ML072400304

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Tech Spec Pages for Amendment 171 Relocate Component Lists for Primary Containment Isolation Valves from Technical Specifications
ML072400304
Person / Time
Site: Hope Creek PSEG icon.png
Issue date: 08/27/2007
From:
NRC/NRR/ADRO/DORL/LPLI-2
To:
Ennis R, NRR/DORL, 415-1420
References
TAC MD3600
Download: ML072400304 (17)
v • d • e


Text

(4) PSEG Nuclear LLC, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess, and use at any time any byprodu, and special nuclear material as sealed neutron sources for reactor startup, sealed sources for reactor instrumentation and radiation monitoring equipment calibration, and as fission detectors in amounts as required; (5) PSEG Nuclear LLC, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess, and use in amounts as required any byproduct, source or special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; and (6) PSEG Nuclear LLC, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to possess, but not separate, such byproduct and special nuclear materials as may be produced by the operation of the facility.

C. This license shall be deemed to contain and is subject to the conditions specified in the Commission's regulations set forth in 10 CFR Chapter I and is subject to all applicable provisions of the Act and to the rules, regulations and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below:

(1) Maximum Power Level PSEG Nuclear LLC is authorized to operate the facility at reactor core power levels not in excess of 3339 megawatts thermal (100 percent rated power) in accordance with the conditions specified herein.

(2) Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A, as revised through Amendment No.171 , and the Environmental Protection Plan contained in Appendix B, are hereby incorporated into the license. PSEG Nuclear LLC shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

(3) Inservice Testing of Pumps and Valves (Section 3.9.6, SSER No. 4)W This License Condition was satisfied as documented in the letter from W. R. Butler (NRC) to C. A. McNeill, Jr.

(PSE&G) dated December 7, 1987. Accordingly, this condition has been deleLed.

Tie paEreithetical iuLatiun following the title of many license

,--nditonrs denotes the section of the Safety Evaluation Report and/or i-s sucolements wherein the license condition is discussed.

Amtendment No. 171

INDEX T.IMTTTNG CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE Drywell Average Air Temperature .......................... 3/4 6-10 Drywell and Suppression Chamber Purge System ........... 3/4 6-11 3/4.6.2 DEPRESSURIZATION SYSTEMS Suppression Chamber ...................................... 3/4 6-12 Suppression Pool Spray ................................... 3/4 6-15 Suppression Pool Cooling ................................. 3/4 6-16 3/4.6.3 FRIMARY CONTAINMENT ISOLATION VALVES .................... 3/4 6-17 Table 3.6.3-1 DELETED 3/4.6.4 VACUUM RELIEF Suppression Chamber - Drywell Vacuum Breakers .......... 3/4 6-43 Reactor Building - Suppression Chamber Vacuum Breakers ................................................ 3/4 6-45 3/4.6.5 SECONDARY CONTAINMENT Secondary Containment Integrity .......................... 3/4 6-47 Secondary Containment Automatic Isolation Dampers ...... 3/4 6-49 Table 3.6.5.2-1 Secondary Containment Ventilation System Automatic Isolation Dampers Isolation Group No. 19 ................ 3/4 6-50 Filtration, Recirculation and Ventilation System ....... 3/4 6-51 3/4.6.6 PRIMARY CONTAINMENT ATMOSPHERE CONTROL Containment Hydrogen Recombiner Systems (Deleted) ...... 3/4 6-54 Drywell and Suppression Chamber Oxygen Concentration... 3/4 6-55 3/4.7 PLANT SYSTEMS 3/4.7.1 SERVICE WATER SYSTEMS Safety Auxiliaries Cooling System ........................ 3/4 7-1 Station Service Water System .............................. 3/4 7-3 Ultimate Heat Sink......................................... 3/4 7-5 3/4.7.2 CONTROL ROOM EMERGENCY FILTRATION SYSTEM ............... 3/4 7-6 n*endment 110. 171

DEFINITIONS OPERABLE - OPERABILITY 1.28 A system, subsystem, train, component or device shall be OPERABLE or have OPERABILITY when it is capable of performing its specified function(s) and when all necessary attendant instrumentation, controls, electrical power, cooling or seal water, lubrication or other auxiliary equipment that are required for the system, subsystem, train, component or device to perform its function(s) are also capable of performing their related support function(s).

