ML20004E419
| ML20004E419 | |
| Person / Time | |
|---|---|
| Site: | Midland |
| Issue date: | 04/29/1981 |
| From: | BECHTEL GROUP, INC. |
| To: | |
| Shared Package | |
| ML20004E411 | List: |
| References | |
| NUDOCS 8106120160 | |
| Download: ML20004E419 (250) | |
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i 9 PRESENTATION TO THE UTILITY DESIGN AND REVIEW BOARD 10 DESIGN TO ACHIEVE AND MAINTAIN COLD SHUTDOWN 11 WEDNESDAY, APRIL 29, 1981 t
HELD AT: BECHTEL POWER CORPORATION OFFICE 12 ANN ARBOR, MICHIGAN, 1:10 P.M.
13 14 v0LuME II 33 16 17 t
18 19 20 21 22 23 24 HURON REPORTING SERVICE 8J06120 t
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i 1 Ann Arbor, Michigan
2 Wednesday, April 29, 1981 3 At or about 1:10 o' clock P.M.
4 ___
5 MR. HUGHES: We have a new 6 transcripter, would everybody please recall to say 7 their name before they ask a question or make a comment, 8 to get us started, until she is familiar with who 9 everyone is.
10 We're going to go right into 11 Section V of our presentation, which is Cold Shutdown 12 following Chapter 15 type events.
13 Bob Schomaker of Babcock & Wilcox 14 will start it off.
15 MR. SLADE: Do you want to get 16 right through five before we ask questions again or 17 do you want to ask questions as they arise?
MR. HUGHES: If it's acceptable 18 19 to the Board, I'd like to go through the presentation. ;
i 20 Then we will go to the questio ns for five. l I
21 MR. COOK: I think - that's l
22 fine. Please proceed. ;
23 MR. SCH0 MAKER: Good afternoon. f 24 l
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1 My name is Robert Schomaker. I would like to address 2 Cold Shutdown as it relates to Chapter 15 type events.
3 I would address post-accident conditions that may exist.
4 and assess the capability of the Midland design to 5 proceed to Cold Shutdown. i 6 Can I have my first slide, j 7 please, 5-1.
8 All the transients that are i 9 analyzed in Chapter 15, except for the ATWS events, l 10 result basically in a reactor trip condition, subcritical ;
11 core with decay heat being removed by one or two steam f 12 generators or by HBI cooling. The final plant condition i
13 that one would see, basically depends upon the accident 14 that has been analyzed and the equipment that has been !
i 15 assumed to fail.
16 The equipment failures that are ,
1 17 assumed in Chapter 15, are based upon detemining i
18 and assuring a bounding response with respect to the ;
f 19 established criterion for those accidents. Thes.e may l 20 or may not be the worse single failure, relative to l f
21 the ability of achieving Cold Shutdown.
22 For most events analyzed in l
23 Chapter 15, the design objective of achieving Cold i 24 l l
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1 Shutdown in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> with safety-grade equipment can 2 be met. The transient analysis of Chapter 15 demonstrates i 3 that the plant can reach a hot stable zero power ;
4 condition with decay heat renoval. The event may require :
5 operator action in order to insure long tem heat l 6 removal or to insure adequate continuous subcritical .
7 margin. Sufficient time and indication exist for the -
t 8 operator to take the appropriate action.
9 Design basis event, such as a l I
10i steamline break or feedwater line break, may result in 11 the loss of one steam generator and may also result j 12 in the loss of forced reactor coolant flow.
l 13 May I have my slide figure 5-2, !
14 please. The essential control functions have been !
15 identified for Cold Shutdown capability, basically .
16 as reactivity and inventory control. The ability to l
17 control primary systempressure, and the ability to 18 remove heat or temperature control. Any accident in !
19 combination with a single failure that eliminates any l t
20 of these control functions, precludes the ability to 21 go to Cold Shutdown with safety-grade equipment.
22 The transients that are analyzed in Chapter 15 do not 23 result in the loss of any one of these functions.
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l Let's look at each control 2 function as we have identified them previously.
3 For reactivity and inventory control, we said that 4 these are provided in the short tem by tripping the 5 reactor control rods or by the emergency boration 6 system, should we decide we want to stay at hot zero 7 power for some period of time. In the long tem or 8 to go to cooldown, to go to a Cold Shutdown condition, 9 one would use the chemical addition system or use 10 high pressure injections from BWST. As long as you 11 don't lose the rods, you don't lose EBS. You don't 12 lose the chemical add system or lose HPI. You have reactivity 13 and inventory control. In tems of primary . system 14 pressure control, ciscussion was provided on the use 15 of auxiliary pressurizer sprays and the use of safety-16 grade heater banks.
17 My slide three, 5-3 In tems of 18 temperature control, the nomal and post-accident way 19 of removing decay heat is by use of the steam generators; 20 one or two generators, whichever happens to be availa 21 We have also talked a little bit about natural 22 circulation capability. The ability to ecol the 23 plant with two generators, with forced or with natural 24 HURON REPORTING SERVICE 76b5328
I circulation flows.
2 We have also mentioned that it 3 remains to be evaluated whether or not a plant can 4
achieve Cold Shutdown within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> with one 5 generator, under a natural circulation capability.
6 Along with the events of 7
Chapter 15, we have also looked at a design basis 8 tornado. This tornado -- survival of this event after 9 a design basis tornado, is assured by having reactor 10 trip, either by an operator performing a manual trip 11 or by loss of offsite power, causing gravity insertion 12 of the control rods. Reactivity and inventory control 13 can be provided from boration, either by BWST, emergency 14 boration system, or the chemical addition tanks.
15 Temperature control is generally maintained by controlling 16 steam generator pressure on the secondary side.
17 Pressure control, once again, by heaters or sprays.
18 Hot standby conditions can be maintained, essentially 19 indefinitely. It's mt always a requirment to go to 20 Cold Shutdown following a Chapter 15 event.
21 In your handout, in table 5-1, 22 there is a discussion, a summary of each of the 23 accidents that are analyzed for the Constaters Midland 1 l
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i 1 Plant.
2 My next slide, slide number four, 3 sunmarizes that sunmary. In other words, I have 4 chosen just a couple of events, some that result in 5 different configurations, just for us to look at an 6 example here today.
7 I chose steamline break, 8 essentially because that event can. result in a situation 9 where Cold Shutdown is not achievable in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> with 10 safety-grade equipment. One could have a loss of 11 offsite power; could have a loss of one HBI system; 12 i could lose one complete generator and therefore, having <
13 only one loop available, time in excess of 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> i
14 may be required.
15 For loss of normal feedwater, 16 Cold Shutdown is capable of being achieved within 17 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />, assuning one has auxiliary feedwater system 18 available to both generators. No limitations are 19 placed on Cold Shutdown capability following the loss .
20 of feedwater. l Control rod withdrawals, these 21 22 are single and multiple group withdrewals. Basically, 23 reactivity excursions. No physical damage to the j t
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I system. Yes, Cold Shutdown is achievable. We assume 2
that all auxiliary feedwater flow is available to both generators. There is nothing going on in the event 3
which would say that I have lost euxiliary feedwater; 4
77 8 # # #' "#' " "" "
- 5 ability to go to Cold Shutdown. I have chosen these 6
just as examples. They are addressed for all events !
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- g Let me basically sunmarize by r saying that the capability of achieving Cold Shutdown exists for the various conditions following Chapter 15 g
events. Various operator actions may be required.
Times in excess of 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> may also be required.
It may be desirable to stay at hot standby conditions l
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15 design objective, if such an action would say minimize 6
radiation doses.
g S there are reasons for staying 8
at a hot zero power condition and not proceen to g
Cold Shutdown.
20 I thank you for listening and I will now introduce to you Robert Burg, who will discuss fire protection. ,
24 HURON REPORTING SERVICE 7615328
1 MR. BURG: My name 10 Rob Budg.
2 I'd like to point out, this is a late addition to the 3 presentation. You received a handout this morning 4 that contains my text and my slides. I have been asked 5
to discuss briefly the ability of the Midland plant 6 to achieve Cold shutdown following a fire. We have 7 described this analysis as the fire protection safe 8 shutdown analysis.
9 The objective or purpose of 10 this analysis is to insure that at least one means 11 is available to reach and achieve -- to achieve and 12 mainta_n safe shutdown, following a design basis 13 or postulated fire.
14 The next slide, please. The 15 regulations and guidelines we are using on analysis 16 are 10 CFR 50 Appendix A Criterion 3, the Branch 17 Technical Position ASE 9.5-1, and 10 CFR 50 Appendi:< R ,
18 The assumptions in performing 19 this analysis are that we assume that exposure fire 20 can occur anywhere outside the primary containment.
Inside tne control room, interpret tnis to mean 21 22 that the exposure fire can disrupt any single 23 ca ~.inuous cabinet. ""ne goal of this analysis , given 24 _ g_
HURON REPORTING SERVICE 761 5328
l 1 those exposure fire ;, is to demonstrate that the plant 2 can achieve hot standby immediately and achieve Cold 3 Shutdown within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
4 The criteria we use in the 5 analysis is that first, only a single fire occurs.
6 The fire can cause hot shorts, open circuits or shorts to ground. The failures in the plant, assune the 8 analysis are only those failures caused by the fire.
9 Offsite power may be available or it may not be 10 available. The fire in the control room, we assune 11 limited manual action is available to be taken inside 12 the control room, but extensive manual action can be 13 taken outside the control room.
14 The analysis, as we are performing 15 it, takes the following approach: We identify the 16 equiP ment needed to achieve and maintain safe shutdown 17 conditions, we identify the possible effects of the 18 exposure fire on those identified pieces of equipment, 19 and finally, we provide protection to insure the 20 operation of that equipment, if in fact the fire does 21 affect it in some manner.
22 Th systems identified needed 23 to achieve this cold or safe shutdown condition are 24 HURON REPORTING SERVICE 761 5328
1 basically the same systems that you hLve been discussing 2 all moming. We have to look at a few more systems 3 that we haven't talked about previously. These are 4 the support systems to the systems you have seen before, ;
At the end of this analysis, 5
6 we will be able to show - to demonstrate that the 7 Midland Plant will be able to achieve and maintain a 8
safe condition, following any exposure fire. Thank you r 9 Ed.
MR. HUGHES: Thank you, Rob and 10 11 Bob.
12 All right, At this timeswe will 13 go ahead into Board questions on the area presented, 14 Cold Shutdown and the Chapter 15 events and Cold 15 Shu.tdown in the event of a fire.
MR. SULLIVAN: Question of 16 17 clarification for Bob.
In talking about the tornado, 18 19 response for the tornado, you had the BWSTs there, but those are not tornado protected things.
20 MR. SCH0 MAKER: That is correct.
21 22 That is not.
MR. SULLIVAN: You'd use them 23 24 HURON REPORTING SERVICE 7615328
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l 1 if you had them, but - l 2 MR. HUGHES: Correct. ,
3 MR. TAYLOR: The last two slides 4 that were presented up there, the next to last slide, 5
I think it said you would identify the equipment :
6 needed for Cold Shutdown and then the last slide l 7
went on over into the - on a systems level basis.
8 Will the evaluation in tems of f r
g equipment needed, go down to a very final level of f 10 detail, down to the relay, switch gear, pump valve, !
i 11 et cetera, level? ,
MR. HUGHES: Yes, it will. 1 12 !
13 When it talks about a system, it would encompass all !
14 those supporting features, whether it be a bus, a 15 valve, solenoid, that are required to perfom whatever 16 safety function is required or Cold Shutdown function.
17 MR. TAYLOR: So this will be i
some sort of a matrix that lists all the equipment 18 f and then shows that it's redundant and protected ;
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against fires in an acceptable way? l 20 g MR. HUGHES: Jim, it will be an analysis. I'm not sure it will be in a matrix 22 fom in the final process. It's in the process now, ,
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1 but yes, that type analysis will be conducted such
2 that we have looked at all the necessary components 3 and assured that they are available. !
4 MR. TAYLOR: Down to basically ,
5 the relay level? ;
6 MR. HUGHES: Yes.
7 MR. LEWIS: Further point of a clarification. We are not necessarily looking at l c
9 each of those entire systems. We are looking at those ;
10 portions of those systems and those ec=penents within i
11 the system that are required to be operable in order !
t 12 to shut down safely following a fire.
13 MR. ANAND: In the itern 5-K f
14 discussion, the Midland design being reviewed, when !
15 is that scheduled? When will we be getting this 16 material for review? What is the schedule?
17 MR. HUGHES: Rob, can you answer !
18 that question? I don't know the schedule. You are 19 talking about fire protection review, completion and 20 submittal?
MR. BURG: We were discussing 21 22 this with the NRC two weeks ago. We agreed to update and submit our fire hazards analysis in the early part 23 24 13 -
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of July. That's - for clarification, that's our 1
2 Appendix 9A of our JSAR.: .
MR. ANAND: I'd just like to 3
4 Point out that on April 23rd, commissioners have 5
ordered that all the near-term OLs licensee shall 6
comply with the fire protection program set forth 7
in Appendix R, 10 CFR part 50, and we will b3 writing a letter to all. the applicants telling them that 8
g Apper. dix R,10 CFR part 50, shall be used as a guidance for the review of tae fire trotection trogram and licensee ecscliance 10 jj with the requirement set forth in the Appendix R, as m dified by the accepted exceptions vill be made 2
as a license ecndition, as IEC has made on the following 13 l
two license conditions. The licensee has to identify g
8nY exceptions to the programs that will be taken into 15 ppendix R as alleged from the position 9.5-4 and the 16 licensee will also describe any alternative which will g
be an equivalent level of the fire protection.
8 MR. HUGHES: Thank you, and this 19 letter will be forthcoming?
,0 4
MR. ANAND: Yes.
21 MR. HUGHES: This next week?
22 MR. ANAND: Sociething like that.
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1 MR. COOK: I see the list 2 of criteria here that you are going to conduct this 3 review against.
4 MR. HUGHES: We're talking fire?
5 MR. COOK: Yes, fire protection.
6 I guess my question is, do we have enough specificity 7 in the individual criteria to be able to conduct, you 8 know, a review that will enable us to fulfill all the 9 expectations that the NRC has of us when they get 10 this submittal in July?
11 MR. HUGHES: Rather than giving k2 you my opinion, let me ask the reviewers, which are 13 Rob Burg and Don Lewis, 14 At present , ve believe we have sufficient 15 specificity to conduct this review and supply this 16 infomation in July, given the latest infomation on 17 Appendix R7 MR. BURG: We are lacking a 18 19 few pieces of infomation. The major piece of 20 infomation we're lacking is the deilnition of the scope of the fire inside the control room. We have 21 made this presentation to the NRC. We did it on, I 22 23 think it was April 15 The NRC agreed to get back to 24 t I
HURON REPORTING SERVICE 761 5328
- us within two weeks. Today is two weeks and we have 2
still not heard from them. 1
., MR. ANAND: We are still working j a
on it and we haven't decided which way to go. There is l 4
a lot of difference of opinion. !
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MR. HUGHES: Are you in a position i 6
7 to tell us approximately wilen you think we will hear?
MR. ANAND: As we told Bob, he 8 ;
9 will have to keep on checking with us in the interval '
tw weeks time. Whenever we come to a decision, we ;
10
- j will let him know.
MR. HUGHES: Because that will 4 12 have a direct affect on our expected submittal dates.
13 MR. COOK: Can one use the 14 Precedence being, you know, sutmitted in the near tena 15 OLs, in terms of how to get the specific 17 definition down in the bowels of this review? I look !
t at this list of criteria. To me, although I'm not 18 g
working directly in the area, there is some questions, unanswered, as far as my recognition of exactly what 20 these things mean.
MR. ANAND: Okay. !
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MR. GARRICK: Regarding your !
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I Chapter 15 analysis, there is some language here that 2 indicates that maybe you identified some troublesome 3 areas as a result of instrumentation failure. ,
t 4 I'd be very interested to know ,
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5 about that, if you did, and what their impact was on 6 achievement of Cold Shutdown and also, has the failure 7 of an entire instrunent power bus 'beenanalyzed when 8 you considered these events?
9 MR. SCH0 MAKER: The word 10 instrunentation should not appear in your text. I 11 Equipment failures, single failures are not limited 12 to instrunentation and no, there was no instrumentation
\ 13 single failure that was uncovered as being troublesome. -
14 It was my impression that that 15 word was going to be removed. That should not 1+M t 16 single failures to instrunentation.
17 The second question, I believe 18 the answer was no, but I forgot the question. l
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19 MR. HUGHES: Was a failure of l l
20 an entire instrunent bus considered? i 21 MR. SCH0 MAKER: The answer is no. l
.22 The failure of an entire instrument bus is not t
'23 nonna11y considered Chapter 15 event, and what we reviewed l,
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1 was - were those accidents which are normally 2 considered in Chapter 15 t 3 MR. GARRICK: I noticed you 4 avoided the language in your presentation, and I 5 was just picking it up from your written material.
6 MR. VAN HOOF: I have got a 7 question concert 11ng the instunentation and control l 8 functions in the event of a fire which might require 9 the abandonment of the control room and controls from ;
i 10 the auxiliary shutdown panel. j i
11 If there complete separation l 12 of the controls and instrumentation that goes to the
13 auxiliary shutdown panel or do they go via the control l 14 room, in they're routing?
15 MR. BURG: To answer that, I 16 have to explain that we are protecting one channel 17 of safe shutdown equipment for a fire in the contzul l 18 room. Channel A will be provided with what we call 19 transfer switches. These will provide complete 20 electrical independence between the controls in the :
21 control room and the controls on the remote shutdown i
22 or auxiliary shutdown panel.
l 23 Channel B, the alternate i i
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f 1 redundant train of safe shutdown equipment, vin not be p-ovided i 2 with tranafer switches, and will not be electrically 3 independent between - there will not be electrical 4 independence between the two panels, so if you have a 5 fire in me control room, it's possible that you would I
6 lose channel B of controls on your auxiliary shutdown .
7 panel, but channel A would still be available. ;
1 8 MR. VAN HOOF: Where will these ,
9 transfer switches be located?
10 MR. BURG: We are installing a ;
11 tzsnsfer switch panel in the channel A electrical 2 penetration area, which is, I believe, elevation 630 13 or 628 in the auxiliary building.
14 MR. VAN HOOF: In the design of 15 the auxiliary shutdown panel, was consideration given i 16 to proceeding from a hot condition to Cold Shutdown 17 and controlling it fmm the auxiliary shutdown panel?
18 MR. HUGHES: The design in -
19 uses the auxiliary shutdown panel, controls it fmm I 20 the auxiliary shutdown panel, but it does not utili::e 21 exclusively the auxiliary shutdown panel.
22 MR. VAN HOOF: I wesn't intending 23 that you only use the auxiliary shutdown panel, but 1 24 19 -
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1 all control panels throughout the plant, other than the 2 control room. With that capability, can you attain 3 Cold Shutdown?
4 MR. BURG: I'm sorry. Could 5 you repeat?
6 MR. VAN HOOF: .If you had to l
7 abandon the control room in case of a fire or some 8 other occurrence and you were controlling the plant l 9 from the auxiliary shutdown panels, with those panels !
10 and any other controls in the plant such as local 11 control of a punp or whatever, can you attain Cold 12- Shutdown?
13 MR. HUGHES: Yes.
14 MR. BURG: The answer is'yes.
15 MR. LEWIS: One clarification.
16 You left out or aitted manual valves. There would 17 be manual operation required as well.
18 MR. VAN HOOF: Manual valves 19 included. i i
20 That's all the questions I have.
21 MR. MAZErIS: Going back to your 22 slide, point of confusion.
23 On the steamline break, it was 24 HURON REPORTING SERVICE 761 5328 l l
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1 indicated, as I recall, it was divided into short tem 2 and long tem, and it was indicated that the emergency 3 boration systesa was included as one of the systems 4 available to cope with a stes=line break.
5 With the idea of the traditional 6 FSAR type calculations, is there - does the emergency 7 boration system play a role? Was there an intent for 8 it to play a role in mitigating the. consequences of 9 a steamline break that -- to meet the acceptance 10 criteria in the FSAR, during the short tem?
11 The acceptance criteria I'm 12 talking about, as I recall, are pressure, a hundred 13 and ten percent of design pressure and I believe the 14 other criteria is either DNB or return to power.
15 MR. HUGHES: For the criteria, 16 I'm going to have Bob Schomaker answer that.
17 MR. SCHOMAKER: EBS is not a 18 required system for mitigation of a steamline break 19 event. Its use was not considered in any of the 20 steamline break analyses presented in the Midland 21 Chapter 15.
22 MR. HUGHES: I believe it's 1
23 correct that that has to do with the long tem timing 24 21 -
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l towards Cold Shutdown.
2 MR. TAYLOR: To what extent can 3
you operate the service water system from the auxiliary 4
shutdown panel?
5 MR. HUGHES: Mike? What do we 6
have on that?
7' MR. GERDING:. The controls for 8
the service water system are not located at the 9
auxiliary shutdown panel. They are -- the service 10 water system is an automatically operated system.
l1 The controls are provided outside the control room 12 at meter control center switch gear and tne like. ,
13 MR. HUGHES: So the answer, 14 Jim, really is there is no specific control of the 15 service water system available from the auxiliary 16 shutdown panel. It's available outside the control room.
17 MR. GIBSON: Do you have status 18 indication of the condition of that system at the 19 aux shutdown panel? If I can't centrol it , I'd at least 20 like to know whether it's running.
21 MR. HUGHES: I believe we'll have 22 to check on that and get back to you, rather than just 23 speaking from memory.
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MR. TAYLOR: Is the same true l 1
for the instrument air system? l 2
f MR. HUGHES: What do you mean?
3 MR. TAYLOR: The ability to know 4
a s doing or con % 1 H.
5 MR. HUGHES: No. Again, as we 6
7 said earlier, we don't treat the instrtsnent air systa g
as a safety related system, so there would be no indication of status of the air syste on the g
auxiliary shutdown panel. We don't consider the to instrument air required for safe shutdown.
g MR. HOOD: Did you comment n the ability to trip the reactor from outside the 13 control room, from the auxiliary panel?
MR. GERDING: I believe the 15 procedures - I can't speak for the final procedures of - for evacuation of the control room, but they g
may in 1 de tripping the reactor before leaving the 8
control room; however, the capability does exist to g
trip the reactor outside the control room, at the 20 Control rod drive breakers themselves.
MR. HUGHES: Effective, we have 22 no scram switch on the auxiliary shutdnm panel.
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l 1 MR. GARRICK: In your fire 2 analysis, you talk about the - considering exposure 3 and exposure fire anywhere at the plant.
4 Can you elaborete on that a 5 little bit as to how that was done? In other words, 6 were you talking about different locations and fires in 7 those different locations.
8 Are you talking about the growth 9 of a fire from one location to another?
10 MR. HUGHES: Basically, for the 11 exposure fire, it's asstmed at different locations 12 within the plant and it's not really the growth of a 13 fire. It is a mechanism for evaluating different 14 locations for their capability to withstand a fire.
15 MR. BURG: John, we look at an 16 exposure fire everywhere in the plant. We don't select 17 specific locations, so we have analyzed the whole plant, 18 except for inside the biological shield.
19 MR. HUGHES: As opposed to a 20 fire starting someplace and growing forward with the
.21 sequential cascading of items. Is that what you are j 22 talking about?
23 We don't analyze in that fashion. <
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I We look at all the locations. I 2 Yes. The requirements MR. BURG:
3 are - there are certain requirements in Appendix R 4 that give you the extent of an exposure fire and that's 5 as far as we have gone, basically. If you come to a l 6 fire stop, front rated fire barrier, 20 foot of free 7
air space with no intervening combustibler, you don't 8 have to assume the fire propagates any further than tha :,
9 MR. GARRICK: Does your analysis 10 draw a distinction between the level of threat, as a lI function of location?
12 MR. BURG: No, it does not.
13 We assume that we have certain pieces of equipment 14 that are required to operate and we will protect those 15 pieces of equipment so they vill operate. We haven't d'one 16 any more in depth level beyond that.
17 MR. SLADE: Do I understand you i
18 currectly that in evaluating the fire, the exposure 19 fire, that you do not also evaluate simultaneous other 20 events which may occur in the plant?
21 MR. HUGHES: That's correct.
22 MR. BURG: The only faults are 23 those caused by the fire. They might occur someplace i 24 HURON REPORTING SERVICE 7615328
1 els e. Like, you may blow a fuse someplace else 2
because of a fire in one location, but it's caused 3 by a fire.
MR. BURG: One clarification 4
on that. The only fire we look at in natural 5
6 occurrence is your reactor coolant pump lube oilcollection 7
system where Appendix R forces you to analyze that as a result of an earthquake, and-it's a non-seismic 8
g structure or systs, so that in that one case, you look at a natural occurrence causing a fire, but 10l that's the only one.
11 MR. TAYLOR: Miscellaneous 12 queetion. Are the steam generator level instrtanents j ,,,
and their readouts qualified?
g
. GH : 1 ed, you mean 15 16 MR. TAYLOR: Yes.
g.
MR. GERDING: Yes, they are.
g MR. SULLIVAN: Rob, can you cc= ment g
on the fire protection analysis? The assumption of loss of offsite power throws you into a whole different mode of operation and calls into play a number of other systes that the operators wouldn't necesrarily, nomally
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HURON REPORTING SERVICE 7615328 l
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1 rely on. Is there a mechanism for - well, or some 2 credible association between an exposure fire somewhere 3 in the plant and the loss of offsite power?
4 MR. BURG: The exposure fire 5 that you would look at would be a fire in your 6 electrical distribution system, of some sort, but you 7 - that would be one fire, but Appendix R requires you 8 to look at the fire with offsite power available or 9 offsite power unavailable, so you have to include that 10 f in your analysis.
1 MR. HUGHES: It is more by 12 definition, as far as what the analysis has done, that 13 we had to do both.
14 MR. SULLIVAN: It gets back to 15, the earlier comments that John was making about risk 16 and spending money and that kind of thing, and Raj 17 mentioned earlier the business about exceptions to 18 Appendix R and it would seem to me that if one in not 19 talking about a fire in an area that could credibly 20 be the result of a consequential loss of offsite power, 21 and then, from a risk or reliability point of view,
. 22 that you would want te look at what alternatives are
~
l 23 available to the operator to accomplish a particular 24 27 -
HURON REPORTING SERVICE 761 5320
1 function.
MR. HUGHES: I guess I can only 2
3 ask Raj to comment on that. I believe in years past, 4 there used to be some consideration of whether the fire caused a generator trip or a reactor trip, [
5 6
directly as being somehow tied to loss of offsite 7
power, but presently, I believe it's just defined as 8
look at it with offsite power and look at it without 9
offsite power and no mechanistic coupling. l MR. ANAND: But safe shutdown 10
- j should include the loss of offsite power.
MR. HUGHES: I believe Terry's 12 13 question was with regard to a fire and any physical 14 coupling, to loss of offsite power, as the fire causing 1 ss f ffsite power and whether that's a realistic 15 analysis requirement; is that correct, Terry?
16 MR. SULLIVAN: Ri ght.
17 MR. HUGHES: I can only say it's 18 jg a requirement and if Raj cares to comment on that --
MR. SULLIVAN: Let me put it 20 an ther way, then. I'm not trying to put you on the 21 spot. I'm trying to find out what Bechtel is doing.
It seems to me that if we're 23 28 -
24 HURON REPORTING SERVICE 7615328
1 l
i getting in a situation where as a result of the 2 analysis, you are considering some change to the l 3 Pl ant or whatever, then you oy;ht to ask the question l 4 about whether it's - how probable the event is and 5 also what the consequences of the change are.
6 Again, gr tting back to John's t
7 Point, could the change possibly result in a reducticn !
8 f the risk, and if that's the case, then it seems to g me we have the obligation to ask for an exception to the 10I requirements and the question I guess is, are we
[
33 considering that rigorously in our review of the plant g for fire protection?
13
. : n Lewis, I p ess I'm going to let you comment on that.
. . a we're doing is 15 16
- ' "" " I" " '" Y * *
- s g are based on our understanding of the NRC requirements, 8
really last summer and last fall -- as they were g understood last sunmer and last fall, and perfoming 20 a alysis, identifying areas in the systems where design changes may be required, and then proposing : nose -
changes.
It's possible that the plant, HURON REPORTING SERVICE 76153 8
1 overall plant reliability is being impacted. It's 2 Possibly beins; reduced by inclusion of some of these 3 transfer switches. The design is such that it's being 4
reviewed to minimize that, but just the insertion of those transfer switches could potentially be reducing 5
6 the plant reliability somewhat.
7 We're forced to that conclusion 8
or that design option by the criteria that has been -
9 sent to us.
MR. SULLIVAN: Let me follow up 10l 3) further. If you find an area where, in your judgment, 2
the change necessitated by, I guess, I prefer to call 13 them guidelines, until I get the order or whatever, 14 y u know, are you making a conscious effort to assess whether an exception sMuld be requested, based on the 15 Specific plant design? Realizing that when the NRC 16 writes these types of criteria, they don't necessarily 37
-- they can't assess the detailed impact on a plant, 18 jg and do we have examples of areas where we might request
- ** U 20 MR. LEWIS: I think we have some 21 question in our mind, the general question of reliability.
This was discussed both, with Consuners and with the g
- ~
24 HURON REPORTING SERVICE 761 5328 l l
l
I l
t NRC last st;mmer and the decision has been to follow the 2
course of action that we're on.
That is, to follow through the 3
design changes, based largely on the precedent that 4
the NRC has managed to force other plants to do this and 5
Midland is likely not going to be an exception in the 6
basic area of the fire analysis, so yes, the question 7
has been raised. There has not been a specific risk 8
g analysis done or any type of a sneak circuit analysis done on the design.
O In fact, the logic changes, I g
don't think are well enough defined yet to do that, in any case. This far, the decision has been based on a precedent, based on the realities of licensing lire -- that we shall go on with the transfer switch.
5 Let me straighten one thing out.
16 We don't have any reservations at this point or feelings the.t the designs we're creating are unsafe. That'c not 18 what I'm trying to say at all, but we have no c done any reliability assessment -- risk assessment comparison between the old design and the new one.
21 MR. HUGHES: We are drawing a 22
' distinction between reliability of the plant and safety 23 l
24 HURON REPORTING SERVICE 761 5328
I of the plant and we have no qualms or doubts as to the 2 safety of what we're putting in. The impact on 3 reliability with any addition of 'ransfer c switches 4 and others are not the subject of a risk analysis by 5 Bechtel. Rather, given schedule consideretions and 6 precedent, we're proceeding with the designs that 7 comply with the requirement as we interpret them and 8 as precedent indicates.
9 MR. TAYLOR: I have one more 10 miscellaneous question. Looking at the issue of 11 single failures, and this is not just related to the 12 Cold Shutdown capability, but the DHR system in general.
13 F.as an evaluation been made of the consequences of 14 lifting and sticking open the big relier valve on the 15 drop line, just after you go into the - just after 16 you activate the low pressure injection systm?
17 MR. HUGHES: Tom Ballweg, are 18 you familiar with any analysia ?
19 MR. TAYLOR: It's the one 20 inside the containment that goes to the sump.
21 MR. BALLWEG: I guess I'd like 22 a little more clarification on that. You said after l
-- 23 you initiate the low pressure injection 24 -
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i HURON REPORTING SERVICE 7615328
1 l
1 MR. TAYLOR: After you put the 2 IER system into operation, you are in the cooldown 3 mode and you just open up the valves inside the 4 containment in the drop line and this valve lifts 5 and sticks.
6 MR. BALLWEG: To my knowledge, 7 there has been no specific anelysis done on that.
8 MR. HUGHES: What you have, 9 in that case, is a small break LOCA, which has been 10 analyzed. Not that specific case, but small break LOCA 11 capability to meet them has been analyzed. Essentially ,
12 that's what has been created in the scenario you're 13 talking about.
14 MR. BALLWEG: Well, except you 15 are at depressurized condition.
16 MR. HUGHES: Correct.
17 MR. TAYLOR: It's a little bit 18 unique, though, because you're going to go -- you're 19 going to be trying to use those pumps to take suction 20 on the reactor coolant system, which nas just probably 21 gone to saturated conditions.
Well, the overall question is, 22 has an evaluation been made of that, and the anser is 23 24 33 -
HURON REPORTING SERVICE 761 5328
I 1
no, not yet.
MR. BALLWEG: It goes a little -
2 bit further. I think the action would be - should h, 3
under those circunstances, to close the letdown valves, 4
5 line back up to the borated water storage tank and start LP injection.
6 MR. TAYLOR: But then there is 7
not a hole in the system.
8 MR. BALLWEG: That's right, but 9
10 y u can bring pressure back up and you can control the subcooling in the system and you can, if necessary, 33 reestablish natural circulation or forced circulation, depending exactly where you are at, using aux feed ~
13 g
and vent through the steam generators, and you have you:s
' ""'#87 #' ** 8
- E" "
15 MR. HUGHES: Tom, is the closing 6
g of those letdown valves automatic or manual?
. e ee s 18 g
-- they're closed on high pressure.
MR. TAYLOR: I would recommend 20 that consideration be given a little more carefully to the need for a study on that particular event, because it's such a big valve and it affects both the 23 34 ~
24 HURON REPORTING SERVICE 7615328
1 punps. It's on that common line. .
2 MR. BALLWEG: Can you more ,
3 specifically define ~
4 MR. TAYLOR: Just that.
5 MR. BALLWEG: What I understood 6 your request to say, you wanted us to do an evaluation 7 as to whether or not a study would be requiz ed? o MR. TAYLOR: Consideration ought 8
9 to be given a little more carefully than just in the 10 room, as to whether that is needed.
11 MR. BALLWEG: So you want us !
i2 to take that up as an action item? -
MR. COOK: I certainly agree.
13 MR. JENSEN: I'd like to add 14 15 something to that. Perhaps there is a possibility of 16 damage here to the decay heat renoval punp by cavitation, 17 so that they could not be subsequently used, to either 18 cool down the plant or inject water into the plant and 19 in the injection pump.'
MR. BALLWEG: Could you explain !
20 21 how you see them being subject to cavitation, if the 22 saf ety valve is open due to a hign pressure condition?
MR. TAEOR: Stuck open in the 23 ,
24 HURON REPORTlNG SERVICE 761 5328
1 system. That very quickly could saturate the condition 2 and it gets vapor bound.
3 MR. BALLWEG: The DHR p eps 4 are very low in the system so that the static head 5 of the water from RCS is more than sufficient to 6 Provide required NPSH to the punps, so as long as 7 the line is full of water --
MR. SM DE: That's the question.
8 9 It may not be full of water. It may be full of 10 bubbles or steam, as a result of flashing thmugh 11 the relief valve.
MR. BALLWEG: At that point, 12 13 either you don't . have an ECCAS or the DHR pumps are tripped on low flow. If you're not cetting adequate flov 14 15 through th m , it could be the result of cavitation 16 or whatever. The DHR pumps will trip and be protected.
MR. COOK: I think it gets into 17 the details, what we're asking you to come back to.
18 I think the question, as I have heard it from Jim 39 20 Taylor, is a situation where he thinks he sees something 21 which ought to be looked at from a preventative point of view. What would you do if that particular valve 22 were to stick open? Can we sense it and can we cut it 23 24 HURON REPORTING SERVICE 761 5320
1 off, and even in addition to that, look at the l 2 consequences of having something like that occur.
3 MR. HUGHES: Jim, can I ask a 4 question? So far as I believe, you are postulating 5 a non-mechanistic operation of this valve; is that I
6 correct?
7 MR. TAYLOR: No, no. That line, 8 which is normally at atmospheric pressure, is -- when 9 you open the block valves coming down the drop line, 10 it now gets syste:m pressure and maybe, because of set 11 point drift or whatever, the valve lifts. As soon as 12 it sees the pressure coming down the drop line --
13 MR. HUGHES: So you have an 14 erroneous set point, followed by a failure of the valve?
15 MR. TAYLOR: Just lifts and 16 sticks open.
17 MR. COOK: The relief valve 18 on the system, it has to be postulated to operate 19 sometime.
20 MR. BALLWEG: The relief valve 21 set pressure is substantially above the pressure which 22 Permits opening of those particular valves. Those 23 let down valves, I believe, have a set point pensitted 24 HURON REPORTING SERVICE 7615328
I 300 PSI to pemit opening to start with - 340, ekay.
2 and I have to look what the set pressure is on thoce 3 valves.
4 MR. PRATT- 3@.
5 MR. TAYLOR: Just relief valves 6 in general cre notorious f< problems, and it seems 7 that if it's something as saple as a special procedure 8 or special precaution, something like that could 9 address it, then fine.
10 MR. HUGHES: My question really 11 was, how do we get there because it's a relatively 12 standard relief with a relatively high set point.
13 It has to get some set point because of it, and that's 14 where I was trying to get to, whether we start 15 examining the random opening or not.
16 MR. COOK: If that's your 17 evaluation at the time, you can tell us, but I want 18 to understand what we can do to sense it, if it's j 19 open then. )
20 MR. HUGHES: I understand the 21 back end for the scenario. You want it looked at.
1 1
22 I want to understand how we get there.
23 MR. SULLIVAN: First off, don't 24 -
38 -
! HURON REPORTING SERVICE l 761 5320 l
I
'i forget -- the first part of the problen was what's 2
the probability of the railure, so don't ignore that 3 ;'n your study.
4 I guess if your initial reaction 5 is, it is not probable at all or not possible, then 6 the study ends, it seems to me.
7 MR. HUGHES: Terry, so many 8 things, you can't say it's possible.
9 MR. SULLIVAN: I'm not prejudging to the answer. I'm just saying don't forget the first 11 step in the problem.
12 MR. PEATT: I think you'd have 13 to get your situation, where you're at a px essure 14 lower than your relief valve set point, otherwise the 15 automatic closer interlock prevents opening of the 16 drop line valves at a high pressure.
17 You would then have to establish 18 let down decay heat drop line valve flov and then have E.
19 pressure increase, such that the relief valve open.s.
20 MR. GIBSON: We have had some 21 occurrences in 1be industry where -- I don't know if 22 it's been a valve failure open, but they have vaper 23 bound DHR through some means or another. I think trying 24 l l
HURON REPORTING SERVICE ,
7615328
1 to argue why this wouldn't happen, I don't think is too 2 fruitful right here.
3 MR. HUGHES: We'll go ahead and 4 provide this and open action the infomation the Board 5 requested.
6 MR. GIBSON: I don't think the 7 consequences are all that severe, if you know what you 8 are doing.
9 MR. TAYLOR: Was there a particular 10 reason why this valve was dmped into the stanp, as 11 opposed to maybe into the quench tank or something like 12 that?
13 MR. BALLWEG: The specific 14 rea:;on it went to the sump is that the tanperature 15 of that was low enough that there was no real concern 16 about the amount of energy that was being dumped 17 in there, but like if it came out of the pressurizer, you'd have steam at nomally 2,000 pounds here. You 18 19 have got hot water at maximum 325 under the emergency 20 mode and 280 nomally, so the amount of flash wouldn't 21 be that much of a problem.
22 MR. MAZEIS: The last area 23 question is, there are some lines discharging water 24 HURON REPORTING SERVICE 761 5328
i 1 to the Eccs sump. It's been our observation in the l 2 past, that depending on how the lines impact the l surface of the water in or over the Ecos su=p, the 3
i 4
tendency to create air and training vortexes or air 5
entrapment to the section of the Eccs pumps is i
increased with this impinging det forces, so the question 6
ishasthatbeenconsideredintheselinesthatdischarlge 7
8 D D'ECCS8"P g MR. BALLWEG: Are you referring to the dump sunp lines, solenoid valves or -
10 11 MR. MAZEIS: Dump to sunp lines, t r I think Jim just mentioned the . relief valve 12 scharge.
