISSIONER ASSELSTINE:
Let me ask you two other 22 questions.
Ifew reliable is the offsite pcwer supply at Grand 2)
Culf as ccmpared to other plants -- about in the middle, very 21, reliable grid, less reliable?
25 MR. SRINIVASANs I would say it is an above average J
39
,~
g
(
)
plan *.
CEA 7?Ri 7 A*.:X::50:
- as vna 7 3
MR. S RIN :*.*AS AN :
Atcve average.
As we stated k
tef :c, =cs: Of the 1:ss Of ef fsite pcver is n:
he:ause cf 5
the grid disturbsn=e but it is plant center in the switch yard i
7 00x:t:53:0$ER ASSE.S!!NE:
70 vnat extent is taa 3
dependent, then, upen the capability ar.d experience and i
e' perfer=4nce cf the utility and its perscanel?
IO MI. $ 7. N *.*AS AN :
In this situati:n,' : vant t: bria; II
- a unique design ve have seen, the Gra..d G;1f destin.
In a )
l *'
l very ::aditi:nal electrical systes des 17n, al' ine house I3 1: ads, including the safety syste: *: ads, are ner ally fed j
(
4 I"
ft:= the rain generat::,th : ugh tae aux transf:rner.
l 15
- 3. c;3:4 ca;g g. 193, 3 7 3,y..:t=::,: 3 3,:
{
1 l
16 and they take tae pcver directly fr:: the effsite.
So, shecid I7 ve have a transient in tae plant which results in the turtine II
- 1p and,qenerater trip cut, you vuuld still naintain a 19 c:ntinueus s urce of ;-cver :: the critical c:=penents ::
23 safety set en the plant.
That's the One plus f:: tais design.
21 Dc ki..7 at tae :perati:nal experience Of the MP&L l
t t
12 grid, we d:n't believe ve have any biy p :h'e= to:ause the
- )
calculated risk is ateve average.
- 4 COMM:SSIONIR A35tLd7:NI:
T:: the extra diesel, is that in anyvay c:nnected er dependent upcn systens that are i
\\
l
'/._
f
.t i
40 I
related to the TDI diesels?
2 MR. SRINIVASAN:
No.
3
-- COMMISSIONER-ASSELSTINE:
Totally independent?
4 MR. SRINIVASAN:
They are totally independent
- They 5
have their own betteries and they have their own offsite power 6
line coming in.
7 CHAIRMAN PALLADINO:
What is the size or the capa-g city of that extra diesel -- the non-TDI diesel?
MR. SRINIVASAN:
The non-TDI -- of the gas turbines?
9 COMMISSIONER ASSELSTINE:
The non-TDI normal diesel.
gg CHAIRMAN PALLADINO:
The non-TDI diesel.
g MR. SRINIVASAN:
Generally., it's about 3,000 kilo-12 watts, but I'm not sure what the range is on this plant.
g MR. DENTON:
N,e said he thought it was alout 3,000 g
kilowatts.
We have a representative in the audience from Mississippi Power and Light, if you would like to ask them that question.
I don't think we know the precise answer to that.
18 CHAIRMAN PALLADINO:
Maybe I will come back to the question.
To handle accident compensatory equipment or 20 accident mitigating equipment, what sort of power level do you need?
22 MR. SRINIVASAN:
For a non-LOCA transient-initiated 23 shutdown, it is about 4,000 kilowatts we need.
24 CHAIRMAN PALLADINO:
How much'-- 4 --
25 i
-w
s 41
~
O MR. SRINIVASAN:
Four thousand.
And, if it's a LOCA 2
situation, it's slightly about 4,700 kilowatts.
3
GAIRMAN-PALLADINO:--How much?-
4 MR. SRINIVASAN:
Forty-seven hundred -- four-seven-
~
5 6
CHAIRMAN PALLADINO:
Ccu.i.d we ask the Mississippi 7
Power and Light representative if he knows what the capacity g
of the non-TDI, diesel is?
MR. WHITE:
If you are talking to me, I am the vice g
president of Public Affairs and lobbyist.
I don't think I am
~
qualified --
(Laughter.)
MR. WHITE: -- to answer that question right u w, but 13 I will find out for you.,
COMMISSIONER BERNTHAL:
15
-Sounds like,a wise move.
CHAIRMAN PALLADINO:
I didn't mean to put you on the spot.
I was just asking.
Do you have more?
(No response.)
18 CHAIRMAN PALLADINO:
Is there any proposal by any 19 member of the Commission?
20 COMMISSIONER BERNTHAL:
Let me ask a question or two 21 here before we get to proposals, if I may, Mr. Chairman.
22 Again, by way of clarifying things, not only for the Commis-23 sion here, but for the record, I would like to have an opinion
~
from the Counsel's office and perhaps from you, Guy, as well, 25 OV
..o s
1 42 s
y on what we are really talking about, here, in terms of our 2
regulations.
... -..--In other words, *-you are coming before us and we can 4
sit here and try and make a best engineering judgment or 5
instinctive judgment, even for those of us who aren't engi-6 r.eers, on adequacy of protection of public health and safety, 7
but what kind of finding are we required to make or expected to make'in this circumstance that would justify the staff g
action consistent with our regulations?
Is there~a pitfall here that I am not aware of or where are we?
10 In other words, what are we required to find in these circumstances in order to justify or not justify the staff actions.
13 MR. CUNNINGHAM:
The Commission doesn't'have to make 14 any finding at all, now, unless it chooses to, review the 15 action of Harold Denton.
He made the required finding which 16 is that the public health, safety, or interest requires that 17 the order he issu'ed be immediately effective.
18
~
In this case, I think'it was primarily public 19 interest, although the order does point out that it is in the 20 j
interest of public health and safety, as well, to get an l
21 s
earlier rather than a later resolution of the adequacy of the 22
{
TDI diesels.
23 COMMISSIONER BERNTEAL:
Let me phrase the question 24 another way.
So is the relevant point, here, that having 25
,,4, ao.,
e
+
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- * ' * * ~ ' * * * *
.t*
9 1
t 43 l
I heard what has been said about the margin of protection for
]
2 public health and safety and, presumably, attaching some
--- - - 3 sign-ificence to-whether you buy the one-hour scenario for-the 4
worst case or the three hours for the worst realistic case, 5
that that's the key judgment that is at stake here?
Is that l
6 the key judgment the staff makes or what is the key judgment, if I am missing the point, here?
7 MR. DENTON:
Basically, we were at an impasse with g
g the licensee'over what was required to qualif,y or requalify the diesels and we gave him a view, he gave us a view, we couldn't resolve it, and we made a decision that it was required.
COMMISSIONER BERNTHAL:
I understand.
But the I
13 j
standard somehow ultimately has to be the protectfon of public 14 health and safety and we focused, for some length of time 15 here, on that particular issue, and the question is, I guess, 16 the adequacy of the standard and the information that we have 17 18 Is that the thing that we need to foc'us heard here, today.
i on.
19 MR. CUNNINGHAM:
Well, it depends on a standard for i
20 what.
If you are looking at the standard for whether the 21 action should be required, that is probably public health and 22 safety.
If you are looking at whether it is immediately l
23 required, which is the way the order was drafted, then the 24 statute says public health, safety, or interest, and Harold's 25
-r--
m,
--e
--,m.
44
)
1 order is a combination of the public interest, as he saw it, 2
in not shutting down a reactor where there was no public'
- 3
- - health--or-safety need--tcrdo so in order to get something 4
accomplished which he did feel was necessary.
5 That is why there was a public health and safety 6
benefit in getting that done earlier rather than later.
COMMISSIONER BERNTHAL:
Maybe I need to turn the 7
g question around.
I am still feeling a bit ill at ease, here.
Is there any judgment on the part of counsel, here, or perhaps g
the only member of the Commission with legal training that, in 10 some sense, we are violating our regulations by this action?
MR. CUNNINGHAM:
If you are asking me, we supported the issuance of the order.
We gave legal counsel on the 13
(
drafting of the order.
COMMISSIONER BERNTHAL: _ All right,.you don't have to 15 comment.
16 COMMISSIONER ROBERTS:
Let me give you a short 17 answer. - This is a "non-event," this whole meeting.
~
18 COMMISSIONER BERNTHAL:
You may very well be right 19 but sometimes I worry about what is a p,ractical non-event 20 l
turning into a legal event.
I guess that's the bottom line of 21 my concern.
22 MR. PLAINE:
Well, this thing came up suddenly.
I 23 hadn't even seen the order.
Offhand, it sounds to me like 24 Guy's analysis appears in orier but, if you want us to study 25
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1 MR. DENTON:
That's correct.
It is also a require-2 ment that you have to have other things that were not in the i
3
-prev ous-1-icense.
4 MR. EISENHUT:
I wouldn't agree that by taking the 5
ne tech spec and relaxing it -- you have got to look at the 6
whole set of tech specs for emergency power and you can take out one diesel requirement'but, in lieu of that, we also put 7
i" **T"irements for the gas turbine.
8 Now, I think it probab*.y came out about equal.
In g
. fact, there is a condition for external events and so while it
-is certainly true, if you look at whatever 4.8.111 -- whatever
^
is the'right number -- it clearly is a relaxation of that particular one, but there others that trade off.
13
/
)
MR. DENTON:
We could have done' it the Gay Guy said.
We could have issued an order to inspect and then they would 15 have been back,~ beating on our door, saying, "How can we 16 inspect? 'You've got your own license.that says you have got 17 to have two' diesels operable."
18
~
And then they would have'come 19
. in through the process.
Since we were already at an impasse over that and I 20 didn't'want that argument to be an excuse as to why they 21
~
didn't carry out the inspection, I decided to deal with the 22 whole issue as a package.
-23 COMMISSIONER ASSELSTINE:
At the May 18 meeting, did 24 the licensee express any views on the order?
Did they l
25
,e se ma wh epe e '-
- M"
- '*%'**9
- "'**M*-
I I '
- WI Y
-_y., -
-C..-.
,.w 47
)
1 indicate whether they wanted the order, they supported the 2
order?
...... _.-mrv-EISENHUT:--I-think, all the way up to the 4
conclusion of the meeting, the utility was still argue his 5
p sition and that.was they think the diesels were reliable for 6
the first refueling cycle, they felt that they could ascend to power, the could operate all the way to 100 percent and 7
8 Perform the diesel inspection at the first refueling outage.
They felt they had done the inspection before.
It g
was an adequate inspection.
They knew, from meetings with our consultants and their consultants, it was a very close call.
They even had an alternate proposal and that alternate pro-posal was that if we conclude as we did on the diesel, then
+
13 they want to perform die,sel inspection during start-up of the 14 plant.
They felt it we.s adequately safe.
15 I think it was more, aft'er a staff causus with all 16 of the appropriate stuif, where we came down was just one way 17 to resolve this was just to say that, from this day forth, we don't have enough confidence in the diesels.
19
. It hasn't been demonstrated to us.
So I think, to this day, they really 20 believe they have adequate, reliable diesels.
21 s
MR. DIRCKS:
What is confusing is I think, when we 22 l
talked about this, I thought the staff was acting in a very 23 stern, regulatory mode, there.
We were tired of arguing and 24 an order was issued.
Now, the order said, stop arguing about 25
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-e eep* -- w w a+f N.WM9F N W "
' W W N* W ""
6
' 'TW*N
a <. ~ a 4
48 1
s this.
Tear down the diesels, inspect them, and get them in 1
shap5.
I think, at the same time, the staff didn't go to the 3
extent of ordering to completely shut down the plant.
4 It is a strange position to be in, today, because 5
here we thought,.if anything, we were acting in a very strin-O gent and stern regulatory mode and all of a sudden, now, we 7
are getting the feeling that we are being relatively soft on 8
the utility.
3 COMMISSIONER ASSELSTINE:
Sinc'e I am the only one 10 who has expressed any disagreement with what you have done, II let me say that, as far as all other aspects of the order and 12
,'ths action, I don't have any problem with it.
I agree with 13
'you.
I think in terms of ordering the inspection right away, 14 I would agree with your characterization.
15 I still have the concern about whether you are 16 boxing yourself in having now ordered the licensee to do this 17 inspectio'n.
If they do this inspection, I question how much 18 flexibility you are then going to have to say, " Wait a minute.
13 That really isn't good enough and now we want something more 20 than that down the road.
But, apart from that concern, I 21 don't have any problem.
22 MR. DIRCKS:
We have already been accused of that.
23 In this particular case, I think the diesels have been torn j
24 down before.
There was a good deal of argument that we were 25 being arbitrary in this matter.
We were just demanding too bG
.. - ~
-- --~~ ~ w~~
~-
. ~.
.. *, C e
49
] f, much since they had already torn them down once and here we 2
were asking them to tear them down again.
3 i
COMMISSIONER BERNTHAL:
I must say that it should be 4
pointed out that tearing down these diesels -- and I was down 5
there; as we all.have, I guess, and looked at these things and j
that's not without its own hazard.
There is a certain built 7
in risk every time you tear apart a piece like that.
0 MR. DIRCKS:
But to answer your point, I don't think
)
we have ever been bound by that boundary where we have asked 3
10 for something and they do it and we say that we are still not 11 satisfied.
In fact, the complaint that you probably here is 12 that we do it'too often.
We demand things, and they do 13 things, and then we'ask them to do them all over again.
I 14 don't think that precedent --
15 COMMISSIONER BERNTHAL:
Is the suggestion that the 16 better path would have been, Jim, for them to do nothing until 17 the task force completed its work or what are you suggesting?
18 COMMISSIONER ASSELSTINE:
No.
I think what the 19 staff did was the right thing-in terms of ordering the in-20 spection.
All I'm doing is saying we are, to a certain i
21 extent, vulnerable then to'the argument later on that, in 22 essence, you have bought off on it.
But as long as it is 23 clear from the staff's side that they have not bought off on 24 the owners' group program, that that is still open until the 25 detailed submissions are made and the staff reaches its final
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50 judgment, then I think the better course was to do just what 2
the b.taff did.
The only area where I have a reservation is on the question of continued operation of the plant and the manner in 5
which that was accomplished, in this case, by issuing an order that had.the effect.of at least relaxing that one portion of-7 the technical specifications rather than requiring that the 8
licensee submit its justification for allowing continued l
I
, operation of the plant by modifying the conditions of the 4
i 10 license.
II COMMISSIONER BERNTHAL:
But you don't have a problem 12 with the issue of adequacy of protection of public health and 13 safety given the presentations that have been made here, 14 today?
15 COMMISSICNER ASSELSTINE:
I still have some ques-16 tions about the adequacy of the staff's review, quite frankly.
17 It does seem to me that maybe it's more than the back of the 18 envelope evaluation, but~I do have some questions about how i.
I'9 thorough and detailed an evaluation really has been done, and 20 I've got some questions about allowing operation of a plant 21 with only one diesel generator of unknown reliability as 22 opposed to two.
23 CHAIRMAN PALLADINO:
Plus another one.
24 COMMISSIONER ASSELSTINE:
Plus this extra --
25 CHAIR E PALLADINO:
But it was pointed out that s
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that diesel alone, with the core spray, can handle the acci-2 dents.
So we are not pulling, apparently, on the one of 3
unknown quality.
COMMISSIONER BERNTHAL:
I will be quiet, now, but I just want to say.it seems like the question of public health 0
and safety is a'dequately addressed.
Whatever questions might 4
7 remain, it seems to me the worst case scenario, here, I O
believe we've heard, we've hearci before, and that seems to be 3
covered and I agree with staff's judgment on that, j
10 I am still a little concerned about what I always II try to keep as a separate issue and not hearing many protes-12
, tations from our legal people around here, I guess I will
" rust their judgment, at this point, that we are not somehow i
13 t
14 getting ourselves into another legal morass, and I am open to 15 suggestions on how we should proceed.
16 COMMISSIONER ROBERTS:
I've got a suggestion.
Let's 17 adjourn.
18 (Laughter.)
- L 19 CHAIRMAN PALLADINO
We are going to try to'do that i
20 in about five minutes.
I 21 COMMISSIONER ROBERTS:
What are we going to accom-22 plish?
23 CHAIRMAN PALLADINO:
I had -- now, let's be frank.
24 One of the problems I had was-I wanted to discuss with the 25 staff what was going on.
The legal advice I.got was that,
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1 since they were relating it c Shore"-2, I was Scing to get 1
into sc=e trcuble.
- he c=ly way I krev to get dis aired was 3
to have a public seeting and hear what the staff has := say.
4 I think it has been very valuable and I suggest, if scuebody wants to take ac ics, they prcycse it.
6 Ncw, I did have a telephc=e call frc= Cc=nissicher 7
Gilinsky who couldn't he here.
His feeling was that we shculd S
shut it dev: and =ct let it start up until de Cc=xissics has 4
a acted.
If any one of the C
- ssicners here entertains such a-10 thcught, prepose a =ctics, and then we vill vote c it.
If II there are other theuc. hts the Cc- 'ssics has dat thev. veuld 4
p-
. like te prepose, we vill hear the=, a.d we vill vete c the=.
13 New, so far, I haven't heard any suggestic that we a
5.
take any ac-ic: and, lacking such, I veuld prepose we =ct take d
15 any actics.
We veuld let c e staff e.c fc:vard.
t 16 CI.wJCSSICNIR ASS ~ SI'INI:
I'll prepcse an actics and 17 then we ca rchably add > curs fairiv. c.uickly.
Sefere I say e
18 that, thengh, let se say, Jce, I certainly agree with ycu.
I IS think this was a useful =eeting.
I disk it was i=por ant 20 that the Cc=missic: had this =eeting.
' t is a significant 21
=atter, there is =ct questics abcut it, and I disk it was 22 useful te de dis and I think it was a necessary step.
23 My prepcsal is very simp'le.
I wculd prepose that we 24 reveke that porties of the staff's order that c:.~'ers the tech 25 spec acdificatiens '-- -we plant.
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CHAIRMAN PALLADINO:
All right.
And your rationale?
2 e
COMMISSIONER ASSELSTINE:
My rationale is that I 3
don't think that's the way that the modifications to the 4
license should have been handled.
I think the burden should
)
5 be on the licensee to come forward with its rationale for why the plant should be allowed to operate while this inspection 7
program is being done with less than the full compliment of 0
diesels that is required by the tech specs, now.
~
3 I think, by requiring a license amendment to do 1
10 that, we would assure that we would get the kind of full and 11 careful analysis of the question that I think needs to be 12
, made, and I think that's the way that license. amendments of 13 that type should be handled under our regulations.
That is
)
14 basically it.
3 1
15 CHAIRMAN PALLADINO:
You are implying, though, that 16 the method that was used was wrong?
17 COMMISSIONER ASSELSTINE:
That's right.
- But,
+
i 18 whether it is wrong or not, I still think that that's a 19 preferable way to go.
'1 1
20 CHAIRMAN PALLADINO:
Do you want to speak to that?
21 (No response.)
22 CHAIRMAN PALLADINO:
Can you tell us what happens if 23 that action is taken -- either you or the staff?
24 COMMISSIONER ASSELSTINE:
I think the practical 25 effect is they would have to shut the plant down within, what,
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w 54 1
two or three days -- something like.that -- until the amend-2 ment was approved.
3 MR. CUNNINGHAM:
I think the order would have to be l
4 rewritten because I don't think it presently contains a basis 5
for immediately effective shutdown.
6 COMMISSIONER ASSELSTINE:
I don't think.you have --
well, okay.
My view is that I don't think you would'have to 8
provide that basis'.
Nhat you would say is, there is a public j
3 f
. health and safety justification for requiring immediate 10 inspection.
A consequence of that is that,.under th'e~ existing II technical specifications, the plant will have to be shut down 12 within a certain period.of time.
If the applicant believes 13 there is a justification for continued operation during the
[
I4 inspection program, it i,s free to submit an application for 15 amendment to the license.
16 MR. CUNNINGHAM:
I am not trying to argue with the j
17 merits'of the. proposal but I just point out that there should 18 be some additional wording changes in the order along the
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19 lines you just stated.
~~
20 CHAIRMAN PALLADINO:
But what would happen if that 21 were done?
j -
22 COMMISSIONER ROBERTS:
The plant would be shut down j-23 is what'would happen.
24 COMMISSIONER ASSELSTINE:
That's right.
25 CHAIRMAN PALLADINO:
For how long and under what
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MR. CUNNINGHAM:
The licensee might come in very 3
quickly with a request for an amendment.
Then you get into 4
your Sholly questions.
Does that involve significant hazards 5
considerations..
6 COMMISSIONER ASSELSTINE:
That's right.
~7 CHAIRMAN PALLADINO:
What strikes me is this is an 8
operating plant, it is a plant that has a license, and it has i
3
~
a right to maintain that license unless there is a health and to safety issue that the staff determines needs to be addressed, II and thereby lead to a shut down.
j 12 I am quite confidence on the staff's analysis on the 13 health and safety question, not only these particular evalua-l IN tions that have been mad,e recently, but the whole host of 15 evaluations that have gone over a number of years on low power.
I j
16 questions.
I don't see the basis for calling for a shutdown 17 of this plant based on health and safety issues and, from what i
18 the staff,has said, neither do they.
None has been presented.
19 That would be my position.
20 COMMISSIONER BERNTHAL:
Let me ask two questions i
21 here, as is my want in these circumstances.. I gather that we t
22 have resolved the question.
Jim, I think, has some reser-23 vations of public health and safety as an issue.
It is my 24 judgment, at least, that,public health and safety is not the i
25 issue, here.
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made by Commissioner Asselstine, I presume you are voting 2
e against it?
3 COMMISSIONER BERNTHAL:
Yes, that's right.
4 COMMISSIONER ROBERTS:
I would vote against it.
l CHAIRMAN PALLADINO:
I would' vote against it and I 6
presume you would --
COMMISSIONER ASSELSTINE:
I would vote for it.
l COMMISSIONER BERNTHAL:
Do you have a proxy, too?
i e
I COMMISSIONER ASSELSTINE:
I don't have one.
We 10 don't vote by proxy.
That's the other end of the street.
II (Laughter.)
I2 CHAIRMAN PALLADINO:
So we have voted and there are I3 three against that motion and one for it.
Is there any other I4 item?
15
' COMMISSIONER ASSELSTINE:
No.
16 CHAIRMAN PALLADINO:
I must mItka a correction ~in my 17 opening remarks.
I was told that there is a pending hearing 18 on a previous Grand Gulf license amendment.
We cannot deter-l 19 mine what the issues in that hearing ~are and whether they. bear 20 any relationship to the issue being discussed today.
4 21 So I should amend my opening statement to reflect 22 that there is a pending proceeding and want to restate my view.
23 that OGC should review the transcript for the need to. serve.it 24 on the Grand Gulf parties as well as interested persons in all i
25 licensing cases.
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COMMISSIONER BERNTHAL:
Mr. Chairman, I would like 2
to make one further request and that is that General Counsel be directed, as I assume he would do anyway in this circum-4 stance, to take a careful-look at what the regulatory and 5
legal requirements are in this circumstance and report back immediately to the Commission with that.
CHAIRMAN PALLADINO:
With regard to whether or not 8
'the staff.had the authority to do what it did?
I COMMISSIONER BERNTHAL:
That's right.
10 CHAIRMAN PALLADINO:
I so direct.
II MR. PLAINE:
Thank you.
II CHAIRMAN'PALLADINO:
Anything more to come before us 13 on this matter?
IN
-(No response.)
15 CHAIRMAN PALLADINO:
Thank you.
We will stand
~16
-adjourned.
17 (whereupon, the foregoing meeting was concluded at 18 11:25 o clock,'a.m.)
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I SAFETY EVALUATION REPORT l
RELATED TO ORDER REQUIRING DIESEL GENERATOR IN5PECTION GRAND GULF UNIT 1
]
1.0 Introduction As a basis for operation of Grand Gulf Unit 1 at full power, Mississippi Power j
& Light (MP&L) submitted reports dated February 20 and April 17, 1984, concerning the MP&L program to verify and enhance the reliability of the TDI l
diesel generators at Grand Gulf Unit 1.
'These submittals were in response to the NRC questions on the TDI issue and are supplemental to other MPAL responses to the NRC requests contained in letters to J. P. McGaugby dated October 31, 1983 and December 27, 1903.
Additional actions taken by MP&L to verify and j
enhance the reliability of onsite/offsite AC power systems were documented by letter dated February 26, 1984.
Based on a review of this information and additional information provided during meetings between the NRC staff and MP&L, the staff informed MP&L by j
letter dated April 25, 1984, that the staff was unable to conclude that the proposed MPAL program for ensuring adequate TDI diesel engine reliability would be sufficient to support operation of Grand Gulf Unit I at power levels in j
excess of 5% of full power.
The staff proposed additional actions to ensure i '
adequate reliability of the TDI diesels including disassembly and inspection of at least one TDI diesel, subsequent preoperational testing of that engine',
and additional maintenance and surveillance actions pertaining to the TDI
~
diesels.
By letter dated May 6, 1984, MP&L submitted additional information to support its conclusions that there is little if any justification to require a disassembly inspection of a TDI diesel engine prior to the first refueling 1
outage, and that adequate basis exists to support 100% power operation of Grand Gulf Unit I until the first refueling outage.
The MP&L submittal also included an alternative proposal to disassemble and inspect the Division 1 TDI diesel generator in parallel with the conduct of the plant's power ascension i
program.
i i
In their submittal of February 26, 1984, the licensee proposed to use gas j
turbines, as supplemental AC sources to the onsite distribution systems.
Therefo're, during the period of time when one TDI diesel generator (Division 1)-
{
is unavailable due to disassembly and inspection of diesel engine components, 4
l the available AC power sources will be the offsite systems (115 KV and 500 KV i
networks), one TDI diesel generator (Division 2) and the gas turbine generators.
a i
Although the Division 2 TDI diesel generator will be maintained with current i
Technical Specifications, our review conservatively assumed both TDI diesel 1
generators were not available.