OPERATIONAL CONDITION - CONDITION 1.29 An OPERATIONAL CONDITION, i.e., CONDITION, shall be any one inclusive combination of mode switch position and average reactor coolant temperature as specified in Table 1.2.

PHYSICS TESTS 1.30 PHYSICS TESTS shall be those tests performed to measure the fundamental nuclear characteristics of the reactor core and related instrumentation and 1) described in Chapter 14 of the FSAR, 2) authorized under the provisions of 10 CFR 50.59, or 3) otherwise approved by the Commission.

PRESSURE BOUNDARY LEAKAGE 1.31 PRESSURE BOUNDARY LEAKAGE shall be leakage through a non-isolable fault in a reactor coolant system component body, pipe wall or vessel wall.

PRIMARY CONTAINMENT INTEGRITY 1.32 PRIMARY CONTAINMENT INTEGRITY shall exist when:

a. All primary containment penetrations required to be closed during accident conditions are either:
1. Capable of being closed by an OPERABLE primary containment automatic: -isolat-o sy.... , or
2. Closed by at least one manual valve, blind flange, or deactivated automatic valve secured in its closed position, except for valves that are opened under administrative control as permitted by Specification 3.6.3.
b. All primary containment equipment hatches are closed and sealed.
c. Each primary containment air lock is in compliance with the requirements of Specification 3.6.1.3.
d. The primary containment leakage rates are within the limits of Specification 3.6.1.2.
e. The suppression chamber is in compliance with the requirements of Specification 3.6.2.1.
f. The sealing mechanism associated with each primary containment penetration; e.g., welds, bellows or 0-rinas, is OPERABLE.

HOPE CREEK HEAmendment 1io. 171

TABLE 3.3.2-1 ISOLATION ACTUATION INSTRUMENTATIOn]

VALVE ACTUA-TION GROUPS MINIMUM APPLICABLE OPERATED BY OPERABLE CHANNELS OPERATIONAL TRIP FUNCTION SIGNAL PER TRIP SYSTEM(a) CONDITION ACTION

1. PRIMARY CONTAINMENT ISOLATION
a. Reactor Vessel Water Level
1) Low Low, level 2 1, 2, 8, 9, 2 1, 2, 3 20 12, 13, 14, 15, 17, 18
2) Low low Low, Level 1 10, 11, 15, 16 2 1, 2, 3 20
b. Drywell Pressure - High 1, 8, 9, 10, 1, 2, 3 20 11, 12, 13, 14, 15, 16, 17, 18
c. Reactor Building Exhaust 1, 8, 9, 12 Radiation - High 13, 14, 15, 3 1, 2, 3 28 17, 18
d. Manual Initiation 1, 8, 9, 10 1 1, 2, 3 24 11, 12, 13, 14, 15, 16, 17, 18
2. SECONDARY CONTAINMENT ISOLATION
a. Reactor Vessel Water Level -

19 (C)

Low Low, Level 2 2 1, 2, 3 and

  • 26
b. Drywell Pressure - High 19 (C) 1, 2, 3 26
c. Refueling Floor Exhaust 3 1, 2, 3 and
  • 29 Radiation - High
d. Reactor Building Exhaust Radiation - High (c) 3 1, 2, 3 and
  • 28 19
e. Manual Initiation 19 (c) 1 1, 2, 3 and
  • 26 HOPE CREEK 3/4 3-11 Amendment No. 171

TABLE 3.3.2-1 (Continued)

ISOLATION ACTUATION INSTRUMENTATION VALVE ACTUA-TION GROUPS MINIMUM APPLICABLE OPERATED BY OPERABLE CHANNELS OPERATIONAL TRIP FUNCTION

