Text

Proposed Tech Specs,Changing Setpoints for Automatic Primary Containment Isolation on MSL Tunnel Differential Temp High & Deleting Automatic Isolation Function on MSL Tunnel Temp High
	ML20096G341
Person / Time
Site:	LaSalle
Issue date:	01/18/1996
From:	; COMMONWEALTH EDISON CO.
To:	;
Shared Package
ML20096G328	List: ML20096G326; ML20096G341;
References
	NUDOCS 9601250130
	Download: ML20096G341 (34)
	v • d • e

. . _ . . - --- - _.

O ATTACHMENT B PROPOSED AMENDMENTS TO THE LICENSE / TECHNICAL SPECIFICATIONS NPF-11 N PF-18 3/4 3-11 3/4 3-11 3/4 3-14* 3/4 3-14*

3/4 3-14(a) 3/4 3-14(a) 3/4 3-15 3/4 3-15 3/4 3-18 3/4 3-18 3/4 3-20 3/4 3-20 B3/4 3-2 B3/4 3-2

This page is provided for information only, no changes.

l B-1 9601250130 960118 PDR ADOCK 05000373 p PDR ,

TABLE 3.3.2-1 -

ISOLATION ACTUATION INSTRUMENTATION VALVE GROUPS MINIMUM OPERABLE APPLICABLE OPERATED BY CHANNELS PER OPERATIONAL TRIP FUNCTION SIGNAL TRIP SYSTEM (b) CONDITION ACTION l A. AUTOMATIC INITIATION -

1. ERIMARY CONTAINMENT ISOLATION,

a. Reactor Vessel Water Level Low, Level 3 7 2 1, 2, 3 20 Low Low, Level 2 2, 3 2 1, 2, 3 20 i Low Low Low, Level 1 1, 10 2 1, 2, 3 20 ;

b. Drywell Pressure - High 2, 7, 10 2 1, 2, 3 20

c. Main Steam Line *

1) Radiation - High 1 2 1, 2, 3 21 3 2 1, 2, 3 22 2 Pressure - Low I 2 1 23 y g}E, 3 Flow - High g 1 2/line'd' 1, 2, 3 21 i i _ -

d. $ainSteamLineTunnel Qemperature-Hi ( 2 1',3y,'g

, 2"3U3,

e. Main Steam Line Tunnel ATemperature - High 1 2 1",',y,'g 2"303, !

f. Condenser Vacuum - Low 1 2 1, 2*, 3* 21 i

2. SECONDARY CONTAINMENT ISOLATION

a. Reactor Building Vent Exhaust Plenum Radletion - High 4'*" 2 1, 2, 3 and ** 24

b. Drywell Pressure - High 4'*"*8 2 1, 2, 3 24 '

c. Reactor Vessel Water :

Level - Low Low, level 2 4'*"*' 2 1, 2, 3, and

24 !

d. Fuel Pool Vent Exhaust ,

Radiation - High 4'*"*8 2 1, 2, 3, and ** 24 [

b h

i A SAll E - UNIT 1 3/4 3-11 Amendment No. 107

.--,=_.---.

.. . ~ - ..

' * ' ' Tiart 1.1.2-1 (C:ntinued) t

YEol.ATION AcTt.fATfoN T _ mUnia- r1TTON ACTIDH ACTION 20 -

~ ' Be in atthe within least NOT24 next SHUTDOWN hours. within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN ACTION 21 -

4 Be in at least STARTUP with the associated isolation valves I

closed within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months or be in at least HOT SHUTDOWN within ACTION 22 - 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the next 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

2 Close the af fected system isolation valves within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and ACTION 23 -

declare the affected system inoperable.

i ACTION 24 - Be in at least STARTUP within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months ..

Establish SECONDARY CONTAINMENT INTEGRITY with the standby gas treatment system operating within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

ACTION 25 -

i Lock the affected system isolation valves closed within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months I and declare the affected system inoperable.

j ACTION 26 - Provided that the manual initiation function is OPERABLE for i each other group valve, inboard or outboard, as applicable, in I mach line, restore the manual initiation function to OPERABLE

status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months otherwise, function to OPERABLE status within 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months srestore the manual initiation

a. otherwise: i i Be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in '

i b.

COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , or !

Close the af fected system isolation valves within the next '

. hour and declare the affected system inoperable.

! IE M j

i May stop be bypassed valves closed.with reactor steam pressure s 1043 psig and all turbine j " .

When handling irradiated fuel in the secondary containment and during i CORE ALTERATIONS and operations with a potential for draining the reactor vessel.

4 i During CORE reactor vessel. ALTERATIONS and operations with a potential for draining the l ~ (a) Deleted.

! (b) d A channel may be placed in an inoperable status for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for required surveillance condition provided at leastwithout placing the channel in the tripped system is monitoring that parameter. one other OPERABLE channel in the same trip with a design providing only one channel per trip system,In addition for those trip systems be placed in an inoperable status for up to 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months for requiredthe channel may surveillance testing without placing the channel in the tripped condition provided that the redundant isolation valve, inboard or outboard, as applicable, in each line is operable and all required actuation instrumentation system for that in the tripped redundant valve is OPERABLE, or place the trip condition.

(c) Also a::tuates the standby gas treatment system. ,

(d) !

(e) A channel is OPERABLE if 2 of 4 instruments in that channel are OPERABLE. 1 Also Tableactuates 3.6.5.2-1. secondary containment ventilation isolation dampers per (f) Closes only RWCU system inlet outboard valve. '

j

< l .

U yf fac& I foM ,

.for. Infor'mo$lon DN Y>

. no ck,3es LA SALLE - UNIT 1 3/4 3-14 Amendment No. 10 )

r

s' g

I TABLE 3.3.2-1 (Continued)

NOTES (Continued)~

i (g) Requires RCIC steam supply pressure-low coincident with drywell pressure-high.

(h) ' Manual initiation isolates 1E51-F008 only and only with a i:oincicent reactor vessel water level-low, level 2, signal.

(1) Both channels of each trip system may be placed in an inoperable status for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for required reactor building ventilation system corrective maintenance, filter changes, damper cycling and surveillance tests, other than Surveillance Requirement 4.6.5.1.c, without placing the trip system in the tripped condition. .

(j) Both channels of each trip system may be placed in an inoperable status for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .for performance of Surveillance Requirement 4.6.5.1.c withoutplacin# the trip system in the tripped condition.

08 Y'O GA 0Y

& l0$$ of r W 0f i

LA SALLE - UNIT 1 3/4 3 14(a) Amendment No. 77 A

I; 1

TARLE 3.3.2-2 ri 4

E ISOLATION ACTUATION INSTRtBENTATION SETP0lNTS __

. . . .fl.

ALL6 M LE .!

I e

TRIP FUNCTION A. AUTOMATIC INITIATION TRIP SETPOINT VALUE I!

t t

E 1. PRIMARY CONTAllOENT ISOLATION .

a. Reactor Vessel Water Level !

