ML21091A223

Technical Requirements Manual

ML21091A223
Person / Time
Site:	Susquehanna
Issue date:	03/19/2021
From:	Susquehanna
To:	Document Control Desk, Office of Nuclear Reactor Regulation
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Download: ML21091A223 (251)

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• MANUAL HARD COPY DISTRIBUTION DOCUMENT TRANSMITTAL 2021-4736

_J USER INFORMATION:

GERLACH*ROSEY M EMPL#: 028401 CA#: 0363 Address: NUCSA2 Phone#: 542-3194 TRANSMITI'AL INFORMATION:

TO: GERLACH*ROSEY M 03/19/2021 LOCATION: USNRC FROM: NUCLEAR RECORDS DOCUMENT CONTROL CENTER (NUCSA-2)

THE FOLLOWING CHANGES HAVE OCCURRED TO THE HARDCOPY OR ELECTRONIC MANUAL ASSIGNED TO YOU. HARDCOPY USERS MUST ENSURE THE DOCUMENTS PROVIDED MATCH THE INFORMATION ON THIS TRANSMITI'AL. WHEN REPLACING THIS MATERIAL IN YOUR HARDCOPY MANUAL, ENSURE THE UPDATE DOCUMENT ID IS THE SAME DOCUMENT ID YOU'RE REMOVING FROM YOUR MANUAL. TOOLS

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TOC will be issued with the updated material.

TRMl - TECHNICAL REQUIREMENTS MANUAL UNIT 1 REMOVE MANUAL TABLE OF CONTENTS DATE: 02/25/2021 ADD MANUAL TABLE OF CONTENTS DATE: 03/18/2021 CATEGORY: DOCUMENTS TYPE: TRMl

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Page 2 of 2

• ID:

ADD:

TEXT 3.0 REV: 7 REMOVE: REV:6 CATEGORY: DOCUMENTS TYPE: TRMl ID: TEXT B3.0 REMOVE: REV:5 ADD: REV: 6 ANY DISCREPANCIES WITH THE MATERIAL PROVIDED, CONTACT DCS@ X3171 OR X3194 FOR ASSISTANCE. UPDATES FOR HARDCOPY MANUALS WILL BE DISTRIBUTED WITHIN 3 DAYS IN ACCORDANCE WITH DEPARTMENT PROCEDURES. PLEASE MAKE ALL CHANGES AND ACKNOWLEDGE COMPLETE IN YOUR NIMS INBOX UPON COMPLETION OF UPDATES. FOR ELECTRONIC MANUAL USERS, ELECTRONICALLY REVIEW THE APPROPRIATE DOCUMENTS AND ACKNOWLEDGE COMPLETE IN YOUR NIMS INBOX.

\

SSES MANUAL Name: TRMl

Title:

TECHNICAL REQUIREMENTS MANUAL UNIT 1 Table Of Contents Issue Date: 03/18/2021 Procedure Name Rev Issue Date Change ID Change Number TEXT LOES 96 01/03/2019

Title:

LIST OF EFFECTIVE SECTIONS TEXT TOC 27 03/05/2019

Title:

TABLE OF CONTENTS TEXT 1.1 1 01/31/2014

Title:

USE AND APPLICATION DEFINITIONS TEXT 2.1 2 04/28/2015 ~ - _;;;

Title, PLANT PROGRAMS AND SETPOINTS PLl\NT P R O ~ ~ V TEXT 2.2

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TEX;i:~:, TECHNICAL REQUIREMENT. ? Q ~ i f ; ~ O ) APPLICABILITY & SURVEILLANCE (TRS)

APPLICABILITY :_ V TEXT 3 .1.1 , . *1 ._-, 11/09/2007 ROD

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INJECTION (A S ',, STRUMENTATION

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TEXT 3.1.2 0 11/18/2002 Title, REACTIVI~~'i, SYSTEMS CONTROL ROD DRIVE (CRD) HOUSING SUPPORT TEXT 3.1.3 6 12/18/2017

Title:

REACTIVITY CONTROL SYSTEMS CONTROL ROD BLOCK INSTRUMENTATION TEXT 3 .1.4 10/12/2020

Title:

REACTIVITY CONTROL SYSTEMS CONTROL ROD SCRAM ACCUMULATORS INSTRUMENTATION &

CHECK VALVE TEXT 3.2.1 20 04/07/2020

Title:

CORE OPERATING LIMIST REPORT (COLR)

Page 1 of 16 Report Date: 03/19/21

SSES MANUAL Manual Name: TRMl

'fanual

Title:

TECHNICAL REQUIREMENTS.MANUAL UNIT 1 TEXT 3.3.1 0 11/18/2002

Title:

INSTRUMENTATION RADIATION MONITORING INSTRUMENTATION TEXT 3.3.2 3 03/31/2011

Title:

INSTRUMENTATION SEISMIC MONITORING INSTRDMEN'r'ATION TEXT 3.3.3 2 11/09/2007

Title:

INSTRUMENTATION METEOROLOGICAL MONITORING INSTRUMENTATION TEXT 3.3.4 11 06/29/2017

Title:

INSTRUMENTATION TRM POST-ACCIDENT MONITORING INSTRUMENTATION TEXT 3.3.5 0 11/18/2002

Title:

INSTRUMENTATION THIS PAGE INTENTIONALLY LEFT BLANK

.5 _ . 93/_Q5_/~_Q_l.,9

Title:

INSTRUMENTATION TRM ISOLATION ACTUATION INSTRUMENTATION TEXT 3.3.7 2 11/10/2015

Title:

INSTRUMENTATION MAIN TURBINE OVERBPEED PROTECTION SYSTEM TEXT 3.3.8 1 10/22/2003

Title:

INSTRUMENTATION INTENTIONALLY LEFT BLANK TEXT 3.3.9 3 04/17/2008

Title:

OPRM INSTRUMENTATION CONFIGORATION TEXT 3.3.10 1 12/14/2004

Title:

INSTRUMENTATION REACTOR RECIRCULATION PUMP MG SET STOPS TEXT 3.3.11 1 10/22/2003

Title:

INSTRUMENTATION MVP ISOLATION INSTRUMENTATION 04/02/2019 TEXT 3.3.12 2

Title:

WATER MONITORING INSTRUMENTATION Page 2 of 16 Report Date: 03/19/21

I Manual Name: TRMl SSES MANUAL

."'<<anual *Title: TECHNICAL REQUIREMENTS MANUAL UNIT 1 TEXT 3.4.1 1 04/26/2006

Title:

REACTOR COOLANT SYSTEM REACTOR COOLANT SYSTEM CHEMISTRY TEXT 3.4.2 1 04/16/2009

Title:

REACTOR COOLANT SYSTEM INTENTIONALLY LEFT BLANK TEXT 3.4.3 1 11/09/2007

Title:

REACTOR COOLANT SYSTEM HIGH/LOW PRESSURE INTERFACE LEAKAGE MONITORS TEXT 3.4.4 2 04/17/2008

Title:

REACTOR COOLANT SYSTEM REACTOR RECIRCULATION FLOW AND ROD LINE LIMIT TEXT 3.4.5 1 04/26/2006

Title:

REACTOR COOLANT SYSTEM REACTOR VESSEL MATERIALS EXT.-3 .4. 6 . . . ____ . ___ 2 . Q4!'.2_5/2Q13

Title:

REACTOR RECIRCOLATION SINGLE LOOP OPERATION SLO FLOW RATE RESTRICTION TEXT 3.5.1 2 03/05/2019

Title:

ECCS RPV WATER INVENTORY CONTROL AND RCIC SYSTEM ADS MANUAL INHIBIT

\

TEXT 3.5.2 2 03/05/2019

Title:

ECCS RPV WATER INVENTORY CONTROL AND RCIC SYSTEM ECCS RPV WATER INVENTORY CONTROL AND RCIC MONITORING INSTRUMENTATION TEXT 3.5.3 1 03/05/2019

Title:

ECCS RPV WATER INVENTORY CONTROL AND RCIC SYSTEM LONG TERM NITROGEN SUPPLY TO ADS TEXT 3.6.1 0 11/18/2002

Title:

CONTAINMENT VENTING OR PURGING TEXT 3.6.2 3 01/03/2019

Title:

SUPPRESSION CHAMBER TO DRYWELL VACUUM BREAKER POSITION INDICATION TEXT 3.6.3 0 11/18/2002

• Page 3 Title, CONTAINMENT SUPPRESSION POOL ALARM INSTRUMENTATION of 16 Report Date: 03/19/21

SSES MANUAL Manual Name: TRMl

~ual

Title:

TECHNICAL REQUIREMENTS MANUAL UNIT 1 TEXT 3.6.4 0 11/18/2002

Title:

CONTAINMENT PRIMARY CONTAINMENT CLOSED SYSTEM BOUNDARIES TEXT 3.7.1 0 11/18/2002

Title:

PLANT SYSTEMS EMERGENCY SERVICE WATER SYSTEM (ESW) SHOTDOWN TEXT 3.7.2 0 11/18/2002 .

Title:

PLANT SYSTEMS ULTIMATE HEAT SINK (DRS) AND GROUND WATER LEVEL TEXT 3.7.3.1 5 02/13/2020

Title:

PLANT SYSTEMS FIRE SUPPRESSION WATER SUPPLY SYSTEM TEXT 3.7.3.2 3 \ 04/16/2009

Title:

PLANT SYSTEMS SPRAY AND SPRINKLER SYSTEMS

'EXT_ 3. 7. 3. 3 ___ ' _ _ _ __ 4_

Title:

PLANT SYSTEMS CO2 SYSTEMS TEXT 3.7.3.4 2

Title:

PLANT SYSTEMS HALON SYSTEMS Q~}l9/_201_6 04/16/2009 TEXT 3.7.3.5 2 04/16/2009

Title:

PLANT SYSTEMS FIRE HOSE STATIONS TEXT 3.7.3.6 2 04/16/2009 r

Title:

PLANT SYSTEMS YARD FIRE HYDRANTS AND HYDRANT HOSE HOUSES TEXT 3.7.3.7 1 04/26/2006

Title:

PLANT SYSTEMS FIRE RATED ASSEMBLIES TEXT 3.7.3.8 13 12/18/2017

Title:

PLANT SYSTEMS FIRE DETECTION INSTRUMENTATION TEXT 3.7.4 1 04/26/2006 Page 4

Title:

PLANT SYSTEMS SOLID RADWASTE SYSTEM of 16 Report Date: 03/19/21

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TECHNICAL REQUIREMENTS MANUAL DNIT 1 TEXT 3.7.5.1 1 03/05/2015

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PLANT SYSTEMS MAIN CONDENSER OFFGAS HYDROGEN MONITOR TEXT 3.7.5.2 0 11/18/2002

Title:

PLANT SYSTEMS MAIN CONDENSER OFFGAS EXPLOSIVE GAS MIXTIIRE

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TEXT 3.7.5.3 1 04/26/2006

Title:

PLANT SYSTEMS LIQUID HOLDUP TANKS TEXT 3.7.6 / 3 06/04/2012

Title:

PLANT SYSTEMS ESSW PUMPHOUSE VENTILATION TEXT 3.7.7 2 09/05/2008

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Title:

PLANT SYSTEMS MAIN CONDENSER OFFGAS PRETREATMENT LOGARITHMIC RADIATION MONITORING

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Title:

PLANT SYSTEMS SNOBBERS TEXT 3.7.9 3 03/05/2019

Title:

PLANT SYSTEMS CONTROL STRUCTURE HVAC TEXT 3.7.10 1 12/14/2004

Title:

PLANT SYSTEMS SPENT FUEL STORAGE POOLS (SFSPS)

TEXT 3.7.11 1 11/01/2018

Title:

STRUCTURAL INTEGRITY TEXT 3.8.1 3 04/22/2020

Title:

ELECTRICAL POWER PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES TEXT 3.8.2.1 2 11/09/2007

Title:

ELECTRICAL POWER MOTOR OPERATED VALVES (MOV) THERMAL OVERLOAD PROTECTION -

CONTINUOUS 12/14/2004 TEXT 3.8.2.2 2

Title:

ELECTRICAL POWER MOTOR OPERATED VALVES (MOV) THERMAL OVERLOAD PROTECTION -

AUTOMATIC Page 5 of 16 Report Date: 03/19/21

SSES MANUAL Manual Name: TRMl

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Title:

TECHNICAL REQUIREMENTS MANUAL UNIT 1

\

TEXT 3.8.3 4 01/28/2020

Title:

ELECTRICAL POWER DIESEL GENERATOR {DG) MAINTENANCE ACTIVITIES TEXT 3.8.4 0 11/18/2002

Title:

ELECTRICAL POWER 24 VDC ELECTRICAL POWER SUBSYSTEM TEXT 3.8.5 1 11/14/2013

Title:

ELECTRICAL POWER DEGRADED VOLTAGE PROTECTION TEXT 3.8.6 2 03/05/2019

Title:

ELECTRICAL POWER EMERGENCY SWITCHGEAR ROOM COOLING TEXT 3.8.7 2 02/25/2021

Title:

BATTERY MAINTENANCE AND MONITORING PROGRAM

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REFUELING OPERATIONS DECAY TIME 11/18/2002

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REFUELING OPERATIONS COMMUNICATIONS

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Title:

REFUELING OPERATIONS REFUELING PLATFORM TEXT 3.10.1 1 04/26/2006

Title:

MISCELLANEOUS SEAL SOURCE CONTAMINATION TEXT 3.10.2 3 06/19/2019

Title:

MISCELLANEOUS SHUTDOWN MARGIN TEST RPS INSTRUMENTATION TEXT 3.10.3 3 ( 10/17/2019

Title:

MISCELLANEOUS INDEPENDENT SPENT FUEL STORAGE INSTALLATION (ISFSI) 04/17/2008 TEXT 3.10.4 2

Title:

INTENTIONALLY LEFT BLANK Page 6 *of 16 Report Date: 03/19/21

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Title:

TECHNICAL REQUIREMENTS MANUAL UNIT 1-TEXT 3 . 11. 1. 1 1 04/26/2006

Title:

RADIOACTIVE EFFLUENTS LIQUID EFFLUENTS CONCENTRATION TEXT 3 . 11. 1. 2 1 04/26/2006

Title:

RADIOACTIVE EFFLUENTS LIQUID EFFLUENTS DOSE TEXT 3 . 11. 1. 3 1 04/26/2006

Title:

RADIOACTIVE EFFLUENTS LIQUID WASTE TREATMENT SYSTEM TEXT 3 . 11 . 1. 4 2 10/09/2012

Title:

RADIOACTIVE EFFLUENTS LIQUID RADWASTE EFFLUENT MONITORING INSTRUMENTATION TEXT 3.11.1.5 3 03/05/2015

Title:

RADIOACTIVE EFFLUENTS RADIOACTIVE LIQUID PROCESS MONITORING INSTRUMENTATION

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Title:

RADIOACTIVE EFFLUENTS DOSE RATE TEXT 3 . 11. 2 . 2 1 04/26/2006

Title:

RADIOACTIVE EFFLUENTS DOSE - NOBLE GA.SES TEXT 3 . 11. 2 . 3 1 04/26/2006

Title:

RADIOACTIVE EFFLUENTS DOSE - IODINE, TRITIUM, AND RADIONUCLIDES IN PARTICULATE FORM TEXT 3 . 11. 2 . 4 0 11/18/2002

Title:

RADIOACTIVE EFFLUENTS GASEOUS RADWASTE TREATMENT SYSTEM TEXT 3 . 11. 2 . 5 4 07/03/2013

Title:

RADIOACTIVE EFFLUENTS VENTILATION EXHAUST TREATMENT SYSTEM TEXT 3 . 11. 2 . 6 8 06/29/2017

Title:

RADIOACTIVE EFFLUENTS RADIOACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION TEXT 3 .11.3 1 04/26/2006 Page 7

Title:

RADIOACTIVE EFFLUENTS TOTAL DOSE of 16 Report Date: 03/19/21

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Title:

TECHNICAL REQUIREMENTS MANUAL UNIT 1 TEXT 3.11.4.1 5 03/05/2015

Title:

RADIOACTIVE EFFLUENTS MONITORING PROGRAM TEXT 3 . 11. 4 . 2 2 04/26/2006

Title:

RADIOACTIVE EFFLUENTS LAND USE CENSUS TEXT 3.11.4.3 1 04/26/2,006 Titlez RADIOACTIVE EFFLUENTS INTERLABORATORY COMPARISON PROGRAM TEXT 3.12.1 0 11/19/2002

Title:

LOADS CONTROL' PROGRAM CRANE TRAVEL-SPENT FUEL POOL STORAGE POOL TEXT 3.12.2 4 04/17/2008

Title:

LOADS CONTROL PROGRAM HEAVY LOADS REQUIREMENTS

~EXT-3 .12. 3 . . - - - -- - - - ... . . 0 . ll/.;J,~/2002

Title:

LOADS CONTROL PROGRAM LIGHT LOADS REQUIREMENT TEXT 4.1

Title:

ADMINISTRATIVE CONTROLS ORGANIZATION 0 08/31/1998 TEXT 4.2 1 01/03/2019 Titlez ADMINISTRATIVE CONTROLS REPORTABLE EVENT ACTION TEXT 4.3 1 01/03/2019

Title:

ADMINISTRATIVE CONTROLS SAFETY LIMIT VIOLATION TEXT 4.4 1 12/18/2008

Title:

ADMINISTRATIVE CONTROLS PROCEDURES & PROGRAMS TEXT 4.5 0 08/31/1998 Titlez ADMINISTRATIVE CONTROLS REPORTING REQUIREMENTS TEXT 4.6 0 08/31/1998 Page 8

Title:

ADMINISTRATIVE CONTROLS RADIATION PROTECTION PROGRAM of 16 Report Date:

03/19/21

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Manual Na.me: TRMl

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"TECHNICAL REQUIREMENTS MANOAL UNIT 1 TEXT 4.7 0 08/31/1998

Title:

ADMINISTRATIVE CONTROLS TRAINING TEXT B3.0 6 03/18/2021

Title:

APPLICABILITY BASES TECHNICAL REQUIREMENT FOR OPERATION (TRO) APPLICABILITY TEXT B3 .1.1 2 04/29/2014

Title:

REACT;IVITY CONTROL SYSTEMS BASES ANTICIPATED TRANSIENT WITHOUT SCRAM ALTERNATE ROD INJECTION (ATWS-ARI) INSTRUMENTATION TEXT B3.l.2 0 11/19/2002

Title:

REACTIVITY CONTROL SYSTEMS BASES CONTROL ROD DRIVE (CRD) HOUSING SUPPORT TEXT B3 .1.3 4 12/18/2017

Title:

REACTIVITY CONTROL SYSTEMS BASES CONTROL ROD BLOCK INSTRUMENTATION

• 'EXLB3 . 1. :4 . . _ . _ . _ .. .. _ . __ . __ .. 1 .. _10/J.. 2/.2no.. _______ _

Title:

REACTIVITY CONTROL SYSTEMS BASES CONTROL ROD SCRAM ACCUMOLATORS INSTRUMENTATION

• AND CHECK VALVE TEXT B3.2.l 0 11/19/2002

Title:

CORE OPERATING LIMITS BASES CORE OPERATING LIMITS REPORT (COLR)

TEXT B3.3.l 1 01/31/2014

Title:

INSTRUMENTATION BASES RADIATION MONITORING INSTRUMENTATION TEXT B3.3.2 2 03/31/2011

Title:

INSTRUMENTATION BASES SEISMIC MONITORING INSTRUMENTATION TEXT B3.3.3 3 12/18/2008

Title:

INSTRUMENTATION BASES METEOROLOGICAL MONITORING INSTRUMENTATION TEXT B3.3.4 7

Title:

INSTRUMENTATION BASES TRM POST ACCIDENT MONITORING (PAM) INSTRUMENTATION 2 11/09/2007 TEXT B3.3.5

Title:

INTENTIONALLY LEFT BLANK Page 9 of 16 Report Date: 03/19/21

SSES MANUAL Manual Name: TRMl ianual Title 1

• TECHNICAL REQUIREMENTS MANUAL UNIT 1 TEXT B3.3.6 6 03/05/2019

Title:

INSTRUMENTATION BASES TRM ISOLATION ACTUATION INSTRUMENTATION TEXT B3.3.7 2 11/10/2015

Title:

INSTRUMENTATION BASES MAIN TURBINE OVERSPEED PROTECTION SYSTEM TEXT B3.3.8 1 10/22/2003

Title:

INTENTIONALLY LEFT BLANK TEXT B3.3.9 4 01/03/2019

Title:

OPRM INSTRUMENTATION TEXT B3.3.10 3 08/09/2010

Title:

INSTRUMENTATION BASES REACTOR RECIRCULATION PUMP MG SET STOPS

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Title:

INSTRUMENTATION BASES MVP ISOLATION INSTRUMENTATION TEXT B3.3.12 1

Title:

WATER MONITORING INSTRUMENTATION 04/02/2019 TEXT B3.4.l 0 11/19/2002

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Title:

REACTOR COOLANT SYSTEM BASES REACTOR COOLANT SYSTEM CHEMISTRY TEXT B3.4.2 1 04/16/2009 Title~ INTENTIONALLY LEFT BLANK TEXT B3.4.3 1 11/09/2007

Title:

REACTOR COOLANT SYSTEM BASES HIGH/LOW PRESSURE INTERFACE LEAKAGE MONITOR TEXT B3.4.4 0 11/19/2002

Title:

REACTOR COOLANT SYSTEM BASES REACTOR RECIRCULATION FLOW AND ROD LINE LIMIT 11/19/2002 TEXT B3.4.5 0

Title:

REACTOR COOLANT SYSTEM BASES REACTOR VESSEL MATERIALS Page 10 of 16 Report Date: 03/19/21

SSES MANUAL Manual Name: TRMl

• fanual

Title:

TECHNICAL REQUIREMENTS MANUAL UNIT 1 TEXT B3.4.6 3 01/03/2019

Title:

REACTOR RECIRCULATION SINGLE LOOP OPERATION SLO FLOW RATE RESTRICTION TEXT B3.5.l 2 03/17/2020

Title:

ECCS RPV WATER INVENTORY CONTROL AND RCIC SYSTEM ADS MANUAL INHIBIT TEXT B3.5.2 2 03/05/2019

Title:

ECCS RPV WATER INVENTORY CONTROL AND RCIC SYSTEM ECCS RPV WATER INVENTORY CONTROL AND RCIC MONITORING INSTRUMENTATION TEXT B3.5.3 2 03/05/2019

Title:

ECCS RPV WATER INVENTORY CONTROL AND RCIC SYSTEM LONG TERM NITROOEN SUPPLY TO ADS TEXT B3.6.l 0 11/19/2002

Title:

CONTAINMENT BASES VENTING OR PURGING

."'EXT . B3.6.2. . . . _ ..0 _, . 11/1.2/2_0_0_4_ _ __________ _

Title:

CONTAINMENT BASES SUPPRESSION CHAMBER-TO-DRYWELL VACUOM BREAKER POSITION INDICATION TEXT B3.6.3 2 04/17/2008

Title:

CONTAINMENT BASES SUPPRESSION POOL ALARM INSTRUMENTATION TEXT B3.6.4 1 12/14/2004

Title:

CONTAINMENT BASES PRIMARY CONTAINMENT CLOSED SYSTEM BOUNDARIES TEXT B3.7.l O 11/19/2002

Title:

PLANT SYSTEMS BASES EMERGENCY SERVICE WATER SYSTEM (SHUTDOWN)

TEXT B3.7.2 0 11/19/2002

Title:

PLANT SYSTEMS BASES ULTIMATE HEAT SINK (UHS) GROUND WATER LEVEL TEXT B3.7.3.l 4 02/16/2017

Title:

PLANT SYSTEMS BASES FIRE SUPPRESSION WATER SUPPLY SYSTEM TEXT B3.7.3.2 2 04/26/2006 Page 11

Title:

PLANT SYSTEMS BASES SPRAY AND SPRINKLER SYSTEMS of 16 Report Date: 03/19/21

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Title:

TECHNICAL REQUIREMENTS MANUAL DNIT 1 TEXT B3.7.3.3 1 01/03/2019

Title:

PLANT SYSTEMS BASES CO2 SYSTEMS TEXT B3.7.3.4 4 06/19/2019

Title:

PLANT SYSTEMS BASES HALON SYSTEMS TEXT B3.7.3.5 1 04/26/2006

Title:

PLANT SYSTEMS BASES FIRE HOSE STATIONS 0

TEXT B3.7.3.6 1 04/26/2006

Title:

PLANT SYSTEMS BASES YARD FIRE HYDRANTS AND HYDRANT HOSE HOUSES TEXT B3.7.3.7 0 11/19/2002

Title:

PLANT SYSTEMS BASES FIRE RATED ASSEMBLIES

'EXT B3. 7. 3. 8 __ _ - _3_ --

Title:

PLANT SYSTEMS BASES FIRE DETECTION INSTRUMENTATION TEXT B3.7.4 0 11/19/~002

Title:

PLANT SYSTEMS BASES SOLID RADWASTE SYSTEM TEXT B3.7.5.l 0 11/19/2002

Title:

PLANT SYSTEMS BASES MAIN CONDEN"SER OFFGAS HYDROGEN MONITOR TEXT B3.7.5.2 0 11/19/2002

Title:

PLANT SYSTEMS BASES MAIN CONDENSER OFFGAS EXPLOSIVE GAS MIXTURE TEXT B3.7.5.3 0 11/19/2002

Title:

PLANT SYSTEMS BASES LIQUID HOLDUP TANKS TEXT B3.7.6 4 06/04/2013

Title:

PLANT SYSTEMS BASES ESSW PTIMPHOUSE VENTILATION 2 01/31/2008 TEXT B3.7.7

Title:

PLANT SYSTEMS BASES MAIN CONDENSER OFFGAS PRETREATMENT LOGARITHMIC RADIATION MONITORING INSTRUMENTATION Page 12 of 16 Report Date: 03/19/21

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Manual Name: TRMl

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• TEXT B3.7.8 4 01/31/2014

Title:

PLANT SYSTEMS BASES SNDBBERS TEXT B3.7.9 3 03/05/2019

Title:

PLANT SYSTEMS BASES CONTROL STRUCTURE HVAC TEXT B3.7.10 1 12/14/2004

Title:

PLANT SYSTEMS BASES SPENT FUEL STORAGE POOLS TEXT B3.7.ll 2 11/01/2018

Title:

STRUCTURAL INTEGRITY TEXT B3.8.l 2 03/10/2010

Title:

ELECTRICAL POWER BASES PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES

.,EXT B3 .. 8.2.l. ... __ _ 0

Title:

ELECTRICAL POWER BASES MOTOR OPERATED VALVES {MOV) THERMAL OVERLOAD PROTECTION -

CONTINUOUS TEXT B3.8.2.2 1 09/17/2004

Title:

ELECTRICAL POWER BASES MOTOR OPERATED VALVES (MOV) THERMAL OVERLOAD PROTECTION -

AUTOMATIC TEXT B3.8.3 0 11/19/2002

Title:

ELECTRICAL POWER BASES DIESEL GENERATOR (DG) MAINTENANCE ACTIVITIES TEXT B3.8.4 0 11/19/2002

Title:

ELECTRICAL POWER BASES 24 VDC ELECTRICAL POWER SUBSYSTEM TEXT B3.8.5 , 1 11/14/2013

Title:

ELECTRICAL POWER BASES DEGRADED VOLTAGE PROTECTION TEXT B3.8.6 3 03/05/2019

Title:

ELECTRICAL POWER BASES EMERGENCY SWITCHGEAR ROOM COOLING TEXT B3.8.7 3 02/25/2021 Page 13

Title:

BATTERY MAINTENANCE AND MONITORING PROGRAM of 16 Report Date: 03/19/21

SSES MANUAL Manual Name: TRMl fanual

Title:

TECHNICAL REQUIREMENTS MANUAL UNIT 1 I *

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TEXT B3.9.1 0 11/19/2002

Title:

REFUELING OPERATIONS BASES DECAY TIME TEXT B3.9.2 0 11/19/2002

Title:

REFUELING OPERATIONS BASES COMMUNICATIONS TEXT B3.9.3 1 03/12/2019

Title:

REFUELING OPERATIONS BASES REFUELING PLATFORM TEXT B3.10.1 0 11/19/2002

Title:

MISCELLANEOUS BASES SEALED SOURCE CONTAMINATION TEXT B3.10.2 1 03/31/2006

Title:

MISCELLANEOUS BASES SHOTDOWN MARGIN TEST RPS INSTRUMENTATION

'EXT B3 .10.. 3 . 2 ___1,o/1:zno19 *

Title:

MISCELLANEOUS BASES INDEPENDENT SPENT FUEL STORAGE INSTALLATION -( I;~s~-) - . - . - ..

TEXT B3.10.4 1 04/17/2008

Title:

INTENTIONALLY LEFT BLANK TEXT B3 .11.1.1 0 11/19/2002

Title:

RADIOACTIVE EFFLUENTS BASES LIQUID EFFLUENTS CONCENTRATION TEXT B3 .11.1. 2 0 11/19/2002

Title:

RADIOACTIVE EFFLUENTS BASES LIQUID EFFLUENTS DOSE TEXT B3 .11.1. 3 0 11/19/2002

Title:

RADIOACTIVE EFFLUENTS BASES LIQUID WASTE TREATMENT SYSTEM TEXT B3 .11.1. 4 0 11/19/2002

Title:

RADIOACTIVE EFFLUENTS BASES LIQUID RADWASTE EFFLUENT MONITORING INSTRUMENTATION TEXT B3 .11.1. 5 0 11/19/2002 Page 14

Title:

RADIOACTIVE EFFLUENTS BASES RADIOACTIVE LIQUID PROCESS MONITORING of INSTRUMENTATION 16 Report Date: 03/19/21

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Title:

RADIOACTIVE EFFLUENTS BASES DOSE - NOBLE GASES TEXT B3.ll.2.3 0 11/19/2002

Title:

RADIOACTIVE EFFLUENTS BASES DOSE - IODINE, TRITIUM, AND RADIONUCLIDES IN PARTICULATES FORM TEXT B3.ll.2.4 0 11/19/2002

Title:

RADIOACTIVE EFFLUENTS BASES GASEOUS RADWASTE TREATMENT SYSTEM TEXT B3 . 11. 2 . 5 5 07/03/2013

Title:

RADIOACTIVE EFFLUENTS BASES VENTILATION EXHAUST TREATMENT SYSTEM

-~EXT. B3 ..11. 2 .. 6 . 2 0;)/9~n_oJ,6_ *- - - - . -- ... ------ --------

Title:

RADIOACTIVE EFFLUENTS BASES RADIOACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION -

TEXT B3 .11. 3 0 11/19/2002

Title:

RADIOACTIVE EFFLUENTS BASES TOTAL DOSE TEXT B3.ll.4.l 5 03/05/2015

Title:

RADIOACTIVE EFFLUENTS BASES MONITORING PROGRAM TEXT B3.ll.4.2 0 11/19/2002

Title:

RADIOACTIVE EFFLUENTS BASES LAND USE CENSUS TEXT B3 . 11. 4 . 3 0 11/19/2002

Title:

RADIOACTIVE EFFLUENTS BASES INTERLABORATORY COMPARISON PROGRAM TEXT B3.12.l 1 10/04/2007

Title:

LOADS CONTROL PROGRAM BASES CRANE TRAVEL-SPENT FUEL STORAGE POOL 12/03/2010 TEXT B3.12.2 1

Title:

LOADS CONTROL PROGRAM BASES HEAVY LOADS REQUIREMENTS Page 15 of 16 Report Date: 03/19/21

. MANUAL SSES Manual Name: TRMl lanual

Title:

TECHNICAL REQUIREMENTS MANUAL UNIT 1 TEXT B3.12.3 0 11/19/2002

Title:

LOADS CONTROL PROGRAM BABES LIGHT LOADS REQUIREMENTS Page 16 of 16 Report Date:

03/19/21

Rev. 7 3.0 TECHNICAL REQUIREMENT FOR OPERATION [fRO) APPLICABILITY TRO Applicability 3.0 TRO 3.0.1 TROs shall be met during the MODES or other specified conditions In the Applicability, except as provided in TRO 3.0.2.

TRO 3.0.2 Upon discovery of a failure to meet an TRO, the Required Actions of the associated Conditions shall be met, except as provided in TRO 3.0.5 and TRO 3.0.6.

If the TRO is met or is no longer applicable prior to expiration of the specified Completion Time(s), completion of the Required Action(s) is not required, unless otherwise stated.

TRO 3.0.3 When a TRO is not met, and the associated ACTIONS are not met, an associated ACTION is not provided, or if directed by the associated ACTIONS, the following actions shall be taken:

1. Take compensatory actions as warranted for exiting TRO 3.0.3 commensurate with the safety significance of the condition.

Development and implementation of the compensatory actions and plan for exit of TRO 3.0.3 shall be pursued withc:n.it delay and in a c __ _ _ _ _ _ _ _ _ _ _ _ controlledmanner__and.shall..be_documentedjnJhe_ THO_3.0.3_entry_.~---

Condition Report.

2. Initiate a TRO 3.0.3 entry Condition Report to document and

. --appropriately evaluate.the issue. --- _- _ - . - - ----- ~ __

When corrective measures are completed that permit operation in accordance with the TRO or the TRO actions, completion of the compensatory actions and plan for exiting TRO 3.0.3 is not required.

TRO 3.0.4 When a TRO is not met, entry into a MODE or other specified condition in the Applicability shall only be made:

a. When the associated ACTIONS to be entered permit continued operation In the MODE or other specified condition in the Applicability for an unlimited period of time; SUSQUEHANNA - UNIT 1 TRM / 3.0--1

TRO Applicability Rev. 7 3.0 3.0 TRO APPLICABILITY TRO 3.0.4 b. After performance of a risk assessment addressing inoperable (continued) systems and components, consideration of the results, determination of the acceptability of entering the MODE or other specified condition in the Applicability, and establishment of risk management actions, if appropriate (exceptions to this Requirement are stated in the individual TROs); or -

I

c. When an allowance is stated in the individual value, parameter, or other Requirement.

This Requirement shall not prevent changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit.

TRO 3.0.5 Equipment removed from service or declared inoperable to comply with ACTIONS may be returned to service under administrative control solely to perform testing required to demonstrate its OPERABILITY, the OPERABILITY of other equipment or variables to be within limits. This is an exception to TRO 3.0.2 for the system returned to service under administrative control to perform the testing required to demonstrate

-*-*~-------========O =P=ERA=B=l=Ll=TY= .==========-= =========== =.-----

TRO 3.0.6 When a suimorted system TRO is not met solely due to a suimort system .

TRO or LCO not being met, the Conditions and Required Actions

_____________ ______ associated_with this_supported system_are__not requirec:Uo_be_entered:____ _

Only the support system TRO or LCO ACTIONS are required to be entered. This is an exception to TRO 3.0.2 for the supported system.

When a support system's Required Action directs a supported system to

- - - - ~- -- - - -1:5e aeclareo inoperableofdirectsentty into Conditions ana Requireo - -

Actions for a supported system, the applicable Conditions and Required Actions shall be entered in accordance with TRO 3.0.2 .

• SUSQUEHANNA - UNIT 1 TRM / 3.0-2

TRS Applicability Rev. 7 3.0

,' ------ -~------- ---- --- ,-----~---- --.......-L- ----- ------~---------- ---- - - - - - - - - - - -- - ---..- ---~- - - - - -

• 3.0 TECHNICAL REQUIREMENT SURVEILLANCE (TRSl APPLICABILITY TRS 3.0.1 TRS shall be met during the MODES or other specified conditions in the Applicability for indMdual TROs, unless otherwise stated in the TRS.

Failure to meet a Surveillance, whether such failure is experienced during the performance of the Surveillance or between performances of the Surveillance, shall be failure to meet the TRO. -Failure to perform a Surveillance within the specified Frequency shall be failure to meet the TRO except as provided in TRS 3.0.3. Surveillances do not have to be performed on inoperable equipment or variables outside specified limits.

TRS 3.0.2 The specified Frequency for each TRS is met if the Surveillance is performed within 1.25 times the interval specified in the Frequency, as measured from the previous performance or as measured from the time a specified condition of the Frequency is met.

For Frequencies specified as "once," the above interval extension does not apply.

If a Completion llme requires periodic performance on a "once per *... "

basis, the above Frequency extension applies to each performance after

-**----------~-th_e_ i.n_1t_ia_1_-P_*e _rf_6_rm_a_n_ce ~-~."------~--~-~-- --------

~ceptions to this Requirement are stated in the individual Requirements.

---

IRS-3.0.3-- ----- lf-itis.discovered.that.a..Surveillance.was.not.performedwtthin-its- - - - - - - -

specified Frequency, then compliance with the requirement to declare the TRO not met may be delayed, from the time of discovery, up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or up to the limit of the specified Frequency, whichever is greater. In the event it is determined that a Surveillance cannot be performed within its

- --- -----~ - --~ - ----.---- -~- - spectfiSCrFrequency, compliance with-ttie requiremenf to aeclare lheTRo-- - - --

• not met may be delayed, from the expiration of the current Surveillance test interval, up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or up to the limit of the specified Frequency, whichever is greater. This delay period is permitted to allow performance of the Surveillance. The delay period is only applicable when there is a reasonable expectation the Surveillance will be met when performed. A risk evaluation shall be performed for any Surveillance delayed greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and the risk impact shall be managed .

• SUSQUEHANNA - UNIT 1 TRM / 3.0-3

• • ---------~e~.--7 ___________________________________ ---~- ____ 3.9__

3.0 TRS Applicability TRS Applicability TRS 3.0.'3 If the Surveillance is not performed within the delay period, the TRO must (continued) immediately be declared not met, and the applicable Condition(s) must be entered.

When the Surveillance is performed within the delay period and the Surveillance .is not met, the TRO must immediately be_declared not met, and the applicable Condition(s) must be entered.

Exceptions to this Requirement are stated in the individual Requirements.

TRS 3.0.4 Entry into a MODE or other specified condition in the Applicability of a TRO shall only be made when the TRO's Surveillances have been met within their specified Frequency, except as provided by TRS 3.0.3. When a TRO is not met due to Surveillances not having been met, entry into a MODE or other specified condition in the Applicability shall only be made in accordance with TRO 3.0.4.

This provision shall not prevent entry into MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit.

-- - - ~ - --- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -

• SUSQUEHANNA - UNIT 1 TRM /3.0-4

TRO Applicability Rev. 6 B 3.0 B 3.0 TECHNICAL REQUIREMENT FOR OPERATION (TRO) APPLICABILITY BASES TROs TRO 3.0.1 through TRO 3.0.6 establish the general requirements applicable to all Requirements and apply at all times, unless otherwise stated.

TRO 3.0.1 TRO 3.0.1 establishes the Applicability statement within each individual Requirement as the requirement for when the TRO is required to be met (i.e., when the Unit is in the MODES or other specified conditions of the Applicability statement of each Requirement).

TRO 3.0.2 TRO 3.0.2 establishes that upon discovery of a failure to meet a TRO, the associated ACTIONS shall be met. The Completion Time of each Required Action for an ACTIONS Condition is applicable from the point in time that an ACTIONS Condition is entered, unless otherwise specified.

The Required Actions establish those remedial measures that must be taken within specified Completion Times when the requirements of a TRO are not met. This Requirement establishes that:

• a.

b.

Completion of the Required Actions within the specified Completion Times constitutes compliance with a Requirement; and Completion of the Required Actions is not required wheh a TRO is met within the specified Completion Time, unless otherwise specified.

There are two basic types of Required Actions. The first type of Required Action specifies a time limit in which the TRO must be met. This time limit is the Completion Time to restore an inoperable system or component to OPERABLE status or to restore variables to within specified limits. If this type of Required Action is not completed within the specified Completion Time, a shutdown may be required to place the unit in a MODE or condition in which the Specification is not applicable.

Whether stated as a Required Actfon or not, correction of the entered Condition is an action that may always be considered upon entering ACTIONS. The second type of Required Action specifies the remedial measures that permit continued operation of the unit that is not further restricted by the Completion Time. In this case, compliance with the Required Actions provides an acceptable level of safety for continued operation .

• SUSQUEHANNA - UNIT 1 TRM / B 3.0-1

TRO Applicability Rev.6 B 3.0

• • BASES TRO 3.0.2 (continued)

Completing the Required Actions is not required when a TRO is met or is no longer applicable, unless otherwise stated in the individual Requirements.

The nature of some Required Actions of some Conditions necessitates that, once the Condition is entered, the Required Actions must be completed even though the associated Conditions no longer exist. The individual TRO's Actions specify the Required Actions where this is the case. An example of this is in Technical Requirement TRO 3.4.1, "Chemistry."

The Completion Times of the Required Actions are also applicable when a system or component is removed from service intentionally. The ACTIONS for not meeting a single TRO adequately manage any increase in plant risk, provided any unusual external conditions (e.g., severe weather, offsite power,instability) are considered. In addition, the increased risk associated with simultaneous removal of multiple structures, systems, trains or components from service is assessed and managed in accordance with 10 CFR 50.65(a)(4).

Individual Requirements may specify a time limit for performing a TRS when equipment is removed from service or bypassed for testing. In this case, the Completion Times of the Required Actions are applicable when this time limit expires, if the equipment remains removed from service or bypassed.

• When a change in MODE or other specified condition is required to comply with Required Actions, the unit may enter a MODE or other specified condition in which another Requirement becomes applicable. In this case, the Completion Times of the associated Required Actions would apply from the point in time that the new Requirement becomes applicable and the ACTIONS Condition(s) are entered.

TRO 3.0.3 TRO 3.0.3 establishes the actions that must be implemented when a TRO is not met and:

a. An associated Required Action and Completion Time is not met and no other Condition applies; or

• • SUSQUEHANNA - UNIT 1 TRM / B 3.0-2

TRO Applicability Rev. 6 B 3.0 BASES TRO 3.0.3 b. The condition of the unit is not specifically addressed by the (continued) associated ACTIONS. "fhis means that no combination of Conditions stated in the ACTIONS can be made that exactly corresponds to the actual condition of the unit. Certain combinations of Conditions may exist such that entering TRO 3.0.3 is warranted; in such cases, the Actions specifically state a Condition corresponding to such combinations and also that TRO 3.0.3 be entered immediately.

Because entry into TRO 3.0.3 is an escalation of the system, structure, component, or unit condition, a Condition Report is required. The Condition Report will address plant safety given the nonconformance with the Technical Requirement TROs which affect OPERABILITY of TS Functions will have an assessment of TS OPERABILITY.

Compensatory actions and a plan for exiting TRO 3.0.3 shall be developed and implemented in a timely manner commensurate with the safety significance of the entry condition. This will allow for an orderly development of actions and plans providing for time to coordinate any actions deemed unwarranted with the station work schedule.

Planned entry into TRO 3.0.3 should be avoided. If it is not practicable to avoid planned entry into TRO 3.0.3, plant risk should be assessed and managed in accordance with 10 CFR 50.65(a)(4), and the planned entry into TRO 3.0.3 should have less effect on plant safety than other practicable alternatives. Thus, it is important to evaluate the TRO 3.0.3 entry circumstances to determine if changes to the TRO not met can be made that would preclude the need for future TRO 3.0.3 entries.

Completion of the evaluation is not required to exit TRO 3.0.3. The evaluation shall be performed even though TRO 3'.0.3 has been/will be exited.

TRO 3.0.4 TRO 3.0.4 establishes limitations on changes in MODES or other specified conditions in the Applicability when a TRO is not met. It allows placing the unit in a MODE or other specified condition stated in that Applicability (e.g., the Applicability desired to be entered) when unit conditions are such that the requirements of the TRO would not be met, in accordance with either TRO 3.0.4.a, TRO 3.0.4.b, or TRO 3.0.4.c.

TRO 3.0.4.a allows entry into a MODE or other specified condition in the Applicability with the TRO not met when the associated ACTIONS to be entered following entry into the MODE or other specified condition in the Applicability will permit continued operation within the MODE or other specffied condition for an unlimited period of time. Compliance with ACTIONS that permit continued operation of the unit for an unlimited period of time in a MODE or other specified condition provides an acceptance level of safety for continued operation. This is without regard SUSQUEHANNA - UNIT 1 TRM / B 3.0-3

TRO Applicability Rev. 6 B 3.0 BASES TRO 3.0.4 to the status of the unit before or after the MODE change. Therefore, in (continued) such cases, entry into a MODE or other specified condition in the Applicability may be made and the Required Actions followed after entry into the Applicability.

For example, TRO 3.0.4 may be used when the Required Action to be entered states that an inoperable instrument channel must be placed in the trip condition within the Completion Time. Transition into a MODE or other specified cor:idition in the Applicability may be made in accordance with TRO 3.0.4 and the channel is subsequently placed in the tripped condition within the Completion Time, which begins when the Applicability is entered. If the instrument channel cannot be placed in the tripped condition and the subsequent default ACTION ("Required Action and associated Completion Time not met") allows the OPERABLE train to be placed in operation, use of TRO 3.0.4.a is acceptable because the subsequent ACTIONS to be entered following entry into the MODE include ACTIONS (place the OPERABLE train in operation) that pennit safe plant operation for an unlimited period of time in the MODE or other specified condition to be entered.

TRO 3.0.4.b allows entry into a MODE or other specified ,condition in the Applicability with the TRO not met after perfonnance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering the MODE or other specified condition in the Applicability, and establishment of risk management actions, if appropriate.

The risk assessment may use quantitative, qualitative, or blended approaches, and the risk assessment will be conducted using the plant program, procedures, and criteria in place to implement 10 CFR 50.65(a)(4), which requires that risk impacts of maintenance activities to

, be assessed and managed. The risk assessment, for the purposes of TRO 3.0.4(b), must take into account all inoperable Technical Requir:ements Manual equipment regardless of whether the equipment is included in the normal 10 CFR 50.65(a)(4) risk assessment scope. The risk assessments will be conducted using the procedures and guidance endorsed by Regulatory Guide 1.182, ~Assessing and Managing Risk Before Maintenance Activities at Nuclear Power Plants." Regulatory Guide 1.182 endorses the guidance in Section 11 of NUMARC 93-01, "Industry Guideline for Monitorir:1g the Effectiveness of Maintenance at Nuclear Power Plants.u These documents address general guidance for conduct of the risk assessment, quantitative and qualitative guidelines for establishing risk management actions, and example risk management actions. These include actions to plan and conduct other activities in a manner that controls overall risk, increased risk awareness by shift and management personnel, actions to reduce the duratior;i of the condition, actions to minimize the magnitude of risk increases (establishment of

• SUSQUEHANNA - UNIT 1 TRM / B 3.0-4

TRO Applicability Rev. 6 B 3.0

• BASES TRO 3.0.4 (continued) backup .success paths or compensatory measures), and determination that the proposed MODE change is acceptable. Consideration should also be given to the probability of completing restoration such that the requirements of the TRO would be met prior to the expiration of ACTIONS Completlon Times that would require exiting the Applicability.

TRO 3.0.4.b may be used with single, or multiple systems and components unavailable. NU MARC 93-01 provides guidance relative to consideration of simultaneous unavailability of multiple systems and components.

The results of the risk assessment shall be considered in determining the acceptability of entering the MODE or other specified condition in the Applicability, and any corresponding risk management actions. The TRO 3.0.4.b risk assessments do not have to be documented.

The Technical Requirements allow continued operation with equipment unavailable in MODE 1 for the duration of the Completion Time. Since this is allowable, and since in general the risk impact in that particular MODE bounds the risk of transitioning into and through the applicable MODES or other specified conditions in the Applicability of the TRO, the

.use of the TRO 3.0.4.b allowance should be generally acceptable, as long

• as the risk is assessed and managed as stated above. However, the Emergency Diesel Generators (TRO 3.8.3) have been determined to be more important to risk and use of the TRO 3.0.4.b allowance is prohibited.

A note is included in TRO 3.8.3 stating that TRO 3.0.4.b is not applicable.

TRO 3.0.4.c allows entry into a MODE or other specified condition in the Applicability with the TRO not met based on a Note in the Requirement which states TRO 3.0.4.c .is applicable. These specific allowances permit entry into MODES or other specified conditions in the Applicability when the associated ACTIONS to be entered do not provide for continued operation for an unlimited period of time and a risk assessment has not been performed. This allowance may apply to all the ACTIONS or to a specific Required Action of a Requirement. The risk assessments performed to justify the use of TRO 3.0.4.b usually only consider systems and components. For this reason, TRO 3.0.4.c is typically applied to Requirements which describe values and parameters (e.g., Radioactive Liquid Process Monitoring Instrumentation), and may be applied to other Requirements based on plant-specific approval.

The provisions of this Requirement should not be interpreted as endorsing the failure to exercise the good practice of restoring systems or components to OPERABLE status before entering an associated MODE or other specified condition in the Applicability.

SUSQUEHANNA - UNIT 1 TRM / B 3.0-5

TRO Applicability Rev. 6 B 3.0

• BASES TRO 3.0.4 (continued)

The provisions of TRO 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that are required. to comply with ACTIONS. In addition, the provisions of TRO 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that result from any unit shutdown. In this context, a unit shutdown is defined as a change in MODE or other specified condition in the Applicability associated with transitioning from MODE 1 to MODE 2 or MODE 3, MODE 2 to MODE 3 or MODE 4, and MODE 3 to MODE 4.

Upon entry into a MODE or other specified condition in the Applicability with the TRO not met, TRO 3.0.1 and TRO 3.0.2 require entry into the applicable Conditions and Required Actions until the Condition is resolved, until the TRO is met, or until the unit is not within the Applicability of the Technical Requirement TRO 3.0.4 is not applicable to TROs that are identified as APPLICABLE

• At all times.* This term is considered to constitute one inclusive operating condition that corresponds to and encompasses all MODES as defined in the Technical Specification, as well as all special operating conditions, including when the reactor vessel is defueled. Enby into any MODE or other special condition is done within the context of "all times,"

and, therefore, is not a Change within the Applicability to which TRO 3.0.4 applies.

Surveillances do not have to be performed on the associated inoperable equipment (or on variables outside the specified limits), as permitted by TRS 3.0.1. Therefore, utilizing TRO 3.0.4 is not a violation of TRS 3.0.1 or TRS 3.0.4 for any Surveillances that have not been performed on inoperable equipment. However, TRSs must be met to ensure OPERABILITY prior to declaring the associated equipment OPERABLE (or variable within limits) and restoring compliance with the affected TRO.

TRO 3.0.5 TRO 3.0.5 establishes the allowance for restoring equipment to service under administrative controls when it has been removed from service or declared inoperable to comply with ACTIONS. The sole purpose of this Requirement is to provide an exception to TRO 3.0.2 (e.g., to not comply with the applicable Required Action(s) to allow the performance of TRSs to demonstrate:

a. The OPERABILITY of the equipment being returned to service; or

b. The OPERABILITY of other equipment; or

c. That variables are within limits

• SUSQUEHANNA - UNIT 1 TRM / B 3.0-6

TRO Applicability Rev. 6 B 3.0 BASES TRO 3.0.5 The administrative controls ensure the time the equipment is returned to (continued) service in conflict with the requirements of the ACTIONS is limited to the time absolutely necessary to perform the allowed TRSs. This Requirement does not provide time to perform any other preventive or corrective maintenance. TRO 3.0.5 should not be used in lieu of other practicable alternatives that comply with Required Actions and that do not require changing the MODE or other specified conditions in the Applicability in order to demonstrate equipment is OPERABLE. TRO 3.0.5 is not intended to be used repeatedly.

An example of demonstrating equipment is OPERABLE with the Required Action not met is opening a manual valve that was closed to comply with Required Actions to isolate a flowpath with excessive Reactor Coolant System (RCS) Pressure Isolation Valve (PIV) leakage in order to perform testing to demonstrate that RCS PIV leakage is now within limit.

Examples of demonstrating equipment OPERABILITY include instances in which it is necessary to take an inoperable channel or trip system out of a tripped condition that was directed by a Required Action, if there is no Required Action Note for this purpose. An example of verifying OPERABILITY of equipment removed from service is taking a tripped channel out of the tripped condition to permit the logic to function and

• indicate the appropriate response during performance of required testing on the inoperable channel. Examples of demonstrating the OPERABILITY of other equipment are taking an inoperable channel or trip system out of the tripped condition 1) to prevent the trip function from occurring during the performance of a TRS on another channel in the other trip system, or

2) to permit the logic to function and indicate the appropriate response during the performance of a TRS on another channel in the same trip system.

The administrative controls in TRO 3.0.5 apply in all cases to systems or components in Chapter 3 of the Technical Requirements Manual, as long as the testing could not be conducted while complying with the Required Actions. This includes the realignment or repositioning of redundant or alternate equipment or trains previously manipulated to comply with ACTIONS, as well as equipment removed from service or declared inoperable to comply with ACTIONS .

• SUSQUEHANNA - UNIT 1 TRM / B 3.0-7

TRO Applicability B 3.0 Rev. 6 BASES TRO 3.0.6 TRO 3.0.6 establishes an exception to TRO 3.0.2 for support systems that have a TRO or LOO specified in the Technical Requirement Specifications (TRS) or Technical Specification (TS). This exception is provided because TRO 3.0.2 would require that the Conditions and Required Actions of the associated inoperable supported system TRO be entered solely due to the i11operability of the support system. This exception is justified because the actions that are required to ensure the plant is maintained in a safe condition are specified in the support system TRO's or LCO's Required Actions. These Required Actions may include entering the supported system's Conditions and Required Actions or may specify other Required Actions.

When a support system is inoperable and there is a TRO or LCO specified for it in the TRS or TS, the supported system(s) are required to be declared inoperable if determined to be inoperable as a result of the support system inoperability. However, it is not necessary to enter into the supported systems' Conditions and Required Actions unless directed to do so by the support system's Required Actions. The potential confusion and inconsistency of requirements related to the entry into multiple support and supported systems' Conditions and Required Actions are eliminated by providing all the actions that are necessary to ensure the plant is maintained in a safe condition in the support system's

• Required Actions .

However, there are instances where a support system's Required Action may either direct a supported system to be declared inoperable or direct entry into Conditions and Required Actions for the supported system. This may occur immediately or after some specified delay to perform some other Required Action. Regardless of whether it is immediate or after some delay, when a support system's Required Action directs a supported system to be declared inoperable or directs entry into Conditions and Required Actions for a supported system, the applicable Conditions and Required Actions shall be entered in accordance with TRO 3.0.2 .

• SUSQUEHANNA - UNIT 1 TRM / B 3.0-8

TRS Applicability Rev.6 B 3.0 B 3.0 TECHNICAL REQUIREMENT SURVEILLANCE (TRS) APPLICABILITY BASES TRS TRS 3.0.1 through TRS 3.0.4 establish the general requirements applicable to all Requirements and apply at all times, unless otherwise stated.

TRS 3.0.1 TRS 3.0.1 establishes the requirementthat TRSs must be met during the MODES or other specified conditions in the Applicability for which the requirements of the TRO apply, unless otherwise specified in the individual TRSs. This Requirement is to ensure that Surveillances are performed to verify the OPERABILITY of systems and components, and that variables are within specified limits. Failure to meet a Surveillance within the specified Frequency, in accordance with TRS 3.0.2, constitutes a failure to meet a TRO.

Systems and components are assumed to be OPERABLE when the associated TRSs have been met. Nothing in this Requirement, however, is to be construed as implying that systems or components are OPERABLE when:

a. The systems or components are known to be inoperable, although still meeting the TRSs; or

b. The requirements of the Surveillance(s) are known to be not met between required Surveillance performances.

Surveillances do not have to be performed when the unit is in a MODE or other specified condition for which the requirements of the associated TRO are not applicable, unless otherwise specified.

