ML19256E761
| ML19256E761 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 11/06/1979 |
| From: | Public Service Enterprise Group |
| To: | |
| Shared Package | |
| ML19256E758 | List: |
| References | |
| PROC-791106, NUDOCS 7911150152 | |
| Download: ML19256E761 (1) | |
Text
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E.'iERGENCY INSTRUCTICS F
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SAFETY I5JECTION ISITIATICS 1.0 PURPCSE theirrediateautcraticahdesnualactions
- .1 This instruction is provided to present 1
^*
required to be performed on the receipt of any Safety !n;ection actuation, regardless cf the cause.
..; Th;s instruction ecntains the inferration required te direct the operater to tne appr:priate Erergency Instruction to cope with the existing plant conditicns.
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S a f e t',' In;ect:On has initiated.
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'ler:fy the fcilowing automatic actions have occurred.
3.1.1 Reactor trip by verifying all control rods are fully inserted by che:%ing the individual rod positten indications and r:d bottor lights.
1.
If any centr:1 rods do not indicate full insertion, initiate a ranual reacter trip.
3.1.2 Accident loading of the Safeguards Equipment has taken place and the felicwing equiprent ir running by cbserving the indicating lights en the status panel en RP-4 and by cbserving the centrol bezela for each of the fellowing:
1.
Certrifugal Charging Purps 2.
Safety Injection Pumps 1.
Residual Heat Removal Purps 4.
Auxiliary Teedwater Purps (M0 tor Driven) 5.
Service Water Pumps 6.
C:ntainrent Fan Coil Units in slew speed 7
Diesel Generators 3.1.3 Reactor Coolant temperature is decreasing to : being raintained at 54 'r by either stear durp or atmosheric stear relief.
3.1.4 Within two rinutes reduce Auxiliary Teedwater ricw to the Stear Generaters to limit the rate of rise to <l.2 in/rin by monitoring the wide range level recorders (<0.21/rin on the wide range until the level is 10i on the narr w range indication fer a]; Stear Genersters not affected by ine failure. ~ hen re-establish maximur Auxiliary Feed ater Flew.
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This liritati:n applies t: Unit 1 cnl.
Rev.0 Saler Unit 1/ Unit 2
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7911150
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.i.5 rurbine trip by verifying the follow.ng:
1.
Unit Trip light on the EH Console 2.
Turbine speed decreasing If the turbine does not indicate a tripped condition, initiate a manual trip from the control console.
3.1.6 Main Feed Pu 1,
tripped by observing the indications en the centrol tezel.
i If either pump has not tripped, trip it manually.
2.1.7 Feedvater isolation by observing the indicating lights on the Teedwater sect;:n of RP4.
3.2 Verify Safety Injection Fump flow to the Cold Legs from the operating Safety Injection Pump (s) by observing the discharge flow meters on the control console.
When RCS pressure decreases to <l550 psig as read on the Wide Range Indicaters on the centrol censole, stop all Reactor Coolant Pumps.
3.3 Verify Containment Phase A isolation has taken place by observing the indica.ing lights on the status panel RP-4.
3.4 Announce over the Station PA System twice: UNIT 1(2) REACTOR TRIP, SATETY INJECTION.
4.0 dCESEOCENT ACTIONS 4.1 Verify Safety In]ection is in progress by checking each of the following. If any eculpr.ent or valve is not in the desired condition or position cttempt to establish the desired cendition at the individual bezel on the control console.
CAUTION DO SOT attempt to reset the Safety Injection or SEC in order to place equipment in the desired condition. System design is such that sufficient redundancy is provided to overcome single failures.
4.1.1 Verify, utilizing console and/or 1(2)RP4 status panel indications, that the loads listed on Table I have been loaded onto the vital busses.
4.1.2 Verify that the Containment Fan Coolers meet the following conditions upon starting:
a.
Fan Coolers have decreased speed b.
Tan Coolers service water flow has increased from 700 gpm to 2500 gym c.
Roughing filter dampers 1. ave closed d.
HEPA inlet dampers have cpened e.
HEPA outlet dampers have opened 4.1.3 Check that the following valves have opened by observing the status panel.
If any valve fails to open, attempt to manually open from the control console 1(2)SJ4 Boron Injection Tank Inlet Val"e 1(2)SJS Beren In;ection Tank Inlet Valve t
1(2)SJ12 Boron Injection Tank Cutlet Valve 1(2)SJ13 Boren In;ection Tank Cutlet Valve Salem Unit 1/ Unit 2 Rev. O
I-4.0 1(2)SJ1 Charging Pump Suction from RWST 1(2)SJ2 Charging Purp Sueticr. fren REST 4.1.4 Check that the fellcwing valves have closed.
If anj talve fails tc cicse,
~
attempt to close the valve frca the centr:1 censcle.
1
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l'2)SJ73 Recirc to Beric Acid Tank
- 1(2)SJ79 Recir to Beric Acid Tank 1(2)SJ1:8 Recirc to Boren Injects m Tank 1(2)CV63 Charging Syster Step falve 1(2)CV69 Charging Systen Step Valve 1(2)CV139 Charging Pump Disch to SWHX 1(2)CV140 Charging Pump Disch to SWHX 1(2;CV40*
Volume Contrci Tank Discharge Valve 1(2)CV41*
Volume Control Tank Discharge Valve 1(2)CV3 Crifice Isolation Valve (Letdown) 1(2)CV4 Crifice Isolation Valve (Letdown) 1(2)CVS Crifice Isolation Valve (Letdown 1 1(2)CV7 CVCS Letdown Lane 1(2)CVil6 Reacter Ccolant Pump Seal Water Discharge 1(2)CV2S4 Reactor Coclant Pump Seal Water Lischarge 11:21)SW20 Turbine Genernter Area Supply Valve 11(21)SW20 Turbine Generator Area Supply Valve 1(2)SW26 Turbine Generator Area Isolation Valve NOTE
- These valven will not close until either 1(2)SJ1 or 1(2)S02 is fully cpen.
4.2 Verify that Phase "A" Centainment Isolation has taken place by checking that the valves listed in Table II are clcsed. Should a valve fait to close, attempt te close it free the centrol censole.
4.2 Verify that Feedwater Isclation has taken place due to the Safety In ectien.
4.3.1 Check that the following valves have closed by observing the status panel and/or the censole bezel.
If any valve has failed to c1cse, attempt to close it from the control console.
ll(21)BF13 Feedwater Inlet Stop Valve ll(21)BF19 Feedwater Control Valve ll(21)BF40 Feedwater Bypass Valve 12(221BF13 Feedwater Inlet Stop Valve 12(22)BF19 Feedwater Centrol valve 12(22)BF40 Feedwater Bypass Valve 1337 019 Salem Unit 1/ Unit 2 F.ev 0
I-4.0 s
13(23)BF13 Feedwac-
... Stcp Valve 13(23)BF19 Feedwate..ontrol Valve 13(23)BF40 Feedwater Bypass Valve 14(24)BF13 Feedwater Inlet Stcp Valve 14(24)BF19 Feedwater Co.trel Valve
.+
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14(24)BF40 Feedwater Bypass Value
., 4. 4 Verify that the 4160 V Group Busses have transferred from the No. 1(2) Auxiliary Pcwer Transferr
- No. 11(12) and No. 12(22) S ta ti-:. Power Transformers.
4.4.1 C eck that the fol.1 wing 4160 V breakers have opened and acknowledge tr.em on the approp.iate control console bezel:
1(2)BGOD 1(2)BFGD 1.2)AEGD 1(2)AHGD 4.4.2 Check that the following 4160 V breakers have closed and acknowledge them on the appropriate console bezel:
12(22)GSD 12(22)FSD ll(21)ESD ll(21)HSD 4.5 Verify the following fans have stcpped by cbserving the indicatiens as noted.
If any fans are still running, attempt to stop them manually.
No. 11 & 12 (21 & 22) Iodine Removal, Centrol Console No. 11, 12 13 14 (21, 22, 23,24) Nozzle Support. Control Console No. 11 & 12 (21 & 22) Reactor Shield, Control Console No. 11, 12, 13, 14 (21, 22, 23, 24) Control Rod Drive, Control Console No. 11 & 12 (21 & 22) RHR Pump Room Ccolers, RP2 No. 11 & 12 (21 & 22) Charging Pump Room Coolers, RP2 No. 11 & 12 (21 & 22) Containment Spray Pump Rocm Coolers, RP2 4.6 Verify Control Area Air Conditioning has shifted to the ACCIDENT - INSIOE AIR mcde of operation and the following actions have occurred by observing the status patel on RP2.
If any actions do not occur, manually initiate them IAW GI II-17.3.2,
~
" Control Rocm Ventilation Operation", Section 5.3.
NDTE Control Room Ventilation Isolation of Unit No.
~
1(2) will also isolate Unit No. 2(1) Control Room, however, its green NCRMAL mode indicator fh[
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will remain illuminated.
Salem Unit 1/ Unit 2 Fev. O
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4.6.1 No. 11, 12, 13 (21, 22, 23) Chillers are running.
4.6.2 No. 11 & 12 (21 & 22) Chilled Water Pumps are running 4.6.3 No. 11, 12, 13 (21, 22, 23) Control Area Suppl, Fans are ru,nning EmergencyControlAreaSupplyFarsaherunning.
4.6.4 No. 11 & 12 (21 & 22) a 4.6.5 Battery Exhaust Fan has stopped.
4.6.6 Centrol Valves 1(2)CH30 and 1(2)CH151 close to isolate the Adminstrative Building.
4.6.7. Control Area Dampers positioned as follows:
CAAl - Closed CAA4 - Closed CAA17 - Open CAA20 - Closed CAA33 - C1csed CAA2 - Closed CAAS - Open CAA18 - Closed CAA31 - Clcsed CAA3 - Closed CAA14 - Closed CAA19 - Closed CAA32 - Closed 5.0 IOENTIFICATION OF FCLLOW-UP ACTIONS 5.1 If RCS Pressure decreased rapidly with no other indications of primary or secondary leakage, verify the following are closed or isolated at their individual control bezels.
5.1.1 Pressurizer Spray Valves (PS-l&3) 1.
If PSl or PS3 is open and will not close, trip the Reactor Coolant Pump in the associated loop.
1(2)PS1 - Trip 11(21) RCP 1(2)PS3 - Trip 13(23) RCP 5.1.2 Pressurizer Power Ope;ated Relief Valves (PR1 & 2) 5.1.3 Pressuriter Overpressure Protection Valves (PR 47 & 48 on Unit 2 only) 5.2 If RCS Pressure has stabilized after the initial decrease which initiated Safety Injection and Containment Isolation, the problem may be in an area or system which has been subsequently isolated. Investiate the following:
5.2.1 Auxiliary Building for:
l.
Increases in Radiation 2.
Unexplained accumulations of water 5.2.2 Pressurizer Auxiliary Spray valve (CV75). Ensure it is closed.
1337 02i Salem Unit 1/ Unit 2 Rev. O
9 1-4.0 e
5.3 Utilize the following :tatrix in order to deter.ine which subsequent E.ergency Instruction to follow.
SAFETY I!iJECTIO!1 II;ITIATED
=
- s RCS FFISS IS65:
RCS PRESS > 1865:
ICS PRESS > 2000:
CR LECFIAS:n BLi < 20004 A';D i
PRESS L'.", > 50i i
A'O RCS PRESS g fg 7y;,. 33;
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. 3 GR C04 TO RCP'S GO Tc EI I-4.2 T F*r "FICO'JRY Frat SAI'E"i 0;JFf"I2;"
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CR FRESS. I2NEL OROTS ~O < 20's Er;ITR"'E SAI'F."Y DE!2!,
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CCT-F:G ECGE hi~E RCS TCG OWES S~M GD; EIOCOC4 OR AIR C2.T "CG., PPESS, PAP O LY kTIE ILE C i EmbR It*S E;CEAS2C KT!H h*.7.!;I~T, SCMP IEJEL FFISS E4 0 2 OR F0PI
!O 1 rREASE 2; C3.T-2:CPIASE:G S21 GCi PAFRCERS I
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GO % EI I-4.4 GO M EI I-4.6 GO 'IO r.I I-4.7
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Manager - S' ale-/ Generating Station I
Rebewedby J.M. Zupko SCRC Meeting :o.
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1.b. Flcoding a;- oce,r as a result of a severe rainster: cr hurr::ane.
w 1.2 Satura. cisaster ficoding, defined as that conditien reached wnen the tide level in rcases to the 120.5 fcet elevat:en
(+
11.5 feet MSL), requires the U..i: to be shut down.
P ctec-tive rcasures sh:uld be taken prior to the fleed stage.
The desicn cf building entrances and site grade, provide pr:tection for adverse censinati:ns of wind velocity and tidal variati:n.
1.3 Sur; p rps are pr vided to.mrintain vital areas as dry as pessible. The use of portable punps
.ay te necessary in cases of excessive interior ficoding.
Th:s pr::edure is to be used during:
4.,
1.4.1 Severe sterns including hurricanes, tornades and other stores where high winds in excess of 60 mph have been fere asted for the area or, 1.4.2 The tide level 2:. creases to or abcVe the 99.0 fcot elevation
(> 10.0 feet MSL).
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_ i..r. c.. c 2.1 aind vale:ity s
60 rph_
2.2 Tide level at e'evation 99.0 feet (10.5 feet MSL).
2.3 To r:.a d o
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3.1 Autcratic None
.2 Ma r.ua l 3.2.1 Implerent Emergency Frecedure EP I-2, "Erergen:; Alert".
3.2.2 Insure that the doors listed in Table I and II are clesed, secured, and d:gged (if water-tight door).
., r_.. r-Technical Specification 3.7.5.1 requires all water-tight doors to he closed within 2 h urs and tido level neasure-rents t: he taken cJery tw: h urs f or ficed prot -::::n
'.hc ever the tife l e' e '. increases :: cr 2; ve 10.5'
.ea-Sc2 Level 490 ::ct e ecar:
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e 3.2.3 If pessihie, move the crance er. the Tartine Eu ;dinc rcef :
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1:..m por1tions and positi:n the lockinc devices to recure tre err iP fcre r.: : P
.nds prevail.
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4.k Monitor the tide icvel trend at least cnce each hour.
If the level :n=reases to or aheve a.
the '00.E foot elevation
(+ 11.5 feet MSL), impicment Erergency Proccdure I-3,
" Plant (Unit: Emergency".
e,~n. e Refer tc Te:hnical Specification 3.7.5.1.
4.7 If plant shutdcwn is deemed necessary, take the plant to hot standby in accordance with OI I-3.5, "M nimum Load to Hot Standby", and as required, en to cold shutdcwn in ac Ordance with CI I-3.6, "Het Standby to Cold Shutdown".
4.3 If, as ' resalt cf the storm (i.e.,
ternado), the Auxiliary Feedwater Tank (AFWT) is net avail:ble (e.g.,
tank damaged, ruptured, inop2rable, etc.), to supply auxiliary feedwater for plant shutdown, sh;ft the suction of the Auxiliary Feedwater Pumps to a preferred (i.e., DSNTs er FW & FPWTs alternate supply of water IAW OI III-10.3.1, " Auxiliary Feed-water System Operation.
In addition, if none of the preferred alternate water supplies are available, che Auxiliary Feedwater System shall be connected to the Service Water System fer u=e as an emergency alternate water supply in ac: rdance with CI III-10.3.1,
" Auxiliary Feedwater System Operation".
CATTION To ensure safe shutdown in the event that the auxiliary feedwater supply is lost in cenjunction with the main feedwater supply, shift ever to an alte ate auxiliary feedwater supply (including the installatien of speol pieces) should be acccmplished within apprcximately 30 minutes.
4.3.1 When the AFWT is returned to aa operable status, return the auxiliary feedwater supply te a normal lineup IAW CI III-10.3.1, " Auxiliary Feedwater System Operatien".
4.4 As practical move locse materials to shelter. As conditicas require, valuable equipment and d::umentation should be moved from out-lying, non-perma. tent structures (i.e.,
trailers) to safer s.crage.
4.5 As practical, fill large tanks as full as possible to r e:1ude wind damage or tank buoyancy
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Pcn. 100' C3 S
S:uth Fenetrat :- - East Side CC - 2.:
Nater-Ticht Orcr cen.
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5:cth icnetratien - S0;th Side FF - 2.5 Kater-T:Cht 0:Or Ten. 100' i
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THE Fe c -einc Area Truck Doer - Wert Side SS -
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THS S cra:e Area Truck Door - West Side i 55 -
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THE Stcrare Area - South Side Aux. 100' Manual A:r -
A S lid Padwaste Area - Truck Coor
- 13.0 Orerata: Do r Seal Aux. 100' A
S:.1d Radwaste Area - Weet Side
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S:uth Fenetration to Prof - 5:uth Eida I Fr - 2.2 l COS 130' NA NA Un:t I containment Ecuirrent Hatch Fr - 3.?
Pecu:rcs Crane i
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!Tenetrat;cn Area - West Corner Past Fers. Hatch KF - 9.2 l
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Cafeteria - Southside Exit AB - 10.3 Acm. 100' i
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Kit chen.'Rece i tinc Area - Southside CS - 10.3 t
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Turbine Area - South :-test Cerner to Stairwell
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Turbine Area - West Side by NO. 13 Cendenser N - 3.E I.
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'Servict 21. d c. - South Side Stairwell NP - 10.0 scutn Sice SOS 100' i
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tertF Fenetratien to R:cf - ? orth Side EE - 25.9 w,.=
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Fen. 130' 9s S
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I-4.2 8
EMER0ENCY INSTRUCTION I-4.2 RECOVERY FROM SATETY INJECTICT 1.0.FURPOSE t
u l.1 To deltneste the steps required to tern.nate Safety Injection and return the unit to a normal, shutdown alignment.
2 2.3 Ir!?IAL CONDITIONS such 2.1 The conc.tions as described in one of the following Energency Instructions exist that terninatien of Safety In3ection is required or desirable.
2.1.1 EI I-4.0,
" Safety In3ecticn Initiation", Step 5.3.
2.1.2 EI I-4.6,
" Loss of Secondary Coolant" 2.1.3 EI I-4.7,
" Steam Generator Tube Rupture"
.3 IMEECIATE ACTIONS 3.1
- c n e.
4.0 SrESICUCNT ACTIONS 4.1 Tne Senior Shift Sapervisor/ Shift Super /isor shall ve:ify that the initial conditlens described in Step 2.1 above are satisfied. The operator shall then proceed as follows:
CAUTION If at any t1 e after the Safety Injection is rese*,,
Reactor Coclant Pressure drops unexpectedly by rcre than 200 psig or pressurizer level cannot be maintained at >20% by norr.al charging, re-initiate Safety Injection manually by inserting the key into either Train"A" or Train "B"
Safety Injection Operate Bezel and turning the key.
Peturn to EI I-4.0,
" Safety Injection Initiation", and re-evaluate the plant conditions.
~
4.2 Reset the following signals:
1)
Depress the Train"A" and Train "B" SI RESIT pushtuttons, on the contren console to reset the Safety Injection signal.
~
1337 029 Saler Unit 1/ Unit 2 i-Ps:.,
1-4.2 4
- 2) Depress the Train "A" and Train "B" CCNT ISCL CA FESET pushbuttons, on the control console, to reset the Centainment Phase A Isolation signal.
- 3) Cepress the Train "A" and Train "B" CONT VENT ISCL RESET pushbuttons, on the control console, to reset the Containrent Ventilatten Iso 4ation signal.
O 4)
Oepress the Train "A"
and Train "S" FEECWATER ISOLATION RESET pushbattens, en the control console, to reset the Feedwater Isolatten signal.
5-Oepress the EXERGENCY LCADING RESET pushbuttens, On the centrol conscle, for lA, 1B and 1C (2A, 2B and 2C) 01esel Generators to reset the Safe-guards Loading sequence.
4.:
Peturn the Service Water System to normal lineup IAW OI V-1.3.1,
" Service Water-Normal Operatien".
4.4 Step Centrifugal Charging Pumps and stop the flow thru the Bcron In3ecticn Tank by closing inlet valves 1(2) SJ4 and 1(2) SJ5.
Step the RHR Pumps and Safety In;ection Purps.
CAUTION Prior to stopping both Centrifugal Charging Pumps, insure the reciprocating Charging Pump is running to supply se&l water to the Reactor Coolant Pumps.
If the reciprocating Charging Pump is not running, leave one Centrifugal Charging Pump operating.
4.5 Eeturn Diesel Generators lA, 1B and 1C (2A, 2B and 2C) to normal operation IAW CI-IV-16.3.1, " Emergency Power - Diesel Operation".
4.6 Return the Charging Fumps to their normal lineup IAW OI II-3.3.2, " Operating the Charging Pumps".
4.7 Feturn tne Centainment Ventilation System to normal operation IAW CI II-16.3.1,
" Containment Ventil;. tion Operation".
4.8 Return the Auxiliary Building Ventilation System to normal operation IAW OI II-17.3.1, " Auxiliary Building Ventilatien Operstion".
4.9 Return the Control Room Ventilation System to normal operaticn IAW OI II-17.3.2,
" Control Rocm Ventilation Operation".
L10 Stop the Emergency Control Air Compressor and return the Control Air System to normal operaticn IA.J CI V-5.3.1,
" Control Air System Operatien".
4.11 Open the Containment Control Air Header 1(21 A and 1(2)2 Isolation Valves.
11(21)CA330 12(22)CA330 Salem Unit 1/ Unit 2 Rev. 7
I 4.2 e
4.12 Re-establish letdown and charging flow IAW OI II-3.3.1, " Establishing Charging, Letdown and Seal In3ection Flow".
4.13 Return the Feedwater System to the desired mode of operation IAW OI III-9.3.2, " Feed Pump Operation", and secure the Auxiliary Feed PumpsE t
- 1) Refill the Auxiliary Teedwater Storage Tank as necessary.
- 2) Realign the Auxiliary Feed System for power operation !AW OI III-10.3.1,
" Auxiliary Feedwater System Cperation".
NOTE If desired, the Auxiliary Feed Pumps may remain in service to maintain Steam Generator Levels. The Condensate Pumps may be removed from service if desired.
4.14 Return the Steam Generator Drains and Blowdown System to normal operation IAh' OI III-13.3.2, " Steam Generator Blowdown - Normal Operation".
4.15 Return the Containment / Plant Vent Radiation Mcnitor to normal operation IAW the following Ol'S:
- 1) Unit 1 - O! IV-ll.3.4, "Cperation of the Centainment/ Plant Vent Sampler (Rll/R12)"
- 2) Unit 2 - OI IV-il.3.2, " Operation of Radiation Monitoring Sfstem Samplers" 4.16 Feturn the inlet valves to the Gas Analyzer, fron the Reactor Coolant Orain Tank and Pressurizer Relief Tank, to normal by opening the following valves:
1(2)wt96 1(2)WL97 s
1(2)PRIS 1(2)PR17 4.17 Drain and refill Boron Injection Tank from the Boric Acid Tanks IAw OI II-4.3.2, " Filling and Venting the Safety In]ection System".
CAUTION DC NOT isolate the Boron Injection Tank during the refilling process or during the subsequent sampling to insure the flow path thru the BIT is operable.
4.18 Sample the Boron Injection Tank to verify the Beren concentration is within the Tech Spec limits.
)
Salem Unit 1/ Unit 2 Rev -
I-4.2 i
4.19 Return tne Safety Injection System to nermal IAW OI II-4.3.1, " Safety In3ection System - Normal Operation".
4.2C Make a visual inspection within the Containment when entrj is permissible.
t 4 all After the plant has stablized in the Hot Standby Conditicn, sample the Reactor Coolant System for boron concentration.
w 4.22 Calculate the shutdcwn margin IAW the Reactor Engineer's Manual to ensure that tne reactor is shutdown by >1.6% 2k/k.
4.23 As indicated by plant conditions proceed as follows:
4.23.1 Take the " nit to Cold Shutdown IAW OI I-3.6,
" Hot Standby to Cold shutdown" or 4.23.2 As authori:ed by AP-5, withdraw the shutdown banks as follows:
- 1) Reset the flux rate trip by momentarily taking the RATE MCDE switches, on each NIS POWER RANGE A drawer, to the RESET position.
- 2) Depress the CLOSE pushbutton, on the control console, for REACTOR TRIP BKR A, verifying the breaker does close.
- 3) Depress the CLOSE pushbutton, on the console, for REACTOR TRIP BKR B, verifying the breaker does close.
- 4) Depress the STARTUP pushbutton, on the control console, and verify each Shutdown and Centrol Rod Step Counters reset to zero.
- 5) Commence withdrawing Shutdown Bank A, B,
C and D, in that order, to their fu!1y withdrawn position.
4.24 Complete Attachment No. 1 and attach it to the Operating Incident Report, AP-6.
Prepared By J.V. Bailey M
Manager - Sal'em Cgderatinglstation Reviewed By J.M. Zupko
)2 /
~
56-79 Cate SORC Meeting No.
/
1337 032 Salem Unit 1/ Unit 2 Pe 7
e I-4.2 4
ATTACHMENT NO. 1 POST SATETY INJECTION DATA
- natiafPressuri:erLevel 5
Final.P.ressura:er Level a
PSIG Inittaj Pressurizer Pressure 1:nal Pressurizer Pressure PSIG 7F
- nitial Tavg 7T 7:nal Tavg FWST Terperature (TC650A) 0F Min-Duration of Safety In e:tien l D 91_ o u,
Q 9
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a E= corded B'i Date
..eviewed Ej Date Senor Shift Sapervisor/ Shift super.
Sale Unit 1/ Unit 2 Pev. 7
'1 I-4.3 EylRGENCY INSTRUCTION I-4.3 A.[] DQ I7
~
dlI b ~ J.d'h'_a P 9' 9 REACTOR TRIP U f
- O 6i
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1.0 PURPCSE l.1 A reactor trip is initiated autceatically by the Rea:ter Pretecticn System ;f unsafe cperatino ccndations are approached. It may also be initiated manually from the
- entr:1 c nstle.
This inctructicn provides the actio.ts required to ensure the reacter it in a safe shutdown condition.
.2 In addition to de-energi:ing tne shutdown and control red drive rechanisms, a reacter trip signal will initiate a turbine trip and, in conjunctitn with a icw T,,.
(554'F) initiate a feedwater isolation signal. This instruction delineates the actions required to ensure bcth of these have occurred.
2.0 INITIAL CCNCITIONS 2.1 Any cf the folicwing conditions will lead to a reactor trio 2nd to an automatic plant shutdewn. The cendition causing the trip will be back lighted in red on the first out everhead annunciator panel (Secticn F).
REACTOR TRIP SETPOINT COINCIDENCE INTERLOCY Manual None 1/2 None 2.
Pwr. Range, High Low Setpoint - 25% of 2/4 P-10
- eutron Flux rated thermal pwr.
High Setpoint - 109% of 2/4 None rated thermal pwr.
3.
Pwr. Range, High
+ 5% of rated thermal 2/4 None Flux Rate Trip pwr. in 2 sec.
4.
- . term 4diate Range, Current equivalent to 1/2 P-10 High Neatron Flux 25% of full pwr.
5.
Scurce Range, High 105 counts per sec.
1/2 P-6 Interlocked Neutron Flux with P-10 6.
Overtemperature 17 Variable Setpoint 2/4 None 7.
Overpower IT Variable Setpoint 2/4 None 8.
Low Reactor 1865 psig 2/4 P-7 Coolant Pressure 9.
High Reactor 2385 psig 2/4 Sene Coolant Pressure 10.
Hign Pressurizer 92% Level 2/3 P-7 11.
Low Reactor 90% of Normal Flow 2/3/ Loop P-7 & P-3 Coolant Flow 12.
Riesctor Coolant Pump 75% of Normal Voltage with a 1/2 Taken P-7 Under Voltage 0.2 sec. time delay Twice 13.
Reactor Coolant Pump 56.5 Hertz with a 0.1 second 1/2 Taken P-7 Under Frequency time delay Twice 14.
Reactor Coolant Pu p 10% Pwr. 2 Bkr. Open 1/Pu=p,
'P-7 & P-8 Breaker Open 36% Pwr. 1 Bkr. Open 6
15.
Low Feedwater Flow 1.4 X 10 Stm. Flow greater than 1/2 Flow Nene feedwater flow & 25% S/0 level M: stat:h, in 7
034 ecincidence w---
1 '2 1:w er.:rsi, p.
1:0:.
?e':.4 Salem Unit 1/ Unit 2
I-4.3 REACTDP TRIP SETPOI::7 COIN CIDE':C E IMTERLOCV 16.
Low-Low steam Si Level per S/G 2/3 per S/G
- ene Generator Wtr. Lvl.
17.
Turbine-Generator 45 psig Auto Stop Cil Pressure 2/3 P-7 Trip or all four Stop Valves closed 4/4 18.
Safety Injecticn
- 1. Manual 1/2 S:ne (Actuation)
- 2. Pressuri:er at 17C5 psig 2/3
- ne 3
- 3. Containment at 4.7 psig
- '3 High C:n-
- ne tainment pressure
- 4. Any one S/G 100 psig icwer 1/2 Steam Pressere
- ne than any cther two S/G's en any S/G Lcwer than 1/2 Steam Pres-sures on 2/3 of the other loops.
- 5. Variable: Steam line flow 1/2 High Steamflow on sene 1.4 X 106 e/hr. 0-20% lead, 2/4 Steam Gen. In 6 : ' tu-cein:idence with 2r*
increasing to 4.0 X 10 at 100% pwr. in coincidence LON T't'G or 2/i low with Low TAVG S43'T or Low steam line pressura.
Stn. Press. 500 psig.
19.
General Alarm Logic Train "A"
& Train "B"
in test simultaneously.
NCTE The General Alarm trip is net alarmed on the first out annunciator.
20.
Trip Sypass Skrs.
Racking in, er attempting to rack in, both Reactor Trip Eypass Bkrs at the same time.
NOTE The Bypass Breaker trip is net alarmed on the first out annunciator.
3.3 I:EE0! ATE ACTIO?:S 3.1 Automatic 3.1.1 Reactor Trip 3.1.2 Turbine Trip 3.1.3 Generator Trip 3.2
. Manual a remet:r ::1p has taken place:
3.2.1 Verify tnat Check th_. all ful'. length rods are frily inserted by checking Indicid::al 1) rod position indicators and rod bc::: lignts.
2 If any full length centrcl r:d d:es not indicate fully inserted, ma n ua ll'i Initiate a reacter trip.
1337 0'35
? *'l 4
Salem Unit 1/ Unit 2 I-4.3 Oj
\\
- 3) If all full length control rods are n:t hen.21;y inserted, RATI?
BORATE by 150 ppm (appr0ximately 3 minutes) for ea:h rod not inserted IAW OI II-3.3.2, "Raoid Beration".
3.2.2 Verify turbine trip by checking the following:
i
~
- 1) UNIT TRIP light On E/M censole illuminated.
- 2) Turbine Step Valves, Governor Valves, Inter:epter Valves and Feheat Stop Valves closed.
- ) Turbine speed decreasing.
3.2.3 Mithin 2 minutes reduce Aux. Feedwater Flow to each Steam Generator to approx 1=ately 2.3 x 10' lb/hr.
NOTE This limination applies to Unit No. 1 only.
3.2.l Verify that T,y is decreasing toward or is being maintained at 547'T by either stear durp or atmospheric steam relief.
3.2.;
Verify that Feedwater Isolation has taken place when T,y decreases to 554*F.
3.2.6 Announce ever the plant PA systen twice: UNIT NO. 1(2) REACTCR TRIF.
4.3 SUBSECUEN~ ACTICNS 4.1 Check that nuclear power is decreasing by observing the nuclear instrumentation.
4.1.1 Check that the Source Range high voltage is reinstated bel:w 5 x 10 '*
arps on both Interrediate Range Channels. This should normally occur in apprcximately 15-18 minutes on a trip fren the power range.
- 1) If the Source Range high voltage does net energize automatically, manually depress the RESET SCURCE RANOE "A" and RESET SOURCE F.ANGE "B"
pushbuttens on the control console.
4.1.2 Switch the Nuclear Power Recorder (NR-45) to read one Internediate Range channel and one Source Range Channel.
4.1.3 Notify the Performance Department that a reactor trip has occurred and snat the cenpensatina 'to;tage on the Intermediate Range detectors should be
~
adjusted. This adjustnent is desirable but is not required.
4.2 Verify that the Pressurizer pressura and level are within limits, and under centrol.
Salem Unit 1/ Unit 2
-3
.m e,.,
I-4.3 e
4.3 Verify that the 4160V Group Busses have transferred frem the No. 1(2) Auxiliar'j Fower Transformer to No. 11(12) 6 No. 12(22) Station Power Transformers.
4.3.1 Check that the following 4160V breakers have opened and acknowledge them on the appropriato control console bezel:
1(2) EGGD o
1(2) BFGD 1(2) AEGD li2) AHOO 4.3.2 Check that the fellowing 4160V breakers have closed and acknowledge ther en the appropriate control console bezel:
12(22) GSD 12(22) FSD 11(21) ESD 11(21) HSD 4.4 Verify that Tavg is decreasing toward or is being maintained at 54-DF due to steam dump operation.
4.4.1 Check the following steam dump indication:
- 1) Steam dump valve indication
- 2) Steam dump de and reter.
4.4.2 Transfer steam dump control from the AVERAGE TEMPERATURE CONTROL mode to the SiAIN STEAM PRESSURE CONTROL code.
Ensure that the F.AIN STEAM PRESSURE SP (setpoint) is set to maintain the reacter coolant terperature at a no load avg temperature of 547 F.
(Approxiametly 1005 psig am pressure).
T NOTE If condenser steam dump is nct availiable, atmospreric stese relief must be used for the rereval of residual heat.
4.3 Verify that Feedwater Isolation has taken place due to the reactor trip in coircidence 0
with low Tavg (554 F).
4.5.1 Check that the following valves have closed by observinc their appropriate bezel Indication:
ll(21)BF19 Feedwt__t Control Valve 12(22):F19 Faedwater Control Valve 13(23)BF19 Feedwater control Valve 14 (24) BF19 Feedwater Control Valve 11(21)BF40 Feedwater Bypass Valve 12(22)BF40 Feedwater Bypass Valve g
12(23)5F40 Feedwater Bypass Valve 14(24)BF40 Feedwater Bypass Valve Salem Unit 1/ Unit 2 Rev. 4
I-4.3
(- 33%) as follcas:
Return the levels in the Steam Generators to normal 4.6 the rate of rise to less than 1.2 in/rin whenever level is belcw 4.6.1 Limit 101 en the Narrow Range.
ints and maintain the rate"of rise to
.r
[
4.6.2 Monitor the f ollcwir ; et 0.91/ Min en t*
.rrow rance a i< 0.21/ min. on the wide tange.
a Wide Rance
?: arrow Pance c;C LO403A 50400A or LO401A or LO402A 11(21' LO4:3A LO420A or LO421A or LO422A 12(22)
LO443A LO440A or LO441A or LO442A 13(23)
LO463A LO460A or LO461A or LO462A 14(24)
~
NOTE the computer ir not available, monitor the I'
narrow range indic.'icn on the Control Console and the Wide range recorders on RP-4.
Control Flow to the Steam Generators as required by controlling the following 4.6.3 valves.
1.
il-14(12-24)Aril if No. 13(23) Auxiliary Feedwater Pump is in operation.
2.
11-14 (21-24) AT21 if No. 11 & 12 (21 & 22) Auxiliary Feedwater Pcmps are in operation.
4.7 Establish and maintain the Hot Stanjby condition IAW OI I-3.5, " Minimum Lead to Hot Standby" and OI I-3.8, " Maintaining Het Standby".
If Rx trip was from >15% Rx Power, have the Chem. Dept. perfcrm an I
,I I
4.3 Isotopic analysis between 2 and 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> following the Rx trip.
Obtain a sample of the Reactor Coolant System and determine boren corcentration.
4.9
" Boron Ccncentration Control".
boron concentration as required IAW OI II-3.3.6, Adjust 4.10 As per Administ:rtive Procedure No. 5:
Notify the Station Operating Eng.neer or Chief Engineer of the reactar trip 4.10.1 and; e
IAW AP-6 and forward it to the station 4.10.2 Initiate an Operational Incident Report Operating Engineer.
4.11 If, at this time, it becomes necessary, take the plant to the Cold Shutdown Condition IAN OI I-3.6, " Hot Stardby to Cold Shutdown".
1337 038 pey 4 Salem Unit 1/ Unit 2 e
I
'3 b
4.12 As auch:rized by AP-5, withdraw the shutdown banks as follcws:
cr. each the flux rate trip by mcmentarily taking the RATE MODE switches, 4.12.1 Reset NIS POWER RANGE A drawer, to the RESET position.
for REACTOR TPI? EF.R A, 4.12.2 Depress the CLCSE pushbutton, on the centrol console, verifying the breaker doese close.
i J
for REACTCF TRIF BFP 2,
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4.12.3 Depress tre CLOSE pushbutton, en the centrol censole, verifying the breaker d:es close.
4.12.4 Depress the STARTUP pushbutton, on the centrol censole, and verify each Shut-down and Centrol Rod Step Counter resets to zero.
4.12.5 Octmence withdrawing Shutdown Bank A, B, C and D, in that order, to their fully withdrawn position.
4.13 When the csuse of the trip has been determined and corrected, cbtain the parmissien of the Station Operating Engineer or the Chief Engineer, IAW AP-5, to take the reactor critical.
4.14 With Steam Generator levels within their normal operating bands and Just prior to ccmmencing the recovery startup, perform the following:
4.14.) Pl*'e the Steam Generator Feedwater C:ntrols in MANUAL and run the valve demand te zero.
4.14.2 Reset the Feedwater Isolation signal by depressing the Train "A" and Train "B" FEEDWATER ISOLATION RESET pushbuttons on the control censole.
4.14.1 Maintain Stean Generator levels within their ncrmcl operating bands by manually controlling Feedwater Bypass Valves 11, 12, 13 and 14 (21, 22 23 and 24) BF40.
4.14.4 Return the Auxiliary Feedwater System to its ncrmal at power lineup IAW OI III-10.3.1, " Auxiliary Feedwater System Operatien".
4.15 Return to Power Operation IAW OI I-3.3, " Hot Standby to Minimum Load", and OI I-3.4,
" Power Operation".
Prepared by J.V. Bailey
/
. 6dLdd (
Manager - Sal %/ Generaking Station Reviewed by J.P. Kovacsofsky 7//6/)'k
~
SORC Meeting No.
56-79 Date
'/
/
Salem Unit 1/ Unit 2 pey, 4
s I-4.4 o
EMERGENCY INSTRUCTION I-4.4 LOSS OF COOLANT (LEAKAGE GREATER THAN MAXIMUM CHARGING FLOW) 1.0 JURPOSE al.1 This instruction provides the necessary operator actions required to provide maximum core cooling to minimize core damage following a loss of coolant accident.
1.2 This instruction centains the steps required of the operator to switch from the injection to recirculation phases of core cooling at the appropriate times.
1.3 This instruction includes the appropriate operator actions required to cope with the following failures.
1.3.1 Loss of a Residual Heat Removal Pump due to eitt.er of the following:
a.
Failure of the associated SJ44, RHR Suction from Containment Sump to open.
b.
Failure of an RHR Pump.
1.3.2 Loss of offsite power with:
a.
All diesels operating b.
Failure of a single diesel.
2.0 INITIAL CONDITIONS 2.1 Safety Injection has been initiated and it has been determined by use of Section 5.0, " Identification of Follow-up Actions" of EI I-4.0, " Safety In3ection Initiation" that a loss of coolant accident has occurred.
3.0 IMMEDIATE ACTIONS e
3.1 Verify that all Immediate and Subsequent Actions dercribed in EI I-4.0 _ S
'ty-Injection Initiation" have been performed. Complet any actions which a e not been previously completed.
QD 3.2 If Containment pressure reaches the Hi-Hi Setpoint of 23.5 psig, W rify the following automatic actions hr.ve taken place by observing t k 1 cations on the status panel on RP-4.
'l s
D 3.2.1 Containment Spray Actuation q
3.2.2 Containment Phase "B" Isolation 4) 3.2.3 Main Steam Isolation 1337 040 Salem Un'.t 1/ Unit 2 Rev. 8
I-4.4 3.3 If Containment Phase "B" Iso.' t. ton is actuated, trip all Reactor Coolant Pumps within five minutes.
4.0 SUBSEQUENT ACTIONS - PART I - COLD LEG INJECTION i
M.1 Check the following indicators on the control console to ensure borated water is being it.jecte? into the Reactor Coolant Sy* ten.
a 4.1.1 Boron Injection Tank Pressure indicating RCS Pressure.
4.1.2 Charging Pumps Discharge Flaw 4.1.3 No. 11(21) Safety Injection Pump Discharge flow when RCS pressure is 1500 psig.
4.1.4 No. 12(22) Safety Injection Pump Discharge flow when RCS tressure is s 1500 psig.
4.1.5 No. 11 (21) RHR Injection Flow when RCS pressure is < % 180 psig.
4.1.6 No. 12(22) RHR Injection Flow when RCS pressure is < % 180 psig.
4.2 If Containment pressure has increased to the Hi-Hi setpoint of 23.5 psig, verify the following:
4.2.1 Containment Spray has initiated a.
Check that the following pumps have started. If a pump fails to start, attempt to start manually from the control console, r
No, 11(21) Containment Spray Pump No. 12(22) Containment Spray Pump b.
Check that the following valves have opened. If a valve fails to open, attempt to open manually from the control console.