" 1) Low, Level 3

> 12.5 inches * > 11.0 inches

i

2) Low Low, Level 2 s -50 faches* I -57 inches

i' :

3) Low Low Low, Level 1 I -129 inches

I -136 inches

l l!

b. Drywell Pressure - High 51.69psig {1.e9psig ,!

c. Main Steam Line i t 1). Radiatten - Nigh i 3.0 x full power background < 3.6 x full background i!

n 2) Pressure - Lew 1 854 psig 1 834 psig u8I8 3) Flow - Hlah q_ < 111 psid < 116 psid

d. (Main 5 team Line Tunnel J : ;

N m perature - Hjelt./ < 14 < 146*

g e. Me"n Steam Line Twinal 70 : ;

a Teeperature - High b<I7 nches

F Ng vacuum

< F I 5.5 inches Ng vacuum i

f.

Condenser Vacuum - Low

2. SEC3NDARY CONTAllelENT ISOLATION

- a. Reacter Rullding Vent Exhaust l Plenum Radiatten - High < 10 ar/hr . < 15 ar/hr

b. Drywell Pressure - High j1.69psig {1.09psig i

c. Reacter Vessel Water Level - Low Low, Level 2 1 -50 inches

1 -57 inches *

d. Fuel Peel Vent Exhaust ;

Radiatten - High i 10 ar/hr ,

< 15 ar/hr -

3. REACTOR WATER CLEANUP SYSTEM ISOLATI0ll A Flow - Nigh i 70 gym < 87.5 p g a.

b. Heat Exchanger Area Temperature j

- High -< 181*F -

< 187'F .

i

c. Heat Exchanger' Area Ventilation .

AT - High < 85'F < 91*F SLCS Initiation HA R4 F d.

e. Reacter Vessel Water Level - i

Low Low, Level 2 1 -50 inches

1 -57 inches * .

i i

. I 1

t

_ _ _ _ . _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _____-__-____?

TABLE 3.3.2-3 ISOLATION SYSTEM INSTRUMENTATION RESPONSE TIME TRIP FUNCTION RESPONSE TIME (Seconds)#

A. AUTOMATIC INITIATION

1. PRIMARY CONTAINMENT ISOLATION

a. Reactor Vessel Water Level

1) Low, Level 3 N/A

2) Low Low, Level 2 N/A

3) Low Low Low, Level 1 s 1.0*

b. Drywell Pressure - High N/A .

c. Main Steam Line

1) Radiation - High "3 - s 1.0*

2) Pressure - Low s 2.0*

hb[6Cd. main 3) Flow - High steam Line Tunnel Ta==arature - Hiah s_0.5*

NhtD-R. t

e. Condenser Vacuum - Low N/A

f. Main Steam Line Tunnel ATemperature - High N/A

2. SECONDARY CONTAINMENT ISOLATION N/A

a. Reactor Building Vent Exhaust Plenum Radiation - High i

b. Drywell Pressure - High '

c. Reactor Vessel Water Level - Low, Level 2 '

d. Fuel Pool Vent Exhaust Radiation - High

3. REACTOR WATER CLEANUP SYSTEM ISOLATION N/A

a. AFlow - High

b. Heat Exchanger Area Temperature - High

c. Heat Exchanger Area Ventilation AT-High

d. SLCS Initiation

e. Reacto,r Vessel Water Level - Low Low, Level 2

4. REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION N/A

a. RCIC Steam Line Flow - High

b. RCIC Steam Su,) ply Pressure - Low

c. RCIC Turbine Exhaust Diaphragm Pressure - High '

d. RCIC Equipment Room Temperature - High

e. RCIC Steam Line Tunnel Temperature - High

f. RCIC Steam Line Tunn'el ATemperature - High

g. Drywell Pressure - High

h. RCIC Equipment Room ATemperature - High

5. RHR SYSTEM STEAM CONDENSING MODE ISOLATION N/A

a. RHR Equipment Area ATemperature - High

b. RHR Area Cooler Temperature - High

c. RHR Heat Exchanger Steam Supply Flow High LA SALLE - UNIT 1 3/4 3-18 AMENDMENT NO. 98

T_anrr 4.3.2.1-1 ISOLATION ACTUATION TMSTsuptENTATION SURVEILLANCE REOUIRDtENTS CHANNEL OPERATIONAL CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR NHICH TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REOUIRED A. AUTOMATIC INITIATION

1. PRINARY CONTAISSIENT ISOLATION ,

a. Reactor Vessel Mater k,evel

1) Low. Level 3 S Q R 1. 2 3

2) Low Low, Level 2 NA Q R 1, 2, 3

3) Low Low Low, Level 1 S Q R 1. 2 3

b. . Drywell Pressure - High NA Q Q 1, 2, 3

c. Nain Steam Line 11 Radiation - High S Q R 1, 2, 3 e eg 2: Pressure - Low NA Q Q 1

3) Flow - Hiah O~ NA Q R 1, 2 3

d. ain Steam Line Tunne1T A Temperature - Hinh / (NA O R 1. 2, 3

e. Condenser vacuum - Low HA Q Q 1, 2 ~.3 Q E. Nain steen Line Tunnel A Temperature - High NA Q R 1 2, 3

2. SECONDARY CONTAIfetENT ISOLATION

a. Reactor Building Vent Exhaust Plenum Radiation - High S Q R 1. 2, 3. and **

b. Drywell Pressure - High NA Q Q 1 2 3

c. Reactor Vessel Mater Level - Low Low. Level 2 NA Q R 1, 2, 3. and 8

d. Fuel Pool Vent Exhaust Radiation e High S Q R 1. 2 3. and **

3. REACTOR NATER CLEANUP SYSTEN ISOLATION

a. A Flow - High S Q R 1, 2, 3

b. Heat Exchanger Area Temperature - High NA Q Q 1, 2, 3

c. Heat Exchanger Area Ventilation AT - High NA Q Q 1, 2, 3

d. SLCS Initiation NA R NA 1, 2, 3

e. Reactor Vessel Mater Level - Low Low, Level 2 NA Q R 1 2 3 f LA SALLE - UNIT 1 3/4 3-20 Amendment No. 104

~

2 . (

' ' . INSTRUMENTATION gggg3 ktglp%utar bnilbg^vcntilatimor.

hA _ # _ + ^

'J/d 3,7 TBeLATION AL*TUATION TK-rmUns4TATTON This specification ensures the effectiveness of the instrumentation used to mitigate the consequences of accidents by prescribing the OPERABILITY trip setpoints and response times for isolation of the reactor systems. When j necessary, one channel may basinoperable for brief intervals to conduct required surveillance. Both7ehannels of each trip system for the main steam tunne1 be plac @auient_ temperature an& ventilation system differential temperature may an an inoperanle status for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months ',for required reactor building ventilation system maintenance and testing and 12 houraVfor the required secondary in the tripped containment Leak Rate test without placing the trip system condition.

This will containment.

the ventilation system and secondary allow for maintaining the reliability of Specified surveillance intervals and surveillance and maintenance outage times have been determined in accordance with NEDC-308517-A, supplement 2. " Technical specification Improvement Analyses for BWR Isolation Instrumentation Common to RPS and ECCS Instrumentation *, March 1989, and with NEDC-31677P-A.

Technical specification Improvement Analysis for SWR Isolation Actuation Instrumentation *, July 1990.

