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consumers Power company

General Offices: 212 West Michigan Avenue, Jackson, Michigar. "'·92C1 .. Area CoCe 517 789-0550

May 8, 1979

Director, :Nuclear Reactor Regu1ation Att .Mr Dennis L Ziemann, Chief' Operating Reactors Br011ch ~k· 2 T3S lfuc:ea1· P.e~illa.torjr Gor!H!t~s s ion Washingtcn, DC 20555

DOCKET 50-255 - LICENSE DPR-20 -?.l'l..LISADES PLANT - RAPID RESPONSE TO NRC FOLLOW-U? QUESTIONS CONCERNING rr.tiE TMI I.1.IJ"CIDEi:fr

Consumers Power Company'·s response to NRC q_uesi:ions receivecl by telecopy on May T, 1979 are attached. These responses may not be totally complete due to the limited amount of time available to meet the NRC req_uested. May 8, 1979 suomitta.l. Consl..uners Power will oe prepared to discuss these :i.ssues at the :May 12, 19!9 meeting in :Bethesda.

R B DeWitt Manager Production-Nuclear

David P Hoffman Assistant Nuclee..r Licensir..g Afu:Jinistrator

CC JGKepp1er) USNRC

79 0511 OD~-~ (

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ATTACHMENT I

Provide written response to the following set of questions by 5/8/79.

Describe backup systems available (to auxiliary feedwater) for providing feed­water to steam generators. Discuss actions and time required to make these systems available. Are procedures available? If so, provide.

1. Provide the foll9wing procedures:

a. Loss of offsite power. b. Loss of feedwater. c. LOCA (small and large). d. Steam line break.

2. Provide following information for PORVs:

a. b. c. d. e. f. g.

h.

Number. Capacity. Setpoints (open and close). Manufacturer and model. Indications of position. Record of periods isolated (isolation valve shut). Challenges during life of plant (from plant records), including performance of valve, cause of challenge . Experience of two-phase or subcooled discharge of PORVs and safety valves with description of valve performance.

3. Provide indications of PORV isolation valve in the control room.

4. Provide the following information on ECCS:

a. Initiation setpoints. b. System description. c. Pump performance characteristics (head curves).

5. Provide reactor protection system trip setpoints.

6. Provide information on charging pumps, how they relate to ECCS including:

a. Number. b. Flow vs pressure. c. Power sources and backup. d. Water sources e. Seismic qualification

7. List all challenges (and cause) to ECCS as indicated on plant records.

8. List and discuss all instances during which your plant has undergone natural circulation .

9. Describe all automatic and manual features which can stop the reactor coolant pumps.

144

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• ATTACHMENT II

1. Procedures

Copies of the requested procedures are attached (Attachment III).

2. PORV Information

a. There are two PORV's.

b. Each has a capacity of 153,000 lb/hr at 2385 psig. Tav 250°F Tav ( 250°F

c. Open: 2385 400 psia Close: not checked not checked

d. Manufacturer: Consolidated Dresser Model: 2 1/2" 31533VX Electromatic Relief Valve

e. A position switch mounted on the value is actuated when the pilot valve is positioned. See the attached drawing (950Y228, Rev. 5).

f. Between 1972 and 1977 the PORV's were isolated. Since 1977, the valves have been isolated whenever Tav was greater than 300°F.

g. These valves have never been challenged.

h. There are no known instances of two-phase or sub-cooled discharge of PORV's or code safety valves •

3. Position indication of the PORV isolation valves (MO 1042A and MO 1043A) is provided by lights on main control console C02. A limit switch on each valve provides the input. Indication receives its power from the same source as the valve motors (480 Volt). See the attached drawings (E-242, Sh 4, Rev. 8, and E-100, Sh 1, Rev. 17).

4. a. ECCS initiation setpoints are provided on the attached Table 3.16.1 from the Palisades Technical Specifications.

b. The system description is attached.

c. Pump performance curves are attached.

5. RPS trip setpoints are provided on the attached Table 2.3.1 from the Palisades Technical Specifications.

6. Charging pump information

a. There are three charging pumps.

b. The pumps are of the positive displacement type; capacities are as follows:

P55A: Variable P55B and P55C:

- 33 to 53 gpm - 40 gpm each

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• ATTACHMENT II

6. Charging pump information (Cont'd):

c. The pumps can be powered from either station power or off-site (startup) power, with backup power supplied from the emergency diesel generators.

d. Water sources are:

Volume Control Tank. SIRW Tank. Concentrated Boric Acid Tank (concentrated or blended).

e. The CVCS system is Seismic Class I (FSAR, Section 9.10.1)

7. A review of records for 1977, 1978 and 1979 was conducted to determine· when safety injection was initiated. The results are tabulated below:

DATES

12-18-78 1-28-79 2-2-79

. 4-7-79 4-25-79

CAUSE

Low pressurizer Pressure due to rapid PCS cooldown following plant trip.

REMARKS

PCS pressure did not go below shutoff head of HPSI pumps.

8. A record review conducted to the extent possible showed that natural circulation was used on the following occassions:

DATES

8-29-74 2-10-78 4-8-78

9-24-77 11-25-77 12-11-77

REMARKS

These three instances' of natural circulation occurred pursuant to the performance of a surveillance.· test (R0-8). This test is performed to verify operability of ESF equipment under postulated accident conditions.

These instances of natural circulation-occurred pursuant to plant trips caused by loss of the 'R' bus. Boron sampling of the PCS under these conditions demonstrated that natural circula~ion was adequate to cause mixing of the boron.

9. Primary coolant pumps can be manually stopped with hand-switches located on the control console in the Control Room, or by local operation of the pump breakers.

Automatic trips are as follows:

TYPE DEVICE NO PRINT NO

Undervoltage 227X-l E-137, Sh 1, Sh 2 227X-2

Overcurrent 250 E-130, Sh 6 251

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ATTACHMENT II

Automatic trips are as follows (Cont'd):

TYPE

Differential Current

Ground overcurrent

TITLE

Primary Coolant Pumps

DEVICE NO

287

250G

The above-referenced drawings are attached .

• PRINT NO

E-130, Sh 6

E-130, Sh 6

Page 3

PRINT NO

E-183, Rev 4

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• D4.3

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•••

• PLANT OPERATING PROCEDURES

LOSS OF A-C POWER

This section pertains to a complete loss of outside electrical

power which either results in or accompanies a plant trip from

power operation .

. Symptoms:

a. Complete power failure to most load distribution centers,

start-up transforme~ power not available.

b. Low bus voltage indications and alarms on all bus sections.

c. Any or all of the following indications or alarms may be present:

1. Reactor and turbine trip .

2. D-C lighting energized.

3. Diesel generators start.

4. Primary coolant pump trips, low coolant flow alarm and

trips.