11(21)CS2 Spray Pump Discharge Valve 12 (22) CS2 Spray Pump Discharge Valve Ng 1(2)CS16 Spray Additive Tank Discharge Valve 1(2)CSl?
Spray Additive Tank Discharge Valve Check the Additive Tank indicator on the control con c.
ensure that the sodium hydroxide (NaOE) solution is being d into the Containment Spray System. Ifthelevelisnotp
- ing, dispatch an operator to verify the level locally and 3 e the following mechanical valves are open.
11 (21)CS20 Eductor Supply Valve
\\
12(22)CS20 Eductor supply Valve (k h) j[ ] j Salem Unit 1/ Unit 2 Rev. 8
I-4.4 PART I 4.2.2 Isolation Phase "E" har taken place a. Check to see tnat the following valves have closed by. observing the status panel and acknowledge on the appropriate contro1 console bezel. 1. If any valve has failed to close, attempt to close" it from the control console bezel. Cocponent Cooling 1(2)CC117 Reactor Coolant Pu:cp Motor Cooling 1(2)CCll8 Reactor Coolant Pump Bearing Inlet 1(2)CCl36 Reactor Coolant Pump Bearing Outlet 1(2)CCl31 Thermal Barrier Discharge 1(2)CC190 Thermal Barrier Discharge 1(2)CC197 Reactor Coolant Bearing Outlet 2. If any heactor Coolant Pumps are running, they must be tripped at this time. 4.2.3 Main Steam Isolation has taken place, a. Chech that the following salves have closed by observing the status panel ar.d acknowledge on the appropriate control console bezel. If any valve has failed to close, attempt to close it from the control console bezel. 11(21)MS167 No. 11 (21) Steam r'anarator Stop Valve 12(22)MS167 No. 12(22) Steam Generator Stop Valve 13(23)MS167 No. 13 (23 ) Steam Generator Stop Valve 14(24)MS167 No. 14 (24 ) Steam Generator Stop Valve 11(21)MS18 No. 13 (21) Steam Generator Stop Warmup Valve 12 (22)MS18 No. 12(22) Steam Generator Stop Warmup Valve 13 (23)MS18 No. 13 (23) Steam Generator Stop Warmup Valve 14 (24)MSlB No. 14 (2 4 ) Steam Generator Stop Warmup Valve ll(21)MS7 No. 11(21) Steam Generator Drain Valve 12 (22)MS7 No. 12(22) Steam Generator Drain Valve 13 (23)M57 No. 13 (23) Steam Generator Drain Valve 14 (24)MS7 No. 14(24) Stear Generator Drain Valve g 4.3 Commence taking the plant to Cold Shutdown Conditio7s by cooling down pb ows: ~ 4.3.1 Manually control the Auxiliary Feedwater Control valves ( o maintain Steam Generator Levels at approximately 334. f. NOTE 44 1337 042 If No.13 (23) AFW Pump is running, (Eswih be necessary to control the AFil Salem Unit 1/ Unit 2 Rev. 8
r I-4.4 PART I .eriodically, reduce the pressure setpoint of the Main Steam Pressure 4.3.4 This action will Controller by depressing the SETPOINT DECREASE pushbutton. increase steam flow thereby continuing the cooldown. i NOTE If steam dump to the condensers is net available, periodically reduce the pressure setpoint of the pressure controller for each MS10 valve by de-pressing their respective PRESS SET PT DECREASE pushbuttons. This action will increase steam flow thereby continuing the cooldown. As applicable, utilize the in11owing Operating Instruction to take the 4.3.3 plant to Cold Shutdown conditions: OI I-3.6, " Hot Standby to Cold Shutdown" 4.3.4 If the Prodae 250 Computer is available, initiate CRT Test No. 41, " Core Temperature / Pressure Monitor Program". 4.4 If Reactor Cnolant Pressure stabilizes above the shutoff head (% 180 psig) of the Residual Heat Removal Pumps, procaed as follows: 4.4.1 Reset Safety Injection by depressing both Train "A" and Train "B" SI RESET pushbuttons on the Safegu1rds Actuation Bezels on the control console. NOTE Automatic Actuation of Safety Injection will no longer be available. Any subsequent actuation of Safety Injection rust be accomplished manually by inserting the Safeguards Key into either Train "A" or Train "B" OPERATE on the Safeguards Actuation Bezel. NOTE If at any time after the Safety Injection and Containment Spray Signals are reset, a Blackout D Signal is recieved, the Vital Busses would be stripped and the blackout loads would be sequenced [ on by the SEC. The RHR, Safety Injection, and g Containment Spray Pumps and the Containment Fan %W [ Coil Units will ng be restarted. These must be manually restarted once the Loading Seque, w is complete as indicated by the " LOADING COMPLETE" lights on the 1A, IB, 1C (2A, 2b % ) Diesel Bezels on the control console, O 1337 043 Salem Unit 1/ Unit 2 Rev. 8
I-4.4 PART I DO NOT restart the equipment by manually initiating Safety Injection or Containment Spray as this may result in undesirable valve operations tihich may result in equipment damage. 4.4.2 Reset the Safeguardt-Loading Sequence by depressing the EMERGENCY ~ LOADING RESET pushbuttons on the control console for lA, 1B, and IC s (2A, 2B, and 2C) Diesel Generators 4.4.3 Stop No. 11 a 12(21 & 22) Residual Heat Removal Pumps. CAUTION If Reactor Coolant Pressure decreases to below the shutoff head (s 180 psig) for the Residual Heat Removal Pumps, restart the pumps. Operate the Safety Injection Pumps as required to maintain pressurizer 4.4.4 level between 20% and 90L. 4.4.5 Restart the following Pump Room Coolers No. 11(21) & 12(22) RHR Pump Room Coolers No. 11(21) & 12(22) Charging Pump Room Coolers No. 11(21) & 12(22) Containment Spray Pump Room Coolers No. 1(2) Aux. Feed Pump Room Cooler 4.4.6 When conditions permit, return the 4kV Vital Busses to normal by: Stopping the Emergency Diesel Generators IAW OI IV-16.3.1, a. " Emergency Power - Diesel Operation". b. Start or stop vital bus loads, as required. 4.5 Closely monitor RWST level. As it approaches the low level alarm (14.1 feet; 132,000 gallons), prepare to change from the injection phase to the Cold Leg Recirculation Phase. Proceed as follows: q ResetSafetyInjectionbydepressingbothTrain"A"andTrain("'pI 4.5.1 RESET Pushbuttons on the Safeguards Actuatior. Sezels on thg$9onWo1 hh console. 0 NOTE );l> Automatic Actuation of Safety Injection wIl g. no longer be available. Any subseque {' hdydation ofSafetyInjectionmustbeaccomplidhsphanually by inserting the Safeguards Key either Train "A" or Train "B" OPERATE on t 76 quards Actuation Bezel. s Salem Unit 1/ Unit 2 Rev. 8
I-4.4 . A* ~" PART I If at any time after the Safety Injection and Containment Spray Signals are reset, a Blackout Signal is recieved, the Vital Busses would be stripped and the blackout loads would be sequenced on by the. SEC. The RHR, Safety [ Injection, and Containment Spray Pumps and the Containment Fan Coil Units will g be restarted. These must be manually restarted see the Loading Sequence is complete as indicatec v the " LOADING COMPLETE" lights on the 1A, 1B, 1C 42A, 2B, 2C) Diesel Bezels on the control console. DO NOT restart the equipment by manually initiating Safety Injection or Containment Spray as this may result in undesirable valve operations which may result in equipment damage. 4.5.2 Reset the Safeguards Loading Sequence by depressing the EMERGENCY LOADING RESET pushbuttone on the Control Console.for lA, 1B and 1C (2A, 2B, 2C) Diesel Generators. 4.5.3 Reset Containment Spray, if Containment pressure is less than 23.5 psig on 3/4 channels, ty depressing Train "A" and Train "B" SPRAY ACT RESET pushbuttons on the Safeguards Ac'uation bezels on the Control Console. 4.5.4 Restart the following Pump Room Coolers No. 11 (21) & 12(22) RHR Pump Room Coolers No. 11 (21) & 12(22) Charging Pump Room Coolers No. 11(21) & 12(22) Containment Spray Pump Room Coolers No. 1(2) Aux. Feed Pump Room Cooler 4.5.5 When Conditions permit, return the 4kV Vital Busses to normal by. a. Stopping the Emergency Diesel Generators IAW OI IV-16.3.1, " Emergency Power - Diesel Operation". b. Start or stop vital bus loads, as re guired. NOTE e If a loss of offsite power has occurred in coincidence with the LOCA, align the g) Electrical System in accordance with Appendix A, prior to proceeding with Parts 8. II or III of this procedure, o cR&' 4.6 Proceed to Section 5.0, Part II - Cold Leg Recircula io'n'M O i777 0'5 Salem tsnit 1/ Unit 2 Rev. 8
I-4.4 T2 5.0 SUBSEQUENT ACTIONS - PAh. n ao a.G RECIRCULATION v CAbTION The changeover from the Safety Injection phase to cold leg recirculation must be done quickly. ~ If any vlaves fail to respond or complete the required movement, continue with the sequence and initiate any corrective actions when the changeover is completed. 5.1 Verify that the following normally closed valves are CLOSED: 11(21)SJ40 11(21) SI Pump Disch Valve to Hot Leg 12(22)SJ40 32(22) SI Pump Disch Valve to Hot Leg 11 (21) SJll3 SI Chg Pumps X-Over Valve 12(22)SJ113 SI Chg Pumps X-Over Valve 11(21)SJ45 Recire Isol Valve to SI Pump M -y '\\h\\ g\\ 11(21)CS36 From 11(21) RHX Valve 12(22)CS36 From 12(22) RHX Valve ( ? - di 1(2)RH2 RHR Common Suction Valve rjg. gn'N (ltp\\Y \\'j h 1(2)RH1 RHR Common Suction Valve Il (21) SJ4 4 SIS Sump Valve U 12(22)SJ44 SIS SEnp Valve 1 (2 ) RH 2 O RHX Bypass Valve 1(2)RH26 RHR Outlet Stop Valve ll(21)RH29* 11(21) RHR Pump Bypass 12(22)RH29* 12(22) RER Pump Bypass 12(22)SJ45 Suction from RHX (to Charging Pumps) NOTE
- 11(21)RH29 and 12(22)RH29 will be closed only if RHR flow is >1200 gpm per pump.
5.2 Verify that there is an adequate water level in the Containment Sump as indicated by an energized SUFFICIENT NPSH light on the control console. 5.3 Open 11(21)CC16 and 12(22)CC16RHR Heat Exhanger Outlet Valves. ,5. 4 Whet. the RWST Low Level Alarm actuates at 14.1 feet (132,000 gals.), sto e following pumps if they are running. No. I1(21) RHR Pump No. 12(22) RHR Pump No. 11 (21) CS Pump or No.12 (22) CS Pump, if containment spray tuation has occurred. D 3 1337 046 Salem Unit 1/ Unit 2 7 Rev. 8
1-4.4 PART II NOTE 1 One CS Pump should continue to operate until the RWST Low-Low level alarm is recieved or the Spray Additive Tank Empties. NOTE 2 Aligning the RHR Pumps as described in the following steps will provide flow to the Charging and Safecy Injection Pumps and the Containment Spray Header. If one RHR Pump is not available to provide flow the other pump will supply the Charging and Safety Injection Pumps and the Containment Spray Header with no additional value operations,'however, the Cold Leg Injection from the operating RHR Pump will have to be isolated by closing the appro-priate SJ-49. NOTE 3 If loss of offsite power has occurred concur-rently with LOCA, see Appendix A for instruc-tions on securing Containment Spray Pump. S.5 Close 11(21)RH4 RHR Pump Suction Valve, if No.11(2)) RHR Pump is available. 5.6 Close 12(22)RH4 RHR Pump Suction Valve, if No. 12(22) RHR Pump is available. NOTE ll(21)RH4 must be closed in order to open 11(21)SJ44. 12(22)RH4 must De closed in order to open 12(22)SJ44. 5.7 Remove the lockout and open ll(21)SJ44 SIS Sump Valve, if No.11(21) RHR Pump is available. 5.8 Remove the lockout and open 12(22)SJ44 SIS Sump Valve, if No. 12(22) RHR Pump is av ailable. 5.9 Close 11(21)RH19 RH Heat Exchanger Outlet Valve. C.' 5.10 close 12(22)RH19 RH Heat Exchanger Outlet Valve 4 5.11 Start No. 11(21) RER Pump.
- h n(\\ f cSN W ga N
1337 047 Salem Unit 1/ Unit 2 -g-Rev. 8
I-4.4 PART II 5.12 Maintain 3,000 gpm on COLD LEG INJECTION 11(21)SJ4 9. flew met by adjusting ll (21) RH18. 5.13 Start No. 12(22) RHR Pump. i E ~ 9.14 Maintain 3,000 gpm on COLD LEG INJECTION 12(22)SJ49 flow meter by adjusting 12(22)RH18. 5.15 Remove the lockout and close 1(2)SJ67, 12(22) Mini Flow Isolation Valve, and 1(2)SJEE 11(21) Mini Flow Isolation Valve. NOTE There are redundant switches on 1(2)RP4 to operate 1(2)SJ67 and 68. Either the pushbutton on the control console or these switches will allow full operation of the valves once the lockout is removed. 5.16 Open 12(22)SJ45 Suction from RHX*, if No. 12(22) RHR Pump is available. ^ a 5.17 Open 11(21)SJ45 Recire Isolation Valve to SI Pu p **, if No. 11(21) RHR Pump is available. NOTES
- To open 11(21)SJ45, the following valves must be positioned as listed below:
- 1) 1(2)RH1 or 1(2)RH2 Closed
- 2) 1(2);J67 or 1(2)SJ68 Closed
- 3) ll(21)SJ44 Open
- To open 12(22)SJ45, the following valves must be positioned as listed below:
- 1) 1(2)RH1 or 1(2)RH2 Closed
- 2) 1(2)SJ67 or 1(2)SJ68 Closed
- 3) 12(22)SJ44 Open e.
S r18 Open ll(21)SJll3 SI Charge Pumps X-Over Valve. Os. 5.19 Open 12 (22)SJll3 SI Charge Pumps X-Over Valve. je 5.20 close 1(2)SJ1 RWST to Charge Pump. .Q
- q s3 )5' 5.21 Close 1(2)SJ2 RWST to Charge Pump.
8S!,3 \\ Salem Unit 1/ Unit 2 _ _ Rev. 8.
o ,3 U.' [ im j.W 6 I-4.4 PART II 5.22 Verify that No. 11(21) SI Pump is operating properly by observing No. 11(21) SI Pump discharge pressure indicator and No. 11(21) S1 Pump discharge flow indicator. ~ 5,23 verify that No. 12(22) SI Pump is operating properly by observing No. 12(22) SI Pump discharge pressure indicator and No. 12(22) SI Pump discharge flow indicator. s 5.24 Verify that No. 11(21) Centrifugal Charging Pur.p is operating properly by observing the Charging Pump discharge flow indicator and Boron Injection Tank discharge pressure indicator. 5.25 Verify that No. 12(22) Cent 2 dfu,1 Garging Pump is operating properly by observing the Charging Pump discharge flow indicator and Boron Injection Tank discharge precsure indicator. NOTE If Containment Sprsy has not been actuated, delete steps 4.26 through 4.29. 5.26 When the RWST Low-Low level alarm actuates at 0.0 feet (0 gallons), stop the following pump: No. 11 (21) Containment Spray Pu=p or No. 12(22) Containmen'. Spray Pump, whichever pump is still running. NOTE 1. Both Containment Spray Pumps should be idle at this time. t 2. If Containment pressure has not decreased to below 23.5 psig, the Containment Spray Pumps cannot be stopped from the control console. To stop the pumps, it will be necessary to trip the breakers locally on the 1A and 1C (2A and 2C) 4kV vital busses by turning off the 125 VDC control power and depressing the manual trip button inside the breaker cabinet. 5.27 Remove the lockout and close 12(22)SJ49 Low Head SJ Stop Valve. [11(21)SJ4S if No. 12(22) RHR Pump is not available). 5.28 open the following Containment Spray valves: ~ 12(22)CS36 [ll(21)CS36 if No.12 (22) RER Pump is not available), M g 5.29 Close the following Containment Spray Valves: 11(21)CS2 e s 12(22)CS2 y eg" 1337 049 03 Salem Unit 1/ Unit 2 b Rev. 8
1-4.4 PART II 5.29.1 Continue Spray operation for a minimum period of 24 hours in order to. assure Containment integrity and removal of airborne-fission products from the Containment atmosphere. i ~ 1 NOTE ^ ';9y The Emergency Core Cooling System is now aligned 't for Cold Leg Recirculation as follows: Y
- 1) RHR Pump No.11(21) is supply water from
- h#
the Containment Sump directly to RCS loop t, 7 .g 11(21) and 13 (23) cold Legs via valve ...? 11(21)SJ49 and to the suction of the Safety ,?.. 1< Injection Pumps through valve 11(21)SJ45. ~ 2). RHR Pump No.12(22) is supplying water from ~- 'the Containment Sump directly to the Contain- ^ *
- ment Spray Header and to the suction of the Y',
Charging Pu.mps through valve 12(22)SJ45. -Le d ;y follcwing Accumulator Isolation Valves, if the Accumulator pressure is
- 5. X-
-Jd to be less than 250 psig. -11(21)SJ54 No. 11(21) Accumulator Tank Ootlet Valve - 12 (22) SJ,54 No. 12(22) Accumulator Tank Outlet Valve 13(23fSJ54 No. 13(23) Accumulator Tank Outlet Valve 14(24)SJ54 No. 14(24) Accumulator Tank Outlet Valve 5.31 Closely monitor the Containment H concentration on RP-5. When the concentration y exceeds % 24, place the Hydrogen Recombiners in service IAW OI II-15.3.1, " Hydrogen Recombiners - Normal Operation". I eW f ~ s. 4, @Y 1337 050 Salem Unit 1/ Unit 2 .gg, Rev- 0 ~ ,. ~ ~,.
I-4.4 PART III 6.0 SUBSEQUENT ACTION - PART III - HOT LEG RECIRCULATION After approximately 22.5 hours of cold leg recirculation, realign the Safety Injection System for tiot Leg Recirculation. The sequence for the changeover from Cold Leg Recirculation to Hot Leg Recirculation is as follows: B NOTE If a loss of offsite power has occurred in coincidence with the LCCA and one of the Diesel Generators has failed to stae+ refer to Section 4.0 of Par
- II, III or IV of Appendix A, as applicable.
6.1 Close 12 (22)CS36 from 12 (22) RHX Valve. 6.2 Open 12 (22)RH19 RHX Cross Discharge Valve. 6.3 open 1(2)RH26 RHR outlet Stop Valve. 6.4 Close 11(21)SJ49 Low Head SJ Stop Valve. 6. 5-Stop No.11(21) Safety Injection Pump. 6.6 Close 11(21)SJ124 SI Pump Discharge to Cold Leg. 6.7 Open ll(21)SJ40 SI Pump Discharge to Hot Leg. 6.8 Start No.11(21) Safety Injection Pump. 6.9 Verify that No. 11(21) Safety Injection Pump is operating properly by observing No. 11 (21) SI Pump Discharge pressure and flow indicators (a pressure of 175 to 1520 psig and an approximate flow of 400 gpm should be indicated). 6.10 Stop No. 12(22) Safety Injection Pump. 6.11 Close 12(22)SJ134 SI Pump Discharge to Cold Leg. ff 6.12 Open 12(22)SJ40 SI Pump Discharge to Hot Leg. 8 kb 4 ) 4.13 Start No. 12(22) Safety Injection Pump. Os. W ? 6.14 Verify that No.12 (22) e SafetyInjectionPumpisope{ati prope,rly by observing No. 12(22) SIPumpdischargepressureandflowinica$ bra ( a pressure of 175 to 1520psigandanapproximateflowof400gpmsh6b(lqfbeindicated). (65 } ~' _? Salem Unit 1/ Unit 2 Rev. 8 ~~-
2-4.4 PART IM NOTE The Residual Heat Removal Pumps and Safety In-jection Pumps are now aligned for Hot Leg recir-culation as follows: 1) No. 11 (21) RHR Pump is supplying water from the Containment Sump to the suction header of the Safety Injection Pumps. 2) No. 12(22) Rhk M is suPP ying water l from the Containment Sump to the Reactor Coolant System through RCS loops 13(23) and 14 (24) ::ot Legs and to the suction of the Centrifugal Charging Pumps. 3I No. 11(21) Safety Injection Pump is supplying cooling water to the Reactor Coolant System through RCS loops 13 (23) and 14(24) Hot Legs. 4) No. 12(22) Safety Injection Pump is sypplying cooling water to the Reactor Coolant System through RCS loops 11(21) and 12(22) Hot Legs. 5) No. 11(21) and 12(22) Charging Pumps are supplying cooling water to the Reactor Coolant System through the BIT via the Cold Legs. Prepared by Manager - Salem Generati SMtion Reviewed by [ th h SORC Meeting No. Date ('&f aY ,s 1337 052 Salem Unit 1/ Unit 2 Rev. 8
I-4.4 APPENDIX A DICCUSSION_ If a loss of offsite power has occurred in coincidence with the LOCA, the Diesel Generators wi,11 be supp,1ying power to the vital busses. During the recirculation phase, it _is necessary to run the Corponent Cooling Pumps and the Hydrogen Recombiners. In order to accombdate this additional load, other equipment must be stopped before the Component Cooling Pumps and Hydrogen Recombiners are started to prevent overloading the Diesel Generators. After the Safety Injection and SEC are reset, proceed with the appropriate section. I - ALL DIESEL GENERATOP.S OPERATING 1.0 Stop the following equipment NCTTE Do not stop looth No. 11(21) and 12(22) Containment Spray Pumps until the RWST Low-Low level alarm actuates. When ~ ^ entering Cold Leg Recirc., stop only one Containment Spray Pump, either 11(21) or 12 (22). 1.1 Equiprent on lA(2A) Vital Bus (powered by 1A(2A) Diesel / Generator) ~ '. ~No. 11'(21) Containment Spray Pump ~~ ~~ ~
- ~~ ~ ~ ~ ~ ~ ~ ~ "
~ ~ a b. No. 11(21) Auxiliary Building E2 aust Fan ~~~~ c. No. 11f21) Switchgear Room Supply Fan ~~ d. No. 11(21) Chiller 1.2 ~ Equipment on 1B(2B) Vital Bus (powered by IB(2B) Diesel / Generator) a. No. 12(22) Containment Fan Coil Unit b. No.14(24) Containment Fan Coil Unit 1.3 Equipment on IC(2C) Vital Bus (powered by IC(2C) Diesel / Generator) a. No. 12 (22) Containment Spray Pump [ ~b. No. 11(21) Auxiliary Building Supply Fan 2.0 Start the'following equipment: ' '~ h ~~ -- f CAtrIION g When entering Cold Leg Recirc. star onl/ one ~ Component Cooling Pump. Ensure t W dosponent Cooling Pump to be started is en ki)Idfrom the same Vital Bus as was the containhent Spray Pump, secured from in the above step. Salem Unit 1/ Unit 2 Page 1 of 6 E8 V
- O
1-4.4 \\ E.u.pment on lA(2A) Vital Bus (powered by 1A(2A) Diesel / Generator) a. No. 11 Component Cooling Pump or 2.2 Equipment on IC(2C) Vital Bus (powered by IC(2C) Diesel / Generator). i a. No. 13 (2 3) Component Cooling Pump NME Od i O If irradiated fuel is stored in the Fuel Handling Building, start No.11 & 12 (21 4 22) THB Exhaust Fans. 3.0 open ll(21)SW122 and 12(22)SW122 to supply Service Water to Component Cooling. II - TAILUPI OP 1A(2.M DIESP.L GENERATOR 1.0 Stop the follet.ng equipments 1.1 Equipment on 1B (2B) Vital Bus (powered by 1B(2B) Diesel / Generator) a. No. 11(21) Charging Pump b. No. 12(22) or No. 14(24) Containment Fan Coil Unit c. No. 12(22) Auxiliary Building Supply Fan 1.2 Equipment on IC(2C). Vital Bus (powered by IC(2C) Diesel / Generator) a._;No.,12(22) Containment Spray Pump when RWST Low-Low level alarm actuates. 2.0 Start No.12 (22) Component Cooling Pump and open 12 (22)SW122 to prcvide Service Water to Component Cooling. NCYTE If irradiated fuel is stored in the Fuel pc. ,,,.... Handling Building, start No. 12(22) FHB Exhaust Fan. E 3.0 The following should be the alignment for Cold Leg Recirculatioq. p 3.-1 _ _ The_following pumps should be running '.< 9* . u.a. No.,12(22) RHR. Pump, 4 g b. No. 12 (22) Charging Pump c. No. 12 (22) Safety Injection Pump _ d. No. 12 (2 2) Containment Spray Pump, until RWST Low-Low level alarm actuates.
- v. :. i..... -...
~~~ 1337 054 Salem Unit 1/ Unit 2 Page 2 of.6 Rav. O sw
l-4.4 3.2 Close valves 12(22)RH19 and 12(22)SJ45 to prevent flow to the Cold Ings and to insure adequate flow to No. 12(22) Charging Pump and No. 12(22) Safety Injection Pump suctions and to insure flow to the Contai.dnent Spray Header through 12(22)CS36 when it is opened. 3.-3 The Cold Leg Recirculation Flow Path would be as follows: i a. No. 12(22) RHR Pump taking suction on the Containment Sump and discharging to the suctions of No. 12(22) Charging Pump and No.12(22) Safety Injection Pump through 12 (22)SJ45,12(22)SJll3,11(21)SJ33 and 12(22)SJJ3. b. No. 12(22) Chargi1g Pump Discharge through the Boron Injection Tank to all four Cold Legs. c. No. 12(22) Safety Injection Pump Discharge through 12(22)SJ134 and 1(2)SJ135 to all four Cold Legs. d. 12(22) Containment Spray Pump taking suction from th>t RWST and discharge to the Spray Header. 4.0 Proceed as follows for Hot Leg Recirculation 4.1 Close 12(22)CS36 to stop containment Spray. 4.2 Stop No. 12(22) Safety Injection Pump and No. 12(22) Charging Purtp. 4.3 Close 12(22)SJ134 and 1(2)SJ135 to isolate Cold Leg Recirculation. 4.4 Open 12 (22)SJ40 to supply Hot Leg Recirculation. 4.5 Start No. 12(22) Safety Injection Pump. 4.6 The Hot Leg Recirculation flow path would be as follows: a. No. 12 (22) RHR Pt np taking suction on the Containment Sump and discharging to the suctions of No.12(22) Charging Pump and No. 12(22) Safety Injection Pump through 12 (22)SJ45,12(22)SJll3, ll(21)SJ33 and 12 (22)SJ33. & 12 .b. No. 12 (22) Safety Injection Pump discharging through 12(22)SJ40 to (21 & 22) Hot Legs. III - JAILURE OF IB(2B) DIESEL GENERATORS _ r ~' o 1.0 Stop the following equipments o NOTE ~ ~ ~ ~ ~ Do not stop both 11(21) and 1 ontainment Spray Pum1 s until the RWST Iow-w level alarm actuates. When entering Cold Leg Recirc., stop only No. .2(22) Containment Spray Pump.
i i I 1-4.4 l 1.1 Equipment on IA(2A) Vital Dus (pu.s.ed by 1A(2A) Diesol Generatc2) a. No. 11(21) Containment Spray Ptmp when RWST Low-Low level alarm actuates. 1.2 Equipment on IC(2C) Vital Bus (powered by IC(2C) Diesei Generator). i a. No. 12 (22) Containment Spray Pump b. No. 12(22) Safety Injection Pump 2.0 Start No.13(23) Component Cooling Pump and open ll(21)SW122 to provide Service Water to Component Cooling. NOTE If irradiated fuel i', Otored in the Fuel Handling Building, start No.12(22) FHB Exhaust Fan. 3.0 The following should be the alignment for Cold Leg Recirculation 3.1 The following pumps should be runnings a. No. 11(21) RHR Pump b. No. 12(22) Chargin-Pump c. No. 11(21) Safety Injection Pump d.' No. 11(21) Containment Spray Pump, until RWST Low-Iow level alarm actuates. 3.2 Close valves 11(21)RH19 and 11(21)SJ49 to prevent flow to the C.!Dd Legs and to insure adequate flow to No. 12(22) Charging Pump and No.11(21) Safety injection Pump suctions and to insure flow to the Containment Spray Header through ll(21)CS36 when it is opened. 3.'3 The Cold Leg Recirculation Flow Path would be as follows: a. No. 11(21) RHR Pump taking suction on the Containment Sump and discharging to the suctions of No. 12(22) Charging Pump and No 11(21) Sefety Injection Pump hrough ll ( 21) SJ 45, 11 ( 21) SJll 3, 11 ( 21) SJ 33 and ll ( 22 ) SJ 33. b. No. 12(22) Charging Pump discharging through the Boron Injection. k R all four Cold Legs. .Sh ~ c. No. 11(21) Safety Injection Pump discharging through 11( and 1(2)SJ135 to all four cold Legs. ~ A d.. No. 11(21) Containment Spray Pump discharging to the'$, pray Heading, until RWST ~ Low-Low level alarm actuates. Nd* 4.0 Proceed as follows for Hot Leg Recirculation ~ 056 4.1 Close ll(21)CS36 to stop containcent spray. Salem Unit 1/ Unit 2 Pace 4 of 6 ,Rev. 8
I-4.4 4.2 Stop No. 11(21) Safety Injection Pump. 4.3 Close 11(21)SJ134 to isolate Cold Leg Recirculation. 4.4 open ll(21)SJ40 to supply Hot Leg Recirculation. s 4 '. 5 Start,No. 11(21) Safety Injection Pump. 4.6 The Hot Leg Recirculation Flow Path would be as follows: a. No. 11(21) RER Pump taking suction on the Containment Sump and discharging to the suction of No. 11(21) Safety Injection Pump througn 11(21)SJ45,11(21)SJll3, 11(21)SJ33, and 12 (22)SJ33. b. No. 11 (21) Safety Injection Pun:p discharging through 11(21)SJ40 to No. 13 & 14 (23 s 24) Hot Legs. c. No. 12 (22) Charging Pump discharging to all RCS Cold Legs. IV - FAILURE OF IC(2C) DIESEL GENERATOR 1.0 Stop the following equipment: 1.1 Equipment on lA(2P.) Vital Bus (powered by 1A(2A) Diesel / Generator) ~ No. 11 (21) Containment Spray Pump, when RWST Low-Low level alarm actuates. a. ,b. No. 11(21) Auxiliary Feedwater Pump 1.2 Equipment an IE(2B) Vital Bus (powered by IB(2B) Diesel / Generator) a. No. 12 (22) RHR Pump 2.0 Start No. 12(22) Component Cooling Pump and open ll(21)SW122 to provide Service Water to Component Cooling. NOTE ~ If irradiated fuel is stored in the Fuel Handling Building, start No. 11 & 12 P (21 & 22) FHB Exhaust Fans. J 3.0 The.following should be the alignment for Cold Leg Recirculatiop Y 3.1 The following pumps should be running: w v a. No. 11(21) RHR Pump b. No. 11(21) Charging Pump c. No. 11(21) Safety Injection Pump d. No. 11(21) Containment Spray Pump, until RWST Low-Low level alarm actua* Salem Unit 1/ Unit 2 } } [ h } f Rev.8 Page 5 of 6
t I-4.4 3.2 Close v'alves' 11(21)RH19 and ll(21)SJ49 to prevent flow to the Cold Legs and to insure ~ adequate flow to No. 11(21) Charging Pump and No. 12(22) Safety Injection Pump suctions and to insure flow to the Containment Spray Header through 11(21)CS36 when it is opened. i 3.*J The Cold 14g Recirculation Flow Path would be as follows: i a. No. 11(21) RHR Pump taking suction on the Containment Sump and discharging to the ~ suctions of No.11(21) Charging Pump and No. 11(21) Safety injection Pump through 11(21] SJ45, ll(21)SJ113,12 (22)SJ113,11(21)SJ33, and 12 (22)3J33. b. No. 11(21) Charging Pump discharging through the Boron Injection Tank to all four Cold legs. c. No. 12(22) Safety Injection Pump discharging through 12(22)SJ134 and 1(2)SJ135 to all four Cold Legs. d. No. 11(21) Containment Spray Pump discharging to Spray Header, until RWST Low-Low level alarm actuates. 4.0 Proceed as.follows for Hot Leg Recirculation: 4.1 Close ll(21)CS36 to stop Containment spray. 4.2 Stop No. 11(21) Safety Injection Pump. f 4.3 Close 11(21)SJ134 and to isolate Cold Leg Recirculation. 4.4 Open 11(21)SJ40 to supply Hot leg Recirculation. 4.5 Start No. 11(21) Safety Injection Pump. 4.6 The Hot Leg Recirculation Flow Path would be as follows: a. No. 11(21) RHR Pump taking suction on the Containment Sump and discharging to the suctions of No. 11(21) Charging Pump and No. 11(21) Safety Injection Pum ough 11 ( 21) SJ 45, ll (21) SJll3, 12 (22 ) SJ113, 11 ( 21) SJ 33, and 12 ( 22) SJ 33. b. No. 11(21) Safety Injection Pump discharging through ll(21)SJ40 to T3 & 14 (23 & 24) Hot Legs. c. No. 11(21) Charging Pump discharging to all RCS Cold Legs. 5.0 Transfer the Security System to the emergency power supply on lA 2 WVital Bus. &(ip e 1337 05B Salem Unit 1/ Unit 2 Page 6 of 6 Rev." 6
I-4.5 EMERGENCY INSTRCCTION O 'O ' 0 00
- ~* 5 LOSS OF REACTOR COOLANT PCMP AND/OR FLOW iQ3 1.0 DISCUSSION 1.
The purpose of this emergency instruction is to describe the automatic actions and operator manual actions, and subsequent actions for a loss of reactor coolant flow. 1.2 Automatic protection circuits are employed to insure that proper flow conditions exist during power operation. These automatic trips can be caused by undervoltage or underfrequency (1 out of 2 taken twice) cn the 4kV group busses which supply power to the Reactor Coolant Pump motors, or Reactor Coolant Pump motor supply breakers openir.c or low flow condition indicated on 2 of the 3 flow instruments in each loop. 1.3 Below the P-7 interlock (10% power) there is no automatic loss of flow protecticn. However, the reactor must never be critical or brought critical with less than two Reactor Coolant Pumps in operation. From P-7 to P-B'(10% to 364 power) three Resetcr Coolant Pumps are required and when the P-8 interlock is in effect (above 36% power) four Reactor Coolant Pumps are required to prevent a reactor-turbine trip. 1.4 Two conditions listed as Part I and II, are described in this instruction: I Loss of Reactor Coolant Flow, With a Reactor Trip II Loss of Reactor Coolant Flow, Without a Reactor Trip. 2.0 SYMPTOMS 2.1 The following could be indicative of a loss of reactor coolant flow: 1. Low flow indicated in one or mere reactor coolant loops. 2. One or more Reactor Coolant Pump creakers indicating a tripped condition. PART I I LCSS OF REACTOR COGLANT WITH A REACTCR TRIP 3.0 (I)~ IMMEDIATE ACTIONS -- Automatic 1. Reactor Trip 2. Turbine Trip and Generator Trip Manual Refer to EI I-4.3, "Peactor Trip". Salen Cnit 1/Cnit 2 Fev :
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I-4.6 EMERGENCY INSTRUCTION I-4.6 LOSS OF SECONDARY COOLANT 1.0 PURPOSE 1.1 This instruction provides the necessary operator actions required to locate and isolate the source of a loss of secondary coolant to minimize the uncontrolled cooldown of the primary plant. 1.2 This instruction contains the actions required to establish decay heat removal from the Reactor Coolant System via the unaffected Steam Generators to prevent the Pressurizer Safety Valves and Power Operated Relief Valves from lifting. 1.3 A feed line rupture downstream of the Feedwater Header Manual Isolation Valves ll-14(21-24)BF22 will have the same characteristics as a steam line rupture and will be virtually indistinguishable. However, it is important for the faulty Steam Generator to be identified and isolated rapidly to preclude a loss of feedwater flow to all Steam Generators through the single line failure. 1.4 This instruction contains the steps required to shift from the injection to the Cold Leg Recirculation mode of core cooling at the appropriate time. 1.5 Also included are the appropriate operator actions required to cope with the following failures:
- 1. 5.1 Loss of a Residual Heat Removal Pump due to either of the following:
A. Failure of the associated SJ44, RHR Suction from Containment Sumr, to open B. Failure of an RHR Pump.
- 1. 5. 2 Loss of offsite power with:
A. All Diesels operating B. Failure of a Single Diesel 2.0 I.NITIAL CONDITIONS A 2.1 SafetyInjectionhasbeeninitiatedandithasbeendeterminedb{ Section 5.0, " Identification of Follow-up Actions" of EI I-4.0, "Safet ^ ' ction Initiation" that a loss of secondary coolant has occurred. fr / 3.0 IMMEDIATE ACTIONS v 3.1 Verify that all Immediate and Subsequent Actions de d in EI I-4.0, " Safety Injection Initiation" have been performed. Compl actions which have not been previously completed. 1337 061 Salem Unit 1/ Unit 2 Rev. 7
I-4.6 3.2 If Containment Pressure reaches the Hi-Hi setpoint of 23.5 psig, verify the following on RP-4 3.2.1 Containment Spray Actuation 3.2.2 Containment Phase "B" Isolation 3.2.3 Main Steam Isolation 3.3 If Containment Phase "B" Isolation is actuated, trip all Reactor Coolant Pumps within five minutes. 4.0 SUBSEQUENT ACTIONS - PART I - COLD LEG INJECTION 4.1 Verify that Main Steam Isolation has occurred. 4.1.1 Check that the following valves have closed by observing the status panel and/or the censole bezel and acknowledge on the appropriate console bezel. If any valve has failed to close, attempt to close it from the control console. 11(21)M5167 No. 11(21) Steam Generator Stop Valve 12(22)MS167 No. 12(22) Steam Generator Stop Valve 13(23)MS167 No. 13(23) Steam Generator Stop Valve 14 (24 )MS167 No. 14(24) Steam Generator Stop Valve ll ( 21) MS18 No. 11(21) Steam Generator Stop Warmup Valve 12(22)MS18 No. 12(22) Steam Generator Stop Warmup Valve 13 (23 ) MS1B No. 13(23) Steam Generatc; Stop Warmup Valve 14 (24) MS18 No. 14(24) Steam Generator Stop Warmup Valve ll (21) MS7 No. 11(21) Steam Generator Drain Valve 12(22)MS7 No. 12(22) Steam Generator Drain Valve 13 (23 ) MS7 No. 13 (2 3) Steam Generator Drain Valve 14 (24 )MS7 No. 14(24) Steam Generator Drain Valve NOTE Steam Line Isolation may not be initiated on a feed line rupture. If it is not initiated, manual initiation should be accomplished by depressing the Main Steam Line Isolation pushbutton for each steam line on either the Train "A" or Train "B" Safeguard bezels. 4.2 Check the following indications on the control console to ensure borated ter is being injected into the Reactor Coolant System. S> 4.2.1 Boron Injection Tank Pressure indicating RCS Pressure. 4.2.2 Charging Pump discharge flow. Y 4.2.3 No. 11(21) Safety Injection Pump discharge f en RCS Pressure is $3 1337 062 < s 1500 psig. Salem Unit 1/ Unit 2 Rev. 7
PART I I-4.6 4.2.4 No. 12 ( 22 ) Safety Injection Pump discharge flow when RCS pressure is 1500 psig. NOTE Reactor Coolant System pressure should stabilize ebove the shutoff head (% 180 psig) for the Residual Heat Removal Pumps, therefore, these pumps will be running on recire. 4.3 If Containment pressure has increased to the Hi-Hi setpoint of 23.5 psig, verify the following: 4.3.1 Containment Spray has initiated A. Check that the following pumps have started. If a pump fails to start, attempt to start if manually from the control console, No. 11(21) Containment Spray Pump No. 12(22) Containment Spray Pump B. Check that the following valves have opened. If a valve fails to open, attempt to manually open it from the control console. 11(21)CS2 Spray Pu=p Discharge Valve 12(22)CS2 Spray Pump Discharge Valve 1(2)CS16 Spray Additive Tank Discharge Valve 1(2)CS17 Spray Additive Tank Discharge Valve C. Check the Additive Tank level indicator on the control console to ensure the Sodium Hydroxide (NaOH) solution is being injected into the Containment Spray System. If the level is not decreasing, dispatch an operator to verify the level locally and to insure the following mechanical valves are open. Il(21)CS20 Eductor Supply Valve 12(22)CS20 Eductor Supply Valve 4.3.2 Phase "B" Isolation has taken place. A. Check that the following valves have closed by obcerving the sta nel and acknowledge on the appropriate control console bezel. If ve has failed to close, attempt to close it from the control c s ezel. P 1(2)CCll7 Reactor Coolant Pump Motor Cooling J 1(2)CCll8 Reactor Coolant Pump Bearing Inlet 1(2)CCl36 Reactor Coolant Pump Bearing Outlet g 1(2)CCl31 Thermal Barrier Discharge 4-1(2)CC190 Thermal Barrier Discharge 1(2)CC187 Reactor Coolant Bearing Outlet }[ ]4}
I-4.6 i PART I B. If any Reactor Coolant Pumps are running, they must be tripped at this time. 4.4 Verify the RHR Pumps are operating on recirc by insuring the associated RH-29, RHR Pump Recire, is open. 4.4.1 If either RH-29 is not open, place the valve in MANUAL and attempt to open the valve. 4.4.2 If either RH-29 will not open, proceed as follows: A. Reset the Safety Injection signal by depressing both Train "A" and Train "B" SI RESET pushbuttons on the Safeguards Actuation Bezels on the control console. B. Reset the Safeguards Loading Sequence by depressing the EMERGENCY LOADING RESET pushbuttons on the control console for IA, IB, IC(2A, 2B, 2C) Diesel Generators. C. Stop the associated RHR Pump. CAUTION DO NOT RESET the Phase "A" Isolation, Feedwater Isolation, or Containment Ventilation at this time. 4.5 Determine the location of the rupture as described below. The following indications and actions assume Main Steam Isolation has occurred. 4.5.1 Downstream of the Main Steam Isolation valves: A. Steam flow on all lines should indicate zero and all Steam Generator pressures should be stabilized at approximately the same pressure. B. Proceed to Subsequent Action Step 4.6. 4.5.2 Upstream of the Main Steam Isolation valves. (This includes the Main Feed-water Header downstream of the BF-22 valves, and the blowdown lines up eam of the GB-4 Containment Isolation Valves). A. One Steam Generator will have a decreasing pressure. This 4 t faulty Steam Generator. N ( B. Isolate Atixiliary Feedwater to the affected Steam, tor by closing the flow control valves, AFil and AF21, to the aff eam Generator. ~ 1337 064 Salem Unit 1/ Unit 2 Rev. 7
I-4.6 PART,, C. If the rupture is inside the containment as indicated by an increase in containment temperature and pressure, proceed to Subsequent Action Step 4.8. D. If the rupture is outside the containment, there shodld be no change in containment temperature or pressure. Proceed to Subsequent Action Step 4.6. 4.6 If the Prodac 250 Computer is available, initiate LAT Test No. 41, " Core Temperature / Pressure Monitor Program". 4.7 When the Reactor Coolant System has reached a stable condition as described by one of the following sets of conditions, terminate Safety Injection. A. 1. One or more T is 1 350'F as read on the Wide Range Temperature H Recorders on RP-4, AND, 2. Reactor Co:ilant pressure is increasing, AR, 3. Pressurizer level is > 20% on at least 2/3 Hot Calibrated channels and is increasing. -OR-B. 1. All four T are > 350*F as read on the Wide Range Temperature Recorders H on RP-4, Ay, 2. Reactor Coolant Pressure is > 2000 psig and is stable or increasing, g, 3. Steam Generator Level is being maintained at % 33% as indicated on at least 2/3 Narrow Range Channels in one or more Steam Generator not affected by the break, AR, 4. Pressurizer Level is > 50% on at least 2/3 Hot Calibrated Channels. NOTE If the criteria described in "A" above are used for termination of Safety Injection and the Reactor g Coolant temperatures increase to > 350"F, maintain p the Safety Injection Pumps in operation until all 4 criteria for "B" above are satisfied. h 4.7.1 Reset the safeguards actuation by performing the follow f a. Reset the Safety Injection signal by depressi > Train "A" and Train "B" SI RESET pushbuttons on the safeguards ao son bezels on the 337 065 control console. D Salem Unit 1/ Unit 2 Rev. 7
I-4.6 PART I b. Reset the safeguards loading sequence by depressing the EMERGENCY LOADING RESET pushbuttons on the control console for lA, 1B and 1C (2A, 2B and 2C) Diesel Generators. c. Reset the Phase "A" Containment Isolation by depressing both CONT ISOL 9A RESET pushbuttons on the safeguards actuation bezels on the control console. CAUTION If RCS Pressure decreases by > 200 psig or Pressu-rizer Level decreases to < 20% following termination of Safety Injection, manually reinitiate Safety Injection by inserting the Safeguards Key into either Tra.n "A" or Train "B" OPERATE on the safeguards Actuation Bezel and return to EI I-4.0, " Safety Injection Initiation" to further evaluate the plant conditions with particular emphasis on the Loss of Coolant and Steam Generator Tube Rupture. 4.7.2 Stop both Residual Heat Removal Pumps. 4.7.3 Operate the Safety Injection Pumps as necessary to maintain Pressurizer Level between 20% and 90%. 4.7.4 Refer to EI I-4.2, " Recovery from Safety Injection," for guidance in returning additional support systems to operation as required to accomplish the subsequent cooldown. 4.7.5 Proceed to Subsequent Action Step 4.10 of this instruction. 4.8 If the Prodae 250 Computer is available, initiate CRT Test No. 41," Core Temperature / Pressure Monitor Program". 4.9 If Containment Spray has been actuated, proceed as follows when containment pressure decreases to < 23.5 psig on 3/4 channels. 4.9.1 Depress the Train "A" and Train "B" SPRAY ACT RESET pushbuttons Safeguards Actuation Bezel on the control console. ,N 4.9.2 Closely monitor RWST Level. As is approaches the Low-Low ev Alarm (0.0 w ) feet, 0.0 gallons) prepare to change from Cold Leg Inje o Cold Leg Recirculation. Proceed as follows. {d / Reset Safety Injection by depressing both TraI g " and Train "B" SI RESET a. pushbuttons on the Safeguards Actuation Bet jpn the control console. 4% Y 1337 OA6
I-4.6 PART I NOTE Automatic Acutation of Safety IV *ction will no longer be available. Any subsequent actuation of Safety Injection must be accomplished manually by inserting the Safeguards Key into either Traia "A" or Train "B" OPERATE on the SafeJuards Actuation Bezel. NOTE If at any time after the Safety Inejection and Containment Spray signals are reset, a blackout signal is received, the Vital Busses would be stripped and the blackout loads would be sequenced on by the SEC. The RHR, Safety Injection, and Containment Spray Pumps and the Containment Fan Coil Units will ng be restarted. These must be manually restarted once the Loading sequence is complete as indicated by the LOADING COMPLETE lights on the the 1A, IB, 1C (2A, 2B, 2C) Diesel Bezels on the control console. DO NOT restart the equipment by manually initiating Safety Injection or Containment Spray as this may result in undesirable valve operations which may result in equipment damage. b. Reset the Safeguards Loading Sequence by depressing the EMERGENCY LOADING RESET pushbuttons on the control console for lA, 18, 1C (2A, 2B, 2C) Diesel Generators. c. Restart the following Pump Room Coolers: No. 11, 12(21, 22) RHR Pump Room No. 11, 12(21,22) Charging Pump Room No. 11, 12(21,22) Containment Spray Pump Room No. 1(2) Aux Feed Pump Room. d. If containment pressure is < 5.0 psig, refer to EI I-4.2, "Recov m .- A Safety Injection" fcr guidance in returning additional sup rtpystemsto operation as required to accorplish the subsequent cooldeln # Proceed to Subsequent Action Step 4.10 of this inttruction. P If containment pressure is > 5.0 psig, proceed t dS otion 5.0 of this e. instruction, " Subsequent Actions Part II - ColMLgg Recirculation". y h 1337 067 Salem Unit 1/ Unit 2 Rev. 7
I-4.6 PART I NOTE If a loss of offsite power has occurred in coincidence with the Steam Line Rupture, align the Electrical System in accordance with Appendix A, prior to proceeding to Part II of this Procedure. 4.lC Restart the following ventilation fans and pump room coolers: 4.10.1 Notzle support fans
- 4.10.2 Reactor snicld vent fans
- 4.10.3 Control rod drive fans
- 4.10.4 Ne 11 & 12 (21 & 22) RHR Puma Room Coolers 4.10.5 No. 11 & 17 (.:1 & 22) Charging Pump Room Cool?rs.
4.10.6 No. 1(2) Aux Feed Pump Room Cooler. NOTF
- The breakers for these fans must be reset manually to start the fans.
4.11 When conditions permit, return the 4kV Vital Busses to rormal by: 4.11.1 Stopping the Emergency Diesel Generators IAW OI IV-16.3.1, " Emergency Power - Diesel Operation". 4.11.2 Start or stop vital bus loads, as required. 4.12 Commence taking the plant to cold shutdown conditions by co.ning down as followS: 4.12.1 If the rupture is downstream of the main steam line isolation valves, cooldown using the atmospheric steam relief valves. Periodically, redue the pressure setpoint of the controller for each MSIC Valve by depress', + heir PRESS SET PT DECREASE pushbuttons. 4.12.2 If the rupture is upstream cf the main steam line isolation va1Ye cool down using the steam dump to the conder ser as follows: a. Open the Bypass Valves (MS18) around the Main Steam k gl tion Valves (MS167) on the unaffected Steam Generators. When pressure equilizes, open the main ste 5 ation valves b. <8 1337 068 Salem Unit 1/ Unit 2 Rev. 7
I-4.6 .' ART I c. Place the steam dump in the MAIN STEAM PRESSURE CONTROL mode and periodically reduce the setpoint by depressir.1 the SETPOING DECREASE pushbutton. 4.12.3 As applicable, utilize the following Operating Instructions to take the plant to Cold Shutdown conditions: OI I-3.5, " Minimum Load to Hot Standby" OI I-3.6, " Hot Standby to Cold Shutdown" + s
- e. % '
4 2 4 1337 069 Salem Unit 1/ Unit 2 Rev. 7
I-4.6 PART II 5.0 SUBSEQUENT ACTIONS - PART II - COLD LEG RECIRCULATION CAUTION The changeover from the Safety Injection Phase to Cold Leg Recirculation most be done quickly. If any valves fail to respond or complete the required movement, continue with the sequence and and initiate any corrective actions when the changeever is completed. 5.1 Verify that the following normally closed valves are CLOSED: 11(21)SJ40 11(21) SI Pump Disch Valve to Hot Leg 12(22)SJ40 12(22) SI Pump Disch Valve to Hot Leg 11(21)SJll3 SI Chg Pumps X-Over Valve 12(22)SJll3 SI Chg Pumps X-Over Valve ll(21)SJ45 Recirc Isol E 've to SI Pump 11(21)CS36 From 11(21) Rn Valve 12(22)CS36 From 12(22) RHX Valve 1(2)RH2 RHR Common Suction Valve 1(2)RH1 RHR Common Suction Valve ll (21) SJ4 4 SIS Sump valve 12(22)SJ44 SIS S rp Valve 1 (2) RH2 O RHX Sypass Valve 1 (2) RH26 RHR Outlet Stop Valve 11(21)RH29* 11(21) RHR Pump Bypass 12(22)RH29* 12(22) RHR Pump Bypass 12(22)SJ45 Suction from RHX (to Charging Pumps) NOTE
- 11(21)RH29 and 12(22)RH29 will be closed only if RHR flow is > 1200 gpm per pump.
5.2 Verify that there is an adequate water level in the Containment Sump as indicated by an energized SUFFICIENT NPSH light on the control console. 5.3 Open ll(21)CC16 and 12 (22)CC16 RHR Heat Exchanger Outlet Valves. 5.4 When the RWST Low-Low Level Alarm actuates at 0.0 feet (0. 0 gals.),$- op the following pumps if they are running. j No. 11 (21) RHR Pump "gM No. 12 (22) RHR Pump No. 11 (21) CS Pump and No. 12(22) CS Pump, if containgden ray actuation has occurred. M [ 1337 070 Salem Unit 1/ Unit 2 Rev. 7
I-4.6 PART TI NOTE If Containment Pressure has not decreased to below 23.5 psig, the Containment Spray Pumps cannot be stopped from the control console. To stop the pumps, it will be necessary to trip the breakers locally on the 1A and IC (2A and 2C) 4kV vital busses by turning off the 125 VDC control power and depressing the manual trip button inside the breaker cabinet. NOTE Aligning the RHR Pumps as described in the following steps will provide flow to the Charging and Safety Injection Pumps and the Containment Spray Header. If one RHR Pump !J not available to provide flow the other pump will supply the Charging and Safety Injection Pumps and the Containment Spray Hoader with no additional valve operations, however, the Cold Leg Injection from the operating RHR Pump will have to be isolated by closing the appro-preiate SJ-49. 5.5 Close ll(21)RH4 RHR Pump Suction Valve, if No. 11(21) RHR Pump is available. 5.6 Close 12 (22) RH4 RHR Pump Suction Valve, if No. 12(22) RER Pump is available. NOTE ll(21)RH4 must be closed in order to open ll(21)SJ44. 12(22)RH4 must be closed in order to open 12(22)SJ44. 5.7 Remove the lockout and open ll(21)SJ44 SIS Sump Valve, if No. 11(21) RHR Pump is available. 5.8 Remove the lockout and open 12(22)SJ44 SIS Sump Valve, if No. 12(22) R p is available. ? 5.9 Close ll(21)RH19 RH Heat Exchanger Outlet Valve. ,dhN S.10. Close 12 (22)RH19 RH Heat Exchanger Outlet Valve qf b ? 5.11 Start No. 11(21) RER Pump. ,( g ' ~ i 5.12 Maintain 3,000 gpm on COLD LEG INJECTION 11(21)SJ44 ow meter by adjusting V 11(21) RH18. p g? 1337 071 b Salem Unit 1/ Unit 2 Rev. 7
I-4.6 FART II 5.13 Start No.12 (22) RHR Pump. 5.14 Maintain 3,000 gpm on COLD LEG INJECTION 12 (22)SJ49 flow meter by adjusting 12 (22) RH18. S'.15 Remove the lockout and close 1(2)SJ67, 12(22) Mini Flow Isolation Valve, and 1(2)SJ68 11(21) Mini Flow Isolation Valve. NOTE There are redundant switches on 1(2)RP4 to operate 1(2)SJ67 and 68. Either the p'ashbutton en the control console or these switches will allow full operation of the valves ence the lockout is rcmoved. 5.16 Open 12(22)SJ45 Suction frcm RHX*, if No. 12(22) RHR Pump is available. 5.17 Open ll(21)SJ45 Recire Isoaltion Valve to SI Pump **, if No. 11(21) RHR Pump is available. NOTES
- To open ll(21)SJ45, the followina valves must be positioned as listed below:
- 1) 1(2)RH1 or 1(2)RH2 Closed
- 2) 1(2SJ67 or 1(2)SJ68 Closed
- 3) ll(21)SJ44 Open
- To open 12(22)SJ45, the following valves must be posit 4oned as listed below:
- 1) 1(2)RH1 cr 1(2)RH2 Closed
- 2) 1(2)SJu7 or 1(2)SJ68 Closed
- 3) 12 (22) SJ44 Open 5.18 Open ll(21)sJll3 SI Charge Pumps X-Over Valve.
5.19 Open 12 (22) Si 113.';I Charge Pumps X-Over '.*alve. .] N 5.20 Clc,se 1 (2) SJ1 RW5'l
- .o Charge Pump.
p 5.21 Close 1(2)SJ2 AFST to Char ge Pump. E' ~d e 5.22 Verify that No. 11(21) SI Pump is operating properly' bserving No. 11(21) SI Pump discharge pressure indicator and No. ll(21)J I ump discharge flow indicator. 9 1337 072 Salem Unit 1/ Unit 2 -lk-Rev. 7
I-4.6 PART II 5.23 Verify that No. 12(22) SI Pump is operating properly by observing No. 12(22) SI Pump discharge pressure indicator and No. 12(22) SI Pump discharge flow indicator. 5.24 Verify that No.11(21) Centrifugal Charging Pump is operating properly by observing the Charging Pump discharge flow indicator and Boron Injection Tank discharge pressure indicator. 5.25 Verify that No.12 (22) Centrifugal Charging Pump is operating properly by observing the Charging Pump discharge flow indicator and Boron Injection Tank discharge pressure indicator. 5.26 Remove the lockout and close 12(22)SJ49 Low Head SJ Stop Valve. [11(21)SJ49 if No. 12(22) RHR Pump is not available]. 5.27 Open the following Containment Spray Valves: 12(22)CS36 [ll(21)CS36 if No.12 (22) RHR Pump is not available). 5.28 Close the following Containment Spray Valves: 11(21)CS2 12(22)CS2 5.28.1 Continue Spray operation until Containment pressure is < 5.0 psig. When Containment pressure is < 5.0 psig proceed to EI I-4.2, " Termination of Safety Injection". NOTE The Emergency Core Cooling System is now aligned for Cold Leg Recirculation as follows: 1) RHR Pump No. 11(21) is supplying water from the Containment Sump directly to RCS locp 11(21) and 13(23) Cold Legs via valve ll(21)SJ49 and to the suction of the Safety Injection Pumps through valve 11(21)SJ45. e> 2) RHR Pump No.12 (22) is supplying water from d the Containment Sump directly to the Contain-ment Spray Header and to the suction of the p j) ~ Charging Pumps through valve 12(22)SJ45. N 5.29 Close the following Accumulator Isolation Valves, if the c ator pressure is indicated to be less than 250 psig, g <f & (;) 1337 073 Salem Unit 1/ Unit 2 Rev. 7
I-4.6 PART II 11(21)SJ54 No. 11 (21) Accumulator Tank Outlet Valve 12 (22) SJ54 No. 12(22) Accumulator Tank Outlet Valve 13(23}SJ54 No. 13(23) Accumulator Tank Outlet Valve 14(24)SJ54 No. 14(24) Accumulator Tank Outlet Valve Prepare' by Manager - Salem Get ' rating Station Reviewed by SORC Meeting No. Date k x l2 4
- b qh e
%em 1337 074 'd Salem Unit 1/ Unit 2
I-4.6 APPENDIX A DISCUSSION If a loss of offsite power has occurred in coincidence with the Steam Line Rupture, the Diesel Generators will be supplying power to the vital busses. During the recirculation phase, it is necessary to run the Component Cooling Pumps. In order to accomdate this additional load, other equipment must be stopped before the Component Cooling Pumps are started to prevent overloading the Diesel Generators. After the Safety Injection and SEC are reset, proceed with the appropriate section. I - ALL DIESEL GENERL'J3RS OPERATING 1.0 Stop the following equipment: NOTE Do not step both No. 11(21) and 12(22) Containment Spray Pumps until the RWST Low-Low level alarm actuates. 1.1 Equipment on lA(2A) Vital Bus (Powered by 1A(2A) Diesel / Generator) a. No. 11(21) Containment Spray Pump b. No. 11(21) Auxiliary Building Exhaust Fan c. No. 1;(21) Switchgear Room Supply Fan d. No. 11(21) Chiller 1.2 Fguipment on IB(2B) Vital Bus (powered by IB(2B) Diesel / Generator) a. No. 12(22) Containment Fan Coil Unit b. No. 14(24) Containment Fan Coil Unit 1.3 Equipment on IC(2C) Vital Bus (powered by 1C(2C) Diesel / Generator a. No. 12(22) Containment Spray Pump b. No. 11(21) Auxiliary Building Supply Fan 2.0 Start the following equipments .g CAUTION 4 ~ A Wh3n entering Cold Leg Recire. r, tart only one P Component Cooling Pump. Ensure the Component W CoolingPumptobestartedisenergizedfro[ the same Vital Bus as was the containment ON Spray Pump, secured from in the abov g 1337 075 Salem Unit l'3 nit 2 1 Of I gg
I-4.6 2.1 Equipment on lA(2A,' Vital Bus (powered by 1A(2A) Diesel / Generator) a. No. ,1 Component Cooling Pump 2.2 Equipment on IC(2C) Vital Bus (powered by IC(2C) Diesel / Generator) a. No. 13(23) Component Cooling Pump NOTE If irradiated fuel is stored in the Fuel Handling Building, start No. 11 & 12 (21 & 22) FHB Exhaust Fans. 3.0 Open 11(21) SW122 and 12 (22) SW122 to Supply Service Water to Component Cooling. II - FAILURE OF 1A (2A) DIESEL GENERATOR 1.0 Stop the following equipment: 1.1 Equipment on IB(2B) Vital Bus (powered by 1B(2B) Diesel / Generator) a. No. 11(21) Charging Pump b. No. 12(22) or No. 14(24) Containment Fan Coil Unit c. No. 12(22) Auxiliary Building Supply Fan 1.2 Equipment on IC(2C) Vital Bus (powered by IC(2C) Diesel / Generator) a. No. 12(22) Containment Spray Pump when RWST Low-Low level alarm actuates. 2.0 Start No. 12(22) Component Cooling Pump and open 12(22)SW122 to provide Service Water to component Cooling. NOTE If irradiated fuel is stored in the Fuel Handling Building, start No. 12(22) FHB Exhaust Fan. 3.0 The following should be the alignment for Cold Leg Recir.culation. 3.1 The following pumps should be running %'b a. No. 12(22) RHR Pump g j b. No. 12 (22) Charging Pump 4 c. No. 12 (22) Safety Injection Pump / 3.2 Close valves 12(22)RH19 and 12(22)SJ49 to prevent flow t N he Cold Legs and to insure adequate flow to No. 12(22) Charging Pump and No. 1 b Safety Injection Pump suctions and to"the Containment Spray Header through 12(22)b 3&[ 4 1337 076 Salem Unit 1/ Unit 2 2 of 5 Rev. 7
A I-4.6 3.3 The Cold Leg Recirculation Flow Path would be as follows: a. No. 12(22) RHR Pump taking suction on the Containment Sump and discharging to the suctions of No.12(22) Charging Pump and No.12 (22) Safety Injection Pump through 12(22)SJ45, 12(22)SJll3, 11(21)SJ33 and 12(22)SJ33, and to the Containment Spray Header through 12(22)CS36. b. No. 12(22) Charging Pump Discharge through the Boron Injection Tank to all four Cold Legs. c. No. 12(22) Safety Injection Pump Discharge through 12 (22)SJ134 and 1(2)SJ135 to all four Cold Legs. III - FAILURE OF 1B(2B) DIESEL GENEFATORS 1.0 Stop the following equipment: 1.1 Equipment on lA(2A) Vital Bus (powered by 1A(2A) Diesel Generator) a. No. 11(21) Containment Spray Pump 1.2 Equipment on IC(2C) Vital Bus (powered by IC(2C) Diesel Generator) a. No. 12(22) Containment Spray Pump b. No. 12(22) Safety Injection Pump 2.0 Start No.13 (23) Component Cooling Pump and open ll(21)SW122 to provide Service Water to Component Cooling. NOTE If irradiated fuel is stored in the Fuel Handling Building, start No. 12(22) FHB Exhaust Fan. 3.0 The followine chould be the alignment for Cold Leg Recirculation: 3.1 The following pumps should be running: a. No. 11(21) RHR Pump ,c\\ b. No. 12(22) Charging Pump { Q c. No. 11(21) Safety Injection Pump 3.2 Close valves 11(21)RH19 and 11(21)SJ49 to prevent flow to the Mgs and to insure adequate flow to No. 12(22) Charging Pump and No.11(21) Safe ection Pump suctions and to the Containment Spray Header through 11(21)d ,s Q'P g** 1337 077 Salem Unit 1/ Unit 2 3 of 5 Rev. 7
I-4.6 3.3 The Cold Leg Recirculation Flow Path would be as follows: a. No. 11(21) RHR Pump taking suction on the Containment Sump and discharging to the suctions of No. 12(22) Charging Pump and No. 11(21) Safety Injection Pump through ll(21)SJ45,11(21)SJ113, ll(21)SJ33 and 11(21)SJ33, and to the Containment Spray Header through ll(21)CS36. b. No. 12(22) Charging Pump discharging through the Boron Injection Tank to all four Cold Legs. c. No. 11(21) Safety Injection Pump discharging through ll(21)SJ134 and 1(2)SJ135 to all four Cold Legs. IV - FAILURE OF 1C(2C) DIESEL GENERATOR 1.0 Stop the following equipment: 1.1 Equipment on lA(2A) Vital Bus (powered by 1A(2A) Diesel / Generator) a. No. 11(21) Containment Spray Pump b. No. 11(21) Auxiliary Feedwater Pump 1.2 Equipment on 1B(2B) Vital Bus (powered by 1B(2B) Diesel / Generator) a. No. 12(22) RHR Pump 2.0 start No. 12(22) Component Cooling Pump and open ll(21)SW122 to provide Service Water to Component Cooling. NOTE If irradiated fuel is tored in the fuel Handling Building, start No. 11 and 12 (21 & 22) FHB Exhaust Fans. 3.0 The following should be the alignment for Cold Leg Recirculation: 3.1 The following pumps should be running: a. No. 11 (21) RHR Pump A b. No. 11(21) Charging Pump h c. No. 11(21) Safety Injection Pump kY 3.2 Close valves ll(21)RH19 and ll(21)SJ49 to prevent flow to the Coldx nd to insure adequate flow to No.11(21) Charging Pump and No. 12(22) Safety ebitionPump suctions and to the Containment Spray Header through ll(21)C 3.3 The Cold Leg Recirculation Flow Path would be as followsA0 1337 078 Qd) A Salem Unit 1/ Unit 2 4 of 5 p,v 7
I-4.6 a. No. 11(21) RHR Pump taking suction on the Containment Sump and disebarging to suctions of No. 11(21) Charging Pump and No. 11(21) Safety Injection Pump through ll(21SJ45, 11(21)SJ113, 12(22)SJ113, ll(21) SJ33, and 12 (22) SJ33, and to the Containment Spray Header through ll(21)CS36. b. No. 11(21) Charging Pump discharging through the Boron Injection Tank to all four Cold Legs. c. No. 12(22) Safety Injection Pump discharging through 12(22)SJ134 and 1(2)SJ135 to all four Cold Legs. 4.0 Transfer the Security System to the emergency power supply on lA 230V Vital Bus. 4% V cSh e %)* n'.$%> sp 4~' (k. ) a-n-
- ^/.
1337 079 Salem Unit 1/ Unit 2 5 of 5 Rev. 7
s I-4.7 EP.ERGENCY INSTRUCTION I-4.7 STEAM GENERATOR TUBL TAILURE 1.0 DISCUSSICN L1 This instruction covers the symptoms, automatic actions and minual actions for a Steam Generator tube leak and a Steam Generator tube rupture. Either of these conditions result in leakage of reactor coolant into the secondary system. 1.2 Operater action is required, in accordance with the accident analysis in the FSAR. in order to identify and isolate.he faulted Steam Generator on a tube rupture. Reacter Coolant System pressure must be reduced to less than 1000 psi within 30 minutes in order to prevent lifting of the Steam Generater safeties and power operated relief valve on the affected Steam Generator. This will minimize radioactive release to the atmosphere and ensure compliance with the limits specified in 10CFR100. 1.3 On a tube rupture the potential exists, depending on the magnitude of the break, for a saturated steam void to be formed at the reactor vessel outlet or in the RCS Mot Leg. This condition will exist if RCS pre.sure has dropped below the saturation pressure for the existing RCS temperature. Refer to the RCS pressure-temperature curve to determine if this cendition exists. 1.4 This instructicn is divided into two parts: I Steam Generator Tube Leak II Steam Generater Tube Rupture PART I I STEAM GENERATOR TUBE LEAK 2.0 SYMPTOMS 2.1 Any of the follcwing high radiation alarms: 11(21) Steam Generator Blewdown lf2)R19A k A )/ 12(22) Steam Generator Slowdown 1(2)R19B 13(23) Steam Generator Blowdown 1(2)R19C 4 +h 14(24) Steam Generator Blowdown 1(2) R190 - 8*. Condeaser Air L;ector 1(2)P15 4s SG Elowdcun rilter Discharge 1(2)R25 2.2 Charging Pump 5 peed and Charganc flew increase te aintal ssur; er le'cel ncrmal. Salem Unit 1/ Unit 2 Rev. 5
I-4.7 PART I 3.0 I.v3.EDIATE ACTIONS 3.1 Autcratic 3.1.1 Charging flow increasing 3.1.2 Automatic makeup to VCT ~ 3.1.3 Warning alarm on RMS Channel R19 isolates 12(22) S/G BD Tank Valves 11, 12, 13 and 14(21,22,23 & 24)CB10 and 1(2)GB50. 3.1.4 High alarm on the Steam Generator Blowdown Radiation M0nitors (R19) will isolate the following: a) Unit 1 - Alarm on any channel, 1R19A-D, will isolate 11,12,13 and 14GB4. b) Unit 2 - 2R19A will trip 21GB4 2R19B will trip 22GB4 2R19C will trip 23GB4 2R19D will trip 24GB4 3.1.5 High alare on RMS Channel R35 shifts 3-way valves 1(2 GB74 and 1(2)GB112 to discharge to the Waste Moniter Holdup Tanks. 3.2 Manual 3.2.1 Verify automatic actions, initiate any that did not occur. 3.2.2 Notify Performance Department of possible Steam Generator tube leak. 4.0 SUBSE2CE';T ACTION 4.1 Determine primary to secondary leak rate. See Technical Specification 3.4.6.2 for leakage limits. 4.2 Determine which Steam Generator is leaking by sample analysis and observing read:ngs on Steam Generator saeple radiation monitors. 4.3
- 4cnitor charging pump flow for any increase and the Steam Generator sarple rad;at en monitors for increased readings which indicate higher leakage.
4.4 Shutdown the plant when Technical Specification leakage limits are reac; OI I-3.4, " Power Operation", I-3.5, " Minimum Load to Hot Standby" an6% -3.6, "Ect -Q = e Standby to Cold Shutdown". 4 NOTE The faulty Steam Generat:r should n:t be sig
- @uring the subsequent c oldcwn. Cooldown shculd
," p mplisned b" using the Atmospheric Stear relief Val.% 'S-13) 'f or the unaffected Steam Generators. Q Salem Unit 1/ Unit 2 E e'l 5
- -4.7 4.5 Refer to Emergency Instruction EI-4.16
" Radiation Incident", if radiatien monitors have alarmed. PART II II STEAM GE!;ERATOR TUBE RUPTURE 2.0 SYMPTOMS The follcwing may be indicative of a Steam Generator tube rupture. 2.1 Charging flow or charging pump speed at maximum with decreasing pressuri:er level and pressuri:er pressure. 2.2 Increasing radiation levels on one or more of the following radiation meniters: 1 (2 ) R19A 11(21) Steam Generator Blowdown 1(2)R19B 12(22) Steam Generator Blowdown 1(2}R19C 13(23) Steam Generator Blcwdown 1 ( 2 ) R19D 14(24) Steam Generator Blewdewn 1(2)R15 1(2) Condenser Air Ejector 1(2)R35 SG Blowdown Filter Discharge 3.0 IF."EDI ATE ACTIO!;5 3.1 Automatic 3.1.1 Reactor Trip 3.1.2 Safety Injection Actuation 3.1.2 Turbine and Generater Trip 3.1.4 Warning alarm en RMS Channel R19 1sciates 12(22'. 5/G BD Tank Valver 4..'2,13 & 14 (21,22,23 and 24)GB10 and 1(2)GB50. ch4 L) 1 isolate 3.1.5 High alarm on the Steam Generator Blowdown Radiaticn Monitors (R19 the following: ,,0 3 ) a) Unit 1 - Alarm en any channel, 1R19A-D, will isolate h33 ',13 and 14CB4. e >O b) Unit 2 - 2R19A will trie 21GB4 dS 2R19B will tric 22GB4 4 qkg3> 2R19C will trip 2;G34 2R190 will trip 24CB4 \\'9 Salem Unit l' Unit 2 P e *> 5
I-4.7 PART II ?.l.6 High alarm on WMS Channel R35 shifts 3-way valves 1(2)BG74 and 1(2)BGil2 to discharge tc the Waste Monitor Holdup Tanks. 3.2 Manual 3.2.1 verify Safety Injection Actuation by checking the following:
- 1) Reactor trip by verifying all full length control rods fully inserted by checking individual rod porition idications and rod bottom lights.
a) If any full length rods do not indicate fully inserted, initiate a manual reactor trip.
- 2) Turbine trip by checking the following:
a) UNIT TRIP light on E/H console illuminated. b) Turbine Stop Valves, Governor Valves, Interceptor Valves and Reheat Stop Valves closed c) Turbine speed decreasing.
- 3) Main reed Pumps tripped and feedwater isolation has occurred.
- 4) Verify the ACCIDENT LCADING light is illuminated on the Diesel Generator bezels and the following equipment is operating:
a) Centrifucal Charging Pumps b) Safety Injection Pumps c) Residual Heat Removal Pumps d) Auxiliary Feedwater Pumps (motor driven) e) Diest1 Generators f) Containrent Fan Ccclers runnin in slow speed. k 3.2.2 Within two minutes reduce Auxiliary Teedwater flow to the Steam Ge g9:rste limit the rate of rise to < 1.2 in/ min by monitoring the wide rar)h level recorders (< o.2%/ min on the Narrow Range) until the Aevel i > on .1 Steam Generators. (NOTE: This limitaticn applies only to $tL ) i 3.2.3 Verify T,y is decreasino toward or beine maintained at# bv either stear dump cr at5cspheric steam relief. N t e 3.2.4 Stop all Feactor Coolant Pumps when Pressura:er 1 reaches Oi. e%> 1337 083 Salem Unit 1/ Unit 2
- Rev. 5
I-4.7 PART II 3.2.5 Announce over the station PA System twice: " UNIT NO. 1(2) REACTOR TRIP SAFETY INJECTION". 4.0 SUBSEC"ENT ACTIONS 4.1 verify that safety injection is in progress. 4.1.1 Verify, utilizing console and/or 1(2)RP4 status panel indications, that the loads listed on Table I have been loaded onto the vital busses. 4.1.2 Verify that the containment fan coolers meet the following conditions upon starting:
- 1) Fan ecclers have decreased speed.
- 2) Fan coolers service water flow has increased from 700 gpm to 2500 gpm.
- 3) Roughing filter dampers have closed.
- 4) HEPA inlet dampers have opened.
- 5) HEPA outlet dampers have cpened.
4.1.3 Check that the following valves have opened by observing the status panel. If any valve fails to open, atterpt to manually open from the contrcl console. 1(2)SJ4 Beren In3cetien Tank Inlet Valve 1(2)SJ5 Bcron Injection Tank Inlet Valve 1(2)SJ12 Beren Injection Tank Outlet Valve 1(2)SJ13 Ecren In3ection Tank Cutlet Valve 1(2)SJ1 Charging Pu :p Suction from RWST 1(2)SJ2 Charging Pump Suction from RWST 4.1.4 Check that the following valves have closed. If any valve fails to close, atte=pt to close the valve fron the Centrol Censole. 1(2)SJ78 Recirc to Boric Acid Tank JQ 1(2)SJ79 Recire o Boric Acid Tank ([ h5 1(2)SJ108 Recire to doron Ir.jection Tank s )*D 1(2)CV68 Charging System Stop Valve 1(2)CV69 Charging System Step Valve g(%hg, 1(2)CV139 Charging Pung Discharge to SWHX U'y 1(2)CV140 Charging Purp Discharge to SWHX ,9$$ / 1(2)CV40' Volune Centrol Tank Discharce Valve rdg >+ 1(2)CV41* Volure Centrol Tank Discharge Val"e 't-n 1(2)CV3 Crifice Isolation Valve :Letd:.n! 's 1 7 084 1(2)CV4 Orifice Isolation valve (Letdewn) (ps, 1(;!Cv5 Orifice Isolatien valve (Le dewn fs 0 Saler L' nit 1/ Unit 2 Rev. 1
I-4.7 FART II 1(2)CV7 CVCS Letdown Line 1(2)CVil6 Reactor Coolant Pump Seal Water Discharge 1(2)CV284 Reactor Coolant Purp Seal Water Discharge ll(21)SW20 Turbine Generator Area Supply Valve 13(23)SW20 Turbine Generator Area Supply Valve 1(2)SW26 Turbine Generator Area Isolation Valve NOTE
- These valves will not close until either 1(2)SJ1 or 1(2)SJ2 is fully open.
4.1.5 Check the followine meters on the control console to ensure that borated water is being injected into the Reactor Ccolant System.
- 1) Boron Injection Tank pressure indicating FCS pressure.
- 2) Charging Purps discharge flow
- 3) 11(21) Safety In3ection Purp Discharge Flow
- 4) 12(22) Safety Injection Punp Discharge Flow 4.2 Verify that Phase "A" Containment Isolation has taken place b) checking that the valves listed in Table II are closed. Should a valve fall to close, attempt to close it from the control censole.
4.3 Verify that feedwater isolation has taken place due to the Safety Injection. 4.3.1 Check that the following valves.; ave closed by cbserving the status panel and/or the console bezel. If any valve h:s failed to close, attempt to close it from the control console. 11(21)BF13 Feedwater Inlet Stop Valve ll(21)BF19 Feedwater Control Valve e ll(21)BF40 Feedwater Bypass Valve dQ(4 12(22)BF13 Feedwater Inlet Stop Valve R$ 12(22)BF19 Feedwater Control Valve b a d 12(22)BF40 Feedwater Bypass Valve - Rg) 13(23)BF13 Feedwater Inlet Stop Valve O'. 13(23)BF19 Feedwater Control Valve <l 13(23)BF40 Feedwater Bypass Valve {:. 14(24)BF13 Feedwater Inlet Stop Valve A ,gh' 14(24)BF19 Feedwater Control Valve 14 ( 2 4 ) BF4 0 Feedwater Bypass 'lalve .Fh Sh % 7 1337 085 Saler Unit i Tnit 2 Per 5
I-4.7 PAsi - 4.4 Verify that the 4160V Group Busses have transferred from the 1(2) Auxiliary Pcwer Transformer to 11(21) and 12 (22) Station Power Transformers. 4.4.1 Check that the following 4160V breakers have opened and acknowledge then on the appropriate control console bezel: 1(2)BGGD 1(2)BFGD 1(2)AEGD 1(2)AHGD 4.4.2 Check that the following 4160V breakers have closed and ackncwledge then on the appropriate control console bezel: 12 ( 22 ) GSD 12(22)FSD ll(21)ESD 11(21)HSD 4.5 Identify the faulted Steam Generator by any of the following: 4.5.1 Stop Auxiliary Feedwater flow to the Steam Generators and observe the water levels in them. The Steam Generator that has an increasing water level will identify the faulty Unit. 4.5.2 Compare radiation readings on the Steam Generator blowdown sarple radiation monitors. The one with the higher radiation reading is the affected Steam Generator. 4.5.3 Re-establish normal water level in the three non-faulted Ste:m Generators by use of the Auxiliary Teed Systems. Do not feed the faulted Steam Generatcr. 4.6 Reduce the RCS temperature and pressure as quickly as possible, within the lirits of the pressure-temperature curve. .w. (f $ 4.6.1 Reduce T,y to N 500*F as follows: 5\\
- 1) If the Condenser is available, shift the Steam Dump System t: '*2Sh 02 7 and reducs the setpoint.
hy A ~
- 2) If the Condenser is not available, take manual control o$
Atmosphere Steam Relief Valves (MS-10) on the unaf fected Steam GeRr,rgters and cren the valves as necessary. J( eys > y& 1337 086 NOTE Do not steam the faulted Steam Generator to' he Atmospnere. Salen Unit 1/ Unit 2 ?e; 5
I-4.7 PART II 4.6.2 Reduce RCS Pressure to approximately 1000 psig as follows:
- 1) If the RCP's are in operation open the Pressurizer Spray Valves (PS1 & 3).
- 2) If the RCP's are not in operation, cycle the Pressurizer Power Operated Relief Valves (PR1 & 2) as necessary to reduce pressure.
4.7 When the RCS pressure and the pressure in the affected Steam Generater reaches 1000 psig or less, close the Steam Generator stop valve en that Steam Generator. 4.0 Check that nuclear power is decreasing by observing the nuclear instrumentation. -10 4.8.1 Check that the source range high voltage is reinstated below 10 amps en both intermediate range channels. This should occur in 18 minutes following a trip fibm the Power Range.
- 1) If the source range high voltage does not energize automatically, manually depress the RESET SOURCE RANGE *A" and RESET SCURCE RANCE "B"
pushbuttons. 4.8.2 Switch the Nuclear Power Recordet (NR-45) to read one intermediate range channel and one source range channel. 4.9 Verify the following fans have stopped: 11 & 12 (21 & 22) Iodine Removal 11, 12, 13, 14 (21, 22, 23, 24) Nozzle Support 11 & 12 (21 & 22) Reactor Shield 11, 12, 13, 14 t21, 22, 23, 24) Control Rod Drive 11 & 12 (21 s 22) RHR Pump Room Coolers 11 & 12 (21 & 22) Charging Pump Room Coolers 11 & 12 (21 & 22) Containment Spray Pump Room Coolers 4.10 Verify Control Area Air Conditioning has shifted to the ACCIDENT - ISSIDE AIR mode cf operation and the following actions have occurred. A 4.10.1 11, 12, 13 (21, 22, 23) Chillers are running p 4.10.2 11 & 12 (21 & 22) Chilled Water Pumps are running D 4 4.10.3 11, 12, 13 (21, 22, 23) Control Area Supply Fans are running dg h t. . 4.10.4 11 & 12 (21 & 22) Emergency Control Area Supply fans are runnino ' dh 4.10.5 Battery exhaust fan has stopped Control valves 1(2)CH30 and 1(2)CH151 c1cse to is:lste^the"4 Administrati"c 4.10.6 Building. a' 1337 087 Salem Unit 1/ Unit 2 Re 5
I-4.7 4.10.7 Control valve 1(2)CH168 opens to supply chilled water to the emergency control area air conditioning coils. 4.10.8 Control area dampers positioned as follows: CAAl - Closed CAA4 - Closed CAA17 - Open CAA20 - Closed CAA33 - Closed CAA2 - Closed CAAS - Open CAA18 - Closed CAA31 - Closed CAA3 - Closed CAA14-Closed CAA19 - Closed CAA32 - Closed 11 If any of the above actions have not occurred, manually initiate them IAW OI II-17.3.2 idection 5.3), " Control Room Ventilation Operation (Operating During Accident Conditions)". 4.11 when Pressurizer level is > 50% on at least two of the hot calibrated channels and Steam Generater level is being maintained at % 33% cn the narrcw range channels for the unaffected Steam Generators, proceed to EI I-4.2, " Recovery fron Safety In]ection". Prepared by Manager - Salem Generating Station Reviewed by SORC Meeting No. Date a' .'4 D N, - 1337 088 Salem Un t 1/ Unit 2 Rev. 5
o I-4.7 TABLE I
- BLACKOUT WITH SAFETY INJECTION" LOADING SECUENCE
- 11(21) DIESEL CENERATOR
- 12(22) DIESEL GENERATOR e13(23) DIESEL _[ERATOR 1(2)A 1(2)B 1(2)C 240/480V Breaker 240/480V Breaker 240/48'0V Breaker 11(21) SI Pump 11(21) Charging Pump 12(22) Charging Pump 11(21) RHR Pump 12(22) RHR Pump 12(22) SI Pump 15(21) SW Pump 14 (24 ) SW Pump 11(25) SW Pump or*
or* or* 16(22) SW Pu=p 13 (23) SW Pump 12(26) SW Pump 11(21) Containment Fan 12(22) Containment Fan 13(23) Containment Fan (Low Speed) (Low Speed) (Low Speed) 11(21) Auxiliary Feed Pump 14(24) Containment Fan 15(25) Containment Fan (Low Speed) (Low Speed) 11(21) Auxiliary Building 12(22) Auxiliary Feed Pump Emergency Air Compressor Exhaust Fan 11(21) Chiller 12(22) Auxiliary Building 11(21) Auxiliary Building Supply Vent Fan Supply Vent Fan 11(21) SWOR Room Supply Fan 12(22) Auxiliary Building 13(23) Auxiliary Building Exhaust Fan Exhaust Fan 12(22) Chiller 13(23) Chiller 12(22) SWGR Room Supply Fan 13(23) SWOR Room Supply Fan NOTE This sequence is initiated on any Safety Injection actuation with or without a blackoat, only in a blackout condition will the Diesel Generator breakers elose af ter first stripping the bus and the loads will then be sequenced onto the bu. This sequence is also initiated with a Safety In]ection coincident with undervoltage on one 4kV vital bus.