This safety evaluation is based on the assumption that the reactor thermal 4 p power level will not exceed 5% power while one TDI diesel generator is un-available.
1 1
. =.
. =
2.0 Engine' Disassembly, Inspection and Pre-Operational Testing v
2.1 Discussion Concerns regarding the reliability of large bore, medium speed diesel generators of the type supplied by TDI at Grand Gulf Unit I and 15 other domestic nuclear plants were first prompted by a crank shaft failure at Shoreham on September 1983.
However, a broad pattern of deficiencies in critical engine ccaponents have since become evident at Shoreham, Grand Gulf Unit 1, and at other nuclear and non-nuclear facilities employing TDI diesel generators.
These deficiencies stem from inadequacies in design, manufacture and QA/QC by TDI.
In response to these problems, eleven U.S. nuclear utility owners, including MP&L, formed a TDI diesel generator owners group to address operational and regulatory issues relative to diesel generator sets used for standby emergency power.
The Owners Group program, which was initiated in October 1983, l
embodies three major efforts.
l 1)
Resolution of 16 known generic problem areas (Phase I program) intended by the Owners Group to serve as an interim basis for the licensing of plants 2)
Design review of important engine components and quality revalidation of important attributes for selected engine components (Phase II program) t 3)
Expanded engine testing and inspection Pending the completion of the Owners Group program, MP&L has submitted a description of its program to enhance the reliability and performance of the two TDI diesel generators.
This includes engineering evaluations, testing, and corrective actions taken in response to problems experienced during the startup testing phase of the plant, and other potential generic problems identified by the TDI Owners Group (i.e., the 16 known problem areas).
2.2 Evaluation Problems to date with TDI diesel generators stem from a broad pattern of design, manufacturing, and QA/QC inadequacies by TDI.
For this reason the staff believes that the comprehensive approach of the Owners Group program to go beyond problems known to exist and to include a systematic review of critica1 engine components is essential for purposes of reestablishing full confidence in the reliability of the diesel engines.
0 4
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,Pending completion of the TDI Owners Group program, and the staff's review of the recomendations stemming from this program, the staff concludes that additional information is needed regarding the present condition of critical engine components to support interim operation of Grand Gulf Unit I at power levels in excess of M power.
An engine disassembly and inspection in accordance with Se: tion 2.2.1 below is needed to obtain the required informa-tion, and subsequent preoperational testing in accordance with Section 2.2.2 below is needed to verify that the engine has been properly reassembled. The staff's findings regarding the need for these actions are g~enerally based on the following:
- 1) Phase I of the Daners Group program which adcresses the 16 known problems has not been completed.
To date, the Owners Group has submitted reports addressing 8 of these potential problem areas for DSP.V-16 engines.
- However, the staff review of the available Owners Group Peports has not yet been completed, and therefore the staff is unable to conclude that a final resolution to these potential problem areas is available.
In addition, some of the Owners Group reports call for NDE inspections of components which have not yet been performed for GGNS (See Item 4 below).
- 2) Owners Grcup Phase I reports still outstanding on the DSP.V engines include reports on the connecting rods and the cylinder block.
Little information has been provided to date regarding the specific causes of failures and/or cracks of these components.
i
- 3) The Owners Group has not completed Phase II of its program consisting of a comprehensive design review and quality reverification of important engine' components.
- 4) Verification (post-operational) NDE inspections have not been perfornied on a number of critical components originally included in the list of 16 known potential problems.
These include:
- pistons
- connecting rod bearings
- connecting rods
- wrist pin bushing
- engine block
- turbocharger thrust bearing To date, these and other important engine components have experienced between 200 and 800 hours0.00926 days <br />0.222 hours <br />0.00132 weeks <br />3.044e-4 months <br /> of service (for Div. I engine).
Confirmation that these components are presently in an acceptable condition will provide needed confidence that these components will not cause an engine failure during the next 50 to 200 hours0.00231 days <br />0.0556 hours <br />3.306878e-4 weeks <br />7.61e-5 months <br /> of anticipated engine running time before the first refueling outage.
(It is anticipated that the Owners Group program and the staff findings stemming from its review of the program results will be complete by that time.)
~ _ _. -
j h 5)
Because of QA/QC deficiencies at TDI, the staff believes there may be
~
h significant differences in the "as manufactured" quality of engine components between the TDI engines at Grand Gulf and those of other plants with similarly designed engines.
Therefore, it is difficult to draw conclusion relative to the Grand Gulf engines based on inspection results from other plants (e.g., Catawba).
2.2.1 Engine Disassembly and Inspection The Division 1 engine (which has accumulated the most operating hours to date) should be disassembled for inspection of key compenents (identified below),
prior to plant operation above 5% power. Action to be taken on the Division 2 engine would be contingent upon the results of the inspections conducted on the Division 1 engine and MP&L's ability to demonstrate, through a review of the manufacturer's QA records, that the two engines have similar "as-manufactured" quality.
The types of inspections to be performed should be similar to those conducted at Shoreham and Catawba (e.g., dye penetrant, eddy current, ultrasonic, radiography, etc.) as appropriate for each ccmponent based on the kinds of problems (e.
or torquing)g., cracks, abnormal wear or other distress, inadequate assembly which have previously been experienced on these components at Grand Gulf Unit 1, Shoreham or other TDI engines.
The staff concludes that the type and scope of inspections proposed by MP&L in their May 6,1984 submittal (Table 1 of Attachment 2 to the Order) would be acceptable subject
- to the changes in Table 2 of Attachment 2 to the Order.
All defective parts d found shall be replaced prior to declaring the engine operable.
The engine block and engine base may be excepted if indications are non-critical.
Non-critical indications are defined as not causing oil or water leakage, not propagating, or not adversely affecting cylinder liners or stud holes.
A description of the inspections performed and the results should be submitted for NRC staff review prior to plant operation above 5% power.
This report
~
should address all indications found and the engineering basis for acceptance or rejection of the subject components.
2.2.2 Preoperational Testing Subsequent to Engine Disassembly and Inspection Preoperational testing must be performed on the Division 1 engine following its disassembly, inspection and reassembly.
In addition to adhering to the manufacturer's preoperational test recommendations, this phase of testing should include the elements listed below, if they are not already included in the manufacturer's recommendations, unless they would not be recommended by the manufacturer in order to satisfy operability requirements.
- 10 modified starts to 40% load
- 2 fast starts to 701 load
- 124-hour run at 70% load 4
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(d,'by the manufacturer and a 3 to 5 minute loading to the specified load level andA modifie run for a minimun of one hour.
The fast starts are " black starts" conducted from the control room on simulation of an ESF signal with the engine on ready standby status.
The engine should be loaded to 70% and run for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> at this load on each fast start test. The 24-hour performance run is suggested to detect abnonnal temperatures and/or temperature excursions that might indicate engine distress.
Either a modified or fast start.may be utilized.
Should these tests -not be performed satisfactorily at the first attempt, i.e.,
the 10 modified starts should be performed with no failure, the NRC staff will review the need for additional testing re'uirements.
A failure is defined as q
i an inability of the engine to start, or an abnormal condition during the respective run which would ultimately preclude the engine from continuing to operate.
2.2.3 Engine Faintenance and Surveillance Program The staff will review MP&L's proposed maintenance, surveillance and inspection program as identified in MP&L's May 6,1984 submittal prior to the issuance of I
a license for plant operation in excess of 5% power.
4 2.3 Conclusion Pending the completion of the TDI Owners Group Program and the staff review of recommendations stemming from this program as they apply to Grand Gulf Unit 1, the staff concludes that a TDI diesel generator disassembly and x
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inspection in accordance with Section 2.2.1 of this SER and subsequent pre-operational testing of the affected engine (s) in accordance with Section 2.2.2 of this SER is needed to support operation of Grand Gulf Unit I at power levels in excess of 5% of full power. The staff will review MP&L's proposed mainten-ance, surveillance and inspection program and any needed license conditions prior to issuance of a full power license.
3.0 Interim Technical Specifications for AC Power Systems 3.1 Review Scope We have reviewed the description of the 500 KV and 115 KV transmission lines, and the. gas turbine generator set connected to the offsite system and evaluat'ed their capacity, capability, reliability and redundancy. We have also reviewed the proposed technical specifications for AC power systems.
3.2 Offsite Power The offsite power system has previously been reviewed in the Safety Evaluation i
Report of the FSAR and was found to satisfy the capacity, capability, reliability and redundancy requirements and, therefore, is acceptable.
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3.3 Gas Turbine Generator The gas turbine generators (GTG) are presently installed at Grand Gulf near the Unit 2 diesel fuel oil storage tanks.
This location will provide an advantageous 1
electrical connection to the non-Class 1E portion of the Unit 1 plant distribution system.
The three units are connected in parallel through their associated
]
circuit breaker to the non-Class IE 4160-volt distribution system which in turn feeds the Class 1E 4160-volt buses.
In view of the physical location of the gas
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turbines surrounded by large substantial structures it is highly unlikely that a tornado would damage the gas turbine simultaneously with both the 115 KV and the 500 KV offsite power sources.
Therefore the gas turbine power source is i
expected to be available to the.onsite distribution system te provide power to the safe shutdown loaos for a tornado event which may damage the offsite power sources.
Also, the location will prevent unavailability of the gas turbines due to flooding and normal standing water conditions.
The gas turbine generator set consists of three units.
Two units have a capacity of 2000 KW each and third unit has a capacity of 2200 KW.
Our review found that, of the three units, the combined two units, aggregate rating of i
4000 KW, are sufficient to provide power to safe shutdown divisional loads of l
3200 KW for long term cooling.
Each gas turbine has a separate auxiliary power unit (APU) for starting.
A 1
single ApU can be used to start any one of the gas turbines. The gas turbine is designed for manual dead-line starting capability:
1.e., the gas turbine is capable of starting and accelerating to rated speed and voltage by using an APU.
After bringing all three units up to rated speed and voltage, the first unit's circuit breaker closes to a dead bus and the second and third units are synchronized in sequence to the first unit and thus become ready to provide power to the bus.
)
To demonstrate this capacity and starting capability following initial testing, the licensee will perform periodic tests which require that (1) at least once every 15 days, each GTG will be started, brought to rated speed and voltage, and run for at least 60 minutes; (2) at least once every 31 days, two of the GTG will be started, synchronized and leaded to 4700 KW in less'than or equal to 25 minutes and operated with a load greater than or equal to 4700 KW for at least 60 minutes.
The periodic tests and the interim surveillance requirement for the gas turbine generator in the proposed technical specification are equivalent to those for the emergency standby power supplies.
We believe that these surveillance requirements on the gas turbine power supply are adequate for the period of time when one of i
TDI diesel generators is being inspected.
3.4 Technical Specifications l
1)
The current surveillance requirements and limiting conditions for operation (LCOs) for the offsite power sources and diesel generator i
No. 12 (DG #12) and diesel generator No. 13 (DGf13) remain the same.
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j ii) Su'rveillance requirements as stated in Section 3.3 of this' evaluation 3
and LCOs for the gas turbine generators are included in the interim technical specifications. ( Attachment 3 to this Order)
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iii) Additional operability requirements for DGs #12, #13, and GTGs during j
tornado warning and watch conditions are also included in the interim technical specifications.
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4.0 Overall Conclusion The NRC staff, in attachment I to this Order, had concluded that total failure of the TD1 diesels at Grand Gulf'would not significantly increase the risk of the low power operation and that the risk is acceptably small.
Nevertheless, the licensee has provided gas turbine generators to substitute for the cut-of-service diesel generator during the period of inspection and
]
subsequent preoperaticnal testing.
Based on our evaluation of the available power sources and in view of the i
j minimum power needs for low power operation, the staff finds that these sources (offsite, one TDI diesel and gas turbine generators) together with 1'
the specified surveillance requirements, represent a power system which has the capacity, capability, reliability, and redundancy for this low power level and that the health and safety of the public will not be endangered by imple-4 mentation cf this Order.
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.n SAFETY EVALUATION OF GRAND GULF UNIT 1 TECHNICAL SPECIFICATIONS FOR LOW-POWER OPERATION The staff has reviewed the Grand Gulf Technical Specifications (TS) to deter-mine whether changes should be made to the TS for operation under the existing low power (5%) license.
In the past 9 months, the licensee has been reviewing the Technical Specifi-cations.
In March 1984, the licensee initiated a comprehensive review of TS by comparing the TS with the Grand Gulf Final Safety Analysis Report (FSAR) requirements, the NRC.taff's Safety Evaluation Report (SER) for Grand Gulf, the as-built design, ard the staf f's draf t BWR/6 Standard Technical Specifica-tions. As a result, th licensee has identified 357 problem areas which may result in requests for changes to the TS.
Each area is assigned a problem sheet number which will be used to track the resolution of the problem either by obtaining a change to the TS or to otherwise resolve it.
Based on its review, the licensee has requested TS changes for 23 problem areas; 14 were requested for restart and operation under the present low power license, and 9 for power escalation tests. All of these were selected for resolution because these Technical Specifications were found by the licensee to be nonconservative with respect to the FSAR safety analyses and the SER.
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The NRC staff and its consultant, Idaho National Engineering Laboratory (INEL),
(V also reviewed the TS to determine any conconservative specifications relative to the FSAR or SER. Most of the staff recommendations and comments regarding changes to the TS have been considered by Mississippi Power and Light (MP&L) and included in their identified 357 problem areas.
For operation under the low power license (54 power), the staff has not found any specifications that need to be changed in addition to the problem areas identified by MP&L.
For operation above 5% power, the staff has identified several problem areas that will be resolved with the license in addition to those identified by the licensee. A safety evaluation for Technical Specification changes needed for power escalation above 5% power will be issued with the issuance of the full-power license amendment.
Table 1 lists the Technical Specification changes identified by the licensee as being needed prior to operation up to 5% power and above 54 power.
Based on its review of these 23 nonconservative problem areas and related requests for Technical Specification changes identified by MP&L, the NRC staff finds that for 22 of the problem areas, the change will be in the direction of in-creased safety. However, the change requested for the standby gas treatment system (Problem Sheet No. 262) to allow bypassing of the radiation monitor during tests is not acceptable because it could result in unmonitored release of radioactive gaseous effluent. Therefore, the change identified by Problem Sheet No. 262 is not acceptabled based on the information provided in the request letter and will not be made in this Order.
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t ni The staff's safety evaluation of each of the 23 problem areas is provided below. provides the Grand Gulf Technical Specification page changes imple-mented by this Order.
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The NRC staff concludes that, with the changes implemented by this Order, the Technical Specifications required for operation under the current license, which is limited to 5*4 power, is in accordance with the FSAR, SER, and applicable regulatory requirements.
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l Table 1 23 Technical Specification Changes Requested by MP&L l
l Problem Licensee Lett'er Sheet No.
Item Date 001 Number of Automatic Depressurization System Valves 03/20/84 005 Reactor Water Cleanup System Isolation 03/20/84 Instrumentation 015 Drywell and Containment Pressure Setpoints 04/07/84 016 Containment High Pressure Sctocints 04/07/84 021 & 139 Listing of Safety-Related Mechanica1 Snubbers 03/29/84 & 10/07/83 033 Containment Spray System Timer Setpoints 04/07/84 l
037 Calibration Frequency:of Rosemont 'and Riley 12/14/83 Instruments 038 Radiation Monitor Calibration Frequency 04/07/84
[r 054 Containment Spray Actuation Instrumentation 03/29/84 s
076 Emergency Core Cooling System Response Times Item 6, 09/09/83 078 Reactor Core Isolation Cooling System Initiation 10/11/83 Instruments 103 Main Steam Flow Instrumentation 04/07/84 198 Radiation Monitor Instrumentation 03/29/84 213 Automatic Depressuri:ation System Instrumentation 03/29/84 233 Containment Spray Flow Conditions 04/07/8?
262 Standby Gas Treatment System Radioactivity Monitor 04/07/84 285 Chlorine Detector Calibration Frequency 03/29/84 292 & 293 Containment and Drywell Air Locks Test Pressure 04/07/84 306 Listing of Drywell Isolation Valves 04/07/84 308 Room Air Temperature Trip Setpoints 04/10/84
)I29 Accident Monitoring Instrumentation 04/10/84 s_/
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. k (1) Technical Soecification Section 3.5.1, ECCS - Operating, Limiting Condition for Operation (LCO),
page 3/4 5-1; Bases 3/4.5.1 and 3/4.5.2, ECCS - Operating and Shutdown, pages B 3/4 5-1 and B 3/4 5-2.
(2) Change Changed LCO to require "eight" operable ADS valves instead of "At least l
7."
Changed Bases to indicate that the ADS controls "eight" selected valves instead of "seven," and that the safety analyses take credit for "seven" of these valves instead.of "six."
(3) Reason for Chance Restore operating safety margins to those associated with initial conditions used in the safety analyses.
(a) Evaluation The requested change would require that eight valves in the automatic depressurization system (ADS) be operable rather than the currently spect-fied seven valves. The FSAR safety analyses are based on the use of eight
_f valves for depre'ssurization following an accident.
In addition, the bases y
would be changed to allow operation with seven valves for 14 days if one valve is-inoperable.
In a letter dated March 20, 1984, the licensee also provided the results i
of small-creak loss-of-coolant-accident (LOCA) analyses that indicate that credit for only seven valves is needed to satisfy 10 CFR 50.46 acceptance criteria. The NRC staff has reviewed the results of the analyses and con-cludes that it is acceptable to allow one of the eight valves to be in-operable for up to 14 days. The LOCA analyses were cerformed using emergency core. cooling system (ECCS) evaluation models which have been
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previously approved by the staff.
The changes are necessary and sufficient to correct deficiencies in the present specifications for ADS valves.
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Problem Sheet No. 005, Reactor Water Cleanup System Isolation Instrumentation im
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(1) Technical Soecification Table 3.3.2-1, Isolation Actuation Instrumentation, page 3/4 3-12.
(2) Chance I
Changed to indicate "1" minimum operable channel per trip system, instead of "NA," for the standby liquid control system (SLCS) initiation of RWCU isolation function.
Changed applicable operational condition to "5" instead of "3," and added footnote "##" to require the SLCS initiation of RWCU isolation function to be operable in Operati.onal Condition 5 only when control rods are withdrawn, but not if removed per Technical Specification 3.9.10.1 or 3.9.10.2.
Replaced present ACTICN 27 for the SLCS initiation RWCU isolation function with new ACTION 30 on Table 3.3.2-1, which requires the affected SLCS pump to be declared inoperable whenever the associated SLCS initiation instru-mentation is inoperable.
(3), Reason for Chance Reflect actual design of the SLCS initiation of RWCU isolation function which consists of I channel per trip system.
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Provide clarity, completeness, and prevent unnecessary isolation of an
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unrelated system.
(4) Evaluation The reactor water cleanup system is isolated automatically upon standby licuid control system initiation.
Each of the two isolation trip systems receive signals from the SLCS.
Each isolation trip systems' SLCS inputs are arranged in a one-out-of-one logic for isolation valve actuation. The "A" trip system initiates closure of valve G33-F004 and the "B" trip system initiates closure of valves G33-F001 and G33-F251.
In the issued version of the Grand Gulf Unit 1 Technical Specifications, the MINIMUM OPERABLE CHANNELS PER TRIP SYSTEM column of Table 3.3.2-1 incorrectly includes NA for the SLCS initiation for RWCU isolation.
If the RWCU is not isolated, some of the sodium pentaborate injected into the reactor to shut it down could be taken out of the reactor.
Therefore, the effective Technical Specification is nonconservative with respect to system design and anticipated system performahce.
The licensee's procosed change corrects this deficiency in the Tecnnical Specifications and is, therefore, necessary and sufficient.
Operational Condition 5 is the reactor refueling condition. The NRC staff finds this change to be necessary.
It is acceptable in that maintenance on the SLCS would be performed in the refueling condition with all control rocs inserted.
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the operability requirements of the SLCS initiating instrumentation. The applicant has proposed a new ACTION statement that would declare the SLCS l.
pump with the inoperable initiation instrumentation to be inoperable. The staff concludes that this Technical Specification change is acceptable
. because it is consistent with approved technical specification philosophy.
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Problem Sheet No. 015, Drywell and Containment Pressure Setpoints N
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(1) Technical Specification Tables 2.2.1-1, Reactor Protection System Instrumentation Setpoints, page 2-4; 3.3.2-2, Isolation Actuation Instrumentation Setpoints, pages 3/4 3-15, 3/4 3-16, 3/4 3-17a; 3.3.3-2, Emergency Core Cooling System Actuation Instrumentation Setpoints, pace 3/4 3-28; and 3.3.8-2, Plant Systems Actuation Instrumentation Setpoints, page 3/4 3-99.
Bases 2.2.1, Reactor Protection System Instrumentation Setpoints, page B 2-8; 3/4.3.2, Isolation Actuation Instrumentation, page B 3/4 3-1; 3/4.3.3, Emergency Core Cooling System Actuation Instrumentation, page B 3/4 3-2; and 3/4.3.8, Plant Systems Actuation Instrumentation, page B 3/4 3-6.
(2) Chance Revised the drywell and containment pressure instrument setpoints and allowable values to account for the effect of worst case negative barometric pressure changes.
The Bases sections are supplemented to reflect that negative carometric pressure fluctuations are accounted for in the trip setpoints and allowable values specified for drywell and containment pressure-high.
(O (3) Reason for Chance V' /
Revise setpoints and allowable values because the drywell and containment pressure instrumentation do not automatically compensate for changes in barometric pressure, and which, if omitted, could contribute to delayed safety system initiation.
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Evaluation For the Grand Gulf I cesign, botn the drywell and containment pressure instrumentation provide trip signals that are necessary to ensure the capability to prevent or mitigate the consepuences of postulated acci-dents.
In addition, the drywell pressure instrumentation also provices trip signals required for achieving safe shu-down.
The licensee has stated that historical weather information for the plant locale indicates that the largest negative barometric deviation from standard pressure expected is 0.50 psi.
The NRC staff has independently reviewed severe weather cata including, data for hurricanes anc confirmed that 0.50 psi bounds expected pressure decreases.
To ensure that.the instrument trip setecints set during normal weather concitions are not exceeded during storm conditions, the licensee has proposed to recuce the setpoints and allowable values by 0.50 psi.
The changes to the Bases sections icentify which setpoints are affected by barometric pressure changes.
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The changes to the drywell and containment pressure instrumentation setpoints and allowable values are necessary to bring limiting initial containment and drywell initial pressures into agreement with initial 4-containment and drywell pressures assumed in FSAR safety analyses. An aanalysis is in progress to justify higher values; however, as an interim measure, the licensee has proposed these more conservative values.
t The licensee has stated that the proposed changes are necessary and suffi-1!
cient to bring the setpoints into agreement with FSAR safety analyses.
In response to a request from the NRC staff, the licensee is participating in a BWR Owners' Group effort to provide more detailed information on their setpoint methodology. The staff concludes that there is reasonable assurance, based on staff participation in meetings with the BWR Owners' Group working group on setpoint methodology, that,the forthcoming more detailed information on setpoints and.setpoint methodology being developed I-by this group will-verify the acceptability of the proposed setpoints.
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the interim, the staff finds tnat the change is in the conservative direc-tion and is acceptable.
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(1) Technical Soecification l
Table 3.3.8-2, Plant Systems Actuation Instrumentation Setpoints, page 3/4 3-99.
(2) Change Containment high pressure trip setpoint is changed to "7.84 psig" instead of "9 psig," and the corresponding allowable value is changed to "8.34 psig" instead of "9.2 psig."
(3) Reason for Chance Restore safety margins c those associated with the safety analyses.
(4) Evaluatien In response to a recommendation from the nuclear steam supply system (NSSS) vendor (General Electric), the licensee is proposing to revise the containment spray initiation instrumentation trip setpoint and allowable value. The licensee has stated that this change is necessary to correct i
an error by the NSSS vendor.
The licensee has stated that this change is necessary and sufficient to
~s bring the Technical Specification trip setpoint and allowable value to
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values consistent with the assumptions of the safety analyses.
In response to a request from the NRC staff, the licensee is participating in a EWR Owners' Group effort to provide more detailed information on their setpoint methocology.
The staff concludes that there is reasonable assurance, based on staff participation in meetings with the EWR Owners' Group working group on setcoint methodology, that the forthcoming more-detailed information on setpoints and setpoint methodology being developed by this group will verify the acceptability of the procosed setooints.
In the interim, the staff finds that the change is in the conservative direction and is acceptaole.
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!t Problem Sheet Nos. 021 and 139, Listing of Safety-Related Mechanical Snubbers En 1
hN hj (1) Technical Soecification j[
Table 3.7.4-2, Safety Related Mechanical Snubbers, page 3/4 7-16.
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(2) Change-Changed the list of snubbers.
l, (3) Reason for Change l
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The snubber list changes are needed to make the list consistent with the as-built plant.
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Snubber operability is determined by an inspection defir.ed in the surveil-j lance requirements. A footnote to Table 3.7.4-2 allows the licensee to add I
snucbers to the list when they are.found to be needed provided a revision j
to the table is included with the next license anencment reouest.
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requirement in the footnote to include changes in tne next license amend-i' ment allows the NRC staff to review the changes in a timely manner.
t' Technical Specification Section 3.7.4 requires that snubbers on systems 7
required to be operable in operational condition 4 (colc shutdown with
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average reactor. coolant temperature less than or equal to 200 F) and i'
operational condition 5 (refueling) must themselves also be operable in operational conditions 4 and 5.
Since the reactor is in operational condition 4, this Technical Specification change is necessary.
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i N' (1) Technical Specification Table 3.3.8-2, Plant Systems Actuation Instrumentation Setpoints, page 3/4 3-99; and Bases 3/4.3.8, Plant Systems Actuation Instrumentation, page B 3/4 3-6.
(2) Chance Revised trip se points and allowable values in both containment spray system timers.
Revised Bases to refer to the analyzed minimum and maximum time delays between the initiation of the accident and containment spray initiation, which are 10 minutes and 13 minutes, respectively.
