Text

Amend 16 to License NPF-10,updating Tech Specs for Consistency W/Unit 3 Tech Specs
	ML20073T283
Person / Time
Site:	San Onofre
Issue date:	04/25/1983
From:	Knighton G; Office of Nuclear Reactor Regulation
To:	;
Shared Package
ML20073T284	List: ML20073T283; ML20073T287; ML20073T288;
References
	NUDOCS 8305110182
	Download: ML20073T283 (81)
	v • d • e

O SOUTHERN CALIFORNIA EDISON COMPANY' SAN DIEGO GAS AND ELECTRIC C0t'PANY THE CITY OF RIVERSIDE, CALIFORNIA THE CITY OF ANAHEIH, CALIFORNIA DOCKET NO. 50-361 SAll ONOFRE NUCLEAR GENERATING STATION, UNIT 2 AMENDMENT 10 FACILITY OPERATING LICENSE Anendment No.16 License No. b'PF-10 1.

The Nuclear Regulatory Comnission (the Comission) has found that:

A.

The applications for amendment for the San Onofre Nuclear Generating Station, Unit 3 (the facility) filed by the Southern California Edison Company on behalf of itself and San Diego Gas and Electric Conpany, The City of Riverside and The Cit" of Anahein, California (licensees) dated Septeaber 3, October 21 and December 1, 1982, conply with the standards and requirenents of the Atomic Eriergy Act of 1954, as amended (the Act) and the Connission's. regulations as set forth in 10 CFR Chapter I; B.

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

There is reasonable assurance (1) that the activities authorized by this anendnent can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Comission's regulations set forth in 10 CFR Chapter I; 0

h9 issuance of this license amendment will not be inimical to the cornon defense and security or to the health and safety of the public; E.

The issuance of this amendnent is in accordance with 10 CFR Part 51 of the Comission's regulations and all applicable requirenents have h en satisfied.

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Accordingly, the license is anended by changes to the Technical Specifi-cations as indicated in the attachment to this license amendment, and paragraph 2.C(2) of Facility Operating License No. hPF-10 is hereby amended to read as follows:

(2) Technical Specifications The Technical Specifications contained in Appendix A and the Environmental Protection Plan contained in Appendix D, as revised through Amendnent Ho.16, are hereby incorporated in the license.

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

3.

This license amendment becomes effective on May 16,1983.

FOR THE NUCLEAR REGULATORY COMMISSION Original signid by:

Ecorge W. Knighton George W. Knighton, Chief Licensing Branch No. 3 Division of Licensing Date of Issuance: APR 2 51c83 OM

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APR 2 51983

, ATTACH!!ENT TO LICENSE AMENDMENT NO. 16 FACILITY OPERATING LICENSE NO. NPF-10 DOCKET NO. 50-362 Replace the following pages of the Appendix A Technical Specifications with the enclosed pages. The revised pages are identified by Anendment number and contain vertical lines indicating the area of change. Also to be replaced are the following overleaf pages to the amendcent pages.

Anendment Pace Overleaf Page I

II VIII VII.

IX X

XI XII XIII XIV XVIII XVII XIX XX XXI XXII 1-3 1-4 3/4 1-5 3/4 1-6 3/4 2-2 3/4 2-1 3/4 3-3 3/4 3-4 3/4 3-8 3/43-7 3/4 3-9 3/4 3-10 3/4 3-11 3/4 3-12 3/4 3-15 3/4 3-16 3/4 3-17 3/4 3-18 3/4 3-24 3/4 3 3/4 3-25 3/4 3 -

3/4 3-28.

3/4 3-27 l

3/4 3-29 3/4:3-30 3/4 3-31

.n4 3-12 orncE).......... 3/.4. 3.: 3.....................

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APR 2 5 B83 i Arendment Page Overleaf Page 3/4 3-53 3/4 3-53a 3/4 3-56 3/4 3-55 3/4 3-57 3/435i8 3/4 3-57 3/4 3-68 3/4 3-70 3/4 3-69 3/4 3-74 3/4 3-73 3/4 3-75 3/4 3-76 e

3/4 4-2 3/4 4-1 3/4 4-3 3/4 4-4 3/4 4-5 3/4 4-6 i

3/4 4-18 3/4 4-17 i

3/4 4-27 3/4 4-28 3/4 4-29 3/4 4-30 3/4 5-3 3/4 5-4 3/4 6-6 3/4 6-5 3/4 6-13 3/4 6-14 3/4 6-15 3/4 6-16 3/4 6-18 3/4 6-17 3/4 6-21 3/4 6-22 3/4 7-13 3/4 7-14 t

3/4 7-26 3/4 7-25 3/4 7-27 3/4 7-28 3/4 7-29 3/4 7-30 3/4 7-34 3/4 7-33 3/4 7-35 3/4 8-4 3/4 8-3 3/4 8-18

-3/4 8-17 l

3/4 8-19 i

3/4 8-20 3/4 8-21 7

3/4 8-22 3/4 8-23 3/4 8-24 3/4 8-25 3/4 8-26 l

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, Anendment Page Overleaf Pace 3/4 11-7 3/4 11-8 3/4 11-9 3/4.11-10 3/4'11-15 3/4 11-16 3/4 12-11 3/4 12-12 B 3/4 1-3 B 3/4 1-4 B 3/4 4-1 B 3/4 4-2 8 3/4 4-7 B 3/4 4-8 B 3/4 4-9 B 3/4 5-3 8 3/4 6-2 B 3/4 6-1 8 3/4 7-2 B 3/4 7-1 B 3/4 9-2 B 3/4 9-1 B 3/4 9-3 B 3/4 10-1 B 3/4 10-2 6-2 6-1 6-4 6-3 6-5 6-6 6-11 6-12 6-14 6-13 I

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INDEX DEFINITIONS PAGE SECTION 1.0 DEFINITIONS 1-1 1.1 ACTI0N......................................................

1-1 1.2 AXIAL SHAPE INDEX.............

1-1 1.3 AZIMUTHAL POWER TILT........................................

1-1 1.4 CHANNEL CALIBRATION........................................

1-1 1.5 CHANNEL CHECK.......................................r.......

1-2 1.6 CHANNEL FUNCTIONAL TEST..............

1-2 1.7 CONTAINMENT INTEGRITY.......................................

1-2 1.8 CO NT RO L LED L EA KAG E..........................................

1-2 1.9 CORE ALTERATION............................................

1-3 1.10 DOSE EQUIVALENT I-131,.....................................

1-3 1.11 E-AVERAGE DISINTEGRATICN ENERGY.............................

1-3 1.12 ENGINEERED SAFETY FEATURES RESPONSE TIME....................

1-3 1.13 FREQUENCY NOTATION.........................................

1-3 1.14 GASEOUS RADWASTE TREATMENT SYSTEM..........................

1-3 1.15 IDENTIFIED LEAKAGE..........................................

1-4 1.16 0FFSITE DOSE CALCULATION MANUAL (0DCM)......................

1-4 1.17 OPERABLE - OPERABILITY......................................

1-4 1.18 OPERATIONAL MODE-MODE............

1-4 1.19 PHYSICS TESTS...............................................

1-4 1.20 PLANAR RADIAL PEAKING FACTOR - Fxy..........................

1-4 1.21 PRESSURE BOUNDARY LEAKAGE...................................

1-4 1.22 PROCESS CONTROL PROGRAM (PCP)...............................

1-5 1.23 PURGE-PURGING...............................................

1-5 1.24 RATED THERMAL POWER....................................,...

1-5 1.25 REACTOR TRIP SYSTEM RESPONSE TIME...........................

1-5 1.26 REPORTABLE OCCURRENCE.....................................

1-5 1.27 SHUTDOWN MARGIN...........

1-5 1.28 50FTWARE...........................

1-5 1.29 SOLIDIFICATION.......,.....................................

1-5 1.30 SOURCE CHECK................................................

1-6 1.31 STAGGERED TEST BASIS.....................................

1-6 1.32 THERMAL P0WER...............................................

1-6 1.33 UNIDENTIFIED LEAKAGE........................................

1-6 1.34 VENTILATION EXHAUST TREATMENT SYSTEM........................

1-6 1.35 VENTING.....................................................

AMENDMENT NO.16 I

SAN ONOFRE-UNIT 2

INDEX SAFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGS SECTION PAGE 2.1 SAFETY LIMITS 2.1.1 REACTOR CORE DNBR....................................................

2-1 PEAK LINEAR HEAT RATE...................................

2-1 REACTOR COOLANT SYSTEM PRESSURE.........................

2-1 2.2 LIMITING SAFE'iY SYSTEM SETTINGS 2.2.1 REACTOR TRIP SETP0lNTS.....................................

2-2 2.2.2 CORE PROTECTION CALCULATION ADDRESSABLE CONSTANTS..........

2-2 BASES SECTION PAGE 2.1 SAFETY LIMITS 2.1.1 REACTOR C0RE...............................................

B 2-1 2.1.2 REACTOR COOLANT SYSTEM PRESSURE............................

B 2-2 2.2 LIMITING SAFETY SYSTEM SETTINGS 2.2.1 REACTOR TRIP SETP01NTS..........................:..........

B 2-2 2.2.2 CPC ADDRESSABLE CONSTANTS..................................

B 2-7 4

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INDEX-LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE 3/4.7 PLANT SYSTEMS 3/4.7.1 TURBINE CYCLE SAFETY VALVES........................................

3/4 7-1 AUXILIARY FEEDWATER SYSTEM................

3/4 7-4 CONDENSATE STOPAGE TANK.....

3/4 7-6 ACTIVITY.............................................

3/4 7-7 MAIN STEAM LINE ISOLATION VALVES................

3/4 7-9 3/4.7.2 STEAM GENERATOR PRESSURE / TEMPERATURE LIMITATION.........

3/4 7-10 3/4.7.3 COMPONENT COOLING WATER SYSTEM.........................

3/4 7-11 3/4.7.4 S ALT WAT E R COO LI NG SYSTEM...............................

3/4 7-12 3/4.7.5 CONTROL ROOM EMERGENCY AIR CLEANUP SYSTEM...............

3/4 7-13 3/4.7.6 SNU3BERS..............................................

3/4 7-16 3/4.7.7 SEALED SOURCE CONTAMINATION................../..........

3/4 7-24 4

3/4.7.8 FIRE SUPPRESSION SYSTEMS FIRE SUPPRESSION WATER SYSTEM........................

3/4 7-26 SPRAY AND/0R SPRINKLER SYSTEMS......................

3/4 7-29 FIRE HOSE STATIONS................................

3/4 7-32 3/4.7.9 FIRE RATED ASSEMBLIES..................................

3/4 7-34 3/4.8 ELECTRICAL POWER SYSTEMS 3/4.8.1 A.C. SOURCES 3/4 8-1 OPERATING.

SHUTDOWN........

3/4 8-8 3/4.8.2 D.C. SOURCES OPERATING............................................

3/4 8-9 SHUTD0WNJ.................................

3/4 8-12 O

SAN GNOTRE-UNIT 2 VII

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS PAGE

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SECTION i

3/4.8.3 ONSITE POWER DISTRIBUTION SYSTEMS 3/4 8-13 OPERATING............................................

3/4 8-15 I

SHUTD0WN.............................................

3/4.8.4 ELECTRICAL EQUIPMENT PROTECTION DEVICES CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES.................................

3/4 8-16 MOTOR-0PERATED VALVES THERMAL OVERLOAD PROTECTION 3/4 8-31 BYPAS5.............................................

i 3/4.9 REFUELING OPERATIONS 3/4.9.1 BORON CONCENTRATION.....................................

3/4 9-1 3/4 9-2 3/4.9.2 INSTRUMENTATION.........................................

g 3/4 9-3 3/4.9.3 DECAY TIME..............................................

3/4.9.4 CONTAINMENT BUILDING PENETRATIONS.......................

3/4 9-4 4

1 3/4 9-5 3/4.9.5 COMMUNICATIONS..........................................

3/4.9.6 REFUELING MACHINE.......................................

3/4 9-6 f

3/4.9.7 FUEL HANDLING MACHINE - SPENT FUEL STORAGE POOL BUILDING 3/4 9-7 3/4.9.8 SHUTDOWN COOLING AND COOLANT CIRCULATION HIGH WATER LEVEL.....................................

3/4 9-8 I

LOW WATER LEVEL......................................

3/4 9-9 3/4.9.9 CONTAINMENT PURGE ISOLATION SYSTEM......................

3/4 9-10 3/4.9.10 WAT E R LEV E L - RE ACTO R V E S S E L............................

3/4 9-11 I

3/4.9.11 WATER LEVEL - STORAGE P00 L..............................

3/4 9-12 3/4.9.12 FUEL HANDLING BUILDING POST-ACCIDENT CLEANUP FILTER 3/4 9-13 SYSTEM...............................................

3/4.10 SPECIAL TEST EXCEPTIONS 4

3/4.10.1 SHUTDOWN MARGIN.........................................

3/4 10-1 3/4.10.2 GROUP HEIGHT, INSERTION AND POWER DISTRIBUTION LIMITS............................

3/4 10-2 3/4.10.3 REACTO R COO LANT L00P S...................................

3/4 10-3 3/4.10.4 CENTER CEA MISALIGNMENT.................................

3/4 10-4 3/4.10.5 RADIATION MONITORING / SAMPLING...........................

3/4 10-5 1

SAN ONOFRE-UNIT 2 VIII AMENDMENT NO.16

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LIMITING CONDITIONS =FOR OPERATION AND SURVEILLANCE REQUIREMENTS j

e i

i SECTION PAGE i,

3/4.11 RADI0 ACTIVE EFFLUENTS 3/4.11.1 LIQUID EFFLUENTS CONCENTRATION.........................................

3/4 11-1 00SE..................................................

3/4 11-5 j

LIQUID WASTE TREATMENT................................

3/4 11-6

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LIQUID HOLDUP TANKS...................................

3/4 11-7 1

3/4.11.2 GASE0US EFFLUENTS I

DOSE RATE.............................................

3/4 11-8 3

DOSE-N0BLE GASES......................................

3/4 11-12 i

DOSE-RADIGIODINES, RADI0 ACTIVE MATERIALS IN I

PARTICULATE FORM AND TRITIUM........................

3/4'11-13 i

GASEOUS RADWASTE TREATMENT............................

13/4 11-14 i

EXPLOSIVE GAS MIXTURE.................................

3/4 11-15 GAS STORAGE TANKS.....................................

3/4 11-16 1

4 4

i 3/4.11.3 SOLID RADI0 ACTIVE WASTE...............................

3/4 11 4 l

3/4.11.4 TOTAL 00SE............................................

3/4 11-19 1

i 3/4.12 RADIOLOGICAL ENVIRONMENTAL MONITORING l

3/4.12.1 MONITORING PR0 GRAM....................................

3/4'12-1

-3/4.12.2 LAND USE CENSUS.......................................

3/4'12-11 3/4.12.3 INTERLABORATORY~COMPARIS0N PR0 GRAM....................

3/4 12-12

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INDEX BASES PAGE SECTION 3/4.0 APPLICABILITY............................................

B 3/4 0-1 3/4.1 REACTIVITY CONTROL SYSTEMS i

3/4.1.1 B0 RATION CONTR0L......................................

B 3/4 1-1 3/4.1.2 BOR5TIONSYSTEMS......................................

B'3/4 1-2 l

3/4.1.3 MOVABLE CONTROL ASSEMBLIES............................

B 3/4 1-3 l

3/4.2 POWER DI5TRIBUTION LIMITS 3/4.2.1 LINEAR HEAT RATE......................................

B 3/4 2-1 3/4.2.2 PLANAR RADIAL PEAKING FACT 0RS.........................

B 3/4 2-2 3/4.2.3 AZ IMUTH A L POWE R T I LT..................................

B 3/4 2-2 3/4.2.4 DNBR MARGIN...........................................

B 3/4 2-3 3/4.2.5 R C S F LOW RAT E.........................................

B 3/4 2-4 3/4.2.6 REACTOR COOLANT COLD LEG TEMPERATURE..................

B 3/4 2-4 3/4.2.7 AXIAL SHAPE IN0EX.....................................

B 3/4 2-4 3/4 2.8 PRESSURIZER PRESSURE..................................

B 3/4 2-4 3/4.3 INSTRUMENTATION 3/4.3.1 and 3/4.3.2 REACTOR PROTECTIVE and ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION.............

B 3/4 3-1 3/4.3.3 MONITbRINGINSTRUMENTATION..............................

B 3/4 3-2 3/4.3.4 TURBINE OVERSPEED PROTECTION............................

B 3/4 3-4 e

SAN ONOFRE-UNIT 2 X

AMEN 0t1ENT NO. 16

INDEX BASES

.SECTION.

PAGE 3/4.4 REACTOR COOLANT SYSTEM 3/4.4.1 REACTOR COOLANT LOOPS AND COOLANT CIRCULATION.........

B 3/4 4-1 3/4.4.2 SAFETY VALVES.........................................

B 3/4-4-1 3/4.4.3 PRESSURIZER...........................................

B 3/4.4-2 3/4.4.4 STEAM GENERATORS......................................

B 3/4-4-2 3/4.4.5 REACTOR COOLANT SYSTEM LEAKAGE........................

.8 3/4 4-4 3/4.4.6 CHEMISTRY.............................................

B 3/4.4-4 3/4.4.7 SPECIFIC ACTIVITY.....................................

B 3/4 4-5 3/4.4.8 PRESSURE / TEMPERATURE LIMITS...........................

B 3/4 4 3/4.4.9 STRUCTURAL INTEGRITY...'...............................

'B 3/4 4-9 3/4.5 EMERGENCY CORE COOLING SYSTEMS 3/4.5.1 SAFETY INJECTION TANKS................................

B 3/4 5-1~

3/4.5.2 and 3/4.5.3 ECCS SUBSYSTEMS...........................

B 3/4 5-1 3/4.5.4 REFUELING WATER TANK..................................

B 3/4 5-2 1

2

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4 SAN ONOFRE-UNIT 2 XI AMEN 0 MENT NO.'16

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INDEX BASES 4

i PAGE SECTION 3/4.6 CONTAINMENT SYSTEMS B 3/4 6-1 3/4.6.1 PRIMARY C0NTAISMENT...................................

3/4.6.2 DEPRESSURIZATION AND COOLING SYSTEMS..................

B 3/4 6-3 3/4.6.3 CONTAINMENT ISOLATION VALVES..........................

- B 3/4 6-4 B 3/4 6-5

- 3/4.6.4 COMBUSTIBLE GAS CONTR0L...............................

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1 INDEX i

F BASES-i PAGE

_SECTION 4

i -

3/4.7 PLANT SYSTEMS B 3/4 7-1 I

l 3/4.7.1 TURBINE CYCLE.........................................

3/4.7.2 STEAM GENERATOR PRESSURE / TEMPERATURE LIMITATION.......

B 3/4 7-3 3/4.7.3 COMPONENT COOLING WATER SYSTEM........................

B 3/4 7-3 J

B 3/4 7-3 3/4.7.4 S ALT WATER COO LING SYSTEM.............................

j 3/4.7.5 CONTROL ROOM EMERGENCY AIR CLEANUP SYSTEM.............

' B 3/4.7-4 B 3/4 7-5 1

3/4.7.6 SNUBBERS..............................................

4 i

3/4.7.7 SEALED SOURCE CONTAMINATION...........................

B 3/4 7-6 3/4.7.8 FIRE SUPPRESSION SYSTEMS..............................

B 3/4.7-6 I

3/4.7.9 FIRE RATED ASSEMBLIES.................................

- B 3/4-7-7.

I 3/4.8 ELECTRICAL POWER SYSTEMS J

J 3/4.8.1, 3/4.8.2 and 3/4.8.3 A.C. SOURCES, DC SOURCES:and ONSITE POWER DISTRIBUTION SYSTEMS................

B 3/4 8-1 3/4.8.4 ELECTRICAL EQUIPMENT PROTECTIVE DEVICES...............

B 3/4 8 :

3/4.9 REFUELING OPERATIONS l

3/4.9.1 BORON CONCENTRATION...................................

B 3/4 9-1 B 3/4 9-1 3/4.9.2 INSTRUMENTATION.......................................

B 3/4 9-1 d -

3/4.9.3 DECAY TIME............................................

l B'3/4'9-1 l

3/4.9.4 CONTAINMENT PENETRATIONS..............................

lB 3/4 9-1 3/4.9.5 COMMUNICATIONS........................................-

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AMENDMENT NO.16-SAN ONOFRE-UNIT 2-XIII

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INDEX BASES PAGE SECTION B 3/4 9-2 3/4.9.6 REFUELING MACHINE.....................................

3/4.9.7 FUEL HANDLING MACHINE - SPENT FUEL STORAGE BUILDING...

B 3/4 9-2 B 3/4 9-2 3/4.9.8 SHUTDOWN COOLING AND COOLANT CIRCULATION..............

B 3/4 9-3 3/4.9.9 CONTAINMENT PURGE VALVE ISOLATION SYSTEM..............

3/4.9.10 and 3/4.9.11 WATER LEVEL - REACTOR VESSEL and B 3/4 9-3 STORAGE POOL.........................................

3/4.9.12 FUEL HANDLING BUILDING POST-ACCIDENT CLEANUP FILTER B 3/4 9-3 SYSTEM..............................................

3/4.10 SPECIAL TEST EXCEPTIONS B 3/4 10-1 3/4.10.1 SHUTDOWN MARGIN.......................................

3/4.10.2 GROUP HEIGHT, INSERTION AND B 3/4 10-1 POWER DISTRIBUTION LIMITS...........................

B.3/4 10-1 3/4.10.3 REACTOR COO LANT L00 P S.................................

B 3/4 10-1 j

3/4.10.4 CENTER CEA MISALIGNMENT...............................

i B 3/4 10-1 3/4.10.S RADIATION MONITORING / SAMPLING.........................

P I

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SAN ONOFRE-UNIT 2 XIV AMENDMENT NO.16

,0 INDEX

,ACMINISTRATIVE CONTROLS SECTION PAGE 6.1 RESPONSIBILITY.........'......................................

6-1 6.2 ORGANIZATION 6.2.1 0FFSITE.................................................

6-1 6.2.2 UNIT STAFF..............................................

6-1 6.2.3 INDEPENDENT SAFETY ENGINEERING GROUP....................

6-5 6.2.4 SHIFT TECHNICAL ADVIS0R...................'..............

6-5 6.3 UNIT STAFF 0UALIFICATIONS....................................

6-5 6.4 TRAINING.................................

6-6 6.5 REVIEW AND AUDIT 6.5.1 ONSITE REVIEW COMMITTEE FUNCTION...................................,.........

6-6 COMPOSITION..........................................

6-6 3

ALTERNATES.........................,..................

6-6 MEETING FREQUENCY....................................

6-7 QU0 RUM...............................................

6-7 RESP 0NSIBILITIES.....................................

6-7 AUTHORITY............................................

6-8 REC 0RDS..............................................

6-8 6.5.2 TECHNICAL REVIEW AND CONTR0L......................'......

6 6 5.3 NUCLEAR SAFETY GROUP FUNCTION................................................

6-9 COMPOSITION.............................................

6-10:

CONSULTANTS.............................................

.6-10 REVIEW..................................................

6-10 4U01T5..................................................

6-11 SAN ONOFRE-UNIT 2 XVII

INDEX ADMINISTRATIVE CONTROLS PAGE SECTION 6-12 AUTH0RITY...............................................

6-12 REC 0RDS.................................................

6-13 6.6 REPORTABLE OCCURRENCE ACTI0N.................................

6-13 6.7 SAFETY LIMIT VIOLATION.......................................

6-13 6.8 PROCEDURES AND PR0 GRAMS......................................

6.9 REPORTING REQUIREMENTS 6-15 6.9.1 ROUTINE AND REPORTABLE OCCURRENCES......................

6-16 STARTUP REP 0RT.......................................

3 6-16 ANNUAL REP 0RTS.......................................

ANNUAL RADIOLOGICAL ENVIRONMENTAL OPERATING REPORT...6-17 SEMIANNUAL RADI0 ACTIVE EFFLUENT RELEASE REPORT.......

6-17 6-19 MONTHLY OPERATING REP 0RT.............................

6-19 REPORTABLE OCCURRENCES...............................

PROMPT NOTIFICATION WITH WRITTEN FOLLOWUP............

6-19 6-21 THIRTY DAY WRITTEN REP 0RTS...........................

6-21 HAZARDOUS CARGO TRAFFIC REP 0RT.......................

6-21 6.9.2 SPECIAL REPORTS........................................

6-21 6.10 RECOPD RETENTION............................................

6-23 6.11 RADIATION PROTECTION PR0 GRAM................................

6-23 6.12 HICH RADIATION AREA.........................................

6-24 6.13 PROCESS CGNTROL PROGRAM (PCP)...............................

6-25 6.14 0FFSITE DOSE CALCULATION MANUAL.............................

6-25

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I 6.15 MAJOR CHANGES TO RADI0 ACTIVE WASTE TREATMENT SYSTEMS........

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SAN ONOFRE-UNIT 2 XVIII AMENDMENT NO. 16 e

INDEX LIST OF TABLES TABLE PAGE 1.1 O P E RAT I ON A L M3 D E S.......................'..................

1-7 1.2 FREQUENCY N0TATION........................................

1-8 2.2-1 RE.^CTOR PROTECTIVE INSTRUMENTATION TRIP SETPOINT LIMITS...

2-3 2.2-2 CORE PROTECTION CALCULATOR ADDRESSABLE CONSTANTS..........

2-5 3.3-1 REACTOR PROTECTIVE INSTRUMENTATION........................

3/4 3-3 3.3-2 REACTOR PROTECTIVE INSTRUMENTATION RESPONSE TIMES.........

3/4 3-8 4.3-1 REACTOR PROTECTIVE INSTRUMENTATION SURVEILLANCE REQUIREMENTS..............................................

3/4 3-10 3.3-3 ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION...........................................

3/4 3-14 3.3-4 ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION TRIPVALUES...............................................- 3/4 3-22 3.3-5 ENGINEERED SAFETY FEAiURES RESPONSE TIMES.................

3/4 3-27 4.3-2 ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS.................................

3/4 3-31 3.3-6 RADIATION MONITORING ALARM INSTRUMENTATION................

3/4/3-35 4.3-3 RADIATION MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS..............................................

3/4/3-38 3.5-7 SEISMIC MONITORING INSTRUMENTATION........................

3/4 3-43 4.3-4 SEISMIC MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS.................................

3/4 3-44 3.3-8 _

METEOROLOGICAL MONITORING INSTRUMENTATION.................

3/4 3-46 4.3-5 METEOROLOGICAL MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS..............................................

3/4 3-47 3.3-9 REMOTE SHUTDOWN MONITORING INSTRUMENTATION................

3/4 3-49 l

4.3-6 REMOTE SHUTDOWN MONITORING INSTRUMENTATION SURVEILLANCE l

, REQUIREMENTS..............................................

3/4 3-50 l

l St.N ONOFRE-UNIT 2 XIX AMENDMENT NO.16 l

l l

INDEX LIST OF TABLES TABLE PAGE 3.3-10 ACCIDENT MONITORING INSTRUMENTATION.......................

3/4 3-52 4.3-7 ACCIDENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS.............................................

3/4 3-54 3.3-11 FIRE DETECTION INSTRUMENTS-MINIMUM INSTRUMENTS OPERABLE..

3/4 3-57 j

3.3-12 RADI0 ACTIVE LIQUID EFFLUENT MONITORING INSTRUMENTATION...

3/4 3-64 4.3-8 RADI0 ACTIVE LIQUID EFFLUENT MONITORING INSTRUMENTATION SU RVEI L LAN C E R EQUI R EMENTS................................

3/4 3-66 3.3-13 RADI0 ACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION..

3/4 3-69 4.3-9 RADI0 ACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS................................

3/4 3-71 4.4-1 MINIMUM NUMBER OF STEAM GENERATORS TO BE INSPECTED DURING INSERVICE INSPECTION.....................................

3/4 4-14 4.4-2 STEAM GENERATOR TUBE INSPECTION..........................

3/4 4-15 3.4-1 REACTOR COOLANT SYSTEM PRESSURE ISOLATION VALVES.........

3/4 4-19 3.4-2 REACTOR COOLANT SYSTEM CHEMISTRY.........................

3/4.4-21 4.4-3 REACTOR COOLANT SYSTEM CHEMISTRY LIMITS SURVEILLANCE REQUIREMENTS.............................................

3/4 4-22 4.4-4 PRIMARY COOLANT SPECIFIC ACTIVITY SAMPLE AND ANALYSIS PR0 GRAM..................................................

3/4 4-25 4.4-5 REACTOR VESSEL MATERIAL SURVEILLANCE' PROGRAM-WITHDRAWAL SCHEDULE.................................................

3/4 4-28 4.6-1 TENDON SURVEILLANCE......................................

3/4 6-12 4.6-2 TENDON LIFT-OFF F0RCE....................................

3/4 6-12a 3.6-1 CONTAINMENT ISO LATION VALVES.............................

3/4 6-20 3.7-1 STEAM LINE SAFETY VALVES PER L00P........................

3/4 7-2 3.7-2 MAXIMUM ALLOWABLE LINEAR POWER LEVEL-HIGH TRIP SETPOINT

'WITH INOPERABLE STEAM LINE SAFETY YALVES DURING OPERATION

- WITH BOTH STEAM GENERATORS...............................

3/4 7-3 SAN ONOFRE-UNIT 2 XX AMENDMENT NO.16 l

k s

INDEX r

LIST OF TABLES-t TABLE PAGE i

4.7-1 SECONDARY COOLANT SYSTEM SPECIFIC ACTIVITY 4

l SAMPLE AND ANALYSIS PR0 GRAM..............................

3/4 7-8 3.7-4a SAFETY-RELATED HYDRAULIC SNUBBERS........................

3/4 7-22 3.7-4b SAFETY-RELATED MECHANICAL SNUBBERS.......................

3/4 7-23 i

3.7-5 SAFETY-RELATED SPRAY AND/0R SPRINKLER SYSTEMS............

3/4 7-31 3.7-6 FIRE HOSE STATIONS.......................................

3/4 7-33 4.8-1 DIESEL GENE RATO R TEST SCHEDULE...........................

3/4 8-7 i

4.8-2 BATTERY SURVEI LLANCE REQUIREMENTS........................

3/4 8-11 1

3.8-1 CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES.......................................

3/4 8-1C l

3.8-2 MOTOR OPERATED VALVES THERMAL OVERLOAD PROTECTION BYPASS DEVICES...........................................

3/4 8-32 3.10-1 RADIATION MONITORING / SAMPLING EXCEPTIONS.................

3/4 10-6 4.11-1 RADI0 ACTIVE LIQUID WASTE SAMPLING AND ANALYSIS PROGRAM...

3/4 11-2 4.11-2 RADI0 ACTIVE GASEOUS WASTE SAMPLING AND ANALYSIS j

PR0 GRAM..................................................

3/4 11-9 3.12-1 RADIOLOGICAL ENVIRONMENTAL MONITORING PROGRAM............

