Text

Amends 26 & 14 to Licenses NPF-11 NPF-18,respectively, Revising Method of Calculating Kw Capacity for Electric Heaters in Control Room Emergency Air Makeup Train
	ML20137Y681
Person / Time
Site:	LaSalle
Issue date:	10/02/1985
From:	Butler W; Office of Nuclear Reactor Regulation
To:	;
Shared Package
ML20137Y688	List: ML20137Y681; ML20137Y716;
References
	NUDOCS 8510080069
	Download: ML20137Y681 (55)
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manatu

'o UNITED STATES g

[

g NUCLEAR REGULATORY COMMISSION y

E WASHINGTON, D. C. 20565

%,.....,o COMMONWEALTH EDISON COMPANY i

DOCKET NO. 50-373 i

LA SALLE COUNTY STATION, UNIT 1 AMENDMENT TO FACILITY OPERATING LICENSE

~

Amendment No. 26 License No. NPF-11 1.

The Nuclear Regulatory Comission (the Comission or the NRC) having found that:

i A.

The application for amendment filed by the Commonwealth Edison Company, dated April 17, 1985, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Comission's regulations set forth in 10 CFR Chapter 1; B.

The facility will operate in conformity with the application, the provisions of the Act, and the regulations of the Comission; C.

There is reasonable assurance:

(1) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Comission's regulations set forth in 10 CFR Chapter I; D.

The issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public; and E.

The issuance of this amendment is in accordance with 10 CFR Part 51 of the Comission's regulations and all applicable requirements have been satisfied.

2.

Accordingly, the license is amended by changes to the Technical i

3~

Specifications as indicated in the attachment to this license amendment and paragraph 2.C(2) of Facility Operating License No. NPF-11 is hereby amended to read as follows:

(2) Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A, as revised through Amendment No. 26, and the Environmental Protection Plan contained in Appendix B, are hereby incorporated in the license.

The licensee shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

f A

D P

3.

This amendment is effective as of date of issuance.

FOR THE liUCLEAR REGULATORY COFAISSION

/

C Walter R. Butler, Chief Licensing Branch No. 2 Division of Licensing

Enclosure:

Changes to the Technical Specifications Date of Issuance: OCT 0 2 MB5

l l

ENCLOSURE TO LICENSE AMENDMENT N0. 26 j

FACILITY OPERATING LICENSE NO. NPF-11 l

DOLKET NO. 50-373 t

l Replace the following pages of the Appendix "A" Technical Specifications with the enclosed pages. The revisea pages are identified by Amendment number and contain a vertical line indicating the area of change.

1 i

REMOVE INSERT 3/4 1-13 3/4 1-13 3/4 1-14 3/4 1-14 3/4 2-5 3/4 2-5 3/4 3-9 3/4 3-9 3/4 3-12 3/4 3-12 3/4 3-13 3/4 3-13 3/4 3-14 3/4 3-14 3/43-14(a) 3/4 3-16 3/4 3-16 3/4 3-18 3/4 3-18 3/4 3-21 3/4 3-21 3/4 3-87 3/4 3-87 3/4 6-9 3/4 6-9 j

3/4 6-22 3/4 6-22 3/4 6-24 3/4 6-24 3/4 6-25 3/4 6-25 3/4 6-26 3/4 6-26 3/4 6-27 3/4 6-27 3/4 6-28 3/4 6-28 3/4 6-32 3/4 6-32 3/4 6-34 3/4 6-34 4

3/4 7-6 3/4 7-6 3/4 11-4 3/4 11-4 i

t d

l I

l

_ _ ~, _ _ _

REACTIVITY CONTROL SYSTEM CONTROL ROD 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 i

indicators inoperable, within one hour:

I Determine the position of the control rod by:

1.

(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 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.

Whtn 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 indi-cators by a second licensed operator or other techni-cally qualified member of the unit technical staff.

(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.

4.

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 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.

LA SALLE - UNIT 1 3/4 1-13 Amendment No. 26

REACTIVITY CONTROL SYSTEM LIMITING CONDITION FOR OPERATION (Continued)

ACTION (Continued) b.

In OPERATIONAL 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 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 cl.anges 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 control rod position indicated by the " Full in" position indicator:

1.

Prior to each reactor startup, and 2

Each time a control rod is fuliy inserted.

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

Amendment No. 26 I

LA SALLE - UNIT 1 3/4 1-14 l

i, i

b (a

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m 1.40 I

0,,

8

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-e c

y 1.35 5

2 c

EOC-RPT inoperable E

g

. ~'..

1.30 1.30

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g EOC-RPT Operable y

3

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i.25 1.25 s

1.20 1.20 E

a

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.75

.76

.77

.78

.79

.80

.81

.82

.83

.84

.85

.88 r+

T f

Figure 3.2.3-1 MINIMUM CRITICAL POWER RATIO (MCPR) VERSUS T AT RATED FLOW 2

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 trip 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.

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 Mini-mum OPERABLE Channels per Trip System requirement for one trip system, place the operable channel (s) and/or trip system in the tripped con-l dition* within one hour. The provisions of Specification 3.0.4 are not applicable.

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 ***

l within one hour and take the ACTION required by Table 3.3.2-1.

An inoperable channel need not be placed in the tripped condition where this l

would cause the Trip Function to occur.

In these cases, the inoperable 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 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 that trip system to place in the tripped condition except when this would cause the Trip Function to occur.

- - An inoperable channel need not be placed in the tripped condition where this would cause the Trip Function to occur.

In these cases, the inoperable channel shall be restored to OPERABLE status within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months or the ACTION required by Table 3.3.2-1 for that Trip Function shall be taken.

LA SALLE UNIT-1 3/4 3-9 Amendment No. 26

-=

t TABLE 3.3.2-1 (Continued)

ISOLATION ACTUATION INSTRUMENTATION

?p VALVE GROUPS MINIMUM OPERABLE APPLICABLE m

OPERATED BY CHANNELS PER OPERATIONAL TRIP FUNCTION SIGNAL (a)

TRIP SYSTEM (b)

CONDITION ACTION E

Q 3.

REACTOR WATER CLEANUP SYSTEM ISOLATION a.

A Flow - High 5

1 1,2,3 22 b.

Heat Exchanger Area Temperature - High 5

1/ heat 1, 2, 3 22 l

exchanger c.

Heat Exchanger Area Ventilation AT - High 5

1/ heat 1,2,3 22 l

exchanger d.

SLCS Initiation 5(I)

NA 1,2,3 22 R

e.

Reactor Vessel Water Level - Low Low, Level 2 5

2 1,2,3 22 4.

REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION a.

RCIC Steam Line Flow - High 8

1 1,2,3 22 b.

RCIC Steam Supply Pressure - Low 8, 9(g) 2 1,2,3 22 c.