When a channel is placed in an inoperable status solely for performance of required surveillances, entry into LCO and required ACTIONS may be delayed, provided the associated function maintains primary containment isolation capability. Some of the trip settings may have tolerances explicitly stated where both the high and low values are critical and may have a substantial effect on safety. The setpoints of other instrumentation, where only the high or low and of the setting have a direct bearing on safety, are established at a level away from the normal operating range to prevent inadvertent actuation of the systems involved. '

Except for the MSIVs, the safety analysis does not address individual sensor response times or the response times of the logic systems to which the sensors are connected. For A.C. operated valves, it is assumed that the A.C.

power generators.

supply is lost and is restored by startup of the emergency diesel In this event, a time of 13 seconds is assumed before the valve starts to move. The safety analysis considers an allowable inventory loss which delay.

in turn determines the valve speed in conjunction with the 13 second 3/4.3.3 MtFRCENCY CORF COOLTMC BYBTEM ACTUATION 1e1mDMENTATION The emergency core cooling system actuation instrumentation is provided the abilityactions to initiate to mitigate of the operator to the consequences of accidents that are beyond control. This specification provides the OPERABILITY requirements, trip setpoints and response times that will ensure.

effectiveness of the systems to provide the design protection. Although the instruments are listed by system, in some cases the same instrument may be used to send the actuation signal to more than one system at the same time.

Specified surveillance intervals and surveillance and maintenance outage times have been determined in accordance with NEDC-30936P-A,

Technical specification Improvement Nethodology (With Demonstration for BWR ECCS ;

l Actuation

1. Instrumentation)*, Parts 1 and 2, December 1988, and RE-025 Revision i

Technical Specification Improvement Analysis for the Emergency Core cooling and System Actuation Instrumentation for LaSalle County Station, Units 1 2*, April 1991.

for performance of required When asurveillances.

channel is placed in an inoperable status solely :

entry into LCO and required ACTIONS may be capability.

delayed, provided the associated function maintains ECCS initiation LA SALLE - UNIT 1 B 3/4 3-2 Amendment No. 104

TABLE 3.3.2-1 ~.

ISOLATION ACTUATION INSTRUMENTATION VALVE GROUPS MINIMUM OPERABLE APPLICABLE OPERATED BY CHANNELS PER OPERATIONAL !

TRIP FUNCTION SIGNAL TRIP SYSTEM (bl CONDITION ACTION l A. AUTOMATIC INITIATION

. 1. PRIMARY CONTAINMENT ISOLATION '

a. Reactor Vessel Water Level l 11 Low, level 3 7 .2 1, 2, 3 20 21 Low Low, level 2 2, 3 2

((3)Low Low Low, Level 1

( 1, 10 2 1, 2, 3 1, 2, 3 20 20

b. Drywell Pressure - High 2, 7, 19 2 1, 2, 3 20

c. Main Steam Line *

1) Radiation - High 1 2 1, 2, 3 21 3 2 1, 2, 3 22 2 Pressure - Low 1 2 1 23 Def8I6 3 Flow - High 1 2/line"' 1, 2, 3 21

d. ain Steam Line Tunnel Temperature - High h- __

2

~

1(ll,'g,2('"I',

3 D21)

e. Main Steam Line Tunnel O ATemperature - High 1 2 -

1(ll,'g ,2('"3) ,

f. Condenser Vacuum - Low 1 2 1, 2* , 3* 21

2. SfCONDARY CONTAINMENT ISOLATION

a. Reactor Building Vent Exhaust Plenum Radiation - High 4 (*"* 3 2 1, 2, 3 and " 24 l

b. Drywell Pressure - High 4'*" 2 1,2,3 24

c. Reactor Vessel Water i level - Low Low, Level 2 4 ( * " 2 1, 2, 3, and

24 t

t l d. Fuel Pool Vent Exhaust '

l Radiation - High 4 (* " 2 1, 2, 3, and " 24 ;

I LA SALLE - UNIT 2 3/4 3-11 Amendment No. 87

-. - -.-.-..?- .--- -

__ _ _ , _ . _ . . _ _ _ - - - - ~ " - ~ ~ ~ ~ ~ ~ ~ ~ ~ ' ~ ~

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Isot.1v10N ACTtJ1TTfts ._ _ , _..__ _ ) vf(Mt .

. ave an -H, ,-aga, ACTION 20 -

, Be in atthe within least nextEDT24sRUTDouN hours. within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN ACTION 21 -

Be in at least STARTUP with the associated isolation valves closed within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months or be is at least EDT SEUTDONE within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in 00LD SEUIDom within the next 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

ACTION 22 -

close the affected system isolation valves within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and declare the affected system anoperable.

ACTION 23 -

Be in at least STARTUP withia 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

ACTION 24 -

Establish SE'=nt*v treatment system CONTAIRMENT operating withinINTEGRITr 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . with the standby gas ACTION 25 -

Lock the affected system inalatian valves closed within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and declare the affocted system inoperable.

E

' ACTION 26 -

Provided that the' manual initiation function is OPERAELE for each other group valve, inhosed or ontboard, as applicable, in l each line, restore the manual initiation function to OPERABLE i status within 24 honest otheswise, restore the m.ma==1 initiation function

a. to OPERAILE status neithin 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months 's otherwise Be in at least 30T SEUIncNN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and

b. in COLD SSUTDONN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , or )

close the affacted system isolation valves within the next i hour and declare the affacted system in operable.' ;

i TABLE NOTATTORS May stop be valvesbypassed closed. with reactor steam pressure < 1043 psig and all turbine

- {

When handling irradiated fuel in the -A=y containment and during i CORE ALTERATIONS and operations with a potential for draining the reactor vessel.

During CORE ALTERATIONS and operations with a potential for draining the reactor-vessel.

I (a) Deleted.

(b)

A channel may be placed in an inoperable status for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for required surveillance without placing the channel in the tripped condition system is provided monitoring at least one other WERABLE channel in the same trip that parameter.

In addition for those trip systems i be placed in an inoperable status for g to 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months for requiredwith { '

surveillance testing without placing the channel in the tripped condition provided that the redundant isolation volve, inboard or outboard, as ,

applicable, in each line is operable and all required actuation !

instrumentation system in the tripped for thatcondition.

redundant valve is OPERABLE, or place the trip (c) Also actuates the standby gas treatment system.

(d)

(e) A channel is OPERABLE if 2 of 4 instruments in that channel are OPERABLE Also actuates secondary containment ventilation isolation dampers per Table 3.6.5.2-1.

(f)

Closes only RWCU system inlet or.tboard valve.

TMs pge is providec

( % \dorma% only, No chayes LA SALLE - UNIT 2 3/4 3-14 Amendment No. 90

TABLE 3.3.2-1 (Continued)

NOTES (Continued)

(g) Requires RCIC steen supply pressure-low coincident with drywell pressure-high. l (h) Manual initiation isolates 2E51-F008 only and only with a coincident reactor vessel water level-low, level 2, signal.

(i) Both channels of each trip system may be placed in an inoperable status for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for required reactor building ventilation system corrective maintenance, filter changes, damper cycling and surveillance tests, other than in theSurveillance Requirement 4.6.5.1.c, without placing the trip system tripped condition.