13 g MR. BALLWEG: Let's talk about ne or the other. Do you want to talk about the sump --
15
- 3 * **
16 MR. BALLWEG: Dump to sump lines 37 a nyme ng em a er a a ge ea , and 18 g
in a case where the direct coolant system pressure is about eight pounds gauge or something like that, so 20 the potential for entraining =uen air or inducing auch -
of a vortex is very small.
22 !
MR. WGHES: The basic answer is, 23 HURON REPORTING SERVICE 761 5328
I i
1 we haven't, in the modeling we have done of the sump, 2
we did not consider the dunps into the sump.
3 MR. BALLWEG: The other part 4 about the MIR valves we're talking about, that is 5 downstream of the nomal drop line letdom line. There 6 is no mechanism that I could identify, which would 7
require or allow that valve to open, under ECCAS 8 conditions.
9 MR. HUGHES: The answer to 10 Jerry's question is no, we haven't.
11 MR. BALLWEG: No, we haven't, 12 but that valve can't lif t then. There is no flow 13 through that line.
14 MR COOK: Does that answer 15 your question?
16 MR. MAZEPIS: Yes. It says 17 that it wasn't considered, and I offer, as an open 18 item, to evaluate the impinging dump to sump discharge 19 of possible vortex fomatien.
20 MR. PRATT: We perfomed, for 21 the Midland Plant, a containment sunp modeling study.
22 It was done several years ago, and the results of that 23 study were submitted to the NRC for review. That 24 HURON REPORTING SERVICE 76b5328
I sump modeling program included a number of test 2
series, including pressure drop across the grading 3 cage and the sump trash racks, and it also included 4
a test sequence in which vortices of a very high 5 circulating strength were artificially created by fle .-
6 veins and it was demonstrated in that series of tests ,
7 that the grading cage which immediately surrounds the 8 outlet of the sump, successfully prohibited the 9 formation of vortices.
10 In other words, it served as 11 a last line of defense against vortex propagation 12 into sump suction lines.
13 Now, admittedly, the trash racks, 14 by virtue of their flow straightening capabilities, 15 also do -- does some good in preventing vertices, but 16 I think our position as described in that report, tha b 17 the grading cage itself will handle a vortex cf very 18 high strength, and so the likelihood of a vortex being 19 induced by a dump to sump line and thrompi 20 the grading cage, is negligible.
21 P.R. HUGHES: Jerry, what I believe 22 we're telling you is it was not factored in the model, 23 directly, but Tom was telling you, yes, we 24 HURON REPORTING SERVICE 761 5320
1 considered the reasons why it wasn't factored into the 2 model and having to do with the pressure dmp, and 3 perhaps we may need to doctanent that for a question, 4 but the created or the modeling tests, we believe 5 demonstrated that should a vortex from these lines 6 be created, that they would be broken up. I don't 7 know about the results of any review of that.
8 MR. MAZETIS: I guess the report 9 you refer to has been submitted and we will have to 10i take a look at the data to see if we agree.
11 Let me ask, do you remember if 12 the discharge lines go down into the pit or are they 13 well above the pit? Would the tendency - wuld you 14 expect post LOCA for the design basis ficed elevation 15 to be well above the discharge opening of the dtrup to 16 sump lines?
17 MR. PRATT: I don't recall.
18 I don't recall whether the dtanp to sump lines penetrate 19 the trash rack sump cover plate boundary, and what i
elevation. they're at . That 's sc=cthing ve can take a look at .
20 MR. GIBSON: I have a question of 21 l Jerry. The NRC has commissioned to work on the part 22 23 of Burns and Roe, on the containment sumps, and we sent i 24 l
HURON REPORTING SERVICE 76b5320
1 them our data package on that.
2 7,m curious if that is partly 3
addressing some of the questions you brought?
4 MR. MAZEIS: I have no personal 5
feeling for whether we have reviewed the package, but 6
-- Midland's data along with others that have been 7
submitted to Burns and Roe.
8 My presumption is their review 9
results are available to us and we will be discussing 10 with them their evaluation of the data.
lI Does that answer your question?
12 MR. COOK: Are they finished?
13 MR. MAZEIS: I don't know.
14 MR. HOOD: I don't believe they 15 are finished. I believe their effort is ongoing. I might comment 16 that the test reports from Consumers tests, that Jerry referred to, 17 Jerry is not personally involved in the review of that repert, but 18 it's being reviewed by others from the ':RC.
19 MR. SLADB Will we be getting 20 some feedback on that shortly or will we --
21 MR. HOOD: Yes. Now that the I
. 22 review has resumed, I would anticipate there would be 23 feedback on that at the appropriate point, but as it 24 HURON REPORTING SERVICE 7615328
' was mentioned, there is the Burns and Roo effort.
2 I'm aware of the interections we have had on this 3
project.
4 One of the areas of concem of 5 that project has to do with the deterinination of 6
insulation used in the containment. What aspect that 7
may give rise to in connection with the containment 8
9 There are other acpects of that 10 as well, but I would expect there would be some 11 interaction with the Burns and Roe effort as well.
12 MR. COOK: I don't see any 13 further questions on the floor. I think you should 14 proceed to the next item.
15 MR. HUGHES: The next section 16 will be presented by John Gunning, a comparison of 17 the present design to the applicable regulatory guide-18 lines, and followed by Mike Gerding, on instrumentation 19 and contml required for safe shutdown.
20 MR. GUNNING: Thank you, Ed.
21 You heard the prescnt design capability of the Midland 22 Plant. In addition, the Midland design has been 23 reviewed against regulatory guidelines, applicable to 24 HURON REPORTING SERVICE 7615328
l 1 the Cold Shutdown issue.
2 My first slide, I want to 3 briefly review the guidance that will be referenced.
4 Standard review plan 5.4.7 is here, which addresses 5 decay heat removal system. The major reason for its 6 mention here is because it contains Branch Technical 7 Position RSB 5-1.
8 Standard review plan 7.4 will 9 be addressed in this section, but at the conclusion 10 of my presentati ' by Mike Gerding.
33 This 7.4 addresses systems 12 required for safe shutdown. Brench Techical Position 13 RSB 5-1, the title of this is the design requirements 14 of the decay heat removal system. This Branch Technica 15 Position is attached to standard review plan 5.h.T, as I 16 previously noted and contains functional requirements 17 for decay heat removal and addresses concems more 18 generel than just the decay heat removal system itself. ,
19 This document is a basis for a 20 nunber of other design guidance docunents, particularly NRC question 211 35 21 22 Table 6-2 in your handout, e ntains a comparisen of the Midland design to the l 23 g I.
HURON REPORTING SERVICE l ;
761-5328
guidance of thiS doctInent. Open items: Associated 2
with NR'J staff review. These open items come from the 3 letter to Consumers of March 30, '79 or fmm meetings 4 associated with staff review, dated April 10 through 11, 5 '79 and April 19 and 20, '79 I won't mention here the 6 subjects of these because the subjects will come up 7 when we do the comparisons.
8 Regulatory guide 1.139, guidance 9 for residual heat removal to achieve and maintain Cold 10 Shutdown. This regulatory guide has been made available 11 to the industry and it is intended to apply to 12 construction pemits issued after January 1st,1978.
13 It is therefore, not specifically applicable to Midland, 14 The implementation section of the latest available 15 version, which is drafted two, revision ene, states that 16 the guide will be used for plants docketed after 17 January 1st,1980 and this, therefore, excludes Midland, 18 The section does state the applications docketed 19 before this date will be reviewed against the guide 20 on a case by case basis. This clarification, the 21 Midland design has been reviewed against the guidance 22 contained in this regulatory guide.
23 NRC question 211 35, contents of 24 -
48 -
HURON REPORTING SERVICE l 7615328 l
I this question are quite similar to the guidance contained 2 in Brsnch Technical peaition RSB 5-1, and a copy of 3 this question response is contained in the Appendix or 4 the last pages of your handout. These are the design 5 guidance documents against which Midland Plant is a being reviewed.
7 Many of these documents contain 8 similar guidance; therefore, in the ranainder of the 9 section, I will address the subject of the guidance, 10 list the applicable design guidance doctanents, then 11 convey the Midland design that's related to the subject 12 guidanc e.
l 13 So in slide 6-1, subject or the 14 NRC -- we have had broken into NRC positions, the 15 references that I have specifically been mentioning 16 before and then what the Midland design is with respect 17 to this particular position. The concern in the position 18 here is that the decay boat removal drop line design be 19 designed to accommodate a single failure.
20 The references contained in 21 slide 6-1, Midland design complies. Parallel / series 22 motor-operated valves are provided insido contninment.
23 The design has a single DHR drop line ; however, 24 HURON REPORTING SERVICE 7615320
1 this parallel / series valve arrengement precludes a 2 single failure preventing decay heat reoval systs 3 operation.
4 Slide 6-2, provide safety grade i
5 steam dump valves. These are the power operated 6 atznospheric vent valves or PCAV valves which have been 7 previously addressed. Applicable guidance contained 8 in slide 6-2. Midland design here complies. Two POAV 9 valves are provided per steam generators.
10l We can take a failure on either 11
- well, in this case, we can actually take a failure 12 of one steam - of one POAV valve on each steam 13 generator, but that is not the guidance.
14 Slide 6-3, auxiliary pressurizer 15 spray. NRC position, provide auxiliary pressurizer 16 spray or show acceptable manual actions as contained 17 in this applicable guidance of 6,3 Midland design 18 complies farther than this in that an auxiliary pressuri::er 19 spray is in fact provided.
20 Slide 6-4, boration capability.
21 Provide safety grade boration capability. Show 22 acceptable manual actions. References in slide 6-4.
23 Midland design complies. Snergency boration system 24 HURON REPORTING SERVICE 7615328
1 and other safety-grade borated water sources provide 2 sufficient boration. This design provides boration 3 capability without letdown.
4 Slide 6-5, provide adequate 5 DHR isolation. Applicable references of slide 6-5 6 Midland design complies. Section isolation is provided 7 by two series motor-opertted valves. Discharge 8 isolation is provided by two series chech valves.
9 Slide 6-6, collect and contain 10, decay heat removal nrasmtr- relie e vsive disch rga, ij Again, the applictble references of slide 6-6. Midland 12 design compties. The discharge is routed to the 13 containment sump, which . in fact is contained within 14 the - inside the containment buildine.
15 Slide 6-7, conduct a natural 16 circulation cooldown and borated water mixing test.
17 Applicable references of slide 6-7. Micland design, l l
a partial compliance. Clarification required.
18 19 Mentioned the 50 degree natural circulation cooldown 20 test will be conducted or referenced if it's conducted 21 before Midland, on a similar plant; however, a separate boron mixing test was planned. Previous discussions 22 23 have shown that boren mixing tests are ingyt3er, 24 HURON REPORTING SERVICE 761 5320
I 1 at the beginning of core life.
2 Slide 6-8, natural circulation -
3 provide procedures for natural circulation cooldown.
4 Applicable references of slide 6-8, and again, this 5 gets into the area of procedures. Midland will comply.
6 Appropriate procedures will ba provided before - well, 7 will be provided.
8 6-9, provide adequate seismic 9 category one auxiliary feedwater supply. Applicable 10 references of 6-9. Midland design complies. The nonnal 11 feedwater supply is from the nonsafety-grade condensate 12 storage tanks; however, automatic switchover is provided 13 for the safety-grade service water systen.
14 Slide 6-10, NRC position, provide 15 boron monitoring capability with the safety-grade 16 systen. Applicable references to slide 6-10. Midland 17 design nonsafety-grade boron monitoring capability is 18 provided. They have continuous monitoring by a 19 boronomet- on letdown. Periodic monitoring by manual 20 sampling capability is being provided.
21 Slide 6-11 -- I hope this isn't getting monotonous. Position, provide safety-grade 22 23 steam generator water level indication and alarm.
24 HURON REPORTING SERVICE 761 5328
1 This is regulatory guide 1.139 Midland design 2 complies with the clarification. Safety-grade water 3 level indication and nonsafety-grade ala:xs are 4 provided.
5 Slide 6-12, provide : safety-grade 6 makeup and letdown to accommodate cooldown shrinkage 7 and boration. Regulatory gulde 1.139, as refereneed 8 partially earlier. Midland design complies with the 9 clarification. Boration and cooldown shrinkage are 10 accommodated using only safety-grade systems without 11 letdown; therefore, safety-grade letdown is not providec ..
2 Slide 6-13, address pressurizer 13 heaters required to maintain natural circulation 14 conditions. The applicable references of slide 6-13 15 Previous discussion has discussed this area. Midland 16 area complies. 'Iwo banks of pressurizer heaters, backet 17 by safety-grada power and controls are provided.
Sinmary: Slide 6-14, NRC position.
18 19 Achieve Cold Shutdown with safety-grade systems.
20 Applicable references of 6-14. Midland design complies 21 with these clarifications:
+- Boration is accomplished w thout 22
" letdown. Boration is monitored and sampled by nonsafety -
23 24 53 -
HURON REPORTING SERVICE 761 5328
I grede systems. no separate boron mixing test is 2 planned. Steam generator water level alams are 3 nonsafety-grade. Indication is safety-grade. One ;
i 4 steam generator cooldown will take longer than 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> m 5 This issue was previously addressed. Upgraded non-6 seismic chemical addition system can provide contraction 7 volume in the case of a tornado. In this condition, 8 we do not postulate a safe shutdown earthquake 9 coincident with a tornado; therefore, we can use 10 a non-seismic chemical addition systen to provide 11 appropriate contraction volume after a tornado.
12 That concludes my section and I 13 now want to turn the floor over to Mike Gerding, who 14 will provide a comparison to regulatory guide -- or 15 excuse me. Standard review plan 7.4.
16 MR. GERDING: Thank you, John.
17 Good afternoon. My name is Mike Gerding. I will be 18 discussing Midland Plant instrunentation and controls 19 required for safe shutdown.
20 Standard review plan section 7.4 21 provides guidelines for the review of these instruments 22 and controls. I will briefly describe to you those 23 provided in the Midland Plant and their'confomance
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24 HURON REPORTING SERVICE 761 5328
1 to the acceptance criteria of the standard review plan.
2 The systems instruments and 3 controls are discussed in your handout and are sunmarized 4 in figures 6-17 A, 3 and C.
5 I will begin with figure 6-17A, 6 reactivity and inventory control. Safety-grade 7 redundant controls for insertion of the control rods 8 are provided by the reactor protection system. Although 9 no controls are provided for the emergency boration 10 system as it is a manually operated system, safety-grade 11 controls are provided for portions of the makeup and 12 Purification systcnn which are used to inject the 13 emergency boration system tank contents or provide 14 makeup from the borated water storage tank or chemical 15 addition system.
16 While the chemical addition 17 system is not a safety-grade systcm, it is tornado 18 Protected and can be made available following a tornado, 39 using the controls provided and various manual actions.
For monitoring of reactivity and inventory control, 20 21 safety-grade redundant indications are provided for control rod drive breaker position, source range neutron 22 23 Power, emergency boration system tank level and 24 HURON REPORTING SERVICE 7615320 1
pressurizer level. These indications are provided 3
both inside and outside the control room, except where 2
3 neutron power is provided inside the control room.
control rod drive breaker position, emergency boration 4
5 8V8t** t""" l'"*' 8"4'878t V'1"" I"#iC"~ti'"' """ *""il*1" outside the Control room.
These indications considered j 7
with the reactivity capability of the emergency g
boration system, preclude the need to monitor neutron ;
power outside the control room.
Figure 6-17B summarizes the
~
systems used for pressure control. Safety-grade 12 contmls and redundant controls are provided for the pressurizer heater banks, 5 and 6, which have >
been upgraded to safety-grade. Safety-grade redundant controls are provided for the auxiliary pressurizer s r,r av. valve, which can be made available following local, manual systanalignment and restoration of power to the valves. Safety-grade controls are provided for the letdown isolation valves. -
20 Also, as discussed previously [
21 ;
today, in the event of overpressure, the power operat ed 22 relief valve on the pressurizer is set to automatically 23 56 -
24 l
HURON REPORTING SERVICE l 7615320
I open at .2260 pounds per square inch, and these 2 are safety-grade controls.
3 Also, the pressurizer safety .
4 valve will operate at 2500 pounds on the primary 5 system. These valves are mechanically operated; 6 therefore, no controls are ; required. In the event 7 that the power operated relief valve sr.ould stick open, 8 safety-grade controls are provided to automatically 9 isolate the PCRV via the block valves which are set 10 to automatically close on a decreasing pressure of 11 2100 Pounds, coincident with the power operated 12 relief valve not in closed position.
13 For monitoring of pressure 14 control, safety-grade redundant indications are 15 " .vided r r react r c lent systen pressure and 16 pressurizer level , and these indications are avaliabl e 17 both inside and outside the control room.
18 Figure 6-170, summarizes the 19 systems used for heat rejection. Safety-grade redundant 20 controls are provided for the main steamline and main 21 feedwater line isolation valves. This includes automati 22 isolation in the event of a steam or feedline break arcl 23 automatic feedwater isolation in the event of an 24 -
57 -
HURON REPORTING SERVICE 7615328
1 abnomally high steam generator level.
2 Safety-grade redundant controls 3 for the auxiliary feedwater system include automatic 4 initiation, steam generator level control and automatic 5 switchover to the service water systen, which is the 6 seismic category one backup feedwater srpply.
7 The main steamline relief valves 8 operate open at 1,050 pounds per square inch steem 9 pressure. These valves are mechanically operated and 10 no controls are required. Safety-grade controls are 11 provided for the power operated atmospheric vent valves. ,
12 Finally, the decay heet removal 13 system controls include safety-grade controls, include 14 the controls and interlocks on the drop line isolation 15 valves, and the system pump and valve controls. The 16 system is -- can be made available following local, 17 manual alignment and restoration of power to some valves.
18 For monitoring of heat rejection, 19 safety-grade redundant indications are provided on the 20 Primary system for hot and cold leg temperatures, and 21 primary system flow rate. This is forced flow rate.
On the secondary side, indications
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. 22 23 are provided for steam. generator level and pressure ,
24 HURON REPORTING SERVICE 761 5320
l l l 1 auxiliary feedwater flow and power operated atmospheric 2 vent valve position. These indications are provided 3 both inside and outside the control room. Safety-grede 4 redundant indications are provided in the DHR system, 5 decay heat removal system,for flow rate and heat 6 exchanger outlet temperatures. These are provided 7 in the control room for accident monitoring purposes 8 and can be available for safe shutdown monitoring 9 purposes; however, they're not immediately required 10 for shutdown monitoring. Sufficient time exists 11 to connect portable instruments to line monitored
$2 equipment and therefore, permanent indications of these 13 indications are not provided outside the control mom.
14 The adequacy of these instruments 15 was the subject of a detailed study of the FSAR Chapter 16 15 accidents by the independent nuclear safety task force. As a result of this study, significant upgrades 17 18 have been made to enhance the Midland Plant instrumen -
19 tation.
Now, I will review the Midland 20 Plant conformance with the acceptance criteria of 21 22 the standard review plan, Section 7.4. Detailed 23 design and procurement of the controls and instrumentc 24 HURON REPORTING SERVICE 7615328
. _ , ~ .
1 required for safe shutdown are nearing final stages 2 for most equipment. The standard review plan 3 acceptance criteria have been considered and are being
.; implemented.
5 These criteria are sunmarized 6 in figure 6,16. They shall be redundant in their 7 intended safety function. They shall meet the single 8 failure criteria. They shall have sufficient capacity 9 and reliability to perfom their intended safety 10 functions whenever necessary. They shall be qualified 11 to function after the design basis events for which 12 their operation is essential, including the earthquake 13 and all FSAR Chapter 15 accident. With clarification 14 pr vided here by the Reg Guide 197, that the indications 15 shall function within required accuracy following, but 16 n t necessarily during the earthquake. They shall 37 satisfy applicable criteria for preoperational and 18 Periodic testing, quality assurance and design provisions 19 for indicating system availability. Finally, they shall 20 be Perable from outside the control room at local control panels with appropriate readouts and they shall g operate independent of those provided inside the control room.
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, HURON REPORTING SERVICE 761 5320
I I'd like to discuss this last 2 criteria in more detail. We have mentioned at various 3 points today, in today's discussions, the controls 4 provided outside the control room.
5 Figure 6-15 sunmarizes these 6 capabilities. The basis of organization of the centrols 7 and instrunents provided outside the contml mom for 8 safe shutdown, is to achieve and maintain hot standby 9 at the auxiliary shutdown panel and then proceed through 10 hot shutdown to cold shutdown, using these indications 11 and contmls, together with those provided at other 2 locations, local contml panels, motor control centers 13 and switchboards.
14 As mentioned today, there are 15 various manual actions required in some systems; 16 examples are, the emergency boration system and 17 decay bet removal system. The monitors provided 18 at the aux'.11ary sL tdown panel, these are safety-grade 19 monitors, include emergency boration system tank level, 20 pressurizer level, primary system hot and cold leg 21 temperatures, auxiliary feedwater flow, steam generator 22 Pressure and level, primary system flow and pressure, 23 and power operated atznospheric vent valve position.
24 HURON REPORTING SERVICE 761 5328
1 The safety-grade controls include, 2 pressurizer heaters, portions of the makeup and 3 purification system, component cooling water pumps, 4 power operated atmospheric vent valves, the pressurizer 5 power operated relief valve and auxiliary feedwater 6 system controls.
7 Controls provided at other 8
locations include those for the systems of the diesel 9 generator, the service water system, component cooling 10 water system, chilled water system, plant heating, ventilation and air conditioning controls and the
11 auxiliary pressurizer spray valves. These controls 12 13 and indications are safety-grade and redundant, just 14 as they are inside the main control room. They're 15 designed to operate without mutual action of those 16 pmvided in the control room and no single failure 17 will defeat the capability to shut down the plant at 18 either location.
In addition, as discussed 19 20 Previously, a study is in progress which will address the fire protection guidelines. The study evaluates the 21 22 feasibility of the installation of transfer switches, relocation of signal processing equipment and improved 23 24 HURON REPORTING SERVICE 761 5328
1 fire protection of safe shutdown control and 2 instrianentation. This is being done to insure that 3 the capability exists, both inside and outside the 4 control mom to safely shut down the plant after a fire.
In conclusion then, significant 5
6 upgrades have been made to enhance the Midland Plant 7
instruments and controls and these changes have been made consistent with the standard review plan, 8
Section 7.4 acceptance criteria. Thank you, and this 9
10 concludes my discussion.
11 MR. HUGHES: Thank you , Mike.
That concludes our prepared presentation for today 12 13 and at this time we can go on .to questions on section 14 six or anything else the Board wants to talk about.
John Wahl just pointed out that 15 16 he has handed out copies of the reference provided earlier, regarding xenon. If anyone is lacking a copy, 37 18 Pl ease say so and we will get them one, MR. COOK: Would it be efficient 39 to handle the questions just by going throu6h the 20 slides of individual points of regulatory guidance 21 and just ask for questions on each one of thosc, 22 individually, to kind of step through it in order?
23 24 ItuRON REPORTING SERVICE 76 8 53 2 tl
1 MR. HUGHES: John, will you just--
2 I will be doing them MR. WAHL:
in order, as they were in the presentation.
4 MR. HUGHES: This is the DHR 5
dropline design to accommodate a single failure.
6 ,Je described a design that has a parallel / series motor operated valve provided inside containment.
8 MR. COOK: Questions from the 9 Eoard or our colleagues of the NRC7 10 MR. HUGHES: Can I help you with 11 a reference on the drawing nunbers or anything else?
12 That is drawing 6-1. Figure 6-1.
13 MR. MAZEIS: Is this where it 14 was mentioned that the discharge sign was provided 15 with two series check valves?
16 MR. HUGHES: That's later.
17 This is where the line is inside the containment and 18 a question relative to single failure. Where a t 19 parallel bypass line is motarized and given reliabla 20 power such that you wouldn't have an inability to open.
21 MR. COOK: No questions on it.
22 Go ahead.
23 MR. HUGHES: 6-2 covered 24 .- 64 --
HURON REPORTING SERVICE 761 5328
1 safety-grade steam disop valves, and we have added to 2 the design, two power operated atznospheric vent 3 valves per steam generator.
4 MR. GIBSON: The POAVs, these 5 are motor driven dog control?
6 MR. HUGHES: That is correct.
7 MR. GIBSON: Are the valve 8 characteristics such that you can achieve - are they 9 linearized so you can achieve a decent control with them?
10 MR. HUGHES: Mike, are you
,11 able -
12 MR. GERDING: I would have to 13 find out the answer to that question.
14 MR. GIBSON: But you didn't just 15 take a standard open/ shut valve and apply dog to it.
16 MR. BALLWEG: No. This is a 17 contml valve.
MR. HUGHES: These are new 18 19 valves procured and replaced the original position 20 referred to,uan valves, which now are downstream of 21 the main stream isolation valves. These POAV valves 22 are t:pstream.
23 MR. GIBSON: But they were 24 t
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HURON REPORTING SERVICE 7615328
[
I designed for control, as opposed to back fitted for 2 the control.
3 MR. BALLWEG: That is correct. .
l 4 MR. GIBSON: That answers my 5 question.
6 MR. GARRICK: I just would like 7 your opinion on this. In order to allow control mom 8 isolation of the stuck open valve, do you think that 9 the P0AVs ought to be provided with motor operated 10 block valves?
11 MR. HUGHES: Tom?
12 MR. BALLWEG: The analysis that's 13 been done on this in the past indicates that that is 14 not required. B & W has perfomed safety analysis 15 on -- with the capacity that would equivalent to a 16 single stuck open safety valve as not presenting 17 any unacceptable consequence to the reactor 18 coolant syst s or the core.
19 On that basis, we detemined that 20 it was not necessary to pmvide a motor operator on 21 those valves. We did ask that question as we were 22 going alorg and detemined that it was not required.
23 MR. GARRICK: So you have that 24 i
HURON REPORTING SERVICE 761 5328 <
l l
1 analysis?
2 MR. BALLWEG: That is the 3 analysis. That's all there is to it.
4 MR. HUGHES: Jim, can you address 5 that?
6 MR. AGAR: I guess I really 7 didn't understand the question. Could I hear the 8 question again?
9 MR. HUGHES: The necessity of 10 motor operated block valves downstream of the POAV 11 valves. Upstream, pardon men in the event that the 12 POAV valve stuck open.
13 MR. GARRICK: Allow control room 14 isolation.
15 MR. AGAR: I believe that our 16 analysis on Chapter 15 accidents would cover such a condition, if the POAV were to stick open. This, of 17 18 course, would be another single failure on top of single 19 failure, on top of single failure. We get into a 20 situation where if we failed enough pieces of equipment, 21 we would be in an uncomfortable condition, but if it 22 did stick open, you might be in a position where you 23 would lose one steam generator and you would have one 24 HURON REPORTING SERVICE 761 5328 i
i I !
1 loop, depending on how - what the position of the l 2 valve was when it stuck open, whether it was wide open 3 or just cracked. There is a whole bunch of scenarios 4 you'd have to get into in this particular case.
5 MR. COOK: Let me see if I can 6 restate the question, at least the way I'm reading it.
7 We have analysis somewhere in 8 B & W that says there is no detrimental overcooling 9 of the reactor, due to that POAV valve being wide open.
10 MR. HUGHES: Bob Schomaker?
11 MR. SCH0 MAKER: Section 15.1.h 12 of ti.e FCAR ia annivsis of an inadvertent onenine 13 of tha atnospheric dump or safety valve, and the POAV 14 is sized less than a safety valve, so the overcooling 15 aff ect ! rom a spurious opening of a POAV is bounded by 16 the spurious opening of a safety valve.
MR. VAN HOOF: It might be noted 17 18 also t act under nomal conditions, the POAVs would 19 Probably not be used, but that the modulating valve 20 would be used, which are downstream from the main 21 steam isolation valves.
MR. HUGHES: The reason we 22 23 refer here to the POAV rather than the modulating
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24 HURON REPORTING SERVICE 761 5320 ,
1 valves is that using class one equipment, we would 2 resune the boundary to be at the main steam isolation 3 valve.
4 The MAD valve Jim referred to p; are downstream of the MSIVs.
6 MR. COOK: Are they differently 7 sized?
8 MR. HUGHES: The sizing is the
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9 same. The time for operation is different.
10 MR. COOK: There is no overcoolin g 11 Potential through an individual MAD valve? I see the 12 isolation valves are there , if yca vant to, but --
13 MR. GIBSON: Once you open the 14 MSIVs, you have got quite a potential for overcooling.
15 MR. BAUMAN: What's the total 16 capacity of both valves on oat, steam generator if 17 they're both open? Perc entage.
18 MR. BALLWEG: The valves have 19 independent , fully independent control and control i
20 switches. The combined capacity is approximately 21 13 percent.
22 MR. BAUMAN: I'm trying to see 23 if this is related to the recent correspondence we have ,
1 24 1 1
HURON REPORTING SERVICE 761 5320
k 1
received fmm B & W on total steam dtznp capacity 2
exceeding 15 percent, and the fact that you get into DNBR 3
problems. Is there any relationship, Jim, between that and these valves?
5 MR. AGAR: Yes. It's one in the 6
same, except that the analysis of the 15 percent was to coincide with the mad valve and the condenser dump 9 valves being opened at the same time and exceeding 9
15 peremt capacity when we run into DNB problems, 10 but the POAVs ;re sized such you wouldn't run into that , <
II MR, BAUMAN: By themselves,
' We're okay?
13 MR. AGAR: In addition to that, ,
14 though, like Tom ws saying, they're individually 15 controlled, so the chances of having two of them 16 stuck open at the same time would be highly incredible.
I7 MR. BAUMAN: I'm not talking about ;
l 18 having them both stuck open. This is a question that's 19 in another department's hands at the moment, but we 20 have a piece of correspondence from B & W that indicate a 21 that if we exceed, what is it? 122 percent or 22 percent 22 steam dtanp, we have got some problems with the core 23 potential problems, and I'm trying to see if there is 24 _
70 _
l HURON REPORTING SERVICr.;
7615328 I
1 any relationship to - between that issue and the !
2 l sizing of these valves.
3 MR. TAYLOR: Let me see if I 4 can clarify that. I think the original issue that 5 you are talking about came about as a result of the 6 question, can a single failure lead to the spurious 7 opening of some dunping capacity, which has not been 8 properly - not been completely analyzed. This was 9
related to control -- to the effects of the control 10 system failures on safety.
11 I think this -
12 MR. BAUMAN: Let me -
13 not mit it down a.s an e.ction item and I'll go heme e.nd 14 do some research on my own and see if there is any 15 relationship.
16 MR. AGAR: It's been analyzed 17 for Midland and not deemed to be a problem.
18 MR. HUGHES: Gentlemen, any more 19 questions on this particular position?
20 MR. MAZEPIS: I guess, just 21 getting back to risk space, in addition to the cooldown 22 part of this, it seems to me that there is another 23 concern you eventually get to and that is for events 24 -
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HURON REPORTING SERVICE 761 5328 i
l i
j where you can't bottle un sav a leak in the steen generator or a steam generator tube rupture where the 2
capability to isolate intuitively has to be a plus.
3 You know, it's a pathway to the atmosphere, and that's 4
another side of the overall risk that some - should 5
be somewhere in there.
6 MR AGAR: May I address that, 7
8 MR. HUGHES: Yes.
9 MR. AGAR: That particular item, 10 Jerry, is -- would be addressed - is being addressed I
now as part of the ATOG program, and there will be 12 operator guidelines to depict what operation they should ,
do. Whether they should isolate the generator or 14 maintain the cooling side of that generetor to reduce 15 ,
the pressure on the primary systs faster.
16 I don't believe the analyses .
P 17 for Midland is other than having just been initiated, 18 started, so it will be sometime before we have got 19 the ATOG program completed, but your concerns will 20 be taken into consideration, I'm sure.
21 MR. GIBSON: Jerry, isn't that a 22 concern being asked pretty much of the whole industry, lr 23 !
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HURON REPORTING SERVICE 761 5328
1 other than WRs. Just how are they balancing their 2 courses of action to expedite getting below obviously 3 the relief pressure?
4 MR. MAZEDIS: Yes.
5 MR. HUGHES: Next position
- i 6 addressed is providing auxiliary pressurizer spray 7 or showing acceptable manual actions. We have discussed 8 Midland has auxiliary pressurizer spray. We have got 9 some questions on that so far. Are there any others?
10 MR. SULLIVAN: Providing that 11 auxiliary pressurizer spray involves some acceptable 12 manual actions; right?
13 MR. HUGHES: Involves with the 14 auxiliary pressurizer spray, yes. Do you want us to 15 run down them or --
16 MR. SULLIVAN: No.
17 DR. GUNNING: The way this was 18 worded in the requirements or in the guidance was ,
19 provide one or the other, and that if one can show that 20 acceptable manual actionscould be performed, one need 21 not in fact provide cuxiliary pressurizer spray; there-l 22 fore, yes, the auxiliary pressurizer spray requires !
manual action to align it, but there's still an "cr" in the 23 design. _ l HURON REPORTING SERVICE 761 5328
1 MR. MAZETIS: It could be that 2 I'm not interpreting our requirements correctly, but 3 my understanding of our position - I think I'd like 4 to take issue with an apparent misunderstanding as 5 to what you mean by compliance.
6 To make a general comment, 7 manual actions, I perceive is three types. One is 8 manual actions typically required during a nomal 9 shutdown process. Everytime you shut down. Manual 10 pction outside the control room. Let's talk about 11 minual actions outside the contml rocm.
12 The two manual actions needed 13 because of the safety-grede requirement . In other 14 words, in order to show the capability, to get to the 15 Cold Shutdown with safety-grade equipment, it would 16 require this safety-grade equipment to be actuated outside the control room, and three, those manual 17 actions needed after a single failure.
18 ig The position 5-1 has a built in flexibility that's obvious with the latter. That is 20 the third one of -- after the single failure, two.
21 It's clear that it's a negotiated item; however, there 22 is little to no flexibility for the former two.
23 24 HURON REPORTING SERVICE 761 5328
1 So that the -- I'm not sure that I recall for the 2 auxiliary sprey, but your indication that it complies, 3 I don't really think in this - in a few of the other 4 cases, too, that the compliance is to 5-1.
5 Maybe it is, in your own mind.
6 A compliance is a viable capability. Just a comment.
7 MR. GUNNING: I was making 8 reference to what's stated in Brench Technical Position 9 RSB 5-1 with regard to Roman Numeral I, under the 10 Pressurization, which addresses aux pressurizer spray and 11 it says compliance for - with respect to the guidelines 12 for the Midland Plant, compliance will not be required 13 if dependence on manual actions inside containment after 14 safe shutdown earthquake or single failure or remaining in l
15 hot standby until manual actions or repairs are complete 16 are found to be acceptable for the individual plant.
I 17 Now, I can't speak about any 18 further interpretation. I was referencing the specific 19 docu: lent.
20 MR. MAZEDIS: Those are the words 21 I was looking at, too, as I spoke and those words you 22 just read or referred to indicate the third category, 23 and that is after a single failure the compliance would 24 i HURON REPORTING SERVICE 761 5328 i
not be required and limited operator action would be 3
allowed outside the control room.
2 MR. HUGHES: Jerry, I believe what we're saying is that our operator action or manual actions are merely for the alignment of the 5
systs, and th'..; this is a long tem action rather than immediately required for depressurization, such that r the time involved and the function or the objective, the depressurization we believe complies with the g
requirements and the intent both of the - providing of an auxiliary spray, and that that requirement didn't
~
require, in the long tem, automatic action.
12 I'm really drawing a distinction on the timing of the need to start the depressurization 14 as pemitting the manual actions, and we can go through what those manual actions are if you are ihterested, 16 because we are prepared for that, and can give you a feel for it, if you'd like.
18 MR. MAZETIS: I guess I'd like 19 to separate a policy from a - I will call technical '
20 argument. All I'm saying, it has been the policy to
.21 implement the position as I have described and your '
22 technical arguments, I presume are rational; however, 23 24 HURON REPORTING SERVICE 761-5328 I
I _ . _ .
j I'm just saying that this is the way we have been 2
implementing for the near tem OL's like yourself, this position.
3 MR. HUGHES: Fully automated 4
auxiliary spray is a requirement?
5 MR. MAZEEIS: Not automated, 6
but the capability from the control room.
7 MR. HUGHES: Okay.
8 MR. GIBSON: When I read this 9
over, I thought you guys were going to come back and say that compliance is not required because we are doing all these things, as opposed to saying that you
~
12 are complying, because in the statement that was handed out, it said it's not required if you can show the 14 following things, and I think you do show all those 15 following things.
16 Referring to the item in table 17 6-2 under Roman Numercl IC. l'd at least like to note l 18
-- Jerry, do you feel that in not complying, that 19 we have answered the other questions that are in that 20 paragraph, such as dependence on manual actions inside 21 centainment after an SSE? We don't need that, and we can ,
22 sustain a single failure.
23 l
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HURON REPORTING SERVICE 761 5328
1 MR. MAZEEIS: I guess I question 2
the relevance of how you have addressed that because 3
it doesn't look like it's - it doesn't look like we're 4
in after the single failure space with your response 5
in this coltann.
6 MR. LEWIS: As I understand the 7
words in RSB 5-1, it says that manual actions for a plant 8
such as Midland are acceptable if they can be justified, 9
That is, if there is access and time available to take 10 those manual actions. We feel we're in that condition.
11
_ Do you disagree? If you dir' gree, please clarify why I
It's not clear to me.
I3 MR. MAZETIS: I was just trying I4 to describe the policy on how we have been implementing 15 5-1 and that is tis t the manual actions are divided 16 into those three categories I described, and that we I7 have not allowed nomal shutdown of plants outside the 18 control room.
I9 The one exception that I could 20 remember is recently, I believe it was on the San '
21 Onofre or Stanmer, that in order to restore the power ;
22 to a valve, they had to remove the power for an '
23 unrelated requirement. Theyhadtodooutsidethe 24 HURON REPORTING SERVICE 761 5320
1 contml room.
2 I believe you have a similar 3 situation. They had to go outside the control room 4 and we evaluated in that one case; how far the operator
5 had to travel, and it happened to be within one floor 6 level, and we accepted thEt restoration of power, but 7 to my knowledge, we have been requiring valves to be 8 changed to motor operated valves, specifically.
9 There have been plants, mostly
- 10. CE plants recently, like San Onofre> that they have 11 - my recollection was six or eight valves that were 12 outside the control mom, manual, and we required them 13 to have motors.
14 MR. HUGHES: Operable from the 15 control room?
16 MR. MAZETIS: Yes.
17 MR. BAUMAN: Is that related to 18 Cold Shutdown? Were these valves necessary to achieve 19 Cold Shutdown or was that necessary for some other 20 safety function?
21 MR. MAZEFIS: I can't answer your 22 question. Maybe some of them were related to some other 23 function, but some of them were related to Cold Shutdown.
24 HURON REPORTING SERVICE 7El5320
1 MR. PRATT: That was for a nozinal 2
Cold Shutdown?
3 MR. IMZEIS: Yes.
4 MR. PRATT: Okay. For example, 5 we have manual isolation valves on the suction or decay 6
heat removal. You are saying your position would be 7 that those would require remote operators?
8 MR. IM2EIS: Right, and I guess, 9 just to rehash, probably the - I would assume that to the Midland docket, although I haven't looked
).I specifically, since the last time I was involved about 12 three years ago, we pointed and we were to commence 13 discussion on those particular areas, as to why we 14 wanted motor operators on those valves, which never 15 took place. I would presume the docket somewhere has 16 our position.
