Text

Amend 151 to License DPR-35,changing TS to Support 24-month Fuel Cycle
	ML20065H437
Person / Time
Site:	Pilgrim
Issue date:	04/06/1994
From:	Butler W; Office of Nuclear Reactor Regulation
To:	;
Shared Package
ML20065H441	List: ML20065H437; ML20065H443;
References
	NUDOCS 9404150007
	Download: ML20065H437 (45)
	v • d • e

o orco

,q 2

UNITED S1 ATES 5-i NUCLEAR REGULATORY COMMISSION

..... j/

t WASHINGTON, D.C. 2055M)o01 y

H0STON EDIS0N COMPANY DOCKET N0. 50-293 PILGRIM NUCLEAR POWER STATION AMENDMENT TO FACILITY OPERATING LICENSE Amendment No.151 License No. DPR-35 1.

The Nuclear Regulatory Commission (the Commission or the NRC) has found that:

A.

The applications for amendment filed by the Boston Edison Compuy (the licensee) dated June 7, 1993, August 9, 1993, and December 10, 1993, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations; B.

The facility will operate in conformity uith the application, the provisions of the Act, and the rules and regulations of ti.e Commission; C.

There is reasonable assurance:

(i) 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 Commission's regulations; 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 Commission's regulations and all applicable requirements have been satisfied.

2.

Accordingly, the license is amended by changes to the Technical Specifica-tions as indicated in the attachment to this license amendment, and paragraph 3.8 of Facility Operating License No. DPR-35 is hereby amended to read as follows:

9404150007 940406 PDR ADOCK 05000293 l

P PDR

~ Technical Specifications j

The Technical Specifications contained in Appendix A, as revised through Amendment No. 151, are hereby incorporated in the license. The iicensee shall operate the facility in accordance with the Technical Specifications.

3.

This amendment is effective as of the date of issuance.

Implementation of the extended surveillance intervals will in some cases be put into effect within 90 days.

For instrumentation requiring setpoint changes, implementation of the extended surveillance intervals will not be put into effect until the changes are made.

j FOR THE NUCLEAR REGULATORY COMMISSION

/

b V

Walter R. Butler, Director l

Project Directorate I-3 Division of Reactor Projects - I/II Office of Nuclear Reactor Regulation

Attachment:

Changes to the Technical i

Specifications Date of Issuance: April 6, 1994 i

ATTACHMENT TO LICENSE AMENDMENT N0.151 FACILITY OPERATING LICENSE NO. OPR-35 DOCKET N0. 50-293 Replace the following pages of the Appendix A Technical Specifications with the attached pages. The revised pages are identified by Amendment number and contain vertical lines indicating the area of change.

Remove Insert 4

4 Sa 5a 27 27 29 29 32 32 40 40 45 45 46a 46a 47 47 48 48 49 49 50 50 50a 50a 53 53 53a 53a 55a 55a 59a 59a-60 60 61 61 62 62 63 63 64-64 68 68 69 69 77 77 125b 125b 137a 137a 137b 137b 137c 137c 158 158 1588 1588 158C 158C 169-169 172 172 i

173 173 190 190 193 193 193a 193a 194a 194a 196 196 197 197 201 201 4

l.0 -DEFINITIONS (Cont'd) 1.

At least one door in each access opening is closed.

2.

The standby gas treatment system is operable.

3.

All automatic ventilation system isolation valves are operable or secured in the isolated position.

O.

Operatino Cycle - Interval between the end of one refueling outage and the end of the next subsequent refueling outage.

P.

Refuelino Frecuencies 1.

Refuelino Outaag - Refueling outage is the period of time between the shutdown of the unit prior to a refueling and the startup of the plant after that refueling.

For the purpose of designating frequency of testing and surveillance, a refueling outage shall mean a regularly scheduled outage; however, where such outages occur within 11 months of completion of the previous refueling outage, the required surveillance testing need not be performed until the next regularly scheduled outage (Definitions U and V apply}.

2.

Refuelino Interval - Refueling interval applies only to ASME Code,Section XI IWP and IWV surveillance tests.

For the purpose of designating frequency of these code tests, a refueling interval shall mean at least once every 24 months.

Q.

Alteration of the Reactor Core - The act of moving any component in i

the region above the core support plate, below the upper grid and within the shroud.

Normal control rod movement with the control rod drive hydraulic system is not defined as a core alteration. Normal movement of in-core instrumentation is not defined as a core I

alteration.

H 7

R.

Reactor Vessel Pressure - Unless otherwise indicated, reactor vessel pressures listed in the Technical Specifications are those measured j

by the reactor vessel steam space detectors.

S.

Thermal Parameters 1.

Minimum Critical Power Ratio (MCPR) - the value of critical power ratio associated with the most limiting assembly in the i

reactor core.

Critical Power Ratio (CPR) is the ratio of that power in a fuel assembly, which is calculated to cause some point in the assembly to experience boiling transition, to the actual assembly operating' power.

2.

Transition Boilino - Transition boiling means the boiling regime between nucleate and film boiling.

Transition boiling is the regime in which both nucleate and film boiling occur intermittently with neither type being completely stable.

3.

Total Peakina Factor - The ratio of the fuel rod surface heat flux to the heat flux of an average rod in an identical geometry fuel assembly operating at the core average bundle power.

Amendment No. 15 149,151 4

l.0 DEFINITIONS (Continued)

U.

Surveillance Frecuency - Each Surveillance Requirement shall be performed within the specified surveillance interval with a maximum allowable extension not to exceed 25 percent of the specified surveillance interval.

The Surveillance Frequency establishes the limit for which the specified time interval for Surveillance Requirements may be extended.

It permits an allowable extension of the normal surveillance interval to facilitate surveillance schedule and consideration of plant operating conditions that may not be suitable for conducting the surveillance; e.g., transient conditions or other ongoing surveillance or maintenance activities.

It is not intended l

that this provision be used repeatedly as a convenience to extend surveillance intervals beyond that specified for surveillances that are not performed during refueling outages. The limitation of Definition "U" is based on engineering judgment and the recognition that the most probable result of any particular surveillance being performed is the verification of cor.fnrmance with the Surveillance Requirements.

This provision is suMicient to ensure that the reliability ensured through surveillance activities is not significantly degraded beyond that obtained from the specified surveillance interval.

V.

Surveillance Interval - The surveillance interval is the calendar time between surveillance tests, checks, calibrations, and examinations to be performed upon an instrument or component when it is required to be operable. These tests may be waived when the instrument, component, or system is not required to be operable, but the instrument, component, or system shall be tested prior to being declared operable. The operating cycle interval is 24 months and l

the 25% tolerance given in Definition "U" is applicable. The refueling interval is 24 months and the 25% tolerance specified in definition "U" is applicable.

W.

Fire Suooression Water Systen - A fire suppression water system shall consist of:

a water source (s); gravity tank (s) or pump (s);

i and distribution piping with associated sectionalizing control or isolation valves.

Such valves shall include hydrant post indicator valves and the first valve ahead of the water flow alarm device on each sprinkler, hose standpipe or spray system riser.

X.

Stacoered Test Basis - A staggered test basis shall consist of:

(a) a test schedule for n systems, subsystems, trains, or other designated components obtained by dividing the specified test interval into D equal subintervals; (b) the testing of one system, subsystem, train or other designated components at the beginning.of each subinterval.

Y.

Source Check - A source check shall be the qualitative assessment of channel response when the channel sensor is exposed to a radioactive source.

Amendment No. 42, 89, 128, 149, 151 Sa

PNPS Tabin 3.1.1 REACTOR PROTECTION SYSTEM fSCRAM) INSTRUMENTATION REQUIREMENT Operable Inst.

Modes in Which Function Channels per Trip Function Trip Level Setting Must Be Operable Action (I)

Trio System (1)

Refuel (7) Startup/ Hot Run MinimumlAvail.

