ML19271A686

Forwards Big Rock Nuclear Power Station Evacuation Time Estimates & Palisades Nuclear Power Station Evacuation Time Estimates, in Response to NRC 791129 Request.Repts Available in Central Files Only

ML19271A686
Person / Time
Site:	Big Rock Point, Palisades  File:Consumers Energy icon.png
Issue date:	07/23/1980
From:	Hoffman D CONSUMERS ENERGY CO. (FORMERLY CONSUMERS POWER CO.)
To:	Crutchfield D Office of Nuclear Reactor Regulation
Shared Package
ML18045A411	List: ML18045A410 ML19271A686 ML19327A225
References
NUDOCS 8008010300
Download: ML19271A686 (1)

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q (h I> %rI q) ; p, r a.n..i on.c..: 212 w.. u.cn.g.a Avenue. sac = on. uienigen 4emoi. Ar.. coa. si7 7ss-osso July 23, 1980 Director, Nuclear Reactor Regulation Att Mr Dennis M Crutchfield, Chief Operating Reactors Branch No 5 US Nuclear Regulatory Commission Washington, DC 20555 DOCKETS 50-135 AND 50-255 - LICENSES DPR-6 AND DPR,

BIG ROCK POINT AND PALISADES PLANTS - RESPONSE TO EVACUATION TIME ES"IMATES - SITE EMERGENCY PLAN Consumers Power Company was requested, by NRC letter dated November 29, 1979, to give information regarding estimates for evacuation of various areas around our Palisades and Big Rock Point Nuclear Plants.

Five copies of the Palisades and Big Rock Point evacuation time astimates, prepared by HMM Associates, have been sent to the NRC staff.

The results for the Palisades Plant show that evacuation clear time for the s

0-10 mile area is approximately 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> for both summer and winter conditions.

At our Big Rock Point Plant, the evacuation clear time for the 0-5 mile area is approximately 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> in the summer and approximately 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> in the wint er.

(Reference Consumers Power April 24, 1980 and NRC June 13, 1980 letterr for basis of 5-mile Emergency Planning Zone.)

David P Hoffman (Signed) h h

David P Hoffman

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Nuclear Licensing Administrator

• k CC JGKeppler, USNRC h

NRC Resident Inspector-Palisades b

NRC Resident Inspector-Big Rock Point 6gh

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Co::ents on SEP Review of Safe Shutdown Systems for San Onofre Nuclear C-enerating Station Unit 1 SEP Tonics V-10.B. V-11. A. V-11.B. VII 1 X 0

1.

Page 2, paragraph 1.

Hot standby conditions are 525 F 1 Tave 1540 F.

0 Cold shutdown conditions are Tave 1150 F.

2.

Page 6, paragraph 1.

The flash evaporator is removed from service before reaching 33 1/3% power (150 MW,).

3 Page 10, item 6 add:

"except when trip is fres electrical protection or re=ote turbine trip push button (see next paragraph)."

4.

Page 11, paragraph 2.

Rewrite the first sentence as follows:

" Prior to the cooldown, it is determined that the boric acid and pri=ary makeup water systems have enough capacity to co=pensate for the reactor coolant shrinkage."

5.

Page 11, nu=bered procedure steps.

Add as Step 1:

"1.

Berate the Reactor Coolant System to the cold shutdown concentration in accordance with approved instructions." Renu =ber the re=aining steps accordingly.

6.

Page 13, paragraph 1.

The normal operating pres ures for the various cooling syste=s are:

RHR 80 to 420 psig (465 =ax)

CCW 65 to 75 psig

( 80 max)

SWC 30 psig

( 50 max) 7.

Page 13, Section 2.2, paragraph 2, second sentence. Delete the phrase "When buses 1C and 2C are energized with diesel power" since the steam driven auxiliary feedwater pu=p should be used if a delay is experienced in re-establishing station power.

8.

Page 14, paragraph 1.

Operating Instruction S-2-13 Rev. 10, Auxiliary Feedwater System Operation, provides for aligning alternate water sources as required.

9 Page 14, paragraph 2.

As stated in the assess =ent, the 6000 kW diesel /generatcr units supply adequate power to bring the unit to cold shutdown in a "nce:al" =anner.

Step 4.11 of 0.I. S-3-5.30 Rev. 10, instructs the operator to place the unit in the appropriate condition.