3/4 12-3 i

3.12-2 REPORTIN3 LEVELS FOR RADIOACTIVITY CONCENTRATIONS IN ENVI RONMENTA L S AMP LES....................................

3/4 12-7 l

j 4.12-1 MAXIMUM VALUES FOR THE LOWER LIMITS OF DETECION (LLD)....

3/4 12-8 1

8 3/4. 4-1 REACTOR VESSEL TOUGHNESS.................................

B 3/4 4-8 i

~

S.7-1 COMPONENT CYCLIC OR TRANSIENT LIMITS.....................

5-8 i

6.2-1 MINIMUM SHIFT CREW COMPOSITION...........................

6-4 l

l l

SAN ONOFRE-UNIT 2 XXI AMENDMENT NO.'16'

INDEX i

LIST OF FIGURES FIGURES PAGE 3.1-1 MINIMUM BORIC ACID STORAGE TANK VOLUME AND TEMPERATURES AS A FUNCTION OF-STORED BORIC ACID CONCENTRATION.........

3/4 1-13 3.1-2 CEA INSERTION LIMITS.....................................

3/4 1-24 3.2-1 DNBR MARGIN OPERATING LIMIT BASED ON C0lSS...............

3/4 2-7 3.2-2 DNBR MARGIN OPERATING LIMIT BASED ON CORE PROTECTION CALCULATORS (COLSS OUT OF SERVICE).......................

3/4 2-8 3.3-1 DEGRADED BUS VOLTAGE TRIP SETTING........................

3/4 3-40 4.4-1 TUBE WALL THINNING ACCEPTANCE-CRITERIA...................

3/4 4-15a 3.4-1 DOSE EQUIVALENT I-131 PRIMARY COOLANT SPECIFIC ACTIVITY LIMIT...........................................

3/4 4-26 3.4-2 HEATUP RCS PRESSURE / TEMPERATURE LIMITATIONS FOR 0-5 YEARS............................................

3/4 4-29 3.4-3 C00LDOWN RCS PRESSURE / TEMPERATURE LIMITATIONS FOR 0-5 YEARS................................................

3/4 4-30 3.7-1 MINIMUM REQUIRED FEEDWATER INVENTORY FOR TANK T-121 FOR MAXIMUM POWER ACHIEVED TO DATE............

3/4 7-6A 4.7-1 SAMPLING P LAN FOR SNUBBER FUNCTIONAL TEST................

3/4 7-21 5.1-1 EXCLUSION AREA...........................................

5-2 5.1-2 LOW POPULATION Z0NE......................................

5-3 5.1-3 SITE BOUNDARY FOR GASEOUS EFFLUENTS......................

5-4 5.1-4 SITE BOUNDARY FOR LIQUID EFFLUENTS.......................

5-5 6.2-1 0FFSITE ORGANIZATION.....................................

6-2 6.2-2 UNIT ORGANIZATION........................................

6-3 C

6.2-3 CONTROL ROOM AREA........................................

6-4a SAN ONOFRE-UNIT 2 XX'1 AMENDMENT NO.16

DEFINITIONS DOSE EQUIVALENT I-131 1.10 DOSE EQUIVALENT I-131'shall be that concentration of I-131 (microcuries/

gram) which alone would produce the same thyroid dose as the quantity and f

isotopic mixture of I-131, I-132, I-133, I-134 and I-135 actually present.

The thyroid dose conversion factors used for this calculation shall be those listed in Table III of TID-14844, " Calculation of Distance Factors for Power and Test Reactor Sites."

E - AVERAGE DISINTEGRATION ENERGY 1.11 E shall be the average (weighted in proportion tn the concentration of each radionuclide in the reactor coolant at the time of sampling) of the sum of the average beta and gamma energies per disintegration (in MeV) for isotopes, other than iodines, with half lives greater than 15 minutes, making up at least 95% of the total non-iodine activity in the coolant.

ENGINFERED SAFETY FEATURES RESPONSE TIME 1.12 The ENGINEERED SAFETY FEATURES RESPONSE TIME shall be that time interval from when the monitored parameter exceeds its ESF actuation setpoint at the channel sensor until the ESF equipment is capable of performing its safety function (i.e., the valves travel to their required positions, pump discharge 1

pressures reach their required values, etc.). Times shall include diesel generator starting and sequence loading delays where applicable.

FREQUENCY NOTATION 1.13 The FREQUENCY NOTATION specified for the performance of Surveillance Requirements shall correspond to the intervals defined in Table 1.~2.

GASEOUS RA0 WASTE TREATMENT SYSTEM 1.14 A GASEOUS RADWASTE TREATMENT SYSTEM is any system designed and installed to reduce radioactive gaseous effluents by collecting primary coolant system offgases from the primary system and providing for delay or holoup for the:

purpose of reducing the total radioactivity prior to release to the environment.

IDENTIFIED LEAKAGE 4

1.15 IDENTIFIED LEAKAGE shall be:

Leakage into closed systems, such as pump seal or valve packing a.

leaks that are captured, and conducted to a sump or collecting tank, or b.

Leakage into the containment atmosphere from sources that are both specifically located and known either not to interfere with the operation of leakage detection systems or not to be PRESSURE B0UNDARY LEAKAGE, or I

Reactor coolant system leakage through a steam generator to the c

secondary system.

' MENDMENT NO.16 A

SAN ONOFRE-UNIT 2 1-3

DEFINITIONS OffSITE DOSE CALCULATION MANUAL (00CM) 1.16 The OFFSITE DOSE CALCULATION MANUAL shall contain the methodology and parameters used in the calculation of offsite doses due to radioactive gaseous and liquid effluents and in the calculation of gaseous and liquid effluent monitoring alarm / trip setpoints.

OPERABLE - OPERABILITY 1.17 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, electrica1 power, cooling or seal water, lubrication or other auxiliary equipment that are required for the system, subsystem, train, component or device to perform its i

function (s) are also capable of performing their related support function (s).

OPERATIONAL MODE - MODE i

1.18 An OPERATIONAL MODE (i.e. MODE) shall correspond to any one inclusive combination of core reactivity condition, power level and average reactor coolant temperature specified in Table 1.1.,

PHYSICS TESTS

~

4 1.19 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 14.0 of the FSAR, 2) authorized under the provisions of 10 CFR 50.59, or 3) otherwise approved by the Commission.

PLANAR RADIAL PEAKING FACTOR - Fg i

1.20 The PLANAR RADIAL PEAKING FACTOR is the ratio of the peak to plane average power density of the individual fuel rods in a given horizontal plane, excluding the effects of azimuthal tilt.

PRESSURE BOUNDARY LEAKAGE 1

1.21 PRESSURE BOUNDARY LEAKAGE shall be leakage (except steam generator tube leakage) through a non-isolable fault in a Reactor Coolant System component body, pipe wall or vessel wall.

PROCESS CONTROL PROGRAM (PCP) 1.22 The PROCESS CONTROL PROGRAM shall contain the sampling, analysis, and formulation determination by which SOLIDIFICATION of radi'oactive wastes from liquid systems is assured.

SAN ONOFRE-UNIT 2 1-4

REACTIVITY CONTROL SYSTEMS MINIMUM TEMPERATURE FOR CRITICALITf LIMITING CONDITION FOR OPERATION 3.1.1.4 The Reactor Coolant System lowest-operating loop temperature (T"V9) shall be greater than or equal to 520 F.

APPLICABIlllY:

MODES 1 and 2#.

ACTION:

WithaReactorCoolantSystembperatinglooptemperature(Ttowithinitslimitwithin15m in HOT STANDBY 520 F, restore T withinthenexti$9 minutes.

SURVEILLANCE REQUIREMENTS 4.1.1.4 The Reactor Coolant System temperature (Tavg) shall be determined to-be greater than or equal to 520 F:

Within 15 minutes prior to achieving reactor criticality, and a.

b.

At least once per 30 minutes when the reactor is critical and the Reactor Coolant System T,yg is less than 535'F.

f

With K,ff greater than or equal to 1.0.

3/4 1-5 AMEN 0 MENT NO. 16 SAN ONOFRE-UNIT 2

REACTIVITY CONTROL SYSTEMS

~

3/4.1.2 BORATION SYSTEMS i

FLOW PATH - SHUTDOWN LIMITING CONDITION FOR OPERATION 1

i 3.1.2.1 As a minimum, one of the following boron injection flow paths and one associated heat tracing circuit shall be OPERABLE and capable of being powered from an OPERABLE emergency power source.

A flow path from either boric acid makeup tank via either one of the J

a.

boric acid makeup pumps, the blending tee or the gravity feed connection and any charging pump to the Reactor Coolant System if i

the boric acid makeup tank in Specification 3.1.2.7.a is OPERABLE, or The flow path from the refueling water tank via either a charging b.

pump or a high pressure safety injection pump to the Reactor Coolant System if the refueling water storage tank in Specification 3.1.2.7.b

]

is OPERABLE.

1 APPLICABILITY:

MODES 5 and 6.,

ACTION:

1 With none of the above flow paths OPERABLE or capable of being powered from an OPERABLE emergency power source, suspend all operations involving CORE l

i ALTERATIONS or positive reactivity changes.

4 SURVEILLANCE REQUIREMENTS 4.1.2.1 At least one of the above required flow paths shall be demonstrated OPERABLE:

At least once per 7 days by verifying that the temperature of the a.

heat traced portion of the flow path is above t,he temperature limit line shown on Figure 3.1-1 when a flow path.from tne boric acid makeup tanks is used.

At least once per 31 days by verifying that each valve (manual, '

b.

power operated or automatic) in the flow path that is not locked, sealed, or otherwise secured in position, is in its correct position.

d SAN ONOFRE-UNIT 2 3/4 1-6

n 3 /4. 2 POWER DISTRIBUTION LIMITS 2 a.2.1 LINEAR HEAT RATE L:MITING CONDITION FOR OPERATION 3.2.1 The linear heat rate shall not exceed 13.9 kw/ft.

APPLICABILITY: MODE 1 above 20% of RATED THERMAL POWER.

ACTION:

With the linear h' eat rate exceeding its limits, as indicated by either (1) the COLSS calculated core power exceeding the COLSS calculated core power operating limit based on kw/f t; or (2) when the COLSS is not being used, any OPERABLE Local Power Density channel exceeding the linear heat rate limit, within 15 minutes initiate corrective action to reduce the linear heat rate to within the limits and either:

a.

Restore the linear heat rate to within its limits within one hour, or b.

Be in at least HOT STANDBY within'the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

SURVEILLANCE REQUIREMENTS 4

4.2.1.1 The provisions of Specification 4.0.4 are not applicable.

4. 2.1. 2 The linear heat rate shall be determined to be within its limits when THERHAL POWER is above 20% of RATED THERMAL POWER by continuously monitoring the core power distribution with the Core Operating Limit Supervisory System (COLSS) or, with the COLSS out of service, by verifying at least once per 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months that the linear heat rate, as indicated on all OPERABLE Local Power Density channels, is within the limit of 13.9 kw/ft.

4.2.1.3 At least once per 31 days, the COLSS Margin Alarm shall be verified to actuate at a THERMAL POWER level less than or equal to the core power operating limit based on kw/f t.

[

l l

l SAS ON0FRE-UNIT 2 3/4 2-1 l

1

POWER DISTRIBUTION LIMITS 3/4.2.2 PLANAR RADIAL PEAKING FACTORS - Fy LIMITING CONDITION FOR OPERATION 3.2.2 The measured PLANAR RADIAL PEAKING FACTORS (F" ) shall be less than or y

equal to the PLANAR RADIAL PEAKING FACTORS (Fc ) used in the Core Operating Limit Supervisory System (COLSS) and in the Core Protection Calculators (CPC).

APPLICABILITY:

MODE I above 20% of RATED THERMAL POWER.*

ACTION:

With a F" exceeding a corresponding F y, within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months either:

C a.

Adjust the CPC and COLSS addressable constants to increase the multiplier applied to PLANAR RADIAL PEAKING FACTORS to a factor greater than or equal to (F" /Fxy)I 0" y

b.

Adjust only the CPC addressable constants as in (a). Restrict subsequent operation so that a margin to the COLSS operating limits c

of at least [(F"y/Fxy) - 1.0] x 100% is maintained; or c.

Adjust the affected PLANAR RADIAL PEAKING FACTORS (Fc ) used in the y

COLSS and CPC to a value greater than or equal to the measured PLANARRADIALPEAKINGFACTORS(F[y)or d.

Be in at least HOT STANDBY.

SURVEILLANCE REQUIREMENTS 4.2.2.1 The provisions of Specification 4.0.4 are not applicable.

The measured PLANAR RADIAL PEAKING FACTORS (F"y) obtained by using 4.2.2.2 the incore detection system, shall be determined to be less than or equal to c

the PLANAR RADIAL PEAKING FACTORS (Fxy), used in the COLSS and CPC at the following intervals:

a.

After each fuel loading with THERMAL POWER greater than 40% but i

prior to operation above 70% of RATED THERMAL POWER, and b.

At least once per 31 EFPD.

See Special Test Exception 3.10.2.

SAN ONOFRE-UNIT 2 3/4 2-2 AMENDMENT NO.16

_ _ _. ~

, TABLE 3.3-1 REACTOR PROTECTIVE INSTRUMENTATION

$f Z

MINIMUM TOTAL NO.

CHANNELS CHANNELS APPLICABLE T

FUNCTIONAL UNIT OF CHANNELS TO TRIP __

OPERABLE MODES ACTION 5

1.

Manual Reactor Trip 2 sets of 2 1 set of 2 2 sets of 2 1, 2 1

c 2 sets of 2 1 set of 2 2 sets of 2 3*, 4*, 5*

7A 2.

Linear Power Level - High 4

2 3

1, 2 2#, 3#

3.

Logarithmic Power Level - High a.

Startup and Operating 4

2(a)(d) 3 1, 2 2#, 3#

4 2

3 3*,

4*, 5*

7A b.

Shutdown 4

0 2

3, 4, 5 4

4.

Pressurizer Pressure - High 4

2 3

1, 2 2#, 3#

5.

Pressurizer Pressure - Low 4

2(b) 3 1, 2 2#, 3#

(

6.

Contain' ment Pressure - High 4

2 3

1, 2 2#,'3#

[

7.

Steam Generator Pressure - Low 4/SG 2/SG 3/SG 1, 2 2#,~3#

E 8.

Steam Generator Level - Low 4/SG 2/SG 3/SG 1, 2 2#, 3#

9.

Local Power Density - High 4

2(c)(d) 3 1, _ 2 2#, 3A

10. DNBR - Low 4

2(c)(d) 3

'1, 2

2#, 3#

11. Steam Generator Level - High 4/SG 2/SG 3/SG 1, 2 2#, 3#'

12. Reactor Protection System Logic 4

2 3

1, 2 2#, 3#

~

3*, 4*, 5*

7A

13. Reactor Trip Breakers 4

2(f) 4 1,~2 5

3*, 4*, 5*

7A

14. Core Protection Calculators 4

2(c)(d) 3 1, 2 2#, 34, 7 h

15. CEA Calculators 2

'1 2(e) 1, - 2 6, 7 l

16. Reactor Coolant Flow - Low 4/SG 2/SG 3/SG 1, 2 2#, 3#

4 2

3 1, 2 2#, 3#

5

17. Seismic - High

'5

18. Loss of Load 4

2 3

1(g) 2#, 3f/

m

4

~.

d b

6

}

TABLE 3.3-1 (Continued)

TABLE NOTATION AWith the protective system ~ trip breakers in the closed position, the CEA drive system capable of CEA withdrawal, and fuel in the reactor vessel.

The provisions of Specification 3.0.4 are not applicable.

~

~4 (a) Trip may be manually bypassed above 10 % of RATED THERMAL POWER; bypass shall g% of RATED THERMAL POWER.e automatically removed when THERMAL PO to 10

~

(b) Trip may be manually bypassed below 400 psia; byoass shall be automatically removed whenever pressurizer pressure is greater than or equal to 400 psia.

-4 (c) Trip may be =anually bypassed below 10 % of RATED THERMAL POWER; bypass shallbeauy%ofRATEDTHERMALPOWER.matically removed when THERMAL POWER equal to 10 During testing pursuant to Special Test Exception 3.10.3, trip may be manually' bypassed below 5% of RATED THERMAL POWER; bypass shall.be automatically removed when THERMAL ~

POWER is greater than or equal to 5% of RATED THERMAL POWER.

(d) Trip may be bypassed during testing pursuant to Special Test Exception 3.10.3.

(e)

See Special Test Exception 3.10.2.

(f) Each channel shall be comprised of two trip breakers; actual trip logic shall be one-out-of-two taken twice.

(g) Trip may be bypassed below 55% RATED THERMAL POWER.

ACTION STATEMENTS ACTION 1 With the number of channels OPERABLE one less than required by the Minimum Channels OPERABLE requirement, restore.the inoperable channel to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or'be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and/or open the protective system trip breakers.

With the number of channels OPERABLE one-less than the Total-ACTION 2 Number of Channels, STARTUP and/or POWER OPERATION may continue provided the inoperable channel is placed in the bypassed or tripp'ed condition within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

If the inoperable channel is bypassed, the desirability of-maintaining this channel in the bypassed condition shall be reviewed in accordance with f

Specification 6.5.1.6e.

The channel shall.be returned to OPERABLE status no later than during the next COLD SHUTDOWN.

w SAN ONOFRE-UNIT 2 3/4 3-4 AMENDMENT NO. 16

TABLE 3.3-1 (Continued)

TABLE NOTATION maintained at a value equivalent to greater than or equal to 19% of RATED THERMAL POWER.

2.

Within 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months s:

a)

All full length and part length CEA groups are withdrawn to and subsequently maintained at the

" Full Out" position, except durir:g Jurveillance testing pursuant to the requirements of Specification 4.1.3.1.2 or for control when CEA group 6 may be inserted no further than

' 127.5 inches withdrawn.

b)

The "RSPT/CEAC Inoperable" addressable constant in the CPCs is set to the inoperable status, r

c)

The Control Element Drive Mechanism Control System (CEDMCS) is placed in and subsequently maintained in the "Off" mode except during CEA group 6 motion per~mitted by a) above, when the CEDMCS may be o~perated in either the " Manual Group" or " Manual Individual" mode.

3.

At least once per 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , all full length and part length CEAs are verified fully withdrawn except during surveillance testing pursuant to Specifica-tion 4.1.3.1.2 or during insertion of CEA group 6 as permitted by 1. a) above, then verify at least once per 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months that the inserted CEAs are aligned within 7 inches (indicated position) of all other CEAs in its group.

+

3 ACTION 7

- With three or more auto restarts of one non-bypassed calculator during a 12-hour interval, demonstrate calculator OPERABILITY by performing a CHANNEL FUNCTIONAL TEST within the next 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

\\

ACTION 7A With the number of OPERABLE channels one less than the-Minimum Channels OPERABLE requirement restore the inoperable channel to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or open.the reactor trip breakers within the next hour.

b f

SAN ON0FRE-UNIT 2 3/4 3-7

l '

f.

TABLE 3.3-2 is REACTOR PROTECTIVE INSTRUMENTATION RESPONSE TIMES S

SA g;

FUNCTIONAL UNIT RESPONSE TIME a

25 1.

Manual Reactor Trip Not Applicable w

2.

Linear Power Level - High

$ 0.40 seconds

3.

Logarithmic Power Level - High 5 0.45 seconds

4.

Pressurizer Pressure - High 5 0.90 seconds 5.

Pressurizer Pressure - Low

$ 0.90' seconds 6.

Containment Pressure - High 5 0.90 seconds 7.

Steam Generator Pressure - (ow

$ 0.90 seconds

}{

48 8.

Steam Generator Level - Low

$ 0.90 seconds

=

9.

Local Power Density - High a.

Neutron Flux Power from Excore Neutron Detectors

< 0.68 seconds" b.

CEA Positions E 0.68 seconds **

c.

CEA Positions:

CEAC Penalty Factor 30.53 seconds 10.

DNBR - Low Neutron' Flux Power fren'Excore Neutron Detectors

< 0.68 seconds

a.

b.

CEA Positions 7 0.68 seconds **

c..

Cold Leg Temperature 7 0.68 secondsv#

h(

d.

Hot Leg Temperature 30.68 seconds ##.

25 e.

Primary Coolant Pump Shaft Speed 5 0.68 seconds #

FR f.

Reactor Coolant Pressure from Pressurizer 1 0.68 seconds g.

CEA positions:

CEAC Pen;alty Factor 1 0.53 seconds is

TABLE 3.3-2 (Continued)

E REACTOR PROTECTIVE INSTRUMENTATION RESPONSE TIMES E

E?

FUNbTIONALUNIT RESPONSE TIE g

11.

Steam Generator Level - High Not Applicable N

12.

Reactor Protection System Logic Not Applicable 13.

Reactor Trip Breakers Not Applicable 14.

Core Protection Calculators Not Applicable 15.

CEA Calculators Not Applicable 16.

Reactor Coolant Flow-Low 0.9 sec 17.

Seismic-High Not Applicable w

18.

Loss of Load Not Applicable e

ANeutron detectors are exempt from response time testing.

Response time of the neutron flux signal portion of the channel shall be measured from detector output or input of first electronic component in channel.

AAResponse time shall be measured from the onset of a single CEA drop.

esponse time shall be measured from f.he onset of a 2 out of 4 Reactor Coolant Pump coastdown.

R NHBased on a resistance temperature detector (RTD) response time of less than or equal to 6.0' seconds when~the RTO response time is equivalent to the time interval required for the RTD output to achieve

,g 63.2% of its total change when subjected to a step change in RTD temperature.

5-E

'i 5

~

f-I TABLE 4.3-1 s

REACTOR PROTECTIVE INSTRUMENTATION SURVEILLANCE REQUIREMENTS z

z CHANNEL MGDES FOR WHICH O

3 CHANNEL CHANNEL FUNCTIONAL SURVEILLANCE J.

CHECK CALIBRATION TEST IS REQUIRED FUNCTIONAL UNIT g

1, 2, 3*, 4*, 5*

N 1.

Manual Reactor Trip N.A.

N.A.

R 2.

Linear Power Level - High S

D(2,4),M(3,4), M 1, 2 Q(4), R(4)

S R(4)

M and S/U(1) 1,2,3,4,5 3.

Logarithmic Power Level - High 4.

Pressurizer Pressure - High S

R M

l. 2 5.

Pressurizer Pressure - Low S

R M

1, 2 6.

Containment Pressure - High S

R H

1, 2 7.

Steam Generator Pressure - Low S

R H

1, 2 8.

Steam Generator Level - Low S

R H

1, 2 9.

Local Power Density - High 5

D(2,4),

M, R(6) 1, 2 R(4,5)

S S(7),D(2,4),

M,R(6) 1, 2 10.

DNBR - Low M(8), R(4,5) 11.

Steam Generator Level - High 5

R H

1, 2 k

12.

Reactor Protection System N.A.

N.A.

M 1, 2, 3*, 4^, 5*

g Logic w

5

TABLE 4.3-1 (Continued)

REACTOR PROTECTIVE INSTRUMENTATION SURVEILLANCE REQUIREMENTS 2

E sa CHANNEL MODES FOR WillCil A

CHANNEL CilANNEL FUNCTIONAL SURVEILLANCE J-FUNCTIONAL UNIT CHECK CALIBRATION TEST IS REQUIRED N

13.

Reactor Trip Breakers N.A.

N.A.

M,(12) 1, 2, 3*, 4*, 5*

14.

Core Protection Calculators S.

0(2,4),5(7)

M(11),R(6) 1, 2 R(4,5),M(8) 15.

CEA Calculators S

R M,R(6) 1, 2 16.

Reactor Coolant Flow-Low S

R M

1, 2 17.

Seismic-High 5

R M

1, 2 18.

Loss of Load S

N.A.

M 1 (9)

T t

9

-e a

A_.

j l

i 4

i TABLE 4.3-1 (Continued)

TABLE NOTATION With. reactor trip breakers in the closed position and the CEA drive system capable of CEA withdrawal.

Each startup or when required with the reactor trip breakers closed (1) and the CEA drive system capable of rod withdrawal, if not performed i

f in the previous 7 days.

Heat balance only (CHANNEL FUNCTIONAL TEST not included), above 15%

l (2) of RATED THERMAL POWER; adjust the Linear Power Level rignals and the CPC addressable constant multipliers to make the CPC delta T i

power and CPC nuclear power calculations agree with the calorimetric calculation if absolute difference is greater than 2%.

During l

PHYSICS TESTS, these daily calibrations may be suspended provided these calibrations are performed upon reaching each major test power plateau and prior to proceeding to the next major test power plateau.

Above 15% of RATED THERMAL POWER, verify that the linear power (3) subchannel gains of the excore detectors are consistent with the values used to establish the shape annealing matrix elements in the Core Protection Calculators.

Neutron detectors may be excluded from CHANNEL CALIBRATION.

(4)

After each fuel loading and prior to exceeding 70% of RATED THERMAL (5)

POWER, the incore detectors shall be used to determine the shape annealing matrix elements and the Core Protection Calculators shall use these elements.

This CHANNEL FUNCTIONAL TEST shall include the injection of simulated (6) process signals into the channel as close to the sensors as practi-cable to verify OPERABILITY including alarm and/or trip functions.

Above 70% of RATED THERMAL POWER, verify that the total RCS flow (7) rate as indicated by each CPC is less than or equal to the actual RCS total flow rate determined by either using the reactor coolant-pump differential pressure instrumentation (conservatively compen-sated for measurement uncertainties) or by calorimetric calculations (conservatively compensated for measurement uncertainties) and if necessary, adjust the CPC addressable constant flow coefficients such that each CPC indicated flow is less than or equal to the actual flow rate.

The flow measurement uncertainty may be included l

in the BERR1 term in the CPC and is equal to or greater than 4%.

Above 70% of RATED THERMAL POWER, verify that the total RCS flow (8) rate as indicated by each CPC is less than or equal to the actual RCS total flow rate determined by calorimetric calculations (conserva-tively compensated for measurement' uncertainties).

l Above 55% of RATED THERMAL POWER.

(9)

(10) -

Deleted.

)

ThemonthlyCHkNNELFUNCTIONALTEST'shallincludeverificationthat (11) -

the correct values of addressable constants are installed'in each OPERABLE CPC per Specification 2.2.2.

l (12) -'

At least once per 18 months and following maintenance or adjustment of the reactor trip breakers, the CHANNEL FUNCTIONAL-TEST shall include independent verification of the undervoltage and shunt trips.

i.

' SAN ONOFRE-UNIT 2 3/4 3-12 AMEN 0 MENT NO. 16

TABLE 3.3-3 (Continued) v,

?E ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION oz x

MINIMUM E

TOTAL NO.

CHANNELS CHANNELS APPLICABLE

q FUNCTIONAL UNIT OF CHANNELS TO TRIP OPERABLE MODES ACTION t

4.

MAIN STEAM LINE ISOLATION a.

Manual (Trip 2/ steam 1/ steam.

2/ operating 1, 2, 3 11 Buttons) generator generator steam generator b.

Steam Generator 4/ steam 2/ steam 3/ steam 1, 2, 3

' 9*, 10*

Pressure - Low generator generator generator c.

Automatic Actuation 4/ steam 2/ steam 3/ steam 1, 2, 3 9", 10*

Logic generator generator generator S.

RECIRCULATION (RAS) toa a.

Refueling Water Storage u'

Tank - Low 4

2 3

1, 2, 3, 4 9*, 10*

b.

Automatic Actuation Logic 4

2 3

1,2,3,4 9*, 10*

6.

CONTAINMENT COOLING (CCAS) a.

Manual CCAS (Trip Buttons) 2 sets of 2 1 set of 2 2 sets of 2 1,2,3,4 8

b.

Manual SIAS (Trip gi Buttons) 2 sets of 2 1 set of 2 2 sets of 2 1,2,3,4 8

3 55 Automatic Actuation c.

55 Logic 4

2 3

1,2,3,4 9*, 10*

5 a

f

--a-

-e-y

,.- ~

g~

ny,,.

,,,,w-g 4

9 g--

r,.---

,e-m--

e

~.... _ _ _ _.

r TABLE 3.3-3 (Continued) v, 20

[

ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTUMENTATION 8

2 m

MINIMUM d;

TOTAL NO.

CHANNELS CHANNELS APPLICABLE i

+

{j FUNCTIONAL UNIT OF CHANNELS 10 TRIP OPERABLE MODES ACTION 7.

LOSS OF POWER (LOV) a.

4.16 kv Emer0ency Bus Undervoltage (Loss of' Voltage and Degraded Voltage) 4/ Bus 2/ Bus 3/ Bus 1, 2, 3,~4 9*,

10*

8.

EMERGENCY FEEDWATER (EFAS) a.' Manual (Trip Buttons) 2 sets of 2 I set of 2 2 sets of 2 1,2,3 11 q,

per S/G per S/G per S/G j

+

us b.

Automatic Actuation

[g Logic 4/SG 2/SG 3/SG 1, 2, 3 9*

10*

c.

SG Level (A/8) - Low and AP (A/8) - High 4/SG 2/SG 3/SG 1,2,3 9 *, 10

d.

SG Level (A/8) - Low and No S/G Pressure -

Low Trip (A/8) 4/SG-2/SG 3/SG 1,2,3 9 *, 10" l

s

.n

-S j

6te e

O l

l TABLE 3.3-3 (Continued) l g

. ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION z

E%

MINIMUM

o

[

TOTAL NO.

CHANNELS CHANNELS APPLICARLE z

FUNCTIONAL UNIT OF CHANNELS TO TRIP OPERABLE MODES ACTION l

~a N

9.

CONTROL ROOM ISOLATION l

.(CRIS) a.

Manual CRIS (Trip

. Buttons) 2 1

1 All 13*#

b.

Manual SIAS (Trip Buttons) 2 sets of 2/ unit 1 set of 2 2 sets of 2/ unit 1, 2, 3, 4 8

c.

Airborne Radiation i.

Particulate / Iodine 2

1 1

All 13*#

ii. Gaseous 2

1 1

All 13*#

w d.

Automatic Actuation D

Logic 1/ train 1

1 All 13*#

10.

T0XIC GAS ISOLATION (TGIS) a.

Manual (Trip Buttons) 2 1

1 All 14*#, 15*#

b.

Chlorine - High 2

1 1

All 14*#, IS*#

c.

Ammonia - High 2

1 1

All 14*#, 15*#

d.

Butane / Propane - High 2

1 1

All 14*#, 15*#

e.

Carbon Gioxide - High 2

1 1

All 14*#, 15*#

f.

Automatic Actuation Logic 1/ train 1

1 All 14*#, 15*#

E B

ut.s n.

TABLE 3.3-3 (Continued)

ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION 3:

9k

??

MINIMUM p?

TOTAL NO.

CHANNELS CHANNELS APPLICABLE a

FUNCTIONAL UNIT OF CHANNELS TO TRIP OPERABLE MODES ACTION sg N

11.