Standby 1

1 Mode Switch in Shutdown X

X X

A i

1 Manual Scram X

X X

A IRM 3

4 High Flux 5120/125 of full scale X

X (5)

A 3

4 Inoperative X

X (5)

A APRM 2

3 High Flux (15)

(17)

X A or B 2

3 Inoperative (13)

X X(9)

X A or B 2

3 High Flux (15%)

515% of Design Power X

X (16)

A or B 2

2 High Reactor Pressure 51063.5 psig X(10)

X X

A 2

2 High Drywell Pressure 52.22 psig X(8).

X(8)

X A

2 2

Reactor low Water Level 211.7 In. Indicated Level X

X X

A SDIV High Water level:

538 Gallons X(2)

X X

A 2

2 East 2

2 West 2

2 Main Condenser low Vacuum 223 In. Hg Vacuum X(3)

X(3)

X A or C 2

2 Main Steam Line High 57x Normal Full Power Radiation Background (18)

X X

X(18)

A or C 4

4 Main Steam Line Isolation Valve Closure

$10% Valve Closure X(3)(6)

X(3)(6)

X(6)

A or C 2

2 Turbine Control Valve 2150 psig Control Oil Fast Closure Pressure at Acceleration Relay X(4)

X(4)

A or D 4

4 Turbine Stop Valve 510% Valve Closure X(4)

X(4)

A or D Closure

_ Amendment No.15r-421-86 -92,-117,133, 147,151 27 1

1 NOTES FOR TABLE 3.1.1 (Cont'd) 2.

Permissible to bypass, with control rod block, for reactor protection system reset in refuel and shutdown positions of the reactor mode switch.

3.

Permissible to bypass when reactor pressure is 1576 psig.

4.

Permissible to bypass when turbine first stage pressure is 1112 psig.

5.

IRM's are bypassed when APRM's are onscale and the reactor mode switch is in the run position.

l 6.

The design permits closure of any two lines without a scram being initiated.

7.

When the reactor is subcritical, fuel is in the reactor vessel and the reactor water temperature is less than 212*F, only the following trip functions need to be operable:

A.

Mode switch in shutdown B.

Manual scram C.

High flux IRM j

D.

Scram discharge volume high level E.

APRM (15%) high flux scram i

8.

Not required to be operable when primary containment integrity is not required.

9.

Not required while performing low power physics tests at atmospheric pressure during or after refueling at power levels not to exceed 5 MW(t).

10. Not required to be operable when the reactor pressure vessel head is not bolted to the vessel.

11. Deleted

12. Deleted

13. An APRM will be considered inoperable if there are less than 2 LPRM inputs per level or there is less than 50% of the normal complement of LPRM's to an APRM.

l

14. Deleted

15. The APRM high flux trip level setting shall be as specified in the CORE OPERATING LIMITS REPORT, but shall in no case exceed 120% of rated thermal power.

16. The APRM (15%) high flux scram is bypassed when in the run mode.

17. The APRM flow biased high flux scram is bypassed when in the refuel or startup/ hot standby modes.

18. Within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months prior to the planned start of hydrogen injection with the reactor power at greater than 20% rated power, the normal full power radiation background level and associated trip se'tpoints may be changed based on a calculated value of the radiation level expected during the injection of hydrogen.

The background radiation level and associated trip setpoints may be adjusted based on either calculations or measurements of actual radiation levels resulting from hydrogen injection.

The background radiation level shall be determined and associated trip setpoints shall be set within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months of re-establishing normal radiation levels after completion of hydrogen injection and prior to withdrawing control rods at reactor power levels below 20% rated power.

Amendment No. 6, 15, 27, 42, 86, 117, 118, 133, 147,151 29

TABLE 4.1.2 REACTOR PROTECTION SYSTEM (SCRAM) INSTRUMENT CALIBRATION MINIMUM CALIBRATION FREQUENCIES FOR REACTOR PROTECTION INSTRUMENT CHANNELS Instrument Channel Calibration Test (5)

Minimum FrecuenCY 12)

IRM High Flux Comparison to APRM on Controlled Note (4)

Shutdowns Full Calibration Once per Operating Cycle APRM High Flux Output Signal Heat Balance Once every 3 Days Flow Blas Signal Calibrate Flow Comparator and At least Once Every Flow Bias Network 18 Months Calibrate Flow Bias Signal (1)

Every 3 Months LPRM Signal TIP System Traverse Every 1000 Effective Full Power Hours High Reactor Pressure Note (7)

Note (7)

High Drywell Pressure Note (7)

Note (7)

Reactor Low Water Level Hote (7)

Note (7)

High Water Level in Scram Discharge Tanks Note (7)

Note-(7)

Turbine Condenser Low Vacuum Note (7)

Note (7)

Main Steam Line Isolation Valve Closure Note (6)

Note (6)

Main Steam Line High Radiation Standard Current Source (3)

Every 3 Months Turbine First Stage Pressure Permissive Note (7)

Note (7)

Turbine Control Valve Fast Closure Standard Pressure Source Every'3 Months Turbine Stop Valve Closure Note (6)

Note (6)

Reactor Pressure Permissive Note (7)

Note (7) 32 Amendment No. 147, 151

i 3.1 BASES (Cont'd)

Scram Discharoe Instrument Volume The control rod drive scram system is designed so that all of the water that is discharged from the reactor by a scram can be accommodated in the discharge piping.

The two scram discharge volumes have a capacity of 48 gallons of water each and are at the low points of the scram discharge piping.

During normal operation the scram discharge volume system is empty; however, should it fill with water, the water discharged to the piping could not be accommodated which would result in slow scram times or partial control rod insertion. To preclude this occurrence, redundant and diverse level detection devices in the scram discharge instrument volumes have been provided. The instruments are set to alarm, initiate a control rod block, and scram the i

reactor at three different progressively increasing water levels in the volume.l As indicated above, there is sufficient volume in the piping to accommodate the scram without impairment of the scram times or amount of insertion of the control rods.

This function shuts the reactor down while sufficient volume remains to accommodate the discharged water and precludes the situation in which a scram would be required but not be able to perform its function properly.

4.1 BASES The reactor protection system is made up of two independent trip systems.

There are usually four channels to monitor each parameter with two channels in each trip system. The outputs of the channels in a trip system are combined in a logic so that either channel will trip that trip system. The tripping of both trip systems will produce a reactor scram. The system meets the intent of IEEE-279 for nuclear power plant protection systems.

Specified surveillance intervals and surveillance and maintenance outage times have been determined in i

accordance with General Electric Company Topical Report NEDC-30851P-A,

" Technical Specification Improvement Analysis for BWR Reactor Protection System," as approved by the NRC and documented in the safety evaluation report (NRC letter to T. A. Pickens from A. Thadani dated July 15,1987).

A comparison of Tables 4.1.1 and 4.1.2 ' indicates that two instrument channels have not been included in the latter table. These are: mode switch in i

shutdown and manual scram. All of the devices or sensors associated with these scram functions are simple on-off switches and, hence, calibration during operation is not applicable (i.e., the switch is either on or off).

The sensitivity of LPRM detectors decreases with exposure to neutron flux at a slow and approximately constant rate. This is compensated for in the APRM system by calibrating every three days using heat balance data and by 4

calibrating individual LPRM's every 1000 effective full power hours using TIP traverse data, j

147. 151 40 Amendment No. 42, 133

9 PNPS TABLE 3.2.A INSTRUNENTATION THAT INITIATES PRINARY CONTAINNENT ISOLATION Operable Instrument Channels Per Trio System f])

Minimum Available Instrument Trip level Settina Action (2) 2(7) 2 Reactor low Water Level 211.7" indicated level (3)

A and D l

1 1

Reactor High Pressure 5110 psig D

2 2

Reactor Low-Low Water Level at or above -46.3 in.

A indicated level (4) 2 2

Reactor High Water Level 545.3" indicated level (5)

B 2(7) 2 High Dry = il Pressere

$2.22 psig A

2 2

High Radiation Main Steam

$7 times normal rated B

Line Tunnel (9) full power background 2

2 Low Pressure Main Steam Line 2810 psig (8)

B 2(6) 2 High Flow Main Steam Line 5136% of rated steam flow B

l 2

2 Main Steam Line Tunnel 0

Exhaust Duct High Temperature

$170 F B

2 2

Turbine Basement Exhaust Duct High Temperature

$150 F B

1 1

Reactor Cleanup System High Flow

$300% of rated flow C

2 2

Reactor Cleanup System l

High Temperature

$150 F C

0 l

Amendment No. 86, 147, 150, 151 45

3.' Instrument set point corresponds to 137.96 inches above top of active fuel, l

4.

Instrument set point corresponds to 79.96 inches above top of active fuel.

l 5.

Not required in Run Mode (bypassed by Mode Switch).

6.

Two required for each steam line.

7.

These signals also start SBGTS and initiate secondary containment isolation.

8.

Only required in Run Mode (interlocked with Mode Switch).

9.

Within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months prior to the planned start of hydrogen injection with the reactor power at greater than 20% rated power, the normal full power radiation background level and associated trip setpoints may be changed based on a calculated value of the radiation level expected during the injection of hydrogen.