D4-4

Rev 18

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• Auto:

a. Turbine and reactor trips initiated if not already present.

b. Turbine trip signal 9r loss of standby power starts diesel

generators.

c. Load shed relays clear loads from 2400 volt buses, if unit is

tripped, standby power is lost and diesels start.

d. Diesel generator breakers close to energize buses, if load shed

relays clear the buses.

e. Normal shutdown sequencer starts when diesel generators are

up ~o voltage and closed to buses.

Immediate:

a. Verify reactor and turbine tripped; manually trip if necessary.

b. Insure all full-length control rods are inserted into core and

that reactor power is dec~easing.

c. Insure the following functions have occurred, initiate any that

have not:

1.

2.

Normal and start-up feede.f breakers open to all 4160 and

2400 volt buses.

Proper load shedding has occurred.

3. .. Diesel generators aut.omatic start, and bus lC & 1D energized.

4.

5. 6.

Steam dump valves open and limiting steam pressure to 885 psig.

Bypass valve closure when condenser vacuum is lost.

Feed-water turbine trip on loss of condensate pumps.

d. Insure d-c battery power is available.for lighting, controls

and vital instrumentation.

e. Start auxiliary feed pump turbine to return SG levels to normal.

f. Check status of 345 kV lines and take any action possible to

restore start-up transformer supply to service.

g. If make up demin regeneration was in progress, manually isolate

it effluent until power can be restored, to prevent contamin­

ation of storage tanks .

D4-5

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\ • Subsequent:

a. Verify proper load shedding of lC and lD buses and subsequent

starting of service water pumps, charging pumps and cooling

fans on diesel power via normal shutdown sequencers.

b. Establish full charging flow capability and take necessary

action to restore pressurizer water ·1evel.

c. If outside a-c power remains unavailable, proceed as follows:

l. When diesel generator is available for further loading:

{a) Insure operation of and proper pressure from turbine

and generator a-c oil pumps.

(b) Energize equipment as may be required for plant

safety and· orderly shutdown within diesel generator

load limitations.

(c) Insure fuel oil transfer pumps start and verify flow

to day tank.

(d) Energize main turbine turning gear .

2. Insure the primary coolant pump d~c oil lift pumps secure ,( .

automatically after five minutes operation.

3. Secure the secondary system.

4. Maintain steam generator water supply with steam driven

auxiliary feed pumps when necessary.

5. Utilize steam dump valves to control Tavg at 532°F to 535°F . 6. If outage is to be prolonged:

{a) Borate primary system to shutdown concentration.

(b) Begin plant cooldown, and place makeup demins in

service. If demins are not aYailable, and condensate

storage tank is depleted, open CV bypass valves to

both CST and PMW, allowing PMW to flow to CST.

7. Restore systems to normal as available diesel power permits:

(a) Establish cooling flow to primary coolant pumps.

(b) Reenergize heat tracing on the CVCS piping.

(c) Restore pressurizer level to no-load level by charging

borated water.

(d) M=lintain pressurizer pressure above saturation by use

of heaters.

D4-6

·b4·_4

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D4.5

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~ .• Symptoms:

Any one or more of the following indications or alarms may be present:

a. ·Primary coolant pump trip.

b. Low flow reactor pretrip or trip.

c. Turbine trip.

d. Generator trip.

Immediate:

Manually trip reactor if necessary and follow up per reactor trip

Procedure D4.l.

Subsequent:

In addition to normal reactor trip follow up:

a. Monitor loop flow reates, pump amperage, loop temperatures and

reactor power levels for possible unstable or abnormal contitions.

b. Determine cause of failure before returning to power.

LOSS OF FEEDWATER

Symptoms:

Any one or more of the following-indications or alarms:

a. Feedwater pump turbine driver trip.

b. Condensate pump trip .

c. i Low condensate pump discharge pressure.

d. Low feedwater pump suction pressure.

e. Heater drain pump trip.

f. Heater drain tank low level.

g. Low steam generator level.

h. Low feedwater flow.

. , , .

i. Low SG level pretrip alarm (RPS).

Au'to: ; :. ·~ :: ·.:. . .,> il :.~ ';: :i ~ .:.;, ~ ~. ·--~-::· .i ··~ ,~· .. ~···.: :·~· .... ~~

;~~~'(" i

Several automatic functions may accompany a low feed flow situation:

a. A condensate pump trip will initiate a trip on the corresponding

FW pump turbine.

b. Low FW suction pressure will open full heater drain pump capacity

to the FW pump suction.

c. Low flow FW suction pressure trips both FW pump turbines.

d. Reactor trip on SG low level if situation continues.

Immediate:

a • If one feedwater pump or condensate pump is lost:

1. Increase speed of operating feed pump to restore steam

generator level.

D4-:-7

Rev 20

PRC 10/4/78

AT>PR ./ii .tU" I \ c :- - ,.--<" ;--.,.

'· .•

.2. Reduce turbine and reactor power level at the maximum

• rate to below 60% load.

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D4.6

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3. Trip the reactor and turbine if SG level cannot be main­

tained above low level pretrip alarm and proceed with

Section b below.

b. If all main feed flow is lost and cannot be restored, manualiy

trip the reactor. Follow up trip per reactor trip _Procedure D4.l

with the following additional' actions: ·

1. Start with motor driven auxiliary feed pump to maintain

SG water level. Auxiliary feed flow must be established

within 10 minutes to avail boiling the steam generators

dry. Minimize cycling auxiliary flow to avoid repetitive

thermal shock.

NOTE: Steam generator refill rate shall not exceed 100 gpm

if steam generator level :'Strip point has been

experienced for ::::. 1 minute and power level was ::: 75% F .P.

If prior power le~el was~ 75% F.P. refill rate may be

increased to 150 gpm provided the S/G level was=:: trip

point for> 15 minutes and the level must be maintained .(

~ 6%. To increase level over 6%, feed rate must be

reduced to < lOOgpm.

2. Secure three of the primary coolant pumps. If possible,

operate pump lB or 2A for maximum pressurizer spray.

Subsequent:

a. Continue operation of the motor or steam driven auxiliary pumps.

CAUTION: Do not add f eedwater to a dry steam generator except in

extreme: -emergency .. -The number -of. such cycles is very

limited.

b. If adequate feedwater cannot be supplied or one steam generator

goes dry, initiate emergency boration Procedure SOP2A.6.13 and

cool do'Wn the Primary System with the water volume left.

LOSS OE SERVICE WATER SYSTEMS:

Symptoms:

A major loss of service water would be indicated by any or all of

the following:

a. All service water pumps tripped.

b. Low-pressure alarms on one or more service water headers.

D4.8 PRC. 10/4/78

Rev 20 APPR /\~ ~----;

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D4.12

D4.12.l

NOTE: With containment isolation in effect, charging to the

plant may continue but letdown has been isolated.

b. Reset the high radiation and pressure circuits and check that

isolation valves return to normal position after the fault

causing the spurious initiation has been corrected.