No special instructions are required because of the loss of offsite power.

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23. Page 27, paragraph 4 Ch& Ige title 00 :

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26. Page 23.

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5.

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30. Page 31, pagagrapt 1.

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31. Page 31, paragra;n 1.

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. 33. Page 31, paragraph 3 Chang.

permits the depressurization" to "would result in depressurization."

34. Page 32, paragraph 2.

a.

It is planned to change the operaticn of the auxiliary feedwater pumps to automatically start on low steam generator level or by remote manual operation in control room.

b.

CV-113 can be opened and controlled manually so that air is not required to operate the turbine. The diesel-driven air compressor system is also available to supply air pressure.

35. Page 32, paragraph 3 The motor-driven AFP is designed to deliver 235 gpm at a dischat ;e of approximately 2450 feet (1060 psig).

36. Page 32 footnote. sequencer does not automatically perform breaker align =ent on loss-of-offsite power. Breakers are manually aligned.

37. Page 33, paragraph 1.

The flow ra*.e Tc.' the motor driven auxiliary feed pump is 235 gps.

This is sufficient to control and raise the steam generator level at approxi=ately seven to eight minutes after reactor scram. The turbine driven auxiliary feedpump flow rate is 300 gpm and is sufficient to control and raise steam generator level after three to four minutes.

36. Page 34, paragraph 3, Item 4.

The nor=al hotwell makeup line is 10" to 12" to 8" branch.

39. Page 35, Table.

Delete "3" AFP Isolation Valves" and add:

Eculement Location Oceration Power Sueelv MOV-1204 Turbine building Remote manual 480V SWGR #2 next to AFP G-10 switch in control room 3"-600-139 Between CS and Local manual None (3 valves) north end of the only turbine building The "4" Isolation Valve" in the emergency flow path is normally open and does not need to be moved for auxiliary feedwater system operation.

40. Page 36, paragraph 4.

a) The fire hydrants have been renumbered. Hydrant

1. 6 is now #9 and #7 is now #10. b) The 3" nipples are on the tank drain and fill lines, not on the overflow. Therefore, footnote // should be deleted. c) The comment made in footnote / is no longer applicable, as designated fittings, hoses and wrenches are now provided.

. 41. Page 36, Footnote 8 The nor=al makeup for the SWR is city water.

42. Page 38, paragraph 2.

A condensate pu=p may be powered from the emergency diesel / generator (s) following a loss of off-site power. This would allow condensate in the hotwell to be utilized for plant shutdown.

43. Page 39, paragraph 4.

It should be noted that RHR performance stated here is for both pumps and heat exchangers in operation. Degraded RHR operation is acceptable but will result in longer cooldown times. Normal RHR cut in is at 350 psig; 400 psig is maximum allowable.

44. Page 40.

FH-6 is now FH-9 and FH-7 is now FH-10.

FH-10 is in the Southwest corner next to the heater deck. FH-9 is located south of the turbine building. Delete the table entry " Portable Fire Hoses and Fittings."

The Main Condensate Pumps and Main Feed Pump power supply is 4160V, not' 2400V.

45. Page 41, paragraph 1.

Insert after the word " temperature", "(one pump and one heat exchanger)."

46. Page 42, paragraph 2.

Delete " bypass" frem the third line. The primary method of controlling cool down rate is by throttling HCV602.

47. Page 42, Footnote. The footnote is not correct. The heat removal rate of 16.1 x 106 BTU /hr per heat exchanger is based on conditions of RCS temperature of 1400F and not 3500F, as shown in line 1 of table on page 44.

Line 2 of that table indicates a total heat removal rate of 141 x 106 BTU /hr, well in excess c f 0.8% power.

Page 44, Table. For 2 RER pump /1 Hx operation, the shell inlet temperature has a typographical error (11920). This should be corrected.

48. Page 46, paragraph 2.

a.

If any one of MOV-813, MOV-814, MOV-833 or MOV-834 fails to open, the RHR is rendered inoperable. However, these valves are also equipped with hand wheels, which would allow the valve to be opened manually if the motor operator er power supply failed.

b.

The CVCS can be used in a " feed and bleed" mode to cool the reactor core with the vessel head in place.