17 MR. SULLIVAN: It wouldn't be 18 on this particular case, because this capability wesn't 19 a part of the design at that time.
20 MR. HUGHES: I believe Jerry's 21 talking about the DHR suction valves.
r ->
va, MAZETIS: Rixht .
22 MR. PRATT: And that this may 5.. .
r 23 have been listsd as an open item?
MR. MAZETIS: Yes.
24 HURON REPORTING SERVICE l 7615320 I
i
1 MR. HUGHES: For the purpose of 2 this, I believe right now all we can do, Jerry, is 3 note your discretica and take it under adviaamant.
4 MR. PRATT: Can I get one 5 clevification en that?
i 6 The auxiliary spray capability 7 is not required for a nomal Cold Shutdown. Does that t 8 situation create a difference, as far as how the design 9 is reviewed?
10 MR. MAZETIS: That's the second 11 category of manual actions I told you about, if I l2 understand what you are. saying, and it falls into the 13 same implementation as the first, and that is, in order 14 to go to Cold Shutdown using safety-grade systems befor e 15 a single failure, our requiremet +, has been to do it fron the control room. There is no identified flexibility 16 17 in 5-1, that I can recall.
18 The only e.xception, again, I l 19l mentioned is if you have got the restoration of power 20 to some valves, we would consider that and talk to you 21 about how far away they are, the motor control centers 22 and so forth.
MR. SULLIVAN: In tems of 23 24 HURON REPORTING SERVICE 7615328
1 clarification, as I read -- I don't have the Branch 2 Technical Position. I assume this is out of it, it 3 says or remain at hot standby until manual actions 4 or repairs are complete, are found to be acceptable 5
for the individual plant.
6 What you are saying is that 7 ordinarily, what we're proposing here would not be 8 found to be acceptable?
9 MR. MAZErIS: That's right.
That -- that sentence you just read is after the 10 11 single failure. The presunption is that a single
$2 failure had taken place and we have to look at that 13 Position, and the repairs reasonable to be expected to be effective while you are at hot standby.
14 MR. SULLIVAN: The way it's 15 written here, it reads, to me, as an or. Compli"nc e 16 will not be required if A , dependence on manual 37 actions inside containment after SSE or single failure 18 jg or B, remain at hot standby until manual actions or repair is complete.
20 In other words, I don't read 21 the: logic as saying that in order to comply that I don't g
need the single failure space. I don't need to be 23 1
82 -
24 HURON REPORTING SERVICE l 7615328 j
I in that post single failure in order to not have to 2
comply by reason of item B. Unless you come out and l 3 tell me, well, you can read it that way, but it's 4 not acceptable.
i That gives you the way out.
5 MR. MAZITIS: I guess that's 6 what I'm saying.
7 MR. HUGHES: Jerry advised us 8 of the past policy practices and the best we can do ,
9 ri.t t here, I believe, is take it under advisement.
10 Are there any other questions? '
11 MR. GUIMING: As a clurification t
12 to that, there are only manual actions required inside 13 containment, and that was one of them. The system is 14 operable from the control room once it is lined up, 15 so it does require manual action to align it. Once 16 it is aligned, there are controls insite the control t
17 room to pemit continued operatio n.
18 MR. HUGHES: The next pocition 19 discussed wasprovididg safety-grade boration capability l 20 or showing acceptable manual actions. We believe the emergency boration system and other safety-grade borated 21 22 water sources provide sufficient borstion. !
23 I believe we have discussed !
24 f HURON REPORTING SERVICE 7615328
1 no far today, the EBS borated water storage tank.
2 to a degree the chemical addition system.
3 MR. SLADE: In the presentation, 4 I believe John indicated that we could provide safety-5 grade boratwn without letdown, and if I remember the 6 earlier discussion, that is the emergency boration 7 sy1 tem; is that correct?
l 8 MR. GUNNING: Yes.
9 MR. SLADE: The part after EBS, 10 rd.er safety-grade, that does require letdown in order .
11 to provide sufficient boration; is that correct? ,
12 MR. GUNNING: One can borate 13 sufficiently without letdown by using the emergency 14 boration system, and in order to accommodate other contraction voltme, one needs additional water that 15 16 is borated, and one can use whatever available water source that may be. The borated water storage tank is 17 18 a safety-grade source of water that can be used.
19 MR. SLADE: With letdown?
20 MR. GUNNING: No. You don' t 21 need letdown.
MR. HUGHES: If you're going 22 fcr contraction voltme only.
23 24 t
i HURON REPORTING SERVICE 7615328
- MR. GUNNING: If you cool down,it i
2 ycu contract the volume inside t% reactor, the water will contrdet ;
3 therefore, one needs to supply additional water to keep
- the pipes filled. This water must come from somewhe e 5 and an available source is the safety-grede boreted 6 water storage tank. One needs additional water, even f 7 if one is not letting down, just bectuse of the change 8 in the specific volume of the water contained within the reactor coolant system.
10 MR. SLADE: My concern is in 11 the event that you - the operator, during the initial 12 transient that we inject borated water from the borated 13 water storage tank or the makeup tank, boric acid 14 addition systen, we inject borated water into the 15 system automatically. We fill the pressurizer up.
The heating transient brings you back up toS32. Ycu 16 17 compress the water into the pressurizer. You fill 18 the pres. orizer back up again.
19 Now, is there sufficient volume 20 in the pressurizer to inject the emergency boration 21 system which requires manual action at some later time?
22 MR. GUNNING: A detailed j
23 analysis of that has been done and I would probably 24 - esi -
HURON REPORTING SERVICE 7615328
1 best reference it over to B & W, who has genereted a 2 report, to address those specific questions.
3 MR. AGAR: One point of clarification. I think the EBS, by itself, ic not or cot rse l 4
t 5
of sufficient volune to take up the contraction volume, 6 and that is what that and is there between the EBS 7 and other safety-grade systems.
8 In order to continue to cool down 9 and supply contraction volume, you need other sources l
10 of water.
11 MR. SIADE: I understand that.
What this is discussing is not inventory contml. ;
12 It's discussing reactivity control. Boration capability.
13 MR. PRATT: Let me try to clarify 14 that. You need the 1800 gallons or perhaps less, 15 16 depending on the scenario of siX veight percent boric acid. In addition, credit is taken for a minimum 37 18 in the Cold Shutdown contractica volune makeup, for a minimum of 1 3 weight percent, so the Cold Shutdown 19 contraction volume provided cannot be domineralized 20 water. It has to be at least 1.3 weight percent, and 21 in that sense, it contributes to the boration 22 Capability.
24 HURON REPORTING SERVICE 7615328 ,
I e
1 MR. SULLIVAN: I think Jerry's 2 prol tem goes away if the NRCs position says provide 3 safety-grade boretion capability and inventory control.
4 It seems to me it's a matter of semantics really; isn't 5 it? You're just saying the bo:sted water source --
6 if you didn't have a volume concern, you don't care.
7 MR. SLADE: What I'm trying to 8 establish is whether or not I have to get that emergency 9 boration water into the system to have sufficient 10 boron to assure the one percent delta K/K shutdown 11 margin.
12 MR. PRATT: For what?
13 Cold Shutdown or hot?
14 MR. SLADE: Hot shutdown.
15 MR. PRATT: No. You do not need 16 to use chemical addition system or BWST.
17 MR. SLADE: That requirement is 18 only for the Cold Shutdown condition, sothat even if you 19 don't get the emergency boration in prior to the 20 cooldown, as you start to cool down, you will be able 21 to inject the water from the emergency boration and 22 stay ahead of the boron requirement?
23 MR. PRATT: Right.
24 HURON REPORTING SERVICE 761 5328
1 MR. VAN HOOF: How about xenon?
2 Don't you need the emergency boration for xenon?
3 Even if you are hot?
4 MR. PRATT: Not if you have 5 injected EBS.
MR. VAN HOOF: Your rods go in.
6 7 The most important rod is stuck out. You go throuEh 8 your xenon transi.ent. When you come down below 9 equilibriu:2 xenon, then you need the boration; do 10 you not?
11 MR. PRATT: From EBS.
12 MR. HUGHES: You need the 13 emergency boretion system for that.
MR. VAN HOOF: Any contraction 14 15 after that, you require the or, or the and other ~
16 systems,such as the borated water system, and if you have contraction, you don't need letdown. You can 17 18 put in your water.
19 MR. BALIXI.D: That isn't the 20 question Jerry has been asking.
MR. SLADE: You are skirting 21 all around the question.
22 MR. BALLWEG: If I might try 23 24 HURON REPORTING SERVICE 7615328
1 and restate the question. You got a trip. HPI is 2 still rien M g. It's pumping water in. It raises 3 the pressurizer level up.
4 MR. PRATT: Due to makeuo?
MR. BALLWEG: Yes, and you don't 5 ,
6 have - you fill the pressurizer up. Now you got it ,
7 nearly full, but you don't have EBS in yet. Now stat?
MR. SLADE: Now you go through 8
your xenon transient. Where does your boron come 9
10 from to take care of the decay xenon after you get 11 through equilibrium concentration?
MR. BALLWM: The answer pert 12 13 of that is, based on the B & W report, you have got 14 over in your hands there -- under what you just put i 15 your hand on -- is that the injection has to be limited to 2200 GPM per that report, to assure that there is 16 17 sufficient space in the pressurizer to pennit injection of the 1800 gallons from EBS.
18 There is a conflict within 39 20 that document that we have called to B & W's attention. They're requesting clarification on it.
21 MR. AGAR: Could we have -- ]
22 Is it clear enough Rich, would you address the concern?
23 24 l} HURON REPORTING SERVICE 7615328
I to you? Would you like it restated? Do you understand 2 what the concem is?
3 MR. LANG: If you initiate HPI 4 immediately and leave it on until you fill the 5 pressurizer up, in order to get the EBS in, you will l 6 have to contract. You will have to cool down some, ,
7 It 's as simple as that.
MR. SLADE: In the meantime, 8
9 if I don't cool down or initiate a cooldown, do I have -
10 enough boron in there to take care of my xenons that 11 are going to be decaying out with time?
MR. LANG: No. You need -
12 13 if you're not going te cool down and you have a stuck <
14 md and you are at the worse time in core life, you 15 must have the EBS or its equivalent in within 24 ,
16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> for the most probable trip sequence.
MR. SLADE: And again, it gets 17 18 into the -- and you don't have letdown capability.
19 There is a lot of ands.
MR. HUGHES: Jerry, we're into 20 21 a hypothetical situation where you do not have letdown, 22 where you have had the unfortunate occurrence of the 23 most reactive rod stuck out at the worse time in core 24
i HURON REPORTING SERVICE 761 5328
1 life, and if you go below the equilibriun xenon condition' 2 you need additional boration to assure more than 3 one percent shutdown. That boration source, concentrated, 4 is EBS. With that given set of conditions, you will 5 need the EBS and you will need some volume available 6 to inject it.
7 MR. GIBSON: The other thing you 8 will need is a loss of auxiliary fe.edwater, in my 9 est!aation, because otherwise -- I can't undcrstand 1
10 any reason you couldn't do some cooldown.
11 In fact, usually with the B & W 12 plant, the problem is not that you can't do some, 13 but you do a little too much.
14 MR. HUGHES: Again, what we're 15 into is a hypothetical situation. It doesn't assume 16 loss of auxiliary feedwater. It deals with the 17 definition of staying in hot standby, ,.hich is a 18 temperature range.
19 MR. GIBSON: A large one.
20 MR. LANG: One other point of 21 clarification. Without cooling down, you necd 22 approximately around, in round figures, about 125 inches 23 in the pressurizer, so if you were to get down on hot 24 i, I
HURON REPORTING SERVICE 7615328
I standby, if you were worried about your pressurizer 2
level and you did turn HPI on, some source of makeup, 3
as long as you teminated it about 270 inches or so, 4
you would have enough room in the pressurizer to put 5
the EBS vater into the reactor coolant system.
6 MR. SLADE: As long as you stop 7
the injection before it goes beyond nomal levels, 8 essentially.
9 MR. LANG: Yes, yes. That would !
10 be adequate.
11 MR. SLADE: I'm satisfied.
12 MR. SULLIVAN: Are your 13 calculations for the need for the EBS, is this only
14 for the first core or is it true for the life of the 15 plant or -
16 MR. LANG: It's -- calculations P 17 have been done based on the design criteria for all 18 nomal cores. If you're going to talk about extended 19 burnup type cores where you have higher boron 20 concentration requirements because the worth of the beren 21 toward shutting the plant down becomes less, so the number 22 ofPRI - you have to mise the concentration to when in hot 23 shutdown goes up, but for the design basis for all 24 HURON REPORTING SERVICE 7615328
j nomal reload cores, this has been accommodated, not 2
just cycle one.
3
- * #' #' "UY #
questions?
4 MR. PRATT: I've got a question 5
f r, pess, . en ep s coments on 6
7 credit for manual actions outside the control mom 8
f r depressurization, boration is one other of the essential functions that need to be perfomed to get ,
g to Cold Shutdown, and would the same definition as far as credit for manual action apply to the manual g
~
valve which isolates the emergency boration system from the makeup system? .
13 i MR. MAZEfIS: Yes. That's 14 categoric, too.
MR. HUGHES: Are there any more questions?
(Whereupon there was a short g
recess taken)
MR. HUGHES: All right. The NRC position, provide adequate DHR isolation. The project believes they complied by suction isolation 22 by two series motor operated valves and dircharge >
24 HURON REFORTING SERVICE 701 5320
1 isolation by two series check valves.
MR. COOK: Where is Jerry?
3 R. HUGHES: I know he has a 4
comment on that. If there are no other questions, j 5
we will go back - oh, here.
6 Jerry, we have got this one on the roard here. You have seen it and we're waiting.
8 We thought perhaps you might have a ' comment.
MR. MAZEIS: Thank you. I was 10 wondering, on the interface between the low pressure
)) and high pressure discharge side, this is probably ,
12 repetitive because I have presumed you have docketed it.
13 The concern on the potential for 14 a loss of integrity of that low to high pressure 15 interface, has dictated the pcst several years, to 16 explore a test program and test capability to - with 17 accompanying criteria for leakage for those check valves.
18 The actual regulatory resolution 19 to that subject, I believe, is probably in mechanical 20 engineering branch, but I was just curious as to 21 whether that's been a considerstion here.
22 MR. HUGHES: Check valve leakage?
23 MR. MAZETIS: The capability i!o 24 _ 94 _
HURON REPORTING SERVICE 7615328
I check for check valve leakage.
2 MR. HUGHES: Tom, can you answer j 3 that? ,
4 MR. GUNNING: Well, in the 5 review, I guess I could refer it over to Tom fur 6 a detailed design, but there are accommodations in 7 the system to be able to measure the check valve 8 leakage or leakage through those check valves. I guess 9 I'd better refer over to Tom for verification.
10- MR. MAZETIS: Perhaps I could 11 short cut it by asking if you recall if your position 12 hes been docketed anywhere that we can just refer to?
13 MR. PRATT: I believe it has.
14 I believe we have gotten questions, or at least a 15 question from the commission on that, and I don't recall 16 just which question that was and which question and/or 17 FSAR section documents our position, but why don't we 18 leave that as an open item, or before we finish here, 19 we can get some research going or look it up.
20 MR. HUGHES: Give us a few minutes 21 to look it up. We'll give you a reference and/or 22 tell you no.
MR. MAZE"2IS: Thank you.
23 MR. SULLIVAN: I guess for 24 !
HURON REPORTING SERVICE 7615328 e
I 1
clarification, I just got either an infomation notice 2 or a bulletin yesterday, but I received it fmm the 3 Falisade's P eople. It was received on their docket.
4 Sometimes that kind of infomation is delayed a little 5
bit before it gets to the applicant, as opposed to the 6 operating class, so in tems of the specific infomation 7
notice or bulletin that requires a rc:ponse, we either 8
have just received it within the last day or two or 9 we will receive it soon.
10 MR. GIBSON: I'd like to elaborate a little bit. As I read that bulletin, it goes a little 11
}2 beyond leakage. What they're concerned about is that 13 we have series check valves. One might be sitting open 14 and you wouldn't know it, and therefore - and I refer to how I read the current system for our plant, as far 15 as detection capability.
16 37 I'm not sure we can detect 18 leakage at each valve point, and they're concerned about 19 leakage past the first valve, leakage past the second valve, and I believe also leakage past the third one, 20 even though it's nomally open.
21
~
I want to make sure you have 22 23 the capability once -- that it can close, so this --
24 HURON REPORTING SERVICE 7615328
1 intersystem LOCA is the name of it, and --
2 MR. SULLIVAN: In fact, Davis 3 Besse had trouble with their check valve in that system 4 in their startup last fall, I think following the --
5 their refueling outage.
6 MR. GIBSON: Two plants were 7 cited in there as having had the problem.
8 MR. COOK: Let's not try to 9 speculate on new material. We can get back to it and i 10 give it some thought.
11 MR. SULLIVAN: I think the ,
12 sunmary is, from the point of view of my departnent, ,
13 it's still under investigation. The infomation may be 14 on the docket already and we will respond in any case 15 L if we're required to, to the IE infomation notice 16 r bulletin, as well.
17 MR. GUNNING: If there is a recent 18 issue, I'm not aware of it; however, in the design i
19 review of the systcm, the system was checked to verify 20 that one could check for leakage through the appropriate ,
21 valves and be sure thst one could measure it, and the 22 system design had this capability. So recent additionc1 23 concernc, I'm not aware of.
24 HURON REPORTING SERVICE
( 761 5328
1 MR. HUGHES: All right. As I said, we will come back and provide a reference. Mike, 2
3 you are prepared to do that?
MR. PRATT: Yes, Ed. The design 4
S position or features for intersystem leakage on the 6 decay heat removal system are described in FSAR 7 Section 5.2.5.2.3 8 MR. HUGHES: What's the date on 9 that page or the latest rev on that page?
10 MR. PRATT: That would be 11 revision 30, although it looks like the update was ,
12 amendment 15 MR. HOOD: I mi6ht clarify, 13 14 that the letter for the Midland docket has been mailed out. I would also clarify that in the prior reviev 15 16 that we did on the Midland docket of the FSAR, we did 17 ask some questions with respect to the ability to 18 test the two check valvns.
19 MR. GIBSON: I'd like to ask 20 Bechtel, I don't find that testing on the P%ID for 21 decay heat removal. Is it located perhaps on the 22 containment penetration precsurization FLID, or 23 where would I find it?
24 HURON REPORTING SERVICE 761 5328
1 MR. PRATT: There is a pressure 2
indicator between the three check valves.
3 MR. GIBSON: That's one indicator.
4 K' PRATT.: That's one.
9 MR. GIBSON: That, I believe, 6
only tells me -
7 MR. SLADE: It says you have pressure.
I 8 It doesn't tell you the source of the cress'ure.
9 MR. O w: Let's go on. We'll 10'I address that whole question off lines.
II MR. HUGHES: All right. We'll 12 go on. Any more questions on this?
13 Next one, John. NRC position 14 was collect and contain decay heat removal systa:1 15 pressure relief valve discharge. Midland discharge 16 routed to the containment sump. We have had some 17 discussion on the valve from the decay heat removal 18 system to containment sump. Are there any other 19 questions?
20 Go on to the next one.
21 The NRC position has conducted natural circulation 22 cooldown and borated water mixing test. Midland 23 design complies, partially in that , presently, 24 HURON REPORTING SERVICE 761 5328
1 the intention it to conduct a 50 degree Fahrenheit 2 natural circulation cooldown test or reference in 3 another appropriate test, but that no separate boron 4 mixing test is planned. Experience to date has shown 5 that boren mixing tests are infeasible. There is no 6 feasible method of measuring boron mixing in this 7 condition.
i 8 MR. TAYLOR: One question, g really. Where is t'.ae -- I think we started to get i 10 to this this morning, but didn't make it.
11 Where is the sampling point for 12 measuring boron concentration when you don't have 13 any letdown flow?
14 MR. HUGHES: Tom Ballweg?
15 MR. BALLWEG: It's on the letdown 16 line. It's at a connection on the letdown line, very ;
17 near the large bore piping, the main loop piping. L 18 I think there is about three feet of two and a half 19 inch letdom line. Then the sample line comes off 20 through the containment penetration and out to the 21 sample panel, so it would require some purged volume 22 to purge that three foot leg of the -- approximately 23 three feet of the two and a half inch line, and then 24
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HURON REPORTING SERVICE 7615328
1 you should be drawing a full regular sample fmm the 2 hot leg.
3 MR. TAYLOR: It's coming up-4 stream of any letdown isolation valve?
5 MR. BALLWEG: Yes. There are 6 actually two sample lines on that letdown line.
7 One is downstream and one is upstream.
8 MR. GARRICK: You don't know 9 how representative that sample would be of the system?
10 MR. HUGHES: I believe Tom ,
11 indicated that after clearing the purge volune, we 12 believe it would be fully representative.
13 MR. BALLWEG: It's representative 14 of whatever is going to be in that pipe, because 15 whatever has come through - it's from the cool leg, 16 so it's already come through the steam generator.
17' It's mixed in the outlet plenum of the steam generator 18 and mixed otherwise around the system, as it comes 19 around, so by the time it gets there, it's representative 20 of whatever is passing through that part of those 21 systems.
22 MR. TAYLOR: This question is verf 23 much releted to the need to denonstrate adequate mixing 24 -
101 -
HURON REPORTING SERVICE 7615328
4 I with one loop in operation.
2 MR. BALLWEG: Yes, I understand 3 that.
4 MR. VAN HOOF: That sample line, ,
5 is it safety grade? In the one upstream?
6 MR. BALLWEG: To the outer 7 containment through the containment and on out, it is. .
l 8 Beyond there, it's not.
9 MR. TAYLOR: So this is a hot i
10* sample then?
11 MR. BALLWEG: Yes.
12 MR. HOOD: With regard to the 13 natural circulation cooldown test that will either be 14 conducted or referenced, would. you tell me if you have 15 in mind now any candidate plants for referencing 16 purposes?
17 MR. HUGHES: Darl, I'm going l
18 to ask Jim Agar to answer that. Jim?
19 MR. AGAR: I'm afraid I'm going 20 to have to pass on that question. I don't know if 21 there is any representative plants right at this sitting, 22 right now or not. I think what he's looking for is 23 a clarification of that statement. Would that be right, Darl?
24 - 102 -
HURON REPORTING SERVICE 761 5328
1 MR. HOOD: That's part of it.
MR. AGAR: If you want to 3
clarify what that sayr. in other words, that's a Consumer's commitment and perhaps, you know, they 5 want to be a little more clear on what they commit 6
to do.
MR. HUGHES: Well, rarl, maybe 0 Basically -
I don't underntand your question.
8 MR. COOK: We do.
10 MR. HUGHES: There is some I) correspondence that --
12 MR. SULLIVAN: We just received 13 a letter on the cocket that references the natural 14 circulation cooldown tests that have been required 15 on, like Sequoia, and it 's not only the demonstrated 16 capability. It's also a matter of operator training 17 and we still have - that letter we just received 18 yesterday, that I saw it, and it's under evaluation.
19 In tems of referencing another 20 plant, i guess ve work with the owners group and if 21 the same requirements are going to be imposed on one
- 22 of the other 177 operating plants, then ve vculd certainly 23 try to take advantage of any useful infomation we 24 - 103 -
HURON REPORTING SERVICE 761 5328
1 could gain there, but it appears the NRC is approaching 2 this now in - different from this context and that is 3 from the point of view of operators actually going 4 through the natural circulation cooldown, like was 5 required on Sequoia.
MR. HUGHES: The question I thought 6
we started with was single loop cooldown. Maybe I 7
8 misunderstood.
MR. COOK: It was analysis; 9
10 wasn't it?
MR. SULLIVAN: That was a 11 12 separete thing.
MR. HUGHES: You're only -
13 14 you're talking about a two loop natural circulation 15 situation.
MR. HOOD: Yes.
16 17 MR. SULLIVAN: That's what 18 I thought Darl - was talking about, too.
MR. MAZETIS: Just to amplify 19 20 what Ted just said, I don't know the details of the 21 Sequoia test. I only knor enough to say that the 22 intent of the Sequoia test on natural circulation were
- 23 not the same as 5-1. The test fell short of the 24
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HURON REPORTING SERVICE 7615328
1 capability that is to be demonstrated in 5-1.
2 My recollection, for example, 3
is they had let down and the major purpose of the 4
Sequoia, if -- it was a unique test. It was almoct 5
solely operator training.
6 MR. SULLIVAN: That's the way I ,
7 understood it, but like I say, it's under evaluation.
8 The letter that we received talked about using pump heat; -
9 for instance, as opposed to decay heat and on end on.
10 We just have to evaluate.
11 MR. MAZE. T IS: My only point in 12 saying something was that Sequoia is still required 13 under 5-1 to either conduct or reference, and in this 14 case, their referencing tests by Diable to be conducted later.
15 A natural circulation cooldown test meets 5-1.
16 MR. SULLIVAN: Can we referenee 17 a test to be conducted at some later date?
18 MR. COOK: Ne7t slice.
19 Go ahead.
20 MR. HUGHES: Are there any other 21 questions on this?
22 MR. VAN HOOF: I've got one.
23 I'd like to know a little bit more about the separate 24
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HURON REPORTING SERVICE 7615328
l 1 boron mixing test and why it's infeasible.
2 Is there any way that a test ,
3 could be conducted prior to fuel loading, during ,
4 cold aus or whatever, to inject and make some 5 measurement of thic mixing mode? What isn't feasible f 6 MR. HUGHES: It's really our !
7 understanding that this has been investigated on other 8 dockets and has been detemined, both by an applicant 9 and the NRC personnel involved, that the test just to vasn't a tractical test.It would not either -- I'm not 11 familiar enough with it to say whether it wouldn't prove 12 or that the method of conducting it was not considered 13 suitable.
14 Jim Agar has got perhaps a bit 15 more infomation on it.
16 MR. W R- Were you going % say 17 s mething, Walt? So I don' t commit myself.
18 MR. JENSEN: I was just going to 19 say that I didn't know cf any NRC position.
20 MR. HUGHES: Not a position, 21 but a conclusion.
22 MR. JENSEN: It's my understanding 23 that such a test will be done on another plant.
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HURON REPORTING SERVICE 7615328
i MR. AGAR: Let me tell you what I j
know, Walt. On the North Anna plant, they were going 2
to conduct a boron mixing test and what it amounted to, 3
4 I guess, was it was robably an improvement over the
* #' *" *** ' Y #" "O
}
5 m al test, and dat Jern as cayhg, is maccWole 6
results, very skimpy results anyway, and the North Anna 7
te0t amounted to a aini boration dilution accident, g
in order to detemine the effects of a slug of fresh g
W er E ng Gm@ 2e core, aner a slug of bomn ,
10 .
went through, to get a fast reaction indication that boron was reuching the core during natural circulation.
12 The determination wa: made by 13 Westinghouse that the test was dangerous and the NRC 15 on the committee, Ivan Green, who is the resident manager of the Midland Plant for B & W, and my source of infomation was from him. I haven't been able to 18 get a hold of any documentation, letters. There must g
be come documentation somewhere.
20 MR. JENSEN: I think that because 21 r ,
the test on one facility was perhaps an in such a way that it was judged not to be safe, doesn't meen 23
- 107 -
24 HURON REPORTING SERVICE 7615328
i 1 that a - it's my understanding that this test brought 2 - either brought the reactor critical or brought it 3 close to critical. Perhaps was even run when the 4 reactor was critical. I don't see why, because such 5 a test was run, would preclude perhaps design test 6 being run at Midland to show that the boron indeed 7 mixed. Perhaps not to show its affect on the reactor 8 criticality. ,
9 It's my understanding that part to of the NRC concern is that the heavy boron vill not 11 - that it will mix with the coolant, but will not 12 perhaps form a pool or puddle in the lower part of ,
13 the reactor ecotyt system. Your sample line seems to 14 me to be in a fairly advantageous position. It requires 15 that the boron travel completely around the coolant 16 loop before reaching the sample point, so the indication .
17 of boron -- the predicted amount of boron at the sa=ple 18 point would seem to me to be a fairly good test, that r
19 the boron was being mixed within the coolant loop. i 20 MR. AGAR: What we're saying is 21 that we haven't identified a feasible way, at this 22 sitting, to run the test, but I guess the only thing 23 that really counts is that this boron gets in the core.
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I HURON REPORTING SERVICE 7615328
1 Not necessarily at the sample point, whether there is 2 bypass flow around the core or backup through the 3 loops. Unless you have some indication in the core 4 that you have got bomn in there, it isn't going to ;
i 5 do you much good if you have a good boron mixing 6 solution at the outlet of the sample line.
7 MR. COOK: What is the extent i 8 of analysis the pmject has done and discussed with ,
9 the NRC on this particular issue?
10 I"1, HUGHES: To my knowledge,'we ,
11 haven't held a discussion with the NRC on this issue.
.. [
12 The extent of our analysis has 13 been discussed with B & W. ;
14 MR. SULLIVAN: We haven't done 15 any analysis of the test, t 16 MR. COOK: My sense of this f l
17 discussion is that we're premature in reaching 18 conclusions and until we can get back and get specifics , !
19 we're not going to get anywhere and we should just put !
20 it on the list of open items with the staff. [
i 21 MR. BUDZIK: Two things. This 22 has been looked at and there ic two. considerations 23 that have gone into the feasibility,of the test.
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i f
HURON REPORTING SERVICE (
7615328
1 I guess the first thing is we 2 don't know what the staff means by a boron mixing test 3 because the primary system is not instri.anented to l 4 measure in various positions and cross sections of the 5 coolant system, the mixing in any kind of real time 6 scenario. You're talking about long flushing lines !
7 7 and so forth, and the only thing you could predict 8 is after the system reaches equilibritan, whether your 9 sample points show an equilibrium amount of boron, but to I would judge the test to be inconclusive because of 11 the lack of sampling points.
12 The sscond thing is, I would 13 also point out that this systen, the boron is being 14 added in a very slow time frame, compared to the 15 loop cycle that we are looking at. You know, that the 16 coolant passes around the loop, and so that it's not ;
17 being injected as one slug, and you have to worry about l l
18 it being spread throughout the primary system.
19 MR. COOK: Back to my original 20 point. I think we owe a little mer e detailed discussion ;
21 to the staff to clarify as you were alluding to, and i
22 also to get down to specifics on this design. '
23 MR. HUGHES: All right. Are there-24 - 110 -
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I Are there any more questions on the naturel circulation 2
cooldown or borsted water mixing test?
3 MR. MAZEIS: One final one.
4 Assuming a test is conducted and assuning it's what 5
you indicate up there, 50 degree natural circulation 6 test, I guess we'd be interested, when we get around 7
to these discussions, in the basis for '.;hy 50 degrees 8 would provide enough of a test to get something out of 9 the test, as far as the cooldown. Why not 100 degrees :
10 I or 75 degrees or 25 degrees?
,1) MR. HUGHES: I believe the basis 12 for the 50 degrees was a detemination of some point P
13 to verify the computer code and confim that it would be 14 reasonable to expect it to be accurate all the way 15 down, and there was no basis than that.
16 MR. AGAR: One point of 17 clarification, Jerry. B & W would like to foresee 18 more extensive cooldown tests because it would help i 19 with the code, but I think the 50 degrees would be i 20 what is detemined to be a minimum point that would be 21 of value in bench marking the code and it would
.4 22 detemine also the ability to cooldown using natural 23 circulation. 1 24 - 111 -
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1 MR. MAZEPIS: I guess it's on 2 the record that when we talk about the test and what 3 we're to get out of the test, that we'll probably 4 expect to discuss further the adequacy of the 50 degree 5 cooldown test.
6 MR. JHISEN: The concem in the 7 cooldown that a - that the -- there would be no 8 bubbles fomed in the primary system. For example, 9 the upper head and I know that I have heard various 10 people comment that the B & W plant has a larger 11 amount of flow to the upper head than some other 12 plants.
13 I haven't really seen thet 14 documented anywhere. Perhaps I didn't -- brought 15 out in the evaluating possibility of vortex femation.
16 MR. HUGHES: Any other questions?
17 I understand thEt there is a bulletin -- is it out
18 on head fomation? Head weight fomation?
19 Okay. Are there any other questions? I don't think ,
20 we have any -- Walt, were you looking for an answer 21 to that?
MR. JENSEN: I just took it 22 I
23 as a comment.
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I MR. HUGHES: All right.
2 The next one. This is provide procedures for natural 3 circulation cooldown and respenses of the appropriate 4 procedures will be provided. I don't know that there 5 is any questions on that. They'ref in the process. ;
6 I'm sure there will be function of the results of 7 the computer calculations.
8 MR. MAZETIS: Do you have a 9 feel for when?
10 MR. SLADE: Again, I just have l1 one question and that is, will that be the subject 12 of an operating spec -- operating procedure to be ,
13 received from B & W7 14 MR. HUGHES: Let me --
15 MR. SULLIVAN: Time out.
16 As I said, we just received the one letter. This whole :
17 area is under consideration right now. It's going to 18 be jointly developed, I'm sure, since the testing people 19 and operating people will be involved, and I guess I 20 don't see any reason to pursue it any further right 21 now.
22 MR. SLADE: As I understand 23 this one, though, Terry, this is talking about procedures 24 - 113 -
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1 for operation and emergency procedures. Not just 2 test procedures.
3 MR. SULLIVAN: I was reading 4 that as the test procedures. These are emergency 5 procedures that are referenced here? Okay.
6 MR. COOK: Jerry's question is 7 already on the record. There was a process action ;
8 from this morning.
9 MR. SLADE: I think that's a I
10 generic question. It covers a lot cf ground.
11 MR. HUGHES: As you stated, 12 I don't believe we're able at this time to give a 13 date when those vill 'be availa'.ble, based on 14 latest information provided to me. We may still have them 15 under review.
16 I'd like to go on to the next 17 ene then. The adequate seismic category one auxiliary 18 feedwater supply.. A normal supuly frcs non-19 safety-grade condensate storage tank, automatic switcheyer 20 to safety-grade service water. Are there any questions 21 regarding thet?
22 MR. VAN HOOF: I have some very 23 strong concerns as far as operation is concerned of 24
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1 getting the chemicals in that service water system, inadvertently into the steam generator, and I see 2
I how you have taken care of the inadvertent automatic 3
switchover with the four second delay with the pump low pressure, but under nomal operating conditions, as I understand the isolation, there is two butterfly valves there.
7 What concern has been given to leakage by the butterfly valves which has been quite a problem over the years? Is there some indication that leakage is occurring by one of the valves, such that
- such as a telltale drain or an indication of pressure 12 buildup or something? What is being done?
MR. BALLWEG: There is a telltale 14 drain which is shown on the P&ID for the system.
15 MR. VAN HOOF: That's nomally 16 left open, such that it will nomally drain in case 17 there is a leakage by the one butterfly valve?
18 MR. BALLWEG: That's right.
19 MR. VAN HOOF: What size line 20 is it?
, 21 MR. BALLWEG: Three quarter inch.
22
[
MR. LEWIS: I'd like to provide a 23
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I clarification at this time regarding the fire protection 2
discussion we had earlier.
3 The criteria for the fire 4
protection do not require combination with an earthquake 5 or combination with -- or even necessarily use of only 6
safety-grade systems and this is one area that is the 7
source of suction water to the aux feedwater, where 8 in fact we are relying on the condensate storage 9
tank for the near tem source -- suction for the 10 aux feedwate , and we are not providing protection l1 for those suction valves, those autcmatic switchover 12 valves to the service water. Point of clarification.
13 I don't think it was as clear as it could have been 14 in the earlier discussisn.
15 MR. HUGHES: Raj, is that clear?
16 MR. ANAND: Yes, it's all right.
17 MR. HUGHES: Any other questions 18 on the switchover? ,
19 Boron monitoring capability with l
20 safety-grade system. Midland design has nonsafety-grad $
21 boron monitoring by continuous monitoring by a 22 boronometer on the letdown and periodic monitorinE 23 by manual sampling, and it's Midland belief that this 24 - 116 -
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l l
1 is adequate.
l 2 MR. TAYLOR: Is the boronometer 3 on the line downstream? Is that on the downstream L
4 letdow.; or downsteem sampling line?
5 MR. BALLWEG: Yes.
6 MR. TAYLOR: That one is not 7 available if the letdown is not available?
8 MR. BALLWEG: That's correct.
9 MR. HOOD: Does the staff like 10, to comment? Apparently not. No comment should not 11 be taken as compliance. I don't know if that's on or 12 off. ,
13 MR. HUGHES: All right. John, 14 the next one. Provide a safety-grade syste generator 15 water level indication and alam. I believe the 16 Midland design complies with the clarification safety-17 grade water level indication and nonsafety-grede 18 alams are provided. Are there any questions?
19 MR. GIBSON: I assume that the 20 reason for this is that the alams were there before .
21 the others were added.
22 MR. HUGHES: I don't believe so.
23 Mike?
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I 1 MR. GERDING: I'm not sure I 2 understand what you are -
3 MR. GIBSON: You are begging 4 the question. Whyaren'tthey all safety-grade? The 5 obvious answer is because they aren't but is there a 6 timing thing here?
7 MR. GERDING: No. Safety-grade 8 alams are not available and we have the redundant g safety-grade indications on each steam generstor, 10 and it's felt that these are sufficient.
11 MR. GIBSON: Are the alams 12 off the indicators?
13 MR. GERDING: No. They have 14 separate switches. In fact, the switches or the 15 bistables that provide the alams are themselves 16 safety-g sde, and they provide an isolated outlet to the non-Class I annunciator system.
37 18 MR. HUGHES: Isn't that a matter that the annunciatore 19 cannot be purchased to a 20 safety-grade or qualified seismic or what-have-you 21 situation. We believe that's state of the art in the industry.
22 23 MR. GERDING: That's correct.
24
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1 MR. HUGHES: That's why I said 2 if there is questions, we have to explain the rationale ,
3 MR. COOK: You just did.
4 MR. HUGHES: The last one we just 5 kind of - everybody was quiet. There is a reason 6 for all of these. ;
7 MR. SULLIVAN: Why don't you go ,
8 back then.
9 MR. HUGHES: We'd be glad to.
10i MR. SULLIVAN: Okay. What's 11 the Istionale for the last non-compliance, nonsafet:r-12 grade?
13 MR. HUGHES: Nonsafety-grade 14 boron monitoring? What's the - Mike, what's the 15 rationale for that? The fact was, it was an existing i
16 design.
17 MR. GERDING: I guess I would have to investigate that one further. I don't have, 18 19 off the top of my head, an answer to that. ;
MR. HUGHES: Jim Agar, isn't 20 that -- we considered just that itself. There is 21 n thing really you can do about it.
22 MR. AGAR: I'll pass on that one.
23 24
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I MR. HOOD: What's been the 2
practice on the recent near-term operating plant?
3 Anyone know?
4 I might also point out that 5 the way the staff slices up its pie for review, I 6 believe this particular item would be outside the responsibility of anyone that is present for the staff today.
8 today.
9 MR. GIBSON: I think it's obvious 10 why the boronometer -
11 MR. HUGHES: It's based on its 12 location.
13 MR. GIBSON: This is a very 14 early procurement, from what I know of a -- it's a 15 little -- kind of a difficult instrtunent to safety-grade ,
16 so the obvious question becomes manual sampling line.
17 I think you have already addressed the fact that ,that 18 is -
19 MR. HUGHES: The line is 20 physically safety-grade out past the containment 21 p enetretion.
22 MR. GIBSON: I think really 23 we would be into maybe a lengthy discussion as to this 24 - 120 -
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I sampling, how much nonsafety-grade are you using, 2 because it's an action that involves a lot of personal 3 involvement. It's not just something you're looking 4 to have happen.