PRIMARY COOLANT INCIDENTS

LOSS-OF-COOLANT ACCIDENT

Symptoms:

a. Leak rate exceeds the capacity of the operable charging pumps.

b. Any one o~ more of the following indications or alarms may be

present:

1. Safety injection initiated.

2. Pressurizer level low-low.

3. Containment sump high level or high-high level.

4. Containment high radiation.

5. 6.

Containment high pressure .

Containment isolation. .I

7. Thermal margin/low-pressure channel trip.

8. Pressurizer low pressure.

c. Reactor trip indication.

Immediate:

a. Trip the reactor and turbine if not already tripped and verify

immediate shutdown. Refer to reactor trip. Procedure D4.l for

initial follow-up.

b. Actuate the safety injection system if not actuated.

c. If a major rupture is indicated by containment pressure and

radiation:

1. Insure that as a minimum:

(a) Two (2) containment spray pumps or three (3) contain-

ment air coolers are operating.

(b) Containment spray isolation valves (2) open.

(c) Noncritical service water valve (l) is closed.

(d) All containment automatic isolation valves close .

(e) Iodine Removal Valves Time Delay Relays operate.

D4-23

Rev 13

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d.

2 •. e e

Sound site emergency alarm and carry out site emergency

plan as conditions warrant .

3. Stop all primary coolant pumps.

Insure the following minimum equipment for safety injection has

operated:

Equipment

1.

2.

3.

4.

5.

6.

7.

1 HP safety injection pump.

1 LP safety injection pump.

8 HP safety injection isolation

4 LP safety injection isolation

1 charging pump.

1 concentrated boric acid pump.

1 component cooling pump.

valves.

valves.

8. The following valves are positioned as indicated:

(a) Check valve leakage pressure control (4).

(b) Volume control tank outlet isolation (1).

(c) Makeup stop (1)

(d) Boric acid recirculation· control (2)

(e) Component cooling to fuel pool (1)

(f) Boric acid gravity feed stops (2)

(g) Boric acid pumped fee/ stop (1)

Condition

ON

ON

OPEN

OPEN

ON

ON

ON

CLOSED

CLOSED

CLOSED

CLOSED

CLOSED

OPEN

OPEN

e. Verify safety injection by observing flow rates and injection

tank levels. As the need arises, start additional equipment

in the engineered safeguards system.

f. After PCS pressure falls to <. 215 psig and prior to RIAS",

the hand switches HS-3027 and.HS-3056 MUST be placed in the

closed position.

g. · Iodine removal valves are open. (CV 0437A, ·cv 0437B)

Subsequent:

a. If the recirculation actuation signal is received, insure that:

1. Safety injection and refueling tank isolation-valves (2) clos~.

2. Containment sump isolation valves (2) open.

3. Low-pressure safety injection pumps (2) stop.

4. SI pump minimum flow stop valves (2) close.

5. Component cooling heat exchanger service water outlet valves

(2) transfer to alternate HICs (pass sufficient water to

maintain near normal component cooling heat exchanger outlet

temperature).

D4-24 PRC 2~/ 7 /_,_7 9"'-----

Rev 22 lJ

APPR_ ~\.....-~

b • ..

c •

• d.

I e.

f.

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Use mot~driven or turbine driven auxi~y feed pump to

maintain normal level in the steam generators.

Check the primary coolant relief and safety valves and quench

tank for indication of leakage.

Initiate action as necessary to limit the spread of radioactive

contamination.

Add NaOH from make-up tank T-103 as directed by Chemistry to

buffer recirculation water to a pH of,.,;7.0.

· Establish long term core cooling/flushing (to prevent

B.A. precipitation in core which could interfere with

proper cooling) within twelve hours of the accident by

one of the following techniques:

If PCS pressure is greater than 20 psig (but less than 250

psig):

1) Check that the hand switches HS-3027 and HS-3056 are in

the closed position. Verify that RAS has been received

and LPSI pumps have tripped, and SIRWT outlet and CV-3027

and CV-3056 have closed.

2)

3)

4)

Check PC temperature~saturation.

Stop all but one cs pump.

OPEN or check OPEN C.S. CVj3001, CV 3002 and S-DHX

CV 3212 and CV 3213.

5) CLOSE S-DHX CV 3223 and CV'3224.

6) OPEN LPSI P67A (or B) Suction Valve from shutdown cooling

3199 ESS (3190 ESS) - preferrably P67A.

CAUTION: This may be a high radiation area - if necessary,

flush suction header from SIR.WT.

7) Check that the air to CV 3006 is on. Then open CV 3055 'and

close CV 3006 and CV 3025 (LPSI to and from S-DHX).

8) Bypass RAS trip of one LPSI pump, preferrably P67A (which­

ever pump whose suction to S-D Clg was opened in step 6)

and start pump.

Q) Verify LPSI pump flow on FI 0·302. If symptoms of pump

cavitation appear STOP LPSI pump, CLOSE CV 3002, CRACK

OPEN CV 3025, and place CV 3006 to AUTO, set for/\.J2000 gpm,

and then restart LPSI pump. Verify LPSI flow on FIC 0306,

and slowly OPEN CV 3025 until CV 3006 is closed; ie,,....,2000 gpm . ...... - .-

going through E60B. - : .. ;

D4-2S PRC 11/10/77 ~~--'--~-'-~~~

Rev 13

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io) Open MOV 3015 .-hen 'crack open' HOV 3016 (th' will require an operator

at the breaker to trip the breaker, since the control circuit seals). Monitor

TR 9351· for indication of flow from hot leg. Jog MOV 3016 OPEN until flow

from hot leg can be verified.

NOTE: If the PS 0104 interlock prevents the opening of either

MOV 3015 or MOV 3016 proceed as follows:

a. Go inside Cl2 to terminal board 12 TV 9 (for MOV 3015)

or 12 TV 7 (for MOV 3016).

b. Open links 12 TV 7-55 and 12 TV 9-98, scheme 167 (for

MOV 3015) or 12 TV 7~55 and 12 TV 7-56, scheme 271 (for

MOV 3015).

NOTE: Terminals are found by counting down from the top of the

terminal board.

c. Short terminal 12 to 13 for cable going to CO 2.

d. Place control switch in the open position.

e. When valve is opened to desired position open breaker and

restore terminals on 12 TV 9 or 12 TV 7 to orginal condition.

If MCC 1 or MCC 2 becomes disablea, power to MOV 3015 or MOV 3016

can be supplied.by connecting the power leads from the operable

breaker to the disabled one.· This operation requires about 20 feet

of three conductor #12 wire. .I

11) Monitor LPSI pump discharge pressure, and FI 0302 or FI 0206 for symptoms

of pump cavitation. If pump cavitation occurs, partially close MOV 3016

until cavitation.ceases. (See breaker trip requirement in 10 above.)