RCIC Turbine Exhaust Diaphragm Pressure - High 8

2 1,2,3 22 d.

RCIC Equipment Room Temperature - High 8

1 1,2,3 22 e.

RCIC Steam Line Tunnel Temperature - High 8

1 1,2,3 22 k

f.

RCIC Steam Line Tunnel R

A Temperature - High 8

1 1,2,3 22 5

f9) 5 Drywell Pressure - High 9

g.

2 1,2,3 22 NL h.

RCIC Equipment Room l

A Temperature - High 8

1 1,2,3 22

I TABLE 3.3.2-1 (Continued)

(n ISOLATION ACTUATION INSTRUMENTATION N

E VALVE GROUPS MINIMUM OPERABLE APPLICABLE i

OPERATED BY CHANNELS PER OPERATIONAL.

g TRIP FUNCTION SIGNAL (a)

TRIP SYSTEM (b)

CONDITION ACTION 5.

RHR SYSTEM STEAM CONDENSING MODE ISOLATION a.

RHR Equipment Area a Temperature - High 8

1/RHR area 1, 2, 3 22 l

b.

RHR Area Temperature -

High 8

1/RHR area 1, 2, 3 22 l

c.

RHR Heat Exchanger Steam Supply Flow - High 8

1 1,2,3 22 6.

RHR SYSTEM SHUTDOWN COOLING MODE ISOLATION R

a.

Reactor Vessel Water

[

Level - Low, Level 3 6

2 1,2,3 25 0

b.

Reactor Vessel (RHR Cut-in Permissive)

Pressure - High 6

1 1,2,3 25 c.

RHR Pump Suction Flow - High 6

1 1,2,3 25 d.

RHR Area Temperature -

High 6

1/RHR area 1, 2, 3 25 l

e.

RHR Equipment Area AT - High 6

1/RHR area 1, 2, 3 25 l

B.

MANUAL INITIATION 1.

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

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

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

4.

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

5.

Inboard Valves 3,8,9 1/ valve 1,2,3 26 5

6.

Outboard Valves 3,8,9 1/ valve 1,2,3 26 7.

Outboard Valve 8(h) 1/ group 1,2,3 26 Es

TABLE 3.3.2-1 (Continued)

ISOLATION ACTUATION INSTRUMENTATION ACTION ACTION 20 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 with the next 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

ACTION 21 Be in at least STARTUP with the associated isolation valves closed within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months or be in at least HOT SHUTOOWN 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 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 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

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

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 SHUTOOWN 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 required surveillance without placing the channel in the tripped l

condition provided at least one other OPERABLE channel in the same trip system is monitoring that parameter.

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 redun-dant valve is OPERABLE, or place the trip system in the tripped condition.

(c) Also actuates the standby gas treatment system.

(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.

LA SALLE - UNIT 1 3/4 3-14 Amendment No. 26

TABLE 3.3.2-1 (Continued)

NOTES (Continued)

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

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

l (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 trip system in the tripped condition provided that the ambient temperature channels in the same trip systems are operable.

1 i

LA SALLE UNIT-1 3/4 3-]4 (a)

Amendment No.26

i-TABLE 3.3.2-2 (Continued)

ISOLATION ACTUATION INSTRUMENTATION SETPOINTS m

ALLOWABLE i

TRIP FUNCTION TRIP SETPOINT VALUE 4.

REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION a.

RCIC' Steam Line Flow - High 1 290% of rated flow, 178" H O

$ 295% of rated flow, 185" H O 2

2 b.

RCIC Steam Supply Pressure - Low 1 57 psig 1 53 psig c.

RCIC Turbine Exhaust Diaphragm Pressure - High 5 10.0 psig 5 20.0 psig d.

RCIC Equipment Room Temperature - High 1 200*F 1 206*F e.

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

RCIC Steam Line Tunnel A Temperature - High

< 117*F

< 123*F q

g.

Drywell Pressure - High 51.69psig i1.89psig

+

h.

RCIC Equipment Room A~ Temperature - High 1 120*F 5 126*F w

5.

RHR SYSTEM STEAM CONDENSING MODE ISOLATION a.

RHR Equipment Area A Temperature - High 1 50*F 5 56"F b.

RHR Area Cooler Temperature -

High 1 200*F 1 206*F l

c.

RHR Heat Exchanger Steam Supply Flow - High 1 123" H O 1 128" H O 2

2

=

2 1

g i

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

A.

AUTOMATIC INITIATION 1.

PRIMARY CONTAINMENT ISOLATION a.

Reactor Vessel Water Level 1)

Low, Level 3 NA11.gs13(,),,

2)

Low Low, Level 2 b.

Drywell Pressure - High 1 13 c.

Main Steam Line 1)

Radiation - High(b) 1 1.0*/< 13,,,

2)

Pressure - Low

< 1.0*R 13 3)

Flow - High 7 0.5* 6 13(a),,

d.

Main Steam Line Tunnel Temperature - High RA

e.

Condenser Vacuum - Low NA f,

Main Steam Line Tunnel A Temperature - High NA 2.

SECONDARY CONTAINMENT ISOLATION ReactorBuilding(gntExhaustPlenum

< 13(,)

a.

Radiation - High b.

Drywell Pressure - High 5 13 ReactorVesselWaterLevel-Low, Level (f) 513(*)

< 13 c.

d.

Fuel Pool Vent Exhaust Radiation - High 3.

REACTOR WATER CLEANUP SYSTEM ISOLATION a.

A Flow - High 1 13(a)##

b.

Heat Exchanger Area Temperature - High NA c.

Heat Exchanger Area Ventilation AT-High NA d.

SLCS Initiation NA e.

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

j 4.

REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION l

a.

RCIC Steam Line Flow - High

< 13(a) N b.

RCIC Steam Supply Pressure - Low i 13(*)

i c.

RCIC Turbine Exhaust Diaphragm Pressure - High WA 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 l

h.

RCIC Equipment Room a Temperature - High NA g

5.

RHR SYSTEM STEAM CONDENSING MODE 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 1

LASALLE UNIT-1 3/4 3-18 Amendment No. 26

ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS us CHANNEL OPERATIONAL CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH li TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED g

4.

REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION i

a.

RCIC Steam Line Flow - High NA M

Q 1,2,3 b.

RCIC Steam Supply Pressure -

Low NA M

Q 1,2,3 c.

RCIC Turbine Exhaust Diaphragm Pressure - High NA M

Q 1,2,3 d.

RCIC Equipment Room Temperature - High NA M

Q 1, 2, 3 e.

RCIC Steam Line Tunnel Temperature - High NA M

Q 1,2,3 f.

RCIC Steam Line Tunnel A Temperature - High NA M

Q 1,2,3 w

g.

Drywell Pressure - High NA M

Q 1,2,3 1

h.