The backgroJnd radiation level and associated trip setpoints may be adjusted based on either calculations or measurements of actual radiation levels resulting from hydrogen injection.

The background radiation level shall be

. determined and associated trip setpoints shall be set within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months of re-establishing normal radiation levels after completion of hydrogen injection and prior to withdrawing control rods at reactor power levels below 20% rated power.

l l

1 Amendment No. 147, 151 46a 1

PNPS TABLE 3.2.B INSTRUMENTATION THAT INITIATES OR CONTROLS THE CORE AND CONTAINMENT COOLING SYSTEMS Minimum # of Operable Instrument Channels Per Trip System (1)

Trip Function Trip Level Settina Remarks 2

Reactor Low-Low Water Level at or above -46.3 in.

1.

In conjunction with Low -

l indicated level (4)

Reactor Pressure, initiates Core Spray and LPC1.

2.

In conjunction with High Drywell Pressure, 94.4 -

115.6 second time delay and LPCI or Core Spray pump interlock initiates Auto Blowdown (ADS).

3.

Initiates HPCI; RCIC.

4.

Initiates starting of Diesel Cenerators.

2 Reactor High Water Level 5 +45.3" indicated Trips HPCI and RGIC turbines.

l

. level 1

Reactor Low Level

>-151" indicated Prevents inadvertent operation l (inside shroud) level of containment spray during accident condition.

(Indicative of 2/3 core coverage) 2 Containment High Pressure 1.55 $ p $ 1.82 psig Prevents inadvertent operation l.

of containment spray during accident condition.. Instrument is set to trip at or before 1.R2 increasing and reset at or beforc 1.55 decreasing.

Amendment No. 94 151 47 m

.a m

u-u a

- m e-

=--

ur-M

t PNPS TABLE 3.2.B (Cont'd)

INSTRUMENTATION THAT INITIATES OR CONTROLS THE CORE AND CONTAINMENT COOLING SYSTEMS Minianum # of Operable Ins t rursent Channels Per Trio System (1)

Trip Function Trip Level Setting Remarks 2

High Drywell Pressure

$2.22 psig

1. Initiates Core Spray; LPCI; HPCI.

l-

2. In conjunction with Low-Low Reactor Water Level, 94.4 - 115.6 second time l delay and LPCI or Core Spray pump running, initiates Auto Blowdown (ADS)

3. Initiates starting of Diesel Generators'

4. In conjunction with Reactor Low Pressure initiates clos are of HPCI vacuum breaker contairrant isolation valves.

1 Reactor Low Pressure 400 psig i 5 Permissive for Opening Core Spray and

[

LPCI Admission valves.

1 Reactor Low Pressure 5110 psig In conjunction with PCIS signal permits closure of RHR (LPCI) injection valves.

1 Reactor Low Pressure 400 psig 1 5 In conjunction with Low-Low Reactor l

Water Level initiates Core Spray and LPCI.

2 Reactor Low Pressure 900 psig i 5 Prevents actuation of LPCI break detection circuit.

2 Reactor Low Pressure 80 psig i 5 Isolates HPCI and in conjunction with l

liigh Drywell Pressure initiates closure of HPCI vacuum breaker containment isolation valves.

Amendment No. 42;-113, 148,151 48

PNPS TABLE 3.2.B (Cont'd)

INSTRUMENTATION THAT INITIATES OR CONTROLS THE CORE AND CONTAINNENT COOLING SYSTEMS Hinimum # of Operable Instrument thannels Per Trio System (1)

Trio Function Trio Level Settino Remarks 1

Core Spray Pump Start 0.21 < t < 1 sec.

Initiates sequential starting of Timer CSCS pumps on any auto start.

1 LPCI Pump Start Timer 4.16 < t < 5.84 sec.

1 LPCI Pump Start Timer 9.5 < t < 11.5 sec.

1 Auto Blowdown Timer

> 94.4, $115.6 sec.

In conjunction with low Low Reactor Water Level, High Drywell Pressure and LPCI or Core Spray Pump running interlock, initiates Auto Blowdown.

2 ADS Drywell Pressure 9 $ t 5 15.4 min.

Permits starting CS and LPCI l

Bypass Timer pumps and actuating ADS SRV's if RPV water level is low and drywell pressure is not high.

2 RHR (LPCI) Pump Discharge 150 10 psig Defers ADS actuation pending Pressure interlock confination of Low Pressure core cooling system operation.

2 Core Spray Pump Discharge 150 10 psig (LPCI or Core Spray Pump Pressure Interlock running interlock.).

2 Emergency Bus Voltage 20-25% of rated 1.

Permits closure of the Diesel Relay voltage resets Generator to an unloaded at less than or emergency bus.

equal to 50%

l 2.

Permits starting of CSCS 4 I

kV motors.

l Amendment No. 40,-196, 120, 151 49

PNPS TABLE 3.2.8 (Cont'd)

INSTRUNENTATION THAT INITIATES OR CONTROLS THE CORE AND CONTAINNENT COOLING SYSTEMS Minimum # of Operable Instrument Channels Per Trio System (1)

Trio Function Trio Level Setting Remarks 2

Startup Transformer At 0 Volts between

1. Trips Startup Transformer to

[

Loss of Voltage 0.96 5 t 5 1.34 seconds Emergency Bus Breaker.

Time' Delay.

2. Locks out automatic closure of Startup Transformer to Emergency Bus.

i

3. Initiates starting of Diesel Generators in conjunction with loss 'of auxiliary transformer.

4. Prevents' simultaneous starting 1

of CSCS components.

5. Starts load shedding logic for Diesel Operation in conjunction with (a) Low Low Reactor Water.

level and Low Reactor. Pressure "j

or (b) High drywell pressure or (c) Core Standby Cooling System components in service in conjunction with Auxiliary Transformer breaker open.

i

~

l

' Amendment '42,10$,151 50

PHPS TABLE 3.2.B (Cont'd)

INSTRUNENTATION THAT INITIATES OR CONTROLS THE CORE AND CONTAINNENT COOLING SYSTENS Minimum # of Operable Instrument

Channels Per Trio System (1)

Trio Function Trio Level Settina Remarks 2

Startup Transformer 3878.7V

.51% with 10.24

1. Trips Startup Transformer to Degraded Voltage 1 0.36 seconds time delay.

Emergency Bus Breaker.

2. Locks out automatic closure of Startup Transformer to Emergency Bus.

3. Initiates starting of Diesel Generators in conjunction with loss of auxiliary transformer.

4. Prevents simultaneous starting of CSCS components.

5. Starts load shedding logic for Diesel Operation in coajunction with a) Low Low Reactor Water Level and Low Reactor Pressure or b) High drywell pressure or c) Core Standby Cooling System components in' service in conjunction with Auxiliary Transformer breaker open.

J Amendment No. 42, 61, 108, 120,151 50a

7 4

NOTES FOR TABLE 3.2.B 1.

Whenever any CSCS subsystem is required by Section 3.5 to be operable, there shall be two (Note 5) operable trip systems.

If the first column cannot be met for one of the trip systems, that system shall be repaired or the reactor shall be placed in the Cold Shutdown Condition within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after this trip system is made or found to be inoperable.

2.

Close isolation valves in RCIC subsystem.

-3.

Close isolation valves in HPCI subsystem.

4.

Instrument set point corresponds to 79.96 inches above top of active fuel.

l 5.

RCIC has only one trip system for these sensors.

i i

l l

I 53 Amendment No. 105, 148,151.

a PNPS TABLE 3.2.B.1 INSTRUMENTATION THAT MONITORS EMERCENCY BUS VOLTAGE Minimum # of Operable Instrument Channels Per Trip system Function Setting Remarks 1

Emergency 4160V Buses A5 3958. 5V + 0.5%, -0.24%

Alerts Operator to possible 6 A6 Degraded Voltage with 10.24 1 0.36 seconds degraded voltage conditions.

Annunciation (1) seconds time delay Provides permissive to initiate load shedding in conjunction with LOCA signal.