FUEL HANDLING ISOLATION (FHIS) 16*#

a.

Manual (Trip Buttons) 2 1

1 b.

Airborne Radiation 16*#

i.

Gaseous 2

1 1

16*#

ii. Particulate / Iodine 2

1 1

c.

Automatic Actuation 16*#

Logic 1/ train 1

1 R:

12.

CONTAINMENT PURGE ISOLATION (CPIS) w a.

Manual (Trip Buttons) 2 1

1 6

17*#

d' b.

Airborne Re?.iation i.

Gaseous 2

1 1

All 17, 17a, 17b ii.

Particulate 2

1 1

All 17, 17a, 17b iii. Iodine 2

1 1

All 17, 17b c.

Containment Area Radiation (Gamma) 2 1

1 6

17*#

d.

Automatic Actuation Logic 1/ train 1

1 All 17, 17a, 17b*#

$9 o

'i

!5

"].

~

TABLE 3.3-4 (Continued) n 3

ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION TRIP VALUES g

m" ALLOWABLE U

FUNCTIONAL UNIT TRIP VALUE VALUES 6.

CONTAINMENT COOLING (CCAS) a.

Manual CCAS (Trip Buttons)

Not Applicable Not Applicable b.

Manual SIAS (Trip Buttons)

Not Applicable Not Applic'able c.

Automatic Actuation Logic Not Applicable Not Applicable 7.

LOSS'0F POWER (LOV)

~

)

a.

4.16 kv Emergency Bus Undervoltage l

(Loss of Voltage and Degraded Voltage) See Fig. 3.3-1 (4)

See Fig. 3.3-1 (4)

L 8.

EMERGENCY FEEDWATER (EFAS) a.

Manual (Trip Buttons)

Not Appli, cable Not Applicable

{

'b.

Steam Generator (A&B) Level-Low 1 25% (3) 1-24.23% (3) c.

Steam Generator AP-High (SG-A > SG-B) 1 50 psi 5 66.25 psi d.

Steam Generator AP-High (SG-B.> SG-A)

$ 50 psi 5 66.25 psi e.

Steam Generator (A&B) Pressure - Low 1 729 psia (2) 2 711 psia (2) f.

Automatic Actuation Logic Not Applicable Not Applicable

~.

~

TABLE 3.3-4 (Continutd)

ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION TRIP VALUES g

z ALLOWABLE 3

rp FUNCTIONAL UNIT TRIP VALUE VALUES 9.

CONTROL ROOM ISOLATION (CRIS) a.

Manual CRIS (Trip Buttons)

Not Applicable Not Applicable b.

Manual SIAS (Trip Buttons)

Not Applicable Not Applicable c.

Airborne Radiation i.

Particulate / Iodine 5 5.7 x 104 cpm **

1 6.0 x 104 cpm **

2 2

ii. Gaseous 1 3.8 x 10 cp,**

1 4.0 x 10 cp,**

d.

Automatic Ac ation Logic Not Applicable Not Applicable Z

- 10. T0XIC GAS ISOLATION (TGIS)

+

a.

Manual (Trip Buttons)

Not Applicable.

Not Applicable b.

Chlorine - High 5 6.0 ppa 1 6.2 ppm c.

Ammonia - High 1 42.4 ppa 1 44.7 ppa i

d.

Butane / Propane - High 5 84.8 ppa 1 89.3 ppe e.

Carbon Dioxide - High 5 4061.3 ppa i 4275.0 ppe g

f.

Automatic Actuationi Logic Not Wpplicable Not Applicable 5

~*w

' arm a h

TABLE 3.3-4 (Continued)

U ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION TRIP VALUES z

9-ALLOWABLE TRIP VALUE VALUES h

FUNCTIONAL UNIT 11.

FUEL ltANDLING ISOLATION (FHIS) a.

Manual (Trip Buttons)

Not Applicable Not Applicable b.

Airborne Radiation i.

Gaseous 5 1.3 x 10 cpm **

1 1.4 x 10 cpm **

2 2

ii. Particulate / Iodine 5 5.7 x 10 cpm **

1 6.0 x 104 cpm **

4 c.

Automatic Actuation Logic Not Applicable Not Applicable 12.

CONTAINMENT PURGE ISOLATION (CPIS) a.

Manual (Trip Buttons)

Not Applicable Not Applicable b.

Airborne Radiation

'i.

Gaseous 5 per 00CM i per ODCM ii.

Particulate

$ per ODCH

$ per ODCM iii. Iodine i per ODCM

$ per 00CM Containment Area Radiation (Gamma) i 2.4 mR/hr 1 2.5 mR/hr c.

3

.d.

Automatic Actuation Logic Not Applicable Not Applicable

=~

E

'.g

+

~

TABLE 3.3-4 (Continued) w

$E TABLE NOTATION E

Value may be decreased manually, to a minimum of greater than or equal to 300 psia, as pressurizer o

h!

(1)'

pressure is. reduced, provided the margin between the pressurizer and this value is maintained at less than or equal to 400 psia;* the setpoint shall be increased automatically as pressurizer pressure a

is increased until the trip setpoint is reached. Trip may be manually bypassed below 400 psia; 25 bypass shall be automatically removed whenever pressurizer is greater than or equal to 400 psia.

-i oa Value may be decreased manually as steam generator pressure is reduced, provided the margin between the

- (2) steam generator pressure and this value is maintained at less than or equal to 200 psi;* the setpoint shall be increased automatically as steam generator pressure is increased until the trip setpoint is reached.

% of the distance between steam generator upper and lower level instrument nozzles.

(3)

Inverse time relay set value 3165V, trip will occur within the tolerances specified in Figure 3.5-1 (4) for the range of bus voltages.

g>

(5) Actuated equipment only; does not result in CIAS.

St Variable setpoints are for use only during normal,_ controlled plant heatups and cooldowns.

A Above normal background.

52 E

9.<

+

3 J

4

TABLE 3.3-5 ENGINEERED SAFETY" FEATURES RESPONSE TIMES INITIATING SIGNAL AND FUNCTION RESPONSE TIME (SEC)

, 1.

Manual a.

SIAS Safety Injection Not Applicable Centrol Room Isolation Not Applicable Containment Isolation (3)

Not Applicable Containment Emergency Cooling Not Applicable b.

CSAS Containment Spray Not Applicable c.

CIAS Containment Isolation Not Applicable d.

MSIS Not Applicable Main Steam Isolation e.

RAS Centainment Sump Recirculation Not Applicable f.-

CCAS Containment Emergency Cooling Not Applicable g.

EFAS Auxiliary Feedwater

~

Not Applicable h.

CRIS 3

Control Room Isolation Not Applicable i.

TGIS Toxic Gas Isolation

~

Not Applicable

)

j.

FHIS

~

Fuel Handling Building Isolation Nbt Applicable k.

CPIS Containment Purge Isolation Not Applicable

~

[

SAN GNOFRE-UNIT 2.

3/4 3-27

Table 3.3-5 (continued)

INITIATING SIGNAL AND FUNCTION RESPONSE TIME (SEC) 2.

Pressurizer Pressure-Low a.

SIAS (1) Safety Injection (a) High Pressure Safety Injection 31.2*

(b) Low Pressure Safety Injection 41.2*

(2) Control Room Isolation Not Applicable I

(3) Containment Isolation (NOTE 3) 11.2* (NOTE 2)

(4) Containment Spray (Pumps) 25.6*

(5) Containment Emergency Cooling (a) CCW Pumps 31.2*

(b) CCW Valves (Note 4b) 23.2*

(c) Emergency Cooling Fans 21.2*

3.

Containment Pressure-High a.

SIAS (1) Safety Injection (a) High Pressure Safety Injection 41.0*

1 (b) Low Pressure Safety Injection 41.0*

e (2) Control Room Isolation Not Applicable-

~

I (3) Containment Spray (Pumps) 25.4*

(4) Containment Emergency Cooling (a) CCW Pumps 31.0*

(b) CCW Valves (Note 4b) 23.0*

(c) Emergency Cooling Fans 21.0*

b.

CIAS (1) Containment Isolation 10.9* (NOTE 2)

(2) CCW Valves (Note 4a) 20.9 4.

Containment Pressure - High-High CSAS Containment Spray 21.0*

~

SAN ONOFRE-UNIT 2 3/4 3-28 AMENDMENT NO.16

Table 3.3-5 (Continued)

INITIATING SIGNAL AND FUNCTION RESPONSE TIME (SEC) 5.

Steam Generator Pressure - Low MSIS (1) Main Steam Isolation 20.9 (2) Main Feedwater Isolation 10.9 6.

Refueling Water Storage Tank - Low l

1 RAS l

(1) Containment Sump Valves Open 50.7*

7.

4.16 kv Emergency Bus Undervoltage LOV (loss of voltage and degraded voltage)

Figure 3.3-1 8.

Steam Generator Level - Low (and No Pressure-Low Trip)

EFAS (1) Auxiliary Feedwater (AC trains) 50.9*/40.9**

(2) Auxiliary Feedwater (steam /DC train) 30.9 (NOTE 6) 9.

Stean Generator Level - Low (and AP - High)

EFAS (1) Auxiliary Feedwater (AC trains) 50.9*/40.9**

(2) Auxiliary Feedwater (Steam /DC train) 30.9 (NOTE 6) 10.

Control Room Ventilation Airborne Radiation CRIS i

(1) Control Recm Ventilation - Emergency i

Mode Not Applicable 11.

Control Room Toxic Gas (Chlorine)

TGIS (1)' Control Room Ventilation - Isolation Mode 16 (NOTE 5)

(

12.

Control Room Toxic Gas (Ammonia)

.TGIS Control Room Ventilation - Isolation Mode 36.(NOTE 5)

SAN ONOFRE-UNIT 2 3/4 3-29 AMENDMENT NO. 16

_-___ N

..._.:. f......:.

r.:. vi 3 -_c...,.._ _.,_ (3:,_C

.,...._...5

, d. -

... : m...:

13.

C:ntr:1 E:-

xit 3as f 3utaae/?rt:ane) 1 ie.3 Centr:1

.0 : Ventilation -

Iscia.ic. M:de 36 (liOTE 5)

~

14.

Centrol E::: Texic Gas (Cerben Dioxide)

TGIS Control Koc: Ventilation -

Isolatica Mede 36 (NOTE 5)-

15.

Fuel Handline Buildinc Airborne Radiation FMIS

.-ar:: nc ut.dinc rest-Accident ruel..

e Cleanup ilter Syste:~

Not Applicable 35.

C ntainment 'irbcrne Radiatien t.: t S

~

Con.ai n. En: Purge Isolation 2 (t,0TE 2) 17.

C r.tainmen

eaRadiati_g CRIS Contai. a..: ? urge isolation 2 (NOTE 2) n.:S.

Res; case times in:-T*u.ri-e ::vement of valves and attainment of pump or 1.

bic.er dis:.t ge :ressure as applicable.

l 2.

Response time inclu:ss e ergency diesel generator starting delay (applicable :: AC. :ter :perated valves other than : ntain: ent purge valves), ins rtmentati:n and logic response only.

Eefer to_ table 3.5-1 f:r contai. :gr.t isclati:n vaive closure times.

3.

All CIAS-Act.ited valves except MSIVs and MFIVs.

Aa.

CC'd non-criti:a1 1 cop isolation valves 2HV-5232, 2HV-5213, 2HV-6218 i

ar.d ZHV-6215.

i 45.

C:.tairment energan:y cc ler CC'd isolation valves 2HV-5355, 2HV-6357,

J 2HV-5355, 2H'.-5355, 2HV-5370, 2HV-6371, 2HV-6372, and 2HV-6373 cpen.

5.

Response tice includes instrumentation,1cgic, and isolation da.mper ciesure tines only.

t l

S.

The.crovisic s of Specification.4.0.4 are not applicable for entry into

}

.M: e 3.

l I

E.ergency dissel ganerator starting delay (10 sec.) and sequence loading,

delavs for 5:AS are included.

~

E erger.cy dissel ;enerat:r starting delay (30 sec.) is included.

c

-o

t r dre-a l

... c... - - r _ :.. -. -

-.- r: ::

l

\\

~

TABLE 4.3-2 ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTAION SURVEILLANCE REQ 2

l CHANNEL MODES FOR WilICil

(

Q CHANNEL CllANNEL FUNCTIONAL SURVEILLANCE g

CilECK CALIBRATION TEST IS REQUIRED I

FUNCTIONAL UNIT g

l U

1.

SAFETY INJECTION (SIAS)

N a.

Manual (Trip Buttons)

N.A.

R 1,2,3,4 b.

Containment Pressure - High S

R H

1,2,3 c.

Pressurizer Pressure - Low S

R H

1,2,3

(

l d.

Automatic Actuation Logic N.A.

N.A.

M(1)(3),SA(4) 1, 2, 3, 4 2.

CONTAINMENT SPRAY (CSAS) a.

Manual (Trip Buttons)

N.A.

R 1,2,3 b.

Containment Pressure --

High - High S

R M

1,2,3 Automatic Actuation Logic N.A.

N.A.

M(1)(3),SA(4) 1, 2, 3 c.

3.

CONTAINMENT ISOLATION (CIAS)

Manual CIAS (Trip Buttons)

N.A.

R 1,2,3,4 1

y Manual SIAS (Trip Buttons)(5)

N.A.

R 1,2,3,4 a.

b.

y Containment Pressure - High S

R H

1,2,3 d.

Automatic Actuation Logic N.A.

N.A.

M(1)(3),SA(4) 1, 2, 3, 4 c.

MAIN STEAM ISOLATION (MSIS) a.

Manual (Trip Buttons)

N.A.

R 1,2,3 4.

l b.

Steam Generator Pressure - Low 5 R

H 1,2,3 l

Automatic Actuation Logic N.A.

N.A.

M(1)(3),SA(4) 1, 2, 3 L

c.

5.

RECIRCULATION (RAS) a.

Refueling Water Storage Tank - Low 5

R M

1,2,3,4 E

b.

Automatic Actuation Logic N.A.

N.A.

M(1)(3),SA(4) 1, 2, 3, 4 9

E 6.

CONTAINMENT COOLING (CCAS)

Manual CCAS (Trip Buttons)

N.A.

R 1,2,3,4 b.

Manual SIAS (Trip Buttons)

N.A.

R 1,2,3,4 z

a.

c.

Automatic Actuation Logic H.A.

N.A.

M(1)(3),SA(4) 1, 2, 3, 4 5

Mm s

TAB:.E 4.3-2 (Continued)

ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION SURVEILLANCE REQ E

CHANNEL MODES FOR WHICH q

CHANNEL CHANNEL FUNCTIONAL SURVEILLANCE g

CHECK CALIBRATION TEST IS REQUIRED a

FUNCTIONAL UNIT zU 7.

LOSS OF POWER (LOV)

N a.

4.16 kv Emergency Bus Undervoltage (Loss of Voltage and Degraded S

R R

1,2,3,4 Voltage) 8.-

ti:ERGENCY FEEDWATER (EFAS) a.

Manual (Trip Buttons)

N.A.

R 1,2,3 b.

SG Level (A/B)-Low and AP (A/B) - High 5

R M

1,2,3 SG Level (A/B) - Low and No Pressure - Low Trip (A/B)

S R

H 1,2,3 c.

y Automatic Actuation Logic N.A.

N.A.

M(1)(3),SA(4) 1, 2, 3 d.

w0 9.

CONTROL ROOM ISOLATION (CRIS)

Manual CRIS (Trip Buttons)

N.A.

R N.A.

l b.

Manual SIAS (Trip Buttons)

N.A.

R N.A.

a.

c.

Airborne Radiation i.

Particulate / Iodine S

R M

All S

R H

All fi. Gaseous d.

Automatic Actuation Logic N.A.

N.A.

R(3)

All f

10. T0XIC GAS ISOLATION (TGIS) 3E a.

Manual (Trip Buttons)

N.A.

R N.A.

I E

b.

Chlorine - High 5

R H

All 3

c.

Ammonia - High S

R M

All E

d.

Butane / Propane - High S

R M

All Carbon Dioxide - High S

R M

All 5

f.

Automatic Actuation Logic N.A.

N.A.

R (3)

All e.

t

TABLE 4.3-2 (Continued)

ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION SURVEILLANC z

E CHANNEL MODES FOR WHICil Q

CHANNEL CHANNEL FUNCTIONAL SURVEILLANCE g;

CHECK CALIBRATION TEST

_,.IS REQUIRED a

FUNCTIONAL UNIT zU 11.

FUEL HANDLING ISOLATION (FHIS)

N a.

Manual (Trip Buttons)

N.A.

R N.A.

b.

Airborne Radiation

^

S R

M i.

Gaseous ii. Particulate / Iodine S

R M

Automatic Actuation Logic N.A.

N.A.

R(3) i c.

I Manual (Trip Buttons)

N. A.

N.A.

R H.A.

-l 12.

CONTAINMENT PURGE ISOLATION (CPIS) a.

b.

Airborne Radiation i.

Gaseous (2)

(2)

'All ii.

Particulate (2)

(2)

All iii. Iodine (2)

(2)

All R

Containment Area Radiation S

R H

6 u

c.

O (Gamma) d.

Automatic Actuation Logic H.A.

N.A.

R (3)

All 4

TABLE NOTATION Each train or logic channel shall be tested at least every 62 days on a STAGGERED TEST 8 ASIS.

(1)

In accordance with Table 4.3-9 surveillance requirements for these instrument channels.

(2)

Testing of Automatic Actuation Logic shall include energization/de-energization of each initiation (3) relay and verification of the OPERABILITY of each initiation relay.

A subgroup relay test shall be performed which shall include the energization/de-energization of each (4) j subgroup relay and verification of the OPERABILITY of each subgroup relay.

E (5) Actuated equipment only; does not result in CIAS.

With irradiated fuel in the storage pool.

i d

5 e.

t INSTRUMENTATION 3/4.3.3 MONITORING INSTRUMENTATION RADIATION MONITORING ALARM INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.3.1 The radiation monitoring alarm instrumentation channels shown in Table 3.3-6 shall be OPERABLE with their alarm / trip setpoints within the specified limits.

APPLICABILITY:

As shown in Table 3.3-6.*

i l

ACTION:

a.

With a radiation monitoring channel alarm satpoint exceeding the value shown in Table 3.3-6, adjust the setpoint to within the limit within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months or declare the channel inoperable.

j b.

With one or more radiation monitoring alarm channels inoperable, take the ACTION shown in Table 3.3-6.

i c.

The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

j f

l

]

1 SURVEILLANCE REQUIREMENTS j

4'.3.3.1 Each radiation monitoring alarm instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL ~

CALIBRATION and CHANNEL FUNCTIONAL TEST operations for the MODES and at the frequencies shown in Table 4.3-3.

4 W

7

See Special Test' Exception 3.10.5.

SAN ONOFRE-UNIT 2 3/4 3-34 J

TABLE 3.3-10 E

ACCIDENT MONITORING INSTRUMENTATION (CONTINUED)

E%

REQUIRED MINIMUM g

NUMBER OF CHANNELS j

z INSTRUMENT CHANNELS OPERABLE ACTION a

N 17.

Containment Water Level - Wide Range 2

1 20, 21 18.

Core Exit Thermocouples 7/ core 4/ core 20, 21 quadrant quadrant 19.

Containment Area Radiation - High Range 2

1

'20., 21 20.

Main Steam Line Area Radiation 1/ steam line N.A.

20 21.

Condenser Evacuation System Radiation 1

N.A.

20 g

Monitor - Wide Range s

y 22.

Purge / Vent Stack Radiation Monitor -

2 1

22 l

g Wide Range

23.

Cold Leg HPSI Flow

.1/ cold leg N.A.

20 24.

Hot Leg HPSI Flow 1/ hot leg N.A.

20 3E E

NOTES _:

E

The two required channels are the Unit 2 monitor and the Unit 3 monitor.

5 4

6 O

TABLE.,3.3-10 (Continued)

AClION STATEMENTS ACTION 20 -

With the number of OPERABLE accident monitoring channels less than the Required Number of Channels, either restore the inoperable channel to OPERABLE status within 7 days, or be in HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

ACTION 21 -

With the number of OPERABLE accident monitoring channels less than the Minimum Channels OPERABLE requirement, either restore the inoperable channel (s) to OPERAriE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or-be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

ACTION 22 -

With the number of OPERABLE accident monitoring channels less than the Required Number of Channels, either restore the inoperable channel (s) to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , or:

1)

Initiate the preplanned alternate method of monitoring l

the appropriate parameter (s), and l

j 2)

Prepare and submit a Special Report to the Commission pursuant to Specification 6.9.2 within 14 days following the event outlining the action taken, the cause of the inoperability and the plans and schedule for restoring the system to OPERABLE status.

~

SAN ONOFRE-UNIT 2 3/4 3-53a AMENDMENT NO. 16

TABLE 4.3-7 ACCIDENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS (CONTINUED) e

.Q A

CHANNEL CHANNEL j

INSTRUMENT CHECK CALIBRATION l

[

19.

Containment Area Radiation - High Range (a)

(a) 20.

Main Steam Line Area Radiation (a)

~ (a) 21.

Condenser Evacuation System Radiation Monitor -

M R

j Wide Range 22.

Purge / Vent Stack Radiation Monitor - Wide Range' M

R 23.

Cold Leg HPSI Flow M

R

{

24.

Hot Leg HPSI Flow M

R l

e i

)

NOTES:

(a) In accordance*~with Table 4.3-3.

l O

e (E6W

=

j.

INSTRUMENTATION 1

FIRE DETECTION INSTRUMENTATION 1

i LIMITING CONDITION FOR OPERATION j

3.3.3.7 As a minimum, the fire detection instrumentation for'each fire i

detection zone shown in Table 3.3-11 shall be OPERABLE.

APPLICABILITY: Whenever equipment protected by the fire detection instrument is. required to be OPERABLE.

I ACTION:

With.the number of OPERABLE fire detection instrument (s) less than the minimus 1

[

number OPERABLE requirement of Table 3.3-11:

j Within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months establish a fire watch patrol to inspect the zone (s) a.

with the inoperable instrument (s) at least once per hour, unless the instrument (s) is located inside the containment, then inspect the l

containment at least once per 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months or monitor the containment air temperature at least once per hour at the locations listed in f

l Specification 4.6.1.5.

The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

,i b.

1 i.

SURVEILLANCE REQUIREMENTS Et h of the above required fire detection instruments shich are l

4.3.3.7.1 accessible during plant operation shall be demonstrated OPERABLE at least once Fire detectors per 6 months by performance of a CHANNEL FUNCTIONAL TEST.

l which are not accessible during plant operation shall be demonstrated OPERABLE by the performance of a CHANNEL FUNCTIONAL TEST during each COLD SHUTDOWN

+

exceeding 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months unless performed in the previous 6 months.

4.3.3.7.2 The NFPA Standard 72D supervised circuits supervision associated with the detector alarms of' each of the above required fire detection j

instruments shall be demonstrated OPERABLE at least once per 6 months.

i The non-supervised circuits associated with detector alarms between 4.3.3.7.3 i

the instruments and the control room shall be demonstrated OPERABLE at least.

i i

once per 31 days.

Following a seismic event (basemat acceleration greater than or equal 4.3.3.7.4 to 0.05 g):

Within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months each zone shown in Table 3.3-11 shall be inspected a.

for fires, and Within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months an engineering evaluation shall be performed to b.

j verify the OPERABILITY of the fire detection system in each zone shown in Table 3.3-11.

i i

F i

SAN ONOFRE-UNIT 2 3/4 3-56 AMENDMENT NO.-

16

o TABLE 3.3-11 FIRE DETECTION INSTRUMENTS MINIMUM INSTRUMENTS OPERABLE

Early Warning Actuation Zone Instrument Location HEAT FLAME SM0KE HEAT FLAME SM0KE 1

Containment Cable Tray Areas Elev 63'3" 10 Cable Tray Areas Elev 45' 9

i Cable Tray Areas Elev 30' 4

Elevator Machinery Room 1

Combustible Oil Area 32 Two steam generator rooms Charcoal Filter Area 2

Elev 45' 4

1 i

2 Penetration Elev 63' 6" 12 4

New Fuel Storage Area and

.I Spent Fuel Pool Areas Spent Fuel Pool 4

New Fuel Pool 3

5 Control Building Elev 70' Cable Riser Gallery Rm 423 2-24-Cable Riser Gallery Rm 449 3

24 6

Control Building Elev 70' Radiation Chemical Lab Rms 421, 420 1

7 Radwaste Elev 63'6" Chemical Storage Area Rm 503 1

Radwaste Control Panel Rm 513 1

Storage Area Rm 523 1

Hot Machine Shop 1

8 Radwaste Elev 63'6" Waste Decay Tank Rms 511A None 9

Fuel Handling Building Elev 45' Emgy. A.C. Unit Rm 309-Train A 1

1 Emgy. A.C. Unit Rm 302-Train B 1

1 10 Penetration Elev 45' 6

The fire detection instruments located within the_ Containment are not required A

to be OPERABLE during the performance of Type A Containment Leakage Rate Tests.

SAN ONOFRE-UNIT 2 3/4 3-57 AMEN 0 MENT NO. 16

~

TABLE 3.3-11 (Continued)

Early Warning Actuation Zone Instrument Location HEAT FLAME SM0KE HEAT FLAME SMOKE 11 S.E.D. Roof and Main Steam-Relief Valves None 12 Control Building Elev 50' Cable Riser Gallery Rm 305 3

42 Cable Riser Gallery Rm 315 3

40 13A Control Building Elev 50' Emgy. HVAC Unit Rm 309A 1

13B Control Building Elev 50'_

Emgy. HVAC Unit Rm 3098 1

14 Radwaste Elev 24' Boric Acid Makeup Tank Rm 204B None Boric Acid Makeup Tank Rm 204A None 15 Control Building Elev 50' ESF Switchgear Rm 308A 2

ESF Switchgear Rm 308B 2

16 Radwaste Elev 37' & 50' Ion Exchangers None 17 Diesel Generator Building Train A 3

4 Train B 3

4 i

18 Diesel Fuel Oil Storage Tank Underground Vaults None 20 Condensate Storage Tank T-121 None 21 Nuclear Storage Tank T-104 None 22 Auxiliary Feedwater Pump Room 2

6 23 Fuel Handling Bldo Elev 30' Spent Fuel Pools Heat Exchange Room 209 None.

28 Penetration Elev. 30' 2

G SAN ONOFRE-UNIT 2 3/4 3-58 AMENDMENT NO.16

o.

TABLE 4.3-8 (Continued)

TABLE NOTATION (1) The CHANNEL FUNCTIONAL TEST shall also demonstrate that automatic isolation of this pathway and control room alarm annunciation occurs if any of the following conditions exists:"

1.

Instrument indicates measured levels above the alarm / trip setpoint.

2.

Circuit failure.

3.

Instrument indicates a downscale failure.

(2) The initial CHANNEL CALIBRATION shall be performed using one or more of the reference standards certified by the National Bureau of Standards or using standards that have been obtained from suppliers that participate l

in measurement assurance activities with NBS.

These standards shall permit calibrating the system over its intended range of energy and I

measurement range.

For subsequent CHANNEL CALIBRATION, sources that have been related to the initial calibration shall be used.

(3)

CHANNEL CHECK shall consist of verifying indication of flow during periods of release.

CHANNEL CHECK shall be made at least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months on days on which continuous, periodic, or batch releases are made.

i

1f the instrument controls are not in the operate mode, procedures shall require that the channel be declared inoperable.

SAN CNOFRE-UNIT 2 3/4 3-67 AMENDMENT NO.16 w

S

' INSTRUMENTATION RADIOACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION s

v LIMITING CONDITION FOR OPERATION 3.3.3.9 The radioactive gaseous effluent monitoring instrumentation channels shown in Table 3.3-13 shall be OPERABLE with their alarm / trip setpoints set to ensure that the limits of Specification 3.11.2.1 are not exceeded.

The alarm / trip setpoints of these chanrels shall be determined in accordance with the ODCM.

APPLICABILITY:

As shown in Table 3.3-13*

ACTION:

With a radioactive gaseous effluent monitoring instrumentation a.

channel alarm / trip setpoint less conservative than required by the above Specification, immediately suspend the release of radioactive gaseous effluents monitored by the affected channel or declare the channel inoperable, b.

With less than the minimum number.of radioactive gateous effluent monitoring instrumentation channels OPERABLE, take the ACTION shown in Table 3.3-13.

Additionally, if the, inoperable instruments are not returned to OPERABLE status within 30 days, explain the next Semi-annual Radioactive Effluent Release Report why the inoperability was not corrected in a timely manner.

c.

The provisions of Specifications 3.0.3, 3.0.4, and 6.9.1.13b are not applicable.

SURVEILLANCE REQUIREMENTS 4.3.3.9 Each radioactive gaseous effluent monitoring instrumentation channel shall be demonstrated OPERABLE by performance of the CHANNEL CHECK, SOURCE CHECK, CHANNEL CALIBRATION and CHANNEL FUNCTIONAL TEST operations at the frequencies shown in Table 4.3-9.

l

See Special Test Exception 3.10.5 SAN ON0FRE-UNIT 2 3/4 3-68 i

TABLE 3.3-13 RADI0 ACTIVE GASE0ll5 EFFLUENT 1:0NITORING INSTRUMENTATION 98 MINIMllM CilANNELS

]

INSTRUMENT OPERABLE APPLICABILIIY ACTION g

1.

WASTE GAS HOLDUP SYSTEM El a.

Noble. Gas Activity Monitor -

Providing Alarm and Automatic no Termination of Release - 2/3 RT - 7814 1

35 or 2/3 RT - 7808 b.

Effluent System Flow Rate Measuring Device 1

36 2.

WASTE GAS Il0LDUP SYSTEM EXPLOSIVE GAS

~ MONITORING SYSTEM a.

Hydrogen Monitor 2

39 b.

Oxygen Monitor 2

39 R'

3.

CONDENSER. EVACUATION SYSTEM

+

u, a.

Noble Gas' Activity Monitor, 2RT - 7818 or J,

2RT - 7870-1 1

37, (a) b.

Iodine Sampler 1

40 c.

Particulate Sampler 1

40 J.

Flow Rate Monitor 1

36 4.

PLANT VENT STACK a.

Noble Gas Activity Monitor f 1

37,(a)

- 2/3 RT 17808, or 2RT-7865-1 and 3RT-7865-1 b.

Iodine. Sampler 1

40 c.

Particulate Sampler 1

40 d.

Flow Rate Monitor I

36 e.

Sampler Flow Rate Measuring Device 1

36 5.

CONTAINMENT PURGE SYSTEM a.

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

- 2RT - 7804-1 1

38, (b),(c) b.

Iodine Sampler 1

40, (c) c.

Particulate Sampler 1

40, (b), (c) d.

Flow Rate Monitor 1

36 e.

Sampler Flow Rate Measuring Device 1

36

o s

TABLE 3.3-13 (Continued)

TABLE NOTATION At all times.