RCIC Equipment Room A Temperature - High NA M

Q 1,2,3 w

1 5.

RHR SYSTEM STEAM CONDENSING MODE ISOLATION a.

RHR Equipment Area A Temperature - High NA M

Q 1,2,3

'l b.

RHR Area Cooler Temperature -

High NA M

Q 1, 2, 3 c.

RHR Heat Exchanger Steam Supply Flow - High NA M

Q 1,2,3 W

)

t e

INSTRUMENTATION 9

TABLE 3.3.7.11-1 E

RADI0 ACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION i

g MINIMUM CHANNELS q

INSTRUMENT OPERABLE APPLICABILITY ACTION 1.

MAIN CONDENSER OFFGAS TREATMENT SYSTEM EFFLUENT MONITORING SYSTEM a.

Noble Gas Activity Monitor - Providing Alarm and Automatic Termination of Release 1

110 l

2.

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

Hydrogen Monitor 1/ train g

111 w

3.

MAIN STACK MONITORING SYSTEM a.

Noble Gas Activity Monitor 1

110 l

b.

Iodine Sampler 1

113 c.

Particulate Sampler 1

113 d.

Effluent System Flow Rate Monitor 1

114 e.

Sampler Flow Rate Monitor 1

114 4.

CONDENSER AIR EJECTOR RADI0 ACTIVITY MONITOR (Prior to Input to Holdup System) a.

Noble Gas Activity Monitor 1

115 l

S.

SBGTS MONITORING SYSTEM E

a.

Noble Gas Activity Monitor 1

110 b.

Iodine Sampler 1

113 I

E c.

Particulate Sampler 1

113 d.

Effluent System Flow Rate Monitor 1

114

[

e.

Sampler Flow Rate Monitor 1

114 m

1

1 CONTAINMENT SYSTEMS l

SURVEILLANCE REQUIREMENTS l

4. 6.1. 5 Primary Containment Tendons.

The primary containment structural integ-i rity shall be demonstrated at the end of 1, 3 and 5 years after the initial l

structural integrity test (ISIT) and every 5 years thereafter in accordance with' Table 4.6.1.5-1.

The structural integrity shall be demonstrated by:

a.

Determining that a representative sample of at least 13 tendons, 8 hori-zontal 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 year 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/ o f r V tendons and a

t i.

Y2 log t/ o frh p tendons where t is the time interval in years from t

initial tensioning of the tendon to the current testing date and to is the time interval in years from initial tensioning of the tendon to the i

first inspection and is equal to 2 years and the values X1, X2, Y1 and Y2 are in accordance with the values listed in Table 4.6.1.5-2 for the surveil-lance tendon. This test shall include essentially a complete detensioning of tendons selected in accordance with Table 4.6.1.5-1 in which the tendon is detensioned to determine if any wires or strands are broken or damaged.

(

Tendons found acceptable during this test shall be retensioned to their observed lift-off force, i 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 load differs by j

more than 5% from that recorded during installation of tendons, an investi-gation 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 i

tendons are found acceptable, the surveillance program may proceed con-sidering the single deficiency as unique and acceptable. The tendon (s) shall be restored to the required level of integrity. More than one tendon below the predicted bounds out of the original sample population or the i

lift-off force of a selected tendon lying below 90% of the prescribed lower j-limit is evidence of abnormal degradation of the containment structure.

t

)

b.

Performing tendon detensioning and material tests and inspections of a previously stressed tendon wire or strand from one tendon of each group, j

hoop and V, and determining that over the entire length of the removed wire or strand that:

1.

The tendon wires or strands are free of corrosion, cracks and damage.

2.

A minimum tensile strength value of 240 ksi, the guaranteed ultimate j

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 degrada-tion of the primary containment structure.

r

-LA SALLE - UNIT 1 3/4 6-9 Amendment No. 26 i

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 instrumentstion line excess flow check valves shown in Table 3.6.3-1 shall be OPERABLF 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 position,* or c)

Isolate each affected penetration by use of at least one closed manual valve or blind flange.*

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.1.b) or a.1.c) above, and provided that the associated system is declared inoper-able, if applicable, and the appropriate action statements for that system are performed.

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 check valves shown in Table 3.6.3-1 inoperable:

1.

Operation may continue and the provisions of Specifications 3.0.3 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:

a)

The inoperable valve is returned to OPERABLE 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 i

intermittent basis under administrative control.

i LA SALLE - UNIT 1 3/4 6-22 Amendment No. 26 r

t TABLE 3.6.3-1 PRIMARY CONTAINMENT ISOLATION VALVES E

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

(Seconds)

[

a.

Automatic Isolation Valves 1.

Main Steam Isolation Valves 1

5*

l 1821-F022A, B, C, D 1821-F028A, B, C, D 2.

Main Steam Line Drain Valves 1

l 1821-F016

< 15 1821-F019 7 15 IB21-F067A, B, C, D(D) 7 23 3.

Reactor Coolant System Sample Line Valves (c) 3 m

IB33-F019

-<5 l

4 1833-F020 4.

Drywell Equipment Drain Valves 2

1RE024

< 20 1RE025 7 20 1RE026 7 15 1RE029 7 15 5.

Drywell Floor Drain Valves 2

2 20 1RF012 1RF013 6.

Reactor Water Cleanup Suction Valves 5

< 30 IG33-F001(d)

IG33-F004 k

7.

RCIC Steam Line Valves 8

h IE51-F008(*)

< 20 a

1E51-F063

< 15 1E51-F064(I)

_ 15 g

y 1E51-F076

< 15 ER

E TABLE 3.6.3-1 (Continued) u,y PRIMARY CONTAINMENT ISOLATION VALVES A

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

(Seconds)

Automatic Isolation Valves (Continued) 8.

Containment Vent and Purge Valves 4

l IVQO26

< 10**

IVQ027 7 10**

IVQ029 7 10**

IVQO30 7 10**

IVQ031 7 10**

IVQ032 75 IVQO34 510**

m}

IVQ035

<5 IVQO36

{10**

4 IVQ040

< 10**

IVQ042

< 10**

m IVQ043 7 10**

IVQ047 75 1VQ048 75 1VQ050 75 IVQ051 75 IVQ068 75 9.

RCIC Turbine Exhaust Vacuum Breaker 9

R.A.

Line Valves IE51-F080 1E51-F086 10.

LPCS, HPCS, RCIC, RHR Injection Testable Check Bypass Valves (9) 2 N. A.

~

g IE21-F333 g

1E22-F354 IE12-F327A, B, C c+

g IE51-F354 1E51-F355

IABLE 3.6.3-1 (Continued) e2 v>

PRIMARY CONTAINMENT ISOLATION VALVES

?

m MAXIMUM e

ISOLATION TIME e

VALVE FUNCTION AND NUMBER VALVE GROUP (a)

(Seconds)

Automatic Isolation Valves (Continued) 11.