3. MAIN STEAM LINE ISOLATION SIGNAL PER TRIP SYSTEM(a) CONDITION ACTION I
a. Reactor Vessel Water Level - 1 2 1, 2, 3 21 Low Low Low, Level 1.
b. Main Steam Line Radiation - 2 (b) 2 1, 2, 3## 28 High, High
c. Main Steam Line Pressure - 2 1. 22 Low 1
d. Main Steam Line Flow - High 2/line 1, 2, 3 20 1
e. Condenser Vacuum - Low 2 1, 2**, 3** 21 1
f. Main Steam Line Tunnel 2/line i, 2, 3 21 Temperature - High
g. Manual Initiation 1, 2, 17 2 1, 2, 3 25
4. REACTOR WATER CLEANUP SYSTEM ISOLATION
a. RWCU A Flow - High 7 1/Valve (e) 1, 2, 3 23
b. RWCU A Flow - High, Timer 7 1/Valve (e) 1, 2, 3 23
c. RWCU Area Temperature - High 7 6/Valve (e) 1, 2, 3 23
d. RWCU Area Ventilation A 7 6/Valve (e) 1, 2, 3 23 Temperature-High
e. SLCS Initiation 7f) 1, 1/Valve(e) 2 23
f. Reactor Vessel Water 7 2/Valve (e) i, 2, 3 23 Level - Low Low, Level 2
g. Manual Initiation 7 1/Valve (e) 1, 2, 3 25 HOPE CREEK 3/4 3-12 Amendment N0.171

TABLE 3.3.2-1 (Continued)

ISOLATION ACTUATION INSTRUMENTATION VALVE ACTUA-TION GROUPS MINIMUM APPLICABLE OPERATED BY OPERABLE CHANNELS OPERATIONAL TRIP FUNCTION SIGNAL PER TRIP SYSTEM~a, CONDITION ACTION

5. REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION
a. RCIC Steam Line A Pressure 6 1/Valve (e) 1, 2, 3 23 (Flow) - High
b. RCIC Steam Line A Pressure 6 1/Valve (e) 1, 2, 3 23 (Flow) - High, Timer C. RCIC Steam Supply 6 2/Valve(e) 1, 2, 3 23 Pressure - Low
d. RCIC Turbine Exhaust 6 2/Valve(e) 1, 2, 3 23 Diaphragm Pressure - High
e. RCIC Pump Room 6 1/Valve(e) 1, 2, 3 23 Temperature - High
f. RCIC Pump Room Ventilation Ducts 6 1/Valve(e) 1, 2, 3 23 A Temperature - High
g. RCIC Pipe Routing Area 6 1/Valve (e) 1, 2, 3 23 Temperature - High
h. RCIC Torus Compartment 6 3/Valve (e) 1, 2, .3 23 Temperature-High
i. Drywell Pressure - High(g) 6 2/Valve (e) 1, 2, 3 23
j. Manual Initiation 6 0h) I/RCIC System 1, 2, 3 25 HOPE CREEK 3/4 3-13 Amendment No. 171

TABLE 3.3.2-1 (Continued)

ISOLATION ACTUATION INSTRUMENTATION VALVE ACTUA-TION GROUPS MINIMUM APPLICABLE OPERATED BY OPERABLE CHANNELS OPERATIONAL TRIP FUNCTION SIGNAL PER TRIP SYSTEM(a) CONDITION ACTION I

6. HIGH PRESSURE COOLANT INJECTION SYSTEM ISOLATION
a. HPCI Steam Line A Pressure 5 1/Valve (e) 1, 2, 3 23 (Flow) - High
b. HPCI Steam Line A Pressure 5 1/Valve (e) 1, 2, 3 23 (Flow) - High, Timer
c. HPCI Steam Supply Pressure-Low 5 2/Valve(e) 1, 2, 3 23
d. HPCI Turbine Exhaust Diaphragm 5 2/Valve (e) 1, 2, 3 23 Pressure - High
e. HPCI Pump Room 5 1/Valve (e) 1, 2, 3 23 Temperature - High
f. HPCI Pump Room Ventilation 5 1/Valve (e) 1, 2, 3 23 Ducts A Temperature - High
g. HPCI Pipe Routing Area 5 1/Valve (e) 1, 2, 3 23 Temperature - High h1. HPCI Torus Compartment 5 3/Valve (e) 1, 2, 3 23 Temperature-High
i. Drywell Pressure - High(g) 5 2/Valve (e) 1, 2, 3 23
j. Manual Initiation 5 (il 1/HPCI system 1, 2, 3 25 HOPE CREEK 3/4 3-14 Amendrer.t No. 171