- NOTE Only the lead Service Water Pump will start, however, 4
if the lead pump falls to start, the backup pump breaker A q will close. + +(lg> -: gg - s, / 1337 089 TABLE I Page 1 of 1 Salem Unit 1/ Unit 2 c.e v. I
I-4.7 TABLE II PHASE "A" ISOLATION 1. Waste Disposal System 1 (2 ) WL12 RCDT PUMP DISCHARGE 1(2)WL13 RCDT PUMP DISCRARGE 1(2)WLl6 CONTAINMENT SUMP PUMP DISCRARGE 'l(2)WLl7 CONTAINMENT SUMP PUMP DISCHARGE 1(2)WL96 GAS ANALYZER FROM RCDT 1(2)WL97 GAS ANALYZER FROM RCDT 1(2)WL98 RCDT VENT 1(2)WL99 RCDT VENT 1 (2 ) WL108 N SUPPLY TO RCDT 2 2. SamplAng System 1(2)SS27 ACCUMULATOR SAMPLE 1(215533 HOT LEG SAMPLE 1(2)SS49 SAMPLE FROM P:R WATER SPACE 1(2)SS64 SAMPLE FROM P:R STEAM SPACE 1(2)SS103 ACCUMULATOR SAMPLE 1(2)SS104 HOT LEG SAMPLE 1(2)SS107 SAMPLE FROM PZR WATER SPACE 1(2)SS110 SAMPLE FROM P:R STEAM SPACE 11(2115594 SAMPLE FROM NO. 11(21) STM GEN BLOWDOWN 12(22)SS94 SAMPLE FROM NO. 12(22) STM GEN BLOWDCWN 13(23)SS94 SAMPLE FROM NO. 13(23) STM GEN BLCWDCWN 14(24)SSO4 SAMPLC FROM NO. 14(24) STM GEN BLOWDOWN 3. Component Cooling 1 (2 ) CCll 3 EXCESS LETDOWN HEAT EXCHANGER COOLING WATER OUTLET 1(2)CC215 EXCESS LETDOWN HEAT EXCHANGER COOLING WATER INLET 4. Steam Generator Drains and Blowdown ll(21)GB4 STEAM GEN CUTLET NO. 11(21) 12 ( 2 2 ) GB4 STEAM GEN OUTLIT NO. 12(22) 13(23)GB4 STEAM GEN OUTLET NO. 13(23) Y) -14 (2 4 ) GB4 STEAM GEN OUTLET NO. 14(24) ~ 5. Eressurizer Relief Tank CN / 1(2)WRB0 PRIMARY WATER SUPPLY TO PRT 1(2)PR17 GAS ANALYZER FROM PRT h 1(2)PR18 GAS ANALYZER FROM PRT 1(2)NT25 N, SUPPLY TO PRT v 1337 090 ^ TABL; II Page 1 of 2 7,. g Salem Unit 1/ Unit 2
l I-4.7 TABLE II 6. Accumulators 1(2)NT32 ACCUMULATOR N SUPPLY 2 7. Containment Ventilation ~ 1(2)VCl PURGE SUPPLY 1(2)VC2 PURGE SUPPLY 1(2)VC3 PURCE EXKAUST 1(2)VC4 PURGE EXHAUST 1(2)VC5 CONT PRESS VAC RELIEF ISOLATION VALVE 1(2)VC6 CONT PRESS VAC RELIEF ISOLATION VALVE 1(2)VC7 CONTAINMENT RADIATION SAMPLE OUTLET 1(2)VC8 COM*AINMENT RADIATION SAMPLE OUTLET 1(2)VCll CONTAINMENT RADIATION SAMPLE INLET 1(2)VCl2 CONTAINMENT RADIATION SAMPLE INLET 6. Dem.ineralized Water 1(2)CR29 DM WATER TO FLUSHING CO!NECTIONS 9. Fire Protection 1 (2 ) FP14 7 PROTECTION WATER SUPPLY
- 10. Safety Injection 1(2)SJ123 ACCUM TEST STOP VALVE 1(2)SJ60 ACCUM DISCH TEST STOP 1(2)SJ53 SJ HDR TEST STOP VALVE
- 11. Control Air ll(21)CA330 A HDR ISCLATION VALVE 12(22)CA330 B HDR ISOLATION VALVE 61s 9
5 9 ~ <gy 1337 091 TABLE II Sale-Unit 1/ Unit 2 Page 2 cf 2 Fev. 3
I-4.8 EMERGENCY INSTRUCTION I-4.8 ROD CONTROL SYSTEM MALFUNCTION This instruction is divided into six (6) parts. l I FAILURE OF A CONTROL ROD BANK TO MOVE II CONTINUOUS INSERTION OF A CONTROL RCD BANK III CONTINUOUS WITHDRAWAL OF A CONTROL ROD BANK IV DROPPED ROD T'JLL LENGTH ROD MIS ALIGNMENT
- 'I MALTUNCTIONINO ROD POSITION INDICATOR PART I TAILURE OF A CONTROL ROD BANK TO MOVE I-1.0 DISCUSSIO:;
- 1. 1 While in automatic control, this abnormal condition may prevent the plant from maintaining the programmed T,yg which may result in a reactor trip. A deviation from the programmed T,yg can be created by a change in either turbine load or coolant boron concentration, or Xenon changes following a reactor power change.
I-2.0 SYMFTOMS I-2.1 rollowing an increase in turbine lead, or during an increase in reactor coolant boron concentration, any of the following symptoms may be indicative of the failure of a control rod bank to withdraw. I-2.1.1 Failure of the control rods to move when the difference between the measured auctioneered Reactor Coolant System average temperature and the reference average temperature exceeds tne control deadband. I-2.1.2 T,, -T Deviation Alarm ref I-2.1.3 Rod insertion limit alarm follcwing an increase in turbine load. I-2.1.4 Decreasing T,yg I-2.1.5 Decreasing Pressurizer pressure and Pressurizer level. I-2.2 Following a decrease in turbine load, or during a decrease in reactor coolant boren concentration, the following symrtoms may be indicative of the failure of a control rod bank to insert. I-2.2.1 Failure of the control rods to move when the difference between the
- asura_ au::2:n ered Reser. ::'.s ; 5 z:ar s"cr ;e terccratsye _ni f
-h2 red. ' re a~srs:e ta tar _. '--'..s - :::1 de:ftana. Salam Uni: 1 and 2 Rev. 5
I-4.8 I-2.2.2 T,yg - Tref Deviation Alarm I-2.2.3 Increasing T,yg I-2.3 Rod stop annunciation I-2.4 Rod Control System U1 gent Failure alarm I-3.0 IMMEDIA E ACTIONS I-3.1 Automatic I-3.1.1 Following an increase in turbine load, or during an increase in reactor coolant boron concentration, the following automatic actions may occur as a consequence of the failure of a control rod bank to move.
- 1) Actuation of the Pressurizer Heaters I-3.1.2 Following a decrease in turbine load, or during a decrease in reactor coolant boron concentration, the following automatic actions may occur as a consequence of the failure of a control rod bank to move.
- 1) Actuation of Pressurizer Spray
- 2) Actuation of Pressurizer Power Operated Relief Valves
- 3) Actuation of the Pressurizer Heaters
- 4) Overtemperature AT rod withdrawal step accompanied by turbine runback.
I-3.2 Manual I-3.2.1 Stop any turbine load or boron concentration changes in progress and return the reactor to stable conditions as they existed before the transient. I-3.2.2 Verify ROD BANK SELECTOR SWITCH is in AUTO. I-3.2.3 If an URGENT FAILURE alarm is received, do not attempt to move the control rods until cause of the alarm is determined, corrections are made to remove the problem, and the alarm is cleared. I-3.2.4 Determine if a rod stop has occurred and take one or more of the following actions to restore ability to move the control rods:
- 1) Overpower AT or overtemperature aT rod stop will be removed automatically via the turbine load reference runback and corresponding control rod insertion. Do not increase turbine load until the cause of the rod stop has been determined and corrected.
Salem Unit 1 and 2 R*V-3
I-4.8
- 2) Nuclear overpower rod stop.
Reduce turbine load until the rod stop signal no longcr exists. Do not increase turbine load until the cause of the rod stop has been determined and corrected. shift the ROD BANK
- 3) Low power (15% turbine power interlock P-2, ON)
SELECTOR SWITCH to MANUAL and position control bank to restore equilibrium conditions.
- 4) Bank D Rod Withdrawal Limit Alarm.
I-3.2.5 If a rod stop or urgent failure has not occurred, shift the ROD BANK SELECTOR SWITCI to MANUAL and position the control rod banks to restore equilibrium conditions at the programmed T,yg value. The reactor may be operated indefinitely under MANUAL control while the Automatic Control System is being repaired. I-4.0 SUBSEQUENT ACTIONS I-4.1 The following steps apply if the control bank cannot be moved: I-4.1.1 Monitor all indications to verify that core power distribution is within normal limits. These indications include all the following:
- 1) All four power range nuclear channels: (upper and lower sections).
- 2) All T,yg and LT channels.
- 3) Feedwater and steam flow for the Steam Generators.
- 4) Core outlet thermocouples and/or in-core movable detectors.
- 5) Delta Flux Indicators.
NOTE If any of the above indicate an abnormal power distribution, or if any abnormal conditions are indicated, comply with Technical Specification Power Distribution, and STS 4.1.1.1.1, if applicable. I-4.2 If normal indications are recorded for all of the variables in step I-4.1.1 above, the plant may continue in operation (not to exceed 4 hours) during failure evaluation. Load changes should be avoided. T,yg must be maintained at its programmed value by boron adjustments to compensate for Xenon transients. Shutdown margin and axial flux difference limits must be maintained at all times. I-4.3 If het standby is required for repair, reactor power may be reduced by reducing the turbine load and increasing the boren concentration such that T,yg matches the programmed T Shutdown by reactor trip is also acceptable. ref. f. A. ](} h ~ Salem Unit 1 and 2
I-4.8 NOTE If shutdown by reactor trip is used, careful surveillance of control rod position is required to verify that all rods have tripped. If any rods are not fully inserted following reactor trip, borate by 150 ppm for each rod not fully inserted. PART II II. CONTINUOUS INSERSION OF A CONTROL ROD BANK II-1.0 LISCUSSION II-1.1 Allowing this condition to persist will create symptoms similar to an excessive cooldown or steamline break. If not corrected, a low pressure reactor trip will occur. II-2.0 SYMPTOMS II-2.1 Any of the following symptoms may be indicative of the continuous insertion of a control rod bank: II-2.1.1 Unwarranted rod motion as indicated by the step counter and red position indicators. s II-2.1.2 T,yg - T,,g Deviation Alarm II-2.1.3 Rod insertion limit alarm II-2.1.4 Decreasing T,yg and steam pressure II-2.1.5 Decreasing Pressurizer pressure. II-2.1.6 Decreasing Pressurizer level. II-3.0 IMMEDIATE ACTIONS II-3.1 Automa tic II-3.1.1 Any of the following automatic actions may occur as a consequence of the continuous insertion of a control rod bank:
- 1) Actuation of the Pressurizer Heaters
- 2) Pressurizer low pressure reactor trip.
II-3.2 Manual II-3.2.1 Verify that a turbine runback is not in progress and place the RCD ( BANK SELECTOR SWITCH in MANUAL. g II-3.2.2 If the control bank continues to insert, trip the reactor. Refer to EI I-4.3, " Reactor Trip. ~4~ Salem Un t 1 and 2
I-4.8 II-3.2.3 If the control rod bank stopped, manually withdraw it to restore ( equilibrium power and temperature conditions. II-4.0 SUBSEQUENT ACTIONS II-4.1 The Plant may be operated indefinitely under manual control until the automatic centrol equipment is repaired. II-4.2 Investigate the cause of the malfunction and make necessary repairs before resuming norma _ operation. PART III III. CONTINUOUS WITHDRAWAL OF CONTROL ROD BANK III-1.0 DISCUSSION III-1.1 The continuous withdrawal of a control rod bank may result from either an operator error or a Control System malfunction. In any case, if the condition is allowed to presist, the Reactor Protection System will initiate a reactor trip at the time protection limits are reached. This procedure is designed to avoid the need for a reactor trip whenever the condition is recognized in time. II III-2.0 SYMPTOMS III-2.1 Any of the follcwing symptons may be indicative of the continuous withdrawal of a control rod bank: III-2.1.1 Unwarranted rod motion as indicated by the step counter and rod position indicators. Deviation Alarm III-2.1.2 T,yg - Tref III-2.1.3 Increasing reactor power without an accompanying turbine load increase. III-2.1.4 Increasing T,yg III-2.1.5 Increasing Pressurizer pressure. III-2.1.6 Increasing Pressurizer level III-2.1.7 Increasing source / intermediate range flux level and/or startup rate during reactor startup. III-3.0 IMMEDIATE ACTIONS III-3.1 Automatic III-3.1.1 One of the following reactor trips may be initiated as a consequence ot a continuous withdrawal of a control rod bank.
- 1) Power Range High Neutron Flux Reactor Trip (High Setpoint),
salem Unit 1 and 2 g z n()/k Rev. 5
I- .8
- 2) Overtemperature iT Reactor Trip
- 3) Overpower AT Reactor Trip
- 4) Source Range High Neutron Flux Reactor Trip
- 5) Intermediate Range High Neutron Flux Reactor Trip
- 6) Power Range High Neutron Flux Reactor Trip (Low Setpaint)
III-3.1.2 If no reactor trip cccurs, one or more of the following automatic actions may have been initiated.
- 1) Power Range High Neutron Flux Rod Withdrawal Stop
- 2) Intermediate Range High Neutroh Flux Rod Withdrawal Stop
- 3) Overtemperature AT Rod Withdrawal Stop accompanied by turbine runback.
- 4) Overpower AT Rod Withdrawal Stop acccmpanied by turbine runback
- 5) Actuation of pressurizer spray and/or power relief valves.
III-3.2 Manual III-3.2.1 If in AUTO, transfer the ROD BANK SELECTOR SWITCH to MANUAL. III-3.2.2 If the control rod bank continues to be withdrawn, trip the reactor. Refer to EI I-4.3, " Reactor Trip". III-3.2.3 If withdrawa* stopped, manually insert the control rod bank to restore equilibrium power and temperature conditions. III-4.0 SUBSEOCENT ACTIONS III-4.1 If a reactor trip occurred, normal operation may be resumed after the fault has been located and repaired. III-4.2 If a reactor trip has not occurred, maintain equilibrium oonditions under MANUAL control until the fault has been determined and corrected. PART IV IV. DROPPED RCD IV-1.0 DISCUSSION IV-1.1 A dropped rod may result from C.a malfunction of one or more rod drive mechanisms. While the plant is at power, me Reactor Protection System will sense this abnormal condition and initiate an alarm. The Rod Control System will automat- [ ically compensate for the decreased T,yg by withdrawing the remaining control rod banks. 1337 097 Salem Unit 1 and 2 -6 Rev. 5
I-4.5 ( IV-2.0 SYMPTOMS IV-2.1 Any of the following syr.ptoms may be indicative of a dropped rod: IV-2.1.1 Individual rod bottom light and alarm frem the rod position indicators. IV-2.1.2 Rod position Deviation Alarm (Corputer) IV-2.1.3 Power Range Nuclear Instrumentation Channel Deviation Alar. IV-2.1.4 Decrease in reactor coolant T,yg. IV-2.1.5 T,,f - T,yg Deviation Alarm IV-2.1.6 Reactor Trip - Hi Negative Rate IV-2.1.7 If in AUTO rod control, the controlling rod bank will be stepped out. IV-2.2 For more than one dropped rod, a reactor trip will cecar due to a high negative flux rate. IV-3.0 IMPFDIATE ACTIONS IV-3.1 Automatic IV-3.1.1 Additional Pressurit.r Heaters turned ON. IV-3.1.2 Withdrawal of remaining control bank (s) to maintain T,yg. IV-3.1.3 In the case of one or more dropped rods, a rsactor trip will occur. IV-IV-3.2 Manual IV-3.2.1 If the RCD BANK SELECTOR SWITCH is in MANUA4 and the reactor did not trip, reduce the turbine load to maintain T, g equal to Tref* IV-3.2.2 If the reactor has tripped, fcllow EI I-4.J, " Reactor Trip". IV-4.0 SUBSEQUENT ACTIONS IV-4.1 If the turbine power is greater than 75%, reduce it to 75% or below within one hour. (Technical Specificatien 3.1.3.1) IV-4.2 When the plant conditions are stable, retrieve the dropped rod by the following steps: IV-4.2.1 place the ROD BANK SELECTOR SWITCH in MANUAL. IV-4.2.2 Record the reading indicated on the step counter (s) and on the P/A converter digital display of the affected bank. IV-4.2.3 Select the affected bank on the ROD BANK SELECTOR SWITCH. IV-4.2.4 DISCONNECT all lift coils of the rods in the affected bank, except the dropped red. Salem Unit 1 and 2 ~~
I-4.8 IV-4.2,5 If the individual position indicator for the rod that dropped does not indicate the rod fully inserted, manually insert tne affected bank to insure complete insertion of the dropped rod. IV-4.2.6 Reset the step counter (s) for the affected bank to zerc by rotating the thumb wheels. IV-4.2.7 If the dropped rod is a control rod, the pulse to analog (P/A) converter has to be zerced as follows: If the dropped rod is a shutdown rod, proceed to step IV-4.2.8 below.
- 1) To zero the P/A Converters a) Place the BANK POSITION DISPLAY SELECTOR SWITCH, on the
?/A Convert 9r to the affected rod bank position. b) Hold the AUTOMATIC-MANUAL switch (spring to AUTOMATIC) in the MANUAL position and push the DOWN pushbutton the required number of times to zero the digital BANK POSITION LISPLAY fer the affected bank. c) Release the AUTOMATIC-MANUAL switch, checking that it dues spring return to AUTOMATIC. ( NOTE The RCD INSERTION LOW LIMIT and ROD INSERTION LOW-LOW LIMIT annunciator alarms will sound during above steps. IV-4.2.8 Manually attempt to withdraw the affected rod while adjusting turbine load to maintain the programmed T,yg. NOTE An URGENT FAILURE alarm will be received during thin step. This will not affect withdrawal of the dropped rod. IV-4.2.9 If successful, withdraw the affected rod to the recorded step counter position. IV-4.2.10 CONNECT the lif t coils of the rods in the af fected bank. IV-4.2.ll Verify that the bank overlap unit and the P/A Con */erter readouts are correct for the rod bank position. IV-4.2.12 Reset the URGENT FAILURE alarm. IV-4.2.13 Verify the ROD BOTTOM DROP / ROD BANK URGENT FAIL annunciator clears. IV-4.2.14 Exercise the affected bank by moving the bank first in, then out L' 10 steps to verify normal operation cf the bank. 1337 099 -S-Rev. 5 Salem Unit 1 and 2
I-4.8 IV-4.3 Reset the flux rate trip on the NIS cabinet (s) for the affected power range channe?(s) by taking the RATE MODE switches to the RESET position and then back to NORMAL. IV-4.4 Resume normal operation by placing the RCD BANK SELECTOR SWITCH in the AUTO position. IV-4.5 If the dropped rod cannot be retrieved, monitor core power distribution to verify that it is within limits of Technical Specification, Power Distribution Limits. .PART V V. TULL LENGTH kOD MISALIGNVEN? V-1.0 DISCUSFION V-1.1 Rod misalignment results from a malfunution of a Control Rod Drive Mechanism or of the zod control power supply which causes a rod or a rod group to be out of alignment with its bank. When at power, rod misalignment can cause an adverse core power distribution. This could result in exr-eding the core safety limits, if caution and attention are not given to each corrective maneuver. 4 V-2.0 SYMPTOMS g V-2.1 One or more of the individual rod position indicators in disagreement with the associated group step counter or with other position indicators for rods in the same bank by more than + 12 steps. V-2.2 Disagreement between the group step counters for the same beak by more than 1 step. V-2.3 Abaermal variation in tcp-to-bottom flux difference between the four power range channels. V-2.4 Rod position Deviatien Alarm (Camputer). V-2.5 Abnormal core pcwer distribution as indicated by the in-core detectors and in-core thermocouples. V-2.6 on abnormal variation between loop T,yg or aT measurements and I,yg or iT Deviation Alarms. V-3.0 IM. MEDIATE ACTIONS V-3.1 Automatic g 1~337 100 V-3.1.1 None Salem Un.t 1 and 2 ~9~
I-4.8 [ V-3.2 Manual \\ V-3.2.1 Place the ROD BANK SELECTOR swit h in MANUAL control and avoid rod motion except as specified below. V-3.2.2 If the condition is indicated only by symptom V-2.1 and none of the other symptoms, check the questionable rod position indicator. Common indicator failure modes are:
- 1) Erratic indicated position when the bank is not being moved.
- 2) Sudden large indicated changes in rod position with no corresponding change in nuclear ?ower or motion of other rods.
NOTE Until indicator failure, and not contrcl rod malfunction, is established, assume rod misalignment. In-core measurements (flux maps and/or thermocouples) should be made, if necessary, to verify rod positions. I( rod position indicator malfunction is determined, refer to Section VI of this instruction. V-4.0 St'BSEQUENT ACTIONS r V-4.1 With a maximum of one full length rod misaligned from its group step counter g + 12 steps, comply with Technical Specification 3.1.3.1. V-4.2 Verify that a rod misalignment has occurred by use cf in-core detectors and the rmocouples. V-4.3 If rod misalignment is verified and the turbine power is greater than 75%, reduce it to 75% or below within one hour. NOTE Closely monitor the power range nuclear instrumentation for occurrence of abnormal flux tilts throughout all subsequent maneuvers. In all cases, DO NOT increase reactor power. V-4.4 When plant conditions are stable, attempt to align the control rod as follows: V-4.4.1 Place the ROD BANK SELECTOR switch in MANUAL. V-4.4.2 Record the reading indicated on the step countr.r(s) of the affected bank and reset the step counter (s) to the misaligned rod position by rotating the thumb wheels. V-4.4.3 Record the reading on the P/A Converter digital display for the affected ( bank. ] V-4.4.4 Select the af fected bank on the RCD BANK SELECTOR SWITCH. Salem Unit 1 and 2 Rev. 5
I-4.d i V-4.4.5 DIbuCNNECT all lift coils of the rods in the affected bank, except the misaligned rod. V-4.4.6 Align the misaligned control rod with its bank while adjusting turbine lead to maintain the programmed T,yg. NOTE When rod motien starts, n URGENT FAILURI alarm will sound. V-4.4.7 CONNECT the lift coils of the rods in the affected bank. V-4.4.8 Reset the Pulse to Analog Ccnverter for the affected bank to the setting recorded in step V-4.4.3. V-4.4.9 Reset the URGENT FAILURE alarm. V-4.4.10 When plant conditions are stable, drive the affected red bank in 10 steps and then out 10 steps to verify proper rod operation. V-4.4 ll Place the ROD BANK SELECTOR SWITCH in AUTO and continue normal plant operation. V-4.5 If the condition cannot be corrected, and only one red is misaligned: V-4.5.1 CONNECT the lift coils of the rods in the afIected bank. V-4.5.2 Reset the affected GROUP step counter to the bank position. V-4.5.3 Reset the Pulse to Analog Convertar foi the affected bank to the setting recorded in step V-4.4.3. V-4.5.4 Continue plant cperation if rod misalignment is within limits of Technical Specification 3.1.3.1 and the core power distribution is within limits of Technical Specifications. PART VI VI. MALFUNCTIONING RCD POSITION I?.'0 !CATv R VI-1. 0 DISCUSSION VI-1.1 Control rod position is of vital importance when the reactor is in the power rango. A rod that is misaligned with respect to its bank could result in exceeding the core design limits. If a rod position indicator is out of service, cc Sful surveillacce is needed to insure that the associated rod is functioning preperly with respect te its bank. 1337 102
- talem Unit 1 and 2 Rev. 5 l
I-4.8 8 f Em3 s V-2.1 The following symptoms indicates a r.alfunctioning red position indicator: VI-2.1.1 An individual rod position indicator in disagree. tent with the associated group step counter or with other position indicators for rods in the same bank by more than + 12 steps when no rods are in motion and che control rod is known to be correctly aligned with its tank. VI-2.. 2 Erratic indicated pcsition when the bank is not being moved. VI-2.1.3 Sudden large indicated changes in rod positien indication with no corre pending change in nuclear power or motion of the other rods. VI-2.1.4 Rod Bottom Rod Drop Alarm. VI-3.0 IMMEDIATE ACTIO"S VI-3.1 Automatic VI-3.1.1 None s VI-3.2 Manual A VI-3.2.1 Until the red position indicator is known to be at fault, assume the rod to be misaligned and follow the red misalignment procedure, Part V or VI of this instruction. Vl-4.0 SUBSECUENT ACTIONS VI-4.1 With a contiol rod position indicator channel for any control rod assembly inoperable, insure compliance with Technical Specification 3.1.3.2. V '- 4. 2 If the faulty rod position indicator is associated with a full length rod in the bank used for control (neither fully inserted nor fully withdrawn), minimize load changes. VI-4. 3 If a plant shutdown occurs, assume that the non-indicated rod is stuck in 14 3 fully withdrawr sosition unless prior power distribution measurements indicated that it '
- n the inserted position. Required shutdown margin as prescribed in the plant Technical Specifications (in the form of boren or withdrawn rods available to trip) must be available at all times.
Borate by 150 ppm for each rtd that the position is net known. ( 1337 103 Salem Unit 1 and 2 Rev. 5 l
I-4.8 VI-4.. During any control red exercise tests fer banks containing a non-indicated red, bank snotion must be suf ficient to verify from thermocouples or in-core detector flux caps that the rod has moved approximately the same as its bank. Make a core thermocouple map before and after the test to verify that the rod has returned to its original position. VI-4. 5 After the cause of the malfunction has been determined and corrected and position indication operability verified, normal power operation may res.ae. M Prepared by R. Hallmark / Manager - Sale / Generating Station Reviewed by J. Bailey SORO Meeting No. 40-79 Date_ 5/24/79 9 L ) 1337 104 Salem Unit 1 and 2 Rev. 5 l
I-4.9 EMERGENCY INSTRUCTION I-4.9 BLACKOUT 1.0 PURPOSE a This instruction provides the steps required to recover the station following a " Blackout". 1.1 A " Blackout", Loss of Power to the 4kV Group Busses, will result in a reactor trip, turbine trip, and a loss of Station power to both Unit 1 and Unit 2. The 4kV Vital Busses will be automatically energized from the emergency Diesel Generators. The 4kV Group Busses can be manually energized from the Gas Turbine Generator. 1.2 Since a Blackout will result in a loss of forced flow through the Reactor, decay heat will be removed by natural circulation. This instruction gives the guidelines to be followed to verify natural circulation is established and maintained. 2.0 INITIAL CONDITIONS 2.1 General loss of electrical power 3.0 IMMEDIATE ACTIONS 3.1 Automatic 3.1.1 Reactor Trip - Turbine Trip 3.1.2 4kV Vital Bus loads s. tripped 3.1.3 Diesel Generators start and load 3.1.4 The 413(23) Turbine driven Auxiliary Feed Pump starts 3.1.5 The equipment listed in Table I will sequence on the bus. 3.1.6 The following DC Oil Pumps will start as header oil pressure decreases:
- 1) 11 & 12 (21 & 22) Feed Pump Turbine Emergency Oil Pumps
- 2) 1& 2 Turbine Generatcr Emergency Bearing Oil Pumps
- 3) 1& 2 Emergency Seal Oil Pumps 3.2 Manual 3.2.1 Verify that a reactor trip has taken place:
- 1) Check that all full length rods are fully inserted by checking individual rod position indicators and rod bottom lights.
2) If all full length control rods are not fully inserted, RAPID BO E by 150 ppm (approximately 8 minutes) for each rod not fully in IAW OI II-3.3.8, " Rapid Boration". 3.2.2 Verify turbine trip by checking the following: rN 3
- 1) UNIT TRIP light on E/H console illuminated.
k
- 2) Turbine Stop Valves, Governor Valves, Inter
' \\ Ives and Reheat Stop bD Valves closed. k
- 3) Turbine Speed decreasing.
gD 1337 105 Salem Unit 1/ Unit 2 _1 Rev. 8
I-4.9 3.2.3 Within 2 minutes reduce Aux. Feedwater flow to the Steam Generators to limit the rate of rise to < l.2 in/ min by monitoring wide range level recorders. Monitor narrow range le,el using the trend typewriter (points LO403A, LO443A, LO463A) and lim.t the rate of rise to < 0.2t/ min until level is > 10%. NOTE This limitation applies to Unit No. 1 only. 3.2.4 Verify that Tavg is decreasing toward or is being maintained at 547'T by either steam dump or atmospheric steam relief. 3.2.5 Announce over the plant PA System twice: " UNIT NO. 1(2) REACTOR TRIP". 3.2.6 Verify Decay Heat Removal by natural circulation by observing the following: a. Reactor Coolant loop AT < 62*F on one or more loops. b. Core exit thermocouples and loop T indicating temperatures are stable or H slowly decreasing. Steam Generator pressure s 1000 psig on all Steam Generators for which c. the loop AT is < 62'F. 3.2.7 Verify all automatic actions listed above, initiate any which have not occurred. 3.2.8 Determit.e whether "Riackout" is due to local malfunction or failure of the New Freedom Infeed Lines 5023, 5024 and/or Keeney Line 5015 (call Load Dispatcher). 4.0 SUBSEQUENT ACTIONS 4.1 Establish or maintain the following conditions to ensure maximum natural circulation is maintained in the Reactor Coolant System for Decay Heat Removal. Reactor Coolant pressure 1 2000 psig. 'ressurizer level 1 50%. ) eam Generator level 3 10% in the narrow range on at least one Steam .ierator, and if possible all four. 2 pen or ve.ify open, 500kV GCB's 1-5, 5-6, 2-6, 1-8, 2-8, 2-10, 9-10, 1-9, Circuit Swicch.s 1T60, 2T60, 13kV ACB's 1-2, 2-3, 3-4, 4 -5, 5-6 and 1-6. ~ utrip all loads from the 4kV Group Busses for Unit I and Unit 2. Open.or check open the following infeed breakers to the group busses: kh lH - llHSD & 1AHGD IE - llESD & 1AEGD 1F - 12FSD & IBFGD ) 1 - 12GSD & IBGGD c's 2H - 21HSD & 2AHGD 2E - 21ESD & 2AEGD 2F - 22FSD & 2BFGD 2G - 22GSD & 2BGGD g 1.4 Energize the 4kV Group Busses from the Gas Turbine as fo
- 4. 4.1 Start the Gas Turbine Generator IAW OI VIII-1.
d" Dead Bus Operation - Bootstrap Start", and verify.the Gas Turbine Ou t Breaker closes. If the Gas Turbine fails to start, proceed to ste 1337 106 Salem Unit 1/ Unit 2 Rev. 8
I-4.9 4.4.2 Close the following 13kV breakers to energize No. 11, 12, 21 and 22 Station Power Transformers: 3-4, 4-5, 2-3, 5-6 4.4.3 Close the following breakers to energize the 4kV Group Busses: 1H - llHSD 2H - 21HSD lE - llESD 2H - 21ESD 1F - 12FSD 2F - 22FSD 1G - 12GSD 2G - 22GSD 4.5 Start the followirig equipment on the Group Busses. The exact cceponent to be starte:i will be determined based en availability, plant conditions, etc. at the time. CAUTION The Gas Turbine is operating in the isolated mode of of opsration. Starting of equipment must be coordi-nated with the operator at the Gas Turbine controls as he mast adjust the unit manually each time there is a change in load. 4.5.1 One station Air Compressor 4.5.2 One Condensate Pump 4.5.3 One Turbine Auxiliary Coolino Pump 4.5.4 One Feed Pump Lube Oil Pump on 11, 12, 21 & 22 Feed Pump 4.5.5 Air side Seal Oil Pump 4.5.6 Auxiliary Bearing Oil Pump 4.5.7 Bearing Lift Pump 4.5.8 High Pressure Seal Oil Pump 4.5.9 Close the following 4kV breakers: e s
- 1) 1H3D to lighting bus lHL g
N.k
- 2) IF3D to lighting bus 1FL y
, a
- 3) lE6D to Pressurizer Heater bus IEP M
- 4) 2H3D to lightin'3 Bus 2HL 4
1337 107
- 5) 2F3D to lighting Bus 2FL Salem Unit 1/ Unit 2 Rev. 8
I-4.9
- 6) 2E6D to Pressurizer Heater Bus 2EP 4.6 S.op the following DC Litbe Oil Pumps 4.6.1 11, 12, 21, 22 Feed Pump Emergency Lube Oil Pump 4.6.2 1, 2 Emergency Air Side Seal Oil Pump 4.6.3 1, 2 Emergency Bearing Oil Pump 4.7 Reset the Safeguards Loading Sequence by depressing the Emergency Loading Reset pushbuttons on the control console for 1A, 1B, 1C (2A, 2B, 2C) Diesel Generators.
4.8 Place Turbine Generator on turning gear. If turning gear trips, do not attempt repeated starts. Thereafter, attempt to place turning gear in operation at one hour intervals. 4.9 If unable to utilize the Gas Turbine Generator, proceed as follows: 4.9.1 Break Condenser vacuum to reduce turbine roll time by manually opening 11, 12 13 (21, 22, 23)AR65 Vacuum Breaker Valves. 4.9.2 The DC Emergency Bearing Oil Pump should supply lubricatirg oil during the roll do rn to zero speed and for 1/2 hour theraf ter. 4.9.3 Subsequent operation of the DC Pump shc11d be intermittent off for 45 minutes and run for 15 minutes, to avoid damaging bearing babbitt. This will extend the usefulness of the station battery power. 4.9.4 During operation of the Emergency Oil Pump, attempt to operate turning gear with an air drive on gear extension shaft. 4.9.5 Reduce H2 pressure in the Main Generator to < 2 psig IAW OI IV-2.3.2, " Generator Gas Systems - Normal Operation", as soon as possible to prevent H leakage. 2 4.9.6 Energize IEP(2EP) Pressurizer Heater Bus from the Emergency Feed from 1A(2A) 460V Vital Bus as follows:
- 1) Open lEPX(2EPX) from the Pressurizer Backup Heater Group 1 Bezel on the control console.
- 2) Open lE6D(2E6D), 4kV infeed to Pressurizer Heater T rmer, from the
'S control console. 'k /
- 3) Remove the key from inside the breaker cubicle fp lE6D(2E6D) for the Correy key interlock.
intheRelayRoomonEl.947 108 1
- 4) Open LEX (2EX) on the 1(2)E 460V Group of the Auxiliary Building and remov hey for the Correy key interlock.
- 5) Close the Manual Disconnect Switch for the Emergency Feed at lEP(2EP) heater bus.
e
I-4.9
- 6) Insert the keys from lE6D(2E6D) and IEX(2EX) into breaker lA14X(2A14X),
IEP(2EP) Pressurizer Heater Emergency Feed, and close the breaker.
- 7) Power is now available to the lEP(2EP) Pressurizer Heater Bus.
The Heaters may be energized in the normal manner by closing lEPX(2EPX) from the Press-urizer Backup Heater Group 12(22) Bezel on the control console. 4.9.7 When off-site power is available, establish station power in coordination with the Load Dispatcher as follows:
- 1) Verify that 5023 and/or 5024 and/or 5015 lines are energized.
- 2) Close the following breakers for the lines which are energized:
5023 8 and 2-8 5024 6 5015 10 Proceed as follows for each breaker. a) Depress the LOCAL pushbutton. b) Select the desired breaker on the Mimic Bus c) Depress SYNC POT ON d) Observe the synchroscope and the running and incoming voltage meters on the control console to assure syr.cl.ronism is attained. If it is not, do not attempt to close the breaker. Contact the Laad Dispatcher as there is nothing which can be done from the Salem end to adjust the lines. e) Close the breaker f) Depress the SYNC POT OFF.
- 3) C1cse circuit switches IT60 and 2T60.
- 4) Close the following 13kV Breakers to energize the No. 11,12,21, an Station Power Transformers.
cSN 1-2, 1-6, 3-4, 4-5 kk #(b e 3
- 5) Close the following breakers to energize the 4kV Group u:
pr - 13 - llHSD 2H - 21HSD ff IE - llESD 2E - 21ESD D 1F - 12FSD 2F - 22FSD 'j 3f ] 1G - 12GSD 2G - 22GSD 3 Coordinate loading of the Busses with the ad Dispatcher. Salem Unit 1/ Unit 2 Rev. 8
I-4.9
- 6) Return the 4kV Vi;,.
o b.:; mal Operation IAW OI IV-16.3.1, " Emergency Power - Dici-t'peration". EAUTION In the event one of the Diese". has failed to energize its Vital Bus, that Vital Bus must be returned to Off-site power first in order to maintain minimum operable safeguards equipment. 4.10 If the Gas Turbine Generator was started in Step 4.3, continue operation until 5023 and/or 5024 and/or 5015 - 500kV Lines are energized to Salem from New Freedom or Keeney. Proceed as follows: 4.10.1 Verify that 5023 and/or 5024 and/or 5015 500kV Lines are energized. CAUTION Two off-site power supplies must be available before synchronizing #3 Generator with the 500kV Infeed Lines, so that the VAR rating of the #3 Generator is not exceeded. 4.10.2 Check that 2T60 Circuit Switch is open. 4.10.3 Close 1T50 Circuit Switch. 4.10.4 Close or verify closed 13kV ACB-s 1-2, J-3 and 3-4. 4.10.5 Close or verify closed 13kV's ACB's 1-6, 5-6 and 4-5. 4.10.6 Parallel across and close the following breakers for the lines which are energized: 5023 8 5024 6 5015 10 NOTE A Synchronism must be established through communications ( )$ between the Control Room and t'e gas turbine local , SN n control. m 'p CAUTION g While No. 3 Generator is synchronized to two $'OQkV Lines 1337 110 A s 5023 (or 5024) (or 5015) the three breakersi associated at New Freedom or Keeney with each line muskk>e closed. s Verify with Load Dispatcher. r a 5023-NewFreedomBreakers20h/21N,22X 4 5024 - New Freedom Breakers 30X, 31X, 32X 5015 - Keeney Breakers 503 or 504 Rev. 8 Salem Unit 1/ Unit 2 -6
I-4.9 Proceed as follows for each breakers a) Depress the LOCAL pushbutton b) Select the desired breaker on the Mimic Bus. c) Depress SYNC POT ON d) Observe the. synet.roscope and the running and incoming voltage meters on the control ecnsole. Adjust the Gas Turbine Generator voltage and fre-quency until the synchroscope is moving slowly in the fast direction and the running and incoming v71tages are matched. e) Close the breaker f) Depress the SYNC POT OFF. 4.10.7 Open 13kV ACB's 2-3 and 5-6 d.10.8 Close 2T60 Circuit Switch 4.10.9 Repeat step 4.8.6 a-f for the 1-8 500kV breaker. NOTE Synchronism must be established through communications between the Control Room and the Gas Turbine local control. 4.10.10 Switch No. 3 Unit mode selector to Parallel Mode and reduce power to zero or operate Unit as requested by the Load Dispatcher. 4.10.11 Return the 4kV Vital Busses to Normal Operation IAW OI IV-16.3.1, " Emergency Power - Diesel Operation". CAUTION In the event one of the Diesels has failed to energize R-i its vital Bus, that Vital Bus must be returned to off-site power first in order to maintain minimum safeguards equipment. j 4.11 As conditions dictate, operate IAW one of the following OI's: h 4.11.1 I-3.3, " Hot Standby to Minimum Load" 4.11.2 I-3.8, " Maintaining Hot Stanby 67 1337 ill 4.11.3 I-3.6, " Hot Standby to Cold Shutdown". e
I-4.9 NOTE In the event Normal-Off-Site Power cannot be restored to the Vital Busses, refer to Appendix A for equipment to be operated during the cooldown. Prepared by Manager - Ealem Generating Station Reviewed by SORC Meeting No. Date D:p%' 1337 112 A)N deb Salcm Unit 1/ Unit 2 Rev. 8
I-4.9 APPENDIX A BLACKOUT DISCUSSION Following a loss of all offsite power, the Diesel Generators will be supplying power to the vital busses. In order to prevent overloading the Diesel Generators, certain equipment must be stopped prior to cooling down and initiating Residual Heat Removal. After SEC is reset, proceed with the appropriate section. PART I - ALL DIESEL GENERATORS AVAILABLE 1. If irradiated fuel is stored in the Fuel Handling Building, proceed as follows as soon as SEC is reset to facilitate coolcucn to the point of RHP initiation. 1.1 Stop the following equipment: lA(2A) Diesel Generator - fil(21) Auxiliary Feedwater Purp 811(21) Component Cooling Pump 1B(2B) Diesel Generator - 811(21) Charging Pump 1C(2C) Diesel Generator - #12(22) Charging Pump 833(23) Component Cooling Pump 1.2 Start the following equipment: 1A(2A) Diesel Generator - #13(23) Charging Pump 811(21) Fuel Handling Area Exhaust Fan
- 11(21) Fan Coil Unit in Fast Speed 1B(2B) Diesel Generator - #12(22) Fuel Handling Area Exhaust Fan
- 12(22) Spent Fuel Pit Pump 1C(2C) Diesel Generator - #11(21) Spent Fuel Pit Pump 813 or 15(23 or 25) Fan Coil Unit in Fast Speed 2.
