ML20040A664
| ML20040A664 | |
| Person / Time | |
|---|---|
| Site: | Midland |
| Issue date: | 12/21/1978 |
| From: | Office of Nuclear Reactor Regulation |
| To: | |
| Shared Package | |
| ML111090060 | List:
|
| References | |
| FOIA-80-515, FOIA-80-555 NUDOCS 8201210376 | |
| Download: ML20040A664 (3) | |
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040.106-Your response to question 040.99 provided Figure 9.5-32 which (9.5.4) shows the emergency diesel fuel oil piping from the storage tanks to and from the day tanics. Considering the fact that there has been some settlement of the diesel generator building:
a) discuss the criteria and tre considerations taken in the design to prevent significant affects of this settlemnt on the ' diesel generator fuel oil lines located under the diesel generator building.
b) discuss the methods of monitoring to assure that the fuel. oil lines under the diesel generator building perform their safety
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function satisfactorally in light of the settling problem.
04a107.
As explained in issue No.1 of HUREG 0138, credit is taken for all (10.3) valves downstream of the MSLIV to limit blowdown of a second steam generator in the event of a steam.line break upstream of the MSLIV.
The design of Midland 1 and 2 includes valves for idolation and routing of steam to the Dow Chemical Ccmpany process steam evaporators.
In order to confirm satisfactory performance following a steam line
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break:
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Expand section 10.3.2.2 in reference to Figure 7.7-11, Table 7.7-2 and Figure 10.3-3 to provide additional infonnation and l
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2-discussion on the block and stop valves.
In reference to
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I Figure 7.7-11 for block valves ~ No. 3, 4, 7, 8, 9 and 10 which receive Class 1E MSLI signals, provide the following information:
a) the type of valves s
b) size of valves c) the quality of the valves l
t d) the design code of the valves e) the load combinations considered for the valves f) the corresponding allowable stresses g) the applicable qualification tests f
s,
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h) the actuating mechanism of the valves
-1) the c1osure tin.e'of the valves j) comparison'of the block valves listed above with the turbine stop valves No. 11,12,13 and 14 shown on Figure 7.7-11.
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- 2) Unlike Unit 1, Unit 2 does not have main steam block valves before the turbine stop valves directly in series after the MSLIV's.
Expand section 10.3.2.2 and Table 10.3-5 in refererce to Figure 10.3-3 for Unit 2.
For the various flow paths of Unit 2 that branch off between the MSLIV's and the turbine stop valves, provide the following information as applicable:
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I a) the maximum steam flow in each flow path (coordinate ;with question 211.I85, item 2).
b) the type of valves t
c) the size of valves d) the quality of the valves e) the design code of the valves f) theclosuretimeofthevdives
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g) the actuation mechan, ism of the' valves.
Add this informathn to Table 10.3-5.
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WASHINGTON, D. C. 20555 DEC 271978 Docket Nos.
50-329/330 MEMORANDUM FOR:
D. B. Vassallo, Assistant Director for,WRs, DPM l
FROM:
R. L. Tedesco, Assistant Director for Reactor Safety, DSS I
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SUBJECT:
SECOND ROUND QUESTIONS - MIDLAND PLANTS UNITS 1 & 2 1
o Plant Name:
Midland Units 1 & 2 Docket Numbers:
50-329 & 330 2
Mil'estone-Number:
12-21 Licensing Stage:
OL Responsible Branch LWR-4 and Project Manager:
Darl Hood Systems Safety Branch Involved:
Reactor Systems Branch Description of Review:
Supplemental Questions Requested Completion Date:
December 1, 1978 l
Review Status:
Incomplete Reactor Systems Branch received the applicant's responses to our supplemental questions on November 17, 1978.
Due to the short time available before 12/1/78 due date, review of the information provided is not yet complete; however, we have enclosed positions and questions in several areas for which we have determined that additional information is
.( ;g necessary. The applicant has not yet provided complete responses but has committed to future submittals in many areas (see Enclosure 2). The Midland schedule is being compromised since we would anticipate follow-up t
questions / discussions to be necessary. Otherwise, the RSB input to the i
SER due 3/1/79 would contain an inordinate number of open items.
In several l
areas, the applicant has responded by takirjl; exception to our position.
f These items will be left open in our safety evaluation unless resolved prior to its formulation.
Our position on several of these areas are provided in
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We met with the applicant on December 11, 1978 to hear their appeal of our position regarding the capability of the Midland units to achieve a cold shutdown condition.
