Text

Emergency Instructions Re Safety Injection Initiation, Flooding &/Or High Wind Conditions,Recovery from Safety Injection,Reactor Trip & Loss of Reactor Coolant Pump &/Or Flow
	ML18079A563
Person / Time
Site:	Salem
Issue date:	07/17/1979
From:	; Public Service Enterprise Group
To:	;
Shared Package
ML18079A562	List: ML18079A561; ML18079A563;
References
	PROC-790717, NUDOCS 7907190597
	Download: ML18079A563 (190)
	v • d • e

I-4.0 EZ>1ERGE~lCY INSTRCCTION I-4.0 SAFETY INJECTIO~ INI~IATION 1.0 PCRPOSE

~

~l.l This instruction is provided to present the immediate automatic and manual ac~ions required to be performed on the receipt of any Safety Injection actuation, regardless o:!' the cause.

l.2 ~his instruction contains the information required to direc~ the operator to the appropriate Emergency Instruction to cope with the existing plant conditions .

..,- * "v r::rTIAL CONDITIONS 2.1 Safety Injection has initiated.

3.0 l)~IBDIATE ACTIOKS 3.1 Verifv the following automatic actions have occurred.

3.1.1 Reactor trip by ~erifying all control rods are fully inserted by checking the individual rod position indications and rod bot~om lights.

1. If any control rods do not indicate full insertion, initiate a manual reactor trip.

3.1.2 Accident loading of the Safeguards Equipment has taken place and the following equipment is running by observing the indicating lights on the status ?anel on RP-4. and by observing the control bezels-for each of the following:

1. Centrifugal Charging Pumps

2. Safety Injection Pumps

3. Residual Heat Removal Pumps

4. Auxiliary Feedwater Pumps (Motor Driven)

5. Service Water Pumps

6. Containment Fan Coil l'nits in slow speed

7. Diesel Generators 3.1.3 Reactor Coolant temperature is decreasing to or being maintained at 547°F by either steam dump or atmosheric steam relief.

3.1.4 Within two minutes reduce Auxiliary Feedwater Flow to the Steam Genera~crs to limit the rate of rise to <1.2 in/min by monitoring the wide range level recorders (<0.2%/min on the wide range until th~ level is~ 10% on the narrow range indication for all Steam Generators not affected by the failure. Then re-establish maximum Auxiliary Feedwater Flow.

JO'!'E

~"T9-0 5"7'~

This limitation applies to Unit 1 en:~.

Rev.O Salem cnit l/Cnit 2

I-4.0

.l.S rurbine trip by verifying the following:

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 Pumps tripped by observing the indications on the control bezel.

If either pump has not tripped, trip it manually.

3.1.7 Feedwater isolation by observing the indicating lights on the Feedwater sec~ion of RP4.

3.2 Verify Safety Injection Pump 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 <1550 psig as read on the Wide Range Indicators on the control console, stop all Reactor Coolant Pumps.

3.3 Verify Containment Phase A isolation has taken place by observing the indicating lights on the status panel RP-4.

3.4 Announce over the Station PA System twice: UNIT 1(2) REACTOR TRIP, SrlFETY INJECTIO~ .

SUBSEQUENT ACTIONS

0 4.1 Verify Safety Injection is in progress by checking each of the following. If any equipment or valve is not in the desired condition or position attempt to establish

~he desired condition at the individual bezel on the control console.

CAUTION DO NOT 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.l 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. Fan Coolers service water flow has increased from 700 gpm to 2500 g~m

c. Roughing filter dampers i:ave closed

d. HEPA inlet dampers have opened

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 BO!"On Injection Tank Inlet Val,re 1(2)SJ5 BO!"On Injection Tank Inlet Valve 1(2)SJ12 Borer. Injection Tank Outlet Valve 1 (2) SJ13 Boron Injection Tank Outlet Valve Salem Unit l/Cnit 2 Rev. 0

I-4.0 1(2)SJ1 Charging Pump Suction From RWST 1(2)SJ2 Charging Pump Suction from RKST 4.1.4 Check that the following valves have closed. If any valve fails to clcse, attempt to close the valve from the control console.

1(2)SJ78 Rec ire to Eerie Acid Tan"

1(2)SJ79 Rec ire to Boric Acid Tank 1(2)SJ108 Rec ire to Boron Injection Tank 1(2)CV68 Charging System Stop Valve 1{2)CV69 Charging System Stop Valve 1 (2) CV139 Charging Pump Disch to SWHX 1(2)CV140 Charging Pump Disch to SWHX 1(2)CV40* Volume Control Tank Discharge Valve 1(2)CV41* Volume Control Tank Discharge Valve 1(2)CV3 Orifice Isolation Valve (Letdown) 1{2)CV4 Orifice Isolation Valve (Letdown) 1(2)CVS Orifice Isolation Valve (Letdown) 1(2)CV7 CVCS Letdown Line 1(2)CV116 Reactor Coolant Pump Seal Water Discharge 1(2)CV284 Reactor Coolant Pump Seal Water Discharge 11(2l)SW20 Turbine Gerrerator Area Supply Valve ll(2l)SW20 Turbine Generator Area Supply Valve 1(2)SW26 Turbine Gen~rator Area Isolation Valve NOTE

These valves will not close until either 1(2)SJ1 or 1(2)SJ2 is fully open.

4.2 Verify that Phase "A Containment I~olation has taken place by checking that the valves listed in Table II are closed. Should a valve fail to close, attempt to close it from the control console.

4.3 Verify that Feedwater Isolation has taken place due to the Safety Injection.

~.3.1 Check that the following valves have closed by observing the status panel and/or the console bezel. If any valve has faileq to close, attempt to close it from the control console.

11 (21) BF13 Feedwater Inlet Stop Valve 11 ( 21) BF19 Feedwater Control Valve 11(2l)BF40 Feedwater Bypass Valve 12(22)BF13 Feedwater Inlet Stop Valve 12(22)BF19 Feed water Control Valve 12(22)BF40 Feed water Bypass Valve Salem Unit l/Unit 2 ?.e'.'. 0

I-4.0 13 (23) BF13 Feedwai:.*- **** p - :.... Stu? Valve 13(23)BF19 FeedwateL *_ontrol Valve 13(23)BF40 Feed water Bypass Valve 14 (24) BF13 Feedwater Inlet Stop Valve Feedwater Cor.~rol Valve 14 (24) BF19 --

14(24)BF40 Feedwater By:;iass Valve "of 4.4 Verify that the 4160 V Group Busses have transferred from the No. 1(2) Auxiliary Power Transformer to No. 11(12) and No. 12(22) Station Power ~ransformers.

4.4.1 Check that the following 4160 V breakers have opened and acknowledge them on the appropriate control console bezel:

1(2)BGGD 1(2)BFGD 1 (2) .r..EGD 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 11(2l)ESD 11 (21) BSD

4. 5 Verify the following fans have stopped by observing the indications as noted.

If any fans are still running, attempt to stop them manually.

No. 11 & 12 (21 & 22) Iodine Removal, Control Console No. 11, 12 I 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 Coolers, RP2 No. 11 & 12 (21 & 22) Charging Pump Room Coolers, RP2 No. 11 & 12 (21 & 22) Containment Spray Pump Room Coolers, RP2

4. 6 Verify Control Area Air Conditioning has shifted to the ACCIDENT - INSIDE AIR mode of operation and the following actions have occurred by observing the stat~s pa*1el on RP2. If any actions do not occur, manually initiate them IAw OI II-17.3.2, "Control Room Ventilation Operation", Section 5.3.

NOTE Control Room Ventilation Isolation of Unit No.

1(2) will also isolate Unit No. 2(1) Con~rol Room, however, its green NORMAL mode indicator will remain illuminated.

Salem Unit l/Unit 2 P.ev. 0

I-4.0 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 Supply Fans are riinning 4.6.4 No. 11 & 12 (21 & 22) Emergency Control Area Supply Fans are running.

4.6.5 Battery Exhaust Fan has stopped.

4.6.6 Control 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 - Closed CAA2 - Closed CAA5 - Open CAA18 - Closed CAJl.31 - Closed CAA3 - Closed CAA14 - Closed CAA19 - Closed CAA32 - Closed 5.0 IDE~TIFICATION OF FOLLOW-UP ACTIONS 5.1 .If RCS Pressure decreased rapidly with no o~her indications of primary or secondary leakage, verify the following are closed or isolated at their individual control bezels.

5.1.l Pressurizer Spray Valves (PS-1&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)PSl - Trip 13(23) RCP 5.1.2 Pressurizer Power Operated Relief Valves (PRl & 2) 5.1.3 Pressurizer 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:

1. Increases in Radiation

2. Unexplained accumulations of water 5.2.2 Pressurizer Auxiliary Spray Valve (CV75). Ensure it is closed.

Salem Unit l/Unit 2 Rev. 0

I-4.0 5.3 Utilize the following matrix in order to determine which subsequent Emergency Instruction to follow.

SAFETY INJECTION INITIATED I

I l RCS PRESS < 1865# RCS PRESS > 1865# RCS PRESS > 2000=

OR DECREASING BUI' < 2000# AND PRESS LVL > 50%

A:.'m

<CS PRESS S/G LVL ', 33"

.* 1550#

OR CC'tl 'IO RCP'S I

GO 'IO EI I-4.2 ISOLATED "RECOVERY FRa1 SAFETY INJECTIQ.',;;"

ALL I RCP'S IF RCS PRESS DECREASES BY 200#

OR PRESS. Li:.""VEL DROPS 'IO < 20%

REINITIATE SAFETY INJECTIOK.

I I CO:CIT'. R"'..S INCREASE wTI'H RCS TEMP DECREASES STM GEN BUM"DCWN OR AIR CO)."T. TEMP . , PRESS , RAPIDLY WITH T.DN S'IM EJECTOR RMS INCREASING WITH h"l."'.*UDITY, SL"}!P LE\'EL PRESS IN ONE OR !>ORE clO INCREASE IN CO~'I'.

INCREASING S GEN PARA.'1ETERS I I I C-0 'IO EI I-4. 4 GO 'IO EI I-4.6 GO 'IO SI I -4 . 7 I.OSS OF COOIAW ACCIDENT S'l'Ek'! LINE RlJP1URE STEk\! GENER1'.TOR TUBE RUPTURE Prepared by ____J_._v_._B_a_i_l_e_y_______

>lanager - S@.n~

Reviewed by ___~J~."'M"'.---'Z~u=p~k~o~------

SORC Meeting No. _ _5_6_-_7_9_________ Date 7 / ~f J

--"-,+--;+----

Salem Unit l/Unit 2 Rev. O

l-~ .l

!:~*~=?.G:::::c*~* r::ST?UC7IO:.J I-~.l 1.0 DI9USSIO'.\'

1.1 Flooding ~ay occur as a result of a severe rainstorm or hurricane.

1.2 :;atural disaster flooding, defined as that condition reached when the tide level increases to the 100.5 foot elevation (+ 11.5 feet MSL), requires the Unit to be shut down. Pre tee-tive me~sures should be taken prior to the flood stage. The design of building entrances and site grade, provide protection for adverse combinations of wind velocity and tidal variation.

-1 . ~

.) Sump pumps are provided to maintain vital areas as dry as possible. The use of portable pumps ::-.ay be necessary in cases of excessive interior floocing.

i.4 This procedure is to be used during:

1.4.1 Severe storms including hurricanes, tornados and other storms where high winds in excess of 60 mph have been forecasted for the area or,

~o

1. 4. 2 The tide ievel increases to or above the 99.0 foot elevation (> 10.0 feet MSL).

S Y!*1PT0!-1S

~ind velocity > 60 mph. *1

2. 2 Tide level at elevation 99.0 feet (10.5 feet MSL).

2.3 Tornado 3.1 .~.ut.Jmatic None 3.2 Mar:ual Imple~ent 'Emerg~ncy 1

3.2.1 Emergency Procedure EP I-2, Alert.

3. 2. 2 Insure that the doors listed in Table I and II are closed, secured, and dogged (if water-tight door).

Technical Specification 3.7.5.l requires all water-tight doo~s to be closed within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months a~d tide level ~e2su=e-

~e~ts to be taken ever~~ t~o hou~s far ~lood protectic~

~;h~*:ever the tide level i~c~eases ~~or 2~cve 10.5' =*1ea~

S~a Le~el (99 foot e:e*:atic~)

?..o;*:

6

possi~le, t~e th~.::-- "l*:.:~~:do*.-.'r.

11 3 .. 2. 3 If move the cru:ies on T"Jrbine Et.:i2.d:..:ig roe:[ t.

!=:OsitionS and posi..tion th,e lockinC? devices to sec*..l::-e t~e c;:-~r!~E bC!fore hi~h w:..::id.s

revail .

.0 SUBSEQUENT riCTIONS 4.'! Monitor the tide level trend at least once each hour. If t~e level increases to or above the 100.5 foot elevation (+ 11.5 feet MSL), implement Emergency Procedure I-3, "Plant (Unit) Emergency".

NOTE Refer to Technical Specification 3.7.5.l.

4.2 If plant shutdown is deemed necessary, take the plant to hot standby in accordance with OI I-3.5, "Minimum Load to Hot Standby", and as required, on to cold shutdown in accordance with OI I-3.6, "Hot Standby to Cold Shutdown".

4.3 If, as a result of the storm (i.e., tornado), the Auxiliary ?eedwater Tank (F.FWT) is not available (e.g., tank damaged, ruptured, inoperable, etc.), to supply auxiliary f&edwater for plant shutdown, shift the suction of the Auxiliary Feedwater Pumps to a preferred (i.e., DMl*;'I's or FW & FPWT~ 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, the Auxiliary Feedwater System shall be connected to the Service Water System for use as an emergency alternate water supply in accordance with OI III-10.3.1, "Auxiliary Feedwater System Operation".

CAUTION To ensure safe shutdown in the event that the auxiliary feedwater supply is lost in conjunction with the main feedwater supply, shift over to an alternate auxiliar~

feedwater supply (including the installation of spool pieces) should be accomplished within approximately 30 minutes.

4.3.l When the AFWT is returned to an operable status, return the auxiliary feedwater supply to a normal lineup IAW OI III-10.3.l, "Auxiliary Feedwater System Operation".

4.4 As practical move loose materials to shelter. As conditions require, valuable equipment and documentation should be moved from out-lying, non-permanent structures (i.e., trailers) to safer s~orage.

4.5 As practical, fill large tanks as full as possible to preclude wind damage or tank buoyancy.

Prepared by R. J. Hallmark

~*1c.:1ager - S.::.le/;cr:'erating Staticn Pe*:iewed :::y F. Schnarr Date 4/25/79

u:nT l & OIJ'l-L'!IllG STF'.JCTUP!::S Dt:OR Ii BLL!G.:..GRlD DESCRIPTION LOCATION R~~~fKS T-.!?E

,. .:..ux. l 0-0--::--'- - + - - - - - - - - - - - - - - -

42 AF I Carricor to Unit 1 Side Elevator BB - 13. 3 Au:-:. 100' 41 SF '-'nit l Side Elevator Area to No. l Relav Fl.""!". BE - 13. 2

.;;u:-:. 100'

~--~..::.3--'~-S-*--+....:..:_:.*..::.u..::.Y..::..i..::.l~i_;_ac.:r;.,}._'_B:;..::lc.:d:...c:~

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Pen. 100' 64 s Sauth Penetration - South Side FF - 2.5 \*iater-Ti'°ht Door Pen. 100' 65 s ?enet:-at.ion P.rea - West Corner Past B.D l'T'ani.. c:: VK - 8.5 FHB 100' 68 s FHB Receivina Area - North Side pp - 8.5 Water-Ticht Door FHB 100' Mant!al J:i.. ir -

69 s FHB Receivina Area Truck Door - West Side SS - 7.8 Ocerated Door Seal FHB 100' 10 ......

' FHB Storage Area Truck Door - West Side SS - 6.5 FEB 100' 71 A FEB Stora ae Area --=S-=o'-'u=-t=:!"i,_,.-=S'-"i'--'d=-e=------------+--"~-~P---=6~-~2~--+------ - - - - - - - - - - l Aux. 100' Manual Air -

27 A Soli~ Radwaste Area - Truck Door TT - 13.0 Oceratec Doar Seal Aux. 100'

..!..: Solid Rad~aste Area - West Side TT - 13.3 Aux. 100'

~9 SF Aux. Eldq. Corridor to Solid Rad~aste Area pp - 13. 7 Water~~icht Door Pen. 120' 2:?5 s Penetration Area to Roof - Southeast Corner cc - 10.0 Pen. 120' 87 s South Penetration to Roof - South Side EE - 2.2 CON 130' NA Unit l Cantainment Ecuioment Ha~ch KK - 3.3 Reauires Crane Pen. 130' 85 s Penet~ation Area - West Corner Past Pers.Hatch KK - 9.2 Aux. 127' 229 s ~o. 11 Diesel Reem Escape Hatch to Roof Qr) - l 0. 0 Aux. 127' I L] I) s No. 12 Diesel acorn Escace Hatch to Roof RR - 10.0 ll.ux. 127

~--'--

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~o. 13-Diesel Roorn Escace Hatch to Roof

. Lo8b~~ - Outer o*oors ___________________

SS - lU.0

.:\.cb. loo*

y - 14. ')

~~d!T.. lo "°o*~,--4----------------*

I .!4 o ! Lonnv '. - Inner Doors I YA - 14. 0 i I Adm. 100' I 244 l>. .Cafeteria - Southside Exit AB - 10.3 1

1* Adm. l OO ' I I 245 A Kitchen/Receiving Area - Southside CB - 10.3 1 ITurbine TGA - 100' : I I! ::: A 1 Area - East Side by Panel 385 ~G~ :. . ~OO, ' 1

, A !Turbine Area - East Side by Main Transfor:ner D - 5.1 1-- --..,1~---+--~-~-~-~--~~--=----~-----~-+--T~G~A--~l~O~O,,..,...'-l~--------~~-~i 116 A Turbine Area - South Side to Stairwell EF - 1. 0 1 !

TGA - 10 0 ' i 114 TA I

Turbine Area - South Side r-~~~1.---+-=-.:..::...:'----='--_::_..::;.__;_--=..;::..=-:=-----~--------<~T~G~A--=-i-l~OO,,..,..'-+I--~---------:

GF - 1.0 1*

i 113 A Turbine Area - South West Corner NM - 1.0

~,~~-~i----1--~-~-------------------~----'---T~GA - 100' I

! 112 1 A Turbine Area - South West Corner to Stairwell N - 1.9 J 110 l A ITurnine .?\.rea - West Side by ';o. 13 Condenser ~G: ;_~oo* I 96 i

,------j-----------------~------------<--~=--=-""""-,---f-a-----------~----

A IService Bldg. - South Side Stairwell SUB l 0 0' N? - 10.0 I

i I South Side SCB 100' I

!~-~?*~-+i_A__--;.l-=s~e_r=---v_i_c_e__3_l_d~g"-'-.-=E~n.:..t~r:.:...:..a_n~c~e=---~t~o---=C~o~*n~t-=r~o~l=-~Pc.:o~i~n~~=-------=---~?~~l~--=l~O~.~O;...,._~!_______________

I 7G;.. - 120' 148 A ,Turbine Area - South Side St_a_.i_*r_*_..,_e_l_l______ EF - 1. O

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47

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DuGR TYPE A

DI:SCRIPTIO!l r.:....r)l~_;_;HJii I../)C.:\TIOiJ TG.:, -

TG_:"l.

TG.; -

l. 9 120'

- 120' 6.2 140' P.I~'.*lAP.!'.5 55 P.. DE - 13.7 SUB ::.,;o*

35 P.. ?~~ - l 0. 4 Aux. l~O'

~l9 A Al~ - 13.S svv.* ioo' 2C2 s S - PIT SVW lOO' 2 03 s :.; - PIT svw 112' 204 s BAY - l 205 s 206 s SVW ll2' I 207 s BP.Y - 4 svw 112' 208 s S - ELEC svw 112 2 c*:-- s :'~ - E2:.,EC

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ur:rr 2 f. OlJT-L 'i l ::r:; STr-::_:CTU!<'.:'

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DESCF.IPTION PL!:.-: !.~l~iL' L~.:Cl.'!'l 1 JrJ

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..! 4 .3F Cc=~i~or to Unit 2 Side Stair ~o. 5 14 0 At.::*: 100' 45 s:: 53 - 14 5

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s f--__::_-'-~f---"-----i-'-N~o~r~t~h'-'--~P~e~r~.e~t~r"-=a~t~i~o~n-'---=E~a~s~t~~~--~;d=-=e--------~--+-~[~'D=------==~s~2=--;-\*~J~~*~~e=-=r-Ti?h~

=>- ~co~

=- Pe:-i 100' 53 s Ns~t~ Penetration North Side :r: - 25 _.) Doo::-

I Pe~ 100'

~, s 1---------1,__P_e_n_.e_t_r_a_t_i_o_n __ ;.._r_e_a_-

__W--'e_s_".'_ Cor:-ier Past B. D. Tan}:s * :\l'. - 19 l FE2 100'

'.), A I FH3 Storaae Area - Nor~h Side PF - 22.0 F:C:B 100'

=: 3 !>. SS - 21.0 59 s 60 s Aux. 100' 32 SF pp - 14.3 Pen. 120' 226 s Penetration Area to Roof - Northeast Corner cc - 17.8 Pen. 120' 9:;_ s ~orth Penetration to Roof - North Side EE - 25.8 co:-; 130

~J.:.. Ni\ KK - 24.7 Pen. 130' 90 s Penetration Area - West Corner Past Pers. Hatch KK - 18.8 Aux. 127 232 s No. 21 Diesel Room Escape Hatch to Roof QQ - 17.8 Aux. 127' 233 s No. 22 Diesel Room ~scaoe Hatch to Roof RR - 17.8 Aux. 127' 234 s No. 23 Diesel Roow Escaoe Hatch to Roof SS - 17.8 TGA 100' 123 A Turbine Area - East Side bv Pa:-iel 385 D - 18.5 T,..,.

u.-.. 100' 124 T*..:r:::i:-ie Area - East SiC.e bv Main Transfo:nner D - 22.7

"' TGJi. 100' 125 l A Turbine Area - Nortn Siue to Stairwell !:F - 27.0

~--,---:-*- .. -~'i'11rhinP :\rP"l - Nnrth SiC:P.

TGA 100' GF - 27.2

,__ __________ A Tur~ine Area - ~orthwest Corner

~~A 2-0C' NM - 27.0 r 129 I I

A I T-..:rbine I Turbine Area - Northwest Corner to Stairwell I

"'G'n 100' N - 26.2 TGA 100' I

131 I

I A Area - West Side by No. 23 Condenser N - 24.3 SUB 100' I ;

i II , 04

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I s Storeroom North Side PN - 18.0 I !

I 105 i s Service Bldg. - North Side Stairwe.11 SUB *100' NP - 18.0 i I iI !

later later Se: :-vice Sldg. to Aux. Bldg. AA - 14.5 I Water-Tigly~_ Door '

iI I 425 - A I Service Bldg. to Aux. Bldq. Elevator A.-:l. - 13. 5 Water-Tight ::ioor '

I TGA 120'

! 152 A Turbine }\rea - North Side Stairwell EF - 27.0 '

TGA 120'

! 153 1' A Turbine Area - Northwest Corne::- Stairwell N - 26.2 i I TGA 120' 15.:l i A I Turbine Ji_rea - West Side by Panel 711-2C ~~ - 21. 9 I

TGA l.J 0 I 156 I' s I ---- - - - - - * - - - - - - - - - -DE - l-L3 22/ s SU3 1.:10 I

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' }1 I-4.2 E~ERGENCY INSTRUCTION I-4.2 RECOVERY FRml SAFETY INJECTION

1. 0 PURPOSE

-<- i.1 To delineate the steps required to terminate sa=ety Injection and return the u~i~

to a nor~al, shutdown alignment.

2.0 I~ITIAL CONDITIONS 2.1 The conditions as described in one of the following Emergency Instructions exist such that termination of Safety Injection is required or desirable.

2. :'.. .1 EI I-4.0, "Safety Injection Initiation", Step 5.3.

2 .1. 2 EI I-4.6, "Loss of Secondary Coolant" 2 .1. 3 EI I-4.7; "Stearn Generator Tube Rupture" 3.0 IMEEDIATE ACTIOKS 3 .1 :*:o!'1e .

4.0 SCBSEQCE~T 4.1 ACTIONS The Senior Shift Supervisor/Shift Supervisor shall verify that the initial conditions described in Step 2.1 above are satisfied.

follows:

The operator shall then proceed as CAUTION If at any time after the Safety Injection is reset, Reactor Coolant Pressure drops unexpectedly by more than 200 psig or pressurizer level cannot be maintained at >20% by normal 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. Return to EI I-4.0, "Saf~ty Injection Initiation", and re-evaluate the plant conditions.

4.2 Reset the following signals:

ll Depress the Train"A" and Train "B" SI RESET pushbuttons, on the contron console to reset the Safety Injection signal.

Salere udit l/Unit 2 -:!..-

I-4.2 Depress the Train "A" and Train "B" CONT ISOL ~A RESET pushbuttons, 2) on the control console, to reset the Containment Phase A Isolation signal.

3)

Depress the Train "A" and Train "B" CONT VENT ISOL RESET pushbut_tons, on the control console, to reset the Containment Ventilation Isolation signal.

4) Depress the Train "A" and Train "B" FEEDWATER ISOLATION RESET pushbuttons, on the control console, to reset the Feedwater Isolation signal.

5) Depress the E~ERGENCY LOADING RESET pushbuttons, on the control console, for lA, lB and lC (2A, 2B and 2C) Diesel Generators to reset the Safe-guards Loading sequence .

.J.2 Return the Service water System to normal lineup IAW OI V-1.3.l, "Service water-Normal Operation".

4.4 Stop Centrifugal Charging Pumps and stop the flow thru the Boron Injection Tank by closing inlet valves 1(2) SJ4 and 1(2) SJS. Stop the RHR Pumps and Safety Injection Pum;:is.

CAUTION Prior to stopping both Centrifugal Charging Pumps,

.insure the reciprocating Charging Pump is running to supply seal water to the Reactor Coolant Pumps. If the reciprocating Charging Pump is not running, leave one Centrifugal Charging Pump operating.

4.5 Return Diesel Generators lA, lB and lC (2A, 2B and 2C) to normal operation I;;;~ OI-IV-16.3.1, "Emergency Power - Diesel Operation".

4.6 Return the Charging Pumps to their normal lineup IAW OI II-3.3.2, "Operating the Charging Pumps" .

.J. 7 Return t!l.e Containment Ventilation System to normal operation IA\v OI II-15. 3 .1, "Containment Ventilation Operation".

4.8 Return the Auxiliary Building Ventilation System to normal operation IAW OI II-17.3.1, "Auxiliary Building Ventilation Operation".

4J 9 Return the Control Room VentL:.ation System to normal operation IAW OI II-17. 3. 2, "Control Room Ventilation Operation".

4.10 Stop the Emergency Control Air Compressor and return the Control Air Syste~

to nor:r.al operation IAW OI V-5. 3 .1, "Control Air System Operation" .

4.11 Open the Containment Control Air Header 1(2)A and 1(2)B Isolation Valves.

11(2l)CA330 12(22)CA330

<ev. 7 Salem Unitl/Unit 2

I 4.2

4.12 4.13

~

Re-establish letdown and charging flow IAW OI II-3.3.l, "Establishing Charging, Letdown and Seal Injection Flow".

Return the Feedwater System to the desired mode of operation IAW ar III-9.3.2, "Feed Pump Operation", and secure the Auxiliary Feed Pumps.

= 1) Refill the Auxiliary Feedwater STorage Tank as necessary.

2) Realign the Auxiliary Feed System for power operation IAW OI III-10.3.l, "Auxiliary Feedwater System Operation".

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 IAW" OI III-13.3.2, "Steam Generator Blowdown - Normal Operation".

4.15 Return the Containment/Plant Vent Radiation Monitor to normal operation IAW the following OI'S:

1) Unit 1 - OI IV-11. 3. 4, "Operation of the Containment/Plant Vent Sampler (Rll/Rl2)"

2) Unit 2 - OI IV-11.3.2, "Operation of Radiation Monitoring System Samplers" 4.16 Return the inlet valves to the Gas Analyzer, from the Reactor Coolant Drain Tank and Pressurizer Relief Tank, to normal by opening the following valves:

1 ( 2 )l-1L9 6 l (2}WL97 1(2}PR18 1(2)PR17 4.17 Drain and refill Boron Injection Ta~k from the Boric Acid Tan~s IAW OI II-4.3.2, "Filling and Venting the Safety Injection 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 Boron concentration is within the Tech Spec limits.