Do not shut MOV 3016 completely. At least 100 gpm flow from hot leg is

required. If cavitation persists while pumping to spray header, ·or PCS

pressure falls to 20 ,PSig, change to throttled flow to LPSI header as in

Step 9.

12) Efforts should be made to flush the LPSI pump (s.) . when shutting down after

recirculation mode of operation and during startups during recirculation ·­

mode.

a. Open SIRW outlet valve(s) by jumpering the RIAS relay(s).

b. Immediately after SIRW outlet valve(s) open, jumper the RIAS relay(s)

to close the containment sump valve(s).

D4-25a

Rev 17

PRC 5/lQ/78 QA-05

APPR_Jf~.....,....~~~-·-......,_~-

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c. Stop (start) the LPSI pump(s) after f\J 5 minuter; run .

d. Remove containment sump valve(s) RIAS relay(s) jumper.

e. Remove SIRW outlet valve(s) RIAS relay(s) jumper after

containment sump valve(s) open.

If PCS pressure is < 20 psig:

1. Check that hand switches HS 3027 and HS 3056 are in the closed

position. Verify that RAS has been received, LPSI pumps tripped,

SIRWT outlet CV 3027 and CV 3056 CLOSED.

2. Check PC temperature~ saturation.

3. Stop all but one C.S. pump.

4 .. Check OPEN or OPEN C.S. CV 3001, and S-DHX CV 3212 and CV 3213.

5. CLOSE CV 3223, CV 3224 and CV 3006 for S-DHX..

6. OPEN CV 3055 and THROTTLE OPEN CV 3025 to and from S-DHX.

7. OPEN LPSI pump suction from shutdown cooling - preferably

JJ67A (3199 ESS) - use P67B (3190 ESS) only if P67A not operable.

CAUTION: This may be a high radiation area

flush suction head.er fr-om SIRWT.

if necessary,

8. Bypass RAS trip of LPSI pump whose suction from S-D cooling

9.

was opened in Step 7, and start pump.

Verify LPSI flow on FIC 0306 aid adjust CV 3025 as necessary

to keep flow ~ 3500 gpm.

10. OPEN MOV 3015. (See e.10 above if valve does not operate.)

11. 'CRACK OPEN' MOV 3016. (This will require an operator at the

breaker to trip the breaker). Monitor TR 0351 for indication

of flow from hot leg. Jog HOV 3016 until flow from hot leg

can be verified~

12. Monitor LPSI pump press and FIC 0306 for symptoms of pump

cavitation. If pump cavitation occurs, partially close

MOV 3016 until cavitation ceases. (See breaker trip

requirement in 10 above.)

Do not shut MOV 3016 completely. At least 100 gpm flow from - •• - ''"!

hot leg is required. . '. . ···--~:· .. ~ .. ~-:·.._·.....;

Throttle CV 3025 if necessary to stop cavitation so as to

insure flow from hot leg; ie., keep MOV at least partially OPE.:."l .

D4-25b

Rev. 11

PRC

APPR.

- ....... J!

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13. Efforts should be made to flush the LPSI pump(s) when shuting

down after recirculation mode of operation and during startup

during recirculation mode.

a. Open SIRH outlet valve(s) by jumpering the RIAS relay(s).

b. Immediately after SIRW outlet valve(s) open, jumper the

RIAS relay(s) to close the containment sump valve(s).

c. Stop (start) the LPSI pump(s) after rv 5 minutes run.

d. Remove containment sump valve(s) RIAS relay(s) jumper.

e. Remove SIRW outlet valve(s) RIAS relay(s) jumper after

containment sump valve(s) open.

If flow from hot leg cannot be obtained:

1. Stop all charging pumps.

2. CLOSE CV 3018, CV 3036, MOV 3062, MOV 3064, HOV 3066 and HOV 3068.

3. CLOSE charging stop CV 2111 and all charging pumps discharge

valves (2094 eve, 2100 CVe and 2106 eve).

4. CLOSE charging CV 2113, CV"2115 and Pzr. spray CV 1057 and

CV 1059.

5.

6.

Check OPEN 2195 CVC and 108· CVC in charging header, Room 104B •

OPEN charging CV 2111, CV 2117~ MOV 3072 and Red HPSI CV 3018

or CV 3036.

7. Verify HPSI flow to pressurizer on FIA 0212, then close discharge

to HPSI header (CV 3037 or CV 3059) of pump(s) pumping to

pressurizer.

TAKE CARE NOT TO 'DEAD-HEAD' ANY HPSI PUMPS IN DOING THIS STEP.

Maintain at least one HPSI pump discharging to HPSI header.

Minimum acceptable flow to pressurizer is 100 gpm.

NOTE: If a break in the air line outside the containment occurs,

a hose can be connected from air receiver tank T-8C to a

test connection at the containment penetration. This test

connection is located in the 602' pipeway above the

boronorneter and is provided·with a chicago fitting. The

amount of hose required is about 250 ft. Refer to P&ID

M-212.

D4-25c

Rev. 11

I PRC 2/9 /:77

;\\ .

APPR. (j\ ~~~

• D4.12.2

1 .• •

•

PRIMARY COOLA.i'l'T LEAK

Symptoms:

a. eves or charging flow increases significantly above letdown

flow.

b. Routine leak rate calculation shows an increase over normal

leakage.

c. High rad~ation levels or alatl!ls may be observed at the

following locations:

1. Steam generator. blowd·own tank drain or vent.

2. Air ejector effluent line.

3. Component cooling system.

4. Containment building atmosphere particulate or gaseous

monitor.

5. Containment or auxiliary building area monitors.

d. Any one or more of the following indications or alarms are

present:

1.

. 2.

Quench tank high level or pressure.

Component cooling surge tank high level .

3.

4.

Primary relief or safety va}ve line high temperature.

Primary drain tank high level.

5. Dirty waste drain tank high level.

6. Pressurizer Jevel low.

7. Volume control tank low l~vel.

8. Containment sump high level.

9. Containment air cooler dry pan high level.

e. Routine radiochemical analysis of the Steam Generator Secondary

or Component Cooling System water shows a significant increase

in radioactivity content .

D4-25d PRC __ 2....:.=-1-· -1-6_77 __ . ___ _ APPR. cJ: __ ~ Rev.

•

• •

•

Immediate:

a. Insure that the increase in average makeup rate has not been

caused by a large generator load change or by a change in Tavg

b. Insure the following automatic functions have occurred; initiate

any that have not occurred:

1. Additional charging pumps start as necessary to provide for

the increased makeup requirements.

2. Average makeup increases to maintain normal level in the

volume control tank.

c. Determine leak rate by observing rate of change in volume

control tank level.

d.

1. If leak rate exceeds the capacity of the operable charging

pumps, immediately trip the·reactor and turbine and follow

procedure for loss-of-coolant accident, D4.12.l.

2. If leak rate is greater than technical specifications iimits,

shut· dm·m the plant. If ·iocation of leak is known, attempt

to isolate affected components to reduce plant conta~ina~ion

during shutdown.