When the Steam Ge.erators have been placed in wet layup, stop No. 12(22) Auxiliary Feedwater Pump. ch v 3. For the initiation of RHR, thefollowingequipmentmaybeoperatedasspecifiedihOIII-6.3.2, Nh " Initiating Residual Heat Removal". 3 ,,o 1A(2A) Diesel Generator - 411(21) RHR Pump J3 93 811(21) Component Cooling Pump
- h IB(2B) Diesel Generator - 012(22) RHR Pump 5
IC(2C) Diesel Generator - 13(23) Component Cooling Pump 's 3 Y PART II - FAILURE OF 1A(2A) DIESEL GENERATOR d b> proceed as follows as soon as dg, 1. If irradiated fuel is stored in the Fuel Handling Buid SEC is reset to facilitate cooldown to the point of RHwinitiation. Sa em
e I-4.9 e 1.1 Stop the following equipment: IB(2B) Diesel Generator - $12(22) Component Cooling Pump IC(2C) Diesel Generator - 812(22) Charging Pump 1.2 Start the following equipment: IB(2B) Diesel Generator - $12(22) Fuel Handling Area Exhaust Fan
- 12(22) Spent Fuel Pit Pump 1C(2C) Diesel Generator - $11(21) Spent Fuel Pit Pump 813 and 15(23 and 25) Fan Coil Units in Fast Speed.
2. Transfer vital heat tracing to emergency source 3. When the Steam Generators have been placed in wet layup, stop No. 12(22) Auxiliary Feedwater Pump. 4. For the initiation of RHR, the following equipment may be operated as specified in OI II-6.3.2, " Initiating Residual Heat Removal". IB(2B) Diesel Generator - $12(22) RHR Pump fl2(22) Component Cooling Pump PART III - FAILURE OF 1B(2B) DIESEL GENERATOR 1. If irradiated fuel is stored in the Fuel Handling Building, proceed as follows as scon as SEC is reset to facilitate cooldown to the point of RHR initiation. 1.1 Stop the following egoipment: IC(2C) Diesel Generator - #13(23) Component Cooling Pump 1.2 Start the following equipments lA(2A) Diesel Generator - $11(21) Fuel Handling Area Exhaust Fan
- 11(21) Fan Coil Unit in Fast Speed IC(2C) Diesel Generator - $11(21) Spent Fuel Pit Pump 413 or 15(23 or 25) Fan Coil Unit in Fast Speed ky p
r: ' 2. When the Steam Generators have been placed in wet layup, stop No. 11(21) Auxilikh Feedwater 3. For the initiation of RHR, the following equipment may be operated '"s ified in OI II-6.3.2, " Initiating Residual Heat Removal". T m 1A(2A) Diesel Generator - $11(21) RHR Pump Th IC(2C) Diesel Generator - 813(23) Component Coolin Pushh y> MS Salem Unit 1/ Unit 2 Page 2 of 3 Rev. 8
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- 4 I-4.10(A)
EMERGENCY INSTRUCTION I-4.10(A) CONTROL ROOM EVACUATION 1.0 DISCUSSION 1.1 The primary purpose of this instruction is to establish a safe and orderly method of maintaining the reactor in a Hot Standby condition from outside the Control Room. Since Control Room inaccessibility is regarded as a single event, this instruction assumes all plant safety features and automatic controls function normally. 1.2 The secondary purpose of this instruction is to establish a safe and orderly method; including provisions for manually operating equipment, operating equipment by use of electrical jumpers and monitoring various system parameters; for taking the plant from a Hot Standby to a Cold Shutdown condition from outside the Control Room. 1.3 Controls for essential systems are provided locally at various plant locations and are detailed in Table I. Most controls located locally are provided with a LOCAL - REMOTE transfer switch. Before local operation can be assumed, such transfer switches must be in the LOCAL position. Table I provides a list of local control stations including locations, controls, and indications available. 1.4 Tables II, III and IV provide guidance on the local operation of valves, pumps, etc. Special insulated electrical jumpers, air " Hand Senders" and Head Sets are stored in a cabinet in the vicinity of the Hot Shutdown Panel (Panel 213). NOTE When conditions permit, the use of all electrical jumpers that are terminated in this instruction should be documented in accordance with Adminstrative Procedure AP-13, " Control of Lif ted Leads and Jumpers". 2.0 SYMPTOMS 2.1 Some unforseen cause or causes which requires evacuation of personnel from the Control Room. 3.0 IHMEDIATE ACTIONS 3.1 Automatic 3.1.1 None 3.2 Manual - Control Room Salem Unit 2 Rev. O
I-4.10(A) NOTE If possible, perform the following manual - immediate actions prior to evacuating the Control Room. 3.2.1 Trip the reactor prior to leaving the Control Room.
- 1) If tripping the reactor is not possible prior to leaving the Control Room, trip the reactor by opening the reactor trip breakers locally in the Switchgear Room, Elevation 84', Auxiliary Building.
(Depress pushbutton on face of Reactor Trip Breakers A and B) 3.2.2 Verify, if possible, that all full length rods are fully inserted by checking individual rod position indicators and rod bottom lights. 1) If all full length control rods are not fully inserted, RAPID BORATE by 150 ppm (approximately 8 minutes) for each rod not fully inserted IAW OI II-3.3.8, " Rapid Boration". NOTE If verification of all rods being full inserted is not possible, the Senior Shift Supervisor / Shift Supervisor may desire to borate locally. 3.2.3 Verify, if possible, that Steam Dump Control System is in AUTO and each Atmospheric Steam Relief Valve (MS10) is in AUTO. 3.2.4 Verify, if possible, that the MAKEUP MODE SELECTOR is in AUTO and set for blended makeup. 3.2.5 Pick up keys to the shutdown panels. 3.3 Manual - Outside Control Room 3.3.1 Assign an operator to Panel 213 (Hot Shutdown Panel) and an operator to control Steam Generator levels by use of Auxiliary Feedwater Pumps and associated flow control valves. Maintain level at 4 33% on the narrow range indicators (equiva-lent to 4 60% on the wide range). 3.3.2 At Panel 213, verify that Pressurizer level is controlling automatically at s 22%.
- 1) If Pressurizer level is not controlling automatically or if decired:
a) Station an operator at Panel 216 (Charging System Panel) b) Establish communication between Panel 213 and 216. 1337 116 Salem Unit 2 Rev. O
I-4.10(A) c) At Panel 216, take lv al-manus 1 control of 2CV55, Charging Flow Control Valve, and maintain Pressurizer level at i 22%. d) Start one Centrifugal Charging Pump in LOCAL control at Panel 213. e) If desired remove from service No. 23 Charging Pump by openinc the breaker on 2A-460V Vital Bus on Auxiliary Building Elevation 84*. 3.3.3 At Panel 213, verify that Pressurizer pressure is controlling automatically at % 2235 psig.
- 1) If Pressurizer pressure is net controlling automatically:
a) Dispatch an operator to the Pressurizer Heater Control Panels in the Electrical Penetration Area, Elevation 78'. b) Establish communications between the Electrical Penetration Area and Panel 213. c) Take local-manual control of the pressurizer heaters and maintain Pressurizer pressure at s 2235 psig. 3.3.4 At Panel 213, verify that T is decreasing toward or is being maintained at H about 547'T by either steam dump to the condensers or by atmospheric steam relief.
- 1) If T is not being controlled automatically at about 547'r:
H a) Dispatch an operator to the North and/or South Penetration Area, Elevation 100'. b) Establish ccmmunications between the Penetration Area and Panel 213. c) Take local-manual control of the Atmospheric Steam Relief Valves (MS1*' by use of manual hand-a ir operators in 3 ccal panels. CAUTION Operate the MS10's such that all Steam Generator Pressures remain within 100 psig so as to preclude the possicility of an inadvertent Safety Injection due to Steam Generator IP. NOTE Manual handwheel operation of the MS10 valves is also available locally at each valve in the Penetration Areas. d) If necessary, close the Steam Generator Stop Valves (MS167) by use of test switches provided in local panels in the Penetration Area. f\\ Salem Unit 2 Re'; O
I-4.10(A) NOTE Leaving the MS167's open will help maintain Steam Generator pressures approximately equal and limit the possibility of an inadvertent Safety Injection due to Steam Generator LP. 4.0 SUBSEQUENT ACTIONS 4.1 Ensure that an adequate volume of water is available in the Auxiliary Feedwater Storage Tank (AFST) and is maintained, if possible, > 37.9 feet (equivalent to N 200,000 gellons) by transferring water from the DM System. 4.1.1 If an adequate volume of water in the AFST cannot be maintained, shift the suction of the Auxiliary Feedwater Pumps to a preferred (i.e. DMWTs or FW & FPWTs) alternate supply of water - IAW OI III-10.3.1, " Auxiliary Feedwater System Operation". In addition, if none of the preferred alternate water supplies are available, the Auxiliary Feedwater System shall be connected to the Service Water System for use as an emergency alternate water supply IAW OI III-10.3.1, " Auxiliary Feedwater System Operation". CAUTION To ensare safe shutdown in the event that the Auxiliary Feedwater supply is lost in conjunction with the Main Feedwater supply, shift over to an alternate Auxiliary Feedwater supply (including the installation of spool pieces) should be accomplished within N 30 minutes.
- 1) When the AFST is returned to an operable status, return the Auxiliary Feedwater supply to a normal lineup IAW OI III-10.3.1, " Auxiliary Feedwater System Operation".
4.2 When T decreases below 554'F, perform the following: H 4.2.1 Start No. 21 and 22 AFW Pumps locally at Panels 205 and 206 respectively. 4.2.2 Trip both Main Feed Pumps locally.
- 1) If the motor-driven AFW Purps cannot be started manually, start No. 23 AFW Pump locally in Panel 207.
NOTE If any two of the four Steam Ger. orator's level decreases below the Low-Low Level setpoint No. 23 AFW Pump should start automatically. 1337 118 Salem Unit 2 Rev. O
I-4.10(A) 4.2.3 Control each Steam Generator's water level at approximately 331 by local narrow range indication by performing the following: (Equivalent to N 60% wide range indication)
- 1) By manual operatu a of 5/G AF Control Valves 21,22,23 & 24AF21, if the motor-driven AFW Pumps are running; a) Check Control Valves 21,22 23 & 24AFll closed.
- 2) Or by manual operation of S/G AF Control Valve 21,22,23 & 24Afil if the turbine-driven AFW Pu=p is running.
4.3 Place the Main Turbine on the T,urning Gear when the shaf t stops. 4.4 If the Generator was on the line, verify the following: 4.4.1 500kV breakers 1-9BS and 9-10B5 have opened. 4.4.2 The 4160 Group Busses have transferred from the No. 2 Auxiliary Power Trans-forrer to No. 21 and No. 22 Station Power Transformers by checking the following breaker alignment: 2BGGD - Open 22GSD - Closed 2BFGD - Open 22FSD - Closed 2AEGD - Open 21ESD - Closed 2AHGD - Open 21HSD - Closed 4.4.3 Generator Exciter Field Breaker has opened (Elev. 120' Turbine Bldg.). 4.5 If operation ouside the Control Room is expected to extend beyond 24 hours from the time of the reactor trip or if the plant is to be taken to Mode 5, borate to the Xenon-free Cold Shutdown condition. 4.6 Borate, as necessary, in the following manner: 4.6.1 Take LOCAL control of No. 21 or No. 22 Boric Acid Transfer Pump at Panel 213 and start the pump in FAST speed. 4.6.2 Check open or fail open Boric Acid Ficw Control Valve 2C'.'172 and open Blender Bypass Valve 2CV174. 4.6.3 Insure charging flow is > 75 gpm at Panel 216. 4.6.4 Bcron concentration should increase at s 23 ppm / minute. 4.7 Perform a shutdown rargin calculation IAW the Peactor Engineering Manual, to verif'i that the shutdown margin is at least 1.6% ak/k. Salem Unit 2 Fe; O
I-4.10(A) 4.8 As regaired by AP-5, notify personnel of the reactor trip and of the Control Room evacuation. 4.9 As conditions require, take the plant to Cold Shutdown as detailed in the remaining steps of this instruction. Install tne following temporary controls, indications and jumpers: 4.9.1 Fluke Digital Thernometer or equivalent at Computer Thermocouple Terminal Cabinet (Unit 2 Relay Room); TP10-82 and 83, (CWG 203451), to monitor regenerative Heat Exchanger outlet temperature (TE-126: Iron-Constantan), 4.9.2 Jumpers for 21SJ49 and 22SJ49 as follows: (These will bypass the lockout switches located on 2RP4).
- 1) At 2A East Valves & Misc. 230V Vital Control Center, terminals 29 and 30 and 3,,1 and 32 on PAN 30.
- 2) At 2B West Valves & Misc. 230V Vital Centrol Center, terminals 29 and 30 and 31 and 32 on PAN 2D.
4.9.3 " Hand Senders" at Panel 101 for 21RH18 and 2RH2O and Panel 102 for 22RH18. 4.9.4 " Hand Sender" at Panel 202 for 2CV8. 4.9.5 Have " Hand Senders" availabe at Panel 314 for 2CV172 and 2CV179 for ase if the makeup system does not function in AUTO. 4.9.6 Establish communications between the plant locations as specified in Table V for Hot Standby to Cold Shutdown (Mode 5). NOTE Should Cold Shutdown not be required and Control Room access be regained:
- 1) Assign operators to the Control Room to cocrdinate with operators assigned at local stations while shif ting back to REMOTE Centrol.
- 2) Coordinate restoratien of the Solid State Protection System with the Performance Department Technicians.
- 3) Refer to El I-4.3,
" Reactor Trip" for continued operation. 4.10 Ensure the level in the VCT is maintained at 20% by auto operation _of the level Centrol System. VCT level indicater is provided at Panel 216. 1337 120 Salem Unit 2 nev 0
1-4.10(A) 4.10.1 Should local-manual operation of 2CV35 be required (i.e. divert to HUT to lower VCT level, position to VCT to raise / maintain VCT level), refer to item 29 of Table II. 4.10.2 Should local-manual operation of individual Reactor Makeup Control System Valves and Pumps become necessary due to loss of auto features, the following local-manual operations may be performed as required.
- 1) At Panel 213, take local-manual control of the Boric Acid Pump (s) and start in fast speed.
- 2) To operate 2CVl72, Boric Acid Flow Control Valve, install the " Hand Sender" at Panel 314.
- 3) Te operate 2CV179, Primary Water Flow Control Valve, install the " Hand Sencer' at Panel 314.
- 4) To operate 2CV185, Makeup Stop Velve, refer to item 30 of Table II.
(2CV185 must be placed in MANUAL and then opened) 5) S* art either No. 21 or 22 Primary Water Makeup Pump, refer to item 1 or 2 of Table IV. Verify the pump starts by observing the discharge pressure on the local gage. 4.11 Notify the Technical Supervisor - Chemistry, or nis designee,tof the impending plant cooldown and the need to samplo the RCS once per hour during the cooldown. 4.11.1 To open 2SS33, Hot Leg Sample Valve, refer to item 18 of Table II. 4.11.2 To open 2SS104, Hot Leg Sample Valve, refer to item 17 of Table II. 4.11.3 To open 2S549, Pressurizer Liquid Sample Valve, refer to item 16 of Table II. 4.11.4 To open 25S107, Pressurizer Liquid Sample Valve, refer to item 15 of Table 'T. 4.12 After the Pressurizer boron concentration has becn verified to be within 50 ppm of the concentration in the reactor coolant loops: 4.12.1 Dispatch an operator to the Pressurizer Heater Control Panels in the Electrical Penetration Area, Elevation 78'. 4.12.2 Establish communications between the Electrical Penetration Area and Panel 213. 4.12.3 De-enernize all Pressurizer heaters. 4.12.4 Monitor RCS pressure and temperature at Panel 213. Operate the pressurizer Heaters as required to maintain RCS pressure such that the highest T indication g is at least 50'F below the saturation temperature as determined fror F1 pure 1. (i.e. if T is 500*F, maintain pressure creater than the saturation pressure for g 5f0 r). Salem Unit 2 Rev 0
I-4.10(A) 4.13 During the subsequent cooldown, provide blended makeup water to the RCS by use of the Reactor Makeup Control System in automatic or as described in step 4.10. NOTE Since the Automatic Controls for the Makeup System may not be set to maintain the RCS at a Cold, Xencn-Free concentration, it may be necessary to increase boron concentration during the cooldown. If the RCS samples indicate a decrease in boron concentration, proceed as outlined in Step 4.6 until the concentration is greater than the cold Xenon-Free concentration. 4.14 Initiate plant cooldown as follows: 4.14.1 To prevent inadvertent Safety Injection, open the following breakers to remove power from the output relays of the Solid State Protection System. Station an operator at the breakers so they may be closed to actuate Safety Injection if conditions warrant.
- 1) TRAIN "A" - Breaker No. 5 on 2A 115 VAC Vital Instrument Bus.
- 2) TRAIN "B" - Breaker No. 8 on 2B 115 VAC Vital Instrument Bus.
NOTE Solid State Protective Functions may be re-established at any time by reclosure of these breakers. 4.14.2 Dispatch an operator (or operators) to the North and/or South Penetration Area, Elevation 100'. 4.14.3 Establish communications betwe.en the ops'ator(s) in the Penetration Area (s) and Panel 213. 4.14.4 Take local-manual control, using " Hand Se..' 4" in local control panels in the Penetration Areas, of the Atmospheric Stea_ Relief Valves (MS10 Valves) and slowly increase the steam flow released to the atmosphere. NOTE Manual handwheel operation of the MS10 valves is also available locally at each valve in the Penetration Areas. 4.14.5 Closely monitor Steam Generator pressures at Panel 213. Salem Unit 2 Rev. O
I-4.10 ( A) 4.14.6' Plot, on Operations Log 84, the cooldown rate at least every 30 minutes maintaining the cooldown rate < 100'F/ hour and within the limits of the pres-sure - temperature curve. 4.15 Maintain each Steam Generator's water level at approximately 33% by local narrow range indication (equivalent to % 60% wide range indication) by continuing the operations initiated in 4.2.3 above. 4.16 Maintain if possible, four (4) Reactor Coolant Pumps in service while RCS temperature is between 547'F and 400*F. 4.17 When the Rr~ temperature decreases to, or below 547'F, close, if deemed necessary, the Steam Generator Stop Valves (M5167) by use of test switches provided in local panels in the Penetration Area. NOTE Leaving the MS167 salves open will help maintain Steam Generator Pressures approximetely equal. 4.18 As cooldown progresses, adjust charging flow to gradually increase Pressurizer level to N 70%. NOTE Refer to step 3.3.2 above. 4.18.1 Maintain seal injection flow to the Reactor Coolant Pumps (RCP) as follows:
- 1) Monitor seal injection flow to each RCP locally with flow indicators FI-ll5, FI-ll6, FI-143, and FI-144.
- 2) Using the Charging Header Pressure Control Valve Bypass Valve, 2CV73, care-fully adjust the position to maintain 6 to 13 gpm seal injection flow for each RCP.
Gradually close Charging Header Pressure Control Valve Isolation Valve 2CV70 while maintaining RCP seal injection flow with Valve 2CV73. NOTE 8 gpm is the desired flow to each operating RCP. 4.19 Initiate Pressurizer cooldown and RCS depressurization as follows: 4.19.1 Open Pressurizer Auxiliary Spray Valve 2CV75; refer to item 2 of Table II. CAUTION Pressurizer Spray using 2CV75 must not be used unless Regenerati"4 Heat Exchanger outlet temperature as t ead on Fluke Digital Thermometer in Unit 2 Relay Room (TE-126) is within 320'F of pressurizer temperature as determined from the saturation curve (Figure 1). \\ ]) )
I-4.10(A) 4.19.2 Closely monitor RCS pressure and temperature at Panel 213. Operate the Pressurizer Heaters and 2CV75 as required to maintain RCS Pressure such that the highest T indication is at least 50*F below the temperature as determined H from Figure 1 (i.e. if T s 500*F, maintain pressure greater than the saturation H pressure for 550*F). 4.20 When the RCS pressure is < 1500 psig, open Reactor Coolant Pump Seal Bypass Valve 2CVll4. To operate 2CV114, refer to item 3 of Table II. 4.21 Utilizing local controls at Panel 213, open additional letdown orifice isolation valves (i.e. 2CV3, 2Cv4 & 2Cv5) as necessary to maintain letdown flow rate. 4.22 When RCS pressure decreases below 1000 psig, manually close 21-24SJ54, Accumulator Outlet Valve. To operate 21-24SJ54, refer to items 25-28 on Table II. 4.23 When RCS temperature has been reduced belov 400*F, remove one (1) RCP from service by manually opening the power supply treaker on the applicable motor control center. 4.23.1 No. 21 RCP breaker is located on the 2H - 4kV Group Bus, Turbine Area, Elevation 100'. 4.23.2 No. 22 RCP breaker is located on the 2E - 4kV Group Bus, Turbine Area, Elevation 100'. 4.23.3 No. 23 RCP breaker is located on the 2F - 4kV Group Bus, Turbine Area, Elevation 100'. 4.23.4 No. 24 RCP breaker is located on the 2G - 4kV Group Bus, Turbine Area, Elevation 100'. 4.24 When the RCS temperature has been reduced below 350'F and RCS pressure is less than 375 psig, place the RHR System in-service as follows: NOTE Operating Instruction OI II-6.3.2, " Initiating Residual Heat Removal", should be used as guidance in conjur.ction with the following specific operations. 4.24.1 Remove blocking tags and close the breaker for 2SJ69 at the 2C West Valves & Miscellaneous Control Center, Auxiliary Building, Elevation 84'. 4.24.2 Establish Component Cooling water flow through the RHR Heat Exchangers by opening 21CC16 and 22CC16, RHR Heat sxchanger CCW Outlet valves as follows:
- 1) To open 21CC16 refer to item 4 of Table II.
- 2) To open 22CC16, refer to item 5 of Table II.
Salem Unit 2 Rev. O
I-4.10(A) 4.24.3 Verify 2SJ69, RHR suction from RWST is open.
- 1) Should 2SJ69 not be open, refer to item 6 of Table II.
4.24.4 Verify 21RH4 and 22RH4, RHR Pump Suction Valves, are open. 4.24.5 Manually open 21RH12 and 22RH12, RHR Heat Exchanger Bypass Isolation Valves. 4.24.6 Manually open 21RH17 and 22RH17, RHR System Letdown Isolation Valves. 4.24.7 Close 21SJ49 and 22SJ49, RHR Discharge to Cold Legs; refer to items 7 and 8, respectively, of Table II. 4.24.8 Close 21RH18 and 22RH18, RHR Heat Exchanger Outlet Valves using the " Hand Senders" installed in Panels 101 and 102. (Increasing pressure from " Hand Senders" closes valves) 4.24.9 Close 2 RH2 0, RHR Heat Exchanger Bypass Valve, using the " Hand Sender" instal ed at Panel 101. (Increasing pressure from " Hand Sender" closes valvt 4.24.10 Verify 21 and 22RH29 are in AUTO per item 11 and 12 of Table II. 4.24.11 Monitor the positien of 21 and 22RH29 per item 11 and 12 of Table II. Start 21 and 22 RHR Pumps per item 3 and 4 of Table IV. Verify 21 and 22RH29 open. CAUTION If 21 and 22RH29 fail to open in AUTO, stop 21 and 22 RHR Pumps per item 3 and 4 of Table IV and open 21 and 22RH29 per item 11 and 12 of Table II. Then restart the RHR Pumps. 4.24.12 After % 10 minutes, notify Chemistry Department personnel to sample the RHR Heat Exchanger outlets for-boron concentration. 4.24.13 If the boron concentration in the RRR System is lower than that in the RCS, borate the RHR System as follows:
- 1) Manually open 2RH21, RHR to RWST Stop Valve.
- 2) Slowly open 2RH20, RHR Heat Exchanger Bypass Valve using the " Hand Sender" installed in Panel 101 and establish % 1200 gpm flow from each RHR Pump as read locally.
31 After t 10 minutes of recirculating RWST water: a) Close 2RH2O using the " Hand sender" installed u Fanel 101. b) Sotify Chemistry Departmenc personnel tc resample the R;iP : a xch Outlets for boron ccncentration. Salem Unit 2 Rev 0
I-4.10(A)
- 4) If the RHR boron concentration is greater than or equal to the RCS boron concentrations a) Manually close 2RH21 b) Proceed to step 4.24.14 below 5)
If the RHR boron concentration is still less than the RCS boron concentra-tion, repeat step 4.24.13-2), 3), 4), and 5). 4.24.14 Open 2RH1 and 2RL2, RHR Common suction valves, as follows:
- 1) To operate 2RH1 rtfer to item 13 of Table II.
- 2) To operate 2RH2, refer to item 14 of Table II.
4.24.15 Close 2SJ69, RHR Suction from RWST; refer to item 6 of Table II. 4.24.16 Establish RHR System letdown to the CVCS as follows:
- 1) Open 2Cv8 using the " Hand Sender" installed in Panel 202.
- 2) Maintain letdown flow approximately equal to charging flow by use of manual valve 2CV20, Low Pressure Letdown Control Valve Bypass Valve and closing 2CVl7, Letdown Pressure Control Valve Isolation Valve.
NOTE The three CVCS Letdown Orifice Isolation Valves 2CV3, 2CV4 and 2CVS should remain open even though letdown is from RHR. This provides additional relieving capacity in case of inadvertent RCS pressurization. 4.24.17 Open 21SJ49 and 22SJ49, RHR Discharge to Cold Legs; refer to items 7 and 8, respectively, of Table II. 4.24.18 Slowly, over a period of approxicately 10 minutes, increase RHR System temp-erature to RCS temperature as follows:
- 1) Slowly open 2RH2O to N 10% open using the " Hand Sender" installed in Panel 101.
4.24.19 After approximately 10 minutes establish the desired RCS cooldown rate as follows: 11 Slowly open 31FH18 and 22RH18 while closing 2RH20, using the " Hand Senders" installed in Panels 101 and 102. 1337 126 Salem Unit 2 Rev. O
D D O WD r,n d [ lJh I-4.10(A)
- 2) If 21RH29 and 22RH29 were opene ! mar : ally in step 4.24.11 (i.e. they failed to open in AUTO).
Close the valves as per item 11 and 12 of Table II. 4.25 When PCS temperature is reduced below 350*F: 4.25.1 Open and rack out the breakers to both Safety Injection Pumps and turn off the DC Contral Pcwer.
- 1) The breaker for No. 21 Safety Injection Pump is located on the 2A-4kV Vital Bus, Auxiliary Building, Elevation 64' -
- 2) The breaker for No. 22 Safety Injection Pump is located on the 2C-4kV Vital Bus, Auxiliary Building, Elevation 64'.
4.25.2 Open and rack out the breaker to one (1) Centrifugal Charging Pump and No. 23 Charging Pump, and turn off the DC Centrol Power. NOTE A minimum of one Centrifugal Chargiaq ? ump must remain operable as a part of an ECOS Subsystem until RCS tempera-ture is below 200*? as required by the Teen Specs, and to maintain RCP seal flow.
- 1) The breaker for No. 21 Charging Pump is located on the 2B-4kV Vital Bus, Auxiliary Building, Elevation 64'.
- 2) The breaker for No. 22 Charging Pump is located on the 2C-4kV Vital Bus, Auxiliary Building, Elevation 64'.
- 3) The breaker for No. 23 Charging Pump is located cn the 2A-460V Vita; Bus, Auxiliary Building, Elevation 84'-
6.25.3 As appropriate, open and rack out the breakers to both rotor-driven Aux 2ita-Teedwater Pumps and turn off the DC "ontrol Power. NOTE If it is necessary or desirable to use the A;xiliary Teed-water Pump (s) to maintain Steam Generator levels, removing the pump (s) from service may be deferred until the pump (s) is no longer required.
- 1) The breaker for Nc. 21 ATW Pump is located on the 2A-4kV Vital Bus. Auxiliary Building, Elevation 64'.
- 2) The breaker for No. 22 A7N Pump is located on the 2B-4kV Vital nu
..' 'G 1 3 / Building, Elevation 64' 4.25.4 Close 2]MF45 and 23MS45, the stea. suppl" valves to Nc. 23 ATS Pump. Selem Unit 2 Re* 3
I-4.10(A) 4.25.5 Reduce the number of running RCP's to two !2) in-se- .ce. NOTE T..!ac to step 4.24 above. 4.26 When the RC3 temperature reaches 312'l (as indicated at Panel 213) reduce RCS pressure to less than 375 psig (as indicated by I T-4 03 and PT-4 05 at Panel 213). 4.26.1 With RCS pressure < 375 psig and RCS temperature is at 312*F, arm the POPS as follows:
- 1) To arm POPS Channel I (A), refer to item 1 of Table III,
- 2) To arm POPS Channel II (B), refer to item 2 of Table III.
4.27 When RCS temperature is reduced below 250*F 4.27.1 Reduce the number of running RCPs to one (1) in-service. NOTE Refer to step
- 4. 23 above.
4.27.2 Fully open 21-24MS10 to facilitate sP.eam generator heat removal. 4.28 When the RCS temperature is reduced below 200'F. 4.28.1 Open and rack out the breakers to both Contrainment Spray Pumps and then turn off the DC Centrol Power.
- 1) The breaker for No. 21 CS Pu::p is located on the 2A-4kV Vital Bus, Auxliary Building, Elevation 64'.
- 2) The t reaker for No. 22 CS Pr.mp is located on the 2C-4hv Vital Bas, Auxiliary Building, Elevatien 64'.
4.29 With the plant in Cold Shutdown (Mode 5) conditions should be maintait.ed with: 4.29.1 One RCP in service. 4.29.2 Pressurizer bubble. 4.29.3 POPE armed. 4.29.4 RHR in-service, Prepared by Carter Nolan Manager - Safem Generating Station Reviewed by J.M. Zupko SORC Meeting No. 33-79 Date 6 j}}[ ]}@ Salem Unit 2 Rev. O
I i I-4.10(A) LOCAL CONTROL STATIONS PANEL 213 NO. 2 UNIT HOT SHUTDOWN STATION [ AUXILIARY BUILDING, ELEV. 84'] o. 21.22.23624 Steam Gen. Pressure Indication Pressurizer Level Indication o. 21622 Component Cooling Flow Indication Component CoolinR Surge Tank Level A&B Indication ervice Water No. 21&22 Header Treasure Indication 21-25 Cont. Fan Coil Unit Star./Stop Switch o. 21.22623 Contrul Area Supply ran Start /Stop Switcn 21.22&23 Ccmp. Cool Pump Start /Stop Switch o. 21-26 Service Water Pump Start /Stop Switch Letdn Orifice Isol. V 2CV3.4&5 Open/Close Switch o. 21622 Boric Acid Transfer Pump Start /Stop Switch No. 21&22 Charging Pump Start /Stop Switch o. 21.22.23&?4 9 team Cen. Level Indication No. 2 Emerg. Air Compressor Start /Stop Switch ess ;te_ Indication - RCS & Pressarizer RCS Wide Ranee Terperature Indication PANEL 205 NO. 2 UNIT NO. 21 AUXILIARY FEEDWATER PUMP PANEL [ AUXILIARY BUILDING, ELEV. 84'] o. 21 Aux. Feed Pump Ftart/Stop Switch 21 Aux. Feed Pump Discharge Pressure Indication 1 Aux. Feed Pump Suction Pressure Indication 23&24AF21 Press Override Toegle Switch PANEL 206 NO. 2 UNIT NO. 22 AUXILIARY FEEDWATER PUMP PANEL [ AUXILIARY BUILDING, ELEV. 84'] o. 22 Aux. Feed Pump Start /Stop Switch 22 Aux. Feed Pump Discharge Pressure Indication 2 Aux. Fe ed Pump Suction Pressure Indication 21&22AF21 Press Override Toggle Switch PANEL 207 NO. 2 UNIT NO. 23 AUXILIARY FEEMATER PUMP PANEL [ AUXILIARY BUILDING, ELEV. 84'] o. 23 Aux. Feed Pump Start /Stop Switch No. 23 Aux. Feed Pump Incr/ Deer Switch o. 23 Aux. Feed Pump Sturt/Stop Switch 23 Aux. Feed Pump Steam Pressure Indication 3 Aux. teed Pump Discharge Pressure 7tdication 23 Aux. Feed Pum Suction Pressure Indication P. 216 NO. 21-22-23 CHARGING PUMP FLOW & PPESSURE PANEL [ AUXILIARY BUILDING, ELEV. 84'] o. 21.22&23 Charging Pumps Tiow Indication ! No. 21622 Charging p apiPressure Jndication o. 21622 Chg Pmps Flow to Regen " eat Exch Indication olume Control Tank Level Indication dCVS5 auto / Manual selector) 2CV35 Marual Hand-Air Regulator Control PANEL NO. 2 GP AND NO. 2 EP PRESSURIZER HEATERS [ ELECTRICAL PENETRATION AREA, ELEV. 78'] ressurizer Heater On/Off Switch Pressurizer Hester Breakers PANEL 379 No. 2 UNIT AUXILIARY F1EDWATER STORAGE TANK PANEL [OUTSIDE AUXILIARY BUILDING W., ELEV. 100'] uxiliary Feedwater Tank Level Indication Aux. Feed Pump Suction Pressure Indication PINEL 687 2A,B,C&D MAIN STEAM STOP VALVE MS167 LOCAL CONT STA [N & S PENETRATION AREA, ELEV. 100'] S167 Close/Open/Byyass Valve open/ Test Selector Swite PANEL 684-2A,B.C&O NO. 2 UNIT STM GEN PRESS CONTROL PANEL [N & S PENETRATION AREA, ELEV. 100'] S10 Local / Remote Selector MS10 Manual Hand-Air Regulator Control ROD DRIVE MG SET CONTROL PANEL [ AUXILIARY BUILDING, ELEV. 84'] eactor Trip Breaker A&B Reactnr Irip Bypass Bry ker A&B AG-A-STAT REGULATOR POWER UNIT [ TURBINE AREA, ELEV. 120;]_ enerator Exciter Field Breaker l -- ~ TABLE I 1337 129 alem Unit 2 Rev. O
I-4.10(A) TABLE II VALVE OPERATIONS INSTRUCTIONS (See Figures No's 2 and 3 for TP and RC Layouts) VALVE STATUS CETERMINATION In the column marked STATUS, terminal points are entered wbAch correspond to the position (OPEN, CLOSE) or mode of operation (AUTO, MANUAL) pf the valve. Presence of the specified voltage between these points and common is indicative of the status of the valve. VALVE OPERATION Cperation of valves will be accomplished at the blue ribbon connectors in the Relay Cabinets (RC). The col;rn marked OPERATION has terminal points entered which correspond to the desired operation of the valve. To operate a valve or change the operating mode of a valve, momentarily
- umper between the +28VDC source in th. Relay Cabinet and the designated pin on the blue ribbon connecter. Remove the jumper and verify valve status as discussed above er locally at the valve.