Containment Monitoring Valves 2

<5 1CM017A,B 1CM018A,B 1CM019A,B 1CM020A,B h)

ICM021B(h)

ICM022A(

ICM025A(h)

R ICM026B(h)

ICM027 T

1CM028 i

EX ICM029 1CM030 1CM031 1CM032 1CM033 1CM034 12.

Drywell Pneumatic Valves 2

IIN001A and B

< 30 IIN017 7 22 11N074 7 22 11N075 7 22 IIN031

(

13.

RHR Shutdown Cooling Mode Valves 6

-75 5

a 1E12-F008

< 40 I

1E12-F009 2 40 1E12-F023 2 90 1E12-F053 A and B 7 29 1E12-F099A and B(9)(I)

M

-< 30

TABLE 3.6.3-1 (Continued) g PRIMARY CONTAINMENT ISOLATION VALVES h

MAXIMUM r-ISOLATION TIME VALVE FUNCTION AND NUMBER VALVE GROUP (a)

(Seconds)

Automatic Isolation Valves (Continued) s 14.

Tip Guide Tube Ball Valves (Five Valves) 7 N.A.

l IC51-J004 15.

Reactor Building Closed Cooling Water System Valves 2

< 30 1WR029 IWR040 1WR179 IWR180 16.

Primary Containment Chilled R

Water Inlet Valves 2

l IVP113 A and B

< 90 i

IVP063 A ar.d B 0

17.

Primary Containment Chilled

-7 40 Water Outlet Valves 2

IVP053 A and B

< 40 l

IVP114 A and B 18.

Recirc. Hydraulic Flow Control

-2 90 Line Valvesf9) 2 1833-F338 A and B

-<5 1833-F339 A and B 1833-F340 A and B 1833-F341 A and B 1833-F342 A and B F

1833-F343 A and B 1833-F344 A and B E

IB33-F345 A and B 19.

Feedwater Testable Check Valves 2

N.A.

[

1821-F032 A and B

?

o, TABLE 3.6.3-1 (Continued)

PRIMARY CONTAINMENT ISOLATION VALVES m

MAXIMUM i

ISOLATION TIME e

VALVE FUNCTION AND NUMBER VALVE GROUP (a)

(Seconds) z b.

. Manual Isolation Valves l

1.

1FC086 N.A.

l 2.

1FC113 N.A.

3.

1FC114 N.A.

4.

1FC115 N.A.

5.

1MC027(1)

N.A.

6.

IMC033(1)

N.A.

7.

ISA042(1)

N.A.

8.

ISA046(1)

N.A.

R.

M F

an 1

l

o, TABLE 3.6.3-1 (Continued) v>

PRIMARY CONTAINMENT ISOLATION VALVES

?

E VALVE FUNCTION AND NUMBER d.

Other Isolation Valves

[

1.

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

Reactor Feedwater and RWCU System Return 1821-F010A, B 1821-F065A, B 1G33-F040 3.

Residual Heat Removal / Low Pressure Coolant Injection System i

1E12-F042A, B, C 1E12-F016A, B cn0 1E12-F017A, B 1E12-F027A,Bjg(I) 1E12-F004A, B g 1E12-F021(y)B(3)

IE12-F024p I) 1E12-F302 1E12-F011A, B jg )

f3 1E12-F064A, B g II)

I 1E12-F088A, B, Cfd) 1E12-F025py)B,C 1E12-F030(3)

IE12-F005 Idf II g

IE12-F073A, B 1E12-F074A, B II) 8.

1E12-F055A, B II)

P.

1E12-F036A,B(d) 5 IE12-F311A, B 1E12-F041A,B(kh(k) z 1E12-F050A, B EX

v.

TABLE 3.6.3-1 (Continued)

PRIMARY CONTAINMENT ISOLATION VALVES y,

?

{

g VALVE FUNCTION AND NUMBER Other Isolation Valves (Continued)

Cz 7.

Post LOCA Hydrogen Control

[

1HG001A, 8 1HG002A, B 1HG005A, B 1HG006A, B 8.

Standby Liquid Control System IC41-F004A, B 1C41-F007 9.

Reactor Recirculation Seal Injection 4

R 1B33-F013A, B 4

1833-F017A, B

}

[

10.

Orywell Pneumatic System IIN018 j

But > 3 seconds.

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

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

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

1 (d) Not closed by SLCS actuation.

I (e) Not closed by Trip Functions Sa, b or c, !pecification 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.

(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.

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

(j) Hydraulic leak test at 43.6 psig.

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

r.

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

5 During operation, these lines will be blind flanged using a double 0-ring and a type B leak z

test.

In addition, the packing of these isolation valves will be soap-bubble tested to ensure P

insignificant or no leakage at the containment test pressure each refueling outage.

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

]

first refueling outage.

4

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 1 2.0 Kw when tested in accordance with ANSI N510-1975.

This reading shall include the appropriate correction for variations from 480 volts at the bus.

l a.

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 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 system at a flow rate of 4000 cfm i 10%.

1. 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 Amendment No. 26 i

TABLE 4.11.1-1 (Continued)

TABLE NOTATION The LLD is the smallest concentration of radioactive material in a sample a.

that will be detected with 95% probability with 5% probability of felsely concluding that a blank observation represents a "real" signal.

For a particular measurement system (which may include radiochemical separation):

4.66 sb LLD =

E V

2.22x106 Y

exp (-AAt)

Where:

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

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

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

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

2.22x108 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 for composite samples, and l

At is the elasped time between midpoint of sample collection and time of counting (for plant effluents, not environmental samples).

For batch samples taken and analyzed prior to release, At is taken to be zero.

The value of s used in the calculation of the LLD for a detection s

system shall bH 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.

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 released.

LA SALLE - UNIT 1 3/4 11-4 Amendment No. 26

pa ntoq 4

4 UNITED STATES 8

NUCLEAR REGULATORY COMMISSION WASHINGTON, D. C. 20555 7

\\..... p$

COMMONWEALTH EDIS0N COMPANY DOCKET N0. 50-374 LA SALLE COUNTY STATION, UNIT 2 AMENDMENT TO FACILITY OPERATING LICENSE Amendment No. 14 License ho. NPF-18 1.

The Nuclear Regulatory Comission (the Comission or the NRC) having found that:

A.

The application for amendment filed by the Comonwealth Edison Company, dated April 17, 1985, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's regulations set forth in 10 CFR Chapter I; B.

The facility will operate in conformity with the application, the provisions of the Act, and the regulations of the Comission; C.

There is reasonable assurance:

(1) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Comission's regulations set forth in 10 CFR Chapter I; D.

The issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public; and E.

The issuance of this amendment is in accordance with 10 CFR Part 51 of the Comission's regulations and all applicable requirements have been satisfied.