Surveillances, fncluding Surveillances invoked by Required Actions, do not have to be performed on inoperable equipment because the ACTIONS define the remedial measures that apply. Surveillances have to be met and performed in accordance with TRS 3.0.2, prior to returning equipment to OPERABLE status. Upon completion of maintenance, appropriate post maintenance testing is required to declare equipment OPERABLE. This includes ensuring applicable Surveillances are not failed and their most recent performance is in accordance with TRS 3.0.2. Post maintenance testing may not be possible in the current MODE or other specified conditions in the Applicability due to the necessary unit parameters not having been established. In these situations, the equipment may be considered OPERABLE provided testing has bean satisfactorily completed to the extent possible and the 9C1Uipment is not otherwise believed to be SUSQUEHANNA - UNIT 1 TRM / B 3.0-9

TRS Applicability Rev. 6 B 3.0 BASES TRS 3.0.1 incapable of performing its function. This will allow operation to proceed (continued) to a MODE or other specified condition where other necessary post maintenance tests can be completed.

TRS 3.0.2 TRS 3.0.2 establishes the requirements for meeting the specified Frequency for Surveillances and any Required Action with a Completion Time that requires the periodic performance of the Required Action oh a "once per ... " interval.

TRS 3.0.2 permits a 25% extension of the interval specified in the Frequency. This extension facilitates Surveillance scheduling and considers plant operating conditions that may not be suitable for conducting the Surveillance (e.g., transient conditions or other ongoing Surveillance or maintenance actjvities).

The 25% extension does not significantly degrade the reliability that results from performing the Surveillance at its specified Frequency. This Is based on the recognition that the most probable result of any particular Surveillance being performed is the verification of conformance with the TRSs. The exceptions to TRS 3.0.2 are those Surveillances for which the 25% extension of the interval specified in the Frequency does not apply.

These exceptions are stated in the indMdual Requirements. As stated in TRS 3.0.2, the 25% extension also does not apply to the initial portion of a periodic Completion Time that requires performance on a "once per ... "

basis. The 25% extension applies to each performance after the initial performance. The initial performance of the Required Action, whether it is a particular Surveillance or some other remedial action, is considered a single action with a single Completion Time. One reason for not allowing the 25% extension to this Completion Time is that such an action usually verifies that no loss of function has occurred by checking the status of redundant or diverse components or accomplishes the function of the inoperable equipment in an alternative manner.

The provisions of TRS 3.0.2 are not intended to be used repeatedly to extend Surveillance intervals (other than those consistent with refueling intervals) or periodic Completion Time intervals beyond those specified.

TRS 3.0.3 TRS 3.0.3 establishes the fle:xibility to defer declaring affected equipment inoperable or an affected variable outside the specified limits when a Surveillance has not been perform~d within the specified Frequency. A delay period of up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or up to the limit of the specified Frequency, whichever is greater, applies from the point in 'time that it is discovered that the Surveillance has not been performed in accordance with TRS 3.0.2, and not at the time that the specified Frequency was not met.

• SUSQUEHANNA - UNIT 1 TRM / B 3.0-10

TRS Applicability Rev. 6 B 3.0

• BASES TRS 3.0.3 (continued)

If a Surveillance cannot be performed within its specified Frequency due to unusual conditions, such as a structure, system, or component configuration that prevents performance of a test, or performance of the test would have an adverse impact on plant risk, compliance with the requirement to declare the TRO not met may be delayed. This delay pedod starts at the expiration of the current Surveillance test interval.

The delay can be up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or Up to the limit of the specified Frequency, whichever is greater.

This delay period provides adequate time to perform Surveillances that have been missed. This delay period permits the performance of a Surveillance before complying with Required Actions or other remedial measures that might preclude performance of the Surveillance.

The basis for this delay period includes consideration of unit conditions, adequate planning, availability of personnel, the time required to perform the Surveillance, the safety significance of the delay in completing the required Surveillance, and the recognition that the most probable result of any particular Surveillance being performed is the verification of conformance with the requirements.

When a Surveillance with a Frequency based not on time intervals, but

• upon specified unit conditions, operating situations, or requirements of regulations (e.g., prior to entering MODE 1 after each fuel loading, or in accordance with 10 CFR 50, Appendix J, as modified by approved exemptions, etc.) is discovered to not have been performed when specified, TRS 3.0.3 allows for the full delay period of up to the specified Frequency to perform the Surveillance. However, since there is not a time interval specified, the missed Surveillance should be performed at the first reasonable opportunity.

TRS 3.0.3 provides a time limit for, and allowances for the performance of, Surveillances that become applicable as a consequence of MODE changes imposed by Required Actions.

TRS 3.0.3 is only applicable if there is a reasonable expectation the associated equipment is OPERABLE or that variables are within limits, and it is eXpected that the Surveillance will be met when performed. Many factors should be considered, such as the period of time since the Surveillance was last performed, or whether the Surveillance, or a portion thereof, has ever been performed, and any other indications, tests, or actMties that might support the expectation that the Surveillance will be met when performed. An example of the use of TRS 3.0.3 would be a relay contact that was not tested as required in accordance with a particular TRS, but previous successful performances of the TRS included the relay contact; the adjacent, physically connected relay contacts were tested during the TRS performance; the subject relay

• SUSQUEHANNA - UNIT 1 TRM / 8 3.0-11

TRS Applicability Rev. 6 13 3.0

• BASES TRS 3.0.3 (continued) contact has been tested by another TRS; or historical operation of the subject relay contact has been successful. It is not sufficient t0 infer the behavior of the associated equipment from the performance of similar equipment. The rigor of determining whether there is a reasonable expectation a Surveillance will be met when performed should increase based on the length of time since the last performance of the Surveillance ..ff the Surveillance has been performed recently, a review of the Surveillance history and equipment performance may be sufficient to support a reasonable eXpectation that the Surveillance will be met when performed. For Surveillances that have not been performed for a long period or that have never been performed, a rigorous evaluation based on objective evidence should provide a high degree of confidence that the equipment is OPERABLE. The evaluation should be documented in sufficient detail to allow a knowledgea.ble individual to understand the basis for the determination.

Failure to comply with specified Frequencies for TRSs is expected to be an infrequent occurrence. Use of the delay period established by TRS 3.0.3 is a flexibility which is not intended to be used repeatedly to extend Surveillance intervals. While up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or the limit of the specified Frequency is provided to perform the missed Surveillance, it is expected that the missed Surveillance will be performed at the first reasonable

• opportunity. The determination of the first reasonable opportunity should include consideration of the impact on plant risk (from delaying the Surveillance as well as any plant configuration changes required or shutting the plant down to perform the Surveillance) and impact on any analysis assumptions, in addition to unit conditions, planning, a1Jailability of personnel, and the time required to perform the Surveillance. This risk impact should be managed through the program in place to implement 10 CFR 50.65(a)(4) and its implementation guidance, NRC Regulatory Guide 1.182, "Assessing and Managing Risk Before Maintenance Activities at Nuclear Power Plants.n This Regulatory Guide addresses consideration of temporary and aggregate risk impacts, determination of risk management action thresholds, and risk management action up to and including plant shutdown. The missed Surveillance should be treated as an emergent condition as discussed in the Regulatory Guide. The risk evaluation may use quantitative, qualitative, or blended methods. The degree of depth and rigor of the evaluation should be commensurate with the importance of the component. Missed Surveillances for important components should be analyzed quantitatively. If the results of the risk evaluation determine the risk increase is significant, this evaluation should be used to determine the safest course of action. All Surveillances whose Frequency has been extended in accordance with TRS 3.0.3 will be placed in the Corrective Action Program.

• • SUSQUEHANNA - UNIT 1 TRM / B 3.0-12

TRS Applicability Rev.6 B 3.0

• BASES TRS 3.0.3 (continued)

If a Surveillance is not completed within the allowed delay period, then the equipment is considered inoperable or the variable is considered outside the specified limits and the Completion Times of the Required Actions for the applicable TRO Conditions begin immediately upon expiration of the delay period. If a Surveillance is failed within the delay period, then the equipment is inoperable, or the variable is outside the specified limits and the Completion Times of the Required Actions for the applicable TRO Conditions begin immediately upon the failure of the Surveillance.

Completion of the Surveillance within the delay period allowed by this Requirement, or within the Completion Time of the ACTIONS, restores compliance with TRS 3.0.1.

Exceptions to TRS 3.0.3 are provided in instances where requiring equipment to be considered inoperable, in accordance with TRS 3.0.3, would not provide appropriate remedial measures for the associated condition. An example of this is in TRO 3.11.4.1, "Radiological Environmental Monitoring.~ TRO 3.11.4.1 has surveillances that implement required environmental sampling and analysis. If a portion of the sampling or analysis is not completed as required, the programmatic response is to report the condition to the Nuclear Regulatory Commission and in most instances describe the corrective actions taken to correct the condition. There are no result thresholds built into the monitoring and analysis program that would result in declaring equipment inoperable or in a plant shutdown. Therefore, it is appropriate that the provisions of TRO 3.0.3 be waived for this TRO. These exceptions are addressed in the individual Requirements.

TRS 3.0.4 TRS 3.0.4 establishes the requirement that all applicable TRSs must be met before entry into a MODE or other specified condition in the Applicability. This Requirement ensures that system and component OPERABILITY requirements and variable limits are met before entry into MODES or other specified conditions in the Applicability for which these systems and components ensure safe operation of the unit.

The provisions of this Requirement should not be interpreted as endorsing the failure to exercise the good practice of restoring systems or components to OPERABLE status before entering an associated MODE or other specifi~ condition in the Applicability.

A provision is included to allow entry into a MODE or other specified condition in the Applicability when a TRO is not met due to Surveillance not being met in accordance with TRO 3.0.4 .

• SUSQUEHANNA - UNIT 1 TRM / B 3.0-13

TRS Applicability Rev. 6 B 3.0

• BASES TRS 3.0.4 (continued)

However, in certain circumstances, failing to meet a TRS will not result in TRS 3.0.4 restricting a MODE change or other specified condition change. When a system, subsystem, division, component, device, or variable is inoperable or outside its specified limits, the associated TRS(s) are not required to be performed per TRS 3.0.1, which states that Surveillances do not have to be performed on inoperable equipment.

When equipment Is inoperable, TRS 3.0.4 does not apply to the associated TRS(s) since the requirement for the TRS(s) to be performed is removed.

Therefore, failing to perform the Surveillance(s) within the specified Frequency does not result in an TRS 3.0.4 resbiction to changing MODES or other specified conditions of the Applicability. However, since the TRO is not met in this instance, TRO 3.0.4 will govern any restrictions that may (or may not) apply to MODE or other specified condition changes. TRS 3.0.4 does not restrict changing MODES or other specified conditions of the Applicability when a Surveillance has not been performed within the specified Frequency, provided the requirement to declare the TRO not met has been delayed in accordance with TRS 3.0.3.

The provisions of TRS 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS. In addition, the provisions of TRO 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that result from any unit shutdown. In this context, a unit shutdown is defined as a change in MODE or other specified condition in the Applicability associated with transitioning from MODE 1 to MODE 2 or MODE 3, MODE 2 to MODE 3 or MODE 4, and MODE 3 to MODE 4.

The precise requirements for performance of TRSs are specified such that exceptions to TRS 3.0.4 are not necessary. The specific time frames and conditions necessary for meeting the TRSs are specified in the Frequency, in the Surveillance, or both.

This allows performance of Surveillances when the prerequisite condition(s) specified in a Surveillance procedure require entry into the MODE or other specified condition in the Applicability of the associated TRO prior to the performance or completion of a Surveillance. A Surveillance that could not be performed until after entering the TRO Applicability would have its Frequency specified such that it is not "due" until the specific conditions needed are met. Alternately, the Surveillance may be stated in the form of a Note as not required (to be met or performed) until a particular event, condition, or time has been reached.

Further discussion of the specific formats of TRS's annotation is found in Section 1.4, Frequency.

SUSQUEHANNA - UNIT 1 TRM / B 3.0-14

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• Table Of Contents Issue Date: 03/18/2021 Procedure Name Rev Issue Date Change ID Change Number TEXT LOES 99 01/03/2019

Title:

LIST OF EFFECTIVE SECTIONS TEXT TOC 27 03/05/2019

Title:

TABLE OF CONTENTS TEXT 1.1 0 11/19/2002

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USE AND APPLICATION DEFINITIONS TEXT 2.1 1 02/04/2005 A ~

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Title:

CORE OPERATING LIMITS REPORT (COLR)

Page 1 of 15 Report Date: 03/19/21

ii SSES MANUAL Manual Name: TRM2

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Title:

INSTRUMENTATION RADIATION MONITORING INSTRUMENTATION TEXT 3.3.2 3 03/31/2011

Title:

INSTRUMENTATION SEISMIC MONITORING INSTRUMENTATION TEXT 3.3.3 2 11/09/2007

Title:

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Title:

INSTRUMENTATION TRM POST-ACCIDENT MONITORING INSTRUMENTATION TEXT 3.3.5 0 11/19/2002

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TECHNICAL REQUIREMENTS MANUAL UNIT 2 TEXT 3.4.1 1 04/26/2006

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Title:

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Title:

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Title:

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Title:

REACTOR COOLANT SYSTEM REACTOR VESSEL MATERIALS

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Title:

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TECHNICAL REQUIREMENTS MANUAL.UNIT 2 TEXT 3.6.4 0 11/19/2002

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CONTAINMENT PRIMARY CONTAINMENT CLOSED SYSTEM BOUNDARIES TEXT 3.7.1 0 11/19/2002

Title:

PLANT :SYSTEMS EMERGENCY SERVICE WATER SYSTEM (ESW) SHUTDOWN TEXT 3.7.2 0 11/19/2002

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PLANT SYSTEMS SOLID RADWASTE SYSTEM Page 4 of 15 Report Date: 03/19/21

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Title:

PLANT SYSTEMS MAIN CONDENSER OFFGAS EXPLOSIVE GAS MIXTURE TEXT 3.7.5.3 1 04/26/2006

Title:

PLANT SYSTEMS LIQUID HOLDUP TANKS TEXT 3.7.6 3 06/04/2012

Title:

PLANT SYSTEMS ESSW PDMPHOUSE VENTILATION TEXT 3.7.7 2 09/05/2008

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Title:

PLANT SYSTEMS TEXT 3.8.1 3 06/20/2012

Title:

ELECTRICAL POWER PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES TEXT 3.8.2.1 2 11/09/2007

Title:

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Title:

ELECTRICAL POWER 24 VDC ELECTRICAL SUBSYSTEM TEXT 3.8.5 1 11/14/2013

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Title:

ELECTRICAL POWER EMERGENCY SWITCHGEAR ROOM COOLING TEXT 3.8.7 3 02/25/2021

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Title:

RADIOACTIVE EFFLUENTS,INTERLABORATORY COMPARISON PROGRAM TEXT 3.12.1 0 11/19/2002

Title:

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Title:

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Title:

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INSTRUMENTATION BASES LPRM UPSCALE ALARM INSTRUMENTATION TEXT B3.3.10 3 02/22/2012

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INSTRUMENTATION BASES REACTOR RECIRCULATION PUMP MG SET STOPS

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Title:

INSTRUMENTATION BASES MVP ISOLATION INSTRUMENTATION TEXT B3.3.12 1

Title:

WATER MONITORING INSTRUMENTATION 04/02/2019 TEXT B3.4.l 0 11/19/2002

Title:

REACTOR COOLANT S,,YSTEM BASES REACTOR COOLANT SYSTEM CHEMISTRY TEXT B3.4.2 1 04/16/2009

Title:

REACTOR COOLANT SYSTEM BASES STRUCTURAL INTEGRITY TEXT B3.4.3 1 11/09/2007

Title:

REACTOR COOLANT SYSTEM BASES HIGH/LOW PRESSURE INTERFACE LEAKAGE MONITOR TEXT B3.4.4 1 01/03/2019

Title:

REACTOR COOLANT SYSTEM BASES REACTOR RECIRCULATION FLOW AND ROD LINE LIMIT I

TEXT B3.4.5 0 11/19/2002 Page 10

Title:

REACTOR COOLANT SYSTEM BASES REACTOR VESSEL MATERIALS of 15 Report Date: 03/19/21

SSES MANUAL Manual Name: TRM2

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Title:

TECHNICAL *REQUIREMENTS MANUAL UNIT 2 TEXT B3.4.6 2 01/03/2019

Title:

REACTOR RECIRCULATION SINGLE LOOP OPERATION SLO FLOW RATE RESTRICTION TEXT B3.5.l 2 03/17/2020

Title:

ECCS RPV WATER INVENTORY CONTROL AND RCIC SYSTEM ADS MANUAL INHIBIT TEXT B3.5.2 2 03/05/2019

Title:

ECCS RPV WATER INVENTORY CONTROL AND RCIC SYSTEM ECCS RPV WATER INVENTORY CONTROL AND RCIC MONITORING INSTRUMENTATION TEXT B3.5.3 2 03/05/2019

Title:

ECCS RPV WATER INVENTORY CONTROL AND RCIC SYSTEM LONG TERM NITROGEN SUPPLY TO ADS TEXT B3.6.l 0 11/19/2002

Title:

CONTAINMENT BASES VENTING OR PURGING

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Title:

CONTAINMENT BASES SUPPRESSION CHAMBER-TO-DRYWELL VACUUM BREAKER POSITION INDICATION TEXT B3.6.3 1 04/19/2007

Title:

CONTAINMENT BASES SUPPRESSION POOL ALARM INSTRUMENTATION TEXT B3.6.4 1 12/14/2004

Title:

CONTAINMENT BASES PRIMARY CONTAINMENT CLOSED SYSTEM BOUNDARIES TEXT B3.7.1 0 11/19/2002

Title:

PLANT SYSTEMS BASES EMERGENCY SERVICE WATER SYSTEM (SHUTDOWN)

TEXT B3.7.2 0 11/19/2002

Title:

PLANT SYSTEMS BASES ULTIMATE HEAT SINK (UHS) GROUND WATER LEVEL TEXT B3.7.3.1 4 02/16/2017

Title:

PLANT SYSTEMS BASES FIRE SUPPRESSION WATER SUPPLY SYSTEM 2 04/26/2006 TEXT B3.7.3.2

Title:

PLANT SYSTEMS BASES SPRAY AND SPRINKLER SYSTEMS Page 11 of 15 Report Date: 03/19/21

SSES MANUAL Manual Name: TRM2

'!anual

Title:

TECIDIICAL REQUIREMENTS MANUAL UNIT 2 TEXT B3.7.3.3 0 11/19/2002

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Title:

PLANT SYSTEMS BASES CO2 SYSTEMS TEXT B3.7.3.4 3 06/19/2019

Title:

PLANT SYSTEMS BASES HALON SYSTEMS TEXT B3.7.3.5 1 04/26/2006

Title:

PLANT SYSTEMS BASES FIRE HOSE STATIONS TEXT B3.7.3.6 1 04/26/2006

Title:

PLANT SYSTEMS BASES YARD FIRE HYDRANTS AND HYDRANT HOSE HOUSES TEXT B3.7.3.7 0 11/19/2002

Title:

PLANT SYSTEMS BASES FIRE RATED ASSEMBLIES

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Title:

PLANT SYSTEMS BASES FIRE DETECTION INSTRUMENTATION TEXT B3.7.4 0 11/19/2002

Title:

PLANT SYSTEMS BASES SOLID RADWASTE SYSTEM TEXT B3.7.5.l 0 11/19/2002

Title:

PLANT SYSTEMS BASES MAIN CONDENSER OFFGAS HYDROGEN MONITOR TEXT B3.7.5.2 0 11/19/2002

Title:

PLANT SYSTEMS BASES MAIN CONDENSER OFFGAS EXPLOSIVE GAS MIXTURE TEXT B3.7.5.3 0 11/19/2002

Title:

PLANT SYSTEMS BASES LIQUID HOLDUP TANKS TEXT B3.7.6 4 06/04/2013

Title:

PLANT SYSTEMS BASES ESSW PUMPHOUSE VENTILATION TEXT B3.7.7 2 01/31/2008 Page 12

Title:

PLANT SYSTEMS BASES MAIN CONDENSER OFFGAS PRETREATMENT LOGAR,ITHMIC RADIATION of MONITORING INSTRUMENTATION 15 Report Date: 03/19/21

SSES MANUAL Manual Name: TRM2

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Title:

TECHNICAL REQUIREMENTS MANUAL UNIT 2 TEXT B3.7.8 4 01/31/2014

Title:

PLANT SYSTEMS BASES SNOBBERS TEXT B3.7.9 3 03/05/2019

Title:

PLANT SYSTEMS BASES CONTROL STRUC"ITJRE HVAC TEXT B3.7.10 1 12/14/2004

Title:

PLANT SYSTEMS BASES SPENT FUEL STORAGE POOLS TEXT B3.7.11 3 11/01/2018

Title:

STRUCTURAL INTEGRITY TEXT B3.8.l 2 03/10/2010

Title:

ELECTRICAL POWER BASES PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES

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Title:

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CONTINUOUS TEXT B3.8.2.2 1 09/17/2004

Title:

ELECTRICAL POWER BASES MOTOR OPERATED VALVES (MOV) THERMAL OVERLOAD PROTECTION -

AUTOMATIC TEXT B3.8.3 0 11/19/2002

Title:

ELECTRICAL POWER BASES DIESEL GENERATOR (DG) MAINTENANCE ACTIVITIES TEXT B3.8.4 0 11/19/2002

Title:

ELECTRICAL POWER BASES 24 VDC ELECTRICAL POWER SUBSYSTEM TEXT B3.8.5 1 11/14/2013

Title:

ELECTRICAL POWER BASES DEGRADED VOLTAGE PROTECTION TEXT B3.8.6 4 03/05/2019

Title:

ELECTRICAL POWER BASES EMERGENCY,pWITCHGEAR ROOM COOLING TEXT B3.8.7 3 02/25/2021

• Titl~: BATTERY MAINTENANCE AND MONITORING PROGRAM Page 13 of 15 Report Date: 03/19/21

SSES MANITAL Manual Name: TRM2

!anual

Title:

TECHNICAL REQUIREMENTS MANUAL UNIT 2 TEXT B3.9.1 0 11/19/2002

Title:

REFUELING OPERATIONS BASES DECAY TIME TEXT B3.9.2 0 11/19/2002

Title:

REFUELING OPERATIONS BASES COMMONICATIONS f

TEXT B3.9.3 1 03/12/2019

Title:

REFUELING OPERATIONS BASES REFUELING PLATFORM TEXT B3.10.l 0 11/19/2002

Title:

MISCELLANEOUS BASES SEALED SOURCE CONTAMINATION TEXT B3.10.2 1 04/10/2007

Title:

MISCELLANEOUS BASES SHUTDOWN MARGIN TEST RPS INSTRUMENTATION

,EXT B3 .10. 3 _ - 2 10/17 /201_9

Title:

MISCELLANEOUS BASES INDEPENDENT SPENT FUEL STORAGE INSTALLATION (ISFSI)

TEXT B3.11.1.1 1 05/10/2016

Title:

RADIOACTIVE EFFLUENTS BASES LIQUID EFFLUENTS CONCENTRATION TEXT B3 .11.1. 2 0 11/19/2002

Title:

RADIOACTIVE EFFLUENTS BASES LIQUID EFFLUENTS DOSE I

TEXT B3.ll.1.3 0 11/19/2002

Title:

RADIOACTIVE EFFLUENTS BASES LIQUID WASTE TREATMENT SYSTEM TEXT B3 . 11 . 1. 4 0 11/19/2002

Title:

RADIOACTIVE EFFLUENTS BASES LIQUID RADWASTE EFFLUENT MONITORING INSTRUMENTATION TEXT B3 .11.1. 5 0 11/19/2002

Title:

RADIOACTIVE EFFLUENTS BASES RADIOACTI;v:E LIQUID PROCESS MONITORING INSTRUMENTATION TEXT B3 .11. 2 .1 1 12/14/2004 Page 14

Title:

RADIOACTIVE EFFLUENTS BASES DOSE RATE of 15 Report Date: 03/19/21

SSES MANUAL Manual Name: TRM2

.!anual

Title:

TECHNICAL REQUIREMENTS MANUAL UNIT 2 TEXT B3 . 11. 2 . 2 0 11/19/2002

Title:

RADIOACTIVE EFFLUENTS BASES DOSE - NOBLE GASES TEXT B3.ll.2.3 0 11/19/2002

Title:

RADIOACTIVE EFFLUENTS BASES DOSE - IODINE, TRITIUM, AND RADIONUCLIDES JN PARTICULATES FORM TEXT B3.ll.2.4 0 11/19/2002

Title:

RADIOACTIVE EFFLUENTS BASES GASEOUS RADWASTE TREATMENT SYSTEM TEXT B3.ll.2.5 5 07/03/2013

Title:

RADIOACTIVE EFFLUENTS BASES VENTILATION EXHAUST TREATMENT SYSTEM TEXT B3 .11. 2. 6 2 09/08/2016

Title:

RADIOACTIVE EFFLUENTS BASES RADIOACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION

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RADIOACTIVE EFFLUENTS BASES MONITORING PROGRAM TEXT B3 .11.4. 2 0 11/19/2002

Title:

RADIOACTIVE EFFLUENTS BASES LAND USE CENSUS TEXT B3.ll.4.3 0 11/19/2002

Title:

RADIOACTIVE EFFLUENTS BASES INTERLABORATORY COMPARISON PROGRAM TEXT B3.12.l 1 10/04/2007

Title:

LOADS CONTROL PROGRAM BASES CRANE TRAVEL-SPENT FUEL STORAGE POOL TEXT B3.12.2 1 12/03/2010

Title:

LOADS CONTROL PROGRAM BASES HEAVY LOADS REQUIREMENTS 11/19/2002 TEXT B3.12.3 0

Title:

LOADS CONTROL PROGRAM BASES LIGHT LOADS REQUIREMENTS Page 15 of 15 Report Date: 03/19/21

TRO Applicability Rev. 8 3.0

• 3.0 TECHNICAL REQUIREMENT FOR OPERATION (TRO) APPLICABILITY TRO 3.0.1 TROs shall be met during the MODES ot other specified conditions in the Applicability, except as provided in TRO 3.0.2.

TRO 3.0.2 Upon discovery of a failure to meet an TRO, the Required Actions of the associated Conditions shall be met, except as provided in TRO 3.0.5 and TRO 3.0.6.

If the TRO is met or is no longer applicable prior to expiration of the specified Completion Time(s), completion of the Required Action(s) is *not required, unless otherwise stated.

TRO 3.0.3 When a TRO is not met, and the associated ACTIONS are not met, an associated ACTION is not provided, or if directed by the associated ACTIONS, the following actions shall be taken:

1. Take compensatory actions as warranted for exiting TRO 3.0.3 commensufate with the safety significance of the condition.

Development and implementation of the compensatory actions and plan for exit of TRO 3.0.3 shall be pursued without delay and ih a

• • 2.

controlled manner and shall be documented in the TRO 3.0.3 entry Condition Report.

Initiate a TRO 3.0.3 entry Condition Report to document and appropriately evaluate the issue.

When corrective measures are completed that permit operation in accordance with the TRO or the TRO actions, completion of the compensatory actions and plan for exiting TRO 3.0.3 is not .required.

TRO 3.0.4 When a TRO is not met, entry into a MODE or other specified condition in the Applicability shall only be made:

a. When the associated ACTIONS to be entered permit continued operation in the MODE or other specified condition in the Applicability for an unlimited period of time;

b. After performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering the MODE or other specified condition in the Applicability, and establishment of risk management actions, if appropriate (exceptions to this Requirement are stated in the individual TROs); or

• SUSQUEHANNA - UNIT 2 TRM / 3.0-1

TRO Applicability Rev. 8 3.0

• 3.0 TRO APPLICABILITY TRO 3.0.4 (continued)

c. When an allowance is stated in the indMdual value, parameter, or other Requirement.

This Requirement shall not prevent changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit.

TRO 3.0.5 Equipment removed from service or declared inoperable to comply with ACTIONS may be returned to service under administrative control solely to perform testing required to demonstrate its OPERABILITY, the OPERABILITY of other equipment or variables to be within limits. This is an exception to TRO 3.0.2 for the system returned to service under administrative control to perform the testing required to demonstrate OPERABILITY.

TRO 3.0.6 When a supported system TRO is not met solely due to a support system TRO or LCO not being met, the Conditions and Required Actions associated with this supported system are not required to be entered.

Only the support system TRO or LCO ACTIONS are required to be entered. This is an exception to TRO 3.0.2 for the supported system .

• When a support system's Required Action directs a supported system to be declared inoperable or directs entry into Conditions and Required Actions for a supported system, the applicable Conditions and Required Actions shall be entered in accordance with TRO 3.0.2 .

• SUSQUEHANNA - UNIT 2 TRM / 3.0-2

TRS Applicability Rev. 8 3.0

• 3.0 TECHNICAL REQUIREMENT SURVEILLANCE (TRS) APPLICABILITY TRS 3.0.1 TRS shall be met during the MODES or other specified conditions in the Applicability for individual TROs, unless otherwise stated In the TRS.

Failure to meet a Surveiiiance, whether such failure is experienced during the perfonnance of the Surveillance or between perfonnances of the Surveillance, shall be failure to meet the TRO. Failure to perfonn a Surveillance within the specified Frequency shall be failure to meet the TRO except as provided in TRS 3.0.3. Surveillances do not have to be performed on inoperable equipment or variables outside specified limits.

TRS 3.0.2 The specified Frequency for each TRS is met if the Surveillance is performed within 1.25 times the interval specified in the Frequency, as measured from the previous performance or as measured from the time a specified condition of the Frequency is met.

For Frequencies specified as "once," the above interval extension does not apply.

If a Completion Time requires periodic performance on a "once per ... "

basis, the above Frequency extension applies to each performance after the initial perfonnance .

• TRS 3.0.3 Exceptions to this Requirement are stated in the individual Requirements.

If it is discovered that a Surveillance was not performed within its specified Frequency, then compliance with the requirement to declare the TRO not met may be delayed, from the time of discovery, up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or up to the limit of the specified Frequency, whichever is greater. In the event it is determined that a Surveillance cannot be perfonned within its specified Frequency, compliance with the requirement to declare the TRO not met may be delayed, from the expiration of the current Surveillance test interval, up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or up to the limit of the specified Frequency, whichever is greater. This delay period is pennitted to allow performance of the Surveillance. The delay period is only applicable when there is a reasonable expectation the Surveillance will be met when perfonned. A risk evaluation shall be performed for any Surveillance delayed greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and the risk impact shall be managed.

SUSQUEHANNA - UNIT 2 TRM / 3.0-3

TRS Applicability Rev.8 3.0 3.0 TRS Applicability TRS 3.0.3 If the Surveillance is not performed within the delay period, the TRO must (continued) immediately be declared not met, and the applicable Condition(s) must be entered.

When the Surveillance is perfonned within the delay period and the Surveillance is not met, the TRO must immediately be declared not met, and the applicable Condition(s) must be entered.

Exceptions to this Requirement are stated in the individual Requirements.

TRS 3.0.4 Enby into a MODE or other specmed condition in the Applicability of a rRo shall only be made when the TRO's Surveillances have been met within their specified Frequency, except as provided by TRS 3.0.3. When a TRO is not met due to Surveillances not having been met, enby into a MODE or other specified condition in the Applicability shall only be made in accordance with TRO 3.0.4.

This provision shall not prevent enby into MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are _part of a shutdown of the unit.

SUSQUEHANNA - UNIT 2 TRM / 3.0-4

TRO Applicability Rev. 7 B 3.0

• B 3.0 TECHNICAL REQUIREMENT FOR OPERATION (TRO) APPLICABILITY BASES TROs TRO 3.0.1 through TRO 3.0.6 establish the general requirements .

applicable to all Requirements and apply at all times, unless otherwise stated.

TRO 3.0.1 TRO 3.0.1 establishes the Applicability statement within each indMdual Requirement as the requirement for when the TRO is required to be met (i.e., when the unit is in the MODES or other specified conditions of the Applicability statement of each Requirement).

TRO 3.0.2 TRO 3.0.2 establishes that upon discovery of a failure to meet a TRO, the associated ACTIONS shall be met. The Completion Time of each Required Action for an ACTIONS Condition is applicable from the point in time that an ACTIONS Condition is entered, unless otherwise specified.

The Required Actions establish those remedial measures that must be taken within specified Completion Times when the requirements of a TRO are not met. This Requirement establishes that:

• a.

b.

Completion of the Required Actions within the specified Completion Times constitutes compliance with a Requirement; and Completion of the Required Actions is not required when a TRO is met within the specified Completion Time, unless otherwise specified.

There are two basic types of Required Actions. The first type of Required Action specifies a time limit in which the TRO must be met. This time limit is the Completion Time to restore an inoperable system or component to OPERABLE status or to restore variables to within specified limits. If this type of Required Action is not completed within the specified Completion Time, a shutdown may be required to place the unit in a MODE or condition In which the Specification is not applicable.

Whether stated as a Required Action or not, correction of the elltered Condition is an action that may always be considered upon entering ACTIONS. The second type of Required Action specifies the remedial measures that permit continued operation of the unit that Is not further restricted by the Completion Time.* In this case, compliance with the Required Actions provides an acceptable level of safety for continued operation .

• SUSQUEHANNA - UNIT 2 TRM / B 3.0-1

TRO Applicability Rev. 7 B 3.0

• BASES TRO 3.0.2 (continued)

Completing the Required Actions is not required when a TRO is met or is no longer applicable, unless otherwise stated in the individual Requirements.

The nature of some Required Actions of some Conditions necessitates that, once the Condition Is entered, the Required Actions must be completed even though the associated Conditions no longer exist. The individual TRO's Actions specify the Required Actions where this is the case. An example of this is in Technical Requirement TRO 3.4.1, "Chemistry."

The CompletiOn Times of the Required Actions are also applicable when a system or component is removed from service intentionally. The ACTIONS for not meeting a single TRO adequately manage any increase in plant risk, provided any unusual external conditions (e.g., severe weather, offsite power instability) are considered. In addition, the increased risk associated with simultaneous removal of multiple structures, systems, trains or components from service is assessed and managed in accordance with 10 CFR 50.65(a)(4).

• Individual Requirements may specify a time limit for perfonning a TRS when equipment is removed from service or bypassed for testing. In this

• case, the Completion Times of the Required Actions are applicable when this time limit. expires, if the equipment remains removed from service or bypassed.

When a change in MODE or other specified condition is required to comply with Required Actions, the unit may enter a MODE or other specified condition in which another Requirement becomes applicable. In this case, the Completion Times of the associated Required Actions would apply from the point in time that the new Requirement becomes applicable and the ACTIONS Condition(s) are entered.

TRO 3.0.3 TRO 3.0.3 establishes the actions that must be implemented when a TRO is not met and:

a. An associated Required Action and Completion Time is not met and no other Condition applies; or SUSQUEHANNA - UNIT 2 TRM / B 3.0-2

TRO Applicability Rev. 7 83.0 I

• BASES TRO 3.0.3 (continued)

b. The condition of the unit is not specifically addressed by the associated ACTIONS. This means that no combination of Conditions stated in the ACTIONS can be made that exactly corresponds to the actual condition of the unit. Certain combinations of Conditions may exist such that entering TRO 3.0.3 is warranted; In such cases, the Actions specifically state a Condition corresponding to such combinations and also that TRO 3.0.3 be entered immediately.

Because entry into TRO 3.0.3 is an escalation of the system, structure, component, or unit condition, a Condition Report is required. The Condition Report will address plant safety given the nonconformance with the Technical Requirement TROs which affect OPERABILITY of TS Functions will have an assessment of TS OPERABILITY.

Compensatory actions and a plan for exiting TRO 3.0.3 shall be developed and implemented in a timely rnanner commensurate with the safety significc!nce of the entry condition. This will .allow for an orderly development of actions and plans providing for time to coordinate any actions deemed unwarranted with the station work schedule.

Planned entry into TRO 3.0.3 should be avoided. If it is not practicable to avoid planned entry into TRO 3.0._3, plant risk should be assessed and

• managed In accordance with 10 CFR 50.65(a)(4), and the planned entry into TRO 3.0.3 should have less effect on plant safety than other .

practicable alternatives. Thus, it is important to evaluate the TRO 3.0.3 entry Circumstances to determine if changes to the TRO not met can be made that would preclude the need for Mure TRO 3.0.3 enbies.

Completion of the evaluation is not required to exit TRO 3.0.~. The evaluation shall be performed even though TRO 3.0.3 has been/will be exited.

TRO 3.0.4 TRO 3.0.4 establishes limitations on changes in MODES or other specified conditions in the Applicability when a TRO is not met. It allows placing the unit in a MODE or other specified condition stated in that Applicability (e.g., the Applicability desired to be entered) when unit conditions are such that the requirements of the TRO would not be met, in accordance with either TRO 3.0.4.a, TRO 3.0.4.b, or TRO 3.0.4.c.

TRO 3.0.4.a allows entry into a MODE or other specified condition in the Applicability with the TRO not met when the associated ACTIONS to be entered following entry into the MODE or other specified condition in the Applicability will permit continued operation within the MODE or other specified condition for an unlimited period of time. Compliance with ACTIONS that permit continued operation of the unit for an unlimited period of time in a MODE or other specified condition provides an acceptance. level of safety for continued operation. This is without regard SUSQUEHANNA - UNIT 2 TRM / B 3.0-3

TRO Applicability Rev. 7 83.0 BASES TRO 3.0.4 to the status of the unit before or after the MODE change. Therefore, In (continued) such cases, entry Into a MODE or other specified condition in the Applicability may be made and the Required Actions followed after entry into the Applicability. *

• For example, TRO 3.0.4 may be used when the Required Action to be entered states that an Inoperable Instrument channel must be placed in the trip condition within the Completion Time. Transition into a MODE or other specified condition in the Applicability may be made in accordance with TRO 3.0.4 and the channel is subsequently placed in the tripped condition within the Completion Time, which begins when the Applicability is entered. If the instrument channel cannot be placed in the tripped condition and the subsequent default ACTION ("Required Action and associated Completion Time not met") allows the OPERABLE train to be placed in operation, use of TRO 3.0.4.a is acceptable because the subsequent ACTIONS to be entered following entry into the MODE include ACTIONS (place the OPERABLE train in operation) that permit safe plant operation for an unlimited period of time in the MODE or other specified condition to be entered.

TRO 3.0.4.b allows entry into a MODE or other specified condition in the Applicability with the TRO not met after performance of a risk assessment

• addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering the MODE or other specified condition in the Applicability, and establishment of risk management actions, tf appropriate.

The risk assessment may use quantitative, qualitative, or blended approaches, and the risk assessment will be conducted using the plant program, procedures, and criteria in place to implement 10 CFR 50.65(a)(4), which requires that risk impacts of maintenance activities to be assessed and managed. The risk assessment, for the purposes of TRO 3.0.4(b), must take into account all inoperable Technical Requirements Manual equipment regardless of whether the equipment is included in tile normal 10 CFR 50.65(a)(4) risk assessment scope. The risk assessments Will be conducted using the procedures and guidance endorsed by Regulatory Guide 1.182, MAssessing and Managing Risk Before Maintenance Activities at Nuclear Power Plants." Regulatory Guide 1.182 endorses the guidance in Section 11 of NUMARC 93-01, "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants." These documents address general guidance for conduct of the risk assessment, quantitative and qualitative guidelines for establishing risk management actions, and example risk management actions .. These include actions to plan ~nd conduct other activities in a manner that controls overall risk, increased risk awareness by shift and management personnel, actions to reduce the duration of the condition, actions to minimize the magnitude of risk increases (establishment of SUSQUEHANNA - UNIT 2 TRM / 83.0-4

TRO Applicability B 3.0 Rev. 7 BASES TRO 3.0.4 backup success paths or compensatory measures), and determination (continued) that the proposed MODE change is acceptable. Consideration should also be given to the probability of completing restoration such that the requirements of the TRO would be met prior to the expiration of ACTIONS Completion Times that would require exiting the Applicability.

TRO 3.0.4.b may be used with single, or multiple systems and components unavailable. NUMARC 93-01 provides guidance relative to consideration of simultaneous unavailability of multiple systems and components.

• The results of the risk assessment shall be considered in determining the acceptability of entering the MODE or other specified condition in the Applicability, and any corresponding risk management actions. The TRO 3.0.4.b risk assessments do not have to be documented.

The Technical Requirements allow continued operation with equipment unavailable in MODE 1 for the duration of the Completion Time. Since this is allowable, and since in general the risk impact in that particular MODE bounds the risk of transitioning into and through the applicable MODES or other specified conditions in the Applicability of the TRO, the use of the TRO 3.0.4.b allowance should be generally acceptable, as long as the risk is assessed afld managed as stated above. However, the Emergency Diesel Generators (TRO 3.8.3) have been determined to be more important to risk and use of the TRO 3.0.4.b allowance is prohibited.

A note is included in TRO 3.8.3 stating that TRO 3.0.4.b is not applicable.

TRO 3.0.4.c allows entry into a MODE or other spectfied condition in the Applicability with the TRO not met based on a Note in the Requirement which states TRO 3.0.4.c is applicable. These specific allowances pennit entry into MODES or other specified conditions in the Applicability when the associated ACTIONS to be entered do not provide for co*ntinued operation for an unlimited period of time and a risk assessment has not been performed. This allowance may apply to all the ACTIONS or to*a specific Required Action of a Requirement. The risk assessments performed to justify the use of TRO 3.0.4.b usually only consider systems and components. For this reason, TRO 3.0.4.c is typically applied to Requimments which describe values and parameters (e.g., Radioactive Liquid Process Monitoring Instrumentation), and may be applied to other Requirements based on plant-specific approval.

The provisions of this Requirement should not be interpreted as endorsing the failure to exercise the good practice of restoring systems or components to OPERABLE status before entering an associated MODE or other specified condition in the Applicability .

• • SUSQUEHANNA - UNIT 2 TRM / B 3.0-5

TRO Applicability Rev. 7 B 3.0

• BASES TRO 3.0.4 (continued)

The provisions of TRO 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS. In addition, the provisions of TRO 3.0.4 shall not prevent changes in MODES or other specified conditions In the Applicability that result from any unit shutdown. In this context, a unit shutdown is defined as a change in MODE or other specified condition In the Applicability associated with transitioning from MODE 1 to MODE 2 or MODE 3, ,

MODE 2 to MODE 3 or MODE 4, and MODE 3 to MODE 4.

Upon entry into a MODE or other specified condition in the Applicability with the TRO not met, TRO 3.0.1 and TRO 3.0.2 require entry into the applicable Conditions and Required Actions until the Condition is resolved, until the TRO is met, or until the unit is not within the Applicability of the Technical Requirement.

TRO 3.0.4 is not applicable to TROs that are identified as APPLICABLE "At all times." This term is considered to constitute one inclusive operating condition that corresponds to and encompasses all MODES as defined in the Technical Specification, as well as all special operating conditions, including when the reactor vessel is defueled. Enby into any MODE or other special condition is done within the context of "all times,"

and, therefore, is not a change.within the Applicability to which TRO 3.0.4 applies.

Surveillances do not have to be performed on the associated inoperable equipment (or on variables outside the specified limits), as permitted by TRS 3.0.1. Therefore, utilizing TRO 3.0.4 is not a violation .of TRS 3.0.1

• or TRS 3.0.4 for any Surveillances that have not been perfom,ed on inoperable equipment However, TRSs must be met to ensure OPERABILITY prior to declaring the associated. equipment OPERABLE (or variable within limits) and restoring .com_pliance with the affected TRO.

TRO 3.0.5 TRO 3.0.5 establishes the allowance for restoring equipment to service under administrative* controls when it has been removed from service or declared inoperable to comply with ACTIONS. The sole purpose of this Requirement is to provide an exception to TRO 3.0.2 (e.g., to not comply with the applicable Required Action(s) to allow the performance of TRSs to demonstrate:

a. The OPERABILITY of the equipment being returned to service; or

b. The OPERABILITY of other equipment; or

c. That variables are within limits SUSQUEHANNA - UNIT 2 TRM / B 3.0-6

TRO Applicability Rev. 7 B 3.0 BASES TRO 3.0.5 The administrative controls ensure the time the equipment is returned to (continued) service in conflict with the requirements of the ACTIONS is limited to the time absolutely necessary to perform the allowed TRSs. This Requirement does not provide time to perform any other preventive or corrective maintenance. TRO 3.0.5 should not be used in lieu of other practicable alternatives that comply with Required Actions and that do not require changing the MODE or other specified conditions in the Applicability in order to demonstrate equipment is OPERABLE. TRO 3.0.5 is not intended to be used repeatedly.

An example of demonstrating equipment is OPERABLE With the Required Action not met is opening a manual valve that was closed to comply with Required Actions to isolate a flowpath with excessive Reactor Coolant System (RCS) Pressure Isolation Valve (PIV) leakage in order to perform testing to demonstrate that RCS PIV leakage is now witl)in limit.

Examples of demonstrating equipment OPERABILITY include instances in which it is necessary to take an inoperable channel or trip system out of a tripped condition that was directed by a Required Action, if tnere is no Required Action Note for this purpose. An example of verifying OPERABILITY of equipment removed from service is taking a tripped channel out of the tripped condition to permit the logic to function and

• indicate the appropriate response during performance of required testing on the inoperable channel. Examples of demonstrating the OPERABILITY of other equipment are taking an inoperable channel or trip system oi..It of the tripped condition 1) to prevent the trip function from occurring during the performance of a TRS on another channel in the other trip system, or

2) to permit the logic to function and indicate the appropriate response during the performance of a TRS on another channel in the same trip system.

The administrative controls in TRO 3.0.5 apply in all cases to systems or components in Chapter 3 of the Technical Requirements Manual, as long as the testing could not be conducted while complying with the Required Actions. This includes the realignment or repositioning of redundant or alternate equipment or trains previously manipulated to comply with ACTIONS, as well as equipment removed from service or declared inoperable to comply with ACTIONS.

• • SUSQUEHANNA - UNIT 2 TRM / B 3.0-7

TRO Applicability Rev. 7 B 3.0 BASES TRO 3.0.6 TRO 3.0.6 establishes an exception to TRO 3.0.2 for support systems that have a TRO or LCO specified in the Technical Requirement Specifications (TRS) or Technical Specification (TS). This exception is provided because TRO 3.0.2 would require that the Conditions and Required Actions of the associated inoperable supported system TRO be entered solely due to the inoperability of the support system. This exception is justified because the actions that are required to ensure the plant is maintained in a safe condition are specified in the support system TRO's or LCO's Required Actions. These Required Actions may include entering the supported system's Conditions and Required Actions or may specify other Required Actions.

When a support system is inoperable and there is a TRO or LCO specified for it in the TRS or TS, the supported system(s) are required to be declared inoperable if determined to be inoperable as a result of the support system inoperability. However, it is not necessary to enter into the supported systems' Conditions and Required Actions unless directed to do so by the support system's Required Actions. The potential confusion and inconsistency of requirements related to the entry into multiple support and supported systems' Conditions and Required Actions are eliminated by providing all the actions that are necessary to ensure the plant is maintained in a safe condition in the*

• • support system's Required Actions .

However, there are instances where a support system's Required Action may either direct a supported system to be declared inoperable or direct entry into Conditions and Required Actions for the supported system. This may occur immediately or after some specified delay to perform some other Required Action. Regardless of whether it is immediate or after some delay, when .a support system's Required Action directs a supported system to be declared inoperable or directs entry into Conditions and Required Actions for a supported system, the applicable Conditions and Required Actions shall be entered in

• accordance with TRO 3.0.2 .

• SUSQUEHANNA - UNIT 2 TRM / B 3.0-8

TRS Applicability Rev. 7 B 3.0 B 3.0 TECHNICAL REQUIREMENT SURVEILLANCE (TRS) APPLICABILITY BASES TRS TRS 3.0.1 through TRS 3.0.4 establish the general requirements applicable to all Requirements and apply at all times, unless otherwise stated.

TRS 3.0.1 TRS 3.0.1 establishes the requirement that TRSs must be met during the MODES or other specified conditions in the Applicability for which the requirements of the TRO apply, unless otherwise specified in the individual TRSs. This Requirement is to ensure that Surveillances are performed to verify the OPERABILITY of systems and components, and that variables are within specified limits. Failure to meet a Surveillance within the specified Frequency, in accordance with TRS 3.0.2, constitutes a failure to meet a TRO.

Systems and components are assumed to be OPERABLE when the associated TRSs have been met. Nothing in this Requirement, however, is to be construed as implying that systems or components are OPERABLE when:

• • a.

b.

The systems or components are known to be inoperable, although still meeting the TRSs; or The requirements of the Surveillance(s) are known to be not met between required Surveillance performances, Surveillances do not have to be performed when the unit is in a MODE or other specified condition for which the requirements of the associated TRO are not applicable, unless otherwise specified.

Surveillances, including Surveillances invoked by Required Actions, do not have to be performed on inoperable equipment because the ACTIONS define the remedial measures that apply. Surveillances have to be met and performed in accordance with TRS 3.0.2, prior to returning equipment to OPERABLE status. Upon completion of maintenance, appropriate post maintenance testing is required to declare equipment OPERABLE. This includes ensuring applicable Surveillances are not failed and their most recent performance is in accordance with TRS 3.0.2.

Post maintenance testing may not be possible in the current MODE or other specified conditions in the Applicability due to the necessary unit parameters hot having been established. In these situations, the equipment may be considered OPERABLE provided testing has been satisfactorily completed to the extent possible and the equipment is not otherwise believed to be

• SUSQUEHANNA - UNIT 2 TRM / B 3.0-9

TRS Applicability Rev. 7 B 3.0 BASES TRS 3.0.1 incapable of performing its function. This will allow operation to proceed (continued) to a MODE or other specified condition where other necessary post maintenance tests can be completed.

TRS 3.0.2 TRS 3.0.2 establishes the requirements for meeting the specified Frequency for Surveillances and any Required Action with a Completion Time that requires the periodic performance of the Required Action on a "once per ... " interval.

TRS 3.0.2 permits a 25% extension of the interval specified in the Frequency. This extension facilitates Surveillance scheduling and considers plant operating conditions that may not be suitable for conducting the Surveillance (e.g., transient conditions or other ongoing Surveillance or maintenance activities).

The 25% extension does not significantly degrade the reliability that results from performing the Surveillance at its specified Frequency. This is based on the recognition that the most probable result of any particular Surveillance being performed is the verification of conformance with the TRSs. The exceptions to TRS 3.0.2 are those Surveillances for which the 25% extension of the interval specified in the Frequency does not apply.

These exceptions are stated in tbe individual Requirements. As stated in TRS 3.0.2, the 25% extension also does not apply to the initial portion of a periodic Completion Time that requires performance on a "once per ... "

basis. The 25% extension applies to each performance after the initial performance. The initial performance of the Required Action, whether it is a particular Surveillance or some other remedial action, is considered a single action with a single Completion Time. One reason for not allowing the 25% extension to this Completion Time is that such an action usually verifies that no loss of function has occurred by checking the status of redundant or diverse components or accomplishes the function of the inoperable equipment in an alternative manner.

The provisions of TRS 3.0.2 are not intended to be used repeatedly to extend Surveillance intervals (other than those consistent with refueling intervals) or periodic Completion Time intervals beyond those specified:

TRS 3.0 ..3 TRS 3.0.3 estab'lishes the flexibility to defer declaring affected equipment inoperable or an affected variable outside the specified limits when a Surveillance has not been performed within the specified Frequency. A delay period of up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or up to the limit of the specified

• Frequency, whichever is greater, applies from the point in time that it is discovered that the Surveillance has not been performed in accordance with TRS 3.0.2, and not at the time that the specified Frequency was not met.

SUSQUEHANNA - UNIT 2 TRM / B 3.0-10

TRS Applicability Rev. 7 83.0

• BASES TRS 3.0.3 (continued)

If a Surveillance cannot be performed Within its specified Frequency due to unusual conditions, such as a structure, system, or component configuration that prevents performance of a test, or performance of the test would have an adverse impact on plant risk, compliance with the requirement to declare the TRO not met may be delayed. This delay period starts at the expiration of the current Surveillance test interval.

The delay can be up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or up to the limit of the specified Frequency, whichever Is greater.

This delay period provides adequate time to perform Surveillances that have been missed. This delay period permits the performance of a Surveillance before complying with Required Actions or other remedial measures that might preclude performance of the Surveillance.

The basis for this delay period includes consideration of unit conditions, adequate planning, availability of personnel, the time required to perform the Surveillance, the safety significance of the delay in completing the required Surveillance, and the recognition that the most probable result of any particular Surveillance being performed is the verification of conformance with the requirements.

When a Surveillance with a Frequency based not on time intervals, but

• upon specified unit conditions, operating situations, or requirements of regulations (e.g., prior to entering MODE 1 after each fuel loading, or in accordance with 10 CFR 50, Appendix J, as modified by approved exemptions, etc.) is discovered to not have been performed when specified, TRS 3.0.3 allows for the full delay period of up to the specified Frequency to perform the Surveillance: However, since there Is not a time interval specified, the missed Surveillance should be performed at the first reasonable opportunity.

TRS 3.0.3 provides a time limit for, and allowances for the performance of, Surveillances that become applicable as a consequence of MODE changes imposed by Required Actions.

TRS 3.0.3 is only applicable if there is a reasonable expectation the associated equipment is OPERABLE or that variables are within limits, and it is expected that the Surveillance will be met when performed. Many factors should be considered, such as the period of time since the Surveillance was last performed, or whether the Surveillance, or a portion thereof, has ever been performed, and any other indications, tests, or activities that might support the expectation that the Surveillance will be met when performed. An example of the use of TRS 3.0.3 would be a relay contact that was not tested as required in accordance with a particular TRS, but previous successful performances of the TRS included the relay contact; the adjacent, physically connected relay contacts were tested during the TRS performance; the subject relay

• SUSQUEHANNA - UNIT 2 TRM / B 3.0-11

TRS Applicability Rev. 7 B 3.0

• BASES TRS 3.0.3 (continued) contact has been tested by another TRS; or historical operation of the subject relay contact has been successful. It Is not sufficient to infer the behavior of the associated equipment from the performance of similar equipment. The rigor of detennining whether there is a reasonable expectation a Surveillance will be met when performed should increase based on the length of time since the last performance of the Surveillance. If the Surveillance has been performed recently, a review of the Surveillance history and equipment performance may be sufficient to support a reasonable expectation that the Surveillance will be met when performed. For Surveillances that have not been performed for a long period or that have never been performed, a rigorous evaluation based on objective evidence should provide a high degree of confidence that the equipment is OPERABLE. The evaluation should be documented in sufficient detail to allow a knowledgeable individual to understand the basis for the determination.

Failure to comply with specified Frequencies for rRss is expected to be an infrequent occurrence. Use of the delay period established by TRS 3.0.3 is a fleXJbility which is not intended to be used repeatedly to extend Surveillance intervals. While up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or the limit of the specified Frequency is provided to perform the missed Surveillance, it is expected that the missed Surveillance will be performed at the first reasonable opportunity. The determination of the first reasonable opportunity should include consideration of the impact on plant risk (from delaying the Surveillance as well as any plant configuration changes required or shutting the plant down to perform the Surveillance) and impact on any analysis assumptions, in addition to unit conditions, planning, availability of personnel, and the time required to perform the Surveillance. This risk impact should be managed through the program in place to implement 10 CFR 50.65(a)(4) and its implementation guidance, NRC Regulatory Guide 1.182, "Assessing and Managing Risk Before Maintenance Activities at Nuclear Power Plants." This Regulatory Guide addresses consideration of temporary and aggregate risk impacts, determination of risk management action thresholds, and risk management action up to and including plant shutdown. The missed Surveillance should be treated as an emergent condition as discussed in the Regulatory Guide. The risk evaluation may use quantitative, qualitative, or blended methods. The degree of depth and rigor of the evaluation should be commensurate with the importance of the component. Missed Surveillances for important components should be analyzed quantitatively. If the results of the risk evaluation determine the risk increase is significant, this evaluation should be used to determine the safest course of action. All Surveillances whose Frequency has been extended in accordance with TRS 3.0.3 will be placed in the Corrective Action Program .