(3) Reason for Chance Restore margins assumed in safety analyses.
Present timer settings permit analytical limits for contair. ment soray initiation to be exceeded and possible delayed safety system initiation.
Avoid coeration which could lead to unanalyzed conditions.
(4) Evaluation D.
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The low pressure coolant injection system and the containment spray system are subsystems of the residual heat removal (RHR) system.
Two of three RHR trains automatically divert low pressure coolant injection flow from the core to the containment spray provided certain conditions are sensed by the containment spray initiation logic.
Timers are provided within this logic to ensure that injection flow is directed to the core for at least 10 minutes ar.d that containment spray will be initiated no later than 13 minutes following a LCCA.
These values were used in the safety analyses for core cooling and initiation of containment spray following a LOCA.
In reviewing the setpoint calculations, the licensee determined that there is a nonconservative error in the setooint resulting from a mistake in determining the total loop accuracy.
In addition, the licensee discovered that the additional 90-second time delay in the initiation of Train B was not considered in the FSAR safety analyses.
Accordingly, the licensee has proposed trip setpoints and allowable values to correct the deficiency in summing the instrument loop inaccuracy and to remove the time delay in Train B initiation. A footnote is proposed to be added to Table 3.3.5-2 to clarify the new trip setpoint for the System 3 timers.
1 This footnote will specify that the present 90-second delay is to be set at a value not to exceed 10 seconds.
A change to the bases has been proposed to acdress the coper and Icwer analytical time limits associated with ccntainment spray initiation.
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The licensee has stated 'that this change to the Technical Specifications is necessary and sufficient to correct the nonconservative errors in the setpoints and allowable values.
In response 'to a request from the NRC staff, the licensee is participating in a BWR Owners' Group effort to provide more detaiicd information on their setpoint methodology.
The staff concludes that there.is reasonable assurance, based on. staff participation in meetings' ith the BWR Owners' w
Group working group on setpoint methodology, that the forthcoming more-detailed information on setpoints and setpoint methodology being developed by this group will verify the acceptability of the proposed setpoints.
In the interim, the staff finds that the change is in the conservative direc-tion and is acceptable.
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a Problem Sheet No. 037, Calibration Frequency of Rosemont and Riley Instruments O
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(1) Technical Specification Table 4.3.2.1-1, Isolation Actuation Instrumentation Surveillance Requirements, pages 3/4 3-20 through 3/4 3-23a.
(2) Change Changed to add footnote (c) requiring trip unit calibration at least once per 31 days to all Rosemont trip units.
Changed the channel calibration frequency for Riley temperature switches from 18 months to annual.
(3) Reason for Change i
Ensure consistency within Technical Specifications for trip unit calibra-tion frequency.and thereby avoid operator confusion and minimize the potential for human error.
a Restore design margin by changing to manufacturer's recommended calibration frequency.
(4) Evaluation Footnote (c) which states " Calibrate trip unit at least once per 31 days" g
is applied to certain Rosemont trip units associated with the isolation 4
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actuation instrumentation channels delineated in Table 4.3.2.1-1 of the
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Technical Specifications.
By letter dated September 9, 1983, from A.
Schwencer (NRC) to J. P. McGaugby (MP&L), the NRC staff requested that the licensee provide the rationale for calibrating certain Rosemont trip units at 18-month intervals and other Rosemont trip units at 31-day intervals.
In response to the staff's request, by letter dated October 14, 1983, from L. F. Dale (MP&L) to H. Denton (NRC), the licensee stated that the Rosemont trip unit for each channel delineated in Table 4.3.2.1-1 (isolation actua-tion instrumentation) was being calibrated monthly, and changes would be proposed.to the Technical Specifications to require this surveillance fre-4 quency on all Rosemont trip units.
Through its review of the isolation actuation instrumentation surveillance requirements, the licensee determined another case where the surveillance testing interval for Riley temperature switches required by the Technical Specifications was greater than that recommended by the manufacturer.
Temperature-monitoring instrument channels are currently being calibrated yearly to satisfy manufacturer's recommendations.
To resolve this defi-ciency, Technical Specification requirements for the temperature-moni-toring instruments are being changed to be consistent with the component manufacturer's recommendations.
On the basis of-its review, the staff finds that the Technical Specifica-tion changes are necessary to provide surveillance requirements consistent N-/
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Therefore, the staff finds the Technical Specification changes acceptable.
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Problem Sheet No. 038, Radiation Monitor Calibration Frequency
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(1) Technical Soecification s
Tables 4.3.2.1-1, Isolation Actuation Instrumentation Surveillance Requirements, page 3/4 3-20; 4.3.7.1-1,- Radiation Monitoring Instrumentation Surveillance Requirements, page 3/4 3-59; 4.3.7.5-1, Accident Monitoring Instrumentation Surveillance Requirements, page 3/4 3-72; and 4.3.7.12-1, Radioactive Gaseous Effluent Monitoring Instrumentation Surveillance Requirements, page 3/4 3-92.
(2) Change Changed the channel calibration frequency for accessible and continuous radiation monitors from 18 months to 12 months.
(3) Reason for Chance t
Recommended by' vendor anc stated in FSAR.
(c) Evaluation From a review of the FSAR and the Technical Specifications, the licensee has found a discrepancy between the commitments contained in the FSAR and the requirements of the Technical Specifications.
The FSAR states that continuous radiation monitoring instruments that are accessible during
-x normal operation and airborne radiation monitors will be calibrated
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annually based on the vendor's reccmmendations.
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The staff finds these changes are necessary to provide surveillance requirements consistent with vendor's recommendations, and are therefore acceptable.
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i Upon sensing a LOCA condition via the drywell pressure-high and/or vessel gs water level-low instrumentation, the spray actuation instrumentation starts
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its timers.
If at the end of the timer cycle (10 minutes) a containment x_ /
high pressure signal exists, the low pressure coolant injection train A flow will be automatically diverted from coolant injection into the core to the containment spray function.
Simultaneously, at the end of its timers' cycles, low pressure coolant injection system B flow to the core will be automatically diverted to containment spray provided a containment high-pressure condition is sensed.
To meet FSAR analyses of a LOCA, the coolant flow to the core must continue for at least 10 minutes and spray flow must begin prior to 13 minutes after the LOCA.
In order to ensure the operability of the containment spray function given a single failure, the minimum number of required operable channels is proposed to be changed from one per trip system to two per trip system for the drywell pressure-high and the reactor vessel Icw-level 1 instruments.
Changes to the Action Statements in Technical Specification 3.3.8 are re-quired to be consistent with the system cesign.
In the issued versicn of the Technical Specifications, Action Statements a and b.1 incorrectly require that inoperable timers be placed in the trippec condition.
Plac-ing a timer in the tripped concition could result in premature diversion of low pressure coolant injection flow to the containment sprays.
The correct action is to declare the associated trip system inoperable when a timer is inoperable and then take the action required by Technical Speci-fication 3.6.3.2.
/
In the issued version of the Grand Gulf Technical Specifications, Action
'l Statement 2.b indicated that there are two, rather than one, trip system for each spray system.
Corrections to indicate the installed number of trip systems are proposed, and appear in Action 130b on Table 3.3.8-1.
Other changes are proposed to reformat the required acticns when instru-ment channels are determined to be inoperable.
Based on its review, the staff finds that the proposed changes improve system reliability and provice a sufficiently conservative set of require-ments should one or more channels cecome inoperable.
These changes are in accordance witn the regulatory guidelines of the Standard Technical Speci-fications for General Electric Boiling Water Reactors and are necessary to correct a deficiency in the Grand Gulf Technical Specifications.
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51-ll Problem Sheet No. 076, Emergency Core Cooling System Response Times (1) Technical Specification Table 3.3.3-3, Emergency Core Cooling System Response Times (Seconds),
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page 3/4 3-30.
(2) Change I
Revised to change response time of LPCI pumps for the injection mode of RHR system to "<40" seconds.
(3) Reason for Chance Restore margin to that assumed in safety analyse's..If uncorrected, could permit operation leading to unanalyzed events.
(Existing pump response time of 45 seconds for pumps A and B is inconsistent with the response time of 40 seconds used in safety analysis providing basis for plant design.)
(4) Evaluation The change requires a faster response of the low pressure coolant injection (LPCI) system following receipt of an emergency core cooling system (ECCS) actuation signal. The response time of less than or equal to 40 seconds is consistent with the analyses assumptions used for ECCS evaluation in Section 6.3 of the Grand Gulf Final Safety Analysis Report (FSAR).
The change is necessary to make the Technical Specifications consistent with accident analyses, and is acceptable.
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i Problem Sheet No. 078, Reactor Core Isolation Ccoling System Initiation (1) Technical Soecification Table 3.3.5-1, Reactor Core Isolation Cooling System Actuation Instru-mentation, pages 3/4 3-45 and 3/4 3-46.
a (2) Chance Minimum OPERABLE channels per trip system for Reactor Vessel Water Level-Low, Level 2 is changed from "2" to "4."
Present ACTION 50 is changed to reflect only one trip system rather than two.
(3) Reasen for Chance Reflect actual system cesign and pecvice a conservative set of require-ents should one or more cnannels become inoperable.
(c) Evaluation The reactor core isolatien cooling syste, initiates on low reactor water level.
The initiatien logic is arranged as one trip system with four water level signals feecine a one-out-of-two-twice logic.
The present reouirement of 2 minimum GPERAELE cnannels per trip system would not result in RCIC initiation unless the correct 2 channels are operable.
To assure that RCIC initiation is available given a single failure, the 1
/N minimum OPERABLE channels per trip system should be revised from 2 to 4 i
.(
channels.
In addition, the proposed change to ACTION 50 is needed.
The i
proposed ACTION statement addresses the one trip system design of the Grand Gulf RCIC system and replaces an ACTION statement intended for a 2-trip system design.
On the basis of its review, the staff finds that the changes enhance system reliacility and provice a sufficiently conservative set of require-ments should one or more channels beccme inoperable.
These changes are in accordance with the -egulatory guidelines of the Standard Technical Specifications for General Electric Eoiling Water Reactors and are neces-sary to correct a deficiency in the Grand Gulf Technical Specifications.
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Problem Sheet No. 103, Main Steam Flow Instrumentation V
(1) Technical Specification Table 3.3.2-1, Isolation Actuation Instrumentation, pages 3/4 3-10, 3/4 3-14a.
(2) Chance The number of main steam line flow channels required to be operable in each trip system is revised from "2" to "8," and note (g) is deleted.
(3) Reascn for Chance Reflect actual plant tric logic design and provide Technical Specification re:uirements consistent with the single-failure criteria assumed in safety analyses.
(4) Evaluation For na Grand Gulf design, one of the signals that initiates main steam lice (MSL) isolation is high steam line flow.
Sixteen main steam line ficw instrument cnannels are arranged into two trip systems, each trip system containing two channels per steam line for a total of eight channels per trip system.
To assure initiation of MSL isolation, postu-lating a single failure in the instrumentation system, all eight MSL flow channels in each trip system should be operable.
Therefore, the licensee has proposed to revise the minimum channels operable requirements of the iV Technical Specifications from two per trip system to eight per trip system.
With the change from 2 to 8 channels per trip, footnote g is not required.
Based on its review, the staff finds that the changes improve system reliability and provide a sufficiently conservative set of requirements should one or more channels become inoperable.
These changes are in accordance with the regulatory guidelines of the Standard Technical Speci-fications for General Electric Boiling Water Reactors and are necessary to correct a ceficiency in the Grand Gulf Technical Specifications.
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i On the basis of its' review, the staff finds that the changes enhance system reliability and provide a sufficiently conservative set of require-ments should one or more channels become inoperable. These changes are
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in accordance with the regulatory guidelines of the Standard Technical Specifications for General Electric Boiling Water Reactors and are neces-stry to correct a deficiency in the Grand Gulf Technical Specifications.
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..___m Problem Sheet No. 213, Automatic Depressurization System Instrumentation 7s iV)
(1) Technical Specification i
Table 3.3.3-1, Emergency Core Cooling System Actuation Instrumentation, 4
pages 3/4 3-25 and 3/4 3-27.
(2) Change Changed the minimum operable channels for the ADS trip system manual initiation function from 1 per valve to to 2 per system.
Changed Action Statement 32 so that with less than the required minimum ocerable channels per trip function, the associated ADS trip system was declared inoperable instead of the associated ADS valve.
(3) Reason for Chance
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place limiting conditions for operation and surveillance requirements on systems level ADS initiation circuits.
(4) Evaluation The automatic depressuri:ation system (ADS) consists of eight safety / relief valves and associated actuation instrumentation. The actuation instrumenta-tion consists of two trip systems, either of which will actuate all eight ADS valves.
Each ADS trip system includes two manual hand switches.
( 's)
Operation of both hand switches will produce an ADS trip system actuation s_ /
signal.~ Table 3.3.3-1 of the effective Technical Specifications requires 1 per valve as the minimum cperable channels for manual initiation.
The 1 cer valve refers to the hand switches used to actuate individual safety /
relief valves, and not to the two hand switches per trip system used to actuate the ADS trip system.
Accordingly, to provide Technical Specifica-tion requirements consistent with tne design configuration for ADS initia-tion, the licensee has proposed to revise the " minimum operable channels per trip function" column of Table 3.3.3-1 from 1 per valve to 2 per system, and to replace the worc " valve" in ACTION 32 with " trip system."
On the basis of its review, the staff finds that the change makes the Technical Specification consistent with the as-built ADS by placing limit-ing conditions for operation and surveillance requirements on the system level ADS manual initiation circuits.
Therefore, the staff finds that the cnange is necessary and acceptable.
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l Problem Sheet No. 233, Containment Spray Flow Conditions l
(1) Technical Specification Section 4.5.1.b, Emergency Core Cooling Systems, Surveillance Require-ments, page 3/4 5-4.
- (2) Change 1
i Revised to increase total developed head values for the emergency core
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cooling system pumps as follows:
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New Head (psid)
Previous Head (psid)
LPCS pump
>290
>261 i
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>125
>89 i
HPCS pump
[445
[182 4
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Revised to add " Flow and total developed head values for surveillance testing include system losses to ensure design requirements are met."
3 j
(3) Reason for Change i
l Reflect system design (injection) requirements.
(Inservice testing of 1
pumps to existing Specification 4.0.5 is not conservative relative to system requirements.)
Provide information for Specification 4.5.1.b to avoid personnel confusion and minimize potential for human error.
)
(4) Evaluation The effective Technical Specification requires a developed head for each emergency core cooling system (ECCS) pump based on manufacturer's data.
l This does not include pressure losses in the system piping that occur in i
the as-built plant configuration.
For consistency with FSAR analyses
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assumptions, the specification is revised to include the effect of these j
system losses.
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The staff has compared the proposed specification with the flow-versus-
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head assumptions used in the emergency core cooling system analyses.
The specification requires a reasonably higher developed head at the pump than i
assumed at the vessel in the LOCA analyses.
This indicates that system losses and ECCS injection requirements have been accounted for in the proposed specification.
I i
The staff therefore finds the change is necessary to correct a deficiency j
in the Technical Specifications, and is acceptable.
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Problem Sheet No. 262, Standby Gas Treatment System Radioactivity Monitor (1) Technical Soecification Tables 3.3.7.12-1, Radioactive Gaseous Effluent Monitoring Instrumenta-tion, pages 3/4 3-90, 3/4 3-91; 4.3.7.12-1, Radioactive Gaseous Effluent Monitoring Instrumentation Surveillance Requirements, page 3/4 3-94; and 4.11.2.1.2-1, Radioactive Gaseous Waste Sampling and Analysis Program, page 3/4 11-9.
(2) Chance Added the stancby gas treatment system to the Technical Specification tables for radioactive gaseous efficent monitoring.
Added the standby gas treatment system to Technical Specification Table 4.11.2.1.2-1 to provide for inclusion of measureable SGTS exhaust contributions in the dose rate calculations, if the SGTS has been run.
(3) Reason for Chance Reflect plant design and ensure consistency witn tne intent of 10 CFR 50 Appendix A, Criterion 64 (4) Evaluation The purpose of the standby gas treatment system (SGTS) radiation monitors Os is to measure radioactive gaseous effluent releases to the environment
.( )
during and following a design-basis accident (CSA) and these radiation v
monitors are included in Table 4.3.7.5-1, Accident Monitoring Instru-mentation. The current design meets General Design Criterion (GOC) 64 of 10 CFR 50 without changing Technical Specifications as requested.
Furthermore, the radiation monitors in Table 4.11.2.1.2-1 are for the i
gaseous effluent monitors for normal plant operation, including antici-pated operational occurrences.
The recuested change could allow SGTS operation for surveillance demon-stration testing without radiation monitors in service as long as grab 4
samples are taken at least every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> and analyzed for gross activity within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
A radiation monitor should be operable whenever the SGTS is in a testing mode.
Testing should not start unless the respective I
radiation m0nitors are operable, and should be terminated in the event of failure of a radiation monitor.
Therefore, the staff finds this request unacceptable, and this change is not included in this Order.
262-1
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l Problem Sheet No 285, Chlorine Detector Calibration Frequency (1) Technical Scecification Section 4.3.7.8, Chlorine Detection System, Surveillance Requirements, i
page 3/4 3-75.
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j (2) Chance l
Changed the channel calibration frequency of the chlorine detection system l
from 18 months to 6 months.
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(3) Reason for Chance J
Ensure the safety margin of the cesign c m-itted to in the FSAR.
(4) E'va l ua ti on The licensee has proposed a chlorine detection instrument channel calibra-tion frequency c.nce per 6 months insteac Of once per 13 montns as in the ef fective Technical Specifications.
Regulatory Guide 1.95, Rev. 1,
" Protection of Nuclear Poner Plant Control R::m Gperaters Against in Accd-l dental Chlorine Release," January 1977, recommends a calibration frequency
]
of once per 6 months.
i t
she staff fines that the change provides for surveillance requirements 1
-"at are consistent with manufacturer's reccmmencations and regulatory guidelines.
Therefore, the staff finds that the change is necessary and i
acceptable.
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I l
1 l!tilli 1
255-1
- - -,, _ - - - _ _.. -. _ -. _ _, -. ~, - _ _ _ - - _, _,.., _ - - - _ - - _ _.. _ _. -. _ -. ~.. - -, _ -
. _ _ _ _ _ - -. - -... - -, ~. -, -..... -,. _ -,...
' i i
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i Problem Sheet No. 292 and 293, Containment and Drywell Air Locks Test Pressure O
(1)
Technical Specification Sections 4.6.1.3, Containment Air Locks, Surveillance Requirements, and 4.6.2.3, Drywell Air Locks, Surveillance Requirements, pages 3/4 6-6 and 3/4 6-16, (2) Chance Revised to recuire verification that the seal air flask pressure for the containment and drywell air locks is greater than or equal to "90" psig rather than "60" psig.
i Changed to include the 30-day leakage criteria in the minimum required seal air flask ;ressure for the crywell air leck coor inflatable seal system.
(3) Reasen for Chance Restore rargin neeced fce actual air lock system cesign.
( Ep i sting allcwable seal air flask pressure is not conservative since it did provide i
for a 30-day leakage criteria after loss of air su; ply.)
l 1
Reflect system design requirements and safety analysis by ensuring drywell air lock inflatable seal integrity for 30 days upon loss of seal air 9
(4) supply.
Evaluation The basis for the change is that the current Technical Specification 4.6.1.3.d.2/4.6.2.3.c.2 requires verifying seal air flask pressure to be greater than or equal to 60 psig.
Technical Specification 4.6.1.3.d.3/
l c.6.2.3.d.3, ho ever, requires verifying that the system pressure does not cecay more than 2 esig frem 90 psig witnin 45 hours5.208333e-4 days <br />0.0125 hours <br />7.440476e-5 weeks <br />1.71225e-5 months <br />.
Based on this allewable :ressure decay rate, the air flask pressure should be changed frem 60 psig to 90 psig.
This will ensure that the minimum inflatable seal pressure of 60 psig will be maintained for at least 30 days assuming
)
no active air supply.
The staff finds the change to the Technical Speci-i fications necessary and acceptable.
I i
)
l I
1 292-1 l
l l
i
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Problem Sheet No. 306, Listing of Drywell Isolation Valves (1) Technical Soecification Table 3.6.4-1, " Containment and Drywell Isolation Valves," page 3/4 6-41.
(2) Change Added 5 valves to the Technical Specification Table for " Containment and Drywell Isolatten Valves."
(3) Reason for Chance Reflect plant design and thereby prevent possible operator error.
I (4) Evaluation i
Four check valves in the combustible gas control system are to be added to 1
Table 3.6.4-1.
In addition, a normally locked closed refueling pool drain i
system valve is to be added.
)
Two of these check valves, E61-F002A and B, are located on the drywell i
purge compressor lines (one per line).
The remaining check valves, E61-F004A and 8, are located on the post-LOCA drywell vacuum breaker line.
In light of the fact that there are no inboard isolation valves provided for these lines, these check valves perform isolation functions as backups O
to the outboard isolation valves presently existing in those lines.
Inclusion of these check valves in Table 3.6.4-1 because of their backup isolation functions is, therefore, considered by the licensee to be appropriate.
A normally locked closed drain valve, G41-F265, is also added to the table.
This valve is an upper containment pool drain system valve that is only opened during a refueling outage.
Because this valve is on a line that penetrates the drywell, inclusion of this valve in the table is considered by the licensee to be appropriate.
The changes correct the Technical $pecifications to reflect the plant 7
design configuration and are, therefore, acceptable.
306-1 i
1
- i t,
e l-Problem Sheet No. 308, Room Air Temperature Trip Setpoints s
(1) Technical Specification Table 3.3.2-2, Isolation Actuation Instrumentation Setpoints, pages 3/4 3-16, 3/4 3-17, 3/4 3-17a.
i j
(2) Chance Decreased the trip setpoints and allowable values for the temperature-high functions for RWCU, RCIC, and RHR system leakage detection instrumentation.
(3) Reason for Chance Reflect plant design to ensure proper leakage detection, thereby ensuring j
safety margins.
i I
(4) Evaluation i
i The licensee has reviewed the calculations used to establish trip l
setpoints and allowable values for the temperature sensing instrument j
channels that provide input to the 1e'ak detection isolation features.
)
From tnis review, the licensee has determined that the values are too high to ensure prompt isolation.
Using the current Technical Specification d
values may result in delayed detection or in some cases no detection of a 25 gpm leak.
In response to a request from the NRC staff, the licensee is participating l
in a BWR Owners' Group effort to provide more detailed information on their setpoint methodology.
The staff concludes that there is reasonable assurance, based on staff participation in meetings with the BWR Owners' Group working group on setpoint methodology, that the forthcoming more detailed information on setpoints and setpoint methodology being i
developed by this group will verify the acceptability of the proposed setpoints.
In the interim, the staff finds that the proposed change is in the conservative direction and is acceptable.
I
)
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308 1 l
s*
1 Problem Sheet No. 329, Accident Monitoring Instrumentation (1) Technical Scecification Table 3.3.7.5-1, Accident Monitoring Instrumentation, page 3/4 3-70.
(2) Chance Transferred and increased the operational conditions applicable to each accident monitoring instrument from Table 3.3.7.5-1.
Changed titles of Items 13 through 18 to indicate the specific monitor type.
For item 2. changed f cm Action Statement 50 to new Action Statement 32.
(3)
Ressc9 for Chance Reflect ;1 ant design requirements thereby ensuring safety margins.
Avoid possible operator error.
Reflect plant design thereby ensuring pecper operator action.
(4) Evaluatten Ine present applicability is for operational conditions 1 and 2 for all instru entation.
The change extends applicability to other conditions (3, 4 and 5) on an instrument specific basis, as a result of licensee's review based on FSAR Appendix ISA, entitled " Plant Nuclear Safety Opera-tional Analysis." Because the change expands the applicability of the current s;ecification, it is censidered conservative and, therefore, acce: table.
l I
s AT7ACHMENT 2 TO ORDER LIMITING OPERATION FACILITY OPERATING LICENSE MO. NFF-13 DOCKET NO. 50-416 Replace the following pages of the Appendix A Technical Specifications with the enclosed pages. The revised pages are identified by date of Order and contain a vertical line indicating the area of change. The corresponding reverse pages are also provided to maintain docueent completeness.
Amended Reverse Page Page 2-4 2-3 B 2-8 8 2-7 3/4 3-10 3/4 3-9 3/A 3-12 3/4 3-11 3/4 3-1A 3/4 3-13 3/4 3-14a 3/4 3-15 3/4 3-16 3/4 3-17 3/4 3-17a 3/4 3-20 3/4 3-19 3/4 3-21 3/4 3-22 3/4 3-23 3/4 3-23a 3/4 3-25 3/4 3-26 3/4 3-27 3/4 3-28 3/4 3-30 3/4 3-29 3/4 3-45 3/4 3 A6 3/4 3-56 3/4 3-55 3/4 3-58 3/4 3-57 3/4 3-59 3/4 3-60 3/4 3-69 3/4 3-70 3/4 3-71 3/4 3-72 3/4 3-75 3/4 3-92 3/4 3-93 3/4 3-94 3/4 3-96 3/4 3-98 3/4 3-97 3/4 3-98a 3/4 3-99 3/4 3-100 "APR * - 1:F*
ATTACHMENT 2 (Con't) Amended Reverse Page Page 3/4 5-1 3/4 5-2 3/4 5-4 3/4 5-3 3/4 6-6 3/4 6-5 3/4 6-16 3/4 6-15 3/4 6-41 3/4 6-42 3/4 7-16 3/4 7-15 3/4 7-17 3/4 7-18 3/4 7-19 3/4 7-20 3/4 7-21 3/4 7-22 3/4 7-23 3/4 7-24 3/4 7-25 3/4 7-26 l
B3/4 3-1 B3/4 3-2 B3/4 3-6 B3/4 3-5 B3/4 5-1 B3/4 5-2 B3/4 5-3 l
O w n,ee4
SAFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGS 2.2 LIMITING SAFETY SYSTEM SETTINGS REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS 2.2.1 The reactor protection system instrumentation setpoints shall be set consistent with the Trip Setpoint values shown in Table 2.2.1-1.
