Text

Proposed Tech Specs Re Max Critical Power Ratio,Rod Position Indication Sys Surveillance,Rcic Pump Room Isolation & Control Room Emergency make-up Train Heaters
	ML20116D368
Person / Time
Site:	LaSalle
Issue date:	04/17/1985
From:	; COMMONWEALTH EDISON CO.
To:	;
Shared Package
ML20116D357	List: ML20116D354; ML20116D368;
References
	9988N, NUDOCS 8504290395
	Download: ML20116D368 (104)
	v • d • e

i i

l CO MONWEALTH EDISON COWANY l LASALLE COUNTY STATION UNITS 1 and 2 TECHNICAL SPECIFICATION CHANGE REQUEST APPENDIX 1

Subject:

Correction of Typographical and Administrative Errors...

Revised Pages:

Unit 1 Unit 2 3/4 2-5 3/4 2-5 3-87 3-87 6-9 4-3 6-24 6-8 6-26 6-27 6-27 6-29 12-9 6-30 7-21 7-28 12-9 9988N 8504290395 850417 PDR ADOCK 05000373 P PDR:

LASALLE COUNTY STATION UNITS 1 AND 2 TECHNICAL SPECIFICATION CHANGE REQUEST

SUBJECT:

Correction of Typographical and Administrative Errors and Inclusion of MCPR Limit Without EOC/RPT Curve on Figure 3.2.3-1.

REFERENCES:

1) C. W. Schroeder letter to H. R. Denton dated August 23, 1983.

2) C. W. Schroeder letter to H. R. Denton dated August 31, 1983.

3) Technical Specification Figure 3.2.3-1 Minimum Critical Power Ratio (KPR) versus T at Rated Flow.

4) FSAR Table 6.2-21

5) C. W. Schroeder letters to H. R. Denton dated January 13, 1984.

The Operating license (PF-18) for LaSalle County Station, Unit 2 was issued on December 16, 1983. Technical Specification Figure 3.2.3-1 (reference 3) in that document did not contain a curve to be used when EOC-RPT is inoperable as allowed for in specifications 3.2.3 and 3.3.4.2.

The analysis which provided the data for determining this curve was provided in references (1) and (2). This data is also applicable to Unit 1 (WF-11). This curve was submitted for Unit 1 as part of reference 5). A revised Figure 3.2.3-1 is included in Attachment A (Page 3/4 2-5).

Several valve stroke times on Technical Specification Table 3.6.3-1 do not reflect actual valve operating times and are not consistent with reference 4. Several of these errors are due to the valve size being less than the "line size" listed in the FSAR. Therfore when appling the actual valve size the standard closure times is reduced. The error in which 41 seconds versus 40 seconds was used for valves E12-F009 and E12-F008 appears to be an oversight. These corrections appear on pages 3/4 6-24 and 3/4 6-26 for Unit 1 and pages 3/4 6-27 and 3/4 6-29 for Unit 2 as indicated in Attachment A. These valves meet and have met the reduced times since each license was issued.

In addition typographical and editorial errors on pages 3/4 3-87, 6-9, 3/4 6-27 and 3/4 12-9 in Unit 1 and 3/4 4-3, 3/4 6-8, 3/4 6-30, 3/4 7-21, 3/4 7-28 and 3/412-9 in Unit 2 should be corrected as indicated in Attachment A.

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Figure 3.2.3-1 MINIMUM CRITICAL POWER RATIO (MCPR) VERSUS T AT RATED FLOW

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TABLE 3.3.7.11-1 r-

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$ RADI0 ACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION L F

MINIMUM CHANNELS l:

i OPERABLE APPLICABILITY ACTION

' INSTRUMENT ,

y 1. MAIN CONDENSER OFFGAS TREATMENT SYSTEM EFFLUENT MONITORING SYSTEM i-r

a. Noble Gas Activity Monitor - Providing Alarm and Automatic Termination of Release

110 1 g

( Elo X05ih and 5)

2. MAIN CONDENSER OFFGAS TREATMENT SYSTEM EXPLOSIVE GAS MONITORING SYSTEM (for systems designed to withstand the effects of a hydrogen explosion) '

- 111

a. Hydrogen Monitor 1/ train i

, .$ 3. MAIN STACK HONITORING SYSTEM '

110 l T a. NobleGasActivityMonitor(00i8-N&l4&M515) 1

.* 113 .

1

$ b. Iodine Sampler

113 1

c. Particulate Sampler

114 1

d. Effluent System Flow Rate Monitor ~

'* 114 1

e. Sampler Flow Rate Monitor

4. CONDENSER AIR EJECTOR RADI0 ACTIVITY MONITOR (Prior to Input to Holdup System) j "'" '

a. Noble Gas Activity Monitor (.1"'" -

115 l 1

1&ie-K60G)

S. SBGTS MONITORING SYSTEM

1. 110

a. Noble Gas Activity Monitor (9010-505 .a 19 1

' 0010 505 ^ 1 S I eB16-514A) ## 113 1

b. Iodine Sampler ## 113 1

c. Particulate Sampler ## 114 1

d. Effluent System Flow Rate Monitor ## 114 1

e. Sampler Flow Rate Monitor

, CONTAINMENT SYSTEMS SURVEILLANCE REOUIREMENTS

~

4. 6.1. 5_fWhrimary Containment Tendons. The primary containment structural integ-rity Oshai shall be cemonstrated at the end of one, three and five years after the in1Tial stru'ctural integrity test (ISIT) and every five years thereafter in accordance with Table 4.6.1.5-1. The structural integrity shall be demon-strated by:

a. Determining that a representative sample of at least 13 tendons, 8 hori-

ental and 5 vertical, selected in accordance with Table 4.6.1.5-1 have a lift-off force between the maximum and minimum values listed in Table 4.6.1.5-2 at,the first year inspection. For subsequent inspections, for tencons and periodicities per Table 4.6.1.5-1, the maximum first year lif t-of f forces shall be decreased by the amount X1 log t kips for V tendons and Y1 log t kips for hoop tendons and the minimum lift-off forces shall be decreased by the amount X2 log t for V tendons and Y2 log t for hoop tendons where t is the time interval in years from initial tensioning of the tendon to the current testing date and the values X1, X2, Y1 ano Y2 are in accoro-ance with the values listed in Table 4.6.1.5-2 for the surveillance tendon.

This test shall include essentially a complete detensioning of tendons selected in accordance with Table 4.E.1.5-1 in which the tendon is deten-sioned to determine if any wires or strands are broken or damaged. Tencons found acceptatie during this test shall be retensioned to their observec lift off force, 1 3%. During retensioning of these tendons, the change in load and elongation shall be measured simultaneously at a minimum of three, approximately equally spaced, levels of force between the seating force and zero. If elongation corresponding to a specific loao differs

- - by more than 5% from that recorded during installation of tendons, an investigation should be made to ensure that such difference is not related to wire failures or slip of wires in anchorages. If the lift-off force

of any one tendon in the total sample population lies between the predicted lower limit and 90% of the predicted lower limit, two tendons, one on each side of this tendon, shall be checked for their lift-off force. If both these adjacent tendons are found acceptable, the surveil',ance program may proceed consicering the single deficiency as unique and acceptable. The tendon (s) shall be restored to the required level of integrity. More than one tendon above or below the predicted bounds out of the original sample population or the lift-off force of a selected tendon lying below 90% of the prescribed lower limit is evidence of abnormal degradation of the con-tainment structure.

b. Performing tendon detensioning and material tests and inspections of a previously stressed tendon wire or strand from one tendon of each group, hoop and V, and determining that over the entire length of the removed

- wire or strand that:

. 1. The tendon wires or strands are f ree of corrosion, cracks and damage.

2. A minimum tensile strength value of 240 ksi, the guaranteed ultimate strength of the tendon material, for at least three wire or strand samples, one from each end and one at mid-length, cut from each removed wire or strand. Failure of any one of the wire or strand samples to meet the minimum tensile strength test is evidence of abnormal degradation of the primary containment structure.

LA SALLE UNIT 1 3/4 6-9

B, TABLE 3.6.3-1 9 '

y, PRIMARY CONTAINMENT ISOLATION VALVES

?

MAXIMUM ISOLATION TIME h VALVE FUNCTION AND NUMBER VALVE GROUP (8) (Seconds) 3

-i

a. Automatic Isolation Valves -

1. Main Steam isolation Valves 1 5*

1821-F022A, B, C, D 1821-F028A, B, C, D

2. Main Steam Line Drain Valves 1 -

IB21-F016 1821-F019 5 15

< 15 1821-F067A, B, C, D I)

R 3. Reactor Coolant System Sample 523 s

I Line Valves (C) 3 $5 4

1833-F019 IB33-F020 4 Drywell Equipment Drain Valves 2 g20' 1RE024 1RE025 32c 1RE026 520 6 i:5*

1RE029 eiT i

5. Drywell Floor Drain Valves 2 IRF012 1 20 ,

1RF013

6. Reactor Water Cleanup Suction Valves 5 1 30 1G33-F001(d) 1G33-F004

7. RCIC Steam Line Valves 8 IE51-F008I ') < 20 IE51-F063 7 15 IE51-F064 fI) 15 IE51-F076 7 15

( -

(

TABLE 3.6. 3-1 (Continued)

E PRIMARY CONTAINMENT ISOLATION VALVES

,E._ MAXIMUM m ISOLATION TIME VALVE GROUP I *) (Seconds) '

e VALVE FUNCTION AND NUMBER z

Automatic Isolation Valves (Contint.ed) .

Bois 7 NA

14. Tip Guide Tube Valves ( FWe VMve5)

UWs a vu5YE l

IC51-J004

15. Reactor Building Closed Cooling Water 2 -

1 30 .

System Valves 1WR029 '

IWR040 .

~

R*

IWR179 IWR180 T 16. Primary Containment Chilled 1 m 2 l

" Water Inlet Valves < 90 l IVP113 A and 8 ~

< 40 IVP063 A and 8

17. Primary Containment Chilled 2

Water Outlet Valves

_ 40 IVP053 A and 8 _< 90 IVP114 A and B l 18. Recirc. Hydraulic Flow Control Line Valves (8} 2 15 1833-F338 A and B 1833-F339 A and 8 i 1833-F340 A and 8 1833-F341 A and 8 IB33-F342 A and B IB33-F343 A and 8 IB33-F344 A and 8 IB33-F345 A and 8 2 NA

19. Feedwater Testable Check Valves -

1821-F032 A and B 1

__ , , _ . , , _ , _ - _ s,_ . _ _ - _ ,

l .~

TABLE 3.f>.3-1 (Continued) -

5 PRIMARY CONTAINMENT ISOLATION VALVES m

N MAXIMUM E -

ISOLATION TIME VALVE FUNCIION AND NUMBER -

VALVE GROUP (8) (Seconds)

-h Automatic Isolation Valves (Continued)

11. Containment Monitoring Valves 2 15 1CM017A,8 1CM018A,B ICM019A,8 1CM020A,B ICM0218(

1CM022A }

I Y ICH023B(9)

^ ICM024A(U}

ICM025A(h)

ICM026B h)

.[

cn ICM027 1CM028 1CM029 1CM030 ICM031 .

ICM032 1CM033 1CM034

12. Drywell Pneumatic Valves 2 ;

IIN001A and B - < J 6 .3. 0 11N017 7 X 32 IIN074 2 )6 33, 11N075 5 W fl1 f IIN031 55 IIN018 NA

13. RNR Shutdown Cooling Mode Valves 6 IE12-F008 < R 'l O 1E12-F009 5 K 'IC IE12-F023 1 90 IE12-F053 A and B i 29 IE12-F099A(9}( } $ 30

(

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O RAD 10LOGTCAL ENVIRONMENTAL MONITORlNG t 3/4.12.2 LAND USE CENSUS

^

LIMITING CONDITION FOR OPERATION 3.12.2 A land use census 'shall be conducted and shall identify the location of the nearest milk animal and the nearest residence in each of the 16 meteor-clogical sectors within a distance of five miles. (For elevated releases as defined in Regulatory Guide 1.111, Revision 1, July 1977, the land use census shall also identify the locations of_ all milk animals in each of the 16 meteorological sectors within a distance'of three miles.)

APPLICABILITY: At all times.

ACTION:

a. With a land use census identifying a location (s) which yields a calculated dose or dose commitment greater than the values currently being calculated in Specification 4.11.2.3, in lieu of any other report required by Specification 6.6.A. or 6.6.B., prepare and submit to the Commission within 30 days, prusuant to Specifica-

. tion 6.6.C., a Special Report.which identifies the new location (s).

D. With a land use census identifying a location (s) which yields a calculated dose or dose commitment (via the same exposure pathway)

20 percent greater than at a location from which samples are currently beingp bt 5 d in accordance with Specification 3.12.1, in lieu of any other report required by Specification 6.6.A. or 6.6.B., prepare b,cbd.- and submit to the Commission within 30 days, pursuant to Specifica-tion 6.6.C., a Special Report which identifies the new location.

The new location shall be added to the radiological environmental monitoring program within 30 days. The sampling location, excluding the control station location, having the lowest calculated dose or dose commitment (via the same exposure pathway) may be deleted from this monitoring program after (October 31) of the year in which this land use census was conducted.

c. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

SURVEILLANCE REOUIREMINTS-

~

4.12.2 The land use census shalf be conducted at least once per 12 months between the dates of (June 1 and October 1) using that information which will provide the best results, such as by a door-to-door survey, aerial survey, or by consulting local agriculture authorities.

4 LA SALLE - UNIT 1 3/4 12-9

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Figure 3.2.3-1 MNNMUM CRITICAL POWER RATIO (MCPR) VERSUS T AT RATED FLOW

~. . _-. __. 1 . . . ._-_. -. .A_.._.__ _ _ _ _ _ _ . _ _ _ _ _ ...._..._.._1,.. ,

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- IAllLE 3.3.7.11-1 ,

~ '

E RADIDACTIVE GASEOUS EFFLUENT HONITORING INSTRUMENTATION m,

r- HINIHUM CilANNELS . i INSTRUMENT OPERABLE APPLICABILITY ACTION Ei .

g 1. MAIN CONDENSER OFFGAS.lREA1HENT SYSTEM

.q EFFLUENT HONITORING SYSTEM to a. Noble Gas Activity Honitor_ Providing Alarm and Automatic Termination of Release ^

( 2'J 10 "00 L^. r ~! E) 1 110 l s.

I

2. MAIN CONDENSER OFFGAS TREATHENT SYSTEM EXPLOSIVE GAS HONITORING SYSTEM (for systems designed to a

withstand the effects of a hydrogen explosion)

a. Ilydrogen Monitor 1/ train 111 ..

3. HAIN STACK HONITORING SYSTEM l D a. Noble Gas Activity Monitor (GBl8-usia n- 519 1

^~

110 l ta b. lodine Sampler 1 113

113 S"

c. Particulate Sampler . 1

d. Effluent System flow Rate Monitor 1

, 114

e. Sampler Flow Rate Honitor 1 114

4. CONDENSER AIR EJECTOR RA010ACTIV11Y HONITOR (Prior to Input to lloidup System)

a. Noble Gas Activity Honitor (2010 "Gi3 ami g 1 # 115 1

-3&le-M600)

S. SDGfS HONITORING SYSTEM

a. Noble Gas Activity Honitor (DDt'8"S0'rA-&-9 i ## 110 0918-506-A-&4 i 0D111:511412.),

b. Iodine Sampler .1 ## 113

c. Particulate Sampler 1 ## 113

d. Effluent System flow Rate Honitor 1 ## 114

e. Sampler Flot.; Rate Monitor 1 #5 114

t REACTOR COOLANT SYSTEM JET PUMPS .

LIMITING CONDITION FOR OPERATION 3.4.1.2 All jet pumps shall be OPERABLE.

APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2.

ACTION:

With one or more jet pumps inoperable, be'in at least HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

SURVEILLANCE REQUIREMENTS 4.4.1.2/1 Each of the above required jet pumps shall be demonstrated OPERABLE prior to THERMAL POWER exceeding 25% of RATED THERMAL POWER and at least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months by measuring and recording each of the below specified parameters and verifying that no two of the following conditions occur when both recircula-tion loops are operating at the same flow control valve position.

a. The indicated recirculation loop flow differs by more than 10% from the established flow control valve position-loop flow characteristics

, for two recirculation loop operation.

b. The indicated total core flow differs by more than 10% from the established total core flow value derived from either the:

1. Established THERMAL POWER-core flow relationship, or

2. Established core plate differential pressure-core flow relationship for two recirculation loop operation.

c. The indicated diffuser-to-lewer plenum differential pressure of any individual jet pump differs from established two recirculation loop operation patterns by more than 10%.

4.4.1.2.2 During single recirculation loop operation, each of the above required jet pumps shall be demonstrated OPERABLE at least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months by verifying that no two of the following conditions occur:

a. The indicated recirculation loop flow in the operating loop differs by more that 10% from the established single recirculation flow

. control valve position-loop flow characteristics.

b. The indicated total core flow differs by more than 10% from the established total core flow value from single recirculation loop flow , measurements,.

o:$4 cy c

c. The indicated <dif-ference-to-lower plenum differential pressure of any individual jet pump differs from established single recirculation loop by more than 10%.