• SUSQUEHANNA - UNIT 2 TRM / B 3.0-12

TRS Applicability Rev. 7 B 3.0 BASES TRS 3.0.3 If a Surveillance is not completed within the allowed delay period, then (continued) the equipment is considered inoperable or the variable is considered outside the specified limits and the Completion Times of the Required

• Actions for the applicable TRO Conditions begin immediately upon expiration of the delay period. If a Surveillance is failed within the delay period, then the equipment is inoperable, or the variable Is outside the specified limits and the Completion Times of the Required Actions for the applicable TRO Conditions begin immediately upon the failure of the Surveillance.

Completion of the Surveillance within the delay period allowed by this Requirement, or within the Completion Time of the ACTIONS, restores compliance with TRS 3.0.1.

Exceptions to TRS 3.0.3 are provided in instances where requiring equipment to be considered inoperable, in accordance with TRS 3.0.3, would not provide appropriate remedial measures for the associated condition. An example of this is in TRO 3.11.4.1, "Radiological Environmental Monitoring." TRO 3.11.4.1 has surveillances that implement required environmental sampling and analysis. If a portion of the sampling or analysis is not completed as required, the programmatic response is to report the condition to the Nuclear Regulatory Commission

• and in most instances describe the corrective actions taken to correct the condition. There are no result thresholds built into the monitoring and analysis program that would result in declaring equipment inoperable or in a plant shutdown. Therefore, it is appropriate that the provisions of TRO 3.0.3 be waived for this TRO. These exceptions are addressed in the individual Requirements.

TRS 3.0.4 TRS 3.0.4 establishes the requirement that all applicable TRSs must be met before entry into a MODE or other specified condition in the

. Applicability. This Requirement ensures that system and component OPERABILITY requirements* and variable limits are met before entry into MODES or other specified conditions in the Applicability for which these systems and components ensure safe operation of the unit.

The provisions of this Requirement should not be interpreted as endorsing the failure to exercise the good practice .of restoring systems or components to OPERABLE status before entering an associated MODE or other specified condition in the Applicability.

A provision is included to allow entry into a MODE or other specified condition in the Applicability when a TRO is not met due to Surveillance not being met in accordance with TRO 3.0.4.

SUSQUEHANNA - UNIT 2 TRM / B 3.0-13

TRS Applicability Rev. 7 B 3.0

• • BASES TRS 3.0.4 (continued)

However, in certain circumstances, failing to meet a TRS will not result in TRS 3.0.4 restricting a MODE change or other specified condition change. When a system, subsystem, division, component, device, or variable is inoperable or outside its specified limits, the associated TRS(s) are not required to be perfonned per TRS 3. 0.1, which states that Surveillances do not have to be performed on inoperable equipment.

When equipment is inoperable, TRS 3.0.4 does not apply to the associated TRS(s) since the requirement for the TRS(s) to be perfonned is removed.

Therefore, failing to perfonn the Surveillance(s) within the specified Frequency does not result ih an TRS 3.0.4 restriction to changing MODES or other specified conditions of the Applicability. However, since the TRO is not met in this instance, TRO 3.0.4 will govern any restrictions that may (or may not) apply to MODE or other specified condition changes. TRS 3.0.4 does not restrict changing MODES or other specified conditions of the Applicability when a Surveillance has not been perfonned within the specified Frequency, provided the requirement to declare the TRO not met has been delayed in accordance with TRS 3.0.3.

The provisions of TRS 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS. In addition, the provisions of TRO 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that result from any unit shutdown. In this context, a unit shutdown is defined as a change in MODE or other specified condition in the Applicability associated with transitioning from MODE 1 to MODE 2 or MODE 3, MODE 2 to MODE 3 or MODE 4, and MODE 3 to MODE 4.

The precise requirements for performance of TRSs are specified such that exceptions to TRS 3.0.4 are not necessary. rhe specific time frames and conditions necessary for meeting the TRSs are specified in the

!=requency, in the Surveillance, or both.

This allows perfonnance of Surveillances when the prerequisite condition(s) specified irf a Surveillance procedure require entry into the MODE or other specified condition in the Applicability of the associated TRO prior to the perfonnance or completion of a Surveillance. A Surveillance that could not be performed until after entering the TRO Applicability would have its Frequency specified such that it is not "due" until the specific conditions needed are met. Alternately, the Surveillance rnay be stated in the fonn of a Note as not required (to be met or perfonned) until a particular event, condition, or time has been reached.

Further discussion of the specific formats of TRS's annotation is found in Section 1.4, Frequency.

• • SUSQUEHANNA - UNIT 2 TRM / B 3.0-14

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LIST OF EFFECTIVE SECTIONS TEXT TOC 25 03/05/2019

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TABLE OF CONTENTS TEXT 2 .1.1 6 01/22/2015 TEXT 3 .1.2

Title:

REACTIVITY TEXT 3.1.3 11/16/2016

Title:

REACTIVI OL SYSTEMS CONTROL ROD OPERABILITY

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TEXT 3.1.4 5 11/16/2016

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REACTIVITY CONTROL SYSTEMS CONTROL ROD SCRAM TIMES TEXT 3.1.5 2 11/16/2016

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REACTIVITY CONTROL SYSTEMS CONTROL ROD SCRAM ACCUMULATORS TEXT 3 .1.6 4 11/16/2016

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REACTIVITY CONTROL SYSTEMS ROD PATTERN CONTROL Page 1 of 8 Report Date: 03/19/21

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Manual Name z TSBl

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TEXT 3.1.7 4* 11/16/2016 Titlez REACTIVITY CONTROL SYSTEMS STANDBY LIQUID CONTROL (SLC) SYSTEM TEXT 3 .1.8 4 11/16/2016

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REACTIVITY CONTROL SYSTEMS SCRAM D+SCHARGE VOLUME (SDV) VENT AND DRAIN VALVES TEXT 3.2.1 3 11/16/2016

Title:

POWER DISTRIBUTION LIMITS AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)

TEXT 3.2.2 4 11/16/2016

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POWER DISTRIBUTION LIMITS MINIMOM CRITICAL POWER RATIO (MCPR)

TEXT 3.2.3 3 11/16/2016 Titlez POWER DISTRIBUTION LIMITS LINEAR HEAT GENERATION RATE (LHGR)

~ 3.3.1.1 7.. ___ 1;)./_16_/201_6 Titlez INSTRUMENTATION REACTOR PROTECTION SYSTEM (RPS) INSTRUMENTATION TEXT 3.3.1.2 4 01/23/2018

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Title:

INSTRUMENTATION END OF CYCLE RECIRCULATION PUMP TRIP (EOC-RPT) INSTRUMENTATION.

Page 2 of 8 Report Date: 03/19/21

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Title:

INSTRUMENTATION EMERGENCY CORE COOLING SYSTEM (ECCS) INSTRUMENTATION TEXT 3.3.5.2 3 03/18/2021

Title:

REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL INSTRUMENTATION TEXT 3.3.5.3 0 03/05/201,9

Title:

INSTRUMENTATION REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM INSTRUMENTATION

• • PREVIOUSLY TEXT 3.3.5.2 REV l**

TEXT 3.3.6.1 9 03/05/2019

Title:

INSTRUMENTATION PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION

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INSTRUMENTATION SECONDARY CONTAINMENT ISOLATION INSTR1JME+ITATION TEXT 3.3.7.1 4 03/05/2019

Title:

INSTRUMENTATION CONTROL ROOM EMERGENCY OUTSIDE AIR SUPPLY (CREOAS) SYSTEM.

INSTRUMENTATION TEXT 3.3.8.1 4 03/18/2021

Title:

INSTRTIMENJ'ATION LOSS OF POWER (LOP) INSTRUMENTATION TEXT 3.3.8.2 1 11/16/2016

Title:

INSTRUMENTATION REACTOR PROTECTION SYSTEM (RPS) ELECTRIC POWER MONITORING TEXT 3.4.1 5 11/16/2016

Title:

REACTOR COOLANT SYSTEM (RCS) RECIRCULATION LOOPS OPERATING TEXT 3.4.2 4 11/16/2016

Title:

REACTOR COOLANT SYSTEM (RCS) JET PUMPS 01/13/2012 TEXT 3.4.3 3

Title:

REACTOR COOLANT SYSTEM RCS SAFETY RELIEF VALVES S/RVS Page 3 of 8 Report Date: 03/19/21

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"TECHNICAL SPECIFICATION BASES DNIT 1 MANUAL TEXT 3.4.4 1 11/16/2016

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REACTOR COOLANT SYSTEM (RCS) RCS OPERATIONAL LEAKAGE TEXT 3.4.5 *2 04/13/2016

Title:

REACTOR COOLANT SYSTEM (RCS) RCS PRESSURE ISOLATION VALVE (PIV) LEAKAGE TEXT 3.4.6 5 11/16/2016

Title:

REACTOR COOLANT SYSTEM (RCS) RCS LEAKAGE DETECTION INSTRUMENTATION TEXT 3.4.7 3 ll/l~/2016

Title:

REACTOR COOLANT SYSTEM (RCS) RCS SPECIFIC ACTIVITY TEXT 3.4.8 3 11/16/2016

Title:

REACTOR COOLANT SYSTEM (RCS) RESIDUAL HEAT REMOVAL (RHR) SHOTDOWN COOLING SYSTEM

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REACTOR COOLANT SYSTEM (RCS) RESIDUAL HEAT REMOVAL (RHR) SHUTDOWN *;;O~I~~ *;~s*;*;

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Title:

REACTOR COOLANT SYSTEM (RCS) RCS.PRESSURE AND TEMPERATORE (P/T) LIMITS TEXT 3 .4 .11 1 11/16/2016

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REACTOR COOLANT SYSTEM (RCS) REACTOR STEAM DOME PRESSURE TEXT 3.5.1 6 03/05/2019

Title:

EMERGENCY CORE COOLING SYSTEMS (ECCS) REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM ECCS OPERATING TEXT 3.5.2 4 03/18/2021

Title:

EMERGENCY CORE COOLING SYSTEMS (ECCS) REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM ECCS OPERATING TEXT 3.5.3 6 03/05/2019

Title:

EMERGENCY CORE COOLING SYSTEMS (ECCS) REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM ECCS Page 4 of OPERATING 8 Report Date: 03/19/21

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TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL TEXT 3 . 6 . 1. 1 6 11/16/2016

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PRIMARY CONTAINMENT TEXT 3.6.1.2 2 11/16/2016

Title:

CONTAINMENT SYSTEMS PRIMARY CONTAINMENT AIR LOCK TEXT 3.6.1.3 17 03/18/2021

Title:

CONTAINMENT SYSTEMS PRIMARY( CONTAINMENT ISOLATION VALVES (PCIVS)

LDCN 5569 TEXT 3.6.1.4 2 11/16/2016

Title:

CONTAINMENT SYSTEMS CONTAINMENT PRESSURE TEXT 3.6.1.5 2 11/16/2016

Title:

CONTAINMENT SYSTEMS DRYWELL AIR TEMPERATURE

.'EXT 3.6.1.6 **- . . . .1 *- _ 11/.~6/2016

Title:

CONTAINMENT SYSTEMS SUPPRESSION CHAMBER-TO-DRYWELL VACOOM BREAKERS TEXT 3.6.2.1 3 11/16/2016

Title:

CONTAINMENT SYSTEMS SUPPRESSION POOL AVERAGE TEMPERATURE TEXT 3.6.2.2 2 03/05/2019

Title:

CONTAINMENT SYSTEMS SUPPRESSION POOL WATER LEVEL TEXT 3.6.2.3 2 11/16/2016

Title:

CONTAINMENT SYSTEMS RESIDUAL HEAT REMOVAL (RHR) SUPPRESSION POOL COOLING TEXT 3.6.2.4 1 11/16/2016

Title:

CONTAINMENT SYSTEMS RESIDUAL HEAT REMOVAL (RHR) SUPPRESSION POOL SPRAY TEXT 3.6.3.1 2 06/13/2006

Title:

CONTAINMENT SYSTEMS PRIMARY CONTAINMENT HYDROGEN RECOMBINERS 04/22/2020 TEXT 3.6.3.2 4

Title:

CONTAINMENT SYSTEMS DRYWELL AIR FLOW SYSTEM Page 5 of B Report Date: 03/19/21

SSES MANUAL Manual Name: TSBl

'{anual

Title:

TECHNICAL SPECIFICATION BASES UNIT 1 TEXT 3.6.3.3 3 09/29/2017 MANOA[j

Title:

CONTAINMENT SYSTEMS PRIMARY CONTAINMENT OXYGEN CONCENTRATION TEXT 3.6.4.1 16 12/16/2020

Title:

CONTAINMENT SYSTEMS SECOND.ARY CONTAINMENT TEXT 3.6.4.2 14 03/05/2019

Title:

CONTAINMENT SYSTEMS SECONDARY CONTAINMENT ISOLATION VALVES (SCIVS)

TEXT 3.6.4.3 7 03/05/2019

Title:

CONTAINMENT SYSTEMS STANDBY GAS TREATMENT (SGT) SYSTEM TEXT 3.7.1 6 03/03/2020

Title:

PLANT SYSTEMS RESIDUAL HEAT REMOVAL SERVICE WATER (RHRSW) SYSTEM AND THE ULTIMATE HEAT SINK ("OHS)

TEXT 3.7.3 4

Title:

PLANT SYSTEMS EMERGENCY SERVICE WATER (ESW) SYSTEM 4 03/05/2019

Title:

PLANT SYSTEMS CONTROL ROOM EMERGENCY OUTSIDE AIR SUPPLY (CR.BOAS) SYSTEM TEXT 3.7.4 2 03/05/2019

Title:

PLANT SYSTEMS CONTROL ROOM FLOOR COOLING SYSTEM TEXT 3.7.5 2 11/16/2016

Title:

PLANT SYSTEMS MAIN CONDENSER OFFGAS TEXT 3.7.6 3 11/16/2016

Title:

PLANT SYSTEMS MAIN TURBINE BYPASS SYSTEM TEXT 3.7.7 2 11/16/2016

Title:

PLANT SYSTEMS SPENI' FUEL STORAGE POOL WATER LEVEL 1 11/16/2016 TEXT 3.7.8

Title:

PLANT SYSTEMS Page 6 of 8 Report Date: 03/19/~1

SSES MANUAL Manual Namez TSBl

.!anual

Title:

TECHNICAL. SPECIFICATION BASES DNIT.1 MANUAL TEXT 3.8.1 13 01/28/2020

Title:

ELECTRICAL POWER SYSTEMS AC SOURCES - OPERATING TEXT 3.8.2 2 03/18/2021

Title:

ELECTRICAL POWER SYSTEMS AC SOURCES - SHUTDOWN TEXT 3.8.3 7 08/07/2019

Title:

ELECTRICAL POWER SYSTEMS DIESEL FUEL OIL, LUBE OIL, AND STARTING AIR TEXT 3.8.4 4 11/16/2016

Title:

ELECTRICAL POWER SYSTEMS DC SOURCES - OPERATING TEXT 3.8.5 2 03/05/2019

Title:

ELECTRICAL POWER SYSTEMS DC SOURCES - SHUTDOWN

.,EXT 3 8 6 2 . 1],_/lpnQ;\.6

. T~t~e*: ELE~I~ ~~- SYSTEMS BATI'ERY CELL PARAMETERS TEXT 3.8.7 3 09/04/2019

Title:

ELECTRICAL POWER SYSTEMS DISTRIBUTION SYSTEMS - OPERATING TEXT 3.8.8 2 03/05/2019

Title:

ELECTRICAL POWER SYSTEMS DISTRIBUTION SYSTEMS - SHUTDOWN TEXT 3.9.1 1 11/16/2016 Title z REFUELING OPERATIONS REFUELING EQUIPMENT INTERLOCKS TEXT 3.9.2 2 11/16/2016

Title:

REFUELING OPERATIONS REFUEL POSITION ONE-ROD-OUT INTERLOCK TEXT 3.9.3 1 11/16/2016

Title:

REFUELING OPERATIONS CONTROL ROD POSITION 11/15/2002 TEXT 3.9.4 0

Title:

REFUELING OPERATIONS CONTROL ROD POSITION INDICATION Page 7 of 8 Report Date: 03/19/21

SSES MANUAL Manual Na.me: TSBl tanual

Title:

TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL TEXT 3.9.5 1 11/16/2016

Title:

REFUELING OPERATIONS CONTROL ROD OPERABILITY - REFUELING TEXT 3.9.6 2 11/16/2016

Title:

REFUELING OPERATIONS REACTOR PRESSURE VESSEL (RPV) WATER LEVEL TEXT 3.9.7 1 . 11/16/2016

Title:

REFUELING OPERATIONS RESIDUAL HEAT REMOVAL (RHR) - HIGH WATER LEVEL TEXT 3.9.B 1 11/16/2016

Title:

REFUELING *oPERATIONS RESIDUAL HEAT REMOVAL (RHR) - LOW WATER LEVEL TEXT 3.10.1 2 03/05/2019

Title:

SPECIAL OPERATIONS INSERVICE LEAK AND HYDROSTATIC TESTING OPERATION

'EXT 3.10.2 l_ ___ Jl/16/.2Ql6

Title:

SPECIAL OPERATIONS REACTOR MODE SWITCH INTERLOCK TESTING TEXT 3.10.3 1 11/16/2016

Title:

SPECIAL OPERATIONS SINGLE CONTROL ROD WITHDRAWAL - HOT SHUTDOWN TEXT 3.10.4 1 ll/16/2016

("

Title:

SPECIAL OPERATIONS SINGLE CONTROL ROD WITHDRAWAL - COLD SHUTDOWN TEXT 3.10.5 1 11/16/2016

Title:

SPECIAL OPERATIONS SINGLE CONTROL ROD DRIVE (CRD) REMOVAL - REFUELING TEXT 3.10.6 1 11/16/2016

Title:

SPECIAL OPERATIONS MOLTIPLE CONTROL ROD WITHDRAWAL - REFUELING TEXT 3.10.7 1 04/18/2006

Title:

SPECIAL OPERATIONS CONTROL ROD TESTING - OPERATING 2 11/16/2016 TEXT 3.10.B

Title:

SPECIAL OPERATIONS SHUTDOWN MARGIN (SDM) TEST - REFUELING Page B of B Report Date: 03/19/21

Rev.5 LCO Applicability

• • B 3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY B 3.0 BASES LCOs LCO 3.0.1 through LCO 3.0.8 establish the general requirements applicable to all Specifications and apply at all times, unless otherwise stated.

LCO 3.0.1 LCO 3.0.1 establishes the Applicability statement within each individual Specification as the requirement for when the LCO is required to be met (i.e., when the unit is in the MODES or other specified conditions of the Applicability statement of each Specification).

LCO 3.0.2 LCO 3.0.2 establishes that upon discovery of a failure to meet an LCO, the associated ACTIONS shall be met The Completion Time of each Required Action for an ACTIONS Condition is applicable from the point in time that an ACTIONS Condition is entered, unless otherwise specified.

The Required Actions establish those remedial measures that must be

• taken within specified Completion Times when the requirements of an LCO are not met This Specification establishes that:

a. Completion of the Required Actions within the specified Completion Times constitutes compliance with a Specification; and

b. Completion of the Required Actions is not required when an LCO Is met within the specified Completion Time, unless otherwise specified.

There are two basic types of Required Actions. The first type of Required Action specifies a time limit in which the LCO must be met.

This time limit is the Completion Time to restore an inoperable system or component to OPERABLE status or to restore variables to within specified limits. If this type of Required Action is not completed within the specified Completion Time, a shutdown may be required to place the unit in a MODE or condition in which the Specification is not applicable. (Whether stated as a Required Action or not, correction of the entered Condition is an action that may always be considered upon entering ACTIONS.) The second type of Required Action specifies the remedial measures that permit continued operation of the unit that is not further restricted by the Completion Time. In this case, compliance with the Required Actions provides an acceptable level of safety for continued operation .

• SUSQUEHANNA - UNIT 1 3.0-1

Rev. 5 LCO Applicability

• BASES LCO 3.0,2 (continued)

Completing the Required Actions is not required when an LCO is met or is no longer applicable, unless otherwise stated in the individual B 3.0 Specifications.

The nature of some Required Actions of some Conditions necessitates that, once the Condition is entered, the Required Actions must be completed even though the associated Conditions no longer exist. The indMdual LCOs ACTIONS specify the Required Actions where this is the case. An example of this is in LCO 3.4.10, "RCS Pressure and Temperature (P/1) Limits."

The Completion Times of the Required Actions are also applicable when a system or component is removed from service intentionally. The ACTIONS for not meeting a single LCO adequately manage any increase Ln plant.risk, provided any unusual external conditions (e.g.,

severe weather, offsite power instability) are considered. In addition, the increased risk associated with simultaneous removal of multiple structures, systems, trains, or components from service is assessed and managed in accordance with 10 CFR 50.65(a)(4). lndMdual Specifications may specify a time limit for performing an SR when equipment is removed from service or bypassed for testing. In this case, the Completion Times of the Required Actions are applicable when this time limit expires, if the equipment-remains removed from service or bypassed.

When a change in MODE or other specified condition is required to comply with Required Actions, the unit may enter a MODE or other specified condition in which another Specification becomes applicable. In this case, the Completion Times of the associated Required Actions would apply from the point in time that the new Specification becomes applicable and the ACTIONS Condition(s) are entered.

LCO 3.0.3 LCO 3.0.3 establishes the actions that must be implemented when an LCO is not met and: *

a. An associated Required Action and Completion Time is not met and no other Condition applies; or

• SUSQUEHANNA - UNIT 1 3.0-2

Rev. 5 LCO Applicability B 3.0 BASES LCO 3.0.3 b. The condition of the unit is not specifically addressed by the (continued) associated ACTIONS. This means that no combination of Conditions stated in the ACTIONS can be made that exactly corresponds to the actual condition of the unit. Sometimes, possible combinations of Conditions are such that entering LCO 3.0.3 is warranted; in such cases, the ACTIONS specifically state a Condition corresponding to such combinations and also that LCO 3.0.3 be entered immediately.

This Specification delineates the time limits for placing the unit in a safe MODE or other specified condition when operation cannot be maintained within the limits for safe operation as defined by the LCO and its ACTIONS. Planned entry into LCO 3.0.3 should be avoided. If it is not practicable to avoid planned entry into LCO 3.0.3, plant risk should be assessed and managed in accordance with 10 CFR 50.65(a)(4), and the planned entry into LCO 3.0.3 should have less effect on plant safety than other practicable alternatives.

Upon entering LCO 3.0.3, 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> is allowed to prepare for an orderly shutdown before initiating a change in unit operation. This includes time to pennit the operator to coordinate the reduction in electrical generation with the load dispatcher to ensure the stability and availability of the electrical grid. The time limits specified to enter lower MODES of operation pennit the shutdown to proceed in a controlled and orderly manner that is well within the specified maximum cooldown rate and within the capabilities of the unit, assuming that only the minimum required equipment is OPERABLE. This reduces thennal stresses on components of the Reactor Coolant System and the potential for a plant upset that could challenge safety systems under conditions to which this Specification applies. The use and interpretation of specified times to complete the actions of LCO 3.0.3 are consistent with the discussion of Section 1.3, Completion Times.

A unit shutdown required in accordance with LCO 3.0.3 may be terminated and LCO 3.0.3 exited if any of the following occurs:

a. The LCO-is now met,

b. The LCO is no longer applicable,

c. A Condition exists for which the Required Actions have now been perfonned, or

d. ACTIONS exist that do not have expired Completion Times. These Completion Times are applicable from the point in time that the Condition is initially entered and not from the time LCO 3.0.3 is exited .

SUSQUEHANNA - UNIT 1 3.0-3

Rev. 5 LCO Applicability B 3.0 BASES LCO 3.0.3 The time limits of LCO 3.0.3 allow 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br /> for the unit to be in MODE 4 (continued) when a shutdown is required during MODE 1 operation. If the unit is in a lower MODE of operation when a shutdown is required, the time limit for entering the next lower MODE applies. If a lower MODE is entered in less time than allowed, however, the total allowable time to enter MODE 4, or other applicable MODE, is not reduced. For example, if MODE 2 is entered in 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, then the time allowed for entering MODE 3 is the next 11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br />, because the total time for entering MODE 3 is not reduced from the allowable limit of 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br />. Therefore, if remedial measures are completed that would pem,it a return to MODE 1, a penalty is not incurred by having to enter a lower MODE of operation in less than the total time allowed.

In MODES 1, 2, and 3, LCO 3.0.3 provides actions for Conditions not covered in other Specifications. The requirements of LCO 3.0.3 do not apply in MODES 4 and 5 because the unit is already in the most restrictive Condition required by LCO 3.0.3. The requirements of LCO 3.0.3 do not apply in other specified conditions of the Applicability (unless in MODE 1, 2, or 3) because the ACTIONS of indMdual Specifications sufficiently define the remedial measures to be taken.

Exceptions to LCO 3.0.3 are provided in instances where requiring a unit shutdown, in accordance with LCO 3.0.3, would not provide appropriate remedial measures for the associated condition of the unit. An example of this is in LCO 3.7.7, "Spent Fuel Storage Pool Water Level." LCO 3.7.7 has an Applicability of "Dufing movement of irradiated fuel assemblies in the spent fuel storage pool." Therefore, this LCO can be applicable in any or all MODES. If the LCO and the Required Actions of LCO 3. 7. 7 are not met while in MODE 1, 2, or 3, there is no safety benefit to be gained by placing the unit in a shutdown condition. The Required Action of LCO 3.7.7 of "Suspend movement of irradiated fuel assemblies in the spent fuel storage pool" is the appropriate Required Action to complete in lieu of the actions of LCO 3.0.3. These exceptions are addressed in the individual Specifications.

LCO 3.0.4 LCO 3.0.4 establishes limitations on changes in MODES or other specified conditions in the Applicability when an LCO is not met. It allows placing the unit in a MODE or other specified condition stated in that Applicability (e.g., the Applicability desired to be entered) when unit conditions are such that the requirements of the LCO would not be met, in accordance with either LCO 3.0,4.a, LCO 3.0.4.b, or LCO 3.0.4.c .

• SUSQUEHANNA - UNIT 1 3.0-4

Rev. 5 LCO Applicability B 3.0 BASES LCO 3.0.4 LCO 3.0.4.a allows entry into a MODE or other specified condition in the (continued) Applicability with the LCO not met when the associated ACTIONS to be entered following entry into the MODE or other specified condition in the Applicability will permit continued operation within the MODE or other specified condition for an unlimited period of time. Compliance with ACTIONS that pern,it continued operation of the unit for an unlimited period of time in a MODE or other specified condition provides an acceptable level of safety for continued operation. This is without regard to the status of the unit before or after the MODE change. Therefore, In such cases, entry into a MODE or other specified condition in the Applicability may be made and the Required Actions followed after entry

!nto the Applicability.

For example, LCO 3.0.4.a may be used when the Required Action to be entered states that an inoperable instrument channel must be placed in the trip condition within the Completion Time. Transition into a MODE or other specified condition in the Applicability may be made in accordance with LCO 3.0.4 and the channel is subsequently placed in the tripped condition within the Completion Time, which begins when the Applicability is entered. If the instrument channel cannot be placed in the tripped condition and the subsequent default ACTION ("Required Action and associated Completion Time not met") allows the OPERABLE train to be placed in operation, use of LCO 3.0.4.a is acceptable because the subsequent ACTIONS to be entered following entry into the MODE include ACTIONS (place the OPERABLE train in operation) that pern,it safe plant operation for an unlimited period of time in the MODE or other specified condition to be entered.

LCO 3.0.4.b allows entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering the MODE or other specified condition in the Applicability, and establishment of risk management actions, if appropriate.

The risk assessment may use quantitative, qualitative, or blended approaches, and the risk assessment will be conducted using the plant program, procedures, and criteria in place to implement 10 CFR 50.65(a)(4), which requires that risk impacts of maintenance activities to be assessed and managed. The risk assessment, for the purposes of LCO 3.0.4 (b), must take into account all inoperable Technical Specification equipment regardless of whether the equipment is included in the normal 10 CFR 50.65(a)(4) risk assessment scope.

• • SUSQUEHANNA - UNIT 1 3.0-5

Rev. 5 LCO Applicability B 3.0 BASES LCO 3.0.4 The risk assessments will be conducted using the procedures and (continued) guidance endorsed by Regulatory Guide 1.182, "Assessing and Managing Risk Before Maintenance Activities at Nuclear Power Plants."

Regulatory Guide 1.182 endorses the guidance in Section 11 of NUMARC 93-01, "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants." These documents address general guidance for conduct of the risk assessment, quantitative and qualitative guidelines for establishing risk management actions, and example risk management actions. These include actions to plan and conduct other activities in a manner that controls overall risk, increased risk awareness by shift and management personnel, actions to reduce the duration of the condition, actions to minimize the magnitude of risk increases (establishment of backup success paths or compensatory measures), and determination that the proposed MODE change is acceptable. Consideration should also be given to the probability of completing restoration such that the requirements of the LCO would be met prior to the expiration of ACTIONS Completion Times that would require exiting the Applicability.

LCO 3.0.4.b may be used with single, or multiple systems and components unavailable. NUMARC 93-01 provides guidance relative to consideration of simultaneous unavailability of multiple systems and components.

The results of the risk assessment shall be considered in determining the acceptability of entering the MODE or other specified condition in the Applicability, and any corresponding risk management actions. The LCO 3.0.4.b risk assessments do not have to be documented.

The Technical Specifications allow continued operation with equipment unavailable in MODE 1 for the duration of the Completion Time. Since this is allowable, and since in general the risk impact in that particular MODE bounds the risk of transitioning into and through the applicable MODES or other specified conditions in the Applicability of the LCO, the use of the LCO 3.0.4.b allowance should be generally acceptable, as long as the risk is assessed and managed as stated above. However, there is a small subset of systems and components that have been determined to be more important to risk and use of the LCO 3.0.4.b allowance is prohibited. The LCOs governing these systems and components contain Notes prohibiting the use of LCO 3.0.4.b by stating that LCO 3.0.4.b is not applicable .

• SUSQUEHANNA - UNIT 1 3.0-6

Rev. 5 LCO Applicability

• BASES LCO 3.0.4 (continued)

LCO 3.0.4.c allows entry into a MODE or other specified condition in the Applicability with the LCO not met based on a Note in the Specification B 3.0 which states LCO 3.0.4.c is applicable. These specific allowances pennit entry into MODES or other specified conditions in the Applicability when the associated ACTIONS to be entered do not provide for continued operation for an unlimited period of time and a risk assessment has not been perfonned. This allowance may apply to all the ACTIONS or to a specific Required Action of a Specification. The risk assessments performed to justify the use of LCO 3.0.4.b usually only consider systems and components. For this reason, LCO 3.0.4.c is typically applied to Specifications which describe values and parameters (e.g., RCS Specific Activity) and may be applied to other Specifications based on NRC plant-specific approval.

The provisions of this Specification should not be interpreted as endorsing the failure to exercise the good practice of restoring systems or components to OPERABLE status before entering an associated MODE or other specified condition in the Applicability.

The provisions of LCO 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS. In addition, the provisions of LCO 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that result from any unit shutdown. In this context, a unit shutdown is defined as a change in MODE or other specified condition in the Applicability associated with transitioning from MODE 1 to MODE 2 or MODE 3, MODE 2 to MODE 3 or MODE 4, and MODE 3 to MODE 4.

Upon entry into a MODE or other specified condition in the Applicability with the LCO not met, LCO 3.0.1 and LCO 3.0.2 require entry Into the applicable Conditions and Required Actions until the Condition is resolved, until the LCO is met, or until the unit is not within the Applicability of the Technical Specification.

Surveillances do not have to be perfonned on the associated inoperable equipment (or on variables outside the specified limits), as permitted by SR 3.0.1. Therefore, utilizing LCO 3.0.4 is not a violation of SR 3.0.1 or SR 3.0.4 for any Surveillances that have not been performed on inoperable equipment. However, SRs must be met to ensure OPERABILITY prior to declaring the associated equipment OPERABLE (or variable within limits) and restoring compliance with the affected LCO.*

• SUSQUEHANNA - UNIT 1 3.0-7

Rev. 5 LCO Applicability B 3.0 BASES LCO 3.0.5 LCO 3.0.5 establishes the allowance for restoring equipment to service under administrative controls when it has been removed from service or declared inoperable to comply with ACTIONS. The sole purpose of this Specification is to provide an exception to LCO 3.0.2 (e.g., to not comply with the applicable Required Action(s)) to allow the perfonnance of required testing to demonstrate:

a. The OPERABILITY of the equipment being returned to service; or

b. The OPERABILITY of other equipment.

The administrative controls ensure the time the equipment is returned to service in conflict with the ,requirements of the ACTIONS is limited to the time absolutely necessary to perfonn the required testing to demonstrate OPERABILITY. This Specification does not provide time to perform any other preventive or corrective maintenance. LCO 3.0.5 should not be used in lieu of other practicable alternatives that comply with Required Actions and that do not require changing the MODE or other specified conditions in the Applicability in order to demonstrate equipment is OPERABLE. LCO 3.0.5 is not intended to be used repeatedly .

• An example of demonstrating equipment is OPERABLE with the Required Actions not met is opening a manual valve that was closed to comply with Required Actions to isolate a flowpath with excessive Reactor Coolant System (RCS) Pressure Isolation Valve (PIV) leakage in order to perform testing to demonstrate that RCS PIV leakage is now within limit.

Examples of demonstrating equipment OPERABILITY include instances in which it is necessary to take an inoperable channel or trip system out of a tripped condition that was directed by a Required Action, if there is no Required Action Note for this purpose. An example of verifying OPERABILITY of equipment removed from service is taking a tripped channel out of the tripped condition to permit the logic to function and indicate the appropriate response during performance of required testing on the inoperable channel. Examples of demonstrating the OPERABILITY of other equipment are taking an inoperable channel or trip system out of the tripped condition 1) to prevent the trip function from occurring during the performance of required testing on another channel in the other trip system, or 2) to permit the logic to function and indicate the appropriate response during the performance of required testing on another channel in the same trip system .

• SUSQUEHANNA - UNIT 1 3.0-8

Rev. 5 LCO Applicability B 3.0 BA$ES LCO 3.0.5 The administrative controls in LCO 3.0.5 apply In all cases.to systems or (continued) components in Chapter 3 of the Technical Specifications, as long as the testing could not be conducted while complying with the Required Actions. This includes the realignment or repositioning of redundant or alternate equipment or trains previously manipulated to comply with ACTIONS, as well as equipment removed from service or declared inoperable to comply with ACTIONS.

LCO 3.0.6 LCO 3.0.6 establishes an exception to LCO 3.0.2 for supported systems that have a support system LCO specified in the Technical Specifications (TS). This exception is provided because LCO 3.0.2 would require that the Conditions and Required Actions of the associated inoperable supported system LCO be entered solely due to the inoperability of the support system. This exception is justified because the actions that are required to ensure the plant is maintained in a safe condition are specified in the support system LCO's Required Actions. These Required Actions may include entering the supported system's Conditions and Required Actions or may specify other Required Actions. When a support system is inoperable and there is an LCO specified for it in the TS, the supported system(s) are required to be declared inoperable if detem1ined to be inoperable as a result of the support system inoperability. However, it is not necessary to enter into the supported systems' Conditions .and Required Actions unless directed to do so by the support system's Required Actions. The potential confusion and inconsistency of requirements related to the entry into multiple support and supported systems' LCOs' Conditions and Required Actions are eliminated by providing all the actions that are necessary to ensure the plant is maintained in a safe conditio11 in the support system's Required Actions.

However, there are instances where a support system's Required Action may either direct a supported system to be declared inoperable or direct entry Into Conditions and Required Actions for the supported systflm.

This may occur immediately or after some specified delay to perfom1 some other Required Action. Regardless of whether it is immediate or after some delay, when a support system's Required Action directs a supported system to be declared inoperable or directs entry into Conditions and Required Actions for a supported system, the applicable Conditions and Required Actions shall be entered in accordance with LCO 3.0.2 .

• SUSQUEHANNA - UNIT 1 3.0-9

Rev. 5 LCO Applicability

• BASES LCO 3.0.6 (continued)

Specification 5.5.11, "Safety Function Determination Program (SFDP),"

ensures loss of safety function is detected and appropriate actions are B 3.0 taken. Upon entry into LCO 3.0.6, an evaluation shall be made to determine if loss of safety function exists. Additionally, other limitations, remedial actions, or compensatory actions may be identified as a result of the support system inoperability and corresponding exception to entering supported system Conditions and Required Actions. The SFDP implements the requirements of LCO 3.0.6.

Cross dMsion checks to identify a loss of safety function for those support systems that support safety systems are required. The cross division check verifies that the supported systems of the redundant OPERABLE support system are OPERABLE, thereby ensuring safety function is retained. If this evaluation determines that a loss of safety function exists, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered.

This loss of safety function does not require the assumption of additional single failures or loss of offsite power or concurrent loss of emergency diesel generators. Since operation is being restrictecl-in accordance with the ACTIONS of the support system, any resulting temporary loss of redundancy or single failure protection is taken into account. Similarty, the ACTIONS for inoperable offsite ciri:::uit(s) and inoperable diesel generator(s) provide the necessary restriction for cross train inoperabilities. This explicit cross train verification for inoperable AC electrical power sources also acknowledges that supported system(s) are not declared inoperable solely as a result of inoperability of a normal or emergency electrical power source (refer to the definition of OPERABILITY).

When a loss of safety function is determined to exist, and the SFDP requires entry into the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists, consideration must be given to the specific type of function affected. Where a loss of safety function is solely due to a single TS support system (e.g., loss of automatic start due to inoperable instrumentation, or loss of pump suction source due to low tank leveQ the appropriate LCO is the LCO for the support system. The ACTIONS for a support system LCO adequately address the inoperabilities of that system without reliance on entering its supported system LCO. When the loss of function is the result of multiple support systems, the appropriate LCO is the LCO for the supported system.

SUSQUEHANNA - UNIT 1 3.0--10

Q Rev. 5 LCO Applicability B 3.0 BASES LCO 3.0.7 There are certain special tests and operations required to be performed at various times over the life of the unit These special tests and operations are necessary to demonstrate select unit performance characteristics, to perform special maintenance activities, and to perform special evolutions.

Special Operations LCOs in Section 3.1 O allow specified TS requirements to be changed to permit performances of these special tests and operations, which otherwise could not be performed if required to comply with the requirements of these TS. Unless otherwise specified, all the 0

other TS requirements remain unchanged. This will ensure all appropriate requirements of the MODE or other specified condition not directly associated with or required to be changed to perform the special test or operation will remain in effect.

The Applicability of a Special Operations LCO represents a condition not necessarily in compliance with the normal requirements of the TS.

Compliance with Special Operations LCOs is optional. A special operation may be performed either under the provisions of the appropriate Special Operations LCO or under the other applicable TS requirements. If it is desired to perform the special operation under the provisions of the Special Operations LCO, the requirements of the Special Operations LCO shall be followed. When a Special Operations LCO requires another LCO to be met, only the requirements of the LCO statement are required to be met regardless of that LCO's Applicability (i.e., should the requirements of this other LCO not be met, the ACTIONS of the Special Operations LCO apply, not the ACTIONS of the other LCO). However, there are instances where the Special Operations LCO ACTIONS may direct the other LCOs' ACTIONS be met The Surveillances of the other LCO are not required to be met, unless specified in the Special Operations LCO. If conditions exist such that the Applicability of any other LCO is met, all the other LCO's requirements (ACTIONS and SRs) are required to be met concurrent with the requirements of the Special Operations LCO.

LCO 3.0.8 LCO 3.0.8 establishes conditions under which systems are considered to remain capable of performing their intended safety function when associated snubbers are not capable of providing their associated support function(s). This LCO states that the supported system is not considered to be inoperable solely due to one or more snubbers not capable of performing their associated support function(s). This is appropriate because a limited length of time is allowed for maintenance, testing, or repair of one or more snubbers not capable of performing their associated support function(s) and appropriate compensatory measures of TRO 3.7.8 are followed. The snubber requirements do not meet the criteria in 10 CFR 50.36(c)(2)(ii), and, as such, are appropriate for control within the Technical Requirements Manual.

SUSQUEHANNA - UNIT 1 3.0-11

Rev. 5 LCO Applicability

• BASES LCO 3.0.8 (continued)

B 3.0 If the allowed time expires and the snubber(s) are unable to perfom1 their associated support function(s), the affected supported system's LCO(s) must be declared not met and the Conditions and Required Actions entered in accordance with LCO 3.0.2.

LCO 3.0.8.a applies when one or more snubbers are not capable of providing their associated support function(s) to a single train or subsystem of a multiple train or subsystem supported system or to a single train or subsystem supported system. LCO 3.0.8.a allows 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to restore the snubber(s) before declaring the supported system inoperable. The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time is reasonable based on the low probability of a seismic event concurrent with an event that would require operation of the supported system occurring while the snubber(s) are not capable of performing their associated support function and due to the availability of the redundant train of the supported system.

LCO 3.0.8.b applies when one or more snubbers are not capable of providing their associated support function(s) to more than one train or subsystem of a multiple train or subsystem supported system. LCO 3.0.8.b allows 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> to restore tile snubber(s) before declaring the supported system inoperable. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Completion Time is reasonable based on the low probability of a seismic event concurrent with an event that would require operation of the supported system occurring while the snubber(s) are not capable of perfom1ing their associated support function.

LCO 3.0.8 requires that risk be assessed and managed. Industry and NRG guidance on the implementation of 10 CFR 50.65(a)(4) (the Maintenance Rule) does not address seismic risk. However, use of LCO 3.0.8 should be considered with respect to other plant maintenance activities, and integrated into the existing Maintenance Rule process to the extent possible so that maintenance on any unaffected train or subsystem is properly controlled, and emergent issues are properly addressed. The risk assessment need not be quantified, but may be a qualitative awareness of the vulnerability of systems and components when one or more snubbers are not able to perfom1 their associated support function.

• • SUSQUEHANNA - UNIT 1 3.0-11a

Rev. 5 SR Applicabillty B 3.0 B 3.0 SURVEILLANCE REQUIREMENT (SR) APPLICABILITY BASES SRs SR 3.0.1 through SR 3.0.4 establish the general requirements applicable to all Specifications and apply at all times, unless otherwise stated.

SR 3.0.1 SR 3.0.1 establishes the requirement that SRs must be met during the MODES or other specified conditions in the Applicabillty for which the.

requirements of the LCO apply, unless otherwise specified in the indMdual SRs. This Specification is to ensure that Surveillances are performed to verify the OPERABILITY of systems and components, and that variables are within specified limits. Failure to meet a Surveillance within the specified Frequency, in accordance with SR 3.0.2, constitutes a failure to meet an LCO.

Systems and components are assumed to be OPERABLE when the associated SRs have been met. Nothing in this Specification, however, is to be construed as implying that systems or components are OPERABLE

• • when:

,a. The systems or components are known to be inoperable, although still b.

meeting the SRs; or The requirements of the Surveillance(s) are known to be not met between required Surveillance performances.

Surveillances do not have to be performed when the unit is in a MODE or other specified condition for which the requirements of the associated LCO are not applicable, unless otherwise specified. The SRs associated with a Special Operations LCO are only applicable when the Special Operations LCO is used as an allowable exception to the requirements of a Specification.

Unplanned events may satisfy the requirements (including applicable acceptance (?riteria) for a given SR. In this case, the unplanned event may be credited as fulfilling the performance of the SR. This allowance includes those SRs whose performance is normally precluded in a given MODE or other specified condition.

Surveillances, including Surveillances invoked by Required Actions, do not have to be performed on inoperable equipment because the ACTIONS define the remedial measures that apply. Surveillances have to be met and performed in accordance with SR 3.0.2, prior to returning equipment to OPERABLE status.

SUSQUEHANNA - UNIT 1 3.0-12

Rev. 5 SR Applicability

• BASES SR 3.0.1 (continued)

Upon completion of maintenance, appropriate post maintenance testing is required to declare equipment OPERABLE. This includes ensuring B 3.0 applicable Surveillances are not failed and their most recent performance is in accordance with SR 3.0.2. Post maintenance testing may not be possible in the current MODE or other specified conditions in the Applicability due to the necessary unit parameters not having been established. In these situations, the equipment may be considered OPERABLE provided testing has been satisfactorily completed to the extent possible and the equipment is not otherwise believed to be incapable of perfonning its function. This will allow operation to proceed to a MODE or other specified condition where other necessary post maintenance tests can be completed.

Some examples of this process are:

a. Control Rod Drive maintenance during refueling that requires scram testing at > 800 psi. However, if other appropriate testing is satisfactorily completed and the scram time testing of SR 3.1.4.3 is satisfied, the control rod can be considered OPERABLE. This allows startup to proceed to reach 800 psi to perform other necessary testing .

• b. High pressure coolant injection (HPCI) maintenance during shutdown that requires system functional tests at a specified pressure. Provided other appropriate testing is satisfactorily completed, startup can proceed with HPCI considered OPERABLE. This allows operation to reach the specified pressure to complete the necessary post maintenance testing.

SR 3.0.2 SR 3.0.2 establishes the requirements for meeting the specified Frequency for Surveillances and any Required Action with a Completion Time that requires the periodic perfonnance of the Required Action on a "once per... " interval.

SR 3.0.2 pennits a 25% extension .of the interval specified in the Frequency. This extension facilitates Surveillance scheduling and considers plant operating conditions that may not be suitable for conducting the Surveillance (e.g., transient conditions or other ongoing Surveillance or maintenance activities).

The 25% extension does not significantly degrade the reliability that results from performing the Surveillance at its specified Frequency. This is based on the recognition that the most probable result of any particular Surveillance being performed is the verification of conformance with the

• SRs. The exceptions to SR 3.0.2 are those Surveillances for which the SUSQUEHANNA - UNIT 1 3.0-13

Rev. 5 SR Applicability B 3.0 BASES SR 3.0.2 25% extension of the interval specified in the Frequency does not apply.

(continued) These exceptions are stated in the individual Specifications.

As stated in SR 3.0.2, the 25% extension also does not apply to the initial portion of a periodic Completion Time that requires perfonnance on a "once per... " basis. The 25% extension applies to each perfonnance after the initial performance. The initial perfonnance of the Required Action, whether it is a particular Surveillance or some other remedial action, is considered a single action with a single Completion Time. One reason for not allowing the 25% extension to this Completion 11me is that such an action usually verifies that no loss of function has occurred by checking the status of redundant or diverse components or accomplishes the function of the inoperable equipment in an alternative manner.

The provisions of SR 3.0.2 are not intended to be used repeatedly to extend Surveillance intervals (other than those consistent with refueling intervals) or periodic Completion Time intervals beyond those specified.

SR 3.0.3 SR 3.0.3 establishes the flexibility to defer declaring affected equipment inoperable or an affected variable outside the specified limits when a Surveillance has not been perfonned within the specified Frequency. A delay period of up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or up to the limit of the specified Frequency, whichever is greater, applies from the point in time that it is discovered that the Surveillance has not been perfonned in accordance with SR 3.0.2, and not at the time that the specified Frequency was not met.

This delay period provides adequate time to perform Surveillances that have been missed. This delay period permits the perfonnance of a Surveillance before complying with Required Actions or other remedial measures that might preclude performance of the Surveillance.

The basis for this delay period includes consideration of unit conditions, adequate planning, availability of personnel, the time required to perform the Surveillance, the safety significance of the delay in completing the required Surveillance, and the recognition that the most probable result of any particular Surveillance being performed is the verification of conformance with the requirements.

When a Surveillance with a Frequency based not on the time intervals, but upon specified unit conditions, operating situations, or requirements of regulations (e.g., prior to entering MODE 1 after each fuel loading, or in accordance with 10 CFR 50, Appendix j, as modified by approved exemptions, etc.) is discovered to not have been performed when specified, SR 3.0.3 allows for the full delay period of up to the specified SUSQUEHANNA- UNIT 1 3.0-14

Rev.5 SR Applicability B 3.0 BASES SR 3.0.3 Frequency to perform the Surveillance. However, since there is not a time (continued) interval specified, the missed Surveillance should be performed at the first reasonable opportunity.

SR 3.0.3 provides a time limit for, and allowances for the performance of Surveillances that become applicable as a consequence of MODE changes imposed by Required Actions.

SR 3.0.3 is only applicable if there is a reasonable expectation the associated equipment is OPERABLE or that variables are within limits, and it is expected that the Surveillance will be met when performed. Many factors should be considered, such as the period of time since the Surveillance was last performed, or whether the Surveillance, or a portion thereof, has ever been performed, and any other indications, tests, or activities that might support the expectation that the Surveillance will be met when performed. An example of the use of SR 3.0.3 would be a relay contact that was not tested as required in accordance with a particular SR, but previous successful performances of the SR included the relay contact; the adjacent, physically connected relay contacts were tested during the SR performance; the subject relay contact has been tested by another SR; or historical operation of the subject relay contact has been successful. It is not sufficient to infer the behavior of the associated equipment from the performance of similar equipment. The rigor of determining Whether there is a reasonable expectation a Surveillance will be met when performed should increase based on the length of time since the last performance of the Surveillance. If the Surveillance has been performed recently, a review of the Surveillance history and equipment performance may be sufficient to support a reasonable expectation that the Surveillance will be met When performed. For Surveillances that have not been performed for a long period or that have never been performed, a rigorous evaluation based on objective evidence should provide a high degree of confidence that the equipment is OPERABLE. The evaluation should be documented in sufficient detail to allow a knowledgeable individual to understand the basis for the determination.

Failure to comply with specified Frequencies for SRs is expected to be an infrequent occurrence. Use of the delay period established by SR 3.0.3 is a flexibility which is not intended .to be used repeatedly to extend Survemance intervals. While up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or the limit of the specified Frequency is provided to perform the missed Surveillance, it is expected that the missed Surveillance will be performed at the first reasonable opportunity. The determination of the first reasonable opportunity should Include consideration of the impact on plant risk (from delaying the Surveillance as well as any plant configuration changes required or shutting the plant down_ to perform the Surveillance) and impact on any analysis assumptions, in addition to unit conditions, planning, availability of SUSQUEHANNA - UNIT 1 3.0-15

Rev. 5 SR Applicability

• BASES SR 3.0.3 (continued) personnel, and the time required to perform the Surveillance. The risk impact should be managed through the program in place to implement 10 B 3.0 CFR 50.65(a)(4) and its implementation guidance, NRC Regulatory Guide 1.182, "Assessing and Managing Risk before Maintenance Activities at Nuclear Power Plants." This Regulatory Guide addresses consideration of temporary and aggregate risk impacts, detennination of risk management action thresholds, and risk management action up to and including plant shutdown. The missed Surveillance should be treated as an emergent condition as discussed in the R~gulatory Guide. The risk evaluation may use quantitative, qualitative, or blended methods. The degree of depth and rigor of the evaluation should be commensurate with the importance of the component. Missed Surveillances for important components should be analyzed quantitatively. If the results of the risk evaluation detennine the risk increase is significant, this evaluation should be used to detennlne the safest course of action. All missed Surveillances will be placed in the Corrective Action Program.

If a Surveillance is not completed within the allowed delay period, then the equipment is considered inoperable or the variable is considered outside the specified limits and the Completion Times of the Required Actions for the applicable LCO Conditions begin immediately upon expiration of the delay period. If a Surveillance is failed within the delay period, then the equipment is inoperable, or the variable is outside the specified limits and the Completion Times of the Required Actions for the applicable LCO Conditions begin immediately upon the failure of the Surveillance.

Completion of the Surveillance within the delay period allowed by this Specification, or within the Completion Time of the ACTIONS, restores compliance with SR 3.0.1.

SR 3.0.4 SR 3.0.4 establishes the requirement that all applicable SRs must be met before entry into a MODE or other specified condition in the Applicability.

This Specification ensures that system and component OPERABILITY requirements and variable limits are met before entry into MODES or other specified conditions in the Applicability for which these systems and components ensure safe operation of the unit. The provisions of this Specification should not be interpreted as endorsing the failure to exercise the good practice of restoring systems or components to OPERABLE status before entering an associated MODE or other specified condition in the Applicability.

A provision is included to allow entry into a MODE or other specified condition in the Applicability when an LCO is not met due to Surveillance not being met in accordance with LCO 3.0.4.

SUSQUEHANNA - UNIT 1 3.0-16

Rev. 5 SR Applicability 83.0 0

BASES SR 3.0.4 However, ln certain circumstances, failing to meet an SR will not result in (continued) SR 3.0.4 restricting a MODE change or other specified condition change. When a system, subsystem, division, component, device, or variable is inoperable or outside its specified limits, the associated SR(s) are not required to be performed, per SR 3.0.1, which states that Surveillances do not have to be performed on inoperable equipment.

When equipment is inoperable, SR 3.0.4 does not apply to the associated SR(s) since the requirement for the SR(s) to be performed is removed. Therefore, failing to perfonn the Surveillance(s) within the specified Frequency does not result in an SR 3.0.4 restriction to changing MODES or other specified conditions of the Applicability.

However, since the LCO is not met in this instance, LCO 3.0.4 will govern any restrictions that may (or may not) apply to MODE or other specified condition changes. SR 3.0.4 does not restrict changing MODES or other specified conditions of the Applicability when a Surveillance has not been performed within the specified Frequency, provided the requirement to declare the LCO not met has been delayed in accordance with SR 3.0.3.

The provisions of SR 3.0.4 shall not prevent entry into MODES or other specified conditions in the Applicability that are required to comply with ACTIONS. In addition, the provisions of SR 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that result from any unit shutdown. In this context, a unit shutdown is defined as a change in MODE or other specified condition in the Applicability associated wtth transitioning from MODE 1 to MODE 2 or MODE 3, MODE 2 to MODE 3 or MODE 4, and MODE 3 to MODE 4.

The precise requirements for perfonnance of SRs are specified such that exceptions to SR 3.0.4 are not necessary. The specific time frames and conditions necessary for meeting the SRs are specified in the Frequency, in the Surveillance, or both. This allows perfonnance of Surveillances when the prerequisite cor:tdition(s) specified in a Surveillance pro~ure require entry into the MODE or other specified condition in the Applicability of the associated LCO prior to the perfonnance or completion of a Surveillance. A Surveillance that could not be perfonned until after entering the LCOs Applicability, would have its Frequency specified such that it is not "due" until the specific conditions needed are met.

Alternately, the Surveillance may be stated in the fonn of a Note, as not required (to be met or performed) until a particular event, condition, or time has been reached. Further discussion of the specific fonnats of SRs' annotation is found in Section 1.4, Frequency.

SUSQUEHANNA - UNIT 1 3.0-17

Rev. 3 RPV Water Inventory Control Instrumentation

• B 3.3 B 3.3.5.2 INSTRUMENTATION Reactor Pr:essure Vessel (RPV) Water Inventory Control Instrumentation B 3.3.5.2 BASES BACKGROUND The RPV contains penetrations below the top of the active fuel (TAF) that have the potential to drain the reactor coolant inventory to below the T AF.

If the water level should drop below the T AF, the ability to remove decay heat is reduced, which could lead to elevated cladding temperatures and clad perforation. Safety Limit 2.1.1.3 requires the RPV water level to be above the top of the active irradiated fuel at all times to prevent such elevated cladding temperatures.