I t

1

.(1)

In the event that tue alarm system is determined inoperable, logging safety related bus voltage every%

commence hour until such time as the alarm is restored to operable status.

l-Amendment No. 42;-61;-198;-120,151 53a

PNPS TABLE 3.2.C-2 CONTROL ROD BLOCK INSTRUMENTATION SETPOINTS Trio Function Trio Setooint APRM Upscale (1) (2)

APRM Inoperative Not Applicable APRM Downscale 2 2.5 Indicated on Scale Rod Block Monitor (Power Dependent)

(1) (3)

Rod Block Monitor Inoperative Not Applicab; Rod Block Monitor Downscale (1) (3)

IRM Downscale 1 5/125 of Fuli k IRM Detector not in Startup Position Not Applicable

~

IRM Upscale s 108/125 of Full Scale IRM Inoperative Not Applicable SRM Detector not in Startup Position Not Applicable SRM Downscale 1 3 counts /second 5

SRM Upscale i 10 counts /second SRM Inoperative Not Applicable Scram Discharge Instrument Volume 117 gallons l

Water Level - High Scram Discharge Instrument Volume -

Not Applicable Scram Trip Bypassed Recirculation Flow Converter - Upscale 1 120/125 of Full Scale Recirculation Flow Converter -

Not Applicable Inoperative Recirculation Flow Converter -

18% Flow Deviation Comparator Mismatch l

(1) The trip level setting shall be as specified in the CORE OPERATING LIMITS REPORT.

(2) When the reactor mode switch is in the refuel or startup positions, the APRM rod block trip setpoint shall be less than or equal to 13%

of rated thermal power, but always less than the APRM flux scram trip setting.

(3) The RBM bypas:; time delay (td2) shall be < 2.0 seconds.

Amendment No. 42, 110, 129, 133, 138,151 55a

vues TABLE 3.2-G INSTRUMENTATION THAT INITIATES RECIRCULATION PUMP TRIP AND ALTERNATE ROD INSERTION t

Minimum Number of Operable or Tripped Instrument Channels i

Per Trio System (1)

Trio Function Trio level Settina 2

High Reactor Dome 1175 5 PSIG l

Pressure 2

Low-Low Reactor 1-46.3"

[

Water level indicated level Actions (1) There shall be two (2) operable trip systems for each function.

i (a)

If the minimum number of operable or tripped instrument channels for one (1) trip system cannot be met, restore the trip system to operable status within 14 days or be in at least hot shutdown within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

(b)

If the minimum operability conditions (1.a) cannot be met for both (2) trip systems, be in at least hot shutdown within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

I I

i Amendment 105.151 59a i

l PNPS TABLE 4.2.A MINIMUM TEST AND CAllBRATION FREQUENCY FOR PCIS Instrument Channel (5)

Instrument Functional Test Calibration Frecuency Instrument Check 1)

Reactor High Pressure (1)

Once/3 months None 2)

Reactor low-Low Water Level Once/3 Months (7)

(7)

Once/ day 3)

Reactor High Water Level Once/3 Months (7)

(7)

Once/ day 4)

Main Steam High Temp.

(1)

Once/3 months None 5)

Main Steam High Flow Once/3 Months (7)

(7)

Once/ day 6)

Main Steam Low Pressure Once/3 Months (7)

(7)

Once/ day 7)

Reactor Water Cleanup High Flow (1)

Or,r.e/3 months Once/ day 8)

Reactor Water Cleanup High Temp.

(1)

Once/J months None Logic System Functional Test (4) (6)

Freauency 1)

Main Steam Line Isolation Vvs.

Once/ operating cycle l

Main Steam Line Drain Vvs.

Reactor Water Sample Vvs.

2)

RHR - Isolation Vv. Control Once/ operating cycle l

Shutdown Cooling Vvs.

Head Spray Discharge to Radwaste 3)

Reactor Water Cleanup Isolation Once/ operating cycle l

4)

Drywell Isolation Vvs.

Once/ operating cycle l

TIP Withdrawal Atmospheric Control Vvs.

Sump Drain Valves 5)

Standby Gas Treatment System Once/ operating cycle Reactor Building Isolation l

Amendment No. 107, 130,151 60

-PNPS o

TABLE 4.2.B MINIMUM TEST AND CAllBRATION FREQUENCY FOR CSCS 1

's.

Instrument Channel Instrument Functional Tes_t Calibration Freauen.c_y Instrument Check 1)

Reactor Water Level (1) (7)

(7)

Once/ day 2)

Drywell Pressure (1) (7)

(7)

Once/ day 3)

Reactor Pressure (1) (7)

(7)

Once/ day 4)

Auto Sequencing Timers NA Once/ operating cycle None 5)

ADS - LPCI or CS Pump Disch.

Pressure Interlock (1)

Once/3 months None 6)

Start-up Transf. (4160V) a.

Loss of Voltage Relays Monthly Once/ operating cycle None b.

Degraded Voltage Relays Monthly

' Once/ operating cycle None 7)

Trip System Bus Power Monitors Once/ operating cycleNA Once/ day 8)

Recirculation System d/p (1)

Once/3 months Once/ day 9)

Core Spray Sparger d/p NA Once/18 months Once/ day l

10)

Steam Line High Flow (HPCI & RCIC)

(1)

Once/3 months None 11)

Steam Line High Temp. (HPCI & RCIC)

(1)

Once/3 months None

12) Safeguards Area High Temp.

(1)

Once/3 months None 13)

RCIC Steam Line Low Pressure (1)

Once/3 months None

14) HPCI Suction Tank Levels (1)

Once/3 months None 15)

Emergency 4160V Buses A5 & A6 Monthly Once/ operating Cycle None Loss of Voltage Relays i

61 Amendment No. 42;-61 -99, 148.151 5

PHPS TABLE 4.2.B HINIMUM TEST AND CALIBRATION FREQUENCY FOR CSCS Logical System Functional Test (4) (6)

Frequency Remarks 1)

Core Spray Subsystem Once/ operating cycle 2)

Low Press. Coolant Injection Subsystem Once/ operating cycle 3)

Containment Spray Subsystem Once/ operating cycle 4)

HPCI Subsystem Once/ operating cycle 5)

HPCI Subsystem Auto Isolation Once/ operating cycle 6)

ADS Subsystem Once/ operating cycle 7)

RCIC Subsystem Auto Isolation Once/ operating cycle 8)

Diesel Generator Initiation once/ operating cycle 9)

Area Cooling for Safeguard System, Once/ operating cycle Amendment No. 130,151 62

W

.s:

1 PNPS TABLE 4.2.C HINIMUM TEST AND CALIBRATION FREQUENCY FOR CONTROL ROD BIDCKS ACTUATION Instrument Channel Instrument Functional Calibration Instrument Check Test APRM - Downscale Once/3 Months once/3 Months once/ Day APRM - Upscale Once/3 Months once/3 Months Once/ Day APRM - Inoperative Once/3 Months Not Applicable Once/ Day, IRM - Upscale.

(2) (3)

Startup or Control Shutdown (2)

IRM - Downscale (2) (3)

Startup or control Shutdown (2) 1RM - Inoperative (2) (3)

Not Applicable (2)

RBM - Upscale Once/3 Months once/6 Months once/ Day RBM - Downscale Once/3 Months once/6 Months once/ Day RBM - Inoperative Once/3 Months Not Applicable Once/ Day SRM - Upscale (2) (3)

Startup or Control Shutdown (2)

SRM - Inoperative (2) (3)

Not Applicable (2)

SRM - Detector Not in Startup Position (2) (3)

Not Applicable (2)

SRM - Downscale

(2) (3)

Startt.p or Control Shutdown (2)

IRM - Detector Not in Startup Position (2) (3)

Not Applicable (2)

Scrca Discharge Instrument Volume Once/3 Months Refuel Not Applicable.

Water Level-High Scrca Discharge Instrument Once/3 Months Not Applicable Not Applicable Volume-Scram Trip Bypassed Racirculation Flow Converter Not Applicable Once/ Operating Cycle Once/ Day l

Racirculation Flow Converter-Upscale Once/3 Months once/3 Months once/ Day Racirculation Flow Converter-Inoperative Once/3 Months Not Applicphie Once/ Day Racirculation Flow converter-comparator Once/3 Months once/3 Months once/ Day Off Limits Racirculation Flow Process Instruments Not Applicable Once/ Operating Cycle Once/ Day g

Loric System Functional Test (4) (6)

System Logic Check Once/ Operating cycle l

Amendment No. 110;-130, 147,151 63

o.