NOTE Insulated jumpers are provided in the cabinet near Panel 213 for use in jumpering PINS en the Blue Ribbon connectors en the Relay Cabinets. Saler Unit 2 i Rev 3
I-4.10(A) VALVE OPERATIONS ^ OPERATION JUMPER METER ITEM +2BVDC BLUE RIBBON RESULT OF COMMON POINT OF NO. VALVE SOURCE CONNECTOR OS PATION f-) urneporveym VorTacp ecurv_m r 1 2CV243 RC 22-7 RC22-7 11-1-11 - -1 NA NA NA 218848 PIN 23 CPE!; RC22-7 7-3-13 PIN 21 CLOSE 2 2CV75 RC22-7 RC22-7 TP22-2 TP22-2 125VDC 218865 11-1-7 7-4-1 OPEN 4-3-B 4-3-C PIN 23 RC22-7 TP22-2 7-4-1 CLOSE 4-3-D PIN 21 125tTC 3 2CVll4 RC24-7 RC24-7 TP24-2 211562 11-1-5 7-3-4 OPEN TP24-2 4-2-F 125VDC PIN 7 4-2-B RC24-7 TP24-2 7-3-4 CLOSE 4-2-H 125VDC PIN 5 4 21CC16 RC21-3 RC21-3 TP21-1 211529 11-1-1, 3-4-10 OPEN TP21-1 2-4-E PIN 7 2-4-B ll5VAC RC21-3 TP21-1 3-4-10 CLOSE 2-4-F PIN 5 115VAC 5 22CC16 RC22-3 RC22-3 TP22-1 11-1-19 3-4-10 OPEN 2-4-E ll5VAC 211530 PIN 7 TP22-1 RC22-3 2-4-B TP22-1 ll5VAC 3-4-10 CuoSE 2-4-F PIN 5 6 2SJ69 RC23-4 RC23-4 TP23-2 TP23-1 11-1-17 4-9-10 OPEN 2-4-R 4-4-E 125VDC 211508 PIN ' (NOTE: Common RC23-4 in adjacec.t TP23-1 125VDC 4-9-10 CLOSE TP) 4-4-F PIN 5 7 21SJ49 RC21-4 RC21-4 TP21-1 11-1-15 4-6-1 OPEN TP21-2 4-2-E 125VDC 211509 PIN 7 5-3-B 211510 IIC'W4 (NME: Connon TP21-1 125VDC 4-6-1 CLOSE in adjacent 4-2-F PIN 5 TP) B 22SJ49 RC22-4 RC22-4 TP22-1 11-1-15 4-6-1 OPEN TP22-2 4-2-E 125VDC 211511 PIN 7 2-4-R 211512 RC22-4 (NOTE: Common TP22-1 4-6-1 CLOSE in adjacent 4-2-F 125tTC PIN 5 TP) 9 21 RH19 RC21-4 RC21-4 "P21-1 11-1-15 4-7-13 OPEN TP21-1 ,-2-X ll5VAC 211509 PIN 7 4-2-Z 211510 RC21-4 TP21-1 4-7-13 CLOSE 4-2-Y 115VAC PIN 5 / I Salem t) nit 2 TABLE II Rev. 0 I-4.10(A) VALVE OPERATIONS OPERATION STATUS JUMPER METER ITEM +28VDC BLUE RIBBON RESULT OF COMMON POINT OF NO. VALVE SOURCE CONNECTOR OPERATION (-) MEASUREMENT VOLTAGE SCHEMATIC 10 22RH19 RC22-4 RC22-4 TP22-1 11-1-15 4-6-7 OPEN TP22-1 4-2-X 115VAC 211511 PIN 7 4-2-2 211512 RC22-4 TP22-1 4-6-7 CLOSE 4-2-Y ll5VAC PIN 5 11 21RH29 RC21-4 RC21-4 TP21-1 11-1-21 4-9-7 OPEN TP21-1 4-5-E 115VAC 211555 PIN 23 4-5-B RC21-4 TP21-1 4-9-8 CLOSE 4-5-F 115VAC PIN 7 RC21-4 RC21-4 4-9-4 AUTO 4-9-4 28VDC PIN 7 RC21-4 PIN 8 RC21-4 11-1-22 RC21-4 4-9-4 MANUAL 4-9-4 28VDC PIN 5 PIN 10 12 22RH29 FC22-4 RC22-4 TP22-1 211556 11-1-19 4-9-7 OPEN 4-5-E 115VAC PIN 23 TP22-1 RC22-4 4-5-B TP22-1 4-9-8 CLOSE 4-5-F ll5VAC PIN 7 RC22-4 RC22-4 4-9-4 AUTO 4-9-4 28VDC PIN 7 RC22-4 PIN 8 RC22-4 11-1-20 RC22-4 4-9-4 MANUAL 4-9-4 28vDC PIN 5 PIN 10 13 2RH1 RC22-4 RC22-4 TP22-1 11-1-13 4-6-10 OPEN 4-1-U ll5VAC 211506 PIN 23 TP22-1 211507 RC22-4 4-1-R TP22-1 4-6-10 CLOSE 4-1-V ll5VAC PIN 7 14 2RH2 RC21-4 RC21-4 TP21-1 211504 11-1-13 4-4-13 OPEN 4-1-U ll5VAC 211505 PIN 23 TP21-1 RC21-4 4-1-R TP21-1 4-4-13 CLOSE 4-1-V ll5VAC PIN 7 15 2SS107 RC24-7 RC24-7 TP24-2 220923 11-1-3 7-2-4 OPEN 4-1-H 125VDC PIN 7 TP24-2 NOTE 1 RC24-7 4-1-B TP24-2 7-2-5 CLOSE 4-1-J 125VDC PIN 7 16 2SS49 RC25-7 RC25-7 TP25-2 220924 11-1-7 7-7-4 OPEN 5-1-H 125VDC PIN 7 TP25-2 NOTE 1 RC25-7 5-1-B TP25-2 7-7-5 CLOSE 5-1-J 125VDC PIN 7 17 2SS104 RC24-7 RC24-7 TP24-2 220923 11-1-3 7-2-7 OPEN 4-1-L 125VDC ~ PIN 7 TP24-2 NOTE 1 RC24-7 4-1-B TP24-2 7-2-8 CLOSE 4-1-M 125VDC PIN 7 1337 1'52 TABLE II Salem Unit 2
I-4.10(A) VALVE OPERATIONS OPERATION STATUS JUMPER 4 R y ATEM +28VDC BLUE RIBBON RESULT OF COMMON POINT OF NO. VALVE SOURCE CONNECTOR OPERATION (-) MEASUREMENT VOLTAGE SCHEMATIC 18 2SS33 RC25-7 RC25-7 TP25-2 220924 i 11-1-7 7-7-7 OPEN 5-1-L 125VDC PIN 7 TP25-2 NOTE 1 RC25-7 5-1-B TP25-2 7-7-8 CLOSE 5-1-M 125VDC i PIN 7 j 19 2PRI RC24-6 RC24-6 TP24-2 224082 l 11-1-15 6-8-1 ^ PEN 3-3-D 125VDC f PIN 7 TP24-2 224083 RC24-6 3-3-E TP24-2 6-9-2 CLOSE 3-3-E 125VDC PIN 7 i RC24-6 RC24-6 I 6-8-1 AUTO 6-8-1 28VDC l PIN 23 RC24-6 PIN 24 RC24-6 11-1-16 RC24-6 6-8-1 MANUAL 6-8-1 28VDC PIN 21 PIN 26 20 2PR6 RC24-6 RC24-6 TP24-2 11-1-15 6-8-7 OPEN 3-3-V ll5VAC 224082 PIN 23 TP24-2 224083 RC24-6 3-3-X TP24-2 6-8-7 CLOSE 3-3-W 115VAC PIN 21 21 2PR2 RC25-6 RC25-6 TP25-2 11-1-15 6-8-1 OPEN 3-3-D 125VDC 224084 l PIN 7 TP25-2 224085 I RC25-6 3-3-B TP25-2 6-8-2 CLOSE 3-3-E 125VDC PIN 7 RC25-6 RC25-6 6-8-1 AUTO 6-8-1 28VDC PIN 23 RC25-6 PIN 24 RC25-6 11-1-16 RC25-6 6-8-1 MANUAL 6-8-1 28VDC PIN 21 PIN 26 22 2PR7 RC25-6 RC25-6 TP25-2 224084 11-1-15 6-8-7 OPEN 3-3-V ll5VAC PIN 23 TP25-2 224085 RC25-6 3-3-X TP25-2 6-8-7 CLOSE 3-3-W ll5VAC PIN 21 23 2PR47 TP24-2 224082 NA NA OPEN TP24-2 3-4-K 125VDC 224083 3-3-B CLOSE TP24-2 3-4-L 125VDC 24 2PR48 TP25-2 224084 NA NA OPEN TP25-2 3-4-W 125VDC 3-3-B 224085 TP25-2 CLOSE 3-4-X 125VDC 25 21SJ54 RC21-6 RC21-6 TP21-2 211668 11-7-2 6-6-1 OPEN 3-1-F 125VDC PIN 7 TP21-2 211669 RC21-6 3-3-B TP21-2 6-6-2 CLOSE 3-1-H l?5VDC PIN 7 f TABLE II Salem Unit 2 Rev. O
I-4.10(A) VALVE OPERATION OPERATION STATUS U R METER afEM +29VDC BLUE RIBBON RESULT OF COMMON POINT OF NO. VALVE SOURCE CONNECTOR OPERATION (-) MEASUREMENT VOLTAGE SCHEMATIC 26 22SJ54 RC22-6 RC22-6 TP22-2 211672 11-1-13 6-6-1 OPEN 3-1-F 125VDC PI5 7 TP22-2 211673 RC22-6 2-5-B TP22-2 6-6-2 CLOSE 3-1-H 125VDC PIN 7 I 27 23SJ54 RC23-5 RC23-5 TP23-1 217126 11-1-9 5-5-1 OPEN 5-4-F 125VDC PIN 7 TP23-1 217127 RC23-5 5-5-B TP23-1 5-5-2 CLOSE 5-4-H 125VDC PIN 7 28 24SJ54 RC22-5 RC22-5 TP22-2 217130 11-1-11 5-7-1 OPEN 1-1-F 125VDC PIN 7 ,TP22-2 217131 RC22-5 1-3-B TP22-2 5-7-2 CLOSE l-1-H 125VDC PIN 7 29 2CV35 RC22-7 RC22-7 FLOW TO RC22-7 211584 11-1-15 7-7-1 VCT RC22-7 7-7-1 28VDC PIN 7 AUTO 11-1-16 PIN 9 211585 RC22-7 FLOW TO TP22-2 7-7-1 VCT 5-2-C 123VDC PIN 3 MANUAL TP22-2 RC22-7 FLOW TO 5-2-B TP22-2 7-7-4 HUT 5-2-D 125VDC PIN 23 FANUAL I 0 2CVlB5 RC21-7 RC21-7 TP21-2 211598 11-1-13 7-3-1 OPEN 5-2-C d25VDC PIN 23 TP21-2 211599 RC21-7 5-2-B TP21-2 7-3-1 CLOSE 5-2-D 125VDC PIN 21 RC21-7 RC21-7 7-3-4 AUTO 7-3-4 28vDC PIN 7 RC21-7 PIN 8 RC21-7 11-1-14 RC21-7 7-3-4 FANUAL 7-3-4 28VDC PIN 5 PIN 10
- NOTE 1: Voltage will pickup as soon as valve leaves closed position (OVC limit switch).
1337 134 TABLE II Calem Unit 2 Rev. O
I-4.10(A) POPS INITIATION OPERATION STATUS JUMPER ME'ER ATEM +28VDC BLUE RIBBON RESULT OF COMMON POINT OF NO. CHANNEL SOURCE CONNECTOR OPERATION (-) MEASUREMENT VOLTAGE SCHEMATIC 1 I RC24-6 RC24-6 TP24-2 244082 11-1-15 6-8-13 ON 3-4-Y 125VDC PIN 7 (ARMED) TP24-2 244083 RC24-6 3-3-B 6-8-14 OFF NA NA PIN 1 2 II RC25-6 RC25-6 TP25-2 244084 11-1-15 6-8-13 ON 3-4-Y 125VDC PIN 7 (ARMED) TP25-2 244085 RC25-6 3-3-B 6-8-14 OFF NA NA PIN 1 NOTE: Operation and status for POPS initiation are performed in a similar manner to valve operations. See instructions at the beginning of Table II for operation and status determination using these tables. 4 1337 135 TABLE III Salem Unit 2 Rev. O
I-4.10(A) PUMP OPERATION OPERATION STATUS JUMPER METER y y AIEM +28VDC BLUE RIBBON RESULT OF COMMON POINT OF NO. PUMP SOURCE CONNECTOR DPERATION 4-) MEASUREMENT VOLTAGE SCHEMATIC 1 No. 21 RC21-7 RC21-7 218870 PRIM. WTR 11-1-9 7-5-1 START VERIFY LOCALLY AT PUMP MAKEUP PUMP PIN 23 218871 RC21-7 7-5-2 STOP PIN 7 RC21-7 RC21-7 7-5-4 AUTO 7-5-4 28vDC PIN 7 RC21-7 PIN 8 RC21-7 11-1-10 RC21-7 7-5-4 MANUAL 7-5-4 28vDC PIN 5 PIN 10 2 NO. 22 RC23-7 RC23-7 218872 PRIM. WTR 11-1-9 7-5-1 START VERIFY LOCALLY AT PUMP MAKEUP PUMP PIN 23 218873 RC23-7 7-5-2 STOP PIN 7 RC23-7 RC23-7 7-5-4 AUTO 7-5-4 28VDC PIN 7 RC23-7 PIN 8 RC23-7 11-1-10 RC23-7 7-5-4 MANUAL 7-5-4 28VDC PIN 5 PIN 10 3 NO. 21 RC21-4 RC21-4 211500 RHR PUMP 11-1-11 4-8-1 START VERIFY AT PUMP BREAKER PIN 23 211501 RC21-4 4-8-2 STOP PIN 7 4 NO. 22 RC22-4 RC22-4 211502 RHR PUMP 11-1-11 4-8-1 START VERIFY AT PUMP BREAKER PIN 23 211503 RC22-4 4-8-2 STOP PIN 7 NOTE: Operation and status for pump operations are performed in a similar manner to valve operations. See instructions at the beginning of Table II for operation and status determinations using these tables. TABLE IV Salem Unit 2 Rev. O
I-4.10(At OPERATING STATIONS Maintaining Hot Standby STATION PRIMARY FUNCTION 1. Panel 213 Overall control and monitoring. 2. Auxiliary Feed Pumps Maintain Steam Generator levels. (Panels 205,206,and 207) 3. Panel 216 Maintain pressurizer level; monitor charging flow and VCT level. 4. Pressurizer Heater Control Panels Maintain plant pressure (Electrical Penetration Area, El. 78') 5. North and/or South Penetration Area at Maintain plant temperature MS10 valves local control stations (El. 100') 6. Rover a. Shift suction for Auxiliary Feedwater Pumps. b. Add water to Auxiliary Feedwater Storage Tanks. c. Trip main feed pumps. d. Place main turbine on turning gear. e. Verify electrical breaker positions and transfers. Hot Star.,y to Cold Shutdown (Mode 5) (The following stations are in addition to stations for Hot Standby with the exception of the Rover) 1. Panel 314 at Boric Acid Pumps (Elev. Boration and makeup control of 2CV172 and 100', Aux. Bldg) 2CV179 2. Unit #2 Relay Room (El. 100', Aux. Bldg) a. Operate valves and pumps through Relay Cabinets. b. Monitor Regenerative Heat Exchanger out-let temperature. c. Operate Train "A" and "B" output relays. 3. Reactor Coolant Pump Seal Flow Monitor seal flow to RCP's and adjust as Indicators (El. 78' piping Penetration necessary. Area). 1337 137 TABLE V Salem Unit 2 Rev. O
I-4.10(A) Hot Standby to Cold Shutdown (Mode 5) STATION PRIMARY FUNCTION 4. Panel 101 and 102 (El. 45' Aux. Bldg) Operate 2RH20, 21RH18 and 22RH18. 5. Low Pressure Letdown Control Valve Maintain letdown flow using Low Pressure 2CV18 (El. 84' Aux. Bldg) Letdown Control Valve Bypass Valve. 6. Rover a. Open RCP breakers b. Close and open electrical breakers as instructed. c. Operate 2CV8. 133J7 138 TABLE V Salem Unit 2 Rev. O
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I-4.10(A) RELAY CABINET J.C ) LAYOUT AND CONNECTOR NUMBERING TERMINALS 1 THRQUG}i 40 POSITIONS 11-1-1 THROUGH 40 (28VDC SOURCE AND COMMON) b b bbb SUPPLY BREAKERS 11 2 3 4 5 6 7 8 9 10 11 1 CABLE CONNECTIONS 17 1 18 2 15 1, 13 12 11 10 9 8 7 6 5 4 3 2 1 2 7 19 3 d 20 4 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 21 5 3 22 6 EXAMPLE: 23 7 7_4 1 1,5 14 13 12 11 10 9 8 7 6 5 4 3 2 1/ 24 8 QLUE RIBBO! CONNECTOR 25 9 ROW 6 10 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1\\ CABINET N 27 11 28 12 PIN 12 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 ~ 29 13 6 30 14 31 15 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 32 16 7 BLUE RISBON 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 CONNECTOR 8 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 9 10 CABLE CONNECTIONS VIEW LOOKING AT BLUE RIBBON CONNECTORS i337 i40 FIGURE NO. 2 Salem Unit 2 Rev. O
I-4.10(A) TERMINAL CABINET (TF) 2AYOUT AND TERMINAL BOARD NUMBIPIN.G CO:.UMN 1 2 3 4 5 A 1 ROW 1-1 1-2 1-3 1-4 1-5 B 2 1 C 3 D 4 E 5 2-1 2-2 2-3 2-4 2-5 y 6 2 H 7 J B ENE: 3-1 3-2 3-3 3-4 3-5 L o 3-5-S -TERMINAL POINT N 12 COLUMN N P 13 4-1 4-2 4-3 4-4 4-5 R 14 4 S 15 (See Note Below) T 16 U 17 5-1 5-2 5-3 5-4 5-5 V 18 5 W 19 X 20 Y 21 VIEW LOOKING AT TERMINAL BOARDS AA 23 BB 24 TERMINAL BOARD NUMBERING NOTE: Letters do not appear on terminal boards. 1337 141 FIGURE NO. 3 Salem Unit 2 Rev. O
.e I-4.11 EMERGENCY INSTRUCTION I-4.11 HIGH REACTOR COOLANT ACTIVITY 1.0 DISCUSSION 1.1 Th!s instruction provides the appropriate action to be taken in the event of high reactor coolant activity. 1.2 The specific activity of the primary coolant shall be limited to 11.0 LCi/ gram DCSE EGJIVALENT I-131 and 1100/E pCi/ gram. These limits apply in modes 1 and 2 and in mode 3 when T,yg 1500'F. 1.3 An increase in the primary coolant activity may be the result of: 1.3.1 Power level change. 1.3.2 Activation of corrosion products. ~ 1.3.3 A crud burst causing evolution such as starting or stopping Reactor Coolant Pumps, chemical shock, thermal shock, rod drops, reactor trips, etc. 1.3.4 Fuel element failure. 1.4 This procedure will normally be used when called out by Emergency Instruction I-4.16, " Radiation Incident", which is ef fective upon the receipt of any RMS Alarm. However, if this procedure is required to be used at any other time, reference should be made te EI I-4.16, " Radiation Incident" in respect to interlocks and other associated alarms and/or instructions. 2.0 SYMPTOMS 2,1 As a result of routine analysis, it is found that DOSE EQUIVALENT I-131 is 1 1.0 aCI/ gram or > 100/E uCi/ gram. 2.2 RMS Channels 1(2)R31A and/or B and/or C (failed fuel monitors) which monitor the letdown line are alarming. 3.0 IM. MEDIATE ACTIONS 3.1 Automatic None 3.2 Manual 1337 142 Nene Saler. Unit 1/ Unit 2 Rev. 3
t I-4.11 4 d 4.0 SUBSECUENT ACTIONS = 4.1 If a RMS Alarm has actuated, refer to the appropriate section of EI.' - 4.16, " Radiation Incident", if not already done. 4.2 Notify the Senior Shift Supervisor / Shift Supervisor. 4.3 The Senior Shift Supervisor shall request Performance Department personnel to draw a reactor coolant sample and analyze for DOSE EQUIVALENT I-131 and gross beta-gamma. CAUTION The Senior Shift Supervisor shall inform Performance Department of the reason for this request and that the personnel taking the sample must take added precautions in surveying the sample lines prior to drawing the sample as high dose rates may be expected if a failed fuel element exists. NOTE The Senior Shift Supervisor may request several reactor coolant samples to be drawn and analyzed for evaluation or Performance Department may be required to draw additional samples as a result of their previous analysis. 4.4 Review the results of the primary coolant sample (s) tnd take the appropriate action IAW Technical Specification 3.4.8, or if these actions are not applicable, go to step 5 below. NOTE If required by step 4 above, take the plant to Hot Standby IAW OI I-3.5, " Minimum Load to Hot Standby". 4.5 If the results of the primary coolant sample (s) do not exceed the limits as outlined in step 4 above, operate with one mixed bed demineralizer and the cation deminerlizer in series. 4.6 If the reactor coolant activity centinues to rise, valve in the standby mixed bed demineralizer and periodically sarple the inlet and the outlet for activity. 4.7 Continue to reduce reactor coolant activity by naximum demineralizer flow and degassing thru the VCT vent IAW OI II-3.3.11, " Volume Control Tank Degassification". 4.8 If the results of the reactor coolant sample (s) indicate the increase in reacter coolant activity was caused by something other than a power level change, the activiation of corrosion products, a failed fuel element, or a " normal" crud burst causing evclution, the cause must be dete1 mined and if possible, corrected and the appropriate actions taken. Prepared by J.V. Bailev / Reviewed by R.J. McCarthy 33[ } f} [) 7N M SOPC '4eeting No. 053-79 Date
I-4.12 ee EMERGENCY INSTRUCTION 4 I-4.12 LOSS OF FEEDWATER 1.0 PURPOSE This instruction describes the Actions required to place the plant in a stable condition following a loss of feedwater. 1.1 Loss of Feedwater may be caused by loss of a : bin Feed Pump, Condensate Pump, or Henter Drain Pump, feedwater line rupture or a malfunction of the Feedwater Control System. 1.2 The primary considerations on a loss of Feed Pump, Heater Drain Pump or Control Valve malfunction are the reduction in steam flow to less than the available feed flow rend the stabilizing of Steam Generator levels in order to avert a Reactor Trip. However, if steam flow is reduced too rapidly, a Reactor Trip will result due to the ensuing shrink in Steam Generator levels. 1.3 A feed line rupture will result in a loss of Feedwater flow to one or more Steam Generators, depending on the location of the break. This will cause a decrease in the water level of the affected Steam Generators and a loss of Heat Transfer cap-abilities, which will result in an increase in Reactor Coolant temperature, Pressurizer level and pressure. The increase in pressure will actuate the Pressurizer sprays and possibly the power operated relief valves. The operator must insure any valves which open as a result of the pressure increase close when the pressure decreases to below their setpoint. In addition, Steam Generator pressure will increase due to the in-crease in Tavg and operation of the Atmospheric Relief Valves anc/or Safety Valves is protable. 1.4 On a feed line rupture, the potential exists for forming a saturated steam void at the reactor vessel outlet or in the RCS Hot Legs. This condition will exist if RCS temperature rises to above the saturation temperature for the existing RCS pressure. Refer to the RCS pressure temperature curve to determine if this condition exists. This instruction provides the actions required to maintain core cooling in the event of void formation. 2.0 INITIAL CONDITIONS 2.1 Steam flow and/or feed flow deviation alarms (F, > F,and/or F,> F,) on one or more Skhy Steam Generators. 2.2 Erratic Steam Generator level indication. h ,4 2.3 Steam Generator level deviation alarms. '2.4 Low Feedwater header pressure. f 2.5 Main Feed Pump trip. f 2.6 Condensate Pump trip. ( 2.7 Heater Drain Pump trip. k
Feed Flow in coincidence vita Low Level, or b) Low-Low Steam Generator Level. 3.2 Manual 3.2.1 Reduce steam flow to a value less than the existing feedwater flow. 3.2.2 Place feedwater control in MANUAL and attempt to stabilize Steam Generator levels. 3.2.3 If a feed line rupture is indicated, proceed as follows: a) Trip both Main Feed Pumps b) Close 11-14 (21-24) BF13 c) Initiate a manual Reactor Trip and refer to EI I-4.3, " Reactor Trip". 4.0 SUBSEQUENT ACTIONS 4.1 If the loss of feedwater is due to a malfunction of the Steam Generator water level Control System, maintain feedwater flow in MANUAL until necessary repairs can be made. 4.2 If the loss of feedwater is due to a Main Feed Pump, Condensate Pump or Heat ain Pump tripping, investigate the cause and restore the pump to service as s practical. 4.3 Monitor Pressurizer pressure and Steam Generator pressure to insure a ny relief valves which opaned automatice.lly, close when the pressure decrea e below the actuating setpoint. 4.4 If void formation in the RCS is indicated or suspected, proc s follows: 4.4.1 Maintain all RCP's in operation to provide forced f' to the core. 1337 145 4.4.2 Reduce Tavg to below the saturation temperat the existing RCS pressure (refer to the RCS pressure-temperature curve) operation of the Atmospheric Stae.r. Relief Valves (MS-101 on the unaffected Steam Generators or by use of thi Steam Dump System in Pressure Control. Salem Unit 1/ Unit 2 -2 Rev. 2 I-?.12 4.4.3 Attempt to increase RCS pressure if it is low by energizing the Pressurizer Heaters and verifying the Power Operated Relief Valves (PRI & 2) and the Spray Valves (PS1 & 3) are closed. Prepared by Manager - Salem Generating Station Reviewed by SORC Meeting No. Date $? ) +% /A(# 1337 146 Salem Unit 1/ Unit 2 Rev. 2 I-4.13 4 Ev.ERGENCY INSTRUCTION I-4.13 LOSS OF CIRCULATING WATER 1.0 DISCUSSION 1.1 Depending on the Unit load and the river water temperature, a circulator can be removed from service to check for a Condenser tube leak, repair a circulatiag Water Pump, or perform maintenance on the traveling screens. With a proper lead decrease, two circulating Water Pumps can be taken out of service. 2.0 SYMPTOMS 2.1 One or more Circulating Water Pumps trip out. 2.2 Condenser vacuum slowly decreasing. 3.0 IM.wEDIATE ACTIONS 3.1 Autenatic 3.1.1 None 3.2 Manual 3.2.1 Peduce load as necessary to maintain vacuum. NOTE If vacuum is lost in the East condenser and the West Condenser, the Condenser Vacuum Permissive is lost and steam dump to the condensers is blocked. In this condition, it will be necessary to use the Atmospheric Steam Relief Valves (MS10) to maintain Steam Generator pressure. 3.2.2 If both Circulating Water Pumps to the same low pressure turbino are lost, closely monitor turbine vibration. If the vibration reaches the alarm point (7 mils) reduce load as necessary to reduce the vibration. If the vibration increases rapidly, manually trip the turbine. (If power is >104, this will result in a reactor trip. Refer to EI I-4.3, " Reactor Trip *, NOTE If both Circulators to a Condenser are lost, steam dump to that Condeaser is blocked. 1337 147 -1_ sev. > 4/24/78 o I-4.13 4.0 SUBSEQUENT AcTrons 4.1 Deter:nine the reason for loss of the Circulating Water Pump (s) and correct er repair as necessary to return to service. Prepared bY D. Jansen Mana ger -f 5Hsi Gen
- rating s%,a SCPC Meeting No.
79 2g <L i 1337 148 2 Rev. 3 4/24/73 I-4.14 EMERGENCY INSTRUCTICN f I-4.14 SERVICE WATER SYSTEM MALFUNCTION 1.0 DISCUSSION 1.1 The purpose of this emergency instruction is to provide guidelines for plant cperation during and subsequent to a malfunction in the Service Water System, either due to a flow decrease or an entire loss of flow. 1.2 Since the Service Water System is an Engineering Safeguards System and is essential to all phases of plant operation, this instruction deals with the necessary course of action to be taken to place the plant in a safe condition in accordance with the Technical Specifications. 1.3 Technical Specification 3.7.4.1 states that in Modes 1,2,3 and 4, "At least two independent service water loops shall be operable." 1.4 Due to the design redundancy of the system, it is not credible to anticipate a complete and total loss of the system. However, failures of a nature to reduce the capability of the system to less than that required for plant operating conditions are considered credible. s t 1.5 The following procedure is divided into four parts to provide separate instructions depending on the cause and location of the Service Water System malfunction. These parts are: Part I Malfunction in or Upstream of a Service Water Say Part II Malfunction in Nucleer Header Part III Malfunction in Turbine Area Header Part IV Malfunction in Downstream Components 2.0 SYMPTOMS 2.1 An increase in outlet temperatures of various components cooled by Service Water is indicative of a decrease in flow. High temperature alarms and/or low ficw alarms for individual components are indicated either on the annunciator or the control console. 2.2 Service Water header pressure is decreasing. The SERV WATER HEADER 11 or 12 (21 or 22) LOW UtESS alarm may annunciate, and the pump auto-start may occur. 2.3 The SERV WATER PMP 11, 12, 13 (21, 22, 23) ARIA SUMP HIGH LEVEL or SERV WATER PMP 14, 15, 16 (24, 25, 26) ARIA SUMP HIGH LEVEL alarm may annunciate, indicating a pipe leak or rupture in the intake structure. 2.4 Elevated temperatures in the Containment, indicacive of insufficient, or a loss of, Service Water flow to the Containment Fan Cooling units, may be indicated. Rev. 4 ] Jh I-4.14 2.5 Actuation of SERV WATER SCREENWASH 11,12,13(21,22,23) or 14,15,15(24,25,26) er SERV WATER STRAINERS 11,12,13(21,22,23) or 14,15,16(24,25,26) TROUBLE may occur indicating a flow obstruction at these components. 3.0 _I*CtEDIATE ACTION 3.1 Automatic 3.1.1 The Service Water Pump (s) in the AUTO mode will start, if the Service Water header pressure decreases to 90 psig. 3.2 Manual 3.2.1 Start additional Service Water Pumps, as necessary, if the pumps in AUTO f ail to start. 3.2.2 Notify plant pezsonnel of loss, partial loss or impending loss of Service Water. NOTE The Equipment Operator should immediately take action to determine the cause of the Service Water malfunction, correct the problem and report the action taken to the Control Room, as soon as possible. 3.2.3 If Service Water to the Turbine - Generator Auxiliaries is Icst, TRIP the Unit. Refer to EI I-4.3, "Raactor Trip". 4.0 SUBSEQUENT ACTIONS 4.1 Proceed as necessary to verify that all safeguards equipment can be supplied with adequate Service Water flow. If necessary, non-vital loads supplied from Service Water should be removed from service. 4.2 If a liquid release is in progress, verify that it is being discharged thrcugh a header with adequate dilution flow. PART I I. MALFUNCTICN IN OR UPSTREAM OF A SERVICE WATra BAY I-4.3 If it is determined that the cause of the loss of or dropping Service Water flow is in or upstream of the Service Water Bay and is indicative of a rupture, perform the following: I-4.3.1 Close 11(21) and 12(22)Swl7 SW Pump Discharge Header Cross Connect Valve. I-4.3.2 Close the affected Nuclear Header Supply Valve 12(22)SW20 or 14(24)SW20. I-4.3.3 Cpen the Nuclear Header Cross Connect valves 11(21)SW23 and 12(22)SW23 to supply Service Water to the affected header's components. b Rev. 4 4/24/78 I-4.14 ,e I-4.3.4 Stop the Service Weter Pumps in the af fected bay. L I-4.3.5 start the third Service Water Pump in the unaffected bay. Closely monitor downstream parameters. I-4.3.6 Close the appropriate TG Header Supply Valve, either ll(21)SW20 or 13 (23) SW20 from the af fected bay to further isolate the bay. I-4.3.7 Inform the appropriate persontel and take corrective action, as necessary, to return the Service water System to a normal lineup IAW OI V-1.3.1, "Se rvic e Water - Normal Operation". I-4.3.8 Return the inoperable Service Water Loop to operable status within the time frame specified in Technical Specification 3.7.4.1 or proceed to Cold Shutdown IAW the following instructions: OI I-3.5, " Minimum Load to Hot Standby" OI I-3.6, " Hot Standby to Cold Shutdown" PART II II. MALFUNCTION IN NUCLEAR HEADER ff II-4.4 If it is determined that the cause of the loss or dropping Service Water flow is in U one of the Nuclear Headers, perform the following: II-4.4.1 Close the af fected Nuclear Header Supply Valve 11(21) or 12(22)SW20 or 14(24)SW20. II-4.4.2 Close the affected Nuclear Eeader Isolation Valve 11(21) or 12 (22) $W22. II-4.4.3 Open Nuclear Header Cross Ccnnect Valves ll(21)SW23 and 12(22)SW23 to supply Service Water to the affected header's components. II-4.4.4 Closely monitor the downstream component's parameters. II-4.4.5 Inform the apprepriate personnel and take corrective action, as necessary, to return the Service Water System to a nornal lineup IAW OI V-1.3.1, " Service Water - Normal Operation". II-4.4.6 Return the inoparable Service Water Loop to operable status within the time frame specifi 1 in Technical Specification 3.7.4.1 tc proceed to Cold Shutdown IAW the following instructions: OI I-3.5, " Minimum Load to act Standby
- OI I-3.6,
" Hot Standby to Cold Shutdown" h }I Rev. 4 4/24/78 I-4.14 PART III 6 III. PALTtlNCTION IN TURBINE AREA READER III-4.5 If it is determined that the cause of the loss or droppin-Service Water fi:w is in the Turbine Area Header, perform the following: III-4.5.1 Close the TG Header Supply Valvta 11(21)SW20 and 13(23)SW20. III-4.5.2 Close 1(2)SW26 TG Header Isolation Valve. III-4.5.3 Trip the plant and refer to Emergency Instruction EI I-4.3, " Reactor Trip", since Service Water to the Turbine - Generator Auxiliaries has been Icst. III-4.5.4 Stop the following pumps : 11,12,13(21,22,23) Condensate Pumps 11,12,13(21,22,23) Heater Drain Pumps 11,12(21,22) Bleed steam coil Drain Tank Pumps III-4.5.5 If the Unit No.1 TG Header is lost, verify the cooling water supply for the Station Air Compressors has shifted from Service Water to Fresh Water. If Fresh Water flow is inadequate, proceed as follows: IR
- 1) Open IST21 and 2ST21 Station Air Compressor Supply Cross Connect valves.
V NOTE opening these two valves will immediately supply Service hater to the Station Air Cocpressors fren Unit No. 2 discharging from Unit No. 1.
- 2) Open IST13 and 2ST13 Station Air Compressor outlet Cross Connect vsives.
- 3) Close IST14 Station Air Compressor Outlet Throttle Valve.
rote Service water to the Station Air Compressors will now be supplied frem and returned to Unit No. 2. III-4.5.6 Inform the appropriate personnel and take ccrrective action, as necessary, to return the Service Water System to a normal lineup IAW CI V-1.3.1, " Service Water - Normal Operation". III-/.5.7 If Service Water to the Turbine - Generator Auxiliaries cannot be restored, maintain the plant in Hot Standby conditions IAW OI I-3.5, ' Minimum Load to Hot Standby". h. III-4.5.8 &/ when Service Water is restored, take the plant to Power Operation IAW the following instruction: OI I-3.3, " Hot Standby to Minimus Load
- OI I-3.4, " Power Operation" 9
1)747 'lR)b 4/24/79 Rev. 4 s J ,4, I-4.14 PART IV f k IV. MAI.rtmC"'IO'I IN COWNSTREAM COMPONE! prs IV-4.6 If it is determined that the cause of a 1 css er dropping Service Water flew is in a downstream component, either in the components supplied from the Nuclear Hea *ers or the Turbine Header, perform the following: IV-4.6.1 If Service Water is lost to a component by either a raptura or blockage, isolate the affected component and perform the following:
- 1) If Service t;ater te a Turbine - Generator Auxiliary has been lost, trip the plant and refer to II Ir4.3, " Reactor Trip".
Maintain Hot Stindby IAW OI I-3.5, " Minimum Load to Hot Standby".
- 2) If Service Watse to a component supplied from a Nuclear He& der has been lost, refer to that cceponent'r appropriate Technical Specificaticn, as applicable.
IV-4.6.2 If Service Water to a co:aponent is lost due to a control valve =alfuncticn, take manual control of the affected valve and perform the following:
- 1) If the malfunctioning valve is to a Turbine - Generator Auxiliary, maintain manual control attempting to maintain rormal system parameters and, if necessary, reduce power to keep parameters within specifications. If parameters cannot be maintained, trip the plant and refer to EI I-4.3,
" Reactor Trip". 2) If the malfunctioning valve is to a component supplied from a Nuclear Header, refer to that component's appropriate Technical Specification, a2 applicable. IV-4.6.3 Inform the appropriate personnel and take corrective action, as necessary, to return the Service Water System to a normal lineep IAW OI V-1.3.1, ".tervice Water - Normal Operation". TV-4.6.4 When Service Water is restored to a normal lineup &nd, if the plant has been tripped, take the plant to Powar Operation IAW the following instructions: OI I-3.4, " Hot Standby to Minimum Load" OI I-3.5, " Power Operation" Prepared by__ R. Hallmark / m a-, Manager - Jalem Genbrating Sta:1cn SCRC Meeting No. 78-26 1337 133 Ray. 4 4/24/78 ~...., 'e I-4.15 'l EKERGENCY INSTRUCTION I-4.15 LOSS OF COMPONENT C^OLING 1.0 DISCUSSION 1.1 This instruction ptovides guidellres for plant operation during and follcwing a failure in the Compocent Cooling System, either due to a loss of flow, a pipe rupture, or inleakage from anotbar system. 1.2 Since the Component Cooling System is an engineered safeguards system and is essential to all phases of plant operation, this instruction deals with the necessary course of action to be taken to place the plant in a safe conditien IAW Technical Specification 3.7.3.1, which states "Two Independent Component Cooling Loops shall be operable in Modes 1,2,3 and 4". 1.3 This instruction will deal with two types of Component Ccoling System malfunettons, and is presented in two separate parts in the subsequent actions: PART 1 LOSS OF COMPONENT COOLING DUT TO LOSS OF FLOW (loss or pumps, pipe rupturo, or flow blockage). PAFT II INLEAKAGE TO THE COMPONENT COOLING SYSTEM (from components which it supplies). 2.0 SYMPTCMS 2.1 The following would be indicative of out-leakage from tae Component Cooling System: 2.1.1 Decreasing CCW Header pressure. 2. .2 Increasing pump amps un the running CCW pumps. 2.1.3 Decreasing Component cooling Surga Tank level. 2.1.4 Increasing Containment Sump level. 2.2 Ine: easing temperatutes on components supplied CCW is indicative of a decrease in flow due to a ficw obstruction, fouling of heat exchanger tubes, rupture upstream of the coxponent, or a loss of pumps. 2.3 The foilowing would be indicative of inleakage to the LCW System: 2.3.1 Increasing activity level on either header. 2.3.2 Increasing Componet Cooling Surge Tank level. 3.0 IKiEDIATE ACTIONS 3.1 Autoratic 3.1.1 The CW Surce Tank Vent /1'xe 1f210C149. will : lese en nach activit'; en either RMS Channel R17A or R17B. Salem Unit 1/Cr. i t 2 Rev. 3 5 I41 ay n cure Se nt nda le. edu sib r s s po to ift a 1 quick y nd sh l a st aa lo akage been le s of ha source ing ol co le. the nt sib nt ne s r o po f po mpo.e al e m quick y n (abn orm l ay,i c Co ch he r t ecess to as io Ng lab le vita is le ak t ai he of cvitat a n t io av of ake p io io ca u n ns 'k 4f h' ic olat at If m at is indic l [] g r). m e uto o [ b' r nk, s essu fo a ndato y. Pu psrge pr no r Ta m rge CCW ma cha Su Trip".
- ing, in sible ning dis rg ute.
Cha run nd s r a cto min ish a ing all a ps w: Re m s I 4 3, " in e l r lo fiv nito pa p fol "Estab le m mo ab s in h ed a EI wit oper y ns Pu ps I 331, io oce in in to uat m ated, pr I the ied r efe nt OI rn cif Pu ps.nd r ola W etu spe he m t c ame IAW CCW a Co IA r,r r r wn lo ". l cto cto do F w s wn al fr do de rea Re let a im Shut e n a Stop he io he t ur nd ct rds he Col t d fo a rging Inje afegu Trip all a t hin to al wit ed ) Stop cha Se s oce nt cure nd the le ola c) ab r pr Co w,a of r Se n e ope o do on r d) Let on
- to3731, cto a
was op Re ndby" lo the ak ing ion le ol t Sta wn to fcia he co w s do n: Hot hut nd fo t l If nt ci io ne Spe ct to S d a o po al str Lo 3) u ad Col m r ade c chnic in um to he Trip" s. Te wing inim ndby rds nd r ute a lo M Sta a I 3 5, "' Hot sfegu fol s cto min ing w: a lo Re e rg ns fol I 4 3, "in fiv cha al no
- I36, OI as ecure Se he ed h
t nd oce EI wit OI on nge, s wn, a Pu ps ed, pr was to r m r do ak efe nt chaing, Let le p r the stop nd ola Ex or a Co at 45 m r r He rg Ci Syste. If was cto cto wn Cha Pu ps Re do ing 1(2)C 4) m rea a r ur Let ish ning ed Wate he t fo the l Trip all to
- Estab ope aliz a) top ted by er al min I 331, S
ola I norm De b) is or was to m w OI el Syste flo IAW v le lo ". nk Wate If r w wn do F Ta 5) let io rge n ay ct Su Prim ifa r a y, t r nen Inje ate ecess CCW s "Co po he NS chr I m om fn he t t om rn fr C146 fo ded.I 7.31, r Retu 6) 1(2)C a pled d I a io ". m was n OI n Addit s r be ate IAW uld w io ci of at mic sho nt ntr Che amou m syste nt conce nd ate Make p Up ISS a The fic a u om signi chr em i, 4.2 II. INLEAl: AGE TO THE COMPONENT COOLING SYSTEM NOTE Attempts to isolate inleakage should proceed one component at a time with sufficient time betweeq steps to allow the Component Cooling System to stabilize. Each componsnt should be retuzned to its original condition, if it is determined not to be the f aulted component. 4.2.1 If the component Cooling Surge Tank level is increasing with no increase in activity on either Pl7A, or 17B, proceed as follows:
- 1) Verify 1(2)CC145 and 1(2)CC146 are closed.
- 2) C:.ose 1(2)DR10
- 3) Close 1(2)WR14
- 4) Isolite No. 11(21) Component Cooling Heat Exchanger as follows:
a) Verify 1(2)CC30 and 1(2)CC31 are open. b) Close ll(21)CC6 and ll(21)CC6.
- 5) Isolate No. 12(22) Component Cooling Heat Exchanger as follows:
a) Verify 1(2)CC30 and 1(2)CC31 are open. b) Close 12(22)CC6 and 12(22)CC8. 4.2.2 If the Component Cooling Surge Tank level is increasing with an accompanying increase in activity levels on either R17A or 17B, proceed as follows:
- 1) When the Hi Alarm setpoint is reached on either R17A or R17B, verify 1(2)CCl49 Surge Tank Vent is closed.
2) Isolate No. 11 Residual Heat Exchanger as follows: a) Close 11 ( 21) RH14, 11 ( 21 } RH17, ll ( 21) RH18 b) Stop No. 11(21) RHR Pump CAUTION Ensure either No. 12(22) RHR Pump or at least one Reactor Coolant Pump is running. c) Close ll(21)CCll and ll(21)CC16 3) Iselate No. 12(22) Residual Heat Exchanger as follows: a) Close 12(22)RHle, 12(22)RH17, 12 (22 ) RH1 B b) Stop No. 12(22) RHR Pump. Salem Cnit 1/ Unit 2 Rev. 3 9 I-4.16 EMERGENCY INSTRUCTION I-4.16 RADIATION INCIOENT 1.0 DISCUSSION 1,1 This emergency instruction provides the guidelines for the actions to be taken in the event of a radiation incident. A radiation incident is defined as any abnormal condition involving higher than normal radiation levels and the spread of discharge of radioactive centaminants (liquids, solids or gases). It is impos=ible to preplan fer every conceivable incident that could occur. It will be necessary to evaluate each incident on an individual basis. When making the decision as to what actions should be taken, keep in mind the followine areas of concern: 1.1.1 Confine the spread of contamination. 1.1.2 Minimize personnel exposure to radiation. 1.2 The instruction is divided into three parts: I Area Radiation Monitors II Process Radiation Monitors III Process Filter Radiation Monitors I. AREA RADIATION MONITORS I-2.0 SYMPTOMS I-2.1 RMS AREA HIGH RADIATION (Unit 1) or RMS TROUBLE (Unit 2) Annunciator Alarm. I-2.2 Indication and/or alarm of high radiation on the following remote (including Unit 2 CRT) and/or local monitors: CHANNEL PURPOSE 1(2) -RlA Control Room 1(2)-R2 Containment R3 Radio-Chemistry Laboratory 1(21-R4 Charging Pump Room 1 ( 2 ) -R5 Fuel Handling Building R6A Sampling Room 1(2)-R7 In-Core Seal Table R8 Waste Load Out lL2)-R9 Fuel Storage Are.- 1 ( 2 ) -R10 A Personnel Hatch u. 100' Cont. 1 ( 21 -R10B Equipment Hatch El. 130' Cont. R20B Counting Room 1(2 -R21 Cont ainme nt Post Accident R22 Solid Waste Area 3 alan Lnit 1 and 2 Rev. 5 I-4.16 R23 Monitoring Ruom (Local Only) 1(21-R32A Fuel dandling Crane (Local only) 1(2)-R23B Cask Handling Crane (Local Only) 1.22-R34 Mechanical Penetration Area El. 100' 2-R42A 21 Gas Decay Tank 2-R42B 22 Cas Decay Tank 2-R42C 23 Gas Decay Tank 2-R423 24 Cas Decay Tank I-3.0 IMMEDIATE ACTIONS j ' (3) b I-3.1 Automatic I-3.1.1 Interlock associated with the alarming channel, as delineated in Table I, actuates. I-3.2 Manual I-3.2.1 Verify,1f possible, that the interlock associated with the alarming channel, as delineated in Table I, has actuated; if not actuated, manually perform the action required to satisfy the inter 10ch. I-3.2.2 Ferform a check on the alarm channel. The check should include:
- 1) Setpoint verification
- 2) Channel check with the check source.