Clarification of our requirements are attached in
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t question 211.187.
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dh Robert L. Tedesco, Assistant Director l
for Reactor Safety i
Division of Systems Safety
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Contact:
Scott Newberry, NRR i
49-27341 f
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D."8. Vassallo.
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Enclosures:
8 1.
Second Round Questions
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2.
Incomplete Response List-t t
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S. Hanauer R. Mattson S. Varga
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D. Hood R. Tedesco'
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S. Israel G. Mazetis i
S. Newberry N
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i RSB Round Two Questions / Positions Midland Units 1 & 2 211.176 The response to questio.n 211.147 provides the initial conditions k) for BAW-10043 to show that it " brackets" the Midland units; It is N
not clear that BAW-10043 bounds the Midland units. Comparison of parameters from the Midland FSAR and your response is as follows:
(RSP) 2l BAW-10043 Midland FSAR_
Core power 3105 MWT (112%)
2452 (100%)
Pump Heat 16 MWT 16.MWT 6
6 RCS Flow Rate (Ib/hr) 137.9x10 126.3x10 r
Pressurizer Code Safety 690,000 595,690 Valve Capacity (1b/hr)
Secondary Safety Valve 13,680,000 12,484,520 Capacity (1b/hr)
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The effects of less flow and relief valve capacity are not obvious
/D relativd 'to the lower power level.
Submit a plant-specific over-
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pressure valve sizing calculation for Midland. Also, the analysis should assume that the reactor scram is initiated by the second safety grade signal from the reactor protection system.
211.177 The response to question 211.131 does not satisfy w= concern
,f7) with respect to the detection and isolation.of passive ECCS failures (RSP) during the long-term cooling phase after a LOCA. Although the test report addressing injection pump seals indicates that seal integrity was maintained for the conditions under which they
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were tested, we do not concur with your proposal for LPI seal leakage of 500 ml/ min to serve as the bounding leak rate for a l
passive failure following a LOCA (valve stem packing or pump seal failure). Operating data indicates that leak rates in I
excess of your proposal have occurred.
" Bounding" leak rate assumptions on the order of 30-50 gpm have been accepted by the f, _,,
staff in the past; therefore, we require that you show that the v
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ECCS equipment layout, room water level detectors and airborne k
5 7) radiation monitors in the Midland plant meet the criteria listed l
N in question 211.47 assuming leakage rates of this magnitude, or
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revise your design accordingly.
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4 211.178 The response to our position in question 211.129 does not provide.
63) assurance that the single vent on the BWST is adequate since:
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1 1.
It is on top of the tank and would be susceptible to i
l blockage due to snow build-up.
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2.
No heat tracing is provided on the vent.
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3.
Your response does not describe the " screen inside the BWST" which is heated.
We require that a BWST vent configuration be provided which will I
preclude vent blockage due to icing or snow accumulation.
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211.179 The response to question 211.126 states that flow indication j
in the. " dump-to-sump" lines is not necessary. Our position is that the operator must be provided with flow indication to confirm that at least the minimum required, dilution flow exists subsequent to a LOCA.
211.180 The response to question 211.106 states that the alarm provided 5) in the control room to detect a reactor building sump level increase corresponding to 1 gpm leak within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> will be generated by the,
plant computer.
Since the plant computer may not be available at all times during plant operation, we require that an alarm be provided in the control room which will be available at all times.
b 211.181 The response to question 211.113 states that extended operation (6.3) of the Decay Heat Removal pumps at flows less than 800 gpm would result in damage to the pumps.
(This was your basis for not using l
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continued recirculation through the DHR heat exchanger and
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recirculation line to protect the DHR pumps from closure of
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asuctionvalve). Confirm, with basis, that the low pressure 3
l injection system will perfonn its function in the piggyback 2
mode, since the LPI (DHR) pump flow will be less than 800 gpm.
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211.182 The response to question 211.103 does not meet our requirements f
with respect to check valve leak testing.
The proposal to test two valves in each of the Core F1'ood and Low Pressure' Injection 1
Lines is acceptable for these systems, however, we require that j
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at least two check vilves in each of the high pressure injection lines be tested also. This should be done by classifying these valves as AC in accordance with Section XI of the ASME Code.
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211.183 The response to question 211.152 does not satisfy our concern 5
.6) that dilution events could occur at rates less than the makeup 3
i flow rate alarm setpoint, and would not be detected.