\

LA SALLE - UNIT 2 3/4 4-3

CONTAINMENT SYSTEMS PRIMARY CONTAINMENT STRUCTURAL INTEGRITY LIMITING CONDITION FOR OPERATION 3.6.1.5 The structural integrity of the primary containment shall be maintained '

at a level consistent with the acceptance criteria in Specification 4.6.1.5.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, and 3.

i ACTION: l

a. With mor'e than one tendon with an observed lift-off force between the predicted lower limit and 90% of the predicted lower limit or with one tendon below 90% of the predicted lower limit, restore the tendon (s) to'the required level of integrity within 15 days and perform an engineering evaluation of the containment and provide a Special Report to the Commission within 30 days in accordance with Specification 6.6C. or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

b. With any other abnormal degradation of the structural integrity at a level below the acceptance criteria of Specification 4.6.1.5, restore the containment vessel to the required level of integrity within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and perform an engineering evaluation of the contain-ment and provide a Special Report to the Commission within 15 days in accordance with Specification 6.6C. or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

SURVEILLANCE REQUIREMENTS 4.6.1.5 Primary Conta96 ment Tendons. The primary containment structural integrity shall snal e demonstrated at the end of 1, 3, and 5 years after the i initial structura integrity test (ISIT) and every 5 years thereafter in accordance with Table 4.6.1.5-1. The structural integrity shall be demon-strated by:

a. Determining that a representative sample of at least 13 tendons, 8 horizontal and 5 vertical, selected in accordance with Table 4.6.1.5-1 have a lift-off force equal to or greater than the minimum values listed in Table 4.6.1.5-2 at the first inspection. For subsequent inspections, for tendons and periodicities per Table 4.6.1.5-1, the minimum lift-off forces shall be decreased by the amount X2 log t/t for V tendons and 4

Y2 log t/t for hoop ten, dons where t is the time i8terval in years from initi81 tensioning of the tendon to the current testing date and t is the time interval in years from initial tensioning of the tendon t8 the first inspection and is equal to 4 years. The values X1, X2, Y1, and.Y2 are-in accordance with the values listed in Table 4.6.1.5-2 for the surveillance tendon. This test shall include essentially a LA SALLE - UNIT 2 3/4 6-8

TABLE 3.6.3-1 g

y PRIMARY CONTAINMENT ISOLATION VALVES P

m- - HAXIMUM ISOLATION TIME VALVE FUNCTION AND NUMBER VALVE GROUP (a) (Seconds)

E m a. Automatic Isolation Valves

1. Main Steam Isolation Valves # 1 5*

2B21-F022A, B, C, D 2821-F028A, B, C, D

2. Main Steam Line Drain Valves, 1 2B21-F016 < 15 2B21-F019 7 15 '

2B21-F067A, B, C, D(b) 23

3. Reactor Coolant System Sample

,m Line Valves (c)# 3 55

) 3 2833-F019

. 2833-F020 5-20' i ,' 4. Drywell Equipment Drain Valves 2 4 2RE024 <i2e 2RE025 s 2o 2RE026 1 a4 .

43' I 2RE029

5. Drywell Floor Drain Valves 2 5 20 2RF012 2RF013

6. Reactor Water Cleanup Suction Valves 5 . 1 30 2G33-F001(d)

! 2G33-F004

7. RCIC Steam Line Valves 8 2E51-F008I *) < 20 2E51-F063 7 15 l

15 2E51-F064(II#

2E51-F076 7 15 2E51-F091 II)# $15 1

TABLE 3.6.3-1 (Continued)

PRIMARY CONTAINMENT ISOLATION VALVES

% MAXIMUM i

{ ISOLATION TIME VALVE FUNCTION AND NUMBER I *)

VALVE GROUP (Seconds)

E Q Automatic Isolation Valves (Continued) , ,

N

11. Containment Monitoring Valves 2 15 2CM017A,B#

2CM018A,0#

2CM019A,B#

2CM020A,B#

2CM021B(h) 2CM022A(h) 2CM025A((h) 2CM026B h)

R 2CM027 2CH028 T 2CM029 E$ 2CM030 2CM031 2CM032 2CM033 ,

2CM034

12. Drywell Pneumatic Valves 2 i 21N001A and B < A0 3o 2IN017 730'21 21N074# 7 30- 2 L 2IN075# 7 30'Z 2 2INO31# 35

13. RHR Shutdown Cooling , Mode Valves 6 2E12-F008 < 41- 'to 2E12-F009 i Al' 'f D i 2E12-F023 7 90 2E12-F053 A and B 529 2E12-F099A and B(9)I ) $ 30 4.;

e

~

TABLE 3.6.3-1 (Continued)

'y PRIMARY CONTAINHENT ISOLATION VALVES MAXIMUM

m. .

ISOLATION TIME VALVE FUNCTION AND NUMBER VALVE GROUP I8) (Seconds)

i

m Automatic Isolation Valves (Continued)

Tau

14. Tip Guide Tube Valves (Rvt VAIVed 7 N.A.

' ^

-Ball-Valve-2C51-J004

15. Reactor Building Closed Cooling Water System Valves 2 5 30 2WR029 2WR040 2WR179 1 y 2WR180

.** 16. Primary Containment Chilled

! i Water Inlet Valves # 2 E$ 2VP113 A and B '< 90 2VP063 A and B 5 40

17. Primary Containment Chilled Water Outlet Valves # 2 2VP053 A and B < 40 2VP114 A and B 390

18. Recirc. liydraulic Flow Control

, Line Valves IU) 2 , 55 2B33-F338.A and B 2833-F339 A and B 2833-F340 A and B i 2B33-F341 A and B

- 2B33-F342 A and B 2833-F343'A and B 2B33-I144 A and B i 2B33-F345 A and B

19. Feedwater Testable Check Valves 2 N.A.

2B21-F032 A and B

TABLE 3.7.5.4-1 (Continued)

FIRE HOSE STATIONS -

LOCATION PROTECTED AREA ELEVATION IDENTIFICATION HOSE RACK Unit 2 Fire Hose Stations (Continued)

22. Zone 8A1 Zone 8A1 736'6" F 362

23. Zone 8A2 Zone 8A2 736'6" F 363

24. Zone 8C3 Zone 8C3 673'0" FB 365 Zone 8C1 8CS

25. Zone 8C4 Zone 8C4 673'0" F 366 Zone 8C2

26. Zone 6E Zone GE 663'0" E 359 F 360 F 399 F 403 F 404 B ., Unit 1 Fire Hobb Stations Required For Unit 2

1. Area 1 Area 1 843'6" F 101 FB 102

.F 103

" F 104 F 105

2. Zone 2B1 Zone 281 820'6" FB 108 F 109 F 111

3. Zone 4A- Zone 4A 815'0" F 150 FB 149

4. ~ Zone 4B Zone 4B 786'6" F 151 FB 152 F 153

5. Zone 4C2 Zone 4C1 768'0" F 154 and SA3 Zone 4C2 FB 175 Zone 4C3 FB 176 Zone 4C4 Zone 4C5

- 6. Zone SA4 Zone SA4 ,

749'0" FB 248 Zone 4D1 FB 253 Zone 402 Zone 403

7. Zone 5B13 Zone SB13 -731'0" FB 250 Zone 5B3 FB 155 Zone 4E3 FB 185 Zone 4E2 Zone 4E1 LA SALLE - UNIT 2 3/4 7-21

l l

PLANT SYSTEMS 3/4.7.9 SNUBBERS .

LIMITING CONDITION FOR OPERATION 3.7.9 All hydraulic and mechanical snubbers shall be OPERABLE.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, and 3.- OPERATIONAL CONDITIONS 4 and 5 for snubbers located on systems required OPERABLE in those OPERATIONAL CONDITIONS.

ACTION:

With one or more snubbers inoperable on any system, within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months replace or restore the inoperable snubber (s) to OPERABLE status and perform an engineering evaluation per Specification 4.7.9g. on the attached component or declare the attached system inoperable and follow the appropriate ACTION statement for that system.

SURVEILLANCE REQUIREMENTS 4.7.9 Each snubber shall be demonstrated OPERABLE by performance of the following augmented inservice inspection program and the requirements of S~pecification 4.0.5.

a. Inspection Types As used in this specification, type of snubber shall mean snubbers of the same design and manufacturer, irrespective of capacity,

b. Viscal Inspections Snubbers are categorized as inaccessible or accessible during reactor operation. Each of these groups (inaccessible and accessible) may be inspected independently according to the schedule below. The first inservice visual inspection of ea:h type of snubber shall be performed after 4 months but within 10 montns of commencing POWER OPERATION and shall include all hydraulic and mechanical snubbers. If all snubbers of each type on any system are found OPERABLE during the fxist,inser- _.g;c3t vice visual inspection, the second inservice visual inspection ~of that system shall be performed at the first refueling outage. Otherwise, subsequent visual inspections of a given system shall be performed in accordance with the following schedule:

No. Inoperable Snubbers of Each Type Subsequent Visual On Any System per Inspection Period Inspection Period * #

. 0 18 months ! 25% ,

e -

1 12 months 25%

2 6 months 25%

3,4 124 days 25%

5,6,7 62 days 25%

8 or more 31 days 25%

"The inspection interval for each type of snubber on a given system shall not be lengthened more than one step at a time unless a generic problem has been identified and corrected; in that event the inspection interval may be lengthened one step the.first time and two steps thereafter if no inoperable snubbers of that' type are found on that system.

The provisions of Specification 4.0.2 are not applicable.

LA SALLE - UNIT 2 3/4 7-28

RADIOLOGICAL ENVIRONMENTAL MONITORINC -

3/4.12.2 LAND USE CENSUS LIMITING CONDITION FOR OPERATION

3.12.2 A land use census shall be conducted and shall identify the location of the nearest milk animal and the nearest residence in each of the 16 meteor-ological sectors within a distance of five miles. (For elevated releases as defined in Regulatory Guide 1.111, Revision 1, July 1977, the land use census shall also identify the locations of all milk Enimals in each of the 16 meteorological sectors within a distance of three miles.)

APPLICABILITY: At all times. -

ACTION:

a. With a land use census identifying a location (s) whicn yields a calculated dose or dose commitment greater than the values currently being calculated in Specification 4.11.2.3, in lieu of any other report required by Specification 6.6.A. or 6.6.B., prepare and submit to the Commission within 30 days, prusuant to Specifica-tion 6.6.C., a Special Report which identifies the new location (s).

b. With a land use census identifying a location (s) which yields a calculated dose or dose commitment (via the same exposure pathway) 20 percent greater than at a location from which samples are currently being,0bt4ened-in accordance with Specification 3.12.1, in lieu of 09 . *f " r any and other submitreport to required by Specification the Commission 6.6. A.

within 30 days, pursuant or 6.6.B. , prepare to Specifica- -

tion 6.6.C. , a Special Report which identifies the new location.

. The new location shall be added to the radiological environmental monitoring program within 30 days. The sampling location, excluding the control station location, having the lowest calculated dose or dose commitment (via the same exposure pathway) may be deleted from this monitoring program after (October 31) of the year in which this land use census was conducted.

c. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS

- 4.12.2 The land use census shall be conducted at least once per 12 months between the dates of (June 1 and October 1) using that information which will provide the best results, such as by a door-to-door survey, aerial survey, or by consulting local agriculture authorities.

LA SALLE - UNIT 2 3/4 12-9

- - . + , , - , . , . , , , - - - - , . . _ - - - - - , . , , ,,- .,, , , , , , . - - - -

- - - , , - ~ - - - , , . ,

t l

ATTACHMENT B SIGNIFICANT HAZARDS CONSIDERATION Correction of Typographical and Administrative Errors Commonwealth Edison has evaluated the proposed Technical Specification Amendment and determined that it does not represent a significant hazards consideration. Based on the criteria 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:

1) Involve a significant increase in the probability or consequences of an accident previously evaluated or create the possibility of a new or different kind of accident from any accidents previously evaluated because these changes are administrative only and do not effect the safety analyses previously performed. The MCPR curve was previously submitted and was inadvertently omitted from the issued Technical Specifications.

2) Involve a significant reduction is the margin of safety because these changes are consistent with previous analyses and do not effect the margin of safety.

Based on the preceding discussion, it is concluded that the proposed changes clearly fall within all acceptable criteria with respect to the system or component, the consequences of previously evaluated accidents will not be increased and the margin of safety will not be decreased. Therefore, based on the guidance provided in the Federal Register and the criteria established in 10 CFR 50.92(e), the proposed changes do not constitute a significant hazards consideration.

9988N

COMMONWEALTH EDISON CO WANY LASALLE COUNTY STATION UNITS 1 and 2 TECHNICAL SPECIFICATION CHANGE REQUEST APPENDIX 2

Subject:

~ Specification 3.0.4 does not apply addition...

Revised Pages:

Unit 1 Unit 2 3/4 6-22 3/4 6-25 6-24 6-27 6-25 6-28 6-26 6-29 6-27 6-30 6-28 6-31 6-32 6-35 6-34 6-37 9988N

['

l LASALLE COUNTY STATION UNITS 1 AND 2 TECHNICAL SPECIFICATION CHANGE REQUEST

SUBJECT:

Specification 3.0.4 does nat apply addition to Tech Spec 3.

6.3 REFERENCES

1. Technical Specification 3.6.3

2. Basis Page B 3/4 0-1.

3. 3.6.3 Basis Page 9 3/4 6-4.

BACKGROUND:

Specification 3.0.4 is provided to " ensure that unit operation is not initiated with either required equipment or systems inoperable or other limits being exceeded." However exceptions are provided "when startup with inoperable equipment would not affect plant safety." (Reference

7) This request is based upon Commonwealth Edison's conclusion that t:artup with the specified component inoperable but with the associated system (primary containment), operable, does not affect plant safety.

The Technical Specification basis for 3.6.3 (Reference 3) states" the operability of the primary containment isolation valves ensures that the containment atmosphere will be isolated from the outside environment in

- the event of a release of radioactive material to the containment atmosphere or pressurization of the containaent."

DISCUSSION:

In order to ensure that the primary containment meets its design function,~ isolation valves are provided. The intent of this specification is to ensure that all lines with isolation valves will be isolated if conditions exist which require the primary containment to perform this design function. This intent may be met by either an automatic isolation valve or a closed valve (or otherwise isolated

.line). Since plant safety is not degraded when an automatic isolation valve is inoperable, but secured in its isolated position per this specification, the question of continued operation should only become one of other requirements and not be based on prinary containment integrity. Since plant safety is not degraded by operation with an isolated primary containment isolation valve, it is reasonable to allow mode changes in this condition.

In addition this specification should be no more restrictive than similar specifications concerning the primary containment such as 3.4.7 Main Steam Isolation valves or 3.6.3 concerning excess flow check valves.

Of course if the isolation of the primary containment boundary per 3.6.3 causes another Technical Specification System to become inoperable and the exemption from Specification 3.0.4 is not allowed for that system, then the plant is restrained from startup by that specification. In all cases the effect upon other systems must be considered and applicable

- other Technical Specifications followed.

Since the # footnote for Technical Specification Table 3.6.3-1 already allows exception to the provisions of 3.0.4 for specific valves this

. charge merely clarifies which action is required to allow the provisions of 3.0.4 to be waved.

I 9988N Y

. ~,~- ...i~; _ .

. u =,.:n. i e r-

$ C. n M W ~i b CONTAINMENT SYSTEMS -

3/4.6.3 PRIMARY CONTAINMENT ISOLATION VALVES LIMITING CONDITION FOR OPERATION 3.6.3 The primary containment isolation, valves and the reactor instrumentation line excess flow check valves shcwn in Table 3.6.3-1 shall be OPERABLE with

? isolation times less than or equal to those shown in Table 3.6.3-1.

.; APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, and 3.

ACTION:

a. With one or more of the primary containment isolation valves shown in Table 3.6.3-1 inoperable:

1. Maintain at least one isolation valve OPERABLE in each affected penetration that is open and within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months either; a) Restore the inoperable valve (s) to OPERABLE status, or

b) Isolate each affected penetration by use of at least one deactivated automatic valve secured in the isolated j position,* or c) Isolate each affected penetration by use of at least one -

.., g _

closed manual valve or blind flange.*

2. Otherwise, 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 f<k J and in COLD SHUTOOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

b. With one or more of the reactor instrumentation line excess flow check valves shown in Table 3.6.3-1 inoperable:

1. Operation may continue and the provisions of Specifications 3.0.3 i and 3.0.4 are not applicable provided that within.4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months

either

,j a) The inoperable valve is returned to OPERABLE status, or j b) The instrument line is isolated and the associated instrument is declared inoperable.

's

2. Otherwise, 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 I and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

" Isolation valves closed to satify these requirements may be reopened on an intermittent basis u.ider administrative control.

1 i.

.j

\ ,

) -

~

4 1

I LA SALLE - UNIT 1 3/4 6-22 1

INSERT FOR PAGE 3/4 6-22 (d) The provisions of Specification 3.0.4 are not applicable provided that within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months the affected penetration is isolated in accordance with Action a.l.b) or a.l.c) above, and provided that the associated syste g it_appilcaoleg is declared inoperabl and the appropriate action statements for that system are per rmed.

DOUCUMENT 0750r

. . . . . , e _v ... . _ . . . . . . . ..:. .n , . _

y~o Q. (2QWD2Cc' ONLY

\ CONTAINMENT SYSTEMS Q)

} .

j SURVEILLANCE REQUIREMENTS j _

i' 4.6.3.1 Each primary containment isolation valve shown in Table 3.6.3-1 shall be demonstrated OPERABLE prior to returr41ng the valve to service after mainte-

nance, repair or replacement work is perforined on the valve or its associated l actuator, control or power circuit 5y cycling the valve through at least one j complete cycle of. full travel and verifing the specified isolation time.

4.6.3.2 Each primary containment automatic isolation valve shown in

.l Table 3.6.3-1 shall be demonstrated CPERABLE during COLD SHUTDOWN or REFUELING

- at least once per 18 months by verifying that on a containment isolation test

signal each automatic isolation valve actuates to its isolation position.