PNPS TABLE 4.2.0 MINIMUM TEST AND CALIBRATION FREQUENCY FOR RADIATION MONITORING SYSTEMS Instrument Channels Instrument Functional Calibration Instrument Check (2)

Test 1)

Refuel Area Exhaust Monitors - Upscale (1)

Once/3 months once/ day 2)

Refuel Area Exhaust Monitors - Downscale (1)

Once/3 months once/ day logic System Functional Test (4) (6)

Freauency 1)

Reactor Building Isalation once/ operating cycle 2)

Standby Gas Treatment System Actuation Once/ operating cycle 4

4 Amendment No. 89r 130,151 64

= - -

=

i BASES:

3.2 In addition to reactor protection instrumentation which initiates a reactnr scram, protective inst!Jmentation has been provided Which initiates action to mitigate the consequences of accidents which are beyond the operator's ability to control, or terminates operator errors before they result in serious consequences.

This set of specifications provides the limiting conditions of operation for the primary system isolation function, initiation of the core cooling systems, control rod block, and standby gas treatment systems.

The objectives of the Specifications are, (i) to assure the effectiveness of the protective instrumentation when required by preserving its capability to tolerate a single failure of any component of such systems even during periods when portions of such systems are out of service for maintenance, and (ii) to prescribe the trip settings required to assure adequate performance. When necessary, one channel may be made inoperable for brief intervals to conduct required functional tests and calibrations.

Some of the settings on the instrumentation that initiate or control core and containment cooling have tolerances explicitly stated where the high and low values are both critical and may have a substantial effect on safety. The set points of other instrumentation, where only the high or low end of the. setting has a direct bearing on safety, are chosen at a level away from the normal operating range to prevent inadvertent actuation of the safety system involved and exposure to abnormal situations.

Actuation of primary containment valves is initiated by protective instrumentation shown in Table 3.2.A which senses the conditions for which i

isolation is requireo.

Such instrumentation must be available whenever primary containment integrity is required.

The instrumentation which initiates primary system isolation is connected in a.

dual bus arrangement.

The low water level instrumentation closes all isolation valves except l

those in Groups 1, 4 and 5.

This trip setting is adequate to prevent core uncovery in the case of a break in the largest line assuming a 60 second valve closing time.

Required closing times are less than this.

The low low reactor water level instrumentation closes the Main Steam Lire Isolation Valves, Main Steam Drain Valves, Recire Sample Valves (Group 1) i activates the CSCS subsystems, starts the emergency diesel generators at,d J

trips the recirculation pumps.

This trip setting level was chosen to be high enough to prevent spurious actuation but low enough to initiate CSCS operation and primary system isolation so that no fuel damage will occur and so that post accident cooling can be accomplished and the guidelines of 10 CFR 100 will not be violated.

For large breaks up to the complete circumferential break of a 28-inch recirculation line and with the trip 4

setting given above, CSCS initiation and primary system isolation are initiated in time to meet the above criteria.

Amendment No. 105, 113,151 68

3.2 BASES (Cont'd)

The high drywell pressure instrumentation is a diverse signal to the water level instrumentation and in addition to initiating CSCS, it causes isolation of Group 2 isolation valves.

For the breaks discussed above, this instrumentation will initiate CSCS operation at about the same time as the low low water level instrumentation; thus the results given above are applicable here also.

The low low water level instrumentation initiates protection for the full spectrum of loss-of-coolant accidents and causes isolation of Group 1 isolation valves.

Venturis are provided in the main steam lines as a means of measuring steam flow and also limiting the loss of mass inventory from the vessel during a steam line break accident.

The primary function of the instrumentation is to detect a break in the main steam line.

For the worst case accident, main steam line break outside the drywell, the steam flow trip setting in conjunction with the flow limiters and main steam line valve closure, limits the mass inventory loss such that fuel is not uncovered, fuel temperatures remain approximately 1000*F and release of radioactivity to the environs,is well below 10 CFR 100 guidelines.

Temperature monitoring instrumentation is provided in the main steam line tunnel and the turbine basement to detect leaks in these areas.

Trips are provided on this instrumentation and when exceeded, cause closure of isolation valves. The setting of 170*F for the main steam line tunnel detector is low enough to detect leaks of the order of 5 to 10 gpm; thus, it is capable of covering the entire spectrum of breaks.

For large breaks, the high steam flow instrumentation is a backup to the temperature instrumentation.

High radiation monitors in the main steam line tunnel have been provided to detect gross fuel failure as in the control rod drop acci-Amendment No. 34, 113,151 69

B 4.2 BASES (Cont'd)

The automatic pressure relief instrumentation can be considered to be a 1 out of 2 logic system and the discussion above applies also.

The instrumentation which is required for the recirculation pump trip and alternate rod insertion systems incorporate analog transmitters.

The transmitter calibration frequency is once per refueling outage, which is consistent with both the equipment capabilities and the requirements for similar equipment used at Pilgrim.

The Trip Unit Calibration and Instrument Functional Test is specified at monthly, which is the same frequency specified for other similar protective devices. An instrument check is specified at once per day; this is considered to be an appropriate frequency, commensurate with the design applications and the fact that the recirculation pump trip and alternate rod insertion systems are backups to existing protective instrumentation.

Control Rod Block and PCIS instrumentation common to RPS instrumentation have surveillance intervals and meintenance outage times selected in accordance with NEDC-30851P-A, Supplements 1 and 2 as approved by the NRC and documented in SERs (letters to D. N. Grace from C. E. Rossi dated September 22, 1988 and January 6, 1989).

A logic system functional test interval of 24 months was selected to l

minimize the frequency of safety system inoperability due to testing and to minimize the potential for inadvertent safety system trips and their attendant transients.

Amendment No. 42, 121, 130, 147,151 77

i w

LIMITING CONDITIONS FOR OPERATION' SURVEILLANCE RE0VIREMENTS 3.6.C.2 Leakaoe Detection Systems 4.6.C.2 Leakaoe Detection Systems-(Cont'd)

(Cont'd) 2.

One channel of a drywell

2. An instrument channel atmospheric particulate calibration at least i

radioactivity monitoring onco per operating 1

system, or cycle.

\\

3.

One channel of a drywell

b. For each required drywell atmospheric gaseous atmospheric radioactivity-radioactivity monitoring monitoring system perform:

system.

I

1. An instrument check at.:

b.

1.

At least one drywell sump least once per day, monitoring system shall be Operable; otherwise, be in

2. An instrument functional Hot Shutdown within the test at least once per next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in Cold 31 days, and Shutdown within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

3. An instrument channel calibration at least

- i 2.

At least one gaseous or once per operating particulate radioactivity cycle.

monitoring channel must be Operable; otherwise, reactor operation may continue for up to 31 days provided grab samples are obtained and analyzed every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , or be in 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

' i' within the following 24 t

hours.

~

c.

With no required leakage-detection systems Operable, be in Cold Shutdown within 24

. hours.

1 Amendment No. 139,151 125b O

~,,

4 g

llMITING CONDITIONS FOR OPERATION SURVEILLANCE RE0VIREMEN75

~

3.6.1 Shoch Sucoressors (Snubbers) 4.6.IShockSuoeressors(Snubbers}

1.

During all modes of operation The following surveillance except Cold' Shutdown and Refuel, requirements apply to all safety all safety-related snubbers related hydraulic and mechanical listed in PNPS Procedures shall snubbers listed in PNPS Procedures.

be operable except as noted in 3.6.I.2 through 3.6.I.3 below.

The required visual inspection interval varies inversely with the An Inoperable Snubber is a observed cumulative number of properly fabricated, installed inoperable snubbers found during an and sized snubber which cannot inspection.

Inspections performed pass its functional test.

before that interval has elapsed may be used as a new reference point to Upon determination that a determine the next inspection, snubber is either improperly However, the results of such early fabricated, installed or sized, inspections performed before the the corrective action will be as original time interval has elapsed specified for an inoperable may not be used to lengthen the snubber in Section 3.6.I.2.

required interval.

2.

Ftom and after the time that a Number of snubbers found inoperable snubber is determined to be during inspection or during inoperable, replace or repair inspection interval:

the snubber during the next 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , and initiate an Subsequent engineering evaluation to Inoperable Visual Inspec-determine if the components Snubbers tion Interval supported by the snubber (s) were adversely affected by the 0

24 Months 25%

inoperability of the snubbers 1

18 Months i 25%

and to ensure that the supported 2

12 Months 25%

component remains capable of 3,4 6 Months 25%

meeting its intended function in 5,6,7 124 Days 25%

the specific safety system 8,9 62 Days 25%

involved.

10 or more 31 Days 25%

Further corrective action for The required inspection interval this snubber, and all shall not be lengthened more than generically susceptible

'one step at a time, snubbers, shall be determined by an engineering evaluation.