Subsequent:

a. Attempt to locate leak by:

1. Radiation surveys.

2. Ensuring the following valves are fully closed:

(a) Pri.mary coolant safety, relief, drain, vent and samplo.

valves.

(b) Relief, vent and drain valves in the chemical and

volume control system.

3. Check all tanks listed above for increasing level.

b. If the primary relief or safety valve high temperature alarms

are actuated, the respective valve may be leaking.

c. Check the pressurizer level and makeup system for proper oper­

ation.

d. If the leak is located and ~an be isolated, continue plant

operation and repair the leak.

D4-26

..

••

D4.12.3

.'

e. If the leak was ·from steam generator tube requiring plant

shutdown see D4.12.5. CAUTION: Take care to insure that PCS pressure remains "' 100

~si greater than S-G nressure until the S-G can be drained,

to preclude dilution of PC with leakage from the S-G.

f. Establish radiological controls in the area of the leak.

PRIMARY COOLMIT LEAK DUE TO CRDM SEAL FAILURE.

Symntoms:. ·

a. CRDM leak off temperatures in excess of 350°F.

b. eves cir charging' flow increases significantly above letdown

flo.;,;.. c2· t.o . 30 g~m unexplained).

c. Steam cloud may be visible in vicinity of reactor head on TV ..

·monitor~·

d. High humidity on detecto~ HI 1812. ·

e. Primary or secondary indication may fail due to water on con­

nectors or contacts.

f. High ·1evel ala..--m on containm,eilt sump.

g. Volume control tank low level alarm.

Immediate:

a. Insure that the increase in average makeup rate has -not been

caused by a large generator load change or by a change in T • ._ ... . avg

b. Insure the following automatic functions have occurred; initiate

any that have not occurred:

l. Additional charging pumps start as necessary to provide.for·

the increase makeup requirements.

2. Average makeup increase to maintain normal level in the vol­

ume control tank.

c. Determine leak rate by observing rate of cha..~ge in volun.e control

d.

tank level.

1. If leak rate is greater than 2 gp~ but less than 5 gpm,

re!!!ove tmit from service in a controlled r::ian..."ler at 10 1·f.-i'e

per r;iinute.

D4-27

•

.. :'"· · .. ·. · ..

D4-.12. 4

•

D4.12. 5

•

2. If leak rate is greater than 5 gpm and con.firmed to be a

seal failure, trip the unit off the line after notifying

load control of your intentions. Refer to Procedure D4.l .. ··for initial follow-up.

e. Trip the CRDM cooling fans to preclude d=ivi.ng ·.rater spray

into drive and electrical connectors.

Subs~ouent:

a. .Borate primary system as required to insuxe cold shutdown margin

. of' 2% lip •

· b. Initiate cooldmro. of pri"'"'ry system at ma:d..nll!!l rate al.lowed in

Figure 3-2 (Technical Specifications) but.not to exceed l00°F/.

hour. Refer to Procedure A5.

c. Lower weter level in primary system to a ~oint below the CRDM

seals to stop the loss of -water via the failed seal.

CONTROL ROD EJECTION ·

The control rod ejection is. defined as a complete severa..~ce of a

control rod housing resulting in a rapid ejection of 18 inc.hes .

and followed by a sudden overpower conditi6n and loss of coolant.

Syn:mtoms : ·

a. Sudden rise in neutron channel traces to off-scale indication.

b. High power level reactor trip.

c. Containment high radiation alarms.

d. High start-up rate alarm.

e. Rapid decrease in pri.rnar'J pressure.

f. Any or all oi' the symptoms associated with D4~12.l, loss-of'-

Coolant Accident.

Immediate:

a. Insure reactor a..~d turbine tripped and follow up per D4.12.l, ··.

Loss-of-Coolant Accident.

STEAM G~lERATOR TUBE RUPl'URE

7.~is procedure assunes a sudden double ended tube rupture which

results _in a leak greater than chargicg capability and a consequent

:cee.ctor t:::-ip, with steam du::ip .

•

•

•

Symptoms:

a. High radioactivity alarm on the following instruments:

l. S~e~ gene~tor blowdow:Ll ~ouitor.

2. Condenser ofr-gas monitor.

3. Waste gas monitor.

4. Stack gas monitor.

5. Penetration and fan room area monitor

b. Decreasing pressurizer level.

c. Standby charging pumps on.

d. Decreasing primary pressure.

e. TM/T.J:J pressure reactor trip and safety injection initiation

af'ter 15-20 minutes.

Immediate:

a. Manually reduce plant load at maximum; rate which will not of ·'

itself cause a plant trip (ie, from low pressurizer pressure):

turbine ramp down @r\l 5rfo/minute. PDIL does not apply for

emergency power reduction. Attempt to reduce load and remove

unit from the line before tripping reactor, to minimize steam

dump. Survey main steam lines to aid in determining which S/G

has failed.

b. Take immediate action to secure plant trip. Follow-up per

D4.l, Reactor Trip Procedure, with the following exceptions:

l. Minimize use of the steam dump valves.

2. Trip prirnary coolant pu.~ps on the affected loop to minimize

stea.~ generation. (S/G level recordings should indicate which

S/G has failed tube within a few minutes of failure.)

c. Secure S/G blowdowns and blowdown tanks vents to atmosphere.

D4-29 Rev. 4

PRC DATE 2~~-1\PR 1975

APPR. &J? <:;.-"'~:>

•

•

•

d. ·As soon as failed S/G can be identified, minimize FH flow to it

(keep level @l"J 25~ following trip) to provide volume for PC

leakage and prevent flooding of S/G and main steam line.

e. Keep a rua.in F.·1 P"~ rw4li-::..g en ~ec:i.:rc. to assist in cooling.

f. If auxiliary FW is required, use motor driven pump only.

Subsequent:

a. Initiate plant cooldown at a maximilln rate per operating Procedure A5,

utilizing shutdown cooling as soon as possible;: to limit further

steam generation.

CAUTION: Take care to insure that PCS pressure remains 100 psi

greater than S/G until the S/G can be drained, to preclude

dilution of PC with leakage from the S/G.

b. Close MSIV :fl:."om failed S/G only by opening solenoid cabinet in NE·

corner of t"Llrbine building on 607 deck and:

l. To close 'C\T0510 from S/G A, mani.m.lly unlatch and allow to drop . . ·'

to the_ tripped position.SV0505B and SV0507B

I 2. To close CV0.501 from S/G B, manually unlatch and allow to drop to ··

the tripped position SV0505A and svo507A.

c. Establish radiation control zones outside the containment as

deemed n.ecessary by surveys.

d. Notify plant personnel of any restricted areas established from

(c)' above.·

D4-30 PRC Ul\TE ,.4 I 5 I 7 8

Rev. is APPR. .)\l ~~"'

- . -

•

•

•

D4.9

D4.9.l

I

MAIN STEAM RELEASE

STEAM LINE RUPTURE - INSIDE

Symptoms:

The following actions and alarms may indicate a steam line rupture:

a. Rapid drop in steam generator pressure followed by renctor trjp

from same.

b. Containment high-pressure alarm.

c. Containment· isolation (eHP) actuation.

d. Safety injection system (SIS) actuation.

e. Steam line isolation valves tripped.

f. Sudden increase or decrease in steam flow, dependent on location·

of break relative to flow element.

g. Rapid steam generator level oscillations.

h. Excessive steam/feed flow mismatch.

i. Reduction in primary system temperature, pressure, and pres­

surizer level and standby charging pump start.