4.6.3.3 The isolation time of each primary containment power operated or automatic valve shown in Table 3.6.3-1 shall be determined to be within its limit when tested pursuant to Specification 4.0.5.

i 4.6.3.4 Each reactor instrumentation line excess flow che k valve shown in Table 3.6.3-1 shall be demonstrated OPERABLE at least once per 18 months by verifying that the valve checks flow. .

t

} } 4.6.3.5 Each traversing in-core probe system explosive isolation valve shall v be der.onstrated OPERA 8LE:

1 i j a. At least once per 31 days by verifying the continuity of the 1 : ,

explosive charge.

l b. At least once per 18 months by removing the explosive squib from at least one explosive valve such that the explosive squib in each l explosive valve will be tested at least once per 90 months, and 1 initiating the explosive squib. The replacement charge for.the j exploded squib shall be from the same manufactured batch as the one fired or from another batch which has been certified by having at least one of that batch successfully fired. No explosive squib shall remain in use beyond the expiration of its shelf-life and operating-life.

~

?

l

]. .

Y LA SALLE - UNIT 1 3/4 6-23 6 .

e

-- -- ~a- ,-,--,,>,,w--- -

, - , - , . - - _ + - - , - - - - - - . - - . - - - _ - . - - - . - , - , - . , . , . , , ,,-,,,__,_n, -n.,. ,, - - - , - - , . -

TABLE 3.6.3-1 9

u, , PRIMARY CONTAINMENT ISOLATION VALVES

?

E MAXIMUM ISOLATION TIME VALVE FUNCTION AND NUMBER VALVE GROUP ("} (Secads) 5

a. Automatic Isolation Valves

1. Main Steam Isolation Valve 1 5* l -

! 1821-F022A, B, C, D(b) i 1821-F028A, B, C, D I)

2. Main Steam Line Drain Valve df p 1 I l

1821-F016 < 15 1821-F019 7 15 l 1821-F067A, B, C, O(b) -

2 23 i 3. Reactor Coolant S stem Sample

$ Line ValvesI ' 3 -<5 l

. IB33-F019 4

IB33-F020

4. Drywell Equipment Drain Valves 2 g G' l

1RE024 Spo

. 1RE025 4 go l 1RE026 2 p~ -

1RE029 ~6 I 6'

5. Drywell Floor Drain Valves . 2 -< 20 1RF012 IRF013

6. . Reactor Water Cleanup Suction Valves 5 -

< 30 1G33-F001(d)

IG33-F004 k 7. RCIC Steam Line Valves 8 h IE51-F008I *) < 20

IE51-F063 7 15

[ IE51-F064 I < 15 l l P 1E51-F076 7

_ 15

.H

4 _

TA8LE 3.6.3-1 (Continued) 5 PRIMARY CONTAINMENT ISOLATION VALVES j ,

2 E MAXIMUM

ISOLATION TIME i VALVE FUNCTION AND NUMBER VALVE GROUP (*) (Seconds)

, [

z U Automatic Isolation Valves (Continued)

8. Containment Vent. and Purge Valve 4 I

< 10**

IVQO26 IVQO27 310**

' < 10**

IVQO29 IVQO30 7 10**

! IVQO31 510**

IVQO32

- <5

IVQO34 510**

IVQO35

<5 w IVQO36 7 10**

E IVQ040 7 10**

m IVQ042 . 5 10 "

u < 10d IVQ043 IVQ047 55 L IVQ048 55

<5 IVQ050 1 IVQ051 15

<5 ,

IVQ068

9. RCIC Turbine Exhaust Vacuum Breaker 9 H.A. l p

o Line Valves 1E51-F080

IE51-F086

.10. LPCS, HPCS, RCIC, RHR Injection Testable Check Bypass Valves I9) 2 N.A. g y 1E21-F333 -

i

= 1E22-F354 5 1E12-F327A, B, C I z 1E51-F354 i - 1E51-F355 M

TABLE 3.6.3-1 (Continued) ~

i 4

9 PRIMARY CONTAINMENT ISOLATION VALVES un MAXIMUM E

E ISOLATION TIME s VALVE FUNCTION AND NUMBER VALVE GROUP (a) (Seconds)

Automatic Isolation Valves (Continued) l

11. Contal Monitoring Valves 2 15 ,

ICM017A, i ICM018A, l ICM019A, ICH020A, j

I ICM0210((h)

ICM022A(h)

ICM025A(h)

ICM026B h) w ICM027 1 1CM028 m ICM029 i' E ICM030 ICM031 1CM032

, ICM033 ji ICM034

12. Drywell Pneumatic Valves 2 11N001A and B < .A& 30 IIN017 7.30 22- ,

IIN07 7.3021 i .

. IIN07 , 'l.3&21 IIN03 -<5 E '13. RHR Shutdown Cooling Mode Valves 6

$ IE12-F008 < Ar40 IE12-F009 5SP40 *

[

a 1E12-F023

< 90

" 1E12-F053 A and B 329 IE12-F099A and B IU)II) $ 30 l 5 .

t i 1ABLE 3.6.3-1 (Continued) 9 PRIMARY CONTAINMENT ISOLATION VALVES j ,

a >

l i

{ I *-)

MAXIMUM ISOLATION TIME VALVE FUNCTION AND NUMBER VALVE GROUP (Seconds)

! [

x U Automatic Isolation Valves (Continued) l H eall .

14. Tip Guide Tube, Valve (, Fire VWfo) 7 N.A. l

}

-Beti Valve i 1C51-J004 l 15. Reactor Building Closed Cooling Water System Valves 2 1 30 1WR029 IWR040 IWR179

! IWR180 N

16. Primary Containment Chilled m Water Inlet' Valve 2 l y ,

IVP113 A and B $ 90 1VP063 A and B $ 40

17. Primary Containment Chilled Water Outlet Valves 2 l

< 40 l IVPC53 A and B

IVP114 A and B 7 90

~

! 18. Recirc. Hydraulic Flow Control f . Line Valves (U) 2 15 1B33-F338 A and B

' 1B33-F339 A and B

' Y 1833-F340 A and B V I

S IB33-F341 A and B -

E IB33-F342 A and B

$ IB33-F343 A and B -

IB33-F344 A and B f 1833-F345 A and B .

19. Feedwater Testable Check Valves 2 N.A. l

$ 1821-F032 A and B t

i

. ?

TABLE 3.6.3-1 (Continued)

5 g PRIMARY CONTAINMENT ISOLATION VALVES MAXIMUM E . ISOLATION TIME e

VALVE GROUP (a) (Seconds) g VALVE FUNCTION AND NUMBER

b. Manual Isolation Valves N.A. .

. 1. 1FC086 N.A.

2. IFC113 N.A.

3. 1FC114 N.A.

! 4. 1FC115 5.

I N.A.

j i 6.

IMC027(I)

IMC033

1) N.A.

II) N.A.

I 7. ISA042 N.A.

III l 8. ISA046 I R.

M i

a E.

\

I TABLE 3.6.3-1 (Continued)

G PRIMARY CONTAINMENT ISOLATION VALVES 2

VALVE FUNCTION AND NUMBER h

[ d. Other Isolation Valves z

O 1. MSIV Leakage control System i e* .

1E32-F001A, E, J, N(b)

I i 2. Reactor Feedwater and RWCU System Return

! 1B21-F010A, B .

i 1821-F065A, B

! IG33-F040

3. Residual Heat Removal / Low Pressure Coolant Injection System w IE12-F042A, B, C

! D 1E12-F016A, B

! m 1E12-F017A, B III

' $. 1E12-F004A,By IE12-F027A, B Id) 1E12-F024py)B 1E12-F021 IE12-F302 I3) i 1E12-F064A,Bfh g l 1E12-F011A, B IE12-F088A, B, C II)

II) 1E12-F025py)B,C 1E12-F030 1E12-F005 II) g -

g

{

n 1E12-F073A, B IE12-F074A, B g E 1E12-F055A, B II) C

$ 1E12-F036A, B II) 1E12-F311A, B II)

,E 1E12-F041A,Bg(k) g IE12-F050A, B on e

J _ . . _ .. ..

TABLE 3.6.3-1 (Continued)

' PRIMARY CONTAINMENT ISOLATION VALVES W

r-VALVE FUNCTION AND NUMBER l Other Isolation Valves (Continued) e 4. Low Pressure Core Spray System .

IE21-F005 l 1E21-F001 Il) 1E21-F012 II) l I i

1E21-F011(S) 1E21-F018 3) .

l I

1E21-F031(II 1E21-F006 k)

5. High Pressure Core Spray System

) 1E22-F004 m IE22-F015 ISI O 1E22-F023 I3) 1E22-F012 IS) i 1E22-F014 h

{ IE22-F005

6. Reactor Core Isolation Cooling System 1E51-F013 Gt 1E51-F069 23 1E51-F028 d Q>

i IE51-F068 g

1E51-F040 3 e 1E51-F031 Il) Qi 1E51-F019 II)

I .

O

~

5 1E51-F065(O 1E51-F066 k) . g e

g

~

TABLE 3.6.3-1 (Continued)

PRIMARY CONTAINMENT ISOLATION VALVES

{

e VALVE FUNCTION AND NUMBER Other Isolation Valves (Continued)

E 7. Post LOCA Hydrogen Control 1HG001A, B

" 1HG002A, B ,

1HG005A, B .

1HG006A, B

8. Standby Liquid Control System i IC41-F004A, B IC41-F007

9. Reactor Recirculation Seal Injection IB33-F013A, B Id) 1833-F017A, B III

{

m 10. Drywell Pneumatic System IIN018 O.

But > 3 seconds.

d' The ir=hi:= cf 4 :ificet'r,r. 3.0.4 ese i, t opplicobi=.

i (a) See Specification 3.3.2, Table 3.3.2-1, for isolation signal (s) that operates each valve group.

(b) Not included in total sum of Type B and C tests.

- (c) May be opened on an intermittent basis under administrative control.

. (d) Not closed by SLCS actuation.

(e) Not closed by Trip Functions Sa, b or c, Specification 3.3.2 Table 3.3.2-1.

h (f) Not closed by Trip Functions 4a, c, d, e or f of Specification 3.3.2,. Table 3.3.2-1.

[ .(g) Not subject to Type C leakage test.

y h

{

s (h) Opens on an isolation signal. Valves will be open during Type A test. No Type C test required.

(1) Also closed by drywell pressure-high signal.

i (

m (j) Hydraulic leak test at 43.6 psig.

(k) Not subject to Type C leakage test - leakage rate tested per Specification 4.4.3.2.2. -

i.

(1) These penetrations are provided with removable spools outboard of the outboard isolation I~ E valve. During operation, these lines will be blind, flanged using a double 0-ring and a

)

type B leak test. In addition, the packing of these isolation valves will be soap-bubble

tested to ensure insignificant or no leakage at the containment test pressure each refuel-l m ing outage.

)

L ** These valves shall have a maximum isolation time of 40 seconds until STARTUP following the i

i first refueling outage.

9 CONTAINMENT SYSTEMS 3/4.6.3 PRIMARY CONTAINMENT ISOLATION VALVES -

LIMITING CONDITION FOR OPERATION 3.6.3 The primary containment isolation valves and the reactor instrumentation line excess flow check valves shown in Table 3.6.3-1 shall be OPERABLE with isolation times less than or equal to those shown in Table 3.6.3-1.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, and 3.

ACTION:

a. With one or more of the primary containment isolation valves shown in Table 3.6.3-1 inoperable:

1. Maintain at least one isolation valve OPERABLE in each affected penetration that is open and within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months either; a) Restore the inoperable valve (s) to OPERABLE status, or b) Isolate each affected penetratfor $y use of at least one

! deactivated automatic valve secured in the isolated position,* or c) Isolate each affected penetration by use of at least one closed manual valve or blind flange."

/NSb 7 Af/M e,

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

b. With one or more of the reactor instrumentation line excess flow '

I check valves shown in Table 3.6.3-1 inoperable:

1. Operation may continue and the provisions of Specifications 3.0.3 l and 3.0.4 are not applicable provided that within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months either:

[

l a) The inoperable valve is returned to OPERA 8LE status, or b) The instrument line is isolated and the associated instrument is declared inoperable.

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

" Isolation valves closed to satify these requirements may be reopened on an ~

intamittent basis under administrative control.

LA SALLE - UNIT 2 3/4 6-25

-- - . - , _ . :. ::.:2 := - - - - . - - - - - _ _ ~

)

l INSERT FOR PAGE 3/4 6-21 l

1d) The provisions of Specification 3.0.4 are not applicable provided that within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months the affected penetration is isolated in accordance with Action a.l.b) or a.1.c) above, and provided that the associated system, if applicable, is declared inoperable and the appropriate action statements for that system are performed.

J i

i l

l l

i i

l

DOUCUMIDfT 0750r

i i .

g ggi: sestJC6 C"'

CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS

. _ _ _ 4.6.3.1. Each primary containment isolation valve shown in Table 3.6.3-1 shall be demonstrated OPERA 8LE prior to returning the valve to service after mainte-nance, repair or replacement work is performed on the valve or its associated actuator, control or power circuit by cycling the valve through at least one complete cycle of full' travel and verifing the specified isolation time.

4.6.3.2 Each primary containment automatic isolation valve shown in Table 3.6.3-1 shall be demonstrated OPERABLE during COLD SHUTDOWN or REFUELING at least once per 18 months by verifying that on a containment isolation test signal each automatic isolation valve actuates to its isolation position.

4.6.3.3 The isolation time of each primary containment power operated or automatic valve shown in Table 3.6.3-1 shall be determined to be within its limit when tested pursuant to Specification 4.0.5.

4.6.3.4 Each reactor instrumentation line excess flow check valve shown in Table 3.6.3-1 shall be demonstrated OPERABLE at least once per 18 months by verifying that the valve checks flow.

4. 6. 3' 5 Each traversing in-core probe system explosive isolation valve shall be demonstrated OPERABLE:

a. At least once per 31 days by verifying the continuity of the .

explosive charge.

b. At least once per 18 months by removing the explosive squib from ~

l at least one explosive valve such that the explosive squib in each explosive valve will be tested at least once per 90 months, and initiating the explosive squib. The replacement charge for the exploded squib shall be from the same manufactured batch as the one fired or from another batch which has been certified by having at least one of,that batch successfully fired. No explosive squib shall remain in use oeyond the expiration of its shelf-life and

- operating-life. -

0

=V e

LA SALLE - UNIT 2 3/4 6-26

b .

TABLE 3.6.3-1

>G y PRIMARY CONTAINMENT ISOLATION VALVES E

m MAXIMUM ISOLATION TIME

' VALVE GROUP I8) (Seconds)

VALVE FUNCTION AND NUNBER y a. Automatic Isolation Valves 1 5* l

1. Main Steam Isolation Valve 2B21-F022A, B, C, D 2821-F028A, B, C, D r,U

2. Main Steam Line Drain Valve W 1 5 15 l 1 2821-F016

< 15

2821-F019 2B21-F067A, 8, C, D(b) 23

3. Reactor Coola tem Sample g m Line Valves 3 55

} 2B33-F019

! 2833-F020 4 4. Drywell Equipment Drain Valves 2 A (;zo N 2RE024 l

2RE025

=a i

2RE026 6 If" l 2RE029 645' j 5. Drywell Floor Drain Valves 2 5 20 l

2RF012 1 2RF013 i 6. Reactor Water Cleanup Suction Valves 5 5 30 l 2G33-F001(d) i 2G33-F004

7. RCIC Steam Line Valves 8 2E51-F008I *)

< 20 7 15 2E51-F063 2E51-F064(I i 15 l l'

5 15 2E51-F076gg g 1 15 { ,

2E51-F091 i 1

k TABLE 3.6.3-1 (Co'ntinued)

's :

'g _

m PRIMARY CONTAINMENT ISOLATION VALVES

? '

MAXIMJM E ISOLATION TIME

' g VALVE r.20_UP ,) (Seconds)

E VALVE FUNCTION AND NUMBER

~~

! H6 . '.

i Automatic Isolation Valves (Continued) . ,

~

8. Containment Vent and Purge Valve # 4 l

4 2VQO26

< 10**

2VQO27 310**

2VQO29 5 10**

l 2VQ030 1 10**

2VQO31 5 10**

< 5 2VQ032 2VQO34 310**

2VQO35 55 R 2VQ036 5 10**

!?VQ040

< 10**

T 4'Q042 310**

y M 043 5 10**

aW47 55 2VQo48 55 j 2vQ050 55 j 2VQ051 55 1 2VQ068 55

9. RCIC Turbine Exhaust Vacuum Breaker 9 N.A.

Line Valves 2E51-F080 2E51-F086

10. LPCS, HPCS, RCIC, RHR Injection Testable Check Bypass Valves I8) N.A. N.A.

]

1 i a

TABLE 3.6.3-1 (Continued) 5 PRIMARY CONTAINMENT ISOLATION VALVES 2

MAXIMUM

{ ISOLATION TIME VALVE FUNCTION AND NUMBER

VALVE GROUP (8) (Seconds)

Q Automatic Isolation Valves (Continued) .

m Containment Monitoring Valves 2 < 5 11.

2CM017A,B 6 2CM018A,87 2CH019A,BitV 2CM020A,B V 2CM021B((h) 2CM022A(h) 2CM025A(h) 2CH026B h)

R*

2CM027 2CM028 i 2CM029 0 2CMn30 2CM031 2CH032 2CM033 2CH034

12. Drywell Pneumatic Valves 2 21N001A and 8 < AO 30 21N017 7 30-22.

7.30-7 2-21N074@ 7 .30-2 7-21N075F 21N031F 55

13. RilR Shutdown Cooling. Mode Valves 6 2E12-F008 < Al' 40 2E12-F009 I .41'W L 2E12-F023 I 90 2E12-F053 A and B j 29 2E12-F099A and B(U}(') < 30 t

i

TA8LE 3.6.3-1 (Continued) 5 PRIMARY CONTAINMENT ISOLATION VALVES br-E MAXIMUM ISOLATION TIME j VALVE FUNCTION AND NUMBER VALVE GROUP (a) (Seconds)

"4 m Automatic Isolation Valves (Continued)

14. 7 N.A.