Salem Unit l/Unit 2 Rev. I

I-4.2 4.19 Return the Safety Injection System to normal IAW OI II-4.3.l, "Safety Injection System - Normal Operation".

4.20 Make a visual inspection within the Containment when ectry is permissible.

4.~l After the plant has stablized. in the Hot Standby Condition, sample the Reactor Coolant System for boron concentration.

4.22 Calculate the shutdown margin IAW the Reactor Engineer's Manual to ensure that the reactor is shutdown by >l,6% ~k/k.

4. 2 3 _;;s in.dica ted by plant conditions proceed as follows:

4. 2 3 .1 Take the Unit to Cold Shutdown IAW OI I-3.6, "Hot Sta;-idby to Cold Shutdown" or

4. 23. 2 As authorized by AP-5, withdraw the shutdown banks as follows:

1) Reset the flux rate trip by momentarily taking the RATE MODE 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 SKR B, verifying the breaker does close.

4) Depress the STARTUP pushbutton, on the control console, and verify each Shutdown and Control Rod Step Counters reset to zero.

5) Commence withdrawing Shutdown Bank A, B, C and D, in that order, to their fully withdrawn position.

4.24 Complete Attachment No. 1 and attach it to the Operating Incident Report, AP-6.

Prepared By J .v. Bailey

)/~~~

1-lanager - Sal'em Gerati!1gStati0!1 Reviewed By J.M. Zupko

SORC Meeting No. _5_6_-_7_9_________ Date I;

Salem Unit l/Unit 2 I-4.2

ATTACHMENT NO. l POST SAFETY INJECTION DATA

=~itial

~

Pressurizer Level

=inal Pressurizer Level Initial Pressurizer Pressure _ _ _ _ _ _ _.PSIG Fi~al Pressurizer Pressure _ _ _ _ _ _.PSIG

_ _ _ _ _ _ _0F Initial Tavg

'JF

?i:1al Tavg -------

RWST Temperature (T0650A)

D~ration o: Safety Injection _ _ _ _ _ _ _Min.

=,ecorded By Date Date Senior Shift Supervisor/Shift Super.

Salem Unit l/Cnit 2 Rev. 7

I-4.3 EMERGENCY INS~RlCCTION I-4.3 REACTOR TRIP

l. O PURPOSE 1.1- A reactor trip is initiated automatically by the Reactor Protection System if unsafe operating conditions are approached. It may also be initiated manually from the control console. This instruction provides the actions required to ensure the reactor is in a safe shutdown condition.

1.2 In addition to de-energizing the shutdown and control rod drive mechanisms, a reactor trip signal will initiate a turbine trip and, in conjunction with a low Tavg (554"FI i~itiate a feedwater isolation signal. This instruction delineates the actions required to ensure both of these have occurred.

2.0 INITIAL CONDITIONS 2.1 Any of the following conditions will lead to a reactor trip and to an automatic plant shutdown. The condition causing the trip will be back lighted in red on the first out overhead annunciator panel (Section F) .

REACTOR TRI? SETPOINT COINCIDENCE INTERLOCK

.Lo !vi.anual 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. Intermediate Range, Current equivalent to 1/2 P-10 High Neutron Flux 25% of full pwr.

5. Source Range, High 105 counts per sec. 1/2 P-6 Ir:terlocked Neutron Flux with P-10

6. Overtemperature ~T Variable Setpoint 2/4 None

7. Overpower £1.T Variable Setpoint 2/4 ::Jone

8. Low Reactor 1865 psig 2/4 P-7 Coolant Pressure

9. High Reactor 2385 psig 2/4 None Coolant Pressure

10. High Pressurizer 92% Level 2/3 P-7

~- Low Reactor 90% of Normal Flow 2/3/!.,oop P-7 & ?-8 Coolant Flow

12. Reactor 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 Pump 10% Pwr. 2 Bkr. Open l/Pump P-7 & ?-8 Breaker Open 36% Pwr. 1 Bkr. Open

15. Low Feedwater Flow 1.4 X 10 6 Stm. Flow greater than 1/2 Flow None feedwater flow & 25% S/G level :~isr..atch, in coincidence

<e".'. 4 Salem Unit l/Unit 2

I-4.3 REACTOR TRIP SETPOINT COINCIDE~;cE ~:-;':'E:RLOCK

16. Low-Low Steam 5% Level per S/G 2/3 per S/G ~one Generator Wtr. Lvl.

17. Turbine-Generator 45 psig Auto Stop Oil Pressure 2/3 P-7 Trip or all four Stop Valves Closed 4/4

18. Safety Injection 1. Manual 1/2 ~:one (Actuation)

2. Pressurizer at 17GS psig 2/3

3. Containment at 4./ psig 2/3 High Con- Xone tainment pressure

4. Any one S/G 100 psig lower 1/2 Steam Pressure Xone than any other two S/G's on any S/G Lower than 1/2 Steam Pres-sures on 2/3 of the other loops.

5. Variable: Steam line flow 1/2 Hich Steamflow on ~one 1.4 X 106 #/hr. 0-20% load, 2/4 St~am Gen. i~

increasing to 4.0 X 106 #/hr coincidence with 2/4 at 100% pwr. in coincidence LOK '::.'. *;c or : / 4 low with Low TAVG 543°F or Low steam line pressure.

Stm. Press. 500 psig.

19. General Alarm Logic Train "A" & Train "B" in test simultaneously.

NOTE The General Alarm trip is not alarmed on the first out annunciator.

20. Trip Bypass Bkrs. Racking in, or attempting to rack in, both Reactor Trip Bypass Bkrs at the same time.

NOTE The Bypass Breaker trip is not alarmed on the first out annunciator.

3. D I~~lEDil>.TE ACTIONS 3.l riutomatic J.1.1 Reactor Trip 3.1.2 Turbine Trip 3.1.3 Generator Trip

..3.. 2 Manual 3.2.1 Verify tha: a reactor :rip has taken ~lace:

l) Check that all ful: length rods are fully inserted by ~becking individual rod position indicators and rod bottom lights.

21 If any full length control rod dces not indicate fullv inserted, manually initiate 3 re~c~c~ t~~p.

Salem unit l/unit 2 Rev. 4

I-4.3

3) If all full length control rods are not '..he:-i ;:ully inserted, RAPID BORATE by 150 ppm (approximately 8 minutes) for each rod not inserted IAW OI II-3.3.8, "Rapid Boration".

3.2.2 Verify turbine trip by checking the following:

ll UNIT TRIP light on E/H console illuminated.

2) Turbine Stop Valves, Governor Valves, Interce~tor Valves and Reheat Stop Valves closed.

3) Turbine speed decreasing.

3.2.3 Within 2 minutes reduce Aux. Feedwater Flow to each Stearn Generator to approximately 2.3 x 10" lb/hr.

NOTE This limination applies to Unit No. 1 only.

3. 2. 4 Verify that T is decreasing toward or is beina maintained at 547°F bv avg - -

either steaffi dump or atmospheric steam relief.

3.2.5 Verify that Feedwater Isolation has taken place when T avg decreases to 554°F.

4.0 3.2.6 Announce over the plant PA system twice:

SUBSEQUENT ACTIONS 4.1 UNIT NO. 1(2) REACTOR TRIP.

Check that nuclear power is decreasing by observing the nuclear instrumentation.

11 4.1.1 Check that the Source Range high voltage is reinstated below 5 x l0-amps on both Intermediate Range Channels. This should normally occur in approximately 15-18 minutes on a trip from the power range.

1) If the Source Range high voltage does not energize automatically, manually depress the RESET SOURCE RANGE "A" and RESET SOCRC:S RANGE "3" pushbuttons on the control console.

4.1.2 Switch the Nuclear Power Recorder (NR-45) to read one Intermediate Range channel and one Source Range Channel."

4.1.3 Notify the Performance Department that a reactor trip has occurred and ~hat the compensating voltage on the Intermediate Range detectors should be adjusted. This adjustment is desirable but is not required .

4.2 Verify that the Pressurizer pressure and level are within limits~ and under control.

Salem Unit l/Unit 2 Rev. 4

I-4.3 4.3 Verify that the 4160V Group Busses have transferred from the No. 1(2) Auxiliary Power Transformer to No. 11(12) & No. 12(22) Station Power Transformers.

4.3.1 Check that the following 4160V breakers have opened and acknewledge them on the appropriate control console bezel:

l (2) BGG::>

1(2) BFGD 1(2) AEGD 1(2) AHGD 4.3.2 Check that the following 4160V breakers have closed and acknowledge the~ on 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 547°F due to steam dump operation.

4.4.1 Check the following steam dump indication:

1) Steam dump valve indication

2) Steam dump demand meter .

4.4.2 Transfer steam dump control from the AVERAGE TE~PERATURE CONTROL mode to the MAIN STEAfl PRESSURE CONTROL mode. Ensure that the MAIN STEAM PRESSURE SP (setpoint) is set to maintain the reactor coolant temperature at a no load Tavg temperature of 547°F. (Approxiametly 1005 psig steam pressure).

NOTE If condenser steam dump is not availiable, atmospheric steam relief must be used for the removal of residual heat.

4.5 Verify that Feedwater Isolation has taken place due to the reactor trip in coincidence with low Tavg (554°F).

4.5.1 Check that the following valves have closed by observing their appropriate bezel indication:

11 (21) BF19 Feedwater Control Valve 12(22)BF19 Feedwater Control Valve 13 ( 23) BF19 Feed water Control Valve 14(24)BF19 Feedwater Control Valve 11(2l)BF40 Feedwater Bypass Valve 12(22)BF40 Feedwater Bypass Valve 13(23)BF40 Feedwater Bypass Valve 14(24)BF40 Feedwater Bypass Valve Salem Unit l/Unit 2 Re\'. 4

I-4.3 4.6 Return the levels in the Steam Generators to normal (~ 33%) as follows:

4.6.1 Limit the rate of rise to less than 1.2 in/min whenever level is below 10% on the Narrow Range.

~ 4.6.2 Monitor the following computer points and maintain the rate,of rise to

< 0.8%/Min on the narrow range and < 0.2%/rein. on the wide range.

S/G Na:crow Rang:e Wide Range 1".(21) L0400A or L0401A or L0402A L0403A 12 ( 22) L0420A or L0421A or L0422A L0423A 13 (23) L0440A or L0441A or L0442A L0443A 14 ( 24) L0460JI. or L0461A or L0462A L0463A NOTE If the computer is not available, monitor the narrow range indication on the Control Console and the Wide range recorders on RP-4.

4.6.3 Control Flow to the Steam Generators as required by controlling the following valves .

1.

2.

ll-14(12-24)AF11 if No. 13(23) Auxiliary Feedwater Pump is in operation.

11-14 ( 21-24) AF21 if No. 11 Pumps are in operation.

& 12 ( 21 & 22) Auxiliary Feedwater

~.7 Establish and maintain the Hot Standby condition IAW OI I-3.5, "Minimum Load to Hot Standby" and or I-3. 8 I "Maintaining Hot Stanqby".

4.3 If Rx trip was from >15% Rx Power, have the Chem. Dept. perform an r 131 , r 133 , r 135 Isotopic analysis between 2 and 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months following the Rx trip.

4.9 Obtain a sample of the Reactor Coolant System and determine boron concentration.

Adjust boron concentration as required IAW OI II-3.3.6, "Boron Concentration Control".

4.10 As per Administrative Procedure No. 5:

4.10.1 Notify the Station Operating Engineer or Chief Engineer of the reactor trip and; 4.10.2 Initiate an Operational Incident Report IAW AP-6 and forward it to the station Operating Engineer.

4.11 If, at this time, it becomes necessary, take the plant to the Cold Shutdown condition IAW OI I-3.6, "Hot Standby to Cold Shutdown".

Salem Unit l/Unit 2 -:::- Rev. 4

I-4.3 4.12 As authorized by AP-5, withdraw the shutdown banks as follows:

4.12.1 4 .12. 2 Reset the flux rate trip by momentarily taking the RATE ~ODE switches, on each NIS POWER RANGE A drawer, to the RESET position.

Depress the CLOSE pushbutton, on the control console, for ~EACTOR TRIP 3KR A, verifying the breaker doese close.

4.12.3 Depress the CLOSE pushbutton, on the control console, for REACTOR TRI? 3KR 3, verifying the breaker does close.

4.12.4 Depress the STARTUP pushbutton, on the control console, and verify each Shut-down and Control Rod Step Counter resets to zero.

4.12.5 Conunence withdrawing Shutdown Bank A, B, C and D, in that order, to thei~

fully withdrawn position.

4.13 When the cause of the trip has been determined and corrected, obtain the permission 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 conunencing the recovery startup, perform the following:

4.14.1 Place the Steam Generator Feedwater Controls in MANUAL and r~n the valve demand to zero.

4.14.2 Reset the Feedwater Isolation signal by depressing the Train "A and Train "B" FEEDWATER ISOLATION RESET pushbuttons on the control console.

4.14.3 Maintain Stearn Generator levels within their normal 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 normal at power lineup IAW OI III-10.3.1, "Auxiliary Feedwater System Operation".

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~*~Vc.__:..*_::B~a~1~*1==e~y~~~~~-

Reviewed by~~~~J_._P~*~K_o~v_a_c__::cs~o~f~s~k:..=.oty~~~

SORC Meeting No.~~~5~6~-_7L..J.9~~~~~~~~

Salem Unit l/Unit 2 Rev. 4

I-4.4 EMERGENCY INSTRUCTION I-4.4 LOSS OF COOLANT (LEAKAGE GREATER THAN MAXIMUM CHARGING FLOW) 1.0 PURPOSE 1.1 This instruction provides the necessary operator actions required to provide maximum core cooling to minimize core damage following a loss of coolant acciden~.

1.2 This instruction contains 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 includ~s the appropriate operator actions required to cope with the following failures.

1.3.1 Loss of a Residual Heat Removal Pump due to either 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 Injection Initiation" that a loss of coolant accident has occurred.

3.0 IMMEDIATE ACTIONS

~

3.1 Verify that all Immediate and Subsequent Actions described in EI I-4.0 ~ty Injection Initiation" have been performed. Complete any actions which~e not been previously completed. -0:~

~ ff 3.2 If Containment pressure reaches the Hi-Hi Setpoint of 23.5 psig-~ify the following automatic actions have taken place by observing t~~c~tions on the status panel on RP-4. ~~v 9~

3.2.1 Containment Spray Actuation

~~- -

~

3.2.2 Containment Phase "B" Isolation 3.2.3 Main Stearn Isolation Salem Un~t l/Unit 2 Rev. 8

I-4.4

3. 3 If Containment Phase "B" Iso-1;, '.:~.on is actuated, trip all Reactor Coolant Pumps within five minutes.

4.0 SUBSEQUENT ACTIONS - PART I - COLD LEG INJECTION

-4 .1 Check the following indicators on the control console to ensure porated water is being injected into the Reactor Coolant System.

4.1.1 Boron Injection Tank Pressure indicating RCS Pressure.

4.1.2 Charging Pumps Discharge Flow 4.1.3 No. 11(21) Safety Injection Pump Discharge flow when RCS pressure is

< -u 1500 psig.

4.1.4 No. 12(22) Safety Injection Pump Discharge flow when RCS pressure is

< "' 1500 psig.

4.1.5 No. 11(21) RHR Injection F1ow 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 ?Sig, 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.

No. 11(21) Containment Spray Pump No. 12(22) Containment Spray Pump

b. Check that the following valves have opened. !f a valve fails to open, attempt to open manually from the control console.

11(2l)CS2 Spray Pump Discharge Valve

~

12(22)CS2 Spray Pump Discharge Valve 1(2)CS16 1(2)CS17 Spray Additive Tank Discharge Valve Spray Additive Tank Discharge Valve ~

~~

c. Check the Additive Tank indicator on the control con~~ensure that ~he sodium hydroxide (NaOH) solutio~ is be~ing ~~ted i~to the Containment Spray System. If the level is not ~~ng, dispatch an operator to verify the level locally and ~~~ e the following mechanical valves are open. ~~

11(2l)CS20 Eductor Supply Valve ~

12 (22) CS20 Eductor Supply Valve '\~

Salem Unit !/Unit 2 Rev. 8

I-4.4 PART I 4.2.2 Isolation Phase "B" has taken place

a. Check to see that the following valves have closed by observing the status panel and ~cknowledge on the appropriate contr~l console bezel.

1. If any valve has failed to close, attempt to closa it from the control console bezel.

Component Cooling 1(2)CC117 Reactor Coolant Pump Motor Cooling 1(2)CC118 Reactor Coolant Pump Bearing Inlet 1 (2) CC136 Reactor Coolant Pump Bearing Outlet 1(2)CC131 Thermal Barrier Discharge 1(2)CC190 Thermal Barrier Discharge 1(2)CC187 Reactor Coolant Bearing Outlet

2. If any Reactor Coolant Pumps are running, they must be tripped at this time.

4.2.3 Main Steam Isolation has taken place.

a. Check that the following valves have closed by observing the status panel and acknowledge on the appropriate control console bezel. If any valve has failed to close, attempt to close it from the control console bezel.

11(2l)MS167 No. 11 (21) Steam Generator Stop Valve 12(22)MS167 No. 12(22) Steam Generator Stop Valve 13 (23) MS167 No. 13 (23) Stearn Generator Stop Valve 14(24)MS167 No. 14(24) Stearn Generator Stop Valve 11 (21) MSlB No. 11 (21) Steam Generator Stop Warmup Valve 12 (22)MS18 No. 12(22) Stearn Generator Stop Warmup Valve 13 (23)MS18 No. 13(23) Steam Generator Stop Warm up Valve 14 (24)MS18 No. 14 (24) Stearn Generator Stop Warmup Valve 11 (2l)MS7 No. 11 (21) Stearn Generator Drain Valve 12(22)MS7 No. 12 (22) Steam Generator Drain Valve 13 (23) MS7 No. 13(23) Stearn Generator Drain Valve 4.3 14 (24) MS7 No. 14(24) Stearn Generator Drain Valve Commence taking the plant to Cold Shutdown Conditions by cooling down __

~

e-'?-~~~ws:

.- ~

4.3.l Manually control the Auxiliary Feedwater Control valves (~~ maintain Steam Generator Levels at approximately 33%. - ~~~

<f'i~~

NOTE -?~~

~~;)

If No. 13(23) AFW Pump is running, ~wi~

be necessary to control the AFll \~~-

Salem Unit l/Unit 2 Rev. 8

I-4.4 PART I 4.~.2 ~eriodically, reduce the pressure setpoint of the Main Steam Pressure Controller by depressing the SETPOINT DECREASE pushbutton. This action will increase steam flow thereby continuing the cooldown.

NOTE If steam dump to the condensers is not available, periodically reduce the pressure setpoint of the pressure controller for each MSlO valve by de-pressing their respective PRESS SET PT DECREASE pushbuttons. This action will increase steam flow thereby continuing the cooldown.

4.3.3 As applicable, utilize the following Operating Instruction to take the plant to Cold Shutdown conditions:

OI I-3.6, "Hot Standby to Cold Shutdown" 4.3.4 If the Prodac 250 Computer is available, initiate CRT Test No. 41, "Core Temperature/Pressure Monitor Program".

4.4 If Reactor Coolant Pressure stabilizes above the shutoff head (~ 180 psig) of the Residual Heat Removal Pumps, proceed as follows:

4.4.1 Reset Safety Injection by depressing both Train "A" and Train "B" SI RESET pushbuttons on the Safeguards Actuation Bezels on the control console.

NOTE Automatic Actuation of Safety Injection will no longer be available. Any subsequent actuation of Safety Injection must 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 ~~

~::::~~:n:e:~::~d~i~~:l~i::~ :::::~ :o:~:c::ut ~~~

stripped and the blackout loads would be sequenced r-:--~

on by the SEC. The RHR, Safety Injection, and ~~~

Co~tai~ent ~pray Pumps and the Containment Fan~~~

Coil Uni ts will not be restarted. ~hese must ('f:,,~....,

be manually restarted once the Loading Sequ;,~,~

is complete as indicated by the "LOADING~,~

COMPLETE" lights on the lA, lB, lC (2A, 2~)

Diesel Bezels on the control console~

~~

Salem Unit l/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 which may result in equipment damage.

4.4.2 Reset the Safeguards Loading Sequence by depressing the EMERGENCY LOADING RESET pushbuttons on the control console for lA, lB, and*1c

- (2A, 2B, and 2C) Diesel Generators 4.4.3 Stop No. 11 & 12(21 & 22) Residual Heat Removal Pumps.

CAUTION If Reactor Coolant Pressure decreases to below the shutoff head (~ 180 psig) for the Residual Heat Removal Pumps, restart the pumps.

4.4.4 Operate the Safety Injection Pumps as required to maintain pressurizer level between 20% and 90%.

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:

a. Stopping the Emergency Diesel Generators IAW OI IV-16.3.1, "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:

4.5.1 Reset Safety Injection by depressing both Train "A" and Train

~

~~I RESET Pushbuttons on the Safeguards Actuation Bezels on t~~~Oj ol console. , ~~;::;,

~~

4

. NOTE ~-,?>

Automatic Actuation of Safety Injection ~~~

no longer be available. Any subsequ~t?~~atiofi of Safety Injection must be accompli: . ~anually by inserting the Safeguards Key i~ e ther Train "A" or Train "B" OPERATE on t~~guards Actuation Bezel, ~~

Salem Unit l/Unit 2 Rev. 8

I-4.4 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 not be restarted.

These must be manually restarted once the Loading Sequence is complete as indicated by the "LOADING COMPLETE" lights on the lA, lB, lC (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.

4.5.2 Reset the Safeguards Loading Sequence by depressing the EMERGENCY LOADING RESET pushbuttons on the Control Console for lA, lB and lC (2A, 2B, 2C)

Diesel Generators.

4.5.3 Reset Containment Spray, if Containment pressure is less than 23.5 psig on 3/4 channels, by depressing Train "A" and Train "B" SPRAY ACT RESET pushbuttons _on the Safeguards Actuation 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 required.

NOTE

~~

If a loss of offsite power has occurred in coincidence with the LOCA, align the &))

Electrical System in accordance with ~~

Appendix A, prior to proceeding with Parts ((-_~~

II or III of this procedure. /) ~~

~v 4.6 Proceed to Section 5.0, Part II - Cold Leg Recirculati~~

Salem Unit l/Unit 2

~

Rev. 8

I-4.4

'T II 5.0 SUBSEQUENT ACTIONS - PAKi' .i. .i. * -..u.uu **".:.G RECIRCULATION CAUTION 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) SJ4 0 11 (21) SI Pump Disch Valve to Hot Leg 12(22)SJ40 12(22) SI Pump Disch Valve to Hot Leg 11 (21) SJ113 SI Chg Pumps X-Over Valve 12(22)SJ113 SI Chg Pumps X-OVer Valve 11(2l)SJ45 Recirc I sol Valve to SI Pump 11(2l)CS36 From 11 (21) RHX Valve 12(22)CS36 From 12 (22) RHX Valve 1(2)RH2 RHR Common Suction Valve 1(2)RH1 RHR Common Suction Valve 11 (21) SJ44 SIS Sump Valve 12(22)SJ44 SIS Sump Valve 1(2)RH20 RHX Bypass 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(2l)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.l CC16RHR Heat Exhanger Outlet Valves.

c$~

-s .4 When the RWST Low Level Alarm actuates at 14.1 feet (132,000 gals.), sto~e following pumps if they are running. --~

No. 11(21) RHR Pump *~~;Y

-~S>

No. 12(22) RHR Pump No. 11(21) CS Pump or No. 12(22) CS Pump, if contai~ent s~~tuation has occurred.

~~

~

Salem Unit l/Unit 2 Rev. 8

I-4.4 PART II

One cs NOTE 1 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 Safety 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 He~der 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 .

5.5 Close 11(2l)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) RHR Pump is available.

NOTE 11(2l)RH4 must be closed in order to open 11(2l)SJ44. 12(22)RH4 must be closed.in order to open 12(22)SJ44.

5.7 Remove the lockout and open 11(2l)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 available.

5.9 Close 11(2l)RH19 RH Heat Exchanger Outlet Valve.

5:-10 Close 12(22)RH19 RH Heat Exchanger Outlet Valve 5.11 Start No. 11(21) RHR Pump.

Salem Unit l/Unit 2 -B- Rev. 8

I-4.4 PART II

5.12 5.13 Maintain 3,000 gpm on COLD LEG INJECTION 11(2l)SJ49 flow 11 (21) RH18.

Start No. 12(22) RHR Pump.

me~_ by adjusting

5;..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)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 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.

5.17 Open 11(2l)SJ45 Recirc Isolation Valve to SI Pump**, if No. 11(21) RHR Pump is available.

NOTES

To open 11(2l)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) 11(2l)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 5.J.8 Open 11(2l)SJ113 SI Charge Pumps X-Dver Valve.

5.19 Open 12(22)SJ113 SI Charge Pumps x-over Valve .

5.20 5.21 Close 1(2)SJ1 RWST to Charge Pump.

Close 1(2)SJ2 RWST to Charge Pump.

Salem Unit l/Unit 2 Rev. 8.

I-4.4 PART II

5.22 5,,.23 Verify that No. 11(21) SI Pump is operating properly by observing No. 11(21) SI Pump discharge pressure indicator and No. 11(21) SI Pump discharge flow indicator.

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 dischar~e flow indicator.

s" 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.

NOTE If Containment Spray 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 Pump or No. 12(22) Containment Spray Pump, whichever pump is still running.

NOTE

1. Both Containment Spray Pumps should be idle at this time.

2. If Containment pressure has not decreased to below 23.5 psig, the Containment Spray Pu.~ps cannot be stopped from the control console. To stop the pumps, it will be necessary to ~rip the breakers locally on the lA and lC (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(2l)SJ49 if ~

No. 12(22) RHR Pump is not available]. ~~

0.-~

5.28 Open the following Containment Spray Valves:

~~

""~

,r ~

12(22)CS36 [11(2l)CS36 if No. 12(22) RHR Pump is not available]. ~!)

5.29 Close the following Containment Spray Valves:

11(2l)CS2 12(22)CS2 ~)

-~~

~~"

/?~~

Salem Unit l/Unit 2 ~~ Rev. 8

I-4.4 PART II 5.29.1 Continue Spray operation for a minimum period of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months in order to assure Containment integrity and removal of airborne fi~sion products from the Containment atmosphere.

NOTE The Emergency Core Cooling System is now aligned for Cold Leg Recirculation as follows:

1) RHR Pu.~p No. 11(21) is supply water from the Containment Sump directly to RCS loop 11(21) and 13(23) Cold Legs via valve 11(2l)SJ49 and to the suction of the Safety Injection Pumps through valve 11(2l)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 Charging Pumps through valve 12(22)SJ45.

5.30 Close the following Accumulator Isolation Valves, if the Accumulator pressure is indicated to be less than 250 psig .

11(2l)SJ54 12(22)SJ54 13(23)SJ54 14(24)SJ54 No. 11(21) Accumulator Tank Outlet Valve No. 12(22) Accumulator Tank Outlet Valve No. 13(23) Accumulator Tank Outlet Valve No. 14(24) Accumulator Tank outlet Valve 5.31 Closely monitor the Containment H concentration on RP-5. When the concentration 2

exceeds '\, 2%, place the Hydrogen Recombiners in service IAW OI II-15.3.1, "Hydrogen Recombiners - Normal Operation".

Salem Unit l/Unit 2 Rev_._8

I-4.4 PART III

~ 6.0 SUBSEQUENT ACTION - PART III - HOT LEG RECIRCULATION After approximately 22.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months of cold leg recirculation, realign the Saf~ty Injection System for Mot Leg Recirculation. The sequence for the changeover from Cold Leg, Recirculation to Hot Leg Recirculation is as follows:

NOTE If a loss of offsite power has occurred in coincidence with the LOCA and one of the Diesel Generators has failed to start, refer to Section 4.0 of Part 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(2l)SJ49 Low Head SJ Stop Valve.

6.5 Stop No. 11(21) Safety Injection Pump.

6.6 Close 11(2l)SJ134 SI Pump Discharge to Cold Leg.

6.7 Open 11(2l)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.

~\~

6".12 Open 12(22)SJ40 SI Pump Discharge to Hot Leg. 0.~

-0.13 Start No. 12(22) Safety Injection Pump. ""~?