I-3.2.3 Monitor affected system (s) paraneters, air monitors, and other radiation monitors to determine the cause and the extent of the high radiation condition. Request radiation protection personnel to take samples and/or sulveys if possible. I-3.2.4 If the alarm is found to be invalid due to a faulty channel, inform the Performance Department and refer to Technical Specification 3.1.3.1. I-3. 2*. S If the alarm is found to be valid, announce over the FA System, .t least twice, the receipt of the RMS alarm and the affected area (s) and netafy the Senier Shift Superviscr/ Shift Superviscr. I-3.2.6 Implemen* Emergency Procedure EP I-3 on valid alarms from RMS Channel RS or R9. DO NCT perform the following Subsecuent Acticns. I-4.0 StBSIOUENT ACTIONS I-4.1 Dispatch radiation protection personnel to the affected area (s) to investigate the cause of the high radiation condition and /or to conduct an initial surve;.
- -4.2 The radiation protection personnel shall, if pessible, report the source and/cr ragnitude of the radiation problem to the Senior Shift Superviscr/ Shift Sunerviser and make recomnendations concerning the seriousness of tne problem.
If condittens permit, the radiation protection personnel should atte.pt te isolate and 'cr contain the radiation. 5112m knit. and 2 Rev. v j [ I-4.3 The Senaer Shift Superviscr/ Shift Supervisor shall evaluate survey results. plant condittans and any recommendations from the radiation protection personnel and determine if the radiation problem is excessive and controllable and as necessary: I-4.3.1 Refer to the appropriate Emergency Instruction listed in Table I and: I-4.3.2 Place the Emergency Plan Procedure EP I-3 or EP I-4 into effect as appropriate or: I-4.3.3 Will Not place the Emergency Plan into effect, if not warranted, but will inform the Technical Supervisor of any abnormal conditions and take corrective actions as necessary to control the problem.
- -4.4 wnen possible, and if required, decontaminate the affected area, make the necessary repairs, corrections, etc., and return system (s) to normal IAW AP-24, Radiation Safety Program.
Q P ECES3 EADIATION MCM: TORS II-2.1 RMS PROCESS HIGH RADIATION (Un16 1) or R"E TROUBLE (Unli 2) Annm.410tez Alarm. II-2.2 Indication and/or alarm of high radiation on the following remote (including Unit 2 CRT) and/or local process monitors: CHANNEL PURPOSE 1(2)-RlB Control Room Intake Duct R6B Primary Sampling Room Particulate (Local Only) 1-RllA Containment or Vent Air Particulate 1-R12A , Containment or Vent Gas Effluent 1-R12B Containment or Vent Gas Effluent (Iodine) 2-RllA Containment Sampling Particulate 2-R12A Containment Sampling Noble Gas 2-R12B Containtnent Sampling Iodine 1(2)-R13A No. 11(21) Fan Coil Unit Cooling Water if2)-R13B No. 12(22&24) Fan Coil Unit Cooling Water 1(2)-R13C No. 13(23&25) Fan Coil Unit Cooling Water 1-R13D No. 14 Fan Coil Unit Cooling Water 1-R13E No. 15 Fan Coil Unit Cooling Water 1-R14 Waste Gas Effluent 1(21-R15 Condenser Air Ejector 1(2)-R16 Plant Vent Effluent 1(2)-E17A Component Cooling Liquid 1(21-R17B Component Cooling Liquid 1(2)-Rl8 Liquid Waste Disposal 1(21-R19A No. 11(21) SG Blowdown 1(21-R19B No. 12(22) SG Blowdown 1(2)-R19C No. 13(23) SG Blowdown 1(2)-R19D No. 14(24) SG Blowdown R20A Chemis.ry Laboratory Particulate (Local onlyl 1(21-R31 Letdown Line railed Fuel 1 7 159 a"' Salem Unit 1 and 2. -3.16 It2s-R35 SG BAowdown F12ter Lisen rge 1(2)-R36 Evap. and Feedwater Preheater Condensatt 2-R41A Plant Vent Sampling Particulate 2-R41B Plant Vent Sam;.lin: Iodine 2-R41C Plant Vent Sampling i;oble Gas II-3.0 IMME0! ATE ACTION II-3.1 Automatic II-3.1.1 Interlock associated with the alarming channel, as delineated in Tahle II, actuates. II-3.2 Manual II-3.2.1 Verify, if possible, that the interlock associated with the clarming channel, as delineated in Table II, has actuated; if not actuated, manually perform the actions required te satisfy the interlock. II-3.2.2 Perforn a check on the alarming channel. The check should include:
- 1) Setpoint verification.
- 2) Channel check uith the check source.
NOTT Channel 1(2)RlB and 1(2)R31 do not have installed check sources. II-3.2.3 Monitor affected system (s) parameters, air monitors and other radiation monitors to determine the cause and the magnitude of the high radiation condition. Request radiation crotection personnel to take samples and/or surveys, if possible. II-3.2.4 If the alarm is found to be invalid due to a faulty channel, inform the Performance Department and refer to Technical Specification 3.3.3.1. II-3.2.5 If the alarm is found to be valid, announce over the PA System, at least twice, the receipt of the alarm and the af f ected area (s) and/or system (s) and notify the Senior Shif t Supervisor'/Shif t Supervisor. II-3.2.6 Implement Emergency Procedure EP I-4 on valid alarms from RMS Channels 1(2)RilA, 1(2)R12A, 1(2)R12B, 2R41A, 2R41B, or 2341C. DO NOT perform the following Subsecuent Actions. 9 1. Saltm Unit 1 and 2 4_ e, -A - l3'3'/ \\6U "*v- I-4.16 II-4.0 SUBSEQUENT ACTIONS II-4.1 Dispatch radiation protection persennel to the affected area (s) to investigate the cause of the high radiation conditien and/cr to conduct an initial survey. II-4.2 The radiation protection personnel shall, if possible, re po rt the source and/or magnitude of the radiation problem to the Senior Shift Supervisor / Shift Supervisor and make recommendations concerning the seriousness of the problem. If conditions permit, the radiation protection personnel should attempt to isolate and/or contain the radiation. II-4.3 Tae Senior Shift Supervisor / Shift Supervisor shall evaluate survey results, plant conditions and reconrendations from the radiation protection personnel and determine if the radiation problem is excessive and controllable and, as necessary: II-4.3.1 Refer to the appropriate Emergency Instruction listed in Table II and; II-4.3.2 Place the Emergency Plan Procedure EP I-3 or EP I-4 into effect as appropriate or; II-4.3.3 Will Not place the Emergency Plan into effect if not warranted but will inform the Technical Supervisor of any abnormal conditiens and take corrective actions as necessary to control the problem. r. I II-4.4 When possible, and if required, decontaminate the affected area, make the necessary repairs, corrections, etc., and return system (s) to normal IAW AP-24, Radiation Safety Program. III. PROCESS FILTER RADIATION MONITORS III-2.0 SYMPTOMS III-2.1 RMS PROCESS FILTER HIGH RAD (Unit 1) or R"S TROUBLE (Unit 2) Annunciator Alarm. III-2.2 Indication and/or alarn of high radiation on the following rer.ote (including Unit 2 CRT) and/cr local process filter monitors: CHANNEL P"RPOSE li2;-R24A Seal Water In;ection Filter 1 ( 2 ) -R2 4B Seal Water Injection Filter 1(2)-R25 Seal Water Filter 1 ( 2 ) -R2 6 Reactor Coolant Filter 1(2) -R27 Liquid Waste Filter 1 (2 ) -R2 8 Spent Fuel Pit Filter 1(22 -R29 Spent Fuel F;t rf.;r er Filter . i 2 ) -R10 .Lefue;;ng xater ?;rificat;cn.':;ter .'2'-P2; I:- D::ha r;+ T. : n 1(2)-R28 Stean Generator Blowcown Fitter 1(2)-R40 Condensate 711tcr Salem Unit 1 and 2, Rev. 5 o I-4.16 III-3.0 IvyIDI ATE ACTIONS III-3.1 Autematic III-3.1.1 None III-3.2 Manual III-3.2.1 Perform a check on the alarming chanrel. The check should include:
- 1) Setpoint verification.
- 2) Channel check with the check scurce.
III-3.2.2 If the alarm is found to be invalid due to a faulty channel, inform the Performance Department and refer to Technical Specification 3.3.3.1. III-3.3.3 If the alarm is found to be valid, announce over the PA System, at least twice, the receipt of the RMS alarm and the affected area (s) and/or system (s) and notify the Senior Shift Supervisor / Shift Supervisor. III-4.0 SUBSEQUENT ACTIONS III-4.1 Dispatch radiation protection personnel to the affected area (s) to conduct a survey. III-4.2 The radiation protection personnel shall report survey results to the Senior Shift Supervisor / Shift Supervisor. NOTE Actuaticn of an RMS process filter channel alarm cculd be indicative of a spent filter and, if verified as such, the appropriate personnel should be informed. III-4.3 The Senior Shift Superviscr/ Shift Supervisor shall evaluate the situation and, if necessary, refer to the appropriate Emergency Instructicn listed in Table III. II", Prepared by__ R. Hallmark // Manager g Sal Generating Statien Reviewed by__ F. C._;Schnarr SORC Meeting No. 23-79 Date 4/5/79 Salem UnAt 1 and 2 1337 162 - s 3 09*0 I-4.16 C w m ARIA RADIATION MONITORS EMERCENCY INSTRUCTIONS (Reference) e CHANNEL NAMI INTERLOCK
- 1. Control Room Ventilation Isolation EP-I-3 Plant (Unit) Emergency 1(2)RIA CONTROL ROOM EI-I-4.4 Loss of Reactor Coolant 1(2)1l2 CONTAINMENT
- 1. None El-I-4.ll High Reactor Coolant Activity EI-I-4.17 Partial Loss of Reactor Coolant EI-I-4.20 Failure of RCP 13 RADIO-CHE'IISTRY IAB
- 1. None EI-1-4.4 Loss of Reactor Coolant 1(2)R4 CHARGING PUMP ROOM
- 1. None EI-I-4.ll High Reactor Coolant Activity EI-I-4.17 Partial Loss of Reactor Coolant 1(2)R5 TUEL HANDLING BUILDING
- 1. Tuel Handling Area Hi-Rad Alarm EI-I-2.8.1 Fuel Handling Incident
- 2. FHB exhaust shifts to HEPA Charcoal Filt EP-I-J Plant (Unit) Emergency R6A SAMPLING ROOM
- 1. None EI-I-4.4 Loss of Reactor Coolant 1(2)R7 15-CORE SEAL TABLE
- 1. None EI-1-4.11 High Reactor Coolant Activity EI-I-4.17 Partial Loss of Reactor Coolant Rf WASTE LOAD OUT
- 1. None 1(2)R9 ITEL STORACE AREA
- 1. Fuel Handling Area Hi-Rad Alarm EI-I-2.8.1 Tuel Handli Incident
- 2. THB exhaust shif ts to HEPA Charcoal Filt. EP-I-3 Plant (Unit) Emergency
.l(2)R10A PERSONNEL MATCN TO CONT.
- 1. None 1(2)R105 EQUIPMENT HATCH TO CONT.
- 1. None RI0B COUNTING ROOM
- 1. None EI-I-4.4 Loss of Reactor Coolant CCNTAINMENT EL. 130'
- l. None f,_( 2) R21 EI-1-4.ll High Reactor Coolant Activity (North Axis)
EI-I-4.17 Partial Loss of Reactor Coolant R22 SOLID WASTE AREA
- 1. None R23 MONITCRING ROOM
- 1. None h 2 RJ2A'TUEL HANDLING CRANE
- 1. Energizes crane yellow varning light EI-I-2.8.1 Fuel Handling Incident
- 2. Prevents hoist-tp operation of crane il2)RZ3lCASKHANDLINGCRANE
- 1. Energizes crane yellow varning light EI-I-2.8.1 Fuel Handling Incident
- 2. Prevents hoist-up operation of crane j
El-1-4.4 Loss of Reactor Coolant f12)R34 lMECHANICALPENETRATION1. None EI-I-4.ll High Reactor Coolant Activity El-I-4.17 Partial Loss of Reactor Coolant a k i I iEI-I-4.ll High Reacter Coolant Activitc i
- 1. None 2?4:A 21 OAs OE:Al TA!:r.
EI-I-4.11 Migh Feacter Occiar.: Activitv
- 1. None
.M 3 22 OAs OE AY TA::g EI~I"4*li H19^ I'* tOf I l'EI ^ #I1" lI'# .I* NO"' 2542 ':3 OAS OECAY TANK !!-I-4.11 H:gn 3eacter Coolant Activat? ' I NW
- -4:0
{C4 OAS OECAY TAMr f d/$7 1 7 TABLE I l ) Fe" 5 Salem Unit ; ar.d 2 Page 1 of I e 1-4.16 PROCESS RADIATION MONITORS CHANNEL NAME INTERLOCK EMEPCENCY INSTRUCTION (Reference) !1.ControlRoomVentilationIsolation 1(2) RIB CONTROL ROOM INTAKE DUCT R6B SAMPLE ROOM PARTICULATE
- 1. None 1EllA CONTAlhMENT OR VENT AIR
- 1. Containment Ventilation Isolation EI-I-4.4 Loss of Reactor Coolant PARTICULATE El-I-4.ll High Reactor Coolant Activity a
as ta r nt 2R11A CONTAINMENT SAMPLING a ure d RO No. 1 Seal PARTICULATE EP-t-4 Site (Station) Emergency 111:A CONTAIhMENT OR VENT CAS
- 1. Containment Ventilation Isolation EI-1-4.4 Loss of Reactor Coolant EFFLUENT EI-I-4.11 High Reactor Coolant Activity El-I-4.17 Partial Loss of Reactor Coolant 2R12A CONTAINMENT SAMPLING EI-I-4.20 Failure of RCP No. 1 Seal NOBLE GAS EP-1-4 Site (Station) Emergency 1R128 CONTAINefENT OR VENT CAS
- 1. Containment Ventilation Isolation El-I-4.4 Loss of Reactor Coolant EFFLUENT ( IODINE)
EI-I-4.11 High Reactor Coolant Activity EI-I-4.17 Fertial Loss of Reactor Coolant 2R12B CONTAINMENT SAMPLING EI-I-4.20 Failure of RCP No. 1 Seal IODINE EP-I-4 Site (Station) Emergency 1(2)R13A NO.11(21) FAN COIL UNIT
- 1. None El-I-4.4 Loss of Reactor Coolant EI-I-4.11 High Reactor Coolant Activity EI-1-4.17 Partial Loss of Reactor Coolan:
1(2)R13B NO. 12 (22 & 24) FAN COIL l'NI" 1. None EI-I-4.4 Loss of Reactor Coolant EI-I-4.ll High Reactor Coolant Activity C EI-I-4.17 Partial Loss of Reactor Coolant 1(2)R13C No.13(23 &W FAN COIL (JNI1 1. None EI-1-4.4 Loss of Reactor Coolant EI-I-4.ll High Reactor Coolant Activity El-I-4.17 Partial Loss of Reactor Coolant IF133 NO. 14 FAN COIL IJNIT
- 1. None EI-I-4.4 Loss of Reactor Coolant EI-1-4.11 High Reactor Coolant Activity EI-I-4.17 Partial Loss of Reactor Coolant IF13E NO.15 FAN COIL l' NIT
- 1. None EI-I-4.4 Loss of Reactor Coolant EI-I-4.ll High Reactor Coolant Activity EI-I-4.17 Partial Loss of Reactor Coolant 1R14 WASTE CAS EFFLUENT
- 1. Trips Caseous Waste Discharge EP-I-4 Site (Station) Emergency Valve IWG41 1(2)R15 CONDENSER AIR EJECTOR
- 1. None EI-I-4.7 Steam Generator Tube Leak 1(2)R16 PLANT VENT EFFLUENT
- 1. None EI-I-4.4 Loss of Reactor Coolant EI-I-4.17 Partial Loss of Reactor Coolant EI-I-4.20 Failure of RCP EP-I-4 Site (Station) Emergency 1(2)R17A COMPONENT COOLING LIQUID
- 1. Trips Component Cooling Surge Tank EI-I-4.15 Loss of Component Cooling Vent Valve 1(2)CC149 1(2)R17B COMPONENT COOLING LIQUID
- 1. Trips Component Cooling Surge Tank EI-1-4.15 Loss of Component Cooling Vent Yalve 1(2)CC149
[ 1(2)R18 LIQUID WASTE DISPOSAL
- 1. Trips Liquid Waste Disposal Discharge EP-I-4 Site (Station) Emergency W
Valve 1(2)WL51 1337 164 TABLE II Salem Unit 1 and 2 Page 1 of 2 pey, 5 e 1-4.16 Il0 CESS _KADIATION MONITORS CHANNEL NAME INTERLOCK EMERCENCY INSTRUCTION Oeference) 1(2)R19A NO. 11(21) STEAM CEN.
- 1. Trips S/C BD Isol. Valves 11.12.13 & 14 El-1-4.7 Steam Generator Iude Leak BLOWDOWN (21.22.23 & 24)CB4 on a IllCH alarm.
- 2. Trips No. 12(22) 5/C BD Tank Valves 11, 12.13 & 14(21.22.23 & 24)CB10 &
1(2)CB50 on a VARNING Alarw. 1(2)R198 NO. 12(22) STEAM CEN.
- 1. Trips S/C BD Isol. Valves 11.12.13 & 14 El-1-4.7 Steam Generator Tube Leak BLOWDOWN (21.22.23 & 24)CB4 on a HICH alarm.
- 2. Trips No. 12(22) S/C BD Tank Valves 11.
12.13 & 14(21.22.23 & 24)GBlD & 1(2)CB50 on a WARNING Alarm 1(2)R19C No.13(23) STEAM CEN.
- 1. Trips S/C BD Isol. Valves 11.12.13 !. 14 EI-I-4.7 Steam Generator Tube Leak BLOWDOWN (21.22.23 & 24)CB4 on a HIGH alarm.
- 2. Trips No.12(22) S/C BD Tank Valves 11.
12.13 & 14(21.22.23 & 24)CB10 & 1(2)CB50 on a WARNING Alarm. 1(2)R19D NO. 14(24) STEAM CEN.
- 1. Trips S/C BD isol. Valves 11.12.13 & 14 LI-I-4.7 Steam Generator Tube Leak BLOVDOWN (21.22.23 & 24)GB4 on a HICH alarm.
- 2. Trips No.12(22) S/C BD Tank Valves 11 12.13 & 14(21.22.23 & 24)CB10 &
1(2)CB50 on a WAPNINC Alarm. R20A CHDi LAB PARTICL'IATE
- 1. None 1(2)R31 LETDOWN LINE FAILED TUEL
- 1. None EI-I-4.ll High Reactor Coolant Activity 1(2)R35 SC BLOWDOWN FILTER
- 1. Shif ts 3-vay valves 1(2)GB74 and EI-I-4.7 Steam Generator Tube Leak DISCHARGE 1(2)CB112 to discharge to the Waste Monitor Holdup Tanks.
1(2)R36 EVAP & FEEDWATER PRE-
- 1. Trips Heating Steam Condensate Return HEATER CONDENSATE Valves 1(2)RS49,1(2)MS293 & SV 1055.
2R41A PIANT VENT SAMFLING
- 1. Containment Ventilation Isolation gg
,4 gp PAR M M EI-I-4.11 High Reacter Coolant Activity EI-I-4.17 Partial-Loss of Reactor Coolant E?-I-4.20 Failure of RCP No. 1 Seal 2R41B PLANT VENT fAMPLING ICDINE
- 1. Containment Ventilation Isolation EP-1-4 Site (Station) Emergency EI-I-4.4 Loss of Reactor Coolant EI-1-4.ll High Reactor Coolant Activity EI-I-4.17 Partial-toss of Reacter Coolant E!-I-4.20 Failure of PCf No. 1 Seal M
PLANT VENT SAMPLING
- 1. Containrent Ventilation Isolation EP-I-4 Site (Station) Emargency
- 2. Trips Gaseous Waste Discharge Valve EI-I-4.ll High Reactor Coolant Activity i
2C41 EI-I-4.17 Partial-Mas of Reactor Coolant EI-I-4.20 Failure of RCP No. 1 Seal i 1337 165 TABLE II Rev. 5 Salem Unit I and 2 p,g, 3 og 2 e I-4.16 h PROCES' TILTER RADIATION MONITORS CRiNNEL N A.V.E INTERLOCK EMIRGENCY INETP'JCTION (Reference) 1(2)R24A SEAL WATER INJECTION TILTER
- 1. None EI I-4.11 High Reactor Coolant Activity 1(2)R24B SEAL WATER INJECTION TILTER
- 1. None El 1-4.11 High Reactor Coolant Activity 1(2) R25 SEAL WATER FILTER
- 1. None EI I-4.11 High Reactor Coolant Activity 1(2)R26 REACTOR COOLANT T11TER
- 1. None El 1-4.11 High Reactor Coolant Activity 1(2)R27 LIQUID WASTE TILTER
- 1. None El I-4.11 High Reactor Coolant Activity 1(2nR23 SPENT Ft'EL PIT TILTER
- 1. None 1(2)R29 SPENT TUEL PIT SKIMMER
- 1. None TILTER 1(2)R33 RETUELING WATER PURITICA-TION TILTER 1(2)R33 ION EXCHANGE TILTER
- 1. None EI I-4.11 High Reactor Coolant Activity 1 I)P33 STEE: GENE RATCR
- 1. None 81 I-4.7 Steam Generator Tube Leak BLOWDGd FILTER 1.:lR4D CONEENSATE FILTER
- 1. None EI I-4.7 Steam Generator Tube Leak f)
TABLE III Salem Unit 1 end 2 Page 1 of 1 3 e t'. 3 1-4.17
- UCTION t
y I-I - 4. ' '. PARTW LOSS OF REACTOR COOLANT 1.0 PUAPOSE This instruction describes the actions required to evaluate the magnitude of a partial loss of Reactor Coolant and the steps to be taken to locate and isolate the source. 1.1 A partial loss of reactor coolant is defined as coolant water escaping from a small break in the Reactor Coolar.t System at a leakage rate which can be compensated.. for by the available charging flow. 1.2 During this emergency conditon, system pressure should be maintained above saturation and Pressurizer level is maintained by operating the Charging Pumps. 2.0 INITIAL CONDITIONS 2.1 Increasing charging flow to maintain programmed Pressurizer level. 2.2 Increasing containment temperature, pressure and humidity 2.3 Increasing condensate drainage frem Containment Fan Coolers. 2.4 Increasing Containment Sump level. 2.5 Increasing radiation levels on one or more containment radiation monitorc. 3.0 IMMEDIATE ACTIONS 3.1 Automatic 3.1.1 None. 3.2 Manual 3.',1 None 4.0 SUBSEQUENT ACTIONS 4.1 If the Pressurizer level is uJereasing slowly, start additional Q ging Pumps to restore and maintait level. If Pressurizer level and Press 'e ntinue to dec. ease, manually initiate Safety Injection by inserting'th into Train "A" and/or Train "B" Operate bezel and turning the key, o EI I-4.4, " Loss of Coolant." g a 1337 167 %*p Salem Unit 1/ Unit 2 Rev. 3 - --.~.. I-4.1'l 4.3 Attempt to locate and isolate the source of leakage. Check the following: 4.3.1 Pressurizer Relief Valve and Safety Valves discharge temperatures. 4.3.2 Pressurizer Relief Tank level, temperature and pressure. 4.3.3 Reactor Coolant Drain Tank level. 4.3.4 CVCS Holdup Tank Levels. 4.4 If the leakage rate exceeds those specified in Technical Specification 3.4.6.2 and cannot be returned to within limits in the time frame specified, proceed to Cold Shutdown IAW the following instructions: 4.4.1 OI I-3.5, " Minimum Load to Hot Standby" 4.4.2 OI I-3.6, " Hot Standay to Cold Shutdown" Prepared By Manager - Salem Generating Station Reviewed By SORC Meet.no No. Date
- s e..
r e. T 1337 168 Salem Unit 1/ Unit 2 Rev. 3 9 I-4.18 4. EMERGENCY INSTRUCTION I-4.18 LOSS OF CONTROL AIR 1.0 DISCUSSION ~ 1.1 The Control Air System is normally fed from the Station Air Compressors with backups from both the other unit and from the Emergency Control Air Compressor. The redundant supply makes a complete loss very unlikely however, the resulting loss of control air would require an immediate plant shutdown. 1.2 This instruction is divided into two parts: I Complete Loss of Instrument Air II Partial Loss of Instrument Air I COMTLETE LOSS OF INSTRUMENT AIR I-2.0 SYMPTOMS e I-2.1 Compressor Trouble A' arms I-2.2 Station Header Pressure Low Alarn I-2.3, Control Air Header Pressure Low Alarm I-3.0 IMMEDIATE ACTION I-3.1 Automatic I-3.1.1 Automatic start of the other Statien Air Compressor. I-3.1.2 Automatic start of Emergency Control Air Compressor. I-3.1.3 Diaphragm operated valves actuate to their fail-safe positions. I-3.2 Manual I-3.2.1 Upon receiving the first air pressure low alarm or cempressor treuble alarm, dispatch an operator to locate the problem. I-3.2.2 Attempt to isolate the leak and/or start another compressor. M s to 65 psig, take -he I-3.2.3 If pressure in the instrument air hcader following actions:
- 1) Manually trip the reactor.
- 2) Initiate a cooldown of the RCS while (if) costir} air :s st:11 available.
Salem Unit 1/ Unit 2 -I-Rev 3 1-4.18 I-4.0 SUBSEQUENT ACTION 1-4.1 If all control ai-is lost, maintain S/G 1evels with the Auxiliary Feedwater Pump (s) while hr-,. is removed through the main steam safety valves. I-4.2 Maintain Pressurizer level through intermittent charging with the Reciprocating Charging Pump. 1-4.3 Locate and repair the fault in the Control Air System. Return plant conditions to normal following appropriate operating procedures. PLANT RESPONSES TO A COMPLETE LOSS OF CONTROL AIR 1. Reactor Coolant System a. The following valves fail closed:
- 1) Pressurizer Power Operated Relief Valves PRl and PR2.
- 2) Pressurizer Spray Valves PSl and PS2.
- 3) Pressurizer Relief Tank Spary Valve WRB2.
- 4) Pressurizer Relief Tank Vent Valve PRIS.
- 5) Pressurizer Felief Tank Drain Valve PR14.
b. The following valves fail open:
- 1) Reactor Vessel Head Leakoff Valve RC4.
2. CVCS a. The following valves fail closed:
- 1) The following letdown stop valves: CV277, CV2, CV3, CV4, CV5 & CV7.
- 2) The following excess letdown stop valves: CV278, CV131, & CV132
- 3) Charging Header Pressure Control Valve CV71.
- 4) Concentrated boric acid tank recirculation valves llCV160 & 12C7160.
- 5) Primary makeup water to blender CV179.
- 6) Normal makeup valves CV185 & CV181.
- 7) Steam to BA batch tank heating HS67.
- 8) PMW to RCP seal stand pipe WR62.
- 9) Auxiliary Spray Valve CV75.
- 10) RHR Letdown Valve CV8.
Salem Unit 1/ Unit 2 Rev. 3 I-4.18 b. The following valves fail open:
- 1) Centrifugal Charging Pump Flow Control Valve CV55.
- 2) Charging Line Stop Valves CV77 & CV79.
- 3) RCP Seal Leakoff Stop Valve CV104.
- 4) Letdown Pressure Control Valve CV18.
- 5) Boric acid to blender CV172.
The following 3-way valves fail in the indicated position: c.
- 1) Letdown flow path selector CV21 to VCT.
- 2) Letdown diversion valve CV35 to VCT.
- 3) Deborating demineralizer inlet / bypass CV27 to VCT.
3. Main Steam System a. The following valves fail closed:
- 1) Condenser steam dump valves (MS31, 33, etc.).
- 2) Steam Generator Stop Valve Bypasses (M518).
- 3) Main steam to MSR's (MS67,68,69).
b. The following valves fail open:
- 1) Turbine driven Auxiliary Feed Pump steam supply (MS132).
- 2) Main Steam Stop Valves Trip Valves (MS169, MS171).
NOTE Tripping open of these valves will cause the Main Steam Stop Valves M5167, to trip closed. 4. Feedwater and Condensate Systems a. The following valve fails closed:
- 1) Feedwater Regulating Valves (BF19).
- 2) Feedwater Bypasses (BF40).
b. The following valves fail open:
- 1) Feedwater Heater Bypasses (CN45, CN47, BF38).
- 2) Main Feed Pump Warmup Valves (CN36).
- 3) Main reed Pump Recirc Valves (BF32).
- 4) Condensate Pump Recire Valves (NC8).
II PARTIAL LOSS OF INSTRUMENT AIR 1337 171 Rev. 3 Salem Unit 1/ Unit 2. e. I-4.18 II-2.0 SYMPTOMS Q O II-2.1 Loss of control air pressure in portion (s) of the plant with the Staticn Air Compressor and/Or the Emergency Air Corpressor operating, discharge pressure normal. II-2.2 Less of valve centrols in isolated portions of the plant. II-2.3 Piping failure (sound of escaping air repcrted). II-2.4 A group of air operated valves move to the fail-safe position, without cpcrater action. II-3.0 IMMEDIATE ACTIC';S II-3.1. Autenatic II-3.1.1 Valves supplied by the failed header, that do net have redundant air supplies, actuate to their fail-safe position. II-3.1.2 Associated panels and valves swap to their alternate air supplies (where redundant air supply was provided). II-3.1.3 The failed header's excess ficw check valves closes as indicated hr a loss cf pressure downstrear of the valve. j II-3.2 Manual II-3.2.1 Atterpt to isolate the pipe rupture. II-3.2.2 If rupture is isolable frem the header and the excess flew :he:k valve can be opened and the header repressurized. then preceef as follows to reopen the excess ficw che:% valve.
- 1) Isolate the clcse excess ficw che:P valve frer the pressure source.
- 2) Bleed cff pressure frcr. between the isolation valve and the closed excess flew check valve.
- 3) Slewly open the isolation valve a cuarter turn and'alle,;
pressure in the header to stabali:e (10 cal pressure ind::at;:n:
- 4) Re pea t step II-3.2.2-3) until the isclatica valve is full, cpen er the header pressure reaches 100 pstg.
II-3.2.3 If rupture cannot be isolated and the ah:le header is lost. tne 5en:Or Shift Supervisor, Shift Supervis:r :s to assess the plant conf::::nz and the effect the lest headcr has tn Operat: g :spab:11t, to ;cterrine the course Of action required. ) f f Sale-Unit 1/ Unit 2 R e.- 3 I-4.18 g,,,,, II-4.0 SUBSEQUENT ACTION II-4.1 Locate and repair the rupture. Return plant conditions to normal IAW appropriate Operating Instructions. [ Prepared by J.V. Bailev Manager-SadmGeneratingStation Reviewed by W. Pahl SORC Meeting No. ~ Date /I 1337 173 Salem Unit 1/ Unit 2 Re; ? t. I-4.19 \\e EMERGENCY INSTRUCTION I-4.19 MALFUNCTION-NUCLEAR INSTRUMENTATION 1.0 DISCUSSION 1.1 This procedure provides symptoms, automatic actions, manual actions, and subsequent actions for malfunctions of the Nuclear Instrumentation System. 1.2 Technical Specification 3.3.1.1 states that "As a minimum, the Reactor Trip System Instrumentation Channels and Interlocks of Table 3.3-1 shall be OPERABLE with response times as shown in Table 3.3-2. The mode " Applicability" and " Action" statements are specified in Table 3.3-1. In addition, Technical Specification 3.9.2 delineates the source range instrumentation requirements for refueling operations (Mode 6)". . 1 This instruction is divided into the following parts: I Source Range Malfunction II Audio Count Rate Malfunction III Intermediate Range Malfunction IV Power Range Malfunction V Channel and Detector Current Comparator Malfunction PART I T. SOURCE RANGE MALFUNCTION g I-2.0 SYMPTCMS I-2.1 Erratic or loss of indication I-2.2 Loss of Detector Voltage overhead annunciator alarmed I-2.3 SR High Flux at Shutdown overhead annunciator alarmed I-2.4 SR High Flux Reactor Trip I-2.5 Audio count rate signal stops I-3.0 IMMEDIATE ACTIONS I-3.1 Autoratic I-3.1.1 None I-3.2 Manual I-3.2.1 If a reactor trip occurs, refer to EI I-4.3, "Reacter Trip" Salem Unit 1/ Unit 2 Fev. 4 I-4.19 I-3.2.2 If an overhead annunciator SR HIGd FLUX AT SHUTDN alarm occurs, verify against the other source range channel and other plant parameters that the alarm is invalid. I-4.0 SUBSEQUENT ACTIONS I-4.1 If a channel has failed: I-4.1.1 Turn the LEVEL TRIP selector switch, for that channel, to the BYPASS position and observe that overhead annunciator SR & IR TRIP BYPASS 1/4 is energized. I-4.1.2 Turn the HIGH FLUX AT SHUTDOWN selector, for that channel, to the BLOCK position and observe that the SR HIGH FLUX AT SHUTDN BLOCKED overhead annunciator alarm is energized. I-4.2 Carefully monitor the remaining nuclear instrumentation channels. I-4.3 Select the remaining channel to supply the audio count rate circuit. I-4.4 Inform the Senior Shift Supervisor / Shift Supervisor and take corrective action, as necessary, to return the inoperable source range channel to OPERABLE status IAW Technical Specification 3.3.1.1 and Technical Specification 3.9.2 and return the system to rormal IAW OI IV-6.3.1, " Operation of the Nuclear Instrumentation stem *. I-4.5 Refer to Technical Specification 3.3.1.1, " Reactor Trip System Instrumentation" and Technical Specification 3.9.2, " Refueling Operations Instrumentation". PART II II. AL'DIO COUNT RATE MALFUNCTION II-2.0 SYMPTOMS II-2.1 Loss of audio count rate signal and possible-coincident loss of scaler / timer with the source range channels not blocked. II-3.0 IMMEDIATE ACTIONS II-3.1 Automatic II-3.1.1 None II-3.2 Manual II-3.2.1 IAW Technical Specification 3.9.2, immediately suspend all operations involving core alterations or positive reactivity changes until audio ratehasbeenrestoredintheContainmder 37 C n*d Roo d count g,y, 4 Salem Unit 1/ Unit 2 o. I-4.19 6 II-4.0 SUBSEQUENT ACTIONS II-4.1 If the scaler / timer has stopped operating, select the other source range channel with the CHANNEL SELECTOR switch on the front of the AUDIO COUNT RATE drawer. II-4.2 If the scaler / timer is operating and the audio count rate is being received in the Control Room but not in the Containment, turn the speaker selector switch in the rear of the AUDIO COUNT RATE drawer from NORMAL to Al or A2. This will disable the Control Room speaker and transfer the signal to the Containment speaker. II-4.3 Inform the Senior Shift Supervisor / Shift Supervisor and take corrective action, as necessary, to return the inoperable channel to OPERABLE status IAW Technical Specification 3.3.1.1 and Technical Specification 3.9.2 and return the system to NORMAL IAW OI IV-6.3.1, " Operation of the Nuclear Inrtrumentation System". PART III III INTERMEDIATE RANGE MALFUNCTION III-2.0 SYMPTOMS e III-2.1 Erratic or loss of indication III-2.2 Any of the following alarms which are not substantiated by other instrumentation: III-2.2.1 IR Loss of Detector Volta 9-III-2.2.2 IR No. 1 Loss of Compensate Voltage III-2.2.3 IR No. 2 Loss of Compensate Voltage III-2.2.4 IR High Flux Rod Withdrawal Stop III-2.2.5 IR High Flux Reactor Trip III-3.0 IMMEDIATE ACTIONS III-3.1 Automatic III-3.1.1 None III-3.2 Manual III-3.2.1 If a reactor trip occurs, refer to EI I-4.3, " Reactor Trip". III-4.0 SUBSEQUENT ACTIONS III-4.1 If a channel has failed: III-4.1.1 Turn the LEVEL TRIP selector switch to the BYPASS position and cbserve that the SR & IR TRIP BYPASS 1/4 is energized. Salem Unit 1/ Unit 2 Rev. 4 I-4.19 o NOTE This removes protective bistable functions. III-4.1.2 Partial failure of either channel in the high direction (under compensation) that prevents automatic reactivation of the source range channels during plant shutdown, requires simultaneous operation of both SOURCE RANGE MANUAL RESET pushbuttons. III-4.1.3 Carefully monitor the remaining nuclear instrumentation channels. III-4.1.4 Refer to Technical Specification 3.3.1.1, " Reactor Trip System Instrumentation". III-4.1.5 Inform the Senior Shif t Supervisor /Shif t St'pervisor and take corrective action, as necessary, to return the inoperable intermediate range channel to OPERABLE status IAW Technical Specification 3.3.1.1 and return the system to normal IAW OI IV-6.3.1, " Operation of the Nuclear Instrumentation System". PART IV IV. POWER RANGE MALFUNCTION IV-2.0 SYMTOMS IV-2.1 Erratic or loss of indication IV-2.2 Any of the following alarms which are not substantiated by other instrumentation: IV-2.2.1 PR Loss of Detector Voltage IV-2.2.2 PR High Range High Flux 1/4 IV-2.2.3 PR Low Range High Flux IV-2.2.4 PR Overpower Rod Withdrawal Stop IV-2.2.5 PR Channel Deviation IV-2.2.6 PR High Neutron Flux Rate 1/4 IV-2.2.7 Upper Section Deviation or Auto Defeat IV-2.2.8 Lower Section Deviation or Auto Defeat IV-2.2.9 Axial Flux Difference IV-2.3 Control rod outward motion in AUTO. IV-3 IMMEDIATE ACTIONS IV-3.1 Automatic IV-3.1.1 None. Salem Unit 1/ Unit 2 Rev. 4 e, I-4.19 IV-3.2 Menual IV-3.2.1 If a reactor trip occurs, refer to EI I-4.3, " Reactor Trip". IV-3.2.2 If rods are misaligned, refer to EI I-4.8, " Rod Control System Malfunction". IV-3.2.3 If overhead annunciator PR HIGH RANGE HIGH FLUX (1/4) or PR LOW RANGE HIGH FLUX (1/4) or PR HI NEUTRON FLUX RATE (1/4) alarmed, verify against other nuclear instruments and other plant parameters that the alarm is invalid. IV-4.0 SUBSEQUENT ACTIONS IV-4.1 If a channel has failed: IV-4.1.1 Turn the ROD STOP BYPASS selector on the MISCELLANEOUS CONTROL AND ~ INDICATION PANEL to the position associated with the failed channel. IV-4.1.2 Trip all bistables associated with the failed channel by remosing the control power fuses from the POWER RANGE A drawer and the instrument power from the POWER RANGE B drawer for the failed channel. IV-4.1.3 Turn the COMPARATOR CHANNEL DEF' s7 selector switch located on the COMPARATOR AND RATE drawer to the positic7 associated with the failed channel. IV-4.1.4 Turn the UPPER SECTION and LOWER SECTION selector switch located on the MISCELLANEOUS CONTROL AND INDICATION PANEL to the position associated with the failed channel. IV-4.1.5 Turn the POWER MISHATCH selector switch on the MISCELLANEOUS CONTROL AND INDICATION PANEL to the position associated with the failed channel. IV-4.2 Carefully monitor the remaining nuclear instrumentation channels. IV-4.3 Refer to Technical Epecifiestion 3.3.1.1, " Reactor Trip Instrumentation" and 4.2.4(c), " Quadrant Power Tilt Ratio". IV-4.4 Inform the Senior Shift Supervisor / Shift Supervisor and take corrective action, as necessary, to return the inoperable power range channel to OPERABLE status, IAW Technical Specification 3.3.1.1 and return the system to normal IAW OI IV-6.3.1, " Operation of the Nuclear Instrumentation System." PART V V CHANNEL AND DETECTOR CURRENT COMPARATOR MALFUNCTION V-2.6 SYMPTOMS V-2.1 Any of the following alarms which are not substantiated by othe.- instrumentaticn: Salem Unit 1/'enit 2 Rev. 4 s. I-4.19 V-2.1.1 PR Channel Deviation V-2.1.2 Upper Section Deviation or Auto Defeat V-2.1.3 Lower Section Deviation or Auto Defeat V-3.0 IMMEDIATE ACTIONS V-3.1 Automatic V-3.1.1 None V-3.2 Manual V-3.2.1 If a PR CRANNEL DEVIATION alarm occurs, place the COMPARATOR CHANNEL DEFEAT selector switch on the COMPARATCR AND RATE drawer to the position associated with the failed channel. V-3.2.2 If an UPPER or LOWER SECTION DEVIATION cr AUTO DEFEAT alarm occurs and reactor power is >50%, turn the UPPER and/or LOWER SECTION selector on the MISCELLANEOUS CONTROL AND INDICATION PANEL to the position associated with the failed channel. V-4.0 SUBSEQUENT ACTIONS V-4.1 Carefully monitor the remaining nuclear instrumentation channels. V-4.2 Refer to Technical Specification 3.2.4, " Quadrant Power Tilt hatio". V-4.3 Inform the Senior Shift Supervisor / Shift Supervisor and take corrective action, as necessary, to return the inoperable instrumentation to OPERABLE status IAW Technical Specification 3.2.4, and return the system to normal IAW OI IV-6.3.1, " Operation of the Nuclear Instrumentation System". Prepared by J. Bailey [ C Manager - S[lem Gen'erating Station W. Rahl Reviewed by SORC Meeting No. 050-79 Date [p 7 I337 l79 Salem Unit 1/ Unit 2 Rev. 4 ?! I-4.20 LAERGENCY INSTRUCTION I-4.20 FAILURE OF A REACTOR COOLANT PUMP 1.0 DISCUSSION 1.1 It is not poss..-lc to anticipate every possible trouble with a Reactor Coolant Pump. This procedure gives steps to cope with general classer of failures and identifies their symptoms. These classes of failures are addressed in this instruction in the following parts: Part I Failure of Thermal Barrier Heat Exhanger Part II Hi Vibration Part III Improper Oil Level Part IV Hi Bearing Temperature Part V No. 1 Seal Failure Part VI No. 2 Seal Failure
- }
O yy Part VII No. 3 Seal Failure U Part VIII Multiple Seal Failure CAUTION A Reactor Coolant Pump stopped IAW this procedure shall not be restarted until it has been inspected and determined to be in an operable condition. PART I I. FAILURE OF THERMAL BARRIER HEAT EXCHANGER I-2.0 SYMPTOMS I-2.1 RC Thermal Barrier Discharge Flow Hi Alarm actuates on the Control Console. I-2. ' Automatic Closure of 1(2)CCl31, CCW from RCP Thermal Barrier Isolation Valve. I-2.3 PCP Thermal Barrier Discharge Flow Low Alarm actuates on the Control Console after 1(2)CCl31 RCP Thermal Barrier Isolation.alve automatically closes. I-2.4 11(21) or 12(22)CC Header Hich Activity Alarm on the Control Console may actuate. I-3.0 IMMEDI ATI ACTIONS I-3.1 Automatic I-3.1.1 Auto closure of 1(2)CCl31 RCP Thermal Barrier Isolation Valve } I-3.2 Manual I-3.2.1 Verify auto closure of 1(2)CCl31 RCP Thermal Barrier Isclatien Valve. Salem Unit 1/ Unit 2 Rev. 5 I-4.20 I-3.2.2 Close 1(2)CC190 RCP Thermal Barrier Discharge Valve. 1-3.2.3 Trip all Feactor Coolant Pumps. I-3.2.4 If Reactor Power was > 10%, refer to EI I-4.3, " Reactor Trip". If Reactor Power wan < lot, trip the reactor and refer to EI-I-4.3, " Reactor Trip". I-4.0 SUBSEQUENT ACTIONS I-4.1 Notify Radiation Protection personnel that the Component Cooling Water System has become contaminated. I-4.2 Place the plant in a Cold Shutdown condition IAW OI I-3.6, " Hot Standby to Cold Shutdown". I-4.3 In the event Check Valve 1(2)CCl28 or Isolation valve 1(2)CCl31 should leak by, maintain CCW Surge tank level by draining from the CCW Surge Tank drains to the contaminated floor drain. DO NOT attempt to isolate that portion of the CCW piping. PART II II. HI VIBRATION II-2.0 SYMPTOMS II-2.1 RCP Hi Vibration Annunciator Alarm actuates. II-3.0 IMMEDIATE ACTIONS II-3.1 Automatic II-3.1.1 None II-3.2 Manual II-3.2.1 Determine magnitude of vibration using the RCP vibration monitors on 1(2) RPl II-3.2.2 If vibration is > 4 mils on sne lower motor flange or > 10 mils on the shaft or is increasing rapidly:
- 1) Above P-8; trip reactor, trip the affected RCP.