Tip Ball Guide TubeVoLJso Valva (F'ist W lve- )

2C51-J004

15. Reactor Building Closed Cooling Water System Valves 2 < 30 2WR029 2WR040 l .

2WR179 2WR180 R* Primary Containment Chilled 16.

[ Water Inlet Valves 7 2

< 90 l o 2VP113 A and B 2VP063 A and B 5 40

17. Primary Containment Chilled WaterOutletValves[ 2

< 40 g

, 2VP053 A and B 2VP114 A and B 390 1 18. Recirc. Hydraulic Flow Control Line Valves I9) 2 < 5 2833-F338 A and 8

, 2833-F339 A and B

- 2833-F340 A and B 2833-F341 A and 8 l! 2833-F342 A and 8 j

2833-F343 A and B 2833-F344 A and B i

2833-F345 A and B l 2 N.A.

19. Feedwater Testable Check Valves 2B21-F032 A and 8 i

TABLE 3.6.3-1 (Continued)

PRIMARY CONTAINMENT ISOLATION VALVES g

b MAXIMUM ISOLATION TIME VALVE GROUP I ") (Seconds)

VALVE FUNCTION AND NUMBER

b. Manual Isolation Valve [

N.A.

1. 2FC086 N.A.

2. 2FC113 M.A.

3. 2FC114 N.A.

4. 2FC115

5. 2MC027 I1) N. A. '

III N.A.

6. 2MC033 N.A.

III

7. 2SA042 N.A.

II}

8. 2SA046

+ s 4

1 i

4

l 1

' e

'l

i I

TABLE 3.6.3-1 (Continued) 5 PRIMARY CONTAINMENT ISOLATION VALVES y y

VALVE FUNCTION AND NUMBER h d. Other Isolation Valves

1. MSIV Leakage Control System 2E32-F001A, E J N(b)

I 2. Reactor Feedwater and RWCU System Return 2B21-F010A, B i

2B21-F065A, B j 2G33-F040

3. Residual Heat Removal / Low Pressure Coolant Injection System j 2E12-F042A, B, C R

2E12-F016A, B

2E12-F017A, B T 2E12-F004A, B U gg )

{ $ 2E12-F027A, B 2E12-F024py)Bg) 2E12-F021 2E12-F302 U) i j 2E12-F064A, B 2E12-F011A,Bg l 2E12-F088A, B, C U)

UI

2E12-F025py)B,C 2E12-F030 2E12-F005 U) i 2E12-F073A, B gy -

4 2E12-F074A, Bg g' 2E12-F055A, B 2E12-F036A, B i

2E12-F311A,Bg) t

! 2E12-F041A,B(kh(k) 2E12-F050A, B ,

i 1

9 TABLE 3.6.3-1 (Continued) 9 PRIMARY CONTAINMENT' ISOLATION VALVES p

F I VALVE FUNCTION ANO NUMBER Other Isolation Valves (Continued)

" 4. Low Pressure Core Spray System 2E21-F005 -

2E21-F001 III 2E21-F012 II) 2E21-F011 III 2E21-F018 II)

I 2E21-F031(II 2E21-F006 k)

S. High Pressure Core Spray System g

2E22-F004 T 2E22-F015 Ili M 2E22-F023 III 2E22-F012 III II 2E22-F014 2E22-F00S l)

"I h

'N

6. Reactor Core Isolation Cooling System 2ESI-F013 2ESI-F069 g 2ES1-F028 .

q, 2ESI-F068 m 41 2ESI-F040 D 2ESI-F031 III 01 2ESI-F019 II) 2ESI-F065 h 0:

2ESI-F066 O

c r

~(

i TABLE 3.6.3-1 (Continued) ,

PRIMARY CONTAINMENT ISOLATION VALVES VALVE FUNCTION AND NUMBER Other Isolation Valves (Continued) c 7. Post LOCA Hydrogen Control z

Q 2HG001A, B n 2HG002A, B 2HG005A, B 2HG006A, B

8. Standby Liquid Control System 2C41-F004A, B i

2C41-F007

9. Reactor Recirculation Seal Injectio' n

)

2833-F013A, B II)

! 1:' 2B33-F017A, B II)

< +

m .10. Drywell Pneumatic Valves l !d 2IN018 TABLE NOTATIONS

! *But > 3 seconds.

^^These valves sha11 have a maximum isolation time of 40 seconds until STARTUP following the first refueling outage.

l #The prev!M::: ef Spe !ffeat4er 3.0.4 ere set applicabler r (a) See Specification 3.1.2, Table 3.3.2-1, for isolation signal (s) that operates each valve group.

(b) Not included in total sum of Type B and C tests.

(c) May be opened on an intermittent basis under administrative control.

(d) Not closed by SLCS actuation.

(e) Not closed by Trip functions Sa, b, or c, Specification 3.3.2, Table 3.3.2-1.

(f) Not closed by Trip Functions 4a, c, d, e, or f of Specification 3.3.2, Table 3.3.2-1.

j' (g) Not subject to Type C leakage test.

(h) Opens on an isolation signal. Valves will be open during Type A test. No Type C test required.

(i) Also closed by drywell pressure-high signal.

(j) Hydraulic leak test at 43.G psig.

l (k) Not subject to Type C leakage test - leakage rate tested per Specification 4.4.3.2.2.

l .

(1) These penetrations are provided with removable spools outboard of the outboard 1salation valve. .

During operation, these lines will be blind flanged using a double 0-ring and a type B leak test. In addition, the packing of these isolation valves will be soap-bubble tested to ensure !

insignificant or no leakage at the containment ' test pressure eacii refueling outage. l

)

ATTACHMENT B SIGNIFICANT HAZARDS CONSIDERATION Specification 3.0.4 does not apply addition Commonwealth Edison has evaluated the proposed Technical Specification Amendment and determined that it does not represent a significant hazards consideration. Based on the criteria 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:

1) Involve a significant increase in the probability or consequences of an accident previously evaluated or create the possibility of a new or different kind of accident from any accident previously evaluated because this change does not affect or degrade the primary containment integrity nor effect other systems important to safety but merely allows plant startup with the primary containment isolated with an inoperable but closed valve. This allowance is already provided for many valves by footnote # to Table 3.6.3-1.

This change clarifies the additional actions which are necessary and already being performed when the use of this exception is needed.

2) Involve a significant leduction in the margin of safety because the margin of safety is not affected, since this specification provides for required isolation barriers to be in the isolated condition when required.

Based on the preceding discussion, it is concluded that the proposed system change clearly falls within all acceptable criteria with respect to the system or component, the consequences of previously evaluated accidents will not be increased and the margin of safety will not be decreased.

Therefore, based on the guidance provided in the Federal Register and the criteria established in 10 CFR 50.92(e), the proposed change does not constitute a significant hazards consideration.

9988N

l l

COMNWEALTH EDISON COWANY LASALLE COUNTY STATION UNITS 1 and 2 TECHNICAL SPECIFICATION CHANGE REQUEST l

APPENDIX 3

Subject:

RPIS Indication and Surveillance...

i i

Revised Pages:

Unit 1 Unit 2 l

l 3/4 1-13 3/4 1-13 ,

1-14 1-14 '

l l

i i

l 9988N J

. - , - _ _ . . _ _ _ _ _ . _ _ . , ... ._ ____ -, _ _ _ ~ . , _ , _ _ - _ - - _ - - . , _ _ , .

LASALLE COUNTY STATION UNITS 1 AND 2 TECHNICAL SP CIFICATION CHANGE REQUEST

SUBJECT:

Technical Specification Change for required action on failure of either " Full In" or " Full Out" RPIS Indication and Surveillance of " Full In" Indication.

REFERENCES (1): NUREG 0123 Revision 3, Standard Technical Specifications for General Electric Boiling Water Reactors (BWR/5).

(2): Unit 1 (PF-11) and Unit 2 (WF-18) Technical Specification 3/4 1.3.7, pages 3/4 1-13 and 3/4 1-14.

BACKGROUND:

The control rod position is required to be known to ensure that control rod patterns can be followed and therefore that other parameters remain within their required limits. Specification 3/41.3.7 is written to maintain this operability and to provide remedial actions should equipment failure occur.

DISCUSSION:

Action a.2 of Reference 2 implies that both the " Full In" and " Full Out" position indicators must be operable, but as presently worded seems to indicate that if either but not both indicators fail no action is required.

This is not consistent with the wording of reference 1 for specification 3.1.3.7. In addition there are no surveillance requirements for the " full in" indication in either reference 1 or 2. Revised Technical Specification 3/4 1.3.7 is included in Attschment A. These revised pages are in accordance with reference 1 and also provide surveillance requirements to ensure operability of the full in" indication. These sruveillance require-ments (4.1.3.7.d) are designed to verify that the " full in" light indicator indicates properly prior to each reactor startup and each time a control rod is fully inserted. Since these changes are in accordance with reference 1 this Technical Specification change is considered an administrative change only.

9988N t

w

~f,.TTACHMENT /4 REACTIVITY CONTROL SYSTEM Partpcs v./irH r25mrso Pu#

CONTROL \ ROD POSITION INDICATION

\

LIMITING CONDITION FOR OPERATION 3.1.3.7 The\controlrodpositionindicationsystemshallbeOPERABLE.

\

' APPLICABILITY:\ 0PERATIONAL CONDITIONS 1, 2 and 5*.

ACTION:

a. In OPERATIONAL CONDITION 1 or 2:

1. With\one or more control rod position indicators inoperable, except' or the " Full-in" or " Full-out" indicators:

a) Within one hour:

\

1) D'etermine the position of the control rod by:

(a Moving the control rod, by single notch movement, to a position with an OPERABLE positio, indicator,

\

(b) Returning the control rod, b'y single notch movement, ta'its original position, and

\

(c) Verifying no control rod drift alarm at least once per12\ hours,or

2) Move the control rod to a position with an OPERABLE position indicator, or

3) When THERMAL POWER is within the low power setpoint of the RSCS, decl~are the control rod inoperable, or

4) When THERMAL POWER'is greater than the low power setpoint of the RSCS',, declare the control rod i

inoperable, insert the. control rod and disarm the associated directional' control valves either:

\

,(a) . Electrically, or ,

(b) Hydraulically by closing the drive water and exhaust water isolation valves.

.c b) Otherwise, 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 . N Not applicable to control rods removed "At least each withdrawn control' rod.

per Specification 3.9.10.1 or 3.9.10.2. s LA SALLE - UNIT 1 3/4 1-13 L

ggggc; w,rs r2Lu.sEo i)A6s REACTIVITY CONTROL SYSTEM LIMITING CONkITION FOR OPERATION ( ontinued)

ACTION (Contin ed)

2. 'th one or more centrol rod " Full-in" and " Full-out" position i icators inoperable:

a) Either:

) When THERMAL POWER is within the low power setpoint of the RSCS:

, (a) Within one hour:

(1) Determine the position of the control rod (s) by:

(a) Moving the control rod, by single notch movement, to a position with an OPERABLE position indicator, (b) Returning the control rod, by single notch movement, to its original position, and (c) Verifying no control rod drift alarm at least per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , or (2) Move the control rod to a position with an OPERABLE position indicator, or (3) D clare the control rod inoperable.

(b) Veri fy be position and bypassing of control rods with

,, inoperabie " Full-in" and/or " Full-out" position indica-tors by'a hecond licensed operator or other technically

qualified member of the unit technical staff.

\

2) WhenTHERMALPOWERisgreaterthanthelowpowersetpoint of the RSCS, determine the position of the control rod (s) per ACTION a.2.a) ll(a)(1), above.

b) Otherwise, be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ,

b. InOPERATIONALCONDITION5*withawiIhdrawncontrolrodposition indicator i'noperable, move the control \ rod to a position with an OPERABLE position indicator or insert the control rod.

SURVEILLANCE REQUIREMENTS k 4,1.3.7 The control rod position indication system shall be determined OPERABLE

'by verifying:

a. At least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months that the position of each control rod is .

indicated,

'b. That the indicated control rod position changes during the movement of the control rod drive when performing Surveilla ce Requirement 4.1.3.1.2, and

c. That the control rod position indicator corresponds \t o the control rod position indicated by the " Full out" position indicator when performing Surveillance Requirement 4.1.3.6.b.

"At least each withdrawn control rod not aoplicable to control rocs removed per Specifications 3.9.10.1 or 3.9.10.2. *

.LA SALLE~- UNIT 1 ,

3/4 1-14 9

g --

REACTIVITY CONTROL SYSTEM CONTROL RCD POSITION INDICATION LIMITING CONDITION FOR OPERATION 3.1.3.7 The control rod position indication system shall be OPERABLE.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 5*. .

ACTION:

a. In Operational Condition 1 or 2 with one or more control rod position indicators inoperable, within one hour:

1. Determine the position of the' control rod by: ,

a). Moving the control rod, by single notch movement, to a position with an OPERABLE position indicator, b). Returning the centrol rod, by single notch movement, to its original position, and ,

c). Verifying no control rod drift alarm at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , or

2. Move the control rod to a position with an OPERABLE position

. - indicator, or

3. When THERMAL POWER is:

' a). Within the low power setpoint of the RSCS:

1) Declare the control rod inoperable,

2) Verify the position and bypassing of control rods with inoperable " Full-in" and/or " Full-out" position indicators by a second I? tensed operator or other technically qualified member of the unit technical

. staff.

l b). Greater than the low power setpoint of the RSCS, declare the control rod inoperable, insert the control rod and

' disarm the associated directional control valves ** either:

1) Electrically, or

2) Hydraulically by closing the drive water and exhaust water isolation valves.

P Otherwase, be in at least HOT SKUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

At least each withdrawn control rod. Not applicable to control rods removed per Specification 3.9.10.1 or 3.9.10.2.

- May be rearmed intermittently, under administrative control, to permit testing associated with restoring the control rod to OPERABLE status.

LASALLE - UNIT l 3/4 1-13 0451r

.

REACTIVITY CONTROL SYSTEM LIMITING CONDITION FOR OPERATION (CONTINUED)

b. In OPERATIONS CONDITION 5*.with a withdrawn control rod position indicator inoperable, move the control rod to a -position with an OPERABLE position indicator or insert the control rod.

c. The provisions of Specification 3.0.4 are not applicable.

SURVEILLANCE REOUIREMENTS 4.1.3.7 The control rod position indication system shall be determined OPERABLE by verifying:

a. At least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .that the position of each control rod is indicated. .

b. That the indicated control rod position changes during the movement of the control rod drive when performing Surveillance Requirement 4.1.3.1.2, and

c. That the control rod position indicator corresponds to the control

, rod position indicated by the " Full out" position indicator when performing Surveillance Requirement 4.1.3.6b.

d. That the control rod position indicator corresponds to the co. trol

. rod position indicated by the " Full in" position indicator:

1. Pelor to each reactor startup, and

2. T. ll._ * ;; . .. :. . . .. ... -- . .e , _;d 'Ib

,20M4 Each time a control rod is fully inserted.

At least each withdrawn control rod. Not applicable to control rods removed per Specification 3.9.10.1 or 3.9.10.2.

LASALLE - UNIT 3 3/4 1-14 DOCUMENT 0451r

. _ ----- X-- -

fAft./K& WTTH W*N V l

REACTIVITY CONTROL SYSTEM i \

CONTROL R00 POSITION INDICATION

\

LIMITING CONDITION FOR OPERATION 3.1.3.7 T control rod position indication system shall be OPERABLE.

APPLICABILITit OPERATIONAL CONDITIONS 1, 2 and 5*.

ACTION:

a. In OPERA IONAL CONDITION 1 or 2:

1. With osie or more control rod position indicators inoperable, except 'for the " Full-in" or " Full-out" indicators:

a) Wit one hour:

1) Determine the position of the control rod by:

(a)NMoving the control rod, by single notch movement.

t' a position with an OPERABLE position indicator, (b) Retu(ning the control rod, by single notch movement,

- to it original position, and .

(c) Verifyi no control rod drift alarm at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , or

2) Move the control rod to a position with an OPERABLE position indicator, or

3) When THERMAL POWER i within the low tower setpoint of the RSCS, declare e control rod inoperable, or 4)

When THERMAL POWER reater is g\ the low power than setpoint of the RSCS, declare the control rod inoperable, insert the control rod and disarm the associated directional contiol N valves either:

(a) Electrically, or (b) Hydraulically by closing the\ drive water and exhaust water isolation valves.

\

b) Otherwise, 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 .

\

At least eacn witndrawn control rod. N'ot applicable to control rods removed per Specification 3.9.10.1 or 3.9.10.2.

LA SALLE - UNIT 2 3/4 1-13

- - =m. m - - . .__ _

yefLN.E wrH s2M MO 9 W

%ACTIVITYCONTROLSYSTEM LIkTINGCONDITIONFOROPERATION(Continued)

ACTIO - (Continued)

2. With one or more control red " Full-in" and " Full-out" position indicators inoperable: .

a) Either:

1) When THERMAL POWE8 is within the low power setpoint of the RSCS: >

(a) Within one hd;ur: .

(1) Determin's the position of the control rod (s) by:

(a) Mov;ing the control rod, by single notch movnment, to a position with an OPERABLE position indicator, (b) Retdrning the control rod, by single notch

'ovgment, to its original position, and m

(c) Verifying no control rod drift alarm at least per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , or (2) Move the ':ontrol rod to a position with an K OPERABLE aosition indicator, or

(3)\ Declare t.1e control rod inoperable.

(b) Verify the position and bypassing of control rods with inoperable " Full-in" and/or " Full-out" position indica-tors by'a.second licensed operator or other technically qualified gmember of the unit technical staff.

2) When THERMAL POWER is greater than the low power setpoint of the RSCS, detegnine the position of the control rod (s) per ACTION a.2.a)~1)(a)(1), above.

b)' . Othenvise, be in at leas HOT SHUTOOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ,

b. In OPERATIONAL CONDITION 5* with a withdrawn control red position indicator inoperable,' move the contro1\ rod to a position with an OPERA 8LE positi.on indicator or insert the control rod.

c. The provisions of Specification 3.0.4 areknot applicable.