Technical Specifications are required by 10 CFR 50.36 to include limiting safety system settings (LSSS) for variables that have .sign!flcant safety functions. LSSS are defined by the regulation as 'Where a LSSS is specified for a variable on which a safety limit has been placed, the setting must be chosen so that automatic protective actions will correct the abnormal situation before a Safety Limit (SL) is exceeded." The Analytical Limit is the limit of the process variable at which a safety action is initiated to ensure that a SL is not exceeded. Any automatic protection action that occurs on reaching the Analytical Limit therefore ensur:es that the SL is not exceeded. However, in practice, the actual settings for automatic protection channels must be chosen to be more conservative than the Analytical Limit to account for instrument loop uncertainties related to the setting at which the automatic protective action would actually occur. The actual settings for the automatic isolation channels are the same as those established for the same functions in MODES 1, 2, and 3 LCO 3.3.6.1, "Primary Containment Isolation Instrumentation".

Wrth the unit in MODE 4 or 5, RPV water inventory control is not required .

to mitigate any events or accidents evaluated in the safety analyses.

RPV water inventory control is required in MODES 4 and 5 to protect Safety Limit 2.1.1.3 and the fuel cladding banier to prevent the release of radioactive material should a draining event occur. Under the definition of DRAIN TIME, some penetration flow paths may be excluded from the DRAIN TIME calculation if they will be isolated by valves that will close automatically without offsite power prior to the RPV water level being equal to the TAF when actuated by RPV water level isolation instrumentation.

• • SUSQUEt-JANNA- UNIT 1 3.3-132

Rev. 3 RPV Water Inventory Control Instrumentation B 3.3.5.2 BASES BACKGROUND The purpose of the RPV Water Inventory Control Instrumentation is to (continued) support the requirements of LCO 3.5.2, "Reactor Pressure Vessel (RPV)

Water Inventory Control," and the definition of DRAIN TIME. There are*

functions that support automatic isolation of Residual Heat Removal subsystem and Reactor Water Cleanup system penetration flow path(s) on low RPV water level.

APPLICABLE Wrth the unit in MODE 4 or 5, RPV water inventory control is not required SAFETY to mitigate any events or accidents evaluated in the safety analyses. RPV ANALYSES, LCO, water inventory control is required in MODES 4 and 5 to protect Safety and APPLICABILITY Limit 2.1.1.3 and the fuel cladding barrier to prevent the release of radioactive material should a draining event occur.

A double-ended guillotine break of the Reactor Coolant System (RCS) is not considered in MODcS 4 and 5 due to the reduced RCS pressure, reduced piping stresses, and ductile piping systems. Instead, an event is considered in which an initiating event allows draining of the RPV water inventory through a single penetration flow path with the highest flow rate, or the sum of the drain rates through multiple penetration flow paths susceptible to a common mode failure. It is assumed, based on engineering judgment, that while in MODES 4 and 5, orae low pressure ECCS injection/spray subsystem can be manually initiated to maintain adequate reactor vessel water level.

I As discussed in References 1, 2, 3, 4, and 5, operating experience has shown RPV water inventory to be significant to public health and safety.

Therefore, RPV Water Inventory Control satisfies Criterion 4 of 10 CFR 50.36(c)(2)(ii).

Permissive and interlock setpolnts are generally considered as nominal values without regard to measurement accuracy.

The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis.

1.. Not used

2. Not used

• • SUSQUEHANNA - UNIT 1 3.3-133

Rev. 3 RPV Water Inventory Control Instrumentation

• BASES APPLICABLE SAFETY RHR System Isolation 3.a - Reactor Vessel Water Level - Low, Level 3 B 3.3.5.2 ANALYSES, LCO, and APPLICABILITY The definition of DRAIN TIME allows crediting the closing *Of penetration (continued) flow paths that are capable of being isolated by valves that will close automatically without offsite power prior to the RPV water level being equal to the TAF when actuated by RPV water level isolation instrumentation. The Reactor Vessel Water Level - Low, Level 3 Function associated with RHR System isolation may be credited for automatic isolation of penetration flow paths associated with the RHR System.

Reactor Vessel Water Level - Lo1/4'., Level 3 signals are initiated from four level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Whne four channels (two channels per trip system) of the Reactor Vessel Water Level - Low, Level 3 Function are available, only two channels (all in the same trip system) are required to be OPERABLE.

The Reactor Vessel Water Level - Low, Level 3 Allowable Value was chosen to be the same as the Primary Containment Isolation

• Instrumentation Reactor Vessel Water Level - Low, Level 3 Allowable Value (LCO 3.3.6.1), since the capability to cool the fuel may be threatened.

The Reactor Vessel Water Level - Low, Level 3 Function is only required to be OPERABLE when automatic isolation of the associated penetration flow path is credited in calculating DRAIN TIME.

Reactor Water Cleanup (RWCU) System Isolation 4.a - Reactor Vessel Water .level - Low Low, Level 2 The definition of DRAIN TIME allows crediting the closing of penetration flow paths that are capable of being isolated by valves that will close automatically without offsite power prior to the RPV water level being equal to the TAF when actuated by RPV water level isolation instrumentation. The Reactor Vessel Water Level - Low Low, Level 2 Function associated with RWCU System isolation may be credited for automatic isolation of penetration flow paths associated with the RWCU System *

• SUSQUEHANNA - UNIT 1 3.3-134

Rev. 3 RPV Water Inventory Control Instrumentation

• BASES APPLICABLE SAFETY Reactor Water Cleanup (RWCU) System Isolation 4.a - Reactor Vessel Water level - Low Low, Level 2 (continued)

B 3.3.5.2 ANALYSES, LCO, and APPLICABILITY Reactor Vessel Water Level - Low Low, Level 2 signals are initiated from (continued) four level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. While four channels (two channels per trip system) of the Reactor Vessel Water Level - Low Low, Level 2 Function are available, only two channels (all in the same trip system) are required to be OPERABLE.

The Reactor Vessel Water Level - Low Low, Level 2 Allowable Value was chosen to be the same as the ECCS Reactor Vessel Water Level - Low Low, Level 2 Allowable Value (LCO 3.3.5.1), since the capability to cool the fuel may be threatened.

The Reactor Vessel Water Level - Low Low, Level 2 Function is only required to be OPERABLE when automatic isolation of the associated penetration flow path is credited in calculating DRAIN TIME.

• ACTIONS A Note has been provided to modify the ACTIONS related to RPV Water Inventory Control instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition discovered to be inoperable or not within limits will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable RPV Water Inventory Control instrumentation channels provide appropriate compensatory measures for separate inoperable Condition entry for each inoperable RPV Water Inventory Control instrumentation channel.

A 1, A.2.1 and A.2.2 RHR System Isolation, Reactor Vessel Water Level - Low Level 3, and Reactor Water Cleanup System, Reactor Vessel Water Level - Low Low, Level 2 functions are applicable when automatic isolation of the associated penetration flow path is credited in calculating DRAIN TIME. If the instrumentation is inoperable, Required Action A.1 directs immediate action to place the channel in trip. With the inoperable channel in the tripped condition, the remaining channel will isolate the penetration flow path on low water level. If both channels are inoperable and placed in trip, the penetration flow path will be isolated. Alternatively, Required Action A.2.1 requires the associated penetration flow path(s) to be immediately

• SUSQUEHANNA - UNIT 1 3.3-135

Rev. 3 RPV Water Inventory Control Instrumentation B 3.3.5.2 BASES ACTIONS A.1, A.2.1 and A.2.2 (continued)

(continued).

declared incapable of automatic isolation. Required Action A.2.2 directs initiating action to calculate DRAIN TIME. The calculation cannot credit automatic isolation of the affected penetration flow paths.

SURVEILLANCE The following SRs apply to each RPV Water Inventory Control instrument REQUIREMEN'fS Function in Table 3.3.5.2-1.

SR 3.3.5.2.1 Performance of .the CHANNEL CHECK ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or something everi more serious. A CHANNEL CHECK guarantees that undetected outright channel failure is lirnited;

• thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL FUNCTIONAL TEST.

Agreement criteria are determined by the plant staff, based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated wtth the channels required by the LCO.

SR 3.3.5.2.2 A CHANNEL FUNCTIONAL T6ST is performed on each required channel to ensure that the entire channel will perform ,the intended function .

• SUSQUEHANNA - UNIT 1 3.3-136

Rev. 3 RPV Water Inventory Control Instrumentation

• BASES SURVEILLANCE REQUIREMENTS SR 3.3.5.2.2 (continued)

B 3.3.5.2 (continued) This SR is modified by a Note that provides a general exception to the definition of CHANNEL FUNCTIONAL TEST. This exception is necessary because the design of instrumentation does not facilitate functional testing of all required contacts of the relay which input into the combinational logic.

Performance of such a test could result in a plant transient or place the plant in an undue risk situation. Therefore, for this SR, the CHANNEL FUNCTIONAL TEST verffies acceptable response by verifying the change of state of the relay which inputs into the combinational logic. The required contacts not tested during the CHANNEL FUNCTIONAL TEST are tested under the LOGIC SYSTEM FUNCTIONAL TEST, SR 3.3.5.2.3. This is acceptable because operating experience shows that the contacts not tested during the CHANNEL FUNCTIONAL TEST nom,ally pass the LOGIC SYSTEM FUNCTIONAL TEST, and the testing methodology minimizes the risk of unplanned transients.

Any setpoint adjusbnent shall be consistent with the assumptions of the current plant specific setpoint methodology.

The Surveillance Frequency is controlled under the Surveillance

• • REFERENCES Frequency Control Program.

1. Information Notice 84-81 "Inadvertent Reduction in Primary Coolant Inventory in Boiling Water Reactors During Shutdown and Startup,"

November 1984.

2. Information-Notice 86-74, "Reduction of Reactor Coolant Inventory Because of Misalignment of RHR Valves," August 1986.

3. Generic Letter 92-04, "Resolution of the Issues Related to Reactor Vessel Water Level Instrumentation in BWRs Pursuant to 10 CFR 50.54(F), "August 1992.

4. NRC Bulletin 93-03, "Resolution of Issues Related to Reactor Vessel Water Level Instrumentation in BWRs," May 1993.

5. Information Notice 94-52, "Inadvertent Containment Spray and Reactor Vessel Draindown at Millstone 1," July 1994.

• • SUSQUEHANNA - UNIT 1 3.3-137

Rev. 3 RPV Water Inventory Control Instrumentation

• BASES B 3.3.5.2

• • THIS PAGE INTENTIONALLY LEFT BLANK

• SUSQUEHANNA - UNIT 1 3.3-138

Rev. 3 RPV Water Inventory Control Instrumentation

• BASES B 3.3.5.2

• THIS PAGE INTENTIONALLY LEFT BLANK

• SUSQUEHANNA - UNIT 1 3.3-139

Rev.4 LOP Instrumentation B 3.3.8.1 B 3.3 INSTRUMENTATION B 3.3.8.1 Loss of Power (LOP) Instrumentation BASES BACKGROUND Successful operation of the required safety functions of the Emergency Core Cooling Systems (ECCS) is dependent upon the availability of adequate power sources for energizing the various components such as pump motors, motor operated valves, and the associated control components. The LOP instrumentation monitors the 4.16 kV emergency buses. Offsite power is the preferred source of power for the 4.16 kV emergency buses. If the monitors detennine that insufficient power is available, the buses are disconnected from the offsite power sources and connected to the onsite diesel generator (DG) power sources.

Each 4.16 kV emergency bus has its own independent LOP instrumentation and associated trip logic. The voltage for each bus is monitored at three levels, which can be considered as three different undervoltage Functions: Loss of Voltage(< 20%), 4.16 kV Emergency Bus Undervoltage Degraded Voltage LOCA (< 93%), and 4.16 kV Emergency Bus Undervoltage Low Setting (Degraded Voltage)(< 65%). Each Function, with the exception of the Loss of Voltage relays is monitored by two undervoltage relays for each emergency bus, whose outputs are arranged in a twcrout-of-two logic configuration. The Loss of Voltage Function is monitored by one undervoltage relay for each emergency bus, whose output is arranged in a one-out-of-one logic configuration.

• When voltage degrades below the setpoint, the channel output relay actuates, which then outputs a LOP trip signal to the trip logic.

APPLICABLE The LOP instrumentation is required for Engineered Safety Features to SAFETY function in any accident with a loss of offsite power. The Unit 1 LOP .

ANALYSES, instrumentation is required to be operable for Unit 2. Unit 2 T.S. 3.3.8.1 is LCO, and affected by this requirement The required channels of LOP

• APPLICABILITY instrumentation ensure that the ECCS and other assumed systems powered from the DGs, provide plant protection in the event of any of the Reference 1 and 2 analyzed accidents in which a loss of offsite power ls assumed. The initiation of the DGs on loss of offsite power, and subsequent initiation of the ECCS, ensure that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.

SUSQUEHANNA - UNIT 1 3.3-205 J

Rev.4

, BASES APPLICABLE LOP Instrumentation B 3.3.8.1 Accident analyses credit the loading of the DG based on the loss of offsite SAFETY power during a loss of coolant accident The diesel starting and loading ANALYSES, times have been included in the delay time associated with each safety LCO, ar:id .system component requiring DG supplied power following a loss of offsite APPLICABILITY . power.

(continued)

The LOP instrumentation satisfies Criterion 3 of the NRG Policy Statement (Ref. 3)

The OPERABILITY of the LOP instrumentation is dependent upon the OPERABILITY of the individual instrumentation channel Functions specified in Table 3.3.8.1-1. Each Function must have a required number of OPERABLE channels per 4.16 kV emergency bus, with their setpoints within the specified Allowable Values. A channel is Inoperable if its actual trip setpoint is not within its required Allowable Value. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions.

The Allowable Values are specified for each Function in the Table. Trip setpoints are specified in the system calculations. The setpoints are selected to ensure that the setpoints do not exceed the Allowable Value.

Operation with a trip setpoint less conservative than the nominal trip setpoint, but within the Allowable Value, is acceptable. Trip setpoints are those predetermined values of output at which an action should take place.

The setpoints are compared to the actual process parameter (e.g.,

degraded voltage), and when the measured output value of the process parameter reaches the setpoint, the associated device changes state. The Allowable Values are derived from the limiting values of the process parameters obtained from the safety analysis. The trip setpoints are then derived based on engineering judgement.

The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis.

1. 4.16 kV Emergency Bus Undervoltage (Loss of Voltage < 20%)

Loss of voltage on a 4.16 kV emergency bus indicates that offsite power may be completely lost to the respective emergency bus and is unable to supply sufficient power for proper operation of the applicable equipment.

Therefore, the power supply to the bus is transferred from offsite power to DG power when the voltage on the bus drops below the Loss of Voltage Function Allowable Values (loss of voltage with a short time delay). This ensures that adequate power will be available to the required equipment.

SUSQUEHANNA - UNIT 1 3.3-206

0 Rev.4

, BASES APPLICABLE LOP Instrumentation

'1. 4.16 kV Emergency Bus Undervoltage (Loss of Voltage< 20%)

B 3.3.8.1 SAFETY (continued)

ANALYSES LCO, and The Bus Undervoltage Allowable Values !=ire low enough to prevent APPLICABILITY inadvertent po'W8r supply transfer, but high enough to ensure that power is (continued) available to the required equipment. The Time Delay Allowable Values are long enough to provide time for the offsite power supply to recover to normal voltages, but short enough to ensure that power Is available ,to the required equipment One channel of 4.16 kV Emergency Bus Undervoltage (Loss of Voltage)

Function per associated emergency bus is required to be OPERABLE when the associated DG is required to be OPERABLE to ensure that no single instrument failure can preclude the DG function. 4.16 kV Emergency Bus Undervoltage (Loss of Voltage) relay controls and provides a permissive to allow closure of the associated alternate source breaker and the associated DG breaker. (one channel input to each of the four DGs.)

Refer to LCO 3.8.1, "AC Sources--Operatin g" for Applicability Bases for the DGs.

2., 3. 4.16 kV Emergency Bus Undervoltage (Degraded Voltage)

A reduced voltage condition on a 4 kV emergency bus indicates that, while offsite power may not be completely lost to the respective emergency bus, available power may be insufficient for starting large ECCS motors without risklng damage to the motors that could disable the ECCS function.

Therefore, power supply to the bus is transferred from offsite power to onsite DG power when there is no offsite po'vVSr or a degraded power supply to the bus. This transfer will occur only if the voltage of the primary and alternate power sources drop below the Degraded Voltage Function Allowable Values (degraded voltage with a time delay) and the source breakers trip which causes the DG to start. This ensures that adequate power 'Nill be available to the required equipment.

SUSQUEHANNA - UNIT 1 3.3-207

Rev.4 LOP Instrumentation B 3.3.8.1 BASES APPLICABLE 2., 3. 4.16 kV Emergency Bus Undervoltage {Degraded Voltage)

SAFETY (continued)

ANALYSES, LCO, and . Two Functions are provided to monitor degraded voltage at two different APPLICABILllY levels. These Functions are the Degraded Voltage LOCA (< 93%) and (continued) Degraded Voltage Low Setting(< 65%). These relays respond to degraded voltage as follows: 93% for approximately 5 minutes (when no LOCA signal is present) and approximately 1O seconds (with a LOCA signal present), and 65% (Degraded Voltage Low Setting). The circuitry is designed such that with the LOCA signal present, the non-LOCA time delay is physically bypassed. The Degraded Voltage LOCA Function preserves the assumptions of the LOCA analysis and the Degraded Voltage Low Setting Function preserves the assumptions of the accident sequence analysis in the FSAR.

The Bus Undervoltage Allowable Values are low enough to prevent inadvertent power supply transfer, but high enough to ensure that sufficient power is _available to the required equipment The Time Delay Allo\Ni:lble Values are long enough to provide time for the offsite po'NE!r supply to recover to normal voltages, but short enough to ensure that sufficient power is available to the required equipment.

TVll'O channels of 4.16 kV Emergency Bus Undervoltage (Degraded Voltage) per Function (Functions 2 and 3) per associated bus are required to be OPERABLE when the associated DG is required to be OPERABLE.

This ensures no single instrument failure can preclude the start of DGs (each logic inputs to each of the four DGs). Refer to LCO 3.8.1 for Applicability Bases for the DGs.

ACTIONS A Note has been provided to modify the ACTIONS related to LOP instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be Inoperable or not within limits, will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable LOP instrumentation channels provide appropriate compensatory measures for separate inoperable channels. As such, a Note has been provided that allows separate Condition entry for each

. Inoperable LOP instrumentation channel.

SUSQUEHANNA - UNIT 1 3.3-208

Rev. 4 LOP Instrumentation B 3.3.8.1 BASES ACTIONS A.1 (continued)

Required Action A.1 directs entry Into the appropriate Condition referenced in Table 3.3.8.1-1. The applicable Condition specified in the Table is Function dependent Each time a channel is discovered inoperable, Condition A Is entered for that channel and provides for transfer to the appropriate subsequent Condition.

8.1 With one or more channels of a Function inoperable, the Function is not capable of performing the intended function. Therefore, only 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> is allowed to restore the inoperable channel to OPERABLE status. If the inoperable channel cannot be restored to OPERABLE status within the allqwable out of service time, the channel must be placed in the tripped condition per Required Action 8.1. Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore capability to accommodate .a single failure (within the LOP instrumentation), and allow operation to continue. Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing the channel in trip would result in a DG initiation), Condition D must be entered and its Required Action taken.

The Completion Time IS intended to allow the operator time to evaluate and repair any discovered inoperabilities. The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Completion Time is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.

C.1 With one channel of the Function inoperable, the Function is not capable of performing the intended function. Therefore, only 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> is allowed to restore the inoperable channel to OPERABLE status. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, Condition D must be entered and its Required Action taken.

The Completion Time is intended to allow the operator time to evaluate and repair any discovered lnoperabilities. The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Completion Time is acceptable because it minimizes risk while allowing time for restoration of channels .

• SUSQUEHANNA - UNIT 1 3.3-209

Rev.4 LOP Instrumentation B 3.3.8.1 BASES ACTIONS fil (continued)

If the Required Action and associated Completion Times of Conditions B or C are not met, the associated Function is not capable of performing the intended function. Therefore, the associated DG(s) is declared inoperable immediately for both Unit 1 and Unit 2. This requires entry into applicable Conditions and Required Actions of LCO 3.8:1 for both Unit 1 and Unit 2, which provide appropriate actions for the inoperable DG(s).

SURVEILLANCE As noted at the beginning of the SRs, the SRs for each LOP REQUIREMENTS instrumentation Function are located in the SRs column of Table 3.3.8.1-1.

The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, enby into associated Condttions and Required Actions may be delayed for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided the associated Function maintains DG initiation capability. Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken.

SR 3.3.8.1.1 Performance of the CHANNEL CHECK ensures that a gross failure of Instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly betwveen each CHANNEL CALIBRATION.

Agreement criteria which are determined by the plant staff based on an investigation of a combination of the channel instrument uncertainties, may be used to support this parameter comparison and Include indication and readability. If a channel is outside the criteria, it may be an Indication that the instrument has drifted outside its limit.

• SUSQUEHANNA - UNIT 1 3.3-210

Rev.4 LOP Instrumentation B 3.3.8.1 BASES SURVEILLANCE SR 3.3.8.1.1 (continued)

REQUIREMENTS (continued) The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The CHANNEL CHECK supplements less formal checks of channels during normal operational use of the displays associated with channels required by the LCO.

SR 3.3.8.1.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.8.1.3 A CHANNEL CALIBRATION verifies that the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.

Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.8.1.4 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required actuation logic for a specific channel. The system functional testing performed in LCO 3.8.1 and LCO 3.8.2 overlaps this Surveillance to provide complete testing of the assumed safety functions.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SUSQUEHANNA - UNIT 1 3.3-211

Rev. 4 LOP Instrumentation B 3.3.8.1 BASES REFERENCES 1. FSAR, Section 6.3.

2. FSAR, Chapter 15.

3. Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 32193)

SUSQUEHANNA - UNIT 1 3.3-212

Rev.4 RPV Water Inventory Control

. B 3.5.2 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS), REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL, AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM B 3.5.2 Reactor Pressure Vessel (RPV) Water Inventory Control BASES BACKGROUND The RPV contains penetrations below the top of the active fuel (TAF) that have the potential to drain the reactor coolant inventory to below the TAF.

If the water level should drop below the TAF, the ability to remove decay heat is reduced, which could lead to elevated cladding temperatures and clad perforation. Safety Limit 2.1.1.3 requires the RPV water level to be above the top of the active irradiated fuel at all times to prevent such elevated cladding temperatures.

APPLICABLE With the unit in MODE 4 or 5, RPV water inventory control is not required SAFElY to mitigate any events or accidents evaluated in the safety analyses.

ANALYSES RPVwater inventory control is required in MODES 4 and 5_to protect Safety Limit 2.1.1.3 and the fuel cladding barrier to prevent the release of radioactive material to the environment should an unexpected draining event occur.

A double-ended guillotine break of the Reactor Coolant System (RCS) is not considered in MODES 4 and 5 due to the reduced RCS pressure, reduced piping stresses, and ductile piping systems. Instead, an event is considered in which an initiating event allows draining of the RPV water inventory through a single penetration flow path with the highest flow rate, or the sum of the drain rates through multiple penetration flow paths susceptible to a common mode failure (an event that creates a drain path through multiple vessel penetrations located below top of active fuel, such as loss of normal power, or a single human error). It Is assumed, based on engineering judgment, that whlle In MODES 4 and 5, one low pressure ECCS injection/spray subsystem can maintain adequate reactor vessel water level.

As discussed in References 1, 2, 3, 4, and 5, operating experience has shown RPV water inventory to be significant to public health and safety.

Therefore, RPV Water Inventory Control satisfies Criterion 4 of 10 CFR 50.36(c)(2)(iQ.

SUSQUEHANNA - UNIT 1 3.5-17

Rev.4 RPV Water Inventory Control B 3.5.2 BASES LCO The RPV water level must be controlled in MODES 4 and 5 to ensure that If an unexpected draining event should occur, the reactor coolant water level remains above the top of the active irradiated fuel as required by Safety Limit 2.1.1.3.

The Limiting Condition for Operation (LCO) requires the DRAIN TIME of RPV water inventory to the TAF to be~ 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. A DRAIN TIME of 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> is considered reasonable to identify and initiate action to mitigate unexpected draining of reactor coolant. An event that could cause loss of RPV water inventory and result in the RPV water level reaching the TAF in greater than 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> does not represent a significant challenge to Safety Limit 2.1.1.3 and can be managed as part of normal plant operation.

One low pressure ECCS Injection/spray subsystem is required to be OPERABLE and capable of being manually aligned and started from the control room to provide defense-in- depth should an unexpected draining event occur. OPERABILITY of the ECCS injection/spray subsystem includes any necessary valves, instrumentation, or controls needed to manually align and start the subsystem from the control room. A low pressure ECCS injection/spray subsystem consists of either one Core Spray (CS) subsystem or one Low Pressure Coolant Injection (LPCI) subsystem. Each CS subsystem consists of one motor driven pump, piping, and valves to transfer water from the suppression pool or condensate storage tank (CST) to the RPV. Each LPCI subsystem consists of one motor driven pump, piping, and valves to transfer water from the suppression pool to the RPV. In MODES 4 and 5, the RHR System cross tie valves are not required to be closed.

The LCO is modified by a Note which allows a required LPCI subsystem to be considered OPERABLE during alignment and operation for decay heat removal if capable of being manually realigned (remote or locaQ to the LPCI mode and is not otherwise inoperable. Alignment and operation for

• decay heat removal includes when the required RHR pump is not operating or when the system is realigned from or to the RHR shutdown cooling mode. This allowance is necessary since the RHR System may be required to operate in the shutdown cooling mode to remove decay heat and sensible heat from the reactor. Because of the restrictions on DRAIN TIME, sufficient time will be avallable following an unexpected draining event to manually align and initiate LPCI subsystem operation to maintain RPV water inventory prior to the RPV water level reaching the TAF.

SUSQUEHANNA - UNIT 1 3.5-18

Rev.4 RPV Water Inventory Control B 3.5.2 BASES APPLICABILITY RPV water Inventory control ls required in MODES 4 and 5. Requirements on water inventory control in other MODES are contained in LCOs in Section 3.3, "Instrumentation/ and other LCOs in Section 3.5, "ECCS, RPV Water Inventory Control, and RCIC System." RPV water inventory control is required to protect Safety Limit 2.1.1.3 which is applicable whenever irradiated fuel is in the reactor vessel.

ACTIONS A.1 and 8.1 If the required low pressure ECCS injection/spray subsystem is Inoperable, it must be restored to OPERABLE status within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. In this Condition, the LCO controls on DRAIN TIME minimize the possibility that an unexpected draining event could necessitate the use of the ECCS injection/spray subsystem, however the defense-in-depth provided by the ECCS injection/spray subsystem Is lost. The 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Completion Time for restoring the required low pressure ECCS injection/spray subsystem to OPERABLE status is based on engineering judgment that considers the LCO controls on DRAIN TIME and the low probability of an unexpected draining event that would result in loss of RPV water inventory.

lfthe inoperable ECCS injection/spray subsystem is not restored to OPERABLE status within the required Completion Time, action must be initiated immediately to establish a method of water injection capable of operating without offsite electrical power. The method of water injection includes the necessary instrumentation and controls, water sources, and pumps and valves needed to add water to the RPV or refueling cavity should an unexpected draining event occur. The method of water injection may be manually initiated and may consist of one or more systems or subsystems, and must be able to access water inventory capable of maintaining the RPV water level above the TAF for ~ 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. If recirculation of injected water would occur, it may be credited in determining the necessary water volume.

C.1, C.2, and C.3 Wrth the DRAIN TIME less than 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> but greater than or equal to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, compensatory measures should be taken to ensure the ability to implement mitigating actions should an unexpected draining event occur.

Should a draining event lower the reactor coolant level to below the T AF, there is potential for damage to the reactor fuel cladding and release of radioactive material. Additional actions are taken to ensure that radioactive material will be contained, diluted, and processed prior to being released to the environment.

SUSQUEHANNA - UNIT 1 3.5-19

, (

Rev.4 RPV Water Inventory Control B 3.5.2 BASES ACTIONS C.1, C.2, and C.3 (continued)

(continued)

The secondary containment provides a controlled volume in which fission products can be contained, diluted, and processed prior to release to the environment. Required Action C.1 requires verification of the capability to establish the secondary containment boundary in less than the DRAIN TIME.

The required verification confim,s actions to establish the secondary containment boundary ar:e preplanned and necessary materials are available. The secondary containment boundary is considered established when one Standby Gas Treatment (SGT) subsystem is capable of maintaining a negative pressure in the secondary containment with respect to the environment. Verification that the secondary containment boundary can be established must be perfom,ed within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The required verification is an administrative activity and does not require manipulation or testing of equipment. Secondary containment penetration flow paths fom, a part of the secondary containment bound?ry. Required Action C.2 requires verification of the capability to isolate each secondary containment penetration flow path in less than the DRAIN TIME. The required verification confim,s actions to isolate the secondary containment penetration flow paths are preplanned and necessary materials are available. Power operated valves are not required to receive automatic isolation signals if they can be closed manually within the required time.

Verification that the secondary containment penetration flow paths can be isolated must be performed within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The required verification is an administrative activity and does not require manipulation or testing of equipment.

One SGT subsystem is capable of maintaining the secondary containment at a negative pressure with respect to the environment and filter gaseous releases. Required Action C.3 requires verification of the capability to place one SGT subsystem in operation in less than the DRAIN TIME. The required verification confirms aetions to place a SGT subsystem in operation are preplanned and necessary materials are available. Verification that a SGT subsystem can be placed in operation must be performed within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The required verification is an administrative activity and does not require manipulation or testing of equipment.

Required Actions C.1, C.2, and C.3 are considered to be met when secondary containment, secondary containment penetrations, arid the SGT System are OPERABLE in accordance with LCO 3.6.4.1, LCO 3.6.4.2, and LCO 3.6.4.3.

SUSQUEHANNA - UNIT 1 3.5-20

Rev.4 RPV Water Inventory Control B 3.5.2 BASES ACTIONS D.1, D.2, D.3, and D.4 (continued)

With the DRAIN TIME less than 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, mitigating actions are implemented in case an unexpected draining event should occur. Note that if the DRAIN TIME is less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, Required Action E.1 is also applicable.

Required Action D.1 requires immediate action to establish an additional method of water injection augmenting the ECCS injection/spray subsystem requ'ired by the LCO. The additional method of water injection includes the necessary instrumentation and controls, water sources, and pumps and valves needed to add water to the RPV or refueling cavity should an unexpected draining event occur. The Note to Required Action D.1 states that either the ECCS injection/spray subsystem or the additional method of water injection must be capable of operating without offsite electrical power. The additional method of water injection may be manually initiated and may consist of one or more systems or subsys-tems. The additional method of water injection must be able to access water inventory capable of being injected to maintain the RPV water level above the T AF for o:: 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The additional method of water injection and the ECCS injection/spray subsystem may share all or part of the same water sources. If recirculation of injected water would occur, it may be credited in determining the required water volume.

Should a draining event lower the reactor coolant level to below the T AF, there is potential for damage to the reactor fuel cladding and release of radioactive material. Additional actions are taken to ensure that radioactive material will be contained, diluted, and processed prior to being released to

• the environment The secondary containment provides a control volume in which fission-products can be contained, diluted, and processed prior to release to the environment. Required Action D.2 requires that actions be immediately initiated to establish the secondary containment boundary. With the secondary containment boundary established, one SGT subsystem is capable of maintaining a negative pressure in the secondary containment with respect to the environment.

The secondary containment penetrations form a part of the secondary containment boundary. Required Action D.3 requires that actions be immediately Initiated to verify that each secondary containment penetration flow path is isolated or to verify that it can be automatically or manually isolated from the control room.

SUSQUEHANNA - UNIT 1 3.5-21

Rev.4 RPV Water Inventory Control 8 3.5.2 BASES ACTIONS D.1, D.2, D.3, and D.4 (continued)

(continued)

One SGT subsystem Is capable of maintaining the secondary containment at a negative pressure with respect to the environment and filter gaseous releases. Required Action D.4 requires that actions be immediately initiated to verify that at least one SGT subsystem is capable of being placed in operation. The required verification is an administrative activity and does not require manipulation or testing of equipment.

Required Actions D.2, D.3, and D.4 are considered to be met when secondary containment, secondary containment penetrations, and the SGT System are OPERABLE in accordance with LCO 3.6.4.1, LCO 3.6.4.2, and LCO 3.6.4.3.

E.1 If the Required Actions and associated Completion times of Conditions C or D are not met or if the DRAIN TIME is less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, actions must be initiated immediately to restore the DRAIN TIME to~ 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. In this condition, there may be insufficient time to respond to an unexpected draining event to prevent the RPV water inventory from reaching the TAF.

Note that Required Actions D.1, D.2, D.3, and D.4 are also applicable when DRAIN TIME is less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

SURVEILLANCE SR 3.5.2.1 REQUIREMENTS This Surveillance verifies that the DRAIN TIME of RPV water inventory to the T AF is ~ 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The period of 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> is considered reasonable to identify and initiate action to mitigate draining of reactor coolant. Loss of RPV water inventory that would result in the RPV water level reaching the T AF in greater ,than 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> does not represent a significant challenge to Safety Limit 2.1.1.3 and can be managed as part of nom,al plant operation.

The definition of DRAIN TIME states that realistic *cross-sectional areas and drain rates are used in the calculation. A realistic drain rate may be determined using a slngle, step-wise, or integrated calculation considering the changing RPV water level during a draining event For a Control Rod RPV penetration flow path with the Control Rod Drive Mechanism removed and not replaced with a blank flange, the realistic cross-sectional area is based on the control rod blade seated in the control rod guide tube. If the control rod blade will be raised from the penetration to adjust or verify seating of the blade, the exposed cross-sectional area of the RPV penetration flow path Is used.

SUSQUEHANNA - UNIT 1 3.5-22

Rev. 4 RPV Water Inventory Control B 3.5.2 BASES SURVEILLANCE SR 3.5.2.1 (continued)

REQUIREMENTS (continued) The definition of DRAIN TIME excludes from the calculation those penetration flow paths connected to an intact closed system, or isolated by manual or automatic valves that are closed and administratively controlled, blank flanges, or other devices that prevent flow of reactor coolant through the penetration flow paths. A blank flange or other bolted device must be connected with a sufficient number of bolts to prevent draining. Normal or expected leakage from closed systems or past isolation devices is permitted. Determination that a system Is intact and closed or isolated must COJ1Sider the status of branch lines.

The Residual Heat Removal (RHR) Shutdown Cooling System is only considered an intact closed system when misalignment issues (Reference

6) have been precluded by functional valve interlocks or by isolation devices, such that redirection of RPV water out of an RHR subsystem is precluded. Further, RHR Shutdown Cooling System is only considered an intact closed system if its controls have not been transferred to Remote Shutdown, which disables the interlocks and isolation signals.

The excluslon of a single penetration flow path, or multiple penetration flow paths susceptible to a common mode failure, from the determination of DRAIN TIME should consider the effects of temporary alterations in support of maintenance (rigging, scaffolding, temporary shielding, piping plugs, freeze seals, etc.). If reasonable controls are implemented to prevent such temporary alterations from causing a draining event from a closed system or between the RPV and the isolation device, the effect of the temporary alterations on DRAIN TIME need not be considered.

Reasonable controls include, but are not limited to controls consistent with the guidance in NU MARC 93-01, "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," Revision 4, NUMARC 91-06, "Guidelines for Industry Actions to Assess Shutdown Management," or commitments to NUREG-0612, "Control of Heavy Loads at Nuclear Power Plants.D Surveillance Requirement 3.0.1 requires SRs to be met between performances. Therefore, any changes in plant conditions that would change the DRAIN TIME requires that a new DRAIN TIME be determined.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SUSQUEHANNA - UNIT 1 3.5-23

Rev.4 RPV Water Inventory Control B 3.5.2 BASES SURVEILLANCE SR 3.5.2.2 and SR 3.5.2.3.

REQUIREMENTS (continued) The minimum water level of 20 ft 0 inches required for the suppression pool is periodically verified to ensure that the suppression pool will provide adequate net positive suction head (NPSH) for the CS subsystem or LPCI subsystem pump, recirculation volume, and vortex prevention. With the suppression pool water level less than the required limit, the required ECCS injection/spray subsystem is inoperable unless aligned to an OPERABLE CST.

The required CS System Is considered OPERABLE if it can take suction from the CST, and the CST water level is sUfficient to provide the required NPSH for the CS pump. Therefore, a verification that either the suppression pool water level is :2:: 20 ft 0 inches or that a required CS subsystem is aligned to take suction from the CST and the CST contains :2::

135,000 gallons of water, equivalent to 49% of capacity, ensures that the CS Subsystem can supply at least 135,000 gallons of makeup water to the RPV.

The Surveillance Frequency is controlled Under the Surveillance Frequency Control Program.

SR 3.5.2.4 The flow path piping has the potential to develop voids and pockets of entrained air. Maintaining the pump discharge lines of the required ECCS injection/spray subsystems full of water ensures that the ECCS subsystem will perform properly. This may also prevent a water hammer following an ECCS actuation. One acceptable method of ensuring that the lines are full is to vent at the high points.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.5.2.5 Not used SUSQUEHANNA - UNIT 1 3.5-24

Rev. 4 RPV Water Inventory Control B 3.5.2 BASES SURVEILLANCE SR 3.5.2.6 REQUIREMENTS (continued) Verifying that the required ECCS injection/spray subsystem can be manually aligned, and the pump started and operated for at least 1O minutes demonstrates that the subsystem is available to mitigate a draining event. This SR is modified by two Notes. Note 1 states that testing the ECCS injection/spray subsystem may be done through the test return line to avoid overfilling the refueling cavity. Note 2 states that credit for meeting the SR may be taken for normal system operation that satisfies the SR, such as using the RHR mode of LPCI for ~ 10 minutes.

The minimum operating time of 10 minutes was based on engineering judgment.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.5.2.7 Verifying that each valve credited for automatically isolating a penetration flow path actuates to the isolation position on an actual or simulated RPV water level isolation signal is required to prevent RPV water inventory from dropping below the TAF should an unexpected draining event occur ..

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.5.2.8 This Surveillance verifies that a required CS subsystem or LPCI subsystem can be manually aligned and started from the control room, including any necessary valve alignment, instrumentation, or controls to transfer water from the suppression pool or CST to the RPV.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

This SR is modified by a Note that excludes vessel injection/spray during the Surveillance. Since all active components are testable and full flow can be demonstrated by recirculation through the test line, coolant injection into the RPV is not required during the Surveillance .

• SUSQUEHANNA - UNIT 1 3.5-25

Rev.4 RPV Water Inventory Control B 3.5.2 BASES REFERENCES 1. Information Notice 84-81 "Inadvertent Reductron in Primary Coolant Inventory in Boiling Water Reactors During Shutdown and Startup,"

November 1984.

2. Information Notice 86-74, "Reduction of Reactor Coolant Inventory Because of Misalignment of RHR Valves," August 1986.

3. Generic Letter 92-04, "Resolution of the Issues Related to Reactor Vessel Water Level Instrumentation in BWRs Pursuant to 10 CFR 50.54(f), " August 1992.

4. NRC Bulletin 93-03, "Resolution of Issues Related to Reactor Vessel Water Level Instrumentation in BWRs," May 1993.

5. Information Notice 94-52, "Inadvertent Containment Spray and Reactor Vessel Draindown at Millstone 1," July 1994.

6. General Electric Service Information Letter No. 388, "RHR Valve Misalignment During Shutdown Cooling Operation for BWR 3/4/5/6,"

February 1983.

• SUSQUEHANNA - UNIT 1 3.5-26

Rev. 17 PCIVs B 3.6.1.3 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.3 Primary Containment Isolation Valves (PCIVs)

BASES BACKGROUND The function of the PC IVs, in combination with other accident mitigation systems, including secondary containment bypass valves that are not PCIVs, is to limit fission product release during and following postulated Design Basis Accidents (DBAs) to within limits. Primary containment isolation within the time limits specified for those isolation valves designed to close automatically ensures that the release of radioactive material to the environment will be consistent with the assumptions used in the analyses for a OBA.

The OPERABILITY requirements for PCIVs help ensure that an adequate primary containment boundary is maintained during and after an accident by minimizing potential paths to the environment.

Therefore, the OPERABILITY requirements provide assurance that primary containment function assumed in the safety analyses will be maintained. For PCIVs, the primary containment isolation function is that the valve must be able to close (automatically or manually) and/or remain closed, and maintain leakage within that assumed in the OBA LOCA Dose Analysis. These isolation devices are either passive or active (automatic). Manual valves, de-activated automatic valves secured in their closed position (including check valves with flow through the valve secured), blind flanges, and closed systems are considered passive devices. The OPERABILITY requirements for closed systems are discussed in Technical Requirements Manual (TRM) Bases 3.6.4. Check valves, or other automatic valves designed to close without operator action following an accident, are considered active devices. Two barriers in series are provided for each penetration so that no single credible failure or malfunction of an active component can result in a loss of isolation or leakage that exceeds limits assumed in the safety analyses. One of these barriers may be a closed system.

For each division of H202 Analyzers, the lines, up to and including the first normally closed valves within the H202 Analyzer panels, are extensions of primary containment (i.e., closed system), and are required to be leak rate tested in accordance with the Leakage Rate Test Program. The H202Analyzer closed system boundary is identified in the Leakage Rate Test Program. The closed system boundary consists of those components, piping, tubing, fittings, and valves, which meet the guidance of Reference 6. The closed system provides a secondary barrier In the event of a single failure of the PCIVs, as described below. The closed system boundary between PASS and the H202 Analyzer system ends at the process sampling solenoid operated SUSQUEHANNA - UNIT 1 3.6-15

Rev. 17 PCIVs B 3.6.1.3 BASES BACKGROUND isolation valves between the systems (SV-12361, SV-12365, SV-12366, (continued) SV-12368, and SV-12369). These solenoid operated isolation valves do not fully meet the guidance of Reference 6 for closed system boundary valves in that they are not powered from a Class 1E power source. However, based upon a risk determination, operating these valves as closed system boundary valves is not risk significant. These valves also form the end of the Seismic Category I boundary between the systems. These process sampling solenoid operated isolation valves are normally closed and are required to be leak rate tested in accordance with the Leakage Rate Test Program as part of the closed system for the H2O2 Analyzer system. These valves are "closed system boundary valves" and may be opened under administr_ative control, as delineated in Technical Requirements Manual (TRM) Bases 3.6.4. Opening of these valves to permit testing of PASS in Modes 1, 2, and 3 is permitted in accordance with TRO 3.6.4.

Each H2O2 Analyzer Sampling line penetrating primary containment has two PCIVs, located just outside primary containment. While two PCIVs are provided on each line, a single active failure of a relay In the control circuitry for these valves, could result in both valves failing to close or falling to remain closed. Furthermore, a_single failure (a hot short in the common raceway to all the valves) could simultaneously affect all of the PCIVs within a H2O2 Analyzer division. Therefore, the containment Isolation barriers for these penetrations consist of two PCIVs and a closed system. For situations where one or both PCIVs are inoperable, the ACTIONS to be taken are similar to the ACTIONS for a single PCIV backed by a closed system.

The drywall vent and purge lines are 24 inches in diameter; the suppression chamber vent and purge lines are 18 inches in diameter.

The containment purge valves are normally maintained closed in MODES 1, 2, and 3 to ensure the primary containment boundary is maintained. The outboard isolation valves have 2 inch bypass lines around them for use during normal reactor operation.

The RHR Shutdown Cooling return llne containment penetrations {X-13A(B)}are provided with a normally closed gate valve {HV-151 F015A(B)} and a normally open globe valve {HV-151 F017A(B)}

outside containment and a testable check valve {HV-151 F050A(B)} with a normally closed parallel air operated globe valve {HV-151F122A(B)}

inside containment. The gate valve Is manually opened and automatically isolates upon a containment isolation signal from the Nuclear Steam Supply Shutoff System or RPV low level 3 when the RHR System is operated in the Shutdown Cooling Mode only. The LPCI subsystem Is an operational mode of the RHR System and uses the same Injection lines to the RPV as the Shutdown Cooling Mode.

SUSQUEHANNA -* UNIT 1 3.6-15a

Rev. 17 PCIVs 8 3.6.1.3 BASES BACKGROUND The design of these containment penetrations is unique in that some (continued) valves are containment isolation valves while others perform the function of pressure isolation valves. In order to meet the 10 CFR 50 Appendix J leakage testing requirements, the closed system outside containment is the only barrier tested in accordance with the Leakage Rate Test Program. HV-151 F015A(B) are .not required to be Appendix J leak rate tested since the Appendix J testing exemption requirements are met Since these containment penetrations {X-13A and X-13B}

include a containment isolation valve outside containment and a closed system outside containment that meets the requirements of USNRC Standard Review Plan 6.2.4 (September 1975), paragraph I1.3.e, the containment isolation provisions for these penetrations provide an acceptable alternative to the explicit requirements of 10 CFR 50, Appendix A, GDC 55.

Containment penetrations X-13A(B) are also high/low pressure system interfaces. In order to meet the requirements to have two (2) isolation valves between the high pressure and low pressure systems, the HV-151 F050A(B), HV-151 F122A(B), 151130 and HV-151 F015A(B) valves are used to meet this requirement and are tested in accordance with the pressure test program.

APPLICABLE The PCIVs LCO was derived from the assumptions related to SAFETY minimizing the loss of reactor coolant inventory, and establishing the ANALYSES primary containment boundary during major accidents. As part of the primary containment boundary, PCIV OPERABILITY supports leak tightness of primary containment Therefore, the safety analysis of any event requiring isolation of primary containment is applicable to this LCO.

The DBAs that result in a release of radioactive material within primary containment are a LOCA and a main steam line break (MSLB). In the analysis for each of these accidents, it is assumed that PCIVs are either closed or close within the required isolation times following event initiation. This ensures that potential paths to the environment through PCIVs 0ncluding primary containment purge valves) and secondary containment bypass valves that are not PCIVs are minimized. The closure time oUhe main steam isolation valves (MSIVs) for a MSLB outside primary containment is a significant variable from a radiological standpoint. The MSIVs are required to close within 3 to 5 seconds since the 5 second closure time is assumed in the analysis. The safety o analyses assume that the purge valves were closed at event initiation.

Likewise, it is assumed that the primary containment is isolated such that release of fission products to the environment is controlled.

0 SUSQUEHANNA - UNIT 1 3.6-15b

Rev. 17 PCIVs B 3.6.1.3 BASES APPLICABLE The OBA analysis assumes that within the required isolation time SAFETY leakage is terminated, except for the maximum allowable leakage rate, ANALYSES La.

(continued)

The single failure criterion required to be imposed in the conduct of unit safety analyses was considered In the original design of the primary containment purge valves. Two valves in series on each purge line provide assurance that both the supply and exhaust lines could be isolated even if a single failure occurred.

The primary containment purge valves may be unable to close irl°the environment following a LOCA. Therefore, each of the purge valves is required to remain closed during MODES 1, 2, and 3 except as permitted under the Note of SR 3.6.1.3.1. In this case, the single failure criterion remains applicable to the primary containment purge valve due to failure in the control circuit associated with each valve. The primary containment purge valve design precludes a single failure from compromising the primary containment boundary as long as the system is operated in accordance with this LCO.

Both H202 Analyzer PCIVs may not be able to close given a single failure in the control circuitry of the valves. The single failure is caused by a "hot short" in the cables/raceway to the PCIVs that causes both PCIVs for a given penetration to remain open or to open when required to be closed. This failure is required to be considered in accordance with IEEE-279 as discussed in FSAR Section 7.3.2a. However, the single failure criterion for containment isolation of the H202 Analyzer penetrations is satisfied by virtue of the combination of the associated PCIVs and the closed system formed by the H202 Analyzer piping system as discussed in the BACKGROUND section above.

The closed system boundary between PASS and the H202 Analyzer system ends at the process sampling solenoid operated isolation valves between the systems (SV-12361, SV-12365, SV-12366, SV-12368, and SV-12369). The closed system is not fully qualified to the guidance of Reference 6 In that the closed system boundary valves between the H202 system and PASS are not powered from a Class 1E power source. However, based upon a risk determination, the use of these valves is considered to have no risk significance. This exemption to the requirement of Reference 6 for the closed system boundary is documented in License Amendment No.

195.

PCIVs satisfy Criterion 3 of the NRC Policy Statement (Ref. 2)

SUSQUEHANNA - UNIT 1 3.6-16

Rev. 17 PCIVs B 3.6.1.3 BASES LCO PCIVs form a part of the primary containment boundary, or in the case of SCBL valves limit leakage from the primary containment. The PCIV safety function is related to minimizing the loss of reactor coolant inventory and establishing the primary containment boundary during a OBA.

The power operated, automatic isolation valves are required to have isolation times within Iitnits and actuate on an automatic isolation signal.

The valves covered by this LCO are listed in Table 8 3.6.1.3-1 and Table B 3.6.1.3-2. .

The normally closed PCIVs, including secondary containment bypass valves li~ted in Table B 3.6.1.3-2 that are not PCIVs, are considered OPERABLE when manual valves are closed or open in accordance with appropriate administrative controls, automatic valves are in their closed position, blind flanges are in place, and closed systems are intact. These passive isolation valves and devices are those listed in Table B 3.6.1.3-1.

Leak rate testing of the secondary containment bypass valves listed in Table 3.6.1.3-2 is permitted in Modes 1, 2 & 3 as described in the Primary Containment Leakage Rate Testing Program.

Purge valves with resilient seals, secondary containment bypass valves, including secondary containment bypass valves listed in Table B 3.6.1.3-2 that are not PCIVs, MSIVs, and hydrostatically tested valves must m~et additional leakage rate requirements. Other PCIV leakage rates are addressed by LCO 3.6.1.1, "Primary Containment," as Type B or C testing.

• This LCO provides assurance that the PCIVs will perform their designed safety functions to minimize the loss of reactor coolant inventory and establish the primary containment boundary during accidents.

APPLICABILITY In MODES 1, 2, and 3, a OBA could cause a release of radioactive material to primary containment In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, PCIVs are not required to be OPERABLE and the primary containment purge valves are not required to be closed in MODES 4 and 5.

SUSQUEHANNA - UNIT 1 3.6-17

Rev. 17 PCIVs B 3.6.1.3 BASES ACTIONS The ACTIONS are modified by a Note allowing penetration flow path(s) to be unisolated intennittently under administrative controls. These controls consist of stationing a dedicated operator at the controls of the valve, who is in continuous communication with the control room. In this way, the penetration can be rapidly isolated when a need for primary containment isolation is indicated.

A second Note has been added to provide clarification that, for the purpose of this LCO, separate Condition entry is allowed for each penetration flow path. This is acceptable, since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable PCIV. Complying with the Required Actions may allow for continued operation, and subsequent inoperable PCIVs are governed by subsequent Condition entry and application of associated Required Actions.

The ACTIONS are modified by Notes 3 and 4. Note 3 ensures that appropriate remedial actions are taken, if necessary, if the affected system(s) are rendered inoperable by an inoperable PCIV (e.g., an Emergency Core Cooling System subsystem is inoperable due to a failed open test return valve). Note 4 ensures appropriate remedial actions are taken when the primary containment leakage limits are exceeded. Pursuant to LCO 3.0.6, these actions are not required even when the associated LCO is not met. Therefore, Notes 3 and 4 are added to require the proper actions be taken.

A.1 and A.2 Wrth one or more penetration flow paths with one PCIV inoperable except for purge valve leakage not within limit, the affected penetration flow paths must be isolated. The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a-single active failure. Isolation barriers that meet this criterion are a closed and de-activated automatic valve, a closed manual valve, a blind flange, and a check valve with flow through the valve secured. For a penetration isolated in accordance with Required Action A.1, the device used to isolate the penetration should be the closest available valve to -

the primary containment. The Required Action must be completed within the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Completion Time (8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> for main steam lines). The Completion Time of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> is reasonable considering the time required to.isolate the penetration and the relative importance of supporting primary containment OPERABILITY during MODES 1, 2, and 3. For main steam lines, an 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> Completion Time is allowed. The Completion Time of 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> for the main steam lines allows a period of time to restore the MS IVs to OPERABLE status given the fact that MSIV closure will result in isolation of the main steam line(s) and a potential for plant shutdown.

SUSQUEHANNA - UNIT 1 3.6-18

Rev. 17 PCIVs B 3.6.1.3 BASES ACTIONS A.1 and A.2 (continued)

(continued)

For affected penetrations that have been isolated in accordance with Required Action A.1, the affected penetration flow path(s) must be verified to be isolated on a periodic basis. This is necessary to ensure that primary containment penetrations required to be isolated following an accident, and no longer capable of being automatically isolated, will be in the isolation position should an event occur. This Required Action does not require any testing or device manipulation. Rather, it involves verification that those devices outside containment and capable of potentially being mispositioned are in the correct position. The Completion Time of "once per 31 days for isolation devices outside primary containment" is appropriate because the devices are operated under administrative controls and the probability of their misalignment is low. For the devices inside primary containment, the time period specified "prior to entering MODE 2 or 3 from MODE 4, if primary containment was de-inerted while 1n MODE 4, if not performed within the previous 92 days" is based on engineering judgment and is considered reasonable in view of the inaccessibility of the devices and other administrative controls ensuring that device misalignment is an unlikely possibility.

Condition A is modified by a Note indicating that this Condition is only applicable to those penetration flow paths with two PCIVs except for the H2O2 Analyzer penetrations. For penetration flow paths with one PCIV, Condition C provides the appropriate Required Actions. For the H2O2 Analyzer Penetrations, Condition D provides the appropriate Required Actions.

Required Action A.2 is modified by a Note that applies to isolation devices located in high radiation areas, and allows them to be verified by use of administrative means. Allowing verification by administrative means is considered acceptable, since access to these areas is typically restricted. Therefore, the probability of misalignment of these devices, once they have been verified to be in the proper position, is low.

8.1 Wrth one or more penetration flow paths with two PCIVs inoperable except for purge valve leakage not within limit, either the inoperable PCIVs must be restored to OPERABLE status or the affected penetration flow path must be isolated within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure. Isolation SUSQUEHANNA - UNIT 1 3.6-19

Rev. 17 PCIVs B 3.6.1.3 0

BASES ACTIONS 8.1 ( continued)

(continued) barriers that meet this criterion are a closed and de-activated automatic valve, a closed manual valve, and a blind flange. The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Completion Time is consistent with the ACTIONS of LCO 3.6.1.1.

Condition B is modified by a Note indicating this Condition is only applicable to penetration flow paths with two PCIVs except for the H2O2 Analyzer penetrations. For penetration flow paths with one PCIV, Condition C provides the appropriate Required Actions. For the H2O2 Analyzer Penetrations, Condition D provides the appropriate Required Actions.

C.1 and C.2 Wrth one or more penetration flow paths with one PCIV inoperable, the inoperable valve must be restored to OPERABLE status or the affected penetration flow path must be isolated. The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a closed and de-activated automatic valve, a closed manual valve, and a blind flange. A check valve may not be used to isolate the affected penetration. Required Action C.1 must be completed within the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time. The Completion Time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> is reasonable considering the relative stability of the closed system (hence, reliability) to act as a penetration isolation boundary and the relative importance of supporting primary containment OPERABILITY during MODES 1, 2, and 3. The closed system must meet the requirements of Reference 6. For conditions where the PCIV and the closed system are inoperable, the Required Actions of TRO 3.6.4, Condition B apply. For the Excess Flow Check Valves (EFCV), the Completion Time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is reasonable considering the instrument and the small pipe diameter of penetration (hence, reliability) to act as a penetration isolation boundary and the small pipe diameter of the affected penetrations. In the event the affected penetration flow path is isolated in accordance with Required Action C.1, the affected penetration must be verified to be isolated on a periodic basis. This is necessary to ensure that primary containment penetrations required to be isolated following an accident are isolated. The Completion Time of once per 31 days for verifying*each affected penetration is isolated is appropriate because the valves are operated under administrative controls and the probability of their misalignment is low.