2.

Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment and paragraph 2.C(2) of Facility Operating License No. NPF-18 is hereby amended to read as follows:

(2) Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A, as revised through Amendment No.

14, and the Environmental Protection Plan contained in Appendix B, are hereby incorporated in the license.

The licensee shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

i 1 3.

This amendment is effective as of date of issuance.

]

FOR THE NUCLEAR REGULATORY C0flillSSIOP i-i Walter R. Butler, Chief Licensing Branch No. 2 Division of Licensing

Enclosure:

Changes to the Technical Specifications Date of Issuance: DCT 03 m i

l i

i a

t i

i k

k j

4 I

i

)

I a

i I

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

ENCLOSURE TO LICENSE AMENDMENT N0. 14 FACILITY OPERATING LICENSE NO. NPF-18 DOCKET NO. 50-374 Replace the following pages of the Appendix "A" Technical Specifications with the enclosed pages. The revised pages are identified by Amendment number and contain a vertical line indicating the area of change.

REN0VE INSERT 3/4 1-13 3/4 1-13 3/4 1-14 3/4 1-14 3/4 2-5 3/4 2-5 3/4 3-9 3/4 3-9 3/4 3-12 3/4 3-12 3/4 3-13 3/4 3-13 3/4 3-14 3/4 3-14 3/4 3-14(a) 3/4 3-16 3/4 3-16 3/4 3-18 3/4 3-18 3/4 3-21 3/4 3-21 3/4 3-87 3/4 3-87 3/4 4-3 3/4 4-3 3/4 6-8 3/4 6-8 3/4 6-25 3/4 6-25 3/4 6-27 3/4 6-27 3/4 6-28 3/4 6-28 3/4 6-29 3/4 6-29 3/4 6-30 3/4 6-30 3/4 6-31 3/4 6-31 3/4 6-35 3/4 6-35 3/4 6-37 3/4 6-37 3/4 7-6 3/4 7-6 3/4 7-21 3/4 7-21 3/4 7-28 3/4 7-28 3/4 11-4 3/4 11-4 4

REACTIVITY CONTROL SYSTEM CONTROL R0D POSITION INDICATION LIMITING CONDITION FOR OPERATION i

3.1.3.7 The control rod position indication system shall be OPERABLE.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 5*.

ACTION:

In OPERATIONAL CONDITION 1 or 2 with one or more control rod position

[

a.

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 control 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.

Hove 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, j2) Verify the position and bypassing of control rod with inoperable " Full in" and/or " Full out" position indi-cators by a second licensed operator or other techni-cally qualified member of. the unit technical staff.

(b)

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

1) Electrically, or

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

4.

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 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.

LA SALLE - UNIT 2 3/4 1-13 Amendment No.14

REACTIVITY CONTROL SYSTEM LIMITING CONDITION FOR OPERATION (Continued)

ACTION:

(Continued) b.

In OPERATIONAL 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.

The provisions of Specification 3.0.4 are not applicable.

c.

i 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 Surveillance Requirement 4.1.3.1.2, and That the control rod position indicator corresponds to the control c.

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.

Each time'a control rod is fully inserted.

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

LA SALLE - UNIT 2 3/4 1-14 Amendment No. 14

r, b

m

=

k 5

e M

1.40 8

0

'C*

b z

H H

2 5

8 1.35 EOC-RPT Inoperable l

g 1.30

.. = '

1.30 m

E

~

b o

Y

~ ~ '

EOC-RPT Operable 1.25 1.25 g

1.20 1.20 N

5

.736.74

.75

.76

.77

.78

.79

.80

.81

.82

.83

.84

.85

.88 T

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

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 trip 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.

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 Minimum OPERABLE Channels per Trip System requirement for one trip system, place the inoperable channe!(s) and/or trip system in the l

tripped condition

within one hour.

The provisions of Specifica-tion 3.0.4 are not applicable.

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 ***

l within one hour and take the ACTION required by Table 3.3.2-1.

"An inoperable channel need not be placed in the tripped condition where thir l

would cause the Trip Function to occur.

In these cases, the inoperable 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 i

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 that trip system to place in the tripped condition except when this would cause the Trip Function to occur.

- - An inoperable channel need not be placed in the tripped condition where this would cause the Trip Function to occur.

In these cases, the inoperable channel shall be restored to OPERABLE status within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months or the ACTION required by Table 3.3.2-1 for that Trip Function shall be taken.

LA SALLE - UNIT 2 3/4 3-9 Amendment No.14

e.

g TABLE 3.3.2-1 (Continued) h ISOLATION ACTUATION INSTRUMENTATION E

VALVE GROUPS MINIMUM OPERABLE APPLICABLE OPERATED BY CHANNELS PER OPERATIONAL E

TRIP FUNCTION SIGNAL (a)

TRIP SYSTEM (b)

CONDITION ACTION

-4 m

3.

REACTOR WATER CLEANUP SYSTEM ISOLATION a.

A Flow - High 5

1 1,2,3 22 b.

Heat Exchanger Area 5

1/ heat 1, 2, 3 22 l

Temperature - High exchanger c.

Heat Exchanger Area 5

g g 9'"

1,2,3 22 l

Ventilation AT - High d.

SLCS Initiation 5(I)

NA 1,2,3 22 w

e.

Reactor Vessel Water A

Level - Low Low, Level 2 5

2 1,2,3 22

{

4.

REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION a.

RCIC Steam Line Flow - High 8

1 1,2,3 22 b.

RCIC Steam Supply Pressure - Low 8, 9(g) 2 1,2,3 22 c.

RCIC Turbine Exhaust Diaphragm Pressure - High 8

2 1,2,3 22 d.

RCIC Equipment Room Temperature - High 8

1 1,2,3 22 y

e.

RCIC Steam Line Tunnel g

Temperature - High 8

1 1,2,3 22 f.

RCIC Steam Line Tunnel A Temperature - High 8

1 1,2,3 22

=

2 g.

Drywell Pressure - High 9(9) 2 1,2,3 22 a

h.

RCIC Equipment Room a Temperature - High 8

1 1,2,3 22 I

t=

g TABLE 3.3.2-1 (Continued) h ISOLATION ACTUATION INSTRUMENTATION G;

VALVE GROUPS MINIMUM OPERABLE APPLICABLE e

OPERATED BY CHANNELS PER OPERATIONAL 5

TRIP FUNCTION SIGNAL (a)

TRIP SYSTEM (b)

CONDITION ACTION a

N 5.

RHR SYSTEM STEAM CONDENSING MODE ISOLATION a.

RHR Equipment Area a Temperature - High 8

1/RHR area 1,2,3 22 l

b.

RHR Area Temperature -

High 8

1/RHR area 1, 2, 3 22 l

c.

RHR Heat Exchanger Steam Supply Flow - High 8

1 1,2,3 22 g

6.