SURVEILLANCE REQUIREMENTS

\

. '4.1.3.7 The control rod position indication system shat'l be determined OPERA 8LE by verifying: \

.' . a. At least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months that the position of each control rod is indicated, \.

b. That the indicated control rod position changes during the movement

~

of the control rod drive when performing Surveillance Requirementg 4.l'.3.1.2, and \

c. That the control rod position indicator corresponds to the control rod position indicated by the " Full out" position indicator when performing 5,urveillance Requirement 4.1.3.6b. \

At least each withdrawn control rod not applicable to control rods rkmoved per Specifications 3.9.10.1 or 3.9.10.2.

. LA SALLE - UNIT 2 3/4 1-14

. L.....

z. - - ' - - - ' ^

a REACTIVITY CONTROL SYSTEN I

CONTROL ROD POSITION INDICATION Li- umu N ITION FOR OPERATION 3.1.3.7 The control rod position indication system shall be OPERABLE.

APPLICABILITY

OPERATIONAL CONDITIONS 1, 2 and 58 ACTION-

a. In Operational Condition 1 or 2 with one or more control rod position

indicators inoperable, within one houe: i I

1. Determine the position of the control rod by:

a). Moving the control rod, by single notch movement, to a 4 position with an OPERABLE position indicator, I l i

b). Returning the control rod, by single notch movement, to its original position, and l l

c). Verifying no control rod drift alarm at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , or

. 2. Nove the control rod to a position with an OPERABLE position

indicator, or

3. When THERMAL POWER is:

l

! a). Within'the low power setpoint of the RSCS:

1) Declarethecontrolrodinoperable,,petj$

2) Verify the position and bypassing of control rods with lt inoperable " Full-in" and/or " Full-out" position l

indicators by a second licensed operator or other i

technically qualified member of the unit technical staff, l

b). Greater than the low power setpoint of the RSCS, declare the control rod inoperable, insert the control rod and disarm the associated directional control valves ** either:

1) Electrically, or

2) Hydraulically by closing the drive water and exhaust water isolation valves.

l Otherwise, be in at least HOT SKUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

At least each withdrawn control rod. Not applicable to control rode removed per Specification 3.9.10.1 or 3.9.10.2.

l

- Nay be rearmed intermittently, under administrative control, to permit testing associated with restoring the control rod to OPERABLE status. ,

1 LASALLE - UNIT 2 3/4 1-13 DOCUNINT 0451r

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

" REACTIVITY CONTROL SYSTEM LIMITING CONDITION FOR OPERATION (CONTINUED)

b. In OPERATIONS CONDITION 58 with a withdrawn control rod position indicator inoperable, move the control rod to a position with an OPERABLE position indicator or insert the control rod,

c. The provisions of Specification 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS 4.1.3.7 The control rod position indication system shall be determined OPERABLE by verifying:

a. At least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months that the position of each control rod is indicated,

b. That the indicated control rod position changes during the movement of the control rod drive when performing Surveillanca Requirement 4.1.3.1. 2, and

c. That the control rod position indicator corresponds to the control rod position indicated by the " Full out" position indicator when performing Surveillance Requirement 4.1.3.6b.

d. That the control rod position indicator corresponds to the control rod position indicated by the " Full in" position indicator:

1. Prior to each reactor startup, and

2. Telly.*u. ..so ....... :::12 trf j$I

,2".N Each time a control rod la fully inserted.

At least each withdrawn control rod. Not applicable to control rods removed per Specification 3.9.10.1 or 3.9.10.2.

LASALLE - UNIT 2 3/4 1-14 DOCUMENT 0451r

l ATTACHMENT B SIGNIFICANT HAZARDS CONSIDERATION RPIS Indication and Surveillance Commonwealth Edison has evaluated the proposed Technical Specification Amendment and determined that it does not represent a significant hazards consideration. Based on the criteria 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:

1) Involve a significant increase in the probability or consequences of an accident previously evaluated or create the possibility of a new or different kind of accident from any accident previously evaluated because the revised specification increases the amount of surveillances to ensure operability and provides for actions with the loss of a single " full in" or " full out" position indicator.

This change is also in accordance with NUREG-0123 revision 3.

(BWR/5 Standard Technical Specifications).

2) Involve a significant reduction in the margin of safety because this change does not remove any previous requirements as stated in the Technical Specifications.

Based on the preceding discussion it is concluded that the proposed system change clearly falls within all acceptable criteria with respect to the system or component, the consequences of previously evaluated accidents will not be increased and the margin of safety will not be decreased. Therefore, based on the guidance provided in the Federal Register and the criteria established in 10 CFR 50.92(e), the proposed change does not constitute a significant hazards consideration.

9988N

CO)440NWEALTH EDISON COWANY LASALLE COUNTY STATION UNITS 1 and 2 TECHNICAL SPECIFICATION CHANGE REQUEST APPENDIX 4

Subject:

. Decay Correction of Liquid Effluent...

Revised Pages:

Unit 1 Unit 2 3/4 11-4 3/4 11-4 i

9988N

P i

LASALLE COUNTY STATION UNITS 1 Ato 2 TECHNICAL SPECIFICATION CHANGE REQUEST

SUBJECT:

Decay Correction of Liquid Effluent Batch Releases for Lower Limit of Detection

REFERENCE:

, (a) LaSalle County Station (tPF-ll and tFF-18)

Technical Specification 4.11.1.1 i

BACKGROUND: Reference (a) Table 4.11.1-1 requires the use of a typical value for at (The elapsed time between the midpoint of sample collection and time of counting) in the decay correction term of the "a priori" LLD Calculation for batch discharge tanks.

It is technically incorrect to decay correct results from an analysis done prior to the discharge back to the time of sampling.

DISCUSSION: It is requested that the revision to Technical Specification 4.11.1.1.1 Table 4.11.1-1 (Note a) be made as indicated on Attachment A.

Since the sample is taken and analyzed prior to the release of the batch discharge tank effluent, the sample is a representa-tive measurement of the radioactive material to be released and need not be decay corrected back to sample time.

9988N

,. . . ; a TABLE 4.11.1-1 (Continued)

~

/ TA8LE NOTATION

a. The LLD is the smallest concentratipn of radioactive material in a sample that will be detected with 95% probability with SY, probability of falsely concluding that a blank observation represents a "real" signal.

For a particular measurement system (which may in:1ude radiochemical separation): ,

4.66 s LLD =

E V 2.22x10' Y exp (-Ant)

Where:

l LLD is the "a priori" lower limit of detection as defined above (as -

l aicrocurie per unit mass or volume),

1 ._

4 su is the standard deviation of the background counting rate or of i tMe counting rate of a blank sample as appropriate (as counts per

, minute), .

j . E is the counting efficiency (as counts per transformation),

V is the sample size (in units of mass or valuee),

2.22x10s is the number of transformations per minute per microcurie,

! Y is the fractional radiochemical yield (when' applicable),

l '

A is the radioactiv decay constant for the particular radionuclide, and

. i~oe ecaposde.14n At is tHe elasped ime between midpoint of sample collection and time of counting (for c

t~ve %kk supos &Mplant efflue ts, not environmental samples).p %

d M Ix.

l+ The value of 6 used in the caYcu ation of the LLO for a datection

- system shall bI based on the actual observed variance of the back-ground counting rate or of the counting rate of the blank samples (as appropriate) rather than on an unverified theoretically predicted variance. Typical values of E, V, Y, and at shall be used. in the

. calculation.

II .

i b. A composite scmple is one in which the quantity of liquid sampled is i: proportional to the quantity of liquid waste discharged and in which l j the method of sample employed results in a specimen which is j

representative of the liouids released.

0

}* ,,)

4 e

~

LA SALLE - UNIT 1 3/4 11-4 -

TABLE 4.11.1-1 (Continued)

. TABLE NOTATION

a. The LLD is the smallest concentration of radioactive material in a sample that will h concluding ,eadetected that with 95%

blank observation probability represents withsignal.

a "real' 5% probability of falsel For a particular measurement system (which may include radiochemical separation):

4.66 s b

- E V 2.22x10' Y exp (-Ant)

Where:

LLD is the "a priori" lower limit of detection as defined above (as microcurie per unit mass or volume),

s is the standard deviation of the background counting rate or of tNe counting rate of a blank sample as appropriate (as counts per minute),

E is the counting efficier.cy (as counts per transformation),

V is the sample size (in units of mass or volume),

2.22x10s is the number of transformations per minute per microcurie, Y is the fractional radiochemical yield (when applicable),

A is the radioactive decay constant for the particular radionuclide, and Fot' com pos.4,:. sm9l a at is the elasped time batween midpoint of sample collection and time of counting (for plant effluents, not environmental samples). d for t: Ak wap(u h wd ,wa4mcJI. pnce 4 rebte 6 tis W 4 be. 3c.rie. l The value of 4 used in the caTculation of the LLD for a detection systemshallbIbasedontheactualo5servedvarianceoftheback-ground counting rate or of the counting rate of the blank samples (as appropriate) rather than on an unverified theoretically predicted '

variance. Typical values of E, V, Y, and at shall be used in the calculation.

b. A composite sample is one in which the quantity of liquid sampled is proportional to the quantity of liquid waste discharged and in which the method of sample employed results in a specimen which is representative of the liquids raleased.

t.A SALLE - UNIT 2 3/4 11-4

- = = _-_- 7.-- ,

ATTACHMENT B SIGNIFICANT HAZARDS CONSIDERATION Decay Correction of Liquid Effluents Commonwealth Edison has evaluated the proposed Technical Specification Amendment and determined that it does not represent a significant hazards consideration. Based on the criteria 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:

1) Involve a significant increase in the probability or consequences of an accident previously evaluated or create the possibility of a new or different kind of accident from any previously evaluated because this change does nat eliminate any previous requirements.

This change is merely an administrative clarification.

2) Involve a significant reduction in the margin of safety because this change does not reduce the ability to properly monitor plant ef fluents.

Based on the preceding discussion, it is concluded that the proposed system change clearly falls within all acceptable criteria with respect to the system or component, the consequences of previously evaluated accidents will not be increased and the margin of safety will not be decreased.

Therefore, based on the guidance provided in the Federal Register and the criteria established in 10 CFR 50.92(e), the proposed change does not constitute a significant hazards consideration.

9988N

COMMONWEALTH EDISON COM3ANY LASALLE COUNTY STATION UNITS 1 and 2 TECHNICAL SPECIFICATION CHANGE REQUEST APPENDIX 5

Subject:

Control Room Emergency Make-Up Train Heaters Revised Pages:

Unit 1 Unit 2 3/4 7-6 3/4 7-6 9988N L

l i

)

l LASALLE COUNTY STATION UNITS 1 AND 2 TECHNICAL SPECIFICATION CHANGE REQUEST

SUBJECT:

Control Room Emergency Make-Up Train Heaters 4

REFERENCES (1): N510-1975, Testing of Nuclear Air-Cleaning System (2): FSAR Section 6.5.1.2.2.d.2 (3): Letter dated January 15, 1985 from B. Rybak to H. R. Denton BACKGROUND The duct heaters for the Control Room Emergency Makeup System are designed to reduce the relative humidity of the airflow to a maximum of 70%

RH at the worst inlet conditions. A 20 VW single stage heater was installed to provide this function (Reference 2). These heaters are provided with surveillance requirements to ensure they provide their design function.

DISCUSSION The Technical Specifications and Reference 1 provide surveillance requirements to ensure that these heaters perform their design function.

Reference 1 requirements are covered in Section 14 of that document. The Technical Specification bases are covered in FSAR Section 6.5.1.2.2.d.2.

The duct heater is sized to provide a minimum of 60,000 BTU /hr at 950F inlet temperature. There is no maximum size heater limit as described in the FSAR or in the design requirements of Reference 1. However, Technical Specifica-tion 4.7.2.d.4 requires that the heater maintain 20 KW + 2 KW. The acceptance range is provided to ensure that heater degradation is detected.

The requirement of Reference 1 to maintain a less than 5% difference between phases will also detect a potential failure of the heater. The proposed specification will still require this standard be followed, and the acceptance range be maintained. However, due to variations in bus voltage, the + 2 KW cannot be maintained for all possible supply voltages. The variations in bus voltage are maintained within design limits but the restriction of 1 2 KW can only apply when the heater power dissipction is corrected for bus voltage variations, 9988N

?

PLANT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

3. Verifying that on each of the below pressurization mode actuation test signals, the emergency train automatically switches to the pressurization mode of operation and the control room is maintained at a positive pressure of 1/8 inch W.G. relative to the adjacent areas during emergency train operation at a flow rate less than or equal to 4000 cfm:

a) Outside air smoke detection, and b) Air intake radiation monitors.

4. Verifying that the heaters dissipate 20 2.0 Kw when tested in accordance with ANSI N510-1975.THIS WADir0G SHALL micLODE THE APPROPP.lATG C.oRRECTIOM FcR VAlunT:0V> FP4M 4eove'75 ATTHE OuS

e. After each complete or partial replacement of a HEPA filter bank by verifying that the HEPA filter banks remove greater than or equal to 99% of the DOP when they are tested in place in accordance with ANSI 4510-1975 while operating the system at a flow rate of 4000 cfm i 10%.

f. Afteggeach complete or partial replacement of a charcoal adsorber -

bank by verifying that the charcoal adsorbers remove 99% of a halogenated hydrocarbon refrigerant test gas when they are tested -

in place in accordance with ANSI N510-1975 while operating the s,,f system at a flow rate of 4000 cfm i 10%. '

m d

This surveillance shall include the recirculating charcoal filter, " odor eater,"

in the normal control room supply filter train using ANSI N510-1975 as a guide to verify > 70% efficiency in removing freon test gas.

4 LA SALLE - UNIT 1 3/4 7-6 .

(^ PLANT SYSTEMS-

- SURVEILLANCE REQUIREMENTS (Continued)

3. Verifying that on each of the below pressurization mode actuation test signals, the emergency train automatically switches to the pressurization mode of operation and the control room is maintained at a positive pressure of 1/8 inch W.G. relative to the adjacent areas during emergency train operation at a flow rate less than or equal to 4000 cfm:

a) Outside air smoke detection, and

~

b) Air intake radiation monitors.

4. Verifying that the heaters dissipate 2012.0 Kw when tested in accordance with ANSI N510-1975. Ten 5 REAP 106.SHN.L lAKLUDE THE hPPROPRihTE. MRECTiod WWMioMS F00tA4eo@LD AT THE B05,

e. After each complete or partial replacement of a HEPA filter bank by verifying that the HEPA filter banks remove greater than or equal to 99% of the 00P when they are tested in place in accordance with ANSI N510-1975 while operating the system at a flow rate of 4000 cfm 10%. .

f. Afteggeach complete or partial replacement of a charcoal adsorber bank by verifying that the charcoal adsorbers remove 99% of a halogenated hydrocarbon refrigerant test gas when they are tested in place in accordance with ANSI N510-1975 while operating the system at a flow rate of 4000 cfm 10%.

This surveillance shall include the recirculating charcoal filter, " odor eater,"

in the normal control room supply filter train using ANSI N510-1975 as a guide to verify > 70% efficiency in removing freon test gas.

\*

\ %.,

e e

LA SALLE - UNIT 2 3/4 7-6 -

t

1

(,

ATTACHENT B L

ls SIGNIFICANT HAZARDS CONSIDERATION f Control Room Emergency Make-Up Train Heater s

(

Comonwealth Edis'on has evaluated the proposed Technical Specification Amendment and determined that it does not represent a significant hazards consideration. Based on the criteria for defining a significant hazards consideration established in 10 CFR 50.92, operation of LaSalle County Station 1, ' Units 1 and 2 in accordance with the proposed amendment will not:

l 1

1) Involve a significant increase ir; the probability or consequerces of k an accident previously evaluated because the revised surveillince requirement does not effect the ability of the Standby Gas Treatment

! S ystem to provide its design function or affect the ability of the

/

i heater to reduce the relative humidity to below its design limit.

.f

2) C'reate the possibility of a new or different kind of accident from any accident previously evaluated because no new accident is possible by the changed surveillance. No plant equipment is removed.

3)- Involve a significant reductior in the margin of safety because the original design function is not affected.

Based on the preceding discussion, it is concluded that the proposed

system change clearly falls within all acceptable criteria with respect to the s system or component, the consequences of previously evaluated Eccidents will not be increased and the margin of safety will not be decreased. Therefore, Yi based on the guidance provided in the Federal Register and the criteria established in 10 CFR 50.92(e), the proposed change does not constitute a significant hazards consideration. '

9999N N

'i

COMONWEALTH EDISON COM)ANY LASALLE COUNTY STATION UNITS 1 and 2 TECHNICAL SPECIFICATION CHANGE REQtEST APPENDIX 6

Subject:

RCIC Pump Room Differential Temperature Isolation Revised Pages:

Unit 1 Unit 2 3/4 3-9 3/4 3-9 3-12 3-12 3-13 3-13 3-14 3-14 3-16 3-16 3-18 3-18 3-21 3-21 i

l 9988N l

)

I i

LASALLE COUNTY STATION UNITS 1 AND 2 TECHNICAL SPECIFICATION CHANGE REQUEST

SUBJECT:

RCIC Pump Room Differential Temperature Isolation

REFERENCES:

(1) Technical Specification 3/4.3.2 Isolation Actuation Instrumentation (2) UFSAR Table 5.2-8 (3) P & ids M-155 and M-157 sheet 2 (4) Standard Technical Specification for General Electric Boiling Water Reactors (BWR/5) - NUREG-0123 revision 3.

(5) Technical Specification 3.4.7 (6) UFSAR Section 7.4.1.1.3.4 (7) UFSAR Table 7.

