Text

Revisions to Technical Specifications Bases, Manual
	ML071200046
Person / Time
Site:	Susquehanna
Issue date:	04/20/2007
From:	; Susquehanna
To:	Gerlach R; Document Control Desk, NRC/NRR/ADRO
References
	028401, 2007-16315
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Apr. 20, 2007 Pagel of 1 MANUAL HARD COPY DISTRIBUTION DOCUMENT TRANSMITTAL 2007-16315 USER INFORMATION:

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TO: GERLACH*ROSE M 04/20/2007 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 TRANSMITTAL. 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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TSB2 - TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL REMOVE MANUAL TABLE OF CONTENTS DATE: 04/10/2007 ADD MANUAL TABLE OF CONTENTS DATE: 04/19/2007 CATEGORY: DOCUMENTS TYPE: TSB2 ID: TEXT 3.3.3.1 REMOVE: REV:4 ADD: REV: 5 CATEGORY: DOCUMENTS TYPE: TSB2 ID: TEXT 3.4.5 REMOVE: REV:l REV: 2 CATEGORY: DOCUMENTS TYPE: TSB2 ID: TEXT 3.6.1.3

/4 ()C) /

Apr. 20, 2007 Page 2 of 2 REMOVE: REV:5 ADD: REV: 6 CATEGORY: DOCUMENTS TYPE: TSB2 ID: TEXT 3.6.2.1 REMOVE: REV:0 ADD: REV: 1 CATEGORY: DOCUMENTS TYPE: TSB2 ID: TEXT LOES REMOVE: REV:82 ADD: REV: 83 ADD: REV: 84 REMOVE: REV:84 I D: REV: 85 REMOVE: REV:85 ANY DISCREPANCIES WITH THE MATERIAL PROVIDED, CONTACT DCS @ X3107 OR X3136 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 Manual Name: TSB2 Manual

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL Table Of Contents Issue Date: 04/19/2007 Procedure Name Rev Issue Date Change ID Change Number TEXT LOES 85 04/19/2007

Title:

LIST OF EFFECTIVE SECTIONS TEXT TOC ii 04/09/2007

Title:

TABLE OF CONTENTS TEXT 2.1.1 2 04/03/2007 ,

Title:

SAFETY LIMITS (SLS) REACTOR CORE SLS

\ \ /

TEXT 2.1.2 0 11/18/2 002\

Title:

SAFETY LIMITS (SLS) REACTOR COOLANT SYSTEM,/(RCS) PRESSURE SL TEXT 3.0 2 1-0/1,2/2006/

Title:

LIMITING CONDITION FOR-OPERATION-.(LCO) APPLICABILITY TEXT 3.1.1 \N /

"1\-' \. K 03-/24/2005

Title:

REACTIVITY CONTROL<SYSTEMS SHUTDOWN MARGIN (SDM)

- K N -

TEXT 3.1.2 S -0, 11/18/2002

Title:

REACTIVITY 'CONTROL 'SYSTEMS REACTIVITY ANOMALIES TEXT 3.1.3 .1 07/06/2005

Title:

REACTIVITY CONTROL SYSTEMS CONTROL ROD OPERABILITY

/

TEXT 3.1.4 3 09/29/2006

Title:

REACTIVITY CONTROL SYSTEMS CONTROL ROD SCRAM TIMES TEXT 3.1.5 1 07/06/2005

Title:

REACTIVITY CONTROL SYSTEMS CONTROL ROD SCRAM ACCUMULATORS TEXT 3.1.6 2 03/24/2005

Title:

REACTIVITY CONTROL SYSTEMS ROD PATTERN CONTROL Report Date: 04/19/07 I

Page .j of of 88 Report Date: 04/19/07

1 SSES M~ANUJAL1 -

Manual Name: TSB2 Manual

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL 6 TEXT 3.1.7 2 04/03/2007

Title:

REACTIVITY CONTROL SYSTEMS STANDBY LIQUID CONTROL (SLC) SYSTEM TEXT 3.1.8 1 10/19/2005

Title:

REACTIVITY CONTROL SYSTEMS SCRAM DISCHARGE VOLUME (SDV) VENT AND DRAIN VALVES TEXT 3.2.1 3 04/09/2007

Title:

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

TEXT 3.2.2 2 04/03/2007

Title:

POWER DISTRIBUTION LIMITS MINIMUM CRITICAL POWER RATIO (MCPR)

TEXT 3.2.3 0 11/18/2002

Title:

POWER DISTRIBUTION LIMITS LINEAR HEAT GENERATION RATE LHGR TEXT 3.3.1.1 3 04/09/2007 -

Title:

INSTRUMENTATION REACTOR PROTECTION SYSTEM (RPS) INSTRUMENTATION TEXT 3.3.1.2 1 04/09/2007

Title:

INSTRUMENTATION SOURCE RANGE MONITOR (SRMT INSTRUMENTATION TEXT 3.3.2.1 2 04/09/2007

Title:

INSTRUMENTATION CONTROL ROD BLOCK INSTRUMENTATION TEXT 3.3.2.2 0 11/18/2002

Title:

INSTRUMENTATION FEEDWATER - MAIN TURBINE HIGH WATER LEVEL TRIP INSTRUMENTATION TEXT 3.3.3.1 5 04/19/2007

Title:

INSTRUMENTATION POST ACCIDENT MONITORING (PAM) INSTRUMENTATION TEXT 3.3.3.2 1 04/18/2005

Title:

INSTRUMENTATION REMOTE SHUTDOWN SYSTEM TEXT 3.3.4.1 0 11/18/2002

Title:

INSTRUMENTATION END OF CYCLE RECIRCULATION PUMP TRIP (EOC-RPT) INSTRUMENTATI Report Date: 04/19/07 PageZ Page 2 of of 8 8 Report Date: 04/19/07

SSES MANUAL

. Manual Name: TSB2 Manual

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL TEXT 3.3.4.2 0 11/18/2002

Title:

INSTRUMENTATION ANTICIPATED TRANSIENT WITHOUT SCRAM RECIRCULATION PUMP TRIP (ATWS-RPT) INSTRUMENTATION TEXT 3.3.5.1 3 07/06/2005

Title:

INSTRUMENTATION EMERGENCY CORE COOLING SYSTEM (ECCS) INSTRUMENTATION TEXT 3.3.5.2 0 11/18/2002

Title:

INSTRUMENTATION REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM INSTRUMENTATION TEXT 3.3.6.1 2 04/03/2007

Title:

INSTRUMENTATION PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION TEXT 3.3.6.2 1 11/09/2004

Title:

INSTRUMENTATION SECONDARY CONTAINMENT ISOLATION INSTRUMENTATION TEXT 3.3.7.1 0 11/18/2002 -

Title:

INSTRUMENTATION CONTROL ROOM EMERGENCY OUTSIDE AIR SUPPLY (CREOAS) SYSTEM INSTRUMENTATION TEXT 3.3.8.1 2 03/31/2006

Title:

INSTRUMENTATION LOSS OF POWER (LOP) INSTRUMENTATION TEXT 3.3.8.2 0 11/18/2002

Title:

INSTRUMENTATION REACTOR PROTECTION SYSTEM (RPS) ELECTRIC POWER MONITORING TEXT 3.4.1 3 04/09/2007

Title:

REACTOR COOLANT SYSTEM (RCS) RECIRCULATION LOOPS OPERATING TEXT 3.4.2 0 11/18/2002

Title:

REACTOR COOLANT SYSTEM (RCS) JET PUMPS TEXT 3.4.3 1 01/16/2006

Title:

REACTOR COOLANT SYSTEM (RCS) SAFETY/RELIEF VALVES (S/RVS)

TEXT 3.4.4 0 11/18/2002

Title:

REACTOR COOLANT SYSTEM (RCS) RCS OPERATIONAL LEAKAGE Report Date: 04/19/07 Page 3-Page~ of8 8 of Report Date: 04/19/07