(j) Both channels of each trip system may be placed in an inoperable status for .

up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for perfomance of Surveillance Requirement 4.6.5.1.c without placing the trip system in the tripped condition.

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LA SALLE - UNIT 2 3/4 3-14(a) Amendment No. 61

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TABLE 3.3.2-3 ISOLATION SYSTEM INSTRUMENTATION RESPONSE TIME TRIP FUNCTION RESPONSE TIME (Seconds M A. AUTOMATIC INITIATION

1. PRIMARY CONTAINMENT ISOLATION

a. Reactor Vessel Water Level

1) Low, Level 3 N/A

2) Low Low, Level 2 N/A

3) Low Low Low, Level I s 1.0*

b. Drywell Pressure - High N/A

c. Main Steam Line

1) Radiation - High("2 s 1.0*

i

2) Pressure - Low $ 2.0*

)BIBf6 3) Flow - High s_0.5*

d. ain steam t.Ine Tunnel T=eratute - High R/A} -4.

e. Londenser Vacuum - Low N/A

f. Main Steam Line Tunnel ATemperature - High N/A

2. SECONDARY CONTAINMENT ISOLATION N/A

a. Reactor Building Vent Exhaust Plenum Radiation - High

b. Drywell Pressure - High

c. Reactor Vessel Water Level - Low, Level 2

d. Fuel Pool Vent Exhaust Radiation - High

3. REACTOR WATER CLEANUP SYSTEM ISOLATION N/A

a. AFlow - High

b. Heat Exchanger Area Temperature - High

c. Heat Exchanger Area Ventilation AT-High

d. SLCS Initiation

e. Reactor Vessel Water Level - Low Low, Level 2

4. REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION N/A

~

a. RCIC Steam Line Flow - High

b. RCIC Steam Supply Pressure - Low

c. RCIC Turbine Exhaust Diaphragm Pressure - High

d. j RCIC Equipment Room Temperature - High *

e. RCIC Steam Line Tunnel Temperature - High '

f. RCIC Steam Line Tunnel ATemperature - High

g. Drywell Pressure - High

h. RCIC Equipment Room ATemperature - High

5. RHR SYSTEM STEAM CONDENSING MODE ISOLATION N/A

a. RHR Equipment Area ATemperature - High

b. RHR Area Cooler Temperature - High

c. RHR Heat Exchanger Steam Supply Flow High LA SALLE - UNIT 2 3/4 3-18 AMENDMENT NO. 82

.m b

TABLE 4.3.2.1-1

~

ISOLATION ACTUATION INSTRUNENTATION SURVEIff2 M E REOUIREni-is t CHANNEL OPERATIONAL CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR NHICH TRIP FUNCTION CHECK _ TEST CALIBRATION SURVEILLANCE REOUIRED A. &UTOMATIC INITIATION i

1. PRINARY CONTAIfelENT ISOLATION

, i

a. Reactor Vessel Nater Level ,

1) Low, Level 3 S Q R 1,2,l'#

21 Low Low, Level 2 NA Q R 1,2,3 31 Low Low Low, Level 1 S Q R 1, 2, 3

b. Drywell Pressure - High NA Q Q 1, 2, 3

c. Main Steam Line il Radiation - High S Q R 1, 2, 3 h' '

2) 3)

Pressure - Low Flow - High NA NA Q

Q Q

R 1

1,2,3

d. Main Steam Line Tunnel _

i Q emperature_- Minh QA O_ m 1, 2, 3

e. Condenset vacuum - Low NA Q Q 1, 2*, 3*

t. Main Steam Line Tunnel ,

A Temperature - High NA Q R 1,2,3

2. 2".cONDhaY COMTAIRAGENT ISOLATION ,

m. Reactor Building Vent Exhaust Plenum Radiation - High S Q R 1, 2, 3 and **

b. Drywell Pressure - High NA Q Q 1, 2, 3

c. Reactor Vessel Nater Level - Low Low, Level 2 NA Q R 1, 2, 3, and 8 ;

d. Fuel Pool Vent Exhaust t Radiation - High S Q R 1, 2, 3.and **

t

3. RCACTOR NATER CLEANUP SYSTEN ISOLATION

a. A Flow - High S Q R 1, 2, 3

b. Heat Exchanger Area Temperatus;e - High NA Q Q 1,2,3 l c. Heat Exchanger Area Ventilation AT - High NA Q Q 1,2,3

d. SLCS Initiation NA R NA 1,2,3

e. Reactor Vessel Nater Level - Low Low, Level 2 NA Q R 1, 2, 3

i LA SALLE - UNIT 2 3/4 3-20 Amendment No. 90

. - - - . _ . _ . . _ - - _ _ - . . - _ - . _ _ ~ _ - . . . . - - - - - . . - _ . _ _ _ . . - . . . -.___ _.__-. --

TNETRUMEN'IATIDN l-

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! y 3 /4.3.2 YEOLATTON ACTUATTON TWRTRDNFNTATTON This specification ensures the effectiveness of the instrumentation used to mitigate the consequences of accidents by prescribing the OPERABILITY trip setpoints and response times for isolation of the reactor systems. When necessary, t,ne channel may be inoperable for brief intervals to conduct required surveillance. Both ch=aaels of each trip system for the main steam tunnel (ammtent t _ ,srature angiventilation system differential temperature may be placea an an inoperable status for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for required ramctor I

building ventilation system maintenance and testing and 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

tor the ;

j required secondary containment Leak Rate test without placing the trip system in the tripped condition. i

This will allow for maintaining the reliability of the ventilation system and secondary containment. specified surveillance I

intervals and surveillance and maintenance outage times have been determined ;

j in accordance with NEDC-308517-A, supplement 2, " Technical specification i Improvement Analyses for BWR Isolation Instrumentation Common to RPS and ECCS Instrumentation *, March 1989, and with NEDC-31677P-A, " Technical specification Improvement Analysis for BWR Isolation Actuation Instrumentation * , July 1990. f l

When a channel is placed in an inoperable status solely for performance of j required surveillances, entry into LCO and required ACTIONS may be delayed, j

provided capability.

the associated function maintains primary containment isolation i

Some of the trip settings may have tolerances explicitly stated i

where both the high and low values are critical and may have a substantial effect on safety. The setpoints of other instrumentation, where only the high or low and of the setting have a direct bearing on safety, are established at a level away from the normal operating range to prevent inadvertent actuation of the systems involved.

Except for the MSIVs, the safety analysis does not address individual I sensor response times or the response times of the logic systems to which the sensors are connected. For A.C. operated valves, it is assumed that the A.C.

power generators.

supply is 1 cat and is restored by startup of the emergency diesel starts to move.

In,this event, a time of 13 seconds is assumed before the valve The safety analysis considers an allowable inventory loss which delay.

in turn determines the valve speed in conjunction with the 13 second 3/4.3.3 FMERCFMEY CORE COOLYMn m sre_si ,cTuiTION TMETRUMENTATION The emergency core cooling system actuation instrumentation is provided the abilityactions to initiate to mitigate of the operator tothe control. consequences of accidents that are beyond This specification provides the OPERABILITY requirements, trip setpoints and response times that will ensure effectiveness of the systems to provide the design protection. Although the instruments are listed by system, in some cases the same instrumhnt may be used to send the actuation signal to more than one system at the same time.