During waste gas holdup system operation (treatment for primary system offgases).

a)

In accordance with Table 3.3-6 ACTION 19 In accordance with the ACTION Requirements of Specification 3.4.5.1 b)

(Modes 1, 2, 3 and 4)

In accordance with the ACTION Requirement of Specification 3.9.9 c)

(Mode 6)

With the number of channels OPERABLE less than required by the ACTION 35 -

Minimum Channels OPERABLE requirement, the contents of the tank (s) may be released to the environment for up to 14 days provided that prior to initiating the release:

At least two independent samples of the tank's contents a.

are analyzed, and At least two technically qualified members of the Facility b.

Staff independently verify the release rate calculations and discharge valve lineup; Otherwise, suspend release of radioactive effluents via this

' pat:1way.

With the number of channels OPERABLE less than required by the ACTION 36 -

Minimum Channels OPERABLE requirement, effluent releases via this pathway may continue for up to 30 days provided the flow rate is estimated at least once per 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

With the number of channels OPERABLE less than required by the ACTION 37 -

Minimum Channels OPERABLE requirement, effluent releases via this pathway may continue for up to 30 days provided grab samples are taken at least once per 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months and these samples are analyzed for gross activity within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

With the number of channels OPERABLE less than required by the ACTION 38 -

Minimum Channels OPERABLE requirement, immediately suspend PURGING of radioactive effluents via this pathway.

With the number of channnels OPERABLE one less than required by ACTION 39 -

the Minimum Channels OPERABLE requirement, operation of this-With two channels l

system may continue for up to 14 days.

inoperable, be in at least HOT STANDBY within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

With the number of channels OPERABLE less than required by the ACTION 40 -

Minimum Channels OPERABLE requirement, effluent releases via the affected pathway may continue for up'to 30 days provided samples are continuously collected with atxiliary sampling equipment as required in Table 4.11-2.

AMEN 0 MENT NO.16 3/4 3-70 SAN ONOFRE-UNIT 2

TABLE 4.3-9 (Continued)

TABLE NOTATION

At all times.

During waste gas holdup system operation (treatment for primary system l

offgases).

(1) The CHANNEL FUNCTIONAL TEST shall also demonstrate that automatic any of the following conditions exists:gom alarm annunciation occurs if isolation of this pathway and control r j

1.

Instrument indicates measured levels above the alarm / trip setpoint.

2.

Circuit failure.

3.

Instrument indicates a downscale failure.

l (2) The CHANNEL FUNCTIONAL TEST shall also demonstrate that control roog:

alarm annunciation occurs if,any of the following conditions exists 1.

Instrument indicates measured levels above the alarm setpoint.

2.

Circuit failure.

3.

Instrument indicates a downscale failure.

1 (3) The initial CHANNEL CALIBRATION shall b.e performed using one or more of l

the reference standards certified by the National Bureau of Standards or using standards that have been obtained from suppliers that participate t

in measurement assurance activities with NBS.. These standards shall permit calibrating the system over it,s intended range of energy and measurement range.

For subsequent CHANNEL CALIBRATION, sources that have been related to the initial calibration shall be used.

(4) The CHANNEL CALIBRATION shall include the use of standard gas samples containing a nominal:

l 1.

One volume percent hydrogen, balance nitrogen, and 2.

Four volume percent hydrogen, balance nitrogen.

(5) The CHANNEL CALIBRATION shall include the use of standard gas samples containing a nominal:

1.

One volume percent oxygen, balance nitrogen, and 2.

Four volume percent oxygen,~ balance nitrogen.

(6) Prior to each release and at least once per month.

(7) Surveillance of.contai.nment airborne monitor 2RT-7807-2 and its associated sampling media, when required OPERABLE by other Specifications, shall be'in accordance with the Surveillance Requirement for Containment Purge Effluent monitoring.

If the instrument controls are not set in the operate mode, procedures shall call for declaring the channel inoperable.

SAN ONOFRE-UNIT 2 3/4~3-73

s INSTRUMENTATION LOOSE-PART DETECTION INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.3.10 The loose part detection system shall be OPERABLE.

APPLICABILITY:

MODES 1 and 2.

ACTION:

With one or more loose part detection system channels inoperable for a.

more than 30 days, prepare and submit a Special Report to the Commission pursuant to Specification 6.9.2 within the next 10 days outlining the cause of the malfunction and the plans for restoring the channel (s) to OPERABLE status.

The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

b.

SURVEILLANCE REQUIREMENTS 4.3.3.10 Each channel of the loose part detection system shall be demonstrated OPERABLE by performance of a:

CHANNEL CHECK at least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , a.

b.

CHANNEL FUNCTIONAL TEST at least once per 31 days, and CHANNEL CALIBRATION at least once per 18 months.

c.

l I

l SAN ONOFRE-UNIT 2 3/4 3-74 AMEN 0 MENT NO.16 1

INSTRUMENTATION 3/4.3.4 TURBINE OVERSFEED PROTECTION LIMITING CONDITION FOR OPERATION 3.3.4 At least one turbine overspeed protection system shall be OPERABLE.

APPLICABILITY:

MODES 1, 2* and 3.*

ACTION:

With one stop valve or one control valve per high pressure turbine a.

steam lead inoperable and/or with one reheat stop valve or one reheat intercept valve per low pressure turbine steam lead inop-erable, restore the inoperable valve (s) to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , or close at least one valve in the affected steam lead or isolate the turbine from the steam supply within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

b.

With the above required turbine overspeed protection system otherwise inoperable, within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months isolate the turbine from the steam supply.

SURVEILLANCE REQUIREMENTS 4.3.4 The above required turbine overspeed protection system shall be demonstrated OPERABLE:

a.

At least once per 7 days by cycling each of the following valves through at least one complete cycle from the running position.

1.

Four high pressure turbine stop valves.

2.

Four high pressure turbine control valves.

3.

Six low pressure turbine reheat stop valves.

4.

Six low pressure turbine reheat intercept valves'.

b.

At least once per 31 days by direct' observation of the movement of each of the above valves through one complete cycle from the running position.

c.

At least once per 18 months by p'erformance of a CHANNEL CALIBRATION on the turbine overspeed protection systems.

d.

At least once per 40 months by disassembling at least one of each' of the above valves and performing a visual and surface inspection of' valve seats, disks and stems and verifying no unacceptable flaws or corrosion.

l l

With any main steam line isolation valve and/or any main steam line isolation l

valve bypass valve not fully closed.

Sa'! ONOFRE-UNIT 2' 3/4 3-75 AMENDMENT NO.16 i

e

~,

INSTRUMENTATION SURVEILLANCEREQUIREMENTS} Continued)

- For performance of surveillance testing of the valves in the unaffected low pressure turbine steam lead, the valve or valves

~

closed in an affected low pressure turbine steam lead may be re-opened following successful completion of surveillance test-ing of that valve in accordance with 4.3.4.2a. for a period not to exceed one hour. The provisions of Specification 3.0.4 are not applicable to the low pressure turbine valves. This license amendment is in effect during the time interval of December 6, 1982 until the completion of 50% power startup testing or until January 31, 1983, whichever occurs first.

~

O 9

0 6

o

[

SAN ONOFRE-UNIT 2 3/4 3-76 AMENDENT NO.11

3/4.4 REACTOR COOLANT SYSTEM 3 / *. 4.1 REACTOR COOLANT LOOPS AND COOLANT CIRCULATION STARTUP AND POWER OPERATION LIMITING CONDITION FOR OPERATION 3.4.1.1 Both Reactor Coolant loops and both Reactor Coolant pumps in each loop l

shall be in operation.

APPLICABILITY: 1 and 2.*

' ACTION:

With less than the above required Reactor Coolant pumps in operation, be in at least HOT STANDBY within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

9 SURVEILLANCE REQUIREMENTS 3-4.4.1.1 The above required Reactor Coolant loops shall be verified to ha in l

operation and circulating Reactor Coolant at least once per-12 hours.

See Special Test Exception 3.10.3.

SAN ONCFRE-UNIT 2 3/4 4-1 Amendment No. 4

m 1

1 a

REACTOR COOLANT SYSTEM i

i I

HOT STANDBY i

LIMITING CONDITION FOR OPERATION 3.4.1.2 The Reactor Coolant loops listed below shall be OPERABLE and at A

1 east one of these Reactor Coolant loops shall be in operation.*

Reactor Coolant Loop 1 and its associated steam generator and i

a.

at least one associated Reactor Coolant pump.

a l

b.

Reactor Coolant loop 2 and its associated steam generator and at least one associated Reactor Coolant pump.

APPLICABILITY:

MODE 3 1

l ACTION:

i With less than the above required Reactor Coolant loops i

a.

OPERABLE, restore the required loops to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 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 .

l b.

With no Reactor Coolant loop in operation, suspend all operations involving a reduction in boron concentration of the

{

Reactor Coolant System and immediately initiate corrective i

action to return-the required Reactor Coolent 1 cop to operation.

I SURVEILLANCE REQUIREMENTS 4.4.1.2.1 At least the above required Reactor Coolant pumps, if not in operation, shall be determined to be OPERABLE once per 7 days by verifying i

correct breaker alignments and indicated power availability.

4.4.1.2.2 At least one Reactor Coolant loop shall be verified to be in operation and circulating reactor coolant at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

4.4.1.2.3 The required steam generator (s) shall be determined OPERA 8LE verifying the secondary side water level to be > 10% (wide range) at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

All Reactor Coolant pumps may be de-energized for up to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months provided (1) no operations are permitted that would cause dilution of the Reactor 4

Coolant System boron concentration, and (2) core outlet temperature is, maintain.ed at least 10*F below saturation temperature.

e SAN ONOFRE-UNIT 2 3/4 4-2 AMENDMENT NO. 16-

?

4

v REACTOR COOLANT SYSTEM HOT SHUTDOWN LIMITING CONDITION FOR OPERATION 3.4.1.3 At least two of the loop (s)/ train (s) listed below shall be OPERABLE and at least one Reactor Coolant and/or shutdown cooling loops shall be in operation.*

a.

Reactor Coolant Loop 1 and its associated steam generator and at least one associated Reactor Coolant pump,**

b.

Reactor Coolant Loop 2 and its associated steam generator and at least one associated React'or Coolant pump,**

c.

Shutdown Cooling Train A, d.

Shutdown Cooling Train B.

APPLICABILITY:

MODE 4 ACTION:

a.

With less than the above required Reactor Coolant loops and/or shutdown cooling trains OPERABLE, immediately initiate correc-tive action to return the required loops / trains to OPERABLE status as soon as possible; if the remaining OPERABLE loop is a 1

shutdown cooling train, be in COLD SHUTDOWN within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

l

\\

b.

With no Reactor Coolant loop or shutdown cooling train in i

operation, suspend all operations involving a reduction in baron concentration of the Reactor Coolant System and immedi-ately initiate corrective action to return the required coolant loop / train to operation.

AAll Reactor Coolant pumps and shutdown cooling pumps may be de-energized for up to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months provided (1) no operations are permitted that would cause dilution of the Reactor Coolant System boron concentration, and (2) core outlet temperature is maintained at least 10*F below saturation temperature.

A Reactor Coolant pump shall not be started with one 'or more of the Reactor Coolant System cold leg temperatures less than or equal to 235'F unless

1) the pressurizer water volume is less than 900 cubic feet or 2) the secondary water temperature of each steam generator is less than 100*F above each of the Reactor Coolant System cold leg temperatures.

SAN ONOFRE-UNIT 2 3/4 4-3 AMENDMENT NO. 16

REACTOR COOLANT SYSTEM HOT SHUTDOWN SURVEILLANCE REQUIREMENTS 4.4.1.3.1 The required Reactor Coolant pump (s), if not in operation, shall be determined to be OPERABLE once per 7 days by verifying correct. breaker t

alignments and indicated power availability.

1 4.4.1.3.2 The required steam generator (s) shall be determined OPERABLE by verifying the secondary side water level to be > 10% (wide range) at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

4.4.1.3.3 At least one Reactor Coolant loop or shutdown cooling train shall be verified to be in operation and circulating Reactor Coolant at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

k O

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e I

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SAN ONOFRE-UNIT 2 3/4 4-4

t 4

l

&lM10}LCQ0LhN13%HH t

@L9_$WID01N

LOOPS fILLEO j

L1817fM6 CON 01710N FOR OPERAf!0N h

J,4,1,4,1 At least one shutdown cooling train shall be OPERABLE and in l

eperation,* and eithers One additional shutdown cooling train sh'all be OPERABLE,# or f

d, l

b, The sesendary side water level of each steam generator shall be j

greater than 10% (wide range),

AFFLisA81Lifff M608/withReactorCoolantloopsfilled.

A6110N!

S j

a, With less than the above required shutdown trains / loops OPERABLE or i

with less than the required stssm generator level, immediately l

initiate corrective action to retur'n the required trains / loops to i

GPfR48tt status or restore the required level as soon as possible.

9, With ne shutdown cooling train in operation, suspend all operations inve1 Wing a feduction in boron concentration of the Reactor Coolant fystem and immediately initiate corrective action to return the required shutdown cooling train to operation.

i tU(dtiLL M i Rt0UIRtMtNis

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4;4,1:4,1,1 Th's secondary side water level of at least two steam generators, When required, shall be determined to be within limits at least once per

}

12 heef9:

4:4 1:4:1:2 The shutdown cooling train shall be determined to be in ope.ation j

d6d 6ff6918 ting feastof coolant at least once per 1R hours.

l

@ne shutdown Essling ifala may be inoperable for up to I hours for surveillance i

146ti6g previded the othef shutdown cooling train is OPERA 8LE and in operation.

l be de=ener to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months provided fheshutdewaEsslingpumpma!dthatwoul!iaedforu!tionoftheReactor 1)nespefatiensarepermitt cause di1

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i Maintainedatleast10gnsentration,andI)coreoutlettemperature13 6eejaat system Beren E j

f below saturation temperatwo.

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l sA# @#@f#f4Nff f 3/4 44 N4tHONENT NO.16

REACTOR COOLANT SYSTEM

' COLD SHUTDOWN - LOOPS NOT FILLED LIMITING CONDITION FOR OPERATION

[

3.4.1.4.2 Two shutdown cooling trains shall be OPERABLE # and at least one shutdown cooling train shall be in operation.*

APPLICABILITY:

MODE 5 with Reactor Coolant loops not filled.

ACTION:

With less than the above required trains OPERABLE, immediately a.

initiate corrective action to return the required trains to OPERABLE status as soon as possible.

With no shutdown cooling trains in operation, suspend all operations l

b.

involving a reduction in boron concentration of the Reactor Coolant System and immediately initiate corrective action to return the required shutdown cooling train to operation.

SURVEILLANCE REQUIREMENTS 4.4.1.4.2 At least one shutdown cooling train shall be determined to be in operation and circulating reactor coolant at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

ne shutdown cooling train may be inoperable for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for surveillance 0testing provided the other shutdown cooling train is OPERABLE and.in operation.

The shutdown cooling pump may be de-energized for up to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months provided 1) no I

x operations are permitted that would cause dilution of the Reactor Coolant System boron concentration, and 2) core outlet-temperature-is maintained at least 10*F below saturation temperature.

I' SAN ONOFRE-UNIT 2

'3/4 4-6 AMEN 0 MENT NO. 16

REACTOR COOLANT SYSTEM OPERATIONAL LEAKAGE LIMITING CONDITION FOR OPERATION 3.4.5.2 Reactor Coolant System leakage shall be limited to:

a.

No PRESSURE BOUNDARY LEAKAGE, b.

1 gpm UNIDENTIFIED LEAKAGE, c.

1 gpm total primary-to-secondary leakage through all steam generators and 720 gallons per day through any one steam generator.

d.

10 gpm IDENTIFIED LEAKAGE from the Reactor Coolant System, and e.

1 GPM leakage at a Reactor Coolant System pressure of 2235 t 20 psig from any Reactor Coolant System Pressure Isolation Valve specified in Table 3.4-1.

APPLICABILITY: MODES 1, 2, 3 and 4 ACTION:

a.

With any PRESSURE BOUNDARY LEAKAGE, be in at least HOT STANDBY within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in' COLD SHUTD0WN withi'n the following'30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months , b.

With any Reactor Coolant System leakage greater than any one of the limits, excluding oRESSURE BOUNDARY LEAKAGE and leakage from Reactor Coolant System Pressure Isolation Valves, reduce the leakage rate to within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

c.

With any Reactor Coolant System Pressure Isolation Valve leakage greater than the above limit, isolate the high pressure portion of the affected system from the low pressure portion within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months by use of at least two closed manual or deactivated automatic valves, or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

~

SURVEILLANCE REQUIREMENTS 4.4.5.2.1 Reactor Coolant System leakages shall be demonstrated to be with'in 4

each of the above limits by:

i a.

Monitoring the containeent atmosphere gaseous or particulate radioactivity monitor at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

b.

Monitoring the containment sump inlet flow at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

SAN ONOFRE-UNIT 2 3/4 4-17

o REACTOR COOLANT SYSTEM SURVEILLANCE REQUIREMENTS (Continued)

Performance of a Reactor Coolant System water inventory balance at c.

least once per 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

d.

Monitoring the reactor head flange leakoff system at least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

Each Reactor Coolant System Pressure Isolation Valve specified in' 4.4.5.2.2 Table 3.4-1 shall be demonstrated OPERABLE by verifying valve leakage to be within its limit:

a.

At least once per 18 months.

Prior to entering MODE 2 whenever the plant has been in COLD SHUTOOWN b.

for 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or more and if leakage testing has not been performed in the previous 9 months, Prior to declaring the valve operable following' maintenance, repair c.

or replacement work on the valve.

Within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months following valve actuation due to automatic or manual d.

action or flow through the valve (for valves in Section B of Table 3.4-1).

The provisions of Specification 4.0.4 are not applicable for entry into MODE 3 or 4.

1

[

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l l

SAN ONOFRE-UNIT 2 3/4 4-18 AMEN 0 MENT NO. 16

REACTOR COOLANT SYSTEM 3/4.4.8 PRESSURE / TEMPERATURE LIMITS REACTOR COOLANT SYSTEM LIMITING CONDITION FOR OPERATION 3.4.8.1 The Reactor Coolant System (except the pressurizer) temperature and pressure shall be limited in accordance with the limit lines shown on Figure 3.4-2 and Figure 3.4-3 during heatup, cooldown, criticality, and inservice leak and hydrostatic testing with:

A maximum heatup of 30*F in any one hour period with RC cold leg a.

temperature less than 280*F.

A maximum heatup of 60*F in any one hour period with RC cold leg temperature greater than 280*F.

b.

A maximum cooldown of 30*F in any one hour period with RC cold leg temperatures less than 280*F.

A maximum cooldown of 100*F in any one hour period with RC temperature greater than 280*F.

A maximum temperature change of less than or equal to 10*F in any c.

one hour period during inservice hydrostatic and leak testing operations above the heatup and cooldown limit curves.

APPLICABILITY:

At all times.

ACTION:

With any of the above limits exceeded, restore the temperature and/or pressure to within the limit within 30 minutes; perform an engineering evaluation to determine the effects of the out-of-limit condition on the structural integrity of the Reactor Coolant System; determine that the Reactor Coolant System remains acceptable for continued operations or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and reduce the RCS T and pressure to less-than200*Fand500 psia,respectively,withinthefoMwing30 hours.

SURVEILLANCE REQUIREMENTS 4.4.8.1.1 The Reactor Coolant System temperature and pressure shall be datermined to be within the limits at least once per 30 minutes during system heatup, cooldown, and inservice leak and hydrostatic testing operations.

4.4.8.1.2 T'he reactor vessel material irradiation surveillance specimens shall be removed and examined, to determine. changes in material properties, at the intervals required by 10 CFR 50. Appendix H in accordance with the schedule in Table 4.4-5.

The results of these examinations shall be used to update Figures 3.4-2 and 3.4-3.

Recalculate the Adjusted Reference Temperature based on the greater of the following:

a.

The actual shift in reference temperature for plates C-6404-2 as determined by impact testing, or b.

The predicted shift in reference temperature for weld seams 3-203A or 3-203B as determined by Regulatory Guide 1.99, Revision 1, April 1977,

" Effects of Residual Elements on Predicted Radiation Damage.to Reactor Vessel Materials."

SAN ONOFRE-UNIT 2 3/4-4-27 AMENOMENT. NO.16

TABLE 4.4-5 4

REACTOR VESSEL MATERIAL SURVEILLANCE PROGRAM - WITHDRAWAL SCHEDULE v,

E

. CAPSULE VESSEL LEAD NUMBER LOCATION FACTOR WITHDRAWAL TIME

=>

2 1

83*

1.15 Standby E

. Ej 2

97*

1.15 3.2 EFPY 3

104*

1.15 13.6 EFPY 4

284 1.15 24 EFPY 5

263*

1.15 Standby 6

277*

1.15 Standby

~

s.

m S

O D-

Figure 3.4-2 HEATUP 0

0 30 /HR <280 F INSERVICE TESTS LOWEST SERVICE 0

3200 -

TEMP - 202 F 2800 -

CORE 2400 -

CRITICAL 4

--m N

D 2000 ua E

5 g

1600 D

E E

O 1200 E9 0

800 400 I

I I

l 1

O 0

Sr 100 150 200 250 J00 INDICATED RCS TEMPERATURE,0F~

HEATUP RCS PRESSURE / TEMPERATURE LIMITATIONS FOR'0-5 YEARS SAN ONOFRE-UNIT 2 3/4 4-29 AMEN 0 MENT NO. 16

4 4

Figure 3.4-3 i

3200 LOWEST SERVICE COOLDOWN 0

0 30 /HR < 280 F 0

TEMP 202 F 2800

/

2400 -

3 2000 E

5 N_

t 1600 l

E a.

Og 1200 49 O

E 800 400 I

I I

I O

O

'50 100 150 2'00 250 300 INDICATED RCS TEMPERATURE, OF Tc l

C00LOOWN RCS PRESSURE / TEMPERATURE LIMITATIONS FOR 0-5 YEARS l

SAN ONOFRE-UNIT 2 3/4 4-30 AMEN 0 MENT NO.16

EMERGENCY CORE COOLING SYSTEMS I

3/4.5.2 ECCS SUBSYSTEMS - T GREATER THAN OR EQUAL TO 350*F avg LIMITING CONDITION FOR OPERATION i

3.5.2 Two independent Emergency Core Cooling System (ECCS) subsystems shall be OPERABLE with each subsystem comprised of:

.i One OPERABLE high pressure safety injection pump, a.

b.

One OPERABLE low pressure safety injection pump, and One OPERABLE charging pump capable of taking suction from either the c.

boric acid makeup tank or the refueling water storage tank.

d.

An independent OPERABLE flow path capable of taking suction from the refueling water tank on a Safety Injection Actuation Signal and i

automatically transferring suction to the containment sump on a j

^

Recirculation Actuation Signal.

i APPLICABILITY:

MODES 1, 2 and 3*.

ACTION:

)

With one ECCS subsystem inoperable, restore the inoperable subsystem a.

to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or be in at least HOT STANDBY l

within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in HOT SHUTDOWN w' thin the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

b.

In the event the'ECCS.is actuated and injects water into the Reactor j

Coolant System,,a'Special, Report shall be prepared and submitted to the Commission pursuant td Specification 6.9.2 within 90 days describing'the=circumsta6ces of the actuation and the total accumu-lated actuation cycles to date.

The current value of the usage factor for each affected safety injection nozzle shall be provided in this Special Report whenever its value exceeds 0.70.

t AWith pressurizer pressure greater than tr equal to 400 psia.

i l

SAN ONOFRE-UNIT 2 3/4 5-3 AMENDMENT NO. 16 l

EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE REQUIREMENTS 4.5.2 Each ECCS subsystem shall be demonstrated OPERABLE:

At least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months by verifying that the following valves are a.

in the indicated positions with power to the valve operators removed:

Valve Number Valve Function Valve Position l

a.

HV9353 SDC Warmup CLOSED b.

HV9359 SDC Warmup CLOSED j

c.

HV8150 SDC(HX) Isolation CLOSED i

d.

HV8151 SDC(HX) Isolation CLOSED e.

HV8152 SOC (HX) Isolation CLOSED f.

HV8153 SDC(HX) Isolation CLOSED l

l g.

FV0306 SDC Bypass Flow Control LOCKED OPEN (THROTTLED)(MANUAL) h.14-153 LOCKED CLOSED (MANUAL) i.14-081 LOCKED OPEN (MANUAL) t J.14-082 LOCKED OPEN (MANUAL) k.

HV9420 Hot Leg Injection CLOSED Isolation 1.

HV9434 Hot Leg Injection CLOSED Isolation m.

HV9316 SOC (HX) Flow Control OPEN (THROTTLED)(AIR REMOVED) n.10-068 RWST Isolation LOCKED OPEN (MANUAL) o.

14-78 HV9316 Isolation LOCKED OPEN (MANUAL) p.

14-80 HV9316 Isolation LOCKED OPEN (MANUAL) b.

At least once per 31 days by:

1.

Verifying that the ECCS piping is full of water by venting the ECCS pump casings and accessible discharge piping high points, and l

2.

Verifying that each valve (manual, power operated or automatic) in the flow path that is not locked, sealed, or otherwise secured in position is in the correct position.

By a visuai inspection which verifies that no loose debris (rags, c.

trash, clothing, etc.) is present in the containment which could be l

transported to the containment sump and cause restriction of the l

pump suctions during LOCA conditions.

This visual inspection shall be performed:

l 1.

For all accessible areas of the containment prior to establishing l

CONTAINMENT INTEGRITY, and 2.

Of the areas affected within containment at the completion of containment entry.when CCNTAINMENT INTEGRITY is established.

d.

At least once per 18 months by:

1.

Verifying automatic isolat' ion of the shutdown cooling system from the Reactor Coolant System when RCS pressure is simulated greater than or equal to 715 psia, and that the interlocks prevent opening the shutdown cooling system isolation valves when simulated RCS pressure is greater than or equal to 376 psia.

SAN ONOFRE-UNIT 2 3/4 5-4 AMEN 0 MENT NO. 16 m

(

CONTAINMENT SYSTEMS CONTAINMENT AIR LOCKS l

LIMITING CONDITION FOR OPERATION

3. 6.1. 3 Each containment air lock shall be OPERABLE with:

a.

Both doors closed except wh'en the air lock is being use'd for normal transit entry and exit through the containment, then at least one i

air lock door shall be closed, and b.

An overall air lock leakage rate of less than or equal to 0.05 L, at P,, (55.7 psig)

APPLICABILITY:

MODES 1, 2, 3 and 4.

ACTION:

a.

With one containment air lock door inoperable:

1.

Maintain at least the OPERABLE air lock door closed and either restore the inoperable air lock door to OPERABLE status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or lock the OPERABLE air lock door closed.

2.

Operation may then' continue until performance of the next required overall air lock ledkage test provided that the OPERABLE air lock door is verified to be locked closed at least once per 31 days.

3.

Otherwise, be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the "ollowing 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

4.

The provisions of Specification 3.0.4 are not applicable.

b.

With the containment air lock inoperable, except as the result of an inoperable. air lock door, maintain at least one air lock door closed; restore the inoperable air lock to OPERABLE status within a

24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

l l

l SAN ONOFRE-UNIT 2 3/4 6-5 i

l l

l

~

i l

CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS 4.6.1.3 Each containment air lock shall be demonstrated OPERABLE:

Within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months following each closing, except when the air lock a.

is being used for multiple entries, then at least once per 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , by verifying seal leakage is less than or equal to.01 L, when determined by flow measurement, with the volume between the door seals pressurized to 9.5 + 0.5 psig for at least 15 minutes.

~

b.

By conducting overall air lock leakage tests at not less than P, (55.7 psig), and verifying the overall air lock leakage rate is within its limit:

At least once per 6 months,# and 1.

2.

Prior to establishing CONTAINMENT INTEGRITY when maintenance has been performed on the air lock that could affect the air lock sealing capability."

At least once per 6 months by verifying that only one door in each c.

air lock can be opened at a time.

l

(

The pro' visions of Specification 4.0.2 are not applicable.

" Exemption to Appendix J of 10 CFR 50.

6 SAN ONOFRE-UNIT 2 3/4 6-6 AMENDMENT NO.16

CONTAINMENT SYSTEMS CONTAINMENT VENTILATION SYSTEM LIMITING CONDITION FOR OPERATION 3.J.1.7 Containment purge supply and exhaust isolation valves shall be OPERABLE and:

Each 42-inch containment purge supply.and exhaust isolation valve a.

shall be sealed closed.

Each 8-inch containment purge supply and exhaust isolation valve b.

may be open for less than or equal to 1000 hours0.0116 days 0.278 hours 0.00165 weeks 3.805e-4 months per 365 days.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTION:

With the 42-inch containment purge supply and/or exhaust isolation a.

valve (s) open or not sealed closed,.or with the 8-inch purge supply and/or exhaust isolation valve (s) open for more than 1000 hours0.0116 days 0.278 hours 0.00165 weeks 3.805e-4 months per l

365 days, close and/or seal closed the open valve (s) within one hour l

or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD

~

SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

With a 42-inch or 8-inch containment purge supply and/or exha'ust 5.

isolation valve having a measured leakage rate exceeding the limits of Surveillance Requ,irement 4.6.1.7.3, restore the inoperable valve (s) to OPERABLE status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or be in at least HOT STANDBY-within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

SURVEILLANCE REOUIREMENTS 4.6.1.7.1 The 42-inch containment purge supply and exhaust isolation valves shall be verified sealed closed at least once per 31 days.

4.6.1.7.2 The cumulative time that the 8-inch purge supply and exhaust isolation valves are bpen during the past 365 days shall be determined at least once per 7 days.

4.6.1.7.3 At least once per 3 months each 42 inch and each 8 inch purge supply and exhaust isolation valve with resilient material seals shall be demonstrated OPERABLE by verifying that the measured leakage rate is less than or equal _ to 0.05 L,when pressurized to P,.

9 O

SAN ONOFRE-UNIT 2 3/4 6-13 AMENDMENT NO. 16

CONTAINMENT SYSTEMS 3/4.6.2 DEPRESSURIZATION AND COOLING SiSTEMS CONTAINMENT SPRAY SYSTEM LIMITING CONDITION FOR OPERATION 3.6.2.1 Two independent containment spray systems shall be OPERABLE with each spray system capable of taking suction from the RWST on a Containment Spray Actuation Signal and automatically transferring suction to the containment sump on a Recirculation Actuation Signal.

Each spray system flow path from the containment sump shall be via an OPERABLE shutdown cooling heat exchanger.

APPLICABILITY: MODES 1, 2 and 3.

ACTION:

With one containment spray system inoperable, restore the inoperable spray system to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months ; restore the inoperable spray, system to OPERABLE status within the next 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or be in HOT SHUTDOWN within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

SURVEILLANCE REQUIREMENTS 4.6.2.1 Each containment spray r.ystem shall be demonstrated OPERABLE:

At least once per 31 days by verifying that each valve (manual, a.

power operated or automatic) in the flow path that is not locked, sealed, or otherwise secured in position is in the correct position with suction aligned to the RWST.

i b.