3.2 BACKGROUND

Reference (1) specifies the required Isolation Actuation Instrumenta-tion. Reference (2) also lists plant instrumentation which is used to provide automatic and remote manual isolation capabilities. A review of these references and reference 3 indicates that the Reactor Core Isola-tion Cooling (RCIC) pump room differential temperature instrumentation is installed in the plant but not included in reference (1). This instrumentation is also not included in the BWR/5 Standard Technical Specification (reference 4). This instrumentation however has been treatd as if it was included in references (1) since each units initial fuel load. Also several clarifications and relaxations in references (1) and (4) need to be made to make the wording consistent with the intent of the specification. The intent of the specification is to ensure that sufficent instrumentation is available to allow for a single failure if the isolation which the instrumentation is monitoring is required based on plant conditions. For short periods consistent with other specifications (references 5 & 6) this instrumentation may be out of service (inoperable) and not be required to meet the single failure criteria.

DISCUSSION The RCIC pump room differential temperature instrumentation have been added to reference (1) on Attachment A. This includes setpoints, surveillance requirements and required remedial actions.

The setpoints have been established using actual plant data during the startup test programs. This data has been analyzed in the same manner as other differential temperature setpoints in Table 3.3.2-2. The setpoint is based on the isolation occurrin at less than or equal to an equivelant 25 gpm leakage rate. This instrumentation will be added to reference (7) at the next update to the UFS4R.

The revision to action b of Specification 3.3.2 and to footnote

is required to clarify that for trip systems which have more than one channel per trip systems, it is acceptable to trip the inoperable channel or channels and not necessary to place the trip system in the tripped condition. With a design which has 2 channels and requires both channels to trip to cause the trip function (isolation) to occur, the present wording can be construed to mean the entire trip system must be tripped when one of the two channels is inoperable. However if the inoperable channel is placed in the tripped condition, no loss of safety function has occured and if the second operable channel trips the trip function will occur as required. This change is merely a clarification of the wording of the actions required and is in accordance with reference (4).

The addition of footnote *** to specification 3.3.2 action c clarifies the action required to allow one hour to restore at least one channel prior to taking the action of Table 3.3.2-1 for single channel trip systems.

The additions to Table 3.3.2-1 clarify that there are a specific number of channels (instruments) in each area (ie pump room, heat exchanger room, etc). These changes clearly specify which instrumentation is required to meet this specification.

The revision to NOTATION (b) for Table 3.3.2-1 is required to allow sufficient time to perform required surveillance testing of those trip system which have only one channel. These surveillences do not fall under this note as presently worded because there is no other Operable channel in the same trip system monitoring the same parameter. In addition the time period is too short to allow for minor problems which may occur during the performance of the surveillance. The allowance of 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months is similar to the time period allowed to restore an inoperable L

Main Steam Isolation Valve (MSIV) to operable status per specification 3.4. if the other isolation valve is fully operable.

The change to notation (h) corrects a typographical error. The low level initiation setpoint for RCIC is level 2 (-50 inches) and not level

3. This is in accordance with Technical specifcation Table 3.3.5-2 and reference (6).

INSTRUMENTATION .

I% -

3/4.3.2 ISOLATION ACTUATION INSTRUMENTATION LINITING CONDITION FOR OPERATION

. ~

8 3.3.2 The isolatior: actuation instrumen,tation channels shown in Table 3.3.2-1 shall be OPERABLE with their trip setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.3.2-2 and with ISOLATION SYSTEM 3 RESPONSE TIME as shown in Table 3.3.2-3.

APPLICA8ILITY: As shown in Table 3.3.2-1.

ACTION:

a. With an isolation actuation instrumentation channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.3.2-2, declare'the channel inoperable until the -

channel is restored to OPERABLE status with its trip setpoint adjusted consistent with the Trip Setpoint value. -

b. With the number of OPERABLE channels less than required by the 4*0fg dQNa d t4 Minimum OPERABLE Channels per Trip System requirement for one trip system, place.Qat trip system in the tripped condition

within one l p /cr hour. The provisions of Specification 3.0.4 are not applicable.

,L -

c. With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip System requirement for both trip systems, place at least one trip system ** in the tripped condition N l within one hour and take the ACTION required by Table 3.3.2-1.

. N;U. . A ;ig.. p rf w aa aaly ans channelnertriosvntam,h pn inoperable l J channel ne'ed not be placed in the tripped condition where this would b cause the Trip Function to occur. In these cases, the inoperable 1 channel shall be restored to OPERABLE status within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or the

'i ACTION required by Table 3.3.2-1 for that Trip Function shall be taken.

,1

] **If more channels are inoperable in one trip system than in the other, select ll that trip system to place in the tripped condition except when this would

]

cause the Trip Function to occur.

J '

l i kw Ad imperAUe cAomA ptadwof L lncrAia ,Me f-; A cou b lica j where ,ldnis' would cause -14 Tr:p Puncho~ -fo cuan p ,jj,ese cases, -/de jacpe,dle chased ska// be, rcsderock 4

, () OPERA BLE shah.s wMh;u .i. hour or 4ke ACTIOW/wfA

% Tale s.s.a-I L At Tc:p Fv~cliou si,nII L . +ae"-

}

LA SALLE - UNIT 1 3/4 3-9 I

.n.. -. . ~ = ~~ ::

. . . .n. . .-

Mo C b ut INSTRUMENTATION (q-

,, ne R .= b w o -d$

SURVEILLANCE REQUIREMENTS I

4.3.2.1 Each isolation actuation instrumentation channel shall be demonstrated

. OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations for the OPERATIONAL CONDITIONS and at the frequencies shown in Table 4.3.2.1-1.

4.3.2.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic operation of all channels shall be performed at least once per 18 months.

3 4.3.2.3 The ISOLATION SYSTEM RESPONSE TIME of each isolation trip function shown in Table 3.3.2-3 shall be demonstrated to be within its limit at least

.: once per 18 months. Each test shall include at least one channel per trip system such that all channels are tested.at least once every N times 18 months, where N is the total number of redundant channels in a specific -

isolation trip system.

ff O l

16 t

i 1

l l

4 LA SALLE - UNIT 1 3/4 3-10 l;

li h--.__.__. . . . . . . _ _ _ _ . . . . _ . . . . . . . . . . .

~

TABLE 3.3.2-1 -

5 ISOLATION ACTUATION INSTRUMENTATION E VALVE GROUPS MINIMUM OPERABLE APPLICABLE

OPERATED BY CHANNELS PER OPERATIONAL TRIP FUNCTION SIGNAL (a) TRIP SYSTEM (b) CONDITION ACTION g

A. AUTOMATIC INITIATION

1. PRIMARY CONTAlleqENT ISOLATION ..

a. Reactor Vessel Water Level (1) Low, Level 3 7 2 1,2,3 20 (2) Low Low, Level 2 1,2,3 2 1,2,3 20

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

c. . Main Steam Line

1) Radiation - High 1 2 1,2,3 .'

21 w 3 2 1,2,3 22 1 2) Pressure - Low 1 2 1 23 w 3) Flow - High 1 2/11ne(d) 1,2,3 21 h d. Main Steam Line Tunnel 1,2,3 21 Temperature - High 1 .

2

e. Main Steam Line Tunnel l A Temperature - High 1 2 1(I) ,2 fI) , 3I'} 21 I

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

2. SECONDARY CONTAlletENT ISOLATION

a. Reactor Building Vent Exhaust 4 IC)(*) 1, 2, 3 and ** -

Plenum Radiation - High 2 24

, [i1

. b. Drywell Pressure - High 4(c)(e) 2 1,2,3 S, 9 J. #

f

{ a

c. Reactor Vessel Water Level - Low Low, Level 2 4(c)(e) 2 1, 2, 3, and 24 p

.ejb

! d. Fuel Pool Vent Exhaust 2 1, 2, 3, and ** 24 5

,, Radiation - High 4(c)(e)

. g e

3 O '

J -

TABLE 3.3.2-1,(Continued) g '

g ISOLATION ACTUATION INSTRUMENTATION VALVE GROUPS MINIMUM OPERABLE APPLICABLE e OPERATED BY CHANNELS PER OPERATIONAL g TRIP fullCTION SIGNAL (a) TRIP SYSTEM (b) CONDITION _ ACTION .

~

[ 3. RLACTOR WATER CLEANUP SYSTEM ISOLATION

a. A Flow - liigh 5 1 1,2,3 -

22

b. Ileat Exchanger Area Temperature - liigh 5 1, 2, 3 22 ?

1[heah#

c. Ileat Exchanger Area Ventilation AT - High 5 1/d[,,. 1, 2, 3

^

22

d. Pump Area Temperature - High 5 1/g. 1, 2, 3 22

e. Pump Area Ventilation AT-g liigh 5 1/pu p e 1,2,3 22 SLCS Initiation S II) NA 1, 2, 3

[' f. 2,2

" ... ' Reactor Vessel Water Level - Low Low, level 2 5 2 1,2,3 22

4. RIACTOR CORE ISOLATION COOLING SYSTEM ISOLATION

a. RCIC Steam Line Flow - High 8 . I 1, 2, 3 22 s b. RCIC Steam' Supply Pressure - Low 8, 9 I9) 2 1,2,3 22

c. RCIC Turbine Exhaust Diaphragm Pressure - liigh 8 2 ' 1, 2, 3 22 il. RCIC Equipment Room .

Temperature - liigh 8 1 1,2,3 22

e. RCIC Steam Line Tunnel

, Temperature - High 8 1 1,2,3 22

1. RCIC Steam Line Tunnel a Temperature - liigh 8 1 1,2,3 22

y. Drywell Pressure - liigh 9 I9) 2 1,2,3 22 i h, EC(C I ju/pued Beem e L I, 2, s 2- I s re y ,s n. - ai ,

__ ~ _ _. . _ _ _

3 J O. .

I TABLE 3.3.2-1 (Cont'.nued) 5

, ISOLATION ACTUATION INSTRUMENTATION

?

l;; VALVE GROUPS MINIMUM OPERABLE APPLICABLE

, OPERATED BY CHANNELS PER OPERATIONAL c TRIP FlitlCTION SIGNAL (a) TRIP SYSTEM (b) CONDITION ACTION ,

3

-1 5. RilR SYSTEM STEAM CONDENSING MODE ISOLATION

d. RHR Equipment Area .

A Temperature - High 8 1 f 1, 2, 3 22

b. RHR Area Temperature - -'

High 8 1/DE 1, 2, 3 22 O f9%

c. RIIR Heat Exchanger Steam Supply Flow - High 8 1 1,2,3 22 ..

6. RllR SYSTG1 S'iUTDOWN COOLING MODE ISOLATION R n. Reactor Vessel Water

Level - Low, Level 3 6 2 1, 2, 3 ,25 Y h. ~ Reactor Vessel U (RllR Cut-in Permissive)

Pressure - High 6 1. 1, 2, 3 25

c. RilR Pump Suction Flow - High 6 1 1,2,3 25

d. RHR Area Temperature -

High 6 1/g#k 1, 2, 3 25

e. RllR Equipment Area AT - High 6 1/ E R 1, 2, 3 25 l.

l 8. MANilAl INITIATION

1. Inhoard Valves 1, 2, 5, 6, 7 1/ group 1, 2, 3 26

2. Uothoard Valves 1,2,5,6,7 1/ group 1, 2, 3 26

3. Inhoard Valves 4 (c) (e) 1/ group 1, 2, 3 and **,# 26

,. 4. Onthoard Valves 4 IC) I'I 1/ group 1, 2', 3 and **,# 26

~

5. Inhoard Valves 3,8,9 1/ valve 1, 2, 3 26

! 6. Outboard Valves 1/ valve 3,8,9 1, 2, 3 26 I

7. Out. board Valve 8 ) 1/ group 1, 2, 3 26 e %

e

TABLE' 3.3.2-1 (Continued) ,

ISOLATION ACTUATION INSTRUMENTATION ACTION ACTION 20 -

Be in at least H0T SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN with the next 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

ACTION 21 -

Se 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 in at least HOT SHUTDOWN within 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 .

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 l declare the affected system, inoperable.

ACTION 23 -

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

ACTION 24 -

Establish SECONDARY CONTAINMENT INTEGRITY with the standby gas treatment system operating within I hour. .

l ACTION 25 -

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 and declare the affected system inoperable.

ACTION 26 - Provided that the manual initiation function is OPERABLE for each other group valve, inboard or outboard, as applicable, in each 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, restore the manual initiation l function to OPERABLE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months ; otherwise:

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

b. Close the affected system isolation valves within the next hour and declare the affected system in operable.

NOTES May be bypassed with reactor steam pressure < 1043 psig and all turbine stop valves closed.

When handling irradiated fuel in the secondary containment and during 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.

(a) See Specification 3.6.3, Table 3.6.3-1 for valves in each valve group.

(b) A channel may be placed in an inoperable status for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for _ d a g required , surveillance without placing the -tri;; :y:t::1n the tripped condition provided at least one other OPERABLE channel in the same trip

, system is monitoring that parameter.

p (c) Also actuates the standby gas treatment system.

(d) A channel is OPERABLE if 2 of 4 instruments in that channel are OPERABLE.

f (e) Also actuates secondary containment ventilation isolation dampers per Table 3.6.5.2-1.

(f) Closes only RWCU system inlet outboard valve.

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

(h) and only with a coincident Manualinitiationisolates1E51-F008ongsignal.

reactor vessel water level-low, level.J. l (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 filter change and damper cycling without placing the trip system in the tripped cond.ition provided that the ambient temperature channels in the same trip systems are operable.

LA SALLE - UNIT 1 3/4 3-14 Amendment No. 18

INSERT FOR PAGE 3/4 3-14 In addition for those trip systems with a design providing only one channel per trip system, the channel may 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 required 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 for that reduMant valve is OPERABLE, or place the trip system in the tripped condition.

l i

DOCUMENT 0711r

No b4 TABLE 3.3.2-2 Ac M rwu OMg' ISOLATION ACTUATION INSTRUMENTATION SETPOINTS

' Y r- ALLOWABLE i

E TRIP FUNCTION TRIP SETPOINT VALUE A

E . AUTOMATIC INITIATION -

q 1. PRIMARY CONTAllMENT ISOLATION w a. Reactor Vessel Water Level

1) Law Level 3 > 12.5 inches * > 11.0 inches * .. .

2) Low Low, Level 2 5 -50 inches

I -57 inches *

b. Drywell Pressure - High 51.69psig 51.89psig

] c. Main Steam Line j 1) Radiation - High i 3.0 x full power background 1 3.6 x full background j 2) Pressure - Low > 854 psig > 834 psig i 3) Flow - High 5 111 psid i 116 psid j d. , Main Steam Line Tunnel 1 Temperature - High -

< 140'F < 146*F

- l R*

e. Main Steam Line Tunnel

. a Temperature - High < 36*F < 42*F l

]

ya, f. Condenser Vacuum - Low I 7 inches Hg vacuum I 5.5 inches Hg vacuum

2. SECONDARY CONTAINNENT ISOLATION

a. Reactor Building Vent Exhaust Plenum Radiation - High < 10 mr/hr < 15 mr/hr l

.' b. Drywell Pressure - High 31.69psig 51.89psig

c. Reactor Vessel Water l Level - Low Low, Level 2 > -50 inches *

> -57 inches *

! d. Fuel Pool Vent Exhaust -

{

. Radiation - High 5 10 mr/hr $ 15 or/hr l 3 REACTOR WATER CLEANUP SYSTEM ISOLATION .

l k a. AFlow - High 5 70 gpa 1 87.5 gpa j

& b. Heat Exchanger Area Temperature

E - High -

< 181*F < 187'F l

5 c. Heat Exchanger Area Ventilation .

x AT - High < 85"F < 91*F F d. Pump Area Temperature - High 3116*F 3122*F g

e. Pump Area Ventilation AT - High < 13*F < 19'F

f. SLCS Initiation HA NA

g. Reactor Vessel Water Level - '

Low Low, Level 2 > -50 inches * > -57 inches *

]

i

i, j . ,

TABLE 3.3.2-2 (Continued) l 5 !

) g ISOLATION ACTUATION INSTRUMENTATION SETPOINTS -l r-

E ALLOWASLE l i e TRIP FUNCTION TRIP SETPOINT VALUE l

! 4. REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION i:

-8 j " a. RCIC Steam Line Flow - High 5 290% of rated flow, 178" H 2O ,'

1 295% of rated flow 185" H 2O

> 53 psig j b. RCIC Steam Supply Pressure - Low > 57 psig

c. RCIC Turbine Exhaust Diaphragm j Pressure - High 1 10.0 psig i 20.0 psig: 1 l d. RCIC Equipment Room l

Temperature - High 1 200*F 1 206*F l 1 e. RCIC Steam Line Tunnel

! . Temperature - High 1 200*F i 206*F l

f. RCIC Steam Line Tunnel i w A Temperature - High 1 117*F i 123*F -

l j ) g.* Dryl Pres,sy g High g1.69psig i 1.89 psig ,

! W At- y emwc - Migk 120 F s j ggep- l

5. RHR SYSTEM S CONDENSING MODE ISOLATION A.

a -

l-

, a. RHR Equipment Area

a Temperature - High 1 50*F $ 56*F l i

i

b. RHR Area Cooler Temperature -

High 1 200*F $ 206*F l i .

l c. RHR Heat Exchanger Steam

. Supply Flow - High 1 123" H 2O 1 128" H 2O l . .

I

k. .

k .

5 .

? l Is

NO Cb 4 5

TA8LE 3.3.2-2 (Continued) p ISOLATION ACTUATION INSTRUMENTATION SETPOINTS E ALLOWA8LE e TRIP FUNCTION TRIP SETPOINT VALUE k

-e

6. RHR SYSTEM SHUTDOWN COOLING MODE ISOLATION - -

" a. Reactor Vessel Water Level -

Low, Level.3 > 12.5 inches *

> 11.0 inches * '

b. Reactor Vessel (RHR Cut-in Permissive)

Pressure - High 1 135 psig** $ 145 psig** g

. c. RHR Pump Suction Flow - High 5 180" H 2O $ 186" H 2O w d. RHR Area Cooler Temperature -

1 High 1 200*F $ 206*F l W

4

e. RHR Equipment Area AT - High 1 50*F .