RHR SYSTEM SHUTDOWN COOLING MODE ISOLATION a.

Reactor Vessel Water "4

Level - Low, Level 3 6

2 1,2,3 25 b.

Reactor Vessel (RHR Cut-in Permissive)

Pressure - High 6

1 1,2,3 25 c.

RHR Pump Suction Flow - High 6

1 1,2,3 25 d.

RHR Area Temperature -

High 6

1/RHR area 1,2,3 25 l

e.

RHR Equipment Area AT - High 6

1/RHR area 1, 2, 3 25 l

B.

MANUAL INITIATION

[

1.

Inboard Valves 1,2,5,6,7 1/ group 1,2,3 26 l

2.

Outboard Valves 1,2,5,6,7 1/ group 1, 2, 3 26

[

3.

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

?

4.

Outboard Valves 4(c) (e) 1/ group 1, 2, 3 and **,# 26 5.

Inboard Valves 3,8,9 1/ valve 1, 2, 3 26 6.

Octboard Valves 3,8,9 1/ valve 1,2,3 26 7.

Outboard Valve 8(h) 1/ group 1,2,3 26

TABLE 3.3.2-1 (Continued)

ISOLATION ACTUATION INSTRUMENTATION ACTION STATEMENTS ACTION 20 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 with the next 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

ACTION 21 -

Be in at least STARTUP with the associated isolation valves closed within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months or be 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 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 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

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

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.

TABLE NOTATIONS 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 required surveillance without placing the channel in the tripped condi-l tion provided at least one other OPERABLE channel in the same trip system is monitoring that parameter.

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 re-dundant valve is OPERABLE, or place the trip system in the tripped condition.

(c) Also actuates the standby gas treatment system.

(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 i

reactor vessel water level-low, level 2, signal.

g LA SALLE - UNIT 2 3/4 3-14 Amendment No. 14

(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 trip system in the tripped condition provided that the ambient temperature channels in the same trip systems are OPERABLE.

i

.I l

LA SALLE - UNIT 2 3/4 3-14(a)

Amendment No. 14

v.

5 i

TABLE 3.3.2-2 (Continued) i l

p ISOLATION ACTUATION INSTRUMENTATION SETPOINTS m

ALLOWABLE g

TRIP FUNCTION TRIP SETPOINT VALUE 4.

REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION y

J a.

RCIC Steam Line Flow - High F 290% of rated flow, 178" H O 5 295% of rated flow, 185" H O 2

2 b.

RCIC Steam Supply Pressure - Low 1 57 psig 1 53 psig 4

i c.

RCIC Turbine Exhaust Diaphragm i

Pressure - High 5 10.0 psig 5 20.0 psig i

d.

RCIC Equipment Room Temperature - High

-< 200*F

< 206*F e.

RCIC-Steam Line Tunnel i

Temperature - High 5 200*F 5 206*F w

f.

RCIC Steam Line Tunnel i

1 A Temperature - High 1 117*F

$ 123*F ll w

g.

Drywell Pressure - High 5 1.69 psig 5 1.89 psig g

h.

RCIC Equipment Room a Temperature - High 5 120*F 5 126*F 5.

RHR SYSTEM STEAM CONDENSING MODE ISOLATION J

i a.

RHR Equipment Area a Temperature - High 5 50*F

$ 56*F a

b.

RHR Area Cooler Temperature -

High 5 200*F 5 206*F t-Ig c.

RHR Heat Exchanger Steam I

Supply Flow - High 5 123" H O 5 128" H 0 2

p a"

5 M

i a

i i

1

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

A.

AUTOMATIC INITIATION 1.

PRIMARY CONTAINMENT ISOLATION a.

Reactor Vessel Water Level 1)

Low, Level 3 N.A.

11.g113(3),a 2)

Low Low, Level 2 b.

Drywell Pressure - High 113 c.

Main Steam Line 1)

Radiation - High(b)

<1.0*/<13(a)**

72.0*/713((a),,

2)

Pressure - Low 70.5*/713 a)**

3)

Flow - High d.

Main Steam Line Tunnel Temperature - High N.A.

e.

Condenser Vacuum - Low N.A.

f.

Main Steam Line Tunnel a Temperature - High N.A.

2.

SECONDARY CONTAINMENT ISOLATION ReactorBuilding(gntExhaustPlenum

<13,a) a.

C Radiation - High b.

Drywell Pressure - High 713(a))

ReactorVesselWaterLevel-Low, Level (g) 713((a) c.

-113 d.

Fuel Pool Vent Exhaust Radiation - High 3.

REACTOR WATER CLEANUP SYSTEM ISOLATION a.

A Flow - High

<13(a)##

b.

Heat Exchanger Area Temperature - High R.A.

c.

Heat Exchanger Area Ventilation AT-High N.A.

d.

SLCS Initiation N.A e.

Reactor Vessel Water Level - Low Low, Level 2 113(a) 4.

REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION a.

RCIC Steam Line Flow - High

<13(a)###

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.

e.

RCIC Steam Line Tunnel Temperature - High N.A.

f.

RCIC Steam Line Tunnel ATemperature - High N.A.

g.

Drywell Pressure - High N.A.

h.

RCIC Equipment Room a Temperature - High N.A.

l 5.

RHR SYSTEM STEAM CONDENSING MODE ISOLAT @

a.

RHR Equipment Area ATemperature - High N.A.

j 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 Amendment No. 14

e.

g TABLE 4.3.2.1-1 (Continued)

ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL OPERATIONAL CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH

_E TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED

.A m

4.

REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION a.

RCIC Steam Line Flow - High NA H

Q 1,2,3 b.

RCIC Steam Supply Pressure -

Low NA M

Q 1,2,3 c.

RCIC Turbine Exhaust Diaphragm Pressure - High NA M

Q 1,2,3 d.

RCIC Equipment Room Temperature - High NA M

Q 1,2,3 e.

RCIC Steam Line Tunnel Temperature - High NA M

Q 1,2,3 w

A f.

RCIC Steam-Line Tunnel W Temperature - High NA M

Q 1,2,3 w

E g.

Drywell Pressure - High NA M

Q 1,2,3 h.

RCIC Equipment Room a Temperature - High NA M

Q 1,2,3 g

5.

RHR SYSTEM STEAM CONDENSING MODE ISOLATION a.

RHR Equipment Area W Temperature - High NA M

Q 1,2,3 b.

RHR Area Cooler Temperature -

High NA M

Q 1,2,3 c.

RHR Heat Exchanger Steam Supply Flow - High NA M

Q 1,2,3

.E a

?.

E i

e.

g TABLE 3.3.7.11-1 RADI0 ACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION l;;

MINIMUM CHANNELS INSTRUMENT OPERABLE APPLICABILITY ACTION czU 1.