Snubbers may be categorized in two groups, " accessible" or.

3.

From and after the time a

" inaccessible" based on their i

snubber is determined to be accessibility for inspection during inoperable, improperly reactor operation. These two groups fabricated, improperly installed may be inspected independently or improperly s12.ed, if the according to the above schedule.

requirements of Section(s) 3.6.I.1 and 3.6.I.2 cannot be 1.

Visual Inspection Acceptance met, then the affected safety Criteria system, or affected portions of that syt, tem, shall be declared A.

Visual inspections shall l

inoperable, and the limiting verify:

condition for that system entered, as appropriate.

i Amendment No. 29, 60, 93,151 137a i

...,~.....v..o

,un or c nm m.

- 3vnven_LANLt Rt0UlHEMENTS-

'3.6.1 Shock Suppressors (Snubbers) 4.6.I Shock Sucoressors (Snubbers) 4.

Snubbers may~be added to, or

1. That there are no visible removed from, per 10 CFR 50.59, indications of damage or safety related systems without impaired operability.

prior NRC approval. The addition or deletion of snubbers

2. Attachments to the foundation-shall be reported to the NRC in or support structure are such accordance with 10 CFR 50.59.

that the functional capability.of the snubber is not suspect.

B.

Snubbers which annear INOPERABLE as a result of visual-inspections may be determined OPERABLE for the purpose of-establishing the~next visual inspection interval provided; that:

1. The cause of the rejection is' clearly established and remedied for that particular snubber, and

2. The affected-snubber is functionally tested, when necessary, in the as found condition and determined OPERABLE per specifications 4.6.I.2.B., 4.6.I.2.C., as applicable.

C. For any snubber determined l

inoperable per' specification 4.6.I.2, clearly establish the cause of rejection and remedy the problem for that snubber, and any generically susceptible snubber.

2. Functional Tests (Hydraulic and Mechanical Snubbers) i A.

Schedule At least once per operating cycle, a representative sample l

(12.5% of the total of each type:

hydraulic, mechanical) of snubbers in use in the ' plant shall be functionally tested, either in place or in a bench test. For each snubber 1

that' does not meet the functional' test _ acceptance criteria of-Amendment No. 29, 60, 93, 151 137b

~

1 L ini f Inu wnut I tufo PUM UPtMAIION.

SURVtILLANCE RE0VIREMENTS

.j 4.6.1 Shock Sucoressors~(Snubbers)

. Specification.4.6.I.2.B, or 4.6.1.2.C, as applicable, an additional 12.5% of that l

type of. snubber shall be j

functionally tested.

B. General Snubber Functional J

Test Acceptance Criteria (Hydraulic and Mechanical)

The general snubber functional test shall verify that:

1. Activation (restraining action) is achieved within the specified range of a

velocity or acceleration in both tension and compression.

2. Snubber release, or bleedrate, as applicable, where required, is within the specified range in I

compression or tension..

For snubbers specifically.-

required not to displace under continuous load, the 4

ability of the snubber to withstand load without.

displacement shall be.

verified.

C. Mechanica1' Snubbers Functional Test Acceptance Criteria The mechanical snubber functional test shall verify.

that:-

1. The force that' initiates free moverr. ant of the snubber rod in either.

l tension or compression is less than the specified maximum drag force.

Drag-force shall not have increased more than 50%-

since the last~ functional.

test.

3.

Snubber Service Life Monitorino A. A record of the service life Amendment No. 60,151' 137c-

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE RE0VIREMENTS 3.7.B Standby Gas Treatment System 4.7.B Standby Gas Treatment System and Control Room Hioh and Control Room Hioh Efficiency Air Filtration Efficiency Air Filtration System System 1.

Standby Gas Treatment System 1.

Standby Gas Treatment System a.

Except as specified in

a. (1.) At least once per 3.7.B.I.c below, both trains operating cycle, it shall of the standby gas treatment be demonstrated that system and the diesel pressure drop across the generators required for combined high efficiency operation of such trains shall filters and charcoal be operable at all times when adsorber banks is less than-secondary containment 8 inches of water at 4000 integrity is required or the cfm.

reactor shall be shutdown in 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

(2.) At least once per operating cycle,

b. (1.) The results of the in-

~

demonstrate that the place cold DOP tests on inlet heaters on each train HEPA filters shall show are operable and are capable 199% D0P removal.

The of an output of at least 14 results of halogenated kW.

hydrocarbon tests on charcoal adsorber banks (3.) The tests and analysis of shall show 199%

Specification 3.7.B.1.b.

halogenated hydrocarbon shall.be performed at least

removal, once per operating cycle l

or following painting, fire (2.) The results of the or chemical release in any laboratory carbon sample ventilation zone analysis shall show 295%

communicating with ne methyl iodide removal at system while the system is a velocity within 10% of operating that could system design, 0.5 to 1.5 contaminate the HEPA filters mg/m3 inlet methyl iodide or charcoal adsorbers.

concentration, 270% R.H.

and 1190"F. The analysis (4.) At least once per results are to be operating cycle, automatic verified as acceptable initiation of~each branch of within 31 days after the standby gas treatment sample removal, or system shall be declare that train demonstrated, with inoperable and take the Specification 3.7.B.1.d actions specified satisfied.

3.7.B.I.c.

Amendment No. 50, 51, 52, 112, 144,151 158

.i _,.......

.m.

-. h m t neum ntnt e

. ' '3.7.B (Continued) 4.7.8 (Continued) 2.

Control Room Hiah Efficiency Air 2.

Control Room Hiah Efficiency Air Filtration System Filtration System At least once per operating

a. Except as specified in a.

Specification 3.7.B.2.c cycle the pressure drop across below, both trains of the each combined filter train'shall

-Control Room High Efficiency be demonstrated to be less than Air Filtration System used 6 inches of water at 1000 cfm or

.l for the processing of inlet the calculated equivalent.

air to the control room under accident conditions and the b.

(1.) The tests and analysis of diesel. generator (s) required Specification 3.7.B.2.b for operation of each train shall be performed once of the system shall be per operating-cycle or_

operable whenever secondary following painting, fire or i

containment integrity is chemical release in' any' H

required and during fuel ventilation zone handling operations.

communicating.with the system while the system is

b. (1.) The results of the in-operating.

place cold 00P tests on HEPA filters shall show (2.) In-place cold 00P testing i

199% DOP removal.

The shall be performed after results of the each complete or partial a

halogenated hydrocarbon replacement of the HEPA 1

tests on charcoal filter bank or after any adsorber banks shall structural maintenance on show 199% halogenated the system housing which hydrocarbon removal when could affect the HEPA test results are filter bank bypass leakage.

extrapolated to the initiation of the test.

(3.) Halogenated hydrocarbon i

testing shall be performed j

(2.) The results of the after each complete or a

laboratory carbon sample partial replacement of the analysis shall show 195%

charcoal adsorber bank or methyl iodide removal at after any structural a velocity within 10% of maintenance on the system system design, 0.05 to housing which could affect 0.15 mg/m3 inlet methyl the charcoal adsorber bank i

iodide concentration,

. bypass leakage.

?

170% R.H.,.and 2125*F.

The analysis results are (4.) Each train shall-be j

to be. verified as operated with the heaters acceptable within 31 in automatic for.at least-days after sample 15 minutes every month.

l removal, or declare that i

train inoperable and (5.) The test and analysis of.

take the actions Specification 3.7.B.2.b.(2) specified in.3.7.B.2.c.

shall be performed after 1

every 720 hours0.00833 days 0.2 hours 0.00119 weeks 2.7396e-4 months of system operation.

.)

During RF0 #9, one train can be without its safety-related bus and/or its emergency diesel generator without entering the LCO action statement provided the conditions listed on page 158A are met.

Amendment No. 50, 51, 52, 191, 112, 144, 151 158B'

, L mi i INb LUNUI I IUW5 FOR OPERA I ION SURVEILLANCE RE0VIREMENTS 3.7.B (Continued) 4.7.8 (Continued)

c. From and after the date that

c. At least once per operating one train of the Control Room cycle demonstrate that the High Efficiency Air inlet heaters on each train Filtration System is made or are operable and capable of found to be incapable of an output of at least 14 kw.

supplying filtered air to the control room for any reason,

d. Perform an instrument reactor operation or functional test on the refueling operations are humidistats controlling the permissible only during the heaters once per operating succeeding 7 days providing cycle.

that within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months all active components of the other CRHEAF train shall be demonstrated operable.