APPLICABILITY:
As shown in Table 3.3.1-1.
ACTION:
With a reactor protection system instrumentation setpoint less conservative than the value shown in the Allowable Values column of Table 2.2.1-1, declare the channel inoperable and apply the applicable ACTION statement requirement of Specification 3.3.1 until the channel is restored to OPERABLE status with its setpoint adjusted consistent with the Trip Setpoint value.
1 I
i GRAND GULF-UNIT 1 2-3
TABLE 2.2.1-1 REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS c) m ALLOWABLE h
FUNCTIONAL UNIT TRIP SETPOINT VALUES S
1.
Intermediate Range Monitor, Neutron Flux-High E
-< 120/125 divisions
-< 122/125 divisions of full scale of full scale h
2.
Average Power Range Monitor:
U a.
Neutron Flux-liigh, Setdown 5 15% of RATED 5 20% of RATED e
liiERMAL POWER THERMAL POWER b.
Flow Biased Simulated Thermal Power-High
- 1) Flow Biased 5 0.66 W+48%, with 5 0.66 W+51%, with a maximum of a maximum of
- 2) High Flow Clamped 5 111.0% of RATED 5 113.0% of RATED TilERMAL. POWER THERMAL POWER c.
Neutron Flux-High 5 118% of RATED 5 120% of RATED THERMAL POWER THERMAL POWER d.
Inoperative NA NA 3.
Reactor Vessel Steam Dome Pressure - High 5 1064.7 psig 5 1079.7 psig 4.
Reactor Vessel Water Level - Low, Level 3 2 11.4 inches above 3 10.8 inches above instrument zero*
instrument zero*
5.
Reactor Vessel Water Level-High, Level 8 5 53.5 inches above 5 54.1 inches above instrument zero*
instrument zero*
6.
Main Steam Line Isolation Valve - Closure 5 6% closed 5 7% closed 7.
Main Steam Line Radiation - High 5 3.0 x full power 5 3.6 x full power background background 8.
Drywell Pressure - High 5 1.23 psig 5 1.43 psig 9.
Scram Discharge Volume Water Level - High 5 60% of full scale 1 63% of full scale 10.
Turbine Stop Valve - Closure 1 40 psig**
1 37 psig 11.
Turbine Control Valve Fast Closure, Trip Oil Pressure - Low 1 44.3 psig**
1 42 psig 3{
12.
Reactor Mode Switch Shutdown Position NA NA 4
13.
Manual Scram NA NA
~
rg
- See Bases Figure B 3/4 3-1.
1) nitial setpoint.
Final setpoint to be determ' uring startup test program.
Any required cht
+o
i 1
LIMITING SAFETY SYSTEM SETTINGS f
\\
BASES REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS (Continued)
Average Power Range Monitor (Continued) amount, the rate of power rise is very slow.
Generally the heat flux is in near equilibrium with the fission rate.
In an assumed uniform rod withdrawal approach to the trip level, the rate of power rise is not more than 5% of RATED THERMAL POWER per minute and the APRM system would be more than adequate to assure shutdown before the power could exceed the Safety Limit.
The 15% neutron i
flux trip remains active until the mode switch is placed in the Run position.
4 The APRM trip system is calibrated using heat balance data taken during steady state conditions.
Fission chambers provide the basic input to the sys-tem and therefore the monitors respond directly and quickly to changes due to transient op'eration for the case of the Neutron Flux-High 118% setpoint; i.e, for a power increase, the THERMAL POWER of the fuel will be less than that indicated by the neutron flux due to the time constants of the heat transfer associated with the fuel.
For the Flow Biased Simulated Thermal Power-High setpoint, a time constant of 6 1 1 seconds is introduced into the flow biased APRM in order to simulate the fuel thermal transient characteristics.
A more conservative maximum value is used for the flow biased setpoint as shown in 3
Table 2.2.1-1.
The APRM setpoints were selected to provide adequate margin for the Safety Limits and yet allow operating margin that reduces the possibility of unneces-sary shutdown.
The flow referenced trip setpoint must be adjusted by the i
specified formula in Specification 3.2.2 in order to maintain these margins when MFLPD is > to FRTP.
3.
Reactor Vessel Steam Dome Pressure-High l
High pressure in the nuclear system could cause a rupture to the nuclear
)
j system process barrier resulting in the release of fission products.
A pres-sure increase while operating will also tend to increase the power of the reactor by compressing voids thus adding reactivity.
The trip will quickly reduce the neutron flux, counteracting the pressure increase.
The trip set-i ting is slightly higher than the operating pressure to permit normal operation without spurious trips.
The setting provides for a wide margin to the maximum allowable design pressure and takes into account the location of the pressure measurement compared to the highest pressure that occurs in the system during a transient.
This trip setpoint is effective at low power / flow conditions when the turbine stop valve closure trip is bypassed.
Fcr a turbine trip under these conditions, the transient analysis indicated an adequate margin to the thermal hydraulic limit.
GRAND GULF-UNIT 1
' 8 2-7
-.m
-.---.--_,--r-.._
v.-.-
m,_
~
...--..-...---,.e,
,n
,, - - -..,, _., - - ~ _ -, - - -,.. - -, - -,.
e r
LIMITING SAFETY SYSTEM SETTINGS BASES REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS (Continued) 4.
Reactor Vessel Water Level-Low The reactor vessel water level trip setpoint was chosen far enough below the normal operating level to avoid spurious trips but high enough above the fuel to assure that there is adequate protection for the fuel and pressure limits.
5.
Reactor Vessel Water Level-High A reactor scram from high reactor water level, approximately two feet above normal operating level, is intended to offset the addition of reactivity effect associated with the introduction of a significant amount of relatively cold feedwater.
An excess of feedwater entering the vessel would be detected by the level increase in a timely manner.
This scram feature is only effective when the reactor mode switch is in the Run position because at THERMAL POWER levels below 10% to 15% of RATED THERMAL POWER, the approximate range of power level for changing to the Run position, the safety margins are more than adequate without a reactor scram.
6.
Main Steam Line Isolation Valve-Closure The main steam line isolation valve closure trip was provided to limit the amount of fission product release for certain postulated events.
The MSIV's are closed automatically from measured parameters such as high steam flow, high steam line radiation, low reactor water level, high steam tunnel temperature and low steam line pressure.
The MSIV's closure scram anticipates the pressure and flux transients which could follow MSIV closure and thereby protects reactor vessel pressure and fuel thermal / hydraulic Safety Limits.
7.
Main Steam Line Radiation-High The main steam line radiation detectors are provided to detect a gross failure of the fuel cladding.
When the high radiation is detected, a trip is initiated to reduce the continued failure of fuel cladding.
At the same time the main steam line isolation valves are closed to limit the release of fission products.
The trip setting is high enough above background radiation levels to prevent spurious trips yet low enough to promptly detect gross failures in the fuel cladding.
8.
Drywell Pressure-High High pressure in the drywell could indicate a break in the primary pressure boundary systems.
The reactor is tripped in order to minimize the possibility of fuel damage and reduce the amount of energy being added to the coolant.
The trip setting was selected as low as possible without causing spurious trips.
Negative barometric pressure fluctuations are accounted for in the trip setpoints and allowable values specified for drywell pressure-high.
GRAND GULF-UNIT 1 B 2-8 Order l
- APR 1 g ;934
INSTRUMENTATION 3/4.3.2 ISOLATION ACTUATION INSTRUMENTATION LIMITING CONDITION FOR OPERATION s
3.3.2 The isolation actuation instrumentation channels shown in Table 3.3.2-1 shall be OPERABLE with their trip setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.3.2-2 and with ISOLATION SYSTEM RESPONSE TIME as shown in Table 3.3.2-3.
APPLICABILITY:
As shown in Table 3.3.2-1.
ACTION:
a.
With an isolation actuation instrumentation channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.3.2-2, declare the channel inoperable until the channel is restored to OPERABLE status with its trip setpoint adjusted consistent with the Trip Setpoint value.
b.
With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip System requirement for one trip system, place that trip system in the tripped condition
- within one hour.
The provisions of Specification 3.0.4 are not applicable.
c.
With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip System requirement for both trip systems, place at least one trip system ** in the tripped condition within one hour and take the ACTION required by Table 3.3.2-1.
SURVEILLANCE REQUIREMENTS 4.3.2.1 Each isolation actuation instrumentation chan.iel shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations i'or the OPERATIONAL CONDITIONS and at the frequencies shown in Table 4.3.2.1-1.
4.3.2.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic operation of all channels shall be performed at least once per 18 months.
4.3.2.3 The ISOLATION SYSTEM RESPONSE TIME of each isolation trip function shown in Table 3.3.2-3 shall be demonstrated to be within its limit at least once per 18 months.
Each test shall include at least one channel per trip system such that all channels are tested at least once every N times 18 months, where N is the total number of redundant channels in a specific isolation trip system.
- With a design providing only one channel per trip system, an inoperable channel need not be placed in the tripped condition where this would cause the Trip Function to occur.
In these cases, the inoperable channel shall be restored to OPERABLE status within.2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or the ACTION required by Table 3.3.2-1 for that Trip Function shall be taken.
- Tf more channels are inoperable in one trip system than in the other, place the trip system with more inoperable channels in the tripped condition, except when this would cause the Trip Function to occur.
GRAND GULF-UNIT 1 3/4 3-9
TABLE 3.3.2-1 o
5g ISOLATION ACTUATION INSTRUMENTATION oc VALVE GROUPS MINIMUM APPLICABLE h
OPERATED BY OPERABLE CHANNELS OPERATIONAL g
TRIP FUNCTION SIGNAL (a) PER TRIP SYSTEM (b)
CONDITION ACTION U
1.
PRIMARY CONTAINMENT ISOLATION a.
Reactor Vessel Water Level-Low Low, Level 2 6A, 7, 8, 10(c)(d) 2 1, 2, 3 and #
20 b.
Reactor Vessel Water Level-Low Low Level 2 (ECCS -
Division 3) 6B 4
1, 2, 3 and #
29 c.
Reactor Vessel Water Level-Low Low Low, Level 1 (ECCS -
Division 1 and Division 2) 5(")
2 1, 2, 3 and #
29 d.
Drywell Pressure - High 6A, 7(C)( )
{
2 1,2,3 20 y
e.
Drywell Pressure-liigh (ECCS - Division 1 and Division 2)
S(")
2 1,2,3 29 f.
Drywell Pressure-High (ECCS - Division 3) 6B 4
1,2,3 29 g.
Containment and Drywell Ventilation Exhaust Radiation - High High 7
2(U) 1, 2, 3 and
- 21 h.
Manual Initiation 6A, 7, 8, 10(c)(d) 2 1, 2, 3 and *#
22 2.
MAIN STEAM LINE ISOLATION a.
Reactor Vessel Water Level-Low Low Low, Level 1 1
2 1,2,3 20 b.
Radiation - High 1, 10(#)
2 1,2,3 23 o o c.
Pressure - Low 1
2 1
24 S
d.
~
Flow - High 1
8 1,2,3 23 l
G3 e.
Condenser Vacuum - Low 1
2 1,
2,** 3**
23
O O
~
n TABLE 3.3.2-1 (Continued) 5 5
ISOLATION ACTUATION INSTRUMENTATION h
VALVE GROUPS MINIMUM APPLICABLE T
OPERATED BY OPERABLE CHANNELS OPERATIONAL i
g TRIP FUNCTION SIGNAL (a) PER TRIP SYSTEM (b)
CONDITION ACTION C
2.
MAIN STEAM LINE ISOLATION (Continued) g f.
Main Steam Line Tunnel Temperature - High 1
2 1,2,3 23 g.
Main Steam Line Tunnel A Temp.- High 1
2 1,2,3 23 h.
Manual Initiation 1, 10 2
1,2,3 22 3.
SECONDARY CONTAINMENT ISOLATION a.
Reactor Vessel Water y
Level-Low Low, Level 2 N.A.(c)(d)(h) 2 1, 2, 3, and #
25 j
[
b.
Drywell Pressure - High N.A.(c)(d)(h) 2 1,2,3 25 c.
Fuel Handling Area N.A.II) 2 1, 2, 3, and
- 25 h
Ventilation Exhaust Radiation - High High d.
Fuel Handling Area Pool Sweep Exhaust Radiation - High High N.A.(3) 2 1, 2, 3, and
- 25 e.
Manual Initiation 2
1,2,3 g
4.
REACTOR WATER CLEANUP SYSTEM ISOLATION
[
a.
A Flow - High 8
1 1,2,3 27 l
b.
A Flow Timer 8
1 1,2,3 27 c.
Equipment Area Temperature -
8 1/ room 1s 2, 3 27 l
l
?
High
.m d.
Equipment Area a Temp. -
a High 8
1/ room 1, 2, 3 27 I
e.
Reactor Vessel Water Level - Low Low, Level 2 8
2 1,2,3 27
TABLE 3.3.2-1 (Continued) a
$g ISOLATION ACTUATION INSTRUMENTATION O
VALVE GROUPS MINIMUM APPLICABLE 5
OPERATED BY OPERABLE CilANNELS OPERATIONAL h
TRIP FUNCTION SIGNAL (a) PER TRIP SYSTEM (b)
CONDITION ACTION 4.
REACTOR WATER CLEANUP SYSTEM ISOLATION (Continued) f.
Main Steam Line Tunnel 8
1 1,2,3 27 Ambient Temperature - liigh g.
Main Steam Line Tunnel A Temp. - liigh 8
1 1,2,3 27 h.
SLCS Initiation 8(i) 1 1, 2, 5##
30 i.
Manual Initiation 8
2 1,2,3 26 w
5.
REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION D
w a.
RCIC Steam Line Flow - High 4
1 1,2,3 27 s-*
b.
RCIC Steam Supply g)
Pressure - Low 4, 9 1
1,2,3 27 c.
RCIC Turbine Exhaust Diaphragm Pressure - High 4
2 1,2,3 27 d.
RCIC Equipment Room Ambient Temperature - High 4
1 1,2,3 27 e.
RCIC Equipment Room A Temp.
- High 4
1 1,2,3 27 f.
Main Steam Line Tunnel Ambient Temperature - High 4 1
1,2,3 27 2=.3 o
g.
Main Steam Line Tunnel d
A Temp. - High 4
1 1,2,3 27 D
-5 h.
Main Steam Line Tunnel Temperature Timer 4
1 1,2,3 27
- s TABLE 3.3.2-1 (Continued)
~-
S ISOLATION ACTUATION INSTRUMENTATION VALVE GROUPS MINIMUM APPLICABLE G;
OPERATED BY OPERABLE CHANNELS OPERATIONAL i
a TRIP FUNCTION SIGNAL (a) PER TRIP SYSTEM (b)
CONDITION ACTION H
S.
REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION w
i.
RHR Equipment Room Ambient Temperature - liigh 4
1/ room 1, 2, 3 27 j.
RHR Equipment Room A Temp. -
High 4
1/ room 1, 2, 3 27 k.
RHR/RCIC Steam Line Flow -
liigh 4
1 1,2,3 27
$g 1.
Manual Initiation 4(k) 1 1,2,3 26 m.
Drywell Pressure-liigh 9(*)
1 1,2,3 27 (ECCS-Division 1 and w
Division 2) 6.
RHR SYSTEM ISOLATION 4
l a.
RHR Equipment Room Ambient Temperature - Hi h 3
1/ room 1, 2, 3 28 0
i b.
RHR Equipment Room A Temp. - High 3
1/ room 1, 2, 3 28 c.
Reactor Vessel Water k
Level - Low, Level 3 3
2 1,2,3 28 o
I d.
Reactor Vessel (RHR Cut-in s,
Permissive) Pressure -
High 3(j) 2 1,2,3 28 2
II) e.
Drywell Pressure - High 3
2 1,2,3 28 f.
Manual Initiation 3
2 1,2,3 26
INSTRUMENTATION TABLE 3.3.2-1 (Continued)
ISOLATION ACTUATION INSTRUMENTATION ACTION ACTION 20 -
Be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
ACTION 21 -
Close the affected system isolation valve (s) within one hour or:
a.
In OPERATIONAL CONDITION 1, 2, or 3, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, b.
In Operational Condition *, suspend CORE ALTERATIONS, handling of irradiated fuel in the primary containment and operations with a potential f.or draining the reactor vessel.
ACTION 22 -
Restore the manual initiation function to OPERABLE status within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
ACTION 23 -
Be in at least STARTUP with the associated isolation valves closed within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> or be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
ACTION 24 -
Be in at least STARTUP within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
ACTION 25 -
Establish SECONDARY CONTAINMENT INTEGRITY with the standby gas treatment system operating within one hour.
ACTION 25 Restore tne manual initiation function to OPERABLE status within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> or close the affected system isolation valves within the next hour and declare the affected system inoperable.
ACTION 27 Close the affected syscem isolation valves within one hour and declare the affected system inoperable.
ACTION 28 -
Lock the affected system isolation valves closed within one hour and declare the affected system inoperable.
ACTION 29 -
Close the affected system isolation valves within one hour and declare the affected system or component inoperable or:
a.
In OPERATIONAL CONDITION 1, 2 or 3 be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
b.
In OPERATIONAL CONDITION # suspend CORE ALTERATIONS and opera-tions with a potential for draining the reactor vessel.
ACTION 30 Declare the affected SLCS pump inoperable.
l NOTES When handling irradiated fuel in the primary or secondary containment and during CORE ALTERATIONS and operations with a potential for draining the reactor vessel.
The low condenser vacuum MSIV closure may be manually bypassed during reactor SHUTDOWN or for reactor STARTUP when condenser vacuum is below the trip setpoint to allow opening of the MSIVs.
The manual bypass shall be removed when condenser vacuum exceeds the trip setpoint.
During CORE ALTERATIONS and operations with a potential for draining the reactor vessel.
With any control rod withdrawn.
Not applicable to control rods removed per Speci fication 3. 9.10.1 or 3. 9.10. 2.
(a) See Specification 3.6.4, Table 3.6.4-1 for valves in each valve group.
(b) A channel may be placed in an inoperable status for up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> for required surveillance without placing the trip system in the tripped con-dition provided at least one other OPERABLE channel in the same trip system is monitoring that parameter.
O GRAND GULF-UNIT 1 3/4 3-14 Order APR I p 1984
INSTRUMENTATION TABLE 3.3.2-1 (Continued)
ISOLATION ACTUATION INSTRUMENTATION NOTES (Continued)
(c) Also actuates the standby gas treatment system.
(d) Also actuates the control room emergency filtration system in the isolation mode of operation.
(e) Two upscale-Hi Hi, one upscale-Hi Hi and one downscale, or two downscale signals from the same trip system actuate the trip system and initiate isolation of the associated containment and drywell isolation valves.
(f) Also trips and isolates the mechanical vacuum pumps.
(g) Deleted.
f (h) Also actuates secondary containment ventilation isolation dampers and 4
valves per Table 3.6.6.2-1.
(i) Closes only RWCU system isolation valves G33-F001, G33-F004, and G33-F251.
(j) Actuates the Standby Gas Treatment System and isolates Auxiliary Building penetration of the ventilation systems within the Auxiliary Building.
(k) Closes only RCIC outboard valves.
A concurrent RCIC initiation signal is required for isolation to occur.
(1) Valves E12-F037A and E12-F0378 are closed by high drywell pressure.
All i
other Group 3 valves are closed by high reactor pressure.
(m) Valve Group 9 requires concurrent drywell high pressure and RCIC Steam Supply Pressure-Low signals to isolate.
(n) Valves E12-F042A and E12-F042B are closed by Containment Spray System i
i initiation signals.
O V
GRAND GULF-UNIT 1 3/4 3-14a Order I
' APR f 8 1984
T BLE 3.3.2-2 h'
ISOLATION ACTUATION INSTRUMENTATION SETPOINTS 5
c)
ALLOWABLE
(
TRIP FUNCTION TRIP SETPOINT VALUE l
yj 1.
PRIMARY CONTAINMENT ISOLATION U
a.
s Low Low, Level 2 1 -41.6 inches
- 1 -43.8 inches i
1 b.
Reactor Vessel Water Level-1 -41.6 inches
- 1 -43.8 inches Low Low, Level 2 (ECCS -
Division 3) 4 d
c.
Reactor Vessel Water Level-
> -150.3 inches
- 1 -152.5 inches Low Low Low, Level 1 (ECCS Division 1 and Division 2) us d.
Drywell Pressure - High 1 1.23 psig i 1.43 psig us e.
Drywell Pressure-High (ECCS -
1 1.39 psig i 1.44 psig O
Division 1 and Division 2) 4 ui i
f.
Drywell Pressure-High (ECCS -
5 1.39 psig 1 1.44 psig Division 3) i
{
g.
Containment and Drywell Ventilation Exhaust Radiation - High High 1 2. 0 mr/hr**
1 4.0 mr/hr**
h.
Manual Initiation NA NA 4
{
2.
MAIN STEAM LINE ISOLATION i
a.
j Low Low Low, Level 1 1 -150.3 inches
- 1 -152.5 inches l
b.
Main Steam Line Radiation - High 5 3.0 x full power 5 3.6 x full power background background 4
c.
Main Steam Line Pressure - Low 1 849 psig 1 837 psig fl {
d.
Main Steam Line Flow - High 5 169 psid 1 176.5 psid E
e.
Condenser Vacuum. Low 1 9 inches Hg. Vacuum 1 8.7 inches Hg. Vacuum f.
Main Steam Line Tunnel Temperature - High 5 185*F**
1 191*F**
- 53 h
i
-l
TABLE 3.3.2-2 (Continued)
Sy ISOLATION ACTUATION INSTRUMENTATION SETPOINTS o
E ALLOWABLE T
TRIP FUNCTION TRIP SETPOINT VALUE E
Z 2.
MAIN STEAM LINE ISOLATION (Continued) g.
Main Steam Line Tunnel A Te.np. - High 5 101 F^*
$ 104 F**
h.
Manual Initiation NA NA 3.
SECONDARY CONTAINMENT ISOLATION a.
Low Low, Level 2 1 -41.6 inches
- 1 -43.8 inches b.
Drywell Pressure - liigh 5 1.23 psig
< 1.43 psig c.
Fuel Handling Area Ventilation R'
Exhaust Radition - High liigh 5 2.0 mR/hr**
< 4.0 mR/hr**
a d.
Fuel Handling Area Pool Sweep w
4 Exhaust Radiation - High High 5 18 mR/hr**
< 35 mR/hr**
cn e.
Manual Initiation NA NA 4.
REACTOR WATER CLEANUP SYSTEM ISOLATION a.
A Flow - High 5 79 gpm 5 89** gpm b.
A Flow Timer 5 45 seconds 5 57 seconds c.
Equipment Area Temperature - High 1.
RWCU Hx Room
< 120 F
< 126 F 2.
RWCU Pump Rooms 5170F 5176F 3.
RWCU Valve Nest Room
< 135 F
< 141 F 4.
RWCU Demin. Rooms 5139F 5145F 5.
RWCU Rec. Tank Room
< 139 F
< 145 F 6.
RWCU Demin. Valve Room 5135F 5141F d.
Equipment Area A Temp. - High
~%o 1.
RWCU Hx Room 5 65 F
< 66 F 2 2 2.
RWCU Pump Rooms 5 115 F 5 118 F
-y 3.
RWCU Valve Nest Room 5 70 F 5 73 F oo 4.
RWCU Demin. Rooms
< 70 F
< 73 F 5.
RWCU Rec. Tank Room 2 70 F 7 73 F
-y 6.
RWCU Demin. Valve Room 5 71 F 574F
i TABLE 3 3."2-2 (Continued) c)
y ISOLATION ACTUATION INSTRUMENTATION SETPOINTS 1
ALLOWABLE TRIP FUNCTION TRIP SETPOINT VALUE 4;
j 4.
REACTOR WATER CLEANUP SYSTEM ISOLATION (Continued)
Z e.
Reactor Vessel Water Level - Low Low, s
Level 2 1 -41.6 inches
- 1 -43.8 inches f.
Main Steam Line Tunnel Ambient Temperature - High 5 185 F**
5 191*F**
g.
Main Steam Line Tunnel A Temp. - High 5 101 F**
1 104*F**
h.
SLCS Initiation NA NA 1
i.
Manual Initiation NA NA 5.
REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION a.
RCIC Steam Line Flow - High 5 363" H O
$ 371" H O 2
2 y
RCIC Steam Supply Pressure - Low 1 60 psig 1 53 psig b.
0 c.
RCIC Turbine Exhaust Diaphragm Pressure - High 1 10 psig 5 20 psig I
d.
RCIC Equipment Room Ambient Temperature - High 1 185 F**
1 191 F**
e.
RCIC Equipment Room A Temp. - High 5 125 F**
1 128 F**
f.
Main Steam Line Tunnel Ambient Temperature - High 5 185 F**
5 191 F**
g.
Main Steam Line Tunnel A Temp. - High 1 101 F**
1 104 F**
h.
Main Steam Line Tunnel Temperature Timer 1 30 minutes 5 30 minutes i.
RHR Equipment Room Ambient Temperature -
,g High 5 165 F**
1 171 F**
,o j.
RHR Equipment Room A Temperature -
2 High 5 99 F**
1 102 F**
k.
RHR/RCIC Steam Line Flow - High 5 145" H O 5 160" H O I
2 2
f) p
/
TABLE 3.3.2-2 (Continued)
ISOLATION ACTUATION INSTRUMENTATION SETPOINTS ALLOWABLE TRIP FUNCTION TRIP SETPOINT VALUE 9
cE 5.
REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION (Continued) 3 H
1.
Manual Initiation NA NA ea m.
Drywell Pressure-High (ECCS Division 1 5 1.39 psig i 1.44 psig and Division 2) 6.