TABLE 3.3.2-1 (Continued)

ISOLATION ACTUATION INSTRUMENTATION VALVE ACTUA-TION GROUPS MINIMUM APPLICABLE OPERATED BY OPERABLE CHANNELS OPERATIONAL TRIP FUNCTION SIGNAL PER TRIP SYSTEM(a) CONDITION ACTION

7. RHR SYSTEM SHUTDOWN COOLING MODE ISOLATION
a. Reactor Vessel Water Level - Low, Level 3 30) 2/Valve (e) 1, 2, 3 27
b. Reactor Vessel (RHR Cut-in Permissive) Pressure - High 3 (j) 2/Valve(e) 1, 2, 3 27
c. Manual Initiation 3 i/Valve(e) 1, *2, 3 25 HOPE CREEK 3/4 3-15 Amendment NO-171

TABLE 3.3.2-1 (Continued)

NOTES When handling recently irradiated fuel in the secondary containment and during operations with a potential for draining the reactor vessel.

When any turbine stop valve is greater than 90% open and/or when the key-locked bypass switch is in the Norm position.

The hydrogen water chemistry (HWC) system shall not be placed in service until reactor power reaches 20% of RATED THERMAL POWER.

After reaching 20% of RATED THERMAL POWER, and prior to operating the HWC system, the normal full power background radiation level and associated trip setpoints may be increased to levels previously measured during full power operation with hydrogen injection. Prior to decreasing below 20% of RATED THERMAL POWER and after the HWC system has been shutoff, the background level and associated setpoint shall be returned to the normal full power values. If a power reduction event occurs so that the reactor power is below 20% of RATED THERMAL POWER without the required setpoint change, control rod motion shall be suspended (except for scram or other emergency actions) until the necessary setpoint adjustment is made.

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

(b) Also trips and isolates the mechanical vacuum pumps.

(c) Also starts the Filtration, Recirculation and Ventilation System (FRVS).

(d) DELETED (e) Sensors arranged per valve group, not per trip system.

(f) Closes only RWCU system isolation valve(s) HV-FO01 and HV-F004.

(g) Requires system steam supply pressure-low coincident with drywell pressure-high to close turbine exhaust vacuum breaker valves.

(h) Manual isolation closes HV-F008 only, and only following manual or automatic initiation of the RCIC system.

(i) Manual isolation closes HV-F003 and HV-F042 only, and only following manual or automatic initiation of the HPCI system.

(j) Trip functions common to RPS instrumentation.

HOPE CREEK 3/4 3- 6, 'c171

Pages 3/4 3-18 through 3/4 3-21 have been intentionally omitted HOPE CREEK 3/4 3-17 171 HOP..CR.E. 3/43-.7..

3/4.6 CONTAINMENT SYSTEMS 3/4.6.1 PRIMARY CONTAINMENT PRIMARY CONTAINMENT INTEGRITY LIMITING CONDITION FOR OPERATION 3.6.1.1 PRIMARY CONTAINMENT INTEGRITY shall be maintained.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2* and 3.

ACTION:

Without PRIMARY CONTAINMENT INTEGRITY, restore PRIMARY CONTAINMENT INTEGRITY within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