At least once per 18 months, during shutdown, by:

1.

Verifying that each automatic valve in the flow path actuates to its correct position on a Containment Spray Actuation test signal.

2.

Verifying that upon a Recirculation Actuation Test Signal, the containment sump isolation valves open and that a recirculation J

mode flow path via an OPERABLE shutdown cooling heat exchanger is established.

SAN ONOFRE-UNIT 2 3/4 6-14 AMENDMENT NO.16 l

~~

i CONTAINMENT SYSTEMS SURVEILLANCE REOUIREMENTS (Continued) 3.

Verifying that each spray pump starts automatically on a Safety Injection Actuation test signal.

4.

Verifying that each containment spray header riser is filled with water to within 10 feet of the lowest spray ring.

1 At least once per 5 years by performing an air or smoke flow test j

c.

through each spray header and verifying each spray nozzle is unobstructed.

2 I

A d

1 1

4 e

l 9

O SAN ONOFRE-UNIT 2 3/4 6-15 AMEN 0 MENT NO.16'

C0!41 AI!a4ENT SYSTEMS IODINE REMOVAL SYSTEM

[

~

LIMITING CONDITION FOR OPERATION 3.6.2.2 The iodine removal system shall be OPERABLE with:

~

5 A spray additive tank containing a minimum solution volume of 1456

's a

a.

gallons of between 40 and 44% by weight Na0H solution with a minimum

,~

solution temperature between 82 F and 88 F and b.

Two spray chemical addition pumps each capable of adding Na0H s

solution from the chemical addition tank to a containment spray system pump flow.

hj APPLICABILITY:

MODES 1, 2 and 3.

s ACTION:

With the iodine removal system inoperable, restore the system to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months ; restore the iodine removal system to OPERABLE status within the next 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or be in HOT SHUTDOWN within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

SURVEILLANCE REQUIREMENTS t

i 4.6.2.2 The iodine removal system shall be demonstrated OPERABLE:

, N

~

a.

At least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months by verifying the Na0H solution,

3 temperature.

b.

At least once per 31 days by verifying that each valve (manual, power operated or automatic) in the flow path that is not locked, sealed, or otherwise secured in position, is in its correct position.

c.

At least once per 6 months by:

1.

Verifying the contained solution volume in the tank, and./

2.

Verifying the concentration of the NaOH solution by chcinical analysis.

d.

At least once per 18 months, during shutdown, by verifying that (1)-

each automatic valve in the flow path actuates to its correct position and (2) that each spray chemical addition pump starts automatically on a Containment Spray Actuation test signal.

At least once per 5 years by verifying a minimum solution flow rate of e.

20 gpm through all piping sections from the spray additive tank to the suction at the containment spray pumps.

SAN 0%FRE-UNIT 2 3/4 6-16 4

H

CONTAINMENT SYSTEMS CONTAINMENT COOLING SYSTEM LIMITING CONDITION FOR OPERATION 3.6.2.3 Two independent groups of containment cooling fans shall be OPERABLE with two fan systems to each g'roup.

~

.c.

APPLICABILITY:

MODES 1, 2, 3 and 4.

A ACTION:

With one group of the above required containment cooling fans

~

a.

inoperable and both containment spray systems OPERABLE, restore the inoperable group of cooling' fans to OPERABLE status within 7 days or

^

be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

b.

With two groups of the above required containment cooling fans inoperable, and both containment spray systems OPERABLE, restore at least one group of cooling fans to OPERARLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or be in at least HOT STANDBY wittiin the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .. Restore both above required

' groups of cooling fans to OPERABLE status within 7 days of initial

' loss or be in at least HOT STANDBY withih the 'next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

With one group of the above required containment cooling fans c.

inoperable and one'contaisent spray system inoperable, restore the inoperable spray system to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or be in at.least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the-following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

Restore the inoperable group of containment coolin~g fans to OPERABLE status within 7 days of initial loss or be in at~least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in iCOLDSHUTDOWNwithinthefollowing30 hours.

SURVEILLANCEREQUIREMENTS 4.6i2.3 Each' group of containment cooling fans shall be, demonstrated OPERABLE:

Ai.leastonce'ver31daysby:

a.

1.

Starting each fan group from the control room and verifying that each fan group perates for at least 15 minutes.

j 2.

Verifying a cooling water flow rate of greater than or equal to 2000 gpm to each cooler.

b.

At least once per 18 months by verifying.that each fan group starts automatically on a Containment' Cooling Actuation test signal.

~

/

SAN ONOFRE-UNIT 2 3/4 6-17 i

missise

1 CONTAINMENT SYSTEMS s

3/4.6.3 CONTAINMENT ISOLATION VALVES l

l c

LIMITING CONDITION FOR OPERATION

(

I, The containment isolation valves specified in Table 3.6-1 shall be l

3.6.3 OPERABLE with isolation times as shown in Table 3.6-1.

f APPLICABILITY:

MODES 1, 2, 3 and 4.

i ACTION:-

\\

l l

l With one or more of the isolation valve (s) specified in Table 3.6-1 inoperable.

l maintain at least one isolation valve OPERABLE in each affected penetration l

that is open and either:

Restore the inoperable valve (s) to OPERABLE status within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , a.

or b.

Isolate each affected penetration within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months by use of at least one deactivated automatic valve secured in the isolation position, i

I or Isolate the affected penetration within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months by use of at least c.

one closed manual valve or blind fiange; or l

d.

Be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD l

SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

i SURVEILLANCE REQUIREMENTS 4.6.3.1 The isolation valves specified in Table 3.6-1 shall be demonstrated OPERABLE prior,to. returning the valve to service after maintenance, repair or replacement work is performed on the valve or its associated actuator, control or power circuit by performance of a cycling test and verification of isolation l

j time.

f 4.6.3.2 Each isolation valve specified in Table 3.6-1 shall be demonstrated

~

OPERABLE during the COLD SHUTDOWN or REFUELING MODE at least once per 18 months by:

Verifying that on a CIAS or SIAS test signal, each isolation valve a.

actuates to its isolation position.

i l

l SAN ONOFRE-UNIT 2 3/4 6-18 AMEN 0 MENT NO.'16

.\\'

~-

TABLE 3.6-1 (Continued) 9=

9 MAXIMUM Q

ISOLATION A

PENETRATION TIME (SEC) j NUMBER VALVE NUMBER FUNCTION 5

10 H

28 HV-4052#-

Steam generator feedwater 10 N

29 HV-4048#

Steam generator feedwater 1

30A HV-7802 Containment air radioactivity monitor inlet 1

30A HV-7803 Containment air radioactivity monitor inlet 1

308 HV-7801 Containment air radioactivity monitor outlet 1

308 HV-7800 Containment air radioactivity monitor outlet 1

308 HV-7816 Containment air radioactivity monitor outlet 40 30C HV-0516 Quench tank and drain tank gas sample 40 30C HV-0514 Quench tank and drain tank gas sample 40 30C HV-0515 Quench tank and drain tank gas sample 5

32 HV-8204#

Mainsteam isolation 5

R 33 HV-8205#

Mainsteam isolation 40 42 HV-6211 Component cooling water inlet 40 T

43 HV-6216 Component cooling water outlet p

45 HV-9900 Containment normal A/C chilled water inlet 40 HV-9920 Containment normal A/C chilled water inlet 40 45 HV-9971 Containment normal A/C chilled water inlet 40 46 40 46 HV-9921 Containment normal A/C chilled water outlet 40 47 HV-7258 Containment waste gas vent header 40 47 HV-7259 Containment waste gas vent header 40 77 HV-5434 Nitrogen supply to safety injection tanks 8.

CONTAINMENT PURGE (CPIS) 12 18 HV-9949**

Containment purge inlet (normal) 12 18 HV-9948**

Containment purge inlet (normal) 5 18 HV-9821 Containment mini purge inlet k

5 g

18 HV-9823 Containment mini purge inlet 12 g

19 HV-9950**

Containment purge outlet (normal) 12 5

19 HV-9951**

Containment purge outlet (normal) 5 19 HV-9824 Containment mini purge outlet 5

P 19 HV-9825 Containment mini purge outlet 2

G

p TABLE 3.6-1 (Continued) z O

MAXIMUM

'k ISOLATION g

PENETRATION TIME (SEC) a NUMBER BLVENUMBER FUNCTION z

U C.

MANUAL NA 4

6 2"-099-C-334*

Safety injection drain to RWST N

NA 8

HV-9200 Charging line to regenerative heat exchanger NA 9

HV-9337#@

Shutdown cooling to LPSI pumps NA 9

HV-9377#@

Shutdown cooling to LPSI pumps NA

-9 HV-9336#@

Shutdown cooliiig to LPSI pumps NA 9'

HV-9379#@

Shutdown cooling to LPSI pumps NA i

10A HV-0352A# _

Containment pressure detectors NA 10C 3/4"-038-C-396 Integrated leak rate test pressure sensor NA 10C 3/4"-039-C-396 Integrated leak rate test pressure sensor NA 16A HV-0500*

Post LOCA hydrogen monitor HA q

HV-0501" Post LOCA hydrogen monitor NA 16A' ai 168 HV-0502*

Post LOCA hydrogen monitor NA 168 HV-0503*

Post LOCA hydrogen monitor NA~

g 2"-321-C-376*

Quench tank makeup NA 20-21 2"-055-C-387 Service air supply line NA 25 10"-100-C-212 Refueling canal fill and drain NA 25 10"-101-C-212 Refueling canal fill and drain NA 27A HV-03520#

Containment pressure detectors NA 31 HV-9946 Containment hydrogen purge inlet NA 31 HCV-9945 Containment hydrogen purge inlet NA 40A HV-03528#

Containment pressure detectors NA 67 HV-9434 Hot leg injection NA 68 2"-130-C-334 Charging line to auxiliary spray NA 70-2"-037-C-387 Auxiliary steam. inlet to utility stations NA 70 2"-038-C-387 Auxiliary steam inlet to utility stations NA 71 HV-9420 Hot leg injection NA g

HV-0352C#.

Containment pressure detectors 73A NA g

74 HV-9917 Containment hydrogen purge outlet NA mj HCV-9918 Containment hydrogen purge outlet 74

=

O

PLANT SYSTEMS 3/4.7.5 CONTROL ROOM EMERGENCY AIR CLEANUP SYSTEMA LIMITING CONDITION FOR OPERATION 3.7.5 Two independent control room =mergency air cleanup systems shall be OPERABLE.

APPLICABILITY:

ALL MODES ACTION:

Unit 2 or 3 in MODE 1, 2, 3 or 4:

With one control room emergency air cleanup syste'm inoperable, restore the inoperable system to OPERABLE status within 7 days or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

Units 2 and 3 in MODE 5 or 6:

a.

With one control room emergency air cleanup system inoperable, restore the inoperable system to OPERABLE status within 7 days or initiate and maintain operation of the remaining OPERABLE control room emergency air cleanup system in the recirculation mode.

b.

With both control room emergency air cleanup systems inoperable, or with the OPERABLE control room emergency air cleanup system required to be in the recirculation mode by ACTION (a), not capable of being powered by an OPERABLE emergency power source, suspend all operations involving CORE ALTERATIONS or positive reactivity changes.

The provisions of Specification 3.0.3 are not applicable in MODE 6'.

c.

SURVEILLANCE REQUIREMENTS i

4.7.5 Each control room emergency air cleanup system shall be demonstrated OPERABLE:

At least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months by verifying that the control room air a.

temperature is less than or equal to 110*F.

b.

At least once per 31 days on a STAGGERED TEST BASIS by initating, from the control room, flow through the HEPA filters and charcoal adsorbers and verifying that the system operates for at least 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months with the heaters on.

c.

At least once per 18 months or (1) after any structural maintenance on the HEPA filter or charcoal adsorber housings, or (2) following painting, fire or chemical release in any ventilation zone communicating with the system by:

1.

Verifying that with-the system operating at a flow rate of 35485 cfm + 10% for the air conditioning unit, and 2050 t 150 cfm for the ventilation unit and recirculating through the respective HEPA filters and charcoal adsorbers, leakage through the system diverting valves is less than or equal to 1% air conditioning unit and 1% ventilation unit when the system is tested by admitting cold DOP at the respective intake.

^ Shared system with San Onofre - Unit 3.

SAN ON0FRE-UNIT 2 3/4 7-13 AMEN 0 MENT NO.16

PLAT 4T SYSTEliS SURVEllLANCE REQUIREMEf4TS (Continued) 2.

Verifying that the cleanup system satisfies the in place testing acceptance criteria and uses the test procedures of Regulatory Positions C.S.a C.5.c and C.5.d of Regulatory i

l Guide 1.52, Revision 2, March 1978, and the system flow rate is, l

2050 1 150 cfm for the ventilation unit and 35,485 cfm i 10%

l for the air conditioning unit.

3.

Verifying within 31 days after removal that a laboratory analysis of'a representative carbon sample obtained in accordance with Reguictory Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, meets the laboratory testing criteria of Regulatory Position C.6.a of Regulatory Guide 1.52, Revision 2, March 1978.

4.

Verifying a system flow rate of 2050 1 150 cfm for the l

ventilation unit and 35,485 cfm 10% for the air conditioning unit during system operation when tested in accordance with AtiSI tis 10-1975.

d.

After every 720 hours0.00833 days 0.2 hours 0.00119 weeks 2.7396e-4 months of charcoal adsorber operation by verifying within 31 days after removal that a laboratory analysis of a representative carbon sample obtained in accordance with Regulatory Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, meets the laboratory testing criteria of Regulatory Position C.6.a of Regulatory Guide 1.52, Revision 2, March 1978.

c.

At least once per 18 months by:

1.

Verifying that the pressure drop across the combined HEPA filters and charcoal adsorber banks is less than 7.0 inches l

Water Gauge ventilation unit and less than 7.3 inches Water Gauge air conditioning unit while operating the system at a flow rate of 2050 150 cfm for the ventilation unit and l

35,485 cfm 10% for the air conditioning unit.

2.

Verifying that on a control room isolation test signal, the system automatically switches into the emergency mode of operation with flow through the HEPA filters and charcoal adsorber banks.

3.

Verifying that on a toxic gas isolation test signal, the system automatically switches into the isolation mode of operation with flow through the HEPA filters and charcoal adsorber banks.

4.

Verifying that the system maintains the control room at a positive pressure of greater than or equal to 1/8 inch W.G.

relative to the outside atmosphere during system operation in the emergency mode.

s 5.

Verifying that the hecters diss'ipate 4.8 kw 5% when tested l

in accordance with At:SI I:510-1975.

S t.N ":0F:iE-UNIT 2 3/4 7-14

.AME! EMEi T I:0. 14

\\

PLANT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) b.

Stored sources not in use - Each sealed source and fission detector l

shall be tested prior to use or transfer to another. licensee unless tested within the previous six months.

Sealed sources and fission detectors transferred without a certificate indicating the last test date shall be tested prior to being placed into use.

l c.

Startup sources and fission detectors - Each sealed startup source and fission detgetor shall be tested within 31 days prior to being subjected to core flux or installed in the core and following repair or maintenance to the source or detector.

4.7.7.3 Reports - A report shall be prepared and. submitted to the Commission on an annual basis if sealed source or fission detector leakage tests reveal the presence of greater than or equal to 0.005 microcuries of removable contamination.

G 9

O O

e e

d e

SAN ONOFRE-UNIT 2 3/4 7-25

PLANT SYSTEMS 3/4.7.8 FIRE SUPPRESSION SYSTEMS FIRE SUPPRESSION WATER SYSTEM LIMITING CONDITION FOR OP'ERATION 3.7.8.1 The fire suppression water system shall be OPERABLE with:

Two electric motor-driven fire pumps, each with a capacity of a.

1500 gpm and one diesel-driven fire pump with a capacity of 2500 gpm, with their discharge aligned to the fire suppression

header, Two separate water supplies, each with a minimum contained volume of b.

300,000 gallons, and An OPERABLE flow path capable of taking suction from each water c.

supply and transferring the water through distribution piping with OPERABLE sectionalizing control or isolation valves to the yard hydrant curb valves, the first valve upstream of the water flow alarm device on each spray and/or sprinkler or fire hose station required to be OPERABLE per Specifications 3.7.8.2 and 3.7.8.3.

APPLICABILITY:

At all times.

ACTION:

With one required electric motor-driven / diesel-driven pump and/or one a.

water supply inoperable, restore the inoperable equipment to OPERABLE status within 7 days or provide an alternate backup pump or supply.

The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

b.

With the fire suppression water system otherwise inoperable, establish a backup fire suppression water system within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

t 9

m I

l l

l SAN ONOFRE-UNIT 2

'3/4 7-26 AMENDMENT NO.16

\\

PLANT SYSTEMS s

SURVEILLANCE RE0VIREMENTS 4.7.8.1.1 The fire suppression water system shall be demonstrated OPERABLE:

At least once per 7 days by verifying the contained water supply a.

volume.

At least once per 31 days on a STAGGERED TEST BASIS by starting each b.

electric motor driven pump and operating it for at least 15 minutes on recirculation flow.

At least once per 31 days by verifying that each valve (manual, c.

power operated or automatic) in the flow path is in its correct position.

d.

At least once per 12 months by cycling each testable valve in the flow path through at least one complete cycle of full travel.

At least once per 18 months by performing a system functional test e.

which includes simulated automatic actuation of the system through-out its operating sequence, and:

1.

Verifying performance of the fire pumps as follows:

Diesel engine drive pump develops at least 2500 gpm at a a.

system head of 283 feet..

b.

Electric motor driven pumps each develop at least 1500 gpm at a system head of 289 ft.

2.

Cycling each valve in the flow path that is not testable during plant operation through at least one complete cycle of full travel, and 3.

Verifying that each fire suppression pump starts (sequentially) to maintain the fire suppression water system pressure greater than or equal to 95 psig.

f.

At least once per 3 years by performance of a system flush.

O e

SAN ONOFRE-UNIT 2 3/4 7-27 AMEN 0 MENT NO.16

a PLANT SYSTEMS f

SURVEILLANCE REQUIREMENTS (Continued)

At least once per 3 years by performing a flow test of the system in accordance with Chapter 5 Section 11 of the Fire Protection g.

Handbook, 14th Edition, published by the National Fire Protection J

Association.

The fire pump diesel engine shall be demonstrated OPERABLE:

l 4.7.8.1.2 At least once per 31 days by verifying:

a.

The diesel fuel oil day storage tank contains at least i

1.

225 gallons of fuel, and The diesel starts from ambient conditions and operates for at 2.

least 30 minutes on recirculation flow.

At least once per 92 days by verifying that a samp b.

0975-1977 i

is within the acceptable limits specified in Table 1 of ASTM when checked for viscosity, water ind sediment.

l At least once per 18 months during shutdown, by subjecting the diesel to an inspection in accordance with procedures prepared in c.

l conjunction with its manufacturer's recommendations for the class of service.

The fire pump diesel starting 24-volt battery bank and charger 4.7.8.1.3 l

shall be demonstrated OPERABLE:

i At least once per 7 days by verifying that:

I a.

The electrolyte level of each battery is above the plates, and i

1.

The overall battery voltage is greater than or equal to l

2.

24 volts.

At least once per 92 days by verifying that the specific gravity is b.

appropriate for continued service of the battery.

At least once per 18 months by verifying that:

/

c.

Th'e batteries, cell plates and battery racks show no visual indication of physical damage or abnormal deterioration, and 1.

s The battery-to-battery and terminal connections are clean, tight, free of corrosion, and coated with anti-corrosion 2.

material.

3/4 7-28

~

5 SAN ONOFRE-UNIT 2

PLANT SYSTEMS SPRAY AND/OR SPRINKLER SYSTEMS LIMITING CONDITION FOR OPERATION 3.7fB.2 The spray and/or sprinkler systems listed in Table 3.7-5 shall be OPERABLE.

APPLICABILITY:

Whenever equipment protected by the spray / sprinkler system is required to be OPERABLE.

ACTION:

f With one or more of the above required spray and/or sprinkler systems a.

inoperable, within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months establish a continuous fire watch with backup fire suppression equipment for those areas outside containment in which redundant systems or components could be damaged; for other areas outside containment, establish an hourly fire watch patrol.

With one or more of the above required spray and/or sprinkler systems b.

inside containment inoperable, restore the system to OPERABLE status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or, in lieu of any other report required by Specifica-tion 6.9.1, prepare and submit a Special Report to the Commission pursuant to Specification 6.9.2 within the next 7 days outlining the action taken, the cause of the inoperability and the plans and schedule for restoring the system to OPERABLE status.

The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

c.

SURVEILLANCE REQUIREMENTS Each of the above required spray and/or sprinkler systems shall be 4.7.8.2 demonstrated OPERABLE:

At least once per 31 days by verifying that each valve (manual, a.

power operated or automatic) outsi.de of containment in the flow' path is in its correct position.

At least once per 31 days during each COLD SHUTDOWN or REFUELING by b.

verifying that each valve (manual, power operated or automatic) inside containment in the flow path is in its correct position, At least once per 12 months by cycling each testable valve in the c.

flow path through at least one complete cycle of full travel.

i SAN ONOFRE-UNIT 2 3/4 7-29' AMEN 0 MENT NO. 16

PLANT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) t d.

At least once per 18 months:

0 1.

By performing a system functional test which includes simulated automatic actuation of the system, and:

a)

Verifying that the automatic valves in the flow path actuate to their correct positions on a test signal, and b)

Cycling each valve in the flow path that is not testable during plant operation through at least one complete cycle of full travel.

l 2.

By a visual inspection of the dry pipe spray and wet pipe spray sprinkler headers to verify their integrity, and 3.

By a visual inspection o' each spray / sprinkler head to verify the spray pattern is not obstructed.

e.

At least once per 3 years by performing an air flow test through each open head spray /spr'inkler header and verifying each open head spray / sprinkler nozzle is unobstructed.

G 9

?

/

SAN ONOFRE-UNIT 2 3/4 7-30

t TABLE 3.7-6~

FIRE HOSE STATIONS LOCATION ELEVATION STATION NUMBER i

.i Containment Bldg. - Unit 2 63'-6" 130 Containment Bldg. - Unit.2 63'-6".

1 Containment Bldg. - Unit 2 63'-6" 8

Containment Bldg. - Unit 2 45'-0" 2

Containment Bldg. - Unit 2 45'-0" 5

t Containment Bldg.

Unit 2 45'-0" 9

Containment Bldg..- Unit 2 30'-0" 3

Containment Bldg. - Unit 2 30'-0" 6

Containment Bldg. - Unit 2 30'-0" 10 Containment Bldg. - Unit 2 17'-6" 4

l Containment Bldg. - Unit 2 17'-6" 7

Containment Bldg. - Unit 2 17'-6" 11~

?

Electrical Penetration Area - Unit 2 45'-0" 120 Electrical Penetration Area - Unit 2 45'-0" 121 l

~

Electrical Penetration Area - Unit 2 63'-6" 122 Electrical Penetration Area - Unit 2 63'-6" 123

{

Cable Riser Gallery-(North)-Auxiliary l

9'-0" 109 Bldg. Control Area Cable Riser Gallery (South)-Auxiliary 9'-0" 114 Bldg. Control Area Cable Spreading Room-Auxiliary Bldg.

4 Control Area 9'-0" 108 l

Cable Spreading Room-Auxiliary Bldg.

Control Area 9'-0" 113 Cable Spreading Room Corridor-Auxiliary Bldg. Control Area 9'-0" 48 Cable Spreading Room Corridor-Auxiliary Bldg. Control Area 9'-0" 60 Cable Riser Gallery (North)-Auxiliary Bldg. Control Area 30'-0" 110 Cable Riser Gallery (South)-Auxiliary Bldg. Control Area 30'-0" 115 Corridor (North)-Auxiliary Bldg. Control Area 30'-0" 49 1

Corridor (South)-Auxiliary Bldg. Control Area 30'-0" 61 Cable Riser Gallery (North)-Auxiliary Bldg. Control Area 50'-0" 111 g

j Cable Riser Gallery (South)-Auxiliary Bldg. Control Area 50'-0" 116 Corridor (North)-Auxiliary Bldg. Control Area 50'-0".

50 Corridor (South)-Auxiliary Bldg. Control Area 50'-0" 62 HVAC Room Corridor-Auxiliary Bldg. Control Area' 50'-0" 56-HVAC Room Corridor-Auxiliary Bldg. Control Area 50'-0" 57 CaDie Riser Gallery (North)-Auxiliary Bldg. Control Area 70'-0" 112 Cable Riser Gallery (South)-Auxiliary Bldg. Control Area 70'-0" 117 Fuel Handling Bldg.-Unit 2 63'-6" 118 Fuel Handling Bldg.-Unit 2 63'-6" 119 I

SAN ONOFRE-UNIT 2-3/4.7-33

PLANT SYSTEMS 3/4.7.9 FIRE RATED ASSEMBLIES LIMITING CONDITION FOR OPERATION 3.7.9 All fire rated assemblies (walls, floor / ceilings, cable tray enclosures and other fire barriers) separating safety related fire areas or separating portions of redundant systems important to safe shutdown within a, fire area and all sealing devices in fire rated assembly penetrations (fire doors, fire windows, fire dampers, cable, ventilation duct, and piping penetration seals) shall be OPERABLE.

APPLICABILITY:

At all times.

ACTION:

a.

With one or more of the above required fire rated assemblies and/or sealing devices inoperable, within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months either establish a continuous fire watch on at least one side of the affected assembly, or verify the OPERABILITY of the fire detectors on at least one side of the inoperable assembly and establish an hourly fire watch patrol, b.

The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS 4.7.9.1 Each of the above required fire doors shall be verified OPERABLE by:

, a.

Verifying at least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months the position of each closed fire door and that doors with automatic hold-open and release mechanisms are free of obstructions.

b.

Verifying at least once per 7 days -the position of each locked closed fire door.

c.

Performing a CHANNEL FUNCTIONAL TEST at least once per 31 days of the fire door supervision system.

I d.

Inspecting at least once per 6 months the automatic hold-open, release and closing mechanism and latches.

e.

Performing a functional test at least once per 18' months of automatic hold open, release, closing mechanisms and latches.

I SAN ONOFRE-UNIT 2 3/4 7-34 AMEN 0 MENT NO. 16

~

PLANT SYSTEMS SURVEILLANCE REQUIREMENTS 4.7.9.2 At least once per 18 months the above required fire rated assemblies and penetration sealing devices other than fire doors shall be verified OPERABLE by:

a.

Performing a visual inspection of the exposed surfaces of each fire rated assembly, b.

Perfotaing a visual inspection of each fire window / fire damper /and associated hardware.

c.

Performing a visual inspection of at least 10% of each type (mechanical and electrical) of sealed penetration.

If apparant changes in appearance or abnormal degradations are found, a visual inspection of an additional 125 of each type of sealed penetration shall be made.

This inspection process shall continue until a 10% sample with no apparent changes in appearance or abnormal degradation is found. Samples shall be selected such that each penetration seal will be inspected at least once per 15 years.

1 l

t 1

o o

a f

SAN ONOFRE-UNIT 2, 3/4 7-35 AMENOMENT NO.16

ELECTRICAL POWER SYSTEM SURVEILLANCE REQUIREMENTS (Continued) b.

Demonstrated OPERABLE at least once per 18 months during shutdown by transfer' ring (manually and automatically) unit power supply from the normal circuit to the alternate circuit.

4.8.1.1.2 Each diesel generator shall be demonstrated OPERABLE:

a.

In accordance with the frequency specified in Table 4.8-1 on a STAGGERED TEST BASIS by:

1.

Verifying the fuel level in the day fuel tank, i

2.

Verifying the fuel level in the fuel storage tank, 3.

Verifying the fuel transfer pump can be started and transfers fuel from the storage system to th day tank, 4.

Verifying the diesel starts from ambient condition and.

accelerates to at least 900 rpm in less than or equal to 10 seconds.

The generator voltage and frequency shall be 4360 436 volts and 60 1 1.2 Hz within 10 seconds after the' start signal.

The diesel generator shall be started for this test by using the m'anual start signal.

5.

Verifying the generator is synchronized,. loaded to greater than or equal to 4700 kw in less than or' equal to 77 secon~ds, and operates with a load greater than or equal to 4700 kw for at least an additional 60 minutes, and I

6.

Verifying the diesel generator is aligned to provide standby power to the associated emergency busses.

l b.

At least once per 31 days and after,each operation of the diesel where the period of operation was greater than or equal to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months by checking for and removing accumulated water from the day tank.

. c.

At least once per 92 days and from new fuel oil prior to addition to the storage tanks by verifying that,a sample obtained in accordance with ASTM-D270-1975 has a water and sediment content of less than or equal to.05 volume percent and a kinematic viscosity @40*C of greater than or equal to 1.9 but less than or equal to 4.1 when tested in accordance with ASTM-0975-77, and.an impurity level of less than 2 mg of insolubles per 100 ml. when tested in accordance with ASTM-D2274-70.

d.

At least once per 18 months during shutdown by:

1.

Subjecting the diesel to an inspection in accordance with procedures prepared in conjunction with its manufacturer's recommendations for this class of standby service.

~

Verifying the generator capability to reject a load of greater 2.

than or equal to 655.7 kw while maintaining voltage at 4360 1 436 volts and frequency at 60 1 6.0 Hz.

SAN ONOFRE-UNIT 2 3/4 8-3

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) 3.

Verifying the generator capability to reject a. load of 4700 kW without tripping.

The generator voltage shall not exceed 5450 volts during and following the load rejection.

4.

Simulating a loss of offsite power by itself, and:

a)

Verifying de-energization of the emergency busses and load shedding from the emergency busses.

1 b)

Verifying the diesel starts on the auto-start signal, energizes the emergency busses with permanently connected loads within 10 seconds and operates for greater than or equal to 5 minutes while its generator is loaded with the permanently connected loads.

/ifter energization, the steady state voltage and frequency of the emergency busses shall be maintained at 4360 t 436 volts and 6011.2 HI during this test.

5.

/erifying that on an ESF test signal (without loss of offsite power) the diesel generator starts on the auto-start signal and operates on standby for greater tha.n or equal to 5 minutes.

The steady' state generator voltage and frequency shall be 4?SO 436 volts and 60 1.2 Hz within 10 seconds after the auto-start signal; the generator vcitage and fregency shall be maintained within these limits during this test.

6.

Verifying that on a simulated loss of the diesel generator (with offsite power not available), the loads are shed from the emergency busses and that subsequent loading of the diesel generator is in accordance with design requirements.

7.

Simulating a loss of offsite power in conjunction with an ESF test signal, and a)

Verifying de-energization of the emergency busses and load l

shedding from the emergency busses.

b)

Verifying the diesel starts on the auto-start sigaal, energizes the emergency busses with permanently connected loads within 10 seconds, energizes the auto connected emergency (accident) loads through the load sequence and operates for greater than or equal to 5 minutes while its generator is loaded with the emergency loads.

After loading, the steady state voltage and frequency of the emergency busses shall be maintained at 4360 t 436 volts and 60 + 1.2/-0.3 Hz during this test.