LA SALLE - UNIT 2 B 3/4 3-2 Amendment No. 90

, o I ATTACHMENT C SIGNIFICANT HAZARDS CONSIDERATION Commonwealth Edison has evaluated the proposed Technical Specification l Amendment and determined that it does not represent a significant hazards ;

consideration. Buaed on the critelia for defining a significant hazards consideration established in 10 CFR 50.92, operation of LaSalle County Station Units 1 and 2 in accordance with the proposed amendment will not i

1) Involve a significant increase in the probability or consequences of an accident previously evaluated because: l

a. There is no effect on accident initiators so there is no change in 1 probability of an accident. The accident analysis associated with a steam line break in the main steam line tunnel assumes an instantaneous circumferential break of a main steam line downstream of the outermost isolation valve. The leak detection isolation on differential temperature based on s 10% of a calculated critical crack of a main steam line is only

, a precursor of a break, and thus does not affect the probability of a break. I

b. There is no or minimal effect on the consequences of analyzed accidents due to deletion of the automatic isolation on high temperature leak detection in the main steam line tunnel or due to increasing the leak detection differential temperature setpoint and allowable values to detect a 100 gpm steam leak from a crack in a main steam line. The worst case accident corresponding to main steam lines outside of the reactor vessel and primary containment boundary is a main steam line break, which bounds the dose consequences of any size steam leak less than a full break. Also, a 200 gpm steam leak results in a calculated offsite dose within the annual whole body dose limit and the radiciodine release limit per 10CFR50 Appendix 1, if detected and isolated within several weeks.

2) Create the possibility of a new or different kind of accident from any accident previously evaluated because:

The purpose of the main steam line isolation is based on leak detection and automatic isolation for leakage in the main steam line tunnel downstream of the outermost isolation valve. This change maintains this capability with only the leak detection based on high differential temperature in the steam line tunnel.

Also, the primary containment isolation logic for main steam line leak detection isolation on high differential temperature remains the same.Thus no new or different accident is created.

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J ATTACHMENT C SIGNIFICANT HAZARDS CONSIDERATION

3) Involve a significant reduction in the margin of safety because:

, The increased setpoint for differential temperature leak detection for automatic isolation of the main steam lines due to a steam leak outside of the primary

containment is based on calculated / analyzed response to a steam leak small i compared to the leak from a critical crack. The leak detection isolation logic remains single failure proof. The previous evaluation of diversity of isolation parameters considered the ambient temperature and differential temperature j isolations as one parameter in Table 5.2-8 of the LaSalle UFSAR. The deletion of leak detection isolation of the main steam lines based on high ambient temperature in the main steam line tunnel is acceptable, because the differential temperature isolation has been analyzed to detect and isolate the

main steam lines based on bounding inlet air temperatures. Therefore, the i Main Steam Line High flow, vessel low level, and the differerd5' temperature instruments maintain adequate diversity of isolation parameters without main steam line tunnel high temperaturo.

4 The differential temperature leak detection for the main steam line tunnel ;

depends on normal ventilation flow to detect leakage. Therefore, the trip l function will be declared inoperable upon loss of or shutdown of normal ventilation. The Technical Specifications currently allow the main steam tunnel :

high temperature and high differertial temperature isolation channels to be inoperable for up to 4 or 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months during the performance of specified required l surveillances. The 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowed outage time is currently for an 18 month l surveillance requirement. The addition of allowance for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowed I outage time to recover normal ventilation following an unplanned loss of normal ,

ventilation is reasonable, since the time is small compared to the time frame l over which a pipe crack grows. Also, supplemental monitoring of water collection sumps and area temperature in the main steam line tunnel provides heightened awareness of operators to detect leakage in the main steam line tunnel during the time normal ventilation is not available. The planned shutdown of normal ventilation is currently allowed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months by the Technical Specifications. The unplanned loss of normal ventilation is expected to be less than two times per cycle upon completion design changes to make l

the isolation logic power supply D.C. instead of A.C. through motor generator sets.

Therefore, this requested Technical Specification amendment does not involve a significant reduction in the margin of safety.

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, . i ATTACHMENT C l SIGNIFICANT HAZARDS CONSIDERATION Guidance has been provided in " Final Procedures and Standards on No Significant Hazards Considerations," Final Rule,51 FR 7744, for the application of standards to license change requests for determination of the existence of significant hazards considerations. This document provides examples of amendments which are and are not considered likely to involve significant hazards, considerations. These proposed amendments most closely fit the example of a change which may either result in some increase to the probability or consequences of a previously analyzed accident or may reduce in some way a safety margin, but where the results of the change are clearly within all acceptable criteria witn respect to the system or component specified in the applicable Standard Review Plan.

This proposed amendment does not involve a significant relaxation of the criteria used to establish safety limits, a significant relaxation of the bases for the limiting safety system settings or a significant relaxation of the bases ior the limiting conditions for operations. Therefore, based on the guidance provided in the Federal Register and the criteria established in 10 CFR 50.92(c), the proposed change does not constitute a significant hazards consideration.

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! ATTACHMENT D l l

l ENVIRONMENTAL ASSESSMENT STATEMENT APPLICABILITY REVIEW i

Commonwealth Edison has evaluated the proposed amendment against the criteria for identification of licensing and regulatory action requiring environmental assessment in accordance with 10 CFR 51.21. It has been determined that the proposed changes meet the criteria for a categorical exclusion as provided under 10 CFR 51.22(c)(9).

This conclusion has been determined because the changes requested do not pose significant hazards considerations or do not involve a significant increase in the amounts, and no significant changes in the types, of any effluents that may be released off-site. Additionally, this request does not involve a significant increase in individual or cumulative occupational radiation exposure.

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, , i ATTACHMENT E UFSAR REFERENCES

1. Table 7.1-8 (7.1-9 in FSAR), Leak Detection System Codes and Standards.

2. PAGE 7.A.3-35 OF SECTION 7.A.3.2.1. CONFORMANCE TO IEEE 279-1971.

OPERATING BYPASSES, IEEE 279-1971 Paragraph 4.8. (FSAR section 7.3.2.2.1 )

3. PAGE 7.A.3-34 OF SECTION 7.A.3.2.1, CONFORMANCE TO IEEE 279-1971.

DERIVATION OF SYSTEM INPUTS, IEEE 279-1971 Paragraph 4.8. (FSAR section 7.3.2.2.1)

4. 7.3.2.2.3.3 Safety Design Bases of the initiating isolation signal, Main Steamline Space High Temperature and Differential Temperature. (FSAR section 7.3.1.1.2.4.3) l

5. BTP ICSB 21 Guidance foi Application of Regulatory Guide 1.47, STP pp. 7.A-i 15, ; and R.G.1.47, Bypassed and Inoperable Status Indication for Nuclear Power Plant Safety Systems.

t i

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, . t ATTACHMENT F HISTORY OF LASALLE UNIT 1 AND 2 MAIN STEAM TUNNEL LEAK DETECTION ISOLATIONS From the initial startup of LaSalle Unit 1, it was recognized that the setpoints of the high differential temperature leak detection for Main Staam Line isolation were very close to the normal operating conditions. This was not a significant problem during steady state conditions, but during transient conditions related to changes in main steam tunnel ventilation (VR) flow and/or inlet temperature, the instruments falsely detected a leak. Flow changes which cause the Main Steam Tunnel (MST) temperature to approach the high temperature trip have been caused by isolation of VR (no flow) or filter plugging (which has occurred quickly due to blizzards). A significant drop in inlet temperature which causes MST differential temperature to approach the differential temperature trip can be caused by loss of the Station Heat Recovery system (SH), loss of the electric heaters or even sudden drops in outside air temperature. Over the years many attempts have been made to mitigate this problem.