RHR SYSTEM ISOLATION a.
RHR Equipment Room Ambient Temperature -
High 5 165*F**
1 171 F**
b.
RHR Equipment Room A Temperature - High 1 99 F**
5 102 F**
w A
w c.
Reactor Vessel Water Level - Low, Level 3
> 11.4 inches *
> 10.8 inches Oj d.
Reactor Vessel (RHR Cut-in Permissive)
Pressure - High 5 135 psig 5 150 psig e.
Drywell Pressure - High 1 1.23 psig 5 1.43 psig l
f.
Manual Initiation NA NA
..N?
- o a.
n y
See Bases Figure B 3/4 3-1.
Initial setpoint.
Final setpoint to be determined during startup test program.
Any required change to g
this setpoint shall be submitted to the Commission within 90 days of test completion.
E j
J INSTRUMENTATION 1
j
, ('
TABLE 3.3.2-3 (Continued) m l
ISOLATION SYSTEM INSTRUMENTATION RESPONSE TIME RESPONSE TIME (Seconds)#
, TRIP FUNCTION 5.
REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION a.
RCIC Steam Line Flow - High
< 13(a) M b.
RCIC Steam Supply Pressure - Low 313(a) c.
RCIC Turbine Exhaust Diaphragm Pressure - High NA d.
RCIC Equipment Room Ambient Temperature - High NA e.
. RCIC Equipment Room A Temp. - High NA f.
Main Steam Line Tunnel Ambient Temp. - High NA g.
Main Steam Line Tunnel A Temp. - High NA h.
Main Steam Line Tunnel Temperature Timer NA i.
RHR Equipment Room Ambient Temperature - High NA j.
RHR Equipment Room a Temp. - High NA l
k.
RHR/RCIC Steam Line Flow - High NA 1.
Manual Initiation NA m.
Drywell Pressure - High (ECCS Division 1 and Division 2) i 13(,)
l 6.
RHR SYSTEM ISOLATION i
a.
RHR Equipment Room Ambient Temperature - High NA J
b.
RHR Equipment Room A Temp. - High NA c.
Reactor Vessel Water Level - Low, level 3 1 13(,)
d.
Reactor Vessel (RHR Cut-in Permissive)
Pressure - High NA e.
Drywell Pressure - High NA f.
Manual Initiation NA 1
(a) The isol tion system instrumentation response time shall be measured and recorded as a part of the ISOLATION SYSTEM RESPONSE TIME.
Isolation system instrumentation response time specified includes the delay for diesel i
generator starting assumed in the accident analysis.
(b) Radiation detectors are exempt from response time testing.
Response time 1
j shall be measured from detector output or the input of the first electronic component in the channel.
- Isolation system instrumentation response time for MSIVs only.
No diesel generator delays assumed.
l
- Isolation system instrumentation response time for associated valves except~MSIVs.
l
- Isolation system instrumentation response time specified for the Trip Function actuating each valve group shall be added to isolation time shown in Tables 3.6.4-1 and 3.6.5.2-1 for valves in each valve group to obtain ISOLATION SYSTEM RESPONSE TIME for each valve.
~###Without 13 second time delay.
l l
GRAND GULF-UNIT 1 3/4 3-19 Amendment No. 7, 9
. _ _ _.. _ _. - -, _ _ - _ _. _ - _ _. - -. - -, _. ~ _
s TABLE 4.3.2.1-1 O
g ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS O
CHANNEL OPERATIONAL Q
CHANNEL FUNCTIONAL CHANNEL CONDITIONS IN WHICH ch TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED 5
1.
PRIMARY CONTAINMENT ISOLATION a.
Low Low, Level 2 S
M R(c) 1, 2, 3 and #
b.
Reactor Vessel Water Level-S M
R(c) 1, 2, 3 and #
Low Low, Level 2 (ECCS -
Division 3) c.
Reactor Vessel Water Level-S M
R(c) 1, 2, 3 and #
Low Low Low, Level 1 (ECCS -
Division 1 and Division 2) d.
Drywell Pressure - High S
M R(c) 1, 2, 3 c)
Y e.
Drywell Pressure-High (ECCS -
S M
R 1, 2, 3 Division 1 and Division 2) f.
Drywell Pressure-High (ECCS -
S M
R(c) 1, 2, 3 Division 3) g.
Containment and Drywell Ventilation Exhaust Radiation - High High S
M A
1, 2, 3 and
- h.
Manual Initiation NA M("}
NA 1, 2, 3 and *#
2.
MAIN STEAM LINE ISOLATION a.
Low Low Low, Level 1 S
M R(c) 1, 2, 3 b.
Main Steam Line Radiation -
High S
M R
1,2,3 o o1 c.
Main Steam Line Pressure -
g y
Low S
M R
1 m
IC) g d.
Main Steam Line Flow - High S
M R
1, 2, 3 E
e.
Condenser Vacuum - Low S
M R(c) 1, 2**,
__e C\\
O V
V TABLE 4.3.2.1-1 (Continued)
L
- 55 ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS l
G CHANNEL OPERATIONAL ch CHANNEL FUNCTIONAL CHANNEL CONDITIONS IN WHICH
{
TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED g
2.
MAIN STEAM LINE ISOLATION (Continued) f.
Main Steam Line Tunnel Temperature - High S
M A
1,2,3 g.
Main Steam Line Tunnel A Temp. - High S
M A
1,2,3 h.
Manual Initiation NA M(a)
NA 1,2,3 3.
SECONDARY CONTAINMENT ISOLATION R
a.
Reactor Vessel Water Level - Low Low, Level 2 S
M R(c) 1, 2, 3 and #
b.
Drywell Pressure - High S
M R(c) 1,2,3 c.
Fuel Handling Area Ventilation j
Exhaust Radiation - High High S M
A 1, 2, 3 and
- d.
Fuel Handling Area Pool Sweep Exhaust Radiation - High High 5 M
A Il 2, 3 and
- e.
Manual Initiation NA M(a)
NA 1, 2, 3 and
- 4.
REACTOR WATER CLEANUP SYSTEM ISOLATION a.
A Flow - High S
M R
1,2,3 b.
A Flow Timer NA M
Q 1, 2, 3 c.
Equipment Area Temperature -
High S
M A
1,2,3 h?
d.
Equipment Area Ventilation g
a Temp. - High S
M A
1,2,3 4m e.
Reactor Vessel Water ig Level - Los Low, Level 2 S
M R(c) 1, 2, 3
- cn
.A l
TABLE 4.3.2.1-1 (Continued) a
$5 ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS 8
9 CilANNEL OPERATIONAL c'
CilANNEL FUNCTIONAL CHANNEL CONDITIONS IN WHICH
- {
TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED H
4.
REACTOR WATER CLEANUP SYSTEM ISOLATION (Continued) f.
Main Steam Line Tunnel Ambient Temperature - High S
M A
1,2,3 g.
Main Steam Line Tunnel A Temp. - High S
M A
1,2,3 h.
SLCS Initiation NA M(b)
NA 1, 2, 5##
i.
Manual Initiation NA M("}
NA 1,2,3 w
5.
REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION a.
RCIC Steam Line Flow - High S
M R(c) 1, 2, 3 b.
RCIC Steam Supply Pressure -
Low S
M R(c) 1,2,3 c.
RCIC Turbine Exhaust Oiaphragm g)
Pressure - High S
M R
1,2,3 d.
RCIC Equipment Room Ambient Temperature - High S
M A
1,2,3 e.
RCIC Equipment Room A Temp. -
High S
M A
1,2,3 f.
Main Steam Line Tunnel Ambient Temperature - High S
M A
1,2,3 g.
Main Steam Line Tunnel h
A Temp. - High S
M A
1,2,3 a
4 w
m r \\
i D
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TABLE 4.3.2.1-1 (Continued) n 5
ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS 4
E c)
CHANNEL OPERATIONAL E
CHANNEL FUNCTIONAL CHANNEL CONDITIONS IN WHICH
[
TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED z
y 6.
RHR SYSTEM ISOLATION (Continued) e.
Drywell Pressure - High S
M R(c) 1, 2, 3 l
f.
Manual Initiation NA M,)
NA 1,2,3 i
j
- When handling. irradiated fuel in the primary or secondary containment and during CORE ALTERATIONS and operations with a potential for draining the reactor vessel.
The manual bypass t
u>
30 shall be removed when condenser vacuum exceeds the trip setpoint.
- 0uring CORE ALTERATION and operations with a potential for draining the reactor vessel.
ua E
- With any control rod withdrawn.
Not applicable to control rods removed per Specification 3.9.10.1 S'
or 3.9.10.2.
(a) Manual initiation switches shall be tested at least once per 18 months during shutdown.
All other circuitry associated with manual initiation shall receive a CHANNEL FUNCTIONAL TEST at least once per 31 days as part of circuitry required to be tested for automatic system isolation.
3 (b) Each train or logic channel shall be tested at least every other 31 days.
j (c) Calibrate trip unit at least once per 31 days.
I I
a
- '" a Q3 1 g hE I
?
1
l s
O
~
TABLE 3.3.3-1 O
E EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION c
MINIMUM OPERABLE APPLICABLE G;
CHANNELS PER OPERATIONAL g)
E TRIP FUNCTION TRIP FUNCTION CONDITIONS ACTION t
3*
A.
DIVISION I TRIP SYSTEM H
1.
RHR-A (LPCI MODE) & LPCS SYSTEM a.
Reactor Vessel Water Level - Low Low Low, Level 1 2
1, 2, 3, 4*, 5*
30 b.
Drywell Pressure - High 2
1,2,3 30 c.
LPCI Pump A Start Time Delay Relay 1
1, 2, 3, 4*, 5*
31 d.
Manual Initiation 1/ system 1, 2, 3, 4*, 5*
32 2.
AUTOMATIC DEPRESSURIZATION SYSTEM TRIP SYSTEM "A"#
a.
Reactor Vessel Water Level - Low Low Low, Level 1 2
1,2,3 30 b.
Drywell Pressure - High 2
1,2,3 30 c.
ADS Timer 1
1,2,3 31 w
i
)
d.
Reactor Vessel Water Level - Low, Level 3 (Permissive) 1 1,2,3 31 e.
LPCS Pump Discharge Pressure-High (Permissive) 2 1,2,3 31 w
d 4
f.
LPCI Pump A Discharge Pressure-High (Permissive) 2 1,2,3 31 m
)
g.
Manual Initiation 2/ system 1,2,3 32 l
B.
DIVISION 2 TRIP SYSTEM 1.
Reactor Vessel Water Level - Low, Low Low, Level 1 2
1, 2, 3, 4*, 5*
30 b.
Drywell Pressure - High 2
1,2,3 30 9
J c.
LPCI Pump B Start Time Delay Relay 1
1, 2, 3, 4*, 5*
31 d.
Manual Initiation 1/ system 1, 2, 3, 4*, 5*
32 t
2.
AUTOMATIC DEPRESSURIZATION SYSTEM TRIP SYSTEM "B"#
1 a.
Reactor Vessel Water Level - Low Low Low, Level 1 2
1,2,3 30 i
b.
Drywell Pressure - High
,2 1,2,3 30
)
c.
ADS Timer 1
1,2,3 31
~
d.
Reactor Vessel Water Level - Low, Level 3 (Permissive) 1 1,2,3 31 e.
LPCI Pump B and C Discharge Pressure - High (Permissive) 2/ pump 1,2,3 31 f.
Manual Initiation 2/ system 1, 2, 3 32 l
o a
4 m
- m iE i
i
m l'ABLE 3.3.3-1 (Continued)
EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION g
MINIMUM OPERABLE APPLICABLE CHANNELS PER OPERATIONAL G;
TRIP FUNCTION (3) CONDITIONS ACTION J.
TRIP FUNCTION C.
DIVISION 3 TRIP SYSTEM 1.
IIPCS SYSTEM a.
Reactor Vessel Water Level - Low, Low, Level 2 4
1, 2, 3, 4*, 5*
33 b.
Drywell Pressure - liigh##
4(c) 1, 2, 3 33 c.
Reactor Vessel Water Level-liigh, Level 8 2(d) 1, 2, 3, 4 *, 5*
31 d.
Condensate Storage Tank Level-Low 2(d)
I', 2',
3, 4*, 5*
34 2
1 2 3,
4", 5*
34 Suppression Pool Water Level-liigh l
e.
f.
Manual Initiation ##
1/ system 1, 2, 3, 4*, 5*
32 D.
LOSS OF POWER 1.
Division 1 and 2
}
a.
4.16 kV Bus Undervoltage 4
1, 2, 3, 4**, 5**
30 m
(Loss of Voltage) g, b.
4.16 kV Bus Undervoltage 4
1, 2, 3, 4**, 5**
30 m
(B0P Load Shed) m c.
4.16 kV Bus Undervoltage 4
1, 2, 3, 4**, 5**
30 (Degraded Voltage) 2.
Division 3 a.
4.16 kV Bus Undervoltage 4
1, 2, 3, 4**, 5**
30 (Loss of Voltage)
(a) A channel may be placed in an inoperable status for up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> during periods of required surveillance without placing the trip system in the tripped condition provided at least one y
other OPERABLE channel in the same trip system is monitoring that parameter, g
g (b) Also actuates the associated division diesel generator.
g (c) Provides signal to close HPCS pump dischar9e valve only.
(d) Provides signal to llPCS pump suction valves only.
r' g'
(e) One out-of-two taken.
Applicable when the system is required to be OPERABLE per Specification 3.5.2 or 3.5.3.
Required when ESF equipment is required to be OPERABLE.
oo Not required to be OPERABLE when reactor steam dome pressure is less than or equal to 135 psig.
o Prior to STARTUP following the first refueling outage, the injection function of Drywell g
Pressure - High and Manual Initiation are not required to be OPERABLE with indicated reactor vessel water level on the wide range instr t greater than Level 8 setpoint coincident with the reactor pressure less than 600 psig.
' INSTRUMENTATION TABLE 3.3.3-1 (Continued) b
(
EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION ACTION ACTION 30 -
With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement:
a.
With one channel inoperable, place the inoperable channel in the tripped condition within one hour
- or declare the associated system (s) inoperable.
b.
With more than one channel inoperable, declare the associated system (s) inoperable.
ACTION 31 -
With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, declare the associated ADS trip system or ECCS inoperable.
a ACTION 32 -
With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, restore the inoperable channel to OPERABLE status within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> or declare the associated ADS trip system or ECCS inoperable.
l ACTION 33 -
With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement:
a.
For one trip system, place that trip system in the tripped condition within one hour
- or declare the HPCS system inoperable.
b.
For both trip systems, declare the HPCS system inoperable.
l ACTION 34 -
With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, place at least one inoperable channel in the tripped condition within one hour
- or declare the HPCS system inoperable.
- The provisions of Specification 3.0.4 are not applicable.
l 1
(
v GRAND GULF-UNIT 1 3/4 3-27 Order
'APR t g 1994
TABLE 3.3.3-2 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION SETP0INTS ALLOWABLE TRIP FUNCTION TRIP SETPOINT VALUE G;
A.
DIVISION 1 TRIP SYSTEM g
1.
RHR-A (LPCI MODE) AND LPCS SYSTEM Q
a.
Reactor Vessel Water Level - Low Low Low, Level 1
> -150.3 inches *
> -152.5 inches b.
Drywell Pressure - High 5 1.39 psig i 1.44 psig l
~
c.
LPCI Pump A Start Time Delay Relay
< 5 seconds
< 5.25 seconds d.
Manual Initiation SA NA 2.
AUTOMATIC DEPRESSURIZATION SYSTEM TRIP SYSTEM "A" a.
Reactor Vessel Water Level - Low Low Low, Level 1
> -150.3 inches *
> -152.5 inches b.
Drywell Pressure - High 31.39psig
{l.44psig l
c.
ADS Timer i 105 seconds i 117 seconds d.
Reactor Vessel Water Level-Low, Level 3
> 11.4 inches *
> 10.8 inches e.
LPCS Pump Discharge Pressure-liigh 145 psig, increasing 125-165 psig, increasing f.
LPCI Pump A Discharge Pressure-High 125 psig, increasing 115-135 psig, increasing R
g.
Manual Initiation NA NA
+
B.
DIVISION 2 TRIP SYSTEM w
1.
RilR B AND C (LPCI MODE) a.
Reactor Vessel Water Level - Low Low Low, Level 1
> -150.3 inches *
> -152.5 inches b.
Drywell Pressure - High 51.39psig 51.44psig l
c.
LPCI Pump B Start Time Delay Relay 5 5 seconds 5 5.25 seconds d.
Manual Initiation NA NA 2.
AUTOMATIC DEPRESSURIZATION SYSTEM TRIP SYSTEM "B" a.
Reactor Vessel Water Level - Low Low Low, Level 1
> -150.3 inches *
> -152.5 inches b.
Drywell Pressure - High
{1.39psig i1.44psig l
c.
ADS Timer 5 105 seconds i 117 seconds d.
Reactor Vessel Water Level-Low, Level 3
> 11.4 inches *
> 10.8 inches e.
LPCI Pump B and C Discharge Pressure-High 125 psig, increasing 115 psig, increasing f.
Manual Initiation NA NA C.
DIVISION 3 TRIP SYSTEM 1.
HPCS SYSTEM a.
Reactor Vessel Water Level - Low Low, Level 2
>-41.6 inches *
>-43.8 inches
- b. Drywell Pressure - High 51.39psig 51.44psig l
g a ga c.
Reactor Vessel Water Level - High, Level 8 5 53.5 inches
- 1 55.7 inches y
d.
Condensate Storage Tank Level - Low
> 0 inches
> -3 inches
[
e.
Suppression Pool Water Level - High y5.9 inches
}NA 6.5 inches f.
Manual Initiation NA G5 9
~ _ _
N i
i TABLE 3.3.3-2 (Continued)
EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION SETPOINTS oc ALLOWABLE G
TRIP FUNCTION TRIP SETPOINT VALUE c55 D.
LOSS OF POWER H
1.
Division 1 and 2 a.
4.16 kV Bus Undervoltage 1.
4.16 kV Basis 2912 +0, -291 volts (Loss of Voltage) 2912 volts 2.
120 volt Basis 83.2 +0,
-8.3 volts 83.2 volts 3.
Time Delay 0.5 +0.5, -0.1 seconds 0.5 seconds b.
4.16 kV Bus Undervoltage 1.
4.16 kV Basis 3328 +0, -167 volts l
(80P Load Shed) 3328 volts 2.
120 volt Basis 95.1 +0,
-4.8 volts D
95.1 volts l
w 3.
Time delay 0.5 +0.5, -0.1 seconds 0.5 seconds y
i c.
4.16 kV Bus Undervoltage 1.
4.16 kV Basis 3744 +93.6, -0 volts (Degraded Voltage) 3744 volts 2.
120 volt Basis 107 +2.7, -0 volts 107 volts 3.
Time Delay 9.0 1 0.5 seconds 9.0 seconds 2.
Division 3 a.
4.16 kV Bus Undervoltage 1.
4.16 kV Basis 3045 1 61 volts
' I $*
(Loss of Voltage) 3045 volts jE 2.
120 volt Basis 87 1 1.7 volts cr &
87 volts
- *J 3.
Time Delay 2.3 + 0.2, -0.3 seconds 2.3 seconds
~
5
~
"See Bases Figure B 3/4 3-1.
~8"
- These are inverse time delay voltage relays or instantaneous voltage relays with a time delay.
The voltages shown are the maximum that will not result in a trip.
Lower voltage conditions will result in decreased trip times.
TABLE 3.3.3-3 EMERGENCY CORE COOLING SYSTEM RESPONSE TIMES (SECONDS)
?
1.
LOW PRESSURE CORE SPRAY SYSTEM i 40 2.
LOW PRESSURE COOLANT INJECTION MODE OF RHR SYSTEM PUMPS A, 8 AND C 1 40 I
3.
AUTOMATIC DEPRESSURIZATION SYSTEM NA 4.
HIGH PRESSURE CORE SPRAY SYSTEM i 27 h
5.
LOSS OF POWER NA i
e i
I l
\\
l l
l 9
GRAND GULF-UNIT 1 3/4 3-30 Order APR ; g 1934
h
(
(
J
=
E TABLE 3.3.5-1 o
REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION Vi ch MINIMUM OPERABLECHANNEL{a)
H FUNCTIONAL UNITS PER TRIP SYSTEM ACTION w
a.
Reactor Vessel Water Level - Low Low, Level 2 4
50 b.
Reactor Vessel Water Level - High, Level 8 2(b) 51 c.
Condensate Storage Tank Water Level - Low 2(C) 52 d.
Suppression Pool Water Level - High 2(c) 52 w
e.
Manual Initiation 1/ system (d) 53 h
Y (a) A channel may be placed in an inoperable status for up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> for required surveillance without placing the trip system in the tripped condition provided at least one other OPERABLE channel in the same trip system is monitoring that parameter.
(b) One trip system with two-out-of-two logic.
(c) One trip system with one-out-of-two logic.
l (d) One trip system with one channel.
l i
a M
'5
INSTRUMENTATION TABLE 3.3.5-1 (Continued)
REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION ACTION 50 -
With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip System requirement for one trip system, place the inoperable channel (s) or that trip system in the tripped condition within one hour or declare the RCIC system inoperable.
ACTION 51 -
With the number of OPERABLE channels less than required by the minimum OPERABLE channels per Trip System requirement, declare the RCIC system inoperable.
ACTION 52 -
With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip System requirement, place at least one inoperable channel in the tripped condition within one hour or declare the RCIC system inoperable.
ACTION 53 -
With the number of OPERABLE channels less than required by the l
Minimum OPERABLE Channels per Trip System requirement, restore the inoperable channel to OPERABLE status within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> or declare the RCIC system inoperable.
1 0
l I
l l
9 GRAND GULF-UNIT 1 3/4 3-46 Order APR I 8 1984
1 INSTRUMENTATION f
3/4.3.7 MONITORING INSTRUMENTATION
\\
RADIATION MONITORING INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.7.1 The radiation monitoring instrumentation channels shown in Table 3.3.7.1-1 shall be OPERABLE with their alarm / trip setpoints within the specified limits.
APPLICABILITY:
As shown in Table 3.3.7.1-1.
ACTION:
a.
With a radiation monitoring instrumentation channel alarm / trip setpoint exceeding the value shown in Table 3.3.7.1-1, adjust the setpoint to within the limit within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or declare the channel inoperable.
b.
With one or more radiation monitoring channels inoperable, take the ACTION required by Table 3.3.7.1-1.
t c.
The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.
O SURVEILLANCE REQUIREMENTS 4.3.7.1 Each of the above required radiation monitoring instrumentation channels shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations for the conditions and at the frequencies shown in Table 4.3.7.1-1.
,o GRAND GULF-UNIT 1 3/4 3-55
- I
TABLE 3.3.7.1-1 h
RA01ATION MONITORING INSTRUMENTATION 5
c)
MINIMUM CHANNELS APPLICABLE ALARM / TRIP MEASUREMENT
(
INSTRUMENTATION OPERABLE CONDITIONS SETFOINT RANGE ACTION cb 1.
Component Cooling 5
Water Radiation 5
0 Monitor 1
At all times 51 x 10 cpm /NA 10 to 10 cpm 70 2.
Standby Service Water System Radiation 5
6 Monitor 1/ heat 1, 2, 3, and* $1 x 10 cpm /NA 10 to 10 cpm 70 exchanger train 3.
Offgas Pre-treatment 3
6 Radiation Monitor 1
1, 2 55 x 10 mR/hr/NA 1 to 10 mR/hr 70 4.
Offgas Post-treatment I) 5 6
R Radiation Monitor 2
1, 2 51 x 10 cpm (Ili),
10 to 10 cpm 71 6
11.0 x 10 cpm (Hi Ili Hi) w 5.
Carbon Bed Vault 6
Radiation Monitor 1
1, 2 5 2 x full power 1 to 10 mR/hr 72 background /NA 6.
Control Room Ventila-2/ trip (h)
-2 2
l tion Radiation Monitor system 1,2,3,5 and**
$4 mR/hr/
10 to 10 mR/hr 73 l
<5 mR/hr#
7.
Containment and Drywell Ventilation Exhaust 2/ trip (h)
-2 2
Radiation Monitor system At all times 12.0 mR/hr/
10 to 10 mR/hr 74
<4 mR/hr(b)#
8.
Fuel Handling Area
-2 s
Ventilation Exhaust 2/ trip (h) 1,2,3,5 and**
-<2mR/hr{d)#
10 to 10 mR/hr 75
${
Radiation Monitor system 4 mR/hr y
9.
Fuel Handling Area Pool
~
Sweep Exhaust Radiation 2/ trip
)
-2 2
g Monitor system (c) 5 18 mR/hr/
10 to 10 mR/hr 75 E
$35 mR/hr(d)#
O O
O
I
\\
l i
i
' TABLE 3.3.7.1-1 (Continued) c, s
RADIATION MONITORING INSTRUMENTATION 5
MINIMUM CHANNELS APPLICABLE ALARM / TRIP MEASUREMENT c3 E
INSTRUMENTATION OPERABLE CONDITIONS SETPOINT RANGE ACTION-T
.E 10.
Area Monitors y
a.
Fuel Handling Area Monitors j
~2 3
1)
New Fuel 1
(e) 12.5 mR/hr/NA 10 to 10 mR/hr 72 Storage Vault
-2 2)
Spent Fuel 1
(f) 52.5 mR/hr/NA 10 to 10 mR/hr 72 Storage Pool 4
-2 3
^3)
. Dryer Storage Area (g) 12.5 mR/hr/NA 10 to 10 mR/hr 72
-2 3
t' b.
Control Room 1
At all times 50.5 mR/hr/NA 10 to 10 mR/hr 72 Radiation Monitor Y
With RHR heat exchangers in operation.
^
When irradiated fuel is being handled in the primary or secondary containment.'
- Initial setpoint.
Final Setpoint to be determined during startup test program.