Immediate:

a. Verify the following· functions have occurred or manually

inititate same:

1. Reactor trip. /

2. Turbine/generator trip. . - - .. ,· ·.-

3. Main steam isolation valves closed.

b. Insure safety injection actuation occurs if pressurizer low:­

low pressure or containment high-pressure alarms are· present.

c. Secure containment sprays manually if air coolers are operating

and primary system conditions are normal. Place Iodine Removal

Control Valves eontrol-··Switches to "Defeat Auto".

d. Insure all chargine pumps are operating at maximum capacity.

e. If steam pressure in one steam generator continues to fall

with main steam isolation valves closed indicating a break

between the steam generator and its isolation valve:

1. Check the eves for proper initiation of boration from SIS

actutation. If necessary, initiate emergency boration

Procedure B2.4.6.5 due to primary system cooldown.

2. Insure containment cooling is functioning properly .

3. Start aux. feedwater flow to the unaffected S/G. D4-15 PRC 11/10/77

Rev 13

. ,. ~ \._:,;-.

.,

•

•

D4.9.2

•

NO~Steam generator refill rate s~ not exceed 100 gpm

if steam generator level~ trip point has been

experienced for ;;:.. 1 minute and power level was'.:'.:: 7 5% F. P .

If prior power level was~ 75% F.P. refill rate raa.y be

increased to 150 gpm provided the S/G J evel was== trip

point for> 15 minutes and the level must be maintained

~ 6%. To increase level over 6%, feed rate must be

reduced to < lOOgpm. CAUTION: Do not add f eedwater to a dry steam generator

unless abs0 tely necessary.

4. Trip primary coolant pumps to aff.ected steam generator to

minimize heat transfer.

Subsequent:

Follow up reactor trip per reactor trip Procedure D4.l with the

following additions:

a. Maintain close watch on containment cooling system.

b. Continue boration to cold shutdown concentration, and complete

primary system coo~doW'l.

c. If makeup to T2 for aux feedwater is required in greater

quantity than can be supplied from the makeup demineralizers,

transfer from primary storage by:

1. (Gravity) Check primary.lmak~up water level higher than

CST2, and open manual bypass valves around both CV 2008

and CV 2010.

2. (Pumped) Check CV 2020, PMW HX inlet, valve 143 WT, and

PCV 2164 3" ou·tlet valves CLOSED,. then OPEN CV 2008 and

CV 2010 bypass valves and PCV 2164, and start P79A or B.

Power from diesel generators for P79 may be had by manually

energizing MCC3, or 4.

NOTE: Backup water supply may be obtained from T-90 or

T-91. (See SOP17 .6.6)

SECONDARY RELIEF VALVE FAILURE

Symptoms:

The following symptoms may indicate failure of a secondary relief

or atmospheric dump valve within the valve room:

a. An obvious load noise level which should be audible in the

control room •

b. Steam escaping around doors to the relief valve room and the

component cooling pump room at 590' level.

c. Any or all of the symptoms of a steam line rupture, D4.9.l.

D4-16

Rev 20

/

PRC 10/4/78 APPR_;\_,·....,..~--.--~---. -.-_-_ :..---

~-'--"'---~~~~~~~

,.,

•

D4.9.3

•

•

Immediate:

In addition to the follow-up listed for a steam line rupture

incident in D4.9.l.

a. Quickly acco1,mt for any personnel who may have been working

in the relief valve room or CCH pump room. The Shift Supervisor

should have this information;

b. Secure access to danger areas and proceed with plant follow-up

to steam line break.

MAIN STEAM LINE RUPTURE OUTSIDE CONTAINMENT

The following procedure describes operating guidelines to lie used

in the event of a main steam line rupture outside the containment,

such that the steam generator content blows down into the steam

line compartment at 607'. In addition, it is assumed that all

offsite power sources are lost following the subsequent plant

trip. For the purpose~ of this procedure, it will be assumed that

the component cooling water system is ~ost due to the extreme

energy imp,arted on that room from the steam line break.

Symptoms:

a. An obvious very loud noise indic!ative of a high energy line

break outside containment.

b. Rapid loss of pressure in one of the steam generators.

·c. Immediate full scale steam flow indication from one of the

.steam generators.

d. Innnediate reactor trip on low steam generator pressure (<3 seconds).

e. Immediate closure of main steam isolation valves, and annuncia­

tion of same.

f. Rapid cooldown of Primary System.

g. Safety Injection System (SIS) initiation from low primary pressure.

Innnediate (First Minute):

a. Verify or initiate the following immediately:

1. Reactor trip. ~~~ .F .,._ : .. ;. ;- : ~ -:- "'! !:.~ ,: -~ r;-~ '-·:,~

':.. ... · . ._") .. 2. Turbine/generator trip.

3. Main steam isolation valves closed.

4. Safety injection initiations.

b. Station an operator at auxiliary power panel to ensure emergency power .

1. Diesels start and come up to speed.

D4-17 PRC 10/4/78

Rev 20

''L

•

•

•

2. ~tion and start-up power bus sutlty breakers all

tripped.

3. Automatic load shedding .

4. Sequenced loading of 2400 volt buses to diesels via DBA

sequencers.

c. Line up auxiliary feedwater to block flow to the failed

steam generator by closing CV 0736 or CV 0737.

d. As soon as possible, start the motor driven auxiliary feed , ...

pump and provide maximum flow ·to the intact steam generator.

NOTE: .Steam generator ref~l rate shall not exceed 100 gpm

if s.team generator level~ trip point has been

experienced for > 1 minute and power level was~ 7 5% F. P.

If prior power lev~l was.;::- 75% F.P. refill rate may be

increased to. 150 gpm provided the S/G level was·= trip

point for> 15 minute-s and the level must b~ maintained

~ 6%. To increase level over 6%, feed rate must be

reduced to < lOOgpm.

e. Verify emergency boratio~ mode. of CVCS, and insure high-pressure

safety injection pumps are operating to provide borated water

. to the reactor .

f. If diesel 1-1 failed to sta~~. dispatch personnel to that room

via outside entry iIIUilediately. This diesel will be required,

for auxiliary feed flow.

g. Switch control room ventilation to recirculation mode.