SURVEILLANCE REQUIREMENTS 4.6.1.1 PRIMARY CONTAINMENT INTEGRITY shall be demonstrated:

a. After each closing of each penetration subject to Type B testing, except the primary containment air locks, if opened following Type A or B test, by. leak rate testing in accordance with the Primary Containment Leakage Rate Testing Program.
b. At least once per 31 days by verifying that all primary containment penetrations** not capable of being closed by OPERABLE containment automatic isolation valves and required to be closed during accident conditions are closed by valves, blind flanges, or deactivated automatic valves secured in position, except for valves that are opened under administrative control as permitted by Specification 3.6.3.
c. By verifying each primary containment air lock is in compliance with the requirements of Specification 3.6.1.3.
d. By verifying the suppression chamber is in compliance with the requirements of Specification 3.6.2.1.
  • See Special Test Exception 3.10.1
    • Except valves, blind flanges, and deactivated automatic valves which are located inside the primary containment, and are locked, sealed or otherwise secured in the closed position. These penetrations shall be verified closed during each COLD SHUTDOWN except such verification need not be performed when the primary containment has not been de-inerted since the last verification or more often than once per 92 days.

HOPE CREEK 3/4 6-1 Amendment No.171

CONTAINMENT SYSTEMS PRIMARY CONTAINMENT LEAKAGE LIMITING CONDITION FOR OPERATION 3.6.1.2 Primary containment leakage rates shall be limited to:

a. An overall integrated leakage rate (Type A test) in accordance with the Primary Containment Leakage Rate Testing Program.
b. A combined leakage rate in accordance with the Primary Containment Leakage Rate Testing Program for all primary containment penetrations and all primary containment isolation valves that are subject to Type B and C tests, except for: main steam line isolation valves*, valves which form the boundary for the long-term seal of the feedwater lines, other valves which are hydrostatically tested, and those valves where an exemption to Appendix J of 10 CFR 50 has been granted.
c. *Less than or equal to 150 scfh per main steam line and less than or equal to 250 scfh combined through all four main steam lines when tested at 5 psig (leakage rate corrected to 1 Pa, 48.1 psig).
d. A combined leakage rate of less than or equal to 10 gpm for all containment isolation valves which form the boundary for the long-term seal of the feedwater lines, when tested at *.10 Pa, 52.9 psig.
e. A combined leakage rate of less than or equal to 10 gpm for all other penetrations and containment isolation valves in hydrostatically tested lines which penetrate the primary containment, when tested at 1.10 Pa, 52.9 psig Ap.

APPLICABILITY: When PRIMARY CONTAINMENT INTEGRITY is required per Specification 3.6.1.1.

ACTION:

With:

a. The measured overall integrated primary containment leakage rate (Type A test) not in accordance with the Primary Containment Leakage Rate Testing Program, or
b. The measured combined leakage rate exceeding the leakage rate specified in the Primary Containment Leakage Rate Testing Program for all primary containment penetrations and all primary containment isolation valves that are subject to Type B and C tests, except for: main steam line isolation valves*, valves which form the boundary for the long-term seal of the feedwater lines, valves which are hydrostatically tested, and those valves where an exemption to Appendix J of 10 CFR 50 has been granted, or
c. The measured leakage rate exceeding 150 scfh per main steam line or exceeding 250 scfh combined through all four main steam lines, or

-Exempticn to Appcndix "J" of 10 CFR 50-HOPE CREEK 3/4 6-2 Amendment No.171

CONTAINMENT SYSTEMS LIMITING CONDITION FOR OPERATION (Continued)

ACTION (Continued)

d. The measured combined leakage rate for all containment isolation valves which form the boundary for the long-term seal of the feedwater lines exceeding 10 gpm, or
e. The measured combined leakage rate for all other penetrations and containment isolation valves in hydrostatically tested lines which penetrate the primary containment exceeding 10 gpm, restore:
a. The overall integrated leakage rate(s) (Type A test) to be in accordance with the Primary Containment Leakage Rate Testing Program, and
b. The combined leakage rate to be in accordance with the Primary Containment Leakage Rate Testing Program for all primary containment penetrations and all primary containment isolation valves that are subject to Type B and C tests, except for: main steam line isolation valves*, valves which form the boundary for the long-term seal of the feedwater lines, valves which are hydrostatically tested, and those valves where an exemption to Appendix J of 10 CFR 50 has been granted, and
c. The leakage rate to less than or equal to 150 scfh per main steam line and less than or equal to 250 scfh combined through all four main steam lines, and
d. The combined leakage rate for all containment isolation valves which form the boundary for the long-term seal of the feedwater lines to less than or equal to 10 gpm, and
e. The combined leakage rate for all other penetrations and containment isolation valves in hydrostatically tested lines which penetrate the primary containment to less than or equal to 10 gpm, prior to increasing reactor coolant system temperature above 2001F.