5 MR. LEWIS: The post-accident 6 sampling system is designed, based on nureg 0578 and 7 nureg 0660, which do not require safety-grade systems. '
8 The nomal sampling system had no safety design basis 9 and therefore, was not a safety-grade system, so prior 10 to this requirement, there was no indication of a need 11 for safety-gzede systs.
12 The design does allow it, if an i
13 earthquake were to occur because of the seismic design 14 out through the containment, there is at least a 15 capability for access, long tem, to take samples, 16 make provocation if that were to be necessary. ,
l 17 MR. JENSEti: Would it be 18 advantageous to move the boronometer to the sampling 19 line upstream of the isclation valve? As I understand, 20 it's on the sample line downstream of the isolation
. 21 valve, and would be lost in case of the letdown being isolat ed.
22 MR. BALLWEG: The boronometer 23 itself is a nonsafety-grade device and dces not get --
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I does not get any qualified power supply to it.
2 In addition, if you were to take 3 the sample from that point, you would be dealing 4 with RCS cold leg te=peratures in the range of 530, give 5 or take a little, and you would have to cool that 6 sample befere you put it through and would reauire 7 auxiliary cooling water supply as well, and simply, would 8 be a fairly elaborete modification' to do it. The idea 9 of the location as it is is to bypass the letdo'm 10 - isloation system, to take the pressure, the sample l1 under pressure, and the temperature is whatever it 12 might be at the point you take it, and to -- in generel, 13 there is no need to take a Rcc sample within less than ,
14 a half hour or so, maybe even two hours.
15 In the case of boron, you wouldn't 16 be interested in measuring that until after you had 17 injected the EBS and given it a chance to mix, so 18 there is ample time to take the samp1e manually and 19 have it analyzed. ,
20 MR. SIADE: Point of clarification, 21 are you saying there is no cooler on that sample line?
22 That you do take the sample hot at pressure and it hac 23 to be cooled by some other means before you can analfre !
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l 1 it?
2 MR. BALLWEG: There is a cooler 3 on the post-accident sampling panel. I misspoke 4 in that regard. It's at pressure, however.
5 MR. HUGHES: All right. 7 6 Next one. Safety-grede makeup and letdown to accommode e 7 cooldown shrinkage and boration. Midland design 8 complies with clarification. The boration and cooldown 9 shrinkage is accommodated using only safety-grade 10 systems and we have demonstrated it can be done without t
11 letdown; therefore, letdown does not need to be safety-12 grade.
13 MR. SLADE: I think we beat this 14 one to death earlier. ,
15 MR. HUGHES: This is the 16 pressurizer heaters required to maintain natural ,
17 circulation condition, and we believe we have two 18 banks -- complied by having two banks of pressurizer 19 heaters capable to safety-grade power and controls, 20 and we have an action item to provide the Board with the 21 size and basis of the contention that one bank of 22 heaters alone is sufficient.
23 MR. MAZEDIS: I guess I'm just i 24 - 123 -
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I curious, not knowing the backgmund. If you're in the 2 process of depressurizing under natural circulation, 3 trying to get to the RHR cut-in, is that - - during that l
4 process, is that when you need the pressurizer heaters or 5 is it to maintain say hot standby where you need to have 6 the pressure at times increased? Or both?
7 MR. HUGHES: I believe it's both 8 the hot standby condition and the ability to control 9 pressure on the way down, because we have a - both 10 pressure and temperature limitation on cooldowns.
11 MR. BALLWEG: It's primarily to 12 maintain temperature at any point. Excuse me, maintain 13 pressure at any point.
14 MR. MAZETIS: Ycu don't think, 15 as you depressurize, that the existing control systems 16 to reduce pressure; i.e. the spray or PORVs are sufficierLt 17 to control the depressuri::ation rate, that you wouldn't want to turn than arcund? There is an apparent concern 18 19 here that the operator would need to counteract the 20 depressurization using the PORVs or the auxiliary 21 spray . I can see it as a nice to have kind of thing, 22 but --
23 MR. HUGHES: Based on, for some 24 - 124 -
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I period of time, being able to maintain using Class I 2 systems in the pressure, it's available for the 3 other function anyway.
4 MR. SULLIVAN: Mp Teco11ection, 5 we started this modification before TMI and the 6 reasoning was the ability to maintain hot standby.
7 Then nureg 0578 came out and I think the requirement 8 was a little less stringent than what we were doing.
9 We went ahead with it anyway, 10 because the design basis of the plant is hot standby.
11 In addition, it's nice to have -- during a cooldom.
12 That's my perception of what I have seen in this area.
13 MR. JENSEN: Are the heaters 14 themselves safety-grede or just the power going to 15 the heaters?
16 MR. HUGHES: We have been going 17 through relatively an extensive program on the 18 pressurizer heaters.
19 MR. BAIRMN:: We have B & W 20 qualifying the heater seism 1617 for us. Tne qualificaticn 21 program has not been completed as of yet. We don't 22 know the results. That's under way.
23 MR. HOOD: I don't know if it 24 - 125 -
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1 gets to your concern or not. We have asked the question about the burnout mode of the heaters and 3
I'm sure there is no concern in that regard.
4 MR. JENSEN: I wonder if someone 5 could address the processus you would go through in going to 6
Cold Shutdown without the pressurizer heaters? Usine other emtimanu 7
such as the makeup equipment or the ECCS.
8 Well, we haven' t MR. AGAR:
9 looked at that weird scenario for going to Cold Shutdovin.
10 We use the available 1-E systems in looking at the Il various methods and modes of getting to Cold Shutdown, 12 and that includes using a pressurizer heater to maintain 13 pressure to various heaters during the cooldown. We 14 It probably would be simply haven't looked at that.
15 impossible. ,
16 MR. GIBSON: I haven't been a 17 Also, I don't have a lot of experienc e plant operator.
18 with B & W, but from what I have obccrved, the way to Control primary system pressure during the cooldown 20 is with aux feedwater. That may nound weird, but 21 as we discussed at lunch, the impact on system pressure 22 of changes, slight changes in pressurizer level seems 23 to outstrip any effect on the part of heaters, and 24 - 126 -
HURON REPORTING SERVICE 7615320
1 having simulated through a couple of cooldowns, I 2 don't ever recall the heaters even being used. That 3 was not the concern. The concern was on the other siden 4 it was even with spray making sure you get enough heat 5 out of that darn thing to keep it up ,cith the cooldown.
i 6 I can't -- I guess my estimation 7 would be that it's possible, depending on when you stop 8 and start and all that kind of thing, that you could go 9 through that. Sure, you might need it, but I think to if you look at the track record, I amn't think people 11 have used those heaters that much. I should -- B & W 12 training people could verify that.
13 MR. TAYLOR: There have beer 14 cooldowns carried out without the heaters, and I think !
15 the thing that Terry m.entioned is appropriate, that 16 the heater capability is as much a convenience as anything 17 else, and if you run into a situation where you'd have 18 a safety valve leakage that you have to overccme or 19 some reason like that, where you needed. extra heet, 20 it would be helpful under those kind of conditions.
21 MR. BAUMAN: What Terry said 22 was right. The decision to go safety-grade on the 23 heaters was to maintain hot standby. That was the 24 - 127 -
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I licensing co mitment that Consumers Power Comuany has 2 always had, and without pressurizer heaters, we could 3 not demonstre.te that we could maintain - it's an 4, unanalyzed situation without heaters, like you can 5
achieve it without heaters, but maintaining hot shutdevm without heaters was a nonanalyzed situation. That's 6 :
7 long before Three Mile Island. We decided it would be 8 a prudent thing for us to do, upgrade the heaters.
MR. HUGHES: Jim Age.r?
9 MR. AGAR: The only point I wanteri 10 11 to make was that as far as I know right now, B & W does not plan to look at this other case. I just 12 13 wanted to make sure that was clear to the Board.
14 At this point, we don't intend to look at any scenaric, 15 other than using our available 1-3 systems for going 16 to Cold Shutdown.
MR. JENSEN: I asked the question 17 18 because there was a good deal of discussion about 19 another B & W plant as to s:hether or not they could 20 attain Cold Shutdown without the pressurizer heaters,
.- 21 and I wanted to be sure that there wasn't any necd 22 for pressurizer heaters here, that I didn't know about i
I 23 some safety requirement.
l
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1 MR. AGAR: I think they made 2 that clear, and I certainly agree with the statements 3 made by Terry and Ron, but I just wanted to make the 4 point, make sure the Board agreed that B & W does not 5 plan to do another analysis.
6 MR. HUGHES: That's the last i
7 one; isn't it? I believe that concludes the various 8 positions. Are there any other questions? .
9 MR. SIADE: Yes. I have one, 10 and I guess maybe -- I'm sorry. I'm getting ahead 11 of myself, but are you going to go through the ,
12 instrumentation separately? The items for 13 instrumentation.
14 MR. LEWIS: We have not yet 15 covered this. SRP 7.6, ecmpliance. We can do that 16 either as open questions or similar to what we have 17 just done.
18 MR. HUGHES: Okay. We'll go 19 through that. This one being a little different 20 fomat, how would you like to go through it?
21 ,
Would you rather go through the tabulation of instruments that we showed and ask questions?
22 MR. COOK: It's really a pretty 23 24 - 129 -
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I free format, Ed.
2 MR. HUGHES: What does the Board 3 want to do? We have stated that the instruments are 4 redundant.
5 , MR. COOK: I think any questions 6 the Board may have or the NRC staff may have, I think 7 Jerry, you were the first one up.
MR. SLADE: I have a concern, 8
9 I guess about the instrumentation that's not 10 available at the auxiliary shutdown panel, and 11 specifically, the lack of a neutron monitor or flux 2 monitor at the remote shutdown panel.
13 MR. SULLIVAN: I think I can 14 respond to that. I just signed a letter yesterday 15 afternoon to Ron Bauman, which contains a recommendation 16 to add neutron flux indication at the aux shutdown 17 panel, so it's -- that particular modification is in just for background. We have a task after TMI, 18 19 called plant status indications. We had completed 20 the bulk of that task, except for the indications on the aux shutdown panel. If Jim remembers, it's 21 22 on the 90 day decision table or whatever, and we 23 just completed that recommendation yesterday and it'c 24 130 - -
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1 on its way to Ron Batanan, and so I guess that the botton, 2 line is, that the nomal process now will allow that 3 to be resolved with the involvement of the Board member 4 and to their satisfaction. I expect the recommendation 5 will carry through.
6 Ma. GIBSON: I have one question 7 of Mike, on his presentation. Again, aux shutdown 8 panel, you allude to controls for component cooling g water pumps. Associated with those controisi vhat kind 10 of indication do you have that your system is functionir.g?
11 MR. GERDING: There are pump 12 indicating lights available on that panel and there may 13 be - just a second.
14 MR. GIBSON: Is that merely 15 breaker status or is that some other -
16 MR. GERDING: That is breaker 17 positica.
18 MR. GIBSON: So you could not have 19 a pump and still have a good breaker position?
20 MR. GERDING: There are also 21 amp meters indicating current to the motors also en the
,'2 auxiliary shutdown panel.
23 MR. GIB30N: That's really what I 24 - 131 -
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I was looking for. I wasn't sure if you had them.
2 MR. GERDING: They are there.
3 MR. GIBSON: Maybe that's my 4 quirk, but I'd much rather see an amp meter next to 5 a light, that not only did I close the circuit, but 6 there is something flowing thmugh it.
I 7 MR. GARRICK: Just a few questions 8 along those lines, just for infor1 nation purposes, 9 and maybe they're trying to get your opinion.
10 For example, should control rod 11 drive trip breaker position indication be provided in 12 the control room or is it provided?
13 MR. GERDING: Again, there are 14 nonsafety-grede indications in the control room.
15 Let me clarify a little further.
16 The indicating light itself is 17 safety-grade; however, it's sensed from a nonsafety- l 18 grede source at the control rod drive breaker, so in 19 effect, an indication is not really qualified.
20 That is in the control room; however, with the neutmn 21 power indication provided in the control room, there 22 is an indication of -- that the reactor is suberitical -
23 and has indeed tripped.
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I MR. GARRICK: So you have l 2 indication, but it's not safety-gmde; is that what 3 you're saying?
4 MR. GERDING: That's correct.
5 MR. GARRICK: I wanted to know 6 what is the range of the reactor coolant system, hot 7 leg and cold leg temperature indication?
8 MR. GERDING: These are 50 to 9 750 degrees Fahrenheit.
10 MR. GARRICK: Is this valid 11 under natural circulation?
12 MR. GERDING: What do you mean 13 by valid?
14 MR. GARRICK: Do you get valid 15 indications under those conditions?
16 MR. HUGHES: Is your question 17 that you may overrange?
18 MR. GARRICK: Yes, it might be.
19 MR. HUGHES: I don't believc we 20 have had any analytical indication of exceeding that 21 range.
22 MR. GARRICK: I just want to be 23 sure that you get indication during natural circulation 24 - 133 -
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l 1 and then there is the range question, yes.
2 MR. GERDING: Well, the 3 indications will function during that time, and the 4' z1tnging has been increased. The range was not always 5 up to 750 degrees. The :enge was increased and it was 6 also done so in agreement with guidance provided in 7 the Reg. Guide 1.97 instrumentation for accident logic. ;
8 MR. GIBSON: Could I expand on 9 that question? Not so much the range, but are the 10 sensor design such that they are representative?
11 Can you elaborate a little? On the bottom of the pipe?
12 Top of pipe? Side? Length of probe or anything, 13 again. For circulation intuitively, I don't have a 14 prublem with it, but --
15 MR. GERDING: I really can't 16 answer that myself. Jim?
17 MR. AGAR: I can't addrcs: that.
18 If you really have that concern, I will have to take --
19 MR. TAYLOR: I can comment on 20 that briefly. There have been about, in excesc of ten 21 different instances where the plants have gone into 22 natural circulation cooling and cooled down substantial:.y.
23 Some of them intentional tests and some of then 24 134 -
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I I
inadvertent entries, and in all of those tests, there 2
have been a very good agreement between all the TC's, 3
and TH's and no reason to question their validity.
4 They allowed a good heat balance on the system, so I ,
5 think both the TC's and TH's are very representative O
under' natural circulation conditions.
It 's been at different plants ,
8 both raised loop and lower loop and under different 9
conditions .
10 MR. GARRICK: I wanted to ask 11 also on the pressurizer liquid and vapor space 12 temperature indication, is that provided in the control 13 room?
14 MR. GERDING: For which parameter?
15 MR. GARRICK: Pressurizer licuid 16 and vapor space temperature. ;
17 MR. GERDING: Indication are 18 available in the control room; however, they are not 19 safety-grade. '
20 MR. GARRICK: Of course, you v.ent 21 this to get sczn e indication of the subcooling and -
22 pressurizer subcooling and the margin between RCS and 23 pressuri::er. Along those same lines -- L 24 - 135 -
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1 MR. HUGHES: Just a second, Tom 2
Ballweg.
3 MR. BALLWEG: I would hope there 4
is no subcooling in the pressurizer.
5 MR. GARRICK: No. It's the 6
indication of pressure - well, okay.
7 MR. BALLWEG: Meybe you skipped 8
a .ew words when you were speaking. Pressuriner, by 9
definition is an equilibrium saturated vessel.
10 MR. GARRICK: That's right, and
[ do you get a PORV position indication in the control 12 room?
13 MR. GERDING: Yes.
14 MR. GAPJ1ICK: Is that safety-grad 2?
15 Yes.
MR. GERDING:
16 MR. SLADE: In reference to 17 Lou's question earlier about length of probe:, are the 18 probes fer pressuriner vapor space temperature and 19 the pressurizer water phase temperature sufficiently >
20 long that they get through the metal of the pressurizer?
21 You are not cieasuring metal temperatures, but actually 22 vapor and water temperctures? ,
23 MR. GERDING: I would have to 24 - 136 -
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1 refer that to B & W. i MR. TAYLOR: They're inserted 2
t into the stream, into T.he fluid.
3 MR. COOK: Further questions on 4 l 8 '##
5 MR. HUGHES: Are there any 6
7 further questions on any topic?
I believe that concludes 7-4; 8
g doesn't it?
R. S W E. I We one addMonsi 10 ,
3, question. We discussed a little earlier some of the
-- that there were manual actions associated with chemical additional system and I guess I'd like to heve 13 g
a little bit more discussion about the extent o ? the manual actions to line up the boric acid addition for L g
insertion into the makeup system.
MR. HUGHES: Mike Pratt?
17 MR. PRATT: What I can do is give 18 g
you a walk thrcugh all of the specific manual actions that would be required for tat event.
,0 2
One thing I would went to point
,1 1
out, though, is we're continuing to evaluate the specific manual actions. Certainly are after today,
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24 HURON REPORTING SERVICE 761 5328
1 but procedures, detailed procedures wot].d be developed 2
and we haven't quite gotten to that point yet.
In particular, what the operStor 3
4 would need to do is first align the suction valve from -- and what -- I have listed all my instrument 5
6 numbers and whatnot in here.
MR. SLADE: Okay, as you go through, 7
g could you indicate whether the manual action is e g
contml room accion or whether it requires local.
That's really what I'm concerned about.
10 MR. PRATT: Okay. The operator 11 w uld need to align the suction valves to 1P70A or B 2
fmm the boric acid addition tanks, which are 1P70 A, B 13 or C for unit one.
34 Essentially, line up from the 15 tank and the pump. Local manual action.
16 MR. GIBSON: Mike, you said 17 align the suction to P70 A or B? Those are the makeup 18 19 P*E 8 MR. PRATT: No. Those are the 20 boric acid addition pumps, which deliver fluid to 21 the makeup tank.
22 MR. GIBSON: Are we talking about 23
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24 HURON REPORTING SERVICE 761 5320
l 1l alignment of EBS7 1
2 MR. SLADE: No, no. Chemical 3 addition.
4 MR. GIBSON: I didn't think I 5 ws there.
S MR. BAUMAN: This is figure I 7 Roman Ntraeral IV, for the benefit of the people who 8 want to follow this?
9 MR. PRATT: Well, the detailed 10 valve configuration isn it shewn on that.
11 Now again depending on what ;
12 the operetor is going to be using the boric acid 13 eddition tank for, let's say that's auxiliary spray.
14 Then we have a need to open the manual auxiliary spray 15 isolation valve, valve 374, for unit one.
i 16 The operator would need to open 17 recirculation valves to recirculate makeup back to the 18 makeup tank solenoid valve 0334 and 0335 19 MR. HUGHES: Mike, are those 20 remote or local?
21 MR. PRATT: That's remote.
22 The operstor would need.to open a - there is an air 23 operated valve and discharge for the boric acid 24 I -
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HURON REPORTING SERVICE 7015328
1 addition pmp, and in the event of a loss of air, which 2 we can assume the operator would need to open the 3 bypass valve. Local manual action, valve nmber 159 4
Another action the operator would 5 have to take, this one identified and I'm not - I have 6 got the valve number indicated and I don't remember 7 specifically what the words are. Let me jmp ahead 8 and come back to that one.
9 Okay. Downstream of the ~~
10l now, we have got a flow path established from the 11 boric acid addition tank to the boric acid addition l2 Pump. Downstream of that, there are solenoid valves 13 in parallel, and that's what I was just touching en.
14 The operator will have to open one of these two solenoid valves. Remote - no, local 15 16 manual. "here is position indication. but local manual.
17 Excuse me, those are rmote. ISV0381 and 03-- 0318 18 and 0371.
Kind of following the flow path, 19 20 okay? So you work through the solenoid valve and at 21 this point we're just tying into the makeup purification 22 system line downstream of the T.hree way feed and 23 ' bleed valve.
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24 HURON REPORTING SERVICE 761532J
1 Working downstream of that, 2 the operator would have to open a post-filter bypass 3 valve. Valves that align flow thmugh the post-filters 4 are air opereted plug valves, and in the event that 5 that was closed, he -- or if it's open and he doesd't 6 want to go through the filter, he'd need to open the 7 bypass valve. Remote manual from the control room.
8 Valve 1SV0366.
9 In the event of a loss -- now, 10 we're down in the makeup tank. In the event of a loss 11 of offsite power, the motor operated valves downstream 12 of the makeup tank close. 1M00328 and 0329. The 13 operator would need to open both of those valves to 14 establish a flow path from the makeup tank to the 15 makeup pump, the suction header.
16 MR. GIBSON: How can those motor 17 operated valves fail to close if they're closed?
18 MR. PRATT: If they're closed, e
19 yes. If they're closed, the operator will have to 20 open them.
MR. COOK: For cor.venience, 21 where are we taking this discussion?
22
~23 MR. SLADE: I was just trying tc 24
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1 get an appreciation for the extent of manual control 2 that was required, the extent of operator action, and 3 I think it leads in the same direction as the question 4
that was asked by Jerry earlier about the ntaber of 5
perator actions required in order to assure that you 6
have boric acid addition and you have - that you are 7
achieving Cold safe Shutdown.
8
- " E I" g to go any farther than thic. The operator actione are 101 s h e W from Gat standpoint, I pss you sam i
you're already reviewing that.
MR. PRATT: These operator action::
are only required in the event of the design basic tornado, so that the operator doesn't use the BWST as the source of contraction volume makeup.
MR. HUGHES: The condition you postulated was, Jerry, essentially the chemical addition system. That's only required for going to Cold Shutdown in the event of a design basic tornado. That takes out the -- that takes out the borated water storage 20 ~
tank and that you have loct offcite power, so you're talking a relatively extensive amount of time available in this situation.
23 l
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HURON REPORTING SERVICE 761 5320
1 MR. GIBSON: I would like to 2 carry on Jerry's conversation a --
3 MR. SLADE: Does that meet 4 the criteria of number three that you were talking 5 about before? That is, permitting operator action, 6 local operator action?
7 MR. VAN HOOF: I'd like a 8 clarification here, too. Do all of those operetions 9 have to be cone or are some of those valves already 10 lined up for normal operation? I think what you're 11 after is what has to be done in that event and you have 12 gone through almost every valve that has to be 1; positioned, and some of those are probably normally 14 lined up already.
15 MR. PRATT: They may be.
16 MR. VAN HOOF: So, he went 17 through every valve and the operator would not have 18 to go through every one of those valves.
19 MR. HUGHES: From a designer 20 standpoint, we presume you'd verify valve lineup 21 before going into that mode. That's up to the 22 operating department, though.
23 MR. GIB50N: What about the 24 - 103 -
HURON REPORTING SERVICE 761 5328
I emergency boration tank? Without going through each valve, how many valves do you position and line up?
3 More than one? More than five?
4 MR. PRATT: To get to the r- up 5 header? Two.
6 MR. GIBSON: Two, t-v;-c?
7 MR. PRATT: Two local manual 8 valves. Dcwnstream of that depends en which makeup 9 pump you are using, and what the configuation of the 10 makeup systcc valving is.
11 MR. HUGHES: Would it be fair 12 to say in a nomal operating mode, nothing abnomel, 13 that if you wanted to cut into the EBS system, you'd 14 only have to cut in two valves?
15 MR. PRATT: That's the minimu=,
16 right. Well, now wait a cinute. That':: only to 17 establish the suction path. You still need to isolate 18 recire. So you got at least one more.
19 MR. GIBSON: From the control 20 room?
21 MR. PRATT: That can be done
. 22 from the control mom.
23 MR. GIBSON: One last question.
24 - 144 -
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I For decay heat removal, hcw many valves do you have to !
2 line up outside the control room?
3 MR. PRATT: Four. You 've go t l 4
to close the valves from the BWST for each train, 5
so you've got to open the comnet. Does someone have 6 P&ID7 e
7 MR. HUGHES: Do we have a psID 8
available?
9 MR. CCOK: Let me go back to the 10 overall point.
l1
_ MR. GRIESE: Let me address this.
12 Nobody asked me to, but that seems to be my forte'.
13 Decay heat removal systs requires isolated -- the 14 isloation valves on the pump suction to be opened.
15 It requires the controls to be re-established to the 16 bypass valve around the decay heat removal cooler.
17 It requires manual valves in the auxiliary pressurizer 18 aprey to be open from the discharge of the decay heat 19 runoval cor.ler.
20 Also, we recommend - B & W 21 recommends that the cross connect between the drop line 22 and the BWST header be closed. Now, that has a check 23 valve in that line, which would be operative; however, 24 - 145 -
HURON REPORTING SERVICE 7615328
I 1 we recommend that it also have a manual valve closed.
2 Now, that takes at least three manual valves open to 3 - you have to establish contrul to two motor operated 4 valves, the bypass valves and the other two valves 5 in the suction header are --
6 MR. PRATT: The power to the 7 bypass valves is electrically locked out. Electrically 8 closed for LPI and you need to restore power back in the 9 breaker 3 for those and open them.
10- MR. GIBSON: Okay.
11 MR. COOK: I think, Ed, we' re -
12 what I think we have heard is - in this review meeting 13 of the Board, is that we have a general question of 14 the adequacy or how much manual action is required, 15 both to understand it from total system operation.
16 I think in the short ter=ye have to address and the 17 Board, I think, has to caucus on this. Generally, hov 18 we close the loop on the overall action ites. We have 19 some questions of just basic design to respond to the 20 NRC about that we have heard today, but in a much 21 bigger picture, is the question of the overall review 22 and the detailed preparation of procedures to make sure 23 that there is adequate understanding from the operating 24 146 - -
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t HURON REPORTING SERVICE l
' 761 5320
(
! 1
1 folks and feedback of any hard spots they nin into t
i 2 in developing their procedures back and forth in the 3 final phases of design, and how we resolve that issue 4 as far as the completion of this Design Review Board.
5 I think we have to caucus on, ,
6 but I think we have the action item identified and i
7 we have the two general levels of endeavor that t
8 are scoped out.
P g MR. HUGHES: Is it clear to 10 the Board the areas where we werc discussing the 11 manual valves are all long tem evolutions?
12 MR. COOK: Yes. I'm not sure 13 if I pers nally have everyone properly categorized, 14 but I think it would be a group discussion.
15 MR. SLADE: With the exception 16 of the boric acid addition in the case of the de:ign 17 basit tornado, is that also long tem or is that a 18 shorter tem?
19 MR. PRATT: That's long tern.
20 That's only required for contraction volume makcup 21 and would not be required in the short tem.
22 MR. COOK: Are there any further 23 questions on any topic from the Board'or the NRC ctcff?
24 - 3 47 ~
HURON REPORTING SERVICE 7615328
I If there are none, I think we 2
now really ought to have two steps left in today's 3
agenda. I think the Design Review Board needs to caucus 4
to clarify and specify for itself and for the record, 5
the action items it expects to get resolved as a result i 6
of this meeting.
7l I think we'd also like to ask 8
the NRC staff to caucus themselves. I'd like to have 9
them give us a reaction, if they would, on just that 10 their observations are in participating with us today ;
11 in this meeting and then I think we ought to talk aboutn 12 when we come back together, those two topics and also 13 the followup.
14 I think as I mentioned in opening 15 the meeting, we have proceeded into this process, 16 basically in an experimental vein. I think we're going 17 to need your feedback as well as our c'.n to deten::ine 18 whether we think this is the most efficient way to 19 carry out the process we have in front of us.
20 I think we are committed to you, as a stsff, to dc ;
21 everything we can to support you in the licensing i 22 review of the Midland Plant and frankly, we really need 23 to get your feedback in terms of which is the best wy '
24 - 148 -
HURON REPORTING SERVICE l 7615328 '
1 that you can see to get the job done and to let us, you 2 know, assist you in trying to go through that task.
3 I also think in terus of just 4 the general protocol of this meeting, as we have talked 5 about in terms of the letter that we sent to you in 6 January initiating the process, I think we need to ask 7 you to comment back to us on the - what our expectatiert::
l 8 are in the last paragraph of that letter as to how we closa 9 with you the activities, such as completing your review to and docunenting it in a draft section of an SER on the 11 various topics we're going to address.
12 I think there is sort of two 13 specific topics, Darl, we need to get response to 14 you. One, how do we close, you know, on the particular 15 items we have addressed today in this Design Review 16 Board with the staff, and then two, that the general 17 evaluation in tems of all the things that you, as 18 the staff, are pursuing with and without us, in tems 19 of the Midland review and how you would suggest that 20 we work together best in the coming months to proceed 21 through the review process.
22 Ed, do we have a room?
MR. HUGHES: Jian, we have threc 23 1
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HURON REPORTING SERVICE 761 5328
1 rooms. The procurement rooms that are just across 2 the little lobby and down the hall. Not the main lobby, t 3 but just the little table out her .. There is a big 4 one at the end, I suspect that will be for the Board, 5 based on the size, and the one next to it for the 6 NRC.
7 MR. COOK: Do you want to lead 8 us down there?
9 MR. HUGHES: We had a coupis of people keeping track of action items. Do you went 10, 11 to --
12 MR. SULLIVAN: I have got mine 13 written down. If somebody from Bechtel was keeping 14 track of action items, why don't they just join the 15 Board.
16 MR. COOK: We will have an 17 adjournment now. Let's -- 20 minutes to a half an hour" 18 MR. HUGHES: You want to get back 19 here at say ten after five?
20 MR. COOK: Let's shoot for five, 21 but ten after at the latest.
22 (Whereupon there was a short 23 recess taken'.)
~
24 150 - i ..
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1 MR. COOK: We're ready to r
2 reconvene if the recorder is really to put us on the 3 record.
4 I thirik it goes without saying 5 it took just a little longer than we anticipated to 6 get through the considerable amount of discussion we 7 have had during this day, and try and make some 8 organized sense out of it. I think in trying to 9 conclude today's discussion, the first thing I'd like 10l to do is to thank the individual members of the Board 11 and the mecbers of the NRC staff vho participated with 12 us. I, for one, it really exceeded my expectations 13 in terus of the amount of infomation we vould get 14 discussed, and the level of discussion; therefore, I ,
15 think it goes without saying that those who are part 16 of the discussion, had given quite a bit of thought to 17 what was presented to them and raised some very 18 interesting questions.
19 I think some of the pmblems 20 we had in getting everything organized to wrap up 21 today's session, is that I find there is a conflict 22 between some of the things that were discussed here 23 today and the context of an individual Design Review 24 - 151 -
HURON REPORTING SERVICE 761 5328
I Board, and the functioning of the ongoing project and 2
the way it does its business, both in the licensing 3
arena and in some of the other activities, such as 4
the preparation of the plant procedures and as such, 5 we try tc , in going through the stuff that was diset.ssed.
6 tuday, tried to sort out in an appropriate fashion, 7
what should go in what catego:"/ for ultimate resciution e i
8 although obviously I think everybody felt that all the 9 items that we didn't close out today, were worthy of 10 resolution.
11 As such, we have -- Don Lewis, 12 who is acting as thescribe and recording secretary of 13 the se sion we just had, who is in charge, with our 14 thanks for getting it co==itted to paper.
15 We'd like to have him list the 16 organization of the open itens as we recorded them in 17 our notes.
18 MR. LEWIS: I have 12 action 19 items as follows: First, describe the analysis of 20 the auxiliary spray line and its connection to the 21 existing line. Address temperature, pressure, number 22 of cycles, potential lov velocity effects, the effectiveness of 23 the auxiliary spray itself. Address also potential 24 - 152 -
HURON REPORTING SERVICE 7615328
1 concern for the fact that many cycles could occur in one usage, and address - include in the discussion 3
both the spray no::le and thepiping.
4 Second, provide the basis for 5
sizing of the pressurizer heater bank capacity, the ,
6 safety-grade heater bank.
7 Third, the mador point of 8 discussion was the interface of ths engineering dt..rign 9
with the development of nonnal and emergency procedures. ,
1 10 including the design for modifications late in the lI This will be referred to project management design.
12 for resolution independent of the Design Review Board 13 pro cess.
14 Fourth -
15 MR. COOK: Let me just amplify.
16 The specific question was related to Cold Shutdown.
17 The discussion we had today. The thing that I --
18 as corporate responsible officer for the project, 19 feel that I want to assure myself of -- that we have 20 an ongoing process that's going to make sure that 21 gets taken care of across the board, and as such, I 22 wanted that back in the nomal chain of business for 23 the project and we have tracking systees and so forth 24 _
153 -
HURON REPORTING SERVICE 7615328
I 1
in our nomal project management meetings, which is the arena in which I propose to resolve that item to 2
my wn satisfaction and of course, the rest of the 3
projects.
4 5
manual a tions associated with proceeding to Cold 6
Shutdown to detemine the cost benefit of potentially 7
automating some of these actionc with emphasis on the 8
do inant actions in the risk sequences. That was given 9
10 M *' '
- Fifth, describe the single loop natural code analysis. State whether potential reverse g flow in the idle loop will be addressed. Address the adequacy of sampling for boron and provide the schedule for completion of this analysis .
Six, describe boron mixing under natural circulation conditions. Include the injection to the idle loop for single loop natural circulation, address sample capability, access considerations i
in sampling, safety grade design of sampling, and discuss also the boron mixing test.
Seven, state the consideration 22 of the . teed for p eriodic testing requirements of the
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24 HURON REPORTING SERVICE 761 5328
4 1 emergency borstion system in the design of that system.
2 Ei 6ht, consider a study of the 3 decay heat resnoval drop 11ne safety valve failure.
4 The probability - consider the probability of such a 5 failure, whether it can be sensed and how -- if it 6 could be adequately isclated.
7 Nine, evaluate discharges to the ,
8 reactor building sunp, addressing possible vortex j 9 fortnation.
10 Ten, demonstrate the acceptability 11 cf manual actions in view of the regulatory requirements .
12 A second part of this one is that the plant operations 13 will review the procedures to be able to operate the 14 plant and this is really folded back into actioniten 15 of three.
16 MR. PRATT: Clarification.
17 I believe that's action iten four, and I don't understand 18 the difference between tour and ten.
19 MR. LEWIS: No. Okay. The cecond 20 Part of that question, ten, the review of plant 21 operstions is part of item three, which is the interface 22 of engineering design with development of operating 23 Procedures.
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I
1 MR. PRATT: Okay. Actually, ,
2 four related to manual actions and risk. Maybe I will 3 wait until you go through all of them.
4 MR. SULLIVAN: I think, maybe 5 a point of clarification is that the last action itesa 6 mentioned relates more to the regulatory criteria l
7 and then the operating concerns. The previcus action 8 item relates to looking at the manual actions that 9 show up in dominant risk sequences, and the two may no t 10 be the same, since it may be that none of these manual 11 valves show up in the dominant risk sequence; ekay?
12 MR. COOK: I think we clearly 13 had some items that came up in the section six of the 14 presentation about compliance with regulatory guidance, 15 which revolve around manual actions that we have to 16 directly resolve wit.n the staff and then that':: the 17 specific part of number ten.
18 Then, the generic part was to 19 fold it back into the overall development and review 20 their -- the operation starr.
21 MR. LEWIS: Item eleven, 22 investigate the concern for intersystem check valve 23 leakage testing as described in the forthcoming NRC 24 156 -
HURON REPORTING SERVICE l 7615328
1 letter.
2 Item twelve, evaluate natural 3 circulation cooldown testing as to demonstrating cooldown 4 capability and operator training.
5 That's the extent of the actien 6 items.
7 MR. HUGHES: Is item twelve 8 again related to this recent NRC correspondence?
9 MR. LEWIS: It's related to 10 it, but it may - that may be part of the response.
11 It may be in that context.
12 MR. HUGHES: It's different from 13 - I can't remember the number that dealt with the 14 naturel -
15 MR. LEWIS: We elected not to 16 state the action items in terus of that letter becauce i 17 there hasn't been enough review on that letter tc 18 really be confident that we know what it says.
F 19 MR. HUGHES: There was a previous action item whoce number I didn't record, which starts 20
. 21 off with the natural code and then goes into the testing, 22 and this is different?
23 MR. SULLIVAN: One is analysis 24 - 157 -
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HURON REPORTING SERVICE 7615328
1 and one is testing.
2 MR. HUGHES: Okay.
3 MR. COOK: I think we ought to 4 put on the record, generally that the complexity of 5 summarizing the action items means that we wil'1 have 6 to take an iteration, at least once on trying to review 7 and clarify for our own sanity, exactly what is intended 8 to be done on the - in specifying the action items.
9 V! hat we propose to request the 10 design team to do, is to respond to the Board directly 11 on the items that were specifically raised by the 12 Board outside the context of the normal project 13 operational iunction. Those things that are cirectly 14 interfacing with the staff and staff positions, would 15 be carried forth in the licensing operation of the 16 proj ect.
17 The one item concerning the 18 overall project work on translating overall design 19 requirements into operating procedures wCuld go forth 20 as a project item cfr line of the Design Review 21 Board. Those particular activities will be referenced 22 tack to the Board in tems of closing out the action 23 items with regard to this particular Design Review Beart, 24 - 158 -
HURON REPORTING SERVICE 7615328
1 plus the specific responses to the questions raised 2 in the context of this design review, and as a result 3 of that response, the total list of action items, 4 the Design Review Board will render a conclusion on 5 the adequacy of the action items and respond back to 6 the design team.
l 7 MR. BAUMAN: Let me ask, do you 8 have --
9 MR. COOK: I certainly intend 10 to. I was just trying to specify for his benefit, the 11 sey we foresaw our method of proceeding in concluding 12 this particular Design Review Board, and that v.ss 13 really the results of our own caucus, and now I'd like 14 to, you know, ask you to give us any comments you may 15 heve as a result of your caucus.
16 MR. HOOD: 7. v.n sn ' t paying L
17 attention to your last comment. You made a statement 18 about the methods by which you intended to conclude 19 the open item. I'm afraid I missed it. I'm going to ,
20 ask you to repeat it for my benefit, f 21 MR. COOK: Once we have beer able !
22 to write down with some clarity and specificity, actuel 23 action items, we're going to have the design team 24 - 159 -
HURON REPORTING SERVICE l 761 5320
1 respond to each of those items and then direct that 2 response back to the Design Review Board, at which time 3 we will circulate that infomation and review it among 4 the Design Review Board mcobers and then draw a 5 conclusion as to its a equacy in tems of closing cut, 6 in our mind, all of the action items that have been 7 raised.
8 I think I have made a condition 9 of that response that certain of those action items 10 will be referred to the normal channels of project 11 cp eretions. Specifically, the licensing activities 12 and the operation of -- procedure writing activities.
13 MR. HOOD: All right, I understand .
14 MR. COOK: I'd like to now ask 15 you if you'd like to give us any comments fror. your 16 caucus in reflections on the day's activities?
17 MR. HOOD: Yes, I do heve a few 18 comments. I'm not going to reitetete comments that 19 were given by the staff during the meeting. I'm sure 20 you know what they were. I will just generally highlight 21 what they were under the category of natural circulation 22 test, and I'd like to make a further application with 23 regard to the natural circulation . test. Referring now 24 - 160 -
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HURON REPORTING SERVICE 7615328
1 to the test with respect to RSB 5-1.
2 Part of this test - a report 3 should be submitted to the staff which defines the ;
4 test goals, 51ves the technical basis for the test, 5 and justifies the acceptance criteria. The report 6 should include calculations of natural circulation 7 flow Inte and loop transition times, estimates of 1
8 expected boron concentrations and should consider the 9 effects of instrument :rrom sample line trensient 10 times, and instrument response times on interpretation 11 of test results.