Spurious trips of these instruments result in a scram which isolates the reactor from its primary heat sink causing a significant challenge to the plant and its operators.

The high temperature channels did not originally cause much of a problem due to their location in the steam tunnel. VR could be shutdown for several hours without tripping the high temperature sensors. The differential temperature sensors were not a problem with VR shutdown (differential temperature goes more slowly), but would trip when VR was restarted due to an inrush of cooler air prior to the outlet sensors cooling off or when running the purge train (VO) with the suction off the steam tunnel.

Solutions at that time provided procedural guidance for methods to avoid the trip of the differential temperature sensors when VR was shutdown and started. The initial 4 solution to this problem was a Technical Specification change to allow the differential ;

temperature channels te be bypassed for up to four hours if the temperature channels were operable. This Technical Specification allowance was provided in the initial Unit 2 Technical Specification and Unit 1 Technical Specification amendment 18 (August 1984). On May 25,1984 an exigent Technical Specification change was submitted (OSR 84-25) to change the differential temperature setpoints based on actual steady state differential temperature data, keeping the calculational basis (25 gpm) unchanged. The original Technical Specification setpoint was based on expected conditions in the main steam tunnel, however the actual differential temperature was greater than pre-startup calculations predicted. This amendment (Unit 1 #17, Unit 2

2) was approved. This provided more operating margin for steady state conditions, but did not prevent isolations from occurring if VR was restarted. The allowed bypass of the differential temperature sensors provided the allowance to restart VR without a trip by installing jumpers.

F-1

ATTACHMENT F HISTORY OF LASALLE UNIT 1 AND 2 MAIN STEAM TUNNEL LEAK DETECTION ISOLATIONS However to make the Leak Detection system more responsive due to an overall Leak Detection review, modifications were initiated to move the temperature and differential temperature sensors in both units. After the Unit 1 sensors were moved, on February 2,1985, the unit scrammed due to high temperature soon after VR was isolated. The installation of the modification was delayed in Unit 2 based on this problem and is still not installed. Since the temperature sensors were relocated, the temperature channels have been a problem in Unit 1.

As a result of the isolation an engineering study was initiated to determine alternatives to the temperature and differential temperature Leak Detection design.

The study concluded that there were technically viable designs which could be pursued to partially mitigate the problem. The engineering solutions were expensive and were not total solutions to the problem in parallel a PRA evaluation with EPRI help was performed to confirm from a risk basis that a small steam leak did not warrant a MSIV closure transient. Another Technical Specification change was pursued on July 10,1987 (C;SR 87-27). This amendment request proposed to delete the temperature and differential temperature isolation signals as a safety improvement.

However, the submittal was incomplete and was rejected on February 8,1988.

The major concern at the time was performing VR isolation damper surveillances and the secondary containment leakage rate test (SCLRT). Up to this point, all SCLRTs were done during dual unit outages since VR must be shut dowr. in both units to perform the test. Due to the urgent need of Technical Specification relief to avoid a dual unit outage, another submittal was made (OSR 89-41) on July 26, 1989 to bypass the trips for a limited time to accomplish the SCLRT and other expected routine activities. This change allowed the station to perform maintenance work and surveillance testing which was the primary concem in the short term and allowed the amendment to be approved in a relatively shcu time (Unit 1 # 77, Unit 2 #

61).

On August 16,1995 Unit 1 secondary containment isolated due to a loss of power to the B RPS bus. Seven minutes after the loss of ventilation, the Unit 1 steam tunnel temperature reached the setpoint of 140 F and caused the isolation of the main steam lines. The MSIV isolation caused the reactor to scram. It was obvious the entire probism had not been resolved.

Over the weekend of September 9 and 10,1995, the Unit 2 differential temperature on one channel monitoring the upper steam tunnel reached 34 *F and another channel F-2

s ATTACHMENT F HISTORY OF LASALLE UNIT 1 AND 2 MAIN STEAM TUNNEL LEAK DETECTION ISOLATIONS reached 32 *F. The trip setpoint is 36 *F. This has occurred as a result of cool nights, and not steam or water leaks.

As a result of non-leak conditions as indicated above there is little margin to a MSIV closure and associated automatic scram due to a false leak detection signal. As discussed in the history above, the steam tunnel temperatures and differential temperatures are affected by many things, which challenges the operators and at times places the unit (s) in jeopardy. The need to evaluate changing the setpoints or eliminate automatic isolation on temperature and differential temperature was reinforced as a result of the Unit 1 scram August 16,1995. The urgency of this evaluation was amplified after the high differential temperatures on Unit 2 on September 9 and 10,1995. Since then, many calculations and associated analyses have been required in order to determine a new basis for leakage detection isolation for the main steam lines outside of the primary containment isolation boundary.

LaSalle Unit 1 is currently scheduled to begin shutdown for its seventh refuel outage, L1R07, on January 25,1995. Due to the short time allowed for operator action to install jumpers to bypass the Main Steam Line Tunnel Temperature - High main steam line isolation automatic isolation, this " operator work around" has been determined to ,

be the most significant in NRC Region 3. LaSalle has initiated design changes in l parallel with the proposed Technical Specification amendm.;nt request. The Unit 1 design changes are being scheduled to be installed during L1R07.

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l ATTACHMENT G I CALCULATION SUMMARIES

1. Critical Crack Calculation and Steam Leakage Flow Calculation Summary:

The Comed calculation NED-P-MSD-086, "LaSalle Station Steam Tunnel Main Steam Line Leak Rate Calculation" Rev.0, dated December 5,1995, determines the critical crack size and its projected leakage for the Main Steam lines downstream of the outboard isolation valves in the MST. These quantities are calculated to determine the maximum possible leak rate, prior to line rupture for the Main Steam lines during normal operation. The calculation ,

determines the critical crack size for a circumferentially oriented throughwall l flaw usirig a limit load approach. The limit load methodology defined in the ASME Boiler and Pressure Vessel Code, Section XI,1989 Edition, is used as guidance for this calculation. This methodology has also been validated by GE for this application in LaSalle Leak Detection Temperature Measurement",

GENE Report DRF-E31-00029-3C, November 1995. To calculate the leak rate from the critical crack, the PICEP, Pipe Crack Evaluation Program, EPRI NP-3596-SR, December 1987, is used. ;

1 The results of this calculation demonstrate the critical crack length to be i 33.2" long. The leak rate for a circumferential flaw of.this length is I approximately 1290 gpm. It is the station's intent to use the min l mum leakage that will ensure adequate operational margin. The value being considered but not finalized is 100 gpm. This represents less than 10% of the critical crack length leakage.