SUSQUEHANNA - UNIT 1 3.6-20

Rev. 17 PCIVs B 3.6.1.3 BASES ACTIONS C.1 and C.2 (continued)

(continued)

Condition C is modified by a Note indicating that this Condition is only applicable to penetration flow paths with only one PCIV. For penetration flow paths with two PCIVs and the H202 Analyzer Penetration. Conditions A, B and D provide the appropriate Required Actions.

Required Action C.2 is modified by a Note that applies to valves and blind flanges located in high radiation areas and allows them to be verified by use of administrative means. Allowing verification by administrative means is considered acceptable, since access to these areas is typically restricted. Therefore, the probability of misalignment of these valves, once they have been verified to be in the proper position, is low.

D.1 and D.2 With one or more H202 Analyzer penetrations with one or both PCIVs inoperable, the inoperable valve(s) must be restored to OPERABLE status or the affected penetration flow path must be isolated. The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a closed and de-activated automatic valve, a closed manual valve, and a blind flange. A check valve may not be used to isolate the affected penetration. Required Action D. 1 must be completed within the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time. The

• completion Time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> is reasonable considering the unique design of the H:z02 Analyzer penetrations. The containment isolation barriers for these penetrations consist of two PCIVs and a closed system. In addition, the Completion Time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> is reasonable considering the relative stability of the closed system (hence, reliability) to act as a penetration isolation boundary and the relative importance of supporting primary containment OPERABILITY during MODES 1, 2, and 3. In the event the affected penetration flow path is isolated in accordance with Required Action D.1, the affected penetration must be verified to be isolated on a periodic basis. This is necessary to ensure that primary containment penetrations required to be isolated following an accident are isolated. The Completion Time of once per 31 days for verifying each affected penetration is isolated is appropriate because the valves are operated under administrative controls and the probability of their misalignment is low.

SUSQUEHANNA - UNIT 1 3.6-21

Rev. 17 PCIVs B 3.6.1.3 BASES ACTIONS D.1 and D.2 (continued)

(continued)

When an H202 Analyzer penetration PCIV is to be closed and deactivated in accordance with Condition D, this must be accomplished by pulling the fuse for the power supply, and either determinating the power cables at the solenoid valve, or jumpering of the power side of the solenoid to ground.

The OPERABILITY requirements for the closed system are discussed in Technical Requirements Manual (TRM) Bases 3.6.4. In the event that either one or both of the PCIVs and the closed system are inoperable, the Required Actions of TRO 3.6.4, Condition B apply.

Condition D is modified by a Note indicating that this Condition is only applicable to the H202 Analyzer penetrations.

E.1 Wrth the secondary containment bypass leakage rate not within limit, the assumptions of the safety analysis may not be met Therefore, the leakage must be restored to within limit within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. Restoration can be accomplished by isolating the penetration that caused the limit to be exceeded by use of one closed and de-activated automatic valve, closed manual valve, or blind flange. When a penetration is isolated, the leakage rate for the isolated penetration is assumed to be the actual pathway leakage through the isolation device. If two Isolation devices are used to isolate the penetration, the leakage rate Is assumed to be the [esser actual pathway leakage of the two devices. The 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Completion Time is reasonable considering the time required to restore the leakage by isolating the penetration and the relative importance of secondary containment bypass leakage to the overall containment function.

Ll In the event one or more containment purge valves are not within the purge valve leakage limits, purge valve leakage must be restored to within limits. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Completion Time is reasonable, considering that one containment purge valve remains closed, except as controlled by SR 3.6.1.3.1 so that a gross breach of containment does not exist.

SUSQUEHANNA - UNIT 1 3.6-22

Rev. 17 PCIVs B 3.6.1.3 BASES ACTIONS G.1 and G.2 (continued)

If any Required Action and associated Completion Time cannot be met, the plant must be brought to a MODE in which the LCO does not apply.

To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and to MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.1.3.1 REQUIRE:MENTS This SR ensures that the primary containment purge valves are closed as required or, if open, open for an allowable reason. If a purge valve is open in violation of this SR, the valve is considered inoperable. If the Inoperable valve is not otherwise known to have excessive leakage when closed, it is not considered to have leakage outside of limits. The SR is modified by a Note stating that the SR is not required to be met when the purge valves are open for the stated reasons. The Note states that these valves may be opened for inertlng, de-inertlng, pressure control, ALARA or air quality considerations for personnel entry, or Surveillances that require the valves to be open. The vent and purge valves are capable of closing in the environment following a LOCA. Therefore, these valves are allowed to be open for limited periods of time. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.6.1.3.2 This SR verifies that each primary containment isolation manual valve and blind flange that is located outside primary containment and not locked, sealed, or otherwise secured and is required to be closed ,,

during accident conditions is closed. The SR helps to ensure that post accident leakage of radioactive fluids or gases outside the primary containment boundary is within design limits.

This SR does not require any testing or valve manipulation. Rather, it involves verification that those PCIVs outside primary containment, and capable of being mispositioned, are in the correct posltlon. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

Two Notes have been added to this SR. The first Note allows valves and blind flanges located in high radiation areas to be verified by use of administrative controls. Allowing verification by administrative controls Is considered acceptable since access to these areas is typically SUSQUEHANNA - UNIT 1 3.6-23

Rev. 17 PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.2 (continued)

REQUIREMENTS (continued) restlicted during MODES 1, 2, and 3 for ALARA reasons. Therefore, the probability of misalignment of these PCIVs, once they have been verified to be in the proper position, Is low. A second Note has been included to clarify that PCIVs that are open under administrative controls are not required to meet the SR during the time that the PC IVs are open. This SR does not apply to valves that are locked, sealed, or otherwise secured in the closed position, since these were verified to be in the correct position upon locking, sealing, or securing.

SR 3.6.1.3.3 This SR verifies that each primary containment manual isolation valve and blind flange that is located inside primary containment and not locked, sealed, or otherwise secured and is required to be closed during accident conditions is closed. The SR helps to ensure that post accident leakage of radioactive fluids or gases outside the primary containment boundary is within design limits. For PCIVs inside primary containment, the Frequency defined as "prior to entering MODE 2 or 3 from MODE 4 if primary containment was de-inerted while in MODE 4, if not perfonned within the previous 92 days" is appropriate since these PCIVs are operated under administrative controls and the probability of their misalignment is low. This SR does not apply to valves that are locked, sealed, or otherwise secured in the closed position, since these were verified to be In the correct position upon locking, sealing, or securing. Two Notes have b~n added to this SR. The first Note allows valves and blind flanges located in high radiation areas to be verified by use of administrative controls. Allowing verification by administrative controls is considered acceptable since the primary containment is inerted ar1d access to these areas is typically restricted during MODES 1, 2, and 3 for ALARA reasons. Therefore, the probability of misalignment of these PCIVs, once they have been verified to be in their proper position, is low. A second Note has been included to clarify that PCIVs that are open under administrative controls are not required to meet the SR during the time that the PCIVs are open.

SR 3.6.1.3.4 The traversing incore probe (TIP) shear isolation valves are actuated by explosive charges. Surveillance of explosive charge continuity provides assurance that TIP valves will actuate when required. Other administrative controls, such as those that limit the shelf life of the explosive charges, must be followed. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program .

• SUSQUEHANNA - UNIT 1 3.6-24

Rev. 17 PCIVs B 3.6.1.3 BASES SURVEILU\NCE SR 3.6.1.3.5 REQUIREMENTS (continued) Verifying the isolation time of each power operated and each automatic PCIV is within limits is required to demonstrate OPERABILITY. MSIVs may be excluded from this SR since MSIV full closure isolation time is demonstrated by SR 3.6.1.3.7. The isolation time test ensures that the valve will isolate in a time period less than or equal to that assumed in the Final Safety Analyses Report. The isolation time and Frequency of this SR are in accordance with the requirements of the lnservice Testing Program.

SR 3.6.1.3.6 For primary containment purge valves with resilient seals, the Appendix J Leakage Rate Test Interval of 24 months is sufficient. The acceptance criteria for these valves is defined in the Primary Containment Leakage Rate Testing Program, 5.5.12.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.6.1.3.7 Verifying that the isolation time of each MSIV is within the specified limits is required to demonstrate OPERABILITY. The isolation time test ensures that the MSIV will isolate in a time period that does not exceed the times assumed in the OBA analyses. This ensures that the calculated radiological consequences of these events remain within regulatory limits. The Frequency of this SR is in acccrdance with the requirements of the 1nservice Testing Program.

SR 3.6.1.3.8 Automatic PCIVs close on a primary containment isolation signal to prevent leakage of radioactive material from primary containment following a OBA. This SR ensures that each automatic PCIV will actuate to its isolation position on a primary containment isolation signal. The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.6.1.5 overlaps this SR to provide complete testing of the safety function. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SUSQUEHANNA - UNl"T 1 3.6-25

Rav. 17 PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.9 REQUIREMENTS (continued) a This SR requires a demonstration that representative sample of reactor instrumentation line excess flow check valves (EFCV) are OPERABLE by verifying that the valve actuates to check flow on a simulated instrument line break. As defined in FSAR Section 6.2.4.3.5 (Reference 4), the conditions under which an EFCV will isolate, simulated instrument line break, are at flow rates, which develop a differential pressure of between 3 psid and 1O psid. This SR provides assurance that the instrumentation line EFCVs will perform its design function to check flow. No specific valve leakage limits are specified because no specific leakage limits are defined in the FSAR. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The representative sample consists of an approximate equal number of EFCVs such that each EFCV is tested at least once every 10 years (nominal). The nominal 10 year interval is based on other performance-based testing programs, such as lnservice Testing (snubbers) and Option B to 10 CFR 50, Appendix J. In addition, the EFCVs in the sample are representative of the various plant configurations, models, sizes and operating environments. This ensures that any potential common problems with a specific type or application of EFCV is detected at the earliest possible time. EFCV failures will be evaluated to determine if additional testing in that test interval is warranted to ensure overall reliability and that failures to isolate are very infrequent. Therefore, testing of a representative sample was concluded to be acceptable from a reliability standpoint (Reference 7).

SR 3.6.1.3.10 The TIP shear isolation valves are actuated by explosive charges. An in place functional test is not possible with this design. The explosive squib is removed and tested to provide assurance that the valves will actuate when required. The replacement charge for the explosive squib shall be from the same manufactured batch as the one fired or from another batch that has been certified by having one of the batch successfully fired. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SUSQUEHANNA- UNIT 1 3.6-26

Rev. 17 PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.11 REQUIREMENTS (continued) This SR ensures that the leakage rate of secondary containment bypass leakage paths Is less than the specified leakage rate. This provides assurance that the assumptions in the radiological evaluations of Reference 4 are met The secondary containment leakage pathways and Frequency are defined by the Primary Containment Leakage Rate Testing Program. This SR simply imposes additional acceptance criteria.

SR 3.6.1.3.12 Tha analyses in References 1 and 4 are based on the specified leakage rate. Leakage through each MSIV must be::;; 100 scfh for any one MSIV and :,;; 300 scfh for total leakage through the MSIVs combined with the Main Steam Line Drain Isolation Valve, HPCI Steam Supply Isolation Valve and the RCIC Steam Supply Isolation Valve.

The MS!Vs can be tested at either~ pt (24.3 psig) or Pa (48.6 psig).

Main Steam Line Drain Isolation, HPCI and RCIC Steam Supply Line Isolation Valves, are tested at Pa (48.6 psig). The Frequency Is required by the Primary Containment Leakage Rate TestirJg Program.

SR 3.6.1.3.13 Surveillance of hydrostatically tested lines provides assurance that the calculation assumptions of Reference 2 are met Tha acceptance criteria for the combined leakage of all hydrostatically tested lines is 3.3 gpm when tasted at 1.1 Pa, (53.46 pslg). The combined leakage rates must be demonstrated in accordance with the leakage rate test Frequency required by tha Primary Containment Leakage Testing Program.

As noted in Table B 3.6.1.3-1, PCIVs associated with this SR are not Type C tested. Containment bypass leakage is prevented since the line terminates below the minimum water level in tha Suppression Chamber. These valves are tested in accordance with the 1ST Program. Therefore, these valves leakage is not included as containment leakage.

SUSQUEHANNA - UNIT 1 3.6-27

Rev. 17 PCIVs B 3.6.1.3 BASES REFERENCES 1. FSAR, Chapter 15.

2. Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 39132).

3. CFR 50, Appendix J, Option 8.

4. FSAR, Section 6.2.

5. NEDO-30851-P-A, Technical Specification Improvement Analyses for BWR Reactor Protection System,~ March 1988.

6. Standard Review Plan 6.2.4, Rev. 1, September 1975

7. NEDO-32977-A, "Excess Flow Check Valve Testing Relaxation," June 2000.

SUSQUEHANNA - UNIT 1 3.6-28

Rev. 17 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 Primary Containment Isolation Valve (Paae 1 of 11)

Isolation Signal LCO 3.3.6.1 Function No.

Plant System Valve Number Valve Description Type of Valve (Maximum Isolation Tbne /Seconds))

Containment 1-57-193 (d) ILRT Manual NIA

!Atmospheric 1-57-194 (d) ILRT Manual NIA

!Control HV-15703 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-15704 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-15705 Containment Purge Automatic Valve 2.b, 2 d, 2 e (15)

HV-15711 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-15713 Containment Purge Automatic Valve 2.b, 2 d, 2.e (15)

HV-15714 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-15721 Containment Purge Automatic Valve 2.b, 2 d, 2.e (15)

HV-15722 Containment Purge - Automatic Valve 2.b, 2.d, 2.e (15)

HV-15723 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-15724 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-15725 Containment Purge Automatic Valve 2.b, 2 d, 2.e (15)

HV-15766 (a) Suppression Pool Cleanup Automatic Valve 2.b, 2.d (30)

HV-15768 (a) Suppression Pool Cleanup Automatic Valve 2.b, 2.d (30)

HV-157113 (d) Hardened Containment Vent Power Operated NIA (Air)

HV-157114 (d) Hardened Containment Vent Power Operated NIA (Air)

SV-157100A !Containment Radiation Detection Automatic Valve 2.b, 2.d iSYst SV-157100 B Containment Radiation Detecbon Automatic Valve 2.b, 2.d ISYst SV-157101 A Containment Radiation Detection Automatic Valve 2.b, 2.d ISyst SV-157101 B !Containment Radiation Detecbon Automatic Valve 2.b, 2.d fSyst SV-157102A !Containment Radiation Detection Automatic Valve 2.b, 2 d fSyst SV-157102 B !Containment Radiation Detection Automatic Valve 2.b, 2.d fSyst SV-157103A Containment Radiation Detection Automatic Valve 2.b, 2.d Syst SV-157103 B !Containment Radiation Detection Automatic Valve 2.b, 2 d ISyst SV-157104 Containment Radiation Detection Automatic Valve 2.b, 2.d Syst SV-157105 Containment Radiation Detection Automatic Valve 2.b, 2.d fSyst SV-157106 !Containment Radiation Detection Automatic Valve 2.b, 2.d iSyst SV-157107 !Containment Radiation Detection Automatic Valve 2.b, 2.d ISyst SV-15734 A (e) IConJalnment Atmosphere Sample Automatic Valve 2.b, 2.d SV-15734 B (e) Containment Atrnosohere Sample Automatic Valve 2 b, 2.d SV-15736 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-15736 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d "

SV-15737 Nitrogen Makeup Automatic Valve 2.b, 2.d, 2.e SUSQUEHANNA - UNIT 1 3.&-29

Rev. 17 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 Primary Containment 18olatlon Valve (Page 2 of 11)

Isolation Signal LCO 3.3.6.1 Function No.

Plant System Valve Number Valve Description Type of Valve (Maximum Isolation Time (Seconds))

Contalnment SV-15738 Nitrogen Makeup Automatic Valve 2.b, 2 d, 2.e Atmospheric SV-1574-0 A (e) !Containment Atmosphere Sample Automabc Valve 2.b, 2.d Control SV-15740 B (e) Containment Atmosphere Sample Automatic Valve 2 b, 2.d (continued) SV-15742 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-15742 B (e) !Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-15750 A (e) leontainment Atmosphere Sample Automatic Valve 2 b, 2.d SV-15750 B (e) !Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-15752 A (e) !Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-15752 B (e) Containment Atmosphere Sample Automabc Valve 2.b, 2.d SV-15767 Nitrogen Makeup Automatic Valve 2.b, 2.d, 2.e SV-ts774 A (e) !Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-15774 B (e) !Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-15776 A (e) Containment Atmosphere Sample Automabc Valve 2.b, 2.d SV-15776 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-15780 A (e) !Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-15780 B (e) !Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-15782 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d

. SV-15782 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2 d SV-15789 Nitrogen Makeup Automatic Valve 2.b, 2.d 1 2.e Containment 1-26-072 (d) Containment Instrument Gas Manual Check N/A Instrument Gas 1-26-074 (d) Containment Instrument Gas Manual Check N/A 1-26-152 {d) Containment Instrument Gas Manual Check NIA 1-26-154 (d) Containment Instrument Gas Manual Check NIA 1-26-164 (d) Containment Instrument Gas Manual Check NIA HV-12603 !Containment Instrument Gas Automatic Valve 2.c, 2.d (20)

SV-12605 Containment Instrument Gas Automatic Valve 2.c, 2.d SV-12651 Containment Instrument Gas Automatic Valve 2.c, 2d SV-12654A Containment Instrument Gas Power Operated N/A SV-12654 B Containment Instrument Gas Power Operated NIA SV-12661 Containment Instrument Gas Automatic Valve 2.b, 2.d SV-12671 Containment Instrument Gas Automatic Valve 2.b, 2.d

!Core Sp_ray HV-152F001 A (b)(c) CS Suction Valve Power Operated N/A HV-152F001 B (b)(c)  !CS Suction Valve Power Operated N/A HV-152F005 A CS Injection Power Operated NIA HV-152F005 B CS Injection Valve Power Operated NIA HV-152F006 A CS Injection Valve Air Operated Check NIA Valve HV-152F006 B CS lnjeCtlon Valve Air Operated Check NIA Valve HV-152F015 A (b)(c) CS Test Valve Automatic Valve 2.c, 2.d (80)

HV-152F015 B (b)(c}  !CS Test Valve Automatic Valve 2.c, 2.d (80)

• SUSQUEHANNA - UNIT 1 3.6-30

Rev. 17 PCIVs B 3.6.1.3 Table 8 3.6.1.3-1 (continued)

Primary Containment lsolatlon Valve (Page 3 of 11)

Isolation Signal LCO 3.3.6.1 Function No.

Plant System Valve Number Valve Delcrlptlon Type of Valve (Maximum Isolation rune /Seconds)}

Core Spray HV-152F031 A (b)(c) CS Minimum Reclrculabon Flow Power Operated NIA (continued) HV-152F031 B (b)(c) CS Minimum Recirculation Flow Power Operated NIA HV-152F037 A iCS Injection Power Operated NIA (Air)

HV-152F037 B CS_Injecbon Power Operated NIA (Air)

XV-152F018 A  !Core Spray Excess Flow Check NIA

!Valve XV-152F018 B  !Core Spray Excess Flow Check NIA

!Valve HPCI 1-55-038 (d) IHPCI Infection Valve Manual NIA 155F046 (b)(c)(d) HPCI Minimum Flow Check Valve Manual Check NIA 155F049 (a)(d) HPCI Turbme Exhaust Valve Manual Check NIA HV-155F002 HPCI Steam Supply Valve Automatic Valve 3.a, 3.b, 3.c, 3.e, 3.f, 3.g (50)

HV-155F003 HPCI Steam Supply Valve IAutomatlc Valve 3.a, 3.b, 3.c, 3.e, 3.f, 3 g (50)

HV-155F006 HPCI Injection Valve Power Operated NIA HV-155F012 (b)(c) HPCI Minimum Flow Valve Power Operated NIA HV-155F042 (b)(c) HPCI Suction Valve Automatic Valve 3.a, 3.b, 3.c, 3.e, 3.f, 3g(115)

HV-155F066 (a) HPCI Turbine Exhaust Valve Power Operated NIA HV-155F075 HPCI Vacuum Breaker Isolation Automatic Valve 3.b, 3.d (15)

!Valve HV-155F079 HPCI Vacuum Breaker Isolation Automatic Valve 3.b, 3.d (15)

!Valve HV-155F100 HPCI Steam Supply Valve Automatic Valve 3.a, 3.b, 3.c, 3.e, 3.f, 3.g (6)

XV-155F024 A HPCI Valve Excess Flow Check NIA Valve IXV-155F024 B HPCIVafve Excess Flow Check NIA Valve XV-155F024 C HPCIVatve Excess Flow Check NIA Valve IXV-155F024 D HPCIValve Excess Flow Check NIA Valve Uquld Radwaste HV-16108A1 Liquid Radwaste Isolation Valve Automatic Valve 2b, 2.d (15)

Collection HV-16108A2 Liquid Radwaste Isolation Valve Automatic Valve 2.b, 2.d (15)

HV-16116A1 Liquid Radwaste Isolation Valve Automatic Valve 2.b, 2.d (15)

HV0 16116A2 Liquid Radwaste Isolation Valve Automatic Valve 2.b, 2.d (15)

DemlnWater 1-41-017 (d) Demlnerallzed Water Manual NIA 1-41-018 (d) Demlneralrzed Water Manual NIA Nuclear Boller 141F010A(d} Feedwater Isolation Valve Manual Check NIA 141F010 B (d) Feedwater Isolation Valve Manual Check NIA SUSQUEHANNA - UNIT 1 3.6-31

Rev. 17 PCIVs 8 3.6.1.3 Table 8 3.6.1.3-1 (continued)

Primary Containment Isolation Valve (Page 4 of 11)

Isolation Signal LCO 3.3.6.1 Function No.

Plant System Valve Number Valve Description Type of Valve (Maximum Isolation Thna (Seconds))

Nuclear Boller 141F039 A (d) Feedwater Isolation Valve Manual Check NIA (continued) 141F039 B (d) Feadwater Isolation Valve Manual Check NIA 141818 A (d) Feedwater Isolation Valve Manual Check NIA 141818 B (d) Feedwater Isolation Valve Manual Check NIA HV-141F016 MSL Drain Isolation Valve Automatic Valve 1.a, 1.b, 1.c, 1.d, 1.e (10)

HV-141F019 MSL Drain Isolation Valve Automatic Valve 1.a, 1.b, 1.c, 1.d, 1.e (15)

HV-141F022 A MSN Automatic Valve 1.a, 1.b, 1.c, 1.d, 1.e (5)

HV-141F022 B MSN Automatic Valve 1.a, 1.b, 1.c, 1.d, 1.e (5)

HV-141F022 C MSN Automatic Valve 1.a, 1 b, 1.c, 1.d, 1.e (5)

HV-141F022 D MSN Automatic Valve 1.a, 1.b, 1.c, 1.d, 1.e (5)

HV-141F028 A MSN Automatic Valve 1.a, 1.b, 1.c, 1.d, 1.e (5)

HV-141F028 B MSN IAutomatJc Valve 1.a, 1.b, 1.c, 1.d, 1.e (5)

HV-141F028 C MSIV !Automatic Valve 1.a, 1.b, 1.c, 1.d, 1.e (5)

HV-141F028 D MSN IAutomatlc Valve 1.a, 1.b, 1 c, 1.d, 1.e (5)

HV-141F032 A Feedwater Isolation Valve Power Operated NIA Check HV-141F032 B Feedwater Isolation Valve Power Operated NIA Check XV-141F009 Nuclear Boiler EFCV Excess Flow Check NIA jl/alve XV-141F070 A Nuclear Boiler EFCV Excess Flow Check NIA

!Valve XV-141F070 B Nuclear Boller EFCV Excess Flow Check NIA

!Valve XV-141F070 C !Nuclear Boller EFCV Excess Flow Check NIA C Valve XV-141F070 D Nuclear Boiler EFCV Excess Flow Check NIA

!Valve XV-141F071 A Nuclear Boiler EFCV Excess Flow Check NIA

!Valve XV-141F071 B Nuclear Boller EFCV Excess Flow Check NIA Valve IXV-141F071 C Nuclear Boller EFCV Excess Flow Check NIA

Valve XV-141 F071 D !Nuclear Boller EFCV Excess Flow Check NIA

!Valve SUSQUEHANNA - UNIT 1 3.6-32

Rev. 17 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 (continued)

Primary Containment Isolation Valve (Page 6 of 11) lso latlon Signal LCO 3.3.6.1 Function No.

Plant System Valve Number Velw Description Type of Valve (Maximum Isolation llme (Seconds))

Nuclear Boner XV-141F072A Nuclear Boiler EFCV Excess Flow Check NIA (continued) !Valve IXV-141F072 B Nuclear Boller EFCV Excess Flow Check NIA

!Valve IXV-141F072 C Nuclear Boller EFCV Excess Flow Check NIA

!Valve IXV-141F072 D Nuclear Boiler EFCV Excess Flow Check NIA

!Valve IXV-141F073 A Nuclear Boller EFCV !Excess Flow Check NIA

!Valve IXV-141F073 B Nuclear Boiler EFCV EXces& Flow Check NIA

!Valve IXV-141F073 C Nuclear Boiler EFCV Excess Flow Check NIA Valve IXV-141F073 D Nuclear Boiler EFCV Excess Flow Check NIA

!Valve Nuclear Boller IXV-14201 !Nuclear Boller Vessel Instrument Excess Flow Check NIA Vessel !Valve Instrumentation XV-14202 !Nuclear Boiler Vessel Instrument Excess Flow Check NIA Valve IXV-142F041 Nuclear Boiler Vessel Instrument Excess Flow Check NIA Valve IXV-142F043 A Nuclear Boller Vessel Instrument Excess Flow Check NIA Valve XV-142F043 B Nuclear Boller Vessel Instrument Excess Flow Check NIA Valve XV-142F045 A :Nuclear Boller Vessel Instrument Excess Flow Check NIA Valve IXV-142F045 B Nuclear Boiler Vessel Instrument Excess Flow Check NIA Valve XV-142F047 A Nuclear Boiler Vessel Instrument Excess Flow Check NIA Valve XV-142F047 B Nuclear Boller Vessel, Instrument Excess Flow Check NIA 1\/alve XV-142F051 A Nuclear Boller Vessel Instrument Excess Flow Check N/A Valve XV-142F051 B Nuclear Boller Vessel Instrument Excess Flow Check NIA Valve XV-142F051 C iNuclear Boiler Vessel Instrument Excess Flow Check NIA Valve XV-142F051 D Nuclear Boiler Vessel Instrument Excess Flow Check NIA Valve XV-142F053 A Nuclear Boller Vessel Instrument Excess Flow Check NIA Valve XV-142F053 B Nuclear Boller Vessel Instrument Excess Flow Check NIA

!Valve SUSQUEHANNA - UNIT 1 3.6-33

Rev. 17 PCIVs B 3.6.1.3 Table 8 3.6.1.3-1 (continued)

Primary Containment Isolation Valve (Page 6 of 11)

Isolation Signal LCO 3.3.6.1 Function No.

PlantSyatam Valve Number Valve Description Type of Valve (Fdaxlmum Isolation Time /Seconds))

Nuclear Boiler XV-142F053 C Nuclear Boiler Vessel Instrument Excess Flow Check NIA

!Vessel Valve Instrumentation IXV-142F053 D Nuclear Boiler Vessel Instrument Excess Flow Check NIA (continued} Valve IXV-142F055 Nuclear Boller Vessel Instrument Excess Flow Check NIA Valve IXV-142F057 !Nuclear Boiler Vessel Instrument Excess Flow Check NIA Valve IXV-142F059 A Nuclear Boiler Vessel Instrument Excess Flow Check NIA Valve IXV-142F059 B Nuclear Boiler Vessel Instrument Excess Flow Check NIA Valve IXV-142F059 C Nuclear Boiler Vessel Instrument Excess Flow Check NIA Valve IXV-142F059 D Nuclear Boller Vessel Instrument Excess Flow Check NIA Valve IXV-142F059 E Nuclear Boller Vessel Instrument Excess Flow Check NIA Valve XV-142F059 F Nuclear Boiler Vessel Instrument Excess Flow Check NIA Valve XV-142F059 G Nuclear Boiler Vessel Instrument Excess Flow Check NIA Valve IXV-142F059 H Nuclear B01ler Vessel Instrument Excess Flow Check NIA Valve XV-142F059 L Nuclear Boner Vessel Instrument Excess Flow Check NIA Valve XV-142F059 M Nuclear Boller Vessel Instrument Excess Flow Check NIA Valve XV-142F059 N Nuclear Boiler Vessel Instrument Excess Flow Check NIA Valve XV-142F059 P Nuclear Boller Vessel Instrument Excess Flow Check NIA Valve XV-142F059 R Nuclear Boiler Vessel Instrument Excess Flow Check NIA Valve XV-142F059 S Nuclear Boiler Vessel Instrument Excess Flow Check N/A Valve XV-142F059 T Nuclear Boller Vessel Instrument Excess Flow Check N/A Valve

.XV-142F059 U Nuclear Boiler Vessel Instrument Excess Flow Check NIA Valve XV-142F081 Nuclear Boller Vessel Instrument Excess Flow Check NIA Valve RBCCW HV-11313 RBCCW Automatic Valve 2.c, 2.d (30)

HV-11314 RBCCW Automatic Valve 2.c, 2.d (30)

HV-11345 RBCCW Automatic Valve 2.c, 2.d (30)

HV-11346 RBCCW Automatic Valve 2 c, 2.d (30)

• SUSQUEHANNA - UNIT 1 3.6-34

Rev. 17 PCIVs B 3.6.1.3 Table 8 3.6.1.3-1 (continued)

Primary Containment Isolation Valve (Page 7 of 11)

Isolation Signal LCO 3.3.6.1 Function No.

Plant 8yatem Valve Number Valve Description Type of Valve (Maximum Isolation llme (Seconds))

RCIC 1-49--020 (d) RCIC INJECTION Manual NIA 149F021 (b)(c)(d) RCIC Minimum Reclrculabon Flow Manual Check NIA 149F028 (a)(d) RCIC Vacuum Pump Discharge Manual Check NIA 149F040 (a)(d) RCIC Turbine Exhaust Manual Check NIA FV-149F019 (b)(c) RCIC Minimum Recirculabon Flow Power Operated NIA HV-149F007 RCIC Steam Supply l'\utomatlc Valve 4.a, 4.b, 4.c, 4 e, 4.f,

' 4.g (20)

HV-149F008 RCIC Steam Supply Automatic Valve 4.a, 4.b, 4.c, 4.e, 4.f, 4.g (20)

HV-149F013 RCIC Injection Power Operated NIA HV-149F031 (b)(c) RCIC Sucbon Power Operated NIA I-N-149F059 (a) RCIC Turbine Exhaust Power Operated NIA HV-149F060 (a) RCIC Vacuum Pump Discharge Power Operated NIA HV-149F062 RCIC Vacuum Breaker Automatic Valve 4.b, 4.d (10)

HV-149F084 RCIC Vacuum Breaker Automatic Valve 4.b, 4.d (10)

HV-149F088 RCIC Stearn Supply Automatic Valve 4.a, 4.b, 4.c, 4.e, 4.f, 4.g (12)

XV-149F044 A RCIC Excess Flow Check N/A Valve XV-149F044 B RCIC Excess Flow Check NIA Valve XV-149F044 C RCIC Excess Flow Check NI_A Valve XV-149F044 D RCIC Excess Flow Check NIA Valve RB Chilled HV-18781 A1 RB Chilled Water Automatic Valve 2.c, 2.d (40)

Water System HV-18781 A2 RB Chilled Water Automatic Valve 2.c, 2.d (40)

HV-18781 81 RB Chilled Water Automatic Valve 2.c, 2 d (40)

HV-18781 82 RB Chilled Water Automatic Valve 2.c, 2.d (40)

HV-18782 A 1 RB Chilled Water Automatic Valve 2.c, 2.d (12)

HV-18782 A2 RB Chilled Water Automatic Valve 2.c, 2.d (12)

HV-18782 81 RB Chllled Water Automatic Valve 2 c, 2.d (12)

HV-18782 82 RB Chilled Water Automatic Valve 2c, 2.d (12)

HV-18791 A1 RB Chilled Water Automatic Valve 2.b, 2.d (15)

HV-18791 A2 RB Chllled Water Automatic Valve 2.b, 2.d (15)

HV-18791 81 IRB Chilled Water Automatic Valve 2.b, 2.d (15)

HV-18791 82 lRB Chnled Water Automatic Valve 2.b, 2.d (15)

HV-18792 A1 RB Chilled Water Automatic Valve 2.b, 2.d (8)

HV-18792 A2 RB Chilled Water Automatic Valve 2.b, 2.d (8)

HV-18792 81 RB Chnled Water Automatic Valve 2.b, 2.d (8)

HV-18792 82 RB Chilled Water Automatic Valve 2.b, 2.d (8)

Reactor 143F013 A (d) Recirculation Pump Seal Water Manual Check N/A Recirculation 143F013 B (d) Recirculation Pump Seal Water Manual Check N/A

• SUSQUEHANNA - UNIT 1 3.6-35

Rev. 17 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 (continued)

Primary Containment Isolation Valve (Page 8 of 11)

Isolation Signal LCO 3.3.6.1 Function No.

Plant System Valve Number Valve Description Type of Valve (Maximum Isolation Time (Seconds))

Reactor XV-143F003 A Reactor Recirculation Excess Flow Check NIA Recirculation Valve (continued) XV-143F003 B Reactor Reclrcula!Jon Excess Flow Check NIA 1\/alve XV-143F004 A Reactor Recirculation Excess Flow Check NIA rvaJve XV-143F004 B Reactor Recirculabon Excess Flow Check NIA Valve XV-143F009 A Reactor Reclrculatlon Excess Flow Check NIA Valve XV-143F009 B Reactor Recirculation Excess Flow Check NIA Valve IXV-143F009 C Reactor Recirculation Excess Flow Check NIA Valve XV-143F009 D Reactor ReCJrcula!Jon Excess Flow Check NIA Valve XV-143F010A Reactor Recirculation Excess Flow Check NIA Valve IXV-143F010 B Reactor Recircula!Jon Excess Flow Check NIA Valve IXV-143F010 C Reactor Recirculation Excess Flow Check NIA Valve ,

IXV-143F010 D Reactor ReCffculation Excess Flow Check NIA Valve IXV-143F011 A Reactor Recirculation Excess Flow Check NIA Valve IXV-143F011 B Reactor Reclrculatlon Excess Flow Check NIA Valve IXV-143F011 C Reactor Recirculation Excess Flow Check NIA Valve XV-143F011 D Reactor Recirculation Excess Flow Check NIA Valve XV-143F012 A Reactor Reclrculatlon Excess Flow Check NIA Valve IXV-143F012 B Reactor Rearculatlon Excess Flow Check NIA Valve XV-143F012 C Reactor Recirculation Excess Flow Check NIA Valve XV-143F012 D Reactor Recirculabon Excess Flow Check NIA Valve XV-143F017 A Recirculation Pump Seal Water Excess Flow Check NIA

!Valve XV-143F017 B IRecirculatlon Pump Seal Water Excess Flow Check NIA

!Valve XV-143F040 A Reactor Recirculation Excess Flow Gheck NIA Valve SUSQUEHANNA - UNIT 1 3.6-36

Rev. 17 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 (continued)

Primary Containment Isolation Valve (Page 9 of 11)

Isolation Signal LCO 3.3.6.1 Function No.

Plant System Valve Number Valve Description Type ofValw (Maxbnum Isolation Thne CSeconda))

Reactor XV-143F040 B Reactor RecirculatJon Excess Flow Check NIA Recirculation !Valve (continued.) XV-143F040 C Reactor Recirculation Excess Flow Check N/A Valve XV-143F040 D Reactor Recirculation Excess Flow Check NIA

!Valve XV-143F057 A Reactor Recirculation Excess Flow Check NIA Valve XV-143F057 B Reactor Recirculation Excess Flow Check N/A Valve HV-143F019 Reactor Coolant Sample Automatic Valve 2.b (9)

HV-143F020 Reactor Coolant Sample Automatic Valve 2.b (2)

Residual Heat HV-151F004 A (b)(c) RHR - Suppression Pool Suction Power Operated NIA Removal HV-151F004 B (b)(c) RHR - Suppression Pool Suction Power Operated NIA HV-151F004 C (b)(c) RHR - Suppression Pool Suction Power Operated N/A HV-151 F004 D (b)(c) RHR - Suppression Pool Suction Power Operated NIA HV-151F007 A (b)(c) RHR-Mlnlmum RecirculatJon Flow Power Operated NIA HV-151F007 B (b)(c) RHR-Minlmum Recrrculatfon Flow Power Operated NIA HV-151F008 (h) RHR - ShutdOY111 Cooling Suction Automatic Valve 6 a, 6.b, 6 c (52)

HV-151F009 (h) RHR - Shutdown Cooling Suction Automatic Valve 6.a, 6.b, 6.c (52)

HV-151 F011 A (b)(d) RHR-Suppresslon Pool Manual N/A (h) Cooling/Spray HV-151 F011 B (b)(d) RHR-Suppresslon Pool Manual NIA

'h) Cooling/Spray HV-151 F015 A (f) (h) RHR - Shutdown Cooling Power Operated NIA Retum/lPCI Injection HV-151F015 B (f) (h) RHR - Shutdown Cooling Power Operated NIA Retum/lPCI Injection HV-151F016 A (b) (h) RHR - DryweU Spray !Automatic Valve 2.c, 2.d (90)

'II HV-151FD16 B (b) (h) RHR - Drywall Spray !Automatic Valve 2.c, 2.d (90)

HV-151F022 (h) RHR - Reactor Vessel Head Spray Automatic Valve 2 d, 6.a, 6.b, 6.c (30)

HV-151F023 (h) RHR - Reactor Vessel Head Spray IAutomatlc Valve 2.d, 6.a, 6.b, 6 c (20)

HV-151FD28 A (b) (h) RHR - Suppression Pool * !Automatic Valve 2.c, 2.d (90)

Cooling/Spray HV-151F028 B (b) (h) RHR - Suppression Pool Automatic Valve 2.c, 2.d (90)

ICoolmg/Spray HV-151F050 A (g) RHR - Shutdown Cooling IAlr Operated Check NIA Return/LPCI Injection Valve !Valve .

HV-151F050 B (g) RHR - Shutdown Cooling Air Operated Check NIA Return/LPCI Injection Valve !Valve HV-151F103 A (b) RHR Heat Exchanger Vent Power Ooerated NIA HV-151F103 B (b) RHR Heat Exchanger Vent Power Operated N/A SUSQUEHANNA - UNIT 1 3.6-37

Rev. 17 PCIVs 8 3.6.1.3 Table B 3.6.1.3-1 (continued)

Primary Containment Isolation Valve (Page 10 of 11)

Isolation Signal LCO 3.3.6.1 Function No.

Pia nt System Valve Number Valve Description Type of Valve (Maximum laolatlon Time (Seconds))

Residua! Heat HV-151F122 A (g) RHR - Shutdown Cooling Power Operated NIA Removal Retum/LPCI Injection Valve 'Air)

(continued) HV-151F122 B (g) RHR - Shutdown Cooling Power Operated NIA Retum/LPCI Injection Valve 'Air)

PSV-15106 A (b)(d) RHR - Relief Valve Discharge Relief Valve NIA PSV-15106 B (b)(d) RHR - Relief Valve Discharge Relief Valve NIA PSV-151F126 (d) (h) RHR - Shutdown Cooling Suction Relief Valve NIA XV-15109A RHR Excess Flow Check NIA

!Valve XV-15109 B RHR Excess Flow Check NIA Valve XV-15109 C RHR Excess FlCNI Check NIA Valve XV-15109 D RHR Excess Flow Check NIA Valve RWCU HV-144F001 (a) RWCU Suction Automatic Valve 5.a, 5.b, 5.c, 5.d, 5.f, 5.g (30)

HV-144F004 (a) RWCU Suction Automatic Valve 5 a, 5.b, 5.c, 5.d, 5 e, 5.f, 5.g (30)

IXV-14411 A RWCU Excess Flow Check NIA Valve IXV-14411 B RWCU Excess Flow Check NIA Valve XV-14411 C RWCU Excess Flow Check NIA Valve IXV-14411 D RWCU Excess Flow Check NIA Valve IXV-144F046 RWCU Excess Flow Check NIA Valve HV-14182A RWCU Return Isolation Valve Power Operated NIA HV-14182 B RWCU Return Isolation Valve Power Operated NIA SLCS 148F007 (a)(d) SLCS Manual Check NIA HV-148F006 (a) SLCS Power Operated NIA Check Valve TIP System C51-J004 A (Shear rTIP Shear Valves Squib Valves NIA

!Valve)

C51-J004 B (Shear TIP Shear Valves Squib Valves NIA

!Valve)

C51-J0D4 C (Shear rTIP Shear Valves Squib Valves NIA

!Valve)

C51-J004 D (Shear TIP Shear Valves Squib Valves NIA Valve)

C51-J004 E (Shear rTIP Shear Valves Squib Valves NIA

!Valve)

SUSQUEHANNA - UNIT 1 3.6-38

Rev. 17 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 Primary Containment Isolation Valve (f:>age 11 of 11)

Isolation Signal LCO 3.3.6.1 Function No.

Plant System Valve Number Valve D88Crlp6on Type of Valve (Maximum Isolation Tone l'Secondsll TIP System C51-J004 A (Ball TIP Ball Valves Automatic Valve 7 a, 7.b (6)

(contlnued) Valve)

C51-J004 B (Ball TIP Ball Valves Automatic Valve 7.a, 7 b (5)

Valve)

C51-J004 C (Ball TIP Ball Valves Automatic Valve 7.a, 7.b (5)

Valve)

C51-J004 D (Ball rnP Ball Valves Automatic Valve 7.a, 7.b (5)

!Valve)

C51-J004 E (Ball rnP Ball Valves Automatic Valve 7.a, 7 b (5)

Valve)

(a) Isolation barrier remains water filled or a water seal remains in the line post-LOCA, Isolation valve is tested with water Isolation valve leakage Is not included in O 60 La total Type B and C tests.

(b) Redundant Isolation boundary for this valve Is provided by the closed system whose Integrity is verified by the Leakage Rate Test Program. This footnote does not apply to valve 155F046 (HPCI) when the associated PCIV, HV155F012 ls dosed and deactivated. Slmllarly, this footnote does not apply to valve 149F021 (RCIC) when It's associated PCIV, FV149F019 ls closed and deacbvated.

(c) Containment Isolation Valves are not Type C tested. Containment bypass leakage Is prevented since the line terminates below the minimum water level In the Suppression Chamber. Refer to the 1ST Program (d) LCO 3.3.3.1, "PAM Instrumentation," Table 3 3.3.1-1, Funcbon 6, does not apply since these are relief valves, check valves, manual valves or deactivated and closed.

(e) The containment Isolation barriers for the penetration associated wrth this valve consists of two PCIVs and a closed system. The closed system provides a redundant Isolation boundary for both PCIVs, and Its Integrity IS required to be verified by the Leakage Rate Test Program.

(f) Redundant Isolation boundary for this valve 1s provided by the closed system whose Integrity is verified by the Leakage Rate Test Program.

(g) These valves are not required to be 10 CFR 50, Appendix J tested since the HV-151F015A(B) valves (see note (h)) and a closed system form the 10 CFR 50, Appendix J boundary. These valves form a higMow pressure interface and are pressure tested In accordance with the pressure test program.

(h) lsolatlon barrier remains filled or a water seal remams In the line post-LOCA. Type C testing IS not required.

SUSQUEHANNA - UNIT 1 3.6-39

Rev. 17 PCIVs B 3.6.1.3 Table B 3.6.1.3-2 Secondary Containment Bypass Leakage 18olatlon Valves (Not PCIVs)

(Page 1 of 1) lsolatlon Signal LCO 3.3.6.1 Function No.

Plant System Valve Number Valve Description Type of Valve (Maximum lsollltlon Tlme /Seconds))

Residua! Heat HV-151F040 RHR- RADWASTE LINE 18 ISO Automatic Valve 2.a, 2.d (45)

Removal IVLV HV-151F049 RHR - RADWASTE LINE OB ISO IAutomatic Valve 2.a, 2 d (20)

IVLV 1-51-136 RHR - COND TRANSFER OB SCBL Check Valve NIA

!CHECK VALVE 1-51-137 RHR - COND TRANSFER 18 SCBL Check Valve NIA CHECK VALVE SUSQUEHANNA - UNIT 1 3.6-40

Rev. 2 AC Sources-Shutdown B 3.8.2 B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.2 AC Sources-Shutdown BASES BACKGROUND A description of the AC sources is provided in the Bases for LCO 3.8.1, "AC Sources-Operating."

APPLICABLE The OPERABILITY of the minimum AC sources during MODES 4 and 5 SAFETY and during movement of irradiated fuel assemblies ensures that:

ANALYSES

a. The facility can be maintained in the shutdown or refueling condition for extended periods;

b. Sufficient instrumentation and control capability is available for monitoring and maintaining the unit status; and

c. Adequate AC electrical power is provided to mitigate events postulated during shutdown, such as a fuel handling accident.

In general, when the unit is shut down the Technical Specifications requirements ensure that the unit has the capabillty to mitigate the consequences of postulated accidents. However, assuming a single failure and concurrent loss of all offsita or loss of all onsite power is not required.

The rationale for this is based _on the fact that many Design Basis Accidents (DBAs) that are analyzed in MODES 1, 2, and 3 have no specific analyses in MODES 4 and 5. Worst case bounding events are deemed not credible in MODES 4 and 5 because the energy contained within the reactor pressure boundary, reactor coolant temperature and pressure, and corresponding stresses result in the probabilities of occurrences significantly reduced or eliminated, and minimal consequences. These deviations from OBA analysis assumptions and design requirements during shutdown conditions are allowed by the LCO for required systems.

The Safety Analysis for Unit 2 assumes the OPERABILITY of some equipment that receives power from Unit 1 AC Sources.

Therefore, Unit 2 Technical Specifications establish requirements for the OPERABILITY of the DG(s) and qualified offsite circuits needed to support the Unit 1 onsite Class 1E AC electrical power distribution subsystem(s) required by Unit 2 LCO 3.8.8, Distribution Systems-Shutdown.

SUSQUEHANNA - UNIT 1 3.8-38

Rev. 2 AC Sources-Shutdown B 3.8.2 BASES APPLICABLE During MODES 1, 2, and 3, various deviations from the analysis SAFETY assumptions and design requirements are allowed within the ACTIONS.

ANALYSES This allowance Is in recognition that certain testing and maintenance (continued) activities must be conducted, provided an acceptable level of risk is not exceeded. During MODES 4 and 5, perfonnance of a significant number of required testing and maintenance activities is also required. In MODES 4 and 5, the activities are generally planned and administratively controlled.

Relaxations from typical MODES 1, 2, and 3 LCO requirements are acceptable during shutdown MODES, based on:

a. The fact that time in an outage is limited. This is a risk prudent goal as well as a utility economic consideration.

b. Requiring appropriate compensatory measures for certain conditions.

These may include administrative controls, reliance on systems that do not necessarily meet typical design requirements applied to systems credited in operation MODE analyses, or both.

c. Prudent utility consideration of the risk associated with multiple activities that could affect multiple systems.

d. Maintaining, to the extent practical, the ability to perform required functions (even if not meeting MODES 1, 2, and 3 OPERABILITY requirements) with systems assumed to function during an event In the event of an accident during shutdown, this LCO ensures the capability of supporting systems necessary for avoiding immediate difficulty, assuming either a loss of all offsite power or a loss of all onsite (diesel generator (DG)) power.

The AC sources satisfy Criterion 3 of the NRC Policy Statement (Ref. 1).

LCO One offsite circuit capable of supplying the onslte Class 1E power distribution subsystem(s) of LCO 3.8.8, "Distribution Systems-Shutdow n,"

ensures that all required loads are powered from offsite power. An OPERABLE DG, associated with a Distribution System Engineered Safeguards System (ESS) bus required OPERABLE by LCO 3.8.8, ensures that a diverse power source is available for providing electrical power support assuming a loss of the offsite circuit. Together, OPERABILITY of the required offsite circuit and the ability to manually start a DG ensures the availability of sufficient AC sources to operate the plant in a* safe manner and to mitigate the consequences of postulated events during shutdown (e.g., fuel handling accidents).

SUSQUEHANNA - UNIT 1 3.8-39

Rev. 2 AC Sources-Shutdown B 3.8.2 BASES LCO The qualified offsite clrcuit(s) must be capable of maintaining rated (continued) frequency and voltage while connected to their respective ESS bus(es),

and of accepting required loads during an accident. Qualified offsite circuits are those that are described in the FSAR and are part of the licensing basis for the unit. An offsite circuit includes all breakers, transfonners, switches, automatic tap changers, interrupting devices, cabling, and controls required to transmit power from the offsite transmission network to the onsite Class 1E ESS bus or buses. The offsite circuit consists of the incoming breaker and disconnect to startup transfonners (ST) No. 10 and ST No. 20 and the respective circuit path including feeder breakers to the four 4.16 kV ESS buses (A, B, C and D) for both Unit 1 and Unit 2. A detailed description of the offsite power network and circuits to the onsite Class 1E ESS buses is found in the FSAR, Section 8.2.

The required DG must be capable of being manually started, accelerating to rated speed and voltage, connecting to its respective ESS bus, and capable of accepting required loads.

APPLICABILITY The AC sources are required to be OPERABLE in MODES 4 and 5 and during movement of irradiated fuel assemblies in the secondary containment to provide assurance that:

a. Systems that provide core cooling are available;

b. Systems needed to mitigate a fuel handling accident are available;

c. Systems necessary to mitigate the effects of events that can lead to core damage during shutdown are available; and

d. Instrumentation and control capability is available for monitoring and maintaining the unit in a cold shutdown condition or refueling condition.

AC power requirements for MODES 1, 2, and 3 are covered in LCO 3.8.1.

ACTIONS The ACTIONS have been modified by a Note stating that LCO 3.0.3 is not applicable. If moving irradiated fuel assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify any action. If moving Irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations.

SUSQUEHANNA - UNIT 1 3.8-40

Rev. 2 AC Sources-Shutdown B 3.8.2 BASES ACTIONS A.1 (continued)

Wrth one or more required AC Sources (DGs or 4.16 kV ESS buses) inoperable, the remaining required sources may be capable of supporting sufficient required features (e.g., system, subsystem, divisions, component or device), to allow continuation of CORE ALTERATIONS and fuel movement. For example, if two or more 4 kV emergency buses are required per LCO 3.8.8, one 4.16 kV emergency bus with offsite power available may be capable of supporting sufficient required features.

Therefore, the option provided by Required Action A.1 to declare required features inoperable when not powered from an offsite source or not capable of being powered by the required DG recognizes that appropriate restrictions will be required by ACTIONS in the LCO for the affected feature(s).

A.2.1, and A.2.2, and A.2.3 With one or more required AC Sources Inoperable, the option exists in ACTION A.1 to declare all affected features inoperable. Since this option may Involve undesired administrative efforts, the allowance for sufficiently conservative actions is made. With one or more required AC Sources inoperable, the minimum required diversity of AC power sources is not available. It is, therefore, required to suspend CORE ALTERATIONS and movement of irradiated fuel assemblies in the secondary containment.

Suspension of these activitles shall not preclude completion of actions to establish a safe conservative condition. These actions minimize the probability of the occurrence of postulated events. It is further required to immediately initiate action to restore the required AC sources and to continue this action until restoration is accomplished in order to provide the necessary AC power to the plant safety systems.

The Completion Time of immediately is consistent with the required times for actions requiring prompt attention. The restoration of the required AC electlical power sources should be completed as quickly as possible in order to minimize the time during which the plant safety systems may be without sufficient power.

Because of the allowance provided by LCO 3.0.6, the Distribution System ACTIONS would not be entered even if all AC sources to it are inoperable, resulting in de-energization. Therefore, the Required Actions of Condition A have been modified by a Note to indicate that when Condition A Is entered with no AC power to any required ESS bus, ACTIONS for LCO 3.8.8 must be immediately entered. This Note allows

• SUSQUEHANNA - UNIT 1 3.8-41

Rev. 2 AC Sources-Shutdown B 3.8.2 BASES ACTIONS A.2.1, and A.2.2, and A2.3 (continued)

(continued)

Condition A to provide requirements for the loss of the offsite circuit whether or not a 4.16 kV ESS bus is de-energized. LCO 3.8.8 provides the appropriate restrictions for the situation invoMng a de-energized 4.16 kV ESS bus.

SURVEILLANCE SR 3.8.2.1 REQUIREMENTS SR 3.8.2.1 requires the SRs from LCO 3.8.1 that are necessary for ensuring the OPERABILITY of the AC sources in other than MODES 1, 2, and 3. SR 3.8.1.8 is not required to be met since only one offsite circuit is required to be OPERABLE. SR 3.8.1. 7, SR 3.8.1.11, SR 3.8.1.12, SR 3.8.1.13, SR 3.8.1.15, SR 3.8.1.18, and SR 3.8.1.19 are not required to be met because DG start and load within a specified time and response on an offsite power or ECCS initiation signal is not required.

SR 3.8.1.17 is not required to be met because the required OPERABLE DG(s) is not required to undergo periods of being synchronized to the offsite circuit SR 3:8.1.20 is excepted because starting independence is not required with the DGs that are not required to be OPERABLE. Refer to the corresponding Bases for LCO 3.8.1 for a discussion of each SR.

This SR is modified by a Note that specified SRs must be met but are not required to be performed. The reason for the Note is to preclude requiring the OPERABLE DG(s) from being paralleled with the offsite power network or otherwise rendered inoperable during the performance of SRs, and to preclude de-energizing a required 4.16 kV ESS bus or disconnecting a required offsite circuit during performance of SRs. Wrth limited AC sources available, a single event could compromise both the required circuit and the DG, It is the intent that these SRs must still be capable of being met, but actual performance is not required during periods when the DG and offsite circuit is required to be OPERABLE.

REFERENCES 1. Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 39132) .