SAN ONOFRE-UNIT 2 3/4 8-4 AMENDMENT NO. 16

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

(c) For each circuit breaker found inoperable during these functional tests, an additional representative sample of at least 10% of all the circuit breakers of the inoperabic type shall also be functionally tested until no more failures are found or all circuit breakers of that type have been functionally tested.

2.

By selecting and functionally testing a representative-sample of at least 10% of each type of lower voltage circuit breakers.

Circuit breakers selected for functional testing shall be selected on a rotating basis.

Testing of these circuit breakers shall consist of injecting a current in excess of the breakers' nominal setpoint and measuring the response time.

The measured response time will be compared to the manufacturer's data to insure that it is less than or equal to a value specified by the manufacturer.

Circuit. breakers found inoperable during functional testing shall be. restored to OPERABLE status prior to resuming operation.

For each circuit breaker found inoperable during these functional tests, an additional representative sample of at least 10% of all the circuit breakers of the inoperable type shall also be functionally tested until no more failures are found or all circuit breakers of that type have been functionally tested.

b.

At least once pcr 60 months by subjecting each circuit br'eaker to an inspection and preventive maintenance in accordance with procedures prepared in conjunction with its manufacturer's recommendations.

9 9

e SAN ONOFRE-UNIT 2 3/4 8-17 AMENDMENT NO, 2

,.o.

-.. ~.. - - -....

m__.

_..___m._._

TABLE 3.8-1 CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES o

t

'E' k

Primary Device Backup Device Service Description Number l

.a Number Containment Normal Cooling Fan E-397 z

l U

2B0106 2BLP0101 280107 2BLP0102 CEDM Cooling Supply Fan E-403B 2BLP0103 CEDM Cooling Supply Fan E-403A 200109 Standby Containment Normal Cooling Fan E-393 2BLP0104 2B0111 Containment Normal Cooling Fan E-394 2BLP0201 280209 2BLP0301 Hydrogen Recombiner E-145 Power Panel L-180 l

280406 Upper Dome Air Circulator A-071 i

2BLP0302 200409 Containment Emergency Fan E-399 2BLP0303 200410 Containment Emergency Fan E-401 2BLP0304 2B0411 Standby. Upper Dome Air Circulator A-074 2BLP0305 2B0419 2BLP0401 Hydrogen Recombiner E-146 Power Panel L-181 200606 Upper Dome Air Circulator A-072-2BLPO402 9

2B0609-Containment Emergency Fan E-400 2BLP0403

~

g 200610 Containment Emergency Fan E-402 2BLP0404 280611

' Standby Upper Come Air Circulator A-073 l

2BLPO405 200619 2BLP0501

Containment Normal Cooling Fan E-396 280809 Containment' Normal Cooling Fan E-398-2BLP0601

- Containment Recirculation Unit E-333 i-280811 2BLP0701 280903 Polar Crane'(Containment) R001 (C) 280906 2BLP0702 280907 2BLP0703 Standby Control Element Drive Mechanism Cooling Supply Fan E-404A-

[

'g s

y 280909T 2BLP0704.

Standby CEDM Cooling Supply Fan E-4048 m

m 280911~

2BLP0705 Containment Recirculating Unit Heater E-568 CCW from RCP P-001 Seal Heat Exchanger TV-9144 l

'i 2BA02' f2BLP0812 E

z.

28A03 2BLP0813

.CCW from RCP P-003 Seal Heat Exchanger _TV-9154 2BA04 2BLP0801 CEDM Cooling Supply Fan E-403A (Enclosure Heater)-

g

.g (28A04-A)_

l s

._p m

m

i l

1

(

TABLE 3.8-1 CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES O

O k

Primary Device Backup Device Service Description a

Number Number z

2BLP0802

,CEDM Cooling Supply Fan E-4038 U

2BA04 (Enclosure Heater)

(2BA04-8)

Standby Containment Normal Cooling Fan E-393 m

2BA04 2BLP0814 (Enclosure Heater)

(2BA34-C)

Containant Normal Cooling Fan E-394 2BA04 2BLP0826 (Enclosure Heater)

(2BA04-D)

Containment Normal Cooling Fan E-397

+

2BA04 2BLP0828 (2BA04-E) 2BA08 2BLP0803 Movable Incore Detector Drive Package W338A 2BA11 2BLP0905

- Cont. Structure Electric Heater E-467 w

28A25 2BLP0910 Cont. Cooling Unit E-393 Circ. Water Outlet HV-9940FB A

28A26 2BLP0911 Cont. Cooling Unit E-394 Circ. Water Outlet HV-9940EB co

.2BA27 2BLP0912 Cont. Cooling Unit E-397 Circ. Water Outlet HV-994008 28A31 2BLP0913 Cont. Cooling Unit E-393 Circ. Water Outlet HV-9940FC 2BA32 2BLP0914 Cont. Cooling Unit E-394 Circ. Water Inlet HV-9940EC 2BA33 2BLP0915 Cont. Cooling Unit E-397 Circ. Water Inlet HV-99400C 2BA36 2BLP0808 RCP 1A 011 Lift Pump 1A1 P-260 2BLP0809 RCP IB 011 Lift Pump 181 P-264 28A37 2BA38 2BLP0810 RCP 28 011 Lift Pump 2B1 P-262 28A39 2BLP0901 Reactor Coolant Drain Pump (W) P-023 2BA40 2BLP0811 RCP 2A 011 Lift Pump 2A1 P-266 g

2BLP0817 RCP 1A Anti Rev. Rotation Device Lube Pump 1 P-399 m

2BA41 RCP 28 Anti Rev. Rotation Device Lube Pump 1 P-401 5

2BA42 2BLP0818 E

RCP IB Anti Rev. Rotation Device Lube Pump 1 P-403 2BA43 2BLP0819 z

28A44 2BLP0820 RCP 2A Anti Rev. Rotation Device Lube Pump 1 P-405 2BA45 2BLP0902 Reactor Cavity Cooling Fan A-319 2BA46 2BLP0903 Standby Reactor Cavity Cooling Fan A-321 cn

TABLE 3.8-1 CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES z

Eq g

Primary Device Backup Device Service Description f

Number Number 2BLP0807 Charging Line to Reactor Cooling Loop 1A HV-9203 z

U 28A47 Reactor Cavity Cooling Unit C HV-9905C h) 28A49 2BLP0821 2BA50 2BLP0822 Reactor Cavity Cooling Unit A HV-9905A 2BA51 2BLP0804 Quench Tank to Reactor Drain Tank HV-9101 28A55 2BLP0805 RCP Bleed Off to Quench Tank HV-9216 2BA57 2BLP0916 CEDM Cooling Unit E-403 CCW Outlet HV-9907AA 28A58 2BLP0917 CEDM Cooling Unit E-403 CCW Inlet HV-9907AC 28A59 2BLP0806 Safety Injection Tank to Reactor Drain Tank HV-9335 28A60 2BLP0904 Welding Receptacles Containment (50 KVA) 2BA62 2BLP0824 Recept. for Portable Cont. Sump Pump (H.P.) P-005 l

2BA63 2BLP0906 Containment Elevator P-003 m

2BA65 2BLP0815 Lower Level Air Circulator A-031 n>

28A66 2BLP0816 Lower Level Air Circulator A-033 2BE09 2BLP1001 Saf. Inj. Tank Drain to Refueling Wtr Tank HV-9334 2BE10 2BLP1002 Saf. Inj. Tk T-007 to Reactor Coolant Loop 1B HV-9350 2BE11 2BLP1003 Saf..Inj. Tk T-009 to Reactor Coolant Loop 2A HV-9350 2BE17 2BLP1010 Auxiliary Spray.to Pressurizer HV-9201 2BE21 2BLP1012 CCW Noncritical Cont. Inlet Isolation Valve HV-6223 2BE25 2BLP1005 Shutdn Coolant Flow from Reac. Coolant Loop 2 HV-9337 2BE26 2BLP1015 Reac.. Coolant Drain Tk Sample Cont. Isolation HV-0516 E

m 2BE27 2BLP1016 Containment Isolation Reactor Coolant Grain to Radwaste System HV-7512

'G 2BE30 2BLP1017 Quench Tank Vapor Sample Cont. Isol. HV-0514 h

H 2BE31 2BLP1004 Containment Sump to Radwaste Sump HV-5803 g.

2BE33 2BLP1021 Containment Purge Inlet HV-9949 2BE35 2BLP1018 Containment Emergency Sump Oulet HV-9305 m"

e e

_.__.. _ _ m _ _ _._

i L

TABLE 3.8-1

^

CONTAINMENT PENETRATION CONOUCTOR OVERCURRENT PROTECTIVE DEVICES Z

+

o

]

k Primary Device Backup Device Service Description J.

Number Number i'i CCW Noncritical Containment Isolation Valve HV-6336 2BLP1011

-8 28E46 i

N 2BF08 2BLP0823 Containment Sump Pur.p P-008 2BF09 2BLP1220 Containment Sump Pump P-007 2BJ05 2BL'P1101 Shutdn Coolant Flow from Reac. Coolant Loop 2 HV-9139 2BJ06 2BLP1104 Saf. Inj. Tk T-008 20 Reactor Coolant Loop 1A HV-9340 2BJ07 2BLP1105 Saf. Inj. Tk T-010 to Reactor Coolant Loop 2B HV-9370 2BJ17 2BLP1123 RCP Bleed off to Volume Control Tank HV-9217 2BJ21 2BLP1106 Cont. Isol. Safety Injection Tank Vent Header HV-7258-2BJ22 2BLP1115 Reactor Coolant Hot Leg Sample Cont. Isol. HV-0508 2BJ23 2BLP1116 Reactor Coolant Hot Leg Sample Cont. Isol. HV-0517 i

R-2BLP1117 Pressurizer Vapor Sample Containment Isol. HV-0510 2BJ26 9

2BJ27 2BLP1121 Pressur. Surge Line Liquid Sepl. Cont. Isol. HV-0512 N

2BJ29 2BLP1110 Containment Purge Outlet HV-9950 2BJ30.

2BLP1102 Hydrogen Purge Exhaust Unit Inlet HY-9917' 2BJ31 2BLP1103 Hydrogen Purge Supply Unit Discharge.HV-9946 2BJ34 2BLP1118 Containment Emergency Sump Outlet HV-9304 2BJ47 2BLP1124 Containment Normal Cooling Supply Isol. Valve HV-9900 l

2BJ48 2BLP1125 Containment Normal Cooling Return Isol. Valve HV-9971 2BN04,

2BLP1201 Movable Incore Detector Drive Pack W-3388 l-2BN07 2BLP1304 Containment Structure Electric Heater E-466 h

2BN21 2BLP1206 Charging Line to Reactor Coolant Loop 2A HV-9202 2

o 2BN24 2BLP1301 Reactor Cavity Cooling Fan A-320 2BN25

-2BLP1302 Stan'dby Reactor Cavity Cooling Fan A-322 h(

2BN26 2BLP1226 CCW from RCP P-004 Seal Heat Exchanger TV-9164 2BN27 2BLP1227 CCW from RCP P-002 Seal Heat Exchanger TV-9174 l

~

TABLE 3.8-1 CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES 2

E sa g

Primary Device Backup Device

/-

Number Number Service Description 5

-i 2BN28 2BLP1207 Reactor Cavity Cooling Unit D HV-9905D N

2BN29 2BLP1208 Reactor Cavity Cooling Unit B HV-9905B 2BN30 2BLP1209 RCP 1A 011 Lift Pump 1A2 P-261 2BN31

~

2BLP1219 RCP IB Oil Lift Pump 182 P-265 2BN32 2BLP1211 RCP 28 011 Lift Pump 282-263 2BN33 2BLP1212 RCP 2A 011 Lift Pump 2A2-267 2BN34 2BLP1303 Reactor Coolant Drain Tank Pump (E) P-022 2BN37 2BLP1213 RCP 1A Anti Rev. Rotation Device Lube Pump 2 P-400

.2BN38 2BLP1214 RCP 28 Anti Rev. Rotation Device tube Pump 2 P-402 2BN39 28LP1215 RCP 18 Anti Rev. Rotation Device Lube Pump 2 P-404 Y

2BN40 2BLP1216 RCP 2A Anti Rev. Rotation Device Lube Pump 2 P-406 m

2BN42 2BLP1305 Welding Recpt. Cont. (50KVA) 2R005A, 2R005b, 2R005C N

2BN43 2BLP1217 CEA Change Mechanism Transfer Machine Control Console (8 KVA) L-023 2BN44 2BLP1306 Welding Recpt. Cont. (50 KVA) 2R007A, 2R0078, 2R007C 2BN45 2BLP1218 Refueling Pool End Junction Box (8KVA) L-371 2BN46 2BLP1308 Welding Recpt. Cont. (50KVA) 2R013A, 2R013B, 2R013C 2BN47 2BLP1219 Receptable for Portable Cont. Sump Pump (1hp) P-005.

2BN49 2BLP1319 Equipment Hatch 200R, Electrical Holst Z-028, Z-029 2BN52 2BLP1221 Lower Level Air Circulator A-032 g

2BN53 2BLP1222 Lower Level Air Circulator A-034 9g 2BN56 2BLP1310 Cont. Cooling Unit E-396 Circ. Water Outlet HV-99403B g

2BN57 2BLP1311 Cont. Cooling Unit E-396 Circ. Water Inlet HV-9940BC

-4 2BN58 2BLP1312 Cont. Cooling Unit E-398 Circ. Water Outlet HV-9940CB g

2BN59 2BLP1313 Cont. Cooling Unit E-398 Circ. Water Inlet HV-9940CC 2BN60 2BLP1314 CEON Cooling Unit E-404 CCW Outlet HV-9907BA P

~

TABLE 3.8-1 CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES z

O o

k Primary Device Backup Device Service Description f.

Number Number

-8 2BN61 2BLP1315 CEDM Cooling Unit E-404 CCW Inlet liv-9907BC x

os 2BN62 2BLP1223 Containment Recirculation Unit A-353 (Motor Enclosure Heater)

(2BN62-A)

CEDM Cooling Supply Fan E-404A 2BLP1224 2BN62 (Motor Enclosure Heater)

(2BN62-8)

CEDM Cooling Supply Fan E-404B 2BN62 2BLP1225 (Motor Enclosure Heater)

(2BN62-C)

Containment Normal Cooling Fan A-398 2BN62 2BLP1202 (Motor Enclosure Heater)

(2BN62-H)

Containment Normal Cooling Fan E-396 2BN62 2BLP1228 (Motor Enclosure Heater)

(2BN62-G)

L0108 LO101 Panel 2LP4 Emergency Lighting m

LO118 LO101 Panel 2LP11 Emergency Lighting LO120 LO101 Panel 2LP16 Emergency Lighting g

2B0205 Backup Pressurizer Heater E-607 2 BHP 0201 2 BHP 0202 2B0205 Backup Pressurizer Heater E-608 2 BHP 0203 2B0205 Backup Pressurizer Heater E-609 2 BHP 0204 280205 Backup Pressurizer Heater E-610 2 BHP 0301 2B0206 Backup Pressurizer Heater E-611 2 BHP 0302 2B0206 Backup Pressurizer Heater E-612 2 BHP 0303 2B0206 Backup Pressurizer Heater E-613 E

2 BHP 0304 2B0206 Backup Pressurizer Heater E-614 2

5 2 BHP 0101 280210 Proportional Pressurizer Heater E-601 2B0210 Proportional Pressurizer Heater E-602 5

2 BHP 0102

~ 2B0210 Proportional Pressurizer Heater E-603 "i

2 BHP 0103 2BHPO401 2B0402 Backup' Pressurizer Heater E-615 g

-.. ~. -. - -

d TABLE 3.8-1

~

CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES o

i E

Backup Device k

Primary Device Service Description i

Number a

Number 2B0402 Backup Pressurizer Heater E-G16 z

U 2BHPO402 Backup Pressurizer Heater E-617 2B0402 N

2BHPO403 Backup Pressurizer Heater E-618 2B0402 2 BHP 0404-280805 Backup Pressurizer Heater E-619 2 BHP 0601 Backup Pressurizer Heater E-620 280805 2 BHP 0602 280805 Backup Pressurizer Heater E-621 2 BHP 0603 Backup Pressurizer Heater E-622 i

280805

-2 BHP 0604 Backup Pressurizer Heater E-623 l

280806 2 BHP 0701 Backup Pressurizer Heater E-624 2B0806 2 BHP 0702 Backup Pressurizer Heater.E-625 280806

.2 BHP 0703 280806 Backup Pressurizer Heater E-626 2 BHP 0704 Proportional Pressurizer. Heater E-604 280810

?.

2 BHP 0501-Proportional Pressurizer Heater E-605 280810 g

2 BHP 0502 Proportional Pressurizer Heater E-606 2 BHP 0503 2B0810 2 BHP 0801

,280602 Backup Pressurizer Heater E-627 Backup Pressurizer Heater E-628

'2 BHP 0802 2B0602 2B0602 Backup Pressurizer Heater E-639 2 BHP 0803 Backup Pressurizer Heater E-630 2B0602 2 BHP 0804 Cont. Bldg. Emer. A/C Unit E-399 (Motor Enclos. Htr.)

2BLP1013 28Y40 Cont. Bldg. Emer. A/C Unit E-401 (Motor Enclos. Htr.)

2BLP1014 28Y40 Reactor Coolant Regen. Heat Exch. Isol. Valve TV-9267 2BLP1111 g

28Z32 Containment Bldg. Emergency A/C Unit E-400 2BLP1112 g

2BZ38.

2BLP1126 Containment Bldg. Emergency A/C Unit E-403 g

28Z38 '

Containment Reactor Cavity. Cooling Fan A-319 2Q01704 2Q017

-1 (Main Breaker)

(Motor Enclosure Heater)

.g 2Q017 Containment Reactor Cavity Cooling Fan A-321 2Q01706 (Main Breaker)

(Motor Enclosure Heater) g

.o c-

=, -

TABLE 3.8-1 1

CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES

o k

Primary Device Backup Device y.

Number Number Service Description -

5 Containment Sump Inlet Flow 2FT5799A/B, 2FT5802A/B 2QO1724 2Q017

-8 (Main Breaker)

N 2QO2801 2QO28 RCP P-001 (Motor Enclosure Heater)

(Main Breaker) 2QO2802 2QO28 RCP P-004 (Motor Enclosure Heater)

(Main Breaker) 2QO2803 2QO28 RCP P-002 (Motor Enclosure Heater)

(Main Breaker) 2QO2804 2QO28 Containment Reactor Cavity Cooling Fan A-320 1

(Main Breaker)

.(Motor Enclosure Heater)

- g 2QO2805 2QO28 RCP P-003 (Motor Enclosure Heater)

(Main Breaker) 2QO2808 2QO28 Containment Reactor Cavity Cooling Fan m

(Main Breaker)

(Motor Enclosure Heater) m* -

2003904 2QO39 Dome Circulating Fan A-071 (letor Enclosure lleater) 3 (Main Breaker)

?QO3906 2QO39 Dome Circulating Fan A-074 (Motor Enclosure Heater)

(Main Breaker) 2Q04104 2Q041 Standby.uonne Circulatisig iasi A 012 (Main Breaker)

(Mutor Oclosure'lleater) 2Q04106 2Q041 Standby Dome Circulating fan A-073 (Main Breaker)

E m

205P108 20503 Panel'2LP4 Emergency Lighting

- y 205P109 2D503 Panel 2LP11 Emergency Lighting 205P118 20503 Panel 2LP16 Emergency Lighting

.l m*

4

-2 2A0101 2A0102 Reactor Coolant Pump P-001 2A0104 Reactor Coolant Pump P-001 2A0105-Resetor Coolant Pump P-001 g.

t

~

1

/

TABLE 3.8-1 2-CONTAINMENT PENETRATION CONOUCTOR OVERCURRENT PROTECTIVE DEVICES C E

fit E'

Primary Device Backup Device Number Number Service Description

.h 2A0103 2A0102 Reactor Coolant Pump P-004 2A0104 Reactor Coolant Pump P-004 2A0105 Reactor Coolant Pump P-004

'2A0201 2A0202 Reactor Coolant Pump P-002 2A0204 Reactor Coolant Pump P-002 4

l 2A0205 Reactor Coolant Pump P-002 q

~

2A0203 2A0202 Reactor Coolant Pump P-003 2A0204 Reactor Coolant Pump P-003 2A0205 Reactor Coolant Pump P-003 CEA04 CB3001 CEA4 T

CEA05 CB3001 CEAS CEA06 C03001 CEA6 CEA07 CB3001 CEA7 CEA08 CB3002 CEA8 CEA09 C83002 CEA9 CEA10 CB3002 CEA10 CEA11 CB3002 CEA11 CEA12 CB3003 CEA12

'CEA14 CB3003 CEA14 CEA16 CB3003 CCA16 g

CEA18 CB3003 CEA16 E

CEA13 g

CEA13 CB3004 g

CEA15 CB3004 CEA15 CEA17 CB3004 CEA17 g

CEA19 CB3004 CEA19 e

?

3/4.10 SPECIAL TEST EXCEPTIONS 3/4.10.1 SHUTDOWN MARGIN a

'~

LIMITING CONDITION FOR OPERATION 3.10.1 The SHUTDOWN MARGIN requirement of Specification 3.1.1.1 may be suspended for measurement of CEA worth and shutdown margin provided reactivity I

equivalent to at least the highest estimated CEA worth is available for trip insertion from OPERABLE CEA(s).

APPLICABILITY:

MODES 2 and 3*

ACTION:

With any full length CEA not fully inserted and with less than the a.

above reactivity equivalent available for trip insertion, immedi-ately initiate and continue boration at greater than or equ51 to 40 gpm of a solution containing greater than or equal to 1720 ppm boron or its equivalent until the SHUTDOWN MARGIN required by Specification 3.1.1.1 is restored.

s b.

With all full length CEAs fully inserted and the reactor subcritical by less than the above reactivity equivalent, immediately initiate and continue boration at greater than or equal to 40 gpm of a solution containing greater than or equal to 1720 ppm boron or its equivalent until the SHUT 00WN MARGIN required by Specification 3.1.1.1 is restored.

SURVEILLANCE REQUIREMENTS 4.10.1.1 The position of each full length and part length CEA required either partially or fully withdrawn shall be determined at -least once per 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

4.10.1.2 Each CEA not fully inserted shall be demonstrated capable of full insertion when tripped from at least the 50% withdrawn position within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months prior to reducing the SHUTDOWN MARGIN to less than the limits of Specification 3.1.1.1.

f.

/

0peration in MODE 3 shall be limited to 6 consecutive hours.

9 l

SAN ONOFRE-UNIT 2 3/4 10-1 AMEN 0 MENT NO.16

SPECIAL TEST EXCEPTIONS 3/4.10.2 GROUP HEIGHT, INSERTION AND DOWER DISTRIBUTION LIMITS LIMITING CONDITION FOR OPERATION-3.10.2 The group height, insertion and power distribution limits of 3.1.1.3, 3.1.3.1, 3_.1.3.5, 3.1.3.6, 3.2.2, 3.2.3, 3.2.7 and Specifications the Minimum Channels OPERABLE requirement of Functional Unit 15 of Table 3.3-1 may be suspended during the performance of PHYSICS TESTS provided:

The THERMAL POWER is restricted to the test power plateau which a.

shall not exceed 85% of RATED THERMAL POWER, and b.

The limits of Specification 3.2.1 are maintained and determined as specified in Specification 4.10.2.2 below.

APPLICABILITY:

MODES 1 a'nd 2.

ACTION:

With any of the limits of Specification 3.2.1 being exceeded while the requirements of Specifications 3.1.1.3, 3.1.3.1, 3.1.3.5, 3.1.3.6, 3.2.2, 3.2.3, 3.2.7 and the Minimum Channels OPERABLE requirement of Functional Unit 15 of Table 3.3-1 are suspended, either:

Reduce THERMAL POWER sufficiently to satisfy the requirements of a.

Specification 3.2.1, or b.

Be in HOT STANDBY wthin 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

SURVEILLANCE REQUIREMENTS L,I 4.10.2.1 The THERMAL POWER shall be determined at'least once per hour during PHYSICS TESTS in which the requirements of Specifications 3.1.1.3, 3.1.3.1, 3.1.3.5, 3.l.3.6, 3.2.2, 3.2.3, 3.2.7 or the Minimum Channels OPERABLE requirement of Functional Unit 15 of Table 3.3-1 are suspended and shall be verified to be within the test power plateau.

4.1O.2.2 The linear heat. rate shall be determined to be within the limits of Specification 3.2.1 by monitoring it continu'ously with the Incore Detector Monitoring System pursuant to the requirements of Specifications 4.2.1.3 and 3.3.3.2 during PHYSICS TESTS.above 5% of RATED THERMAL POWER in which the requirements of Specifications 3.1.1.3, 3.1.3.1, 3.1.3.5, 3.1.3.6, 3.2.2, 3.2.3, 3.2.7 or the Minimum Channels OPERABLE requirement of Functional Unit 15 of Table 3.3-1 are suspended.

SAN ONOFRE-UNIT 2 3/4 10-2 AMEN 0 MENT NO. 16

RADI0 ACTIVE EFFLUENTS e

LIQUID HOLDUP TANKS LIMITING CONDITION FOR OPERATION 3.11.1.4 The quantity of radioactive material contained in each outside temporary tank shall be limited to less than or equal to 10 curies, excluding tritium and dissolved or entrained noble gases.

APPLICABILITY:

At all times.

i ACTION:

a.

With the quantity of radioactive material in any outside temporary tank exceeding the above limit, immediately suspend all additions of radioactive material to the tank and within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months reduce the tank contents to within the limit.

b.

The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS 4.11.1.4 The quantity of radioactive material contained in each outside temporary tank shall be determined to be within the above limit by analyzing a representative sample of the tank's contents at least once per 7 days'when radioactive materials are being added to the tank.

l l

l SAN ONOFRE-UNIT 2 3/4 11-7 AMENDMENT NO. 16

e RADIOACTIVE EFFLUENTS 3/4.11.2 GASE0US EFFLUENTS DOSE RATE LIMITING CONDITION FOR OPERATION The dose rate in unrestricted areas due to radioactive materials 3.11.2.1 released in gaseous effluents from the site (see Figure 5.1-3) shall be limited to the following:

Less than or equal to 500 mrem /yr to the total a.

For noble gases:

body.and less than or equal to 3000 mrem /yr to the skin, and-b.

For all radioiodines, tritium and for all radioactive materials in particulate form with half lives greater. than 8 days:

Less than or equal to 1500 mrem /yr to any organ.

APPLICABILITY:

At all times.

ACTION:

With the dose rate (s) exceeding the above limits, immediately decrease the release rate to within the above limit (s).

SURVEILLANCE REQUIREMENTS 4.11.2.1.1 The dose rate due to noble gases in gaseous effluents shall be determined to be within the above limits in accordance with the methods and procedures of the ODCM.

4.11.2.1.2 The dose rate due to radioiodines, tritium and radioactive materials in particulate. form with half lives greater than 8 days in gaseous effluents shall be determined to be within the above limits in accordance with the methods and procedures of the ODCM by obtaini'ng representative samples and performing analyses in accordance'with the' sampling and analysis-program gg;773specified in Table 4.11-2.

l

)

f 9

t e

i SAN ONOFRE-UNIT 2 3/4 11-8 i

TABLE 4.11-2 RADI0 ACTIVE GASEOUS WASTE SAMPLING AND ANALYSIS PROGRAM E

Lower Limit of

~z Minitaum g

Sampling Analysis Type of Detection (gLD) o g

Gaseous Release Type Frequency Frequency Activity Analysis (pCi/ml)

P P

9 lx10 4 Tg A.

Waste Gas Storage Each Tank Each Tank Principal Gamma Emitters

.p Tank Grab l

Sample 9

1x1'0 4 y

B.

Containment Purge P

P Principal Gamma Emitters D

D 42 inch Each Purge

Each Purge g

ga b

b 9

1x10 4 8 inch M

g Principal Gamma Emmitters Grab Sample

,,_3 1x10

b b

9 C.

1. Condenser M

g Principal Gamma Emitters 1x10 4 m

Evacuation Grab

_g System Sample g

1x10 8 H-

2. Plant Vent D

D Stack W

W D.

All Release Types Continuous W

I-131 1x102 I

d as listed in.B and Sampler Charcoal C above.

Sample I-133 lx10 20 I

d 9

lx10 11 f

Continuous W

Principal Gamma Emitters Sampler Particulate (I-131, Others)

Sample Continuous M

Gross Alpha 1x10 11 I

Sampler Composite Particulate g

Sample g

k Continuous Q

Sr-89, Sr-90 lx10 11 I

Sampler Composite z

Particulate 5

Sample Continuous Noble Gas Noble Gases 1x10 8 I

Monitor Monitor Gross Beta or Gamma

e TABLE 4.11-2 (Continued)

TABLE NOTATION The LLD is the smallest concentration of radioactive material in a sample that will be detected with 95% probability with 5% probability of falsely~

concluding that a blank observation represents a "real" signal.

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

4.66 s D=

E V

2.22 x 106 Y

exp (-Aat)

Where:

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

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

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

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

is the. number of transformations per minute per microcurie, 2.22 x 108 Y is the fractional radiochemical yield (when applicable),

A is the radioactive decay constant for the particular radionuclide, and at is the elpsed time between midpoint of sample collection and time of counting (for plant effluents, not environmental samples).

The value of s used in the calculation of the LLD for a particular h

measurement sy5 tem shall be based on the actual observed variance of the background counting rate or of the count,ing rate of the blank.

samples (as appropriate) rather than on an unverified theoretically

% predicted variance.

incalculatingtheLLDforaradionuclidedeterminebygammarayspectrometry, the background should include the typical co.ntributions of other radio-nuclides normally present in the samples.

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

It should be recognized that the LLD is defined as an a' priori (before the fact) limit representing the capability of the m'easurement system and notasaposteriori(afterthefact)limitforaparticularmeasurement.j

For a more complete discussion of the LLD, and other detection limits, see the following:

(1) HASL Procedures Manual, HASL-300 (revised annually).

(2) Currie, L.

A., " Limits for Qualitative Detection and Quantitative Determination - Application to Radiochemistry" Anal. Chem. 40, 586-93 (1968).

(3) Hartwell, J. K., " Detection Limits for Radioisotopic Counting Techniques,"

Atlantic Richfield Hanford Company Report ARH-2537 (June 22, 1972).

SAN ONOFRE-UNIT 2 3/4 11-10

t RADIOACTIVE EFFLUENTS EXPLOSIVE GAS MIXTURE LIMITING CONDITION FOR OPERATION 3.11.2.5 The concentration of oxygen in the waste gas holdup system shall be limited to less than or equal to 2% by volume whenever the hydrogen concentration exceeds 4% by volume.

APPLICABILITY:

At all times.

ACTION:

a.

With the concentration of oxygen in the waste gas holdup system greater than 2% by volume but less than or equal to 4% by volume, restore the concentration of oxygen to within the limit within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months , b.