2. Calculation of changes in differential temperature in response to a steam leak:

Comed calculation, LaSalle Main Steam Tunnel Temperature Response due to Steam Leakage with Ventilation System in Operation, BSA-L-95-05, Rev.

O, dated January 13,1996. This calculation uses the GOTHIC computer code to determine the main steam tunnel temperature (MST) response due to a variety of leak rates and supply air temperatures. GOTHIC (Generation Of Thermal-Hydraulic Information for Containments) is a general purpose thermal-hydraulics computer program for design, licensing, safety and operating analysis of nuclear power plant containments and other confinement buildings.

Applications of GOTHIC include evaluations of containment and containment subcompartment response to the full spectrum of high energy line breaks within the design basis envelope as described in UFSAR chapter 6, section 2.

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s o i ATTACHMENT G CALCULATION SUMMARIES )

i Applications may include pressure and temperature determination, equipment l qualification profiles and inadvertent system initiation, and degradation or failure of engineered safety features.

A sketch of the main steam tunnel is shown in Figure 1. In this analysis the MST is subdivided into three areas denoted as the lower, middle, and upper MST. The lower and upper MST extend from elevation 687 to 706 ft and from !

elevation 736 ft 7 in to 768 ft 4.5 in, respectively. The middle MST consists of the vertical section of the tunnel between elevation 706 ft and 736 ft 7 in.

The temperature of the MST is maintained by the reactor building j ventilation (VR) system. Two streams of VR air enter the MST, one at 687' elevation and the other at 740' elevation and exit the tunnel via an exhaust riser located at the top of the MST.

The analysis assumes the crack and steam leak develop over a 100 second period in the main steam line. The cracks are postulated to occur at any location along the full length of the steam line in the MST. For leak detection purposes, the lowest temperature rise in the MST would form the basis for establishing a leak detection setpoint. The lowest temperature rise in the MST, due to a given amount of steam leakage, occurs near the exit of the l upper MST VR flow and with a crack located in the lower MST near the area where the steam lines exit the tunnel. Thus, in this analysis, only a leak in the lower MST was considered.

The analytical model consists of three control volumes representing the upper, middle and lower MST. Five additional control volumes are used to model the structures adjacent to the MST. A flow path is used to represent the flow from the lower to the middle MST and another path from the middle to the upper MST. Additional flow paths are used to model the VR inlet and exhaust flows. The heat load in the MST is produced predominantly from the main steam and feedwater lines and is represented by one heater located in each of the MST control volumes. The VR supply air originates from outside the plant and enters the MST after passing through various areas in the reactor building.

Hence, the VR supply air temperature is dependent on the outdoor air temperature. Two different supply air temperature values,65 and 110 F, are used to bound the conditions expected year round. The VR flow rates are based on plant data and are:

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ATTACHMENT G CALCULATION SUMMARIES Upper MST supply flow 24,000 cfm Lower MST supply flow 40,000 cfm ,

Exhaust MST flow 64,000 cfm The upper MST supply flow and the exhaust MST flow are held constant during the analysis. The lower MST supply flow is varied in relation to the steam leakage rate according to a mass balance in and out of the MST.

The GOTHIC computer code results were compared with plant data and show good agreement between the calculated results and plant data.

The results show that the upper MST temperature varies directly with the quantity of steam leakage. For a given leakage rate, the upper MST temperature is highest for a VR inlet temperature of 110 *F and lowest for a VR inlet temperature of 65 F.

The data (see Figure 2 attached) indicates that with a 65 *F VR inlet temperature and a 125 gpm leak in the lower MST, the upper MST temperature would reach a value of approximately 164 *F. Using a leak detection setpoint for the temperature high of 164 F would still result in the requirement to quickly ;

bypass the isolation logic for a loss of VR in order to avoid the main steam isolation. The required response of bypassing the logic becomes even more critical on hotter days. In order to eliminate the need to bypass the leak detection logic on a loss of VR, a temperature high setpoint of ~200 "F would be required. The crack leakage required to generate a 200 F temperature in the upper MST with VR in operation with a 65 F inlet air temperature would be several hundred gpm. Therefore, leak detection isolation based on Main Steam Line Tunnel Temperature High would not allow operation without the potential for spurious trips.

The results also show that the upper MST differential temperature (the temperature difference between the exhaust riser air temperature and the VR inlet air temperature) varies directly with the quantity of steam leakage. For a given leakage rate, the upper MST differential temperature is highest for a VR inlet temperature of s 65 F and lowest for a VR inlet temperature of 2110 F.

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ATTACHMENT G l

CALCULATION SUMMARIES l l

The data (see Figure 3, attached) indicates that with a 110 *F VR inlet temperature and a 100 gpm leak in the lower MST, the upper MST differential ,

temperature would reach a value of 72.5 F. It is estimated that over 99% of )

the year the VR inlet temperature will be less than or equal to 100 *F. With the !

VR inlet temperature less than 110 *F, the setpoint will actually be isolating the j main steam lines on a leak of less than 100 gpm. i a

The current MST leak detection temperature instruments would remain available for alarm and indication capability. With a loss of VR, the differential temperature instrumentation would be made technically inoperable. The current temperature instruments would then be used to augment a monitoring surveillance of the MST to confirm no leaks develop while the differential ;

temperature instrumentation is inoperable. If a leak is confirmed, manual l isolation could be initiated as required. l Because the VR flows are induced by the VR exhaust fans, the inlet VR flow is reduced by the presence of steam. The reduce inlet flow phenomenon may affect the temperature indication frotn a sensor located in the VR inlet. As the air inlet flow reduces to zero due to increased leakage flow, the temperature i indicated will be that of the MST instead of the inlet flow. An analysis was performed that determined that both upper and lower VR flows are reduced to zero for a 250 gpm steam leak that grows from zero to 250 gpm over a 100 second period. Isolating on a 100 gpm steam leak assures that leak detection on differential temperature remains operable.

3. Setpoint Calculation:

Main Steam Tunnel Temperature Isolation Setpoint Error Analysis. Calculation No. NED-I-EIC-0208, Dated January 16,1996.

The purpose of this calculation is to determine the calibrated setpoint and )

allowable value for the Main Steam Tunnel Area Vent High Differential i Temperature Isolation instrument channels. This channel provides a Technical Specification setpoint and initiates a Group I isolation of the MSIVs and MSL drain valves on high differential temperature.

The calculation is valid under normal operating, accident environmental condi-tions, and allows for all normal operating and accident errors, thus ensuring Technical Specification compliance for the instrument channels.

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ATTACHMENT G CALCULATION SUMMARIES The methodology used herein is based on Comed documents,

1. Comed TID-E/l&C-20, " Basis for Analysis of Instrument Channel Set-point Error & Loop Accuracy", Rev. O, dated April 6,1992, and

2. Comed TID E/l&C-10, " Analysis of Instrument Channel Setpoint Error and Instrument Loop Accuracy", Rev. O, dated April 6,1992.

I The primary basis for Comed setpoint methodology is ANSI /ISA-S67.04-1988, "Setpoints for Nuclear Safety Related Instrumentation."