49. Page 47 RCS/RHR MOVs are operable from the control room, at the breaker and manually at the valve by hand wheel.

50. Page 48, paragraph 1.

Add charging pump oil coolers to CCW heat loads.

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56. Page 55, paragraph 2.

There is a cross-tie line between t15-12"-KP1 and t16-12"-K?! such that either er both heat changer (s) (E-20 A cr E-203) tay be eccled by ficw frc: any cc:binati0n Of SWC? G-13A, G-133 and the ASWCP.

57. Page 56. Add the e:ergency air c:=;resser to ciscussion.

53. Page 57 table. All equip:ent is operable frc: the switchgear ree:. Bus 1C and Eus 2C are 41607. The screen wash pu=ps are c;erable locally at the pu:p. The auxiliary SWCP is located cutside, west of the ;t:; well, next Oc the tsunari wall, and is 0;erable fr== the centrol rc== cr its pcwer

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59. Page 59, paragra;h 1.

The SE7s are susceptible to the sa:e single passive failure (failure of the air headers) as the A0"s.

Air connections have teen cade to use the diesel-driven air supply.

60. Page 59, Fcotnote - the hockups have been =ade.

elete "and time schedule" frc: the second sentence.

61. Page 60, last paragra;n and fc0t:0te. The beric acid tank (EAT) and beric acid transfer pu:p (EAT?) are not required t0 terate the RCS fer cold

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63. Page 61.

The air receivers are Outside, just north Of the CST.

Air coc;ressers are c;erable frac the switchgear rec =.

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the syste= evaluation. It should be included in the Discussion and Redund ancy.

, 66. Page 66. There are no heaters in the Refueling Water Storage Tank. The power supply for the Boric Acid Tank heaters and heat tracing is MCC 1.

The Boric Acid Tank (BAT) is filled by local manual valve alignment and operation of the BATP thru CV-333 CV-333 is air operated. The BATP is powered from 480V MCC-1.

67. Page 84, paragraph 2.

330oF should be 350c.

c 422 psig should be 400 psig.

68. Page 85, paragraph 2.

The volume of the PRT is 8500 gallons with normal level of 6800 gallons.

69. Page 85, paragraph 2.

The two containment sump pumps should be used to drain the su=p, not the SIS recire pumps, since sufficient NPSH would not be available.

70. Page 86, paragraph 1.

If one RHR pump were operating, RHR flow to the RCS would decrease and the low flow alarm would alert the operator. However, if both RHR pumps were running, no low flow alarm would result since RHR flow to the RCS would be approximately 1557 gpm (2 x 1170 - 783 = 1557) and the alar is set at 1000 gps.

71. Page 86, paragraph 1.

Insert after " containment floor", "not designed for submerged operation."

72. Page 86, Evaluatien - To be consistent, "RHR" should be used instead of "SCS".

73. Page 87, paragraph 3 If any one (or any ecmbination) of valves MOV-813, MOV-814, MOV-833 or MOV-834 were shut, the 3/4" recire line would provide minimum flow to the RHR pumps. RER Pump G14A is now equipped with a 2" (5056-2"-S2) recire line. The 3/4" recire line would pass less than 1000 gpm and the low flow alarm would alert the operator to system misalignment.

74. Page 90, paragraph 1.

To adequately document review results, the basis for believing that adequate boron mixing occurs should be given.

75. Page 93, paragraph 2.

Section 4.2 does not state that the RHR relief valve does not provide sufficient relief capacity to protect the RER system from overpressure by the most severe postulated transient.

76. Page 100, paragraph 1, 2 and 3 As noted in previous comments, the auxiliary feedwater system is being modified to provide for both automatic initiation and remote (control room) operation.

77. Page 101, paragraph 2.

As part of the auxiliary feedwater eystem modification, additional instrumentation, namely auxiliary feedwater flow, has been added to the system and would allow the operator to detect an abnormal auxiliary feedwater system condition. These changes are shown in of this letter.