If the system is not made fully operable within 7 days, reactor shutdown shall be initiated and the reactor shall be in cold shutdown within the next 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months and irradiated fuel handling operations shall be terminated within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

Fuel handling operations in progress may be completed.

I

d. Fans shall operate within 10% of 1000 cfm.

i During RF0 #9, one train can be without its safety-related bus and/or its emergency diesel generator without entering the i.00 action statement provided the conditions listed on page 158/ are met.

Amendment No. 50, 51, 57, 112, 144,151 158C

. BASES:

3.7.A & 4.7.A Primary Containment Grouc 6 - process lines are normally in use and it is therefore not desirable to cause spurious isolation due to high drywell pressure resulting from non-safety related causes.

To protect the reactor from a possible pipe break in the system, isolation is provided by high temperature in the cleanup system area or high flow through the inlet to the cleanup system. Also, since the vessel could potentially be drained through the cleanup system, a low level isolation is provided.

G oup 7 - The HPCI vacuum breaker line is designed to remain operable when the t

HPCI system is required. The signals which initiate isolation of the HPCI vacuum breaker line are indicative of a break inside containment and reactor pressure below that at which HPCI can operate.

The maximum closure time for the automatic isolation valves of the primary containment and reactor vessel isolation control system have been selected in consideration of the design intent to prevent core uncovering following pipe breaks outside the primary containment and the need to contain released fission products following pipe breaks inside the primary containment.

In satisfying this design intent an additional margin has been included in specifying maximum closure times.

This margin permits identification of degraded valve performance, prior to exceeding the design closure times.

In order to assure that the doses that may result from a steam line break do not exceed the 10CFR100 guidelines, it is necessary that no fuel rod perforation resulting from the accident occur prior to closure of the main steam line isolation valves. Analyses indicate that fuel rod cladding perforations would be avoided for main steam valve closure times, including instrument delay, as long as 10.5 seconds.

l These valves are highly reliable, have low service requirements and most are normally closed.

The initiating sensors and associated trip channels are also checked to demonstrate the capability for automatic isolation. The test 1

interval of once per operating cycle for automatic initiation results in a failure probability of 1.1 x 10 7 that a line will not isolate. More frequent i

testing for valve operability results in,a greater assurance that the valve will be operable when needed.

The main steam line isolation valves are functionally tested on a more frequent interval to establish a high degree of reliability.

The primary containment is penetrated by several small diameter instrument

~

lines connected to the reactor coolant system.

Each instrument line contains a 0.25 inch restricting orifice inside the primary containment. A program for i

periodic testing and examination of the excess flow check valves is in place.

Primary Containment Paintino The interiors of the drywell and suppression chamber are painted to prevent rusting. The inspection of the paint during each major refueling outage assures the paint is intact.

Experience at Pilgrim Station and other BWRs with this type of paint indicates that the inspection interval is adequate.

Amendment No. 113,151 169

' BASES:

3.7.8.1 and 4.7.B.1 - Standby Gas Treatment System The Standby Gas Treatment System is designed to filter and exhaust the reactor building atmosphere to the stack during secondary containment isolation conditions.

Upon containment isolation, both standby gas treatment fans are designed to start to bring the reactor building pressure negative so that all leakage should be in-leakage..After a preset time delay, the standby fan automatically shuts down so the reactor building pressure is maintained approximately 1/4 inch of water negative.

Should one system fail to start, the redundant system is designed to start automatically.

Each of the two trains has 100% capacity.

High Efficiency Particulate Air (HEPA) filters are installed before and after the charcoal adsorbers to minimize potential release of particulates to the environment and to prevent clogging of the iodine adsorbers.

The charcoal adsorbers are installed to reduce the potential release of radiciodine to the environment.

The in-place test results should indicate a system leak tightness of less than 1 percent bypass leakage for the charcoal adsorbers and a HEPA filter efficien6y of at least 99 percent removal of cold DOP particulates. The laboratory carbon sample test results should indicate a methyl iodide removal efficiency of at least 95 percent for expected accident conditions.

The specified efficiencies for the charcoal and particulate filters is sufficient to preclude exceeding 10 CFR 100 guidelines for the accidents analyzed.

The analysis of the loss of coolant accident assumed a charcoal adsorber efficiency of 95% and TID 14844 fission product source terms, hence, installing two banks of adsorbers and filters in each train provides adequate margin. A 14 kW heater maintains relative humidity below 70% in order to ensure the efficient removal of methyl iodide on the impregnated charcoal adsorbers.

Considering the relative simplicity of the heating circuit, the test frequency of once/ operating cycle is adequate to l

demonstrate operability.

Air flow through the filters and charcoal adsorbers for 15 minutes each month assures operability of the system. Since the system heaters are automatically controlled, the air flowing through the filters and adsorbers will be 170%

relative humidity and will have the desired drying effect.

Tests of impregnated charcoal identical to that used in the filters indicate that shelf life of five years leads to only minor decreases in methyl iodide removal efficiency.

Hence, the frequency of laboratory carbon sample analysis is adequate to demonstrate acceptability.

Since adsorbers must be be removed to perform this analysis this frequency also minimizes the system out.of service time as a result of surveillance testing.

In addition, although.the halogenated hydrocarbon testing is basically a leak test, the adsorbers have charcoal of known efficiency and holding capacity for elemental iodine and/or methyl iodide, the testing also gives an indication of the relative efficiency of the installed system. The 31 day requirement for the ascertaining of test results ensures that the ability of the charcoal to perform its designed function is demonstrated and known in a timely manner.

The required Standby Gas Treatment System flow rate is that flow, less than or equal to 4000 CFM which is needed to maintain the Reactor Building at a 0.25 inch of water negative pressure under calm wind conditions. This capability is adequately demonstrated during Secondary Containment Leak Rate Testing performed pursuant to Technical Specification 4.7.C.1.c.

Amendment No. 42, 112,151 172

M 3.7.B.1 and 4.7.B.1 (continued)

The test frequencies are adequate to detect equipment deterioration prior to significant defects, but the tests are not frequent enough to load the filters or adsorbers, thus reducing their reserve capacity too quickly.

The filter testing is performed pursuant to appropriate procedures reviewed and approved by the Operations Review Committee pursuant to Section 6 of these Technical Specifications. The in-place testing of charcoal filters is performed by injecting a halogenated hydrocarbon into the system upstream of the charcoal adsorbers. Measurements of the concentration upstream and downstream are made.

The ratio of the inlet and outlet concentrations gives an overall indication of the leak tightness of the system. A similar procedure substituting dioctyl phthalate for halogenated hydrocarbon is used to test the HEPA filters.

Pressure drop tests across filter and adsorber banks are performed to detect plugging or leak paths though the filter or adsorber media.

Considering the relatively short times the fans will be run for test purposes, plugging is unlikely and the test interval of once per operating cycle is reasonable.

l System drains and housing gasket doors are designed such that any leakage would be in-leakage from the Standby Gas Treatment System Room.

This ensures that there will be no bypass of process air around the filters or adsorbers.

i Only one of the two Standby Gas Treatment Systems (S8GTS) is needed to maintain the secondary containment at a 0.25 inch of water negative pressure upon containment isolation.

If one system is found to be inoperable, there is no immediate threat to the containment system performance and reactor operation or refueling activities may continue while repairs are being made.

In the event one SBGTS is inoperable, the redundant system's active components will be tested within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months . This substantiates the availability of the operable system and justifies continued reactor or refueling operations.

If both trains of SBGTS are inoperable, the plant is brought to a condition j

where the SBGTS is not required.

Amendment No. 42, 112, 151 173

TABLE 4.8-2 RADI0 ACTIVE LIOUID EFFLUENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREME i

Channel Instrument Source Channel Functional Instrument Check Check Calibration Test 1.

Gross Beta or Gamma Radioactivity Monitors Providing Alarm and Auto-matic Isolation

a. Liquid Radwaste Effluents Line i

NA Once per Quarterly l

18 months 2 2.

Flow Rate Measurement Devices

a. Liquid Radwaste Effluent Line i

NA Once per Quarterly l

18 months 1During or prior to release via this pathway.

2Previously established calibration procedures will be used for these requirements.

Amendment No. 89,151 190

TABLE 4.8-4 RADIOACTIVE GASEQUS EFFLUENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS Instrument Instrument Source Instrument functional Instrument Check Check Calibration Test 1.