SURVEILLANCE REQUIREMENTS 4.6.1.2.a The primary containment leakage rates shall be demonstrated in accordance with the Primary Containment Leakage Rate Testing Program for the following:

1. Type A test.
2. Type B and C tests (including air locks).
b. DELETED.
c. DELETED.

HOPE CREEK 3/4 6-3 Amendment No.171

CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

d. DELETED.
e. DELETED.
f. Main steam line isolation valves shall be leak tested at least once per 18 months.
g. Containment isolation valves which form the boundry for the long-term seal of the feedwater lines shall be hydrostatically tested at 1.10 Pa, 52.9 psig, at least once per 18 months.
h. All containment isolation valves in hydrostatically tested lines which penetrate the primary containment shall be leak tested at least once per 18 months.
i. DELETED.
j. DELETED.

TIOPE CREEK 3/4 G-4 Amendment No.171

CONTAINMENT SYSTEMS 3/4.6.3 PRIMARY CONTAINMENT ISOLATION VALVES LIMITING CONDITION FOR OPERATION 3.6.3 Each primary containment isolation valve and each reactor instrumentation line excess flow check valve shall be OPERABLE.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3.

ACTION:

a. With one or more of the primary containment isolation valves inoperable, maintain at least one isolation valve OPERABLE in each affected penetration that is open and within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> either:
1. Restore the inoperable valve(s) to OPERABLE status, or
2. Isolate each affected penetration by use of at least one deactivated automatic valve secured in the isolated position,* or
3. Isolate each affected penetration by use of at least one closed manual valve or blind-flange.*
4. The provisions of Specification 3.0.4 are not applicable provided that within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> the affected penetration is isolated in accordance with ACTION a.2. or a.3. above, and provided that the associated system, if applicable, is declared inoperable and the appropriate ACTION statements for that system are performed.

Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

b. With one or more of the reactor instrumentation line excess flow check valves inoperable, 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 <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> either:
1. The inoperable valve is returned to OPERABLE status, or
2. The instrument line is isolated and the associated instrument is declared inoperable.

Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

  • Isolation valves closed to satisfy these requirements may be reopened on an intermittent basis under administrative control.

HOPE CREEK 3/4 6-17 6-7 No. 1 71 mendIment.

CEEK3/

HOP

CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS 4.6.3.1 Each primary containment isolation valve shall be demonstrated OPERABLE prior to returning Lhe valve Lo service afLer maiiLenziance, repair or replacement work is performed on the valve or its associated actuator, control or power circuit by cycling the valve through at least one complete cycle of full travel and verifying the specified isolation time.

4.6.3.2 Each primary containment automatic isolation valve shall be demonstrated OPERABLE at least once per 18 months by verifying that on a containment isolation test signal each automatic isolation valve actuates to its isolation position.

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

4.6.3.4 At least once per 18 months, verify that a representative sample of reactor instrumentation line excess flow check valveso actuates to the isolation position on a simulated instrument line break signal.

4.6.3.5 Each traversing in-core probe system explosive isolation valve shall be demonstrated OPERABLE*:

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

b. At least once per 18 months by removing the explosive squib from at least one explosive valve such that each explosive squib in each explosive valve will be tested at least once per 90 months, and initiating the explosive squib. The replacement charge for the exploded squib shall be from the same manufactured batch as the one fired or from another batch which has been certified by having at least one of that batch successfully fired. No squib shall remain in use beyond the expiration of its shelf-life or operating life, as applicable.
  1. The reactor vessel head seal leak detection line (penetration J5C) is not required to be tested pursuant to this requirement.

HOPE CREEK 3/4 6-18 Amendment No.171

TABLE 3.6.3-1 DELETED Pages 3/4 6-20 through 3/4 6-42 have been intentionally omitted HOPE CREEK 3/4 6-19 Amendment No.171

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