6.14 Verify that No. 12(22) Safety Injection Pump is ope~'f ;rope_;r::-ly by observing

/; >

No. 12(22) SI Pump discharge pressure and flow i~c- rs (a pressure of 175 to 1520 psig and an approximate flow of 400 gpm sh~~~e indicated)

s v

~-~

Salem Unit l/Unit 2 Rev. 8

I-4.4 PART III 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) RHR Pump is supplying water from the Containment Sump to the Reactor Coolant System through RCS loops 13(23) and 14(24) Hot Legs and to the suction of the Centrifugal Charging Pumps.

3)

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.

SORC Meeting No.~~~~~~~~~~~~~

i::,, l "'m n,.., i t- 1 /n,.., it- 2 I-4.4 APPENDIX A If a loss of offsite power has occurred in coincidence with the LOCA, the Di~sel Generators will be supplying power to the vital busses. During the recirculation phase, it 1s necessary to run the Co~onent Cooling Pumps and the Hydrogen Recombiners. In order to accom9date this additional load, cft.her equipment must be stopped before the Component Cooling Pumps and Hydrogen Recombiners are sta'rted to prevent overloading the Diesel Generators.

After the Safety Injection and SEC are reset, proceed with the appropriate section.

I - ALL DIESEL GENERATORS OPERATING 1.0 Stop the following equipment:

NOTE Do no~ stop both 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 Equipment on 1A(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. 11 (21) Switchgear Room Supply Fan

d. No. 11 (21) Chiller 1.2 Equipment on 1B(2B) Vital Bus (powered by 1B(2B) Diesel/Generator)

a. No. 12(22) Containment Fan Coil Unit

b. No. 14(24) Containment Fan Coil Unit

~

1.3 Equipment on 1C(2C) Vital Bus (powered by 1C(2C) Diesel/Generator) <>~

~~

a. No. 12(22) Containment Spray Pump <'::~

-':">~

No. 11(21) Auxiliary Building SUp?lY Fan

~~~

2.0 Start the following equipment:

<<-~~

~' ~~

CAUTION ,/"~.

~~)

Wnen entering Cold Leg Recirc. start on~one Component Cooling Pump. Ensure ~~ponent Cooling P~ to be started is en~~~d from the same V~taL Bus as was the C-0ntainment Spray Pump, secured from in the above step.

Salem Unit l/Unit 2 Page 1 qf 6 Rev. 8

I-4.4 E~~~~ment on lA(2A) Vital Bus (powered by lA(2A) Diesel/Generator)

2.2 a.

a.

No. ll Component Cooling Pump or Equipment on lC(2C) Vital Bus (powered by lC(2C)

No. 13(23) Component Cooling Pump Diesel/Generator)~

NOTE If irradiated fuel is stored in the Fuel Handling Building, start No. ll & 12 (21 ' 22) FHB Exhaust Fans.

3.0 Open ll(2l)SW122 and l2(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 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 l.2 Equipment on lC(2C)_ Vital Bus (powered by 1C(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 3.1. The following pumps should be running:

a. No. 12(22) RHR Pump

b. No. 12(22) Charging Pump

c. No. 12(22) Safety Injection Pump

d. No. 12(22) Containment Spray Pump, until RWST Low-Low level alarm actuates.

Salem Unit l/Unit 2 Page 2 of.6 Rev. 8

I-4.4

- 3.2 3.-3 Close valves 12(22)RH19 and 12(22)SJ49 to prevent flow to the Cold Legs 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 Containment Spray Header through 12(22)~S36 when it is opened.

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)SJ113, 11(2l)SJ33 and 12(22)SJ33.

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.

d. 12(22) Containment Spray Pump taking suction from the 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 4.3 4.4 Stop No. 12(22) Safety Injection Pump and No. 12(22) Charging Pump.

Close 12(22)SJ134 and 1(2)SJ135 to isolate Cold Leg Recirculation.

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 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)SJ113, 11(2l)SJ33 and 12(22)SJ33.

b. No. 12(22) Safety Injection Pump discharging through 12(22)SJ40 to~~l & 12 (21 & 22) Hot Legs. --~~

~,~~

re~~~

III - ~AILURE OF 1B(2B) DIESEL GENERATORS 1.0 Stop the following equipment:

. ~-~->

~) .

~

Do not stop both 11 (21) and l~~ontainment Spray Pum.1:-*s until the RWST LOW~= level alarm actuates. When entering Cold Leg Recirc., stop only No. *.2 (22) Containment Spray Pump.

Rev. 8

I-4.4

l. l Equipment on l.A(2A) Vital Bus (po~*s..:-ed by 1A(2A) Diesel Generator)

a. No. 11(21) Containment Spray Pump when RWST Low-Low level alarm actuates.

l. 2 Equipment on lC (2C) Vital Bus (powered by lC (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(2l)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 Recirculation:

3.1 The following pumps shoul.d be running:

a. No. 11(21) RHR Pump

b. No. 12(22) Charging Pump

c. No. 11(21) Safety Injection Pump

d. No. 11(21) Containment Spray Pump, until RWST Low-Low level alarm actuates.

3.2 Close valves 11(2l)RH19 and 11(2l)SJ49 to prevent flow to the Cold 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(2l)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) Safety Injection Pump~hrough ll(2l)SJ45, ll(2l)SJ113, ll(2l)SJ33 and ll(22)SJ33. "'-~~

b. No. 12(22) Charging Pump discharging through the Boron Injection ~~~l four Cold Legs. 4,.._~ $)~

c. No. 11(21) Safety Injection Pump discharging through 11'}~~~ and 1(2)SJ135 to all four Cold Legs. ,., ~v

~*~->

d. No. 11(21) Containment Spray Pump discharging to tsh~ray Heading, until RWST Low-Low level alarm actuates. '~

4.0 Proceed as follows for Hot Leg Recirculation: ~~

4.1 Close ll(2l)CS36 to stop Containment Spray.

Salem Unit l/Unit 2 Page 4 of.6 Rev. 8

I-4.4 4.2 Stop No. 11(21) Safety Injection Pump .

4.3 4.4 4.5 Close 11(2l)SJ134 to isolate Cold Leg Recirculation.

Open 11(2l)SJ40 to supply Hot Leg Recirculation.

Start No. 11(21) Safety Injection Pump.

~

4.6 The Hot Leg .Recirc:ul.ation Flow Path would be as follows:

a. No. 11(211 .RHR Pmnp taking suction on the Containment Sump and discharging to the suction of No. 11(21) Safety Injection Pump through 11(2l)SJ45, 11(2l)SJ113, 11(2l)SJ33, and 12(22)SJ33.

b. No. 11(21) Sa£ety Injection Pump discharging through 11(2l)SJ40 to No. 13 & 14 (23 ' 24) Hot Legs.

c. No. 12(22) Charging Pump discharging to all RCS Cold Legs.

IV - FAILURE OF 1C(2C) DIESEL GENERATOR 1.0 Stop the following equipment:

1.1 Equipment on 1A(2A) Vital Bus (powered by 1A(2A) Diesel/Generator) a.

b.

No. 11(21) Containment Spray Pump, when RWST Low-Low level alarm actuates.

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 11(2l)SW122 to provide Service Water to Component Cooling.

NOTE If irradiated fuel is stored in the Fuel Handling Building, start No. 11 & 12 (21 & 22) FHB Exhaust Fans.

3.0 'i"Jie following should be the alignment for Cold Leg 3.1 The following pumps should be running:

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 actuates.

Salem Unit !/Unit 2 Page 5 of 6 Rev.B

I-4. 4 3.2 Close valv~s 11(2l)RH19 and 11(2l)SJ49 to prevent flow to the Cold Legs and to insure

3.3 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 ll(2l)CS36 when it is opened.

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. 11(21) Charging Pump and No. 11(21) Safety Injection Pump through 11(2l)SJ45, 11(2l)SJ113, 12(22)SJ113, 11(2l)SJ33, and 12(22)SJ33.

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 11(2l)CS36 to stop Containment Spray .

4.2 4.3 4.4 Stop No. 11(21) Safety Injection Pump.

Close 11(2l)SJ134 and to isolate Cold Leg Recirculation.

Open 11(2l)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 Pump~ough 11(2l)SJ45, 11(2l)SJ113, 12(22)SJ113, 11(2l)SJ33, and 12(22)SJ33. '~ ~

~~

b. No. 11(21) Safety Injection Pump discharging through 11(2l)SJ40 to,-:--~~~ & 14 (23 & 24) Hot Legs. ~,~

c. No. 11(21) Charging Pump discharging to all RCS Cold

-'~v Legs.~.~.~~-

<f~~

s.o Transfer the Security System to the emergency power supply on lA ~~ital Bus.

~~, -

~

~~

Salem Unit l/Unit 2 Page 6 of 6 Rev."*B

I-4.5 EMERGENCY INSTRUCTION I-4.5 LOSS OF REACTOR COOLANT PUMP AND/OR FLOW 1.0 DISCUSSION l.l 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) on the 4kV group busses which supply power ~o the Reactor Coolant Pump Th~tors, or Reactor Coolant Pump motor supply breakers opening 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 protection.

However, the reactor must never be critical or brought critical with less than two Reactor Coolant Pumps in operation. From P-7 to P-8" (10% to 36% power) three Reactor Coolant Pumps are required and when the P-8 interlock is in effect (above 36% power) fo'lr 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 Lo5s 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 more reactor coolant loops.

2. One or more Reactor Coolant Pump breakers indicating a tripped condition.

PART I I LOSS OF REACTOR COOLANT WITH A REACTOR TRIP 3.0 (I)- IMMEDIATE ACTIONS Automatic

1. Reactor Trip

2. Turbine Trip and Generator Trip Manual Refer to EI I-4.3, "Reactor Trip".

Salem Unit l/Unit 2 Rev. 3

-- :css CF REA:~O? c~c~~~T FLOW ~ITHO[~ A REACTO~ 7R~?

l:: I)

.ess tha~ P-7 ( 10'

4. SCES~QUE~T ACTIONS If 3teac Ge~erator le?el is err~tic in the affe~ted lcop(s), take manual co~trol

( :1, 2 2, 23,

!:::;~:_--*:..: =,

_:.:-s3l.D.!.e, I.:--..~\" G: II-l.3.1, 11 Reac:.o!'" Coola:-~t r~:-:-1p Ope!'"atior... "

1 - ~~~Reactor Coclant ?~me .cannot be returned tc ser":ice, per~~r~ e:~~e= s~e~

2 er s~e? b below:

_:-. ..= -:::-*.:-::..:..: :-. , .. . ._ - - -* -**- -

QI :-3.8, Maintai~ing Hot Stan~by 11 o: I-3.6, "not StandCy ~o Cold Sh*.1-:.dc*.-.rn 11 l")-. J.V. Bailey J.P. Kovacsofsky 053-79 Sale::-, :<a*:.

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 2.0 B. Failure of a Single Diesel k:~

~~

INITIAL CONDITIONS ('~

-,<:~

2.1 Safety Injection has been initiated and it has been determined by~f Section 5.0, "Identification of Follow-up Actions" of EI I-4.0, "Safet~y.ction Initiation"

~-

that a loss of secondary coolant has occurred. ~

/)~~~-

~,

3.0 IMMEDIATE ACTIONS 3.1 Verify that all Immediate and Subsequent Actions d~ed in EI I-4. O, "Safety Injection Initiation" have been performed. Compl ~ actions which have *not been previously completed.

Salem Unit l/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 Stearn 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 console 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) MS167 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 11 (21) MSlB No. 11 (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)MS18 No. 14(24) Steam Generator Stop Warmup Valve 11 (2l)MS7 No. 11(21) Steam Generator Drain Valve 12(22)MS7 No. 12 (22) Steam Generator Drain Valve 13 (23) MS7 No. 13(23) 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. I f it is not initiated, manual initiation should be accomplished by depressing the Main Stearn

~~

Line Isolation pushbutton for each steam line on either the Train "A" or Train "B" Safeguard bezels.

Check the following indications on the control console to ensure borat~~er is being injected into the Reactor Coolant System. ,,~ '})~

4.2.1 Boron Injection Tank Pressure indicating RCS Pressur~. <!::-~~~

4.2.2

.// ~--~

tj~

Charging Pump discharge flow.

~>

4.2.3 No. 11(21) Safety Injection Pump discharge ~~en RCS Pressure is

< "' 1500 psig. ~~~v Salem Unit l/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 above the shutoff head ("- 180 psig) for the Residual Heat Removal Pumps, therefore, these pumps will be running on recirc.

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. ~f a pump fails to start, attempt to start if manually from the control consol~

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(2l)CS2 Spray Pump 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.

11(2l)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 observing the sta~~nel and acknowledge on the appropriate control console bezel. If ~~~ve has failed to close, attempt to close it from the control cons~'$bezel.

<~

1(2)CC117 Reactor Coolant Pump Motor Cooling -~.~"\j~

1(2)CC118 Reactor Coolant Pump Bearing Inlet ~~

1(2)CC136 Reactor Coolant Pump Bearing Outlet _(;~,

1(2)CC131 Thermal Barrier Discharge ,~~v 1(2}CC190 Thermal Barrier Discharge ~

1(2)CC187 Reactor Coolant Bearing Outlet ~ >

~+

Salem Unit l/Unit 2 Rev. 7

I-4.6 PART I B. If any Reactor Coolant Pumps are running, they ~ust be tripped at this time.

4.4 Verify the RHR Pumps are operating on recirc by insuring the associated RH-29, RHR Pump Recirc, 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 lA, lB, 1C(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 Stearn Isolation has occurred.

4.5.1 Downstream of the Main Stearn Isolation Valves:

A. Steam flow on all lines should indicate zero and all Stearn Generator pressures should be stabilized at approximately the same pressure.

B. Proceed to Subsequent Action Step 4.6.

4. 5. 2 Upst.rearn of the Main Stearn Isolation Valves. (This includes the Main Feed-water Header downstream of the BF-22 valves, and the blowdown lines up~earn of the GB-4 Containment Isolation Valves). <:'-.~ ~

~~~

A. One Stearn Generator will have a decreasing pressure. This,~~ faulty

\~;;~

Stearn Generator.

B. Isolate Auxiliary Feedwater to the affected Ste~~.~~tor by closing the flow control valves_' AFll and AF21, to the af~e~~~earn Generator .

. ~~

\~

Salem Unit l/Unit 2 Rev. 7

I-4.6 "PART

--**.~

c.

D.

If the rupture is inside the containment as indicated by an increase in containment temp,erature and pressure, proceed to Subsequent Action Step 4.8.

If the rupture is outside the containment, there should 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 CRT 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 TH is ~ 350°F as read on the Wide Range Temperature Recorders on RP-4, AND,

2. Reactor Coolant pressure is increasing, AND,

3. Pressurizer level is > 20% on at least 2/3 Hot Calibrated channels and is increasing.

-OR-B. 1. All four TH are > 350°F as read on the Wide Range Temperature Recorders on RP-4, AND,

2. Reactor Coolant Pressure is > 2000 psig and is stable or increasing, AND,

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, AND,

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 Coolant temperatures increase to > 350°F, maintain the Safety Injection Pumps in operation until all

<':-~

.~-*-~

criteria for "B" above are satisfied.

~~~

follow~~

4.7.1 Reset the safeguards actuation. by performing the (F~'>>

a. Reset the Safety Injection signal by depressi~i~~rain "A" and Train "B" SI RESET pushbuttons on the safeguards a~~j.on bezels on the control console. ~ ~

~~$>

Salem Unit l/Unit 2 -s- 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, lB and lC (2A, 2B and 2C) Diesel Generators.

c. Reset the Phase "A" Containment Isolation by depressing both CONT ISOL

~A 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 Train "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. B If the Prodac 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 o~

Safeguards Actuation Bezel on the control console. ~~

4.9.2 Closely monitor RWST Level. As is approaches the Low-Low~--;;~~Alarm (O.O feet, 0.0 gallons) prepare to change from Cold Leg Inje~~?!': Cold Leg Recirculation. Proceed as follows.

~~

~~~

""~'>

a. Reset Safety Injection by depressing both Tr.a~~" and Train "B" SI RESET pushbuttons on the Safeguards Actuation B~~ :>>n the control console.

"~~

~~

~~~

Salem Unit l/Unit 2 Rev. 7

I-4.6 PART I

NOTE Automatic Acutation of Safety Injection will no longer be available. Any subsequent actuatio~

of Safety Injection must be accomplished manually by inserting the Safeguards Key into either Train "A" or Train "B" OPERJ\.TE on the Safeguards 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 not be restarted. These must be manually restarted once the Loading Sequence is complete as indicated by the LOADING COMPLETE lights on the the lA, lB, lC (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, lB, lC (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, "Re~v~ ~from Safety I~jection" for guidance in returning additional ~up o~t'~stems to operation as required to accomplish the subsequent cool YProceed to Subsequent Action Step 4.10 of this instruction. ~0....*~

(F~~>

e. If containment pressure is > 5.0 psig, proceed ~c("~~~ion 5.0 of this instruction, "Subsequent Actions Part II - C~W,Leg Recirculat.ion".

~~~

~1)>

Salem Unit l/Unit 2 Rev. 7

_J

I-4.6 PART I

NOTE If a loss of offsite power has occurred in coincidence with the Stearn Line Rupture, align the Electrical System in accordance with Appendix A, prior to proceeding to Part II of this Procedure.

4.10 Restart the following ventilation fans and pump room coolers:

4.10.1 Nozzle support fans*

4.10.2 Reactor shield vent fans*

4.10.3 Control rod drive fans*

4.10.4 No. 11 & 12 (21 & 22) RHR Pump Room Coolers 4.10.5 No. 11 & 12 (21 & 22) Charging Pump Room Coolers.

4.10.6 No. 1(2) Aux Feed Pump Room Cooler.

NOTE

The breakers for these fans must be reset manually to start the fans.

4.11 When conditions permit, return the 4kV Vital Busses to normal 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 cooling 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, redu~\

the pressure setpoint of the controller for each MSlO Valve by depress~~heir PRESS SET PT DECREASE pushbuttons. . ~

4.12.2 If the rupture is upstream of the main steam line isolation var-It~ cool down using the steam dump to the condenser as follows: ~~>>

~

a. ~:::,~~e0:y::::*u::~;:;t~s~::.:r::::r:.:::r~in Ste'l"'~~tion Valves

~~~

b. When pressure equilizes, open the main~~ation valves Salem Unit l/Unit 2 Rev. 7

I-4.6

~'ART I

4.12.3

c. Place the steam dump in the MAIN STEAM PRESSURE CONTROL mode and periodically reduce the setpoint by depressing the SETPOING DECREASE pushbutton.

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" Salem Unit l/Unit 2 Rev. 7

I-4.6 PART II

5.0 SUBSEQUENT ACT-IONS - PART II - COLD LEG RECIRCULATION CAUTION The changeover from the Safety Injection Phase to Cold Leg Recirculation must 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 changeover is completed.

5.1 Verify that the following normally closed valves are CLOSED:

11(2l)SJ40 11 (21) SI Pump Disch Valve to Hot Leg 12(22)SJ40 12(22) SI Pump Disch Valve to Hot Leg 11 (21) SJ113 SI Chg Pumps X-Over Valve 12(22)SJ113 SI Chg Pumps X-Over Valve 11(2l)SJ45 Recirc Isol Valve to SI Pump 11(2l)CS36 From 11 (21) RHX Valve 12(22)CS36 From 12(22) RHX Valve 1(2)RH2 RHR Common Suction Valve 1(2)RH1 RHR Common Suction Valve 11(2l)SJ44 SIS Sump Valve 12(22)SJ44 SIS Sump Valve 1(2)RH20 RHX :Sypass Valve 1(2)RH26 RHR Outlet Stop Valve 11(2l)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(2l)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(2l)CC16 and 12(22)CC16 RHR Heat Exchanger Outlet Valves.

5.4 When the RWST Low-Low Level Alarm actuates at 0.0 feet (O.O gals.~~~op the following pumps if they are running. ~ *~

No. 11(21) RHR Pump

~~j

<<~-

~~~~~~ ~RP:pand No. 12(22) CS Pump, .if contai~~~ray actuation has occurred. ~~)

~

~*,~)

Salem Unit l/Unit 2 Rev. 7

I-4.6 PART II

NOTE If Containment Pressure has not decreased to below 23.5 psig, the Containment Spray Pumps cannot be stopped f7om the control console. To stop the pumps, it will be necessary to trip the breakers locally on the lA and lC (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 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 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 5.6 Close 11(2l)RH4 RHR Pump Suction Valve, if No. 11(21) RHR Pump is available.

Close 12(22)RH4 RHR Pump Suction Valve, if No. 12(22) RHR Pump is available.

NOTE 11(2l)RH4 must be closed in order to open 11(2l)SJ44. 12(22)RH4 must be closed in order to open 12(22)SJ44.

5.7 Remove the lockout and open 11(2l)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~mp is available. ~

~-~

5.9 Close 11(2l)RH19 RH Heat Exchanger Outlet Valve.

.~<::::~

S-.10. Close 12(22)RH19 RH Heat Exchanger Outlet Valve 4~/

5.11 Start No. 11(21) RHR Pump.

/~~~

,;~~"

5.12 Maintain 3,000 gpm on COLD LEG INJECTION 11(2l)SJ~).ow m~ter by adjusting 11(2l)RH18. (0:\ v

~(')~

/('\:' ' )

"".'1 .:)

-~

Salem Unit l/Unit 2 Rev. 7

I-4.6 PART II

5.13 5.14 5_.15 Sta.rt No. 12 (22) RHR Pump.

Maintain 3,000 gpm on COLD LEG INJECTION l2(22)SJ49 flow meter by adjusting l2(22)RH18.

Remove the lockout and close l(2)SJ67, 12(22) Mini Flow Isolation Valve, and l(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 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.

5.17 Open 11(2l)SJ45 Recirc Isoaltion Valve to SI Pump** if No. 11(21) RHR Pump is available.

NOTES

To open 11(2l)SJ45, the following valves must be positioned as listed below:

1) 1 (2) RHl or 1 ( 2) RH2 Closed 21 1(2SJ67 or 1(2)SJ68 Closed

3) 11(2l)SJ44 Open

- To open 12(22)SJ45, the following valves must be positioned as listed below:

ll 1(2)RH1 or 1(2)RH2 Closed

2) 1(2)SJ67 or l(2)SJ68 Closed

~'~

3) l2(22)SJ44 Open 5.18 Open 11(2l)SJ113 SI Charge Pumps X-Over Valve.

,, ~~

.- ~

5.19 Open 12(22)SJ113 SI Charge Pumps X-Over Valve. ~

~;~!)

5.20

~-~~

Close 1(2)SJ1 RWST to Charge Pump.

5.21 Close l(2)SJ2 RWST to Charge Pump. C'~~~

-~

~~

<:.'-*~~>

5.22 Verify that No. 11(21) SI Pump is operating proper;_y *~observing No. 11(21) SI Pump discharge pressure indicator and No. ll(2l)~~ump discharge flow indicator.

~~<>

Salem Unit l/Unit 2 Rev. 7

I-4.6 PART II

5.23 5.24 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.

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 i f No. 12(22) RHR Pump is not available].

5.27 Open the following Containment Spray Valves:

12(22)CS36 [11(2l)CS36 if No. 12(22) RHR Pump is not available].

5.28 Close the following Containment Spray Valves:

11(2l)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 loop 11(21) and 13(23) Cold Legs via valve 11(2l)SJ49 and to the suction of the Safety Injection Pumps through valve 11(2l)SJ45.

2) RHR Pump No. 12(22) is supplying water from the Containment Sump directly to the Contain-

~~1) ment Spray Header and to the suction of the Charging Pumps through valve 12(22)SJ45.

~~

~~etor 5.29 Close the following Accumulator Isolation Valves, if the pressure is indicated to be less than 250 psig. '~~

~~

~*

Salem Unit l/Unit 2

~-

Rev. 7

I-4.6 PART I I 11(2l)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 Manager - Salem Generating Station SORC Meeting No.

Salem Unit l/Unit 2 Rev. 7 J

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.

is necessary to run the Component Cooling Pumps.

During the recirculation phase, it In order to accomdate this additional load, othei 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 GENERATORS OPERATING 1.0 Stop the following equipment:

NOTE Do not stop both No. 11(21) and 12(22) Containment Spray Pumps until the RWST Low-Low level alarm*actuates.

1.1 Equipment on 1A(2A) Vital Bus (Powered by 1A(2A) Diesel/Generator)

1.2 a.

b.

c.

d.

No. 11 (21) Containment Spray Pump No. 11 (21) Auxiliary Building Exhaust Fan No. 11 (21) Switchgear Room Supply Fan No. 11 (21) Chiller Equipment on 1B(2B) Vital Bus (powered by 1B(2B) Dies~l/Generator)

a. No. 12(22) Containment Fan Coil Unit

b. No. 14(24) Containment Fan Coil Unit 1.3 Equipment on 1C(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' equipment:

"~~~

rf--~ ~~

~)

.*'~

CAUTION

~/~

When entering Cold Leg Recirc. start only one ~~~

. tF -~

Component Cooling Pump. Ensure the Component~*~

Cooling Pump to be started is energized fro~~~

the same Vital Bus as was the Containment~~

Spray Pump, secured from in the abo~~

Salem Unit l/Unit 2 1 of 5 Rev.7

I-4.6 2.1 Equipment on 1A(2A1 "vital Bus (powered by 1A(2A) Diesel/Generator)

a. No. 11 Component Cooling Pump 2.2 Equipment on 1C(2C) Vital Bus (powered by 1C(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(2l)SW122 and 12(22)SW122 to Supply Service Water to Component Cooling.

II - FAILURE OF l.A (2A) DIESEL GENERATOR 1.0 Stop the following equipment:

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 1C(2C) Vital Bus (powered by 1C(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 Recirculation.

0~

~

"3 .1 The following pumps should be running:

~~~

a.

b.

No. 12(22) RHR Pump No. 12(22) Charging Pump

&~

(0.~v c* No. 12(22} Safety Injection Pump

'?~~

3.2 Close valves 12(22)RH19 and 12(22)SJ49 to prevent flow~~ Cold Legs and to insure adequate flow to No. 12(22) Charging Pu.~p and No. l~~Safety Injection Pump suctions and to' the Containment Spray Header through 12(22)~~~J>

Salem Unit l/Unit 2 2 of 5 Rev. 7

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)SJ113, 11(2l)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 GENERATORS 1.0 Stop the following equipment:

1.1 Equipment on 1A(2A) Vital Bus (powered by 1A(2A) Diesel Generator)

a. No. 11(21) Containment Spray Pump 1.2 Equipment on 1C(2C) Vital Bus (powered by 1C(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 11(2l)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 Recirculation:

3.1 The following pumps should be running:

a.

b.

No. 11(21) RHR Pump No. 12(22) Charging Pump

,~~~

c. No. 11(21) Safety Injection Pump -~

~~

3.2 Close valves 11(2l)RH19 and 11(2l)SJ49 to prevent flow to the C~~~~s and to insure adequate flow to No. 12(22) Charging Pump and No. 11(21) Sa~,(-~,\~ection Pump suctions and to the Containment Spray Header through 11(21).

rf . <-">

~~

~)

~~

Salem Unit l/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 11(2l)SJ45, 11(2l)SJ113, 11(2l)SJ33 and 11(2l)SJ33, and to the Containment Spray Header through 11(2l)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 11(2l)SJ134 and 1(2)s.J"l35 to all four Cold Legs.

IV - FAILURE OF 1C(2C) DIESEL GENERATOR 1.0 Stop the following equipment:

1.1 Equipment on 1A(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 11(2l)SW122 to provide Service Water to Component Cooling.

NOTE If irradiated fuel is tared 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.

b.

No. 11(21) RHR Pump No. 11(21) Charging Pump

~~

~~~

3.2

c. No. 11(21) Safety Injection Pump Close valves 11(2l)RH19 and 11(2l)SJ49 to prevent flow to the

. "'?

Cola;;_~

J and to insure adequate flow to No. 11(21) Charging Pump and No. 12(22) Safe~;~~'Btion Pump suctions and to the Containment Spray Header through 11(2l)C~6~~

3.3 The Cold Leg Recirculation Flow Path would be as Salem Unit l/Unit 2 4 of 5 follow~~~

~)~

A ~

~~-:>

Rev. 7

I-4.6

a. No. 11(21) RHR Pump taking suction on the Containment Sump and discharging to suctions of No. 11(21) Charging Pump and No. 11(21) Safety Injection Pump through 11(21SJ45, 11(2l)SJ113, 12(22)SJ113, 11(2l)SJ33, and 12(22)SJ33, and to the Containment Spray Header through 11(2l)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.