With the concentration of oxygen in the waste gas holdup system greater than 4% by volume, immediately suspe'nd all additions of waste gases to the system and reduce the concentration of oxygen to less than 4% by volume within one hour and less than or equal to 2%

by volume within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months .

c.

The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS 4.11.2.5 The concentrations of hydrogen and oxygen in the waste gas holdup system shall be determined to be within the above limits by continuously moni-toring the waste gases in the waste gas holdup system with the hydrogen and oxygen monitors required OPERABLE by Table 3.3-13 of Specification 3.3.3.9.

e SAN ONOFRE-UNIT 2 3/4 11-15 AMENDMENT NO.16 l

RADIOACTIVE EFFLUENTS GAS STORAGE TANKS LIMITING CONDITION FOR OPERATION 3.11.2.6 The quantity of radioactivity contained in each gas storage tank shall be limited to less than or equal to 134,000 curies noble gases (considered as Xe-133).

APPLICABILITY:

At all times.

ACTION:

With the quantity of radioactive material in any gas storage tank a.

exceeding the above limit, immediately suspend all additions of radioactive material to the tank and within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months reduce the tank contents to within the limit, b.

The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS

' 4.11.2.6 The quantity of radioactive material contained in each gas storage tank shall be determined to be within the above limit at least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months when radioactive materials are being added to the tank.

e e

9 f*

\\

e SAN ONOFRE-UNIT 2 3/4 11-16

- 1

e Li RADIOLOGICAL ENVIRONMENTAL MONITORING 3/4.12.2 LAND USE CENSUS LIMITING CONDITION FOR OPERATION 3.12.2 A land use census shall be conducted and shall identify the location of the nearest milk animal, the nearest residence and the nearest garden

of greater than 500 square feet producing fresh leafy vegetables in each of the 16 meteorological sectors within a distance of five miles.

For elevated releases as defined in Regulatory Guide 1.111, Revision 1, July 1977, the land use census shall also identify the locations of all milk animals and all gardens of greater than 500 square feet producing fresh leafy vegetables in i

each of the 16 meteorological sectors within a distance of three miles.

APPLICABILITY:

At all times.

ACTION:

a.

With a land use census identifying a location (s) which yields a calculated dose or dose commitment greater than the values currently being calculated in Specification 4.11.2.3, in lieu of any other report required by Specification 6.9.1., prepare and submit to the Commission within 30 days, pursuant to Specification 6.9.2, a Special Report which identifies the new location (s).

b.

With a land use census identifying a location (s) which yields a calculated dose or dose commitment via the same exposure pathway 20 percent greater than at a location from which samples are currently being obtained in accordance with Specification 3.12.1, in lieu of any other report required by Specification 6.9.1, prepare and submit to the Commission within 30 days,. pursuant to Specifica-tion 6.9.2, a Special Report which identifies the new location. The new location shall be added to the radiological environmental monitoring program within 30 days.

The sampling location, excluding the control station location, having the lowest calculated dose or dose commitment via the same exposure pathway may be deleted from this monitoring program after October 31 of the year in which this land use census was conducted.

The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

c.

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

A Broad leaf vegetation sampling may be performed at the site boundary in the direction sector with the highest D/Q in lieu of the garden census.

I SAN ONOFRE-UNIT 2 3/4 12-11 AMENDMENT NO.16 l

~~

.o l

RADIOLOGICAL ENVIRONMENTAL MONITORING l

3/4.12.3 INTERLABORATORY COMPARISON PROGRAM LIMITING CONDITION FOR OPERATION 3.12.3 Analyses shall be performed on radioactive materials supplied as part i

of an Interlaboratory Comparison Program which has been approved by the Commission.

1 APPLICABILITY:

At all times.

ACTION:

With analyses not being performed as required above, report the i,

a.

corrective actions taken to prevent a recurrence to the Commission in the Annual Radiological Environmental Operating Report.

b.

The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS 4.12.3 A summary of the results obtained as part of the above required Interlaboratory Comparison Program and in accordance with the ODCM shall be included in the Annual Radiological Environmental Operating Report.

j SAN ONOFRE-UNIT 2 3/4 12-12 AMENDMENT N0.16

w REACTIVITY CONTROL SYSTEMS BASES BORATION SYSTEMS (Continued)

The water volume limits are specified relative to the top of the highest suction connection to the tank.

(Water volume below this datum is not 3

considered recoverable for purposes of this specification.) Vortexing, I

internal structures and instrument error are considered in determining the l

tank level corresponding to the specified water volume limits.

I The OPERABILITY of one boron injection system during REFUELING ensures that this system is available for reactivity control while in MODE 6.

The limits on water volume and boron concentration of the RWST also ensure a pH value of between 8.0 and 10.0 for the solution recirculated within contain-ment after a LOCA.

This pH band minimizes the evolution of iodine and minimizes the effect of chloride and caustic stress corrosion on mechanical systems and components.

The maximum RWST volume is not specified since analysis of pH limits and containment flooding post-LOCA considered RWST overflow conditions.

3/4.1.3 MOVABLE CONTROL ASSEMBLIES The specifications of this section ensure that (1) acceptable power-distribution limits are maintained, (2) the minimum SHUTOOWN MARGIN is main-tained, and (3) the potential effects of CEA misalignments are limited to acceptable levels.

The ACTION statements which permit limited variations from the basic requirements are accompanied by additional restrictions which ensure that the original design criteria are met.

The ACTION statements applicable to a stuck or untrippable, CEA to two or more inoperable CEAs and to a large misalignment (greater than or equal to 19 inches) of two or more CEAs, require a prompt shutdown of the reactor since l

either of these conditions may be indicative of a possible loss of mechanical functional capability of the CEAs and in the event of a stuck or untrippable CEA, the loss of SHUTD0kN MARGIN.

For small misalignments (less than 19 inches) of the CEAs, there is 1) a small e#ffect on the time dependent long term power distributions relative to those used in generating LCOs and LSSS setpoints, 2) a small effect on the available SHUTDOWN MARGIN, and 3) a small effect on the ejected CEA worth used in the safety analysis.

Therefore, the ACTION statement associated with small misalignments of CEAs permits a one hour time interval during which attempts may be made to restore the CEA to within its alignment requirements.

The one hour time limit is sufficient'to (1)_ identify causes of a misaligned CEA, (2) take appropriate corrective action to realign-the CEAs and (3). minimize the effects of xenon redistribution.

SAN ONOFRE-UNIT 2 B 3/4 1-3 AMEN 0 MENT N0. 16 w

REACTIVITY CONTROL SYSTEMS BASES MOVABLE CONTROL ASSEMBLIES (Continued)

The CPCs provide protection to the core in the event of a large misalignment (greater than or equal to 19 inches) of a CE d

However, this misalignment would cause distortion of the core p CEA.

1) the available SHUTDOWN, MARGIN, 2) the time dependen distribution.

Therefore, the and 3) the ejected CEA worth used in the safety analysis. ACTIO prompt realignment of the misaligned CEA.

The ACTION statements applicable to misalign'ed or inoperable CEAs include requirements to align the OPERABLE CEAs in a given gro short period of time, to a configuration consistent with that assumed inHow CEA.

generating LCO and LSSS setpoints.significantly inserted in the core may l burnup, 2) peaking factors and 3) available shutdown margin which are more adverse than the conditions assumed to exist in the safety analyses _a and LSSS setpo'ints determinatton.

operation with inoperable CEAs to preclude such adverse conditions from developing.

Operabil.ity of at least two CEA position indicator channels is required to determine CEA positions and thereby ensure compliance with the CEA The CEA " Full In" and " Full Out" limits alignment and insertion limits.

provide an additional independent means for petermining the CEA positions the CEAs are at either their fully inserted or fully withdrawn positions.

Therefore, the ACTION statements applicable to inoperable CEA position

~

indicators permit continued operations when the position limits.

CEA positions and OPERABILITY of the CEA position indicators are require to be verified on a nominal basis of once per 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months sJwith more frequent verifications required if an automatic monitoring channe'l LCO's are satisfied.

The maximum CEA drop time restriction is consistent with the assumed CEA Measurement with T,yg greater than or drop time used in the safety analyses.

equal to 520*F and with all reactor coolant pumps ' operating ensures that't d

measured drop times will be representative of insertion times experience during a reactor trip at operating conditiuns.

B 3/4 1-4 SAN ONOFRE-UNIT 2

3/4.4 REACTOR COOLANT SYSTEM BASES 3/4.4.1 REACTOR COOLANT LOOPS AND COOLANT CIRCULATION The plant is designed to operate with both reactor coolant loops and associated reactor coolant pumps in operation, and maintain DNBR greater than 1.20 during all' normal operations and anticipated transients.

As a result, in MODES 1 and 2 with one reactor coolant loop not in operation, this speci-fication requires that the plant be in at least HOT STANDBY within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months since no safety analysis has been conducted for operation with less than 4 reactor coolant pumps or less than two reactor coolant loops in operation.

In MODE 3, a single reactor coolant loop provides sufficient heat removal capability for removing decay heat; however, single failure considerations require that two loops be OPERABLE.

In MODE 4, and in MODE 5 with reactor coolant loops filled, a single reactor coolant loop or shutdown cooling train provides sufficient heat removal capability for removing decay heat; but single failure considerations require that at least two loops / trains (either RCS or shutdown cooling) be OPERABLE.

In MODE 5 with reactor coolant loops not filled, a single shutdown cool-ing train provides sufficient heat removal capability for removing decay heat; but single failure considerations, and the unavailability of the stean genera-tors as a heat removing component, require that at least two shutdown cooling trains be OPERABLE.

The operation of one Reactor Coolant Pump or-one shutdown cooling pump provides adequate flow to ensure mixing, prevent stratification and produce gradual reactivity changes during boron concentration reductions in the Reac-tor Coolant System.

The reactivity change rate associated with boron reduc-tions will, therefore, be within the capability of operator recognition and control.

The restrictions on starting a Reactor Coolant Pump in Modes 4 and 5 with one or more RCS cold legs less than or equal to 235*F are provided to prevent RCS pressure transients, caused by energy additions from the secondary system, which could exceed the limits of Appendix G to 10 CFR Part 50.

The RCS will be protected against overpressure transients and will not exceed the limits of Appendix G by either (1) restricting the water volume in the pressurizer and thereby providing a volume for the primary coolant to expand into or (2) by l

restricting starting of the RCPs to when the secondary water temperature of each steam generator is less than 100*F above each of the RCS cold leg temper-atures.

3/4.4.2 SAFETY VALVES The pressurizer code safety valves operate to prevent the RCS from being pressurized above its Safety Limit of 2750 psia.

Each safety valve is designed to relieve 4.6 x 10S lbs per hour of saturated steam at the talve setpoint plus 3% accumulation.

The relief capacity of a single safety valve is adequate to relieve any overpressure condition which could occur during shutdown with RCS cold leg temperature greater than 235*F.

In the event that no safety valves are OPERABLE and for RCS cold leg temperature less than or equal to 235*F, the operating shutdown cooling relief valve, connected to the RCS, provides over-pressure relief. capability and will prevent RCS overpressurization.

SAN ONOFRE-UNIT 2 B 3/4 4-1 AMENDMENT N0.16

REACTOR COOLANT SYiTEM BASES i

SAFETY VALVES (Continued)

During operation, all pressurizer code safety valves must be OPERABLE to prevent the RCS from being pressurized above its safety limit of 2750 psia.

The combined relief capacity of these valves is sufficient to limit the System pressure to within its Safety Limit of 2750 psia following a complete loss of turbine generator load while operating at RATED THERMAL POWER and assuming no reactor trip until the first Reactor Protective System trip setpoint (Pres-surizer Pressure-High) is reached (i.e., no credit is taken for a direct reactor trip on the loss of turbine) and also assuming no operation of the steam dump valves.

Demonstration of the safety valves' lift setti,ngs will occur only during shutdown and will be performed in accordance with the provisions of Section XI of the ASME Boiler and Pressure Vessel Code.

3/4.4.3 PRESSURIZER The limit on the maximum water volume in the pressurizer assures that the parameter is maintained within the normal steady-state envelope of operation assumed in the SAR.

A steam bubble in the pressurizer ensures that the RCS is not a hydraulically solid system and is capable of accommodating pressure surges during operation.

The steam bubble,also protects the pressurizer code safety valves against water relief.

The requirement that a minimum number of pressurizer heaters be OPERABLE enhances the capability of the plant to control Reactor Coolant System pressure and establish natural circulation.

3/4.4.4 STEAM GENERATORS The Surveillance Requirements for inspect' ion of the steam generator tubes

~

ensure that the structural integrity of this portion of the RCS will be main-tained.

The program for inservice inspection of steam generator tubes is based on a modification of Regulatory Guide 1.63, Revision 1.

Inservice inspection of steam generator tubing is essential in order to maintain surveillance of the conditions of the tubes in' the event that there is evidence of rechanical damage or progressive de' gradation due to design, manufacturing errors, or inservice conditions that lead.to corrosion.

e O

SAN ONOFRE-UNIT 2 B 3/4 4-2

l 4

1 P

l I

REACTOR COOLANT SYSTEM j

BASES i

A l

PRESSURE / TEMPERATURE LIMITS (Continued)

The heatup and cooldown limit curves (Figures 3.4-2 and 3.4-3) are composite curves which were prepared by determining the most conservative case, with i.

l either the inside or outside wall controlling, for any heatup rate of up to.

60*F/hr or cooldown rate of up to 100*F/hr.

The heatup and cooldown curves 4

l were prepared based upon the most limiting value of the predicted adjusted reference temperature at the end of the service period indicated on Figure 3.4-2 and,3.4-3.

The reactor vessel materials have been tested to determine their initial

]

the results of these test are shown in Table B 3/4.4-1.

Reactor opera-RTtiggT;ndresultantfastneutron(Egreaterthan1Mev)irradiationwillcause-a

-Therefore, an adjusted reference temperature, based an increase in the RT l

uponthefluenceand50hp,erandphosphorouscontentofthematerialinque_stion, i

can be predicted using FSAR Table 5.2-5 and the recommendations of Regulatory i

Guide 1.99, Revision 1, " Effects of Residual Elements on Predicted Radiation The heatup and cooldown limit curves, Damage to Reactor Vessel Materials."

l Figures 3.4-2 and 3.4-3, include predicted adjustments for this shift in RT NOT i

]

at the end of the applicable service period, as well as adjustments for possible errors in the pressure and temperature sensing instruments.

The actual shift in RT of lished periodically during operatiBRT,y,the vessel material will be estab,,,,,

,cc,,,,,c,,,,,

l i

ASTM E185-73 and 10 CFR Appendix H, reactor vessel material irradiation sur-j veillance specimens installed near the inside wall of-the reactor vessel in l

The surveillance specimen withdrawal schedule is shown in i

the core area.

4 Table 4.4-5.

Since the neutron spectra at the irradiation samples and vessel inside radius are essentially identical, the measured transition shift for a sample can be applied with confidence to the adjacent section of the reactor-j vessel taking into account the location of the sample closer to -the core than

)

the vessel wall by means of the Lead Factor.

The heatup and cooldown curves j

must be recalculated when the delta RT determined from the surveillance i

j capsuleisdifferentfromthecalculatNSdeltaRT f r the equivalent capsule

~

NOT j

radiation exposure.

j The pressure-temperature limit lines shown on Figure 3.4-2 and 3.4-3 for reactor criticality and for inservice leak and hydrostatic testing have.been i

provided to assure compliance with the minimum temperatdre requirements of l

Appendix G to 10 CFR 50.

I l

The maximum RT for aH reactor _ coolant system pressure-retaining materials, with the SIception of the reactor pressure vessel, has been deter-N l'

mined to be.90*F.

The Lowest Service Temperature limit line shown on.

since Article NS-2332 (Summer Figure 3.4-2and3.4-3isbaseduponthisRTlSIlerandPressureVesselCode.

Addenda of 1972) of Section III of the ASME

~

requires the Lowest Service Temperature to be RT 100*F for piping,' pumps andvalves.Belowthistemperature,thesystempYhIs+uremustbelimitedtoa maximum of 20% of the system's hydrostatic test pressure of 3125 psia.

j The limitations imposed on the pressurizer heatup and cooldown rates and s

spray water temperature differential are provided to assure that the pres-surizer is operated within the design criteria assumed for the fatigue analysis.

performed in accordance_with the'ASME Code-requirements.

4 SAN ONOFRE-UNIT 2 B 3/4 4-7 AMENDMENT.NO. 16

TABLE 8 3/4.4-1 REACTOR VESSEL TOUGHNESS E-Temperature of Minimum Upper Drop Charpy V-Notch Shelf CV energy 5$

Weight

@ 30 9 50 for Longitudinal-g Piece.No.

Code No.

Material Vessel Location Results ft - lb - f t - Ib Direction-ft Ib Z

215-01 C-6403-1 A533GRBCL-1 Upper Shell Plate 40 15 35 130 215-01 C-6403-2 0

20 25 133

-10 20 45 131 m

215-01 C-6403-3 215-03 C-6404-1 Intermediate Shell Plate

-30 10 50 145 215-03 C-6404-2

-20 20 50 155

-20 10 50 131 4-215-03 C-6404-3 215-02 C-6404-4 Lower Shell Plate

-10

-5 25 124 215-02 C-6404-5

-20 10 25 134 215-02 C-6404-6

-10

-20 0

151 238-02 C-6401 A508C1-2 Vessel Flange Fo'rging

-10

-70

-35 148 om l

R 209-02 C-6402 Closure Head Flange.

-10

-90

-40 142 Forging h

205-02 C-6410-1 Inlet Nozzle Forging 20

-40

-35 130 0

-20

-5 135 205-02 C-6410-2 0

-15

-15 140 205-02 C-6410-3 205-02 C-6410-4 0

-65

-50 140 l

205-06 C-6411-1 Outlet Nozzle Forging

-100

-30

-10 140 205-06 C6411-2 0

-35

-10 140 232-01 C-6424.

A533GRBCL-1 Botton Head Torus

-50

-20 10 122 I i

232-02 C-6425 Bottom Head Dome

-50

-30

-20 136

~

205-03 C-6428-1 A508CL-1 Inlet Nozzle Forging S/E -70

-50 174 205-03 C-6428-2

-30

-70

-50 174 205-03 C-6428-3

-30

-70

-50 174

-30

-70

-50 174 205-03 C-6428-4 i

205-07 C-6429-1 Outlet Nozzle Ext.

-30

-40

-25 229 Forging 205-07 C-6429-1

-30

-40

-25 229

.0 55 118 2

231-02 C-6430-1 A533GRBCL-1 Closure Head-Peels

+10 231-02 C-6431-1

-20 10 50

'100 231-02 C-6432-1

-10

-15 45 115 231-02 C-6432 Closure Head Dome

-10

-15 45 115 e

a e

O

. r l

REACTOR COOLANT SYSTEM BASES i

PRESSURE / TEMPERATURE LIMITS (Continued)

The OPERABILITY of the Shutdown Cooling System relief valve or a RCS vent l

opening of greater than 5.6 square inches ensures that the RCS will be protected from pressure transients which could exceed the limits of Appendix G l

to 10 CFR Part 50 when one or more of the RCS cold legs are less than or equal to 235'F. The Shutdown Cooling System relief valve has adequate relieving l

capability to protect the RCS from overpressurization when the transient is limited to either (1) the start of an idle RCP with the secondary water l

temperature of the steam generator less than or equal to 100*F above the RCS cold leg temperatures or (2) inadvertant safety injection actuation with two HPSI pumps injecting into a water-sclid RCS with full charging capacity and letdown isolated.

3/4.4.9 STRUCTURAL INTEGRITY i

The inservice inspection and testing programs for ASME Code Class 1, r

f 2 and 3 components ensure that the structural integrity and operational readiness of these components will be maintained at an acceptable level throughout the life of the plant. These programs are in accordance with-i Section XI of the ASME Boiler and Pressure Vessel Code and applicable Addenda as required by 10 CFR Part 50.55a(g) except where specific written relief has been granted by the Commission pursuant to 10 CFR Part 50.55a (g) (6) (1).

l Components of the reactor coolant system were designed to provide access-l to permit inservice inspections in accordance with Section XI of the ASME i

Boiler and Pressure Vessel Code, 1974 Edition and Addenda through Summer 1975.

l O

w SAN ONOFRE-UNIT 2 8 3/4 4-9 AMENDMENT NO.16 y

r--

m%

6 EMERGENCY CORE COOLING SYSTEMS BASES REFUELING WATER STORAGE TANK (Continued)

The water volume limits are specified relative to the top of the highest suction connection to the tank.

(Water volume below this datum is not considered recoverable for purposes of this specification).

The specified volume limits consist of the minimum volume required for ECCS injection above the Recirculatiun Actuation Signal (RAS) setpoint, plus the mimumum volume required for the transition to ECCS recirculation below the RAS setpoint, plus the volume corresponding to the range of the RAS setpoint, including RAS instrument error high and low. Vortexing, internal structure, and instrument error are considered in determining'the tank level corresponding to the specified water volyme limits.

The limits on water volume and boron concentration of the RWST also ensure that the solution recirculated within containment after a LOCA has a pH value between 8.0 and 10.0 at the end of the NaOH injection period.

This pH band minimizes the evolution of iodine and minimizes the effect of chloride and caustic stress corrosion on mechanical systems and components.

The maximum RWST volume is not specified since analysis of pH limits and containment flooding post-LOCA considered RWST overflow conditions.

l SAN ONOFRE-UNIT 2 B 3/4 5-3 AMENDMENT NO.16

3/4.6 CONTAINMENT SYSTEMS BASES 3/4.6.1 PRIMARY CONTAINMENT 3/4.6.1.1 CONTAINMENT INTEGRITY Primary CONTAINMENT INTEGRITY ensures that the release of radioactive materials from the containment atmosphere will be restricted to those leakage paths and associated leak rates assumed in the accident analyses.

This restriction, in conjunction with the leakage rate limitation, will limit the site boundary radiation doses to within the limits of 10 CFR 100 during accident conditions.

3/4.6.1.2 CONTAINMENT LEAKAGE The limitations on containment leakage rates ensure that the total containment leakage volume will not exceed the value assumed in the accident analyses at the peak accident pressure, P.

Asanaddedconservatism,the measuredoverallintegratedleakagerateisfurtherlimitedtolessthanor equal to 0.75 L or less than or equal to 0.75 L, as applicable during t

performance of fhe periodic tests to account for possible degradation of the containment leakage barriers bqtween leakage tests.-

The surveillance testing for measurin'g leakage rates are consistent with the requirements of Appendix J of 10 CFR 50.

3/4.6.1.3 CONTAINMENT AIR LOCKS The limitations on closure and leak rate'for,the containment air locks are required to meet the restrictions on CONTAINMENT INTEGRITY and containment leak rate.

Surveillance testing of the air lock seals provides assurance that the overall air lock leakage will not become excessive due to seal damage during the intervals between air lock leakage tests.

O SAN ONOFRE-UNIT 2 B 3/4 6-1

~

j 4

l CONTAINMENT SYSTEMS i

i BASES i

i l

l 3/4.6.1.4 INTERNAL PRESSURE The limitations on containment internal pressure ensure that 1) the con-tainment structure is prevented from exceeding its design negative pressure i

l differential with respect to the outside atmosphere of 5.0 psig, 2) the con-tainment peak pressure does not exceed the design pressure of 60 psig during LOCA cr steam line break conditions, and 3) the assumptions used for the l

initial conditions of the LOCA safety analysis remain valid.

The maximum peak pressure expected to be obtained from a LOCA or steam line break event is 55.7 psig. The limit of 1.5 psig for initial positive containment pressure will limit the total pressure to 57.2 psig which is less j

than the design pressure and is consistent with the accident analyses.

i 3/4.6.1.5 AIR TEMPERATURE The limitation on containment average air temperature ensures that the l

overall containment average air temperature does not exceed the initial temperature condition assumed in the accident analysis for a steam line break i

accident.

3/4.6.1.6 CONTAINM$NT STRUCTURAL INTEGRITY This limitation ensures that the structural integrity of the containment will be maintained comparable to the original design standards for the life of Structural integrity is required to ensure that the containment the facility.

will withstand the maximum pressure of 55.7 psig in the event of a steam line The measurement of containment tendon lift off force, the break accident.

tensile tests of the tendon wires or strands, the visual examination of ten-dons, anchorages and exposed interior and exterior surfaces of the contain-ment, the chemical and visual examination of.the sheathing filler grease, and the Type A leakage tests are sufficient to demonstrate this capability.

The surveillance requirements for demonstrating the containment's struc-tural integrity are in compliance with the recommendations of Proposed Revi-l sion 3 to Regulatory Guide 1.35, " Determining Prestressing Forces for Inspec-l tion of Prestressed Concrete Containments," April 1979; and Proposed Regula-

. tory Guide 1.35.1, " Inservice Surveillance of Ungrouted Tendons in Prestressed l

Concrete Containment Structures," April 1979.

AMENDMENT NO.16 8 3/4 6-2 SAN ONOFRE-UNIT 2

4 3/4.7 PLANT SYSTEMS BASES I

3/4.7.1 TURBINE CYCLE 3/4.7.1.1 SAFETY VALVES The OPERABILITY of the main steam line code safety valves <!nsures that the secondary system pressure will be limited to within 110% (1210 psig) of l

its design pressure of 1100 psig during the most severe anticipated system operational transient.

The maximum relieving capacity is associated with a turbine trip from 100% RATED THERMAL POWER coincident with an assumed. loss of condenser heat sink (i.e., no steam bypass to the condenser).

The specified valve lift settings and relieving capacities are in accord-l ante with the requirements of Section III of the ASME Boiler and Pressure Vessel Code, 1974 Edition.

The total relieving capacity for all valves on all of the steam lines is 15,473,628 lbs/hr which is 102.3 percent of the total i

secondary steam flow of 15,130,000 lbs/hr at 100% RATED THERMAL POWER.

A minimum of 1 OPERABLE safety valves per steam. generator ensures that sufficient relieving capacity is available for removing decay heat.

i STARTUP and/or POWER OPERATION is allowable with safety valves inoperable i

within the limitations of the ACTION requirements.on the basis of.the reduc-j'

(

tion in secondary system steam flow and TMERMAL POWER required by the reduced reactor trip settings of the Power Level-High channels.

The reactor trip l

setpoint reductions are derived on the following bases:

For two loop, four pump operation 1

SP = (X) - (Y) W) x 111.3 X

where:

SP = reduced reactor trip setpoint in percent of RATED THERMAL POWER.

V = maximum number of inoperable safety valves per steam line.

111.3 = Power Level-High Trip Setpoint for two-loop operation.

X=Totalrelievingcapacityofallsafetyvalvespersteamlibein l

lbs/ hour (15,473,628 lbs/hr at 1190 psia).

Y = Maximum relieving capacity of any one safety valve in 1bs/ hour.

l (859,646 lbs/hr at 1190 psia).

SAN ONOFRE-UNIT 2 B 3/4 7-1

I j

PLANT SYSTEMS BASES 3/4.7.1.2 AUXILIARY FEEDWATER SYSTEM i

The OPERABILITY of the auxiliary feedwater system ensures that the Reactor Coolant System can be cooled down to less than 350*F from normal operating conditions in the event of a total loss of off-site power.

I i

Each electric driven auxiliary feedwater pump is capable of delivering a total feedwater f~ow of 700 gpm at a pressure of 1170 psig to the entrance of the steam generators.

The steam driven auxiliary feedwater pump is capable of 4

delivering a total feedwater flow of 700 gpm at a pressure of 1170 psig to the 1

l entrance of the steam generators.

This capacity is sufficient to ensure that I

adequate feedwater flow is available to remove decay heat and reduce the Reactor Coolant System temperature to less than 350'F when the shutdown

{

cooling system may be placed into operation.

l 3/4.7.1.3 CONDENSATE STORAGE TANKS The OPERABILITY of the condensate storage tank T-121 with the minimum water volume ensures that sufficient water is available to maintain the RCS at HOT STANDBY conditions for 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months followed by cooldown to shutdown cooling initiation, with steam discharge to atmosphere with. concurrent loss.of offsite power and most limiting single failure.

The OPERABILITY of condensate storage t

tank T-120 in conjunction with tank T-121 ensures that sufficient water is available to maintain the RCS at HOT STANDBY conditions for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months including 4

cooldown to shutdown cooling initiation, with steam discharge to atmosphere with concurrent loss of offsite power and most limiting single failure.

The j

contained water volume limits are specified relative to the highest auxiliary feedwater pump suction inlet in the tank for T-121, and to the T-121 cross connect siphon inlet for T-120.

(Water. volume below these datum levels is not considered recoverable for purposes of this specification.) Vortexing, internal structure, and instrument error are considered in determining the tank j

levels corresponding to the specified water volume ~ limits.

Prior to achieving 100% RATED THERMAL POWER, Figure 3.7-1 is used to 4

i determine the minimum required water volume for T-121 for the maximum power

]

level (hence maximum decay heat) achieved.

I f

4 i

Y SAN ON0FRE-UNIT 2 B 3/4 7-2 AMENDMENT N0. 16'

4 3/4.9 REFUELING OPERATIONS BASES 3/4.9.1 BORON CONCENTRATION The limitations on reactivity conditions during REFUELING ensure i

that:

1) the reactor will remain subcritical during CORE ALTERATIONS, and

2) a uniform boron concentration is maintained for reactivity control in the i

we.ter volume having direct access to the reactor vessel.

These limitations are consistent with the initial conditions assumed for the boron dilution includes j

incident in the accident analyscs.

Thevalueof0.95orlessforK*f(heboron a 1% delta K/K conservative allowance for uncertainties.

Similarly concentration value of 1720 ppm or greater also includes a conservative uncertainty allowance of 50 ppm boron.

3/4.9.2 INSTRUMENTATION

}

l The OPERABILITY of the source range neutron flux monitors ensures that i

redundant monitoring capability is available to detect changes in the reactivity condition of the core.

3/4.9.3 DECAY' TIME The minimum requirement for reactor subcriticality prior to movement of irradiated fuel assemblies in the reactor pressure vessel ensures that 2

sufficient time has elapsed to allow the radioactive decay of the short lived fission products.

This decay time is consistent with the assumptions used in the accident analyses.

i l

3/4.9.4 CONTAINMENT PENETRATIONS J

The requirements on containment penetration closure and OPERABILITY l

ensure that a release of radioactive material within containment will be restricted from leakage to the environment.

The OPERABILITY and closure restrictions are sufficient to restrict radioactive material release from a fuel element rupture based upon the lack of containment pressurization potential while in the REFUELING MODE.

3/4.9.5 COMMUNICATIONS The requirement for communications capability ensures that refueling station personnel can be promptly informed of significant changes in the facility status or core reactivity condition during CORE ALTERATIONS.