12 Another area of frequent staff 13 comment during this meetirg was with regard to a manual 14 action, with respect to RSB 5-1. I won't reiterate 15 those, but I'm sure you observed Mr. Mazetis' comment 16 with respect to three categories of manual actions,
. 17 and his comment that in general, the - only the third 18 category, category dealing with action after a single 19 failure, is negotiable in the Staff's view -- I believe 20 he did mention the exception in regards to restoring 21 power to a valve, in that regard, and Mr. Jensen, as
22 I recall, made a statement about basis for Cold Shutdowr in ,
23 less than 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. I believe he was after the 24 - 161'.-
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HURON REPORTING SERVICE 2 ei.s 3 28 l
I analytical basis for why it can reach a Cold Shutdown 2 in less than 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />, exactly the where -- of its 3
prior commitments on other matters that relate to 4 this meeting, he referred specifically to our feedback 5 of our position regarding a single fire in the cabinets I
6 in the control room.
7 I'm also aware of the need for 8 feedback with respect to the containment sump test.
9 I do have a few general ccoments 10 to make about the observations of the meeting today 11 and its affect, if that would be appropriate at this 12 time.
13 MR. COOK: We'd appreciate 14 your comment.
15 MR. HOOD: It's been my 16 impression that this meeting has been very worthwhile.
17 I would characterize it as a very probing type of 18 meeting and its been very helpful to us. I dare say 19 that the meeting was much more probing in certain areas
.20 than the staff would have gone. That was also of 21 considerable interest to us.
22 At the same time, while the 23 meeting has been very helpful in bringing out the issues 24 - 162 -
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1 that need the action, I would - I'm also aware that 2 whatfollowup comes out of this meeting is also quite 3 important and in that sense, the true effectiveness 4 of a meeting like this is still in balance, subject 5 to that followup act, but I can say at this point that 6 what has trenspired so far has been extremely encouraging.
7 I'd like to complement Consumers 8 on the composition of the Board as its evidenced her'e 9 today. That composition has pmven to be excellent.
10 I have also seen much evidence in the discussion today 11 that Consumers and all of its consultants, have been 12 very active in making improvements in the systas during 13 a period of relatively inactive review on the part of th e 14 staff.
15 I would also like to e:: tend the 16 EPPreciation on the part of the staff for a very nice 17 tour that we -- was given to us yesterday, and I 18 particularly would like to thank Jiu Aldering who a:.ted 19 as our tour guide. I think it was a very well organized 20 tour and no doubt it was very helpful to the staff in 21 today's discussion.
22 MR. C00!h I think ent :ning I 23 failed ta mention, all of our followup correspondence 24 - 163 -
l HURON REPORTING SERVICE l 7615328 l
1 will be part of the record in this and m2de availablo 2
to the staff.
MR. HOOD: I did want to ask 2
about that, Jim. You know, that one of the -- one 4
5 f the end products of a meeting like this and ene !
f its measuresof usefulness will be an early SER.
6 I believe thet the meeting today, discussion that I 7
have heard today and the followup actions that I 8
g anticipate will lead to such an end product.
- 8 "8 8 8 10 33 that within 30 days after the cpen items are addressed, we would issue a SER. I would anticipate interecting W DSMerS n e PrqaWon of het SER, or 13 at least before issuance in its final forv..
I am enCou!Eged by your comment that the docunentation for resolution of those items 6
g would be in the open forum. As you know, I am sure you will appreciate the Commission Department in that 8
- E '
- E 19 surrogate review to the review perfomed by the staff ,
and in that sense, we are sensitive to our documentatica .
department. Thank you.
MR. COOK: Thank you. I think,
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l i
l 1 '
if there are no further comments by any of the I
i 2
members preSent, this will be the conclusion of the 3 Cold Shutdown.
Design Review Board meeting en 4
Thank you very much.: ,
5 6
7 8
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HURON REPORTING SERVICE 761-5328
1 2
CERTIFICATE OF NOTARY PUBLIC 3
4 I, Kim Marie Peterson, of the firm of HURON REPORTING SERVICE, a Notary Public within and for the 6
County of Genesce, State of Michigan, do hereby certify that 7
I reported stenographically the foregoing proceedings con- ;
8 g
sisting of (165) typewritten pages and is a full and correct-transcript of my stenographic notes so taken.
11 DATED: !M (L Ut b 'il M /_ h Y\CLttt C M dthl.'
13 { Kim Marie Peterson Certified Sho:cthand Reporter 14 15 16 17 18 19
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24 -166-HURON REPORTING SERVICE 7615328 ,
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SAFETY :m h I MAD TO TURBINE f :b:
MSIV 2
REACTOR OTSG CONDENSER i
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- HEAT REJECTION i
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I e HEAT REJECTION l MIDLANDUNITS 1 AND2 4/24/81 G-1510-24 i
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e O Cold Shutdown Capability l Following ,
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8 TRANSIENT FINAL CONDITIONS:
. TRIPPED - SUBCRITICAL CORE e LONG TERM HEAT REMOVAL BY SG's OR HPI i
9 FINAL CONDITIONS DEPEND ON: !
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TRANSIENT CONSIDERED I
I e FAILURES ASSUMED i
i 0 MEETING DESIGN OBJECTIVE:
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0 ESSENTIAL CONTROL FUNCTIONS l
. REACTIVITY / INVENTORY CONTROL
. PRIMARY PRESSURE CONTROL
. HEAT REJECTION O REACTIVITY / INVENTORY CONTROL e SHORT TERM CONTROL ROOS EMERGENCY BORATION SYSTEM
. LONG TERM /COOLDOWN CHEMICAL ADOITION SYSTEM HIGH PRESSURE INJECTION O PRESSURE CONTROL
- AUXILIARY SPRAYS
. SAFETY GRADE HEATER BANKS FIGURE V-2 0
l 1
1 O N i
9 TEWERATURE CONTROL i
e USE OF ONE OR BOTH STEAM GENERATORS
. NATURAL CIRCULATION CAPABILITY .
9 DESIGN BASIS TORNADO REACTOR TRIP e MANUAL -
e LOSS OF POWER REACTIVITY / INVENTORY CONTROL - BORATION FROM BWST EBS l l
O CHEM ADD TANKS TEWERATURE CONTROL f
. MAINTAINED BY STEAM GENERATOR PRESS lURE CONTROL l PRESSURE CONTROL e HEATERS OR AUXILIEr1Y SPRAY t l
l 8 HOT STANDBY CONDITIONS CAN BE MAINTAINED INDEFINITELY j i
O F1GuRe v-3 !
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Cold Shutdown Capability Following Chapter 15 Events l (From Table V-1?
COLD SHUTDOWN ACHIEVABLE COLD !
IN 36 HOURS WITH SAFETY SHUTDOWN EVENT GRADE EQUIPMENT ASSUMPTIONS LIMITATIONS i STEAM LINE LOOP .,
-0M_Y ONE LOOP MAY BREAK NO LOSS OF 1 FPI BE AVAILABLE
-TIME > 36 HOURS REQUIRED LOSS OF NORMAL AFW FLOW AVAILABLE NONE FEEDWATER YES TO BOTH STEAM GENERATORS CONTROL ROD GROUP AFW FLOW AVAILABLE NONE WITHDRAWAL YES TO BOTH STEAM GENERATORS FIGURE V-4
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O O O .j DESIGN GUIDANCE TO ACHIEVElMAINTAIN HOT AND COLD SHUTDOWN i
j e STANDARD REVIEW PLAN (SRP) 5.4.7,7A l
e BRANCH TECHNICAL POGITION (BTP) RSB 5-1 e OPEN ITEMS ASSOCIATED WITH NRC STAFF REVIEW e RSB-7
- ASB-8
- PSB-11
- RSB-10
- RSB-20 i e REGULATORY GUIDE (RG) 1.139 .
l . NRC QUESTION (OR) 211.35 l ==T s n #"*"' o. , si o.2, 1
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P BWNP-20032A-5 (11-80
. CONTRACT / STANDARD NO.
DOCIFIENT RELEASE K 620-0013/12 Q mumun MAR 2619811 em w 1 APR 001981 NOTICE (DRN)
PART-MARK / TASK- B&W DOCUMENT No. DOCUMENT TITLE "'"'
s N.
GROUP-SEQ.
Y 09-001-001 86-1123880-00 Xenon Dynamics and Shutdown Marain N/A l -
O Pa r'* %~\,,)~[ " [.
i l REQUIRED NO. COPIES INFORMATION NO. COPlES RELEASED BY i DISTRIBtJTION CDS DRN DOC- COPIES CDS DRN DOC ORGANIZATION OR TE INDIVIDUAL'S NAME J. S. Shively 15 15 15 R. G. Griese 1 1 1 __
h~/8-8/
NAME DATE J. D. Agar 2 2 2 G. J. Brazill 1 1 1 D. L. Smith 1 1 1 G. E. Hanson 1 1 1 REVIEWED BY C. W. Tally 1 1 1 J. J. Woods 1 1 1 lO i.. J. Rody K. A. Shepherd i
1 i
1 i W. T. sconson J. S. Tulenko i
1 i
1 i
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1 3,3g og7g B. J. Delano 1 1 1 J. D. Carlton 1 1 1 -
RETURN ORIGINAL TO R..R. LANG':
BWNP-20210-1 (1-78)
CALCULATION DATA / TRANSMITTAL SHEET C CALC. 32__ - ,
- ~
DO M M ID M IFIER TRANS. 86 - 1123880 _ 00 TYPE: _uSEARCE & DETE!CI*ENT _ SAFEU ANA1,TSIS REFCRT _ dCC. SERY. INPUT _ DESICN RQMT. _ DESICM YERIF.
TITLE Xenon Dynamics and Shutdown Margin PREPARED BY_
R. R. Lange [ h REVIEWED BY B. J. Delano @pQ TITLE Engineer DATE 3/10/81rITLE Sr. Engineer (/ DATE 3/10/81 PURPOSE:
The Midland Emergency Boration System (EBS) is designed to provide reactivity control to compensate for the decay of xenon following reacter shutdown. This report will discuss xenon dynamics following reactor trip from a variety of equilibrium and transient conditions. The purpose is to provide technical justification for a two hour EBS availability criterion.
" hat is, the EBS must be designed to permit the operator to inject the contents of the EBS storage tank in two hours. More details on the ECS functional requirements are contained in Reference 2.
.)
SUMMARY
OF RESULTS PACKAGES FOR (INCLUDE D0C. ID'S OF PREVIOUS TRANSMITTALS &
THIS TRANSMITTAL)
Source calculation file (1) 32-112379-00 (2) 86-1103856-00 Xenon reactivity will not decay to levels below those at reactor trip for at least two hours if the system has been operated at 5-100% power for '
extended periods.
It was determined that the mar.imum positive reactivity change due to xenon decay two hours after trip was less than 0.3% ap. This occurred for a double reactor trip where the reactor was restarted 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after a trip and then tripped a second time after one hour of full power operation.
The ability of the EBS to achieve its design function (long term reactivity
- control of hot shutdown) with a two hour availability criterion was confirmed.
1 DISTRIBUTION Page of 20
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XENON DYNAMICS AND
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INTRODUCTION ,
This report will discuss xenon dynamics as related to post trip xenon
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reactivity changes and shutdown margin. In B&W plants, the control rod design accounts for the reactivity deficits between hot full power and 532 F as well as a 1% ap shutdown margin with the control rod assembly of
. greatest worth stuck out of the core. This l% Ap shutdown margin is i calculated assuming a xenon reactivity corresponding to equilibrium 100% >
power operation. The xenon level eventually decays to zero if the reactor -
is shutdown long enough with the resulting reactivity insertion countered by increasing the soluble boron concentration in the reactor coolant system.
The time frame of the xenon decay dictates when the boric acid should be '
injected into the reactor coolant system to preserve shutdown mcrgin or prevent return to criticality. Post trip xenon dynamics directly impact how soon after reactor trip boric acid addition systems should be functional.
Xenon reactivity following trip from equilibrium conditions and transient conditions will be examined. The purpose is to identify the maximum O and expected xenon reactivity decreases that will occur following a reactor trip, particularly those in a two hour time frame.
ASSUMPTIONS
- 1. Typical iodine-xenon parameters for a 177 FA plant were used. Equilibrium i Hot Full Power (HFP) xenor, worth was assumed to be 2.7% Ap. These base case parameters were varied + 10% for the limiting case of interest.
- 2. The report deals with hot standby reactivity control. The plant was assumed to be at the Hot Zero Power (HZP) condition for B&W plants ;
(532 F) when shutdown.
- 3. It is assumed that return to power is accomplished by control rod l
withdrawal. ;
- 4. The operators are assumed to obey Technical Specification rod insertion limits.
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O 5. no additionai maaeuveria9 restrictioas are imposed.
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86-1123880-00 EQUILIBRIUM CONDITIONS O During steady state operation at power, the levels of iodine and xenon -
remain essentially constant. Upon reactor trip, xenon burnout (destruction due to neutron absorption) and iodine production (due to fission yield) are no longer occurring. The iodine and xenon inventories begin to decay.
However, since fodine is transformed by decay into xenon faster than xenon decays, the xenon inventory increases for swe period of time. The result is a temporary increase in the xenon reactivity before its ultimate .
decay. This post trip phenomenon is illustrated in Figure 1. The values of xenon reactivity at t = 0 are the equilibrium values for infinite irradiation at the power levels indicated. The reactor trips at t = 0, and the xenon levels increase as expected. A curve has been drawn through each of the xenon reactivity traces showing the locus of times when the xenon reactivity has decayed to its value at reactor trip. These are the periods during which the degree of subcriticality of the cere is greater than it was at the immediate post trip condition. This assumes that the :
temperature of the system has not changed. It is noteworthy that as the times to decay to equilibrium xenon decrease with power level, the rate of change decreases as well. Thus for the trips from the lower power levels, the time to decay to equilibrium should be considered in conjunction l
with the rate of change of xenon reactivity. For example,1.2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> after a trip from equilibrium operation at 5% power, the reactivity returns to t
its value at trip. However, two hours after trip the reactivity has i decayed below equilibrium by only 0.003% ap, an essentially negligible amount.
Also shown are the points in time at which the xenon reactivity has !
decayed to a value 1% ao below the equilibrium value. These correspond, f
for a core which is shutdown margin limited (i.e., only 1% ao subcritical immediately following trip), to the points at which the reactor could return to criticality if no bor6 tion operations were undertaken. Figure 1 f shows that the minimum time is approximately 27-1/2 hours. The time tends to increase with power at the higher equilibrium pretrip conditions because of increased iodine levels. At the lower power levels, the 1% ap xenon decay becomes a larger and larger portion of the equilibrium value. As O expected, the curve goes to infinity for the case where the equilibrium i power level (between 10 and 15% power) suppcrts just 1% ap ;:t.non.
A . _ _ _ . _ _ - . _ _ _
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86-1123880-OO
. l The opposite extreme from ope. ration at equilibrium xenon is operation _.
transient for start-up to a number of power levels. Figure 3 shows the ~l t
xenon transtent for trip from a number of power levels one hour after l a xenon free start-up. It can be seen that for all power levels xenon !
returns to its value at the time of trip more than 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> after the !
start-up. Figure 4 shows the xenon transient for a reactor trip three [
hours following a xenon' free start-up. Note that for bath Figure 3 and 4 l
- the transient shown begins with the reactor start-up, not the subsequent -f I reactor trip. Note from Figure 4 the times of decay to the value of xenon ;
reactivity at the time of trip. Note that only three hours of full power !
operation before the reactor trip is sufficient to produce enough iodine i to create a considerable xenon transient. In the limit, as the time at !
_ power increases, the results will converge to those of Figure 1. The f
significance of this is that the most limiting cases regarding the time !
decay of xenon to and below its value at reactor trip following equilibrium l operation are represented in Figure 1.
~
A xenon free start-up implies that the reactor is either in the beginning 3
of Cycle 1 or has been shutdown for several days. It is of interest j to observe the xenon transient for a start-up from some sort of post trip I condition. Figure 5 compares a xenon free start-up with a reactor start-up following a 40 hour4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> shutdown. The xenon transient for the latter case is based on a recovery at 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> from reactor trip from 100% power I equilibrium conditions. Start-up is at t = 0 for cases in Figure 5. !
I The curves for start-up to a given power level approach each other faster !
for higher power levels. For the start-up to 100% power, the curves become indistinguishable between 12 and 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br /> after reactor start-up. !
Thus as far as the post start-up xenon reactivity trace is concerned, l recovery from reactor trip may be considered a xenon free start-up for start-up after a shutdown of at least 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br />. i
- DOUBLE REACTOR TRIPS -
4 The logical extension of the above discussion is to examine the effects of tripping the reactor after recovery from a reactor trip. That is, !
suppose the reactor tripped at t = 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> on Figure 5 for both cases.
The xenon free case has already been shown on Figura 2. Before showing toe ;
effects of a double reactor trip on xenon reactivity for trip after I
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86-1123880-00
recovery from a trip, it is useful to list all of the pertinent variables. ,;
U The following parameters were investigated for the double reactor trips. -
The variables are labeled for reference on the Figures.
- 1. The equilibrium power level of the reactor prier to the first trip (PO )* l 2.
The number of hours the reactor was shutdown before restart (T)).
- 3. The power level to which the reactor was brought following restart.(P ).
3 [
- 4. The number c? hours the reactor operated after restart before the !
second trip occ:;rred (T2 )*
Figure F shows a reactor trip from 100% power 0(P ) with a restart to !
100% power (P)) at 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> (T)). The parameter varied is the du-ation of the return to power (T2). As expected, longer periods at power produced more iodine and thus larger increases in xenon reactivity !
I following the second trip. Virtually no increase in xenon reactivity O was shown for the case where the return to power lasted but one hour.
Thus small values of T2 lead to earlier xenon decay below equilibrium. i Figures 7 and 8 are similar representations of double reactor trips where l the parameter T) has been varied to 24 and 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br />, respectively. The [
trends are the same if the reactor operates at power for 5-10 hours following '
the reactor restart. It is seen, kever, that upon reactor trip at j 25 hours2.893519e-4 days <br />0.00694 hours <br />4.133598e-5 weeks <br />9.5125e-6 months <br /> in Figure 7 and 19 hours2.199074e-4 days <br />0.00528 hours <br />3.141534e-5 weeks <br />7.2295e-6 months <br /> in Figure 8 the xenon reactivity decreases. !
There has been insufficient fission to produce enough iodine to overcome ,
the xenon decay even temporarily. Indeed the rate of xenon reactivity
[
change after the second trip is greater for the earlier restart. The earlier the restart, however, the greater the residual iodine from equilibrium power operation prior to the first trip. This may be seen i from Figure 9, which shows the restart to 100% power near peak xenon '
at 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br />. '
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86-1123880-00 The presence of " xenon humps" during the 10 and 40 hour4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> double reactor ,
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trip cases and their absence in the 18-24 hour cases 111 plies that a restart
~
exists that produces the maximum xenon reactivity decrease following a second trip. This maximum is observed to be the point at which xenon
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reactivity decay rate is the greatest following the first trip. It occurs at approximately 19 hours2.199074e-4 days <br />0.00528 hours <br />3.141534e-5 weeks <br />7.2295e-6 months <br /> after the initial shutdown.
It is seen that a number of factors govern the rates of reactivity change due to xenon. The greater xenon density tends to increase the rate of .
xenon reactivity decay. This is seen from Figure 1. During the restart of the double reactor trip, xenon burns out until the second trip.
The xenon decay then continues but its rate has been decreased somewhat due to the iodine inventory increase that occurred after the restart. Thus longer operation at power increases the time it takes xenon to decay to some specified value. This is in contrast to the trips following xenon free start-up where lore time at power until trip shortened the time to decay l
to the xenon level at trip. The difference is that in the double reactor
- 1. trip case the residual xenon inventory decaying from the first trip overrides the tendency of th: newly r.stablished iodine inventory to increase d xenon reactivity following the second trip. -
Since it has been observed that less buildup of iodine during the ,
restart leads to faster xenon decay after the second trip, it is logical to expect that the results will be more severe if the second trip occurred after power operation at levels below 100%. This is confimed from inspection of Figure 10. Shown are restarts at 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> to 20 60, and ,
100% power levels for one hour before the second trip. l The lower the power level to which the reactor is restarted, the less the t
xenon burnout that occurs and the less the replenishment of the decaying f l
iodine inventory. The profile begins to approach that of no restart at all. The conclusion is that the maximum rate of change of xenon reactivity occurs for the case where the reactor returns to 0% power and i then is tripped. The largest theoretical change of xenon reactivity [
in some time period may then be calculated from the time derivative of the xenon reactivity of a reactor shutdown from 100% equilibrium power conditions.
The maximum decrease in reactivity is less than 0.3% ao over a two hour period after the second trip of a double reacto- trip sequence.
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86-1123880-00 h
Also investigated is the effect of equilibrium operation at a lower power O
ievei (50%) pr4er to the first trip. For the cases where the reactor is operated at lower and lower equilibrium power ?avels before the first trip, the situation approaches the xenon free start-up.
UNCERTAINTIES IN DATA l
The parameters involved in deriving these results include: equilibrium xenon reactivity, neutron flux, fissior, and absorption cross sections, and fission yields and decay constants of iodine and xenon. The parameters were varied arbitrarily by + 10% to assess the impact on the results.
The results indice.te that if all of the parameters (except the well known decay constants) are increased by 10%, the results are affected by about
.06% apfor the worst double reactor trip. The two hour reactivity change ;
was still 0.3% ao to the nearest 0.1% ap.
SHUTDOWN MARGIN AND SOLUBLE BORON LEVELS In the above discussions, the emphasis has been on the examination o~f xenon changes from the levels at reactor trip. The final result of interest is the cost trip shutdown margin. lypical statements of control worth design criteria involve the achievement of the shutdown margin at 532 F at equilibrium xenon. The behavior of the shutdown margin from tne nonequilibrium conditions will be discussed in this section. The boration requirements during the double reactor trip sequence as well as other factors will be discussed.
It is important to note that the minimum available shutdown margin occurs :
at the end of a cycle for a push-pull (feed and bleed to compensate xenon changes during load swings) plant. The critical boron level at this point is approximately 17 ppm. k
The case of interest is the double reactor trip at the time in life of minimum shutdown margin, Jf the trip were to occur after a restart k 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> after a previous trip, it is clear that since the xenca reactivity
{
is well below equilibrium the boron concentration would be higher than equilibrium. This is equivalent to saying that some of the xenon-boron I reactivity swap that must be made ins already been accomplished. Since xenta reactivity was above equilibrium after the first trip for approximately 23 hours2.662037e-4 days <br />0.00639 hours <br />3.80291e-5 weeks <br />8.7515e-6 months <br />, no boration was required. Between 23 and 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br />, the boron
~
86'-1123880-00 level was raised to compensate xenon decay. The boron level could be ,
O raised stiii further to preveat rod $asertioa at ioo5 eo er durias = aoa I
burnout. These factors tend to reduce the amount of xenon reactivity ;
that must be compensated by boron addition after the second trip. '
The time of restart that would result ' the maximi.m rate of xenon burnout l
.has been identified as 19 hours2.199074e-4 days <br />0.00528 hours <br />3.141534e-5 weeks <br />7.2295e-6 months <br />. It is of interest to note that the xenon level at this point is above equilibrium. The implication appears to be that the equilibrium value of xenon is not the greatest reactivity ~
insertion that must be compensated via boration. However, it is apparent i that the reactor could not be deborated sufficiently at EOL (s 17 ppm b) I to compensate for the added reactivity required durir.g start-up with i
greater than equilibrium xenon nor could the control rod withdrawal ;
provide enough reactivity as the nonnal regulating bank position at 100%
power and equilibrium xenon is 90% withdrawn. Rod position limits would prevent start-up of a rodded plant at these conditions to 100% oower at design ramp rates.
v Thus, the double reactor trip with restcrt no earlier than the decay O to equ'iibrium xeaoa is the worst case. E9u'iibrium xenoa decay is thus !
confirmed as the largest post trip reactivity insertion at hot zero power I that must be compensated via boration.
i i
It is important to put the 0.3% ap xenon reactivity decrease for the worst dcuble reactor trip into proper perspective. Although double reactor trips are quite credible, the decrease in xenon reactivity will only I I
occur if the reactor was restarted between approximately 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and 40 I
hoars after a trip and then tripped again with less than one hour of full power !
opc-, d cion. Decrease of shutdown margin below 1% ap for a short period l I would not occur if the mini;.iam shutdown margin provided by the control ;
rods was at least 1.3% ap. '
A review of recent fuel cycles for B&W plants indicated that the average minimum shutdown margin encountered was 1.85% ap. The lowest recent i t
cycle was 1.6% ap. No attempt was made to be comprehensive, but the 13 cycles examined are representative. The data was taken from Table 5-2, :
"Snutdown Margin Calculations" from various reload reports. !
O t 3 -' _- , _ _ _ _ _ __ _ ,, __ __ , _ _ , ____ t
86-1123880-00 i
O,
SUMMARY
AND CONCLUSIONS V .
- 1. Long term shutdown margin can be provided without cooldown.
l
- 2. Trip from equilibrium power levels between 5% and 100% will not result ,
in xenon reactivity falling below its equilibrium value in two hours.
- 3. Under very select or improbable circumstances, xenon reactivity could !
decay 0.3% ao below its value at trip in two hours. .
- 4. If the duration of the shutdown period following a reactor trip is i at least 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, xenon reactivity will never decrease below 0.3% ap ;
in two hours if the reactor trips following restart (provided there has been at least one full power hour of operation following restart).
f
- 5. No safety problems exist if up to two hours elapse before boric acid is added to the RCS to compensate xenon decay.
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t l-LIST OF FIGURES ,l Figure Title 1 Reactor T sp From Equilibrium Power Operation l 2 Xenon Free Start-up 3 Trip One Hour After Xenon Free Start-up to P% Power Trip Three Hours After Y.enon Free Start-up to P% Power 4
-l Comparison of a Xenon Free Start-up with Start-up 40 Hours 5
after Reactor Trip 6 Double Reactor Trip P0 = P) = 100, T) = 40 T2 Varied [;
7 Double Reactor Trip0P ~ l = 100, Tj = 24, T2 Varied {
8 Double Reactor Trip P0" l = 100, T) = 18, T2 Varied 9 Double Reactor Trip P 0 = P) = 100 T) = 10, T Varied 2 f 10 Double Reactor Trip P 0 = 100, 50, T) = 18, P) Varied-o .
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Fi gu r e 1. REACTOR TRIP FROM EDUlllBRIUM POWER OPERATION P% 10 0% POWER j'
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SUPPLEMENT TO PRESENTATION TO THE UTILITY DESIGN AND REVIE'4 BOARD DESIGN TO ACHIEVE AND MAINTAIN COLD SHUTDOWN V. COLD SHUTDOWN CAPABILITY >OLLOWING CHAPTER 15 EVENTS Va. COLD SHUTDOWN CAPABILITY FOLLOWING A FIRE
! A. Purpose This section describes the ability of the Midland plant design to enBure that at least one means of achieving and maintaining safe shutdown conditions will remain available during and af ter a postulated fire in the plant.
B. Discussion The Midland design is presently being reviewed to verify it meets the intent of 10 CFR 50 Appendix R l and Branch Technical Position 9.5-1.
'N The review to verify that the Midland plant will (A l remain safe in case of a fire assumes an exposure fire can occur anywhere in the plant outside the primary containment (biological shield). The re-view also assumes a fire inside the control room that can disrupt the operation of any single con-tinuous cabinet and result in evacuation of the control room. The goal of the review is to demon-strate that given the fires described, the plant can achieve hot standby immediately and cold shut-down within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
The criteria used in the review are as follows:
- 1. Only one fire occurs.
- 2. The fire can cause hot shorts, open circuits, l
and shorts to ground.
- 3. The only failures considered are those caused by the fire.
- 4. Offsite power may be available or unavailable.
O
k.
SUPPLEMENT TO PRESENTATION TO THE UTILITY DESIGN AND REVIEW .
BOARD DESIGN TO ACHIEVE AND MAINTAIN COLD SHUTDOWN (Continued;
{}
- 5. Limited manual action inside the control room is possible for a fire inside the control room.
(These actions are assumed possible immediately af ter discovering the fire and prior to evacu-ation of the control room if that should become necessary.)
- 6. Extensive manual action is possible outside the control room.
In the review, the equipment needed to achieve and maintain safe shutdown conditions is determined.
The ef fects of the postulated fire on that equipment are identified. If the identified effects are un-desirable, protection will be provided to ensure operation of that equipment.
The systems identified that are required to achieve and maintain safe shutdown conditions are the same as described in-other parts of this presentation.
C. Summari l -
\- At the conclusion of the present review, the Midland plant will be demonstrably able to achieve and main-tain a safe shutdown condition during and af ter a fire.
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FIRE PROTECTION - SAFE 3HUTDOWN ANALYSIS OBJECTIVE e ENSURE THAT AT LEAST ONE MEANS OF ,
! ACHIEVING AND MAINTAINING SAFE l4 SHUTDOWN CONDITIONS REMAINS AVAILABLE '
DURING AND AFTER A POSTULATED FIRE i MIOLAND UMTS 1 AND 2 G-1512-08 V-10 l
O O O ;
l '
)
! u j' FIRE PROTECTION - SAFE SHUTDOWN ANALYSIS j REGULATIONS AND GUIDELINES
! e 10 CFR 50 APP A, CRITERION 3 (FIRE I PROTECTION)
' ~
e NRC BRANCH TECHNICAL POSITION ASB 9.5-1 (GUIDELINES FOR FIRE PROTECTION FOR i
NUCLEAR POWER PLANTS) e 10 CFR 50 APP R (FIRE PROTECTION PROGRAM FOR OPERATING NUCLEAR POWER PLANTS)(OPERATING LICENSE PRIOR TO JANUARY 1,1979)
MIDLAND UMTS 1 AND 2 G-161210
\
\ O O O :
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l.
1 FIRE PROTECTION - SAFE SHUTDOWN ANALYSIS ASSUMPTIONS j . .
!' e EXPOSURE FIRE OUTSIDE PRIMARY i CONTAINMENT l
'i e EXPOSURE FIRE INSIDE CONTROL ROOM CAUSING DISRUPTION OF ANY SINGLE CONTINUOUS CABINET MIDLAND UNITS 1 AND 2 G-154rrO8 e
i O O O
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l; FIRE PROTECTION - SAFE SHUTDOWN ANALYSIS GOAL i!
a 4
l< e ACHIEVE HOT STANDBY IMMEDIATELY l
1 i
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e ACHIEVE COLD SHUTDOWN WITHIN 72 HOURS MIDLAND UNITS 1 AND 2 G-1540-09
. )
i l O O O -
) .-
1 FIRE PROTECTION - SAFE SHUTDOWN ANALYSIS CRITERIA 1
e SINGLE FIRE i 1 e HOT SHORTS, OPEN CIRC 0lTS, SHORTS TO
- GROUND e FAILURES CAUSED BY FIRE ONLY .
MDLAND UNITS 1 AND 2 V-14 G 1540-06
. . )
O O O -
i FIRE PROTECTION - SAFE SHUTDOWN ANALYSIS CRITERIA (cont'd) i e OFFSITE POWER AVAILABLE OR UNAVAILABLE t
e LIMITED MANUAL ACTION INSIDE CONTROL l'
i ROOM e EXTENSIVE MANUAL ACTION OUTSIDE 4
CONTROL ROOM
?
l V 15
} MOLAND UMTS 1 AND 2 G-1540-07
I
.J
1-O 6 O -
! FIRE PROTECTION - SAFE SHUTDOWN ANALYSIS
! APPROACH i
l e IDENTIFY EQUIPMENT NEEDED TO ACHIEVE I
AND MAINTAIN SAFE SHUTDOWN
! CONDITIONS l -
!t j e IDENTIFY POSSIBLE EFFECTS OF FIRE ON i
THAT EQUIPMENT I
l e PROVIDE PROTECTION TO ENSURE '
OPERATION MIDLAND UMTS 1 AND 2 y.16 G 151212
. . )
4; O O .
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~i FIRE PROTECTION - SAFE SHUTDOWN ANALYSIS i
, e SYSTEMS REQUIRED TO ACHIEVE AND 4
MAINTAIN SAFE SHUTDOWN CONDITIONS
. Makeup l
= Emergency Boration !
! . Pressurizer Heaters, Safety Valves
. Component Cooling Water
. Chilled Water - Safeguards
! . Reactor Building HVAC
- . Service Water Pump Structure HVAC
. Control Room HVAC
! . Auxiliary Pressurizer Spray l . Power-Operated Atmospheric Vent Valves
. Decay Heat Removal MIDLAND UNITS 1 AND 2 G-151213 V-17
. 3
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! .r PRESENTATION TO THE UTILITY DESIGN AND REVIEW-BOARD I
~g- DESIGN TO ACHIEVE AND MAINTAIN COLD SHUTDOWN
.t l t i
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O Revision 0 February 26, 1981' !
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PRESENTATION TO THE UTILITY DESIGN AND REVIEW BOARD DESIGN TO ACHIEVE AND MAINTAIN COLD SHUTDOWN TABLE OF CONTENTS Page I. INTRODUCTION 1 A. WELCOME 1 B. PURPOSE OF PRESENTATION 1 C. OUTLINE FORMAT OF TALK 1 II. HISTORY l III. PRECEDING DESIGN - HOT STANDBY CAPABILITY 2 A. REACTIVITY CONTROL / INVENTORY CONTROL 3 B. PRESSURE CONTROL 4
{} C. HEAT REJECTION (TEMPERATURE CONTROL) 4 l IV. PRESENT DESIGN - COLD SHUTDOWN CAPABILITY 6 l
A. REACTIVITY CONTROL / INVENTORY CONTROL 7
, B. PRESSURE CONTROL 9 C. HEAT REJECTION (TEMPERAT!TRE CONTROL) 11 V. COLD SHUTDOWN CAPABILITY FOLLOWING CHAPTER 15 14 TYPE EVENTS A. PURPOSE 14 B. DISCUSSION 14 C.
SUMMARY
17
- c. F,w, Fr.Ld$~
e VI. COMPARISON OF PRESENT DESIGN TO APPLICABLE 17 REGULATORY GUIDANCE A. SRP 5.4.7, RESIDUAL HEAT REMOVAL SYSTEM 18 B. BTP-RSB 5-1 (REVISION 1), DESIGN REQUIRE- 18 MENTS ~F THE DECAY HEAT REMOVAL SYSTEM l
i l
i O -
Page C. OPEN ITEMS ASSOCIATED WITH STAFF REVIEW 22 OF MIDLAND PLANTS D. SRP 7.4, SYSTEMS REQUIRED FOR SAFE SHUTDOWN 23 E. REGULATORY GUIDE 1.13S, GUIDANCE FOR -
29 RESIDUAL DUAL HEAT REMOVAL TO ACHIEVE AND MAINTAIN COLD SHUTDOWN LIST OF ABBREVIATIONS 34 TABLES FIGURES APPDDIX O
l l
O 11
Midland Plant Units 1 and 2 Design to Achicvo and Maintain Cold Shutdcwn O -
PRESENTATION TO THE UTILITY DESIGN AND REVIEW BOARD DESIGN TO ACHIEVE AND MAINTAIN COLD SHUTDOWN I. INTRODUCTION A. Welcome B. Purpose of Presentation C. Outline Format of Talk .
II. HISTORY The ability to establish a stable condition for a nuclear reactor following a normal or emergency shut-down has always been a consideration in plant design.
However, the design requirements for pertinent systems and the condition to be established have evolved over the years.
A significant emphasis has traditionally been placed on ensuring a stable condition following a large loss-of-O> coolant accident (LOCA) event. During a large LOCA, the reactor coolant system (RCS) pressure decreases and a safe shutdown condition is established by the emergency core cooling system. Because of the attention previously l
given to this event, it is not a current concern and will be addressed only peripherally in this review.
For a non-LOCA event in which RCS integrity is maintained, the stable condition to be achieved is the hot standby condition in which the RCS pressure and temperature remain near their normal operating values. This safe hot standby condition could be achieved without offsite power. The hot standby condition could be maintained until offsite power is restored and further cooldown is desired. Subsequently, emphasis was placed on ensuring that systems necessary to maintain hot standby were safety grade.
More recently, a similar emphasis has been placed on ensuring that systems necessary to achieve cold shut-down are safety grade. This situation evolved from a i concern that the safe shutdown condition be cold shutdown.
Previously, the safe shutdown condition was considered to be hot standby. Cold shutdown is achieved when the RCS temperature is <200F, and the reactor is at least 1% Sk/k subcritica17 assuming the highest worth rod
()
1
Midlend Plant Unite 1 and 2 Design to Achieve and Maintain Cold Shutdown . . .
() stuck out, and no xenon. The event useful for evalua-ting the capability to achieve cold shutdown is the loss of offsite power coincident with a safe shutdown earthquake (SSE). This event is used as a basis to address Sections III (Preceding Design - Hot Standby Capability) and IV (Present Design - Cold Shutdown Capability) of this presentation. Other accident scenarios will be addressed in Section V (Cold Shutdown Following Chapter 15 Type Events).
Subsequent to the Three Mile Island (TMI) accident, the Midland project formed
- task force to address some open issues that existec ;?ior to TMI or were raised by the accident. One of the subjects addressed wa's cold shutdown. During this review, a number of design upgrades were recommended to enhance the hot standby and cold shutdown capability. Most of the design upgrades that have been implemented with respect to shutdown capability have evolved from this effort.
The present Midland design basis is that hot standby is a safe shutdown condition. This design basis is appro-priate because hot standby is a safe, stable condition that can be maintained for an extended period of time with a minimal amount of operator action; therefore, it (s) provides additional time to further evaluate the condition of the reactor. In addition, it frequently is preferable to maintain the reactor in this hot stable condition for an extended period of time rather than subjecting the plant to an immediate cooldown transient. The current Midland design provides for the ability to achieve and maintain, by safety-grade means, the hot standby condition following an SSE coincident with loss of offsite power. (Safety-grade systems are seismically designed and capable of being operated with or without offsite power.) Although it is not a design basis, the present Midland design incorporates the ability to be taken to the cold shutdown condition using only safety-grade equipment assuming only onsite or offsite power is available and considering a single failure. In addition, the present Midland plant design can achieve and maintain cold shutdown following a tornado by using equipment that is protected from the effects of a tornado.
III. PRECEDING DESIGN - HOT STANDBY CAPABILITY This section briefly addresses previous design capabili-ties of the Midland plant to facilitate an understanding of the design upgrades that have been made. No compari-son to the present design is made, because Section IV O
(>
2
- Midland Plant Units 1 and 2 Design to Achiava and Mcintain Cold Shutdown
(:)
(Present Design - Cold Shutdown Capability) addresses current design.
The design prior to the changes of the past 2 years considered hot standby to be the design basis safe shutdown condition. The hot standby condition was considered to be one in which the RCS temperature is in the range from normal operating temperature to the decay heat removal (DHR) cut-in temperature, and the reacter is 1% ak/k subcritical. Initially af ter the reactor trip, the reactor would be at the high end of the hot standby temperature range and this condition could be maintained for a period of time. During this period, offsite power could be restored, operation of nonsafety-grade equipment could be achieved, and the plant could be taken to cold shutdown. The essential functions to be maintained to ensure this safe and stable hot standby condition were reactivity and inventory control, heat rejection, and pressure control.
A. Reactivity Control / Inventory Control l
l 1. Control Rods
() The control rods are designed to bring the reactor at least 1% ak/k subcritical upon reactor scram. Allowance in the design is made for the highest worth control rod assembly sticking out of the core as well as for the temperature effects between hot full power (579F) and hot zero power (532F).