5 56*F l t

l 8. MANUAL INITIATION Not Applicable . Not Applicable l

1. Inboard Valves

2. Outboard Valves

3. Inboard Valves

4. Outboard Valves

5. Inboard Valves

6. Outboard Valves

7. Outboard Valve k

'g. *See Bases Figure B 3/4 3-1.

E ** Corrected for cold water head with reactor vessel flooded. I a I .

F 1

4 .

1 l

s

1 4

P' TABLE 3.3.2-3 2 .

I' SOLATION SYSTEM INSTRUMENTATION RESPONSE TIME -

TRIP FUNCTION RESPONSE TIME (Seconds)#

A. AUTOMATIC INITIATION

1. PRIMARY CONTAIP99ENT ISOLATION

a. Reactor Vessel Water Level .

1) Low, Level 3 NA Low Low, Level 2 g)..

l b.

2)

Drywell Pressure - High 51.g 13 l .

1 13

c. Main Steam Line

1) Radiation - High(b) 4)**

1 1 1.0*/5 13 ..

2) Pressure - Low $ 1.0*/1 13(,)..

3) Flow - High 5'O.5*/1 13g ,)

d. Main Steam Line Tunnel Temperature - High NA

e. Condenser Vacuus - Low NA

f. Main Steam Line Tunnel A Temperature - High NA

2. SECONDARY CONTAINMENT ISOLATION

a. ReactorBuildinggntExhaustPlenum Radiation - High < 13(,)

b. Crywell Pressure - High 5 13 1

c. Reactor Vessel Water Level - Low, Level (g) $ 13

d. Fuel Pool Vent Exhaust Radiation - High 1 13(,)

3. REACTOR WATER CLEANUP SYSTEM ISOLATION

a. A Flow - High 1 13(*)

b. Heat Exchanger Area Temperature - High NA

c. Heat Exchanger Area Ventilation AT-High .NA

d. Pump Area Tamperature - High NA

e. Pump Area Ventilation AT - High NA

f. SLCS Initiation NA

g. Reactor Vessel Water Level - Low Low, Level 2 1 13(*)

4. REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION

a. RCIC Steam Line Flow - High < 13(*) !

b. RCIC Steam Supply Pressure - Low 513(*)

c. RCIC Turbine Exhaust Diaphragm Pressure - High NA ' -

d. RCIC Equipment Room Temperature - High NA I

e. RCIC Steam Line Tunnel Temperature - High NA

f. RCIC Steam Line Tunnel A Temperature - High NA

g. Drywell Pressure - High NA

h. ectc. [ a:mM Eeam bi'em m % .- m y MA

5. RHR SYSTEM E4M CONDENSING N00 E ISOLATION

a. RHR Equipment Area A Temperature - High .NA

b. RHR Area Cooler Temperature - High NA

c. RHR Heat Exchanger Steam Supply Flow High NA LA SALLE - UNIT 1 3/4 3-18 Amendment No. 18

14o CMa9 For %%w CNG 9

TABLE 3.3.2-3 (Continued)

IN0LATIONSYSTEMINSTRUMENTATIONRESPONSETIME TRIP FUNCTION RESPONSE TIME (Seconds)#

6. RHR SYSTEM SHUTDOWN C0OLING MODE ISOLATION

a. Reactor Vessel Water Level - Low, Level 3 < 13I *)

b. Reactor Vessel (RHR Cut-In Permissive) Pressure - High N.A. I

c. RHR Pump Suction Flow - High N.A. I

d. RHR Area Cooler Temperature High N.A. g

e. RHR Equipment Area AT High N.A. g B. MANUAL INITIATION N.A. g

1. Inboard Valves

2. Outboard Valves

3. Inboard Valves

4. Outboard Valves

5. Inboard Valves

6. Outboard Valves '

7. Outboard Valve .

l (a) The isolation system instrumentation response time shall be measured and recorded as a part of the ISOLATION SYSTEM RESPONSE TIME. Isolation system instrumentation response time specified includes the delay for diesel generator starting assumed in the accident analysis.

(b) Radiation detectors are exempt from response time testing. Response time shall be measured from detector output or the input of the first electronic component in the channel.

Isolation system instrumentation response time for MSIVs only. No diesel l generator delays assumed.

- Isolation system instrumentation response time for associated valves except MSIVs.

l # Isolation system instrumentation response time specified for the Trip Function actuating each valve group shall be added to isolation time shown in Table 3.6.3-1 and 3.6.5.2-1 for valves in each valve group to obtain ISOLATION SYSTEM RESPONSE TIME for each valve.

M Without 45+1 second time delay.

N Without < 5 second time delay. g N.A. Not Applicable. g LA SALLE - UNIT 1 3/4 3-19 Amendment No.18

l N.. %

TABLE 4.3.2.1-1 g NO gg C bd y ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS O r-CHANNEL OPERATIONAL CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WilCH jj TRIP FINICTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRE 0 A. AUTOMAllC INITIATION

1. PRIMARY CONTAINMENT ISOLATION '

a. Reactor Vessel Water Level

1) Low, Level 3 S M R 1, 2, 3

2) Low Low, Level 2 5 M R 1, 2, 3 Drywell Pressure - High t, . NA M 1, 2, 3 Q

c. Main Steam Line

1) Radiation - High S M R 1, 2, 3

2) Pressure - Low NA M Q l ,

3) Flow - High S M R 1, 2, 3

d. Main Steam Line Tunnel '

Temperature - High NA M R 1, 2, 3 g e. Condenser Vacuum - Low NA M Q 1, 28, 3*

f. Main Steam Line Tunnel y a Temperature - liigh NA M R 1,' 2, 3 S 2. SECONDARY CONTAINMENT ISOLATION

a. Reactor Building Vent Exhaust '

Plenum Radiation - High S' M R . 1, 2, 3 and **

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

c. Reactor Vessel Water Level - Low Low, level 2 y S M R 1, 2, 3, and

d. Fuel Pool Vdnt Exhaust Radiation - High S M i R 1, 2, 3 and **

3. REACTOR WATER CLEANUP SYSTEM ISOLATION

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

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

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

d. Pump Area Temperature - High NA M 1, 2, 3 Q

c. Pump Area Ventilation - a Temperature - liigh NA M Q 1, 2, 3

t. SLCS Initiation NA -

R NA 1, 2, 3 9 Reactor Vessel Water Level - tow Low, Level 2 S M R 1, 2, 3

TABLE 4.3.2.1-1 (Continued) i g ,

i u. ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS

?

E CHANNEL OPERATIONAL i . CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR letICH l c- TRIP FilflCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED

5 -

j 4. REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION i

]

i

a. RCIC Steam Line Flow - High NA M Q 1, 2, 3 l

h. RCIC Steam Supply Pressure -

, to.s NA M Q 1,2,3 j c. RCIC Turbine Exhaust Diaphragm i Pressure - High NA M Q 1, 2, 3

d. RCIC Equipment Room L Temperature - liigh

, NA M Q 1,2,3 i -

e. RCIC Steam Line Tunnel

Temperature - liigh NA M Q 1, 2, 3 l R*

f. RCIC Steam Line Tunnel l a Temperature - High NA M Q 1,,2, 3

! ';' g. Drywell Pressure - High NA M Q 1, 2, 3 -

M L #CIC ffo: pef-Resw ATewpim6,-IliqL A/A M Cl i/ 2 7 S. HilR SYSTEM STEAM CONDENSINGIMODE ISOLATION ' .

l 1

4 j a. RilR Equipment Area a .

Temperature - High NA M Q 1,2,3

b. RHR Area Cooler Temperature - .

! High NA M Q 1,2,3 l c. RilR lleat Exdhanger Steam

. Supply Flow - liigh NA M i Q 1,2,3 I

4 1 e t %

r-( \

j .

~

D O TABLE 4.3.2.1-1 (Continued) ~

l g . -o e A(RetWCL Ol'd-

, ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS

, r-

E CHANNEL OPERATIONAL.

i , CHANNEL FUNCTIONA: CHANNEL CONDITIONS FOR WHICH l c TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED

{ 5 1 6. RilR SYSTEM StrJTDOWN COOLING MODE ISOLATION

) H 4 '

a. Reactor Vessel Water Level -

4 Low, level 3 S M R 1, 2, 3 ',

< b. Reactor Vessel (RilR Cut-in Permissive) l Pressure - High NA M Q 1, 2, 3

, c. RilR Pump Suction Flow - High NA M Q 1, 2, 3 ~1

. al. RilR Area Temperature - High NA M Q 1, 2, 3

c. RilR Equipment Area AT - High NA M Q 1, 2, 3 2:

8 B. MANt!AL INITIATION l * '

] Y 1. Inboard Valves NA R NA 1,' 2, 3 *

-M 2. Outboard Valves 1, 2, 3 j 3. Inhoard Valves 1, 2, 3 and **,#

4. Outboard Valves 1, 2, 3 and **,#

5. Inboard Valves 1, 2, 3 .

6. Dot. board Valves 1, 2, 3

7. Outboard Valve 1, 2, 3 1

) *When reactor steam pressure > 1043 psig and/or any turbine stop v.alve is open.

- When handling irradiated fuel in tne secondary containment and during CORE ALTERATIONS and operations

, with a potential for draining the reactor vessel.

) #Daring CORE ALTERATIONS and operations with a potential i'or draining the reactor vessel.

\

i l

j -

I

s l, ,

l l

INSTRUMENTATION 3/4.3.2 ISOLATION ACTUATION INSTRUMENTATION LIMITING CONDITION FOR OPERATION

~

3.3.2 The isolation actuation instrumentation channels shown in Table 3.3.2-1 shall be OPERABLE with their trfp setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.3.2-2 and with ISOLATION SYSTEM RESPONSE TIME as shown in Table 3.3.2-3.

APPLICABILITY: As shown in Table 3.3.2-1. l i

ACTION:

! a. With an isolation actuation instrumentation channel trip setpoint l 1ess conservative than the value shown in the Allowable Values '

column of Table 3.3.2-2, declare the channel inoperable until the '

channel is restored to OPERABLE statu.s with its trip setpoint adjusted consistent with the Trip Setpoint value.

b. With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip System requirement for one trip system, place p trip system in the tripped condition

within one ]

h= s,ue Able- nour. The provisions of Specification 3.0.4 are not applicable.

,ckoakecs>

l -

c. With the number of OPERABLE channels less than required by the Av Or Minimum OPERABLE Channels per Trip System requirement for both trip

systems, place at least.one trip system ** in the tripped condition I within one hour and take the ACTION required by Table 3.3.2-1.

I 9A

! "M r. : tt ;-avidf ~; : 1y ;r.: d.;r.r.;; ;;;r t-ip eyc+=. An inoperable 'l channel need not be placed in the tripped condition where this would cause the Trip Function to occur. In these cases, the inoperable l

channel shall be restored to OPERABLE status within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or the ACTION required by Table 3.3.2-1 for that Trip Function shall be taken.

- If more channels are inoperable in one trip system than in the other, select o that trip system to place in the tripped condition except when this would cause the Trip Function to occur.

tu 0 CM AiW Asl Ino trahl2 C.NGuse$ 900 m4- be f \A ca$ iH h kt1 '

. tekee h wed cause & Try F-vedim 4o ouuc. ra 4hese-Cases j 4k ,6O(er AblR. Ckopd Sk A H be, res4ocd 4o OPistAGLE l E 4% w h 1 hcoc oe & Ac,TiotJ ryvina Q Thble 3 3 9-1 i

L u 19 % un mee.

LA SALLE - UNIT 2 3/4 3-9

=w~~~-_..s _ _ . . _ _ _ _ _ _ _ _ _ _ _ _ _ , ,,-m_- -

, . . , , . _ - - _ _ _ _ . , , . . ,,.-m. - _ . , - - - . , , , _ _ . - _ _ _ _ . _ ,

h\o c h g e.

l i=3 e %% t-a. w1 T INSTRUMENTATION SURVEILLANCE REQUIREMENTS 4.3.2.1 Each isolation actuation instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations for the OPERATIONAL CONDITIONS and at the frequencies shown in Table 4.3.2.1-1.

4.3.2.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic operation of all channels shall be performed at least once per 18 months.

4.3.2.3 The ISOLATION SYSTEM RESPONSE TIME of each isolation trip function shown in Table 3.3.2-3 shall be demonstrated to be within its limit at least once per 18 months. Each test shall include at least one channel per trip system such that all channels are tested at least once every N times 18 months, where N is the total number of redundant channels in a specific isolation trip system.

i e

0 LA SALLE - UNIT 2 3/4 3-10

^

NO Cbqt_

Fo c %%eem Q

TABLE 3.3.2-1 g

g! ISOLATION ACTUATION INSTRUMENTATION l

I~ APPLICABLE m VALVE GROUPS MINIMUM OPERA 8LE

' OPERATED BY CHANNELS PER OPERATIONAL CONDITION ACTION g TRIP FUNCTION SIGNAL (a) TRIP SYSTEM (b)

.' y j u A. AUTOMATIC INITIATION l 1. PRIMARY CONTAINNENT ISOLATION

a. Reactor Vessel Water Level (1) Low, Level 3 7 2 1,2,3 20 i (2) Low Low, Level 2 1,2,3 2 1,2,3 20 t

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

c. Main Steam Line

1) Radiation - High 1 2 1,2,3 21 i

3 2 1,2,3 22 Pressure - Low 2 1 23

2) 1 Flow - High 2/11ne(d) 1, 2, 3 21

$ 3) 1 f y d. Main Steam Line Tunnel 1,2,3 21 l p Temperature - High 1 2

e. Main Steam Line Tunnel

] A Temperature - High 1 2 1(1), 2(1), 3(1) 21

f. Condenser Vacuum - Low 1 2 1, 28, 3* 21

. 2. SECONDARY CONTAINMENT ISOLATION

a. Reactor ' Building Vent Exhaust Plenum Radiation - High 4(c)(e) 2 1, 2, 3 and ** 24

b. Drywell Pressure - High 4(c)(e) 2 1,2,3 24

c. Reactor Vessel Water y Level - Low Low, Level 2 4(c)(e) 2 1, 2, 3, and 24

d. Fuel P'ool Vent Exhaust Radiation - High 4(c)(e) 2 1, 2, 3, and ** 24

~

i TABLE 3.3.2-1 (Contir.ued) 9 ISOLATION ACTUATION INSTRUMENTATION

l l 5 APPLICABLE !'

VALVE GROUPS MINIMUM OPERA 8LE l

h OPERATED BY CHANNELS PER OPERATIONAL I;

j ,

CONDITION ACTION i TRIP FUNCTION SIGNAL (a) TRIP SYSTEM (b)

I kH 3. REACTOR WATER CLEANUP SYSTEM 150fATION j

" 1,2,3 22

a. A Flow - High 5 1

b. Heat Exchanger Area 1, 2, 3 22 Temperature - High 5 ht l

c. Heat Exchanger Area Ventilation AT - High 5 1[MY 1/pg 1, 2, 3 22 l

d. Pump Area Temperature - High 5 1/ p g . 1, 2, 3 22 j

e. Pump Area Ventilation AT-

, High 5 1/posp e 1,2,3 22 II) 22 l 5 f. SLCS Initiation S NA 1, 2, 3 l T g. Reactor Vessel Water 5 Level - Low Low, Level 2 5 2 1,2,3 22

l. 4. REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION 1,2,3 22 l

a. RCIC Steam Line Flow - High 8 1

b. RCIC Steam Supply Pressure - Low 8, 9 gg) 2 _1, 2, 3 22

c. RCIC Turbine Exhaust Diaphragm Pressure - High 8 2 1,2,3 22

d. RCIC Equipment Room 8 1,2,3 22 Temperature - High 1

e. RCIC Steam Line Tunnel 8 1,2,3 22 Temperature - High 1

f. RCIC Steam Line Tunnel 22 a Temperature - High 8 1 1,2,3

g. Drywell Pressure - High 9 I8) 2 1,2,3 22

b. 60tC (go;pu mF Poes j 6 Tes e m h e. - i4 q b 8 i 1233 3 22.

l.

i TABLE 3.3.2-1 (Continued)

ISOLATION ACTUATION INSTRUMENTATION

W APPLICABLE

! VALVE GROUPS MINIMUM OPERA 8LE I

% OPERATED BY CHANNELS PER OPERATIONAL

TRIP SYSTEM (b) CONDITION ACTION

! TRIP FUNCTION SIGNAL (a) l E I Z 5. RHR SYSTEM STEAM CONDENSING M00E ISOLATION

" RHR Equipment Area

! a. 1,2,3 22 i a Temperature - High 8 1/El4R

/ oreev

! b. RHR Area Temperature -

High 8 1/'R H R 1, 2, 3 , 22

c. RHR Heat Exchanger Steam 8 1,2,3 22 l

Supply Flow - High 1

)

! 6. RHR SYSTEM SHHT00WN COOLING MODE ISOLATION

! w a. Reactor Vessel Water 25 Level - Low, Level 3 2 1,2,3 A 6 Y b. Reactor Vessel

! U (RHR Cut-in Permissive) 1,2,3 25 Pressure - High 6 1 l 1,2,3 25

c. RHR Pump Suction Flow - High 6 1

~

d. RHR Area Temperature -

! High 6 6

1[f[

p 1, 2, 3 1, 2, 3 25 25

e. RHR Equipment Area AT - High 1/or/cen j B. MANUAL INITIATION 1, 2, 5, 6, 7 1/ group 1, 2, 3 26

1. Inboard Valves j 26

2. Outboard Valves 1,2,5,6,7 1/ group 1, 2, 3 l

4 (c) (e) 1/ group 1, 2, 3 and **,# 26

3. Inboard Valves

4. Outboard Valves 4 IC) (*I 1/ group 1, 2, 3 and **,# 26 3,8,9 1/ valve 1, 2, 3 26 a 5. Inboard Valves

3. 8, 9 1/ valve 1, 2, 3 26

6. Outboard Valves

7. Outboerd Valve 8 0) 1/ group 1, 2, 3 26

~

I

[ _

- ' ~ z.: .:... . - -

....-..=.:.:.=..=-_:.-.----- ---

TABLE 3.3.2-1 (Continued)

ISOLATION ACTUATION INSTRUMENTATION ACTION STATEMENTS ACTION 20 -

Se in at least H0T SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN with the next 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

ACTION 21 -

8e in at least STARTUP with the associated isclation valves 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 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the flext 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 inoperable.