9 SAN ONOFRE-UNIT 2 B 3/4 9-1

REFUELING OPERATIONS BASES 3/4.9.6 REFUELING MACHINE The OPERABILITY requirements for the refueling machine ensure that:

(1) the refueling machine will be used for movement of all fuel assemblies including those with a CEA inserted, (2) each machine has sufficient load capacity to lift a fuel assembly including those with a CEA, and (3) the core internals and pressure vessel are protected from excessive lifting force in the event they are inadvertently engaged during lifting operations.

With the exception of the four finger CEA's, CEA's are removed from the reactor vessel along with the fuel bundle in which they are inserted utilizing the refueling machine.

The four finger CEA's are inserted through the upper guide structure with two fingers in each of the two adjacent fuel bundles in the periphery of the core.

The four finger CEA's are either removed with the upper guide structure and lift rig or can be removed with separate tooling prior to upper guide structure removal utilizing the auxiliary hoist of the polar crane.

3/4.9.7 FUEL HANDLING MACHINE - SPENT FUEL STORAGE BUILDING The restriction on movement of loads in excess'of th'e nominal' weight of a fuel assembly, CEA and associated handling tool over other fuel assemblies in the storage pool ensures that in the event this load is dropped (1) the activity release will be limited to that contained in a single fuel assembly and (2) any possible distortion of fuel in the storage racks will not result in a critical array.

This assumption is consistent with the activity release assumed in the accident analyses.

3/4.9.8 SHUTDOWN COOLING AND COOLANT CIRCULATION t

l The requirement that at least one shutdown cooling train be in operation i

ensures that (1) sufficient cooling capacity is aVailable to remove decay heat and maintain the water in the reactor pressure. vessel below 140*F as required during the REFUELING MODE, and (2) sufficient coolant circulation is main-tained through the reactor core to minimize the effects of a boron. dilution j

incident and prevent boron stratification.

l The requirement to have two shutdown cooling trains OPERABLE when there 1s less than 23 feet of water above the reactor pressure vessel flange, ensures l

that a single failure ~of the operating shutdown cooling loop will not result in a complete loss of decay heat removal capability.

With the reactor vessel head removed and 23 feet of water above the reactor pressure vessel flange, a large heat sink is available for core cooling, thus in the event of a failure of the operating shutdown cooling train, adequate time is provided to initiate emergency procedures to cool the core.

F SAN ONOFRE-UNIT 2 B 3/4 9-2 AMENDMENT NO. 16

REFUELING OPERATIONS BASES 3/4.9.9 CONTAINMENT PURGE VALVE ISOLATION SYSTEM The OPERABILITY of this system ensures that the containment purge valves will be automatically isolated upon detection of high radiation levels within the containment.

The OPERABILITY of this system is required to restrict the re-lease of radioactive material from the containment atmosphere to the environment.

3/4.9.10 and 3/4.9.11 WATER LEVEL-REACTOR VESSEL and STORAGE POOL The restrictions on minimum water level ensure that sufficient water depth is available to remove 99% of the assumed 10% iodine gap activity released from the rupture of an irradiated fuel assembly.

The minimum water depth is consistent with the assumptions of the accident analysis.

3/4.9.12 FUEL HANDLING BUILDING POST-ACCIDENT CLEANUP FILTER SYSTEM The limitations on the fuel handling building post-accident cleanup filter system ensure that all radioactive material released from an irradiated fuel assembly will be filtered through the HEPA filters and charcoal adsorber prior to discharge to the atmosphere.

The OPERABILITY of this system and the resulting iodine removal capacity are consistent with the assumptions of the accident analyses.

Cumulative operation U the system with the heaters on for at least 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months over a 31 day period is sufficient to reduce the buildup of moisture on the adsorbers and HEPA filters.

l SAN ON0FRE-UNIT 2 8 3/4 9-3 AMENDMENT NO. 16

3/4.10 SPECIAL TEST EXCEPTIONS BASES 3/4.10.1 SHUT 00WN MARGIN This special test exception provides that a minimum amount of CEA worth is immediately available for reactivity control when CEA worth measurement tests 4

This special test exception is required to permit the periodic are performed.

verification of the actual versus predicted core reactivity condition occurring as a result of fuel burnup or fuel cycling operations.

Although CEA worth testing is conducted in MODE 2, during the performance of these tests sufficient negative reactivity is inserted to result in temporary entry into MODE 3.

Because the intent is to immediately return to MODE 2 to continue CEA worth measurements, the special test exception allows limited operation in MODE 3 without having to borate to meet the SHUTDOWN MARGIN requirements of Technical Specification 3.1.1.1.

3/4.10.2 GROUP HEIGHT, INSERTION, AND POWER DISTRIBUTION LIMITS This special test exception permits individual CEAs to be positioned 4

outside of their normal group heights and insertion limits during the performance of such PHYSICS TESTS as those requi. red to 1) measure CEA worth and 2) determine-the reactor stability index and damping factor under xenon oscillation conditions.

3/4.10.3 REACTOR COOLANT LOOPS i

This special test exception permits reactor criticality under no flow i

conditions and is required to perform certain startup and PHYSICS TESTS while i

at low THERMAL POWER levels.

4 3/4.10.4 CENTER CEA MISALIGNMENT 4

This special test exception permits the center CEA to be misaligned, during PHYSICS TESTS required to determine the isothermal temperature coefficient i

and power coefficient.

3/4.10.5 RADIATION MONITORING / SAMPLING This special test exception permits fuel loading and reactor operation with radiation monitoring / sampling instrumentation calibration and quality j

assurance conforming to either FSAR procedures or Regulatory Guide 4.15 Rev 1, February 1979.

This' test exception is required to allow for a phased implementa-tion of Regulatory Guide 4.15 Rev.1, February 1979.

Equivalent instrumentation, quality assurance and/or calibration is provided until full implementation of Regulatory Guide 4.15 Rev. 1, February 1979.

~

' SAN ONOFRE-UNIT 2 8 3/4 10-1 AMENDMENT NO.

16

3/4.10 SPECIAL TEST EXCEPTIONS BASES' The containment airborne monitors and associated sampling media test exception is required to allow for operation prior to and during installation of upgraded monitors / media. Adequate monitoring is provided until and subsequent to'the completion of the-upgraded installation.

Extensive containment air j

mixing during high volume' purge (MODES 5 and 6) occurs as a result of containment HVAC and fans resulting in representative air monitoring via either 2RT-7804-1 or i

During low volume purge operations (MODES 1, 2, 3 and 4) 2RT-7804 2RT-7807-2.

provides representative indication of purged air due to its location in the immediate vicinity of the low volume purge exhaust.

I E

i l

e l

r i

SAN ONOFRE-UNIT 2 B 3/4 10-2 AMENDMENT NO. 16 i

i

9 ADMINISTRATIVE CONTROLS 6.1 RESPONSIBILITY 6.1.1 The Station Manager shall be responsible for overall unit operation and shall delegate in writing the succession to this responsibility during his absence.

6.1. 2 The Shift Supervisor (or during his absence from the Control Room Area,

{

a designated individual) shall be responsible for the Control Room command function.

A management directive to this effect, signed by the Vice-President of Nuclear Operations shall be reissued to all station personnel on an annual basis.

6.2 ORGANIZATION OFFSITE 6.2.1 The offsite organization for unit management and technical support shall be as shown in Figure 6.2-1.

UNIT STefF 6.2.2 The Unit organization shall be as show'n in Figure 6.2-2 and:

a.

Each on duty shift shall be composed of at least the minimum shift crew composition shown in Table 6,.2-1.

b.

At least one licensed Reactor Operator shall be in the Control Room when fuel is in the reactor.

In addition, while the unit is in MODE 1, 2, 3 or 4, at least one licensed Senior Reactor Operator shall be in the Control Room area identified as such on Table. 6.2-1.

A health physics technician # shall be on site when fuel is in the c.

reactor.

d.

All CORE ALTERATIONS shall be observed and.directly supervised by either a licensed Senior Reactor Operator or Senior Reactor Operator Limited 'to Fuel Handling who has no other concurrent responsibilities during this operation.

A site Fire Bpigade of at least 5 members shall be maintained onsite e.

at all times.

The Fire Brigade shall not include the Shift Super-l visor and the 2 other memb.ers of the minimum 'shif t crew necessary for I

safe shutdown of the unit and any personnel required for other.

essential functions during a fire. emergency.

The health physics technician and Fire Brigade composition may be less than the minimum requirements for a period of time not to exceed 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months in order to accommodate unexpected absence provided immediate action is taken to fil? the required positions.

l SAN ONOFRE-UPIT 2 6-1 Amendment No. 4 l

l l

l

l CHAIRMAN OF THE BOARD I

SENIOR VICE PRESIDENT I

I I

I VICE PRESIDENT VICE PRESIDENT VICE PRESIDENT VICE PRESIDENT VICE PRF.SIDENT VICE PRESIDENT (SYSTEM (ENGINEERING &

(ADVANCED (NUCLEAR ENGINEERING (POWER SUPPLY)

DEVELOPMENT)

CONSTRUCTION)

ENGINEERING)

(FUEL SUPPLY)

AND O*ERATIONS) l MANAGER OF MANAGER OF MANAGER OF MANAGER CF NUCLEAR ENGINEERING, NUCLEAR ENVIRONMENTAL ENGINEERING SAFETY & LICENSING OPERATIONS AFFAIRS DESIGN I

DIRECTOR OF

MANAGER, TRAINING RESEARCH AND QUALITY MANAGER DEVELOPMENT ASSURANCE ANAGE R, NUCLE AR

MANAGER, MANAGER PROJECT MANAGER I

NUCLEAR LICEhSING SAN ONOFRE UNITS 2 & 3 AFET S

SR&D I

NUCLEAR SAFETY HEADQUARTERS GROUP STAFF 1

STATION ON SITE STATION STAFF REVIEW MANAGER COMMITTEE Figure 6.21 j

OFFSITE ORGANIZATION SAN ONOFRE NUCLEAR GENERATING STATION - UNIT 2 1

O l*

I SAN ONOFRE-UNIT 2 6-2 AMENDMENT. NO.16

a 1

STATION MANAGER i

DEPUTY STATION MANAGER 1

I I

I MANAGER.

MANAGER. 4 MANAGER.

MANAGER.

CONFIGURATION STATION MATERIAL AND STATION CONTROL AND EMERGENCY ADMINISTRATIVE SECURITY COMPLIANCE PREPAREONESS SERVICES I

4 I

I I

I MANAGER.

M AN AGE R, M A N AG E R.

M ANAGER.

HEALTH OPE R ATIONS MAINTENANCE TECHNICAL p

PLANT 1

SUPERVISING COMPUTER SUPT.

SONGS 263 ENGINEER Mp-SUPERVISOR I

MAINTENANCE PLANNING SUPERVISING SUPERVISOR ENGINEER 4

RADWASTE f

SUPERVISOR l

SUPERVISING l

SUPERVISOR OF ENGINEER NUCLJAR PLANT NSSS SUPPORT DOSIM ETRY f

MAINTENANCE SONGS 263 SU PE RVISING

]

ENGINEER SHIFT TECH.

2 SUPERVISOR ADVISORS H Pc ENGR S SHIFT OF PLANT GROUP j

SL'PERVISORS COOR DIN ATION SUPERVISOR I

SUPERVISOR OPERATING COORDINATORS FOREMAN SUPERVISOR

~

I OF 3

CHE MISTRY SHIFT 4

PERSONNEL i

1. AT TIME OF APPOINTMTNT TO THE POSITION SENIOR RE ACTOR OPER ATOR LICENSE REQUIRED.

2. SENIOR REACTOR LICENSE REQUIRED.

3. CONTROL AND ASSISTANT CONTROL OPERATORS ARE HOLDERS OF REACTOR OPERATOR LICENSES.

4. INCLUDES FIRE PROTECTION.

i Figure 6.2 2 Unit Organization, San Onofre Nuclear Generting Station. Unit 2-i l

l l

SAN ONOFRE-UNIT 2 6-3 Amendment NO. 4 i

i t

_ _ ~ _

I i

Table 6.2 <

j MINIMUM SHIFT CREW COMPOSITION i

l 1

WITH UNIT 3 IN MODE 5 OR 6 OR DE-FUELED 4

POSITION NUMBER OF INDIVIDUALS REQUIRED TO FILL POSITION MODES 1, 2,'3 &.4 MODES 5 & 6 a

a SS l

y SR0 1

None RO 2

l b

A0 2

2 STA 1

None i

WITH UNIT 3 IN MODE 1, 2, 3 or 4 i

POSITION NUMBER OF INDIVIDUALS REQUIRED TO FILL POSITION

l MODES 1, 2, 3 & 4 MODES 5'& 6 1

8 a

i SS 1

l a

j SRO l

None R0 2

1 b

A0 2

1 a

STA l

None 4

q j

Individual may fill the same position on Unit 3 a

j One of the two required individuals may fill the same positita on Unit 3 Shift Supervisor with a Senior Reactor Operators License on Units'2 SS

{

and 3 Individual with a Senior Reactor Operators License on Units 2 and 3 1

SRO Individual with,a Reactor Operators License on Units 2 and 3 j

RO Auxiliary Operator AO j

Shift Technical Advisor i

STA 4

l Except for the Shift Supervisor, the Shift Crew Composition may be~one less than the minimum requirements of Table 6.2-1 for a period of time not to exceed j

2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months in order to accommodate unexpected absence of on-duty shift crew

{

members provided immediate action is taken to restore the Shift Crew Composi-4 tion to within the minimum requirements ~of Table 6.2-1.

This provision does not permit any shift crew position to be unmanned upon shift change due to an oncoming shift crewman being late or absent.

i l

During any absence of the Shift Supervisor from the Control Room Aree.shown in Figure 6.2-3 while the unit is in MODE 1, 2, 3 or 4, an individual (other than j

the Shift Technical Advisor) with a valid SRO license shall be designated to i

assume the Control Room command function.

During any absence of the Shift i

Supervi4or from the Control Room Area shown in Figure 6.2-3 while the unit is l

in MODE 5 or 6, an individual with a valid SRO or R0 license shall be designated to assume the Control Room command function.

i SAN ONOFRE-UNIT 2 6-4 Amendment No.16 i

..?

+

ADMINISTRATIVE CONTROLS 6.2.3 INDEPENDENT SAFETY ENGINEERING GROUP (ISEG)

FUNCTION l

6.2.3.1 The ISEG shall function to examine plant operating characteristics, NRC issuances, industry advisories, Licensee Event Reports and other sources of plant design and operating experience information which may indicate areas 4

for improving plant safe,ty.

)

I COMPOSITION 6.2.3.2 The ISEG shall be composed of at least five dedicated full-time

)

Each shall have a Bachelor's Degree in Engineering or Physical engineers.

Science or equivalent and at least two years professional level experience in his field.

Off-duty qualified Shift Technical Advisors may be used to fulfill this requirement.

RESPONSIBILITIES 6.2.3.3 The ISEG shall be responsible for maintaining surveillance of plant activities to provide independent verification

that these activities are performed correctly and that human errors are reduced as much as practical.

AUTHORITY 6.2.3.4 The ISEG shall make detailed recommendations for revised procedures, equipment modifications, maintenance activities, operations activities or other means of improving plant safety to the Supervisor, Nuclear Safety Group.

RECORDS 6.2.3.5 Records of activities performed by the ISEG shall be prepared, maintained, and forwarded each calendar month to the NSG Supervisor.

6.2.4 SHIFT TECHNICAL ADVISOR The Shift Technical Advisor shall provide technical support to the Shift Supervisor in the areas of thermal hydraulics, reactor engineering and plant analysis with regard to the safe operation of the unit.

The Shift Technical Advisor shall have a Bachelor's Degree or equivalent in a scientific or engineering discipline with specific training in plant design and in the response and analysis of the plant for transients and accidents.

j 6.3 UNIT STAFF QUALIFICATIONS.

6.3.1 Each member of the utj. staff shall meet cc exceed the minimum qualifications of ANSI N18.1-1971 for comparable positions, except for the Health Physics Manager who shall meet or exceed the qualifications of

~

Regulatory Guide 1.8, September 1975.

aNot responsible for sign-off function.

[

SAN ONOFRE-UNIT 2 6-5 Amendment No. 16

ADMINISTRATIVE CONTROLS 6.4 TRAINING 6.4.1 A retraining and replacement training program fo.r the unit staff shall be maintained under the direction of the Manager, Nuclear Training and shall meet or exceed the requirements and recommendations of Sections 5.5 of ANSI N18.1-1971 and Appendix "A" of 10 CFR Part 55 and the supplemental requirements specified in Section A and C of Enclosure 1 of the March 28, 1980 NRC letter to all licensees, and shall include familiarization with relevant industry operational experience identified by the ISEG.

6.5 REVIEW AND AUDIT 6.5.1 ONSITE REVIEW COMMITTEE (OSRC)

FUNCTION 6.5.1.1 The Onsite Review Committee shall furiction to advise the Station Manager on all matters related to nuclear safety.

COMPOSITION 6.5.1.2 The Onsite Review Committee shall be composed of the:

Chairman:

Station Manager Member:

Deputy Station Manager Member:

Manager, Operations Member:

Manager, Technical Member:

Plant Superintendent SONGS Unit 2 & 3 Member:

Supervisor of I&C Member:

Manager, Health Physics l

Member:

Supervisor of Chemistry 3

s Member:

Manager, Mainten'ance l

Member:

Supervising Engineer (NSSS, NSSS Support, Computer, or STA)

Member:

SanDiegoGas&gectricRepresentative, Senior Engineer ALTERNATES 6.5.1.3 All alternate members shall be appointed in writing.by the OSRC Chairman to serve on a temporary basis; however, no more than two alternates shall participate as voting members in OSRC activities at any one time.

l (1)BS degree in Engineering or Physical Science plus at least four years l

professional level experience in his field.

At least one of the four years l

experience shall be nuclear power plant experience.

SAN ONOFRE-UNIT 2 6-6 Amendment No. 4 l

c

6 ADMINISTRATIVE CONTROLS Proposed changes to Technical Specifications or this Operating d.

License.

Violations of codes, regulations, orders, Technical Specifications, i

e.

license requirements, or of internal procedures or instructions having nuclear safety significance.

Significant coerating abnormalities or deviations from normal and j

f.

expecte.d performance of unit equipment that affect nuclear safety.

f Events requiring 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months written notification to the Commission.

g.

All recognized indications of an unanticipated deficiency in some h.

aspect of design or operation of structures, systems, or components that could affect nuclear safety.

i.

Reports and meetings minutes of the Onsite Review Committee.

4 AUDITS Audits of unit activities shall be performed under the cognizance of 6.5.3.5 the NSG.

These audits shall encompass:

The conformance of unit operation to provisions contained within the 4

a.

Technical Specifications and applicable license conditions at least once per 12 months.

The performance, training and qualifications of the entire unit b.

staff at least once per 12 months.

The results of actions taken to correct deficiencies occurring in c.

unit equipment, structures, systems or method of operation that affect nuclear safety at least once per 6 months.

The performance of activities required by the Operational Quality d.

Assurance Program to meet the criteria of Appendix "B", 10 CFR 50, at least once per 24 months.

i Any other area of unit operation considered appropriate by the e.

Nuclear, Safety Group or Manager of Nuclear Operations.

f.

The Fire Protection Program and implementing procedures at least once per 24 months.

An independent fire protection and loss prevention inspection and g.

audit shall be performed annually utilizing either qualified'offsite licensee personnel or an outside fire protection firm.

An inspection and audit of'the fire protection and loss prevention h.

program shall be performed by an outside qualified fire consultant at intervals no greater than 3 years.

AMENDMENT NO.16 SAN ONOFRE-UNIT 2 6-11 w

o ADMINISTRATIVE CONTROLS AUTHORITY 6.5.3.6 The NSG shall report to and advise the Manager, Nuclear Engineering and Safety on thost areas of responsibility specified in Sections 6.5.3.4 and 6.5.3.5.

F RECORDS Records of NSG activities shall be prepared and maintained.

Report 6.5.3.7 of reviews and audits shall be distributed monthly to the Station Manager and to the management positions responsible for the areas audited.

SAN ONOFRE-UNIT 2 6-12 AMENDMENT NO.16

ADMINISTRATIVE CONTROLS 6.6 REPORTABLE OCCURRENCE ACTION

6. 6.~ 1 The following actions shall be taken for REPORTABLE OCCURRENCES:

a.

The Commission shall be notified and/or a report submitted pursuant to the requirements of Specification 6.9.

b.

Each REPORTABLE OCCURRENCE requiring 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months notification to the Commission shall be reviewed by the OSRC and submitted to the NSG and the Manager of Nuclear Operations.

6.7 SAFETY LIMIT VIOLATION 6.7.1 The following actions shall be taken in the event a Safety Limit is violated:

a.

The NRC Operations Center shall be notified by telephone as soon as possible and in all cases within one hour.

The Manager of Nuclear Operations and the NSG Chairman shall be notified within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

b.

A Safety Limit Violation. Report shall be prepared.

The report shall be reviewed by the OSRC.

This report shall describe (1) applicable circumstances preceding the violation, (2) effects of the violation upon facility compon'ents,. systems or structures, and (3) corrective I

action taken to prevent recurre'nce.

c.

The Safety Limit Violation Report shall be submitted to the Commission, the Manager of Nuclear Operations and the NSG within 14 days of the vioTation.

d.

Critical operation of the unit shall not be resumed until authorized by the Commission.

6.8 PROCEDURES AND PROGRAMS 6.8.1 Written procedures shall be established, implemented and maintained covering the activities referenced below:

a.

The applicable procedures recommended in Appendix "A" of Regulatory Guide 1.33, Revision 2, February 1978, i

b.

Refueling operations.

c.

Surveillance and test activities of safety related equipment.

d.

Security Plan implementation.

e.

Emergency Plan implementation.

f., Fire Protection Program implementation.

SAN ONOFRE-UNIT 2 6-13 s

o 8

j 4

ADMINISTRATIVE CONTROLS g.

PROCESS CONTROL PROGRAM implementation.*

h.

OFFSITE DOSE CALCULATION MANUAL implementation.

i.

Quality Assurance Program for effluent and environmental monitoring, using the guidance in Regulatory Guide 4.15 Rev. 1, February 1979.

j.

Modification of Core Protection Calculator (CPC) Addressable Constants.

NOTE:

Modification to the CPC addressable constants based on information obtained through the Plant Computer - CPC data link shall not be made without prior approval of the Onsite Review Committee.

I I

6.8.2 Each procedure of 6.8.1 above, and changes thereto, shall be approved by the Station Manager; or by (1) the Manager, Operations (2) the Manager, Technical (3) the Manager, Maintenance, (4) the Deputy Station Manager, or (5) the Manager, Health Physics as previously designated by the Station Manager; t

prior to implementation and shall be reviewed periodically as set forth in administrative procedures.

6.8.3 Temporary changes to procedures of 6.8.1 above may be made provided:

a.

The intent of the original procedure is not altered.

b.

The change is approved by two members of the plant management staff, at least one of whom holds a Senior Reactor Operator's License on i

the unit affected.

The change is documented, reviewed and approved by the Station c.

Manager; or by (1) the Deputy Station Manager, (2) the Manager, Operations, (3) the Manager, Maintenance, (4) the Manager, Technical, or (5) the Manager, Health Physics as previously designated by the Station Manager; within 14 days of implementation.

6.8.4 The following programs shall be established, implemented, and maintained:

a.

Primary Coolant Sources Outside Containment A program to reduce leakage from those portions of systems outside containment that could contain highly radioactive fluids during a serious transient or accident to as low as practical levels.

The systems include the high pressure safety injection recirculation, the shutdown cooling system, the reactor coolant sampling system (post-accident sampling piping only), the containment spray system, the radioactive waste gas system (post-accident samplirg return piping only) and the liquid radwaste system (post-accident sampling return piping only).

The program shall include the following:

(i) Preventive maintenance and periodic visual inspection requirements, and (ii) Integrated leak test requirements for lach system at refueling cycle intervals or less.

^See Specification 6.13.1 SAN ONOFRE-UNIT 2 6-14 AMENDMENT NO. 16

ADMINISTRATIVE CONTROLS The radioactive effluent release reports shall include unplanned releases from the site to unrestricted areas of radioactive materials in gaseous and liquid effluents on a quarterly basis.

The radioactive effluent release reports shall include any changes to the PROCESS CONTROL PROGRAM (PCP) made during the reporting period.

MONTHLY OPERATING REPORT 6.9.1.10 Routine reports of operating statistics and shutdown experience, including documentation of all challenges to the safety valves, shall be submitted on a monthly basis to the Director, Office of Resource Management, U.S. Nuclear Regulatory Commission, Washington, D.C.

20555, with a copy to the Regional Administrator of the Regional Office of the NRC, no later than the 15th of each month following the calendar month covered by the report.

Any changes to the OFFSITE DOSE CALCULATION MANUAL shall be submitted with the Monthly Operating Report within 90 days in which the change (s) was made effective.

In addition, a report of any major changes to the radioactive waste treatment systems shall be submitted with the Monthly Operating Report for the period in which the evaluation was reviewed and accepted by the Onsite Review Committee.

REPORTABLE OCCURRENCES 6.9.1.11 The REPORTABLE OCCURRENCES of Specifications 6.9.1.12 and 6.9.1.13 below, including corrective actions and measures to prevent recurrence, shall be reported to the NRC.

Supplemental reports may be required to fully 1

describe final resolution of occurrence.

In case of corrected or supplemental reports, a licensee event report shall be completed and reference shall be made to the original report date.

PROMPT NOTIFICATION WITH WRITTEN FOLLOWUP 6.9.1.12 The types of events listed below shall be reported within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months by telephone and confirmed by telegraph, mailgram, or facsimile transmission to the NRC Regional Administrator, or his designate no later than the first working day following the event, with a written followup report within 14 days.

The written followup report shall include, as a minimum, a completed copy of a licensee event report form.

Information provided on the licensee event report form shall be supplemented, as needed, by additional narrative material to provide complete explanation of the circumstances surrounding the event.

a.

Failure of the reactor protection system or other systems subject to limiting safety system settings to initiate the required protective l

function by the tire a monitored parameter reaches the setpoint specified as the limiting safety system setting in the technical

. specifications or failure to complete the required protective function.

SAN ONOFRE-UNIT 2 6-19 AMENDMENT NO. 16

T e

ADMINISTRATIVE CONTROLS Operation of the unit or affected systems when any parameter or b.

operation subject to a limiting condition for operation is less conservative than the least conservative aspect of the Limiting Condition for Operation established in the Technical Specifications.

Abnormal degradation discovered in fuel cladding, reactor coolant c.

pressure boundary, or primary containment.

Reactivity anomalies involving disagreement with the predicted value i

d.

of reactivity balance under steady state conditions during power operation greater than or equal to 1% Ak/k; a calculated reactivity balance indicating a SHUTDOWN MARGIN less conservative than specified in the Technical Specifications; short-term reactivity 2

increases that correspond to a reactor pericd of less than 5 seconds or, if subcritical, an unplanned reactivity insertion of more than 0.5% ak/k; or occurrence of any unplanned criticality.

Failure or malfunction of one or more components which prevents or e.

could prevent, by itself, the fulfillment of the functional require-j ments of system (s) used to cope with accidents analyzed in the SAR.

~

Personnel error or procedural inadequacy which prevents or could f.

prevent, by itself, the fulfillment of the functional requirements of systems required to cope with accidents analyzed in the SAR.

Conditions arising from natural or man-made events that, as a direct j

g.

result of the event require unit shutdown, ' operation of safety systems, 9

l or other protective measures required by Technical Specifications.

Errors discovered in the transient or accident analyses or in the l

h.

methods used for such analyses as described in the safety analysis report, or in the bases for the Technical Specifications that have or could have permitted reactor operation in a manner less conservative than assumed in the analyses.

Performance of structures, systems, or components that requires i.

remedial action or corrective measures to prevent operation in a manner less conservative than assumed in the accident analyses in the safety analysis report or Technical Specifications bases; or discovery during unit life of conditions not specifically considered in the safety analysis report or Technical Specifications that require remedial action or corrective measures to prevent the existence or development of an unsafe cohdition.

Offsite releases of radioactive materials in liquid and gaseous efflu-j.

ents that exceed the limits of Specifications 3.11.1.1 or 3.11.2.1.

l Exceeding the limits in Specification 3.11.1.4 or 3.11.2.6 for the I

f k.

The written storage of radioactive materials in the listed tanks.

follow-up report shall include a schedule and a description of acti-vities planned and/or taken to reduce the contents to within the specified limits.

~

1.

Failure of one or more pressurizer safety valves.

AMENDMENT NO. 16 SAN ONOFRE-UNIT 2 6-20

e l

ADMINISTRATIVE CONTROLS i

1 6.14 0FFSITE DOSE CALCULATION MANUAL (00CM) 6.14.1 The ODCM shall be approvad by the Commission prior to implementation.

6.14.2 Licensee initiated changes to the ODCM:

1.

Shall be submitted to the Commission in the Monthly Operating Report within 90 days of the date the change (s) was made effective.

This

+

submittal shall contain:

l i

Sufficiently detailed information to totally support the a.

rationale for the change without benefit of additional or supplemental information.

Information submitted should consist of a package of those pages of the ODCM to be changed with each page numbered and provided with an approval and date box, together with appropriate analyses or evaluations justifying the change (s);

b.

A determination that the change will not reduce the accuracy or reliability of dose calculations or setpoint determinations; and r

Documentation of the fact that the change has been reviewed and c.

found acceptable by the OSRC.

~

2.

Shall become effective upon review and acceptance by the OSRC.

6.15 MAJOR CHANGES TO RADI0 ACTIVE WASTE TREATMENT SYSTEMS (Liquid, Gaseous and i

solid)

I l

6.15.1 Licensee initiated major changes to the radioactive waste systems (liquid, gaseous and solid):

l 1.

Shall be reported to the Commission in the Monthly Operating Report for the period in which the evaluation was reviewed by the OSRC.

The discussion of each change shall contain:

A summary of the evaluation that led to the determination that a.

the change could be made in accordance with 10 CFR 50.59; b.

Sufficient detailed information to totally support the reason for the change without benefit of additional or supplemental l

information; A detailed description of the equipment, components and

[

c.

processes involved and the interfaces with other plant systems;-

d.

An evaluation of the change which shows the predicted releases of radioactive materials in liquid and gaseous effluents and/or quantity of solid waste that differ from those previously predicted in the license application and amendments thereto; SAN ONOFRE-UNIT 2 6-25 AMENDMENT. NO.16

~

o ADMINISTRATIVE CONTROLS i

e.

An evaluation of the change which shows the expected maximum exposures to individual in the unrestricted area and to the general population that differ from those previously estimated in the license application and amendments thereto; f.

A comparison of the predicted releases of radioactive materials, in liquid and gaseous effluents and in solid waste, to the actual releases for the period prior to when the changes are to be made; g.

An estimate of the exposure to plant operating personnel as a result of the change; and h.

Documentation of the fact that the change was reviewed and found acceptable by the OSRC.

2.

Shall become effective upon review and acceptance by the OSRC.

O O

/

0 a

b a

e G

9 SAN ONOFRE-UNIT 2 6-26

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ML20073T283

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