- 2. Boration l For t! e limiting control rod design described above, the decay of xenon reactivity and temperature effects below 532F are controlled by boration. Following equilibrium power operation, reactor trip will lead to an increase
' in xenon reactivity above its equilibrium value for periods up to approximately 23 hours2.662037e-4 days <br />0.00639 hours <br />3.80291e-5 weeks <br />8.7515e-6 months <br />
- (trip from 100% power). If the equilibrium l xenon reactivity is less than or equal to 1% ak/k, which corresponds to low power operation of approximately 0-12% power, ensured without operator action. For the case in which equilibrium xenon worth is greater than 1% ak/k, which corresponds to equilibrium power operation of approximately
(
3
Midland Plant Unita 1 and 2 Design to Achieve and Maintain Cold Shutdown 12-100% power, the xenon reactivity is above its equilibrium value for at least 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after a reactor trip. The xenon poison transient permits sufficient time to bleed the RCS and inject water from the BWST.
The boron concentration of the reactor is normally increased by using the makeup system to inject boric acid frcm the boric acid addition tanks of the chemical addition system. In the event of an accident, the borated water from the borated water storage tank (BWST) is available for injection into the RCS.
- 3. Inventory control The makeup system normally controls the RCS inventory. Portions of the makeup system are used for high-pressure injection (HPI) to ensure adequate boron concentration and core cooling. Safety-grade portions of the makeup system are powered by Class 1E onsite power.
The makeup water is from the BWST, which is
(} also safety grade.
B. Pressure Control The pressurizer safety valves prevent overpres-surization of the RCS. In the event of loss of offsite power, the thermal inertia of the pressu-rizer allows it to maintain system pressure for
- some time after power is removed from the heaters.
l Thus, sufficient time exists to connect the pressurizer heaters to the emergency diesel generators.
C. Heat Rejection (Temperature Control)
- 1. Steam generator l
- a. Main steam isolation valve (MSIV) and l main feedwater isolation valve (MFIV) closure l
Heat transfer from the RCS to the secondary side of the steam generator must be established for cooldown. In the event of a main steam line break (MSLB), MSIV O 4
Midland Plant Unita 1 and 2 Decign to AchiGva cnd Maintain Cold Shutdown
~
(
and MFIV closure ensure that the heat removal can be controlled. The MSIVs and MFIVs close automatically on low-steam pressure or an emergency core cooling actuation signal (ECCAS), or can be manually closed from the control room.
- b. Auxiliary feedwarer (AFW) operation The auxiliary feedwater actuation system (AFWAS) initiates the automatic starting of both the turbine-driven and the motor-driven AFW pumps and the automatic positioning of AFW valves. This mitigates the consequences of the loss of main feedwater or a loss of offsite power accident, and provides feedwater to allow primary heat removal through the steam generators.
A motor-driven and a turbine-driven AFW pump provide redundancy of AFW supply and diversity of motive pumping power.
Each pump has a rating of 885 gpm.
()'
Discharge piping from both pumps is cross-connected through two normally open valves, permitting each AFW pump to feed both steam generators.
In the safeguards mode, pump suction is normally from the condensate storage tank, with emergency backup provided from the service water system. Steam i supply piping to the turbine driver is provided by each of the main steam lines inside the containment. A line from each steam generator, equipped with a normally closed, de motor-operated iso-lation .alve, supplies steam to a common header.
- c. Main steam relief valves The main stvam relief valves lift to remove heat from the secondary systen.
The hot standby condition can be main-tained by cycling of these relief valves. Cooldown to a temperature that corresponds to a pressure below the main steam relief valve setpoint could be O
5
Midland Plant Units 1 and 2 Design to Achieve and Maintain Cold Shutdown C:)
accomplished by opening the modula-ting atmospheric dump (MAD) valve.
r If instrument air were unavailable, the MAD valve could be opened by local manual operation.
- 2. Natural circulation of reactor coclant Natural circulation characteristics of the RCS have been calculated by Babcock & Wilcox with conservative values for all resistance i and form loss factors, and have been found to provide adequate core cooling.
IV. PF"SENT DESIGN - COLD SHUTDOWN CAPABILITY The Midland design provides for the ability to achieve and maintain, by safety-grade means, the hot standby condition following a SSE coincident with loss of offsite power. Although it is not a design basis, the Midland design incorporates the ability to be taken to i che cold shutdown condition using only safety-grade equipment, assuming only onsite or offsite power is available and considering a single failure. Therefore, O in the unlikely event that a design basis earthquake occurs which results in the need to achieve cold shut-down expeditiously, design features exist to accomplish this evaluation. Reactivity control / inventory control, pressure control, and heat rejection are the essential l functions that must be maintained.
Detailed treatment of necessarj suppo' ting systems and l equipment (such as power and control ~ystems, cooling water, and diesel generators) is not addressed in this presentation. However, plant design ensures that these systems and equipment fulfill the necessary design requirements to achieve cold shutdown.
The loss of offsite power coincident with an SSE is l used as a basis for evaluating the capability of achieving cold shutdown.
The NRC design guidance and the guidance followed on i
the Midland plant to meet the functional requirements necessary to achieve cold shutdown follow.
l a. Cold shutdown shall be achieved using l safety-grade systems.
6 i
Midland Plcnt Units 1 and 2 Design to Achieve and Maintain Cold Shutdown
(:) - -
- b. Systems shall have suitable redundancy in components and features to ensure that the system functions can be accom-plished (assuming a single active failure).
- c. Systems are capable of being operated from the control room. (Some systems require local manual alignment, but control can be performed from the control roca.)
- d. The necessary systems can function whether offsite power is available or unavailable.
The essential functions that must be maintained are individually addressed below.
A. Reactivity Control / Inventory Control
- 1. Centrol rods The Midland design (per unit) incorporates 61 control rod drive mechanisms (CRDMs), excluding
(]) the axial power shaping rod assemblies (APSRAs),
which do not perform a trip function. The CRDMs are the B&W Type C design, which is in use at the Oconee Unit 3 and Davis Besse Unit 1 plants. Rapid control rod insertion is activated by the reactor protection system (RPS), anticipatory reactor trip system (ARTS),
loss of power to control rod drive (CRD) motors or a switch in the main control room.
The reactivity control capabilities of the control rods are identical to those described in Section III.
- 2. Boration For normal shutdown reactivity control, the design of the Midland plant includes two sources of borated water: BWST and the chemical addition system (CAS). With letdown available, either the BWST or the CAS is capable of maintaining the reactor at in ak/k subcritical at hot shutdown or during transition to cold shutdown at any time in core life for the most limiting normal fuel cycle, assuming xenon-free conditions and the maximum worth rod stuck out of the core. The ese of only
[}
7
- Midland Plcnt Units 1 and 2 Design to Achievo and Maintain l Cold Shutdown l (b
ss -
safety-grade equipment to maintain the reactor at 1% ak/k suberitical at hot standby, and the transition to a cold shutdown condition, requires the use of the emergency boration system (EBS) .
The EBS is a safety-grade system designed to provide a 6 weight percent boric acid solution to the RCS via the makeup and purification system (MU&PS), in the event of a design basis tornado (DBT) or SSE, in conjunction with the maximum worth stuck control rod.
The contents and concentration, in conjunc-tion with the other contraction volume makeup sources, are sized to ensure the ability to maintain a 1% ak/k suberitical margin during hot standby and during the transition to cold shutdown. Adequate shutdown margin is main-tained during the transition from hot standby to cold shutdown by using borated water from the BWST or the CAS. These borated water sources provide adequate compensation for reactivity changes that result from the change in moderator temperature.
[}
Following any event which results in the loss of letdown capability and a stuck rod, i che 6 weight percent boric acid solution from l the EBS storage tank (which contains at least l 1,800 gallons), and the contraction makeup l
from the BWST or CAS can be transferred to
weight percent boric acid into the RCS.
Contraction volume makeup during cooldown is pcovided by the makeup and EBS tanks and either the BWST, which is designed for an i
SSE, or the CAS, which is designed to with-stand the DBT.
- 3. Inventory control As coolant is removed (or let down) from the RCS, this coolant must be replaced (or made
- up) by additional makeup water that is delivered i to the RCS by the makeup portion of the MU&PS.
O 8 l
r Midland Plant Units 1 and 2 Design to Achieve and Maintain Cold Shutdown
() Even if reactor coolant is not let down, the makeup portion of the MU&PS is still required 1
to ensure a safe shutdown condition. As the RCS cools, the specific volume of water decreases. It is necesscry to keep the volume of water in the RCS approximately constant. Therefore, additional water is
~
injected into the RCS via the makeup system.
1 The safety-grade source of makeup water is the BWST, which contains at least 300,000
gallons of 1.3 wt% boric acid solution.
Because the BWST is not required after a design basis tornado, the BWST is not tornado-protected. In addition, three boric acid addition tanks (part of the nonsafety-grade CAS) are also available for makeup addition. These three 10,000 gallon tanks, which contain a total of at least 16,500 sallons of 3.5 wt% boric acid, can provide the required RCS contraction volume in conjunction with other available water sources. These water sources are tornado-protected and can be made available following loss of offsite power.
B. Pressure Control
- 1. Reactor coolant system pressure boundary l
[ power-operated relief valve (PORV), PORV block valves, and pressurizer safety valves]
The RCS pressure is controlled by maintaining the RCS pressure boundary and keeping a steam l
j bubble in the pressurizer.
I l The PORV is sized to limit the pressure during step load changes, including the maximum design load rejection, to a value l
less than e a high-pressure trip setpoint.
l While contributing to plant safety by improv-i ing operating efficiency, the valve is not required for safety reasons. It may be isolated either manually or automatically upon a coincident signal that the PORV is not closed and a low RCS pressure exists. The isolation is accomplished by either of two Class 1E motor-operated PORV block valves installed upstream of the PORV. Both the PORV and the PORV block valves are Class A O .
I 9 I
i
(
Midlcnd Plant Units 1 and 2 Design to Achieve and Maintain Cold Shutdown
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(as defined by Regulatory Guide (RG) 1.26),
and, as such, are designed, fabricated, tested, installed, and certificd by the i requirements of the ASME Code of Class 1 valves.
i The pressurizer safety valves ensure that the RCS is protected against overpressure. They
- are spring-loaded devices, and open automatically by direct action of the fluid pressure in the l pressurizer as a result of forces acting l against a spring. They are bellows-sealed to make the setpoint independent of backpressure and are equipped with an auxiliary piston to ensure pressure balance in the event of damage to the bellows. These valves are l designed, fabricated, tested, installed, and
, certified in accordance with Article NB-7000,Section III of the ASME Code for Class 1 l components. They are Class A components as l defined in RG 1.26.
- 2. Pressurizer heaters 1
To maintain normal operating RCS pressure for more than a few hours after shutdown, i operation of the pressurizer heaters is l
required.
The pressurizer must be maintained as the hottest point in the RCS to ensure the vapor bubble exists only in the pressurizer.
Power and controls for two banks of pressurizer heaters have been upgraded to safety-grade Class 1E standards. In the event of loss of offsite - power, power to the two banks of heaters is controlled by a manual switch in the control room. One bank is sufficient to control RCS pressure via a steam bubble in
! the pressurizer when the reactor is shut down i and the energy input te the RCS is decay l heat.
- 3. Auxiliary pressurizer spray The auxiliary HPI pressurizer spray is designed to depressurize the RCS from its normal operating pressure to a pressure associated with the emergency DHR system cut-in temperature, and is intended for use 10
Midlcnd Plcnt Unito 1 and 2 Design to Achieva and Maintain Cold Shutdown
() ~
only during emergency cold shutdown. The spray system driving head is derived from the HPI pump discharge. Suction for the HPI pump is normally taken from the BWST. The boric acid addition tanks, via the makeup tanks, serve as an alternative suctior. source. The spray line discharges to the auxiliary DHR pressurizer spray line upstream of parallel, motor-operated globe valves; these valves permit manual control of flow into the pressurizer. The spray system requires local alignment prior to initiation, but is remotely initiated and controlled from the control room. Once initiated, the spray will be operator-controlled to provide the desired depressurization rate that is detarmined by the cooldown rate and plant status.
C. Heat Rejection (Temperature Control)
- 1. Steam generator (at high pressures / temperatures) l To remove heat via the steam generators, a t
source of water to the secondary side of the steam generators and a steam vent path for
(]) energy removal must be provided. The water is provided by rhe AFW system and steam is vented via the main steam relief valves or the power-operated atmospheric vent (POAV) valves. .
- a. Auxiliary feedwater Auxiliary feedwater is automatically supplied at a controlled rate by redun-dant 100% cap 32ity AFW pumps. One pump is an electric motor-driven pump; the other is a steam turbine driven pump with steam provided oy the safety-grade portion of the main steam system. Power and controls to both pumps are safety-grade and Class lE.
Normally, the 300,000 gallon non-Seismic Category I condensate storage tank serves as the water source for these l pumps. The safety-grade service water system provides an alternate source.
Because of concern for the quality of steam generator feedwater, automatic S transfer is provided only upon coincident (Ls) AFW actuation signal (AFWAS) and low AFW pump suction pressure.
11 I
~ _ _ _ _ - - . .- - . . . .- . -. . . - . . . . - - . _ _ _
Midland Plent Units 1 and 2 Design to Achieve and Maintain Cold Shutdown
. (:) -
- b. Main steam relief valves These spring-loaded pressure relief valves cycle to relieve steam,. enabling the reactor to remain in the hot standby condition.
- c. Power-operated atmospheric vent valves Steam can be relieved through the POAV valves to maintain the reactor in a hot standby condition without cycling the main steam relief valves; steam can also be relieved to cool the reactor to a temperature where the DHR system can be used.
The POAV valves are safety-grade, metor-operated control valves located upstream of the MSIV. The PCAV valves are sized so an inadvertent stuck-open POAV valve will not result in unacceptable consequences to the core.
The POAV valve capacity will permit the 4
(]) RCS to be cooled to the emergency DHR cut-in temperature of 325F within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> 3
assuming one operational POAV valve for each steam generator. The 325F cut-in temperature is discussed in Item 2
- below.
Each POAV valve can be jog-centrolled from a switch in the control room or the l auxiliary shutdown panel. The operator will position the POAV valves until an accep2able temperature is maintained or until an acceptable cooldown rate is established.
Steam relief can also be accomplished by dumping steam to the condenser or opening the MAD valves. These components are downstream of the MSIVs and are not powered or controlled by safety-grade equipment. Thus, to ensure cold shutdown can be achieved using only onsite emergency power and saf ety-grade systems, credit is taken only for components upstream of the MSIVs.
O 12
Midlcnd Plent Units 1 and 2 Design to Achieve and Mnintoin Cold Shutdown O 2. Decay heat removal system After the RCS pressura and temperature are reduced to approximately 300 psig and 280F (or 325F under emergency conditions),
- respectively, the DHR system operation may begin.
The previous design directed that the DHR system not be operated until the RCS temperature was 280F. The DHR system was analyzed to determine that operation of the DHR system at 325F is an acceptable, although not normal, mode of operation. The higher DHR cut-in temperature permits operation of the DHR system, within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> assuming operation of one POAV valve on each loop.
Four parallel-series, motor-operated isolation valves are installed on the DHR dropline inside the containment. These are installed so a single failure of a vulve to open will not inhibit the flowpath for . DHR cooling.
- 3. Reactor coolant circulation
() a. Natural circulation test l The Midland plant has been analyzed to l , ensure that natural circulation will l
occur during a cooldown without forced
( circulation of the reactor coolant. In addition, a natural circulation cooldown test will be referenced if it has been conducted on a plant similar to Midland.
If such a test is unavailable, a test will be conducted to verify that operation of the POAV valves under natural circulation l will satisfactorily remove heat required to cool down the plant. This test will cool the RCS approximately 50F under natural circulation. The data will be used to verify the adequacy of prior analytical results.
l l
13
Midicnd Plant Units 1 and 2 Design to Achieve and Maintain Cold Shutdown
'( ) -
- b. Auxiliary feedwater level control The AFW system will be the subject of another presentation and details of that system operation are not addressed here.
However, the system will include safety-grade, automatic control of the steam generator water level. The steam generator water level is normally maintained at a level of 2 feet when two or more reactor coolant pumps (RCPs) are operating. If 0 or 1 RCP is operating, the level is automatically increased to i
20 feet; this ensures sufficient feedwater is present in the steam generator to promote natural circulation of the reactor coolant.
The automatic transition from the low-water level to the high-water level in the steam generator is made smoothly by ramping the setpoint between the two values at a controlled rate. This orderly transition prevents overcooling
() of the primary loop.
V. COLD SHUTDOWN CAPABILITY FOLLOWING CHAPTER 15 TYPE EVENTS A. Purpose This section describes the ability of the Midland plant to achieve cold shutdown from the postulated plant conditions and equipment availability that exist following the events addressed in Chapter 15.
Previous sections have provided detailed descriptions
! of the equipment needed to achieve cold shutdown.
This section addresses the general post-accident conditions that may exist and assesses the ability to proceed to cold shutdown conditions.
l B. Discussion All of the transients analyzed in Chapter 15, with the exception of anticipated transients without scram events, result in a reactor tripped, suberiti-cal core condition with long-term decay heat removal being provided by one or more intact RC/ steam generator loops, or HPI cooling.
O 14
- _____._w
Midland Plcnt Units 1 cnd 2 Decign to Achisvo and Mnintain Cold Shutdown C) -
I The final plant condition and equipment remaining available for use in achieving cold shutdown are dependent on the transient and assumed equipment .
l failures. Equipment failures assumed for Chapter 15' events are based on ensuring a bounding transient response with respect to the established acceptance
[ This failure may not be the worst one criteria.
with respect to achieving cold shutdown following the event.
For most events analyzed in Chapter 15, the design objective of achieving cold shutdown within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> can be met. This is true of all transients where no failure of safety-grade instrumentation has been imposed. With the imposition of a single failure of one piece of safety-grade instrumentation equipment, the remaining minimum performance level is still sufficient to achieve cold shutdown.
The transient analyses of Chapter 15 demonstrate l that the plant can reach a stable plant condition I at hot standby with ensured decay heat removal.
An event may rely on an operator action to ensure long-term heat removal or adequate continuous i - subcritical margin at hot standby. Sufficient time and indication is available to the operator
, to take the required action in such instances.
Design basis events, such as steam and feedwater line breaks or a LOCA, may result in the loss of forced RC flow and the loss of the use of one steam generator for timely decay heat removal.
The essential control functions that must be maintained in order to ensure the capability of 1 achieving cold shutdown are reactivity / inventory control, primary pressure control, and heat rejection. Any accident event, which, in combi-nation with a single failure, results in the complete ' loss of any one of these functions would preclude cold shutdown with safety-grade equip-ment. However, the transients analyzed in Chapter 15 do not result in the complete loss of any one of these functions.
- 1. Reactivity / inventory control Short-term reactivity control is provided by the control rods. Upon reactor trip, a 1% ak/k shutdown margin (the control rod assembly of greatest worth is assumed not to O 15 i
i t .
l -
Midicnd Plent Unita 1 and 2 Decign to Achiovo end Maintain Cold Shutdown C:)
drop into the core) is provided by the rods at hot zero power (532F) temperatures. The EBS provides reactivity control to compensate for the decay of xenon. Replacement of the primary system contraction volume following reactor trip is provided from the makeup tank by the HPI system. The EBS water along with the contents of the makeup tank can be injected prior to cooldown below 532F. Reactivity control for long-term maintenance of hot standby is thus ensured.
Primary system inventory and reactivity control during the cooldown to cold shutdown must be provided by either the CAS or HPI system.
- 2. Pressure control Pressure control is provided by auxiliary spray and the safety-grade banks of heaters during the cooldown following non-LOCA events.
Letdown from the RCS is not required.
- 3. Heat rejection (temperature control)
O The design method of primary heat removal for both normal and transient conditions is by use of the steam generators. This method requires a source of' fluid (AFW) to the steam generators and a mode of steam relief (main steam relief or POAV valves), all of which are safety-grade components or systems for the Midland plant. A secondary system transient such as a steam or feedwater line break may result in the loss of controlled heat removal capability from one steam generator. Heat l removal is then provided by the intact loop with AFW flow directed to the intact once-through steam generator (OTSG) by the feed I
only good generator (FCGG) logic system.
Af ter stabilizing plant conditions, the POAV l
valves on the intact steam generator may be operated to decrease RCS temperature.
If the reactor coolant pumps are not operating, reactor cooling will be maintained by natural circulation. The ability to achieve cold shutdown within a reasonable time frame under the conditions of natural circulation and one 16 t
.. MidlEnd Pltnt Units 1 and 2 Design to Achieve and Maintain Cold Shutdown O m intact loop rggain- to ha vaiuated. The '
AFW system will be operated to control the A
Ad$
gv,-~' .
OTSG level to promote natural circulation.
g The capability to achieve cold shutdown following the design basis tornado (coincident with loss of offsite power) has also been l considered. Reactor trip occurs either by l
manual trip or automatically by loss of l
onsite and offsite power. Continued reactivity and inventory control are accomplished by j injection of borated water from one or more of the three following sources, depending on' l availability: BWST (not tornado protected),
l EBS (tornado protected), or chemical addition tanks (tornado protected). Heat rejection is maintained by steam generator pressure control l using AFW, main steam safety valves, or by
manual operation of the POAV valves. Natural l circulation is maintained by proper operation i of the AFW system to control OTSG level.
I Primary pressure control is accomplished by
! operation of safety-grade heaters or auxiliary pressurizer spray.
O Hot standby conditions can be maintained in-l definitely unless it becomes desirable to proceed to cold shutdown.
C. Summary The capability of achieving cold shutdown exists for the conditions following the Chapter 15 events.
Various operator actions may be required depending on the transient involved and the assumed equip-ment failure. Times in excess of 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> may be required ur ,er the conditions of natural circula-tion with only one intact loop. It may be desira-l l
ble to stay at hot standby or cool more slowly if l such an action would minimize radiation releases.
l Table V-I summarizes the capability and limitations i relative to achieving cold shutdown for each Chapter 15 event.
VI. COMPARISON OF PRESENT DESIGN TO APPLICABLE REGULATORY GUIDANCE The Midland design has been compared with the NRC concerns and the design guidance related to the f=="a I of cold shutdown. This section contains the comp
()
17 i
Midland Plant Units 1 and 2 Design to Achieve and Maintain Cold Shutdown
(:)
The design guides examined include the Standard Review Plan (SRP) 5.4.7; Branch Technical Position (BTP)
RSB 5-1; Cpen Items Associated with NRC Sstaff Review:
1 RSB-7, ASB-8, PSB-11, RSB-10, RSB-20 ; SRP 7. 4, and l RG 1.139. Table VI-l is a cross index illustrating the l
! origin of the applicable guidance; it also shows which guidance is incorporated into the Midland design.
A. SRP 5.4.7, Residual Heat Removal System 1 l
SRP 5.4.7 is primarily directed at review of the residual heat removal system that operates after i the RCS has been initially cooled and depres- )
surized. However, the SRP also directs that the '
chemical volume and control system (CVCS), resi- )
dual heat removal system, atmospheric dump valves, and source of auxiliary feedwater be reviewed to meet the functional requirements of BTP-RSB 5-1.
Therefore, the functional requirements of BTP- l RSB 5-1 are examined in more detail. (The SRP and BTP refer to CVCS, residual heat removal l (RHR), and atmospheric dump valves. On the Midland plant, the function of these systems is performed by the MU&PS, DHR system, and POAV valves, re,spectively. Future references are to the latter nomenclature.
( B. BTP-RSB 5-1 (Revision 1), Design Requirements of the Decay Heat Removal System This BTP states the functional requirements to l
take a reactor from normal operating conditions to t cold shutdown. In addition, further guidance is given for the DHR system design, cold shutdown operation procedures, and AFW supply requirements.
Table VI-2 contains a summary of guidance contained in BTP-RSB 5-1. In addition, the far right column of this table contains the design being implemented on the Midland project that is associated with the l design guidance of the preceding columns.
The individual positions of the BTP are addressed because they are the main substance of the cold shutdown issue. Most of the subsequent NRC questions and Open Items refer to the issues addressed in this table. A (G) designates the guidance a (D) designates the Midland design.
(Note: Midland is a Class 2 plant because the construction permit (CP) was issued before January 1, 1978.)
O 18
-- . - - . , - . . - . . . . - . . - . . . - - . - - _ - - . - _ - - - _ - _ ~ - - . . - . _ -
Midicnd Plant Units 1 and 2 Design to Achieve end Maintain Cold Shutdown C:)
- 1. .~ng-term cooling / decay heat renoval dropline (Gl The DHR dropline shall be able to accommo-date a single active failure or ensure that manual action is possible to rectify the situation.
(D) Midland has a single DHR dropline. Th3 l
. line divides into two lines inside the containment and each line has two motor-
! operated isolation valves inside the contain--
ment. The lines rejoin and exit the contain-ment. Thus, a single failure can be accommodated and containment access is not required. The power supplies and controls to I the valves are arranged to function with a
! single failure.
- 2. Safety-grade steam dump valves (G) Provide safety-grade steam dump valves (D) The Midland plant has two safety-grade POAV valves associated with each steam gen-erator. These motor-operated valves ensure
() adequate steam removal from the secondary side coincident with a single failure. This steam removal can be accommodated without manual actions at the location of the valve.
These valves are located upstream of the MSIVs.
- 3. Depressurization (G) Review or upgrade RCS depressurization l
method
(D) The Midland plant has a safety-grade auxiliary pressurizer spray.
- 4. Boration for cold shutdown / chemical and volume control system, and boron sampling (G) Revise shutdown reactivity requirements to ensure required shutdown margin by safety-grade systems at cold condition (D) The Midland plant has the capability to attain a 1% Ak/k shutdown margin, assuming the most reactive red stuck out of the core, no xenon, no letdown, no offsite power, and using only safety-grade systems.
({}
19
Midland Plant Units 1 and 2 Design to Achieve End Maintain Cold Shutdown
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A safety-grade EBS is being added to ensure that an adequate shutdown margin can be accommodater without letdown.
The RCS boron concentration is normally measured with a boronometer that takes samples from the letdown system. A sample
! lins is being installed on the letdown line upstream of the letdown valves to permit RCS srcaries to be taken with normal letdown itolated. Sample lines in the DHR system permit sample taking af ter the DHR operation.
The next two requirements are more specific
& DER design and are not cold shutdown ccacerns. However, they are included in the comparison for completeness.
- 5. Decay heat removal isolation (G) Provide sufficient DHR system isolat_ ion I (D) The suction side of the DHR system has two parallel lines with two valves on each line, as described in long-term cooling /DHR O dropline. These valves have interlocks te prevent opening unless RCS pressure is below DHR design pressure. The valves also have interlocks that close the valve if RCS pres-sure exceeds approximately 500 psig.
' Overpressure protection of DHR system is accomplished by a relief valve that dis-charges to the reactor building sump.
The discharge side of the DHR system has two check valves in series between the RCS and the DHR system. The system will have provi-sions to permit periodic leak testing of the valves.
t l
l Compliance with the BTP is met, with a
clarification required for the isolation valve closure interlock. Overpressure i
protection of the DHR system is ensured by the DHR system relief valve. This valve also l
provides one means of overpressure protection of the RCS at low temperature. To maintain l this means of overpressure protection, the i
automatic closure interlock is not actuated
, O 20 i
Midland Plcnt Units 1 and 2 Design to Achiava and Maintain Cold Shutdown
() -
until an RCS pressure of approximately 500 psig is reached; this exceeds the DHR relief valve setpoint (approximately 360 psig).
- 6. Decay heat removal pressure relief (G) Collect and contain DHR pressure relief
! and discharge (D) Relief valve discharge is routed to the containment sump. This fluid is contained and also available for suction from the sump if sump recirculation is necessary.
- 7. Test requirements (G) Develop procedures for cooldown and natural circulation. Meet RG 1.68 and use analysis and testing to confirm adequate l mixing and cooldown under natural circu-lation.
l (D) The Midland plant will reference a
]/-. natural circulation test if one has been I conducted on a plant similar to Midland. If such a test has not been completed, Midland will perform a natural circulation cooldown I
test for 50F to verify previous calculations.
l A test to measure mixing is not anticipated.
With this clarification, Midland will meet the testing requirements as delineated in the response to RG 1.68 in Appendix 3A of the FSAR.
- 8. Operational procedures (G) Meet RG 1.33 and develop procedures for l
cooldown under natural circulation.
(D) Operating procedures for natural circu-lation cooldown will be written and made available to the operators before initial criticality.
l
- 9. Auxiliary feedwater aupply (G) Ensure that an adequate alternate Seismic l
l Category I source of water is available.
I s 21 l
Midland Plcnt Unito 1 and 2 Design to Achieva and Maintain Cold Shutdown C)
(D) The AFW system has an automatic switch- I over to safety-grade service water. This volume of water (i.e., the ultimate heat sink and the cooling pond) exceeds any inventory requirements for AFW. )
C. Open Items Associated with Staff Review of Midland ,
Plants (NRC Letter, 3/30/79; Meetings of 4/10-11/79 and 4/19-20/79)
- 1. RSB-7 (G) This open ' item states that the Midland design does not comply with SRP 5.4.7 and BTP-RSB 5-1 for Class 2 plants (NRC letter, 3/30/79).
(D) A revised response to 211.35 has been provided to respond to this issue. The question in 211.35 closely parallels the issues addressed in BTP-RSB 5-1; the response closely parallels the previous discussion of compliance to BTP-RSB 5-1. The question and response to 211.35 are included in the. appendix, O ""* === =ot aar a zurte r her -
- 2. ASB-8, Manual operation of MAD valves (G) This open item required demonstration of manual operation of the MAD valves (Meeting of 4/10-11/79).
(D) The safety function of the MAD valves has been eliminated. The safety function is now accomplished by redundant POAV valves that are operable from the control room. This obviates the need to demonstrate manual operation.
- 3. PSB-11, Decay heat removal letdown valve (G) Midland should have motor-operated DHR letdown isolation valves to preclude die need for containment access (Meeting of 4/19-20/79).
(D) Midland meets this requirement as dis-cussed in BTP-RSB 5-1.
[v 22
__ _ . _ . . _ ._ __ ._. . _ _ .._._. _ ._.~.. __
Midland Plant Units 1 and 2 DeQign to Achiovo and Maintain Cold Shutdown
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- 4. RSB-10, Pressurizer heaters J (G) Justify the use of nonsafety-grade pre-saurizer heaters (NRC letter, 3/30/79).
(L) The plant design has been revised to provide safety-grade power and controls to two banks of pressurizer heaters. The power and controls are backed by onsite emergency power systems in the event of loss of offsite power.
4 5. RSB-20, Long-term cooling af ter a main steam line break (NRC letter, 3/30/79)
(G) The effects of possible submergence of the DHR dropline valve motor operators inside containment following a main steam line break
, were questionsd.
(D) The response to Question 211.163 addresses this concern. The isolation valve operators are located at the approximate water elevation that would exist if a MSLB were to occur inside 4
p the containment and the entire contents of v the BWST were also to be injected into the containment. However, the control room operator has safety-grade indication of the reactor containment building water level and l
l has approximately 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> to terminate the spray. Thus, operator action will preclude water in the containment from reaching a level to be of a concern with respect to the DHR isolation valve operation.
D. SRP 7.4, Systems Required for Safe Shutdown
- 1. Purpose This section of the SRP provides review guidelines for instrumentation and control systems associated with parts of the nuclear steam supply system used to achieve and maintain a safe shutdown condition of the plant.
- 2. Controls required to achieve and maintain safe shutdown: The following controls are provided in the Midland design to achieve the necessary safety functions:
O 23 f
i
-.._..__,..,_.___,-.__.-__,m , _ . _ . . . . . . _ _ _ _ _ . . _ . . . . , _ _ _ _ _ . , . - . . . _ . . _ _ . . _ _ _ _ , . . . . . . - _ .
Midland Plant Units 1 and 2 Design to Achiova and Maintain Cold Shutdown O a. Reactivity control / inventory control
- 1) Control rod drive trip circuitry
- 2) Safety-grade portion of the MU&PS, BWST, and EBS
- b. Heat rejection (temperature control)
- 1) Auxiliary feedwater controls - Main steam line and main feedwater line isolation valve controls
- 2) Power-operated atmospheric vent valve controls
- 3) Necessary service water and compo-nent cooling water (CCW) system controls
- 4) Control of natural circulation by proper operation of the AFW and POAV valve control systems
- 5) During hot shutdown and cold shut-down conditions, DHR system con-(]
U trols are provided.
- c. Pressure reduction and control
- 1) Pressurizer heater controls for banks 5 and 6
- 2) Auxiliary pressurizer spray controls
- 3. Instrumentation required to achieve and maintain safe shutdown The following instrumentation capability exists in the Midland design to moniter the safe shutdown condition:
- a. Reactivity control / inventory control
- 1) Control rod drive trip breaker position indication (at the breaker)
- 2) Emergency boration system tank level indicatica
- 3) Source range neutrcn power O
24
Midland Plant Units 1 and 2 Losign to Achieve and Maintain Cold Shutdown C)
- b. Heat rejection (temperature control)
- 1) Reactor coolant system hot and cold leg temperature
- 2) Decay heat removal heat exchanger outlet temperature (see note below) l
- 3) Auxiliary feedwater flowrate
- 4) OTSG pressure and level
- 5) Power-operated atmospheric vent valve position
- 6) Reactor coolant system flowrate
- 7) Decay heat removal flowrate (see note below) l
- c. Pressure reduction and control
- 1) Reactor coolant system pressure
() 2) Pressurizer level Note: Safety-grade indication is provided in the main control room for accident monitoring j purposes and is available for safe shutdown i monitoring. -However, these indications are not immediately required for safe shutdown monitoring. Sufficient time exists to connect portable instruments to line-mounted i equipment and, therefore, permanent instruments ;
for these parameters are not provided outside the control room.
- 4. Conformange to SRP 7.4 Detailed design and procurement of the controls and instrumentation required for safe shutdown are nearing final stages for most items. The SRP acceptance criteria were considered and are being implemented. These criteria are summarized below.
O 25
Midland Plent Units 1 cnd 2 Design to Achieve and Maintain Cold Shutdown
(:)
- a. Redundancy (G) All instrumentation and controls essential to achieve and/or maintain the cold shutdown condition are redun-dant to their intended safety function.
(D) The project is implementing this SRP acceptance criterion.
- b. Single failure criterion (G) All instrumentation and controls essential to the achievement and/or maintenance of the cold shutdown condi-tion meet the single failure criterion.
(D) The project is implementing this SRP acceptance criterion.
- c. Capacity and reliability (G) All instrt%2r.tation and controls l essential to tr.e achievement and/or maintenance of the cold shutdown condi-(]) tion have the capacity.and reliability to perform their intended safety func-tions whenever necessary.
(D) The project is implementing this SRP acceptance criterion.
- d. Qualification (G) All instrumentation and controls i essential to the achievement and/or maintenance of the cold shutdown con-dition are qualified to function during and after the design basis events for which their operation is essential, including earthquakes and all FSAR Chapter 15 accidents.
(D) The project is implementing this SRP acceptance criterion with the clarifica-tion provided in RG 1.97 that instrumen-tation should continue to read within the required accuracy following but not necessarily during an SSE.
O 26
Midland Plant Unito 1 and 2 Design to Achieva and Maintain Cold Shutdown
(:')
- e. Testing (G) All instrumentation and controls essential to the achievement and/or maintenance of the cold shutdown con-dition satisfy applicable criteria for preoperational and periodic testing, quality assurance, and design provisions
- fer indicating system availability.
l l
(D) The project is implementing this SRP acceptance criterion.
- f. Remote / local station capability (G) SRP 7.4 states that equipment re-quired for safe shutdown be operable from local control panels and that access to these local control panels should be administratively controlled.
l Appropriate readouts (such as steam l generator level, steam generator i pressure, pressurizer pressure,
(]) pressurizer level, and AFW flow) to monitor the status of the shutdown should be provided. This equipment should be designed to accommodate a single failure and should be capable of operating independently of the equip-ment in the main control room. The equipment should also be designed to the same standards as the corresponding equipment in the control room.
(D) The Midland design will comply with this SRP acceptance criterion with the following clarifications:
l
- 1) The Midland design provides redun-dant controls and indications outs?.de the control room on local control panels. These controls and '
indications outside the control room are designed to operate without the mutual action of those in the control room. No single failure will defeat this capability for safe shutdown at either location.
in addition, a study is in progress which responds to fire protection
[}
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Midland Plant Units 1 and 2 Design to Achieve and Maintain Cold Shutdown
() -
guidelines. The study evaluates 4
the feasibility of installation of transfer switches, relocation of signal processing equipment, and improved fire protection of safe shutdown control and instrumentation to ensure that the capability exists outslde the control room to shut the plarat down af ter a fire.
- 2) The Midland design provides instru-mentation capability at the auxi-liary shutdown panel and local control stations beyond the examples provided in SRP 7.4. Instrumenta-tion for monitoring safe shutdown is consistent with the control room capability as described in Sec-tion VII.D.3 except as follows:
a) Source range neutron power for reactivity control monitoring Control room: Safety-grade O indication is provided.
Auxiliary shutdown panel:
Computer terminal display of isolated safety-grade inputs to the computer is provided.
Discussion: Complete safety-grade indication of source range neutron power is not available outside the control room. Analysis indicates chat in the worst-case scenario, upon completion of EBS injec-tion, the reactor will remain subcritical. Safety-grade EBS tank level indication is provided on the auxiliary shutdown panel and this, togethsr with valve indications, provides sufficient-verification of proper EBS injection. Therefore, this precludes the need to monitor ,
source range neutron power.
O 28
Midicnd Plcnt Unita 1 and 2 Design to Achieve and Maintain Cold Shutdown
() -
E. Regulatory Guide 1.139, Guidance for Residual Heat Removal to Achieve and Maintain Cold Shutdown
,,1.139 has been made available to the industry and is intended' to apply to cps issued af ter January 1, 1978; therefore, it is not specifically applicable to Midland. The implementation section of the latest available version (Draft 2, Revision 1 transmitted to A.L. Cahn of Bechtel Power Corp.
l by G.A. Arlotto of the NRC on March 21, 1980) states that the guide will be used for plants docketed af ter January 1,1980, and this excludes Midland. This section also states applications docketed before this date will be reviewed against this guide on a case-by-case basis.
Nevertheless, the guidance in RG 1.139 will be compared to the Midland design. This comparison will be made with Section C, Regulatory Position, of the regulatory guide.
- 1. Functional
- a. (G) The design shall be such that the
~% reactor can be taken from normal opera-ting conditions to cold shutdown using only safety-grade equipment.
(D) Midland has this capability.
- b. (G) The systems utilized are redundant, provide fuaction assuming a single failure, and are capable of operation with onsite or offsite power.
(D) The systems used satisfy this guidance.
- c. (G) The RCS shall be capable of being cooled and depressurized so DHR ini-l tiation can begin in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.
(D) The POAV valves that have been added can cool the reactor sufficiently enabling DHR operation to be initiated within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> after shutdown.
- d. (G) Instrumentation and controls conform to IEEE Std 279-1971, 323, 384, and 344; and RG 1.89, 1.75, and 1.100.
O V
29
Midicnd Plcnt Unita 1 cnd 2 Design to Achiovo end Mnintain Cold Shutdown
() (D) All necessary instruments and contruic will be safety grade.
- e. (G) Safety-related systems should be Seismic Category I and meet RG 1.29.
(D) The Midland design is in accordance with this guidance except for the CAS, which is an alternate system that may be used to provide for RCS contraction volume following a tornado. A seismic event is not assumed to occur simulta-neously with a design basis tornado.
- 2. Reactivity control (G) A safety-related system shall exist to control and monitor the boron concentration.
(D) Safety-related systems exist to inject sufficient boron to ensure subcriticality.