Salem Unit l/Unit 2 5 of 5 Rev. 7

I-4.7 EMERGENCY INSTRUCTION I-4.7 STEAM GENERATOR TUBE FAILURE

1. 0 DISCUSSION l~l This instruction covers t~e symptoms, automatic actions and manual actions for a Steam Generator tube leak and a Steam Generator tube rupture. Either of these conditions result ~n leakage of reactor coolant into the secondary system.

1.2 Operator action is required, in accordance with the accident analysis in the FSAR, in order to identify and isolate the faulted Steam Generator on a tube rupture.

Reactor Coolant System pressure must be reduced to less than 1000 psi within 30 minutes in order to prevent lifting of the Steam Generator 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 10CFRlOO.

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 Hot Leg. This condition will exist if RCS pressure has dropped below the saturation pressure for the existing RCS temperature. Refer to the RCS pressure-temperature curve to determine if this condition exists.

1.4 This instruction is divided into two parts:

I Stearn Generator Tube Leak II Stearn Generator Tube Rupture PART I I STEA.~~ GENERl1.TOR TUBE LEAK 2.0 SYMPTOMS 2.1 Any of the following high radiation alar;ns:

11(21) Steam Generator Blowdown 1(2)Rl9A 12(22) Steam Generator Blowdown 1(2)Rl9B 13(23) Stearn Generator Blowdown 1(2)Rl9C 14(24) Stearn Generator Blowdown 1(2)Rl9D

2.2 Condenser Air Ejector 1(2)Rl5 SG Elowdown Filter Discharge 1(2)R3S Charging Pump S?eed and Charging flow increase Salem Unit l/Unit 2 Rev. 5

I-4.7 P.!\.RT I IMMEDIATE ACTIONS 3.1 riutornatic 3.1.l Charging flow increasing 3.1.2 Automatic makeup to VCT 3.1.3 Warning alarm on RMS Channel Rl9 isolates 12(22) S/G BD Tank Valves 11, 12, 13 and 14(21,22,23 & 24)GB10 and 1(2)GB50.

3.1.4 High alarm on the Stearn Generator Blowdown Radiation Monitors (Rl9) will isolate the following:

a) Unit 1 - Alarm on any channel, 1Rl9A-D, will isolate 11,12,13 and 14GB4.

b) Unit 2 - 2Rl9A will trip 21GB4 2Rl9B will trip 22GB4 2Rl9C will trip 23GB4 2Rl9D will trip 24GB4 3.1.5 High alarm on RMS Channel R35 shifts 3-way valves 1(2)GB74 and 1(2)GB11( to discharge to the Waste Monitor 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 Stearn Generator tube leak.

4.0 SUBSEQliENT ACTION 4.1 Determine primary to secondary leak rate. See Technical Specification 3.4.6.2 for leakage limits.

4.2 Determine which Stearn Generator is leaking by sample analysis and observinq readings on Stearn Generator sample radiation monitors.

4. 3 ~onitor char9ing pump flow for any increase and the Stearn Generator sample radiation monitors for increased readings which indicate higher leakage.

~

<'~

4... 4 Shutdown the plant when Technical Specification ~eakage limits are reac~~W OI I-3.4, "Power Operation", I-3.5, "Minimum Load to Hot Standby" an~~-3.6, "Hot c- *,~

Standby t:::i Cold Shutdown".

~l NOTE

~~

(f-~..

The faulty Stea:::i Generator should not be st/7~:<{~~:.irinc; the subsequent c:::ioldown. CoolC.:::i*.*J:1. s~ould ~ ~:::i:npl i s~ed by usinq the Atmospheric Stea:e rel!.er: Val~'.'.>'.S-10) for

~

the unaffected Steam Generators.

Salem Unit l/Unit 2 -:2-

I-4.7 4.5 Refer to Emergency Instruction EI-4.16, "Radiation Incident", if radiation monitors have alarmed.

PART II II STEAM GENERATOR TUBE RUPTURE 2.0 SYMPTOMS The following may be indicative of a Steam Generator tube rupture.

2.1 Charging flow or charging pump speed at maximum with decreasing pressurizer level and pressurizer pressure.

2.2 Increasing radiation levels on one or more of the following radiation monitors:

1(2)Rl9A 11(21) Steam Generator Blowdown 1(2)Rl9B 12(22) Steam Generator Blowdown 1(2)Rl9C 13(23) Steam Generator Blowdown 1(2)Rl9D 14(24) Steam Generator Blowdown 1(2)Rl5 1(2) Condenser Air Ejector

1(2)R35 SG Blowdown Filter Discharge

3. 0 I1"..C*1EDIATE ACTIONS 3.1 Automatic 3.1.1 Reactor Trip 3.1.2 Safety Injection Actuation 3.1.3 Turbine and Generator Trip 3 .1. 4 Warning alarr:1 on R11S Channel Rl9 isolates 12 (22) S/G BD Tank Valves 11~2,13 & 14 (21,22,23 and 24)GB10 and 1(2)GB50. ~~

~~

3 .1. 5 High alarm on the Steam Generator Blowdown Radiation Monitors (Rl9~fll isolate the following: ~~

~'. :~

~ -~

~,{3 aJ Unit l - Alarm on any channel, 1Rl9A-D, will isolate and l4GB4 .

~~,>~

b) Unit 2 - 2Rl9A will trip 21GB4 2Rl9B will tri? 22GB4 ,;,~~

2Rl9C will trip 23G34 2Rl9D will trip 24GB4

~)

Salem Cnit l/unit 2 ~

I-4.7 PART II

3.2 3.1.6 Manual 3.2.1 High alarm on ~MS Channel R35 shifts 3-way valves 1(2)BG74 and 1(2)BG112 to discharge tc the Waste Monitor Holdup Tanks.

Verify Safety Injection Actuation by checking the following:

1) Reactor trip by verifying all full length control rods fully inserted by checking individual rod position 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 Feed Pumps tripped and feedwater isolation has occurred .

4) Verify the ACCIDENT LOADING light is illuminated on the Diesel Generator bezels and the following equipment is operating:

a) Centrifugal CRarging Pumps bl Safety Injection Pumps c) Residual Heat Removal Pumps d) Auxiliary Feedwater Pumps (motor driven) e) Diesel Generators f) Containment Fan Coolers runr.ing in slow speed.

~

3.2.2 Within two minutes reduce Auxiliary Feedwater flow to the

'~~

Steam Gen~~rs to limit the rate of rise to < 1.2 in/min by monitoring the wide ra~ level recorders (< o.2%/min on the Narrow Range) until the level~* > ~ on all Steam Generators. (NOTE: This limitation applies only to )

\~..

3.2.3 Verify T avg is decreasing toward or beir.g maintained at4~by either s~eam dump er atmospheric steam relief. ~~~

3. 2. 4 Stop all Reactor Coolant Pumps whe:-i ?:?::essurizer l~)reaches 0'5.

<<)I~

~~

Salem Unit l/Unit 2 Rev. S

I-4.7 PART II 3.2.5 Announce over the station ?A System twice: "UNIT NO. 1(2) REACTOR TRIP SAFETY INJECTION".

4.0 SUBSEQUENT 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:

ll Fan coolers 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 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 con_sole.

1(2)SJ4 Boron Injection Tank Inlet Valve 1(2)SJ5 Boron Injection Tank Inlet Valve 1(2)SJ12 Boron Injection Tank Outlet Valve 1(2)SJ13 Boron Injection Tank Outlet Valve 1(2)SJ1 Charging Pump 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, attempt to close the valve from the Control Console.

1(2)SJ78 Recirc to aoric Acid Tank 1(2)SJ79 Recirc to Boric Acid Tank 1(2)SJ108 Recirc to Boron Injection Tank 1(2)CV68 Charging System Stop Valve 1(2)CV69 Charging System Stop Valve 1(2)CV139 Charging Pump Discharge to SWHX 1(2)CV140 Charging Pump Discharge to SWHX 1(2)CV40* Volume Control Tank Discharge Val~e 1(2)CV41* Volume Control Tank Discharge Val7e 1(2)CV3 Ori.::ice Isolation 1(2)CV4 Orifice Isolation Val~e Or if ice Isolation IJalve Salem Unit l/Unit _

I-4.7 PART II 1(2)CV7 CVCS Letdown Line 1(2)CV116 Reactor Coolant Pump Seal Water Discharge 1(2)CV284 Reactor Coolant Pump Seal Water Discharge 11(2l)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 following meters on the control console to ensure that borated water is being injected into the Reactor Coolant System.

1) Boron Injection Tank pressure indicating RCS pressure.

2) Charging Pumps discharge flow

3) 11(21) Safety Injection Pump Discharge Flow

4) 12(22) Safety Injection Pump Discharge Flow 4.2 Verify that Phase "A" Containment Isolation has taken place by checking that the valves listed in Table II are closed. Should a valve fail to close, attempt to close it from the control console.

~.3 Verify that feedwater isolation has taken place due to the Safety Injection.

4.3.1 Check that the following valves have closed by observing the status panel and/or the console bezel. If any valve has failed to close, attempt to close it from the control console.

11 (21) BF13 Feedwater Inlet Stop Valve 11(2l)BF19 Feedwater Control Valve 11(2l)BF40 Feedwater Bypass Valve 12(22)BF13 Feedwater Inlet Stop Valve 12 ( 22) BF19 Feedwater Control Valve 12(22)BF40 Feedwater Bypass Valve 13(23)BF13 Feedwater Inlet Stop Valve 13(23)BF19 Feed water Control Valve 13(23)BF40 Feed water Bypass Valve 14(24)BF13 Feed water Inlet Stop Valve 14 ( 24) BF19 Feed water Control Valve 14(24)BF40 Feedwater Bypass Valve Salem Gnit l/Cnit 2 ?.e~.r ~ 5

I-4.7

4.4 Verify that the 4160V Group Busses have transferred from the 1(2) Auxiliary Power Transformer to 11(21) and 12(22) Station Power Transformers.

4.4.1 Check that the following 4160V breakers have opened and acknowledge them on the appropriate control consol~ 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 acknowledge them on the appropriate control console bezel:

12(22)GSD 12 (22) FSD 11(2l)ESD 11(2l)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 sample 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 Steam Generators by use of the Auxiliary Feed Systems. Do not feed the faulted Steam Generator.

4.6 Reduce the RCS temperature and pressure as quickly as possible, within the limits of

-~

the pressure-temperature curve.

4.6.1 Reduce Tavg to ~ 500°F as follows: ~~

1) I f the Conden*er i ' available , *hif t the Steam Dump s Y' tem to '!!:;,~CCS1 and reduce the setpoint. ,~ ])

2) If the Condenser is not available, take manual control 9~S~Z\.tmosphere Steam Relief Valves (MS-10) on the unaffected Steam G~r~ors and open the valves as necessary. ~ '~

(~~:>

~*

NOTE <&

~~

Do not steam the faulted Steam Generator t~*he .Zl.t::::'losphere.

Salem Unit !/Unit 2 Rev. 5

I-4.7 PART II

4.6.2 Reduce RCS Pressure to approximately 1000 psig as follows:

1) 2)

If the RCP's are in operation open the Pressurizer Spray Valves (PSl & 3).

If the RCP's are not in operation, cycle the Pressurizer Power Operated Relief Valves (PRl & 2) as necessary to reduce pressure.

4.7 When the RCS pressure and the pressure in the affected Steam Generator reaches 1000 psig or less, close the Steam Generator stop valve on that Steam Generator.

4.8 Check that nuclear power is decreasing by observing the nuclear instrumentation.

4.8.1 Check that the source range high voltage is reinstated below 10-lO amps on both intermediate range channels. This should occur in ~ 15-18 minutes following a trip from the Power Range.

1) If the source range high voltage does not energize automatically, manually depress the RESET SOURCE RANGE "A" and RESET SOURCE RANGE "B" pushbuttons.

4.8.2 Switch the Nuclear Power Recorder (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 (21, 22, ~3, 24) Control Rod Drive 11 & 12 (21 & 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 - INSIDE AIR mode of operation and the following actions have occurred.

4.10.l 11, 12, 13 (21, 22, 23) Chillers are running 4.10.2 11 & 12 (21 & 22) Chilled Water Pumps are running

~

4.10.3 11, 12, 13 (21, 22, 23) Control Area Supply Fans are running ,~}'>

4.10.4 11 & 12 (21 & 22) Emergency Control Area Supply fans are runniri'~~?

~"

'** -~

4.10.5 Battery exhaust fan has stopped

.*~)

~

4.10.6 Control valves 1(2)CH30 and 1(2)CH151 close to isclate-"":'-the~'-.C:::-,inist::::ati*..-e

--=::* '5::>

Building.

~~~

Salem Unit l/Unit 2 Rev. 5

I-4.7 4.10.7 Control valve 1(2)CH168 opens to supply chilled water to the emergency c0ntrol 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 l., If any of the above actions have not occurred, manually initiate them IAW OI TI-17.3.2 (Section 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 Stearn Generator level is being maintained at ~ 33% on the narrow range channels for the unaffected Steam Generators, proceed to EI I-4.2, "Recovery frorn Safety Injection".

Manager - Salem Generating Station SORC Meeting No.~~~~~~~~~~~~~-

Salem Unit l/Unit 2 I-4.7 TABLE I "BLACKOUT WITH SAFETY INJECTION" LOADING SEQUENCE

#11(21) DIESEL GENERATOR #12(22) DIESEL GENERATOR #13(23) DIESEL GENERATOR 1(2)A 1(2)B 1(2)C 240/480V Breaker 240/480V Breaker 240/480V Breaker ll (21) SI Pump 11(21) Charging Pump 12(22) Charging Pump ll(21) RHR Pump 12(22) RHR Pump 12(22) SI Pump 15(21) SW Pump 14 (24) SW Pump ll (25) SW Pump or* or* or*

16(22) SW Pump 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 ll (21) Chiller 12(22) Auxiliary Building 11(21) Auxiliary Building Supply Vent Fan Supply Vent Fan 11(21) SWGR Room Supply Fan 12(22) Auxiliary Building 13 (23) Auxiliary Bui.lding Exhaust Fan Exhaust ='an 12(22) Chiller 13(23) Chiller 12(22) SWGR Room Supply Fan 13(23) SWGR Room Supply Fan NOTE This sequence is initiated on any Safety Inje~tion actuation with or without a blackout, only in a blackout condition will the Diesel Generator breakers close after first stripping the bus and the loads will then be sequenced onto the bus. This sequence is also initiated with a Safety Injection coincident with undervoltage on one 4kV vital bus.

NOTE Only the lead Service Water P'.llllp will start, however, if the lead pump fails to start, the backup pump breaker will close .

TABLE I Page 1 of 1 Salem Unit l/Unit 2 Rev. -

I-4.7 TABLE II

~*

PHASE "A" ISOLATION

1. Waste Disposal System 1(2)WL12 RCDT PUMP DISCHARGE 1(2)WL13 RCDT PUMP DISCHARGE

.l (2)WL16 CONTAINMENT SUMP PUMP DISCHARGE 1(2)WL17 *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)WLl08 N2 SUPPLY TO RCDT

2. Sampling System 1{2)SS27 ACCUMULATOR SAMPLE 1{2)SS33 HOT LEG SAMPLE 1(2)SS49 SAMPLE FROM PZR WATER SPACE 1(2)SS64 SAMPLE FROM PZR 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 PZR STEAM SPACE 11{2l)SS94 SAMPLE FROM NO. 11 (21) STM GEN BLOWDOWN 12(22)SS94 SAMPLE FROM NO. 12(22) STM GEN BLOWDOWN 13(23)SS94 SAMPLE FROM NO. 13 (23) STM GEN BLOWDOWN 14(24)SS04 SAMPLE FROM NO. 14 (24) STM GEN BLOWDOWN

3. Component Cooling 1 (2) CC113 EXCESS LETDOWN HEAT EXCHANGER COOLING WATER OUTLET 1(2)CC215 EXCESS LETDOWN HEAT EXCHANGER COOLING WATER INLET

4. Steam Generator Drains and Blowdown 11 (21) GB4 STEAM GEN OUTLET NO. 11 (21) 12(22)GB4 STEAM GEN OUTLET NO. 12 (22) 13 (23) GB4 STEAM GEN OUTLET NO. 13(23)

~14 (24)GB4 STEAM GEN OUTLET NO. 14(24)

5. ~ressurizer Relief Tank 1(2)WR80 PRIMARY WATER SUPP!..Y TO PR'!:'

1(2)PR17 GAS ANALYZER FROM PRT 1(2)PR18 GAS ANJ>.L YZER FROM PRT 1(2)NT25 N2 SUPPLY TO ?RT TF>.BLE I I Page 2. of 2 ?.e:.

Salem Unit l/Unit 2 ~

I-4.7 TABLE II

6. Accumulators 1(2)NT32 ACCUMULATOR N SUPPLY 2

7. Containment Ventilation 1(2)VC1 PURGE SUPPLY 1(2)VC2 PURGE SUPPLY 1(2)VC3 PURGE EXHAUST 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 CONTAINMENT RADIATION SAMPLE OUTLET 1 (2) VCll CONTAINMENT RADIATION SAMPLE INLET 1(2)VC12 CONTAINMENT RADIATION SAMPLE INLET

8. Demineralized Water 1(2)DR29 DM WATER TO FLT.:SHING CONNECTIONS

9. Fire Protection 1(2)FP147 PROTECTION WATER SUPPLY

10. Safety Injection 1(2)SJ123 AC CUM TEST STOP VALVE 1(2)SJ60 AC CUM DISCH TEST STOP 1(2)SJ53 SJ HDR TEST STOP VALVE

11. Control Air 11(2l)CA330 A HDR ISOLATION VALVE 12(22)CA330 B HDR ISOLATION VALVE TABLE II Salem Unit l/Unit 2 Page 2 of 2

I-4.8 EMERGENCY INSTRUCTION I-4.8 ROD CONTROL SYSTEM MALFUNCTION This instruction is divided into six (6) parts.

I FAILURE OF A CONTROL ROD BANK TO MOVE II CONTINUOUS INSERTION OF A CONTROL ROD BANK III CONTINUOUS WITHDRAWAL OF A CONTROL ROD BANK IV DROPPED ROD V FULL LENGT!-1 ROD MISALIGNMENT

'/I MALFUNCTIONING ROD POSITION .INDICATOR PART I I. FAILURE OF A CONTROL ROD BANK TO MOVE I-1.0 DISCUSSION I-1. l While in automatic control, this abnormal condition may prevent the plant from maintaining the programmed Tavg which may result in a reactor trip. A deviation from the programmed Tavg 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 SYMPTOMS I-2.l Following an.increase in turbine load, 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.l 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 the control deadband.

I-2.1.2 Tavg - Tref Deviation Alarm I-2.1.3 Rod insertion limit alarm following an increase in turbine load.

I-2.1.4 Decreasing T avg I-2.l.5 Decreasing Pressurizer pressure and Pressurizer level.

I-2.2 Following a decrease in turbine load, or during a decrease in reactor coolant boron concentration, the following symptoms 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 S2l2m Cnit 1 and 2 Rev. 5

I-4.8 I-2.2.2 Tavg - T re f Deviation Alarm I-2.2.3 Increasing Tavg I-2.3 Rod stop annunciation I-2.4 Rod Control System Urgent Failure alarm I-3.0 IMMEDIATE ACTIONS I-3.l Automatic I-3.1.1 Foilowing 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.

ll Actuation of Pressurizer Spray

2) Actuation of Pressurizer Power Operated Relief Valves

3) Actuation of the Pressurizer Heaters

4) Overtemperature ~T rod withdrawal stop 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 ~T or overtemperature ~T 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 Rev. 5

I-4.8

2) Nuclear overpower rod stop. Reduce turbine load until the rod stop signal no longer exists. Do not increase turbine load until the cause of the rod stop has been determined and corrected.

3) Low power (15% turbine power interlock P-2, ON) - shift the ROD BANK 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 SWITCH to MANUAL and position the control rod banks to restore equilibrium conditions at the programmed T value. The reactor may be avg 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 Tavg and 6T channels.

3) Feedwater and steam flow for the Steam Generators.

4) Core outlet thermocouples and/or in-co~e movable detectors.

5) Delta Flux Indicators.

NOTE If any of the above indicate an abnormal power dist=ibution, 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 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months ) during failure evaluation.

Load changes should be avoided. Tavg 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 hot standby is required for re~air, reactor power may be reduced by reducing the turbine load and increasing the boron concentration such that T matches avg the programmed Tref" Shutdown by reactor trip is also acceptable.

~*

Rev. 5 SaJern 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 INSERTION OF A CONTROL ROD BANK II-1.0 DISCUSSION 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.l Unwarranted rod motion as indicated by the step counter and rod position indicators.

II-2.1.2 Tavg - Tref Deviation Alarm II-2.1.3 Rod insertion limit alarm II-2.1.4 Decreasing T and steam pressure avg II-2.1.5 Decreasing Pressurizer pressure.

II-2.l.6 Decreasing Pressurizer level.

II-3.0 IM."1'1EDIATE ACTIONS II-3.l Automatic 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 ROD BANK SELECTOR SWITCH in MANUAL.

II-3.2.2 If the control bank continues to insert, trip the reactor. Refer to EI I-4.3, "Reactor Trip.

Rev. 5 Salem Unit 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 control equipment is repaired.

II-4.2 Investigate the cause of the malfunction and make necessary repairs before resuming normal 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.

SYMPTOMS III-2.1 Any of the following symptoms may be indicative of the continuous withdrawal of a control rod bank:

III-2.1.~ Unwarranted rod motion as indicated by the step counter and rod position indicators.

III-2.1.2 Tavg - Tre f Deviation Alarm III-2.1.3 Increasing reactor power without an accompanying turbine load increase.

III-2.1.4 Increasing T avg 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 of a continuous withdrawal of a control rod bank.

1) Power Range High Neutron Flux Reactor Trip (High Setpoint).

Salem Unit 1 and 2 Rev. 5

I-4.8

2) Overtemperature llT Reactor Trip

3) Overpower llT 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 Setpoint)

III-3.1.2 If no reactor trip occurs, 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 Neutron Flux Rod Withdrawal Stop

3) Overtemperature llT Rod Withdrawal Stop accompanied by turbine runback.

4) Overpower llT Rod Withdrawal Stop accompanied by turbine runback

5) Actuation of pressurizer spray and/or power relief valves.

III-3.2 Manual III-3.2.1 If in ~UTO, 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 withdrawal stopped, manually insert the control rod bank to restore equilibrium power and temperature conditions.

III-4.0 SuBSEQUENT 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 equiiibrium Gonditions under MANUAL control until the fault has been determined and corrected.

PART IV IV. DROPPED ROD IV-1.0 DISCUSSION IV-1.1 A dropped rod may result from the malfunction of one or more rod drive mechanisms.

While the plant is at power, the Reactor Protection System will sense this abnormal condition and initiate an alarm. The Rod Control System will automat-ically compensate for the decreased Tavg by withdrawing the remaining control rod banks.

Salem Unit 1 and 2 Rev. 5

I-4.8 IV-2.0 SYMPTOMS IV-2.l Any of the following symptoms may be indicative of a dropped rod:

IV-2.1.1 Individual rod bottom light and alarm from the rod position indicators.

IV-2.1.2 Rod position Deviation Alarm (Computer)

IV-2.1.3 Power Range Nuclear Instrumentation Channel Deviation Alarm.

IV-2 .1. 4 Decrease in reactor coolant T avg IV-2 .1.5 T - T Deviation Alarm ref avg 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 occur due to a high negative flux rate.

IV-3.0 IMMEDIATE ACTIONS IV-3.l Automatic IV-3.1.1 Additional Pressurizer Heaters turned ON.

IV-3.1.2 Withdrawal of remaining control bank(s) to maintain Tavg IV-3.1. 3 In the case of one or more dropped rods, a reactor trip will occur.

IV- IV-3.2 Manual IV-3.2.1 If the ROD BANK SELECTOR SWITCH is in MANUAL and the reactor did not trip, reduce the turbine load to maintain Tavg equal to Tref' IV-3.2.2 If the reactor has tripped, follow EI I-4.3, "Reactor Trip".

IV-4.0 SUBSEQUENT ACTIONS IV-4.1 I= the turbine power is greater than 75%, reduce it to 75% or below within one hour. (Technical Specification 3.1.3.1)

IV-4.2 When the plant conditions are stable, retrieve the dropped rod by the following steps:

IV-4.2.l 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 rod.

-i- :cl.ev. 5 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 the affected bank to insure complete insertion of the dropped rod.

IV-4.2.6 Reset the step counter(s) for the affected bank to zero by rotating the thumb wheels.

IV-4.2.7 If the dropped rod is a control rod, the pulse to analog (P/Al converter has to be zeroed as follows: If the dropped rod is a shutdown rod, proceed to step IV-4.2.8 below.

1) To zero the P/A Converter:

a) Place the BANK POSITION DISPLAY SELECTOR SWITCH, on the P/A Converter 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 DISPLAY for the affected bank.

cl Release the AUTOMATIC-MANUAL switch, checking that it does spring return to AUTOMATIC.

NOTE The ROD 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 Tavg NOTE An URGENT FAILURE alarm will be received during this 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 lift coils of the rods in the affected bank.

IV-4.2.11 Verify that the bank overlap unit and the P/A Converter 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 10 steps to verify normal operation of the bank.

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 channel(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 ROD 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. FULL LE~GTH ROD MISALIGNMENT V-1.0 DISCUSSION V-1.1 Rod misalignment results from a malfunction of a Control Rod Drive Mechanism or of the rod 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 exceeding the core safety limits, if caution and attention are not given to each corrective maneuver.

V-2.0 SYMPTOMS 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 bank by more than 1 step.

V-2.3 Abnormal variation in top-to-botto~ flux difference between the four power range channels.

V-2.4 Rod position Deviation Alarm (ComP,uter).

V-2.5 Abnormal core power distribution as indicated by the in-core detectors and in-core thermocouples.

V-2.6 An abnormal variation between loop Tavg or ~T measurements and Tavg or ~T Deviation Alarms.

V-3.0 IMMEDIATE ACTIONS V-3.1 Automatic V- 3. 1. 1 None Rev. 5 Salem Un:_ t 1 and 2

I-4.8 V-3. 2 Manual V-3.2.l Place the ROD BANK SELECTOR switch 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.l 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 power or motion of other rods.

NOTE Until indicator failure, and not control 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 SUBSEQUENT ACTIONS V-4.1 With a maximum of one full length rod misaligned from its group step counter

+ 12 steps, comply with Technical Specification 3.1.3.1.

V-4.2 Verify that a rod misalignment has occurred by use of in-core detectors and thermocouples.

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 counter(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 affected ba~k on the ROD BANK SELECTOR SWITCH.

Rev. 5 Salem Unit 1 and 2

I-4.8 V-4.4.5 DIS~C~NECT 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 load to maintain the programmed Tavg NOTE When rod motion starts, an URGENT FAILURE alarm will sound.

V-4.4.7 CONNECT the lift coils of the rods in the affected bank.

V-4.4.B Reset the Pulse to Analog Converter 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 rod bank in 10 steps and then out 10 steps to verify proper rod operation.

V-4.4.11 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 rod is misaligned:

V-4.5.l V-4.5.2 V-4.5.3 CONNECT the lift coils of the rods in the affected bank.

Reset the affected GROUP step counter to the bank position.

Reset the Pulse to Analog Converter for the affected bank to the setting recorded in step V-4.4.3.

V-4.5.4 Continue plant operation 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 ROD POSITIOr:-; INDICATOR VI-1.0 DISCUSSION VI-1.1 Control rod position is of vital importance when the reactor is in the power range. 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, careful surveillance is needed to insure that the associated rod is functioning properly ~ith =espect t~ its bank.

Balem Unit 1 and 2 Rev. 5

I-4.8 V-2.1 The following symptoms indicates a malfunctioning rod position indicator:

VI-2.1.1 An individual rod position indicator in disagreement 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 the control rod is known to be correctly aligned VI-2.l.2 Erratic indicated position when the bank is not being moved.

VI-2.1.3 Sudden large indicated changes in rod position indication with no corresponding change in nuclear power or motion of the other rods.

VI-2 .1. 4 Rod Bottom Rod Drop Alarm.

VI-3. 0 IMMEDIATE ACTIONS VI-3 .1 Automatic VI-3 .1.1 None*

VI-3.2 Manual VI-3.2.l Until the rod position indicator is known to be at fault, assume the rod to be misaligned and follow the rod misalignment procedure, Part V or VI of this instruction.

VI-4. 0 SUBSEQUENT ACTIONS VI-4 .1 With a control rod position indicator channel for any control rod assembly inoperable, insure compliance with Technical Specification 3.1.3.2.

VI-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 its fully withdrawn position unless prior power distribution measurements indicated that it was in the inserted position. Required shutdown margin as prescribed in the plant Technical Specifications (in the form of boron or withdrawn rods available to trip) must be available at all times. Borate by 150 ppm for each red that the ~0sicion is not known.

Salem Unit 1 and 2 Rev. 5

,. I-4.8 VI-4. 4 During any control rod exercise tests for banks containing a non-indicated rod, bank motion must be sufficient to verify from thermocouples or in-core detector flux maps 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 oper3tion may resume.

Prepared by~------'-R~.--'H~a~l~l=m=a=r~k-------~ ,;/<;?~~-.-

Manager - s:ierlGenerating Station SORC Meeting No.~--=4=0_-_7~9~-----~~~~- Date~~~~-5~/_2_4~/_7_9~~~~~~~~~~-

Salem Unit 1 and 2 Rev. s

I-4.9 EMERGENCY INSTRUCTION I-4.9 BLACKOUT

~.O PURPOSE 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.l Reactor Trip - Turbine Trip 3.1.2 4kV Vital Bus loads stripped 3.1.3 Diesel Generators start and load 3.1.4 The #13(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 Generator Emergency Bearing Oil Pumps

3) 1 & 2 Emergency Seal Oil Pumps 3.2 Manual 3.2.l 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 (appro~imately.8 minutes) for each rod not fully i~~~ IAW OI II-3.~.B, "Rapid Borat1on". _ ~~~

3.2.2 Verify turbine trip by checking the following: -~~

ll UNIT TRIP light on E/H console illuminated. ~'W:.._~\ j)

2) Turbine Stop Valves, Governor Valves, Interc~~~lves and Reheat Stop Valves closed. -?~~

3) Turbine Speed decreasing. ~~

\~~

Salem Unit l/Unit 2 Rev. 8

I-4.9 3.2.3 Within 2 minutes reduce Aux. Feedwater flow to the Stearn Generators to limit the rate of rise to < 1.2 in/min by monitoring wide range level recorders.

Monitor narrow range level using the trend typewriter (points L0403A, L0443A, L0463A) and limit the rate of rise to < 0.2%/rnin 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°F 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 ~T < 62°F on one or more loops.

b. Core exit thermocouples and loop TH indicating temperatures are.stable or slowly decreasing.

c. Steam Generator pressure ~ 1000 psig on all Steam Generators for which the loop ~T is < 62°F.

3.2.7 Verify all automatic actions listed above, initiate any which have not occurred.

3.2.8 Determine whether "Blackout" 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.

4.1.1 Reactor Coolant pressure > 2000 psig, 4.1.2 Pressurizer level > 50%.

4.1.3 Steam Generator level > 10% in the narrow range on at least one Steam Generator, and if possible all four.

4.2 Open or verify open, 500kV GCB's 1-5, 5-6, 2-6, 1-8, 2-8, 2-10, 9-10, 1-9, Circuit Switchers 1T60, 2T60, 13kV ACB's 1-2, 2-3, 3-4, 4-5, 5-6 and 1-6.

4.3 Strip all loads from the 4kV Group Busses for Unit 1 and Unit 2. Open.or check open the following infeed breakers to the group busses:

lH - llHSD & lAHGD

~

lE - llESD & lAEGD lF - 12FSD & lBFGD lG - 12GSD & lBGGD

-~~

2H - 21HSD 2AHGD

~}

2E - 21ESD & 2AEGD 2F - 22FSD 2BFGD ~