MAIN CONDENSER OFFGAS TREATMENT SYSTEM N

EFFLUENT MONITORING SYSTEM a.

Noble Gas Activity Monitor - Providing Alarm and Automatic Termination of Release 1

110 2.

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

Hydrogen Monitor 1/ train 111

{

3.

MAIN STACK MONITORING SYSTEM w

a.

Noble Gas Activity Monitor 1

110 l

c'o b.

Iodine Sampler 1

113 c.

Particulate Sampler 1

113 d.

Effluent System Flow Rate Monitor 1

114 e.

Sampler Flow Rate Monitor 1

114 4.

CONDENSER AIR EJECTOR RADIOACTIVITY MONITOR (Prior to Input to Holdup System) a.

Noble Gas Activity Monitor 1

115 t

5.

SBGTS MONITORING SYSTEM a.

Noble Gas Activity Monitor 1

110 g

b.

Iodine Sampler 1

113 I

e c.

Particulate Sampler 1

113 5

d.

Effluent System Flow Rate Monitor 1

114 y

i e.

Sampler Flow Rate Monitor 1

114 e

h

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.

The indicated recirculation loop flow differs by more than 10% from a.

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.

The indicated diffuser-to-lower plenum differential pressure of any c.

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:

1 The indicated recirculation loop flow in the operating loop differs a.

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.

The indicated diffuser-to-lower plenum differential pressure of I

c.

any individual jet pump differs from established single recirculation loop by more than 10%.

LA SALLE - UNIT 2 3/4 4-3 Amendment No.14

a--

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.

ACTION:

a.

With more 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 SHUTOOWN 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 Containment Tendons.

The primary containment structural integrity shall be demonstratei at the end of 1, 3, and 5 years after the l

initial structural integrity test (ISIT) and every 5 years thereaf ter in accordance with Table 4.6.1.5-1.

The structural integrity shall be demon-i 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 l

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 Y2 log t/t for hoop tendons where t is the time 18terval 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 t8thefirstinspectionandisequalto4 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 Amendment No.14

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; 3)

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 position,* or c)

Isolate each affected penetration by use of at least one closed manual valve or blind flange.*

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.1.b) or a.1.c) above, and provided that the associated system is declared inoper-able, if applicable, and the appropriate action statements for that system are performed.

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 , o

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 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:

a)

The inoperable valve is returned to OPERABLE 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 intermittent basis under administrative control.

LA SALLE - UNIT 2 3/4 6-25 Amendment No. 14 4

TABLE 3.6.3-1 (n

PRIMARY CONTAINMENT ISOLATION VALVES 5

m MAXIMUM ISOLATION TIME VALVE FUNCTION AND NUMBER VALVE GROUP (a)

(Seconds) a.

Automatic Isolation Valves 1.

Main Steam Isolation Valves 1

5*

l 2821-F022A, B, C, D 2821-F028A, B, C, D 2.

Main Steam Line Drain Valves 1

g 2B21-F016

< 15 2B21-F019 7 15 2B21-F067A, B, C, D(b) 3.

Reactor Coolant System Sample

~i 23 Line Valves (c) 3

< 5 2833-F019 cn g

e',,

2B33-F020 1

4.

Drywell Equipment Drain Valves 2

2RE024

< 20 2RE025 7 20 2RE026 7 15 2RE029 7 15 5.

Drywell Floor Drain Valves 2

7 20 2RF012

~

2RF013 6.

Reactor Water Cleanup Suction Valves 5

< 30 2G33-F001(d)

~

2G33-F004 y

7.

RCIC Steam Line Valves 8

k 2E51-F008(*)

< 20 2E51-F063 7 15 5

2E51-F064(I)

< 15 I

E 2E51-F076 i 15 ff) 1 2E51-F091

{15 l

1 m

-. -. ~.. _.

TABLE 3.6.3-1 (Continued)

PRIMARY CONTAINMENT ISOLATION VALVES v.?

r-m MAXIMUM ISOLATION TIME VALVE FUNCTION AND NUMBER VALVE GROUP (a)

E (Seconds)

Q Automatic Isolation Valves (Continued) ro 8.

Containment Vent and Purge Valves 4

I 2VQO26

< 10**

2VQO27 7 10**

2VQO29 7 10**

2VQO30 7 10**

2VQO31 7 10**

2VQO32 7 5 2VQO34 7 10**

2VQ035 i

7 5 R

2VQO36 2VQ040 310**

< 10**

T 2VQ042 7 10**

y 2VQ043 2VQ047 510**

< 5 2VQ048 7 5 2VQ050 7 5 2VQ051 7 5 2VQ068 i 5 9.

RCIC Turbine Exhaust Vacuum Breaker 9

H.A.

Line Valves 2E51-F080 i

i 2E51-F086 10.

LPCS, HPCS, RCIC, RHR Injection g

Testable Check Bypass ValvesI9) l N.A.

N.A.

2 Me b2

TABLE 3.6.3-1 (Continued) 5 PRIMARY CONTAINMENT ISOLATION VALVES m?;;;

MAXIMUM ISOLATION TIME VALVE FUNCTION AND h0MBER VALVE GROUP (a)

(Seconds)

Automatic Isolation Valves (Continued) 11.

Containment Monitoring Valves 2

< 5 2CM017A,B 2CM018A,B 2CM019A,6 2CM020A,B 2CM021B(h) h)

2CM022A((h) 2CM025A 2CM026B(h) wD 2CM027 T

2CM028 m

2CM029 2CM030 2CM031 2CM032 2CM033 2CM034 12.

Drywell Pneumatic Valves 2

2IN001A and B

< 30 2IN017 7 22 1

2IN074 7 22 21N075 7 22 2IN031 7

i g

13.

RHR Shutdown Cooling Mode Valves 6

- 5 2E12-F008

< 40 l

E 2E12-F009 7 40 8

5 2E12-F023 2 90

?+

2E12-F053 A and B 7 29 f

2E12-F099A and B(9)(i) 1 g

-< 30

0..

3 TABLE 3.6.3-1 (Continued) 9 m

PRIMARY CONTAINMENT ISOLATION VALVES

?g MAXIMUM ISOLATION lime VALVE FUNCTION AND NUMBER VALVE GROUP (a)

(Seconds) l Automatic Isolation V

'tinued) t

14. Tip Guide Tube Ball Valves (Five Valves) 7 N.A.

l 2C51-J004 15.

Reactor Building Closed Cooling Water System Valves 2

2WR029

-< 30 2WR040 2WR179 2WR180 R

16.

Primary Containment Chilled

[

Water Inlet Valves 2

a 2VP113 A and B

< 90 I

o 2VP063 A and B

< 40 17.

Primary Containment Chilled Water Outlet Valves 2

2VP053 A and B 2VP114 A and B

~< 40 l

18.