Follow-Up (First Hour):

The primary follow-up action will be to insure reactor boration to

cold shutdown concentration and provide adequate core cooldown.

a. Switch safety injection pump· cooling to service water backup

supply.

b. Once blowdown is complete (3 minutes), dispatch operators as

soon as possible to open all exterior doors to the auxiliary

building.

c. Continue emergency boration of the reactor until boric acid

tanks are drained. If PCS water level returns to normal,

secure high-pressure injection flow temporarily to allow full

charging of boric acid.

d. Operate atmospheric dumps on intact steam generator to enable

controlled cooling rate allowed by available auxiliary feed flo•

D4-18

Rev 20

PRC~~~i~0~/4~/~7~8~~~­

APPR:__~~:~\~\'--'~~-=--~·--_-_· ,_~~~~

·-

•

•

D4.10

•

Subsequent (>l Hour):

a. Notify the necessary repair crews to stand by for repairs to

CCW and other systems as soon as conditions allow. ..

b. If motor-driven auxiliary feed pllillp is lof;t, continue ·PCS cool-

do•m by intermittent charging flow and operation of pressurizer

relief valve. (Open auto reliefs by pulling any two high­

pressure trip bistables. Control relief with manual stops.)

c. All efforts at this point should be directed to restoring opera­

tion of CCW system, and auxiliary feed if necessary. Proceed

with inspection of auxiliary building basement as soon as possible

and call in repair crews to begin work on dewatering efforts.

d. If it appears CCW system cannot be restored within a few days,

cool system down and maintain at 212°F with steam du1nps. Begin

work on an emergency tie-in to provide service water directly

to the shutdown heat exchanger.

e.

NOTE: If necessary, limited cooling to shutdown heat exchanger

is available by backflow through SIS pump cooling service water

backup lines. Open CV 0913 & CV 09.50 and close CV 0945, CV 0946

and CV 0910 to provide SW backflow of about 500 gpm to only the

shutdown exchangers.

Provide makeup to the condensate tank from demineralizer opera­

tion to insure adequate long-term auxiliary feedwater supply.

If this is not possible, open bypass valves around CV 2008 and

CV 2010 to provide backup source from the primary makeup tank.

NOTE: Backup water supply may be obtained from T-90 or T-91. (See ~Of:i.17 .6.6) p-- - _ • ~...,,,

I I l .::_ r. .• i ~I~~" ~~ .. i~ ·~_;.=ai~~~·~!~ E ~~~}·i··~

MAIN FEED-WATER RUPI'URE (OUTSIDE CONTAINMENTl

This procedure outlines basic operator action to be taken in the

event of a main feed-water line rupture outside the containment,

in particular a break between containment and the check valve in

the component cooling water (CCW) room. In addition, it is assumed

all offsite power is lost after the subsequent plant trip.

~toms:

The follmring are probable indications of a main feed line break,

in order of im~ortance:

D4-196 Rev.

PRC July 7, 1-975 J~~'l?l~ • /.. ) -::; ,i'/ .1 / ;· I -

•

•

•

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• • • TABLE 3.16.1

Engineered Safety Features System Initiation Instrument Setting Limits

Functional Unit

1. High Containment Pressure

2. Pressurizer Low Pressure

3. Containment High Radiation

4. Low Steam Generator Pressure

5. SIRW Low-Level Switches

6. Engineered Safeguards Pump Room Vent - Radiation Monitors

Channel

a. Safety Injection b. Containment Spray c. Containment

Isolation d. Containment Air

Cooler DBA Mode

Safety Injection

Containment Isolation

Steam Line Isolation

Recirculation Actuation :......

Engineered Safeguards • Pi.imp Room Isolation

Setting Limit

5 - 5.75 Psig

~ 1550 Psia(l) for Nominal Operating Pressures < 1900 Psia ~ 1593 Psia(2) for Nominal Operating Pressures ~ 1900 Psia

_;:_ 20 R/h

~ 500 Psia( 3 )

(+O ~ 27-Inch (-6 Above Tank Bottom

< 2.2 x 105 CPM

~ ~ (l)May be bypassed below 1600 psia and is automatically reinstated above 1600 psia.

l ~ (,2 )May be bypassed below 1700 psia and is automatically reinstated above 1700 psia.

~ § (3

)May be bypassed below 550 psia and is automatically reinstated above 550 psia. c+

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•

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ECCS DESCRIPTION (Response to Question 4b)

Safety Injection Operation

A. Normal Plant Operation

During normal power operation, no components of the system are in operation, all components are on standby awaiting a safety injection actuation sigrial (SIAS) per start-up check sheet.

B. Safety Injection Actuation Signal (SIAS)

The safety injection signal automatically starts the high- and low-pressure injection pumps and opens all safety injection motor-operated loop valves. The system is always aligned for safety injection during power. operation.

It is permissible to operate with the high-pressure or redundant high­pressure safety injection motor-operated valves in the "open" position if all of the following conditions are met:

1. Approval of Management •

2. Primary coolant system check valves show no adverse leakage •

.I 3. Sa:fety injection system check valves show no adverse leak.age.

4. Relief valves RV-3165 and/or RV-3264 are.not relieving.

5. Pressure indicator PI 0318 or PI 0375 is monitored and readings logged hourly.

Deviations from any of these steps will require closure of the motor­operated valves and a reevaluation by Management of the situation.

General:

a. SIAS with standby power starts all HP and LP injection pumps, opens 12 SI valves.

b. SIAS without standby power starts one HP and one LP SI pump ~n each emergency generator, automatically lines up SI system valves.

c. SIRWT level switches (LS-0327, LS-0328, LS-0329, LS-0330) actuate RAS to close tank outlet valves and recirculate from containment sump.

d. On primary system low pressure (240 psig),' all SI tanks drain into primary system. Four tanks of 1000 cubic feet borated water each at 1720 ppm boron.

e. Low-pressure safety injection standby pump starts if inactive pump set up for "standby" operation when in the shutdown cooling mode. Pump start from PS-0322, PS-0323 at 75 psig .

. . •, :

1

•

••

•

Safety Injection Operation (Contd)

C. Sequence of Safety Injection With Standby Power

The safety injection actuation signal operates the following equipment:

NOTE: If primary system pressure decreases to 240 psig, all safety injection tanks drain into primary system. Each tank should be filled with 1000 cubic feet of borated water with 1720 ppm boron concentration.

1. Starts all available high-pressure safety injection pumps.

2. Opens safety injection motor-operated loop valves.

3. Starts both low-pressure safety injection pumps.

4. Starts both boric acid pumps.

5.

6.

7.

8 •

9.

10.

11.

12.

13.

14.

Opens boric acid gravity feed motor-operated valves MOV-2169 and MOV-2170.

Closes volume control ta.Iik outlet motor-operated valve MOV-2087.

Opens concentrated boric acid pumped feed motor-operated valve MOV-2140.