~~~

2G - 22GSD & 2BGGD

-L4 Energize the 4kV Group Busses from the Gas Turbine as fa~~:

4. 4.1 Start the Gas Turbine Generator IAW OI VIII-1.~~'Dead Bus Operation -

Bootstrap Start", and verify_the Gas Turbine O~t Breaker closes. If the Gas Turbine fails to start, proceed to st~

Salem Unit l/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:

4.4.3 3-4, 4-5, 2-3, 5-6 Close the following breakers to energize the 4kV Group Busses:

lH - llHSD 2H - 21HSD lE - llESD 2H - 21ESD lF - 12FSD 2F - 22FSD lG - 12GSD 2G - 22GSD 4.5 Start the following equipment on the Group Busses. The exact component to be started will be determined based on availability, plant conditions, etc. at the time.

CAUTION The Gas Turbine is operating in the isolated mode of of operation. Starting of equipment must be coordi-nated with the operator at the Gas Turbine controls as he must 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 Cooling 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:

1) 1H3D to lighting bus lHL

2) lf3D to lighting bus lFL

3) 1E6D to Pressurizer Heater bus lEP

4) 2H3D to lighting Bus 2HL

5) 2F3D to lighting Bus 2FL Salem Unit l/Unit 2 Rev. 8

I-4.9

6) 2E6D to Pressurizer Heater Bus 2EP

4. 6 S ::op the following DC Lube 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 lA, lB, lC (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 lubricating oil during the roll down to zero speed and for 1/2 hour therafter.

4.9.3 Subsequent operation of the DC Pump should 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 H pressure in the Main Generator to < 2 psig IAW OI IV-2. 3. 2, "Generator 2

Gas Systems - Normal Operation", as soon as possible to prevent H leakage.

2 4.9.6 Energize 1EP(2EP) Pressurizer Heater Bus from the Emergency Feed from 1A(2A)

~

460V Vital Bus as follows:

1) Open 1EPX(2EPX) from the Pressurizer Backup Heater Group

'~

~~ Bezel on the control console. ~

2) Open 1E6D(2E6D), 4kV infeed to Pressurizer Heater ~~~er, from the control console. / ~ -~-~

3) Remove the key from inside the breaker cubic~~ 1E6D(2E6D) for the Correy key interlock. ~-~

~) .

4) Open 1EX(2EX) on the 1(2)E 460V Group ~in the Relay Room on El. 84' of the Auxiliary Building and remov~~ey for the Correy key interlock.

5) Close the Manual Disconnect Switch for the Emergency Feed at 1EP(2EP) heater bus.

Salem Unit l/Unit 2 Rev. 8

I-4.9

6) Insert ,the ~s from .1E6D(2E6D) and 1EX(2EX) into breaker 1Al4X(2Al4X),

1EP(2EP) Pressurizer Heater Emergency Feed, and close the breaker .

4.9.7

7) Power is now available to the 1EP(2EP) Pressurizer Heater Bus. The Heaters may be energized in the normal manner by closing 1EPX(2EPX) from the Press-urizer Backup Heater Group 12(22) Bezel on the control console.

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 synchronism is attained.

do not attempt to close the breaker.

If it is not, Contact the Load 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) Close circuit switches 1T60 and 2T60.

4) Close the following 13kV Breakers to energize the No. 11,12,21, an~~~~

Station Power Transformers: ~~

1-2, 1-6, 3-4, 4-5 r

~-~

~?

5) Close the following breakers to energize the 4kV Group~~'

lH - llHSD 2H - 21HSD ~

~ *~

n~~

lE - llESD 2E - 21ESD lF - 12FSD 2F - 22FSD

~

lG - 12GSD 2G - 22GSD Coordinate loading of the Busses with th~ad Dispatcher.

Salem Unit l/Unit 2 Rev. 8

I-4.9

6) Return the 4kV Yi.:c;.1....'.'" ::o r-.;*.,_-raal Operation IAW OI IV-16. 3 .1, "Emergency Power - Die.o.;

__ Operation" .

CAUTION In the event one of the Diesel has failed to energize its Vital Bus, that Vital Bus must be returned to Off-site power first in orde::: 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 4.10.4 4.10.5 Close 1T60 Circuit Switch.

Close or verify closed 13kV ACB-s 1-2, 2-3 and 3-4.

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

~

'~~

Synchronism must be established through communications ~))

between the Control Room and the gas turbine local

_c~

control.

~~v c~>

CAUTION

~-:::. ..;,

While No. 3 Generator is synchronized to two 5.~~V Lines 5023 (or 5024) (or 5015) the three breake~~s,sociated at New Freedom or Keeney with each lin~mu~be closed.

Verify with Load Dispatcher. F'* *:J 5023 - New Freedom Breakers 2oi~1~: 22X 5024 - New Freedom Breakers 30X, 31X, 32X 5015 - Keeney Breakers 503 or 504 Salem Unit l/Unit 2 Rev. B I-4.9 Proceed as follows for each breaker:

a) b)

c)

Depress the LOCAL pushbutton Select the desired breaker on the Mimic Bus.

Depress SYNC POT ON d) Observe the synchroscope and the running and incoming voltage meters on the control console. Adjust the Gas Turbine Generator voltage and fre-quency until the synchroscope is moving slowly in the fast direction and the running and incoming voltages are matched.

e) Close the breaker f) Depress the SYNC POT OFF.

4.lC.7 Open 13kV ACB's 2-3 and 5-6 4.10.8 Close 2T60 Circuit Switch 4.10.9 Repeat step 4.8.6 a-f for the 1-8 SOOkV 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 its Vital Bus, that Vital Bus must be returned to off- ~~