- 2) Below P-8; trip the affected RCP and reduce power to <P-7 (10% Power).
1337 18i Salem Unit 1/ Unit 2 Rev. 5 I-4.20 II-4.0 SUBSEQUENT ACTION 4 mils on the motor flange or is > 8 mils but II-4.1 If vibration is > 3 mils but < < 10 mils on the shaft, reduce power to less than P-7 (10%) and stop the affected RCP and operate IAW OI II-1.3.3, " Operation with less than four RC Loops in Service". II d.2 If vibration remains at or below 3 mils on the motor flange and below 8 mils on the Pump Shaft, periodically monitor the vibration readings on the affected pump. PART III III. IMPRCPER OIL LEVEL III-2.0 SYMPTOMS III-2.1 RCP Radial Bearing Oil Hi/Lo Level Annunciator Alarm actuates. III-3.0 IMMEDIATE ACTIONS III-3.1 Automatic III-3.1.1 None III-3.2 Manual III-3.2.1 If oil level is accompanied by a high bearing temper ture alarm and/or a high vibration alarm,
- 1) Above P-8; trip reactor, trip affected RCP
- 2) Below P-8; trip affected RCP and reduce reactor power to
<P-7 (10% Power). III-4.0 SUBSEOUENT ACTIOj II-4.1 If oi. level alarm is not accompanied by high bearing temperature or high vib.a+~.. ala rms, immediately: III-4.1.1 Reduce power to below P-7 (10%). III-4.1.2 Remove the RCP from service IAW OI II-1.3.3, " Operation with Less Than Four RC Loops in Service". PART IV IV. HIGH BEARING TEM ERATURE IV-2.0 SYMPTOMS IV-2.1 High RCP Bearing Temperature Alarm. Salem Unit 1/ Unit 2 Rev. 5 s. D** 3 1.: _Cc W =3 e ....3.. ..a...., .....a. a h::h citrat;cn als r IV-3.2.1 If bear:ng temperature Llarm is acecrpanied by and/cr low 0;l lo"c'. alare: 1 AL:.e F-E: trip the reacter, trip the affs:ted T.CF F-d trip the 2fferta 27.1 anf ree; e rei t r
- L..:_...
.....ox ~. I'l-4.1 If high bearing temperature alarm is not accompanied by eitratien er cil level alares, immediately: I'J-4.1.1 Reduce power below P-7 If bearing temperature reaches 185*r f_mrediately trip the affected purp.
- "-4.1..
Per:te affected PCP fr:r service IAU OI !!-1.3.2, "". p er at ; :n ; t '-. Less 'hcn Four RC L0 cps in Service". PART V er.. ......y .e..... n.. _., Een. _eakcff _? L:1 Alarr u. .... x.s 4A. n. Jeter :n.e: er.;tlet Ter- :ncrassin: &c. 5-1. .:ater rics In:reasin: 'J ~. 3 Incre a se d Pure *.'.cra tien "-3.C DJT0! ATE ACTIONS V-3.1 Autoratic f h 'l-3.1.1 !:ene v-3.2 xa r.u a ' I'l-3.2.1 If 3+al Leakoff ficw step increases to 6.C :gr, proceed as f ll:.:s: 11 C3cae the seal Leakof f st:p Val"e f C'J104) for the affects: ;cre. Feduce poaer to 10' arc step in-pump within 1'; heu. 2. Operate I A?. E! !-4.5, P:r: :~, "Less cf FC T10
- t.-e t : Re::t:r Trip", ar.d O' I
-l.3.3. "".peration with _ars Than 7:;r 20 L::Fs ;n Service". Salem Unit 1/ Unit 2 F e *> 5 I-4.20 e V-3.2.2 A gradual increase in seal leakoff flow to 10 gpm is permissible. If flow indication increases above scale, open CV108 (Flowmeter bypass) so that flow changes can be monitored. Seal injection must be maintained greater flow than seal leakoff at all times. Monitor Component Cooling Water ittlet and outlet temperatures to the thermal barrier. V-4.0 SUBSEQUENT ACTIONS V-4.1 Monitor Seal Water injection temperature; if it exceeds 140*F, secure the RCP IAW OI II-1.3.3, " Operation with Loss Than Four RC Loops in Service". PART VI VI. NO. 2 SEAL FAILURE VI-2.0 SYMPTOMS VI-2.1 Standpipe High Level alarm VI-2.2 Seal Leakoff Low Flow Alarm VI-2.3 Decreased Seal Leakoff Flow VI-2.4 Increasing RCDT Level VI_2.5 Increased RCP Vibration VI-3.0 IMMEDIATE ACTIONS VI-3.1 Automatic VI-3.1.1 None VI-3.2 Manual VI-3.2.1 Check Standpipe Supply Valve WR62 to the af2ected RCP closed. VI-4.0 SUBSEQUENT ACTIONS VI-4.1 Perform RCS Leak Rate check, as required by Technical Specification 3.4.6.2, IAW OI II-1.3.5, " Reactor Coolant Leak Detection". PART VII VII. NO. 3 SEAL FAILURE VII-2.0 SYMPTOMS VII-2.1 Standpipe Low Level Alarm VII-2.2 Increased RCP Vibration l Salem Unit 1/ Unit 2 Rev 5 I-4.20 VII-3.0 IMMEDIATE ACTIONS VII-3.1 Automatic VII-3.1.1 None VII-3.2 Manual VII-3.2.1 Refill the standpipe of the affected RCP, utilizing Standpipe Supply Valve WR62. VII-4.0 SUBSEQUENT ACTIONS VII-4.1 Continue to refill the standpipe upon each acutation of the Low Level Alarm. VII-4.2 If unable to clear the Low Level Alarm using the standpipe Supply Valve WR62, reduce power and secure the af fected RCP IAW OI II-1.3.3, " Operation With Less Than Four RC Loops in Service". PART VIII VIII. hULTIPLE SEAL FAILURE VIII-2.0 SYMPTOMS VIII-2.1 Combination of symptoms listed in Parts V, VI and VII above indicating failure of more than one RCP Seal on the same Reactor Coolant Pump. VIII-3.0 IMMEDIATE ACTIONS VIII-3.1 Automatic VIII-1.1.1 None VIII-3.2 Manual VIII-3.2.1 Trip the reactor, trip the affected RCP. VIII-4.0 SUBSECUENT ACTICNS VIII-4.1 Commence an imme6iate plant cooldown at the maximum allowable rate IAW OI I-3.6, " Hot Standby to Cold Shutdown". Prepared by J.V. Bailey / M Manager'- Safem Generating Station Reviewed by J.P. Kovacsofsky 7!/ N SORC Meeting No. 053-79 Date 1337 185 Salem Unit 1/ Unit 2 Rev. 5 i I-4.21 4 EMERGENCY INSTPUCTION I-4.21 JONDENSER TUBE LEAK 1.0 DISCUSSION 1.1 It is very important that Condenser tube leakage is detected early and the plant made ready for shutdown if the leakage is significant. 1.2 The use of All volatile Treatment (AVT) Chemistry provides no protection against serious Steam Generator damage that can result from operation of the plant with a Condenser leak. 1.3 This procedure s divided into two parts: I Small Condeaser Leak II Major Condenser Leak PART I I. SMALL CONDENSER LEAK I-2.0 SYMPTOMS I-2.1 Increased Cation Conductivity reading on either side of any Condenser (six readings). I-2.2 Increased conductivity readings on any of the three Condensate Pump suctions. I-2.3 Increased Cation Conductivity readings on any of the three Condensate Pump discharges. I-2.4 Increased Na readings on any of the thraa Condensate Pump discharges. I-2.5 Increased conductivity reading on 86 Feedwater Heater outlet. I-2.6 Increased conductivity readings on any of the Steam Generator blowdown samples. I-2.7 Decreasing pH in Steam Generator Bloelown. I-3.0 IMMEDIATE ACTION I-3.1 Autematic I-3.1.1 None I-3.2 Manual I-3.2.1 Notify the Performance Department personnel of suspected leak. I-3.2.2 If readings continue increasing, increase Steam Generator blowdown. I-4.0 SUBSECUENT ACTIONS I-4.1 If leak is very sma*l, observe limits and allowed time of operation per Table II ( of Chemistry Instruction PD-3.1.012, " Steam Generator Steam Side Surveillance", (Table attached). }f }}h Salem Uni' I and 2 Rev. 2 _1 t i I-4.21 I-4.2 If the pH of the Steam Generator Blowdown water cannot be maintained >8.0 pH ene Unit will have to be shutdown as soon as possible. o I-4.3 Determine the defective Condenser and which half of it is leaking by comcaring the six Cation Conductivity readings on the condenser Hotwells. 7-4.4 Reduce load, as required, and stop circulating water flow to faulty Condenser half. Drain Condenser half and plug leaking tubes. PART II II. LARGE CONDENSER LEAK II-2.0 SYMPTOMS II-2.1 Very major and rapid changes in Symptoms I-2.1 through I-2.6. II-2.2 Decreasing pH on Steam Generator feedwater. II-2.3 Decreasing pH on Steam Generator blowdown samples. II-2.4 Reduction in condensate makeup to Condenser Hotwells. II-3.0 IMMEDIATE ACT1'JNS II-3.1 Automa tic II-3.1.1 None II-3.2 Manual II-3.2.1 Notify the Performance Department of the situation. II-3.2.2 Increase Steam Generator blowdown to maximum. II-4.0 SUBSEQUENT ACTIONS II-4.1 Start rapid load reduction II-4.2 Locate faulted Condenser half (s) and stop circulating water to it as load reduction permits. II-4.3 Take Unit of f the line and make repairs, as necessary. Prepared by C. A. Burge Manager - Salem! enerating Station G SARC Heeting No. 74-78 Date 12-6-78 s ) Salem Unit I and 2 Rev. 2 e 1 I-4.21 LIMITING AVT SPECIFICATIONS FOR POWER OPERATIONS AT BRACKISH WATER SITES Control Parameter Steam Generator Blowdown Two Weeks 24 Hours Immediate pH 9 25*C 8.0 - 9.2 N/A <8.0 or >9.4 Cation Conductivity >2.0 but < 120
- / A
>l20 umhos/cm 9 25'c /1 Free Hydroxide 373 > 0.15 but < l. 0 ->1.0 ppm as CACO 3 Blowdown Rate Maximum Available Capacity gpm/SG N/A Not Applicable. Comment: Operation beyond the normal AVT specifications is limited as indicated above. Corrective action including shutdown, if necessary, is recommended within.the time periods, as applicable. /1 No relief for Free Hydrovide over and above the Normal Operating Control Limit is provided for periods in excess of 24 hours. ? ma B 1337 188 Salem Unit 1 and 2 Rev. 2 _3 9 I-4.22 e EMERGENCY INSTRUCTION I-4.22 %u LOSS OF RESIDUAL HEAT REMOVAL SHUTDOWN COCLING 1.0 DISCUSSION 1.1 This instruction describes the actions required upon loss of residual heat removal cooling capability during plant cooldown or shutdown periods. 1.2 Possible causes of loss of RHR System cooling capability considered by this procedure are: 1.2.1 Pipe break occurring in the RHR System 1.2.2 Loss of RHR System flow 1.2.3 Loss of RER Heat Exchangers due to loss of Component Cooling Water 1.3 Whenever fuel is loaded in the core, flow must be maintained by either a Reactor coolant Pump or RHR Pu=p at all times (Technical Specification 3.4.1.1), except in ocde 6, Refueling, when the RER Pu=p may be stopped for up to I hour in every 8 hour period to facilitate core alterations in the vicinity of the hot leg penetrations in the vessel (Technical Specification 3.9.8). 2.0 SYMPTOMS 2.1 Residual Heat Removal Pump High Discharge Pressure 2.2 Residual Heat Removal Sump 11(21) Overflow 2.3 Residual Heat Removal Sump 12(22) Overflow 2.4 Abnormal increase in RRR Pump motor current 2.5 RHR Pump Trip Alarm 2.6 Low CCW Flow to RHX Alarms 2.7 RHR Common Suction Valves RH1 or RH2 Indicates Closed 3.0 IMMEDIATE ACTIONS 3.1 Automatie 3.1.1 1(2) RH1 and 1(2)RH2 will close automatically if RCS pressure increases to 600 psig. 3.2 Manual 3.2.1 If RHR common suction valves 1(2) RR1 and 1(2) RH2 indicate closed, stop the RER Pump (s). 3.2.2 If the operating RHR Pump trips, start the standby RHR Pu=p and check for satisfactory operation. If neither RHR Pump can be started, proceed as follows: }h Rev. 2
- /25/78 2
1 I-4.22 e +.
- 1) Mode 4 and 5 a)
Increase RCS pressure to %375 psig to develop the required 200 psid On RCP tl Seal b) Establish seal water injection to at least i RCP IAW OI II-2.3.1, " Establishing Charging, Letdown and Seal Injection ricw". c) Start at least one RCP IAW Oi II-1.3.1, " Reactor Coolant Pump Operation".
- 2) Mode 6 a) Establish alternate decay heat removal as specified by Subsequent Action 4.4 of this procedure.
3.2.3 If it is evident tha t a RHR System pipe break has cccurred, perfor= the following:
- 1) Stop the RHR Pump (s)
- 2) Isolate break, if possible, or isolate the RHR System
- 3) Establish alternate decay heat removal, as specified by step 3.2.3 above.
4.2 SUBSECL* INT ACTION 9: 4.1 If RHR co= men suction valves closed due to high RCS pressure, decrease pressure by ai;usting the Letdown Pressure Control Valve 1(2)CV13 and re-establisn RHR IAW OI II-6.3.2, " Initiating Residual Heat Removal". 4.2 If loss cf heat sink occurs, attempt to restore ccmpenent cooling to the RHR Heat Exchangers. 4.3 With the RHR System unavailable, RCS temperature must be regulated by either condenser or atmospheric steam dump. The use of condenser steam dump will be dependent en the availability of one Circulating Water Pump and ability to raintain %22" of vacuum. The use of atmospheric steam dump will be governed by the radicactivity level in the Steam Generators. 4.4 Alternate decay heat remcval after loss of RHR cooling capability - reacter vessel head removal. 4.4.1 If not already done, flood the refueling cavity to the normal refueAzng level IAW OI II-8.3.3,
- Tilling the Reacter R3 fueling Cavity".
4.4.2 Establish maximum spent fuel pit cooling IAW 01 II-8.3.2, " Spent ruel Pit Cooling System operation". e 1337 190 Re r. 2 4/25/73 I-4.22 4.4.3 Establish maximum reactor refueling cavity filtering and purification IAW OI II-8.3.5, " Refueling Water Purification System Operation". 4.4.4 Operate Containment Fan Cooler Units to maintain Containment air temperature at or below abcut 80'F. Prepared by J. Bailey hy SCRC Meeting No. 7e.n I337 I91 3 4/25/78 I-4.23 EMERGENCY INSTRUCTION I-4.23 LOSS OF CONTAINMENT INTEGRITY 1.0 DISCUSSION 1.1 This emergency instruction provides the actions to be taken, if containment Integrity, as defined in the Technical Specification 3.6.1.1, is lost. 2.0 SYMPTCMS 2.1 Due to the maximum pressures (-1. 5 psi to + 0. 3 psig) maintained in the Containment, less of Containment Integrity, other than in the double barriers, may be difficult to detect. It will be necessary to closely observe Containment pressure and te=perature relationship and any unusual changes in parameters (mainly high steam line flow which would be indication of a pipe rupture) for systems which penetrate the Containment boundary. 2.2 The following may indicate the loss of Containment Integrity: .2.1 Any unexplained change in Containment pressure and temperature.
- 1) Observe the containment Dew Point and Temperature Recorder
- 2) Cbserve the Containment Pressure Recorders or Containment Pressure Indicators.
- 3) Unexplained changes in Containment pressure and temperature as recorded on the Control Console Reading Sheets.
2.2.2 Personnel Access Hatch Door Open. 2.2.3 Equipment Hatch Door Open 2.2.4 Any Containment Iselation valve not indicated in its proper position either on the Control Console on the status panel, or as determined by Surveillance Procedure SP(0) 4.6.1.1, Containment Systems - Primarf Containment. 3.0 IMv_EDIATE ACTIONS 3.1 Automa tic 3.1.1 None 3.2 Manua? NOTE These actions are intended to immediately initiate operator action for restoration of Containe.ent Integrity and, if possible, eliminate the need for subsequent reactor shutdown. 1337 i92 Rev. 2 4/25/78 t I-4.23 s W 3.2.1 Notify Senior Shif t Supervisor / Shift Supervisor of loss or impending loss 3 of Containment Integrity. (, 3.2.2 Commence checking other system parameters which could be the cause of the symptoms indicated. 3.2.3 Ensure that the reactor power, RCS pressure, RCS te.t.perature, and Pressurizer level are not affected. 3.2.4 If a Containment Isolation valve required for Containment Integrity fails and, as a result of the failure, does not close, attempt to close the valve. If unable to close the valve, close a manual valve in the same line. 4.0 SUBSEOtJINT ACTIONS 4.1 If Containment Integrity, as defined in the Technical Specifications, is lost and cannot be restored in the allowable time, bring the Unit to Cold Shuteswn IAW the following instructions: 4.1.1 OI I-3.4, " Power Operation" 4.1.2 01 I-3.5, " Minimum Load to Hot Standby" 4.1.3 OI I-3.6, " Hot Standby to Cold Shutdown" e Prepared by R. Hall' mark //, 6_> - f SCRC Meeting No. 78-26 s d 2 Rev. 2 4/25/79 I-4.24 EMERGENCY INSTRUCTION _y I-4.24 MALFUNCTION - PRESSURIZER RELIEF OR SAFETY VALVE 1.0 PURPOSE 1.1 This instruction provides the actions required to identify and isolate Power Operated Relief Valve which is failed open or leaking. 1.2 This instruction describes the actions to be taken if it is identified that a Pressurizer Safety Valve is leaking. 2.0 INITIAL CONDITIONS 2.1 Any of the following symptoms may be an indication of a power operated relief valve or safety valve malfunction: 2.1.1 Reactor Coolant - low pressure - Alarm / Trip 2.1.2 Pressurizer Relief Tank - high-low level alarm 2.1.3 Pressurizer Relief Tank - High pressure alarm 2.1.4 Relief Valve Temperature Alarm (Computer) 2.1.5 No. 11(21), 12(22) & 13(23) Safety Valves Temperature Alarm (Computer) 2.J.6 Pressurizer Relief Tank Water Temperature High Alarm (Computer) 2.1.7 Relief Valve Temperature Inidcator - increasing temperature 2.1.8 No. 11(21), 12(22) & 13(23) Safety Valves Temperature Indication - increasing temperature. 2.1.9 The following c verhead annunciators indicate a valve is open: Unit,1 Unit 2 K-7 .PRI K-7 2PRl K-15 1.)R2 K-15 2PR2 K-23 2PR47 J-31 2PR48 3.0 IMMEDIATE ACTIONS 3.1 Automatic 3.1.1 Reactor will trip automatically, if there is a very high leakagee' (f,which will cause a Low Pressurizer Pressure Trip followed by a Low Pres' e Safety Injection. .)[' Pressurizer Relief ".ank Vent Valve 1(2)PR15 will automaticall'hblose if 3.1.2 pressure exceeds 10 psig in the Pressurizer Relief Tank.,9% 3.2 Manual 3.2.1 Power Operated Relief Valve or Safety Valve Leaking: 4
- 1) If increasing temperature is indicated on No.
Safety Valve Temperaturc Indicator, or No.12 (22) Safety Valve Tempera ndicator, or No. 13(23) Safety Valve Tamperature Indicator, the le ide,nt'ified as to which Safety Valve is leaking. Perform a wate tory balance to determine the leakage rate as follows: 1337 194 a. OI II-1.3.5, " Reactor Coolant Leak Detection", and/or; b. SP(0)4.4.6.2td), " Reactor Coolant System - Leak Rate Computation". Salem Unit 1/ Unit 2 Rev. 4 I-4.24 i
- 2) If increasing temperature is indicated on the Relief Valve Temperaturft Indicator, identify the lead as follows:
(Perform all four steps below) a) Close Pressurizer Relief Valve Stop Valves 1(2)PR6 and 1(2)PR7, verify that relief line temperature is decreasing. b) Open Pressurizer Relief Valve Stop Valve 1(2)PB6, if terperature is increasing, the leaking valve is 1(2;PRl. Close 1(2)rR6. c) Open Pressurizer Relief Valve S.op Valve 1(2) PR7, if temperatare is increasing, the leaking valve is 1(2)PR2. Close 1(2)DR7. If temperature is not inc5eaung, leave 1(2)PR7 open. d) If 1(2)PRI was determined not to be leaking, then open 1(2) Pit 6. NOTE Closing 1(2)PR6 and 1(2)PR7 will isolate tae POPS. For Unit 2 refer to Tech. Spec. 3.4.9.3 for operational limits when the valves are closed. 3.2.2 Safety Valve Stuck Open
- 1) Start additional charging pumps as necessary to maintain Pressurizer Pressure and Level. Refer to EI T-4.17, " Partial Loss of Reactor Coolant".
- 2) If Pressurizer Pressure drops to 1765 PSIG, Safety Injection will automatically initiate. Refer to EI.I-4.4, " Loss of Coolant".
NOTE The Pressuri::er Relief Tank Rupture Disc will relieve at 100 PSIC. W 3.2.3 Power - Operatec Relief Valve stuck Open
- 1) Verify which Power Operated Relief Valve is open by conso el indicating lights.
- 2) Try to close the open Power Operated Relief Valve b.
essing its MANUAL pushbutton, then depressing its CLOSE pushbu
- 3) If the Power Operated Relief Valve does not clp e, lose its respective Pressurizer Relief Stop Valve (PR6 or PR7).
1337 M5 salen Unit 1/ Unit 2 Rev. 4 I-4.24 b s NOTE The Pressurizer helief Tank Rupture Disc will relieve at 100 PSIG 4.0 SUBSEQt,ENT ACTIONS 4.1 Power Operated Relief Valve 4.1.1 The reactor may be operated until the Power Operated Relief Valvo can be repaired. NOTE For Unit 2 the POPS is covered by Tech Spec 3.4.9.3. Refer to that Tech Spec for operational limitations when 2PR6 and/or 2PR7 are closed 4.2 If Primary System leakage is greater than the operational limits specified in Technical Specification 3.4.6.2 and leakage cannot be stopped, place the Unit in Cold Shutdown IAW the following instructions: 4.2.1 OI I-3.4, " Power Operation" 4.2.2 OI I-3.5, " Minimum Loa.' to Hot Standby" 4.2.3 OI I-3.6, " Hot Standby to Cold Shutdown" Prepared By Manager - Salem Generating Station Reviewed By SORC Meeting No. Date Ah $$+t N e$+ i337 196 4 Rev. 4 Salem Unit 1/ Unit 2 ,? I-4.25 EMERGENCY INSTRUCTION %-4.25 FUEL EANhLING INCIDENT 1.0 DISCUSSION 1.1 This instruction specifies procedures to be followed in the event that new or spent fuel assemblies are damaged during handling or in the event tnat dif ficulty is encountered in removing a fuel assembly from the core or from the fuel assembly centainer. Procedures are concerned with first mintsizing any radiological hatards which might occur and secondly with the dispctition of damaged or potentially damaged new or spent fuel assemblies. Any asifunction of fuel handling equipment will be dealt with by the " Fuel Bandling System Operating Inytructions", Volume 2 Section 9. 1.2 This instruction is divided into five parts: I A new UO fuel assembly is drepped or collides with anetSer object. 2 II A new Puo -UO fuel assambly is dropped or coilides 'with arather y 2 object. III A spent fuel assembly or rod control cluster is dropfad or collides with another object. IV A spent fuel assembly or rod control cluster is dropped or collides with another object resulting in a High Radiation alarm /High Airborne Activity alarm (local). V A fuel assembly becomes stuck inside tne reactor core or inside the fuel assembly container. PART I I A NEW UO FUEL ASSEMBLY IS DROPPED OR COLLIDES WITH ANOTHER OBJECT 2 2.0 SYMPTOMS 2.1 It is expected tnat first notification to the Control Room will be by word of mouth over the station public address system, telephone, or sound powered phone. ~ 3.0 IMMEDIATE ACTIONS 3.1 Personnel concerned evacuate the immediate area using the nearest available exit and remaining cleaz of potentially contaminated areas. Remain in a group immediately outside the affected area to prevent spread of possible contamination until released by Radiation Protection. ( 3.2 Ensure that the local ventilation f an, el.100' truck bay, is secured (normal condition during refuelin;). (Not applicable during initial }h Fuel Receipt.) Salem Unit 1 and 2 Rev. 0 I-4.25 3.3 Dispatch one man to the nearest telephone to inform the Control Room of the incident. Control Operator wills a) notify Supervisor in charge of Radiation Protection. b) observe the stack radiation monitor for any change, and ensure the fuel handling building ventilation is operating normally. c) Change over to the emergency filter exhaust bank (charcool filters) if there is any increase in stack activity. (Fuel handling building ventilation is not applicable during initial Fuel Receipt.) 4.0 SUBSEQUENT ACTIONS 4.1 Monitor and decontaminate all personnel involved. 4.2 Monitor for contamination in the vicinity of the damaged assembly and decontaminate as necessary. 4.3 Radiation Protection will monitor the air in the vicinity of the damaged fuel assembly. 4.4 If the incident occurs in an area other than the refueling canal, wrap the damaged fuel assembly in a polyethylene wrapper and store it away from tne remaining fuel until such time as it is to be inspected by the Reactor Engineer or his designate. 4.5 If the incident occurs in the refueling canal proceed as follows: a) If the assembly is not mechanically distortad and can be handled by the manipulator crane and fuel transfer system, transfer the assemnly to the spent fuel pit, and store it until such time as it can be inspected by the Reactor Supervisor or his designate. b) If the assembly is mechanically distorted or cannot be handled by the manipulator crane and fuel transfer system, a method of handling it must be devised af ter inspection and evaluation. The assembly should be lifted from the refueling canal, decon-taminated, wrapped in polyethylene, and transported to the fuel storage area. Place temporary protection around the damaged element and store until such time as it can be inspected by the Reactor Ergineer or his designate. PART II II A NEW Puo -UO FUEL ASSEMBLY IS DROPPED OR COLLIDES WITH ANOTHER OBJECT. 2 2 2.0 SYMPTOMS 2.1 It is expected that first notification to the Control Room will be by word of mouth over the station public address system, telephone, or sound powered phone. Salem Unit 1 and 2 Rev. O I-4.25 3.0 IMMEDIATE ACTIONS I 3.1 Personnel concerned evacuate the immediate area using the nearest available exit and remaining clear of potentielly contaminated areas. Remain in a group immediately outside the affected area to prevent spread of possible contamination until released by Radiation Protection. 3.2 Ensure that the local ventilation f an, el. 100' truck bay is secured (normal condition during refueling). 3.3 Dispatch one man to the nearest telephone to inform the Control Room of the incident. Control Operator wills a) Notify Supervisor in charge of Radiation Protection. b) Observe tne stack radiation monitor for any change, and ensure the fuel handling building ventilation is operating normally. c) Change over to the emergency filter axhaust bank (charcoal filters) if there is any increase in stack activity. CAUTION No approach should be made to a potentially damaged PuO -UO fuel assembly without donning proper 2 2 ( protective clothing. For an initial approach, this should include, at a minimua, coveralls, hood, shoe covers, gloves, and full f ace mask with a cannister filter. 4.0 SUBSEQUENT ACTIONS 4.1 Monitor all personnel involved for potential alrha contamination. Any count rate above normal background indicates a possible release from the damaged assembly. Record levels of contamination founc on personnel and decontaminate. 4.2 If the incident occurs in an area other than the refueling canal, proceea as fellows: a) Wearing proper protective clotning and full face masks with a self-contained air supply, monitor the affected area for alpha contamination. b) If no alpha contamination is found on the floor or on the protective covering around the assembly, cautiously open the polyethylene wrapper and survey the fuel assembly using the survey meter and taking smears. ( 133' 199 Salem Unit 1 and 2 Rev. 0 I-4.25 c) If no alpha contamination has been released from the assembly, I other personnel may approac.: to begin recovery operations. No movement of the assembly should be attempted without first determining that such rovement will not further damage the cladding e.nd subsequently release contamination. d) If alpha contamination exists on the 41oor, protective wrapping, or fuel assembly itself, no further recovery operations should be attempted without a plan to cover the specific situation. This immediate effort should be co limit the contamination. Contaminated areas should be located, marked, and covered with plastic sheet or tape. If wicespread contamination has occurred, the area shouid be sealed off to tne maximum extent possible, and no one shoul$ be permitted to enter until a specific plan of action has been formulated. 4.3 If the incident occurs in the refueling canal, attempt no other action until the assembly has Deen inspected, evaluated, and a specific plan of action formulated. PART III III A SPENT FUEL ASSEMBLY OR CONTROL 30D CLUSTER IS DROPPED OR COLLIDES WITH ANOTHER OBJECT. k 2.0 SYMPTOMS 2.1 It is expected that first notification to the Control Room will be by word of mouth over the station public address system or telephone. 2.2 If at any time the Containment or Fuel Handling Building High Radiation alarm /High Airborne alarm (local) sounds, proceed with the instructions of PART IV, page 6 3.0 IMMEDIATE ACTIONS 3.1 Personnel concerned evacuate the immediate area using the nearest available exit and remaining clear of potentially contaminated areas. Remain in a group immediately outside the affr.ted area to prevent spread of possible contamination until released by Radiation Protection. 3.2 Ensure that the local ventilation fan, el. 100' truck bay, is sectred (normal cor.dition curing refueling). 3.3 Dispatch one man to the nearest telephone to inform the Control Room of the incident. C 1337 200 Setem Unit I and 2 Rev. 0 I-4.25 Controi Operator wills (a) Notify Supervisor in charge of Radiation Protection. (b) Observe the stack radiation monitor for any change, anc insure the fuel handling building ventilation is operating normally. (c) Change over to the amargency filter axnaust bank (charcoal filters) if there is any increase in stack activity. 3.4 nnsure that all doors are closed or temporary coverings erected over apenings leading to the affected area. CAUTION Entry to tne affected area should be mace with continuous Radiation Protection surveillance only. 4.0 SUBSEQUENT ACTIONS 4.1 Monitor and decontaminate all personnel involved. 4.2 Radiation monitoring team enter the affected area, wearing full face masks witn self-contained air supply to obtain air, water, and gaseous activity samples. ( 4.3 Visually inspect the damaged fuel assembly. Gas bubbles may bu visible if the assambly has ruptured. 4.4 If the fuel assembly is not mechanically distorted and no fission gas is present, transfer it to the spent fuel pit. If no leaks develop during this step, store it as any other assambly. Note its location and monitor the spent fuel pool. 4.5 If the fuel assembly is mechanically distortec or is releasing fission gas, it must be placed in a suitable storage can until disposal plans can be formulated. Due to the presence of decay heat and fission gases, this can must be vented tnrough a filter system to a gas vent and should include provisions for flushing and filtering. 4.6 If an irradiated rod control cluster is dropped, store by suspending from the side of the cavity until refueling is complete. Then remove and put in cask provided for trensportation. PART IV IV A SPENT FUEL ASSEMBLY OR ROD CONTROL CLUSTER IS DROPPED OR COLLIDES WITH ANOTHIR OB ECT MESULTING IN A HIGH RADIATION ALAxM/HIGH AIRBORNE ACTIVITY ALARM (LOCAL). 2.0 SYMPTOMS 2.1 Any of five alarms sound locally. ] \\ Rev. O Salam Unit 1 and 2 I-4.25 a) Spent fuel storage area high radiation alarm. b) New fuel storage area high radiation alarm. c) Reactor operating floor high radiation alarm. d) Containment or fuel handling Duilding high airborne activity alarm (portable monitor). 3.0 INTEDIATE ACTIONS 3.1 Evacuate the Containment Building (Fuel Handling Building) Dy following the posted evacuation route arrows. 3.2 Proceed to the Monitor and Change Room area. 3.3 Standby for further instructions. 3.4 The Control haom wills " Radiation Incident". a) Follow SPM Emergency Instruction (I-4.16) b) Sound the Site Radiation Alarm and announce evacuation of Containment Building (Fuel Handling Euilcing). c) Standby for further instructions from the Senior Shift Supervisor. 3.5 Operating shift personnel wills a) Proceed to Control Room. b) Standty for further instructions from watch Engineer. J.G The Senior Shift Supervisor / Shift Supervisor wills a) Proceed to Control Room. b) Notify the supervisor in charge or Radiation Protection. c) Notify Chief Engineer. d) Monitor the Area Radiation Monitor System indicators to determine Contal'- nt Building (Fuel Handling Building) radiation levels. e) Report Containment Building (Fuel Handling Building) radiation conditions to the supervisor in charge of Radiation Protection. 3.7 All other station personnel will: a) StandDy at working area for further instructions. 4.0 SUBSEQUENT ACTIONS 4.1 Supervisor in charge of Radiation Protection wills a) Proceed to the Monitor and Change Room. 1337 202 Salem Unit 1 and 2 Rev. 0 n I-4.25 b) Contact Senior Shif t Supervisor and obtain report of Containment i Building LPuel Handling Building) radiation conditions. c) Determine that all pbrsonnel have been evacuated and supervise monitoring of evacuatea personnel. di Dispaten monitoring personnel, equipped with respiratory cavice, high range dosimeter, anc hign range survey meter into the Containment Building (Fuel Handling Building) tot
- 1) Obtain Containment Building (Fuel Handling Building) air sample.
- 2) Monitor Containment Building (Fuel Handling Building) radiation levels.
e) Evaluate data from monitoring personnel and the Area Hadiation Monitoring System to determine action levels and hazards involvec for:
- 1) Recovery operation.
- 2) Subsequent 'otificetion of outside agencies.
- 3) Further on-site and off-site evacuation.
( PART V V A FUEL ASSEMBLY BECOMES STUCK INSIDE THE REACTOR CORE OR INSIDE THE FUEL ASSEMBLY CONTAINER. 2.0 SYMPTOMS 2.1 Abn al load is indicated on the manipulator crane load cell. 2.2 The overload circuit on the load cell is actuated at 2825 lbs., preventing operation of the manipulator crane hoist in the up direction. 3.0 IMMEDIATE ACTIONS 3.1 Stop the manipulator crane hoist and r.otify the SRO in charge of-refueling. 4.0 SUBSEQUENT ACTIONS 4.1 Check load cell and ILmit circuits for proper operation. 4.2 Using the manipulator crane, make one additional attempt to remove the fuel assembly, exerting a maximum force of 2825 lbs. as indicated on the load cell. 1337 203 Salem Unit 1 and 2 Rev. 0 I-4.25 4.3 If the arsembiv is stJck in the fuel essembly container and is not freed in Step 2, sonsult the Reactor Engineer before proceeding. Conduct visual inspection of the fuel assembly 4.id transfer container to determine cause of problem. If the assembly is stuck in the core, and Step 2 coes not free it, proceed as follows: a) Remove and transfer fuel asserblies adjacent to the affected assembly. b) Once adjacent assemblies are removed, attempt to free the affected assembly using a maximum of 2250 lbs. force as indicated on the readout. c) If the fuel assembly remains stuck consult with the Reactor Engineer and formulate further procedures. ' w IA--- r Prepared by J. Nichols/J. Harrick Manager - Salem denerating Station SORC f%.# ting No. 75-78 Date 1/11/79 1337 204 Salem Unit 1 and 2 Rev. 0 EI I-4.26 / EMERGENCY INSTRUCTION EI I-4.26 LOSS OF CONDENSER VACUUM 1.0 DISCUSSICN 1.1 A loss of condenser vacuum will cauce a Turbine Trip if Resctor Power < 10% and a Turbine Trip / Reactor Trip if Reactor power is > 104. 2.0 SYM7 toms 2.1 Condenser vacuum decreasing. 2.2 Overhead Alarms F-7 and G-2 are alarming. 2.3 Rr. actor and/or Turbine tripped due to low vacuum. 2.4 Steam Generator Feet Pumps tripped due to low vacuum. g 2.5 Main Turbine ruptur-lises may have ruptured. 3.0 IMMEDIATE ACTION 3.1 Automatic 3.1.1 Turbine Trip, if Reactor Power is < 104, Reactor Trip / Turbine Trip, if Reactor Power is > 104. 3.1.2 Steam Dump to tne condensers is blocked. 3.1.3 The Atmospheric Steam Relief Valves (MS10 's) are maintaining S/G pressure. 3.1.4 Auxiliary Feed Pcmps started and are supplying feed to the S/G's. 3.2 Manual 3.2.1 Take MANUAL centrol of the Auxillfly Feed System to feed S/G's as necessary. 3.2.2 Take MANUAL control of the Atmospheric Relief valves to maintain S/G pressure / RCS temperature. CAUTION Us. sf 11-14 (21-24)MS10's requires close operator monitoring of the S/G pressure so that S/G AP inadvertent safety injection will not occur. 1337 205 Sale, Unit 1/ Unit 2 Rev. 0 EI I-4. F D u 4.0 SCEErOUD:T AC'"!CN 4.1 If res tor tripped, 1: plement EI I-4.3, "Reacter Trip". 4.2 If conden.rnt vacu=i cannot be restored in a reasonable time, take the reactcr s :cr2:.ral IAW OI I-3 5. "Minir.us I, cad to Hot Standby". 4.3 If condenser vacuur. can be restored, commence synchronization and F0wer Operation IA.s OI I-3.4, after condenser vacuun is restored. NOTE Selection of Step 4.2 or 4.3 shall be at the discretion of the Chief Engineer or Staticn Operating Encineer. , hM Prepared by J. Ronafalvy Manager - Sal d Gener' sting Station seviewed by F. C. schnarr SCPC Meeting No. 21-79 Date 3/27/79 1 1337 206 Salem Unit 1/ Unit 2 2 p e.; O}}