Starts all available charging pumps.

Starts all available service water pumpsi

Maintains running containment cooling fans "A" and trips fans "B."

Starts all component cooling pumps.

Closes boric acid makeup valve CV-2155.

Closes boric acid tank recirculation valves CV-2130 and CV-2136.

Closes safety injection tank test valves CV-3038, CV-3042, CV-3046 and CV-3047.

15. Opens service water to valves CV-0825 and CV-0878 to engineered safe­guards room cooler.

16. Closes noncritical service water header supply valve CV-1359.

17. Opens component cooling water valves CV-0913 and CV-0950 to engineered safeguards pump seal cooling.

18. Closes component cooling water v8.lve CV-0944A to fuel pool heat exchanger.

19. Closes component cooling water valve CV-0910 to containment •

20. Closes safety injection tank leak.age valve CV-3069.

2

•

;.

•

•" • Safety Injection Operation (Contd)·

C. Sequence of Safety Injection With Standby Power (Contd)

21. Opens component cooling water valves CV-0937 and CV-0938 to shut down heat exchanger.

22. Closes component cooling water discharge valve CV-0911 from containment.

23. Opens containment air cooler high capacity service ~ater outlet valves.

NOTE: All safety injection pumps operating for approximately 20 minutes at maximum flow will reduce safety injection and refueling water tank level to 27" (7%), at which time level switches LS-0327, LS-0328, LS-0329 and LS-0330 operate the recirculation actuation signal (RAS) to operate fol­lowing:

a.

b. c. d.

e.

f.

Gives permissive to close safety injection and refueling water tank minimum flow stop valves CV-3027 and CV-3056. Trips low-pressure safety injection pumps. Opens containment sump valves CV-3029 and CV-3030. Close1s safety injection and refueling water tank outlet valves CV-3031 and CV-3057. Fully opens component cooling water inlet valves CV-0945 and CV-0946 to the component cooling water heat exchangers. Transfers control of service water discharge valves CV-0823 and CV-0826 from component cooling water heat exchdnger from hand indicating con-trollers HIC-0823 and HIC-0826 .to HIC-0881 and HIC-0882.

g. Safety injection and refueling water tank low level alarm annunciated.

D. Sequence of Safety Injection Without Standby Power

The safety injection actuation signal (SIAS) operates the following equipment:

1. Loss of standby power or turbine trip starts both diesel generators.

2. Diesel generator running and no standby power, initiates load shedding oµ buses lC and/or lD, if associated diesel generator breaker is open.

3. Diesel generator voltage normal and load shed signal closes diesel generator breaker.

4. Diesel generator breaker closed clears load shed signal.

5. Diesel generator breaker closed and safety injection signal starts designed basic accident (DBA) sequencers •

3

,,,

•

•

•

Safety Injection Operation (Contd)

E. Operation of Design Basis Accident Sequencers 1 and 3 Serviced From Diesel Generator 1-1

Time in Seconds From Diesel Generator Breaker Closure

0

2

6

9

13

20

23

40

Service

Miscellaneous 480 V Loads (Valves, Etc)

Boric Acid Pump P56B; Charging Pump P55C; High-Pressure Safety Injection Pump P66B

Service Water Pump P7B

Containment Cooling Fan V4A; Containment Spray Pump P54B if Containment High Pressure (CHP)

Low-Pressure Safety Injection Pump P67B

Contai1:1illent 9pray Pump P54C (if CHP)

Component.Cooling Pump P52A

C t C 1 . Pump P52C ( i· f "A" and omponen oo ing "B" Pumps .lfail to Start)

F. Operation of Design Basis Accident Sequencers 2 and 4 Serviced From Diesel Generator 1-2

Time iri Seconds From Diesel Generator Breaker Closure

0

2

6

9

13

20

23

26

Service

Miscellaneous 480 V Loads (Valves, Etc)

Boric Acid Pump P56A; Charging Pump P55A; High-Pressure Safety Injection Pump P66A

Service Water Pump PTA

Containment Cooling Fan VlA; Containment Spray Pump P54A (if CHP)

Low-Pressure Safety Injection Pump P67A

Two Containment Cooling Fans V2A, V3A; Charging Pump P55B

Component Cooling Pump P52B

Service Water Pump P7C

4

•

•

•

.. ,

Safety Injection Operation (Contd)

F. Operation of Design Basis Accident Sequencers 2 and 4 Serviced From Diesel Generator 1-2 (Contd)

CAUTION: Recirculation actuation signal (RAS) will activate when safety injection and refueling water tank level reaches 27 11 (0%).

NOTE: The low-pressure safety injection pumps may be used with shutdown cooling heat exchanger for emergency core cooling at anytime primary system pressure is below 270 psia .

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Thermal Margin/Low Pressure(2, 3) .

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• TABLE ..... J.l

Reactor Protective System Trip Setting Limits

Four Primary Coolant Pumps Operating

< 106.5% of Rated Power

~ 95% of Primary Coolant Flow With Four Pumps Operating

~ 2255 Psia

PT ~Applicable Limits To Satisfy Figure 2-3

Not Lower Than the Cen­ter Line of Feed-Water Ring Which Is Located 61 -0" Below Normal Water Level

~ 500 Psia.

< 5 Psig

"·

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~ 71% of Primary Cool­ant Flow With Four Pumps Operating

~ 2255 Psia.

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Not Lower Than the Cen­ter Line of Feed-Water Ring Which Is Located 6' -O'' Below NorinE..l Water Level

> 500• Psia.

< 5 Psig

(l)Below 5% rated power, the trip setting may be manually reduced by a factor of 10.

• Two Primary Coolant

Pumps Operating

. ~ 213 of Rated Power( 4) (Continuous Operation

. Not Fermi tted)

~ 46% of Primary Cool­ant Flow With Four Pumps Operating

~ 2255 Psia

Replaced by High Power Level Trip and 1750 Psia Minimum Low­Pressure Setting

Not Lower Than the Cen­ter Line of Feed-Water Ring Which Is Located 6 1 -0" Below Normal Water Level

~ 500 Psia

~ 5 Psig

(2 )May be bypassed below lo-4% of rated power provided auto bypass removal circuitry is operable. For low power physics tests, thermal margin/low pressure and low steam genera.tor pressure trips may be bypassed until their react points a.re reached (approximately 1750 psia and 500 psia., respectively), provided auto-matic bypass removal circuitry a.t lo-1% rated power is operable. .

( 3 )Th and Tc in °F. Minimum trip setting shall be 1750 psia for two- and three-pump combinations" For four­pump operation, the minimum trip setting shall be 1650 psia. for nominal operating pressures less than 1900 psia; and 1750 psia for nominal operating pressures 1900 psia and greater.

( 4 )operation with two or three pumps is permitted to provide a limited time for repair/pump restart, to provide for an orderly shutdown or to provide for the conduct of reactor internals noise monitoring test measurements

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