'~~

site power first in order to maintain minimum safeguards ~~

equipment. ~

~~y 4 .11 As conditions dictate, operate IAW one of the following OI's: .-~~

~~~

4 .11.1 I-3.3, "Hot Standby to Minimum Load" I-3.8, "Maintaining Hot Stanby

~~

4 .11. 2 4.11.3 I-3.6, "Hot Standby to Cold Shutdown". ~

Salem Unit l/Unit 2 Rev. 8

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 - Salem Generating Station

~eviewed by~~~~~~~~~~~~~~~~

SORC Meeting No.~~~~~~~~~~~~~

Salem Unit l/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 cooldown to the point of RHR initiation.

1.1 Stop the following equipment:

1A(2A) Diesel Generator - #11 (21) Auxiliary Feedwater Pump

11 (21) Component Cooling Pump 1B(2B) Diesel Generator - #11 (21) Charging Pump 1C(2C) Diesel Generator - U2(22) Charging Pump

13 (23) Component Cooling Pump 1.2 Start the following equipment:

1A(2A) Diesel Generator - #13(23) Charging Pump

11(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

13 or 15(23 or 25) Fan Coil Unit in Fast Speed

2. When the Steam Generators have been placed in wet layup, stop No. 12(22) Auxiliary Feedwater

~- ~

3. For the initiation of RHR, the following equipment may be operated as specif~~OI II-6.3.2, "Initiating Residual Heat Removal". -~

~

~

1A(2A) Diesel Generator - Ul (21) RHR Pump

11(21) Component Cooling Pump

-:~~~

'.~

(",- *)

1B(2B) Diesel Generator - #12(22) RHR Pump . '~

lC (2C) Diesel Generator - 13 (23) Component Cooling Pump \:~~->">

PART II - FAILURE OF 1A(2A) DIESEL GENERATOR c'~>

~

f."\

~~

1. If irradiated fuel is stored in the Fuel Handling Bui~i'&,~ proceed as follows as soon as SEC is reset to facilitate cooldown to the point of RH~initiation.

Salem Unit l/Unit 2 Page 1 of 3 Rev. 8

I-4.9 1.1 Stop the following equipment:

1.2 1B(2B) Diesel Generator - #12(22) Component Cooling Pump 1C(2C) Diesel Generator - #12(22) Charging Pump Start the following equipment:

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

13 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".

1B(2B) Diesel Generator - #12(22) RHR Pump

12(22) Component Cooling Pump ART III - FAILURE OF 1B(2B) DIESEL GENERATOR If irradiated fuel is stored in the Fuel Handling Building, proceed as follows as soon as SEC is reset to facilitate cooldown to the point of RHR initiation.

1.1 Stop the following equipment:

1C(2C) Diesel Generator - #13(23) Component Cooling Pump 1.2 Start the following equipment:

1A(2A) Diesel Generator - #11(21) Fuel Handling Area Exhaust Fan

11(21) Fan Coil Unit in Fast Speed 1C(2C) Diesel Generator - #11(21) Spent Fuel Pit Pump

13 or 15(23 or 25) Fan Coil Unit in Fast Spee:'-'~

((-:-\.~

2. When the Steam Generators have been placed in wet layup, stop No. 11(21) Au~l~y Feedwater Pump. :.0

~~_}~

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 1A(2A) Diesel Generator - #11(21) RHR Pump ~

1C(2C) Diesel Generator - 113(23) Component Cooling P~~

,,-0::,

{~~

Salem Unit l/Unit 2 Page 2 of 3 Rev. 8

I-4.lO(A)

EMERGENCY INSTRUCTION I-4.lO(A)

CONTROL ROOM EVACUATION

l. 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 c~ld 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.

l. 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 Lifted Leads and Jumpers".

2.0 SYMPTOMS 2.1 Some unforseen cause or causes which requires evacuation of personnel from the Control Room.

3.0 IMMEDIATE ACTIONS 3.1 Automatic 3.1.1 None 3.2 Manual - Control Room Salem Unit 2 Rev. 0

I-4.lO(A)

NOTE

3.2.1 If possible, perform the following manual - immediate actions prJor to evacuating the Control Room.

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 Stearn Dump Control System is in AUTO and each Atmospheric Stearn Relief Valve (MSlO) 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 Stearn Generator levels by use of Auxiliary Feedwater Pumps and associated flow control valves. Maintain level at ~ 33% on the narrow range indicators (equiva-lent to~ 60% on the wide range).

3.3.2 At Panel 213, verify that Pressurizer level is controlling automatically at

~ 22%.

1) If Pressurizer level is not controlling automatically or if desired:

a) Station an operator at Panel 216 (Charging System Panell b) Establish communication between Panel 213 and 216.

Salem Unit 2 Rev. 0

I-4.lO(A) cl At Panel 216, take lv~~l-manual control of 2CV55, Charging Flow Control Valve, and maintain Pressurizer level at ~ 22%.

d) Start one Centrifugal Charging Pump in LOCAL control at Panel 213.

el If desired remove from service No. 23 Charging Pump by opening 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.

ll If Pressurizer pressure is not controlling automatically:

al Dispatch an operator to the Pressurizer Heater Control Panels in the Electrical Penetration Area, Elevation 78'.

bl Establish conununications between the Electrical Penetration Area and Panel 213.

cl Take local-manual control of the pressurizer heaters and maintain Pressurizer pressure at ~ 2235 psig.

3.3.4 At Panel 213, verify that TH is decreasing toward or is being maintained at about 547°F by either steam dump to the condensers or by atmospheric steam relief.

1) If TH is not being controlled automatically at about 547°F:

a) Dispatch an operator to the North and/or South Penetration Area, Elevation lOD'.

b) Establish communications between the Penetration Area and Panel 213.

c) Take local-manual control of the Atmospheric Steam Relief Valves (MS]n' by use of manual hand-air operators in Jocal panels.

CAUTION Operate the MSlO's such that all Steam Generator Pressures remain within 100 psig so as to preclude the possibility o=

an inadvertent Safety Injection due to Steam Generator ~P.

NOTE Manual handwheel operation of the MSlO valves is also

dl available locally at each valve in the Penetration Areas.

If necessary, close the Steam Generator Stop Valves test switches provided in local panels in the

(~Sl67l Pene~ration by use of Area.

Salem Unit 2 Re~. 0

I-4.lO(A)

NOTE

Leaving the MS167's open will help maintain Stearn Generator pressures approximately equal and limit the possibility of an inadvertent Safety Injection due to Stearn Generator ~P.

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~ 200,000 gallons) 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 ensure 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 ~ 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 TH decreases below 554°F, perform the following:

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 Pumps cannot be started manually, start No. 23 AFW Pump locally in Panel 207.

NOTE If any two of the four Steam Generator's level decreases below the Low-Low Level setpoint No. 23 AFW Pump should start automatically.

Salem Unit 2 Rev. 0 J

I-4.lO(A) 4.2.3 Control each Steam Generator's water level at approximately 33% by local narrow range indication by performing the following: (Equivalent to ~ 60%

wide range indication)

1) By manual operation of S/G AF Control Valves 21,22,23 & 24AF21, if the motor-driven AFW Pumps are running; a) Check Control Valves 21,22,23 & 24AF11 closed.

2) Or by manual operation of S/G AF Control Valve 21,22,23 & 24AF11 if the turbine-driven AFW Pump is running.

4.3 Place the Main Turbine on the Turning Gear when the shaft stops.

4.4 If the Generator was on the line, verify the following:

4.4.1 ~OOkV breakers l-9BS and 9-lOBS have opened.

4.4.2 The 4160 Group Busses have transferred from the No. 2 Auxiliary Power Trans-former to No. 21 and No. 22 Station Power Transformers by checking the following breaker alignment:

2BGGD - Open 22GSD - Closed

4.4.3 2BFGD - Open 2AEGD - Open 2AHGD - Open 22FSD - Closed 21ESD - Closed 21HSD - Closed Generator Exciter Field Breaker has opened (Elev. 120' Turbine Bldg.).

4.5 If operation ouside the Control Room is expected to extend beyond 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 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 Flow Control Valve 2CV172 and open Blender Bypass Valve 2CV174.

4.6.3 Insure charging flow is > 75 gpm at Panel 216.

4.6.4 Boron concentration should increase at~ 23 ppm/minute .

4.7 Perform a shutdown margin calculation IAW the Reactor Engineering Manual, to verify that the shutdo~m margin is at least 1.6% lk/k.

Salem Unit 2 Rev. 0

I-4.lO(A) 4.8 As required 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 the following temporary controls, indications and jumpers:

4.9.1 Fluke Digital Thermometer or equivalent at Computer Thermocouple Terminal Cabinet (Unit 2 Relay Room); TPl0-82 and 83, (DWG 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 31 and 32 on PAN 3D.

2) At 2B West Valves & Misc. 230V Vital Control Center, terminals 29 and 30 and 31 and 32 on PAN 2D.

4.9.3 "Hand Senders" at Panel 101 for 21RH18 and 2RH20 and Panel 102 for 22RH18.

4.9.4 "Hand Sender" at Panel 202 for 2CVB .

4.9.5 4.9.6 Have "Hand Senders" availabe at Panel 314 for 2CV172 and 2CV179 for use if the makeup system does not function in AUTO.

Establish communications between the plant locations as specified in Table V for Hot Standby to Cold Shutdown (Mode 5).

NOTE Should Cold Shu~down not be required and Control Room access be regained:

1) Assign operators to the Control Room to coordinate with operators assigned at local stations while shifting back to REMOTE Control.

2) Coordinate restoration of the Solid State Protection System with the Performance Department Technicians.

3) Refer to EI 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 Control System. VCT level indicator is provided at Panel 216.

Salem Unit 2 Rev. 0

I-4.lO(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 2CV172, Boric Acid Flow Control Valve, install the "Hand Sender

at Panel 314.

3) To operate 2CV179, Primary Water Flow Control Valve, install the "Hand Sender' at Panel 314.

4) To operate 2CV185, Makeup Stop Valve, refer to item 30 of Table II. (2CV185 must be placed in MANUAL and then opened)

5) Start 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 j~s jesignee, of the inpending plant cooldown and the need to sample 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 2SS49, Pressurizer Liquid Sample Valve, refer to item 16 of Table II.

4.11.4 To open 2SS107, Pressurizer Liquid Sample Valve, refer to item 15 of Table T(_

4.12 After the Pressurizer boron concentration has been 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-enerqize all Pressurizer heaters .

4.12.4 Monitor RCS pressure and temperature at Panel 213. Operate the press~rizer Heaters as required to maintain RCS pressure such that the highest TH indication is at least SO"F below the saturation temperature as determined from Figure 1.

(i.e. if TE is SOO"F, maintain pressure qreater than the saturation pressure =or 550"F).

Salem Unit 2 Rev. 0

I-4.lO(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, Xenon-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 between the operator(s) in the Penetration Area(s) and Panel 213.

4.14.4 Take local-manual control, using "Hand Senders" in local control panels in the Penetration Areas, of the Atmospheric Stearn Relief Valves (MSlO Valves) and slowly increase the steam flow released to the atmosphere.

NOTE Manual handwheel operation of the MSlO valves is also available locally at each valve in the Penetration Areas.

4.14.5 Closely monitor Stearn Generator pressures at Panel 213.

Salem Unit 2 Rev. 0

I-4.lO(A) 4.14.6 Plot, on Operations Log #4, 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 RCS temperature decreases to, or below 547°F, close, if deemed necessary, the Steam Generator Stop Valves {MS167) by use of test switches provided in local panels in the Penetration Area.

NOTE Leaving the MS167 valves open will help maintain Steam Generator Pressures approximately equal.

4.18 As cooldown progresses, adjust charging flow to gradually increase Pressurizer level to ~ 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-115, FI-116, 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 Regenerative Heat Exchanger outlet temperature as read 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) .

Salem Unit 2 Rev. 0

I-4.lO(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 TH indication is at least 50°F below the temperature as determined from Figure 1 (i.e. if TH is 500°F, maintain pressure greater than the saturation pressure for 550°F) .

4.20 When the RCS pressure is < 1500 psig, open Reactor Coolant Pump Seal Bypass Valve 2CV114. 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 below 400°F, remove one (1) RCP from service by manually opening the power supply breaker 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 I

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 I

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 conjunction 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 Exchanger CCW outlet Valves as follows:

1) 2)

To open 21CC16 refer to item 4 of Table II.

To open 22CC16, refer to item 5 of Table II.

Salem Unit 2 Rev. 0

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 2RH20, RHR Heat Exchanger Bypass Valve, using the "Hand Sender" installed at Panel 101. (Increasing pressure from "Hand Sender" closes valve) 4.24.10 Verify 21 and 22RH29 are in AUTO per item 11 and 12 of Table II.

4.24.11 Monitor the position 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 concentra\ion.

4.24.13 If the boron concentration in the RHR 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.

3) After ~ 10 minutes of recirculating RWST water:

a) Close 2RH20 using the "Hand Sender" installed in Panel 101.

bl Notify Chemistry Department personnel to resample the RHR Heat ~xchanger Outlets for boron concentration.

Salem Unit 2 Rev. 0

I-4.lO(A)

4) If the RHR boron concentration is greater than or equal to the RCS boron concentration:

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 2RH2, RHR Common suction valves, as follows:

1) To operate 2RH1 refer 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 2CV17, Letdown Pressure Control Valve Isolation Valve.

NOTE The three CVCS Letdown Orifice Isolation Valves 2CV3, 2CV4 and 2CV5 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 approximately 10 minutes, increase RHR System temp-erature to RCS temperature as follows:

1) Slowly open 2RH20 to -v 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:

l~ Slowly open 21P.Hl8 and 22RH18 while closing 2RH20, using the "Hand Senders" installed in Panels 101 and 102.

Salem Unit 2 Rev. 0

I-4.10(.l>)

2) If 21RH29 and 22RH29 were opened manually 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 l\'hen RCS 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 Control Power.

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 Control Power.

NOTE A minimum of one Centrifugal Charging Pump must remain operable as a part of an ECCS Subsystem until RCS tempera-ture is below 200°F as required by the Tech 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 on the 2A-460V Vital Bus, Auxiliary Building, Elevation 84' .

4.25.3 As appropriate, open and rack out the breakers to both rr~lor-driven Auxi11a:

Feedwater Pumps and turn off the DC Control Power.

NOTE If it is necessary or desirable to use the Auxiliary Feed-water Pump(s) to maintain Steam Generator levels, removing the purnp(s) from service may be deferred until the pump(s) is no longer required.

1) The breaker for No. 21 AFW Pump is located on the 2A-4kV Vital Bus, Auxiliary

~.25.4 2)

Building, Elevation 64'.

The breaker for No. 22 AFW Pump is located on the 2B-4kV Vital Bus, Auxiliary Building, Elevation 64'.

Close 21MS45 and 23MS45, the steam supplv valves to No. 23 AFW Pump.

Si"lem Unit 2 I-4.lO(A) 4.25.5 Reduce the nunilier of running RCP's to two (2) in-service.

NOTE

~-~~~ to ~tep 4.24 above .

4.26 When the RCS temperatu=e reaches 312°F (as indicated at Panel 213) reduce RCS pressure to less than 375 psig (as indicated by PT-403 and PT-405 at Panel 213).

4.26.l With RCS pressure follows:

< 375 psig and RCS temperature is at 312°F, arm the POPS as

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 steam 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 Control Power.

1) The breaker for No. 21 CS Pump is located on the 2A-4kV Vital Bus, Auxliary Building, Elevation 64'.

2) The breaker for No. 22 CS Pump is located on the 2C-4kV Vital Bus, Auxiliary Building, Elevation 64'.

4.29 With the plant in Cold Shutdown (Mode 5) conditions should be maintained with:

4.29.1 One RCP in service.

4.29.2 Pressurizer bubble.

4.29.3 POPS armed.

4.29.4 RHR in-service.

epared by~~-C~a_r_t_e_r~_N_o_l~a_n~~~~~~~

Reviewed by~~-J~*-M_.~Z~u~p_k_o~~~~~~~~-

SORC Meeting No.~~~3_3_-_7~9~~~~~~~-

Salem Unit 2 Rev. 0

I-4.lO(A)

LOCAL CONTROL STATIONS

-p 13 NO. 2 UNIT HOT SHUTDOWN STATION [AUXILIARY BUILDING, ELEV. 84 I]

No. 21. 2 2 23&24 Steam *Gen. Pressure Indication Pressurizer Level Indication No. 21&22 Component Cooling Flow Indication Component Cooling Surge Tank Level A&B Indication Service Water No. 21&22 Header Pressure Indication 21-25 Cont. Fan Coil Unit Start/Stop Switch No. 21 22&23 Control Area Supply Fan Start/Stop Switch 21 22&23 Comp. Cool Pump Start/Stop Switch No. 21-26 Service Water Pump Start/Stop Switch Letdn Orifice Isol. v 2CV3 4&5 Open/Close Switch No. 21&22 Boric Acid Transfer PumP Start/Stop Switch No. 21&22 Charging Pump Start/Stop Switch No. 21 22.23&24 Steam Gen. Level Indication No. 2 Emerg. Air Compressor Start/Stop Switch Pressure Indication - RCS & Pressurizer RCS Wide Range Temperature Indication PANEL 205 NO. 2 UNIT NO. 21 AUXILIARY FEEDWATER PUMP PANEL [AUXILIARY BUILDING, ELEV. 84' l No. 21 Aux. Feed Pump Start/Stop Switch 21 Aux. Feed Pump Discharge Pressure Indication 21 Aux. Feed Pump Suction Pres s.ure Indication 23&24AF21 Press Override Toggle Switch PANEL 206 NO. 2 UNIT NO. 22 AUXILIARY FEEDWATER PUMP PANEL [AUXILIARY BUILDING, ELEV. 84']

No. 22 Aux. Feed Pump Start/Stop Switch 22 Aux. Feed Pump Discharge Pressure Indication 22 Aux. Feed Pump Suction Pressure Indication 21&22AF21 Press Override Toggle Switch PANEL 207 NO. 2 UNIT NO. 23 AUXILIARY FEEDWATER PUMP PANEL [AUXILIARY BUILDING, ELEV. 84 I]

No. 23 Aux. Feed Pump Start/Stop Switch No. 23 Aux. Feed Pump Iner/Deer Switch No. 23 Aux. Feed Pump Start/Stop Switch 23 Aux. Feed Pump Steam Pressure Indication 23 Au Feed Pump Discharge Pressure Indication 23 Aux. Feed Pump Suction Pressure Indication p; 6 NO. 21-22-23 CHARGING PUMP FLOW & PRESSURE PANEL [AUXILIARY BUILDING, ELEV. 84 I]

No. 21,22&23 Charging Pumps Flow Indication No. 21&22 Charging Pump Pressure Indication No. 21&22 Chg Pmps Flow to Regen-Heat Ex ch Indication Volume Control Tank Level Indication

( 2CV55 Auto/Manual Selector) 2CV55 Manual Hand-Air Regulator Control PANEL NO. 2 GP AND NO. 2 EP PRESSURIZER HEATERS [ELECTRICAL PENETRATION AREA, ELEV. 78 I]

Pressurizer Heater On/Off Switch Pressurizer Heater Breakers PANEL 379 No. 2 UNIT AUXILIARY FEEDWATER STORAGE TANK PANEL [OUTSIDE AUXILIARY BUILDING W.' ELEV. 100' l l\uxiliary Feedwater Tank Level Indication Aux. Feed Pump Suction Pressure Indication PANEL 687 2A,B,C&D MAIN STEAM STOP VALVE MS167 LOCAL CONT STA [N & s PENETRATION AREA, ELEV. 100 I]

~Sl67 Close/Open/Bypass Valve Open/Test Selector Switch PANEL 684-2A,B,C&D NO. 2 UNIT STM GEN PRESS CONTROL PANEL [N & s PENETRATION AREA, ELEV. 100' l

'ISlO Local/Remote Selector MSlO Manual Hand-Air Regulator Control ROD DRIVE MG SET CONTROL PANEL [AUXILIARY BUILDING, ELEV. 84 I]

Reactor Trip Breaker A&B Reactor Trip Bypass Breaker A&B MAG-A-STAT REGULATOR POWER UNIT [TURBINE AREA, ELEV. 120' l

enerator Exciter Field Breaker TABLE I Salem Unit 2 Rev. 0

I-4.lO(A)

TABLE II VALVE OPERATIONS INSTRUCTIONS (See Figures No's 2 and 3 for TP and RC Layouts)

VALVE STATUS DETERMINATION In the column marked STATUS, terminal points are entered which correspond to the position (OPEN, CLOSE) or mode of operation (AUTO, MANUAL) of the valve. Presence of the specified voltage between these points and common is indicative of the status of the valve.

VALVE OPERATION Operation of valves will be accomplished at the blue ribbon connectors in the Relay Cabinets (RC). The column 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 jumper between the +28VDC source in the Relay Cabinet and the designated pin on the blue ribbon connector. Remove the jumper and verify valve status as discussed above or locally at the valve.

NOTE Insulated jumpers are provided in the cabinet near Panel 213 for use in jumpering PINS on the Blue Ribbon connectors on the Relay Cabinets .

Salem Unit 2 i ~ev. 0

I-4.lO(A)

VALVE OPERATIONS STATUS OPERATION f

l JUMPER i ~

M +28VDC BLUE RIBBON RESULT OF COMMON POINT OF NO. VALVE SOURCE CONNECTOR OPERATION ( . ' M1"~!=:.Tn<F.MF.N'l' VOLT AC~~ !':.ri:1FM""'Tr 1 2CV243 RC 22-7 RC22-7 11-1-11 7-3-13 PIN 23 OPEN NA NA NA 218848 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 125VDC 3 2CV114 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-l 211529 11-1-19 3-4-10 OPEN TP21-l 2-4-E PIN 7 2-4-B 115VAC RC21-3 TP21-l 3-4-10 CLOSE 2-4-F PIN 5 115VAC 22CC16 RC22-3 RC22-3 TP22-l 11-1-19 3-4-10 OPEN 2-4-E 115VAC 211530 PIN 7 TP22-l RC22-3 2-4-B TP22-l 115VAC 3-4-10 CLOSE 2-4-F PIN 5 6 2SJ69 RC23-4 RC23-4 TP23-2 TP23-l 11-1-17 4-9-10 OPEN 2-4-R 4-4-E 125VDC 211508 PIN 7 (NOTE : Col!DllOn RC23-4 in adjacent TP23-l 125VDC 4-9-10 CLOSE TP) 4-4-F PIN 5 7 21SJ49 RC21-4 RC21-4 TP21-l 11-1-15 4-6-1 OPEN TP21-2 4-2-E 125VDC 211509 PIN 7 5-3-B 211510 RC21-4 (NOTE: Common TP21-l 125VDC 4-6-1 CLOSE in adjacent 4-2-F PIN 5 TP) 8 22SJ49 RC22-4 RC22-4 TP22-l 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-l 4-6-1 CLOSE in adjacent 4-2-F 125VDC PIN 5 TP) 9 21RH19 RC21-4 RC21-4 TP21-l I.

11-1-15 4-7-13 OPEN TP21-l 4-2-X 115VAC 211509 PIN 7 4-2-Z 211510 RC21-4 TP21-l 4-7-13 CLOSE 4-2-Y 115VAC PIN 5 I

Salem Unit 2 TABLE II Rev. 0 I-4.lO(A)

VALVE OPERATIONS OPERATION

~us l JUMPER l R ITEM +28VDC BLUE RIBBON RESULT OF COMMON POINT OF NO. VALVE SOURCE CONNECTOR OPERATION (-) MEASUREMENT VOLTAGE SCHEMATIC 10 22RH19 RC22-4 RC22-4 TP22-l 11-1-15 4-6-7 OPEN TP22-l 4-2-X 115VAC 211511 PIN 7 4-2-Z 211512 RC22-4 TP22-l 4-,6-7 CLOSE 4-2-Y 115VAC PIN 5 11 21RH29 RC21-4 RC21-4 TP21-l 11-1-21 4-9-7 OPEN TP21-l 4-5-E 115VAC 211555 PIN 23 4-5-B RC21-4 TP21-l 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 RC22-4 RC22-4 TP22-l 211556 11-1-19 4-9-7 OPEN 4-5-E 115VAC PIN 23 TP22-l RC22-4 4-5-B TP22-l 4-9-8 CLOSE 4-5-F 115VAC 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-l 11-1-13 4-6-10 OPEN 4-1-U 115VAC 211506 PIN 23 TP22-l ' 211507 RC22-4 4-1-R TP22-l 4-6-10 CLOSE 4-1-V 115VAC PIN 7

~,

14 2RH2 RC21-4 RC21-4 TP21-l 211504 11-1-13 4-4-13 OPEN 4-1-U 115VAC 211505 PIN 23 TP21-l RC21-4 4-1-R TP21-l 4-4-13 CLOSE 4-1-V 115VAC 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 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 I

TABLE II Salem Unit 2

I-4.lO(A)

VALVE OPERATIONS OPERATION

~us i JUMPER

~

+28VDC BLUE RIBBON RESULT OF COMMON POINT OF !

I NO. VALVE SOURCE CONNECTOR OPERATION (-) MEASUREMENT fJOLTAGE SCHEMATIC I 18 2SS33 RC25-7 RC25-7 TP25-2 220924 11-1-7 7-7-7 OPEN 5-1-L 125VDC I PIN 7 TP25-2 NOTE 1 I RC25-7 5-1-B TP25-2 i 7-7-8 CLOSE 5-1-M 125VDC !

PIN 7 I 19 2PR1 RC24-6 RC24-6 TP24-2 224082 11-1-15 6-8-1 OPEN 3-3-D 125VDC I PIN 7 TP24-2 224083 RC24-6 3-3-B TP24-2 II I

6-8-2 CLOSE 3-3-E 125VDC PIN 7 RC24-6 RC24-6 6-8-1 AUTO 6-8-1 28VDC PIN 23 RC24-6 PIN 24 RC24-6 11-1-16 RC24-6 i 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 115VAC 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 PIN 7 TP25-2 224085 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 llSVAC PIN 23 TP25-2 224085 RC25-6 3-3-X TP25-2 6-8-7 CLOSE 3-3-W llSVAC 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 125VDC PIN 7 I

TABLE II Salem Unit 2 Rev. 0

I-4.lO(A)

VALVE OPERATION OPERATION

~us

! JUMPER i R

+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 PIN 7 TP22-2 211673 RC22-6 2-5-B TP22-2 6-6-2 CLOSE 3-1-H 125VDC PIN 7 27 23SJ54 RC23-5 RC23-5 TP23-l 217126 11-1-9 5-5-1 OPEN 5-4-F 125VDC PIN 7 TP23-l 217127 RC23-5 5-5-B TP23-l 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 1-1-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 125VDC I PIN 3 MANUAL TP22-2 RC22-7 FLOW TO 5-2-B TP22-2 7-7-4 HUT 5-2-D 125VDC PIN 23 MANUAL 2CV185 RC21-7 RC21-7 TP21-2 211598 11-1-13 7-3-1 OPEN 5-2-C 125VDC 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 f.'.ANUAL 7-3-4 28VDC PIN 5 PIN 10

NOTE 1: Voltage will pickup as soon as valve leaves closed position (OVC limit switch).

TABLE II Salem Unit 2 Rev. 0

I-4.lO(A}

POPS INITIATION OPERATION JUMPER

+28VDC BLUE RIBBON RESULT OF COMMON POINT OF NO. CHANNEL SOURCE CONNECTOR OPERATION (-) MEASUREMENT OLTAGE 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 .

TABLE III Salem Unit 2 Rev. 0 J

I-4.lO(A)

PUMP OPERATION OPERATION

~us l JUMPER ~ R J. +2BVDC BLUE RIBBON !RESULT OF COMMON POINT OF NO. PUMP SOURCE CONNECTOR OPERATION (-) MEASUREMENT VOLTAG:E 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. 0

I-4.lO(A)

OPERATING STATIONS

STATION

1. Panel 213 Maintaining Hot Standby PRIMARY FUNCTION Overall control and monitoring.

2. Auxiliary Feed Pumps Maintain Steam Generator levels.

(Panels 205,206,and 207)

3. Panel 216 Maintain p~essurizer 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 MSlO 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 Standby 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).

TABLE V Salem Unit 2 Rev. 0

I-4.lO(A)

Hot Standby to Cold Shutdown (Mode 5)

STATION

4. Panel 101 and 102 (El. 45' Aux. Bldg)

PRIMARY FUNCTION 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 2CVB .

TABLE V Salem Unit 2 Rev. 0

I-4.10 (A) 700 -~~-:-,..

1~:-:...:

=

680 h1.:

c::...-** --

I=*--'

660 640 i-:-;. -* . --- - _ _,,

620 600 ---- =

580 560 540 520 i--..o- -

I--- ---- -- -

500

~ ~

i-:..:..:-: -- *- .:;: -

--=

480 f - - - *- --

460

>-:.:..:...L.:....::- - *->-:-:..:..: --

~--

_...:.:===--

440 --

.: . ----+---

1--

- -- - *-- - - - _- *.J -- :-----t-::-:-

420 - *- --- ~--~~;;:~=~k

==:J:=---- .:. : *-L- -~i=-~.:=-~~

400 *- - *--" * ---<

1-

--1-~~~

---r----

=

380 t-- -f4--

t::::: -:

-==+=-

t== :=!= :=-

360

~ti:- - T--~--

=l°----.=--~-

....____ ---- *-- --L-

=+---- -

I--- -

_: -i:=-= : -~=~~

340 -----

__ I=-

r:=*

--~

320 -- - - --

300 _ _ _ _ J __

__ .__ .- r----- I ____ ._:.:.:_ I - - -

-- --+--==

~- - - - L - f . -

280

__ ;..,.=

260

=

240 220 200 -

0 400 800 1200 1600 2000 2400 SATURATION PRESSURE Salem Unit 2 FIGURE NO. 1 Rev. o' J

I-4.lO(A)

RELAY CABINET (RC) LAYOUT AND CONNECTOR NUMBERING I TERMINALS 1 THROUGH 40 l POSITIONS 11- 1-1 THROUGH 40 (28VDC SOURCE AND COMMON)

EJ2 EJ3 EJ4 EJ5 E3 EJ7 EJ8 EJ9 EJ10 E3 6 11 SUPPLY BREAKE RS 1 CABLE CONNECTIONS 17 1 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 18 2 2

DDDDDDDDDDDDDDD 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 19 20 21 3

4 5

3 DDDDDDDDDDDDDDD/

15 14 13 12 11 10 9 8 7 6 5 4 3 2 i/

22 23 6

7 E XAMPLE:

7-4 -1

~LUE RIBBO:l' 24 8 4

DDDDDDDDDDDDDDD 15 14 13 12 11 10 9 8 7 6 5 4 3 2 ~

25 26 9

10 CONNECTOR ROW CABINET 5

DDDDDDDDDDDDDDD 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 -

27 28 29 11 12 13 k=J PIN 12 6

UDDDDODDDDDDDDD 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 30 31 14 15 32 16 7

ODDDDODDDDDDDDD 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 BLUE RIBBON CONNECTOR noooooooooooooo 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 9

o DD0DD00 D00 DD00 10 CABLE CONNECTIONS VIEW LOOKING AT BLUE RIBBON CONNECTORS FIGURE NO. 2 Salem Unit 2 Rev. 0 J

I-4.lO(A)

TERMINAL CABINET (TP) LAYOUT AND TERMINAL BOARD NUMBERING COLUMN 1 2 3 4 5 A 1 ROW 1-1 1-2 1-3 1-4 1-5 B 2 1 c 3 D D D D D D 4 E 5 2-1 2-2 2-3 2-4 2-5 F 6 2 H 7 D D D D D J 8 K 9 3-1 3-2 3-3 3-4 E XAMPLE:

3-5 L 10 0

3 3 M 11 D D D D N p

12

\ \. TERMINAL POINT

\_COLUMN 13 4-1 4-2 4-3 ROW 4-4 4-5 R 14 0 0 0 D D s T

15 16

µ (See Note Below) u 17 5

5-1 0 0 0 0 5-2 5-3 5-4 n v w

y x

z 18 19 20 21 22 VIEW LOOKING AT TERMINAL BOARDS AA 23 BB 24 TERMINAL BOARD NUMBERING NOTE: Letters do not appear on terminal boards.

FIGURE NO. 3 Salem Unit 2 Rev. 0

-'--.-**- . ---~-- -.. - ~--~-'-- _::.

I-4 .11 EMERGENCY INSTRUCTION I-4 .11 HIGH REACTOR COOLANT ACTIVITY

1. 0 DISCUSSION 1.1 This 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 ~1.0 wCi/gram DOSE EQUIVALENT I-131 and ~100/E µCi/gram. These limits apply in modes 1 and 2 and in mode 3 when T >500°F.

avg 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 wh_en called out by Emergency Instruction I-4 .16, "Radiation Incident", which is effective upon the receipt of any RMS Alarm. However, if this procedure is required to be used at any other time, reference should be made to 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. O

µCI/gram or > 100/E µCi/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 IMMEDIATE ACTIONS 3.1 Automatic None 3.2 Manual None Sale~ Unit l/Unit 2 Rev. 3

...... -------*~-------~"'-a-.*-...._..._ ____ *- --- -----"--. -** ---

~. I-4 .11

\ '

_ . p, 4.0 SUBSEQUENT ACTIONS

"/

4.1 If a RMS Alarm has actuated, refer to the appropriate section of EI I-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) and 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 deminerlizcc in series.

4.6 If the reactor coolant activity continues to rise, valve in the standby mixed bed demineralizer and periodically sample the inlet and the outlet for activity.

4.7 Continue to reduce reactor coolant activity by maximum 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 reactor 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 evolution, the cause must be determined and if possible, corrected and the appropriate actions taken.

Prepared by~~~~J::.-=.*~V~.'-'B==a~i~l~e~v_,_~~~~~

Reviewed by~~~-R~*-J_.~M~c_C_a_r~t_h_y~~~~-

SORC Meeting No.~~0_5_3_-~7_9~~~~~~~ Date

I-4.12 EMERGENCY INSTRUCTION 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 Main Feed Pump, Condensate Pump, or Heater 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 and 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 and/or Safety Valves is probable.

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 (Fs > Fw and/or Fw > F ) on one or more Steam Generators. s~

-~

2.2 Erratic Steam Generator level indication. :.::i.

~~

2.3 Steam Generator level deviation alarms. '~

2.4 Low Feedwater header pressure.

2.5 Main Feed Pump trip.

2.6 Condensate Pump trip.

2.7 Heater Drain Pump trip.

,Jf-'

I

~

Salem Unit l/Unit 2 Rev. 2

I-4.12

,* t 3. 0 IMMEDIATE ACTIONS 3.1 Automatic 3.1.1 Feedwater Heater Bypass Valve 1(2)CN47 opens when the pressure at the suction of the Main Feed Pumps decreases to 265 psig.

3.1.2 Main Feed Pumps trip at 215 psig decreasing suction pressure. This will result in No. 11 & 12 (21 & 22) Auxiliary Feedwater Pumps starting. As Stearn Generator levels decrease, a Reactor Trip will occur as a result of one of the following:

a) Steam Flow > Feed Flow in coincidence with Low Level, or b) Low-Low Stearn 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 Stearn 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 Hea~~ain Pump tripping, investigate the cause and restore the pump to service as so~

practical. ~~

~~

4.3 Monitor Pressurizer pressure and Steam Generator pressure to insure ~~~ny relief valves which opened automatically, close when the pressure decrea~ below the actuating setpoint. ~

4.4

<<:~

If void formation in the RCS is indicated or suspected, pro~~:..s follows:

/: 4.4.1 Maintain all RCP's in operation to provide forced ~to the core.

4.4.2 Reduce Tavg to below the saturation temperatllt~ the existing RCS pressure (refer to the RCS pressure-temperature curve)~~operation of the Atmospheric st.~am Relief Valves (MS-101 on the unaffected Steam Generators or by use of th~ Steam Dump System in Pressure Control.

Salem Unit l/Unit 2 Rev *. 2

--~*~*--..:-=-----

I-4.12 4.4.3 Attempt to increase RCS pressure if; it is low by energizing the Pressurizer Heaters and verifying the Power Operated Relief Valves (PRl & 2) and the Spray Valves (PSl & 3) are closed.

Prepared by__________________

Manager, - Salem Generating Station Reviewed by _ _ _ _ _ _ _ _ _ _ _ _ _ _ __

SORC Meeting No*------------~ Date Salem Unit l/Unit 2 Rev. 2

I-4 .13 EMERGENCY INSTRUCTION r-4.13 LOSS OF CIRCULATING WATER

l. 0 DISCUSSION 1.1 Depending on the Unit load and the river water temperatur<\l, a Circulator can be removed from service to check for a Condenser tube leak, repair a Circulating Water Pump, or perform maintenance on the traveling screens. With a proper load 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 IMMEDIATE ACTIONS 3.l Automatic 3.1.1 None 3.2 Manual

3. 2 .l Reduce load as necessa.ry 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 neceissary to use the Atmospheric Steam Relief Valves (MSlO) to maintain Steam Generate~

pressure.

3. 2. 2 If both Circulating Wa*ter Pwnps to the. same low pressure turbine 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 >10%, 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 Condenser is blocked.

Rev. 3 4/24/78

I-4.13 4.0 SUBSEQUENT ACTIONS 4.1 Determine the reason for loss of the Circ~lating Water Pump(s) and correct or repair as necessary to return to service.

Prepared by~~~~-D~*~J_a_n_s_e_n~~~~~~~~~~~~~~~

Manager rating Stat~

SORC Meeting No.~_...7~8_-a2~6~~---

Rev. 3 4/24/73

.} ..

.. ./

I-4 .14 EMERGENCY INSTRUCTION

[*.

I-4.14 SERVICE WATER SYSTEM MALFUNCTION

!.}

l.O DISCUSSION l.l The purpose of this emergency instruction is to provide guidelines for plant operation during and subsequent l:o a malfunction in the Service Water System, either due to a flow decrease or an entire loss of flow.

l. 2 Since the Service Water System is an Engineering Safegua.rds System and is essential to all phases of plant operation, this instruction deals with the riecessa1:y course of action to be taken to place the plant in a safe condition in accordance with the Technical Specifications.

l.3 Technical Specification 3.7.4.l states that in Modes 1,2,3 and 4, "At least two independent service water loops shall be operable.n 1.4 Due to the design redundancy of the system, it is not credible to anticipate a compl~te 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.

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 Bay Part II Malfunction in Nuclear Header Part I I I 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 und/or low flow alarms for individual component;; are indicated either on the annunciator or the control console.

2.2 Service Water header pressure is decr~asing. The SERV WATER HE.'CJ)ER 11 or 12 (21 or 22)

LOW PRESS alarn1 may annWlciate, and the pump auto-start may occur.

2.3 The SERV WATER PMP 11, 12, 13 (21, 22, 23) AREA SU~JP HIGH LEVEL or SERV WATER PMP 14, 15, 16 (24, 25, 26) AREA SUMP HIGH LEVEL &la.rm may annunciate, indicating a pipe leak or rupture in the intake structure.

2.4 Elevated temperatures in the Containment, indicative of insufficient, or a loss of, Service Water flow to the Containment Fan Cooling units, may be indicated.

Rev. 4 4/24/78

I-4.14 2.5 Actuation of SERV WATER SCREENWASH 11,12,13(21,22,23) or 14,15,16(24,25,26) or 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 IMMEDIATE ACTION 3.1 Automatic 3.1.l The Service Water l?ump(s) in the AUTO mode will start, if the Service Water header pressure decreases to 80 psig.

3.2 l>Janual 3.2.l Start additional Service Water Pumps, as necessary, if the pumps in AUTO fail to start.

3.2.2 Notify plant personnel 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 lost, TRIP the unit.

Refer to EI I-4.3, "Reactor Trip".

4.0 SUBSEQUENT ACTIONS 4.l Proceed as necessary to verify that all safeguards equipment can be supplied with adequate Service Water flow. If necess~u-y, non-vital loads supplied from Service Water should be reinoved from service.

4.2 If a liquid release is in progress, verify that it is being discharged through a header with adequate dilution flow.

I. MALFUNCTION IN OR UPSTREAM OF A SERV7CE WATER BAY I-4.3 ! f 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.J.l Close 11(21) and 12(22)SW17 SW Ptunp Discharge Header Cross Connect Va.lve .

I-4.3.2

!-4.3.3 0

Close the affected N'uclear Header Supply Valve 12(22)SW20 or 14(24JSW20.

Open the Nuclear Header Cross Connect Valves ll(2l)SW23 and 12(22)SW23 to supply Service Water to the affected header's components.

Rev. 4 4/24/78

I-4.14 I-4.3.4 Stop the Service Water Pumps in the affected bay.

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(2l)SW20 or 13(23)SW20 from the affected bay to further isolate the bay.

I-4.3.7 Inform the appropriate personnel and take corrective action, as necessary, to return, the Service water System to a normal lineup IAW OI V-1. 3 .1, "Service Water - Normal Operation".

I-4. 3. B Return the inoperable Service Water J,oop 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 HE:ADER

'llY II-4.4 If it is determined that the cause of the loss or dropping Service Water flow is in one of the Nuclear Headers, perform the following:

II-4.4.l Close <;he affected Nuclear Header Supply Valve 11(21) or l2(22)SW20 or l4{24)SW20.

II-4.4.2 Close the affected Nuclear Header Isolation Valve 11(21) or l2(22)SW22.

II-4.4.3 Open Nuclear Header Cross Connect Valves ll{2l)SW23 and 12(22JSW23 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 appropriate personnel and take corrective action, as necessary, to return the Service Water System to a normal lineup IAW or V-1. 3 .1, "Service Water - Normal Operation".

II-4.4.6 Return the inoperable Service Water Loop to operable status within the time frame specified in Technical Specification 3.7.4.l or proceed to Cold Shutdown IAW the following instructions:

OI I-3.S, nMinimum Load to Hot Standby" OI I-3.6, "Hot Standby to cold Shutdown"

Rev. 4 4/24/78

I-4 .14

\.

f III. MALFUNCTION IN TURBINE AREA HEADER

=======-

III-4.5

"' "'"' =

If it is determined that the cause of the loss or dropping Service Water flow is in the Turbine Area Header, perform the following:

III-4.5.1 Close the TG Header Supply Valves ll(2l)SW20 and l3(23)SW20.

III-4.5.2 Close 1(2)SW26 TG Header Isolation Valve.

I!!-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 lost.

III-4.5.4 Stop the following pumps:

11, l2, l.3 (21, 22, 23) Condensate Pumps ll,12,13(21,22,23) Heater Drain Pumps ll,l2(21,22) Bleed Steam Coil Drain Tank Pumps III-4.5.5 If the Unit No. l 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:

l) Open lST21 and 2ST21 Station Air Compressor Supply Cross Connect Valves.

NOTE Opening these two valves will immediately supply Service Water to the Station Air Compressors from Unit No. 2 discharging from Unit No. l.

2) Open lST13 and 2ST13 Station Air Compressor Outlet Cross Connect Valves.

3) Close lST14 Station Air Compressor Outlet Throttle Valve.

NOTE Service Water to the Station Air Compressors will now be supplied from and returned to Unit No. 2.

!II-4.5.6 Inform the appropriate personnel and take corrective action, as necessary, to return the Service Water System to a normal lineup IAW or V-1.3.l, nservice Water - Normal Operation".

III-4.5.7 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" *

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 Minimum Load" OI I-3.4, nPower Operation~

Rev. 4 4/24/78

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

I-4.14 PART IV IV. MALFUNC'!'ION IN DOWNSTREAM COMPONE:'ITS IV-4.6 If it is determined that the cause of a loss or dropping Service Water flow is in a downstream component, either in the components supplied from the Nuclear Headers or the Turbine Header, perform the following:

IV-4.6.l If Service Water is lost to a component by either a rupture or blockage, isolate the affected component and perform the following:

l) If Service Water to a Turbine - Generator Auxiliary has been lost, trip the plant and refer to EI I-4.3, "Reactor Trip". :.iaintain Hot Standby IAW or I-3. 5, KMinimum Load to Hot: Standby".

2) If Service Water to a component supplied from a Nuclear Header has been lost, refer to that component's appropriate Technical Specification, as applicable.

IV-4.6.2 If Service Water to a component is lost due to a control valve malfunction, take manual control of the affected valve and perforn1 the following:

1) If the malfunctioning valve is to a Turbine - Generator Auxiliary, maintain r* manual control attempting to maintain normal 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, as applicable.

IV-4.6.3 Inform the appropriate personnel and take corrective action, as necessary, to return the Service Water System to a normal lineup IAW or V-1.3.1, "Service Water - Normal Operation".

IV-4. 6. 4 When _service Water is restored to a normal lineup and, i f the plant has been tripped, take the plant to Power Operation IAW the following instructions:

OI !-3.4, "Hot Standby to Minimum Load" OI I-3.5, "Power Operation" Prepared by R. Hallmark /lfe<<~~

Manager _,,,Salem Gerttrating Station

SORC Meeting No.~~7_8_-_2~6~~~~~~

-s- Rev. 4 4/24/iB

I-4.15

, I EMERGENCY INSTRUCTION I-4.15 LOSS OF COMPONENT COOLING

1. 0 DISCUSSION 1.1 This instruction provides guidelines for plant operation during and following a failure in the Component Cooling System, either due to a loss of flow, a pipe rupture, or inleakage from another 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 condition 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 Cooling System malfunctions, and is presented in two separate parts in the subsequent actions:

PART I LOSS OF COMPONENT COOLING DUE TO LOSS OF FLOW (loss of pumps, pipe rupture, or flow blockage).

PART II INLEAKAGE TO THE COMPONENT COOLING SYSTEM (from components which it supplies).

SY~1PTOMS 2.1 The following would be indicative of out-leakage from the Component Cooling System:

2.1.1 Decreasing CCW Header pressure.

2.1.2 Increasing pump amps on the running CCW pumps.

2.1.3 Decreasing Component Cooling Surge Tank level.

2.1.4 Increasing Cor.tainment Sump level.

2.2 Increasing temperatures on components supplied CCW is indicative of a decrease in flow due to a flow obstruction, fouling of heat exchanger tubes, rupture upstream of the component, or a loss of pumps.

2.3 The following would be indicative of inleakage to the CCW System:

2.3.1 Increasing activity level on either header.

2.3.2 Increasin9 Componet Cooling Surge Tank level.

3. 0 IM;*!E!:>IATE ACTIONS 3.1 Automatic 3.1.l The CW Surge Tank Vent Val~e 1(2)CC1~9. will =lose en high activity on either RMS Channel Rl 7A *'.)r Rl 7B.

Salem Unit l/C~it 2 Rev. 3

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4.2 II. INLEAKAGE TO THE COMPONENT COOLING SYSTEM NOTE Attempts to isolate inleakage should proceed one component

4.2.1 at a time with sufficient time betwe~n steps to allow the Component Cooling System to stabilize. Each component should be returned to its original condition, if it is determined not to be the faulted component.

If the Component Cooling Surge Tank level is increasing with no increase in activity on either Rl7A, or 17B, proceed as follows:

1) Verify 1(2)CC145 and 1(2)CC146 are closed.

2) Close 1{2)DR10

3) Close 1(2)WR14

4) Isolate No. 11(21) Component Cooling Heat Exchanger as follows:

a) Verify 1{2)CC30 and 1{2)CC31 are open.

b) Close 11{2l)CC6 and 11(2l)CCB.

5) Isolate No. 12 (22) Component Cooling. Heat Exchanger as follows:

a) Verify 1(2)CC30 and 1{2)CC31 are open.

bl Close 12(22)CC6 and 12(22)CC8.

4.2.2 If the Component Cooling Surge Tank level is increasing with an accompanying

(,_J increase in 1) activit',"_lev~l<<-"n either Rl7A or 17B, proceed as follows:

When the ~***--*-----:*is reached on either Rl7A or Rl7B, verify 1(2)CC149 Surge Tank Vent is closed.

2) Isolate No. 11 Residual Heat Exchanger as follows:

a) Close 11(2l)RH14, 11{2l)RH17, 11(2l)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.

cl Close 11{2l)CC11 and 11{2l)CC16

3) Isolate No. 12(22) Residual Heat Exchanger as follows:

a) Close 12(22)RH14, 12{22)RH17, 12(22)RH18 bl Stop No. 12(22) RHR Pump.

Salem Unit l/Unit 2 Rev. 3

~ .:_._,__...:. ***- .; . - . --

I-4.16 EMERGENCY INSTRUCTION

1. 0 DISCUSSION I-4.16 RADIATION INCIDENT 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 contaminants (liquids, solids or gases). It is impossible to preplan for every conceivable incident that could occur. It will be necessary to evaluate each incident or. an individual basis~ When making the decision as to what actions should be taken, keep in mind the followincr areas of concern:

1.1.l 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.

I-2. 0 AREA RADIATION MONITORS 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(2)-R4 Charging Pump Room 1(2)-RS Fuel Handling Building R6A Sampling Room 1(2)-R7 In-Core Seal Table RS Waste Load Out 1(2)-R9 Fuel Storage Area 1(2)-RlOA Personnel Hatch El. 100' Cont.

1(2)-RlOB Equipment Hatch El. 130' Cont.

R20B Counting Room 1(2i-R21 Containment Post Accident R22 Solid Waste Area Sal~m Lnit 1 and 2 Rev. 5

I-4.16 R23 Monitoring Room (Local Only) 1(2)-R32A Fuel Handling Crane (Local Only) 1(2)-R23B Cask Handling Crane (Local Only) 1(2)-R34 Mechanical Penetration Area El. 100' 2-R42A 21 Gas Decay Tank 2-R42B 22 Gas Decay Tank 2-R42C 23 Gas Decay Tank 2-R42D 24 Gas Decay Tank I-3.0 IMMEDIATE ACTIONS I-3.l 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, if 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 interlock.

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) parameters, air monitors, and other radiation monitors to determine the cause and the extent of the high radiation condition. Request radia~ion protection personnel to take samples and/or surveys 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 3.3.3.1.

I-3.2".5 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) anc noti=y t~e Senior Shift Supervisor/Shift Supervisor.

I-3.2.6 Impleme~~ Emergency Procedure EP I-3 on valid alarms from R.~S C~ar.nel RS or R9. DO ~OT per:or~ the following Subse~uent Actions.

I-4. 0 SUBSEQUENT ACTIONS I-4.l Dispatch radiation protection personnel to the affected area(s) to investigate the cause of the high radiation condition and/or to conduct an initial survey .

~-4.2 The radiation protection personnel shall, if possible, report 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 cor.ditions permit, the radiation protection personnel should attel".?t to isola-.:e a::d.'cr contain the radiation.

a:-:C: 2 Rev. S

I-4.16 I-4.3 The Senior Shift Supervisor/Shift Supervisor shall evaluate survey results, plant conditions and any recommendations from the radiation protection personnel and determine if the radiation problem is excessive and controllable and as necessary:

I-4.3.l 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.

I-4.~ When possible, and if required, decontaminate the affected area, make the necessary repairs, corrections, etc., and return system(s) to normal !AW AP-24, Radiation Safety Program.

?~OCESS R.;_DIA~ION MON~TORS II-2.l RMS PROCESS HIG!-! RADlATIO~: (Unl.l. 1) o:r :!:t'1S TROUBLE (Uni;_ 2) Annu.r1ciu.i:or Alar:"'\.

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 l-Rl2A Containment or Vent Gas Effluent l-Rl2B Containment or Vent Gas Effluent (Iodine) 2-RllA Containment Sampling Particulate 2-Rl2A Containment Sampling Noble Gas 2-Rl2B Containment Sampling Iodine 1(2)-Rl3A No. 11 (21) Fan Coil Unit Cooling Water 1(2)-Rl3B No. 12(22&24) Fan Coil Unit Cooling Water 1(2)-Rl3C No. 13 (23&25) Fan Coil Unit Cooling Water l-Rl3D No. 14 Fan Coil Unit Cooling Water l-Rl3E No. 15 Fan Coil Unit Cooling Water 1-RH Waste Gas Effluent 1(2)-Rl5 Condenser Air Ejector 1(2)-Rl6 Plant Vent Effluent 1(2)-Rl7A Component Cooling Liquid 1(2)-Rl7B Component Cooling Liquid 1(2)-RlB Liquid Waste Disposal 1(2)-Rl9A No. 11(21) SG Blowdown 1(2)-Rl9B No. 12(22) SG Blowdown 1(2)-Rl9C No. 13(23) SG Blowdown 1(2)-Rl9D No. 14(24) SG Blowdown R20A Chemistry Laboratory Particulate (Local Only~

1(2)-R31 Letdown Lin~ Failed Fuel Rev. 5 Salem Unit l and 2

.- !. ~5 ll2J-R35 SG Biowdown ril~er Discnars~

1(2)-R36 Evap. and Feedwater Preheater Condensate 2-R41A Plant Vent Sampling Particulate 2-R41B Plant Vent Samplina Iodine 2-R41C Plant Vent Sampling Noble Gaa II-3. 0 I.V:.'.'!EDL'\TE ACTION II-3.1 Automatic II-3.1.1 Interlock associated with the alarming channel, as delineated in Table II, actuates.

II-3.2 Manual II-3.2.1 Verify, if possible, that the interlock associated with the alarming channel, as delineated in Table II, has actuated; if not actuated, manually perform the actions required to satisfy the interlock.

II-3.2.2 Perforn a check on the alarming channel. The check should include:

1) Setpoint verification.

2) Channel check with the check source.

NOTE 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 ?rotection personnel to take samples and/or surveys, if possible.

II-3.2.4 If the alarm is found to be invali~ 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 affected area(s) and/or system(s) and notify the Senior Shift Supervisor/Shift Supervisor.

II-3.2.6 Implement Emergency Procedure EP I-4 on valid alarms from RMS Channels 1(2)RllA, 1{2)Rl2A, 1{2)Rl2B, 2R41A, 2R41B, or 2R41C. DO ~OT p~rform the following Subsequent Actions.

Salem Unit l and 2 Rev. 5

I-4.16 II-4.0 SUBSEQUENT ACTIONS II-4.1 Dispatch radiation protection personnel to the affected area(s) to investigate the cause of the high radiacion condition and/or to conduct an initial survey.

II-4.2 The radiation protection personnel shall, if possible, report 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 The Senior Shift Supervisor/Shift Supervisor shall evaluate survey results, plant conditions and recommendations from the radiation protection personnel and.

determine if the radiation problem is excessive and controllable and, as necessary:

II-4.3.l 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; 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.

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.

I!I. ?RCCESS FILTER RADIATION MONITORS III-2.0 SYMPTOMS III-2.l RMS PROCESS FILTER HIGH RAD (Unit 1) or Rl*!S TROUBLE (Unit 2) Annunciator Alarm.

Ii.:-2.2 Indication and/or alarM of high radiation on the following re~ote (including Unit 2 CRT) and/er local process filter monitors:

CHANNEL PURPOSE l (2) -R24A Seal Wacer Injection Filter 1(2)-R24B Seal Water Injection Fi~ter 1(2) -R25 Seal Water Filter 1 (2) -R26 Reactor Coolant Filter 1 (2) -R27 Liquid Waste Filter 1 (2) -R28 Spent Fuel Pit Filter 1 ( 2 i -R29 j_."2'-?.33 1(2)-RJB SteaM Generator Blowcown rl~c~r 1(2)-R40 Conder.sate Filter Salem Unit 1 and 2 Rev. 5

I-4.16 III-3.0 IMMEDIATE ACTIO~S

III-3.1 III-3. 2 Automatic III-3.1.l Manual None III-3.2.1 Perform a check on the alarming channel. The check should include:

1) Setpoint verification.

2) Channel check with the check source.

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.

II!-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 Actuation of an fil"S process filter channel alarm could be indicative of a spent filter and, if ~erified as such, the appropriate personnel should be informed.

III-4.3 The Senior Shift Supervisor/Shift Supervisor shall evaluate the situation and, if necessary, refer to the appropriate Emergency Instruction listed in Table III.

Prepared by R. Hallmark -~~at:;~

Manager L;al~nerating Station Re'liewed by F. C. Schnarr SORC Meeting No. _ _ _ _ _2_3_-_7_9___________

Salem Unit 1 and 2 I-4.16 AREA RADIATION MONITORS CHANNEL NAME INTERLOCK EMERGENCY INSTRUCTIONS (Reference)

)RlA CONTROL ROOM 1. Control Room Ventilation Isolation EP-I-3 Plant (Unit) Emergency 1(2)R2 CONTAINMENT 1. None EI-I-4.4 Loss of Reactor Coolant EI-I-4.11 High Reactor Coolant Activity EI-I-4.17 Partial Loss of Reactor Coolant EI-I-4.20 Failure of RCP R3 RADIO-CHE!!ISTRY LAB 1. None 1(2)R4 CHARGING PUMP ROOM 1. None EI-I-4.4 Loss of Reactor Coolant EI-I-4.11 High Reactor Coolant Activity EI-I-4.17 Partial Loss of Reactor Coolant 1(2)RS FUEL HANDLING BUILDING 1. Fuel Handling Area Hi-Rad Alarm EI-I-2.8.1 Fuel Handling Incident

2. FHB e~haust shifts to HEPA Charcoal Filt EP-I-3 Plant (Unit) Emergency R6A SAMPLING ROOM 1. None 1(2)R7 IN-CORE SEAL TABLE 1. None EI-I-4.4 Loss of Reactor Coolant EI-I-4.11 High Reactor Coolant Activity EI-1-4.17 Partial Loss of Reactor Coolant RE WASTE LOAD OUT 1. None 11 (2) R9 FUEL STORAGE AREA 1. Fuel Handling Area Hi-Rad Alarm EI-1-2.8.1 Fuel Handling Incident

2. FHB exhaust shifts to HEPA Charcoal File EP-1-3 Plant (Unit) Emergency J)RlOA PERSONNEL HATCH TO CONT. 1. None l(2)RlOB,EQUIPML~T HATCH TO CONT. 1. None R20B !COUNTING ROOM 1. None i::.(2)R21 lcoNTAINMENT EL. 130' 1. None El-1-4.4 Loss of Reactor Coolant

j (North Axis) El-1-4.11 High Reactor Coolant Activity El-1-4.17 Partial Loss of Reactor Coolant I i R~'

""~ SOLID WASTE AREA 1. None R:3 !MONITORING ROOM 1. None

!1*.2: R32A ;FUEL HANDLING CR..'.!-IE 1. Energizes crane yellow warning light El-1-2.8.1 Fuel Handling Incident I l 2. Prevents hoist-up operation of crane i1 ':2 J R32B !cASK H.~--DLING CRANE 1. Energizes crane yellow warning light EI-1-2.8.l Fuel Handling Incident

! 2. Prevents hoist-up operation of crane I j I

jl *'. 2 )l~.34 jMECHANICAL PENETRATION 1. None EI-I-4.4 Loss of Reactor Coolant i El-I-4.11 High Reactor Coolant Activity l EI-I-4.17 Partial Loss of Reactor Coolant I i

.224~A *21 1. None lEI-I-4.11 High Reactor Coolar.~ Ac~ivit:*;

~;,.s !:lEC.".i' TANK

.:.~:3

~.,

"'~ G.;5 !:lE'.:AY TANK 1. None :EI-I-4.11 ~igh i\eactor Coolar..": Ac-:.:.*,;i ":y

,.,_ 1. None . EI-I-4.11 Higr. ?.eact::>r C::>ola:-:: ~-=~i.vi~::

I_,

.:.~ GAS ::lEc;;y TANK

42!) ;~4 GAS CJEC:AY '!'ANK I 1. None ! S!-I-4.11 Hii;:h Reactor Coola:;t Ac~ivi~y TABLE I S~lem Ur.it ~ ar.d 2 Page 1 of 1 ?.e'.*. 5

I-4.16 PROCESS RADIATION MONITORS HAi.\"'NEL NAME INTERLOCK EMERGENCY INSTRUCTION (Reference)

(2)RlB CONTROL ROOM INTAKE DUCT 1. Control Room Ventilation Isolation R6B SAMPLE ROOM PARTICULATE 1. None lRllA CONTAINMENT OR VENT AIR 1. Containment Ventilation Isolation EI-I-4.4 Loss of Reactor Coolant PARTICULATE EI-I-4.11 High Reactor Coolant Activity EI-I-4.17 Partial Loss of Reactor Coolant 2RllA CONTAINMENT SAMPLING EI-I-4.20 Failure of RCP No. 1 Seal PARTICULATE EP-I-4 Site (Station) Emergency 1Rl2A CONTAINMENT OR VENT GAS 1. Containment Ventilation Isolation EI-I-4.4 Loss of Reactor Coolant EFFLUENT EI-I-4.11 High Reactor Coolant Activity EI-I-4.17 Partial Loss of Reactor Coolant 2Rl2A CONTAINMENT SAMPLING EI-I-4.20 Failure of RCP No. 1 Seal NOBLE GAS EP-I-4 Site (Station) Emergency 1Rl2B CONTAINMENT OR VENT GAS 1. Containment Ventilation Isolation EI-I-4.4 Loss of Reactor Coolant EFFLUENT ( IODINE) EI-I-4.11 High Reactor Coolant Activity EI-I-4.17 Partial Loss of Reactor Coolant 2Rl2B 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 EI-I-4.4 Loss of Reactor Coolant EI-I-4.11 High Reactor Coolant Activity EI-I-4.17 Partial Loss of Reactor Coolant 1(2)R13B NO. 12 (22&24) FAN COIL Loss of Reactor Coolant UNI~

1. None EI-I-4.4 EI-I-4.11 High Reactor Coolant Activity EI-I-4.17 Partial Loss of Reactor Coolant (2) Rl3C NO. 13 (23 &2."I) FAN COIL UNn 1. None EI-I-4.4 Loss of Reactor Coolant EI-I-4.11 High Reactor Coolant Activity EI-I-4.17 Partial Loss of Reactor Coolant 1F.l3D NO. 14 FAN COIL UNIT 1. None EI-I-4.4 Loss of Reactor Coolant EI-I-4.11 High Reactor Coolant Activity EI-I-4.17 Partial Loss of Reactor Coolant 1Rl3E NO. 15 FAN COIL UNIT 1. None EI-I-4.4 Loss of Reactor Coolant EI-I-4.11 High Reactor Coolant Activity EI-I-4.17 Partial Loss of Reactor Coolant 1Rl4 WASTE GAS EFFLUENT 1. Trips Gaseous Waste Discharge EP-I-4 Site (Station) Emergency Valve 1WG41 1(2)Rl5 CONDENSER AIR EJECTOR 1. None EI-I-4.7 Steam Generator Tube Leak 1(2)Rl6 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)Rl7A COMPONENT COOLING LIQUID 1. Trips Component Cooling Surge Tank EI-I-4.15 Loss of Component Cooling Vent Valve 1(2)CC149

.1(2)Rl7B COMPONENT COOLING LIQUID 1. Trips Component Cooling Surge Tank EI-I-4.15 Loss of Component Cooling Vent Valve 1(2)CC149 (2)Rl8 LIQUID WASTE DISPOSAL 1. Trips Liquid Waste Disposal Discharge EP-I-4 Site (Station) Emergency Valve 1(2)WL51 TABLE II Salem Unit 1 and 2 Page 1 of 2 Rev. 5

il 1-4.16 PROCESS RADIATION MONITORS

..~

EL NAME INTERLOCK EMERGENCY INSTRUCTION (Reference) 1(2)Rl9A NO. 11(21) STEAM GEN. 1. Trips S/G BD !sol. Valves 11,12,13 & 14 El-1-4.7 Steam Generator Tube Leak BLOWDOWN (21,22,23 & 24)GB4 on a HIGH alarm.

2. Trips No. 12(22) S/G BD Tank Valves 11, 12,13 & 14(21,22,23 & 24)GB10 &

1(2)GB50 on a WARNING Alarm.

1(2)Rl9B NO. 12(22) STEAM GEN. 1. Trips S/G BD !sol. Valves 11,12,13 & 14 EI-1-4.7 Steam Generator Tube Leak BLOWDOWN (21,22,23 & 24)GB4 on a HIGH alarm.

2. Trips No. 12(22) S/G BD Tank Valves 11, 12,13 & 14(21,22,23 & 24)GB10 &

1(2lGB50 on a WARNING Alarm.

1(2)Rl9C NO. 13(23) STEAM GEN. 1. Trips S/G BD Isol. Valves 11,12,13 & 14 EI-I-4.7 Steam Generator Tube Leak BLOWDOWN (21,22,23 & 24)GB4 on a HIGH alarm.

2. Trips No. 12(22) S/G BD Tank Valves 11, 12,13 & 14(21,22,23 & 24)GB10 &

1(2)GB50 on a WARNING Alarm.

1(2)Rl9D NO. 14(24) STEAM GEN. 1. Trips S/G BD !sol. Valves 11,12,13 & 14 EI-I-4.7 Steam Generator Tube Leak BLOWDOWN (21,22,23 & 24)GB4 on a HIGH alarm.

2. Trips No. 12(22) S/G BD Tank Valves 11, 12,13 & 14(21,22,23 & 24)GB10 &

1(2)GB50 on a WARNING Alarm.

R20A CHEM LAB PARTICULATE 1. None 1(2)R31 LETDOWN LINE FAILED FUEL 1. None EI-I-4.11 High Reactor Coolant Activity (2)R35 SG BLOWDOWN FILTER 1. Shifts 3-way valves 1(2)GB74 and EI-I-4. 7 Steam Generator Tube Leak DISCHARGE 1(2)GB112 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)HS49, 1(2)HS293 & SV 1055.

EP-1-4 Site (Station) Emergency 2R41A PLANT VENT SAMPLING l. Containment Ventilation Isolation EI-I-4.4 Loss of Reactor Coolant PARTICULATE EI-I-4.11 High Reactor Coolant Activity EI-I-4.17 Partial-Loss of Reactor Coolant EI-I-4.20 Failure Of RCP No. l Seal i2R41B PLANT VENT ~AM?LING IODINE 1. Containment Ventilation Isolation EP-1-4 Site (Stat:ion) Emergency EI-I-4.4 Loss of Reactor Coolant EI-I-4.11 High Reactor Coolant Activity EI-I-4.17 Partial-Loss of Reactor Coolant EI-I-4.20 Failure of RCP No. l Seal 2R41C PLANT VENT SAMPLING EP-I-4

l. Containment Ventilation Isolation Site (Station) Emergency NOBLE GAS EI-I-4.4 Loss of Reactor Coolant

2. Trips Gaseous Waste Discharge Valve EI-I-4.11 High Reactor Coolant Activity 2WG41 EI-I-4.17 Partial-Loss of Reactor Coolant EI-I-4.20 Failure of RCP No.* l S@al TABLE II Salem Unit 1 and 2 Page 2 of 2 Re.v. 5

.. I-4.16 PROCES" FILTER RADIATION ~!ONITORS

~.NNEL NA11E INTERLOCK EXERGE~CY INSTRUCT10~ (Reference) 2)R24A SEAL 'WATER INJECTION FILTER 1. None EI I-4.11 High Reactor Coolant Activity 1(2)R24! SEAL WATER INJECTION FILTER 1. None EI I-4.11 High Reactor Coolant Act:j.vity 1(2)R25 SE.AL WATER FILTER 1. None EI I-4 .11 High Reactor Coolant Activity 1(2)R26 REACTOR COOLANT FILTER 1. None EI I-4.11 High Reactor Coolant Activity 1(2)R27 LIQUID WASTE FILTER 1. None EI I-4.11 High Reactor Coolant Activity 1(2)R2S SPE.i.'ff FUEL PIT FILTER 1. None 1(2)R29 SPENT FUEL PIT SKIMMER

1. None FILTER 1(2)R30 REFU:!':LING WATER PURIFICA-

1. None TION FILTER

' 1(2)R33 ION EXCHA."GE FILTER 1. None EI I-4.11 High Reactor Coolant Activity l.2)R38 STEAM GENERATOR 1. None EI I-4.7 Steam Generator Tube Leak SLOWDOWN FILTER 1:2)R40 CONDENSATE FILTER 1. None EI I-4.7 Steam Generator Tube Leak

Salem Unit 1 end 2 TABLE III

!'age 1 of l Rev. 5

*-~-* _, ___ - - - **-- - *- --

~ *- _______ .

, _ ~---*---...... -*- **---------------**-***----- --~-------------..*---

I-4.17

-, . (

. Y I" - ':'.'<UCTION I-LJ * ~.*:

PART*,-*,. J"OSS OF REACTOR COOY..J\NT 1.0 PURPOSE 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.

l.l A partial loss of reactor coolant is defined as coolant water escaping from a small break in the Reactor Coolant 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 from Containment Fan Coolers.

2.JJ Increasing Containment Sump level *

3.0 2.5 Increasing radiation levels on one or more Containment radiation monitors.

IMMEDIATE ACTIONS 3.1 Automatic 3 .l.l None.

3.2 Manual 3.2.l None

~

4.0 SUBSEQUENT ACTIONS ~

~~

4.l If the Pressurizer level is decreasing slowly, start additional .~~ing Pumps to restore and maintain level. If Pressurizer level and Press~~ntinue to decrease, manually initiate Safety Injection by inserting'th~into Train

~A 0 and/or Train'!B" Operate bezel and turning the key *. R~o EI I-4.4, "Loss of Coolant.~ ~~

~~ -

,/~

~~

~

~~

Salem Unit l/Unit 2 Rev. 3

I-4.17 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.l OI I-3.5, "Minimum Load to Hot Standby" 4.4.2 DI I-3.6, "Hot Standby to Cold Shutdown" Prepared By Manager - Salem Generating Station Reviewed By SORC Meeting No. Date Salem Unit l/Unit 2 Rev. 3

,/

I-4.18

'. 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 COMPLETE LOSS OF INSTRUMENT AIR I-2.0 SYMPTOMS I-2.1 Compressor Trouble Alarms I-2. 2 Station Header. Pressure Low Alarm

I-3.0 I-2.3 Control Air Header Pressure Low Alarm IMMEDIATE ACTION I-3.1 Automatic I-3.1.l Automatic start of the other Station 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 compressor trouble alarm, dispatch an operator to locate the problem.

I-3.2.2 Attempt to isolate the leak and/or start another compressor.

I-3.2.3 If pressure in the instrument air header falls to 65 psig, take t~e following actions:

1) Manually trip the reactor.

2) I~itiate a cooldown of the RCS while (if) co~trcl air is stil~

available.

Re\*. 3 Sal~m Unit l/Unit 2

I-4.18

~~4.0 SUBSEQUENT ACTION

I-4.1 I-4.2 If all control air is lost, maintain S/G levels with the Auxiliary Feedwater Pump(s) while heat is removed through the main steam safety valves.

Maintain Pressurizer level through intermittent charging with the Reciprocating Charging Pump.

I-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 WR82.

4) Pressurizer Relief Tank Vent Valve PR15.

5) Pressurizer Relief Tank Drain Valve PR14.

b. The following valves fail open:

1) Reactor Vessel Head Leakoff Valve RC4.

2. eves

a. The following valves fail closed:

1) The following letdown stop valves: CV277, CV2, CV3, CV4, CVS & 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 11CV160 & 12CV160.

5) Primary makeup water to blender CV179.

6) Normal makeup valves CV185 & CVlBl.

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 CVS.

Salem Unit l/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.

c. The following 3-way valves fail in the indicated position:

1) Letdown flow path selector CV21 to VCT.

2) Letdown diversion valve CV35 to YCT.

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 (MS18).

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 MS167, 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 Feed Pump Recirc Valves (BF32).

4) Condensate Pump Recirc Valves (NCS).

II PARTIAL LOSS OF INSTRUMENT AIR Salem Unit l/Unit 2 ~ev. 3

1 *--~-