Operation of these systems ensures sufficient boron concentration. Boron concentration can be measured by sampling or by the nonsafety-grade boronometer when letdown is available.
~^ A safety-related boron measuring device is not installed.
~
- 3. Heat removal t
i
- a. Auxiliary feedwater (G) A safety-related water source should l
exist to supply water for sufficient time.
(D) Refer to response to BTP RSB 5-1.
- b. Steam relief (G) Provide safety-related atmospheric vent valves.
' (D) Refer to response to BTP RSB 5-1. -
- c. Steam generator inventory (G) Provide safety-related steam genera-tor water level indication and alarm.
O 30 i
i l
(
Midicnd Plcnt Units 1 and 2 DeDign to Achieva and Maintain Cold Shutdown
(:) (D) Safety-grade steam generator water level indication is provided. An alarm is provided that is actuated by a Class lE signal transmitted through an isolation device.
- 4. Decay heat removal (G) Provide redundant trains for the RHR system with capability to cool core by 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after shutdown.
(D) The DHR system has redundant trains, but operation of DHR system within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after shutdown is not a design basis. However, the system will be capable of operation within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> after shutdown.
- a. Decay heat removal isolation Refer to response to BTP-RSB 5-1. The
(
requirements of BTP-RSB 5-1 and this regulatory guide are similar on this issue.
m b. Decay heat removal system pressure relief i Refer to the response to BTP-RSB 5-1.
The requirements of BTP-RSB S-1 and this regulatory guide are similar on this issue.
I c. Decay heat removal pump protection (G) Procedures should be such that a single failure or operator error will not result in loss of RHR function due to pump damage.
(D) Operating procedures for the DHR system will be written and made avail-able to the operator before initial criticality. In addition, the present design includes DER pump protection by a nonsafety-grade low-flow trip. This trip is inhibited during ECCAS actuation.
31 L
.v._ _ _ _ .
Midland Plant Unito 1 and 2
- Deoign to Achiavo cnd Maintain Cold Shutdown
() d. Decay heat removal testing Refer to the response to BTP-RSB 5-1.
The requirements of BTP-RSB 5-1 and this regulatory guide are similar on this issue.
- e. Decay heat removal system operation and indication DBR isolation valve position (G) Provide isolation valve position indication, system pressure and flow, and pump operating status in control room.
(D) These indications are available in i the control room.
. f. Residual heat removal system integrity
- 1) Residual heat removal system leakage (G) Monitor and control DHR system pump and valve leakage.
' () (D) The DHR pump rooms have floor drains that are normally closed.
Safety-grade redundant water level indicators for those rooms are i located in the control room. The l valves may be opened locally (nonsafety-grade system) and drained to the auxiliary building sumps. The pump rooms are equipped with an engineered safety features (ESP) filtration system to collect airborne radiation after a postu-lated accident.
- 2) Shielding of personnel and per-sonnel access The present design is adequate for all design base scenarios.
l 3) Engineered safety features filtra-l tion system 32 l
I Midland Plant Units 1 and 2 j Design to Achieve end Maintain l Cold Shutdown t . .. .
I C:)
(G) Service the DHR system, including leakage collection system, by an ESF filtration system (D) The DHR pump room has an ESF i filtration system. Leakage is contained in the pump room by closed drains ~.
- g. Residual heat removal cooling water supply
) (G) Provide safety-related cooling water to the DHR heat exhangers and monitor the water for radioactivity at the DHR heat exchanger outlet.
l (D) The DER coolers are serviced by a safety-grade CCW system. Each DHR cooler is serviced by a separate CCW j train. Each CCW train is equipped with a nonsafety-grade radiation monitor in the line, but not at the output of the i
DHR heat exchanger.
' O 5. Natural circulation cooling (G) Provide redundant emergency power and controls to required number of pressurizer heaters, PORV and PORV block valves, and pressurizer level indicator channels.
(D) Safety-grade power and controls are provided for these instruments and components.
- 6. Reactor coolant system inventory (G) Provide Oapability of supplying makeup and letdawn control to accommodate couldown shrinxage and letdown for boration.
(D) The Midland design can accommodate safety-grade cold shutdown without letdown. Suffi-cient inventory is available from the BWST.
If the BWST is unavailable, RCS makeup can be provided by the tornado-protected, non-l safety-grade, CAS. The letdown system is nonsafety grade, but the letdown isolation is safety grade.
7.
(} Operational procedures Refer to response to BTP-RSB 5-1.
l 33
Midlcnd Plcnt Unito 1 cnd 2 Decign to Achiove and Maintain Cold Shutdown
~ ~' ' ~
LIST OF ABBREVIATIONS
~
AFWAS Auxiliary feedwater actuation signal APSRA Axial power shaping rod assemblies BTP Branch Technical Position BWST Borated water storage tank CAS Chemical addition system CCW Component cooling water CP Construction permit CR Control, room CRD Control rod drive CRDM Control rod drive mechanism CVCS Chemical volume and control system (D) Design DBT Design basis tornado DHR Decay heat removal DHRS Decay heat removal system ECCAS Emergency core cooling actuation system EBS Emergency boration system ESF Engineered safety features (G) Guidance HPI High-pressure injection LOCA Loss-of-coolant accident 6
LPI Low-pressure injection MAD Modulating atmospheric dump MFIV Main feedwater isolation valve MSIV Main steam isolation valve MSLB Main steam line break MU&PS Makeup and purification system OTSG Once-through steam generator POAV Power-operated atmospheric vent PORV Power-operated relief valve l RCS Reactor coolant system RG Regulatory Guide RPS Reactor protection system RHR Residual heat removal SER Safety Evaluation Report SF Single failure l SRP Standard Review Plan i
SSE Safe shutdown earthquake I
(~%
q_) TMI Three Mile Island l
34
r-i 4
O
l l
l l
TABLES I
O l
O
O O O -
TABLE V-1 COLD SHUTDOWN CAPABILITY FOLLOWING CilAPTER 15 EVENTS Cold Shutdown Achievabic in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> with Safety Grade Event Equipment Assumptions Cold Shutdown Limitations 15.1.1 Decrease in feedwater Yes AFW available none temperature 15.1.2 Increase in feedwater Yes AFW available none flow 15.1.3 Steam pressure mal- Yes AFW available Intermittent use of both steam function resulting in generators may be required 4 increased steam flow b
S 15.1.4 Inadvertent opening of Yes AFW available Intermittent use of both steam an atmospheric pump or gener atora may be required safety valve 15.1.5 Steam line break No Loop -only one intact loop available Loss of 1 HPI Pump -time > 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> required 15.2.1 Steam pressure regulator Yes AFW available none malfunction resulting in decreasing steam flow 15.T.2 Loss of external Yes EBS available even none load (turbine trip) with LOOP .
15.2.3 furbine trip Yes EBS available none
- 15.2.4 Inadvertent HSIV Yes AFW available to both none I closure steam generators l
l
o o o i
t TABLE V-1 (Continued)
I Cold Shutdown
- Achievable in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> with Safety Grade
! Event Equipment Assumptions Cold Shutdown Limitations l
15.2.5 Loss of condenser Yes AFW available to both none i vacuum steam generators t
15.2.6 Loss of all nonemer- Yes none
- gency ac power 15.2.7 Loss f normal feed- Yes AFW flow available none
' water to both steam genera-tors 4 15.2.8 Hain feedwater line No AFW flesw available to With LOOP - natural circu-break only one steam generator lation cooldown may require f: > 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />
]
i 15.3.1, Decrease in RCS flow Yes AFW flow to both steam none i 15.3.3, rate generators following 1
15.3.4 loss of RC flow up to
] four pumps
]
15.4.1, Reactivity anomolles Yes none
- 15.4.2,
! 15.4.3, 15.4.4 15.4.6 Chemical addition Yes Operator terminates Continued RC inventory in-system malfunction source of dilution crease may result in inabili .
ty to borate without re-quiring letdown -
l .
4 1
I 4
~
O O O 4
TABLE V-1 (Continued) l Cold Shutdown
- Achievable in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> with
- Safety Grade Event Equipment Assumptions Cold Shutdown Limitations i 15.4.8 Control rod assembly Small LOCA none ejection a
15.5.1 Inadvertent operation Yes none of ECCS
- 15.6.1 Inadvertent opening Yet ilPI maintains primary none
, of a pressurizer safety pressure control or relief valve AFW flow to both steam j generators
<a 15.6.2 Break in instrument Yes ilPI maintains primary none kO line or line from pressure control primary system that AFW flow to both steam panetrates containment generators
! 15.6.3 Steam generator tube Yes llPI maintains primary Choosing to use one unaffec-failure pressure control ted steam generator for cool-down may increase time to cold shutdown and ultimately i increase radiation released 15.6.5 LOCA Yes llPI and LPI availvble l 15.8 Anticipated transient No Time required without scram .
s d
O rintz v -1 LOCATION OF DESIGN REQUIREMENTS TO ACHIEVE / MAINTAIN i 1
Guidance Document BTP RSB QR Midland i Requirement 5-1 211.35 ASB-8 PSB-ll RSB-20 RSB-10 RC 1.139 Desian DER drop line Yes Yes Yes Yes Yes that can accommo-date single fail-ure ,
Safety-grade Yes Yes Yes Yes Yes steam dump valves Provide aux. Yes Yes Yes spray or show manual actions are acceptable
' Provide safety- Yes Yes Yes Yes(l)
O related boration system without letdown, or pro-vide safety-l grade letdown, or l
show that manual actions are accep-table Provide adequate Yes Yes Yes RER isolation Discuss collec- Yes Yes Yes Yes tion of RER sys-tem pressure re-lief valve dis-I charge Conduct borated Yes Yes No water mixing test Conduct natural Yes Yes Yes circulation test O
l VI-la l
t l
~
f l . .. .
TABI.E VI-l (Continued)
Guidance Document BTP RSB QR Midland Requirement 5-1 211.35 ASB-8 PSB-ll RSB-20 RSB-10 RG 1.139 Design Provide natural Yes Yes Yes Yes circulation pro-cedures Provide Seismic Yes Yes Yes Yes Category I AFW system water sup-pl7 Provide safety- Yes No( )
grade means of
- nonitoring boron concentration Provide safety- Yes Yes( )
grade steam gen-erator level in-dication and alarm Provide safety- Yes Yes(')
grade makeup and letdown control Provide necessary Yes Yes Yes safety-grade pressurizer heat-ers with Class 1E power and control gS: Midland provides safety-grade boration without letdown (2)Nonsafety grade sampling is provided
( ) Alarms exist but are not safety grade
( ) Letdown is safety grade only for isolation of letdown i
O
!. vi-lb I
l-----___.-_ __ . _ . ___ . . _ . _ _ _ . _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ . . , _ _ _ _ _ __ _ _ _ ,
O
~
s
,. TABLE VI.2
]
DgSIGN CUIDANCE OF BTF RSS 5-1 FOR Ct. ASS 2 FLANTS AND COMPARISON TO MIDIAND DESICN( }
Destan Requirements Frocess and System Branch Technical Fonttion Design Guidance of hTP RSS 5-1 or Component for Midland MAJland Deslan
- 1. Functional requirement Long-term cooling (RHR Compliance will not be required if it can be shown that Midland complies.
for taking to cold drop line) correction for eingle fatture by manual actions inside ,
' shutdown or outside of containment, or return to loot standby Midland has e single DER i until man.al actions (or repaire) are complete, are dropline that divides into
- a. Capability using only found to be acceptable for the individual plant. a series / parallel remote safety grade ayeten motor-operated valve 4
arrangement inside
! b. Capability with either cont:Innsats the line i
only onette or only then reconverges to cult of fsite power and with containment. Local single failure manual actione la the (limitad action auxiliary building are outside CR to meet SF) required for alignment.
- c. Reasonable time for cooldown assuming most g
liettlag SF and only
, offatte or only onsite y power Heat removal and RCS Frovide safety grada dump valves, operators, and power Nidland complies, circulation during supplies, etc so that manual actione alsound not be cooldown to cold required after an SSE except to meet single failure. Remote manual safety grade shutdown p0AV valves are provided and are operated by safety-grada power and controls. The eingle failure criteria is met. Remote manual action la required.
Depressurization Compliance will not be required if a) dependence on Midland complies.
(pressuriser suaillary manuel actions inside containment after SSE or eingle spray or power-operated failure, or b) rumaining at loot standby until manual A safety grade muni!!ary relief valves) actions or repairs are complete, are found to be pressuriser spray is acceptable for the individual plant. prov1Jed. Local manual action in the mustliary building to required for alignment. Control is .
acceeptiehed from the control room.
- boration for cold Compliance will not be required if a) dependence on Midland complies.
shutdown (CVCS and manual actione instae containment after SSE or single boron asepling) failure, or b) remaining at het standby untti manual Midland has the capability actions or repairs are complete, are found to be to borate without letdown.
acceptable for the ladividual plant. A safety grade emergency boration syntes provides
i f"'N .
\
l 1
l Table VI-2 (Continued)
Dealga Requiremente Process and System Branch Technical Position Design Cuidance i
of BTP RSS 5-1 or Component for Midland Midland Desian for borettoa to bot standby.
The BWST or CAS provides for boration to cold abu.Jown.
Local manual alignment is required. Baron concentration is normally measured after being let down. Samp!!ag capability will be added on the 4
cold-loop letdova line upstream of the toolation
- valve.
j 11. kHR leolation kut system Comply with one of the a!!owable arrangements. Nidland complies.
I The DER system section le j isolated by two series j motor-operated valves on each of two lines.
! $ The DuR discharge is isolated i {p by two serine check valves on each of tuo lines.
j 111. RHR pressure relief l b. Collect and contata Det systee Compliance w!!! not be required if it can be shown Midland complies.
i relief discharge that adequate methods of disposing of discharge are
! available. The DMR rettet valve
- discharge la routed to the containment mump.
V. Test requirement
- b. Heat RC 1.68 for Rua tes'!s and confirm analysis to meet the requirement. Nidland complies with PWRs test plus clarification for baron analysis for mixing test.
cooldown under .
natural circulation Midland will use the results to confirm adequate of a natural circulation l mining and cooldown eldown test on a stellar within limits ...at to confirm esisting ,
spectiled in kor, calculations if a similar
- plant la tested before Midland. Othervloe, a 50F cooldown test will be I performed on Midland. No .
separate boroa alzing test is presently planned.
i l e
. 1 Table VI-2 (Congaued}
Deelga Requirements Process and Systes Branch Technical Position Destga Cuidance of BTP RSS S-1 or Component for Hidland Midland Destaa VI. Operational procedure
- a. Meet RC 1.33 for bevelop procedures and information from tests and Midland will comply.
FWRe, include analysis.
specific procedures Appropriate procedures will sad information for be developed.
cooldown under natural circulation.
VII. Austilary feedwater supply
- a. Salamic Category I Emergency feedwater Compliance will act be required if it la shown that Midland complies.
supply for AFW for at supply an adequate alternative Seismic Category I source least 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> at hot le available. An automatic auttchover shutdown (etc) plus to a safety grade source of coolJown to RRR AfW is provided upon low cutin based on longest suction to the AFW pumpe, time for only onette cotacident with an or only off-site accident afspel.
power and assumed slagte failure.
h~
II Hidland is a Class 2 plant because the construction permit wee leaued before January 1, 1973.
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! Accommodate a Single Failure i
f-l eREFERENCES i BTP RSB 5-1, Q211.35, PSB-11, RSB-20 1
1 i
1 o MIDLAND DESIGN
- Complies
- ParallellSeries Motor-Opersted
! Valves Provided Inside Containment
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a eREFERENCE
! BTP RSB 5-1, Q211.35, ASB-8, RG 1.139 l
l e MIDLAND DESIGN Complies: Two POAV Valves Provided por Steam Generator M40 LAND UNIS 1 ANO 2 G- 1610-07 i 6
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Acceptable Manual Actions l :s 6
i eREFERENCES l BTP RSP 5-1, Q211.35 e MIDLAND DESIGN Complies: Auxiliary Pressurizer Spray Provided MIDL ANO UNilS 1 AND 2 G-1610 08 6
s
- .
1 e NRC POSITION .
Provide Safety-Grade Boration Capability or Show Acceptable Manual Actions
. s
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MIOLANOUMTS I AND 2 G-1610 69 l
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Provide Adequate DHR isolation
l
- s eREFERENCES d'
l BTP RSB 5-1, RG 1.139 e MIDLAND DESIGN j Comp!ies: Suction isolation by Two Series i Motor-Operated Valves; Discharge Isolation l by Two Series Check Valves MIDLAND UNilS 1 AND 2 G-16tO-10
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Collect and Contain DHRS Pressure Relief l Valve Discharge 9
eREFERENCES
! BTP RSB 5-1, Q211.35, RG 1.139 l
! e MIDLAND DESIGN
! Complies: Discharge Routed to Containment j Sump i i 8
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l
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! Conduct Natural Circulation Cooldown and ;
j Borated Water Mixing Test i
$ eREFERENCES
! BTP RSB 5-1, Q211.35, RG 1.139 l e MIDLAND DESIGN l
Partial Compliance: 50F Natural Circulation Cooldown Test Will Be Conducted or
) R'eferenced; No Separate Boron Mixing Test Planned; Safe Boron Mixing Test infeasible i ,
O o o 'l l :
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Provide Procedures for Natural Circulation Cooldown f
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l e REFERENCES l BTP RSB 5-1, Q211.35, RG 1.139 e MIDLAND DESIGN Complies: Appropriate Procedures to Be
- Provided -
anoLAt40 utaiS 1 AND 2 G-1510- 13 j
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! Provide Adequate Seismic Category I AFW l
Supply
! .1 a
eREFERENCES BTP RSB 5-1, Q211.35, RG 1.139 e MIDLAND DESIGN Complies: Normal Supply is Nonsafety-Grade Condensate; Automatic Switchover Provided to Safety-Grade Service Water ,
MiOLANO utaTS 1 ANO 2 G l510-14 ,
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i e NRC POSITION Provide Boron Monitoring Capability with '
Safety-Grade System eREFERENCES g BTP RSB 5-1, RG 1.139 s
l
- e MIDLAND DESIGN
! . Nonsafety-Grade Boron Monitoring Provided l . Continuous monitoring by boronometer on
! letdown
. Periodic monitoring by manual sampling ,
MiOL AND UNIS I At0 2 G-15sa 15
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! Provide Safety-Grade Steam Generator Water l Level Indication and Alarm l
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i Complies with Clarification: Safety-Grade Water Level Indication and Nonsafety-Grade Alarms Providad ,
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[ eREFERENCES RG 1.139 e MIDLAND DESIGN Complies with Clarification: Boratica and .
Cooldown Shrinkage Accommodated Using '
Only Safety-Grade Systems Without Letdown .
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l l g eREFERENCES l
t Open item RSB-10, RG 1.139 e MIDLAND DESIGN !
Complies: Two Banks of Pressurizer Heaters Backed by Safety-Grade Power and Controls l
MIDLAND UNITS 1 AND 2 G-1510-18 l -
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e NRC POSITION Achieve Cold Shutdown with Safety-Grade Systems
- e REFERENCES
( BTP RSB 5-1, Q211.35, RG 1.139 l Open items PSB-11, RSB-10, ASB-8, RSB-7 o MIDLAND DESIGN Complies with Clarifications:
g
= Boration accomplished without letdown
%
- Boration monitored and sampled by nonsafety-grade l
i systems
e No separate boron mixing test planned l
= Steam generator water level alarms are nonsafety-grade
- One steam generator ccoidown will take longer than 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> e Upgraded nonseismic CAS can provide contraction volume '
4 after tornado ,
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MIDL AND UNiiS 1 AND 2 G- 1510- l e
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- AUXILIARY SHUTDOWN PANEL I I i MONITORS i
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OTSG Pressure & Level l
RCS Flow & Pressure LOCAL CONTROL PANELS, POAV Position MCC, & SWGR G
g CONTROLS SYSTEMS Pressurizar Heaters Diesel Generator Portions of MU&PS Service Water CCW Pumps Component Cooling Water POAV Valves -
Chilled Water Pressurizer PORV VARIOUS Plant HVAC Auxiliary Feedwater ACTIONS Auxiliary Pressurizer Spray INDICATED (e.g , EBS DHR)
LOCAL AT ,
EQUlPMENT
- HOT STANDBY : -
l HOT SHUTDOWN :
COLD SHUTDOWN : ,
MDL ANDupeIS 9 AND2 O 1560 02 s
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l . -l STANDARD REVIEW PLAN SECTION 7.4 ACCEPTANCE CRITERIA 1
e ALL INSTRUMENTATION AND CONTROLS ESSENTIAL TO ACHIEVE ANDIOR MAINTAIN COLD SHUTDOWN SHALL:
l
- BE REDUNDANT in Their Intended Safety Function
!
- MEET THE SINGLE-FAILURE CRITERION i
- HAVE CAPACITY AND RELIABILITY to Perform Their intended Safety Functions Whenever Necessary l {
=
- SE QUALIFIED to Function After the Design Basis Events
- for Which Their Operation is Essential, including Earthquakes and All FSAR Chapter 15 Accidents
- Satisfy Applicable Criteria for Preoperational and Periodic TESTING, QUALITY Assurance, and Design Provisions for i INDICATING SYSTEM AVAILABILITY ,
- BE OPERABLE FROM OUTSIDE THE CONTROL ROOM at -
Local Control Panels with Appropriate Readouts, and :
4 Operate Independent of the Control Room M4DLAND UtMS 1 AND 2 G- 1608-01
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! POAV l Decay Heat Removal numll -
l System T-HOT T-COLD Al-W FLOW OTSG LEVEL & PRESSURE
! RCS FLOW POAV VALVE POSITION DHR FLOW l DHR HX OUTLET TEMP i i i i l i I l 600 579 632 600 400 325 300 280 200 OPE EHo PoWGJ CUT T-IN .
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ROcpen000 to NRC Qucaticn3 Midland 1&2 l
Question 211.35 (5,4.7) ,
Should the Midland plants experience an event that will require eventual cooldown to permit either long-term cooling with the DER l system or going to cold shutdown for inspection and repairs (extended loss of offsite power, steam generator tube rupture, failure of steam generator relief valves to reclose, etc), it is desirable that qualified systems be available to perform the operation safely and in an orderly manner. Discuss the capability of the Midland plants to be taken to a cold shutdown condition using only safety-grade equipment, assuming only onsite i
! or off-ite power is available, and considering a single failure.
Address each of the following areas of concern in your response:
- 1. Discuss the capability of the single DHR drop line to provide for the cooldown of the plant assuming a single active failure, including manual actions inside or outside of containment or the return to hot standby until manual actions or maintenance can be performed to correct the failure.
With regard to the Midland shutdown capability, we note that manual operation outside the control room is 8 required for normal shutdown, and containment entry is required for a failure of a motor-operated DHR suction valve. With regard to reducing the need for such manual i
actions, address the following areas: ,
O a. Discuss the modifications required to provide the ;
capability to conduct a normal shutdown from the control room.
- b. Justify the viability of the manual actions required after a suction valve failure (i.e., i
- opening cross-connects 093, 094). Address times required, doses expected, and potential for inadvertent opening of cross-connects during high primary side pressure conditions. Compare the Midland cross-connect design to Davis-Besse Unit 1.
Provide a reliability analysis for the manual action outside the control room and discuss the incremental increase in reliability expected for various selected design modifications.
- 2. Provide safety-grade steam generator dump valves, operators, air, and power supplies which meet the single failure criterion.
- 3. Provide the capability to cool down to cold shutdown assuming the most limiting single failure in less than 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> or show that manual actions inside or outside ;
containment or return to hot standby until the manual i
- r O Q&R 5.4-8 Revision 9 5/78
l
- .
Responses to NRC Questions Midland 1&2 - -- - -
g .
T actions or maintenance can be performed provides an acceptable alternative.
- 4. Provide the capability to depressurize the reactor ,
coolant system with only safety grade systems assuming a '
- single failure, or show that manual actions inside or outside containment or remaining at hot standby until manual actions or repairs are complete provides an acceptable alternative.
- 5. Discuss the capability for boration with only safety-grade systems assuming a single failure or show that manual actions inside or outside containment or
! remaining at hot standby until manual action or repairs are completed provides an acceptable alternative.
- 6. Discuss the capability for the collection and containment of DER system pressure relief valve discharge.
! 7. Conduct tests to study the mixing of the added borated 9 water and cooldown under natural circulation conditions
( with and without a single failure of a steam generator atmospheric dump valve.
- 8. Commit to providing specific procedures for cooling down Cg',i ""*"' "" **'""**** " '"' """"** * """"
procedures.
- 9. Provide a S'aismic Category I AWF (SIC] supply for at least 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> at hot shutdown plus cooldown to the DER system cut-in based on the longest time (for only onsite or offsite power and assuming the worst single failure),
or show that an adequate alternate seismic category I source is available.
Response
The Midland design basis provides for the ability to achieve and 3o maintain, by safety grade means, the hot shutdown condition as described in Section 7.4 of the FSAR. As discussed in the response to Question 110.16, hot shutdown provides for an 14 extremely stable and safe condition at which the plant can be -
maintained until an e'7entual cooldown can proceed. Although not a design basis, the Midland design does incorporate the ability 30 to be taken to the cold shutdown condition using only safety tu grade equipment, assuming only onsite or offsite power is available and considering a single failure. Thereforr., in the unlikely event that a design basis earthquake occurs which 30 results in the need to achieve cold shutdown expeditiously, design features exist to accomplish this evolution. This b Q&R 5.4-9 Revision 30 10/80 i
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ROcponsO3 to NRC Quoction3 Midland 1&2 . . . .
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capability is' discussed in the following point-by-point response 18 keyed to the item numbers of NRC Question 211.35:
- 1. The suction side of the decay heat removal (DER) system inside containment has been upgraded to incorporate l motor operators for the previously manual bypass valves.
These bypass valves are supplied with redundant Class 1E power (channel E) through manual transfer switches operated outside containment. Therefore, operator action inside containment is not required assuming a 30 single active failure. In addition, the isolation valve
outside containment (IMO-1010 or 2MO-1110) is mechanically locked open. Therefore, this valve is not susceptible to an active failure.
To align the DER system for cooldown will require
- limited operator action outside the control room. The
operator actions required are:
i lu a.
The operator must open the LER pump suction cross-connect manual valves (Unit i valves 009 and 016 or Unit 2 valves 003 and 008) to establish the suction flowpath.
- b. The operator must reestablish power to the DER cooler bypass valve (IMO-1014A, B or 2MO-1114A, B).
This valve is electrically locked closed during e
{) normal reactor operation. '
i To reduce the need for manual actions outside the
- control room for initiating the normal DER system cooldown, the DER system would require
- a. Replacement of the DER pump suction cross-connect manual valves with power operated valves
- b. Removal of the electrical lock on the DER cooler
, bypass valves. These valves would be ensured 14 i closed during normal reactor operation by administrative control.
The multiple purposes of the DER system pump suction
_ cross-connect manual isolation valves are given below:
- a. During power operation (DER system aligned for starAby low-pressure injection (LPI) mode), the valves function to separate the suction of the LPI pumps.
- b. During the DBR mode of operation, the valves provide the capability to isolate one DER train while providing DER with the other train.
(]) Q&R 5.4-10 Revision 30 10/80 y, ,,- - w - =--~+--~-2 v. --+-e-.- - - - - - .-e,--- w,,--r- -
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Responses to NRC Questions Midland 1&2 , ,, ,
This combination of functhus requires manual valves and operator actions outside the control room, or power 1g
, operated valves controlled from the control room, to l align the system for decay heat removal operations. I30 i Because ample time is available for operator action to l align the system for DER operation (approximately 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />), and because of the cost of equipment 14 considerations, manual valves were selected for the appplication.
The Davis-Besse Unit 1 DER suction cross-connect design is similar to the Midland design. The outstanding differences are that the Davis-Besse DER pump suction valves are provided with motor operators, no containment isolation valve is provided, and the bypass valves
! inside contain.nent are not motorized. Incorporation of pump suction valve motor operators for Midland would reduce one of the manual actions outside the control room required to align the DER system for plant cooldow u. However, the operator has at least 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> to perform this action. The valves should be opened after plant cooldown commences with the steam generator, but before cooldown commences with the DER system. Due to the magnitude of the time available to perform the action, the modification is not deemed necessary. 30 2,3. To remove heat after a postulated design basis h_ V earthquake, two class lE power operated atmospheric vent (POAV) valves are provided on each steam line between the once-through steam generator (OTSG) outlet nozzle and the main steam isolation valve. These valves and their actuators are qualified as seismic active components. The POAV valves are capable of being jogged to any position between full open and full closed by operator action from the main control room or the auxiliary shutdown panel. Each valve has individual manual isolation provisions. The existence of four POAV '
valves per unit (two per steam generator) ensures the '
capability of conducting a balanced cooldown regardless of the occurrence of a single active failure. This
! cooldown will proceed until the emergency DER cut-in l temperature of 325F is achieved. Operation of the DER l system at this temperature is described in Subsection
! 5.4.7.1.1.1. A detailed description of the POAV valves and their associated controls can be found in Subsections 10.3.2 and 7.4.1.2.1.
Water is added to the steam generators by a safety l grade, seismically qualified auxiliary feedwater system. 14 This system will provide adequate water assuming a loss
! of offsite power and a single active failure. The steam produced in the steam generators will be relieved by the POAV valves as discussed above. l30 l
Q&R 5.4-11 l
Midicnc 1&2
- 4. During normal plant cocidown, the reactor coolant system (RCS) is depressurized through normal pressurizer spray . . . . .
The driving force for this spray flow is derived from the reactor coolant pump head. Assuming loss of offsite~
O power, reactor coolant pumps stop and are unavailable to provide normal pressurizer spray flow. Under these circumstances, RCS depressurization can be achieved through the operation of the high-pressure auxiliary i pressurizer spray system. This system utilizes the
- discharge of the high-pressure injection (HPI)/ makeup
- '- pumps to supply spray flow to the pressurizer. Two Class 1E, parallel, motor operated valves are provided that can be jogged by the operator to control the rate
- of depressurization. The design of this system l incorporates a seismic Category'I connection from the l makeup pump discharge to the auxiliary pressurizer spray line. The system can perform its f unction assuming a single active failure. A detailed description of this system and' its associated controls is presented in FSAR Subsection 9.3.4.2.3.9.
- 5. The chemical addition system provides the means to borate the RCS to the required shutdown levels during 30 normal plant cooldown. Using this method, boron is added to the RCS while simultaneously creating volume for this addition through primary letdown. Neither the chemical addition nor the letdown systems are qualified q.
, to operate af ter a design basis earthquake and therefore may not be available af ter this postulated event. Under nf /
these circumstances, coincident with a stuck rod, boration to the cold shutdown concentration can be
(]) achieved through use of the emergency boration system (EBS). This system stores 6 weight percent boric acid which can be injected into the RCS by the HPI/ makeup pumps. If necessary, the operator can add the contents of this system through pump and valve manipulations from the control room af ter initial manual system alignment.
l The concentration and storage volume of the EBS, coupled with available excess volume in the pressurizer, ensures that the necessary boric acid required to maintain hot shutdown and achieve cold shutdown concentrations can be injected into the RCS without letdown.
l The EBS is a safety grade system capable of performing i its design function assuming a single active failure. A detailed description of this system is provided in FSAR Subsection 9.3.10.
- 6. DHR pressure relief capacity is described in FSAR i l Subsection 5.4.7.1.1.3. The discharge fluid is directed g to the reactor building semp. A further description of m -e -
QER 5.4-12 Revision 30 10/80 0
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Responses to NRC Questions Midland 1&2 , ,, ,
relief valve design is contained in the revised FSAR 14 Table 5.4-10.
- 7. A natural circulation cooldown test will be referenced 18 if it has been conducted on a plant similar to Midland.
If such a test is not available, a test will be conducted to verify that operation of the PCAV valves l30 under natural circulation will satisfactorily remove heat required to cool down the plant. This test will demonstrate the ability to cool down approximately 50F 18 under natural circulation conditions and compare the temperature versus 'f ae plot developed with an analytical plot derived for the entire cooldown process. I 30 The test will therefore be used to verify the analytical results.
18
- 8. Operating procedures for natural circulation cooldown will be written and made available to the operators before initial criticality. ,
- 9. As detailed in our response to Question 010.34 and l14 revised Subsection 10.4.9.2.3, an adequate sei.smic 30 category I feedwater source is available.
l f
l l
OV Q&R 5.4-13 Revision 30 10/80 1
Bechtel Associates ProfessionalCorporation 777 East Eisennower Parkway Q 3 2.l !) ,3 Ann Arcor. Micmgan -
wu 4e as P O. Box 1000. Ann Arbor, M:Chgan 481C6 June 4, 1981 ELC- 10938 Locsucers ?cwer Company 194; West Parnall Read Jac! son, Michican 49201 Atta.. tion:
Licensing aau Safety 12 nager
Subject:
Y.idland Plarit L* nits 1 and 2 Consurers Pcwer Co pany Sechtal Job 7220 Cold Chutdown Lesign Soview
- card
References:
a) 3LC-10766, L.li. Curtis to T.J. Sullivan, 5/6/81 (con C29370)
J) 3LC-10?CC, L.ii. Curtis to T.J. Sullivan, 5/29/81 (Cen C01454) action itec dispositions (which are listed in Reference A) f rom the cold shutcown design review bcard meeting held April 22, 1951 are attached for your use.
The attachment to this letter clarifies the responses proviced in Rerer-ence 3 by addressing the courents and concerns expressed by the cesign review board at its tecting on F.ay 29, 1951. The attachnent la a com-plete statecent of the disposition of each action iten and further use cf F.eference 3 is unnecessary.
Pri ary input to the attachment has been provided by Consuoers Power Ccupany, Babcock & Wilcox, and Sechtel as follows:
Action Item :4o. Cecpany la Bechtel Ib B&W 2 25W 3 Consumers Power Ccapany 4 Consurers ?ower Company 5 P,4W 6a Con::umers Pever Company 66 Sechtel 7 Pechtel 8 B&W
') Eechtel &'" N .* j @
P[N' -' ' # '( .j 10 hechtel 11 'Je ch tel g),3 ' 'fi/
12 Consumers Power Company JUN 0 0195'.
- .Nl N.bU 0 . E M$d53U. . '.
c ..
Bechtel Associates Professional Corporation June 4, 1981 BtC-io938 032Iti5
- Page 2 Bv copy of this letter, J.W. Cook, chairman of the cold shutdown design review board, is provided with the disposition of the action items.
Very truly yours, C3 b&
L.H. Curtis # bc A:.
Project Engineer DFL/RJB/jsn(LS) 6/1/1
Attachment:
Cold' Shutdown Design Review Board Action Item Disposition 3 cc: R.C. Bauman w/a J.W. Cook w/a D.F.' Judd w/a D.B. Miller w/a Written Response - Requested: No
Midland Units 1 cnd 2 Cold Shutdown D2 sign Review COLD SHUTDCWN DESIGN REVIEW BOARD 0321!;5 Action Item la Describe analysis of auxiliary spray line and connections to existing line. Address temperature, pressure, and number of cycles.
Disposition The analysis of the auxiliary spray line is being incorporated in the plant stress analysis effort. As described below, the analysis considers the effect of using relatively cold, highpressure spr ay.
Nuclear Class I piping stress analysis of the auxiliary and normal pressurizer spray system uses data which envelop operating conditions. Four operating modes are considered for the purposes of the analysis and are defined below:
Mode 1: Normal Operation consists of a continuous low-flowrate spray through the bypass valve into the pres-surizer from the reactor coolant pump (RCP) discharge.
Thiu mode enhances boron mixing in the pressurizer and maintains a constant temperature in the spray line.
Mode 2: Normal Operation - Reactor Coolant System (RCS)
Pressure Control and Cooldown Depressurization consists of intermittent actuation of one normal pressurizer spray valve to reduce pressure in the RCS for the following conditions:
a) Norr..al pressure variations during power operation (2,160 to 2,210 psig) b) Normal cooldown from power operation to decay heat removal (DHR) cut-in Mode 3: Decay Heat Removal Cooldown Depressurization consists of intermittent actuation of the auxiliary pressurizer spray valves to reduce pressure in the RCS for normal cooldown from DHR cut-in to cold shutdown.
Mode 4: Emergency Cooldown - High-Pressure Injection (HPI) Depressurization consists of continuous low-flowrate spray into the pressurizer from the HPI system through the auxiliary pressurizer spray valves to reduce pressure in the RCS from power operation to DHR cut-in.
Figure 1 represents the normal and auxiliary spray piping system for Midland Unit 2. Unit 1 is typical. Table 1 describes the valve alignment and cyclic information for the four spray modes.
la-1 u
Midland Units 1 and 2 0321I5i Cold Shutdown Design Review i Figures 2, 3, 4, ar.d 5 are schematic representations of the spray piping system as aligned for operation described in
- Modes 1, 2, 3, and 4, respectively.
Table 2 delineates the data used in the Nuclear Class I stress analys s, including temperatures, pressures, and flowrates. Node points listed in Table 2 are identified in Figures 2, 3, 4, and 5.
It should be noted that this input data to the analysis is judged to conservatively envelop design conditions trans-mitted by the NSSS vendor.
The auxiliary pressurizer spray line will be analyzed and supported to acceptable stress levels. The analysis per-fo rmed , to date, indicates that the stress levels'of the normal pressurizer spray lines are acceptable. Finaliza-tion of the analysis will be performed as part of the plant stress analysis. This analysis will incorporate information from D&W Functional Specification 1092, Revision 4, and results of the as-built stress walkdown, as appropriate.
i la-2
Midland Units 1 and 2 C ld Sh"td "" *S19 " **vi'"
32145 COLD SHUTDOWN DESIGN REVIEW BOARD Action Item lb Address low velocity effects of auxiliary spray in terms of the potential for asymmetric stresses caused by steam / water in the spray line. Also, address low velocity effect on spray effectiveness. Address cycle requirements for design of the auxiliary spray line in terms of spray nozzle and piping.
Disposition The analysis that has been completed by B&W assumed a filled spray line and spray nozzle upstream of the spray head. The spray line piping arrangement will be evaluated to ensure that the lines will be kept full. This evaluation is scheduled to be completed by July 1, 1981. The loop trap between the nozzle and the spray head will remain full after initial f illing . The actual stress analysis will be completed by
, September 1,1981s Three scheduling dates are required for completion of this test:
- a. If the lines are not full, determine whether it is a problem. This will be completed by August 15, 1981.
- b. If there is a problem, cef?.ne conditions for stress analyst by January 15, 1982.
- c. Complete new stress analyr,is by September 15, 1982.
The cycle requirements and design fluid conditions are presented in B&W Functional Specification 1092, Revision 4.
An assessment will be nade of low velocity on spray effectiveness.
This assessment will be completed by August 15, 1981.
e
.lb
Midlend Units 1 and 2 Cold Shutdown Design Review 032145 COLD SHUTDOWN DESIGN REVIEW BOARD Action Item 2 Provide basis for sizing of safety grade pressurizer heater bank capacity.
Disposition The 126 kW capacity is sized to replace all pressurizer heat losses during a loss of offsite power with the pressurizer at the normal operating temperature of 650F. Experience and testing has shown that the actual pressurizer heat losses vary significantly, depending on how well the insulation is installed on the pressurizer. The actual heat losses tend to be greater than the calculated value, which is based on the specified pressurizer insulation requirements. For example, the calculated heat losses at Oconee are approxi-mately 35 kW, whereas the actual losses were almost three times higher in one instance. Bechtel has imposed a require-ment that insulation be supplied such that the heat flux from the pressurizer will be less than that specifiSd by B&W BOP Criteria 36-1004527-01.