• SUSQUEHANNA - UNIT 1 3.8-42

Rev. 2 AC Sources-Shutdown B 3.8.2 BASES THIS PAGE INTENTIONALLY LEFT BLANK

• SUSQUEHANNA - UNIT 1 3.8-43

Rev.2 AC Sources-Shutdown B 3.8.2 BASES THIS PAGE INTENTIONALLY LEFT BLANK

• SUSQUEHANNA - UNIT 1 3.8-44

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SSES MANUAL Manual Name: TSB2

.'Canual

Title:

TECHNICAL SPECIFICATIONS BASES TINIT 2 MANUAL Table Of Contents Issue Date: 03/18/2021 Procedure Name Rev Issue Date Change ID Change Number TEXT LOES 138 01/03/2019

Title:

LIST OF EFFECTIVE SECTIONS TEXT TOC 25 03/05/2019

Title:

TABLE OF CONTENTS TEXT 2 .1.1 5 01/22/2015

Title:

SAFETY LIMITS (SLS) REACTOR CORE SLS TEXT 2.1.2 1 10/04/2007 ~~

Title, SAFETY LIMITS (SLS) REACTOR COOLANT SYS~t.:,SURE SL TEXT 3.0 5 03/18/~

• Title, LIMITING CONDITION FOR OPERATI~¥LICAB ILITY TEXT 3 .1.1 . - 1 A~sz(fjm;,

Title:

REACTIVITY CONTROL~YS s~wtl MARGIN (SDM)

TEXT 3.1.2 0 11/18/2002 Title, REACTIVITY C r c 5 1 v S REACTIVITY ANOMALIES TEXT 3.1.3 Wo~ 3 11/16/2016 Title, REACTIVI~OL SYSTEMS CONTROL ROD OPERABILITY TEXT 3.1.4 5 11/16/2016

Title:

REACTIVITY CONTROL SYSTEMS CONTROL ROD SCRAM TIMES TEXT 3.1.5 2 11/16/2016

Title:

REACTIVITY CONTROL SYSTEMS CONTROL ROD SCRAM ACCUMULATORS TEXT 3.1.6 4 11/16/2016

Title:

REACTIVITY CONTROL SYSTEMS ROD PATTERN CONTROL Page 1 of 8 Report Date: 03/19/21

SSES MANUAL Manual Name: TSB2

'Canual

Title:

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REACTIVITY CONTROL SYSTEMS STANDBY LIQUID CONTROL (SLC) SYSTEM TEXT 3 .1. 8 4 11/16/2016

Title:

REACTIVITY CONTROL SYSTEMS SCRAM DISCHARGE VOLUME (SDV) VENT AND DRAIN VALVES TEXT 3.2.1 5 11/16/2016

Title:

POWER DISTRIBUTION LIMITS AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)

TEXT 3.2.2 4 11/16/2016

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POWER DISTRIBUTION LIMITS MINIMOM CRITICAL POWER RATIO (MCPR)

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POWER DISTRIBUTION LIMITS LINEAR HEAT GENERATION RATE LHGR

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Title:

INSTRUMENTATION SOURCE RANGE MONITOR (SRM) INSTRUMENTATION TEXT 3.3.2.1 4 11/16/2016

Title:

INSTRUMENTATION CONTROL ROD BLOCK INSTRUMENTATION TEXT 3.3.2.2 3 11/16/2016

Title:

INSTRUMENTATION FEEDWATER - MAIN TURBINE HIGH WATER LEVEL TRIP INSTRUMENTATION TEXT 3.3.3.1 9 11/16/2016

Title:

INSTRUMENTATION POST ACCIDENT MONITORING (PAM) INSTRUMENTATION TEXT 3.3.3.2 2 11/16/2016

Title:

INSTRUMENTATION REMOTE SHUTDOWN SYSTEM TEXT 3.3.4.1 2 11/16/2016

Title:

INSTRUMENTATION END OF CYCLE RECIRCULATION PUMP TRIP (EOC-RPT) INSTRUMENTA TION.

Page 2 of 8 Report Date: 03/19/21

. . SSES MANUAL

Manual Name: TSB2

.lanual

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL TEXT 3.3.4.2 1 11/16/2016

Title:

INSTRUMENTATION ANTICIPATED TRANSIENT WITHOUT SCRAM RECIRCULATION PUMP TRIP (ATWS-RPT) INSTRUMENTJ\TION TEXT 3.3.5.1 7 03/05/2019

Title:

INSTRUMENTATION EMERGENCY CORE COOLING SYSTEM (ECCS) INSTRUMENTATION TEXT 3.3.5.2 3 03/18/2021

Title:

REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL INSTRUMENTATION TEXT 3.3.5.3 0 03/05/2019

Title:

INSTRUMENTATION REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM INSTRUMENTATION (PREVIOUSLY TEXT 3.3.5.2 REVISION 1)

TEXT 3.3.6.1 9 03/05/2019

Title:

INSTRUMENTATION PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION

.._,EXT 3. 3. 6 .2 . . . _. _ . 6 JJ3/P;i/.20J_~--

Title:

INSTRUMENTATION SECONDARY CONTAINMENT ISOLATION INSTRUMENTATION \.

TEXT 3.3.7.1 4 03/05/2019

Title:

INSTRUMENTATION CONTROL ROOM EMERGENCY OUTSIDE AIR SUPPLY (CREOAS) SYSTEM INSTRUMENTATION TEXT 3.3.8.1 5 03/18/2021

Title:

INSTRUMENTATION LOSS OF POWER (LOP) INSTRUMENTATION TEXT 3.3.8.2 1 11/16/2016

Title:

INSTRUMENTATION REACTOR PROTECTION SYSTEM (RPS) ELECTRIC POWER MONITORING TEXT 3.4.1 5 11/16/2016

Title:

REACTOR COOLANT SYSTEM (RCS) RECIRCULATION LOOPS OPERATING TEXT 3.4.2 4 11/16/2016

Title:

REACTOR COOLANT SYSTEM (RGS) JET PUMPS TEXT 3.4.3 3 01/13/2012 Page 3

Title:

REACTOR COOLANT SYSTEM (RCS) SAFETY/RELIEF VALVES (S/RVS) of 8 Report Date: 03/19/21

SSES MANUAL Manual Name: TSB2

~anual

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL TEXT 3.4.4 1 11/16/2016

Title:

REACTOR COOLANT SYSTEM (RCS) RCS OPERATIONAL LEAKAGE TEXT 3.4.5 3 03/10/2010

Title:

REACTOR COOLANT SYSTEM (RCS) RCS PRESSURE ISOLATION VALVE (PIV) LEAKAGE TEXT 3.4.6 5 11/16/2016

Title:

REACTOR COOLANT SYSTEM (RCS) RCS LEAKAGE DETECTION INSTRUMENTATION TEXT 3.4.7 3 11/16/2016

Title:

REACTOR COOLANT SYSTEM (RCS) RCS SPECIFIC ACTIVITY TEXT 3.4.8 3 11/16/2016

Title:

REACTOR COOLANT SYSTEM (RCS) RESIDUAL HEAT REMOVAL (RHR) SHOTDOWN COOLING SYSTEM HOT SHOTDOWN 1EX:i:~:;.9~CTOR -~o~~

COLD SHUTDOWN 2

SYSTEM (R~s)

• 1

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6 REMO~--;~) SHOTDOWN COOLING sYsTA TEXT 3.4.10 6 05/14/2019

Title:

REACTOR COOLANT SYSTEM (RCS) RCS PRESSURE AND TEMPERATURE (P/T) LIMITS TEXT 3.4.11 1 11/16/2016

Title:

REACTOR COOLANT SYSTEM (RCS) REACTOR STEAM DOME PRESSURE TEXT 3.5.1 6 03/05/2019

Title:

EMERGENCY CORE COOLING SYSTEMS (ECCS) REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM ECCS OPERATING TEXT 3.5.2 6 03/18/2021

Title:

EMERGENCY CORE COOLING SYSTEMS (ECCS) REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM ECCS OPERATING TEXT 3.5.3 6 03/05/2019

Title:

EMERGENCY CORE COOLING SYSTEMS (ECCS) REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM ECCS Page 4 of OPERATING 8 Report Date:

03/19/21

SSES MANUAL

Manual Name: TSB2

.ianual

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL TEXT 3.6.1.1 6 11/16/2016

Title:

PRIMARY CONTAINMENT TEXT 3.6.1.2 2 11/16/2016

Title:

CONTAINMENT SYSTEMS PRIMARY CONTAINMENT AIR LOCK TEXT 3.6.1.3 19 03/18/2021

Title:

CONTAINMENT SYSTEMS PRIMARY CONTAINMENT ISOLATION VALVES (PCIVS)

TEXT 3.6.1.4 2 11/16/2016

Title:

CONTAINMENT SYSTEMS CONTAINMENT PRESSURE TEXT 3.6.1.5 2 11/16/2016

Title:

CONTAINMENT SYSTEMS DRYWELL AIR TEMPERATURE

'EXT. 3. 6 .1. 6 .1 _11/;L6/~Ql_6

Title:

CONTAINMENT SYSTEMS SUPPRESSION CHAMBER-TO-DRYWELL VACUUM BREAKERS TEXT 3.6.2.1 3 11/16/2016

Title:

CONTAINMENT SYSTEMS SUPPRESSION POOL AVERAGE TEMPERATURE TEXT 3.6.2.2 2 03/05/2019

Title:

CONTAINMENT SYSTEMS SUPPRESSION POOL WATER LEVEL TEXT 3.6.2.3 2 11/16/2016

Title:

CONTAINMENT SYSTEMS RESIDUAL HEAT REMOVAL (RHR) SUPPRESSION POOL COOLING TEXT 3.6.2.4 1 11/16/2016

Title:

CONTAINMENT SYSTEMS RESIDUAL HEAT REMOVAL (RHR) SUPPRESSION POOL SPRAY TEXT 3.6.3.1 2 06/13/2006

Title:

CONTAINMENT SYSTEMS INTENTIONALLY LEFT BLANK TEXT 3.6.3.2 3 09/29/2017

Title:

CONTAINMENT SYSTEMS DRYWELL AIR FLOW SYSTEM Page 5 of 8 Report Date: 03/19/21

,L SSES MANUAL Manual Name: TSB2 lanua1

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL TEXT 3.6.3.3 3 09/29/2017

Title:

CONTAINMENT SYSTEMS PRIMARY CONTAINMENT OXYGEN CONCENTRATION TEXT 3.6.4.1 17 12/16/2020

Title:

CONTAINMENT SYSTEMS SECONDARY CONTAINMENT TEXT 3.6.4.2 14 03/05/2019

Title:

CONTAINMENT SYSTEMS SECONDARY CONTAINMENT ISOLATION VALVES (SCIVS} .

TEXT 3.6.4.3 7 03/05/2019

Title:

CONTAINMENT SYSTEMS STANDBY GAS TREATMENT (SGT} SYSTEM TEXT 3.7.1 8 03/03/2020

Title:

PLANT SYSTEMS RESIDUAL HEAT REMOVAL SERVICE WATER (RHRSW} SYSTEM AND THE ULTIMATE HEAT SINK (UHS}

'EXT 3.7.2 .. - 4 _0_3/ P3 /2 02_0.

Title:

PLANT SYSTEMS EMERGENCY SERVICE WATER (ESW} SYSTEM TEXT 3.7.3 4 03/ 05/2 01.9

Title:

PLANT SYSTEMS CONTROL ROOM EMERGENCY OUTSIDE AIR SUPPLY (CREOAS} SYSTEM TEXT 3.7.4 2 03/05/2019

Title:

PLANT SYSTEMS CONTROL ROOM FLOOR COOLING SYSTEM TEXT 3.7.5 2 11/16/2016

Title:

PLANT SYSTEMS MAIN CONDENSER OFFGAS TEXT 3.7.6 4 11/16/2016

Title:

PLANT SYSTEMS MAIN TURBINE BYPASS SYSTEM TEXT 3.7.7 2 11/16/2016

Title:

PLANT SYSTEMS SPENT FUEL STORAGE POOL WATER LEVEL TEXT 3.7.8 1 11/16/2016 Page 6

Title:

MAINE TURBINE PRESSURE REGULATION SYSTEM of 8 Report Date: 03/19/21

SSES MANUAL Manual Name: TSB2

.tanual Title1 TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL TEXT 3.8.1 15 01/28/2020

Title:

ELECTRICAL POWER SYSTEMS AC SOURCES - OPERATING TEXT 3.8.2 2 03/18/2021

Title:

ELECTRICAL POWER SYSTEMS AC SOURCES - SHUTDOWN TEXT 3.8.3 7 08/07/2019

Title:

ELECTRICAL POWER SYSTEMS DIESEL FUEL OIL LUBE OIL AND STARTING AIR TEXT 3.8.4 4 11/16/2016

Title:

ELECTRICAL POWER SYSTEMS DC SOURCES - OPERATING TEXT 3.8.5 2 03/05/2019

Title:

ELECTRICAL POWER SYSTEMS DC SOURCES - SHOTDOWN

'EXT 3. 8. 6 _ . 2 -- __ 1;1./1_6:/20_1_6

Title:

ELECTRICAL POWER SYSTEMS BATTERY CELL PARAMETERS TEXT 3.8.7 7 09/04/2019

Title:

ELECTRICAL POWER SYSTEMS DISTRIBUTION SYSTEMS - OPERATING TEXT 3.8.8 2 03/05/2019

Title:

ELECTRICAL POWER SYSTEMS DISTRIBUTION SYSTEMS - SHUTDOWN TEXT 3.9.1 1 11/16/2016

Title:

REFUELING OPERATIONS REFUELING EQUIPMENT INTERLOCKS TEXT 3.9.2 2 11/16 /2 0.J.6

Title:

REFUELING OPERATIONS REFUEL POSITION ONE-ROD-OUT INTERLOCK TEXT 3.9.3 1 11/16/2016

Title:

REFUELING OPERATIONS CONTROL ROD POSITION TEXT 3.9.4 0 11/18/2002 Page 7

Title:

REFUELING OPERATIONS CONTROL ROD POSITION INDICATION of

• 8 Report Date: 03/19/21

SSES MANUAL Manual Name: TSB2

"'fflnual

Title:

TECHN'ICAL SPECIFICATIONS BASES DNIT 2 MANUAL

.TEXT 3 .9.5 1 11/16/2016

Title:

REFUELING OPERATIONS CONTROL ROD OPERABILITY - REFUELING TEXT 3.9.6 2 11/16/2016 J

Title:

REFUELING OPERATIONS REACTOR PRESSURE VESSEL (RPV) WATER LEVEL TEXT 3.9.7 1 11/16/201'6

Title:

REFUELING OPERATIONS RESIDUAL HEAT REMOVAL (RHR) - HIGH WATER LEVEL TEXT 3.9.8 1 11/16/2016

Title:

REFUELING OPERATIONS RESIDUAL HEAT REMOVAL (RHR) - LOW WATER LEVEL TEXT 3.10.1 2 03/05/2019

Title:

SPECIAL OPERATIONS INSERVICE LEAK AND HYDROSTATIC TESTING OPERATION

':'EXT_ 3 .10. 2 __

TEXT 3.10.3

- --- ____l

Title:

SPECIAL OPERATIONS REACTOR MODE SWITCH INTERLOCK TESTING 1 .11/16/2016

Title:

SPECIAL OPERATIONS SINGLE CONTROL ROD WITHDRAWAL - HOT SHUTDOWN TEXT 3.10.4 1 11/16/2016

Title:

SPECIAL OPERATIONS SINGLE CONTROL ROD WITHDRAWAL - COLD SHUTDOWN TEXT 3.10.5 1 11/16/2016 j

Title:

SPECIAL OPERATIONS SINGLE CONTROL ROD DRIVE (CRD) REMOVAL - REFUELING TEXT 3.10.6 1 11/16/2016

Title:

SPECIAL OPERATIONS MULTIPLE CONTROL ROD WITHDRAWAL - REFUELING TEXT 3.10.7 1 03/24/2005

Title:

SPECIAL OPERATIONS CONTROL ROD TESTING - OPERATING TEXT 3.10.8 3 11/16/2016 Page 8

Title:

SPECIAL OPERATIONS SHUTDOWN MARGIN (SDM) TEST - REFUELING of 8 Report Date:

03/19/21

Rev. 5 LCO Applicabilrty

• 8 3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY 8 3.0 BASES LCOs LCO 3.0.1 through LCO 3.0.8 establish the general requirements applicable to all Specifications and apply at all times', unless otherwise stated.

LCO 3.0.1 LCO 3.0.1 establishes the Applicabilrty statement within each individual Specification as the requirement for when the LCO is required to be met (i.e., when the unit is in the MODES or other specified conditions of the Applicability statement of each Specification).

LCO 3.0.2 LCO 3.0.2 establishes that upon discovery of a failure to meet an LCO, the associated ACTIONS shall be met. The Completion Time of each Required Action for an ACTIONS Condition is applicable from the point in time that an ACTIONS Condition is entered, unless otherwise specified.

The Required Actions establish those remedial measures that must be taken within specified Completion Times when the requirements of an LCO are not met. This Specification establishes that:

a. Completion of the Required Actions within the specified Completion Times constitutes compliance with a Specification; and

b. Completion of the Required Actions is not required when an LCO is met within the specified Completion Time, unless otherwise specified.

There are two basic types of Required Actions. The first type of Required Action specifies a time limit in which the LCO must be met.

This time limit is the Completion Time to restore an inoperable system or component to OPERABLE: status or to restore variables to within specified limits. If this type of Required Action is not completed within the specified Completion Time, a shutdown may be required to place the unit in a MODE or condition in which the Specification is not applicable. (Whether stated as a Required Action or not, correction of the entered Condition is an action that may always be considered upon entering ACTIONS.) The second type of Required Action specifies the remedial measures that permit continued operation of the unit that is not further restricted by the Completion Time. In this case, compliance with the Required Actions provides an acceptable level of safety for continued operation.

• • SUSQUEHANNA - UNIT 2 3.0-1

Rev.5 LCO Applicability B 3.0 BASES LCO 3.0.2 Completing the Required Actior:is is not required when an LCO is met or is (continued) no longer applicable, unless otherwise stated in the indMdual Specifications.

The nature of some Required Actions of some Conditions necessitates that, once the Condition is entered, the Required Actions must be completed even though the associated Conditions no longer exist. The individual LCO's ACTIONS specify the Required Actions where th'is is the case. An example of this is in LCO 3.4.10, "RCS Pressure and Temperature (PIT) Limits."

The Completion Times of the Required Actions are also applicable when a system or component is removed from service intentionally. The ACTIONS for not meeting a single LCO adequately manage any increase in plant risk, provided any unusual external conditions (e.g.,

severe weather, offsite power instability) are considered. In addition, the increased risk associated with simultaneous removal of multiple structures, systems, trains, or components from service is-assessed and managed in accordance with 10 CFR 50.65(a)(4). Individual Specifications may specify a time limit for performing an SR when equipment is removed from service or bypassed for testing. In this case, the Completion Times of the Required Actions are applicable when this time limit expires, if the equipment remains removed from service or bypassed.

When a change in MODE or other specified condition is required to comply with Required Actions, the unit may enter a MODE or other specified condition in which another Specification becomes applicable. In this case, the Completion Times of the associated Required Actions would apply from the point in time that the new Specification becomes applicable and the ACTIONS Condition(s) are entered.

LCO 3.0.3 LCO 3.0.3 establishes the actions that must be implemented when an LCO is not met and:

a. An associated Required Action and Completion Time is not met and no other Condition applies; or SUSQUEHANNA - UNIT 2 3.0-2

Rev. 5 LCO Applicability

• BASES LCO 3.0.3 (continued)

B 3.0

b. The condition of the unit is not specifically addressed by the associated ACTIONS. This means that no combination of Conditions stated in the ACTIONS can be made that exactly corresponds to the actual condition of the unit. Sometimes,possible combinations of Conditions are such that entering LCO 3.0.3 is warranted; in such cases, the ACTIONS specifically state a Condition corresponding to such combinations and also that LCO 3.0.3 be entered immediately.

This Specification delineates the time limits for placing the unit in a safe MODE or other specified condition when operation cannot be maintained within the limits for safe operation as defined by the LCO and its ACTIONS. Planned entry into LCO 3.0.3 should be avoided. If it is not practicable to avoid planned entry into LCO 3.0.3, plant risk should be assessed and managed in accordance with 10 CFR 50.65(a)(4), and the planned entry into LCO 3.0.3 should have less effect on plant safety than ottier practicable alternatives, Upon entering LCO 3.0.3, 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> is allowed to prepare for an orderty shutdown before initiating a change in unit operation. This includes time to permit the operator to coordinate the reduction in electrical generation with the load dispatcher to ensure the stability and availability of the electrical grid. The time limits specified to enter lower MODES of operation permit the shutdown to proceed in a controlled and orderly manner that is well within the specified maximum cooldown rate and within the capabilities of the unit, assuming that only the minimum required equipment Is OPERABLE. This reduces thermal stresses on components of the Reactor Coolant System and the potential for a plant upset that could challenge safety systems under conditions to which this Specification applies. The use and interpretation of specified times to complete the actions of LCO 3.0.3 are consistent with the discussion of Section 1.3, Completion Times.

A unit shutdown required in accordance with LCO 3.0.3.may be terminated and LCO 3.0.3 exited if any of the following occurs:

a. The LCO is now met,

b. The LCO is no longer applicable,

c. A Condition exists for which the Required Actions have now been performed, or

d. ACTIONS exist that do not have expired Completion Times. These Completion Times are applicable from the point in time that the Condition is initially entered and not from the time LCO 3.0.3 is exited .

• SUSQUEHANNA - UNIT 2 3.0-3

Rev. 5 LCO Applicability

• BASES LCO 3.0.3 (continued)

The time limits of LCO 3.0.3 allow 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br /> for the unit to be in MODE 4 when a shutdown is required during MODE 1 operation. If the unit is in a B 3.0 lower MODE of operation when a shutdown is required, the time limit for entering the next lower MODE applies. If a lower MODE is entered in less time than allowed, however, the total allowable time to enter MODE 4, or other applicable MODE, is not reduced. For example, if MODE 2 is entered in 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, then the time allowed for entering MODE 3 is the next 11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br />, because the total time for entering MODE 3 is not reduced from the allowable limit of 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br />. Therefore, if remedial measures are completed that would permit a return to MODE 1, a penalty is not incurred by having to enter a lower MODE of operation in less than the total time allowed.

In MODES 1, 2, and 3, LCO 3.0.3 provides actions for Conditions not covered in other Specifications. The requirements of LCO 3.0.3 do not apply in MODES 4 and 5 because the unit is already in the most restrictive Condition required by LCO 3.0.3. The requirements 'Of LCO 3.0.3 do not apply in other specified conditions of the Applicability (unless in MODE 1, 2, or 3) because the ACTIONS of individual Specifications sufficiently define the remedial measures to be taken .

• Exceptions to LCO 3.0.3 are provided in instances where requiring a unit shutdown, in accordance with LCO 3.0.3, would not provide appropriate remedial measures for the associated condition of the unit. An example of this is i_n LCO 3.7.7, "Spent Fuel Storage Pool Water Level." LCO 3.7.7 has an Applicability of "During movement of irradiated fuel assemblies in the spent fuel storage pool." Therefore, this LCO can be applicable in any or all MODES. If the LCO and the Required Actions of LCO 3.7.7 are not met while in MODE 1, 2; or 3, there is no safety benefit to be gained by placing the l!nit in a shutdown condition. The Required Action of LCO 3.7.7 of "Suspend movement of irradiated fuel assemblies in the spent fuel storage poor' is the appropriate Required Action to complete in lieu of the actions of LCO 3.0.3. These exceptions are addressed in the individual Specifications.

LCO 3.0.4 LCO 3.0.4 establishes limitations on changes in MODES or other specified conditions in the Applicability when an LCO is not met. It allows placing the unit in a MODE or other specified condition stated in that Applicability (e.g., the Applicability desired to be entered) when unit conditions are such that the requirements of the LCO would not be met, in accordance with either LCO 3.0.4.a, LCO 3.0.4.b, or LCO 3.0.4.c. I.

SUSQUEHANNA - UNIT 2 3.0-4

Rev. 5 LCO Applicablllty

• BASES LCO 3.0.4 (continued)

LCO 3.0.4.a allows entry into a MODE or other specified condition in the Applicability with the LCO not met when the associated ACTIONS to be B 3.0 entered following entry into the MODE or other specified condition in the Applicability will permit continued operation within the MODE or other specified condition for an unlimited period of time. Compliance with ACTIONS that permit continued operation of the unit for an unlimited period of time in a MODE or other specified condition provides an acceptable level of safety for continued operation. This is without regard to the status of the unit before or after the MODE change. Therefore, In such cases, entry into a MODE or other specified condition in the Applicability may be made and the Required Actions followed after entry into the Applicability.

For example, LCO 3.0.4.a may be used when the Required Action to be entered states that an inoperable instrument channel must be placed in the trip condition within the Completion Time. Transition into a MODE or other specified condition in the Applicability may be made in accordance with LCO 3.0.4 and the channel is subsequently placed in the tripped condition within the Completion Time, which begins when the Applicability is entered. If the instrument channel cannot be placed in the tripped condition and the subsequent default ACTION ("Required Action and associated Completion Time not met") allows the OPERABLE train to be placed in operation, use of LOO 3.0.4.a is acceptable because the subsequent ACTIONS to be entered following entry into the MODE include ACTIONS (place the OPERABLE train in operation) that permit safe plant operation for an unlimited period of time in the MODE or other specified condition to be entered.

LCO 3.0.4.b allows entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering the MODE or other specified condition in the Applicability, and establishment of risk management actions, tf appropriate.

The risk assessment may use quantitative, qualitative, or blended approaches, and the risk* assessment will be conducted using the plant program, procedures, and criteria in place to implement 10 CFR 50.65(a)(4}, which requires that risk impacts of maintenance activities to be assessed and managed. The risk assessment, for the purposes of LCO 3.0.4 (b), must take into account all inoperable Technical Specification ,equipment regardless of whether the equipment is included in the normal 10 CFR 50.65(a)(4) risk assessment scope .

• SUSQUEHANNA - UNIT 2 3.0-5

Rev. 5 LCO Applicability

• BASES LCO 3.0.4 (continued)

The risk assessments will be conducted using the procedures and guidance endorsed by Regulatory Guide 1.182, "Assessing and B 3.0 Managing Risk Before Maintenance Activities at Nuclear Power Plants.n Regulatory Guide 1.182 endorses the guidance in Section 11 of NUMARC 93-01, "Industry Guideline for Monitoring_ the Effectiveness of Maintenance at Nuclear Power Plants.m These documents address general guidance for conduct of the risk assessment, quantitative and qualitative guidelines for establishing risk management actions, and example risk management actions. These include actions to plan and conduct other activities in a manner that controls overall risk, increased risk awareness by shift and management personnel, actions to reduce the duration of the condition, actions to minimize the magnitude of risk increases (establishment of backup success paths or compensatory measures), and detennination that the proposed MODE change is acceptable. Consideration should also be given to the probability of completing restoration such that the requirements of the LCO would be met prior to the expiration of ACTIONS Completion Times that would require exiting the Applicability.

LCO 3.0.4.b may be used with single, or multiple systems and components unavailable. NUMARC 93-01 provides guidance relative to consideration of simultaneous unavailability of multiple systems and components.

The results of the risk assessment shall be considered in determining the acceptability of entering the MODE or other specified condition in the .

Applicability, and any corresponding risk management actions. The LCO 3.0.4.b risk assessments do not have to be documented.

The Technical Specifications allow continued operation with equipment unavailable in MODE 1 for the duration of the Completion Time. Since this is allowable, and since in general the .risk impact in that particular MODE bounds the risk of transitioning into and through the applicable MODES or other specified conditions in the Applicability of the LCO, the use of the LCO 3.0.4.b allowance should be generally acceptable, as long as the risk is assessed and managed as stated above. However, there is a small subset of systems and components that have been detennined to be more important to risk and use of the LCO 3.0.4.b allowance is prohibited. The LCOs governing these systems and components contain Notes prohibiting the use of LCO 3.0.4.b by stating that LCO 3.0.4.b is not applicable .

• SUSQUEHANNA - UNIT 2 3.0-6

Rev. 5 LCO Applicability B 3.0 BASES LCO 3.0.4 LCO 3.0.4.c allows entry into a MODE or other specified condition in the (continued) a Applicability with the LCO not met based on Note in the Specification which states LCO 3.0.4.c is applicable. These specific allowances permit entry into MODES or other specified conditions in the Applicability when the associated ACTIONS to be entered do not provide for continued operation for an unlimited period of time and a risk assessment has not been performed. This allowance may apply to all the ACTIONS or to a specific Required Action of a Specification. The risk assessments performed to justify the use of LCO 3.0.4.b usually only consider systems and components. For this reason, LCO 3.0.4.c is typically applied to Specifications which describe values and parameters (e.g., RCS Specific Activity) and may be applied to other Specifications based on NRC plant-specific approval.

The provisions of this Specification should not be interpreted as endorsing the failure to exercise the good practice of restoring systems or components to OPERABLE status before entering an associated MODE or other specified condition in the Applicability.

rhe provisions of LCO 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS. In addition, the provisions of LCO 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that result from any unit shutdown. In this context, a unit shutdown is defined as a change in MODE or other specified condition in the Applicability associated with transitioning from MODE 1 to MODE 2 or MODE 3, MODE 2 to MODE 3 or MODE 4, and MODE 3 to MODE 4.

Upon entry into a MODE or other specified condition in the Applicability with the LCO not met, LCO 3.0.1 and LCO 3.0.2 require entry into the applicable Conditions and Required Actions until the Condition is resolved, until the LCO is met, or until the unit is not within the Applicability of the Technical Specification.

Surveillances do not have to be performed on the associated inoperable equipment (or on variables outside the specified limits}, as permitted by SR 3.0.1. Therefore, utilizing LCO 3.0.4 is not a violation of SR 3.0.1 or SR 3.0.4 for any Surveillances that have not been performed on inoperable equipment. Howev~r, SRs must be met to ensure OPERABILITY prior to declaring the associated equipment OPERABLE (or variable within limits) and restoring compliance with the affected LCO.

SUSQUEHANNA - UNIT 2 3.0-7

Rev. 5 LCO Applicability B 3.0 BASES LCO 3.0.5 LCO 3.0.5 establishes the allowance for restming equipment to service under administrative controls when it has been removed from service or declared inoperable to comply with ACTIONS. The sole purpose of this Specification is to provide an exception to LCO 3.0.2 (e.g., to not comply with the applicable Required Action(s)) to allow the performance of required testing to demonstrate:

a. The OPERABILITY of the equipment being returned to service; or

b. The OPERABILITY of other equipment.

The administrative controls ensure the time the equipment is returned to service in conflict with the requirements of the ACTIONS is limited to the time absolutely necessary to perform the required testing to demonstrate OPERABILITY. This Specification does not provide tirne to perform any other preventive or corrective maintenance. LCO 3.0.5 should not be used in lieu of other practicable alternatives that comply with Required Actions and that do not require changing the MODE or other specified conditions in the Applicability in order to demonstrate equipment is OPERABLE. LCO 3.0.5 is not intended to be used repeatedly .

• An example. of demonstrating equipment is OPERABLE with the Required Actions not met is opening a manual valve that was closed to comply with Required Actions to isolate a flowpath with excessive Reactor Coolant System (RCS) Pressure Isolation Valve (PIV) leakage in order to perform testing to demonstrate that RCS PIV leakage is now Within limit.

Examples of demonstrating equipment OPERABILITY include instances in which it is necessary to take an inoperable channel or trip system out of a tripped condition that was directed by a Required Action, if there is no Required Action Note for this purpose. An example of verifying OPERABILITY of equipment removed from service is taking a tripped channel out of the tripped condition to permit the logic to function and indicate the appropriate response during performance of required testing on the inoperable channel. Examples of demonstrating the OPERABILITY of other equipment are taking an inoperable channel or trip system out of the tripped condition 1) to prevent the trip function from

• occurring during the performance of teqtiired testing on another channel in the other tlip system, or 2) to permit the logic to function and indicate the appropriate response during the performance of required testing on another channel in the same. trip system .

• SUSQUEHANNA - UNIT 2 3.0-8

Rev. 5 LCO Applicability B 3.0 BASES LCO 3.0.5 The administrative controls in LCO 3.0.5 apply in all cases to systems or (continued) components in Chapter 3 of the Technical Specifications, as long as the testing could not be conducted while complying with the Required Actions. This includes the realignment or repositioning of redundant or alternate equipment or trains previously manipulated to comply with ACTIONS, as well as equipment removed from service or declared inoperable to comply with ACTIONS.

LCO 3.0.6 LCO 3.0.6 establishes an exception to LCO 3.0.2 for supported systems*

that have a support system LCO specified in the Technical Specificatioris (TS). This exception is provided because LCO 3.0.2 woula require that the Conditions and Required Actions of the associated inoperable supported system LCO be entered solely due to the inoperability of the support system. This exception is justified because the actions that are required to ensure the plant is maintained in a safe condition are specified in the support system LCO's Required Actions. These Required Actions may include entering the supported system's Conditions and Required Actions or may specify other Required Actions. When a support system is inoperable and there is an LCO specified for it in the TS, the supported system(s) are required to be declared inoperable tf determined to be inoperable as a result of the support system inoperability. However, it is not necessary to enter into the supported systems' Conditions and Required Actions unless directed to do so by the support system's Required Actions. The potential confusion and inconsistency of requirements related to the entry into multiple support and supported systems' LCOS' Conditions and Required Actions are eliminated by providing all the actions that are necessary to ensure the plant is maintained in a safe condition in the support system's Required Actions.

However, there are instances where a support system's Required Action may either direct a supported system to be declared inoperable or direct entry into Conditions and Required Actions for the supported system.

This may occur immediately or after some specified delay to perform some other Required Action. Regardless of whether it is immediate or after some delay, when a support system's Required Action directs a supported system to be declared inoperable or directs entry into Conditions and Required Actions for a supported system, the applicable Conditions and Required Actions shall be entered in accordance with LCO 3.0.2.

SUSQUEHANNA - UNIT 2 3.0-9

Rev. 5 LCO Applicability B 3.0 BASES LCO 3.0.6 Specification 5.5 .. 11, "Safety Function Determination Program (SFDP),"

(continued) ensures loss of safety function is detected and appropriate actions are taken. Upon entry into LCO 3.0.6, an evaluation shall be made to determine if loss of safety function exists. Additionally, other limitations, remedial actions, or compensatory actions may be identified as a result of the support system inoperabilify and corresponding exception to entering supported system Conditions and Required Actions. The SFDP implements the *requirements of LCO 3.0.6 ..

Cross dMsion checks to identify a loss of safety function for those support systems that support safety sy$tems are required. The cross dMsion check verifies that the supported systems of the redundant OPERABLE support system are OPERABLE, thereby ensuring safety fu*nction is retained. If this evaluation determines that a loss of safety function exists, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered.

This loss of safety function does not require the assumption of additional single failures or loss of offsite power or concurrent loss of emergency diesel generators. Since operation is being restricted in accordance with the ACTIONS of the support system, any resulting temporary loss of redundancy or single failure protection is taken into account. Similarly, the ACTIONS for inoperable offSite circuit(s) and inoperable diesel generator(s) provide the necessary restriction for cross train ihoperabilities. This explicit cross train _verification for inoperable AC electrical power sources also acknowledges that supported system(s) are not declared-inoperable solely as a result of inoperability of a normal or emergency electrical power source (refer to the definition of OPERABILITY).

When a loss of safety function is determined to exist, and the SFDP requires entry into the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists, consideration must be given to the specific type of function affected. Where a loss of safety function is solely due to a single TS support system (e.g., loss of automatic start due to inoperable instrumentation, or loss of pump suction source due to low tank leveQ the appropriate LCO is the LCO for the support system. The ACTIONS for a support system LCO adequately address the inoperabilities of that system without reliance on entering its supported system LCO. When the loss offunction is the result of .multiple support systems, the appropriate LCO is the LCO for the supported

.system .

• SUSQUEHANNA - UNIT 2 3.0-10

Rev. 5 LCO Applicability B 3.0 BASES LCO 3.0.7 There are certain special tests and operations required to be performed at various times over the life of the unit. These special tests and operations are necessary to demonstrate select unit perfonnance characteristics, to perfom1 ~pecial maintenance activities, and to perform special evolutions.

Special Operations LCOs in Section 3.1 O allow specified TS requirements to be changed to pem1it perfom,ances of these special tests and operations, which otherwise could not be perfonned if required to comply with the requirements of these TS. Unless otherwise specified, all the other TS requirements remain unchanged. This will ensure all appropriate requirements of the MODE or other specified condition not directly*

aS$ociated with or required to be changed to perfbm, the special test or operation will remain in effect.

The Applicability of a Special Operations LCO represents a condition not necessarily In compliance with the nonnal requirements of the TS.

Compliance with Special Operations LCOs Is optional. A special operation may be perfom,ed either under the provisions of the appropriate Special Operations LCO or under the other applicable TS requirements. If it is desired to perfom, the special operation under the provisions of the Special Operations LCO, the requirements of the Special Operations LCO shall be followed. When a Special Operations LCO requires another LCO to be met, only the requirements of the LCO statement are required to be met regardless of that LCO's Applicability (i.e., should the requirements of this other LCO not be met, the ACTIONS of the Special Operations LCO apply, not the ACTIONS of the other LCO). However, there are instances where the Special Operations LCO ACTIONS may direct the other LCOs' ACTIONS be met. The Surveillances of the other LCO are not required to be met, unless specified in the Special Operations LCO. If conditions exist such that the Applicability of any other LCO is met, all the other LCO's requirements (ACTIONS and SRs) are required to be met concurrent with the requirements of the Special Operations LCO.

LCO 3.0.8 LCO 3.0.8 establishes conditions under which systems are considered to remain capable of performing their intended safety function when associated snubbers are not capable of providing their associated support function(s). This LCO states that the supported system is not considered to be inoperable solely due to one or more snubbers not capable of perfonning their associated support function(s). This is appropriate because a limited length of time is allowed for maintenance, testing, or repair of one or more snubbers not capable of performing their associated support function(s) and appropriate compensatory measures of TRO 3.7.8 are followed. The snubber requirements do not meet the criteria in 10 CFR 50.36(c)(2)(ii), and, as such, are appropriate for control within the Technical Requirements Manual.

SUSQUEHANNA - UNIT 2 3.0-11

Rev. 5 LCO Applicability

• BASES LCO 3.0.8 (continued) 8 3.0 If the allo\Yed time expires and the snubber(s) are unable to perform their associated support function(s), the affected supported system's LCO(s) must be declared not met and the Conditions and Required Actions entered in accordance with LCO 3.0.2.

LCO 3.0.8.a applies when one or more snubbers are not capable of providing their associated support function(s) to a single train or subsystem of a multiple train or subsystem supported system or to a single train or subsystem supported system. LCO 3.0.8.a allows 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to restore the snubber(s) before declaring the supported system inoperable. The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time is reasonable based on the low probability of a seismic event concurrent with an event that would require operation of the supported system occurring while the snubber(s) are not capable of perfom,ing their associated support function and due to the availability of the redundant train of the supported system.

LCO 3.0.8.b applies when one or more snubbers are not capable of providing their associated support functlon(s) to more than one train or subsystem of a multiple train or subsystem supported system. LCO 3.0.8.b allows 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> to restore the snubber(s) before declaring the supported system inoperable. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Completion Time is reasonable based on the low probability of a seismic event concurrent with an event that would require operation of the supported system occurring while the snubber(s) are not capable of perfom,lng their associated support function.

LCO 3.0.8 requires that risk be assessed and managed. Industry and NRC guidance on the implementation of 10 CFR 50.65(a)(4) (the Maintenance Rule) does not address seismic risk. However, use of LCO 3.0.8 should be considered with respect to other plant maintenance activities, and integrated into the existing Maintenance Rule process to the extent possible so that maintenance on any unaffected train or subsystem is properly controlled, and emergent issues are properly addressed. The risk assessment need not be quantified, but may be a qualitative awareness of the vulnerability of systems and components when one or more snubbers are not able to perfom, their associated support function.

SUSQUEHANNA - UNIT 2 3.0-11a

Rev. 5 SR Applicability B 3.0 B 3.0 SURVEILLANCE REQUIREMENT (SR) APPLICABILITY BASES SRs SR 3.0.1 through SR 3.0.4 establish the general requirements applicable to all Specifications and apply at all times, unless otherwise stated.

SR 3.0.1 SR 3.0.1 establishes the requirement that SRs must be met during the MODES or other specified conditions in the Applicability for which the requirements of the LCO apply, unless otherwise specified in the individual SRs. .This Specification is to ensure that Surveillances are performed to verify the OPERABILITY of systems and components, and that variables are within specified limits. Failure to meet a Surveillance witllin the specified Frequency, in accordance with SR 3.0.2, constitutes a failure to meet an LCO.

Systems and components are assumed to be OPERABLE when the associated SRs have been met. Nothing in this Specification, however, is to be construed as implying that systems or components are OPERABLE when:

a. The systems or components are known to be inoperable, although still meeting the SRs; or

b. The requirements of the Survelllance(s) are known to be not met between reqyired Surveillance performances.

Surveillances do not have to be performed when the unit is in a MODE or other specified condition for which the requirements of the associated LCO are not applicable, unless otherwise specified. The SRs associated with a Special Operations LCO are only applicable when the Special Operations LCO is used as an allowable exception to the requirements of a Specification.

Unplanned events may satisfy the requirements CTncluding applicable acceptance criteria) for a give'n SR. In this case, .the unplanned event may be credited as fulfilling the performance of the SR. This allowance includes those SRs whose performance is normally precluded in a given MODE or other specified condition.

Surveillances, including Surveillances invoked by Required Actions, do not have to be performed on inoperable equipment because the ACTIONS define the remedial measures that apply. Surveillances have to be met and performed in accordance with SR. 3.0.2, prior to returning equipment to OPERABLE status.

SUSQUEHANNA - UNIT 2 3.0-12

Rev.5 SR Applicability

• BASES SR 3.0.1 (continued)

Upon completion of maintenance, appropriate post maintenance testing is required to declare equipment OPERABLE. This includes ensuring B 3.0 applicable Surveillances are not failed and their most recent perfom,ance is in accordance with SR 3.0.2'. Post maintenance testing may not be possible in the current MODE or other specified conditions in the Applicability due to the necessary unit parameters not having been

• established. In these situations, the equipment may be considered OPERABLE provided testing has been satisfactorily completed to the extent possible and the equipment is not otherwise believed to be incapable of perfom,ing its function. This will allow operation to proceed to a MODE or other specified condition where other necessary post maintenance tests can be completed.

Some examples of this process are:

Control Rod Drive maintenance during refueling that requires scram testing at > 800 psi. However, if other appropriate testing is satisfactorily completed and the scram time testing of SR 3 .. 1.4.3 is satisfied, the control rod can be considered OPERABLE. This allows startup to proceed to reach 800 psi to perfom, other necessary testing.

High pressure coolant injection (HPCI) maintenance during shutdown that requires system functional tests at a specified pressure. Provided other appropriate testing is satisfactorily completed, startup can proceed with HPCI considered OPERABLE. This allows operation to reach the specified pressure to complete the necessary post maintenance testing.

SR 3.0.2 SR 3.0.2 establishes the requirements for meeting the specified Frequency for Surveillances and any Required Action with a Completion Time that requires the periodic performance of the Required Action on a "once per ... " interval.

SR 3.0.2 pennits a 25% extension of the interval specified in the Frequency. This extension facilitates Surveillance scheduling and considers plant operating conditions that may not be suitable for conducting the Surveillance (e.g., transient conditions or other ongoing Surveillance or maintenance activities).

The 25% extension does not significantly degrade the reliability that results from performing the Surveillance at its specified Frequency. This is based on the recognition that the most probable result of any particular Surveillance being performed is the verification of confom,ance with the SRs. The exceptions to SR 3.0.2 are those Surveillances for which the

• SUSQUEHANNA - UNIT 2 3.0-13

Rev. 5 SR Applicability

• BASES SR 3.0.2 (continued) 25% extension of the interval specified in the Frequency does not apply.

These exceptions are stated in the individual Specifications.

B 3.0 As stated in SR 3.0.2, the 25% extension also does not apply to the initial portion of a periodic Completion Time that requires performance on a "once per. .. basis. The 25% extension applies to each performance after the initial performance. The Initial performance of the Required Action, whether it is a particular Surveillance or some other remedial action, is considered a single action with a single Completion Time. One reason for not allowing the 25% extension to this Completion Time is that such an action usually verifies that no loss of function has occurred by checking the status of redundant or diverse components or accomplishes the function of the inoperable equipment in an alternative manner.

The provisions of SR 3.0.2 are not intended to be used repeatedly to extend Surveillance intervals (other than those consistent with refueling intervals) or periodic Completion Time intervals beyond those specified.

SR 3.0.3 SR 3.0.3 establishes the flexibility to defer declaring affected equipment inoperable or an affected variable outside the specified limits when a Surveillance has n0t been performed within the specified Frequency. A delay period of up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or up to the limit of the specified Frequency, whichever is greater, applies from the point in time that it is discovered that the Surveillance has not been performed in accordance with SR 3.0.2, and not at the time that the specified Frequency was not met.

This delay period provides adequate time to perform Surveillances that have been missed. This delay period permits the performance of a Surveillance before complying with Required Actions or other remedial measures that might preclude performance of the Surveillance.

The wsis for this delay period includes consideration of unit conditions, adequate planning, availability of personnel, the time required to perform the Surveillance, the safety significance of the delay in completing the required Surveillance, and the recognition that the most probable result of any particular Surveillance being performed is the verffication of conformance with the requirements.

When a Surveillance with a l=requency based not on the time intervals, but upon specified unit conditions, operating situations, or requirements of regulations (e.g., prior to entering MODE 1 after each fuel loading, or in accordance with 10 CFR 50, Appendix j, as modified by approved exemptions, etc.) is discovered to not have been performed when specified, SR 3.0.3 allows for the full delay period of up to the specified

• SUSQUEHANNA - UNIT 2 3.0--14

Rev. 5 SR Applicabillty

• BASES SR 3.0.3 (continued)

Frequency to perfonn the Surveillance. However, since there Is not a time B 3.0 interval specified, the missed Surveillance should be perfonned at the first reasonable opportunity.

SR 3.0.3 provides a time limit for, and allowances for the performance of Surveillances that become applicable as a consequence of MODE changes imposed by Required Actions.

SR 3.0.3 is only applicable if there is a reasonable expectation the associated equipment is OPERABLE or that variables are within limits, and it is expected that the Surveillance will be met when perfonned. Many factors should be considered, such as the period of time since the

~urveillance was last perfonned, or whether the Surveillance, or a portion thereof, has ever been perfonned, and any other indications, tests, or activities that might support the expectation that the Surveillance will be met when perfonned. Ah example of the use of SR 3.0.3 would be a relay contact that was not tested as required in accordance with a particular SR, but previous successful perfonnances of the SR included the relay contact; the adjacent, physically connected relay contacts were tested during the SR performance; the subject relay contact has been tested by another SR; or historical operation of the subject relay contact has been successful. It is not sufficient to infer the behavior of the associated equipment from the perfonnance of similar equipment The rigor of determining whether there is a reasonable expectation a Surveillance will be met when perfonned should increase based on the length of time since the last perfonnance of the Surveillance. If the Surveillance has been performed recently, a review of the Surveillance history and equipment performance may be sufficient to support a reasonable expectation that the Surveillance will be met when perfonned. For Surveillances that have not been perfonned for a long period or that have never been perfonned, a rigorous evaluation based on objective evidence should provide a high degree of confidence that the equipment is OPERABLE. The *evaluation should be documented in sufficient detail to allow a knowledgeable individual to understand the basis for the detennination.

Failure to comply with specified Frequencies for SRs is expected to be an infrequent occurrence. Use of the delay period established by SR 3.0.3 Is a flexibility which is not intended to be used repeatedly to extend Surveillance intervals. While up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or the limit of the specified Frequency Is provided to perfonn the missed Surveillance, it is expected that the missed Surveillance will be performed at the first reasonable opportunity. The* determination of the first reasonable opportunity should include consideration of the impact on plant risk (from delaying the Surveillance as well as any plant configuration changes required or shutting the plant down to perfonn the Surveillance) and impact on any analysis assumptions, in addition to unit conditions, planning, availabillty of SUSQUEHANNA - UNfT 2 3.0-15

Rev. 5 SR Applicability

• • BASES SR 3.0.3 (continued) personnel, and the time required to perform the Surveillance. The risk impact should be managed through the program ih place to implement 1O B 3.0 CFR 50.65(a)(4) and its implementation guidance, NRC Regulatory Guide 1.182, "Assessing and Managing Risk before Maintenance Activities at Nuclear Power Plants." This Regulatory Guide addresses consideration of temporary and aggregate risk impacts, determination of risk management action thresholds, and risk management action up to and including plant shutdown. The missed Surveillance should be treated as an emergent condition as discussed in the Regulatory Guide. The risk evaluation may use quantitative, qualitative, or blended methods. The degree of ,depth and rigor of the evaluation should be commensurate with the importance of the component. Missed Surveillances for important components should be analyzed quantitatively. If the results of the risk evaluation determine the risk increase is significant, this evaluation should be used to determine the safest course of action. All missed Surveillances will be placed in the Corrective Action Program.

If a Surveillance is not completed within the allowed delay period, then the equipment is considered inoperable or the variable is considered outside the specified limits and the Completion Times of the Required Actions for the applicable LCO Conditions begin immediately upon expiration of the delay period. If a Surveillance is failed within the delay period, then the equipment is inoperable, or the variable is outside the specified limits and the Completion Times of the Required Actions for the applicable LCO Conditions begin immediately upon the failure of the Surveillance.

Completion of the Surveillance within the delay period allowed by this Specification, or within the Completion Time of the ACTIONS, restores compliance with SR 3.0.1.

SR 3.0.4 SR 3.0.4 establishes the requirement that all applicable SRs must be met before enby into a MODE or other specified condition in the Applicability.

This.Specification ensures that system and component OPERABILITY requirements and variable limits are met before entry into MODES or other specified conditions in the Applicability for which these systems and components ensure safe operation of the unit. The provisions of this Specification should not be interpreted as endorsing the failure to exercise the good practice of restoring systems or components to OPERABLE status before entering an associated MODE or other specified condition in the Applicability.

A provision is included to allow entry into a MODE or other specified condition in the Applicability when an LCO is not met due to Surveillance not being met in accordance with LCO 3.0.4.

• SUSQUEHANNA - UNIT 2 3.0-16

Rev. 5 SR Applicability

• BASES SR 3.0.4 (continued)

B 3.0 However, in certain circumstances, failing to meet an SR will not result in SR 3.0.4 restricting a MODE change or other specified condition change. When a system, subsystem, division, component, device, or variable is inoperable or outside its specified limits, the associated SR(s) are not required to be performed, per SR 3.0.1, which states that Surveillances do not have to be performed on inoperable equipment.

When equipment is inoperable, SR 3.0.4 does not apply to the associated SR(s) since the requirement for the SR(s) to be performed is removed. Therefore, failing to perform the Surveillance(s) within the specified Frequency does not result in an SR 3.0.4 restriction to changing MODES or other specified conditions of the .Applicability.

However, since the LCO is not met in this instance, ~CO 3.0.4 will govern any restrictions that may (or may not) apply to MODE or other specified condition changes. SR 3.0.4 does not restrict changing MODES or other specified conditions of the Applicability when a Surveillance has not been performed within the specified Frequency, provided the requirement to declare *the LCO not met has been delayed in accordance with SR 3.0.3.

The provisions of SR 3.0.4 shall not prevent entry into MODES or other specified conditions in the Applicability that are required to comply with ACTIONS. In addition, the provisions of SR 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that result from any unit shutdown. In this context, a unit shutdown is defined as a change in MODE or other specified condition in the Applicability associated with transitioning from MODE 1 to MODE 2 or MODE 3, MODE 2 to MODE 3 or MODE 4, and MODE 3 to MODE 4.

The precise requirements for performance of SRs are specified such that exceptions to SR 3.0.4 are not necessary. The specific time frames and conditions necessary for meeting the SRs are specified in the Frequency, ih the Surveillance, or both. This allows performance of Surveillances when the prerequisite condition(s) specified in a Surveillance procedure require entry into the MODE or other specified condition in the Applicability of the associated LCO prior to the performance or completion of a Surveillance. A Surveillance that could not be performed until after entering the LCOs Applicability, would have its Frequency specified such that it is not "due" until the specific conditions needed are met.

Alternately, the Surveillance may be stated in the form of a Note, as not required (to be met or performed) until a particular event, condition, or time has been reached. Further discussion of the specific formats of SRs' annotation is found in Section 1.4, Frequency.

SUSQUEHANNA - UNIT 2 3.0-17

Rev. 3 RPV Water Inventory Control Instrumentation B 3.3.5.2 B 3.3 INSTRUMENTATION B 3.3.5.2 Reactor Pressure Vessel (RPV) Water Inventory Control Instrumentation BASES BACKGROUND The RPV contains penetrations below the top of the active fuel (TAF) that have the potential to drain the reactor coolant inventory to below the T AF.

If the water level should drop below the TAF, the ability to remove decay heat is reduced, which could lead to elevated cladding temperatures and clad perforation. Safety Limit 2.1.1.3 requires the RPV water level to be above the top of the active irradiated fuel at all times to prevent such elevated cladding temperatures.

Technical Specifications are required by 10 CFR 50.36 to include limiting safety system settings (LSSS) for variables that have significant safety functions. LSSS are defined by the regulation as 'Where a LSSS is specified for a variable on which a safety limit has been placed, the setting must be chosen so that automatic protective actions will correct the abnormal situation before a Safety Limit (SL) is exceeded." The Analytical Limit is the limit of the pr:ocess variable at which a safety action is initiated to ensure that a SL is not exceeded. Any automatic protection action that occurs on reaching the Analytical Limit therefore ensures that the SL is not exceeded. However, in practice, the actual settings for automatic protection channels must be chosen to be more conservative than the Analytical Limit to account for instrument loop uncertainties related to the setting at which the automatic protective action would actually occur. The actual settings for the automatic isolation channels are the same as those established for the same functions in MODES 1, 2, and 3 in LCO 3.3.6.1, "Primary Containment Isolation instrumentation".

Wrth the unit in MODE 4 or 5, RPV water inventory control is not required to mitigate any events or accidents evaluated in the safety analyses.

RPV water inventory control is required in MODES 4 and 5 to protect Safety Limit 2.1.1.3 and the fuel cladding barrier to prevent the release of radioactive material should a draining event occur. Under the definition of DRAIN TIME, some penetration flow paths may be excluded from the DRAIN TIME calculation if they will be isolated by valves that will close automatically without offsrte power prior to the RPV water level being equal to the TAF when actuated by RPV water level isolation instrumentation .

• SUSQUEHANNA - UNIT 2 3.3-133

Rev. 3 RPV Water Inventory Control Instrumentation B 3.3 ..5.2 BASES BACKGROUND The purpose of the RPV Water Inventory Control Instrumentation is to

' (continued) support the requirements of LCO 3.5.2, "Reactor Pressure Vessel (RPV)

Water Inventory Control," and the definition of DRAIN TIME. There are functions that support automatic isolation of Residual Heat Removal subsystem and Reactor Water Cleanup system penetration flow path(s) on low RPV water level.

APPLICABLE Wrth the unit in MODE 4 or 5, RPV water inventory control is not required SAFETY to mitigate any events or accidents evaloated in the safety analyses. RPV ANALYSES, LCO, water inventory control is required In MODE~ 4 and 5 to protect Safety and Limit 2.1.1.3 and the fuel cladding barrier to prevent the release of APPLICABILITY radioactive material should a draining event occur.

A double-ended guillotine break of the Reactor Coolant System (RCS) is not considered in MODES 4 and 5 due to the reduced RCS pressure, reduced piping stresses, and ductile piping systems. Instead, an event is considered in which an initiating event allows draining of the RPV water inventory through a single penetration flow path with the highest flow rate, or the sum of the drain rates through multiple penetration flow patns susceptible to a common mode failure. It is assumed, based on engineering judgment, that while in MODES 4 and 5, one low pressure ECCS injection/spray subsystem can be manually initiated to maintain adequate reactor vessel water level.

As discussed in References 1, 2, 3, 4, and 5, operating experience has shown RPV water inventory to be significant to public health and safety.

Therefore, RPV Water Inventory Control satisfies Criterion 4 of 10 CFR 50.36(c)(2)(iQ.

Permissive ahd interlock setpoints are generally considered as nominal values without regard to measurement accuracy.

The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis.

1. Not used

2. Not used SUSQUEHANNA - UNIT 2 3.3-134

Rev. 3 RPV Water Inventory Control Instrumentation B 3.3.5.2 BASES APPLICABLE. RHR System Isolation SAFETY 3.a - Reactor Vessel Water Level - Low, Level 3 ANALYSES, LCO, and The definition of DRAIN TIME allows crediting the closing of penetration APPLICABILITY flow paths that are capable of being isolated by valves that will close (continued) automatically without offsite power prior to the RPV water level being equal to the TAF when actuated by RPV water level isolation instrumentation. The Reactor Vessel Water Level - Low, Level 3 Function associated with RHR System isolation may be credited for automatic isolation of penetration flow paths associated with the RHR System.