Any required change to this setpoint shall be submitted to Commission within 90 days after test completion.
(a) Trips system with 2 channels upscale-Hi Hl.Hi, or one channel upscale Hi Hi Hi and one channel downscale or 2 channels downscale.
(b) Isolates containment /drywell purge penetrations.
j (c) With irradiated fuel in spent fuel storage pool.
j (d) Also isolates the Auxiliary Building and fuel Handling Area Ventilation Systems.
l l
2 (e) With fuel in the new fuel storage vault.
I R
(f) With fuel in the spent fuel storage pool.
2 (g) With fuel in the dryer storage area.
f, (h) Two upscale Hi Hi, one upscale Hi Hi and one downscale, or two downscale signals from the same trip j
system actuate the trip system and. initiate isolation of the associated isolation values.
'o
=
i 1
INSTRUMENTATION TABLE 3.3.7.1-1 (Continued)
RADIATION MONITORING INSTRUMENTATION ACTION ACTION 70 -
With the required monitor inoperable, obtain and analyze at least one grab sample of the monitored parameter at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
ACTION 71 -
a.
With one of the required monitors inoperable, place the inoperable channel in the downscale tripped condition within one hour.
b.
With both of the required monitors inoperable, be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
ACTION 72-With the required monitor inoperable, perform area surveys of the monitored area with portable monitoring instrumentation at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
ACTION 73 -
a.
With one of the required monitors in a trip system inoperable, place the inoperable channel in the downscale tripped condition within one hour; restore the inoperable channel to OPERABLE status within 7 days, or, within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, initiate and maintain operation of at least one control room emergency filtration system in the isolation mode of operation.
b.
With both of the required monitors in a trip system inoperable, initiate and maintain operation of at least one control room emergency filtration system in the isolation mode of operation within one hour.
ACTION 74 -
With one of the required monitors in a trip system inoperable, a.
place the inoperable channel in the downscale tripped condition within one hour.
b.
With two of the required monitors in a trip system inop< able, isolate the containment and drywell purge and vent penet ations within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
ACTION 75 -
With one of the required monitors in a trip system inopercble, a.
place the inoperable channel in the downscale tripped contition within one hour.
b.
With two of the required monitors in a trip system inoperable, initiate and maintain operation of at least one standby gas treatment subsystem within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
O GRAND GULF-UNIT 1 3/4 3-58 Order
- APR 1 n 1984
Q R
0 U
wJ TABLE 4.3.7.1-1 i
m RADIATION MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS c3 OPERATIONAL E
CHANNEL CONDITIONS FOR T
CHANNEL FUNCTIONAL CHANNEL WHICH SURVEILLANCE E
INSTRUMENTATION CHECK TEST CALIBRATION REQUIRED 1.
Component Cooling Water Radiation Monitor S
M A
At all times 2.
Standby Service Water System Radiation Monitor 5
M A
1, 2, 3, and*
3.
Offgas Pre-treatment Radiation Monitor S
M A
1, 2 4.
Offgas Post-treatment Radiation Monitor S
M A
1, 2 5.
Carbon Bed Vault Radiation Monitor S
M A
1, 2 6.
Control Room Ventilation Radiation Monitor S
M(a)
A 1, 2, 3, 5 and**
7.
Containment and Drywell Ventilation Exhaust Radiation Monitor S
M g
A At all times 8.
Fuel Handling Area Ventilation T
Radiation Monitor S
M A
1, 2, 3, 5 and**
9.
Fuel Handling Area Pool Sweep Exhaust Radiation Monitor S
M A
(b) 10.
Area Monitors i
a.
Fuel Handling Area Monitors 1)
New Fuel Storage Vault S
M R
(c) 2)
Spent Fuel Storage Pool S
M R
(d) 3)
Dryer Storage Area S
M R
(e) b.
Control Room Radiation Monitor S
M R
At all times With RHR heat exchangers in operation.
When irradiated fuel is being handled in the primary or secondary containment.
(a) The CHANNEL FUNCTIONAL TEST shall demonstrate that control room annunciation occurs if any of the following conditions exist, i
1.
Instrument indicates measured levels above the alarm / trip setpoint.
1 g
2.
Circuit failure.
3.
Instrument indicates a downscale failure.
- m o 1
4.
Instrument controls not in Operate mode.
tl (b) With irradiated fuel in the spent fuel storage pool.
m (c) With fuel in the new fuel storage vault.
's (d) With fuel in the spent fuel storage pool.
6 (e) With fuel in the dryer storage area.
INSTRUMENTATION l
SEISMIC MONITORING INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.7.2 The seismic monitoring instrumentation shown in Table 3.3.7.2-1 shall be OPERABLE.
APPLICABILITY:
At all times.
ACTION:
a.
With one or more of the above required seismic monitoring instruments inoperable for more than 30 days, in lieu of any other report required by Specification 6.9.1, prepare and submit a Special Report to the Commission pursuant to Specification 6.9.2 within the next 10 days outlining the cause of the malfunction and the plans for restoring the instrument (s) to OPERABLE status.
b.
The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.
SURVEILLANCE REQUIREMENTS O
4.3.7.2.1 Each of the above required seismic monitoring instruments shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNC-TIONAL TEST and CHANNEL CALIBRATION operations at the frequencies shown in Table 4.3.7.2-1.
4.3.7.2.2 Each of the above required seismic monitoring instruments actuated during a seismic event greater than or equal to 0.01 g shall be restored to OPERABLE status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and a CHANNEL CALIBRATION performed within 5 days following the seismic event.
Data shall be retrieved from actuated instruments and analyzed to determine the magnitude of the vibratory ground j
motion.
In lieu of any other report required by Specification 6.9.1, a i
Special Report shall be prepared and submitted to the Commission pursuant to Specification 6.9.2 within 10 days describing the magnitude, frequency spectrum and resultant effect upon unit features important to safety.
O GRAND GULF-UNIT 1 3/4 3-60
INSTRUMENTATION ACCIDENT MONITORING INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.7.5 The accident monitoring instrumentation channels shown in Table 3.3.7.5-1 shall be OPERABLE.
APPLICABILITY: As shown in Table 3.3.7.5-1.
ACTION:
With one or more accident monitoring instrumentation channels inoperable, take the ACTION required by Table 3.3.7.5-1.
SURVEILLANCE REQUIREMENTS 4.3.7.5 Each of the above required accident monitoring instrumentation channels shall be demonstrated OPERABLE by performance of the CHANNEL CHECK and CHANNEL CALIBRATION operations at the frequencies shown in Table 4.3.7.5-1.
GRAND GULF-UNIT 1 3/4 3-69 Order
'APR 1 g 1994
TABLE 3.3.7.5-1 S
ACCIDENT MONITORING INSTRUMENTATION APPLICABLE MINIMUM S
OPERATIONAL REQUIRED NUMBER CHANNELS E
INSTRUMENT CONDITIONS OF CHANNELS OPERABLE ACTION h
1.
Reactor Vessel Pressure 1,2,3 2
1 80 Z
2.
Reactor Vessel Water Level 1,2,3,4,5 2
1 82 3.
Suppression Pool Water Level 1, 2, 3 2
1 80 4.
Suppression Pool Water Temperature 1,2,3 6, 1/ sector 6, 1/ sector 80 5.
Drywell/ Containment Differential Pressure 1,2,3 2
1 80 6.
Drywell Pressure 1,2,3 2
1 80 7.
Drywell and Control Rod Drive Cavity Temperature 1, 2, 3 2 (each) 1 (each) 80 8.
Containment Hydrogen Concentration Analyzer and Monitor 1,2,3 2
1 80
'E 9.
Drywell Hydrogen Concentration Analyzer and Monitor 1,2,3 2
1 80 y
5 10.
Containment Pressure (wide and narrow range) 1, 2, 3 2 (each) 1 (each) 80 11.
Containment Air Temperature 1, 2, 3 2
1 80 12.
Safety / Relief Valve Tail Pipe Pressure Switch Position Indicators 1, 2, 3 1/ valve 1/ valve 80 13.
Containment /Drywell Area Radiation Monitors 1,2,3,4,5 2
1 81 14.
Containment Ventilation Exhaust Radiation Monitor 1,2,3,4,5 1
1 81 15.
Off gas and Radwaste Bldg. Ventilation Exhaust Radiation Monitor 1,2,3,4,5 1
1 81 16.
Fuel Handling Area Ventilation Exhaust Radiation Monitor 1,2,3,4,5 1
1 81 mi 17.
Turbine Bldg. Ventilation Exhaust Radiation 3
o Monitor 1,2,3 1
1 81 0
18.
Standby Gas Treatment System A & B Exhaust
~
Radiation Monitors 1/each 1/each 81 22s W
ach for containment and drywell.
en its associated train of the standby gas tr it system is required operable (Ref. 3.6.6.3).
l TABLE 3.3.7.5-1 (Continued) l ACCIDENT MONITORING INSTRUMENTATION ACTION STATEMENTS ACTION 80 -
)
a.
With the number of OPERABLE accident monitoring instrumentation j
channels less than the Required Number of Channels shown in Table 3.3.7.5-1, restore the inoperable. channel (s) to OPERA 8LE i
status ^within 7 days or be in at least HOT SHUTDOWN within the 1
next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and be in COLO-SHUTDOWN within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
l b.
With the number of OPERABLE accident monitoring instrumentation channels less than the Minimum Channels OPERABLE requirements j
of Table 3.3.7.5-1, restore the inoperable channel (s) to OPERABLE status within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and be in COLD SHUTDOWN within the l
f next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
ACTION 81 -
With the number of OPERA 8LE accident monitoring instrumentation channels less than required by the Minimum Channels OPERABLE i
requirement, either restore the inoperable channel (s) to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, or:
i t
a.
Initiate the preplanned alternate method of monitoring the appropriate parameter (s), and b.
Prepare and submit a Special Report to the Commission pursuant I
to Specification 6.9.2 within 14 days following the event outlining the action taken, the cause of the inoperability and the plans and ' schedule for restoring the system to OPERABLE l
status.
]
ACTION 82 -
For OPERATIONAL CONDITIONS 1, 2, 3' j
a.
With the number of OPERABLE accident monitoring instrumentation channels less than the Required Number of Channels shown in i
Table 3.3.7.5-1, restore the inoperable channel (s) to OPERABLE
]
status within 7 days or be in at least HOT SHUTDOWN within the j
next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and be in COLD SHUTDOWN within the next-24 hours.
b.
With the number of OPERABLE accident monitoring instrumentation j
channels less than the Minimum Channels OPERABLE requirements of Table 3.3.7.5-1, restore the inoperable channel (s) to j
OPERA 6LE status within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and be in COLD SHUTDOWN within the i
next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
I I
For OPERATIONAL CONDITIONS 4, 5 With the number of OPERABLE accident monitoring instrumentation i
channels less than required by the Minimum Channels OPERA 8LE' require-l ment, either restore the inoperable channel (s) to OPERABLE status
{
within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, or initiate the preplanned alternate method of
{
monitoring the appropriate parameter (s).
i GRAND GULF-UNIT 1 3/4 3-71
' Order j
M I R 1984
"A.:'r 4.1.7.c 7 i
ACCICENT MONITCRI M INSTRtNENTATICN SURVEILLASCE RECJJI:_ VENTS CFANNEL CrANNEL INSTRUVENT CHECK CALIE RAT!C-N 1.
Reactcr Vessel Pressure M
R 2.
Reactor Vessel kater Level M
R 3.
Suppressica Peel Water Level M
R 4
Succressica Pcci kater Te::erature M
R 5.
Crysell/Centain=ent Differential Pressure M
R 5.
Cry *eli Pressure M
R T.
Crywell and Centrol Dec Cavity Tercerature W
R 3.
Containment Hydrogen Ccccentration Analycer arc Mcnitor NA M*
3.
Cry-ell Hycr: gen Concentraticn Analyzer anc Wenitor NA V*
10.
Centaircent Pressure M
R 11.
Centainment Ai-Te;;erature w
i 12.
Safecy/ Relief Valve Tail Pice Pressure 5 iten Position Indicators M
R 13.
Ocetainment/ Cry-ell Area Raciatic, Monitces M
R**
14 Centairment Ventilatien Exnaust Radiation Mcnitor M
A 15.
Cff gas anc Rae-aste Eleg. Vertilatico Exnaast Raciation Mcnitor M
A 16.
Fuei "andling Area Ventilatien Exnaust Radiation Mcnitor M
A 17.
Turcire Eidg. Ventilation Exhaust Radiation Monitcr M
A 18.
Stancty Gas Treatner. Systes A & 2 Exhaust Radiaticn Mcnitors M
A
'Using sarole gas containirg:
One <clu e percent eycregen, retaincer nitregen.
a.
b.
Fcur scluee cercent nydecgen, re ainder nitregen
- The CKANNEL CALIERATICN shall censist of an electrenic calicaatice of the channel, not inclucing tre detecter, for range decades ateve 10R/hr and a cne ceint calicratien creck of tre cetector belcw 10R/h* -itP an installed er portacle ga_9na source.
GRAND GULF-LSIT 1 3/4 3-72 Orcer
- AFR ! e-bo
INSTRUMENTATION CHLORINE DETECTION SYSTEM LIMITING CONDITION FOR OPERATION i-3.3.7.8 Two independent chlorine detection systems shall be OPERABLE with their trip setpoints adjusted to actuate at a chlorine concentration of less than or equal to 5 ppm.
APPLICABILITY:
All OPERATIONAL CONDITIONS.
.I ACTION:
I 4
a.
With one chlorine detection system inoperable, restore the inoperable i
detection system to OPERABLE status within 7 days, or within the i
next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, initiate and maintai'n operation of at least one control room emergency filtration system subsystem in the isolation mode of operation.
j b.
With both chlorine detection systems inoperable, within one hour l
initiate and maintain operation of at least one control room emer-l gency filtration system subsystem in the isolation mode of operation.
c.
The provisions of Specification 3.0.4 are not applicable.
\\
SURVEILLANCE REQUIREMENTS I
l 4.3.7.8 Each of the above required chlorine detection syste?is shall be i
demonstrated OPERABLE by performance of a CHANNEL CHECK at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, a CHANNEL FUNCTIONAL TEST at least once per 31 days and a CHANNEL CALIBRATION at least once per 6 months.
l
?
I l
i I
i i
GRAND GULF-UNIT 1 3/4 3-75 Order
,\\
yy
\\
s~/
TA 4.3.7.12-1 a
RADI0 ACTIVE GASE0US EFFLUENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS 8
CilANNEL MODES IN WilICil Q
CilANNEL SOURCE CilANNEL FUNCTIONAL SURVEILLANCE ch INSTRUMENT CHECK CllECK CALIBRATION TEST REQUIRED 1.
RADWASTE BUILDING VENTILATION MONITORING SYSTEM a.
Noble Gas Activity Monitor -
l Providing Alarm D
M A(3)
Q(2) b.
Iodine Sampler W
N.A.
N.A.
N.A.
c.
Particulate Sampler W
N.A.
N.A.
N.A.
d.
Flow Rate Monitor D
N.A.
R Q
w1 w
e.
Sampler Flow Rate Monitor D
H.A.
R N.A.
O N
2.
MAIN CONDENSER OFFGAS TREATMENT SYSTEM EXPLOSIVE GAS MONITORING SYSTEM a.
Hydrogen Monitor D
N.A.
Q(4)
M 3.
CONTAINMENT VENTILATION MONITORING SYSTEM a.
Noble Gas Activity Monitor l
Providing Alarm D
M A(3)
Q(2) b.
Iodine Sampler W
N.A.
N.A.
N.A.
c.
Particulate Sampler W
N.A.
N.A.
N.A.
o 1
d.
Effluent System Flow Rate
~n y
Monitor D
N.A.
R Q
e.
Sampler Flow Rate Monitor D
N.A.
R N.A.
s I
TABLE 4.3.7.12-1 (Continued) o 5
l g
RADI0 ACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS o
l E
n CHANNEL MODES IN WHICH
/=
CHANNEL SOURCE
' CHANNEL FUNCTIONAL SURVEILLANCE INSTRUMENT CHECK CHECK CALIBRATION TEST REQUIRED 1
l 4.
TURBINE BLDG. VENTILATION MONITORING SYSTEM i
l a.
Noble Gas Activity Monitor D
M A(3)
Q(2) b.
Iodine Sampler W
N.A.
N.A.
N.A.
1 l
c.
Particulate Sampler W
N.A.
N.A.
N.A.
I
)
d.
Flow Rate Monitor D
N.A.
R Q
y e.
Sampler Flow Rate Monitor D
N.A.
R N.A.
i 8
)
5.
FUEL HANDLING AREA VENTILATION MONT0 RING SYSTEM
]
l a.
Noble Gas Activity Manitor D
M A(3)
Q(2) l l
b.
Iodine Sampler W
N.A.
N.A.
N.A.
i c.
Particulate Sampler W.
N.A.
N.A.
N.A.
J d.
Flow Rate Monitor D
N.A.
R Q
l e.
Sampler Flow Rate Monitor D
N.A.
R N.A.
i
~
I! "% o O d o
4 1
3 E
}A 1
i d
a
TABLE 4.3.7.12-1 (Continued) g RADI0 ACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS O
E CHANNEL MODES IN WHICH cb CHANNEL SOURCE CHANNEL FUNCTIONAL SURVEILLANCE 5.
INSTRUMENT CHECK CHECK CALIBRATION TEST REQUIRED
-A 6.
OFFGAS PRE-TREATMENT MONITOR A(3)##
Q(2) a.
Noble Gas Activity Monitor D
H 7.
OFFGAS POST-TREATMENT MONITOR a.
Noble Gas Activity Monitor Providing Alarm and Auto-matic Termination of Release D
M A(3)gg Q(1)
T
'e s
c1 4
m b*
O O
O
f INSTRUMENTATION 3/4.3.8 PLANT SYSTEMS ACTUATION INSTRUMENTATION 4
LIMITING CONDITION FOR OPERATION 4
3.3.8 The plant systems actuation instrumentation channels shown in Table 3.3.8-1 shall be OPERABLE with their trip setpoints set consistent with the
{
values shown in the Trip Setpoint column of Table 3.3.8-2.
4
]
APPLICABILITY: As shown in Table 3.3.8-1.
ACTION:
I a.
With a plant system actuation instrumentation channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.3.8-2, declare the channel inoperable and take the ACTION required by Table 3.3.8-1.
j b.
With one or more plant systems actuation instrument channels in-operable, take the ACTION required by Table 3.3.8-1.
i
! OO i
I 4
i
)
i 1
i i
s l
GRAND GULF-UNIT 1 3/4 3-96 Order a
'APR I p lge4 i.
INSTRUMENTATION SURVEILLANCE REQUIREMENTS 4.3.8.1 Each plant system actuation instrumentation channel shall be l
demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations for the OPERATIONAL CONDITIONS and at the frequencies shown in Table 4.3.8.1-1.
4.3.8.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic operation of all channels shall be performed at least once per 18 months.
)
J I
l 1
i I
i i
l GRAND GULF-UNIT 1 3/4 3-97
TABLE 3.3.8-1 n
$g PLANT SYSTEMS ACTUATION INSTRUMENTATION O
MINIMUM APPLICABLE h
OPERABLE CHANNELS OPERATIONAL g
TRIP FUNCTION PER TRIP SYSTEM CONDITIONS ACTION M
1.
CONTAINMENT SPRAY SYSTEM a.
Drywell Pressure-High 2
1,2,3 130 b.
Containment Pressure-High 1
1,2,3 131 c.
Reactor Vessel Water Level-Low Low Low, Level 1 2
1,2,3 130 d.
Timers ca
- 1) System A 1
1,2,3 131 D
- 2) System B 1
1,2,3 131 2.
FEEDWATER SYSTEM / MAIN TURBINE TRIP SYSTEM a.
Reactor Vessel Water Level-High, Level 8 3
1 132 k= ?
f,t co O
O O
TABLE 3.3.8-1 (Continued)
PLANT SYSTEMS ACTUATION INSTRUMENTATION ACTION ACTION 130 -
a.
With the nuober of OPERABLE channels one less than required by the Minimum OPERA 8LE Channels per Trip System requirement, place the inoperable channel in the tripped condition within one hour; otherwise, declare the associated containment spray system inoperable and take the action required by Tech-nical Specification 3.6.3.2.
b.
With the number of OPERABLE channels two less than required by the Minimum OPERABLE channels per Trip System require-i ment, declare the associated containment spray system inoperable and take the action required by Technical Specification 3.6.3.2.
ACTION 131 -
With the number of OPERA 8LE channels less than required by the 1
Minimum OPERABLE Channels per Trip System requirement, restore the channels to OPERABLE status within one hour; otherwise, declare the associated containment spray system inoperable and take the action required by Technical Specification 3.6.3.2.
ACTION 132 -
For the feedwater system / main turbine trip system:
(
With the number of OPERABLE channels one less than required a.
\\-
by the Minimum OPERABLE Channels requirement, restore the inoperable channel to OPERABLE status within 7 days or be in at least STARTUP within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, b..
With the number of OPERABLE channels two less than required by the Minimum OPERABLE Channels per Trip System require-ment, restore at least one of the inoperable channels to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in at least STARTUP within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
4
\\
GRAND GULF-UNIT 1 3/4 3-98a Order
' AfR l Q 1984
t w
TABLE 3.3.8-2 E
PLANT SYSTEMS ACTUATION INSTRUMENTATION SETPOINTS
^
O E
ALLOWtBLE l
Q TRIP FUNCTION TRIP SETPOINT VALUE i
a l
3 1.
CONTAINMENT SPRAY SYSTEM
-4 4
a.
Drywell Pressure-High 5 1.39 psig 5 1.44 psig l
b.
Containment Pressure-High 5 7.84 psig i 8.34 psig 1
c.
Reactor Vessel Water Level-Low Low Low, Level 1 1 - 150.3 inches 1 - 152.5 inches d.
Timers l
- 1) System A 10.85 1 0.10 minutes 10.26 - 0.00, + 1.18 minutes
- 2) System B 10.85 1 0.10 minutes **
10.26 - 0.00, + 1.18 minutes 2.
FEEDWATER SYSTEM / MAIN TURBINE TRIP SYSTEM a.
Reactor Vessel Water Level-High, Level 8 5 53.5 inches *
$ 55.7 inches
}
T e
o
- 5ee Bases Figure B 3/4 3-1.
- Setpoint for System 8 is the sum of E12-K0938 plus E12-K116.
E12-K116 is not to exceed 10.00 seconds.
l f
3 5
i i
l i
. -s
- =
a, t-ICD E
i i
i
TABLE 4.3.8.1-1 c,
m j
PLANT SYSTEMS ACTUATION INSTRUMENTATION SURVEILLANCE RE(UIREMENTS O
5 CilANNEL OPERATIONAL E
CilANNEL FUNCTIONAL CllANNEL CONDITIONS IN WillCil di-TRIP FUNCTION CilECK TEST CALIBRATION SURVEILLANCE REQUIRED
-a 1.
CONTAINMENT SPRAY SYSTEM i
i a.
Drywell Pressure-liigh 5
H R
1, 2, 3 b.
Containment Pressure-liigh S
H R
1, 2, 3-1 c.
~
Low Low Low, Level 1 S
H R
1,2,3 d.
Timers NA H
Q 1,2,3 2.
FEEDWATER SYSTEH/ MAIN TURBINE TRIP SYSTEM u,
D w
a.
Reactor Vessel Water level-liigh, S
H R
1
'o Level 8 8
9 O
4 O
O O~
l-
-.= -
l l
l i
3/4.5 EMERGENCY CORE COOLING SYSTEMS 3/4.5.1 ECCS - OPERATING LIMITING CONDITION FOR OPERATION 3.5.1 ECCS divisions 1, 2 and 3 shall be OPERABLE with:
a.
ECCS division 1 consisting of:
1.
The OPERA 8LE low pressure core spray (LPCS) system with a flow path capable of taking suction from the suppression pool and transferring the water through the spray sparger to the reactor vessel.
2.
The OPERABLE low pressure coolant injection (LPCI) subsystem "A" of the RHR system with a flow path capable of taking suction from the suppression puoi and transferring the water to the reactor vessel.
3.
j.
b.
ECCS division 2 consisting of:
1.
The OPERABLE low pressure coolant injection (LPCI) subsystems "B" and "C" of the RHR system, each with a flow path capable of taking suction from the suppression pool and transferring the water to the reactor vessel.
2.
c.
ECCS division 3 consisting of the OPERABLE high pressure core spray (HPCS) system with a flow path capable of taking suction from the suppression pool and transferring the water through the spray sparger to the reactor vessel.
APPLICABILITY:
OPERATIONAL CONDITION 1, 2" # and 3*.
ACTION:
a.
For ECCS division 1, provided that ECCS divisions 2 and 3 are OPERABLE:
1.
With the LPCS system inoperable, restore the inoperable LPCS system to OPERABLE status within 7 days.
2.
With LPCI subsystem "A" inoperable, restore the inoperable LPCI subsystem "A" to OPERABLE status within 7 days.
3.
With the LPCS system inoperable and LPCI subsystem "A" inoperable, restore at least the inoperable LPCI subsystein "A" or the inoperable LPCS system to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
4.
Otherwise, be in at least HOT SHUTOOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
- The AOS is not required to be OPERABLE when reactor steam dome pressure is less than or equal to 135 psig,
- See Special Test-Exception 3.10.5.
s GRAND GULF-UNIT 1 3/4 5-1 Order l
A l R 1984
4 EMERGENCY CORE COOLING SYSTEMS
(
LIMITING CONDITION FOR OPERATION (Continued)
ACTION:
(Continued) b.
For ECCS division 2, provided that ECCS divisions 1 and 3 are OPERABLE:
1.
With either LPCI subsystem "B" or "C" inoperable, restore the inoperable LPCI subsystem "B" or "C" to OPERABLE status within 7 days.
2.