ACTION 23 -

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

ACTION 2A - Establish SECONDARY CONTAINMENT INTEGRITY with the standby gas treatment system operating within I hour.

ACTION 25 -

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 and declare the affected system inoperable.

ACTION 26 - Provided that the manual initiation function is OPERA 8LE for each other group valve, inboard or outboard, as applicable, in each 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, restore the manual initiation

- function to OPERA 8LE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months ; otherwise:

a. Se 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

. COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , or Close the affected system isolation valves within the next i b.

hour and declare the affected system in operable.

TABLE NOTATIONS

May be bypassed with reactor steam pressure 11043 psig and all turbine -

stop valves closed.

- When handling irradiated fuel in the secondary containment and during 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.

(a) See Specification 3.6.3, Table 3.6.3-1 for valves in each valve group.

1 (b) A channel may be placed in an inoperable status for up to 2 houn far dend required surveillance without placing the Artp asses in the tripped l condition provided at least one other OPERA 8LE channel in the same trip

system is monitoring that parameter.

d %(c)Also actuates the standby gas treatment system. l

@ (d) A channel is OPERABLE if 2 of 4 instruments in that channel are OPERABLE.

(e) Also actuates secondary containment ventilation isolation dampers per .

Table 3.6.5.2-1.

(f) Closes only RWCU system inlet outboard valve.

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

(h) Manual initiation isolates 2E51-F008 only and only with a coincident reactor vessel water level-low, level #, 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 filter change and damper cycling without placing the tr'ip system in the tripped condition provided that the ambient temperatere channels in the same trip systems are OPERA 8LE.

LA SALLE - UNIT 2 3/4 3-14

INSERT FOR PAGE 3/4 3-14 In addition for those trip systems with a design providing only one channel per trip system, the channel may 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 required 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 for that' redundant valve is OPERABLE, or place the trip system in the tripped condition.

i i

i l

l l

DOCUMENT 0711r

(" V \Mo Chde - -

TABLE 3.3.2-2

> ISOLATION ACTUATION INSTRUMENTATION SETPOINTS

% 0%% lb.[qU-h ALLOWABLE g TRIP FUNCTION TRIP SETPOINT VALUE

' A. AUTOMATIC INITIATION k 1. PRIMARY CONTAINMENT ISOLATION u a. Reactor Vessel Water level

1) Low, level 3 > 12.5 inches * > 11.0 inches *

2) Low Low,. Level 2 [-50 inches * [-57 inches *

b. Orywell Pressure - High 5 1.69 psig $ 1.89 psig

c. Main Steam Line

1) Radiation - High 5 3.0 x full power background 5 3.6 x full background

2) Pressure - Low > 854 psig

> 834 psig

3) Flow - High 5 111 psid i 116 psid

d. Main Steam Line Tunnel Temperature - High -< 140*F -< 146*F w e. Main Steam Line Tunnel '

} o Temperature - High 1 36*F $ 42*F l m f. Condenser vacuum - Low > 7 inches Hg vacuum > 5.5 inches Hg vacuum

2. SECONDARY CONTAINMENT ISOLATION

a. Reactor Building Vent Exhaust Plenum Radiation - High 5 10 mr/h i 15 mr/h

b. Drywell Pressure - High 5 1.69 psig 5 1.89 psig

c. Reactor Vessel Water Level - Low Low, level 2 -> -50 inches * .

-> -57 inches *

d. Fuel Pool Vent Exhaust Radiation - High 5 10 mr/h 5 15 mr/h g 3. REACTOR WATER CLEANUP SYSTEM ISOLATION

a. AFlow - High 5 70 gpm 1 87.5 gpm

b. Heat Exchanger Area Temperature 6

- High -< 181*F -< 187'F

c. Heat Exchanger Area Ventilation ai - High < 85* < 91*F

d. Pump Area Temperature .lligh 5116*F 3122*F

e. Pump Area Ventilation AT - liigh, i 13 F i 19*F .

f. SLCS Initiation N.A. N.A.

g. Reactor Vessel Water Level -

. Low Low, level 2 > -50 inches * > -57 inches

TABLE 3.3.2-2 (Continued) 5 ISOLATION ACTUATION INSTRUMENTATION SETPOINTS Y

ALLOWA8LE h TRIP SETPOINT VALUE

, TRIP FUNCTION

4. REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION N a. RCIC Steam Line Flow - High 1 290% of rated flow, 178" H 2O 1 2955 of rated flow, 185" H20

b. RCIC Steam Supply Pressure - Low > 57 psig > 53 psig

c. RCIC Turbine Exhaust Diaphragm Pressure - High 5 10.0 psig i 20.0 psig

d. RCIC Equipment Room Temperature - High 1 200*F i 206*F

e. RCIC Steam Line Tunnel Temperature - High 5 200*F 5 206*F .

f. RCIC Steam Line Tunnel A Temperature - High $ 117*F < 123*F

. i 1.89 psig

g. 1 Pressur High i 1.69 psig

)

w h. p6}C1.g% , 6 lao *F d: l26*F 4 5. RHRSYSTEN'SYAMCONDENSINGM00EISOLATION

a. RHR Equipment Area A Temperature - High 5 50*F $ 56*F -

b. RHR Area Cooler Temperature -

High. 1 200*F $ 206'F

c. RHR Heat Exchanger Steam Supply Flow - High 5 123" H 2O 1 128" H 2O

- ' I? F '

W.

~

NO Cbg(

TABLE 3.3.2-2 (Continued) fo r k G m u o-1 y c ISOLATION ACTUATION INSTRUMENTATION SETPOINTS-p f r- -

ALLOWA8LE !

E TRIP SETPOINT VALUE ;

e - TRIP FUNCTION '

k~ 6. RHR SYSTEM SHUTDOWN COOLING MDOE ISOLATION

. {

" a. Reactor Vessel Water Level - !'

Low, Level 3 > 12.5 inches * > 11.0 inches" i

j.

b. Reactor Vessel (RHR Cut-in Permissive) 1 145 psig**

Pressure - High 1 135 psig**

c. RHR Pump Suction Flow - High 1 180" H 2O $ 186" H 2O w d. RHR Area Cooler Temperature -

HIgh $ 200*F 1 206*F l

) ;

e. RHR Equipment Area AT - High i 50*F $ 56*F w i N.A. ;

8. MANUAL INITIATION N.A.

I

1. Inboard Valves i

2. Outboard Valves

3. Inboard Valves ,

4. Outboard Valves ,

5. Inboard Valves

6. Outboard Valves .

7. Outboard Valve .

l "See Br.ses Figure B 3/4 3-1.

- Corrected for cold water head with reactor vessel flooded.

N.A. - Not Applicable. .

G .

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

A. AUTOMATIC INITIATION

1. PRIMARY CONTAlle4ENT ISOLATION

a. Reactor Vessel Water Level

1) Low, Level 3 N.A.

2) Low Low, Level 2 < 1. g 13(,)..

b. Drywell Pressure - High < 13

c. Main Steam Line

1) Radiation - High(b) < 1.0*/< 13(a)**

2) Pressure - Low I

3) Flow - High 2 7 0.5*R-

)..

1.0* 81313("a)..

d. Main Steam Line Tunnel Temperature - High N.A.

e. Condenser Vacuus - Low N.A.

f. Main Steam Line Tunnel A Temperature - High N.A.

2. SECONDARY CONTAINMENT ISOLATION

a. Reactor Building (gnt Exhaust Plenum Radiation - High < 13(,)

b. Drywell Pressure - High 313

c. ReactorVesselWaterLevel-Low, Level (g) < 13

d. Fuel Pool Vent Exhaust Radiation - High 313(a)

3. REACTOR WATER CLEANUP SYSTEM ISOLATION

a. A Flow - High < 13(*)"

i b. Heat Exchanger Area Temperature - High N.A.

c. Heat Exchanger Area Ventilation AT-High N.A.

d. Pump Area Temperature - High N.A.

j e. Pump Area Ventilation AT - High N.A.

f. SLCS Initiation N.A.I")

Reactor Vessel Water Level - Low Low, Leve' 2

g. < 13

4. REACTOR CORE ISOLATION COOLING SYSTEN ISOLATION

a. RCIC Steam Line Flow - High < 13I ")#

b. RCIC Steam Supply Pressure - Low 513(a) _

c. RCIC Turbine Exhaust Diaphragm Pressure - High N.A.

d. RCIC Equipment Room Temperature - High N.A.

l e. RCIC Steam Line Tunnel Temperature - High N.A.

f. RCIC Steam Line Tunnel A Temperature - High N.A.

g. Drywell Pressure - High N.A.

A. Reic fru;tM Ecoa ate pwa+m - Web N.A. l i l 5. RHR SYSTEM STEAM CONDENSING N00E ISOLATION l

! a. RHR Equipment Area A Temperature - High M.A.

b. RHR Area Cooler Temperature - High N.A.

c. RHR Heat Exchanger Steam Supply Flow High N.A.

LA SALLE - UNIT 2 3/4 3-18 l

l

t __ ___ _ . _ _ _ _ .

Mo Oww.ge few L k a onl y TABLE 3.3.2-3 (Continued)

ISOLATION SYSTEM INSTRtMENTATION RESPONSE TIME TRIP FUNCTION RESPONSE TIME (Seconds)#

6. RHR SYSTEM SHUTDOWN COOLING M00E ISOLATION

a. Reactor Vessel Water Level - Low, Level 3 < 13(*)

b. Reactor Vessel

.(RHR Cut-In Permissive) Pressure - High N.A.

c. RHR Pump Suction Flow - High N.A.

d. RHR Area Cooler Temperature High N.A.

e. RHR Equipment Area AT High N.A.

8. MANUAL INITIATION N.A.

1. Inboard Valves

2. Outboard Valves

3. Inboard Valves

4. Outboard Valves

5. Inboard Valves

6. Outboard Valves

7. Outboard Valve TABLE NOTATIONS (a) The isolation system instrumentation response time shall be measured and recorded as a part of the ISOLATION SYSTEM RESPONSE TIME. Isolation system instrumentation response time specified includes the delay for diesel generator starting assumed in the accident analysis.

(b) Radiation detectors are exempt from response time testing. Response time shall be measured from detector output or the input of the first electronic component in the channel.

Isolation system instrumentation response time for MSIVs only. No diesel generator delays assumed.

- Isolation system instrumentation response time for associated valves except MSIVs.

Isolation system instrumentation response time specified for the Trip Function actuating each valve group shall be added to isolation time -

shown in Table 3.6.3-1 and 3.6.5.2-1 for valves in each valve group to obtain ISOLATION SYSTEM RESPONSE TIME for each valve.

N Without 45_+1 second time delay.

N# Without < 5 second time delay.

M.A. Not Applicable. .

LA SALLE - UNIT 2 3/4 3-19

No CL% e_

nc kbeac4 dbl -

TABLE 4.3.2.1-1 ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS g OPERATIONAL m CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH N CHANNEL TEST CALIBRATION SURVEILLANCE REQUIRE 0 m TRIP FUNCTION CHECK

[A. AUTOMATIC INITIATION

'(

m

1. PRIMARY CONTAlletENT ISOLATION

a. Reactor Vessel Water Level M R 1, 2, 3

1) Low, Level 3 S .

1, 2, 3 Low Low, Level 2 S M R

2) 1, 2, 3

b. Drywell Pressure - High NA M Q

c. Main Steam Line 1, 2, 3

1) Radiation - High S M R M 1

2) Pressure - Low NA Q R 1, 2, 3

3) Flow - High S M

d. Main Steam Line Tunnel 1, 2, 3 Temperature - High NA M R NA M Q 1, 28, 3*

w e. Condenser Vacuum - Low D f. Main Steam Line Tunnel R 1, 2, 3 w A Temperature - High NA M

{ .

! E$ 2. SECONDARY CONTAINMENT ISOLATION I :-

i, -

a. Reactor Building Vent Exhaust 1, 2, 3 and **

Plenum Radiation - High S M R M 1, 2, 3 I b. Drywell Pressure - High NA Q

c. Reactor Vessel Water y l 1, 2, 3, and

! Level - Low Low, Level 2 S M R g

! d. Fuel Pool Vent Exhaust 1, 2, 3 and **

Radiation - High S M R ,

l i 3. REACTOR WATER CLEANUP SYSTEM ISOLATION 1, 2, 3

a. A Flow - High S M R

{

i~ b. Heat Exchanger Area M 1, 2, 3 Temperature - High NA Q ;

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

d. Pump Area Temperature - High NA Q

e. Pump Area Ventilation - A 1, 2, 3 Temperature - High NA M Q R NA 1, 2, 3

f. SLCS Init'iation NA

g. Reactor Vessel Water 1, 2, 3 Level - Low Low, Level 2 S M R l ,

- TABLE 4.3.2.1-1 (Continued) 9 ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS W OPERATIONAL E CHANNEL CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH 7 TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE RFOUIRED E

U 4. REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION m .

RCIC Steam Line Flow - High NA M Q 1, 2, 3 a.

b. RCIC Steam Supply Pressure -

NA M Q 1, 2, 3 l Low l c. RCIC Turbine Exhaust Diaphragm Pressure - High NA M Q 1,2,3 i d. RCIC Equipment Room Temperature - High NA M Q 1,2,3 i

e. RCIC Steam Line Tunnel Temperature - High NA M Q 1, 2, 3 l;

w f. RCIC Steam Line Tunnel 1, 2, 3 D A Temperature - High NA M Q 1, 2, 3 w g. Drywell Pressure - High NA M Q IOC. fro:pwi-Reow hTe9 tan 4SN A M Q 1, 2., 3 I l h h.

S. RHR SYSTEM STEAM CONDENSING MODE ISOLATION 4

l a. RHR Equipment Area a Temperature - High NA M Q 1, 2, 3 j

b. RHR Area Cooler Temperature -

High NA M Q 1, 2, 3

c. RHR Heat Exchanger Steam M 1, 2, 3 i Supply Flow - Hi,gh NA Q i

l t

. , j' NO CbgR -

ac L b umcm/ i TA8LE 4.3.2.1-1 (Continued) {-

4 ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS

$ CHANNEL OPERATIOMAL F

CHANNEL CONDITIONS FOR WHICH CHANNEL FUNCTIONAL CHECK TEST CALIBRATION SURVEILLANCE REQUIRED }

TRIP FUNCTION i

[

z I G 6. RHR SYSTEN SHUTDOWN COOLING MODE ISOLATION N

a. Reactor Vessel Water Level - 1, 2, 3 I Low, Level 3 S M R

b. Reactor Vessel l'

(RHR Cut-in Permissive) 1,2,3 Pressure - High NA . M Q RHR Pump Suction Flow - High M Q 1,2,3 i

c. NA 1, 2, 3 l

d. RHR Area Temperature - High NA M Q RHR Equipment Area AT - High NA M Q 1,2,3 e.

g 8. MANUAL INITIATION

. 1,2,3 Inboard Valves NA R NA w 1. 1, 2, 3 A

2. Outboard Valves 1, 2, 3 and **,#

3. Inboard Valves '

1, 2, 3 and **,#

4. Outboard Valves 1, 2, 3

5. Inboard Valves 1, 2, 3 l

6. Outboard Valves 1, 2, 3 ;,

7. Outboard Valve 8'When reactor steam pressure > 1043 psig and/or any turbine stop valve is open.

- When handling irradiated fuel in the secondary containment and during 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.

' e

ATTACHENT B SIGNIFICANT HAZARDS CONSIDERATION RCIC Pump Room Differential Temperature Isolation Commonwealth Edison has evaluated the proposed Technical Specifica-tion Amendment and determined that it does not represent a significant hazards consideration. Based on the criteria for defining a significant hazards consideration extablished in 10 CFR 50.92, operation of LaSalle County Station Units 1 and 2 in accurdance with the proposed amendment will not:

1) Involve a'significant increase in the probability or consequences of an accident previously evaluated or create the possibility of a new or different kind of accident from any accident previously evaluated because: (1) This amendment adds additional instrumentation which is already installed an described in the FSAR. (2) The changes to action by of specification 3.3.2 do not effect the nriginal intent and do not reduce the ability of the isolation system to function as previously evaluated. (3) The changes to notation (b) for Table 3.3.2-1 allow appropriate times to complete the required operability surveillences and ensure redundant systems are operable. In addition the times are consistant with other specifications for redundant equipment being inoperable.

2) Involve a significant reduction in the margin of safety because the changes add additional instrumentation which is already described in the FSAR and does not significantly reduce the ability of the isolation system to be available if required.

Based on the preceding discussion, it is concluded that the proposed system change clearly falls within all acceptable criteria with respect to the system or component, the consequences of previously evaluated accidents will not be increased and the margin of safety will not be decreased.

Therefore, based on the guidance provided in the Federal Register and the criteria established in 10CFR50.92(e), the proposed change does not constitute a significant hazards consideration.

t 9988N

ML20116D368

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