The B&W operating 177 FA plants generally have a 126 kW capacity bank which is continuously energized. This capa-city has been demonstrated as being adequate to make up for pressurizer heat losses. Midland has redundant safety-grade pressurizer heater banks, each sized at 126 xW.
In the remote possibility that all insulation is lost from the pressurizer, the installed safety-grade heater capacity may not be adequate to control RCS pressure which will result in_a more rapid cooldown. If the depressurization rate becomes excessive during cooldown, the high pressure injec-tion is available as an ultimate backup to assure sufficient inventory to maintain a subcooled core.
1 2
Midland Units 1 and 2 Cold Shutdown Design Re"iew COLD SHUTDOWN DESIGN REVIEW BOARD Action Item 3 The interf ace of engineering design, including late modifi-cation, with the development of normal and emergency proce-dures will be referred to project management for resolution
' independent of the Design Review Board.
Disposition During the Design Review Board Meeting on April 29, 1981, Consumers Power Company management committed to review the interface between engineering design and operating procedure development independent of the Design Review Board. There-fore, this item is considered closed.
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. , . - . - - . - ..-..,,z , . - . - _ . - - . . . - , . . _ , - - . _ - _ . - . -, . . . -
. l Midland Units 1 and 2
, Cold Shutdown Design Review 032143 COLD SHUTDOWN DESIGN REVIEW BOARD Action Item 4 Review the manual actions associated with proceeding to cold shutdown utilizing safety grade equipment tc determine cost benefit of automuting. Emphasis should be on actions in dominant risk sequences.
Dispos ition The consultant for the Midland plant PRA has been requested to analyze the manual actions associated with proceeding to cold shutdown to determine the impact on system unavailability.
The letter to the consultant, PL&G, is attached. If system unavailability does not change by a significant factor on the assumption that the actions were performed from the control room, the manual actions outside the control room will be considered acceptable. Consideration of risk is implicit with this approach. A reply from the consultant should ' be received by September 1, 1981 (Consumers Power Company letter Serial 12206 dated May 14, 1981).
i t
4
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Midlond Units 1 and-2 Cold Shutdown Design Review 7gg}
- COLD SHUTDOWN DESIGN REVIEW BOARD Action Item 5 Describe the single loop NATURAL code analysis. State whether- potential reverse flow in idle loop will be addressed.
Provide schedule for completion.
Cisposition 4
B&W is presently evaluating.several options for a mathe-matical code to evaluate single loop, natural circulation cocidown. This analysis will include the potential for reverse flow in the idle loop. A description of the code can be provided by January 15, 1982. The scheduled completion date for the development of the code and for completion of the cooldown analyses is August 15, 1982.
i i
5
Midland Units 1 and 2 Cold Shutdown Design Review 032140 COLD SHUTDOWN DESIGN REVIEW BOARD Action Item 6a Discuss boron mixing under natural circulation conditions with one or two loops. Address injection to idle loop and feasibility _of boron mixing test.
Disposition Natural circulation boron mixing will be addressed in the Natural Circulation Test Program discussed in Action Item No 12.
6a
Midland Units 1 and 2 Cold Shutdown Design Review COLD SHUTDCWN DESIGN REVIEW BOARD Action Item 6b Address RCS sampling capability, access requirements, and provisions and requirements for safety grade sampling.
Disposition
- a. Sampling Capability A safety-grade emergency boration system provides the boration necessary to maintain hot standby. The Mid-land _ design has the carability to maintain hot standby for an extended period. During normal operation, boron concentration is monitored via samples drawn from the letdown line outside the reactor building, downstream of the letdown line isolation valves. These samples are monitored by either the nonsafety-grade boronometer or the nonsafety-grade reactor plant sampling system (RPSS) (grab sample). Additional boron sampling capa-bility is provided through seismic piping connected to the pressurizer liquid space and the letdown line at the reactor coolant system (RCS) cold leg. The single active failure inside containment will permit sampling from one of these points. The seismic piping is down-graded to nonseismic tubing downstream of the second isolation valve outside the reactor building. Here the sample can be diverted to either the RPSS, described above, or the post-accident sampling system (PASS) which was installed in response to TMI Lessons Learned (NUREG-0578, Section 2.1.8a). The PASS is shielded to allow operators to draw a sample with the potentially high levels of activity in the reactor coolant after an accident and to draw a sample assuming a loss of off-site power. Operator action and/or repairs may be necessary outside containment after a single failure or a seismic event. Sampling lines for the RCS are to be provided from the decay heat removal system to PASS to provide boron sampling capability during cold shutdown conditions.
The sample line connection to the letdown line has not been located. The connection will be located as close as practical to the RCS cold leg. There will be no isolation valves in the letdown line between the cold leg and the sample line connection. Sample system operation will encure that sufficient liquid is drawn to obtain a representative sample. Sample system design will provide for disposal of purge and sampling fluids.
Midland Units 1 and 2 Cold Shutdown Design Review b .- Access Requirements and Provisions of Sampling System The PASS station area and the pathways to the panel 0 3 2 l l> 5 area t re accessible after an accident. NUREG-0578 dcse guidelines specify that doses due to direct radiation while obtaining and analyzing post-accident samples must not exceed 3 rem to the whole body and 18.75 rem to the extremities. (The Midland design will provide reduced direct radiation doses of 1.75 rem to the whole body and 11 rem to the e.xtremities.)
Provisions are made to transport the grab samples to the sample analysis area and offsite in lead sampling casks. The liquid sample panel area and the onsite analysis laboratory area are provided with a. hood type, nonsafety-grade ventilation system which exhausts through high-efficiency particulate air and charcoal filters to control airborne activity levels due to leakage.
- c. Requirements for Safety-Grade Sampling Standard Review Plan (SRP) Section 9.3, Process Sampling System, and Section 11.5, Process and Ef21uent Radio-logical Monitoring and Sampling Systems, require reactor coolant system (RCS) sampling provisions. NUREG-0737, II.B.5 requires RCS sampling capability after an acci-dent but does not require a safety-grade sampling system. Nuclear Regulatory Commission Branch Technical Position RSB 5-1 does not specifically require safety-grade sampling. No regulatory requirements currently exist for safety-grade RCS sampling following an acci-dent. Regulatory Guides 1.26 and 1.29 define the regulatory guidance for safety system classification.
These regulatory guides do not require a safety-grade sampling system. Regulatory Guide 1.139, a draft which is presently in circulation for comment, requires a safety-grade sampling system. However, the require-ments of Regulatory Guide 1.139 (Draft 2) do not apply to Midland design because of its draft status and because the guide stated applicability is only to plants whose construction permit docket dates are later than Midland's.
Regulatory Guide 1.139 Section C.2 states:
A safety-related system should meet GDC 1-5, 26, and 27 and be capable of controlling and monitoring boron concen-tration in order to ensure reactor subcriticality from operating conditions through cold shutdown.
6b-2 km .
Mid1Gnd Units 1 and 2 Cold Shutdown Design Review The following general design criteria (GDC) are appli-cable to the boron monitoring system:
G DC-1: Quality Standards and Records GDC-2: Design Bases for Protection Against Natural Phenomena GDC-3: Fire Protection GDC-4: -Environmental and Missile Design Bases GDC-5: Sharing of Structures, Systems, and Components The PASS design inside the containment meets these criteria. Pass design outside containment does not meet the above GDCs. The PASS does meet applicable existing regulatory requirements and guidance.
9 6b-3
Midland Units 1 and 2 Cold Shutdown Design Review COLD SHUTDOWN DESIGN REVIEW BOARD Action Item 7 State consideration of the need for periodic testing require-ments of the EBS in the design.
Disposition A technical specification will be developed for the emergency
'boration system as a part of the technical specification generation program which is currently in progress. The technical specification will require the following:
- a. Monitor tank level to ensure the required volume of boric acid is maintained
- b. Sample boric acid concentration to ensure specified concentration is maintained
- c. Verify that the system heat tracing is functional 7
Midland Units 1 and 2 Cold Shutdown Dasign Review COLD 6:!UTDOWN DESIGN REVIEW BOARD 032145' Action Item 8 Evaluate the failure of a DHR dropline safety valve. Address probability of failure, its consequences, how the failure would be sensed and how it would be isolated.
Disposition An' analysis will be performed by B&W to determine tae effects of the failure of the DHR dropline safety valve to.reclose and will specifically address the following:
- a. Consequences of valve not closing
'b. How the failure to close would-be sensed
- c. How the open valve would be isolated The analysis is scheduled for completion by August 1, 1981.
s 8
Midland Units 1 and 2 Cold Shutdown Design Review COLD SHUTDOWN DESIGN REVIEW BOARD 0 3 2 1 4 ,a
' Action Item 9 Evaluate discharges to reactor building surp addressing possible vortex formation.
Dispos ition The discharges to the sump fall in two categories: 1) discharges inside the trash racks and 2) discharges outside the trash racks. The Midland design for vortex prevention includes a trash rack, which provides flow straightening, and a grating cage surrounding the recirculation suction lines. No discharge lines penetrate the grating cage.
The only discharge to the area inside the trash rack is from the decay heat. removal relief valve. It is not feasible to discharge from these valves to the sump when in the recirculation mode because the flowpath that includes this relief valve is isolated during the recirculation mode.
The dump-to-sump line discharges outside the trash rack.
The trash rack and grating cage effectively prevent vortex formation as verified by the sump model test report by bestern Canada Hydraulic Laboratories Ltd. The model test was discussed in response to NRC Question 211.189 (attached),
regarding vortex prevention in the sump and the adequacy of the sump model test.
t 9
Midland Units 1 and 2 Cold Shutdown Design Review 032165 COLD SHUTDOWN DESIGN REVIEW BOARD Action Item 10 Demonstrate acceptability of manual actions in view of regulatory requirements. (The general concern for the development of plant operations procedures is to be addressed as part of Item 3. )
Disposition In the April 29, 1981, cold shutdown presentation' to the Midland Design Review Board, J. Mazetis defined the NRC position regarding manual actions outside the control room for achieving cold shutdown. This included definition of the following types of manual action:
- a. Those required for normal shutdown
- b. Those required for emergency shutdown
- c. These required for recovery from a single failure J. Mazetis further stated that the NRC policy for implemen-tation of Branch Technical Position (BTP) RSB 5-1 is that no credit could be taken for Categories a and b above, and that credit for Category c actions was "a negotiated item."
This policy summarizes the requirements for full compliance i with BTP RSB 5-1. However, for the purpose of implementa-tio n , this BTP divides plants into three classes. Class 2 plants are defined as "all plants (custom or standard) for j which CP or PDA applications are docketed before January 1,
- 1978 and for which an OL issuance is expected on or af ter January 1, 1979," and thus include the Midland plant. For
! such plants, only partial implementation is required.
[ Recommended implementation for. Class 2 plants is addressed i
in Table 1 of the BTP RSB 5-1, which allows local manual actions in cases other than recovery from a single failure if such manual actions are found to be acceptable.
The Midland design requires local manual alignment for portions of three processes within the scope of BTP RSB 5-1:
- 1) boration [using the akeup and purification system, emergency boration system BS), and borated water storage tank or boric acid addition tanks (BAAT)], 2) depressuri-zation (using the auxiliary pressurizer spray), and 3) long-term cooling (using the decay heat removal drop line) . As discussed below, these manual actions are performed in accessible areas and within acceptable time frames.
10-1
Midland Units 1 and 2 032\4,3 Cold Shutdown Design Review Table 1 of BTP RSB 5-1 does not give any specific system design as a possible solution for full compliance regarding boration. Instead, the BTP requires that boration be performed using only safety-grade systems which can operate with eittar onsite or offsite power and with a single failure.
Boration without letdown is mentioned as an acceptable example of such safety-grade boration. The BTP also requires monitoring the boron concentration. For full compliance,
" limited operator action inside or outside containment if justified" is allowed.
The recommended implementation for Class 2 plants states:
Compliance will not be required if a) dependence on manual actions inside containment after SSE or single failure or b) remaining at hot standby until manual actions or repairs are complete are found to be acceptable for the individual plant.
The Midland design provides a safety-grade EBS which can provide sufficient boration for hot standby with onsite or offsite power. Local manual actions are required to align the EBS and for reactor coolant system sampling. These actions are performed in the auxiliary building. The earlies:
manual action outside the control room is alignment of the EBS . For the scenario requiring the earliest EBS i.jection, this alignment is required approximately 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> after a reactor trip. Thus, relying on operator actions is justi-fied in terms of access and time available, as allowed by the BTP for full compliance. Use of the EBS is required only in the avent of a reactor trip with a stuck control rod. In addition, local manual actions are required to align the borated water storage tank or (after a design basis tornado) the BAAT for borated water injection. These actions are long-term and are performed in the auxiliary j building. The Midland design exceeds the recommended imple-l mentation for Class 2 plants, which allows for nonsafety-l grade boration with manual actions in containment.
l Table 1 of the BTP provides the following possible solution for full compliance regarding depressurization:
l Provide upgrading and additional valves
! to ensure operation of auxiliary pressuri-l zer spray using only safety-grade subsystem
! meeting single failure. Possible alternative may involve using pressurizer power-l operated relief valves which have been
! upgraded. Meet SSE and single failure
{ without manual operation within contain-ment.
I 10-2 L
Midland Units 1 and 2 Cold Shutdown Design Review 32145 The recommended implementation for Class 2 plants states:
Compliance will not be required if a) dependence on manual actions inside containment after SSE or single failure or b) remaining at hot standby until manual actions or repairs are complete are found to be acceptable for the individual plant.
The Midland design provides a safety-grade auxiliary pres-surizer spray which requires local manual alignment. This alignment is not required until after EBS injection, thus giving the operator sufficient time to take action. The manual action for the alignment is performed in the auxili-ary building. The auxiliary pressurizer spray is required only in the event of a loss of offsite power resulting in the loss of all reactor coolant flow. The Midland design meets the proposed solution for full compliance and exceeds the recommended implementation for Class 2 plants, which could be a nonsafety-grade auxiliary pressurizer spray with manual actions in containment.
For long-term cooling, BTP RSB 5-1 provides the following possible solution for full compliance:
Provide double drop line (or valves in parallel) to prevent single valve failure from stopping RHR cooling function.
The recommended implementation for Class 2 plants states:
Compliance will not be required if it can be shown Lnat correction for single failure by manual actions inside or outside of containment or return to hot standby until manual actions (or repairs) are found to be acceptable for the individual plant.
The Midland design provides a single decay heat removal (DHR) drop line which divides into two for a series / parallel motor-operated valve arrangement in containment and then converges to a single line to exit containment. Local manual actions in the auxiliary building are required for alignment. Because the plant can be maintained indefinitely at hot standby, sufficient time is available for the operator to perform these actions. Manual actions are not required outside the control room to recover from single active failures that could stop decay heat removal cooling. The Midland design meets or exceeds the recommended implementa-tion for-Class 2 plants, which allows for the possibility of a single drop line inside containment as well as outside.
10-3
~. , _-
Midland Units 1 and 2 C Id Shutdown Design Review 3 2 i f+ 5 Thus all of the local manual actions which the Midland design requires for cold shutdown are justified under the recommended implementation of BTP RSB 5-1 provided for plants of Midland's category. To require, in spite of this, that no manual actions be taken outside the control room except in case of a single failure would require major design changes. This was not the intent of the BTP, which specifically states in Note 1 to Table 1, The implementation for Class 2 plants does not result in a major impact while providing additional capability to go to cold shut ]wn.
Therefore, interpretation of BTP RSB 5-1 to mean that local manual actions to achieve and maintain cold shutdown are only allowable after a single failure is not justifiable for Midland.
The existing design uses an appropriate and acceptable combination of local and control room controls that have been, and will continue to be, communicated with Consumers Power Company to provide the opportunity for review by the plant operators to determine proper operating procedures.
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i 10-4
Midland Units 1 and 2 Cold Shutdown Design Review 032143 COLD SHUTDOWN DESIGN REVIEW BOARD Action Item 11
-Investigate the concern for intersystem check valve leakage testing as described in the forthcoming NRC letter.
Disposition The. leakage concern expressed in the referenced NRC letter was the subject of NRC Question 110.58 (attached). A complete response to this question was supplied in FSAR Revision 33.
e 11
Midland Units 1 and 2
,, e Cold Shutdown D3 sign Review 03214a COLD SHUTDOWN DESIGN REVIEW BOARD Action Item 12 Evaluate natural circulation cooldown testing with respect to demonstrating cooldown capability and operating training.
Disposition A natural circulation cooldown test will be performed which is consistent with the guidance contained in the NRC letter from R.L. Tedesco to J.W. Cook, dated April 22, 1981, and the recent Natural Circulation Test Programs at new license facilities. This NRC letter informed OL applicants of a future requirement for such testing and associated training.
The site agrees with the objectives of natural circulation testing and has scheduled time for its performance. The scope of the Natural Circulation Test Program will be docu-mented in Chapter 14 of the FSAR.
12
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e 032145 Responses to naC ouestions Midland 1&2 Qunction 211.189 (6.3) l 18 During our meeting of January 16, 1979, you described proposed full-scale hydraulic model studies which are planned to assess vortex formation and to determine the trash rack and intake lo:ces for the Midland ECCS intakes (i.e., containment sump) following a LOCA. We have further reviewed related FSAR 39 information and the propcsed testing program as to its ability to sufficiently address our concerns and to determine our need for c.dditional information:
- 1. We note that your propocal does not model the containment structures outside the trash racks and the resultant far field effects. Zou imply that the trash racks will suppress cny vortex generated in the far field and that this offectiveness has been documented for other plants. We are concerned that certain vortices could be formed in the far field particular to the Midland configuration which could penetrate the trash rack. Provide data / justification to show the following: 18 A. Far field vortex formation is unlikely for the Midland containment configuration considering the low velocities that would exist.
B. The trash racks would eliminate all vortices produced in the far field which could approach the trash rack at various angles.
- 2. Provide justification for proposing all tests at the minimum water level since more severe vortices have been known to form at other levels.
- 3. Discuss more thoroughly the instrumentation and methods used to measure and calculate the sump and intake structure pressure losses during the tests. Address the accuracy and calibration of these instruments.
- 4. Provide your proposal for the in-plant test which will be 19 used to establish as-built piping losses in the Midland ECCS.
Discuss how these tests will be used to confirm that the FSAR npsh calculation is conservative considering the difference batween the test conditions (temperature, flows, flow paths, etc) and the worst case pumping modes following a LOCA.
- 5. Provide the details of your FSAR npsh calculations for which your results are provided in FSAR Table 6.3-10. These calculations should be provided for the high- and low-pressure injection pumps, including the head loss calculated for each section of pipe and the associated L/D, K factors, velocities, Reynolds numbers, etc.
Revision 19 Q&R 6.3-70 3/79
Ret,snLes to NRC Questions "id2""d l'2 32145
- 6. Provide an additional test or test data to Justify testing for vortex formation at prototype Reynolds number. 39
Response
A series of tests has been periormed by Western Canada Hydraulic Laboratories Ltd to evaluate the perfornance capability of the Midland sump design. A full scale sump model was built and tested to verify vortex control and to determine the head loss !
associated with the trash rack, grating cage, and inlet piping. 30 Results of the test program have been submitted under separate cover in a letter, dated June 26, 1980, from J.W. Cook to A. Schwencer.
- 1. Circulation which is essential for vortex formation may be developed in the approaches to the trash rack by two mechanisms:
A. Eddy shedding from structural members B. Configuration of the plant geometry The strength of eddy shedding is a function of the velocity past the member which sheds the eddies. Tests were conducted on a full scale model of the J.M. Farley Nuclear Plant Unit 1 in which all structural members, valves, restraints, stairs,
[
etc in the far field were modeled. The approach velocities past these members ranged from 0.02 to 0.5 fps for water depths above the containment floor ranging from 4.8 to 7.4 feet. Eddy shedding was very weak, resulting in only a ninor dimpling of the water surface in the eye of the eddy. 18 The maximum postulated approach velocity past far field components in the Midland containment is 0.5 fps.
Further documentation of the weakness of eddy shedding in i approach velocities of 0.5 fps or less was obtained during i tests for the San Onofre generating station. Structural l members placed in a 2 foot side flume were subjected to
- approach flow velocities up to 0.5 fps. Eddy shedding was l very weak. An additional test was conducted by placing a i
~
1 foot by 1 foot column in the flume such that the maximum velocity past the column was 1 fps. Even with this !
condition, the eddies shed produced only a dimpling of the l l
surface amidst the general turbulence produced by the memoer. ;
Other tests were made by placing 2-1/4 inch by 3/16 inch
! grating bars on 1-3/16 inch centers in the flume at angles up to 60 degrees to the direction of the approach flow. These ;
tests documented that: i
( A. The circulation generated by eddies shed from structural '
members with flow velocities passing them up to 1 fps f
was completely eliminated by the grating. Even air core j Q&R 6.3-71 Revision 30 10/80
Responses so NRC Questions Midland 1&2 03214-a vortexes forced on the upstream side of the grating by a j moving paddle were completely eliminated as the flow passed through the grating.
B. Flow exited from the downstream side of the grating in alignment with the grating bars irrespective of approach angle. The grating bars acted as flow straightening vanes.
i The trash rack for the Midland recirculation sump will be l 2-1/4 inch by 3/16 inch bars on 1-3/16 inch centers. Because l the maximum approach velocity past far field components in the Midland plant will be approximately 0.5 fps at a water l 18 depth of 3.75 feet, eddy shedding will be weak and ;
circulation associated with these eddies will be totally- '
removed by the trash rack, irrespective of the approach ;
angle.
Circulation generated by the plant configuration will be i removed uy the trash rack. Because circulation is an
essential feature of a vortex, no vortex will penetrate the trash rack f rom the f ar field. {
i The effectiveness of the Midland trash rack in eliminating i23 far field vortex formation has been demonstrated by actual ! 30 induced vortex testing as part of the sump model testing program. l23
- 2. The severity of a vortex is primarily a function of the I strength of circulation, the depth of submergence of the 19 intake, and the discharge. Application of the approach given by Dagget and Keulegan"' shows that the Reynolds number for ,
the Midland intake for a discharge of 6,000 gpm and a water temperature of 227F is 2.4 x 108 l32 l
For a given discharge, the severity of a vortex will be i reduced with an increased depth of submergence unless the strength of circulation in the approach flow is increased to offset the effect of the greater submergence. Situations ,
where vortexes have been more severe at increased depths of I water have resulted due to change in the planform of the , 19 geometry at higher water levels which in turn led to a !
stronger circulation.
There is no significant change in planform in the vicinity of the Midland recirculation sump over the 5.55 feet between 3
minimum and maximum postulated water levels (reference FSAR Figures b.2-58 and 6.2-58A). Because there will be a decrease in the strength of circulation at the higher water -
Icvels due to the reduction in approach velocities, there will also be a decrease in vortex potential. ,
Q&R b.3-72 Revision 32 1/81
Responses to NRC Ouestions 03214*a nidland 1&2 without any change in planform, the lowest submergence depth !
represents the severest potential for vortex formation. I
, Furthermore, the lowest water depth produces the lowest !19 ambient pressures in the sump and the greatest potential for the formation of vapor cores associated with vortexes generated within the trach reck.
- 3. Trash rack screen losses and intake losses have been l30 determined by measuring the piezometric pressures at the t following locations: i 1
A. At four points outside of and around the trash rach with !19 the four plezometer taps interconnected.
B. At four points within the sump, but outside of the grating cage, with the four piezometer taps interconnected. These were located near corners where 130 velocity heads will be negligible. !19 C. At six points on the intake pipe, 5.23, 8.23, 10.74, 13.24, 15.75, and 16.26 pipe diameters downstream of the
'30 intake, with each point consisting of two interconnected l19 piezometer taps. I The piezometer taps were connected to a bank of water l manometers. The manometer scales were graduated in 30 1 toot increments and were reauable to less than i
+0.003 foot. 119 The trash rack screen loss was determined by subtracting '30 the piezometric level in the sump from the piezometric level outside of the sump plus the approach velocity ;19 l
head.
The intake loss was determined by subtracting the 1 30 piezometric level measured 18.0 diameters downstreau of the intake plus the velocity head plus the friction loss 19 f rom the piezometric level measured within the sump. .
Discharges were measured through standard orifice plates 130 with a probable accuracy of +15. Differential '
piezometric levels will be measured by water manometers 19 with a reading accuracy of +0.003 foot. .
- 4. Refer to the Appendix 3A response to Regulatory Guide 1.79 l for a discussion of the in-plant test.
l30 1
- 5. FSAR Subsection 6.3.2.2.4.1 has been added in response to ' 20 this question. 126 I
'19 6 Tests were conducted at the prototype Reynolds number for two 130 reasons: 119 Q&R 6.3-73 Revision 30
-10/8C
032145 Responses to NRC Questions Midland 1&2 Ai To develop intake loss coefficients at the correct prototype Reynolds number 32 B. To provide conservatism in the tests to document vortex control With respect to vortex control, Dagget and Keule have shown that above an intake Reynolds number of 5 x 10' gan'" the vortex severity is a function of circulation number. Because the 39 discharge will be augmented above prototype flowrates to achieve prototype Reynolds numbers, the strength of circulation and, hence, potential severity of vortex formations will be increased.
Such testing thus provides considerable conservatism.
'"Dagg et , . L. C . and Keulagan, G.H., " Similitude Conditions in Free Surface Vcetex Formations," Journal of Hydraulics Division, ASCE, Volume 100, Number HYll, November 1974, pp 1565-1581.
Q&R 6.3-74 Revision 32 1/51
!sponsas to NRC Questions Midland 1&2 032145 Question 110.58 (3.9.6)
There are several safety systems connected to the reactor coolant system pressure boundary that have design pressures below the rated reactor coolant system (RCS) pressure. There are also some systems which are rated at full reactor pressure on the discharge side of pumps but have pump suction below RCS pressure. In order to protect these systems from RCS pressure, two or more isolation valves are placed in series to form the interface between the high pressure RCS and the low pressure systems. The leak tight integrity of these valves must be ensured by periodic leak f testing to prevent exceeding the design pressure of the low pressure systems thus causing an inter-system LOCA.
Provide a list of all pressure isolation valves included in your testing program. Also discuss in detail how your leak testing program will conform to the following staff position:
It is our position that pressure isolation valves be classified as Category A or AC per IWV-2000 and that they meet the appropriate requireuents of IWV-3420 of Section XI of the ASME Code excep t as discussed below.
32 Limiting Conditions for Operation (LCO) are required to be added to the technical specifications which will require corrective action, i.e., shutdown or system isolation when the final approved leakage limits are not met. Also surveillance requirements, which will state {
the acceptable leak rate testing frequency, shall be provided in the technical specifications.
Periodic leak testing of each pressure isolation valve s is required to be performed at least once each refueling outage, after valve maintenance prior to return to service, and for systems rated at less than 50% of RCS design pressure each time the valve has moved from its fully closed position unless justification is given.
The testing interval should average to be approximately one year. Leak testing should also be performed after all disturbances to the valves are complete, prior to reaching power operation following a refueling outage, maintenance and etc.
The staff's present position for the LCO regarding leak rate is that the leak rate must not exceed 1 gallon per minute for each valve. m This leak rate is established to ensure the integrity of the valve, demonstrate the adequacy of the redundant pressure isolation function and give an indication of valve degradation over a finite period of time. Significant increases over this limiting value would be an indication of valve degradation from one test to another.
Q&R 3.9-51 Revision 32 1/81
, Ras; sss to NRC Questions Midland 1&2 032145 The Class 1 to Class 2 boundary shall be considered the isolation point which must be protected by redundant isolation valves.
In cas2s where pressure isolation is provided by two valves, both shall be independently leak tested. When three or more valves provide isolation, only two of the va.'ves need be leak tested.
32 08 Leak rates higher than 1 gpm will be considered by the NRC if the leak rate changes are below 1 gpm above the previous test leak rate or system design precludes measuring 1 gpm with sufficient accuracy. These items will be reviewed by the NRC staff on a case-by-case basis.
Rasponse The following pressure isolation valves are included in the Midland valve testing program and classified as Category A or AC.
System F;ID M- Valve Number IWV-200 Category Pressurizer spray 401A 005 AC Pressurizer spray 401A 075 AC Prcssurizer spray 402A 032 AC ,.
Pressurizer spray 402A 075 AC Mckeup purification 403 Sh 2B 001 AC Makeup purification 403 Sh 2B 003"' A Makeup purification 403 Sh 2B 004 AC Mrkeup purification 403 Sh 2B 006"' A Mckeup purification 403 Sh 2B 0 2 8"'- A Makeup purification 403 Sh 2B 029"' A Mckeup purification 403 Sh 2B 030"' A Makeup purification 403 Sh 2B 031"' A 33 M keup purification 403 Sh 2B 049"' A M:keup purification 403 Sh 2B 051'" A MEkeup purification 403 Sh 2B 123 A Makeup purification 403 Sh 2B 128 A Mckeup purification 403 Sh 2B 130"' A Mckeup purification 403 Sh 2B 162 AC Mckeup purification 403 Sh 2B 163 AC Makeup purification 403 Sh 2B 164 AC Makeup purification 403 Sh 2B 165 AC Mckeup purification 404 Sh 2B 001 AC Mckeup purification 404 Sh 2B 003"' A Mckeup purification 404 Sh 2B 004 AC Makeup purification 404 Sh 2B 006"' A Mrkeup purification 404 Sh 2B 028"' A Makeup purification 404 Sh 2B 029'" A Makeup purification 404 Sh 2B 030"' A Makeup purification 404 Sh 2B 031"' A O&R 3.9-52 Revision 33 4/81
Responses to NRC Questions 032145 Midland 1&2 Makeup purification 404 Sh 2B 049"' A Makeup purification 404 Sh 2B 051"' A Makeup purification 404 Sh 2B 123 AC Makeup purification 404 Sh 28 128 AC Makoup purification 404 Sh 2B 130"' A Makeup purification 404 Sh 2B 162 AC Makeup purification 404 Sh 2B 163 AC Makeup purification 404 Sh 2B 164 AC Makeup purification 404 Sh 2B 165 AC Decay heat removal 410 045 A Decay heat removal 410 046 A Decay heat removal 410 048 AC Decay heat removal 410 049 AC Decay heat removal 410 050 AC Decay heat removal 410 051 AC Decay heat removal 410 052 AC Decay heat removal 410 053 AC Decay heat removal 410 093 A Decay heat removal 410 094 A Decay heat removal 411 046 A Decay heat removal 411 048 A Decay heat removal 411 050 AC Decay heat removal 411 051 AC Decay heat removal 411 052 AC Decay heat removal 411 053 AC Decay heat removal 411 054 AC Decay heat removal 411 33 055 AC Decay heat renoval 411 093 A Decay heat removal 411 094 A
'HThese valves are not at the Class 1 to 2 boundary; however, they satisfy the concern of protecting low-pressure system piping.
The valves in the makeup and purificatior. systems will be tested using the appropriate pressurization points and drains each refueling to meet the requirements of IWV-3420 of Section XI of the ASME Code.
Decay heat removal check valves 049 and 052 (P&ID M-410) and 050 and 053 (P&ID M-411) will be tested each disturbance using core i
flood tank pressure. Upstream observation of leakage will be measured through an appropriate vent or drain, and extrapolated to RCS pressure for comparison with the 1 gpm leak rate.
Decay heat removal check valves 050 and 051 (P&ID M-410) and 052 and 054 (P&ID M-411) will be tested each disturbance using RCS pressure and the leakage measured using the appropriate upstream vent for a leakage not to exceed 1 gpm.
Decay heat removal check valves 048 and 053 (P&ID M-410) and 050 and 053 (P&ID M-411) will be tested each disturbance using the discharge pressure of the decay heat removal pump to seat the O&R 3.9-53 Revision 33 4/81 t
s Rasponses to NRC Ouestions 032143 sidland 1&2 valves and the leakage will be measured using an upstream vent cnd the leak rate extrapolated to RCS pressure for comparison with the 1 gpm leak rate.
Decay heat removal valves 045, 046, 093, and 094 (P&ID M-420) and 046, 048, 093, and 094 (P&ID M-411) will be tested each l
disturbance using RCS pressure and the leakage measured using the cppropriate downstream vent for a leak rate below 1 gpm.
Auxiliary pressurizer spray line check valves 075 (P&ID M-401A) 33 cnd 075 (P&ID M-402A) will be tested each disturbance using RCS pressure and the leakage measured using the appropriate upstream vent for a leak rate not to exceed 1 gpm.
Auxiliary pressurizer spray line check valves 005 (P&ID M-401A) cnd 032 (P&ID M-402A) will be tested using the appropriate pressurization points and drains at RCS design pressure for a leak rate of less than 1 gpm.
Technical specifications for these valves will be included by cmendment.
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Q&R 3.9-54 Revision 33 4/81 i-i
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Hay 14, 1983 JFK 28-8; Mr H F Perla Pickard, Lowe and Garrick Inc 17840 Skypark Boulevard Irvine, CA 92714 I -
HIDLAND PROJECT -
COLD SHUTDOWN RISK CONTRIBUTION FILE 0929.2 UFI 02352(S) SERIAL 12206 During the April 29, 1981 meeting of the Design Review Board on cold shutdown capaoility with safety grade equipment, an item was discussed concerning manual actions outside the control root. Valves must be positioned manually at different times during the cold shutdown procedure; based on the availability of equipment and plant conditions.
As part of the ongoing probabilistic risk assessment of the Midland Plant, Pickard, Lowe and Garrick, Inc is requested to evaluate the manual actions outside the control room required for cold shutdown in the context of their impact on risk. Initially, the following questions should be answered:
- 1. What is the contribution to system unavailability of the following manual actions outside the control room which may be required to achieve cold shutdown?
- a. Selection and alignment of alternate borated water sources (BAAT, EBT)
- b. Alignment of the auxiliary pressurizer spray
- c. Alignment of the Decay Heat Removal System
- 2. How would system availability improve if these actions could be performed from the control room?
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' These questions were selected to permit utilization of the system failure analysis due to be completed in the near future with little, if any, special effort required. The impact of these manual actions outside the control room on overall risk will be addressed at a later date if this inquiry indicates that meaningful improvement in system availability may be possible by performing these manual actions from the control room.
oc0581-0345a102
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Serial 12206 2 Please feel free to criticize this approach and propose a suitable al. native if necessary. A reply is requested as soon as the required informati . has been developed.
2, e John P Kindinger For Louis S Gibson Section Head Nuclear Safety and Analysis Section CC DFJudd, B&W DFlewis, Bechtel DBMiller, Midland JRWebb, P-24-505 Q
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oc0581-0345a102
UNITED STATES
//ge NUCLEAR REGULATORY COMMISSION j WASHINOT ON, D. C. 20555 J/ i
"*032145 'APR 2 2 1981 cket Nos.: 50-329/330
.Mr. J. W. Cook
'Vice President Consumers Power Company 1945 West Parnall Road Jackson, Michigan 49201
Dear Mr. Cook:
SUBJECT:
TMI-2 TASK ACTION PLAN ITEM I.G.1 - SPECIAL LOW POWER TESTING
! NUREG-0694 "TMI Related Requirements for New Operating Licenses", Item I.G.1, requires applicants to perform "a special low power testing program approved by NRC to be conducted at power levels no greater than 5 percent for the purposes of providing meaningful technical information beyond that obtained in the normal startup test program and to provide supplemental i training". To comply with this requirement new PWR applicants have committed
! to a series of natural circulation tests. To date such tests have been performed at the Sequoyah 1, North Anna 2, and Salem 2 facilities. Based on the success of the programs at these plants, the staff has concluded that augmented natural circulation training should be performed for all future PWR operating licenses. This is to be implemented by including
- descriptions of natural circulation tests in your FSAR (Chapter 14 -
, Test Program). If they are not already included in your FSAR, i
Init the natural circulation tests and associated training should be included, either by modifying existing or adding new test descriptions in accordance with Regulatory Guide 1.70 (Paragraph 14.2.12). The tests should fulfill the following objectives:
Training Each licensed reactor operator (R0 or SRO who performs RO or SRO duties, respectively) should participate in the initiation, maintenance and recovery frcm natural circulation mode. Operators should be able to recognize when natural circulation has stabilized, and should be able to control saturation ma gin, RCS pressure, and heat removal rate without exceeding specified operating limits.
Testing The tests should demonstrate the following plani. characteristics:
l length of time required to stabilize natural circulation, core flow distribution, ability to establish and maintain natural circulation with or without onsite and offsite power, the ability to uniformly borate and cool down to hot shetdown conditions using natural circulation, and subcooling monitor performance.
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-2 APR 2 2 1981 032145 If these tests have been performed at a cc:nparable prototype plant, they need be repeated only to the extent necessary to accomplish the above training objectives.
Procedure Validation The tests should make maximum practical use of written plant procedures to validate the completeness and accuracy of the procedures.
The natural circulation tests require a source of actual or simulated decay heat. The tests may be perfromed during initial startup using nuclear heat to simulate decay heat, or may be performed later in the initial fuel cycle when actual decay heat is adequate to permit meaningful testing. If the test objectives are not compromised, pump heat during forced circulation operation coulo provide an acceptable source of simulated decay heat (e.g., the Loss-of-Onsite and Offsite A/C Test perfromed at North Anna 2).
Applicants who perform a natural circulation boron-mixing and cooldown test to demonstrate compliance with Branch Technical Position RSB BTP 5-1 may use tnat test to accomplish some or all of the above training and testing objectives.
This guidance is provided for all new PWR OL applicants. Regulatory Guide 1.69 and/or the Standard Review Plan will be revised at a future date to include natural circulation testing and the associated training. OL applicants should submit test descriptions in accordance with Regulatory Guide 1.70 Paraqraph 14.2.12 as part of their FSAR or an amendment thereto. Detailed test procedures should be made available for NRC review 60 days prior to scheduled test performance (see Regulatory Guide 1.68 Appendix B). When required by 10 CFR 50.59, a safety analysis must be prepared and distributed in accordance with the requirements stated therein.
Sincerely, l
( Robert L. Tedesco, Assistant Director l
for Licensing Division of Licensing l
I P00ROR3NAL a
, . ..~.
Mr. J. L'. Cock Y'ce President Consurers Power Company 1945 ** cst Parr.all Road 032II>5 '
. Jackson, Micnigan 49201 ,
I cc: Michael I. Mf11er, Esc. Mr. Don van Farowe, Chief Ronald G. Zamarin, Eso. Division of F.adiological Health Alan 5. Farnell, Esc. Departrent of Public Health Isham, Lincoln & Beale P.O. Box 33035 Suite A200 Lansing, Michigan 49909
, 1 Firs
- National Pia:a Chicago, Illinois 60603 James E. Brunner, Esc. William J. Scanlon, Esq. +
Consumers Power Company 2034 Pauline Boulevard i 212 West Micnigan Avenue . Ann Arbor, Michigan 42103 Jackson, Michigan 49201 U. S. Nuclear Regulatory Cor:nission i Myron M. Cherry, Esq. Resident Inspectors Office 1 IBM Plaza Route 7 Chicago, Illinois 60511 Midland, Michigan 48640 s
Ms. Mary Sinclair 5711 Su.nnerset Drive Ms/ Barbara Stamiris -
5795 N. River Midlano, Michigan 46640 Freeland, Micnigan 48623 Frank J. Kelley, Esq. '
Attorney General .
State of Michigan Environmental Protection Di~ision '
120 Law Bui1Hng Lansing, Michtgan 48913 Mr. Wendell Marshall '
Route 10 Midland, Michigan 48640 Mr. Steve Gadler **
2120 Carter Avenue :
,, St. Paul, Minnesota 55108 y
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