Although these events would take longer than 30 minutes to reach criticality, no indication would be'provided from the high 4
makeup flow alarm to alert the operator so he could terminate the event. We require that the operator have adequate time i
af.ter indication of the event in accordance with the following I
criteria.
4 Plant Condition Time Prior to Criticality After Indication Refueling 30 minutes Startup, cold shutdown, hot 15 minutes
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standby, and power operation Provide assurence that these criteria are met or revise your design accordingly.
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During the recent review of the loss-of-offsite-power 211.184 (G_j 05.2) preoperative test procedure for another B&W plant, a concern was developed regarding the control of OTSG level by the auxiliary feedwater system during the event. Specifically, overcooling of the primary system could res' ult from feeding the OTSG with the i
cold auxiliary feedwater. The cooldown could be large enough to t-t cmpty the pressurizer and cause a steam bubble to form in the hot I
j leg high points, which could impede natural circulation and core
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cooling. Address this concern for the Midland units.
Provide the results of an analysis of a loss-of-offsite power assuming 5
f the worst-case initial conditions (low power appears.to be worst since programmed steam generator level is lowest).
Include plots of steam generator level, reactor coolant system temperature and pressurizer level. Discuss your assumptions regarding auxiliary feedwater control.
Show that MDNBR will remain above 1.30 and core cooling will not be ' impaired.
-N 211.185 The response to question 211.157 regarding worst case single failure f r a main steam line break is insufficient. The analysis should i
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(RSP) consider the following:
- k 1.
Inadvertent atmospheric dump valve opening 2.
Steam flow through all unisolated lines down stream of the MSIV's (Unit 2). Table 10.3-5 indic'ates that.all. lines are not isolated after a steam line break assuming the single failure of 1 MSIV.
3.
Process steam cross-connect valves opening, (see question 211.160) unless power will be removed.
Provide your basis for stating that 1 HPI pump is the worst single failure with respect to overcooling.
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Provide the worst single failure with basis for the worst DNB l
Ni main steam line break.
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21 86 Confirm that the bounding Midland Chapter 15 accident and f15.1.5)transient analyses consider all events which could occur _ in
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Modes 1, 2, 3 and 4 as defined in FSAR section 7.7.1.6'.2.2.
We require that all modes of operation be considered in your f
analysis (i.e., Unit 1 NSSS supplying Unit 2 turbine) and specifically defined in the Midland Technical Specifications.
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211.187 We met with you on December 11, 1978 to hear your appeal of our position regarding the capability of the Midland units to a'chieve n) a cold shutdown condition. Our requirements are listed in question 211.35.
Your position was that hot shutdown was a safe shutdown condition and that the Midland units could not reach cold shutdown with equipment previously qualified as safety grade, assuming loss of offsite power and.a single failure. We informed you that your position was not acceptable and that more work was necessary to satisfy uur requirements. The following additional guidance was 7,
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provided at our meeting:
1.
Repair and maintenance of equipment is acceptable if reasonably justified.
2.
A reasonable time period to reach cold shutdown would be acceptable.
3.
Additionalanalysiswithr.especttoseisdicqualification of systcms may be acceptable.
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4.
A natural circulation cooldown test is required.
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Operating procedures are required.
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We require that you provide information to show that the Midland l
I units meet the cold shutdown requirements of question 211.35 as modified with this additional guidance.
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Responses Not Complete:
k 1.
Missiles Inside Containment (211.95) l 2.
Reactor Coolant Pump Mounting (211'100) 3.
Pressurizer Safety Valves (211.104) 4.
Appendix G Overpressure Protection (211.105) 5.
Pressurizer Heaters (211.112) 6.
HPI I.ine Break Analysis (211.117) 7.
LOCA - Reactor Coolant Flow Input (211.119) (O 8.
BPRA and ORA Modifications (211.138)
/9. Decrease in Feedwater Temperature Analysis (211.143)
- 10. Locked Rotor Accident Analysis (211.149) w
- 11. Loss of Flow Transient Analysis' (1 Reactor Coolant Pump) (211.150) L 12.
Feedwater,LineBreak(211.153)
- 13. Main Steam Line Break Operator. Actions (211.161) W
- 14. Main Steam Line Isolation Valve Closure Analysis (211.164)
- 15. f'ain Steam Line Break (stuck rod assumption) (211.166-211.175)
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- 16. Overpressure Protection Report - BAW-10043 (211.147) e i
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