I-4.lB II-2.0 SYMPTOMS II-2.1 Loss of control air pressure in portion(s) of the plant with the Station Air Compressor and/or the Emer~ency Air Compressor operating, discharge pressure normal.

II-2.2 Loss of valve controls in isolated portions of the plant.

II-2.3 Piping failure (sound of escaping air reported).

II-2.4 A group of air operated valves move to the fail-safe position, without o=erator action.

II-3. 0 I.M.:*!EDIATE ACTIONS II-3.1. Automatic II-3.l.l Valves supplied by the failed header, that do not 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 flo~ check valves closes as indicated by a loss of pressure downstrea~ of the valve.

II-3.2 Manual II-3.2.l Attempt to isolate the pipe rupture.

II-3.2.2 If rupture is isolable from the header and the excess flow check valve can be opened and the header repressurized, then proceed as follows to reopen the excess flow check valve.

I

1) Isolate the close excess flow check valve from the pressure

I source.

2) Bleed off pressure from between the isolation valve an= the closed excess flow check valve.

31 Slowly open the isolation valve a quarter turn and allo~

pressure in the header to stabalize (local pressure indication).

4) Repeat step II-3.2.2-3) until the isolation valve is ful:y open or the header pressure reaches 100 psiq.

II-3.2.3 If rupture cannot be isolated and the whole header is lost, c~e Senior Shift Supervisor/Shift Supervisor is to assess the p2ant conditi=ns and the effect the lost heade~ has c~ cpe~ati~g caFabi:ity ~~ de~er~i~e t~e course o= ac~ion re=uire=.

Sale~ ~ni~ l/~nit 2 Rev. ~

--- --...:. * ------ - - **-- - -- ---- - - -*- - - - - - ------ *- - ___ .,__,....,..;-:-:_:~=-*--**- - -

l

.~.

EJ.llli..:' .,,*

I-4.18 II-4. 0 SUBSEQUENT ACTION

II-4.1 Locate and repair the rupture.

Operating Instructions

Return plant conditions to normal IAW appropriate

Prepared by~~~~-J~.V-'--'-.--=B~a==i=l~e~v...._~~~~

Reviewed by~~~~-W_.~Ra~_h_l~~~~~~~-

SORC Meeting No.~~~~~~~~~~~~~

053-79 Da te _

Manager l/;_7._/

__..4'--+-/_..__'/__

Salem Unit l/Unit 2 j.

I-4.19

-t I EMERGENCY INSTRUCTION I-4.19 MALFUNCTION-NUCLEAR INSTRUMENTATION

l. 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.l.l 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) ".

1.3 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

I.

I-2.0 SOURCE RANGE MALFUNCTION SYMPTOMS

PART I 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 Automatic I-3.l.l None

I-3.2 Manual I-3.2.l If a reactor trip occ~rs, refer to EI I-4.3, "Reactor Trio".

Salem Unit l/Unit 2 ~ev. 4

I ..

I I-4.19 I .5.

I-3.2.2 If an overhead annunciator SR HIGH FLUX AT SHUTDN alarm occurs, verify le I-4.0 SUBSEQUENT ACTIONS against the other source range channel and other plant parameters that the alarm is invalid.

I 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.l and Technical Specification 3.9.2 and return the system to normal IAW OI IV-6.3.1, "Operation of the Nuclear Instrumentation System".

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. AUDIO 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 count rate has been restored in the Containment and Control Room.

Rev. 4 Salem Unit l/Unit 2

I-4.19 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.l.l and Technical Specification 3.9.2 and return the system to NORMAL IAW OI IV-6.3.l, "Operation of the Nuclear Instrumentation System".

PART III III INTERMEDIATE RANGE MALFUNCTION III-2.0 SYMPTOMS 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 III-2.2.2 III-2.2.3 IR Loss of Detector Voltage IR No. 1 Loss of Compensate Voltage 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.l 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 observe that the SR & IR TRIP BYPASS 1/4 is energized.

Salem Unit l/Unit 2 Rev. 4

I-4.19 NOTE

III-4 .1. 2 This removes protective bistable functions.

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 Shift Supervisor/Shift Supervisor and take corrective action, as necessary, to return the inoperable intermediate range channel to OPERABLE status IAW Technical Specification 3.3.l.l and return the system to normal IAW OI IV-6.3.l, "Operation of the Nuclear Instrumentation System".

PART IV IV. POWER RANGE MALFUNCTION

IV-2.0 SYMTOMS IV-2.l Erratic or loss of indication IV-2.2 Any of the following alarms which are not substantiated ny other instrumentation:

IV-2.2.l 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.l Automatic IV-3. 1. 1 None.

Salem Unit l/Unit 2 Rev. 4

I-4.19 IV-3.2 Manual IV-3.2.l 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 RA'NGE 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.l 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 removing 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.l.3 Turn the COMPARATOR CHANNEL DEFEAT selector switch located on the COMPARATOR AND RATE drawer to the position 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 MISMATCH 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 Specification 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-2.0 SYMPTOMS V-2.1 Any of the following alarms which are not substantiated by other instrumentation:

Salem Unit l/Unit 2 -s- Rev. 4

I-4.19 V-2.1.1 PR Channel Deviation

V-3.0 V-2.1.2 V-2.1.3 IMMEDIATE ACTIONS Upper Section Deviation or Auto Defeat Lower Section Deviation or Auto Defeat V-3.l Automatic V-3 .1.1 None V-3.2 Manual V-3.2.l If a PR CHANNEL DEVIATION alarm occurs, place the COMPARATOR CHANNEL DEFEAT selector switch on the COMPARATOR AND RATE drawer to the position associated with the failed channel.

V-3.2.2 If an UPPER or LOWER SECTION DEVIATION or 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 Specifi_cation 3.2.4, "Quadrant Power Tilt Ratio".

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~*~B_a_i_l_e_y~~~~~~-

Manager ~Sliem Generating Station Reviewed by~~~~W~*~Ra~_h_l~~~~~~~~

soRc Meeting No.~_o_s_o~--7_9~~~~~~~~ Date Salem Unit l/Unit 2 Rev. 4

I-4.20

..;,'!E.KGENCY INSTRUCTION I-4.20 FAILURE OF A REACTOR COOLANT PUMP

l. 0 DISCUSSION 1.1 It is not poss~.;-,1: to anticipate every possible trouble with a Reactor Coolant Pump.

This procedure gives steps to cope with general classes 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 Oi1. Level Part IV Hi Bearing Temperature Part v No. 1 Seal Failure Part VI No. 2 Seal Failure Part VII No. 3 Seal Failure 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-2.2 Automatic Closure of 1(2)CC131, CCW from RCP Thermal Barrier Isolation Valve.

I-2.3 RCP Thermal Barrier Discharge Flow Low Alarm actuates on the Control Console after 1(2)CC131 RCP Thermal Barrier Isolation Valve automatically closes.

I-2.4 11(21) or 12(22)CC Header High Activity Alarm on the Control Console may actuate.

I-3.0 IMMEDIATE ACTIONS I-3.1 Automatic I-3.1.1 Auto closure of 1(2)CC131 RCP Thermal Barrier Isolation Valve I-3.2 Manual I-3.2.1 Verify auto closure of 1(2)CC131 RCP Thermal Barrier Isolation Valve_

Salem Unit l/Unit 2 Rev. 5

I-4.20

\ ,,. I-3.2.2 Close lt2)CC190 RCP Thermal Barrier Discharge Valve.

I-3.2.3 Trip all Reactor Coolant Pumps.

I-3.2.4 If Reactor Power was > 10%, refer to EI I-4.3, "Reactor Trip". If Reactor Power was < 10%, 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)CC128 or Isolation Valve 1(2)CC131 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 I I II. HI VIBRATION

II-2.0 SYMPTOMS II-2.1 RCP Hi Vibration Annunciator Alarm actuates.

II-3.0 IMMEDIATE ACTIONS

,,I 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)RP1 II-3.2.2 If vibration is > 4 mils on the 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).

Salem Unit l/Unit 2 Rev. 5

I, I-4.20

\v..

II-4.0 SUBSEQUENT ACTION II-4.1 If vibration is > 3 mils but < 4 mils on the motor flange or is > 8 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-4.2 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. IMPROPER OIL LEVEL III-2.0 SYMPTOMS III-2.1 RCP Radial Bearing Oil Hi/Lo Level Annunciator Alarm actuates.

III-3.0 IM.."1EDIATE ACTIONS III-3.l Automatic III-3 .1.1 None

III-3. 2 Manual III-3.2.1 If oil level is accompanied by a high bearing temperature 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 SUBSEQUENT ACTION II-4 .1 If oil level alarm is not accompanied by high bearing temperature or high vibration alarms, 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 TEMPERATURE IV-2.0 SYMPTOMS IV-2.1 High RCP Bearing Temperature Alarm.

Rev. 5 Salem Unit l/Unit 2

\i

!:**:- 3. ~

c*:-3.:2.l If bearing te~pera~~=e alarm is accc~;a~is~

a:.d/or low cil le-*el alar:r.:

.=-_-:::.:::::*:.:...=::! .=-.c:iro:.::

IV--!.l If high bearing temperature alarm is not accompanied by vibratio~ or oil level alarms, ir:unediately:

I'.--4.l.l Reduce power below P-7 . If bearing temperature reaches 185°F im.~ediately trip the affected pump .

. -~. l. 2 Re~c~e affected RC? fro~ ser".'ice r.:._\*I OI -- .... ,:; ..... ,

T"T"-1 ...., J

~~an Four RC Loops in Service**.

PART V

-~. c.

'.1-3. 0 rn:*!E:JIATE ACTI'.JNS V-3.: A~tomatic

".'-3. l. l :*:one V-3 .. 2 :1ar.ual I~-3.2.l If Seal Leakoff flew step i~creases to

6. c ...... ,

......... "'T'

':.'.:. procee:i as :=0:!..l.J*.*:s:

ll Close the Seai Leakoff Stsp \1al*!e fC'.'104) :or t!:o: a:::ec".:ec Trip, a~d OI II-1.3 .. 3, Q~e~aticn with ~~ss Tha~ ~c~~ ~C ~co~s ~ ..

Serv1ce 11 Salem Cnit l/Cnit 2 -~ - :=:e*:. 5

I-4.20 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 inlet and outlet temperatures to the thermal barrier.

V-4.0 SUBSEQUENT ACTIONS V-4.l Monitor Seal Water injection temperature; if it exceeds 140°F, secure the RCP IAW OI II-1.3.3, "Operation with Less 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 RC~T L~vel VI 2.5 Increased RCP Vibration VI-3.0 IMMEDIATE ACTIONS

VI-3.1 VI-3.2 Automatic VI-3.1.1 Manual None VI-3.2.1 Check Standpipe Supply Valve WR62 to the affected RCP closed.

VI-4.0 SUBSEQUENT ACTIONS VI-4.l 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 Rev. 5 Salem Unit l/Unit 2

I-4.20 vrr-3.0 IMMEDIATE ACTIONS VII-3.l 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.l 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 affected RCP IAW OI II-1.3.3, "Operation With Less Than Four RC Loops in Service".

PART VIII VIII. MULTIPLE SEAL FAILURE VIII-2.0 SYMPTOMS VIII-2.l 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.l Automatic VIII-3.1.1 None VIII-3.2 Manual VIII-3.2.l Trip the reactor, trip the affected RCP.

VIII-4.0 SUBSEQUE~T ACTIONS VIII-4.1 Commence an immediate plant cooldown at the maximum allowable rate IAW OI I-3.6, "Hot Standby to Cold Shutdown".

Prepared by~~-J~*-V_.~_B_a_i_l_e~y~~~~~~~

Manager4~

Reviewed by~~-J~._P_.~K~o_v_a_c_s~o_f~s~k_y.._~~~

SORC Meeting No. 053-79 Date Rev. 5 Salem Unit l/Unit 2

*~------~ .......~-::-;-~- - - -

-~--*-----

-~----------.--. -__-:._-

I-4.21 EMERGENCY INSTRUCTION I-4.21 CONDENSER 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 is divided into two parts:

I Small Condenser Leak II Major Condenser Leak PART I I. SMALL CONDENSER LEAK I-2.0 SYMPTOMS

I-2.1 I-2.2 I-2.3 I-2.4 Increased Cation Conductivity reading on either side of any Condenser (six readings).

Increased conductivity readings on any of the three Condensate Pump suctions.

Increased Cation Conductivity readings on any of the three Condensate Pump discharges.

Increased Na readings on any of the three Condensate Pump discharges.

I-2.5 Increased conductivity reading on #6 Feedwater Heater outlet.

I-2.6 Increased conductivity readings on any of the Stearn Generator blowdown samples.

I-2.7 Decreasing pH in Steam Generator Blowdown.

I-3.0 IMMEDIATE ACTION I-3.l Automatic 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 Gene.rater blowdown.

I-4.0 SUBSEQUENT ACTIONS I-4.l If leak is very small, observe limits and allowed time of operation per Table II of Chemistry Instruction PD-3.1.012, "Steam Generator Steam Side Surveiilance",

~-**

(Table attached).

Salem Unit l and 2 Rev. 2

-** *----*---~*--*- - ,.. __ ----- - - ---*--~-*--*------~--*_ .... __ ...,__ __ ._.

I-4.21 I-4.2 If the pH of the Steam Generator Blowaown water cannot be maintained >8.0 pH the Unit will have to be shutdown as soon as possible.

I-4.3 Determine the defective Condenser and which half of it is leaking by comparing the six Cation Conductivity readings on the Condenser Hotwells.

I-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 SY1-!PTOMS II-2.l 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 ACTIONS II-3.l Automatic 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.l 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 off the line and make repairs, as necessary.

Prepared by c. A. Bur e Manager -

Salem Unit l and 2 Rev. 2

I-4.21

LIMITING AVT SPECIFICATIONS FOR POWER OPERATIONS AT BRACKISH WATER SITES Control Parameter Steam Generator Blowdown Two Weeks 24 Hours Immediate pH @ 25°C 8.0 - 9.2 N/A <8.0 or >9.4 Cation Conductivity >2.0 but < 120 N/A >120 umhos/cm @ 25°C Free Hydroxide N/A/l >0.15 but <1.0 >l. 0 ppm as caco 3 Slowdown 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.

/I. No relief for Free Hydroxide over and above the Normal Operating Control Limit is provided for periods in excess of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

Salem Unit 1 and 2 Rev. 2

.... I-4.22 EMERGENCY INSTRUCTION I-4.22 LOSS OF RESIDUAL HEAT REMOVAL SHUTDOWN COOLING 1.0 DISCUSSION l.l 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.l Pipe break occurring in the RHR System 1.2.2 Loss of RHR System flow l.2.3 Loss of RHR Heat Exchangers due to loss of Component Cooling Water l.3 Whenever fuel is loaded in the core, flow must be maintained by either a Reactor Coolant Pump or RHR Pump at all times (Technical Specification 3.4.l.ll, except in mode 6, Refueling, when the RHR Pump may be stopped for up to l hour in every B hour period to facilitate core alterations in the vicinity of the hot leg penetrations in the vessel (Technical Specification 3.9.B).

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 RHR Pump motor current 2.5 RHR Pump Trip Alarm 2.6 Low CCW Flow to RHX Alarms 2.7 RHR Common Suction Valves RHl or RH2 Indicates Closed 3.0 IMMEDIATE ACTIONS 3.1 Automatic 3.1.l l(2)RH1 and 1(2)RH2 will close automatically if RCS pressure increases to 600 psig.

3.2 Manual 3.2.l If RHR common suction valves l(2)RHl and l(2)RH2 indicate closed, stop the RHR Pump (s).

3.2.2 If the operating RHR Pump trips, start the standby RHR Pump and check for satisfactory operation. If neither RHR ?ump can be started, proceed as follows:

Rev. 2 4/25/78

I-4.22

1) Mode 4 and 5 a) Increase RCS pressure to ~375 psig to develop the required 200 ?Sid on RCP #1 Seal b) Establish seal water injection to at least l RCP IAW OI I!-3.3.1, "Establishing Charging, Letdown and Seal Injectiori Flew".

c) Start at least one RCP IAW Oi II-1.3.l, "Reactor Coolant ?:l:n:: Operat:.on".

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 t.~at a RHR System pipe break has occurred, perfor:n the following:

l) 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 azove.

SUBSEQ~'"E~T ACTION 4.1 If RHR common suction valves closed due to high RCS pressu=e, dec=ease ?ress~re by

- adjusti~g t.~e Letdown Pressure Control Valve 1(2)CV13 and re-establish RHR IAW OI II-6.3.2, "Initiating Residual Heat Removal".

4.2 If loss of heat sink occurs, attempt to restore component cooling to the RP.R Eeat Exchange=s.

4.3 With the RHR System unavailable, RCS temperature must be regulated by eithe= condenser or atmospheric steam dump. The use of condenser steam dump will be dependent on the availability of one Circulating Water Pump and ability to maintain ~22" of vacuum.

The use of at.~ospheric steam dump will be governed by the radioactivity level in the Steam Generators.

4.4 Alternate decay heat rerrGval after loss of RHR cooling capability - reactor vessel head removal.

4.4.l If not already done, flood the refueling cavity to the normal refueling level IAW OI II-8.3.3, "Filling the Reactor Refueling Cavity".

4.4.2 Establish maximum spent fuel pit cooling IAW Oi II-8.3.2, "Spent Fuel ?it Cooling System Operation".

Rev. 2

.0/25/iS

p I-4.22 4.4.3 Establish mAximum reactor refueling cavity filtering and purification IAW OI II-B.3.5, "Refueling Water Purification System Operation".

4.4.4 Operate Containment Fan Cooler Units to maintain Containment air temperature at or below about B0°F.

Prepared by~---------------J~**-..B~a--"'i~l_e~v_____________________

nerating Station SCRC Meeting No. _______7~8~-.-..2~6---

Rev. 2 4/25/78

I-4.23 E."'!ERGENCY INSTRUCTION I-4.23 LOSS OF CONTAINMENT INTEGRITY

l. 0 DISCUSSION 1.1 This emergency instruction provides the actions to be taken, if Containment Integrity, as defined in the Technical Specification 3.6.l.l, is lost.

2.0 SYMPTOMS 2.1 Due to the maximum pressures (-1.5 psi to + 0.3 psig) maintained in the Containment, loss of Containment Integrity, other than in the double barriers, may be difficult to detect. It will be necessary to closely observe Containment pressure and temperature 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:

2.2.l Any unexplained change in Containment pressure and temperature.

l) 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 Isolation 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.l.l, Containment Systems - Primary Containment.

3.0 IM.'IBD!AT'E ACTIONS 3.l Automatic 3.1. l None 3.2 Manual NOTE These actions are intended to inunediately initiate operator action for restoration of Contai:unent Integrity and, if possible, eliminate the need for subsequent reactor shutdown.

Rev. 2 4/25/78

I-4.23 3.2.1 Notify Senior Shift Supervisor/Shift Supervisor of loss or impending loss of Containment Integrity.

3.2.2 Co:n.~ence checking other system parame~ers which could be t.~e cause o= the symptoms indicated.

3.2.3 Ensure that the reactor power, RCS pressure, RCS temperature, 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 t.~e valve, close a manual valve in the same line.

4.0 SUBSEQUENT 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 Shutdown IAW the following instructions:

4.1.l OI I-3.4, "Power Operation" 4.1.2 OI I-3.5, "Minimum Load to Hot Standby" 4.1.3 OI I-3.6, "Hot Standby to Cold Shutdown" Prepared by~----~---R_.__H_a_1_1_*ma

___r_k____~-----------------

SCRC Meeting No. __~7~8_-~2~6____________

Rev. 2 4/25/78

,,, -. I-4.24 EMERGENCY INSTRUCTION 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) 2.1.6 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 overhead annunciators indicate a valve is open:

Unit 1 Unit 2 K-7 lPRl K-7 2PR1 K-15 1PR2 K-15 2PR2 K-23 2PR47 K-31 2PR48 3.0 IMMEDIATE ACTIONS 3.1 Automatic 3.1.1 Reactor will trip automatically, if there is a very high leakage~~'~ which will cause a Low Pressurizer Pressure Trip followed by a Low Pre~: safety Injection. .**_ ~

3.1. 2 Pressurizer Relief Tank Vent Valve 1(2)PR15 will automatic~~lose if pressure exceeds 10 psig in the Pressurizer Relief Tank. ~"'

3.2 Manual 3.2.1 Power Operated Relief Valve or Safety Valve

. #Jr Leaking~~

1) If*increasing temperature is indicated on No.~~Safety Valve Temperature Indicator, or No. 12 (22) Safety Valve Tempera ~~nd*icator, or No. 13 (23) b.

Safety Valve Temperature Indicator, the le~)~'s idBntified as to which

~ *~

Safety Valve is leaking. Perform a water~ , to:r;~' balan~e to . determine the leakage rate as follows: ~ ..

a. OI II-1.3.5, "Reactor Coolant Leak Detection", and/or;

b. SP(0)4.4.6.2(d), "Reactor Coolant System - Leak Rate Computation".

Salem Unit l/Unit 2 Rev. 4

I-4.24

2) If increasing temperature is indicated on the Relief Valve Temperature

Indicator, identify the lead as follows:

a)

(Perform all four steps below)

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)PR6, if temperature is increasing, the leaking valve is 1(2)PR1. Close 1(2)PR6.

c) Ope!1 Pressurizer Relief Valve Stop Valve l (2) PR7, if temperature is increasing, the leaking valve is 1{2)PR2. Close 1(2)PR7. If temperature is not increasing, leave 1(2)PR7 open.

d.) If 1 ( 2) PRl was determined not to be leaking, then open 1 ( 2) PR6.

NOTE Closing 1{2)PR6 and 1(2)PR7 will isolate the 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) 2)

Start additional charging pumps as necessary to maintain Pressurizer Pressure and Level.

Coolant".

Refer to EI I-4.17, "Partial Loss of Reactor If Pressurizer Pressure drops to 1765 PSIG, Safety Injection will automatically initiate. Refer to EI :I-4.4, "Loss of Coolant".

NOTE The Pressurizer Relief Tank Rupture Disc will relieve 100 PSIG.

3.2.3 Power - Operated Relief Valve stuck Open:

.. * ~

1) Verify which Power Operated Relief Valve is open by c~ns.~~el indicating lights. _ *~

2) Try to close the open Power Operated Relief Valve MANUAL pushbutton, then depressing its CLOSE pus~.

b~~ssing its c~~close

3) If the Power Operated Relief Valve does not its respective Pressurizer Relief Stop Valve (PR6 or PR7).~~~

Salem Unit l/Unit 2 Rev. 4

I-4.24 NOTE The Pressurizer Relief Tank Rupture Disc will relieve at 100 PSIG 4.0 SUBSEQUENT ACTIONS 4.1 Power Operated Relief Valve 4.1.l The reactor may be operated until the Power Operated Relief Valve 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.l OI I-3.4, "Power Operation" 4.2.2 OI I-3.5, "Minimum Load 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

Salem Unit l/Unit 2 Rev. 4

I-4.25 EMERGENCY INSTRUCTION I-4.25 FUEL HANDLING INCIDENT l.O DISCUSSION l.l 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 difficulty is encountered in removing a fuel assembly from the core or from the fuel assembly container. Procedures are concerned with first minimizing any radiological hazards which might occur and secondly with the disposition of damaged or potentially damaged new or spent fuel assemblies. Any malfunction of fuel handling equipment will be dealt with by the *Fuel Handling System Operating Instructions", Volume 2 Section 9.

1.2 This instruction is divided into five parts:

I A new uo fuel assembly is dropped or collides with another object.

2 II A new Puo 2

-uo2 fuel assembly is dropped or collides with another object.

III A spent fuel assembly or rod control cluster is dropped 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 U0 FUEL ASSEMBLY IS DROPPED OR COLLIDES WITH ANOTHER OBJECT 2

2.0 SYMPTOMS 2.l 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 clear 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 fan, el. 100' truck bay, is secured (normal condition during refueling). lNot applicable during initial Fuel Receipt. )

Rev. 0 Salem Unit l and 2

I-4.25 3.3 Dispatch one man to the nearest telephone to info:cn the Control Room of the incident.

Control Operator will:

a) notify Supervisor in charge of Radiation Protection.

bl observe the stack radiation monitor for any change, and ensure the fuel handling building ventilation is operating no:cnally.

c) Change over to the emergency filter exhaust bank (charcoal 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 distorted and can be handled by the manipulator crane and fuel transfer system, transfer the assembly to the spent fuel pit, and store it until such time as it can be inspected by the Reactor Supervisor or his designate.

bl 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 after 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 Engineer or his designate.

PART II II A NEW Pu02-uo2 FUEL ASSEMBLY IS DROPPED OR COLLIDES WITH ANOTHER OBJECT.

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 phqne.

Salem Un~t 1 and 2 -i- Rev. 0

I-4.25 IMMEDIATE ACTIONS 3.1 Personnel concerned evacuate th~ immediate area using the nearest available exit and remaining clear 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 fan, 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 will:

a) Notify Supervisor in charge of Radiation Protection.

bl Observe the stack radiation monitor for any change, and ensure the fuel handling building ventilation is operating normally.

cl Change over to the emergency filter exhaust 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 minimum, coveralls, hood, shoe covers, gloves, and full face mask with a cannister filter.

4.0 SUBSEQUENT ACTIONS 4.1 Monitor all personnel involved for potential alpha contamination.

Any count rate above normal background indicates a possible release from the damaged assembly. Record levels of contamination found on personnel and decontaminate.

4.2 If the incident occurs in an area other than the refueling canal, proceed as follows:

a) Wearing proper protective clothing 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.

Salem Unit l and 2 Rev. 0

I-4.25 c) If no alpha contamination has been released from the assembly, other personnel may approach to begin recovery operations. No movement of the assembly should be attempted without first determining that such movement will not further damage the cladding and subsequently release contamination.

d) If alpha contamination exists on the floor, 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 to limit the contamination.

contaminated areas should be located, marked, and covered with plastic sheet or tape. If widespread contamination has occurred, the area should be sealed off to tne maximum extent possible, and no one should 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 been inspected, evaluated, and a specific plan of action formulated.

PART III III A SPENT FUEL ASSEMBLY OR CONTROL ROD CLUSTER IS DROPPED OR COLLIDES WITH ANOTHER OBJECT.

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*i.Jnmediate area using the nearest available exit and remaining clear 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 fan, 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.

Salem Unit 1 and 2 Rev. 0

I-4, 25 Control Operator will:

(al Notify Supervisor in charge of Radiation Protection.

I (

(b) Observe the stack radiation monitor for any change, and insure the fuel handling building ventilation is operating normally.

(c) Change over to the emergency filter exhaust bank (charcoal filters) if there is any increase in stack activity.

3.4 Ensure that all doors are closed or temporary coverings erected over openings leading to the affected area.

CAUTION Entry to tne affected area should be made 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 be visible if the assembly 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 assembly. Note its location and monitor tne spent fuel pool.

4.5 If the fuel assembly is mechanically distorted 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 neat 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 transportation.

PART IV IV A SPENT FUEL ASSEMBLY OR ROD CONTROL CLUSTER IS DROPPED OR COLLIDES WITH ANOTHER OBJECT RESULTING IN A HIGH RADIATION ALA.HM/HIGH AIRBORNE ACTIVITY ALARM (LOCAL).

2.0 SYMPTOMS 2.1 Any of five alarms sound locally.

Salem Unit 1 and 2 Rev. 0

I-4.25 a) Spent fuel storage area high radiation alaxm.

bJ New fuel storage area high radiation alarm.

c) Reactor operating floor high radiation alarm.

d) Containment or fuel handling building high airborne activity alarm (portable monitor).

3.0 IMMEDIATE ACTIONS 3.1 Evacuate the Containment Building (Fuel Handling Building) by 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 Room will:

a) Follow SPM Emergency Instruction lI-4.16) - *Radiation Incident*.

b) Sound the Site Radiation Alarm and announce evacuation of Containment Building (Fuel Handling Building).

c) Standby for further instructions from the Senior Shift Supervisor.

3.5 Operating shift personnel will:

a) Proceed to Control Room.

b) Standby for further instructions from watch Engineer.

3.6 The Senior Shift Supervisor/Shift Supervisor will:

a) Proceed to Control Room.

bl Notify the supervisor in charge or Radiation Protection.

cJ Notify Chief Engineer.

d) Monitor the Area Radiation Monitor System indicators to determine Containment 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) Standby at working area for further instructions.

4.0 SUBSEQUENT ACTIONS 4 .1 Superviso_r in charge of Radiation Protection will:

a) Proceed to the Monitor and Change Room.

Salem Unit 1 and 2 Rev. 0

I-4.25 b) Contact Senior Shift Supervisor and obtain report of Containment Building tFuel Handling Building) radiation conditions

c) Determine that all p~rsonnel have been evacuated and supervise monitoring of evacuated personnel.

dJ Dispatch monitoring personnel, equipped with respiratory device, high range dosimeter, and high range survey meter into the Containment Building (Fuel Handling Building) to:

l) 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 involved for:

1) Recovery operation.

2) Subsequent notification of outside agencies.

3) Further on-site and off-site evacuation.

i PART V V A FUEL ASSEMBLY BECOMES STUCK INSIDE THE REACTOR CORE OR INSIDE THE FUEL ASSEMBLY CONTAINER.

2.0 SYMPTOMS 2.1 Abnormal 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 notify the SRO in charge of **refueling.

4.0 SUBSEQUENT ACTIONS 4.1 Check load cell and limit 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~

Salem Unit l and 2 Rev. 0

I-4.25 4.3 If the assembly is stuck in the fuel assembly container and is not freed in Step 2, consult the Reactor Engineer before proceeding. Conduct visual inspection of the fuel assembly and transfer. container to determine cause of problem.

If the assembly is stuck in the core, and Step 2 does not free it, proceed as follows:

a) Remove and transfer fuel assemblies 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

Prepared by~~J~.'--'N~i-*~c~h~o~l~s~/~J,,_.,,-"'H~a=r~r~i~*c~k=-~~~~~~

Manager -

SORC Meeting No*~~~~~~-7_5_-_7_8~~~~~~~- Date________~l/~l_l~/_7~9_________________

Salem Unit l and 2 Rev. 0

EI I-4.26 EMERGENCY INSTRUCTION EI I-4.26 LOSS OF CONDENSER VACUUM

1. 0 DISCUSSION 1.1 A loss of condenser vacuum will cause a Turbine Trip if Reactor Power < 10% and a Turbine Trip/Reactor Trip if Reactor power is> 10%.

2.0 SYMPTOMS 2.1 Condenser vacuum decreasing.

2.2 Overhead Alarms F-7 and G-2 are alarming.

2.3 Reactor and/or Turbine tripped due to low vacuum.

2.4 Steam Generator Feed Pumps tripped due to low vacuum.

2.5 Main Turbine rupture discs may have ruptured.

3.0 IMMEDIATE ACTION 3.1 Automatic 3.l..1 Turbine Trip, if Reactor Power is < 10%, Reactor Trip/Turbine Trip, if Reactor Power is > 10%.

3.1.2 Steam Dump to the condensers is blocked.

3.1.3 The Atmospheric Steam Relief Valves (MSlO's) are maintaining S/G pressure.

3.1.4 Auxiliary Feed Pumps started and are supplying feed to the S/G's.

3.2 Manual 3.2.1 Take Ml-illUAL control of the Auxiliary 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 Use of l1-14(21-24)MS10'a requires close operator monitoring of the S/G pressure so that S/G 6P inadvertent safety injection will not occur.

Salem Unit l/Unit 2 Rev. 0

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E:I I--l.26 4.0 SUBSEQUENT ACTION 4.1 If reactor tripped, implement EI I-4.3, "Reactor Trip".

4.2 If condenser vacuum cannot be restored in a reasonable time, take the reactor s~bcritical IAW OI I-3.5, "Minimum Load to Hot Standby".

4.3 If condense~ vacuum can be restored, commence synchronization and Power Operation IAW OI I-3.4, after condenser vacuum is restored.

NOTE Selection of Step 4.2 or 4.3 shall be at the discretion of the Chief Engineer or Station Operating Engineer.

Manager Reviewed by _ _ _ _ _~F-'.'--c=--=-.-"'S-"c...:.h:on;;.:.a:;.:r::..;r=----------

SORC r.!eeting l\o. __......:2::cl=--_,7_,9"---------------

Salem Unit l/Vnit 2 Re*;. 0

ML18079A563

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