With both LPCI subsystems "B" and "C" inoperable, restore at least the inoperable LPCI subsystem "B" or "C" to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
3.
Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> *.
c.
For ECCS division 3, provided that ECCS divisions 1 and 2 and the RCIC system are OPERABLE:
1.
With ECCS division 3 inoperable, restore the inoperable division to OPERABLE status within 14 days.
2.
Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, d.
For ECCS divisions 1 and 2, provided that ECCS division 3 is OPERABLE:
1.
With LPCI subsystem "A" and either LPCI subsystem "B" or "C" inoperable, restore at least the inoperable LPCI subsystem "A" or the inoperable LPCI subsystem "B" or "C" to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
2.
With the LPCS system inoperable and either LPCI subsystems "B" or "C" inoperable, restore at least the inoperable LPCS system or the inoperable LPCI subsystem "B" or "C" to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
3.
Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />".
"Whenever two or more RHR subsystems are inoperable, if unable to attain COLD SHUTDOWN as required by this ACTION, maintain reactor coolant temperature as low as practical by use of alternate heat removal methods.
O GRAND GULF-UNIT 1 3/4 5-2 i
)
EMERGENCY CORE COOLING SYSTEMS
(
~
^ 'MITING CONDITION FOR OPERATION (Continued)
' ACTION:
(Continued) e.
For ECCS divisions 1 and 2, provided that ECCS division 3 is OPERABLE and divisions 1 and 2 are otherwise OPERABLE:
1.
With one of the above required ADS valves inoperable, restore the inoperable ADS valve to OPERA 3LE status within 14 days or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and reduce reactor steam dome pressure to 5 135 psig within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
2.
With two or more of the above required ADS valves inoperable, be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and reduce reactor steam dome pressure to 1 135 psig within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
f.
With an ECCS discharge line " keep filled" pressure alarm instrumentation channel inoperable, perform Surveillance Requirement 4.5.1.a.1 at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
g.
With an ECCS header delta P instrumentation channel inoperable, restore the inoperable channel to OPERABLE status with 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or de'termine ECCS header delta P locally at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />; otherwise declare the associated ECCS inoperable.
( j h.
In the event an ECCS system is actuated and injects water into the Reactor Coolant System, a Special Report shall be prepared and sub-mitted to the Commission pursuant to Specification 6.9.2 within 90 days describing the circumstances of the actuation and the total accumulated actuation cycles to date.
The current value of the useage factor for each affected safety injection nozzle shall be provided in this Special Report whenever its value exceeds 0.70.
- bhenever two or more RHR subsystems are inoperable, if unable to attain COLD SHUTDOWN as required by this ACTION, maintain reactor coolant temperature as low as practical by use of alternate heat removal methods.
O
!+
GRAND GULF-UNIT 1 3/4 5-3 y _.,,g._
EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE REQUIREMENTS 4.5.1 ECCS division 1, 2 and 3 shall be demonstrated OPERABLE by:
a.
At least once per 31 days for the LPCS, LPCI and HPCS systems:
1.
Verifying by venting at the high point vents that the system piping from the pump discharge valve to the system isolation valve is filled with water.
2.
Performance of a CHANNEL FUNCTIONAL TEST of the:
a)
Discharge line " keep filled" pressure alarm instrumentation, and b)
Header delta P instrumentation.
3.
Verifing that each valve, manual, power operated or automatic, in the flow path that is not locked, sealed, or.Otherwise secured in position, is in its correct position.
b.
Verifing that, when tested pursuant to Specification 4.0.5, each:
1.
LPC' pump develops a flow of at least 7115 gpm with a total developed head of greater than or equal to 290 psid.
l 2.
LPCI pump develops a flow of at least 7450 gpm with a total developed head of greater than or equal to 125 psid.
l 3.
HPCS pump develops a flow of at least 7115 gpm with a total developed head af greater than or equal to 445 psid.
For the LPCS, LPCI and HPCS systems, at least once per 18 months:
c.
1.
Performing a system functional test which includes simulated automatic actuation of the system throughout its emergency operating sequence and verifying that each automatic valve in the flow path actuates to its correct position.
Actual injec-tion of coolant into the reactor vessel may be excluded from this test.
2.
Performing a CHANNEL CALIBRATION of the:
a)
Discharge line " keep filled" pressure alarm instrumentation and verifying the:
1)
High pressure setpoint of the:
(a)
LPCS system to be 580 + 20. - O psig.
(b)
LPCI subsystems to be 480 + 20, - 0 psig.
O GRAND GULF-UNIT 1 3/4 5-4 Order
- R I g lg84
-)
9 CONTAINMENT SYSTEMS CONTAINMENT AIR LOCKS LIMITING CON 0! TION FOR OPERATION 3.6.1.3 Each containment air lock shall be OPERA 8LE with:
a.
Both doors closed except when the air lock is being used for normal transit entry and exit through the containment, then at least one air lock door shall be closed, and b.
An overall air lock leakage rate of less than or equal to 2 scf per hour at P,, 11.5 psig.
APPLICA8ILITY:
OPERATIONAL CONDITIONS 1, 28 and 3.
ACTION:
a.
With one containment air lock door inoperable:
1.
Maintain at least the OPERA 8LE air lock door closed and either restore the inoperable air lock door to OPERA 8LE status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or lock the OPERA 8LE air lock door closed.
O Operation may then continue until performance of the next required 2.
overall air lock leakage test provided that the OPERA 8LE air lock door is verified to be locked closed at least once per 31 days.
~
3.
Otherwise, be in at least HOT SHUT 00WN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
4.
The provisions of Specification 3.0.4 are not applicable.
b.
With the containment air lock inoperable, except as a result of an inoperable air lock door, maintain at least one air lock door closed; restore the inoperable air lock to OPERA 8LE status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
With one containment air lock door inflatable seal system seal pressure l
c.
instrumentation channel inoperable, restore the inoperable channel to OPERABLE status within 7 days or verify the associated inflatable seal pressure to be > 60 psig at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
"See Special Test Exception 3.10.1.
GRAND GULF-UNIT 1 3/4 6-5 Amendment No. 8
CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS 4.6.1.3 Each containment air lock shall be demonstrated OPERABLE:
Within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> after each closing, except when the air lock is being a.
used for multiple entries, then at least once per 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, by verifying seal leakage rate less than or equal to 2 scf per hour when the gap between the door seals is pressurized to Pa, 11.5 psig.
b.
By conducting an overall air lock leakage test at P*,11.5 psig, and verifying that the overall air lock leakage rate is within its limit:
1.
At least once per 6 months #, and 2.
Prior to establishing PRIMARY CONTAINMENT INTEGRITY when maintenance has been performed on the air lock that could affect the air lock sealing capability.*
At least once per 6 months by verifying that only one door in each c.
air lock can be opened at a time.
d.
By verifying each airlock door inflatable seal system OPERABLE by:
1.
Demonstrating each of the two inflatable seal pressure instrumentation channels per airlock door OPERABLE by performance of a:
a)
CHANNEL FUNCTIONAL TEST at least once per 31 days, and b)
CHANNEL CALIBRATION at least once per 18 months, I
with a low pressure setpoint of > 60 psig.
2.
At least once per 7 days, verifying seal air flask pressure to g
be greater than or equal to 90 psig.
I 3.
At least once per 18 months, conducting a seal pneumatic system leak test and verifying that system pressure does not decay more than 2 psig from 90 psig within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.
The provisions of Specification 4.0.2 are not applicable.
Exemption to Appendix J of 10 CFR 50.
O GRAND GULF-UNIT 1 3/4 6-6 Order APR 1 g 1984
CONTAINMENT SYSTEMS DRYWELL AIR LOCKS LIMITING CONDITION FOR OPERATION 3.6.2.3 Each drywell air lock shall be OPERABLE with:
Both doors closed except when the air lock is being used for normal transit a.
entry and exit through the drywell, then at least one air lock door shall be closed, and
)
b.
An overall air lock leakage rate of less than or equal to 2 scf per hour at P,, 11.5 psig.
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2* and 3.
ACTION:
With one drywell air lock door inoperable:
a.
1.
Maintain at least the OPERABLE air lock door closed and either restore the inoperable air lock door to OPERABLE status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or lock the OPERA 8LE air lock door closed.
2.
Operation may then continue provided that the OPERABLE air lock door is verified to be locked closed at least once per 31 days.
3 3.
Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
4.
The provisions of Specification 3.0.4 are not applicable.
j t
i b.
With the drywell air lock inoperable, except as a result of an inoperable air lock door, maintain at least one air lock door closed; restore the inoperable air lock to OPERABLE status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or be in at least l
l HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
With one drywell air lock door inflatable seal system seal pressure c.
instrumentation channel inoperable, restore the inoperable channel to OPERABLE status within 7 days or verify the associated inflatable seal pressure to be > 60 psig at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
- See Special Test Exception 3.10.1.
b GRAND GULF-UNIT 1 3/4 6-15 Amendment No. 8
CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS 4.6.2.3 Each drywell air lock shall be demonstrated OPERABLE:
a.
Within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> after each closing, except when the air lock is being used for multiple entries, then at least once per 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, by verifying seal leakage rate less than or equal to 2 scf per hour when the gap between the door seals is pressurized to P,,
11.5 psig.
b.
At least once per 6 months by conducting an overall air lock leakage test at P,11.5 psig and by veriping that the overall air lock leakage r$te is within its limit.
c.
At least once per 6 months by verifying that only one door in each air lock can be opened at a time.
d.
By verifying each airlock door inflatable seal system OPERABLE by:
1.
Demonstrating each of the two inflatable seal pressure instrumentation channels per airlock door OPERABLE by performance of a:
a)
CHANNEL FUNCTIONAL TEST at least once per 31 days, and b)
CHANNEL CALIBRATION at least once per 18 months, with a low pressure setpoint of > 60 psig.
2.
At least once per 7 days verifying seal air flask pressure to l
be greater than or equal to 90 psig.
I 3.
At least once per 18 months, conducting a seal pneumatic system leak test and verifying that system pressure does not decay more than 2 psig from 90 psig within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.
- The provisions of Specification 4.0.2 are not applicable.
O GRAND GULF-UNIT 1 3/4 6-16 Order
- APR I g 1994
TABLE 3.6.4-1 (Continued)
CONTAINMENT AND DRYWELL ISOLATION VALVES N
SYSTEM AND PENETRATION VALVE NUMBER NUMBER b.
Drywell LPCI "A" E12-F041A 313(I)
LPCI "B" E12-F041B 314(I)
LPCI "B" E12-F236 314(0)
CRD to Recirc.
B33-F013A 326(I)
Pump A Seals CRD to Recirc.
B33-F017A 326(0)
Pump A Seals Instrument Air PS3-F008 335(I) l Standby Liquid C41-F007 328(I)
Control Standby Liquid C41-F006 328(0)
Control Cont. Cooling P42-F115
'329(I)
Water Supply Plant Service P44-F075 332(I)
Water Supply Condensate Flush B33-F204 333(I)
Conn.
Condensate Flush B33-F205 333(0)
Conn.
Combustible Gas E61-F002A 339(0)
Control Combustible Gas E61-F0028 338(0) 4 Control Combustible Gas E61-F004A 340(0)
Control Combustible Gas E61-F0048 340(0)
Control Upper Containment G41-F265 342(0)
Pool Drain CRD to Recire.
B33-F0138 346(I)
Pump B Seals i
CRD to Recire.
833-F017B 346(0) l l
Pump B Seals Service Air PS2-F196 363(I)
Cont. Leak Rate M61-F021 438A(I)
Test Inst.
Cont. Leak Rate M61-F020 438A(0)
Sys.
BLIND FLANGES Cont. Leak Rate NA 40(I)(0)
- Sys, Cont. Leak Rate NA 82(I)(0)
Sys.
C Containment NA 343(I)(0)
Leak Rate System GRAND GULF-UNIT l' 3/4 6-41 Order
- R I g ;9g4-
TABLE 3.6.4-1 (Continued)
CONTAINMENT AND DRYWELL ISOLATION VALVES,
SYSTEM AND PENETRATION VALVE NUMBER NUMBER 4.
Test Connections (9) a.
Containment Main Steam T/C B21-F025A 5(0)
Main Steam T/C 821-F0258 6(0)
Main Steam T/C B21-F025C 7(0)
Main Steam T/C B21-F025D 8(0)(f)
Feedwater T/C B21-F030A 9(0) 9(0)((f)
Feedwater T/C B21-F063A 10(0) f)
Feedwater T/C B21-F0638 10(0)(c) f Feedwater T/C 821-F030B 14(0)( )
RHR Shutdown Cool.
E12-F002 Suction T/C RCIC Steam Line E51-F072 17(0)
T/C RHR to Head E12-F342 18(0)(c)
Spray T/C RHR to Head E12-F061 18(0)(c)
Spray T/C 22(0)((c)
LPCI "C" T/C E12-F056C 23(0) c)
RHR "A" Pump E12-F322 Test Line T/C RHR " A" Pump E12-F336 23(0)(c)
Test Line T/C RHR "A" Pump E12-F349 23(0)(c)
Test Line T/C RHR "A" Pump E12-F303 23(0)(c)
Test Line T/C RHR "A" Pump E12-F310 23(0)(c)
Test Line T/C RHR "A" Pump E12-F348 23(0)(c)
Test Line T/C RHR"C" Pump E12-F311 24(0)(c)
Test Line T/C RHR"C" Pump E12-F304 24(0)(c)
Test Line T/C HPCS Discharge T/C E22-F021 26(0)
HPCS Test Line T/C E22-F303 27(0)(c)
HPCS Test Line T/C E22-F304 27(0)
RCIC Turbine E51-F258 29(0)(c)
Exhaust T/C RCIC Turbine E51-F257 29(0)(c) l Exhaust T/C 31(0)fe c
LPCS T/C E21-F013 LPCS Test Line E21-F222 32(0)
T/C t
LPCS Test Line E21-F221 32(0)(c)
T/C GRAND GULF-UNIT 1 3/4 6-42 Amendment No. 4, 7, 9
O O
~
y TABLE 3.7.4-1 (Continued) 4 x
SAFETY RELATED llYDRAULIC SNUBBERS
- 9 ch SNUBBER
}
NO.
AREA ELEVATION MAIN S1EAM SYSTDj Q1821G0065102A 11 155 Q1821G0065103A 11 150 Q1821G0065104A 11 150 QlB21G0065105A 11 150 Q1821G00651010 11 156 Q1821G006S1020 11 156 Q1821G00651030 11 149 Q1821G0065104B 11 150 t'
QlB21G006S105B 11 150 l
Q1821G006S1068 11 150 l
7 Q1821G006S1078 11 150 t;;
Q1821G006S108B 11 150 QlB21G006S101C 11 156 Q1821G006S102C 11 156 Q1821G0065103C 11 149 l
Q1821G006S104C 11 150 i
Q1821G0065105C 11 150 QlB21G0065106C 11 150 QlB21G006S107C 11 150 QlB21G006S108C 11 150 Q1821G006S1020 11 155 Q1821G006S1030 11 150 Q1821G00651040 11 150 t
Q1821G006S1050 11 150 4
4 4
i f-
1 I
TABLE 3.7.4-2 S
MECHANICAL SNUBBERS *,**
o 1.
SAFETY RELATE 0 MECHANICAL SNUBBERS E
SNUBBER SNUBBER NO.
AREA ELEVATION NO.
AREA ELEVATION H
a.
RECIRCULATION SYSTEM RECIRCULATION SYSTEM ',;ontinued)
Q1833G023R01(2) 11 117 Q1833G128C01(2) 11 121 Q1B33G024R01 11 102 Q1833G129C01 11 121 Q1833G024R02(2) 11 102 Q1B33G262R02 11 103 Q1833G024R05 11 101 Q1B33G265C01 11 102 Q1833G105C01 11 101 Q1833G265R04 11 107 Q1833G105R01 11 101 Q1B33G265R05 11 112 Q1833G105R02(2) 11 101 Q1833G318R01 11 102 Q1833G108C01 11 101 Q1833G322R01(2) 11 112 u,
)
Q1833G108R01(3) 11 101 Q1B33G331R02 11 111 Q1B33G108R02(2) 11 101 Q1B33G337R02 11 109 y
4 Q1833G112R01 11 101 Q1B33G339R01 11 111 Q1833G122R01 11 108 QlB33G346R01 11 105 m
Q1833G124R01 11 122 Q1833G355R01(2) 11 102
- Snubbers may be added to safety related systems without prior License Amendment to Table 3.7.4-2 provided that a revision to Table 3.7.4-2 is included with the next License Amendment request.
^^The number in parentheses is the number of snubbers associated with the component support.
If no number in parentheses appears, there is only one snubber associated with the support.
z$e 0 a,
'b E
O O
O 9
l O
O O
~
~
TABLE 3.7.4-2 (Continued) a h
MECHANICAL SNUBBERS *,**
O 1.
SAFETY RELATED MECHANICAL SNUBBERS l
n i
j SNUBBER SNUBBER i
NO.
AREA ELEVATION NO.
AREA ELEVATION
-4 H
b.
MAIN STEAM SYSTEM
-MAIN STEAM SYSTEM (Continued)
Q1821G021C04 11 141 Q1821G024R11 11 138 Q1821G022R01(2) 11 135 Q1821G024R12(2) 11 127 i
Q1821G022R03(2) 11 133 Q1821G024R13 11 123 Q1821G022R06(2) 11 124 Q1821G024R17 11 128 Q1821G022R12(2) 11 132 Q1821G025R02 11 128 Q1821G022R13(2) 11 131 Q1821G025R03 11 125 1
Q1821G022R14 11 126 Q1821G025R04(2) 11 124 R
Q1821G022R15 11 125 Q1821G025R05 11 120 Q1821G022R16 11 121 Q1B21G026C01(2) 11 143 I
y Q1821G023R03 11 137 Q1821G026C02(2) 11 143 t-j Q1821G023R05 11 133 Q1821G026R01 11 143 Q1821G023R06(2) 11 133 Q1821G026R02(2) 11 153 Q1B21G023R08 11 126 Q1821G026R03 11 149 Q1821G023R09 11 122 Q1821G026R04(2)-
11 153 i
{
Q1821G023R10 11 122 Q1821G026R05 11 143 l
Q1821G023R11(2) 11 120 Q1821G026R06(2) 11 143
}
Q1821G023R14 11 141 Q1821G026R07 11 143 Q1821G023R15(2) 11 141 Q1821G026R08 11 149 l
Q1821G023R16 11 133 Q1821G026R03(2) 8 143 Q1821G023R17 11 121 Q1821G030R03 11 129 Q1821G023R18(2) 11 119 Q1821G032R04 11 127 I
i Q1821G023R20 11 120 Q1821G032R05 11 120 Q1821G024C01 11 131 Q1821G123R01 11 165 Q1821G024R03 11 137 Q1821G126R01 11 159 4
-i) g o
Q1821G024R05(2) 11 132 Q1821G127R01(2) 11 193 Q1821G024R06 11 125 Q1821G127R04 11 186
.{
Q1821G024R07(2) 11 119 Q1B21G127R01 11 150 M
I -$+
k s
TABLE 3.7.4-2 (Continued)
MECHANICAL SNUBBERS *,**
1.
SAFETY RELATED MECHANICAL SNUBBERS
[
SNUB 8ER SNUBBER
=
NO.
AREA ELEVATION NO.
AREA ELEVATION H
MAIN STEAM SYSTEM (Continued)
MAIN STEAM SYSTEM (Continued)
H Q1821G139R02 11 150 Q1821G180R02(2) 11 158 Q1821G141R01 11 173 Q1821G180R03 11 161 Q1821G142R01(2) 11 173 Q1821G181C01 11 158 Q1821G144R01 11 173 Q1821G183R01(2) 11 152 Q1821G146C03(2) 11 169 Q1821G189R02 11 151 Q1821G146C04 11 169 Q1821G189R01 11 153 Q1B21G146R03 11 173 Q1821G194R01 11 161 y
Q1B21G147CO2 11 167 Q1821G194R02(2) 11 159 Q1821G148C01(2) 11 173 Q1B21G195R01 11 161 y
Q1821G1489R01(2) 11 172 Q1821G195R02(2) 11 160 g
Q1821G153C01 11 174 Q1821G196R01(2) 11 151 Q1821G153CO2 11 182 Q1821G197R01(2) 11 157 Q1B21G153C03(2) 11 171 Q1821G201R01 11 158 Q1821G153R01 11 181 Q1821G201R02(2) 11 157 Q1B21G153R02(2)
I '.
175 Q1821G204R01 11 152 Q1821G153R03(2) 11 172 Q1821G204R02(2) 11 160 Q1B21G153R05(2) 11 170 Q1821G205R01 11 159 Q1B21G162R01 11 113 Q1821G205R02(2) 11 160 Q1B21G163R01 11 113 Q1821G208R01 11 157 Q1821G163R02 11 113 Q1B21G208R03 11 160 Q1821G171R01 11 165 Q1821G210R01(2) 11 157 Q1821G174C01(2) 11 196 Q1821G213R01 11 151 Q1821G174R01 11 197 Q1821G213R02(2) 11 152 g
Q1821G174R02 11 196 Q1821G217R02 11 159 u o Q1B21G175R01(2) 11 153 Q1821G219R01(2) 11 157
- E Q1821G175R02(2) 11 158 Q1B21G222R01 11 160
{
N Q1821G180R01 11 152 Q1821G224R01 11 152 5
O O
O
....~
O O
TABLE 3.7.4-2 (Continued) e I
Oy MECHANICAL SNUBBERS *,**
o 1.
SAFETY RELATED MECHANICAL SNUBBERS j
d.
SNUBBER SNUBBER i
5 NO.
AREA ELEVATION NO.
AREA ELEVATION j
-a H
MAIN STEAM SYSTEM (Continued) c.
SLC SYSTEM p
Q1B21G225R01 11 147 Q1C41G113C02 11 185 Q1821G226C03 11 168 Q1C41G113C03 11 181 Q1B21G226R01(2) 11 173 Q1C41G113R02 11 181 Q1821G304R01 11 156 Q1C41G113R03 11 181 Q1821G306R01 11 151 Q1C41G117C02 11 145
]
Q1B21G311R01(2) 11 152 Q1C41G117R01 11 151 Q1821G355R01 11 147 Q1C41G119R01(2) 11 129 Q1B21G357C03 11 148 Q1C41G119R03 11 114 j
w i
)
Q1821G359C03 11 148 Q1C41G119R04 11 112 Q1821G361C03 11 147 Q1C41G119R05 11 112 y
4 Q1821G369R01(2).
11 148 Q1C41G120C05 11 155 Q1821G372R01(2) 11 148 Q1C41G124R01 11 159 j
-e i
Q1821G382R02(2) 11 152 Q1C41G124R03 11 162 Q1821G384R01 11 152 I
Q1821G423R01 11 147 d.
RESIDUAL HEAT REMOVAL SYSTEM i
Q1821G424R01 11 147 i
Q1821G490R03 11
'152 Q1E12G009R03 7
134 Q1E12G009R04 7
134
{
Q1E12G009R05 8
134 I
i L
o g
i CD E
i i
TABLE 3.7.4-2 (Continued)
E MECHANICAL SNUBBERS *,**
a 1.
SAFETY RELATED MECHANICAL SNUBBERS 9
a SNUBBER SNUBBER NO.
AREA ELEVATION NO.
AREA ELEVATION H
RESIDUAL HEAT REMOVAL SYSTEM (Continued)
RESIDUAL HEAT REMOVAL SYSTEM (Continued)
Q1E12G009R06 8
134 Q1E12G013R04 7
119 Q1E12G010R02 8
105 Q1E12G013R05(2) 7 100 Q1E12G010R04 8
103 Q1E12G013R06(3) 7 120 Q1E12G010R05 8
125 Q1E12G013R07 7
121 Q1E12G010R07 8
133 Q1E12G013R08 7
105 Q1E12G010R10 8
142 Q1E12G013R11 7
97 Q1E12G010R11 8
142 Q1E12G014C01 8
110 y
Q1E12G010R13(2) 8 113 Q1E12G014C03 8
106 Q1E12G010R15 8
103 Q1E12G014C04 8
130 y
Q1E12G010R16 8
104 Q1E12G014R01(2) 8 129 g
Q1E12G010R17(2) 8 104 Q1E12G014R03(2) 8 98 Q1E12G010R18(2) 8 96 Q1E12G014R04(3) 8 122 Q1E12G011R02(3) 8 99 Q1E12G104R05 8
105 Q1E12G012R02(2) 7 114 Q1E12G014R07 8
106 Q1E12G012R04 7
142 Q1E12G014R10(2) 8 109 Q1E12G012R05 7
142 Q1E12G014R11(2) 8 110 Q1E12G012R08 8
104 Q1E12G015R02 11 156 Q1E12G012R09 8
102 Q1E12G015R04(2) 11 143 Q1E12G012R13 7
119 Q1E12G015R06 11 143 Q1E12G012R15 7
133 Q1E12G015R07 11 214 Q1E12G012R16 7
99 Q1E12G015R08 11 210 Q1E12G012R18 11 133 Q1E12G015R11 11 143 Q1E12G012R19 11 133 Q1E12G015R17 11 210 Q1E12G013C01 7
110 Q1E12G015R19 11 214
%G Q1E12G013C02 7
130 Q1E12G015R20 11 144
- g Q1E12G013R02(2) 7 115 Q1E12G015R21(2) 11 140 Q1E12G013R03 7
110 Q1E12G015R28(3) 11 192
~,
co E
O O
O
O O
O
~
TABLE 3.7.4-2 (Continued)
MECHANICAL SNUBBERS *,**
ca 1.
SAFETY RELATED MECHANICAL SNUBBERS E
SNUBBER SNUBBER 35 NO.
AREA ELEVATION NO.