Reactor Vessel Water Level - Low, Level 3 signals are initiated from four level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. While four channels (two channels pet trip system) of the Reactor Vessel Water Level - Low, Level 3 Function are available, only two channels (all in the same trip system) are required to be OPERABLE.

The Reactor Vessel Water Level - Low, Level 3 Allowable Value was chosen to be the same as the Primary Containment Isolation Instrumentation Reactor Vessel Water Level - Low, Level 3 Allowable Value (LCO 3.3.6.1), since the capability to cool the fuel may be threatened.

The Reactor Vessel Water Level - Low, Level 3 Function is only required to be OPERABLE when automatic isolation of the associated penetration flow path is credited in calculating DRAIN TIME.

Reactor Water Cleanup (RWCU) System Isolation 4.a - Reactor Vessel Water level - Low Low, Level 2 The definition of DRAIN TIME allows crediting the closing of penetration flow paths that are capable of being isolated by valves that will close automatically without offsite power prior to the RPV water level being equal to the TAF when actuated by RPV water level isolation instrumentation. The Reactor Vessel Water Level - Low Low, Level 2 Function associated with RWCU System isolation may be credited for automatic isolation of penetration flow paths associated with the RWCU System.

SUSQUEHANNA - UNIT 2 3.3-135

Rev. 3 RPV Water Inventory Control Instrumenta tion B 3.3.5.2 BASES APPLICABLE Reactor Water Cleanup (RWCU) System Isolation SAFETY 4.a - Reactor Vessel Water level - Low Low, Level 2 (continued)

ANALYSES, LCO, and Reactor Vessel Water Level - Low Low, Level 2 signals are initiated from APPLICABILITY four level transmitters that sense the difference between the pressure due (continued) to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. While four channels (two channels per trip system) of the Reactor Vessel Water Level - Low Low, Level 2 Function are available, only two channels (all in the same trip system) are required to be OPERABLE.

The Reactor Vessel Water Level - Low Low, Level 2 Allowable Value was chosen to be the same as the ECCS Reactor Vessel Water Level - Low Low, Level 2 Allowable Value (LCO 3.3.5.1), since the capability to cool the fuel may be threatened.

The Reactor Vessel Water Level - Low Low, Level 2 Function is only required to be OPERABLE When automatic isolation of the associated penetration flow path is credited in calculating DRAIN TIME .

• ACTIONS A Note has been provided to modify the ACTIONS related to RPV Water ln~entory Control instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems 1 components, or variables expressed in the Condition discovered to be inoperable or not within limits will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable RPV Water Inventory Control instrumentation channels provide appropriate compensatory measures for separate inoperable Condition entry for each inoperable RPV Water InventoryControl instrumentation channel.

A.1, A.2.1 and A.2.2 RHR System Isolation, Reactor Vessel Water Level - Low Level 3, and Reactor Water Cleanup System, Reactor Vessel Water Level - Low Low,

• Level 2 functions are applicable when automatic isolation of the associated penetration flow path is* credited In calculating DRAIN TIME. If the instrumentation is inoperable, Required Action A.1 directs immediate action to place the channel in trip. Wrth the inoperable channel in the tripped condition, the remaining channel will isolate the penetration flow path on low water level. If both channels are inoperable and placed in trip, the penetration flow path will be isolated. Alternatively, Required Action A.2.1 requires the associated penetration flow path(s) to be immediately SUSQUEH ANNA - UNIT 2 3.3-136

Rev. 3 RPV Water Inventory Control Instrumen tation B 3.3.5.2 BASES ACTIONS A.1, A.2.1 and A.2.2 (continued)

(continued) declared incapable of automatic isolation. Required Action A.2.2 directs initiating action to calculate DRAIN TIME. The calculation cannot credit automatic isolation of the affected penetratio n flow paths.

SURVEIL LANCE The following SRs apply to each RPV Water inventory Control instrumen t REQUIRE MENTS Function in Table 3.3.5.2-1.

SR 3.3.5.2.1 Performance of the CHANNEL CHECK ensures that a gross failure of instrumentation has not occurred. A CHANNE L CHECK is normally a comparison of the parameter indicated on one channel to a similar paramete r oh other channels. It is based on the assumption that instrument channels monitoring the same paramete r should read approximately the same value. Significan t deviation s between the instrument channels could be an indication of excessive instrumen t drift in one of the channels or something even more serious. A CHANNE L CHECK guarantee s that undetected outright channel failure is limited; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL FUNCTIO NAL TEST.

Agreeme nt criteria are determined by the plant staff, based on a combination of the channel instrument uncertainties, including Indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit.

The Surveillance Frequency is controlled under the Surveillan ce Frequency Control Program.

The CHANNE L CHECK suppleme nts less formal, but more frequent, checks of channels during normal operational use .of the displays associated with the channels required by the LCO.

SR 3.3.5.2.2 A CHANNE L FUNCTIO NAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function .

• SUSQUE HANNA - UNIT 2 3.3-137

Rev. 3 RPV Water Inventory Control Instrumentatio n B 3.3.5.2 BASES SURVEILLAN CE SR 3.3.5.2.2 (continued)

REQUIREME NTS (continued) This SR is modified by a Note that provides a general exception to the definition of CHANNEL FUNCTIONAL TEST. This exception is necessary because the design of instrumentation does not facilitate functional testing of all required contacts of the relay which ihput into the combinational logic.

Performance of such a test could result in a plant transient or place the plant In an undue risk situation. Therefore, for this SR, the CHANNEL FUNCTIONAL TEST verifies acceptable.response by verifying the cnange of state of the relay which inputs into the combinational logic. The required contacts not tested during the CHANNEL FUNCTIONAL TEST are tested under the LOGIC SYSTEM FUNCTIONAL TEST, SR 3.3.5.2.3. This is acceptable because operating experience shows that the contacts not tested during the CHANNEL FUNCTIONAL TEST normally pass the LOGIC SYSTEM FUNCTIONAL TEST, and the testing methodology minimizes the risk of Unplanned transients.

Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

• • REFERENCE S The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

1. Information Notice 84-81 "Inadvertent Reduction ir::1 Primary Coolant Inventory in Boiling Water Reactors During Shutdown and Startup,"

November 1984.

2. Information Notice 86-74, "Reduction of Reactor Coolant Inventory Because of Misalignment of RHR Valves," August 1986.

3. Generic Letter 92-04, "Resolution of the Issues Related to Reactor Vessel Water Level Instrumentation in BWRs Pursua.nt to 10 CFR 50.54(F), "August 1992.

4. NRC Bulletin 93-03, "Resolution of Issues Related to Reactor Vessel Water Level Instrumentation in BWRs," May 1993.

5. Information Notice 94-52, "Inadvertent Containment Spray and Reactor Vessel Draindown at Millstone 1," July 1994 .

• SUSQUEHAN NA - UNIT 2 3.3-138

Rev. 3 RPV Water Inventory Control Instrumentation B 3.3.5.2 BASES

• THIS PAGE INTENTIONALLY LEFT BLANK SUSQUEHAN NA - UNIT 2 3.3-139

Rev. 3 RPV Water Inventory.Control lnsttumentatio n B 3.3.5.2 BASES THIS PAGE INTENTIONALLY LEFT BLANK SUSQUEHAN NA - UNIT 2 3.3-140

Rev. 5 LOP Instrumentation B 3.3.8.1 B 3.3 INSTRUMENTATION B 3.3.8.1 Loss of Power (LOP) Instrumentation BASES BACKGROUND Successful operation of the required safety functions of the Emergency Core Cooling Systems (ECCS) Is dependent upon the availability of adequate power sources for energizing the various components. such as pump motors, motor operated valves, and ttie associated control components. The LOP instrumentation monitors the 4.16 kV emergency buses. Offsite power is the preferred source of power for the 4.16 kV emergency buses. If the monitors determine that insufficient power is available, the buses are disconnected from the offsite power sources and connected to the onsite diesel generator (DG) power sources.

Each 4.16 kV emergency bus has its own independent LOP instrumentation and associated bip logic. The voltage for _each bus is monitored at three levels, which*can be considered as three different

• • undervoltage Functions: Loss of Voltage(< 20%), 4.16 kV Emergency Bus Undervoltage Degraded Voltage LOCA (< 93%), and 4.16 kV Emergency Bus Undervoltage Low Setting (Degraded Voltage) (< 65%). Each Function, with the exception of the Loss of Voltage relays is monitored by two undervoltage relays for each emergency bus, whose outputs are arranged in a two-out-of-two logic configuration. The LosS of Voltage Function is monitored by one undervoltage relay for each emergency bus, whose output is arranged in a _one-out-of-one logic configuration. When voltage degrades below the setpoint, the channel output relay actuates, which then outputs a LOP trip signal to the trip logic.

APPLICABLE The LOP instrumentation is required for Engineered Safety Features to SAFETY function in any accident with a loss of offsite power. The Unit 1 LOP ANALYSES, instrumentation is required to be operable for Unit 2 when the associated LCO, and Unit 1 4.16 kV emergency buses ate required to be operable per Unit 2 APPLICABILITY T.S. 3.8.7 and 3.8.8. The required channels of LOP instrumentation ensure that the ECCS and other assumed systems powered from the DGs, provide plant protection in the event of any of the Reference 1 and 2 analyzed accidents in which a loss of offsite power is assumed. The initiation of the DGs on loss of offsite power, and subsequent initiation of the ECCS, ensure that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.

SUSQUEH ANNA - UNIT 2 3.3-206

Rev.5 LOP Instrumenta tion B 3.3.8.1 BASES APPLICABL E Accident .analyses credit the loading of the DG based on the loss of offsite SAFETY power during a loss of coolant accident The diesel starting and loading ANALYSES , times have been included in the delay time associated with each safety LCO, and system component requiring DG supplied power following a loss of offsite APPLICABI LITY power.

(continued)

The LOP instrumentation satisfies Criterion 3 of the NRC Policy statement.

(Ref. 3)

The OPERABILITY of the LOP instrumentation is dependent upon the OPERABIL ITY of the Individual instrur:nentatiori channel Functions specified in Table 3.3.8.1-1. Each Function must have a required number of OPERABLE channels per 4.16 kV emergency bus, with their setpoints within the specified Allowable Values. A channel is inoperable if its actual trip setpoint is not within its required Allowable Value. The actual setpoint is calibrated consistent with applicable setpoint methodolog y assumption s.

The Allowable Values are specified for each Function in the Table. Trip setpoints are specified in the system calculations. The setpoints are selected to ensure that the setpoints do not exceed the Allowable Value .

• Operation with a trip setpoint less conservative than the nominal trip setpoint, but within the Allowable Value, is acceptable. Trip setpoints are those predetermined values of output at which an action should take place.

The setpoints are compared to the actual process parameter (e.g.,

degraded voltage), and when the measured output value of the process parameter reaches the setpoint, the associated device changes state. The Allowable Values are derived from the limiting values of the process parameters obtained from the safety analysis. The trip setpoints are then derived based on engineering judgment The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis.

1. 4.16 kV Emergency Bus Undervoltag e (Loss of Voltage< 20%)

Loss of voltage on a 4.16 kV emergency bus indicates that offsite power may be completely lost to the respective emergency bus and is unable to supply sufficient power for proper operation of the applicable equipment.

Therefore, the power supply to the bus is transferred from offsite power to DG power when the voltage on the bus drops below the Loss of Voltage Function Allowable Values (loss of voltage with a short time delay). This ensures that adequate power will be available to the required equipment.

• SUSQUEH ANNA - UNIT 2 3.3-207

Rev. 5 LOP Instrumentation B 3.3.8.1 BASES APPLICABL E 1. 4.16 kV Emergency Bus Undervoltage (Loss of Voltage< 20%)

SAFETY ( continued)

ANALYSES, LCO, and The Bus Undervoltage Allowable Values are low enough to prevent APPLICABI LITY inadvertent power supply transfer, but high enough to ensure that power is (continued) available to the required equipment. The Time Delay Allowable Values are long enough to provide time for the offsite power supply to recover to normal voltages, but short enough to ensure that power Is available to the required equipment.

One channel of 4.16 kV Emergency Bus Undervoltage (Loss of Voltage)

Function per associated emergency bus is required to be OPERABLE when the associated DG is required to be OPERABLE to ensure that no single instrument failure can preclude the DG function. 4.16 kV Emergency Bus Undervoltage (Loss of Voltage) relay controls and provides a permissive to allow closure of the associated alternate source breaker and the associated DG breaker. (one channel input to each of the four DGs.)

Refer to LCO 3.8.1, "AC Sources-O perating," for Applicability Bases for the DGs .

• 2., 3. 4.16 kV Emergency Bus Undervoltage (Degraded Voltage)

A reduced voltage condition on a 4 kV emergency bus indicates that, while offsite power may not be completely lost to the respective emergency bus, available power may be insufficient for starting large ECCS motors without

-risking damage to the motors that could disable the ECCS function.

Therefore, power supply to the bus Is transferred from offsite power to onsite DG power when there is no offsite power or a degraded power supply to the bus. This transfer will occur only if the voltage of the primary and alternate power sources drop below the Degraded Voltage Function_

Allowable Values (degraded voltage with a time delay) and the source breakers trip which causes the DG to start. This ensures that adequate power will be available to the required equipment.

• SUSQUEH ANNA - UNIT 2 3.3-208

Rev. 5 LOP Instrumen tation B 3.3.8.1 BASES APPLICA BLE 2., 3. 4.16 kV Emergency Bus Undervoltage (Degraded Voltage)

SAFETY (continued)

ANALYSES, LCO, and Two Function::; are provided to monitor degraded voltage at two different APPLICABILITY levels. These Functions are the Degraded Voltage LOCA (< 93%) and (continued) Degraded Voltage Low Setting(< 65%). These relays respond to degraded voltage as follows: 93% for approximately 5 minutes (when no LOCA signal is present) and approximately 10 seconds (with a LOCA signal present), and 65% (Degraded Voltage Low Setting). The Degraded Voltage LOCA Function preserves the assumptions of the LOCA analysis and the Degraded Voltage Low Setting Function preserves the assumptions of the accident sequence analysis in the FSAR. The circuitry is designed such that with the LOCA signal present, the non-LOC A time delay is, physically bypassed.

The Bus Undervoltage Allowable Values are low enough to prevent inadvertent power supply transfer, but high enough to ensure that sufficient power is available to the required equipment.' The Time Delay Allowable Values are long enough to provide time for the offsite power supply to recover to nonnal voltages, but short enough to ensure that sufficient power is available to the required equipment.

Two channels of 4.16 kV Emergency Bus Undervoltage (Degraded Voltage) per Function (Functions 2 and 3) per associated bus are required to be OPERABLE when the associated DG is required to be OPERABLE.

This ensures no single instrument failure can preclude the start of DGs (each logic inputs to each of the four DGs). Refer to LCO 3.8.1 for Applicability Bases for the DGs.

ACTIONS A Note has been provided to modify the ACTIONS related to LOP Instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable LOP instrumentation channels provide appropriate compensatory measures for separate inoperable channels. As such, a Note has been provided that allows separate Condition entry for each inoperable LOP instrumentation channel.

SUSQUE HANNA - UNIT 2 3.3-209

Rev. 5 LOP Instrumentation B 3 3.8.1 BASES ACTIONS 6,1 (continued)

Required Action A.1 directs entry into the appropriate Condition referenced

!n Table 3.3.8.1-1 when LOP insti:umentation channels are inoperable for

~easons other than for the performance of SR 3.8.1.19 on Unit 1. The applicable Condition specified in the Table is Function dependent. Each time a channel associated with a Unit 1 4.16 kV ESS Bus since the Unit 1 4.16 kV ESS Buses power station common loads such as SGTS, OREOASS, and ESW or a Unit 2 4.16 ESS Bus is discovered inoperable, Condition A is entered for that channel and provides for transfer to the appropriate subsequent Condition.

B.1 Wrth one or more required channels on the Unit 1 4.16 kV ESS Buses in one DMsion for the performance of SR 3.8.1.19 in Unit 1 inoperable but hot resulting in a loss of safety function, the remaining channels are capable of supporting the minimum safety functions necessary to shut down the reactor and maintain it in a safe shutdown condition, assuming no single failure. The overall reliability is reduced, however, because a single failure

• in the remaining channels could result in the minimum required ESF functions not being supported. Therefore, the required Unit 1 4.16 kV ESS Bus channels must be restored to OPERABLE status within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.

C.1 Wrth one or more channels of a Function inoperable, the Function is not capable of performing the intended function. Therefore, only 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> is allowed to restore the inoperable channel to OPERABLE status. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per Required Action C.1'. Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore capability to accommodate a single failure (Within the LOP instrumentation), and allow operation to continue. Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing the channel in trip would result in a DG initiation), Condition E must be entered and its Required Action taken.

The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. Th_e 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Completion Time is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.

SUSQUEH ANNA - UNIT 2 3.3-210

Rev.5 LOP Instrumentation B 3.3.8.1 BASES ACTIONS D.1 (continued)

Wrth one channel of the Function inoperable, the Function is not capabl~

of perfomiing the intended function. Therefore, only 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> is allowed to restore the inoperable channel to OPERABLE status. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, Condition E must be entered and its Required Action taken.

The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Completion Time is acceptable because it minimizes risk while allowing time for restoration of channels.

E.1 If the Required Action and associated Completion Times of Conditions 8, C, or D are not rnet, the a5:5ociated Function is not capable of performing the intended function. Therefore, the associated DG(s) is declared inoperable immediately for Unit 2 only. This requires entry into applicable Conditions and Required Actions of Unit 2 LCO 3.8.1, which provide appropriate actions for the inoperable DG(s).

SURVEILLANCE: As noted at the beginning of the SRs, the SRs for each LOP REQUIREMENTS instrumentation Function are located in the SRs column of Table 3.3.8.1-1.

The Su,veillances are modified by a Note to indicat_e that When a channel is placed in an inoperable status solely for performance of required Surveillances, enby into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided the associated Function maintains DG initiation ~pability. Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> allowance, the channel must be returned to OPERABLE

• status or the applicable Condition entered and Required Actions taken.

SR 3.3.8.1.1 Performance of the CHANNEL CHECK ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channef to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same par:ameter should read -

approximately the same value. Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or SUSQUEHANNA - UNIT 2 3.3-211

Rev.5

• • BASES SURVEILLA NCE SR 3.3.8.1.1 (continued)

LOP Instrumenta tion 8 3.3.8.1 REQUIREM ENTS

( continued) something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATI ON.

Agreement criteria Which are determined by the plant staff based on an investigation of a combination of the channel instrument uncertaintie s may be used to support this parameter comparison and include indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside Its limit.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The CHANNEL CHECK supplement s less formal checks

• of channels during normal operational use of the displays associated with channels required by the LCO.

SR 3.3.8.1.2 A CHANNEL FUNCTION AL TEST is performed on each required channel

• to ensure that the entire channel will perform the intended function.

The Surveillance Frequency is controlled under the Surveillanc e Frequency Control Program.

SR 3.3.8.1.3 A CHANNEL CALIBRATION verifies that the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATI ON leaves the channel adjusted to account for instrum~nt drifts between successive calibrations consistent with the plant specific setpoint methodology.

Any setpoint adjustment shall be consistent with the assumption s of the current plant specific setpoint methodolog y.

The Surveillance Frequency is controlled under the Surveillanc e Frequency Control Program .

• SUSQUEH ANNA - UNIT 2 3.3-212

Rev. 5 LOP Instrumentation B 3.3.8.1 BASES SURVEIL LANCE SR 3.3.8.1.4 REQUIRE MENTS (continued) The LOGIC SYST~M FUNCTIONAL TEST demonstrates the OPERABILITY of the required actuation logic for a specific channel. The system functional testing performed in LCO 3.8.1 and LCO 3.8.2 overlaps this Surveillance to provide complete testing of the assumed safety functions ..

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFEREN CES 1. t=SAR, Section 6.3.

2. FSAR, Chapter 15.

3. Final Policy Statemen t on Technical Specifications Improvements, July 22,1993 (58 FR 32193)

• SUSQUE HANNA - UNIT 2 3.3-213

Rev.6 RPV Water Inventory Control B 3.5.2 B 3.5 EMERGEN CY CORE COOLING SYSTEMS (ECCS), REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL, AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM B 3.5.2 Reactor Pressure Vessel (RPV) Water Inventory Control BASES BACKGRO UND The RPV contains penetration s below the top of the active fuel (TAF) that have the potential to drain the reactor coolant inventory to below the T AF.

If the water level should drop below the TAF, the ability to remove decay heat is reduced, which could lead to elevated cladding temperatur es and clad perforation. Safety Limit 2.1.1.3 requires the RPV water level to be above the top of the active irradiated fuel at all times to prevent such elevated cladding temperature s.

APPLICAB LE Wrth the unit in MODE 4 or 5, RPV water inventory control is not required SAFETY to mitigate any events or accidents evaluated in the safety analyses.

ANALYSES RPV water inventory control is required in MODES 4 and 5 to protect Safety Limit 2.1.1.3 and the fuel cladding barrier to prevent the release of radioactive material to the environmen t should an unexpected draining event occur.

A double-ended guillotine break of the Reactor Coolant System (RCS) is not considered in MODES 4 and 5 due to the reduced RCS pressure, reduced piping stresses, a.nd ductile piping systems. Instead, an event is considered in which an initiating event allows draining of the RPV water inventory through a single penetration flow path with the highest flow rate.,

or the sum of the drain rates through. multiple penetration flow paths susceptibfe to a common mode failure (an event that creates a drain path through multiple vessel penetrations located below top of active fuel, such as loss of normal 'power, or a single human error). It is assumed, based on engineering judgement, that while in MODES 4 and 5, one low pressure ECCS injection/spray subsystem can maintain adequate reactor vessel water level.

As discussed in References 1, 2, 3, 4, and 5, operating experience has shown RPV water inventory to be significant to public health and safety.

Therefore, RPV Water Inventory Control satisfies Criterion 4 of 10 CFR 50.36(c)(2)(i~.

SUSQUEH ANNA - UNIT 2 3.5-17

Rev.6 RPV Water Inventory Control B 3.5.2 BASES LCO The RPV water level must be controlled in MODES 4 and 5 to ensure that if an unexpected draining event should occur, the reactor coolant water level remains above the top of the active irradiated fuel as required by Safety Limit 2.1.1.3.

The Limiting Condition for Operation (LCO) requires the DRAIN TIME of RPV water inventory to the TAF to be~ 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. A DRAIN TIME of 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> is considered reasonable to identify and initiate action to mitigate unexpected draining of reactor coolant An event that could cause loss of RPV water inventory and result in the RPV water level reaching the T ~ in greater than 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> does not represent a significant challenge to Safety Limit 2.1.1.3 and can be managed as part of normal plant operation.

One low pressure ECCS injection/spray subsystem is required to be OPERABLE and capable of being manually aligned and started from the control room to provide defense-in- depth should an unexpected draining event occur. OPERABIL ITY of the ECCS injection/spray subsystem includes any necessary valves, instrumentation, or controls needed to manually align and start the subsystem from the control room. A low pressure ECCS injection/spray subsystem consists of either one Core Spray (CS) subsystem or one Low Pressure Coolant Injection (LPCI) subsystem. Each CS subsystem consists of one motor driven pump, piping, and valves to transfer water from the suppression pool or condensate storage tank (CST) to the RPV. Each LPCI subsystem consists of one motor driven pump, piping, and valves to transfer water from the suppression pool to the RPV. In MODES 4 and 5, the RHR System cross tie valves are not required to be closed.

The LCO is modified by a Note which allows a required LPCI subsystem to be considered OPERABLE during alignment and operation for decay heat removal if capable of being manually realigned (remote or local) to the LPCI mode and is not otherwise inoperable. Alignment and operation for decay heat removal includes when the required RHR pump is not operating or when the system is reaHgned from or to the RHR shutdown cooling mode. This allowance is necessary since the RHR System may be

• required to operate in the shutdown cooling mode to remove decay heat and sensible heat from the reactor. Because of the restrictions on DRAIN TIME, sufficient time will be available following an unexpected draining event to manually align and initiate LPCI subsystem operation to maintain RPV water inventory prior to the RPV water level reaching the TAF.

SUSQUEH ANNA - UNIT 2 . 3.5-18

Rev. 6 RPV Water Inventory Control B 3.5.2 BASES APPLICAB ILITY RPV water inventory control is required In MODES 4 and 5. Requirements on water inventory control in other MODES are contained in LCOs in Section 3.3, "Instrumen tation/ and other LCOs In Section 3.5, "ECCS, RPV Water Inventory Control, and RCIC System." RPV water Inventory control is required to protect Safety Limit 2.1.1.3 which is applicable whenever irradiated fuel is in the reactor vessel.

ACTIONS A.1 and B.1 If the required low pressure EGGS injection/spray subsystem Is inoperable, it must be restored to OPERABLE status within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. In this Condition, the LCO controls on DRAIN TIME minimize the possibility that an unexpected draining event could necessitate the use of the EGGS injection/spray subsystem, however the defense-in-depth provided by the EGGS injection/spray subsystem is lost The 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Completion Time for restoring the required low pressure ECCS injection/spray subsystem to OPERABLE status is based on engineering judgment that considers the LCO controls on DRAIN TIME and the low probability of an unexpected draining event that would result in loss of RPV water inventory.

If the inoperable EGGS injection/spray subsystem is not restored to OPERABLE status within the required Completion Time, action must be initiated immediately to establish a method of water injection capable of operating without offsite ~lectrical power. The method of water injection includes the necessary instrumentation and controls, water sources, and pumps and valves needed to add water to the RPV or refueling cavity should an unexpected draining event occur. The method of water injection may be manually initiated and may consist of one or more systems or subsystems, and must be able to access water inventory capable of maintaining the RPV water level above the TAF for ~ 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. If recirculation of injected water would occur, it may be credited in determining the necessary water volume.

C.1, C.2, and C.3 With the DRAIN TIME less than 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> but greater than or equal to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, compensatory measures should be taken to ensure the ability to implement mitigating actions should an unexpected draining event occur.

Should a draining event lower the reactor coolant level to below the TAF, there is potential for damage to the reactor fuel cladding and release of radioactive material. Additional actions are taken to ensure that radioactive material will be contained, diluted, and processed prior to being released to the environment.

• SUSQUEH ANNA - UNIT 2 3.5-19

Rev. 6 RPV Water Inventory Control B 3.5.2 BASES ACTIONS C.1, C.2, and C.3 (continued)

(continued)

The secondary containment provides a controlled volume in which fission products can be contained, diluted, and processed prior to release to the environment. Required Action C.1 requires verification of the capability to establish the secondary containment boundary in less than the DRAIN TIME.

The required verification confirms actions to establish the secondary containment boundary are preplanned and necessary materials are available. The secondary containment boundary is considered established when one Standby Gas Treatment (SGD subsystem is capable of maintaining a negative pressure in the secondary containmen t with respect to the environment. Verification that the secondary containmen t boundary can be established must be performed within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The required verification is an administrative activity and does not require manipulation or testing of equipment. Secondary containmen t penetration flow paths form a part of the secondary containmen t boundary. Required Action C.2 requires verification of the capability to isolate each secondary containmen t penetration flow path in less than the DRAIN TIME. The required verification confirms actions to isolate the secondary containmen t penetration flow paths are preplanned and necessary materials are available. Power operated valves are not required to receive automatic isolation signals if they can be closed manually within the required time.

Verification that the secondary containmen t penetration flow paths can be Isolated must be performed within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The required verification is an administrative activity and does not require manipulatio n or testing of equipment.

One SGT subsystem is capable of maintaining the secondary containmen t at a negative pressure with respect to the environmen t and filter gaseous releases. Required Action C.3 requires verification of the capability to place one SGT subsystem in operation in less than the DRAIN TIME. The required verification confirms actions to place a SGT subsystem in operation are preplanned and necessary materials are availaQle.

Verification that a SGT subsystem can be placed In operation must be performed within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The required verification is an administrative activity and does not require manipulation or testing of equipment.

Required Actions C.1, C.2, and C.3 are considered to be met when secondary containmen t, secondary containmen t penetration s, and the SGT System are OPERABLE in accordance with LCO 3.6.4.1, LCO 3.6.4.2, and LCO 3.6.4.3 .

• SUSQUEH ANNA - UNIT 2 3.5-20

Rev.6

• RPV Water Inventory Control B 3.5.2 BASES ACTIONS D.1, D.2, D.3, and D.4 (continued)

With the DRAIN TIME less than 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, mitigating actions are implemented in case an unexpected draining event should occur. Note that if the DRAIN TIME is less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, Required Action E.1 is also applicable.

Required Action D.1 requires immediate action to establish an additional method of water injection augmenting the ECCS injection/spray subsystem required by the LCO. The additional method of water injection includes the necessary lnstrumentatior:i and controls, water sources, and pumps and valves needed to add water to the RPV or refueling cavity should an unexpected draining event occur. The Note to Required Action D.1 states that either the ECCS injection/spray subsystem or the additional method of water injection must be capable of operating without offsite electrical power. The additional method of water injection may be manually initiated and may consist of one or more systems or subsystems. The additional method of water injection must be able to access water inventory capable of being injected to maintain the RPV water level above the T AF for ~ 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The additional method of water injection and the ECCS injection/spray subsystem may share all or part of the same watE?[ sources.

If recirculation of injected water would occur, it may be credited in detennlning the required water volume.

Should a draining event lower the reactor coolant level to below the TAF, there is potential for damage to the reactor fuel cladding and release of radioactive material. Additional actions are taken to ensure that radioactive material will be contained, diluted, and processed prior to being released to the environmen t The secondary containment provides a control volume in which fission products can be contained, diluted, and processed prior to release to the environment. Required Action D.2 requires that actions be immediately initiated to establish the secondary containmen t boundary. Wrth the secondary containment boundary established, one SGT subsystem is capable of maintaining a negative pressure in the secondary containment with respect to the environment.

The secondary containment penetrations fonn a part of the secondary containment boundary. Required Action D.3 requires that actions be immediately initiated to verify that each secondary containment penetration flow path is isolated or to verify that it can be automatically or manually Isolated from the control room .

• • SUSQUEH ANNA - UNIT 2 3.5-21

Rev.6

• BASES

-ACTIONS D.1, D.2, D.3, and D.4 (continued)

RPV Water Inventory Control B 3.5.2 (continued)

One SGT subsystem is capable of maintaining the secondary containment at a negative pressure with respect to the environmen t and filter gaseous releases. Required Action D.4 requires that actions be immediately initiated to verify that at least one SGT subsystem is capable of being placed in operation. The required verification is an administrative activity and does not require manipulation or testing of equipment Required Actions D.2, D.3, and D.4 are considered to be met when secondary containmen t, secondary containmen t penetration s, and the SGT System are OPERABLE in accordance with LCO 3.6.4.1, LCO 3.6.4.2, and LCO 3.6.4.3.

E.1 If the Required Actions and associated Completion times of Conditions C or D are not met or if the DRAIN TIME is less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, actions must be initiated immediately to restore the DRAIN TIME to ~ 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. In this condition, there may be insufficient time to respond to an unexpected draining event to prevent the RPV water inventory from reaching the T AF.

Note that Required Actions D.1, D.2, D.3, and D.4 are also applicable when DRAIN TIME is less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

SURVEILLA NCE SR 3.5.2.1 REQUIREM ENTS This Surveillance verifies that the DRAIN TIME of RPV water inventory to the T AF is ~ 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The period of 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> is considered reasonable to identify and initiate action to mitigate draining of reactor coolant. Loss of RPV water inventory that would result in the RPV water level reaching the T AF in greater than 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> does not represent a significant challenge to Safety Limit 2.1.1.3 and can be managed as part of normal plant operation.

The definition of DRAIN TIME states that realistic cross-sectional areas and drain rates are used in the calculation. A realistic dr:ain rate may be determined using a single, step-wise, or integrated calculation considering the changing RPV water level during a draining event. For a Control Rod RPV penetration flow path with the Control Rod Drive Mechanism removed and not replaced with a blank flange, the realistic cross-sectional area is based on the control rod blade seated in the control rod guide tube. If the control rod blade will be raised from the penetration to adjust or vertfy seating of the blade, the exposed cross-sectional area of the RPV penetration flow path is used .

• • SUSQUEH ANNA - UNIT 2 3.5-22

Rev. 6 RPV Water Inventory Control B 3.5.2 BASES SURVEILLA NCE SR 3.5.2.1 (continued)

REQUIREM ENTS (continued) The definition of DRAIN TIME excludes from the calculation those penetration flow paths connected to an intact closed system, or isolated by manual or automatic valves that are closed and administratively controlled, blank flanges, or other devices that prevent flow of reactor coolant through the penetration flow paths. A blank flange or other bolted device must be connected with a sufficient number of bolts to prevent draining. Normal or expected leakage from closed systems or past isolation devices is permitted. Determination that a system is intact and closed or isolated must consider the status of branch Lines.

The Residual Heat Removal (RHR) Shutdown Cooling System is only considered an intact closed system when misalignme nt issues (Reference

6) have been precluded by functional valve interlocks or by isolation devices, such that redirection of RPV water out of an RHR subsystem is precluded. Further, RHR Shutdown Cooling System is only considered an intact closed system if its controls have not been transferred to Remote Shutdown, which disables the int~rlocks and isolation signals .

• The exclusion of a single penetration flow path, or multiple penetration flow paths susceptible to a common mode failure, from the determination of DRAIN TIME should consider the effects of temporary alterations in support of maintenanc e (rigging, scaffolding, temporary shielding, piping -

plugs, freeze seals, etc.). If reasonable controls are implemented to prevent such temporary alterations from causing a draining event from a closed system or between the RPV and the isolation device, the effect of the temporary alterations on DRAIN TIME need not be considered.

Reasonable controls include, but are not limited to, controls consistent with the guidance in NUMARC 93-01, "Industry Guideline for Monitonng the Effectivene ss of Maintenance at Nuclear Power Plants," Revision 4, NUMARC 91-06, "Guidelines for Industry Actions to Assess Shutdown Manageme nt," or commitments to NUREG-06 12, "Control of Heavy Loads at Nuclear Power Plants."

Surveillance Requirement 3.0.1 requires SRs to be met between performances. Therefore, any changes in plant conditions that would change the DRAIN TIME requires that a new DRAIN TIME be determined .

The Surveillanc e Frequency is controlled under the Surveillance Frequency Control Program.

SUSQUEH ANNA - UNIT 2 3.5-23

Rev.6

• BASES SURVEILLANCE SR 3.5.2.2 and SR 3.5.2.3 RPV Water Inventory Control B 3.5.2 REQUIREMENTS (continued) The minimum water level of 20 ft. O inches required for the suppression pool is periodically verified to ensure that the suppression pool will provide adequate net positive suction head (NPSH) for the CS subsystem or LPCI subsystem pump, recirculation volume, and vortex prevention. Wrth the suppression pool water level less than the required limit, the required ECCS injection/spray subsystem is inoperable unless aligned to an OPERABLE CST.

The required CS System is considered OPERABLE if it can take suction from the CST, and the CST water level is sufficient to provide the required NPSH for the CS pump. Therefore, a verification that either the suppression pool water level is ~20 ft. 0 inches or that a required CS subsystem is aligned to take suction from the CST and the CST contains

~ 135,000 gallons of water, equivalent to 49% of capacity, ensures that the CS Subsystem can supply at least 135,000 gallons of makeup water to the RPV.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.5.2.4 The flow path piping has the potential to develop voids and pockets of entrained ait. Maintaining the pump discharge lines of the required ECCS injection/spray subsystems full of water ensures that the ECCS subsystem will perform properly. This may also prevent a water hammer following an ECCS actuation. One acceptable method of ensuring that the lines are full is to vent at the high points.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.,

SR 3.5.2.5 Not used SUSQUEHAN NA - UNIT 2 3.5-24

Rev.6 RPV Water Inventor y Control B3.5.2 BASES SURVEILLANCE SR 3.5.2.6 REQUIREMENTS (continued) Verifying that the required ECCS injection/spray suosystem can be manually aligned, and the pump started and operated for at least 10 minutes demonstrates that the subsystem is available to mitigate a draining event. This SR is modified by two Notes. Note 1 states that testing the ECCS injection/spray subsystem may be done through the test return line to avoid overfilling the refueling cavity. Note 2 states that credit for meeting the SR may be taken for nonnal system operation that satisfies the SR, such as using the RHR mode of LPCI for :2: 1O minutes.

The minimum operating time of 1O minutes was based on engineering judgment.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.5.2.7 Verifying that each valve credited fot automatically isolating a penetration flow path actuates to the isolation position on an actual or simulated RPV

• water level isolation signal is required to prevent RPV water inventory from dropping below the TAF should an unexpected draining event occur.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.5.2.8 This Surveillance verifies that a required CS subsystem or LPCI subsystem can be manuall y aligned and started from the control room, includihg any necessary valve alignment, instrumentation, or controls, to transfer water from the suppression pool or CST to the RPV.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

This SR is modified by a Note that excludes V9S$el injection/spray during the Surveillance. Since all active components are testable and full flow can be demonstrated by recirculation through the test line, coolant injection into the RPV is not required during the Surveillance .

• • SUSQU EHANN A - UNII 2 3.5-25

Rev. 6 RPV Water Inventory Control B 3.5.2 BASES REFERENCES 1. Information Notice 84-81 "Inadvertent Reduction in Primary Coolant Inventory in Boiling Water Reactors During Shutdown and Startup,"

November 1984.

2. Information Notice 86-74, "Reduction of Reactor Coolant Inventory Because of Misalignment of RHR Valves," August 1986.

3. Generic Letter 92-04, "Resolution of the Issues Related to Reactor Vessel Water Level Instrumentation in BWRs Pursuant to 10 CFR 50.54(f), "August 1992.

4. NRC Bulletin 93-03, "Resolution of Issues Related to Reactor Vessel Water Level Instrumentation in BWRs," May 1993.

5. Information Notice 94-52, "Inadvertent Containment Spray and Reactor Vessel Draindown at Millstone 1," July 1994.

6. General Electric Service Information Letter No. 388, "RHR Valve Misalignment During Shutdown Cooling Operation for BWR 3/4/5/6,"

February 1983.

• SUSQUEHANNA - UNIT 2 3.5-26

Rev. 19 PCIVs B 3.6.1.3 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.3 Primary Containment Isolation Valves (PCIVs)

BASES BACKGROUND The function of the PC IVs, in combination with other accident mitigation systems, including secondary containment bypass valves that are not PCIVs is to limit fission product release during and following postulated Design Basis Accidents (DBAs) to within limits. Primary containment isolation within the time limits specified for those isolation valves designed to close automatically ensures that the release of radioactive material to the environment Will be consistent with the assumptions used in the analyses for a OBA.

The OPERABILl1Y requirements for PCIVs help ensure that an adequate primary containment boundary is maintained during and after an accident by minimizing potential paths to the environment.

Therefore, the OPERABILITY requirements provide assurance that primary containment function assumed in the safety analyses will be

• main~ined . For PCIVs, the primary containment isolation function is that the valve must be able to close (automatically or manually) and/or remain closed, and maintain leakage within that assumed in the OBA LOCA Dose Analysis. These isolation devices are either passive or active (automatic). Manual valves, de-activated automatic Valves secured in their closed position (including check valves with flow through the valve secured), blind flanges, and closed systems are considered passive devices. The OPERABILITY requirements for closed systems are discussed in Technical Requirements Manual (TRM) Bases 3.6.4. Check valves, or other automatic valves designed to close without operator action following an accident, are considered active devices. Two barriers in series are provided for each penetration so that no single credible failure or malfunction of an active component can result in a loss of isolation or leakage that exceeds limits assumed in the safety analyses. One of these barriers may be a closed system.

For each dMsion of H202 Analyzers, the lines, up to and including the first normally closed valves within the H202 Analyzer panels, are extensions of primary containment (i.e., closed ~ystern), and are required to be leak rate tested in accordance with the Leakage Rate Test Program. The H202 Analyzer closed system boundary is identified in the Leakage Rate Test Program. The closed system boundary consists of those components, piping, tubing, fittings, and valves, which meet the guidance of Reference 6. The closed system provides a secondary barrier in the event of a single failure of the PCIVs, as described below.

The closed system boundary between PASS and the H202 Arialyzer

• • system ends at the process sampling solenoid operated isolation valves SUSQUEHANNA - UNIT 2 3.6-15

Rev. 19 PCIVs 8 3.6.1.3 BASES BACKGROUND between the systems (SV-22361, SV-22365, SV-22366, SV-22368,. and (continued) SV-22369). These solenoid operated isolation valves do not fully meet the guidance of Reference 6 for closed system boundary valves in that they are not powered from a Class 1E power source. However, based upon a risk determination, operating .these valves as closed system boundary valves is not risk significant. Ttlese valves also form the end of the Seismic Category I boundary between the systems. These process sampling solenoid operated isolation valves are normally closed and are required to be leak rate tested in accordance with the Leakage R.ate Test Program as part of the closed system for the H2O2 Analyzer system.

These valves are "closed system boundary valves" and may be opened under administrative control, as delineated in Technical Requirements Manual (TRM) Bases 3.6.4. Opening of these valv:es to permit testing of PASS in Modes 1, 2, and 3 is permitted in accordance with TRO 3.6.4.

Each H2O2 Analyzer Sampling line penetrating primary containment has two PCIVs, located just outside primary containment. While two PCIVs are provided on each line, a single active failure of a relay in the control circuitry for these valves could result in both valves failing to close or, failing to remain closed. Furthermore, a single failure (a hot short in the common raceway to all the valves) could simultaneously affect all of the PCIVs within a H2O2 Analyzer dMsion. Therefore, the containment isolation barriers for these penetrations consist of two PCIVs and a closed system. For situations where one or both PCIVs are inoperable, the ACTIONS to be taken are similar to the ACTIONS for a single PCIV backed by a closed system.

The drywall vent and purge lines are 24 inches in diameter; the suppression chamber vent and purge lines are 18 inches in diameter.

The containment purge valves are normally main4iined closed in MODES 1, 2, and 3 to ensure the primary containment boundary is maintained. The outboard isolation valves have 2. inch bypass lines around them for use during normal reactor operation.

The RHR Shutdown Cooling return line containment penetrations {X-13A(B)}are provided with a normally closed gate valve {HV-251 F015A(B)}

and a normally open globe valve {HV-251 F017A(B)} outside containment and a testable check valve {HV-251 F0S0A(B)} with a normally closed parallel air operated globe valve {HV-251F122A(B) } inside containment The gate valve is manually opened and automatically isolates upon a containment isolation signal from the Nuclear Steam Supply Shutoff System or RPV low level 3 when the RHR System is operated in the Shutdown Cooling Mode only. The LPCI subsystem is an operational mode of the RHR System and uses the same injection lines to the RPV as the Shutdown Cooling Mode .

• SUSQUEHANNA - UNIT 2 3.6-15a

Rev. 19 PCIVs B 3.6.1.3 BASES BACKGROUN D The design of these containment penetrations is unique in that some (continued) valves are containment isolation valves while others perfom1 the function of pressure isolation valves. In order to meet the 10 CFR 50 Appendix J leakage testing requirements, the closed system outside containment is the only barriers tested in accordance with the Leakage Rate Test Program. HV-251 F015A(B) are not required to be Appendix J leak rate tested since the Appendix J testing exemption requirements are met.

Since these containment penetrations {X-13A and X-138} include a containment isolation valve outside containment and a closed system outside containment that meets the requirements of USNRC Standard Review Plan 6.2.4 (September 1975), paragraph I1.3.e, the containment isolation provisions for these penetrations provide an acceptable alternative to the explicit requirements of 10 CFR 50, Appendix A, GDC 55.

Containment penetrations X-13A(B) are also high/low pressure system interfaces. In order to meet the requirements to have two (2) isolation valves between the high pressure and low pressure systems, the HV-251 F050A(B), HV-251F122A (B), 251130, and HV-251 F015A(B) valves are used to meet this requirement and are tested in accordance with the pressure test program .

APPLICABLE The PCIVs LCO was derived from the assumptions related to minimizing SAFETY the loss of reactor coolant inventory, and establishing the primary ANALYSES containment boundary during major accidents. As part of the primary containment boundary, PCIV OPERABILITY supports leak tightness of primary containment. Therefore, the safety analysis of any event requiring isolation of primary containment is applicable to this LCO.

The DBAs that result in a release of radioactive material within primary containment are a LOCA and a main steam line break (MSLB). In the analysis for each of these accidents, it is assumed that PCIVs are either closed or close within the required isolation times following event initiation. This ensures that potential paths to the environment through PCIVs (including primary containment purge valves) and secondary containment bypass valves that are not PCIVs are minimized. The closure time of the main steam isolation valves (MSIVs) for a MSLB outside primary containment is a significant variable from a radiological standpoint. The MSIVs are required to close within 3 to 5 seconds since the 5 second closure time is assumed in the analysis. The safety analyses assume that the purge valves were closed at event initiation.

LikewiSe, it is assumed that the primary containment is isolated such that release of fission products to the environment is controlled.

SUSQUEHAN NA - UNIT 2 3.6-15b

Rev. 19 PCIVs B 3.6.1.3 BASES APPLICAB LE The OBA analysis assumes that within the required isolation time SAFETY leakage is terminated, except for the maximum allowable leakage rate, ANALYSES La.

(continued)

The single failure criterion required to be imposed in the conduct of unit safety analyses was considered in the original design of the primary containment purge valves. Two valves in series on each purge line provide assurance that both the supply and exhaust lines could be isolated even if a single failure occurred.

The primary containment purge valves may be unable to close in the environment following a LOCA. Therefore, each of the purge valves is required to remain closed during MODES 1, 2, and 3 except as permitted under the Note of SR 3.6.1.3.1. In this case, the single failure criterion remains applicable to the primary containment purge valve due to failure in the control circuit associated with each valve. The primary containment purge valve design precludes a single failure from compromising the primary containment boundary as long as the system is operated in accordance with this LCO.

Both H2O2 Analyzer PCIVs may not be able to clo$e given a single failure in the control circuitry of the valves. The single failure is caused by a "hot short" in the cables/raceway to the PCIVs that causes both PCIVs for a given penetration to remain open or to open when required to be closed. This failure is required to be considered in accordance with IEEE-279 as discussed in FSAR Section 7.3.2a. However, the single failure criterion for containment isolation of the H2O2 Analyzer penetrations is satisfied by virtue of the combination of the associated PCIVs and the closed system formed by the H2O2 Analyzer piping system as discussed in the BACKGRO UND section above.

The closed system boundary between PASS and the H2O2 Analyzer system ends at the process sampling solenoid operated isolation valves between the systems (SV-22361, SV-22365, SV-22366, SV-22368, and SV-22369). The closed system is not fully qualified to the guidance of Reference 6 in that the closed system boundary valves between the H2O2 system and PASS are not powered from a Class 1E power source.

However, based upon a risk determination, the use of these valves is considered to have no risk significance. This exemption to the requirement of Refere.nce 6 for the closed system boundary is documented in License Amendmen t No. 170.

PCIVs satisfy Criterion 3 of the NRC Policy Statement. (Ref. 2)

• SUSQUEH ANNA - UNIT 2 3.6-16

Rev. 19

• • BASES LCO PCIVs B 3.6.1.3 PCIVs form a part of the primary containment boundary, or in the case of SCBL valves limit leakage from the primary containment. The PCIV -

safety function is related to minimizing the loss of reactor coolant inventory and establishing the primary containment boundary during a OBA.

The power operated, automatic isolation valves are required to have isolation times within limits and actuate on an automatic isolation signal.

The valves covered by this LCO are listed in Table B 3.6.1.3-1 and Table B 3.6.1.3-2.

The normally closed PCIVs, including secondary containment bypass valves listed in Table B 3.6.1.3-2 tnat are not PCIVs are considered OPERABLE when manual valves are closed or open in accordance with appropriate administrative controls, automatic valves are in their closed position, blind flanges are in place, and closed systems are intact. These passive isolation valves and devices are those .listed in Table B 3.6.1.3-1.

Leak rate testing of the secondary containment bypass valves listed in Table 3.6.1.3-2 is permitted in Modes 1, 2 & 3 as described in the Primary

• Containment Leakage Rate Testing Program .

Purge valves with resilient seals, secondary containment bypass valves, including secondary containment bypass valves listed in Table B 3.6.1.3-2 that are not PCIVs, MS IVs, and hydrostatically tested valves must meet additional leakage rate requirements. Other PCIV leakage rates are addressed by LCO 3.6.1.1, "Primary Containment, as Type B or C testing.

This LCO provides assurance that the PCIVs will perform their designed safety functions to minimize .the loss of reactor coolant inventory and establish the primary containment boundary during accidents.

APPLICABILI TY In MODES 1, 2, and 3, a OBA could cause a ~elease of radioactive material to primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, PCIVs are not required to be OPERABLE and the primary containment purge valves are not required to be closed in MODES 4 and 5.

SUSQUEHAN NA - UNIT 2 3.6-1.7

Rev. 19 PCIVs B 3.6.1.3 BASES ACTIONS The ACTIONS are modified by a Note allowing penetration flow path(s) to be unisolated intem,ittently under administrative controls. The$e controls consist of stationing a dedicated operator at the controls of the valve, who is .in continuous communication with the control room. In this way, the penetration can be rapidly isolated when a need for primary containment isolation is indicated.

A second Note has been added to provide clarification that, for the purpose of this LCO, separate Condition entry is allowed for each penetration flow path. This is acceptable, since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable PCIV. Complying with the Required Actions may allow for continued operation, and subsequent inoperable PCIVs are governed by subsequent Condition entry and application of associated Required Actions.

The ACTIONS are modified by Notes 3 and 4. Note 3 ensures that appropriate remedial actions are taken, if necessary, if the affected systern(s) are rendered inoperable by an inoperable PCIV (e.g., an Emergency Core Cooling System subsystem is inoperable due to a failed open test return valve). Note 4 ensures appropriate remedial actions are taken when the primary containment leakage limits are exceeded.

Pursuant to LCO 3.0.6, these actions are not required even when the associated LCO is not met. Therefore, Notes 3 and 4 are added to require the proper actions be taken.

A.1 and A.2 Wrth one or more penetration flow paths with one PCIV inoperable except for purge valve leakage not within limit, the affected penetration flow paths must be isolated. The method of isolation must Include the use of at least one isolation barrier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a closed and de-activated automatic valve, a closed manual valve, a blind flange, and a check valve with flow through the valve secured. For a penetration isolated in accordance with Required Action A.1, the device used to isolate the penetration should be the closest available valve to the primary containment. The Required Action must be completed within the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Completion llme (8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> for main steam lines). The Completion Time of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> is reasonable considering the time required to isolate the penetration and the relative importance of supporting primary containment OPERABILITY during MODES 1, 2, and 3. For main steam lines, an 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> Completion Time is allowed. The Completion Time of 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> for the main steam lines allows a period of time to restore the MS IVs to OPERABLE status given the fact that MSIV closure will result in isolation of the main steam line(s) and a potential for plant shutdown .

SUSQUEH ANNA - UNIT 2 3.6-18

Rev. 19 PCIVs B 3.6.1.3 BASES ACTIONS A. t and A.2 (continued)

(continued)

For affected penetrations that have been isolated in accordance with Required Action A.1, the affected penetration flow path(s) must be verified to be isolated on a periodic basis. This is necessary to ensure that primary containment penetrations required to .be isolated following an accident, and no longer capable of beihg automatically isolated, will be in the isolation position should an event occur. This Required Action does not require any testing or device manipulation. Rather, it involves verification that those devices outside containment and capable of potentially being mispositioned are in the correct position. The Completion Time of "once per 31 days for isolation devices outside primary containment" is appropriate because the devices are operated under administrative controls and the probability of their misalignment is low. For the devices inside primary containment, the time period specified "prior to entering MODE 2 or 3 from MODE 4, if primary containment was de-inerted while in MODE 4, if not performed within the previous 92 days" is based on engineering judgment and is considered reasonable in view of the inaccessibility of the devices and other administrative controls ensuring that device misalignment is an unlikely possibility .

Condition A is modified by a Note indicating that this Condition is only applicable to those penetration flow paths with two PCIVs except for the H2O2 Analyzer penetrations. For penetration flow paths with one PCIV, Condition C provides the appropriate Required Actions. For the H2O2 Analyzer penetrations, Condition D provides the appropriate Required Actions.

Required Action A.2 is modified by a Note that applies to isolation devices located in high radiation areas, and allows them to be verified by use of administrative means. Allowing verification by administrative means is considered acceptable, since access to these areas is typically restricted. Therefore, the probability of misalignment of these devices, once they have been verified to be in the proper position, is low.

B.1 Wrth one or more penetration flow paths with two PCIVs inoperable except for purge valve leakage not within limit, either the inoperable PCIVs must be restored to OPERABLE status or the affected penetration flow path must be isolated Within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure. Isolation SUSQUEHAN NA - UNIT 2 3.6-19

Rev. 19 PCIVs B 3.6.1.3 BASES ACTIONS B.1 (continued)

(continued) baniers that meet this criterion are a closed and de-activate d automatic valve, a closed manual valve, and a blind flange. The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Completion Time is consistent with the ACTIONS of LCO 3.6.1.1.

Condition B is modified by a Note indicating this Condition is only applicable to penetration flow paths with two PCIVs except for the H2O2 Analyzer penetrations. For penetration flow paths with one PCIV, Condition C provides the appropriate Required Actions. For the H2O2 Analyzer penetrations, Condition D provides the appropriate Required Actions.

C.1 and C.2 Wrth one or more penetration flow paths with one PCIV inoperable, the inoperable valve must be restored to OPERABLE status or the affected penetration flow path must be isolated. The method *of isolation must include the use of at least one isolation banier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a closed and de-activate d automatic valve, a closed manual valve, and a blind flange. A check-valve may not be used to isolate the affected penetration. Required Action C.1 must be completed within the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time. The.Compl etion Time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> is reasonable considering the relative stability of the closed system (hence, reliability) to act as a penetration isolation boundary and the relative importance of supporting primary containmen t OPERABIL ITY during MODES 1, 2, and 3. The closed system must meet the requiremen ts of Reference 6. For conditions where the PCIV and the closed system are inoperable, the Required Actions of TRO 3.6.4, Condition B apply. For the Excess Flow Check Valves (EFCV), the Completion Time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is reasonable considering the instrument and the small pipe diameter of penetration (hence, reliability) to act as a penetration isolation boundary and the small pipe diameter of the affected penetrations. In the event the affected penetration flow path is isolated in accordance with Required Action C.1, the affected penetration must be vertfied to be isolated on a periodic basis. This is necessary to ensure that primary containmen t penetration s required to be isolated following an accident are isolated. The Completion Time of once per 31 days for verifying each affected penetration is isolated is appropriate because the valves are operated under administrat ive controls and the probability of their misalignme nt is low.

• SUSQUEH ANNA - UNIT 2 3.6-20

Rev. 19 PCIVs B 3.6.1.3 BASES ACTIONS C.1 and C.2 (continued)

(continued)

Condition C is modified by a Note indicating that this Condition is only applicable to penetration flow paths with only one PCIV. For penetration flow paths with two PCIVs and the H2O2 Analyzer penetration, Conditions A, B, and D provide the appropriate Required Actions.

Required Action C.2 is modified by a Note that applies to valves and blind flanges located in high radiation areas and allows them to be verified by use of administrative means. Allowing verification by administrative means is considered acceptable, since access to these areas is typically restricted. Therefore, the probability of misalignme nt of these valves, once they have been verified to be in the proper position, is low.