Main Stack Effluent Monitoring System l

a. Noble Gas Activity Monitor Daily Monthly Once per Quarterly

[

(Two Channels) 18 Months 4

b. Iodine Sampler Cartridge NA NA NA NA

c. Particulate Sampler Filter NA NA NA NA l

d. Effluent System Flow Rate Daily NA Once per Quarterly

[

Measuring Device 18 Months I

e. Sampler Flow Rate Measuring Daily NA Once per Quarterly l

Device 18 Months 2.

Reactor Building Ventilation Effluent Monitoring System l

a. Noble Gas Activity Monitor Daily Monthly once per Quarterly

[

18 Months 4

b. Iodine Sampler Cartridge NA NA NA NA

c. Particulate Sampler Filter NA NA NA NA l

d. Effluent System Flow Rate Daily NA Once per Quarterly l

Measuring Device 18 Months Amendment No. 89,151 193

TABLE 4.8-4 (continued)

RADI0 ACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS i

Instrument Instrument Source Instrument functional instrument-Check Check Calibration Test l

e. Sampler Flow Rate Measuring Daily NA Once per

-Quarterly l

Device 18 Months 3.

Steam Jet Air Ejector Radioactivity Monitor I

3

a. Noble. Gas Activity Monitor Daily NA Once per Quarterly operaging cycle 4.

Augmented-Offgas Treatment System Explosive Gas Monitoring System 2

5

a. Hydrogen Monitor Daily NA Quarterly Monthly 1

During releases via this pathway 2

During augmented offgas treatment system operation.

3 During operation of the steam jet air ejector.

4 Previously established calibration procedures will be used for these requirements.

5 Calibrate at 2 pol'nts with standard gas samples differing by at least 1% but not exceeding 4%.

' Amendment No. 89,151 193a

. ~ _.

9 r+

r i

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REOUIREMENTS 4.9.A ~ Auxiliary Electrical

-Eauioment Surveillance

.(Cont'd) 1.

Verifying de-energization of the emergency buses and load sheddin i

buses. g from the emergency

.i 2.

Verifying the diesel. starts from ambient condition on the auto-start signal, energizes the emergency buses with permanently connected loads, i

energizes the auto-connected ~

emergency loads through'the.

' load sequence,.and operates for.2-5 minutes while its generator is loaded with the emergency loads.

During performance of'this

~

surveillance verify that HPCI and RCIC inverters do not trip.

The results shall be logged.

lc.

Once per operating cycle with the diesel loaded per.

4.9. A.1.b verify that.on diesel generator. trip, a

secondary (offsite) AC power-is automatically connected

.l within '11.8:to 13.2 seconds l q

to the emergency service buses.and emergency loads are.

=i energized through thi load

~

. sequencer in the same manner as described in 4.9.A.1.b.1.

The~ results shall be logged.

k Amendment No. 42,.61, 14\\151

'194a

r LfMITING CONDITIONS FOR OPERATION SURVEILLANCE RE0VIREMENTS 3.9.B Operation with Inocerable 4.9.A Auxiliary Electrical Eouioment Eauioment Surveillance (Cont'd)

Whenever the reactor is in Run 3.

Emergency 4160V Buses AS-A6 Mode or Startup Mode with the Degraded Voltage Annunciation reactor not.in a Cold Condition, System.

the availability of electric power shall be as specified in

a. Once each operating cycle, 3.9.8.1, 3.9.B.2, 3.9.B.3, calibrate the alarm sensor.

3.9.B.4, and 3.9.B.5.

b. Once each 31 days perform a 1.

From and after the date that channel functional test on the incoming power is not available alarm system.

from the startup or shutdown transformer, continued reactor

c. In the event the alarm system operation is permissible under is f.etermined inoperable under this condition for seven days.

3.b above, commence logging During this period, both diesel safety related bus voltage generators and associated every 30 minutes until such emergency buses must be time as the alarm is restored demonstrated to be operable.

, to operable status.

2.

From and after the date that 4.

RFS Electrical Protection incoming power is not available Asremblies from both startup and shutdown transformers, continued

a. Each pair of redundant RPS operation is permissible, EPAs shall be determined to provided both diesel generators be operable at least once and associated emergency buses per 6 months by performance are demonstrated to be operable, of an instrument functional all core and containment cooling test.

systems are operable, reactor power level is reduced to 25% of

b. Once per 18 months, each l

design and the NRC is notified pair of redundant RPS EPAs within one (1) hour as required shall be determined to be i

by 10CFR50.72.

operable by performance of an instrument calibration 3.

From and after the date that one and by verifying tripping of the diesel generators or of the circuit breakers associated emergency bus is made upon the simulated or found to be inoperable for conditions for automatic any reason, continued reactor actuation of the protective operation is permissible in relays within the following j

accordance with Specification limits:

3.5.F if Specification 3.9.A.1 and 3.9.A.2.a are satisfied.

Overvoltage 1 132 volts Undervoltage 2 108 volts 4.

From and after the date that one Underfrequency 1 57Hz of the diesel generators or associated emergency buses and either the shutdown or startup transformer power source are made Amendment No. 88, 127,145,151 196

LIMITINO CONDITION FOR OPERATION SORVEILLANCE REQUIREMENTS 3.9 AUXILIARY ELECTRICAL SYSTEM (Cont)

B.

Operation with Inocerable Eauipment (Cont) or found to be inoperable for any reason, continued reactor operation is permissiFle in accordance with Specification 3.5.F. provided either of the following conditions are satisfied:

a. The startup transformer and both offsite 345 kV transmission lines are available and capable of automatically supplying auxiliary power to the emergency 4160 volt buses.

b. A transmission line and j

associated shutdown transformer are available and capable of automatically supplying auxiliary power to the emergency 4160 volt buses.

5. From and after the date that one of the 125 or 250 volt battery systems is made or found to be inoperable for any reason, continued reactor operation is permissible during the succeeding three days within electrical safety considerations, provided repair work is initiated in the most expeditious manner to return the failed component to an operable state, and Specification 3.5.F

)

is satisfied.

6. With the emergency bus voltage less than 3958.5v but above 3878.7V(excluding transients) during normal operation, transfer the safety related buses to the diesel generators.

If grid voltage continues _to degrade be in at least Hot Shutdown within the next 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months and in Cold Shutdown within the following 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months unless the grid conditions improve.

Amendment No. 42,-61,.88;-120, 127,151 197

fL&SJJi:

(Cont'd) 4.9 deliver full flow.

Periodic testing of the various components, plus a functional test once per cycle, is sufficient to maintain adequate reliability.

Although station batteries will deteriorate with time, utility experience indicates there is almost no possibility of precipitous failure.

The type of surveillance described in this specification has been demonstrated over the years to provide an indication of a cell becoming irregular or unserviceable long before it becomes a failure.

Tne Service Discharge Test provides indication of the batteries' at,ility to satisfy the design requirements (battery duty cycle) of the associated de system.

This test will be performed i. sing simulated or actual loads at the rates and for the duration specified in the design load profile. A once per cycle testing interval was chosen to coincide with planned outages.

The Performance Discharge Test provides adequate indication and assurance that the batteries have the specified ampere hour capacity.

The results of these tests will be logged and compared with the manufacturer's recommendations of acceptability.

This test is performed once every five years in lieu of the Service Discharge test that would normally occur within that time frame.

l The diesel fuel oil quality must be checked to ensure proper operation of the diesel generators. Water content should be minimized because water in the fuel could contribute to excessive damage to the diesel engine.

The electrical protection assemblies (EPAs) on the RPS inservice power supplies, either two motor generator sets or one motor generator and the alternative supply, consist of protective relays that trip their incorporated circuit breakers on overvoltage, undervoltage, or underfrequency conditions. There are j

two EPAs in series per power source.

It is necessary to periodically test the relays to ensure the sensor is operating correctly and to ensure the trip unit is operable.

Based on experience at conventional and nuclear power plants, a six-month frequency for the channel functional test is established. This frequency is consistent with the Standard Technical Specifications.

The EPAs of the power sources to the RPS shall be determined to be operable by performance of a channel calibration of the relays once per 18 months.

During l

calibration, a transfer to the alternative power source is required; however, prior to switching to alternative feed, de-energization of the applicable MG set power source must be accomplished.

This resu'ts in a half scram on the channel being calibrated until the alternative power source is connected and the i

half scram is cleared.

Based on operating experience, drift of the EPA protective relays is not significant.

I i

Amendment No. 127, 135, 141, 145,151 201 4.

ML20065H437

Text

Attachment:

Navigation menu

Search