The evaluation of errors used to determine the " Total Error" (TE) is consistent with the above methodology with the following exception:

The calibration tolerance is assumed to describe the limits of the as-left component outputs. For a random error, this corresponds to 100% of the population and can be statistically represented by a 3 sigma value. Per the above TIDs , the " Setting Tolerance" (ST) is defined as a random j error which is due to the procedural allowances given to the technician j performing the calibration.

As stated above, the objective of this calculation was to determine the available margin between the Tech Spec allowable value and the nominal trip setpoint for normal operating conditions and the margin between the analyticallimit and the nominal trip setpoint for accident conditions. The acceptance criteria for this calculation was that a positive margin is required.

Conclusions:

1 The calculation determined a nominal setpoint for the main steam line tunnel differential temperature isolation setpoint that ensures a high level of confidence that the analytical limit will not be exceeded under normal or accident operating l conditions. I

1. The nominal trip setpoint is determined to be s 65.6 *F.

2. The allowable value is determined to be s 70.1 *F.

1 G-5

ATTACHMENT G CALCULATION SUMMARIES

4. 10CFR20 calculation of the offsite dose consequences due to a 200 gpm steam leak in the main steam line tunnel:

The off-site radiological doses due to postulated steam leakage in the l LaSalle County Station main steam line tunnel were calculated based on the normal operating condition radionuclide source documented in General Electric ,

Report NEDO 10871, dated March 1973, " Technical Derivation of BWR 1971 l Design Basis Radioactive Material Source Terms". This corresponds to " failed i fuel" releasing 100,000 microcuries of noble gases per second after 30 minutes )

delay along with 700 microcuries per second of radioiodines. The off-site dose l assessment methodology and site specific data are included in the Comed l Offsite Dose Calculation Manual (ODCM). j l

The calculation, Radiological Doses Due to Postulated Steam Tunnel Leakage, I BSA-L-96-03, Rev. O, dated 1/12/96, indicates that a steam leak of 200 gallons l per minute will result in a whole body dose rate of 1.9E-3 mrads per hour. The 10CFR50, Appendix I whole body annual dose limit is 5 mrem per year. At 1.9E-3 mrads per hour, it take over 2600 hours0.0301 days 0.722 hours 0.0043 weeks 9.893e-4 months to exceed the 5 mrem limit.

The radiciodine release rate is 9.8E-2 microcuries per second, and for a short duration is small compared to the limit of 1 curie per year in Appendix 1. ,

l In conclusion, a steam leak of 200 gpm could continue for several weeks without exceeding Appendix I limits. Thus, isolation of a main steam line on a steam leak of 100 gpm is well below the normal operation radionuclide release l limits of 10CFR50, Appendix 1.

l l

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. FIGURE 1 i MAIN STEAM LINE TUNNEL I EXHAUST AIR RISER

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. Upper Steam Tunnel Temperature due to Lower Steam Tunnel l Leakage ;

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4 90 -t- -! ;

7 L- - 1

. l 80 f 0 25 50 75 100 125 150 175 200 Steam Leakage, gpm 4

l

4 e

Fi0ure 3 i

Upper Steam Tunnel VR Delta T due to Lower Steam Tunnel Leakage 120 110 g 100 /i 90 7-80 .

i

70 Y- -

/ 4 E

E \' ,

l 60 - _ . --

50 - -J 1. -+-65 deg F VR inlet

-e-95 deg F VR inlet

--*-110 deg F VR inlet l

40 e ;

l l

30 - J --p-.

I 3

f i l l j l l

20 O 25 50 75 100 125 150 175 200 Steam Leakage, gpm 1

1 I

- ~ K 4A s.

l l

' 1 ATTACHMENT H l BASIS FOR DELETION OF MAIN STEAM LINE TUNNEL TEMPERATURE HIGH PRIMARY CONTAINMENT ISOLATION TRIP FUNCTION The Bases for deletion of the Main Steam Line Tunnel Temperature - High Primary Containment Isolation instrumentation trip function from Technical Specification 3/4.3.2 l is as follows:

The temperature and differential temperature instruments are not assumed to function to mitigate any accident described in Chapters 6 or 15 of the Updated Final Safety Analysis Report. The temperature instruments are provided only to detect and initiate isolation of a 25-gpm-equivalent steam leak. However, these instruments constitute only one method of determining steam leakage in their respective areas. In addition to the temperature monitoring, excess reactor coolant leakage can be detected by low reactor water level, high process line flow, high steam line tunnel differential temperature and various other plant specific methods. Several of the BWR-6s have performed studies and analyses which supports the relocation of both the ambient and differential temperature )

instruments from the Technical Specifications. In addition, LaSalle County ,

Station submitted an Amendment Request in July 1987 to delete these I instruments from Technical Specifications. This Amendment Request was rejected by the staff based on the emphasis being primarily based on PRA study, however conceptually not unacceptable. In May 1989, a package was prepared to resubmit deletion of the high temperature and high differential temperature trips. However, due to time limits the package was revised to request longer allowed outage time for surveillances that affect main steam tunnel temperature and differential temperature instead of deletion. This emendment was approved for Units 1 and 2 on April 15,1991 as amendments 77 and 61 to Unit 1 and 2 licenses NPF-11 and NPF-18, respectively.

The Ambient and Differential Temperature Isolation Instruments are neither used for, nor capable of, detecting a significant abnormal degradation of the reactor coolant pressure boundary prior to a design basis accident (DBA).

The Ambient and Differential Temperature Isolation Instruments are neither used for, nor capable of, monitoring a process variable that is an initial condition of a DBA or transient analyses.

The Ambient and Differential Temperature Isolation Instruments are not used as part of a primary success path in the mitigation of a DBA or transient. No pressure-temperature analyses, radiation dose calculations, or equipment qualification parameters take credit for operation of these ambient or differential H-1

l l

ATTACHMENT H j BASIS FOR DELETION OF MAIN STEAM LINE TUNNEL TEMPERATURE HIGH l PRIMARY CONTAINMENT ISOLATION TRIP FUNCTION temperature instruments. In addition, adequate redundancy is available to I perform their functions by other methods.

A PRA study considered two factors in determining core damage frequency l (CDF) impact: 1. The increase in CDF due to eliminating the automatic MSIV closure; and 2. the reduction in CDF by eliminating spurious MSIV closures.

1. Based on the low frequency for leaks to occur and the extremely low probability that operator action would not terminate the event in the available time frame, it was concluded that the increase in CDF due to J elimination of the automatic trip function is negligible.

2. The results of the analysis indicate that the CDF would be reduced by an insignificant amount by elimination of all MSIV closure events. This analysis bounds the elimination of spurious events causing MSIV closure.

However, the differential temperature instruments will be retained for the purpose of an additional line break detection method that will provide earlier isolation of the steam lines and steam line drains than the other line break instrumentation. Together with Main Steam Line High flow and vessellow level, the differential temperature instruments adequate diversity is maintained, l because previous evaluation of diversity of isolation parameters considered the ambient temperature and differential temperature isolations as one parameter in Table 5.2-8 of the LaSalle UFSAR.

H-2

ML20096G341

Text

Conclusions:

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