D.1 and D.2 With one or more H2O2 Analyzer penetrations with one or both PCIVs inoperable, the inoperable valve(s) must be restored to OPERABLE status or the affected penetration flow path must be isolated. The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a closed and de-activate d automatic valve, a closed manual valve, and a blind flange. A check valve may not be used to isolate the affected penetration. Required Action D.1 must be completed within the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time. The Completion Time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> is reasonable considering the unique design of the H~2 Analyzer penetrations. The containmen t isolation barriers for these penetrations consist of two PC IVs and a closed system. In addition, the Completion Time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Is reasonable considering the relative stability of the closed system (hence, reliability)

• to act as a penetration isolation boundary and the relative importance of supporting primary containment OPERABILITY_ during MODES 1, 2, and 3. In the event the affected penetration flow path is isolated in accordance with Required Action D.1, the affected penetration must be verified to be isolated on a periodic basis. This is necessary to ensure that primary containment penetrations required to be isolated following an accident are isolated. The Completion Time of once per 31 days for verifying each affected penetration is isolated is appropriate because the valves are operated under administrative controls and the probability of their misalignment is low.

• SUSQUEH ANNA - UNIT 2 3.6-21

Rev. 19 PCIVs B 3.6.1.3 BASES ACTIONS D.1 and D.2 (continued)

(continued)

When an H202 Analyzer penetration PCIV is to be closed and deactivated in accordance with Condition D, this must be accomplished by pulling the fuse for the power supply, and eith~r deterrninating the power cables at the solenoid valve, or jumpering of the power side of the solenoid to ground.

• The OPERABIL ITY requirements for the closed system are discussed in Technical Requirements Manual (TRM) Bases 3.6.4. In the event that either one or both of the PC IVs and the closed system are inoperable, the Required Actions of TRO 3.6.4, Condition B apply.

Condition D is modified by a Note indicating that this Condition is only applicable to the H202 Analyzer penetrations.

Wrth the secondary containment bypass leakage rate not within limit, the assumptions of the safety analysis may not be met. Therefore, the

• • leakage must be restored to within limit within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. Restoration can be accomplished by isolating the penetration that caused the limit to be exceeded by use of one closed and de-activate d automatic valve, closed manual valve, or blind flange. When a penetration is isolated, the leakage rate for the isolated penetration is assumed to be the actual pathway leakage through the isolation device. If two isolation devices are used to isolate the penetration, the leakage rate is assumed to be the lesser actual pathway leakage of the two devices. The 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Completion Time is reasonable considering the time required to restore the leakage by isolating the penetration and the relative importance of secondary containmen t bypass leakage to the overall containmen t function.

F.t In the event one or more containment purge valves are not within the purge valve leakage limits, purge valve leakage must be restored to within limits. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Completion Time is reasonable, considering that one containment purge valve remains closed, except as controlled by SR 3.6.1.3.1 sd that a gross breach of containmen t does not exist.

SUSQUEH ANNA - UNIT 2 3.6-22

Rev. 19 PCIVs B 3.6.1.3 BASES ACTIONS G.1 and G.2 (continued)

If any Required Action and associated Completion Time cannot be met, the plant must be brought to a MODE in which the LCO does not apply.

To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and to MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLAN CE SR 3.6.1.3.1 REQUIREMEN TS This SR ensures that the primary containment purge valves are closed as required or, if open, open for an allowable reason. If a purge valve is open in violation of this SR, the valve is considered inoperable. If the inoperable valve is not otherwise known to have excessive leakage when closed, it is not considered to have leakage outside*of limits. The SR is modified by a Note stating that the SR is not required to be met when the purge valves are open for the stated reasons. The Note

• • states that these valves may be opened for inerting, de-inerting, pressure control, ALARA or air quality considerations for personnel entry, or Surveillances that require the valves to be open. The vent and purge valves are capable of closing in the environment following a LOCA. Therefore, these valves are allowed to be open for limited periods of time. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.6.1.3.2 This SR verifies that each primary containment isolation manual valve and blind flange that is located outside primary containment and not locked, sealed, or otherwise secured and is required to be closed during accident conditions is closed. The SR helps to ensure that post accident leakage of radioactive fluids or gases outside the primary containment boundary is within design limits.

This SR does not require any testing or valve manipulation. Rather, it involves verification that those PCIVs outside primary containment, and capable of being mispositioned, are. In the correct position. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

Two Notes have been added to this SR. The first Note allows valves and blind flanges located in high radiation areas to be verified by use of administrative controls. Allowfng vertfication by administrative controls is considered acceptable since access to these areas is typically SUSQUEHAN NA - UNIT 2 3.6-23

Rev. 19 PCIVs B 3.6.1.3 BASES SURVEILLAN CE SR 3.6.1.3.2 (continued)

REQUIREMEN TS (coritinued) restricted during MODES 1, 2, and 3 for ALARA reasons. Therefore, the probability of misalignment of these PCIVs, once they have been verified to be in the proper position, is low. -A second Note has been included to clarify that PCIVs that are open under administrative controls are not required to meet the SR during the time that the PCIVs are open. This SR does not apply to valves that are locked, sealed, or otherwise secured in the closed position, since these were verified to be in the correct position upon locking, sealing, or securing.

SR 3.6.1.3.3 This SR verifies that each primary containment manual isolation valve and blind flange that is located inside primary containment and not locked, sealed, or otherwise secured and is req~ired to be closed during accident conditions is closed. The SR helps to ensure that post accident leakage of radioactive fluids or gases outside the primary containment boundary is within design limits. For PCIVs inside primary containment, the Frequency defined as "prior to entering MODE 2 or 3 from MODE 4 if primary containment was de-inerted while in MODE 4, if not perfonned within the previous 92 days" is appropriate since these PCIVs are operated under administrative controls and the probability of their misalignment is low. This SR does not apply to valves that are locked, sealed, or otherwise secured in the closed position, since these were verified to be in the correct position upon locking, sealing, or securing.

Two Notes have been added to this SR. The first Note allows valves and blind flanges located In high radiation areas to be verffied by use of administrative controls. Allowing verification by administrative controls is considered acceptable since the primary containment is inerted and access to these areas is typically restricted during MODES 1, 2, and 3 for ALARA reasons. Therefore, the probability of misalignment of these PCIVs, once they have been verified to be in their proper position, is low.

A second Note has been included to clarify that PCIVs that are open under administrative controls are not required to meet the SR during the time that the PCIVs are open.

SR 3.6.1.3.4 The traversing incore probe (TIP) shear isolation valves are actuated by explosive charges. Surveillance of explosive charge continuity provides assurance that TIP valves will actuate when required. Other administrative controls, such as those that limit the shelf life of the explosive charges, must be followed. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program .

• • SUSQUEHAN NA - UNIT 2 3.6-24

Rev. 19 PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.5 REQUIREME NTS (continued) Verifying the isolation time of each power operated and each automatic PCIV is within limits is required to demonstrate OPERABILITY. MSIVs may be excluded from this SR since MSIV full closure isolation time is demonstrated by SR 3.6.1.3. 7. The isolation time test ensures that the valve will isolate in a time period less than or equal to that assumed In the Final Safety Analyses. Report. The isolation time and Frequency of this SR are in accordance with the requirements of the lnservice Testing Program.

SR 3.6.1.3.6 For primary containment purge valves with resilient seals, the Appendix J Leakage Rate Test Interval is sufficient. The acceptance criteria for these valves is defined in the Primary Containment Leakage Rate Testing Program, 5.5.12.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program .

• SR 3.6.1.3.7 Verifying that the isolation time of each MSIV is within the specified limits is required to demonstrate OPERABILITY. The isolation time test ensures that the MSIV will isolate in a time period that does not exceed the times assumed in the OBA analyses. This ensures that the calculated radiological consequences of these events remain within regulatory limits.

The Frequency of this SR is in accordance with the requirements of the lnservice Testing Program.

SR 3.6.1.3.8 Automatic PCIVs close on a primary containment isolation signal to prevent leakage of radioactive material from primary containment following a OBA. This SR ensures *that each automatic PCIV will actuate to its isolation position on a primary containment isolation signal. 'fhe LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.6.1.5 overlaps this SR to provide complete testing of the safety function. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SUSQUEHAN NA - UNIT 2 3.6-25

Rev. 19 PCIVs B 3.6.1.3 BASES SURVEILL ANCE SR 3.6.1.3.9 REQUIREM ENTS (continued) This SR requires a demonstration that a representat ive sample of reactor instrumentation line excess flow check valves (EFCV) are OPERABLE by verifying that the valve actuates to check flow on a simulated instrument line break. As defined in FSAR Section 6.2.4.3.5 (Reference 4), the conditions under which an EFCV will isolate, simulated instrument line breaks are at flow rates, which develop a differential pressure of between 3 psid and 10 psid. This SR provides assurance that the instrumentation line EFCVs will perfonn its design function to check flow. No specific valve leakage limits are specified because no specific leakage limits are defined in the FSAR. The Surveillance Frequency is controlled under the Surveillanc e Frequency Control Program. The representative sample consists of an approximate equal number of EFCVs such that each EFOV is tested at least once every 1O years (nominaQ. The nominal 1O year .interval is based on other performance-based testing programs, such as lnservice Testing (snubbers) and Option B to 10 CFR 50, Appendix J. In addition, the EFCVs in the sample are representative of the various plant configurations, models, sizes and operating environmen ts. This

• • ensures that any potential common problem with a specific type or application of EFCV is detected at the earliest possible time. EFCV failures will be evaluated to detennine if additional testing in that test interval is warranted to ensure overall rellability and that failures to isolate are very infrequent Therefore, testing of a representative sample was concluded to be acceptable from a reliability standpoint (Reference 7).

SR 3.6.1.3.10 The TIP shear isolation valves are actuated by explosive charges. An in place functional test is not possible with this design. The explosive squib is removed and tested to provide assurance that the valves will actuate when required. The replacement charge for the explosive squib shall be from the same manufactured batch as the one fired or from another batch that has been certified by having one of the batch successfully fired. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program .

• SUSQUEH ANNA - UNIT 2 3.6-26

Rev. 19 PCIVs B 3.6.1.3 BASES SURVEILLAN CE SR 3.6.1.3.11 REQUIREMEN TS (continued) This SR ensures that the leakage rate of secondary containment bypass leakage paths is less than the specified leakage rate. This provides assurance that the assumptions in the radiological evaluations of Reference 4 are met The secondary containment leakage pathways and Frequency are defined by the Primary Containment Leakage Rate Testing Program. This SR simply imposes additional acceptance criteria.

SR 3.6.1.3.12 The analyses in References 1 and 4 are based on the specified leakage rate. Leakage through each MSIV must be ~ 100 scfh for anyone MSIV and~ 300 scfh for total leakage through the MSIVs combined with the Main Steam Line Drain Isolation Valve, HPCI Steam Supply Isolation Valve and the RCIC Steam Supply Isolation Valve. The MSIVs can be tested at either~ pt (24.3 psig) or Pa (48.6 psig). Main steam Line Drain Isolation, HPCI and RCIC steam Supply Line Isolation Valves, ate tested at Pa (48.6 psig). The Frequency is required by the Primary

• Containment Leakage Rate Testing Program .

SR 3.6.1.3.13 Surveillance of hydrostatically tested lines provides assurance that the calculation assumptions of Reference 2 are met. The acceptance criteria for the combined leakage of all hydrostatlcally tested lines is 3.3 gpm when tested at 1.1 Pa,. (53.46 psig). The combined leakage rates must be demonstrated in accordance with the leakage rate test Frequency required by the Primary Containment Leakage Testing Program.

As noted in Table B 3.6.1.3-1, PCIVs associated with this SR are not Type C tested. Containment bypass leakage is prevented since the line terminates below the minimum water level in the suppression chamber.

These valves are tested in accordance with the 1ST Program.

Therefore, these valves leakage is not included as containment leakage.

SUSQUEHAN NA - UNIT 2 3.6-27

Rev. 19 PCIVs B 3.6.1.3 BASES REFERENCES 1. FSAR, Chapter 15.

2. Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 39132).

3. 10 CFR 50, Appendix J, Option B.

4. FSAR, Section 6.2.

5. NEDO-30851-P-A, '1"echnical Specification Improvement Analyses for BWR Reactor Protection System," March 1988.

6. Standard Review Plan 6.2.4, Rev. 1, September 1975.

7. NED0-32977-A, "Excess Flow Check Valve Testing Relaxation," June 2000 .

• • SUSQUEHANNA - UNIT 2 3.6-28

Rev. 19 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 Primary Containment Isolation Valve (Paae 1 of 1m Isolation Signal LCO 3.3.6.1 Function No.

Plant System Valve Number Valve Description Type of Valve (Maximum Isolation llme (Seconds))

Containment 2-57-199 (d) ILRT Manual NIA IAfmospheric 12-57-200 (d) ILRT Manual NIA Control HV-25703 Containment Purae !Automatic Valve 2.b 2 d 2.e (15)

HV-25704 Containment Purae !Automatic Valve 2.b 2.d 2.e (15)

HV-25705 Containment Purae !Automatic Valve 2.b 2.d 2.e (15)

HV-25711 Containment Purge !Automatic Valve 2.b 2.d 2.e (15)

HV-25713 Containment Purne IAutomabc Valve 2 b, 2.d 2.e {15)

HV-25714 Containment Purae Automatic Valve 12.b 2.d 2.e (15)

HV-25721 Containment Purge !Automatic Valve 2.b, 2.d, 2.e (15)

HV-25722 Containment Pume IAutomabc Valve 2 b 2.d 2.e {15)

HV-25723 Containment Purge )\utomatic Valve 2.b 2.d 2.e (15)

HV-25724 Containment Pul'Qe )'\Utamatlc Valve 2.b 2.d, 2.e {15)

HV-25725 Containment Purae Automabc Valve 2 b 2.d 2.e (15)

HV-25766 (a) Succresston Pool Cleanup !Automatic Valve 2.b 2.d {35)

HV-25768 (a) Succression Pool Cleanup ~utomatlc Valve 2.b 2.d (30)

HV-257113 (d) Hardened Containment Vent Power Operated NIA

'Air)

HV-257114 (d) Hardened Containment Vent Power Operated N/A

'Air)

SV-257100-A Containment Radiation Detecbon !Automatic Valve 2.b, 2 d, 2.f SVst SV-257100 B Containment Radiation Detection Automatic Valve 2.b, 2.d, 2.f Syst SV-257101 A Containment Radiation Detecbon Automatic Valve 12.b, 2.d, 2.f Syst SV-257101 B Containment Radlatlon Detection Automatic Valve 2.b, 2.d, 2.f Svst SV-257102A Containment Radiation Detection Automatic Valve 2.b, 2.d, 2.f SVst SV-257102 B Containment Radiation Detection Automatic Valve 12.b, 2.d, 2.f Svst SV-257103A Containment Radiation Detection Automatic Valve 2.b, 2.d, 2.f Svst SV_-257103 B Containment Radiation Detection Automatic Valve 2 b, 2.d, 2.f Svst SV-257104 Containment Radiation Detection Automatic Valve 2.b, 2.d, 2.f Svst SV-257105 Containment Radiation Detection Automatic Valve 2.b, 2.d, 2.f Svst SV-257106 Containment Radiation Detection Automatic Valve 2.b, 2.d, 2.f Syst SV-257107 Containment Radiation Detection Automatic Valve 2 b, 2.d, 2.f SVst SV-25734 A (e) Containment Atrnosohere Samele Automatic Valve 2.b 2.d SV-25734 B (e) Containment Atmosphere Sample Automatic Valve 2.b 2.d SV-25736 A (e) Contalnme11t Atmosphere Sample Automatic Valve 2.b 2d SV-25738 B (e) Containment Atmosphere Sample Automatic Valve 2.b 2.d SV-25737 Nltroaen Makeuc Automatic Valve 2.b 2.d 2 e

• SUSQUEHAN NA - UNIT 2 3.6-29

Rev. 19 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 Primary Containment Isolation Valve (Paae 2 of 1O)

Isolation Signal LCO 3.3.6.1 Function No.

Plant System Valve Number Valve Description Type of Valve (Maximum Isolation Tlme (Seconds))

Containment SV-25738 Nitrogen Makeup !Automatic Valve 2.b, 2.d, 2.e

!Atmospheric SV-25740 A (e) Containment Atmosphere Sample !Automatic Valve 2.b, 2.d Control ISV-25740 B (e) Contamment Atmosphere Sample !Automatic Valve 2.b, 2.d (continued) ISV-25742 A (e) Containment Atmosphere Sample IAutomatlc Valve 12.b, 2.d SV-25742 B (e) Containment Atmosphere Sample IAutomabc Valve 2.b, 2.d SV-25750 A (e) !Containment Atmosphere Sample !Automatic Valve 12.b, 2.d SV-25750 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-25752 A (e) Containment Atmosphere Sample !Automatic Valve 12.b, 2.d SV-25752 B (e) !Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-25767 Nitrogen Makeup Automatic Valve 2.b, 2.d, 2.e SV-25774 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-25774 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2 d SV-25776 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-25776 B (e) !Containment Atmosphere. Sample Automatic Valve 2.b, 2.d SV-25780 A (e) !Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-25780 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-25782 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-25782 B (e)

• Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-25789 Nitrogen Makeup Automatic Valve 2.b, 2.d, 2.e Containment 2-26-072 (d) :Containment Instrument Gas Manual Check NIA Instrument Gas 2-26-074 (d) Containment Instrument Gas Manual Check NIA 2-26-152 (d) Containment Instrument Gas Manual Check NIA 2-26-154 (d) Contamment Instrument Gas Manual Check NIA 2-26-164 (d) Containment Instrument Gas Manual Check NIA HV-22603 Containment Instrument Gas Automatic Valve 2.c, 2.d (20)

SV-22605 Containment Instrument Gas Automatic Valve 2.c, 2.d SV-22651 Containment Instrument Gas !Automatic Valve 2.c, 2.d SV-22654A Containment Instrument Gas Power Operated NIA ISV-22654 B Containment Instrument Gas Power Operated NIA SV-22661 Containment Instrument Gas Automatic Valve 2.b, 2.d SV-22671 Containment Instrument Gas !Automatic Valve 2.b, 2.d Core Spray HV-252F001 A (b)(c) CS Suction Power Operated NIA HV-252F001 B (bXc) CS Suction Power Operated NIA HV-252F005 A CS Injection Power Operated NIA HV-252F005 B CS Injection Power Operated NIA IA!r Operated Check NIA HV-252F006 A CS lnj8Ction !Valve IA!r Operated Check HV-252F006 B CS Injection NIA

!Valve HV-252F015 A (b)(c) CS Test !Automatic Valve 2.c, 2.d (80)

HV-252F015 B (b)(c) CS Test !Automatic Valve 2.c, 2.d (80)

HV-252F031 A (b)(c) iCS Minimum Recirculatlon Flow Power Operated NIA HV-252F031 B (b)(c) CS Minimum Recirculation Flow Power Operated NIA SUSQUEH ANNA - UNIT 2 3.6-30

Rev. 19 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 Primary Containment Isolation Valve (Paae 3 of 1O}

Isolation Signal LCO 3.3.6.1 Function No.

PlantSyatem Valve Number Valve Description Type of Valve (Maximum Isolation Tlme (Seconds))

Core Spray HV-252F037 A CS Injection Power Operated NIA (contmued) 'Afr)

HV-252F037 B CS lnJectlon Power Operated NIA 1Air)

XV-252F018 A Core Spray Excess FIOIN Check NIA Valve XV-252F018 B Gore Spray Excess Flow Check NIA Valve Demln Water 2-41-017 (d) Demlnerallzed Water Manual NIA 2-41-018 (dl Deminerallzed Water Manual NIA HPCI 2-55-038 (di HPCI lruectJon Manual NIA 255F046 (b) (c) (d) HPCI Minimum Rearculabon Flow Manual Check NIA l255F049 (a) (d) HPCI Manual Check NIA HV-255F002 HPCI Steam Supply !Automatic Valve ~ a, 3.b, 3.c, 3.e, 3.f, 3.a. (50)

HV-255F003 HPCI Steam Supply . IAutomatlc Valve J a, 3.b, 3 c, 3.e, 3.f, 13.g, (50)

HV-255F006 HPCI lnlectlon Power Operated NIA HV-255F012 (b) (c) HPCI Minimum Recirculation Flow Power Ooerated NIA HV-255F042 (b) (c) HPCI Suction !Automatic Valve 13.a, 3.b, 3.c, 3.e, 3.f, 3.o. (115)

HV-255F066 (a) HPCI Turbine ExhatJSt Power Ooerated N/A HV-255F075 HPCI Vacuum Breaker !Automatic Valve i3.b 3.d (15)

HV-255F079 HPCI Vacuum Breaker IAutomatlc Valve 3.b 3.d (15)

HV-255F100 HPCI Steam Supply !Automatic Valve 3.a, 3 b, 3.c, 3.e, 3.f, G.a. (6)

IXV-255F024 A HPCI Excess Flow Check NIA

!Valve IXV-255F024 B HPCI Excess Flow Check NIA

!Valve IXV-255F024 C HPCI Excess Flow Check NIA

!Valve

x\/-255F024 D HPCI Excess Flow Check NIA Valve Liquid Raclwaste HV-26108A1 Liquid Radwaste !Automatic Valve 2.b, 2.d (15)

Collection HV-26108A2 UqulCi Radwaste !Automatic Valve 2.b 2.d (15)

HV-26116A1 Uauid Radwaste Automatic Valve 2.b 2.d (15)

HV-26116A2 IUauld Radwaste IAutomatic Valve 12 b 2.d (15)

Nuclear Boiler i241F010A (d) Feedwater Manual Check NIA 241F010 B /dl Feedwater Manual Check NIA l241F039 A fd) Feedwater Isolation Valve Manual Check NIA l241F039 B (d) Feedwater Isolation Valve Manual Check N/A 1241818A (d) Feedwater Isolation Valve Manual Check NIA 1241818 B (d) Feeclwater Isolation Valve Manual Check NIA

• SUSQUEHAN NA - UNIT 2 3.6-31

Rev. 19 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 Primary Containment Isolation Valvo (Paaa 4 of 1O)

Isolation Signal LCO 3.3.6.1 Function No.

Plant System Valve Number Valve Description Type of Valve (Pillaxlmum Isolation Time (Seconds))

Nuclear Boiler HV-241F016 MSL Draln Automatic Valve 1.a, 1.b, 1.c, 1.d, 1.e (continued) '10)

HV-241F019 MSL Drain Automatic Valve 1.a, 1.b, 1.c, 1.d, 1.e

'15)

HV-241 F022 A MSN Automatic Valve 1.a, 1 b, 1.c, 1 d, 1.e (5)

HV-241F022 B MSN Automatic Valve 1.a, 1 b, 1 c, 1.d, 1.e 1(5)

HV-241F022 C MSN Automatic Valve 1.a, 1.b, 1.c, 1.d, 1 e

'5)

HV-241 F022 D MSN Automatic Valve 1.a, 1.b, 1.t, 1.d, 1 e (5)

HV-241 F028 A MSN Automatic Valve 1.a, 1.b, 1 c, 1.d, 1.e 1(5)

HV-241 F028 B MSN Automatic Valve 1.a, 1 b, 1.c, 1.d, 1.e 1(5)

HV-241F028 C MSN Automatic Valve 1.a, 1.b, 1.c, 1.d, 1.e

'5)

HV-241F028 D MSN IAutomatJc Valve 1.a, 1.b, 1.c, 1.d, 1.e

'5)

N/A HV-241F032 A Feedwater Isolation Valve Power Operated Check Valves HV-241F032 B Feedwater Isolation Valve Power Operated NIA

!Check Valves XV-241F009 Nuclear Sotlar EFCV Excess Flow Check NIA

' !Valve XV-241F070 A Nuclear Boiler EFCV Excess Flow Check N/A

!Valve XV-241F070 B Nucl~ Boner EFCV Excess Flow Check NIA

!Valve XV-241F070 C Nuclear Boiler EFCV Excess Flow Check NIA

!Valve XV-241F070 D Nuclear Boller EFCV Excess Flow Check NIA

!Valve XV-241F071 A Nuclear Boiler EFCV Excess Flow Check NIA

!Valve XV-241F071 B Nuclear Boller EFCV Excess Flow Check NIA

!Valve XV-:M1F071 C Nuclear Boller EFCV Excess Flow Check NIA

!Valve XV-241 F071 D Nuclear Boner EFCV Excess Flow Check NIA

!Valve XV-241 F072 A Nuclear Boiler EFCV Excess Flow Check NIA Valve XV-241F072 B Nuclear Boiler EFCV Excess Flow Check NIA 1\/alve XV-241F072 C Nuclear Boiler EFCV Excess Flow Check NIA

!Valve XV-241F072 D Nuclear Boiler EFCV Excess Flow Check NIA

!Valve XV-241 F073 A Nuclear Boller EFCV Excess Flow Check NIA Valve

• SUSQUEH ANNA - UNIT 2 3.6-32

Rev. 19 PCIVs B 3.6.1.3 Table B 3.8.1.3-1 Prhnary Containment Isolation Valve (Pace 5 of 1Ol Isolation Signal LCO 3.3.6.1 Function No.

Plant System Valve Number Valve Description Type of Valve (Maximum Isolation Tlme (Seconds))

Nuclear Boller X:V-241 F073 B Nuclear Boiler EFCV Excess Flow Check NIA (continued) Valve XV-241F073 C Nuclear Boiler EFCV Excess Flow Check NIA Valve XV-241F073 D Nuclear Boiler EFCV Excess Flow Check NIA Valve Nuclear Boller XV-24201 !Nuclear Boller Vessel Instrument Excess Flow Check NIA Vessel Valve Instrumentation XV-24202 Nuclear Boiler Vessel Instrument Excess Flem Check NIA Valve XV-242F041 Nuclear Boller Vessel Instrument Excess Flow Check NIA

' Valve XV-242F043 A Nuclear Boller Vessel Instrument Excess Flow Check NIA Valve XV-242F043 B Nuclear Boller Vessel Instrument Excess Flow Check NIA Valve XV-242F045 A Nuclear Boller Vessel Instrument Excess Flow Check NIA Valve XV-242F045 B Nuclear Boller Vessel Instrument Excess Flow Check NIA Valve IXV-242F047 A Nuclear Boiler Vessel Instrument Excess Flow Check NIA Valve XV-242F047B Nuclear Boiler Vessel Instrument Excess Flow Check NIA Valve IXV-242F051 A Nuclear Boller Vessel Instrument Excess Flow Check NIA Valve XV-242F051 B Nuclear Boller Vessel Instrument Excess Flow Check NIA Valve IXV-242F051 C Nuclear Boller Vessel Instrument Excess Flow Check NIA Valve IXV-l42F051 D Nuclear Boiler Vessel Instrument Excess Flow Check NIA Valve IXV-242F053 A Nuclear Boller Vessel lnstrum~nt Excess Flcrw Check NIA Valve IXV-242F053 B Nuclear Boller Vessel Instrument Excess Flow Check NIA Valve IXV-242F053 C Nuclear Boiler Vessel Instrument Excess Flow Check NIA Valve IXV-242F053 D Nuclear Boller Vessel Instrument Excess Flow Check NIA Valve IXV-242F055 Nuclear Boiler Vessel Instrument Excess Flow Check NIA Valve IXV-242F057 Nuclear Boiler Vessel Instrument Excess Flow Check NIA Valve XV-242F059 A Nuclear Boiler Vessel Instrument Excess Flow Check NIA Valve IXV-242F059 B Nuclear Boiler Vessel Instrument Excess Flow Check NIA Valve  ;

• SUSQUEHAN NA - UNIT 2 3.6-33

Rev. 19 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 Primary Containment Isolation Valve CPaQe 6 of 10) lsolatlon Signal LCO 3.3.6.1 Function No.

Plant System Valve Number Valve Description Type of Valve (Maximum Isolation llme {Secondsll Nuclear Boiler XV-242F059 C Nuclear Boller Vessel Instrument Excess Flow Check NIA

!Vessel Valve Instrumentation IXV-242F059 D Nuclear Boller Vessel Instrument Excess Flow Check NIA (continued) Valve XV-242F059 E Nuclear Boller Vessel Instrument Excess Flow Check NIA Valve IXV-242F059 F Nuclear Boiler Vessel Instrument Excess Flow Check NIA Valve XV-242F059 G Nuclear Boller Vessel Instrument Excess Flow Check NIA Valve IXV-242F059 H Nuclear Boiler Vessel Instrument Excess Flow Check NIA

!Valve IXV-242F059 L Nuclear Boiler Vessel Instrument Excess Flow Check NIA Valve IXV-242F059 M Nuclear Boller Vessel lnstnlment Excess Flow Check NIA 1\/alve IXV-242F059 N Nuclear Boiler Vessel Instrument Excess Flow Check NIA

!Valve IXV-242F059 P Nuclear Boller Vessel Instrument Excess Flow Check NIA

!Valve XV-242F059 R Nuclear Boller Vessel Instrument Excess Flow Check NIA

!Valve IXV-242F059 s Nuclear Boller Vessel Instrument Excess Flow Check NIA

!Valve XV-242F059 T Nuclear Boiler Vessel Instrument Excess Flow Check NIA

!Valve XV-242F059 U Nuclear Boller Vessel Instrument Excess Flow Check NIA Valve XV-242F061 Nuclear Boiler Vessel Instrument Excess Flow Check NIA

!Valve RB Chilled Water HV-28781 A1 RB Chilled Water !Automatic Valve 12.c 2.d (40)

System HV-28781 A2 RB Chllled Water !Automatic Valve 12.c 2.d (40)

HV-28781 81 RB Chilled Water !Automatic Valve 12.c 2.d (40)

HV-28781 82 RB Chllled Water IAutomatic Valve 12.c 2.d (40)

HV-28782A1 RB Chilled Water Automatic Valve 12.c. 2 d (12)

HV-28782A2 RB Chilled Water !Automatic Valve 12.c 2.d (12)

HV-28782 81 1RB Chilled Water IAutomatlc Valve 12.c 2.d (12)

HV-28782 82 RB Chilled Water IAutomatJc Valve 12.c 2.d (12)

HV-28791 A1 RB Chined Water !Automatic Valve 2.b, 2.d (15)

HV-28791 A2 RB Chilled Water Automatic Valve 12.b 2.d (15)

HV-28791 81 RB Chilled Water IAutomatic Valve 12.b 2.d (15)

HV-28791 82 RB Chilled Water IAutomatlc Valve 2.b 2.d (15)

HV-28792A1 RB Chllled Water Automatic Valve 2.b 2.d (8)

HV-28792A2 RB Chilled Water IAutomatic Valve 12.b 2.d (8)

HV-28792 81 RB Chilled Water !Automatic Valve 2.b 2.d (8)

• SUSQUEHAN NA - UNIT 2 3.6--34

Rev. 19 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 Primary Containment Isolation Valve (PaQe 7 of 10)

Isolation Signal LCO 3.3.6.1 Function No.

Plant System Valve Number Valw Description Type of Valve (Maximum Isolation Time {Seconds))

RB Chilled Water HV-28792 B2 RB Chilled Water IAutomabc Valve 2.b, 2.d (8)

System icontlnued)

RBCCW HV-21313 RBCCW IAutomatlc Valve 2.c 2.d (30)

HV-21314 RBCCW Automatic Valve 2.c 2.d /30)

HV-21345 RBCCW !Automatic Valve 12.c, 2.d (30)

HV-21346 RBCCW !Automatic Valve 2.c 2.d /30)

RCIC 12-49--020 (d) RCIC lnlectlon Manual NIA l249F021 lb) (c) (d) RCIC Minimum Recirculation Flow Manual Check NIA l249F028 (a) fd) RCIC Vacuum Pump Dlscharoe Manual Check NIA 249F040 /a) (d) RCIC Turbine Exhaust Manual Check NIA FV-249F019 (b) (c) RCIC Minimum Reclrculatlon Flow Power Operated NIA HV-249F007 RCIC Steam Supply Automatic Valve f4.a, 4 b, 4.c, 4.e, 4.f, 14.a <20)

HV-249F008 RCIC Stewn Supply !Automatic Valve 14.a, 4.b, 4.c, 4.e, 4.f, f4.g (20)

HV-249F013 RCIC lnlection Power Operated NIA HV-249F031 fb) (c) RCIC Suction Power Operated NIA HV-249F059 (a) RCIC Turbine Exhaust Power Ooerated NIA HV-249F060 (al RCIC Vacuum Pump Dlschame Power Operated NIA HV-249F062 RCIC Vacuum Breaker Automatic Valve 14.b 4.d /1 m HV-249F084 RCIC Vacuum Breaker IAutomatlc Valve l-4.b 4.d 110)

HV-249F088 RCIC Steam Supply IAutomatic Valve 14.a, 4 b, 4.c, 4.e, 4 f, l4g(12)

IXV-249F044 A RCIC Excess Flow Chee!< NIA 1\/alve IXV-249F044 B RCIC Excess Flow Check NIA

!Valve IXV-249F044 C RCIC Excess Flow Check NIA

!Valve IXV-249F044 D RCIC Excess Flow Check NIA Valve Reactor i243F013 A (d) Recirculation Pump Seal Water Manual Check NIA Recirculation [243F013 B (d) Recirculation Pump Seal Water Manual Check NIA HV-243F019 Reactor Coolant Sample Automatic Valve !2-b (9)

HV-243F020 Reactor Coolant Sample IAutomabc Valve 2.b /2)

IXV-243F003 A Reactor Recirculation Excess Flow Check NIA Valve XV-243F003 B Reactor Reclrculabon Excess Flow Check NIA Valve XV-243F004 A Reactor Recirculation Excess Flow Check NIA

!Valve

XV-243F004 B Reactor Reclrculatlon Excess Flow Check NIA

!Valve

• • SUSQUEH ANNA - UNIT 2 3.6-35

Rev. 19 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 Primary Containment Isolation Valve (Paoe 8 of 1O)

Isolation Signal LCO 3.3.6.1 Function No.

Plant System Valve Number Valve Description Type or Valve (Maximum Isolation Time (Seconds))

Reactor XV-243F009A Reactor Recirculation Excess Flow Check NIA Recirculation Valve (continued) XV-243F009 B Reactor Reclrculatlon Excess Flow Check NIA Valve XV-243F009 C Reactor Recirculation Excess Flow Check NIA Valve XV-243F009 D Reactor Recirculation Excess Flow Check NIA Valve XV-243F010A Reactor Recirculation Excess Flow Check NIA Valve XV-243F010 B Reactor Recirculation Excess Flow Check NIA Valve XV-243F010 C Reactor Rectrculation Excess Flow Check N/A Valve XV-243F010 D Reactor Recirculation Excess Plow Check NIA Valve XV-243F011 A Reactor Recirculation Excess Flow Check NIA Valve XV-243F011 B Reactor Recirculation Excess Flow Check NIA Valve XV-243F011 C Reactor Rectrculabon Excess Flow Check NIA Valve XV-243F011 D Reactor Recirculation Excess Flow Check NIA Valve XV-243F012 A Reactor Recirculation Excess Flow Check NIA Valve XV-243F012 B Reactor Recirculation Excess Flow Check NIA Valve XV-243FQ12 C Reactor Recirculation Excess Flow Check NIA Valve XV-243F012 D Reactor Reclrculatioo Excess Flow Check NIA Valve XV-243F017 A Recirculation Pump Seal Water Excess Flow Check NIA Valve XV-243F017 B Recirculation Pump Seal Water Excess Flow Check NIA Valve XV-243F040 A Reactor Roorculation Excess Flow Check NIA Valve XV-243F040 B Reactor Recirculatloo Excess Flow Check NIA Valve XV-243F040 C Reactor Recirculation Excess Flow Check NIA Valve XV-243F040 D Reactor Recirculation Excess Flow Check NIA Valve XV-243F057 A Reactor Reclrculatioo Excess Flow Check NIA Valve XV-243F057 B Reactor Recirculatioo Excess Flow Check NIA Valve Residual Heat HV-251F004 A (bl (c) RHR- Suppression Pool Suction Power Ooerated NIA Removal HV-251F004 B (b) (c) RHR - Suppression Pool Suction Power Operated NIA HV-251F004 C <b) (c) RHR - Suppression Pool Suction Power Operated NIA

• SUSQUEHAN NA - UNIT 2

• 3.6-36

Rev. 19 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 Primary Containment Isolation Valve

/Pace 9 of 10)

Isolation Signal LCO

'- 3.3.6.1 Function No.

Plant System Valve Number Valve Description Type of Valve (Maximum Isolation Time lSecondsll Residual Heat HV-251F004 D(b) (c) RHR- Suppression Pool Suction Power Operated NIA Removal HV-251 F007 A (bl (c) RHR - Minimum RecJrculatlon Pov,.rer Operated NIA (continued) HV-251F007 B (bl (c) RHR - Minimum ReCJrculabon Power Operated NIA HV-251 F00B (h) RHR - Shutdown Cooling Suction !Automatic Valve 6.a 6.b, 6.c (52)

HV-251F009 (h) RHR - Sliutdown Coollno Suction Autorriatlc Valve 6.a, 6.b 6.c (52)

HV-251F011 A(b) (d) RHR - Suppression Pool Cooling Manual NIA

'h)

HV-251F011 B (b) (d) RHR - Suppression Pool Cooling Manual NIA

'h)

HV-251F015 A (f) (h) iRHR - Shutdown Cooling Power Operated NIA Retum/LPCl lnlection HV-251F015 B (f) (h) RHR - Shutdown Cooling Power Operated NIA

Retum/LPCI Infection HV-251F016 A (bl (hl RHR - Drw,rell Sorav lAutomatic Valve 2.c, 2 d (90)

HV-251F016 B (b) (h) RHR - Drywall Spray Automatic Valve 12.c, 2 d (90)

HV-251F022 (hl RHR - Reactor Vessel Head Spray IAutomabc Valve 12.d 6 a 6.b, 6.c (30)

HV-251 F023 fhl RHR - Reactor Vessel Head Spray !Automatic Valve 2.d 6.a 6.b 6.c (20)

HV-251F028 A (b) (h) RHR - Suppression Pool ~omatlc Valve 2.c, 2.d (90)

ICoollnQ/Sprav HV-251F028 B (b) (h) RHR - Suppression Pool !Automatic Valve 12.c, 2 d (90)

Coollna/Spray HV-251 F050 A (g) RHR - Shutdown Cooling !Air Operated Checl< NIA Return/LPCl lnlactlon !Valve HV-251 F050 B (g) RHR - Shutdown Cooling !Air Operated Check NIA Retum/LPCI lnlectlon !Valve HV-251 F103 A (b) RHR Heat Exchanaer Ve11t Power Ooerated NIA HV-251F103 B (b) RHR Heat Excharmer Vent Power Operated NIA HV-251F122 A (g) RHR - Shutdown Cooling Power Operated NIA Retum/LPCI lnlectlon IIAJr)

HV-251F122 B (g) RHR - Shutdown Cooling Power Operated NIA Retum/LPCI lnlecbon IIAJr)

PSV-25106A (bl (d) RHR- Relief Valve Dlscharne Relief Valve NIA PSV-25106 B (bl (d) RHR- Relief Valve Dlscharoe Relief Valve NIA PSV-251F126 (d) (h) RHR- Shutdown Coohno Suction Relief Valve NIA XV-25109A RHR Excess Flow Check NIA

!Valve

><V-25109 B RHR Excess Flow Check NIA

!Valve XV-25109 C RHR Excess Flow Check N/A

!Valve XV-25109 D RHR Excess Flow Check NIA

!Valve RWCU HV-244F001 (a) RWCU Suction !Automatic Valve 15.a, 5.b, 5.c, 5.d, 5.f, 5.g (30)

HV-244F004 (a) RWCU Sucbon !Automatic Valve 5.a, 5.b, 5.c, 5.d, 5.e, 15 f 5.Q (30)

XV-24411 A RWCU  !:,xcess Flow Check NIA

!Valve XV-24411 B RWCU Excess Flow Check NIA

!Valve

• SUSQUEHAN NA - UNIT 2 3.6-37

Rev. 19

• PCIVs B 3.6.1.3 Table B 3.6.1.3-1 Prhnary Containment Isolation Valve (Paoe 10 of 10)

Isolation Signal LCO 3.3.6.1 Function No.

Plant System Valve Number Valve Description Type of Valve (Maximum Isolation llme (Seconds))

RWCU IXV-24411 c RWCU Excess Flow Check NIA (continued) Valve IXV-24411 D RWCU Excess Flow Check NIA

~afve IXV-244F046 RWCU Excess Flow Check WA Valve HV-24182A RWCURetum Power Ooerated NIA HV-24182 B RWCU Return Power Operated NIA SLCS l248F007 (a) (d) SLCS Manual Check NIA HV-248F006 (a) SLCS Power Operated NIA Check Valve ITTP System C51-J004 A (Ball Valve) TIP Ball Valves Automatic Valve 7.a 7.b (5)

C51-J004 B (Ball Valve) TIP Ball Valves Automatic Valve 7.a 7.b (5)

C51-J004 C (Ball Valve) rJlP Ball Valves Automatic Valve 7.a 7.b (5)

C51-J004 D (Ban Valve) TIP Ball Valves Automatic Valve 7.a 7.b (5)

C51-J004 E (Ball Valve) TIP Ball Valves Automatic Valve 7.a 7 b (5) ri,p System IC51-J004 A (Shear TIP Shear Valves Squib Valve NIA (continued) ~alve)

C51-J004 B (Shear TIP Shear Valves Squib Valve NIA

!Valve)

C51-J004 C (Shear TIP Shear Valves Squib Valve NIA

~alve)

IC51-J004 D (Shear TIP Shear Valves Squib Valve NIA Valve)

C51-J004 E (Shear TIP Shear Valves Squib Valve NIA Valve)

(a) Isolation barrier remains filled or a water seal remains in the line post-LOCA, Isolation valve Is tested with water.

Isolation valve leakage Is not included In 0.60 L. total Type B and C tests.

(b) Redundant Isolation boundwy for this valve is pro\<lded by the closed system wh95a Integrity Is verified by the Leakage Rate Test Program. This footnote does not apply to valve 255F046 (HPCI) when the associated PCIV, HV255F012 Is closed and deactivated. Similarly, this footnote does not apply to valve 249F021 (RCIC) when It's associated PCIV, FV249F019 is closed and deactivated.

(c) Containment lsolatlon Valves are not Type C tested Containment bypass leakage Is prevented since the lme terminates below the mlnlmwn water level In the Suppression Chamber. Refer to the 1ST Program.

(d) LCO 3.3.3 1, "PAM Instrumentation," Table 3.3.3.1-1, Function 6, (PCIV Position) does not apply since these are relief valves, check valves, manual valves or deacbvated and closed.

(e) Toa containment Isolation barriers for the penetrabon associated with this valve consists of two PCIVs and a closed system. The closed system provides a redundant lsolatlon boundary for both PCIVs, and its integrity Is required to be verified by the Leakage Rate Test Program.

(f) Redundant isolatlon boundary for this valve Is provided by the closed system whose Integrity Is verified by the Leakage Rate Test Program (g) These valves are not required to be 10 CFR 50, Appendix J tested since the HV-251F015A(B) valves (sea note (h)) and a closed system form the 10 CFR 50, AppendD< J boundary. These valves form a high/low pressure Interface and are pressure tested In accordance with the pressure test program.

(h) Isolation barner remains fined or a water seal remains in the line post-LOCA. Type C tasting is not required SUSQUEHAN NA - UNIT 2 3.6-38

Rev. 19 PCIVs B 3.6.1.3 Table B 3.6.1.3-2 Secondary Containment Bypass Leakage Isolation Valves (Not PCIVs)

(Page 1 of 1)

Isolation Signal LC0 3.3.6.1 F1D1ction No.

Plant System Valve Number Valve Description Type of Valve {Maximum Isolation Tbne!Second11ll Residual Heat HV-251F040 RHR- RADWASTE LINE 18 ISO VLV IAutomatlc Valve 2.a, 2.d (45)

Removal HV-251F049 RHR - DISCH TO RAfJW OB ISO VLV IAutomatlc Valve 2.a, 2.d (20) 2-51-136 RHR - COND TRANSFER OB SCBL Check Valve NIA CHECKVAf..VE 12-51-137 RHR - COND TRANSFER IB SCBL Check Valve NIA CHECK VALVE

• SUSQUEHANNA - UNIT 2 3.6-39

Rev. 2 AC Source-Shutdown B 3.8.2 B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.2 AC Sources-Shutdow n BASES BACKGROUND A description of the AC sources Is provided in the Bases for LCO 3.8.1, "AC Sources--Operatin g."

APPLICABLE The OPERABILITY of the minimum AC sources during MODES 4 and 5 SAFETY and during movement of irradiated fuel assemblies ensures that ANALYSES

a. The facility can be maintained in the shutdown or refueling condition for extended periods;

b. Sufficient instrumentation and control capability Is available for monitoring and maintaining the unit status; and

c. Adequate AC electrical power is provided to mitigate events postulated during shutdown, such as a fuel handling a~ident.

In general, when the unit is shut down the Technical Specifications requirements ensure that the unit has the capability to mitigate the consequences of postulated accidents. However, assuming a single failure and concurrent loss of all offsite or loss of all onsite power is not required.

The rationale for this is based on the fact that many Design Basis Accidents (DBAs) that are analyzed in MODES 1, 2, and 3 have no specific analyses in MODES 4 and 5. Worst case bounding events are deemed not credible in MODES 4 and 5 because the energy contained within the reactor pressure boundary, reactor coolant temperature and pressure, and corresponding stresses result in the probabilities of occurrences significantly reduced or eliminated, and minimal consequences. These deviations from OBA analysis assumptions and design requirements during shutdown conditions are allowed by the LCO for required systems.

The Safety Analysis for Unit 2 assumes the OPERABILITY of some equipment that receives power from Unit 1 AC Sources.

Therefore, Unit 2 Technical Specifications establish requirements for the OPERABILITY of the DG(s) and qualified offslte circuits needed to support the Unit 1 onsite Class 1E AC elecbical power distribution subsystem(s) required by Unit 2 LCO 3.8.8, Distribution Systems-Shutdow n .

• SUSQUEHANNA - UNIT 2 3.8-39

Rev. 2 AC Source-Shutdown B 3.8.2 BASES APPLICABLE During MODES 1, 2, and 3, various deviations from the analysis SAFETY assumptions and design requirements are allowed within the ACTIONS.

ANALYSES This allowance is In recognition that certain testing and maintenance (continued) activities must be conducted, provided an acceptable level of risk is not exceeded. During MODES 4 and 5, perfonnance of a significant number of requjred testing and maintenance activities is also required. In MODES 4 and 5, the activities are generally planned and administratively controlled.

Relaxations from typical MODES 1, 2, and 3 LCO requirements are acceptable during shutdown MODES, based on:

. a. The fact that time in an outage is limited. This is a risk prudent goal as well as a utility economic consideration.

b. Requiring appropriate compensatory measures for certain conditions.

These may include administrative controls, reliance on systems that do not necessarily meet typical design requirements applied to systems credited in operation MODE analyses, or both.

c. Prudent utility consideration of the risk associated with multiple activities that could affect multiple systems .

d. Maintaining, to the extent practical, the ability to perfom, required functions (even if not meeting MODES 1, 2, and 3 OPERABILITY requirements) with systems assumed to function during an event In the event of an accident during shutdown, this LCO ensures the capability of supporting systems necessary for avoiding immediate difficulty, assuming either a loss of all offsite power or a loss of all onsite (diesel generator (DG)) power.

The AC sources satisfy Criterion 3 of the NRC Policy Statement (Ref. 1).

LCO One offsite circuit capable of supplying the onsite Class 1E power distribution subsystem(s) of LCO 3.8.8, "Distribution Systems-Shu tdown,"

ensures that all required loads are powered from offsite power. An OPERABLE DG, associated with a Distribution System Engineered Safeguards System (ESS) bus required OPERABLE by LCO 3.8.8, ensures that a diverse power source is available for providing electrical power support assuming a loss of the offsite circuit. Together, OPERABlLITY of the required offsite circuit and the ability to manually start a DG ensures the availability of sufficient AC sources to operate the plant in a safe manner and to mitigate the consequences of postulated events during shutdown (e.g., fuel handling accidents) .

• SUSQUEHAN NA - UNIT 2 3.8-40

Rev. 2 AC Source-Shutd own B 3.8.2 BASES LCO The qualified offsite circuit(s) must be capable of maintaining rated (continued) frequency and voltage while connected to their respective ESS bus(es),

and of accepting required loads during an accident. Qualified offsite circuits are those that are described in the FSAR and are part of the licensing basis for the unit. An offsite circuit includes all breakers, transfonners, switches, automatic tap changers, interrupting devices, cabling, and controls required to transmit power from the offsite transmission network to the onsite Class 1E ESS bus or buses. The offsite circuit consists of the incoming breaker and disconnect to startup transfonners (SD No. 10 and ST No. 20 and the respective circuit path including feeder breakers to the four 4.16 kV ESS buses (A, B, C and D) for both Unit 1 and Unit 2. A detailed description of the offsite power network and circuits to the onsite Class 1E ESS buses is found in the FSAR, Section 8.2.

The required DG must be capable of being manually started, accelerating to rated speed and voltage, connecting to its respective ESS bus, and capable of accepting required loads .

• APPLICABILIT Y The AC sources are required to be OPERABLE in MODES 4 and 5 and during movement of irradiated fuel assemblies in the secondary containment to provide assurance that:

a. Systems that provide core cooling are available;

b. Systems needed to mitigate a fuel handling accident are available;

c. Systems necessary to mitigate the effects of events that can lead to core damage during shutdown are available; and

d. Instrumentation and control capability is avallable for monitoring and maintaining the unit in a cold shutdown condition or refueling condition.

AC power requirements for MODES 1, 2, and 3 are covered in LCO 3.8.1.

ACTIONS The ACTIONS have been modified by a Note stating that LCO 3.0.3 is not applicable. If moving Irradiated fuel assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify any action. If moving irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations .

• SUSQUEHAN NA - UNIT 2 3.8-41

Rev. 2 AC Source-Shutd own B 3.8.2 BASES ACTIONS A.1 (continued)

With one or more required AC Sources (DGs or 4.16 kV ESS buses) inoperable, the remaining required sources may be capable of supporting sufficient required features (e.g., system, subsystem, dMsions, component or device), to allow continuation of CORE ALTERATIONS and fuel movement. For example, if two or more 4 kV emergency buses are required per LCO 3.8.8, one 4.16 kV emergency bus with offsrte power available may be capable of supporting sufficient required features. Therefore, the option provided by Required Action A.1 to declare required features inoperable when not powered from an offsite source or not capable of being powered by the required DG recognizes that appropriate restrictions will be required by ACTIONS in the LCO for the affected feature(s).

If a DG is credited with meeting both Unit 2 LCO 3.8.2.b and Unit 2 LCO 3.8.2.d or an offsite circuit is credited with meeting both Unit 2 LCO 3.8.2.a and Unit 2 LCO 3.8.2.c, the AC Source may considered OPERABLE for meeting one of the requirements even if is considered inoperable for meeting the other.

• • A.2.1, and A.2.2, and A.2.3 With one. or more required AC Sources inoperable, the option exists in ACTION A. 1 to declare all affected features inoperable. Since this option may involve undesired administrative efforts, the allowance for sufficiently conservative actions is made. Wrth one or more required AC Sources inoperable, the minimum required diversity of AC power sources is not available. It is, therefore, required to suspend CORE ALTERATION S and movement of irradiated fuel assemblies in the secondary containment Suspension of these activities shall not preclude completion of actions to establish a safe conservative condition. These actions minimize the probability of the occurrence of postulated events. It is further required to immediately initiate action to restore the required AC sources and to continue this action until restoration is accomplished in ordet to provide the necessary AC power to the plant safety systems.

The Completion Time of immediately Is consistent with the required times for actions requiring prompt attention. The restoration of the required AC electrical power sources should be completed as quickly as possible in order to minimize the time during which the plant safety systems may be without sufficient power.

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Rev. 2 AC Source-Shutdown B 3.8.2 BASES ACTIONS A.2.1, and A.2.2, and A2.3 (continued)

(continued)

Because of the allowance provided by LCO 3.0.6, the Distribution System ACTIONS would not be entered even if all AC sources to it are inoperable, resulting in de-energization. Therefore, the Required Actions of Condition A have been modified by a Note to indicate that when Condition A is entered with no AC power to any required ESS bus, ACTIONS for LCO 3.8.8 must be immediately entered. This Note allows Condition A to provide requirements for the loss of the offsite circuit whether or not a 4.16 kV ESS bus is de-energized. LCO 3.8.8 provides the appropriate restrictions for the situation involving a de-energized 4.16 kV ESS bus.

SURVEILLANCE SR 3.8.2.1 REQUIREMENTS SR 3.8.2.1 requires the SRs from LCO 3.8.1 that are necessary for ensuring the OPERABILITY of the AC sources in other than MODES 1, 2, and 3. SR 3.8.1.8 is not required to be met since only one offsite circuit is required to be OPERABLE. SR 3.8.1.7, SR 3.8.1.11, SR 3.8.1.12,

• SR 3.8.1.13, SR 3.8.1.15, SR 3.8.1.18, and SR 3.8.1.19 are not required to be met because DG start and load within a specified time and response on an offsite power or ECCS initiation signal is not required.

SR 3.8.1.17 is not required to be met because the required OPERABLE DG(s) Is not required to undergo periods of being synchronized to the offsite circuit. SR 3.8.1.20 is excepted because starting independence is not required with the DGs that are not required to be OPERABLE. Refer to the corresponding Bases for LCO 3.8.1 for a discussion of each SR.

This SR is modified by a Note that specified SRs must be met but are not required to be performed. The reason for the Note is to preclude requiring the OPERABLE DG(s) from being paralleled with the offsite power network or otherwise rendered inoperable during the performance of SRs, and to preclude de-energizing a required 4160 V ESS bus or disconnecting a required offsite circuit during performance of SRs. With limited AC sources available, a single event could compromise both the required circuit and the DG.

It is the intent that these SRs must still be capable of being met, but actual performance is not required during periods when the DG and offsite circuit is required to be OPERABLE .

• SUSQUEHANNA - UNIT 2 3.8-43

Rev.2 AC Source-Shutdown 8 3.8.2 BASES SURVEILLANCE SR 3.8.2.2 REQUIREMENTS (continued) This Surveillance is provided to direct that the appropriate Surveillances for Unit 1 AC sources required to support Unit 2 are governed by the Unit 2 Technical Specifications. Wrth the exception of this Surveillance, all other Surveillances of this Specification (SR 3.8.1.1 through SR 3.8: 1.20) ar:e applicable to the Unit 2 AC sources only. Meeting the SR requirements of Unit 1 LCO 3.8.1 will satisfy all Unit 2 requirements for Unit 1 AC sources.

However, ten Unit 1 LCO 3.8.1 SRs, if not required to support Unit 1 OPERABILITY requirements, are not required when demonstrating Unit 1 sources are capable of supporting Unit 2. SR 3.8.1.8 is not required if only one Unit 1 offsite circuit is required by the Unit 2 Specification. SR 3.8.1. 7, SR 3.8.1.11, SR 3.8.1.12, SR 3.8.1.13, SR 3.8.1.15, SR 3.8.1.17, SR 3.8.1.18 and SR 3.8.1.19 are not required to be met because DG start and load within a specified time and response on an offslte power or ECCS initiation signal is not required for the AC sources to be OPERABLE on Unit 2. SR 3.8.1.20 is not required since starting independence is not required with the DG(s) not required to be OPERABLE.

The Frequency required by the applicable Unit 1 SR also governs performance of that SR for Unit 2.

As Noted, if Unit 1 is in MODE 4 or 5, the Note to Unit 1 SR 3.8.2.1 is applicable. This ensures that a Unit 2 SR will not require a Unit 1 SR to be perfom,ed, when the Unit 1 Technical Specifications do not require .

perfom,ance of a Unit 1 SR. (However, as stated In the Unit 2 SR 3.8.2.1 Note, while perfonnance of an SR is not required, the SR still must be met).

REFERENCES 1. Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 39132) .

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Rev. 2 AC Source-Shutdown B 3.8.2 BASES

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