AREA ELEVATION H
RESIOUAL HEAT REMOVAL SYSTEM (Continued)
RESIDUAL HEAT REMOVAL SYSTEM (Continued)
H Q1E12G015R33(2) 11 205 Q1E12G021R03(2) 8 146 Q1E12G01SR38 11 157 Q1E12G025C01(2) 8 95 Q1E12G016C01 11 143 Q1E12G025R01 8
110 Q1E12G016R01 11 146 Q1E12G119R02 7
152 Q1E12G016R02 11 143 Q1E12G159R01 7
126 Q1E12G016R03 11 143 Q1E12G159R03 7
126 Q1E12G016R05(2) 11 143 Q1E12G159R04 7
131 R2 Q1E12G019R05(2) 8 139 Q1E12G019R07 8
149 e.
LPCS SYSTEM y
Q1E12G019R08 7
149 p
Q1E12G019R09(2) 7 143 Q1E21G001R05 9
96 Q1E12G020R01(2) 8 148 Q1E21G001R07(2) 9 96 Q1E12G020R02(2) 7 148 Q1E21G002R01 11 150 Q1E12G020R03 8
148 Q1E21G002R02 11 150 Q1E12G020R04(2) 8 148 Q1E21G002R03 11 151 Q1E12G020R05 7
147 Q1E21G002R04 11 153 Q1E12G020R07(2) 7 147 Q1E21G002R05 11 153 Q1E12G020R09 7
147 Q1E21G002R06 11 153 i
Q1E12G021R01 8
147 Q1E21G002R07 11 150 In c3 S E.
' 03 b
9
TABLE 3.7.4-2 (Continued)
E g
MECHANICAL SNUBBERS *,**
g 1.
SAFETY RELATED MECHANICAL SNUBBERS
[
SNUBBER SNUBBER 2
NO.
AREA ELEVATION NO.
AREA ELEVATION f.
HPCS SYSTEM h.
MSIV LEAKAGE CONTROL SYSTEM Q1E22G001R10(2) 8 96 Q1E32G103C01(2) 8 122 Q1E22G002R02(2) 8 96 Q1E32G106C01 8
121 Q1E22G002R03 8
96 Q1E32G109C01 8
122 Q1E22G003R01 11 153 Q1E32G119C01 8
148 Q1E22G003R02 11 153 Q1E22G003R03 11 149 i.
FEE 0 WATER LEAKAGE CONTROL SYSTEM Q1E22G003R04 11 150 Q1E22G003R05 11 151 Q1E38G102R01 8
145 g.
RCS LEAK DETECTION SYSTEM j.
RCIC SYSTEM S
Q1E31G116R01 11 169 QlE51G001R05 8
104 Q1E31G122R01(2) 11 149 Q1E51G001R06 8
109 QlE31G124R01(2) 11 151 Q1E51G001R09 11 133 QlE31G126C01 11 149 Q1E51G001R10(2) 11 134 Q1E31G140R01 11 159 Q1E51G001R15 11 178 Q1E31G140R02(2) 11 159 Q1E51G001R17(2) 11 190 Q1E31G148R01(2) 11 151 Q1E51G001R18 11 194 Q1E31G149R01(2) 11 151 Q1E51G001R19(2) 11 194 Q1E31G168R01 11 158 Q1E51G003R03 7
126 Q1E31G174R01(2) 11 151 Q1E51G003R04 7
117 Q1E31G176C01 11 147 Q1E51G003R05(2) 7 127 Q1E31G178R08 11 179 Q1E51G003R07 8
112
-%o Q1E31G178R09 11 179 Q1E51G003R08(2) 8 112 2
d Q1E31G181R01 11 156 Q1E51G003R09(2) 8 109 4
Q1E31G?43R01 11 144 Q1E51G003R10 8
105
~
Q1E31G243R02 11 140 Q1E51G003R11(2) 8 100 g
QlE31G246R01(2) 11 144 Q1E51G003R12(2) 8 106 E
O O
O O
O O
O i
)
TABLE 3.7.4-2 (Continued)
Og MECHANICAL SNUBBERS *,**
o 1.
SAFETY RELATED MECHANICAL SNUBBERS E
c!.
SNUBBER SNUBBER NO.
AREA ELEVATION NO.
AREA ELEVATION RCIC SYSTEM (Continued)
RWCU SYSTEM (Continued) w Q1E51G004C02(2) 8 97 Q1G33G002R18 8
116 Q1E51G004R01(2) 8 98 Q1G33G002R19 8
l 116 Q1E51G004R05(2) 8 106 Q1G33G002R21(2) 11 102 i
Q1E51G004R06(2) 8 96 Q1G33G002R22 11 102 Q1E51G004R07(2) 8 97 Q1G33G002R24 11 102 Q1E51G004R08(2) 11 164 Q1G33G011R01 11 140 j
Q1E51G004R11 8
97 Q1G33G011R03(2) 11 145 y
Q1E51G004R13(2) 11 167 Q1G33G012R01(2) 11 142
{
Q1E51G004R14(2) 11 152 Q1G33G012R02 11 152
)
y Q1E51G158R03(2) 11 143 Q1G33G015R01(3) 11 103 4
y Q1E51G180R01 8
97 m.
FPCC SYSTEM l
k.
COMBUSTIBLE GAS CONTROL SYSTEM Q1G41G006R01 9
114 Q1E61G001R07 11 189 Q1G41G006R07(3) 7 99 Q1G41G015R09 11 204 1.
RWCU SYSTEM Q1G41G016C08 11 163 Q1G41G016R04 11 166 Q1G33G002CO3(2) 11 113 Q1G41G016R24 11 163 Q1G33G002R03(2) 8 136 Q1G41G016R27(2) 11 203 Q1G33G002R05(2) 11 140 Q1G41G016R28(2) 11 206 Q1G33G002R08(2) 11 102 Q1G41G016R32 11 197 Q1G33G002R09(3) 11 102 Q1G41G018R06 9
197 Q1G33G002R10(2) 11 102 ko Q1G33G002R11 11 102 n.
SSW SYSTEM
. *A Q1G33G002R12 11 102 5
Q1G33G002R13(2) 11 102 Q1P41G001R14(2) 7 98
~
Q1G33G002R14(2) 11 102 Q1P41G002R10(2) 8 106 E
Q1G33G002R16 11 112 Q1P41G002R12(2) 8 106 2
Q1G33G002R17(2) 8 125 Q1P41G006C01 8
99
TABLE 3.7.4-2 (Continued) c>
l MECHANICAL SNUBBERS *,**
a g
1.
SAFETY RELATED MECHANICAL SNUBBERS 9
i SNUBBER SNUBBER NO.
AREA ELEVATION NO.
AREA ELEVATION s
SSW SYSTEM (Continued) o.
CCW SYSTEM Q1P41G006C17 8
99 Q1P42G002R06(2) 9 193 Q1P41G007R19 025A 144 Q1P42G002R07(2) 9 186 Q1P4IG007R20 025A 144 Q1P42G002R11(2) 9 186 Q1P41G007R23(2) 025A 138 Q1P42G002R13(2) 9 186 Q1P41G007R24(2) 025A 137 N
a m
r 0
0 0
O TABLE 3.7.4-2 (Continued) g MECHANICAL SNUBBERS *, **
Cy 2.
NON-Q MECHANICAL SNUBBERS C3 SNUBBER SNUBBER NO.
AREA ELEVATION NO.
AREA ELEVATION a.
MAIN STEAM SYSTEM c.
RESIDUAL HEAT REMOVAL SYSTEM N1B21G118R01 11 148 NIE12G172R02 11 129 l
N1821G118R02 11 147 NIE12G212R01 11 136 i
NIB 21G191CO2 11 137 NIE12G212R03 11 133 N1821G192003 11 136 i
N1821G193R01(2) 11 138 d.
REACTOR CORE ISOLATING COOLING SYSTEM N1821G193R04 11 136 N1821G231R01(2) 11 163 NIE51G120R01 11 127 b.
RECIRCULATION SYSTEM e.
REACTOR WATER CLEANUP SYSTEM y
N1B33G104R02 11 102 N1G33G002R01 7
120 N1833G105C01 11 101 N1G33G002R02 8
118 I
N1833G105C03 11 101 NIG33G002R03 8
123 N1833G105C04 11 101 N1G33G002R04 8
123 N1B33G105C05 11 101 NIG33G002R05(2) 11 147 N1833G105R01 11 101 NIG33G002R08(2) 11 164 N1833G106R01 11 102 H1G33G002R10(2) 11 147 N1833G107R01 11 102 N1G33G002R11(3) 11 180 N1833G107R02 11 102 NIG33G002R12(3) 11 180 N1833G108C02 11 101 NIG33G002R13 11 178 N1833G108R03(2) 11 101 NIG33G002R14 8
120 N1833G108R05 11 101 NIG33G002R21 8
120 N1833G108R06(2) 11 101 N1833G108R07 11 101 k
N1833G119R04 11 112 i
28 N1833G120R03 11 101 o
d N1833G123C01 11 102
~
y N1833G362R03 11 102 G
PLANT SYSTEMS 3/4.7.5 SEALED SOURCE CONTAMINATION LIMITING CONDITION FOR OPERATION 3.7.5 Each sealed source containing radioactive material either in excess of 100 microcuries of beta and/or gamma emitting material or 10 microcuries of alpha emitting material shall be free of greater than or equal to 0.005 microcuries of removable contamination.
APPLICABILITY:
At all times.
ACTION:
a.
With a sealed source having removable contamination in excess of the above limit, withdraw the sealed source from use and either:
1.
Decontaminate and repair the sealed source, or 2.
Dispose of the sealed source in accordance with Commission Regulations.
b.
The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.
SURVEILLANCE RE0VIREMENTS 4.7.5.1 Test Requirements - Each sealed source shall be tested for leakage and/or contamination by:
a.
The licensee, or b.
Other persons specifically authorized by the Commission or an Agreement State.
The test method shall have a detection sensitivity of at least 0.005 microcuries per test sample.
4.7.5.2 Test Frequencies - Each category of sealed sources, excluding startup sources and fission detectors previously subjected to ccre flux, shall be tested at the frequency described below.
a.
Sources in use - At least once per six months for all sealed sources containing radioactive material:
1.
With a half-life greater than 30 days, excluding Hydrogen 3, and 2.
In any form other than gas.
O GRAND GULF-UNIT 1 3/4 7-26 Amendment No. 8 l
+
3/4.3 INSTRUMENTATION
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BASES s
3/4.3.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION The reactor protection system automatically initiates a reactor scram to:
a.
Preserve the integrity of the fuel cladding.
b.
Preserve the integrity of the reactor coolant system.
c.
Minimize the energy which must be adsorbed following a loss-of-coolant accident, and d.
Prevent inadvertent criticality.
This specification provides the limiting conditions for operation necessary to preserve the ability of the system to perform its intended function even during periods when instrument channels may be out of service because of main-tenance.
When necessary, one channel may be made inoperable for brief intervals to conduct required surveillance.
The reactor protection system is made up of two independent trip systems.
Thrre are usually four channels to monitor each parameter with two channels in each trip system.
The outputs of the channels in a trip system are combined in a logic so that either channel will trip that trip system. The tripping of both trip systems will produce a reactor scram.
The system meets the intent of IEEE-279 for nuclear power plant protection systems.
The bases for the trip
,/)
settings of the RPS are discussed in the bases for Specification 2.2.1.
(
)
The measurement of response time at the specified frequencies provides assurance that the protective functions associated with each channel are com-pleted within the time limit assumed in the accident analysis.
No credit was taken for those channels with response times indicated as not applicable.
Response time may be demonstrated by any series of sequential, overlapping or tot al channel test measurement, provided such tests demonstrate the total channel response time as defined.
Sensor response time verification may be demonstrated by either (1) inplace, onsite or offsite test measurements, or (2) utilizing replacement sensors with certified response times.
3/4.3.2 ISOLATION ACTUATION INSTRUMENTATION This specification ensures the effectiveness of the instrumentation used to mitigate the consequences of accidents by prescribing the OPERABILITY trip set-points and response times for isolation of the reactor systems.
When necessary, one phannel may be inoperable for brief intervals to conduct required surveillance.
Some\\of the trip settings may have tolerances explicitly stated where both the high and lov values are critical and may have a substantial effect on safety.
Negative barometric pressure fluctuations are accounted for in the trip setpoints and allowable values specified for drywell pressure-high.
The setpoints of other instrumentation, where only the high or low end of the setting have a direct bearing on safety, are established at a level away from the normal operating range to prevent inadvertent actuation of the systems involved.
Except for the MSIVs, the safety analysis does not address individual
,7 s
sensor response times or the response times of the logic systems to which the
[
j sensors are connected.
For D.C. operated valves, a 3 second delay is assumed x__,/
before the valve starts to move.
For A.C. operated valves, it is assumed that GRAND GULF-UNIT 1 B 3/4 3-1 Order 64PR r g 1934
~
INSTRUMENTATION BASES ISOLATION ACTUATION INSTRUMENTATION (continued) the A.C. power supply is lost and is restored by startup of the emergency diesel generators.
In this event, a time of 13 seconds is assumed before the valve starts to move.
In addition to the pipe break, the failure of the D.C. operated valve is assumed; thus the signal delay (sensor response) is concurrent with the 13 second diesel startup.
The safety analysis considers an allowable inventory loss in each case which in turn determines the valve speed in conjunc-tion with the 13 second delay.
It follows that checking the valve speeds and the 13 second time for emergency power establishment will establish the response time for the isolation functions.
However, to enhance overall system relia-bility and to monitor instrument channel response time trends, the isolation actuation instrumentation response time shall be measured and recorded as a part of the ISOLATION SYSTEM RESPONSE TIME.
Operation with a trip set less conservative than its Trip Setpoint but within its specified Allowable Value is acceptable on the basis that the difference between each Trip Setpoint and the Allowable Value is equal to or greater than the drift allowance assumed for each trip in the safety analyses.
3/4.3.3 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION The emergency core cooling system actuation instrumentation is provided to initiate actions to mitigate the consequences of accidents that are beyond the ability of the operator to control.
This specification provides the OPERABILITY requirements, trip setpoints and response times that will ensure effectiveness of the systems to provide the design protection.
Negative barometric pressure fluctuations are accounted for in the trip setpoints and allowable values specified for drywell pressure-high.
Although the instruments are listed by system, in some cases the same instrument may be used to send the actuation signal to more than one system at the same time.
Operation with a trip set less conservative than its Trip Setpoint but within its specified Allowable Value is acceptable on the basis that the difference between each Trip Setpoint and the Allowable Value is equal to or greater than the drift allowance assumed for each trip in the safety analyses.
3/4.3.4 RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION The anticipated transient without scram (ATWS) recirculation pump trip system provides a means of limiting the consequences of the unlikely occurrence of a failure to scram during an anticipated transient.
The response of the plant to this postulated event falls within the envelope of study events in General Electric Company Topical Report NED0-10349, dated March 1971 and NED0-24222, dated December 1979, and Section 15.8 Appendix 15A of the FSAR.
The end-of-cycle recirculation pump trip (ECC-RPT) system is a part of the Reactor Protection System and is an essential safety supplement to the reactor trip.
The purpose of the EOC-RPT is to recover the loss of thermal margin which occurs at the end of-cycle.
The physical phencmenon involved is that the void reactivity feedback due to a pressurization transient can add positive reactivity to the reactor system at a faster rate than the control rods add negative scram reactivity.
Each E0C-RPT system trips both recirculation pumps, reducing coolant flow in order to reduce the void collapse in the core during two of the most limiting pressurization events.
The two events for which the EOC-RPT protective GRAND GULF-UNIT 1 B 3/4 3-2 Order
' APR I e 1984
INSTRUMENTATION C
BASES f mx (f
3/4.3.7.6 SOURCE RANGE MONITORS The source range monitors provide the cperator with infor:ation of the status of the neutron level in the core at very Icw power levels during startup and shutdown.
At these power levels, reactivity additions should not be cade without this flux level information available to the operatcr.
'4 hen the inter-mediate range =onitors are on scale adequate infor=ation is available without the SRMs and they can be retracted.
3/4.3.7.7 TRAVERSING IN-CORE PROBE SYSTEM The OPERABILITY of the traversing in-core prebe system with the specified minimum cc:plerent of equipment ensures that the ceasurements cDtained from use of this equipment accurately represent the spatial neutron flux distribution of the reactor core.
3/4.3.7.8 CHLORINE DETECTION SYSTEM The OPERASILITY of the chlorine cetection syste, ensures tnat an accidental chlorine release will be detected promptly and the necessary protective actions will be aute atically initiated to provide protecticn for control roce ersonnel.
Upon detection of a high concentration of chlorine, the control reca ecergency ventilation system will autenatically be placed in the isolation =cce of cperation to provice the requirec protection.
The detection systens requirec by tnis specification are consistent with the recc:=endations of Regulatory Guice 1.95
" Protection of Nuclear Pcwer Plant Control Rocs Operators against an Accidental Chlorine Release", Revision 1, January 1977.
3/4.3.7.9 FIRE DETECTION INSTRUMENTATION OPERASILITY of the fire detection instru entation ensures that adequate warning cacability is available for the prcept cetecticn of fires.
Tnis capa-bslity is required in order to detect and locate fires in their early stages.
Pro pt detection of fires will reduce the potential for damage to safety-related equip =ent and is an integral element in the overall facility fire protection progras.
In the event that a portion of the fire detecticn instru entatien is inoperable, increasing the frecuency of fire watch patrols in the affectec areas is required te provide detecticn capability until the inc;erable instrumentation is restored to CPEDJEILITY.
3/*.3 7.10 LCOSE-PART DETECTICN SYSTEM The OPERAEILITY of the loose-; art detection systen ensures that sufficient capability is avai?able to detect icose metallic parts in the pri=a y syste and avoid or citigate damage to prix y systen ccepcnents.
The allcw3bie out-of-service ti es and surveillance require ents are consistent with the reccccencations of Regulatory Guide 1.133, " Loose-Part Detection Prcgram for the Prir.ary System of Light-Water-Ccoled Reactors," May 195L GRAND GULF-UNIT 1 E 3/4 3-5 i
INSTRUMENTATION BASES O
3/4.3.7.11 RADI0 ACTIVE LIQUID EFFLUENT MONITORING INSTRUMENTATION The radioactive liquid effluent monitoring instrumentation is provided to monitor and control, as applicable, the releases of radioactive materials in liquid effluents during actual or potential releases of liquid effluents.
The alarm / trip setpoints for these instruments shall be calculated in accordance with the procedures in the 00CM to ensure that the alarm / trip will occur prior to exceeding the limits of 10 CFR Part 20.
The OPERABILITY and use of this instrumentation is consistent with the requirements of General Design Criteria 60, 63 and 64 of Appendix A to 10 CFR Part 50.
3/4.3.7.12 RADIOACTIVE GASm0US EFFLUENT MONITORING INSTRUMENTATION The radioactive gaseous effluent monitoring instrumentation is provided to monitor and control, as applicable, the raleases of radioactive materials in gaseous effluents during actual or potential releases of gaseous effluents.
The alarm / trip setpoints for these instruments shall be calculated in accordance with the procedures in the ODCM to ensure that the alarm / trip will occur prior to exceeding the limits of 10 CFR Part 20.
This instrumentation of potentially explosive gas mixtures in the waste gas holdup system.
The OPERABILITY and use of this instrumentation is consistent with the requirements of General Design Criteria 60, 63 ad 64 of Appendix A to 10 CFR Part 50.
O 3/4.3.8 PLANT SYSTEMS ACTUATION INSTRUMENTATION The plant systems actuation instrumentation is provided to initiate action to mitigate the consequences of accidents that are beyond the ability of the operator to control.
The LPCI mode of the RHR system is automatically initiated on a high drywell pressure signal and/or a low reactor water level, level 1, signal.
The containment spray system will then actuate automatically following high drywell and high containment pressure signals.
Negative barometric pressure fluctuations are accounted for in the trip setpoints and allowable values speci-fied for drywell and containment pressure-high.
A 10-minute minimum, 13 minute maximum time delay exists between initiation of LPCI and containment spray actuation.
A high reactor water level, level 8, signal will actuate the feed-water system / main turbine trip system.
O GRAND GULF-UNIT 1 B 3/4 3-6 Order APR f 8 1984
i
=
g.
3/4.5 EMERGENCY CORE COOLING SYSTEM q
BASES 3/4.5.1 and 3/4.5.2 ECCS - OPERATING and SHUTDOWN ECCS division 1 consists of the low pressure core spray system and low pressure coolant injection subsystem "A" of the RHR system and the automatic depressurization system (ADS) as actuated by trip system "A".
ECCS division 2 consists of low pressure coolant injection subsystems "B" and "C" of the RHR system and the automatic depressurization system as actuated by trip system "B".
The low pressure core spray (LPCS) system is provided to assure that the core is adequately cooled following a loss-of-coolant accident and, together l
with the LPCI system, provides adequate core cooling capacity for all break sizes up to and including the double-ended reactor recirculation line break, i
and for smaller breaks following depressurization by the ADS.
The LPCS is a primary source of emergency core cooling after the reactor i
vessel is depressurized and a source for flooding of the core in case of 1
accidental draining.
The surveillance requirements provide adequate assurance that the LPCS system will be OPERABLE when required.
Flow and total developed head values for surveillance testing include system losses to ensure design requirements are met.
Although all active components are testable and full flow can be demonstrated by recirculation through a test loop during reactor. operation, a complete functional test requires reactor shutdown.
The pump discharge piping is maintained full to prevent water hammer damage to piping and to start O
cooling at the earliest moment.
The low pressure coolant injection (LPCI) mode of the RHR system is provided to assure that the core is adequately cooled following a loss-of-coolant accident.
The LPCI system, together with the LPCS system, provide
' adequate core flooding for all break sizes up to and including the double-ended reactor recirculation line break, and for small breaks following depressurization by the ADS.
The surveillance requirements provide adequate assurance that the LPCI system will be OPERABLE when requirr.d.
Flow and total developed head values for surveillance testing include system losses to ensure design requirements are met.
Although all active components are testable and full flow can be demonstrated by recirculation through a test loop during reactor operation, a complete functional test requires reactor shutdown.
The pump discharge piping is maintained full to prevent water hammer damage to piping and to start cooling at the earliest moment.
ECCS division 3 consists of the high pressure core spray system.
The high pressure core spray (HPCS) system is provided to assure that the reactor core is adequately cooled to limit fuel clad temperature in the event of a small break in the reactor coolant system and loss of coolant which does not i
result in rapid depressurization of the reactor vessel.
The HPCS system permits the reactor to be shut down while maintaining sufficient reactor vessel water level inventory until the vessel is depressurized.
The HPCS system operates over a range of 1160 psid, differential pressure between reactor vessel and HPCS suction source, to O psid.
(\\
GRAND GULF-UNIT 1 B 3/4 5-1 Order
'APR t g 1984
3/4.5 EMERGENCY CORE COOLING SYSTEM BASES ECCS-0PERATING and SHUTDOWN (Continued)
The capacity of the system is selected to provide the required core cooling.
The HPCS pump is designed to deliver greater than or equal to 1440/5010 gpm at differential pressures of 1160/200 psi.
Initially, water from the condensate storage tank is used instead of injecting water from the suppression pool into the reactor, but no credit is taken in the safety analyses for the condensate storage tank water.
With the HPCS system inoperable, adequate core cooling is assured by the OPERABILITY of the redundant and diversified automatic depressurization system and both the LPCS and LPCI systems.
In addition, the reactor core isolation cooling (RCIC) system, a system for which no credit is taken in the safety analysis, will automatically provide makeup at reactor operating pressures on a reactor low water level condition.
The HPCS out-of-service period of 14 days is based on the demonstrated OPERABILITY of redundant and diversified low pressure core cooling systems.
The surveillance requirements provide adequate assurance that the HPCS system will be OPERABLE when required.
Flow and total developed head values for surveillance testing include system losses to ensure design requirements are met.
Although all active components are testable and full flow can be demonstrated by recirculation through a test loop during reactor operation, a complete functional test with reactor vessel injection requires reactor shutdown.
The pump discharge piping is maintained full to prevent water hammer damage and to provide cooling at the earliest moment.
Upon failure of the HPCS system to function properly after a small break loss-of-coolant accident, the automatic depressurization system (ADS) auto-matically causes selected safety-relief valves to open, depressurizing the reactor so that flow from the low pressure core cooling systems can enter the core in time to limit fuel cladding temperature to less than 2200 F.
ADS is conservatively required to be OPERABLE whenever reactor vessel pressure exceeds 135 psig even though low pressure core cooling systems provide adequate core cooling up to 350 psig.
ADS automatically controls eight selected safety-relief valves although the safety analysis only takes credit for seven valves.
It is therefore appro-priate to permit one valve to be out of-service for up to 14 days without materially reducing system reliability.
3/4.5.3 SUPPRESSION POOL The supression pool is required to be OPERABLE as part of the ECCS to ensure that a suf ficient supply of water is available to the HPCS, LPCS and LPCI systems in the event of a LOCA.
This limit on suppression pool minimum water volume ensu*es that sufficient water is available to permit recirculation cooling flow to the core.
The OPERABILITY of the suppression pool in OPERATIONAL CONDITIONS 1, 2 or 3 is required by Specification 3.6.3.1.
Repair work might require making the suppression pool inoperable.
This specification will permit those repairs to be made and at the same time give assurance that the irradiated fuel has an adequate cooling water supply when the suppression pool must be made inoperable, including draining, in OPERATIONAL CONDITION 4 or 5.
GRAND GULF-UNIT 1 8 3/4 5-2 Order APR t p 1984
i 3/4.5 EMERGENCY CORE COOLING SYSTEM i
BASES SUPPRESSION POOL (Continued)
In OPERATIONAL CONDITION 4 and 5 the suppression chamber minimum required 3
water volume is reduced because the reactor coolant is maintained at or below f
200 F.
Since pressure suppression is not required below 212*F, the minimum j
required water volume is based on NPSH, recirculation volume, and vortex preven-tion plus a l'2" safety. margin for conservatism.
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GRAND GULF-UNIT 1 B 3/4 5-3 Order PR I 8 1984
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