Recirc. Hydraulic Flow Control

- 90 Line Valves (9) 2 2B33-F338 A and B

- 5 2833-F339 A and B 2833-F340 A and B 2833-F341 A and B

(

2B33-F342 A and B 4

=

2833-F343 A and B E

2833-F344 A and B 2B33-F345 A and B 19.

Feedwater Testable Check Valves 2

N.A.

.[

2821-F032 A and B

TABLE 3.6.3-1 (Continued) m PRIMARY CONTAINMENT ISOLATION VALVES

?

l E

MAXIMUM ISOLATION TIME h

VALVE FUNCTION AND NUMBER VALVE GROUP (a)

(Seconds) 5 b.

Manual Isolation Valves l

~

1.

2FC086 N.A.

2.

2FC113 N.A.

3.

2FC114 N.A.

4.

2FC115(1)

N.A.

5.

2MC027 N.A.

6.

2MC033(1)

N.A.

7.

2SA042(1)

N.A.

8.

2SA046(1)

N.A.

R.

O 1

l F

2e M

O

O.

TABLE 3.6.3-1 (Continued) y:>

g PRIMARY CONTAINMENT ISOLATION VALVES VALVE FUNCTION AND NUMBER d.

Other Isolation Valves

[

1.

MSIV Leakage Control System I) 2E32-F001A, E, J, N i

2.

Reactor Feedwater and RWCU System Return 2821-F010A, B 2B21-F065A, B 2G33-F040 l

3.

Residual Heat Removal / Low Pressure Coolant Injection System

,1 2E12-F042A, B, C cn 2E12-F016A,-B O

2E12-F017A,-B 2E12-F004A,B)g(I) g 2E12-F027A, B 1

Id) 2E12-F024pS)B 2E12-F021 i

2E12-F302(d)

I3 IIg )

2E12-F064A, B 2E12-F011A, B II) 2E12-F088A, B, C 2E12-F025py)B,C(d) 4 2E12-F030 2E12-F005(3) 1 k

2E12-F073A,B(d) f i

3) 2E12-F074A, B II)

I 2E12-F055A, B I

"k Id) 2E12-F036A, BId) 5 2E12-F311A, B 2E12-F050A,B(kh(k) 2E12-F041A, B z

P 4

v.

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

h VALVE FUNCTION AND NUMBER 7

Other Isolation Valves (Continued) g 7.

Post LOCA Hydrogen Control N

2HG001A, 8 N

2HG002A, B 2HG005A, B 2HG006A, B 8.

Standby Liquid Control System 2C41-F004A, B 2C41-F007 9.

Reactor Recirculation Seal Injection R

2833-F013A, B 2833-F017A, B' J,

10. Drywell Pneumatic Valves 2IN018 TABLE NOTATIONS

But > 3 seconds.

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

(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.

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

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

g (h) Opens on an isolation signal.

Valves will be open during Type A test.

No Type C test required.

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

(j) Hydraulic leak test at 43.6 psig.

s

[

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

,o (1) These penetrations are provided with removable spools outboard of the outboard isolation valve.

Dtring operation, these lines will be blind flanged using a double 0-ring and a type B leak a

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 refueling outage.

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.

This reading shall include the appropriate correction for variations from 400 volts at the bus.

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 N510-1975 while operating the system at a flow rate of 4000 cfm i 10%.

Aftegeach complete or partial replacement of a charcoal"adsorber f.

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 i 10%.

i 5

i "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.

LA SALLE UNIT 2 3/4 7-6 Amendment No.14

1 TABLE 3.7.5.4-1 (Continued)

FIRE H0SE STATIONS LOCATION PROTECTED AREA ELEVATION IDENTIFICATION HOSE RACK Unit 2 Fire Hose Stations (Continued) j

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 j

Zone 8C1 1

8C5 l

25.

Zone 8C4 Zone 8C4 673'0" F 366 l

Zone 8C2 26.

Zone 6E Zone 6E 663'0" F 359

)

F 360 F 399 l

F 403 F 404 i

j B.

Unit 1 Fire Hose Stations Required For Unit 2

~g 1.

Area 1 Area 1 843'6" F 101 4

FB 102 l

F 103 F 104 F 105 1

2.

Zone 2B1 Zone 2B1 820'6" FB 108 F 109 F 111 3.

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

Zone 48 Zone 48 786'6" F 151 FB 152 F 153

..! o 5.

Zone 4C2 Zone 4C1 768'0" F 154

{

and 5A3 Zone 4C2 FB 175 Zone 4C3 FB 176 Zone 4C4 Zone 4C5 6.

Zone SA4 Zone SA4 749'0" FB 248 Zone 401 FB 253 Zone 402 Zone 403 7.

Zone SB13 Zone 5B13 731'0" FB 250 Zone SB3 FB 155 i

Zone 4E3 FB 185 l

Zone 4E2 Zone 4E1

?

f LA SALLE - UNIT 2 3/4 7-21 Amendment No.14 l

t

-____.-_,cy-,

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._-.y,.,___..

m.,_.._.,_.._,__._,,__,_._____.._,.___,_-,.m.~

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 4.7.99. 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 Specification 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.

Visual 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 each type of snubber shall be performed after 4 months but within 10 months 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 first inser-l 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 i 25%

1 12 months i 25%

2 6 months i 25%

3,4 124 days i 25%

5,6,7 62 days i 25%

8 or more 31 days i 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 Amendment No. 14

i l

TABLE 4.11.1-1 (Continued)

TABLE NOTATION 1

a.

The LLD is the smallest concentration of radioactive material in a sample that will be detected with 95% probability with 5% probability of falsely concluding that a blank observation represents a "real" signal.

1 i

For a particular measurement system (which may include radiochemical j

separation):

4.66 sb LLD =

E V + 2.22x10' Y

exp (-Aat)

Where:

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

microcurie per unit mass or volume),

i s is the standard deviation of the background counting rate or of tNecountingrateofablanksampleasappropriate(ascountsper minute),

1 t

l l

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

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

i j

2.22x108 is the number of transformations per minute per microcurie, Y is the fractional radiochemical yield (when applicable),

j A is the radioactive decay constant for the particular radionuclide and I

for composite samples, and I

z At is the elasped time between midpoint of sample collection and time of counting (for plant effluents, not environmental samples).

j For bat ^ samples taken and analyzed prior to release, at is taken to be j

zero.

i i

The value of s used in the calculation of the LLD for a detection g

j system shall b5 based on the actual observed variance of the back-ground counting rate or of the counting rate of the blank samples j

(as appropriate) rather than on an unverified theoretically predicted variance.

Typical values of E, V, Y, and at shall be used in the l

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 released.

1 LA SALLE - UNIT 2 3/4 11-4 Amendment No.14

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

ML20137Y681

Text

Enclosure:

Enclosure:

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