. 78. The following is a list of typographical errors:

E.agat Line currentiv Should Be 8

16 withdrawal withdrawn 20 2

109 106 25 13 p = 100 psig P = 1000 psig 25 Last 650 x 105 6.50 x 105 27 12 "be" is esitted aft er "=ay" 28 1

Delete "Du=p" 28 7

SDSC SDCS 36 6

these th e.~ e 36 17 from for 36 19 fir for 37 9

houses hoses 44 9

effect affect 45 3

PPo P/Pc 47 11 776-4"-754 776-4"-T54 51 9

delete the cc==a 57 5

G435 G43S 57 5

48) 480 59 12 EDVs EDGs 62 15 steam stream 66 20 elution elevation

Revised Operating Instructions San Onofre Nuclear Generating Station Unit 1 Operating Instruction Revision No.

Title 1.

S-3-1.4 9

Unit 1 Shutdown to Hot Standby Condition 2.

S-3-5.1 7

Emergency Shutdown 3

S-3-1.5 14 Plant Hot Shutdown to Cold Conditions 4.

S-3-5.28 7

Forced Evacuation of Control Room due to Fire Causing Loss of All Station Power and/or Normal Instrument Air 5.

S-3-5.30 10 Station Loss of Off-Site Power 6.

S-2-13 10 Auxiliary Feedwater System Opc. ration 7.

S-3-1.13 5

Reactor Shutdown From Hot Standby to Hot Shutdown

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. SAN ONOFRE Hl; CLEAR GENERATING STATION OPERATING INSTRUCTION S-3-1.4 Ih Revision 9 - July 26,1979 J

UNIT 1 SHUTDOWN TO HOT STANDBY CONDITION g. -- -., -. - n gs.g i I.

OBJECTIVE t.

[

To shut down Unit 1 from full load or any intemediate load to a hot standby condition of the primary plant and secondary plant to a generator-off-the-line, full vacuum, steam dump control of main steam at 930 psig condition.

II. CONDITIONS A.

Unit I is on the line at any electrical load.

EDM-SITE B.

The nuclear instrumentation: startup, intermediate, and power channels shall be operating normally or in a ready-to-operate condition.

C.

Auxiliary systems are in service as required for hot standby conditions.

III. PRECAUTI,0NS_

A.

P" plant changes which produce a sudden change in reactor coolant ccmperature of the order of 10*F or in reactor coolant boron con-centration of the order of 10 ppm must be avoided.

B.

Xenon level variations must be anticipated following a load decrease and boron concentration changes made as required to maintain the control group in the nomal operating band.

C.

Whenever reactor power is greater than or equal to 10% full. power, three (3) reactor coolant pwnps shall be in operation. Whenever r.eactor pc cer is less than 10% of full power, operation with less than three (3) reactor coolant pumps operating shall be limited to less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />; except durin ducted below 5% of full power.) g low power physics testing.

(Con-D.

The steam generator water levels should be manually controlled when in the hot standby condition and maintained at 50% level as indicated on the narrow range recorders to prevent the feedrings from being uncovered.

E.

Failure to place the feedwater controls on manual prior to tripping the turbine stop valves may result in a large volume of feedwater being added to the steam generators. This could result in cooldown of the reactor coolant.

F.

Isotopic analysis for iodine in the reactor coolant must be made.

between 2 and 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> following a thermal power change exceeding 115%

within a one hour period.

'. i s. k,i.'c i s

,N i eW. '-

~

c a.. m x -

I IV. CHECK-OFF LIST (Not Applicable)

V.

' INSTRUCTIONS g

(

M' KEY POINTS IMPORTANT STEPS 1.

Inform System Dispatcher and Switching

1. The Dispatcher and Switching Center the unit is ready to reduce load, Center should be informed as estimated time of going off the line, far in advance as practicable and the rate of load reduction.

when preparing to take the unit off the line.

3008060 %

SAN ONOFRE NUCLEAR GENERATING STATION OPERATIN3 I:J R"CTION S-3-1.4 REVI3 ION 9 July 26, 1979 Page 2 IMPORTANT STEPS KEY POINTS 2.

Reduce load on the unit.

2.

a.

Mark charts as per 0.I.

5-12-11.

3.

On load reducticn, observe 3.

alares and recorder indica-tions.

a.

Alar: " Alert-Switch NIS Mode of Operatien to tiid-Range".

b.

Change mode of operaticn switch frcn High to itid.

4.

At less than 70t lead, re-4.

See 0;eration Instructicn move reheater steam dump S-9-2.

system frcm service.

5.

Remove flash evaporators 5.

Refer to 0.I. 5-2-5.

from service.

6.

Borate as necessary to keep control rods above shutdown cargin.

7.

Unit at 33% of full load.

7 a.

Observe operation of reheater controls.

b.

125'F/hr. maximu= rate of temperature change on cross-over 8.

Unit at 20t of full load.

8.

a.

a.

(1) Transfer reactor over-power code of operation from Mid to 1cw positien.

(2) Transfer red control from automatic to canual.

(3) Transfer feedwater to manual control and slewly increase level to 50t as indicated en the narrow range recorders.

(4) Transfer steam dump ecde switch from automatic to pressure control at 930 psig set point.

~

SAN ONOFRE NUCLEAR GENERATING STATION OPERATING INSTRUCTION S-3-1.4 Ravision 9 -July 26,1979 Page 3 IMPORTANT STEPS KEY POIfRS 8.

(continued) 8.

(continued) a.

(5) Open turbine drain valves and extraction trap bypasses.

b.

Transfer 4160 volt bus b.

(1) If the 220 kv and 138kv 1A and 1B from the unit switchyards are con-auxiliary transformers nected, transfer by to station auxiliary parallel operation.

buses 1C and 2C (refer to 0. I. S-6-5).

(2)

If the 220kv and 138kv switchyards are not interconnected, transfer by drop and pickup operation.

c.

Stop heater drain pumps 9.

Reduce unit load to minimum on 9.

load limit.

a.

Under manual control, insert control rods to maintain avg Tavg between 535' and 540*F.

b.

Verify that steam dump or pressure control is regu-lating for a stable reactor power level.

10. Below 10% of full load, reduce 10. Stop a feedwater pump and a con-feedwater pump and condensate densate pump.

pump requirements

11. Start turbine auxiliary oil Pump.

12. Notify Dispatcher and Switching 12.

Center that unit is ready to a.

The Dispatcher and Switching take off the line.

Center should be infomed of status of unit. The Dis-patcher gives permission to

~

take unit off the system.

b.

Take the power system stabilizer and voltage regulator out of service.

s

~

SAN ONOFRE NUCLEAR GENERATING STATION OPERATING INSTRUCTION S-3-1.4 Revision 9 - July 26,1979 fage4 IMPORTANT STEPS KEY POINTS

12. (continued) 12.

(continued) c.

If turbine tests are plan-ned, remove unit from lir.e by opening unit PCB's.

d.

If no tests are planned, reduce steam flow to zero and allow unit to be removed from service by no-load and anti-motoring circuits.

13. Turbine-generator on turning 13.

gear.

a.

Verify unit automatically on turning gear, and field breaker open.

b.

Lube oil cooling set points changed from 115*F to 85'c.

c.

Turbine hood sprays on tempera-ture control.

14. Complete switching to provide 14.

an alternate source of auxiliary a.

Notify Switching Center of electrical power.

switching procedure.

5.

Check open Unit 1 PCB's and 4160V ACB's 11A04 and 11B04.

c.

Open the generator motor operated disconnect.

d.

Close unit PCB's

15. Maintain reactor nuclear power 15.

a.

Adjust reactor makeup con-level <10% of full load power.

trol to automatic et reactor coolant boron concentration for leakage requirements.

b.

Periodically initiate pres-surizer spray flow to adjust boron concentration.

16. Reduce primary and secondary a.

11 ark charts as per 0.I.S-12-11.

plant auxiliary requirements.

SAN ON0FRE NUCLEAR GENERATING STATION OPERATING INSTRUCTION S-3-1.4 Revision 9 - July 26,1979 Page 5 VI. FINAL CONDITIONS The final conditions of hot standby are:

A.

The reactor power level is being maintained by manual control of the contro111r.g group of rods at <10% of full power by observ-ing the nuclear intermediate channels and maintaining Tavg between 525* - 540*F. The pressure control of the main coolant will be automatically controlled and maintained at 2085 psig.

B.

Secondary plant (turbine-generator and auxiliaries) is in a ilot standby condition with the unit on turning gear, steam seals on, nomal vacuum, steam generator levels manually controlled at 50%,

and a minimum number of auxiliaries in operation. An alternate source of auxiliary electrical power is available.

R. R. BRUNET SUPERINTENDENT UNIT 1 APPROVED:

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. at. W J. M. CURRAN PLANT MANAGER JER:sel

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