SSES MANUAL -,

Manual Name: TSB2 Manual

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL a TEXT 3.4.5 2 04/19/2007

Title:

REACTOR COOLANT SYSTEM (RCS) RCS PRESSURE ISOLATION VALVE (PIV) LEAKAGE TEXT 3.4.6 1 04/18/2005

Title:

REACTOR COOLANT SYSTEM (RCS) RCS LEAKAGE DETECTION INSTRUMENTATION TEXT 3.4.7 1 04/18/2005

Title:

REACTOR COOLANT SYSTEM (RCS) RCS SPECIFIC ACTIVITY TEXT 3.4.8 1 04/18/2005

Title:

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

- HOT SHUTDOWN TEXT 3.4.9 0 11/18/2002

Title:

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

- COLD SHUTDOWN TEXT 3.4.10 2 05/10/2006 -

Title:

REACTOR COOLANT SYSTEM (RCS) RCS PRESSURE AND TEMPERATURE (P/T) LIMITS TEXT 3.4.11 0 11/18/2002

Title:

REACTOR COOLANT SYSTEM (RCS) REACTOR STEAM DOME PRESSURE TEXT 3.5.1 3 -01/16/2006

Title:

EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC)

SYSTEM ECCS - OPERATING TEXT 3.5.2 0 11/18/2002

Title:

EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC)

SYSTEM ECCS - SHUTDOWN TEXT 3.5.3 1 04/18/2005

Title:

EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC)

SYSTEM RCIC SYSTEM TEXT 3.6.1.1 1 04/03/2007

Title:

CONTAINMENT SYSTEMS PRIMARY CONTAINMENT TEXT 3.6.1.2 0 11/18/2002

Title:

CONTAINMENT SYSTEMS PRIMARY CONTAINMENT AIR LOCK Report Date: 04/19/07 Page4 Page 4 of of 88 Report Date: 04/19/07

SSES MANUJAL Manual Name: TSB2 O Manual

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL TEXT 3.6.1.3 6 04/19/2007

Title:

CONTAINMENT SYSTEMS PRIMARY CONTAINMENT ISOLATION VALVES (PCIVS)

TEXT 3.6.1.4 0 11/18/2002

Title:

CONTAINMENT SYSTEMS CONTAINMENT PRESSURE TEXT 3.6.1.5 1 10/05/2005

Title:

CONTAINMENT SYSTEMS DRYWELL AIR TEMPERATURE TEXT 3.6.1.6 0 11/18/2002

Title:

CONTAINMENT SYSTEMS SUPPRESSION CHAMBER-TO-DRYWELL VACUUM BREAKERS TEXT 3.6.2.1 1 04/19/2007

Title:

CONTAINMENT SYSTEMS SUPPRESSION POOL AVERAGE TEMPERATURE TEXT 3.6.2.2 0 11/18/2002 _

Title:

CONTAINMENT SYSTEMS-SUPPRESSION POOL WATER LEVEL TEXT 3.6.2.3 1 01/16/2006

Title:

CONTAINMENT SYSTEMS RESIDUAL HEAT REMOVAL-(RHR) SUPPRESSION POOL COOLING TEXT 3.6.2.4 0 11/18/2002

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 TEXT 3.6.3.2 1 04/18/2005

Title:

CONTAINMENT SYSTEMS DRYWELL AIR FLOW SYSTEM TEXT 3.6.3.3 0 11/18/2002

Title:

CONTAINMENT SYSTEMS PRIMARY CONTAINMENT OXYGEN CONCENTRATION TEXT 3.6.4.1 6 08/08/2006

Title:

CONTAINMENT SYSTEMS SECONDARY CONTAINMENT Page 5 of 8 Report Date: 04/19/07

SSES MANUAL Manual Name: TSB2 Manual

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL TEXT 3.6.4.2 2 01/03/2005

Title:

CONTAINMENT SYSTEMS SECONDARY CONTAINMENT ISOLATION VALVES (SCIVS)

TEXT 3.6.4.3 4 09/21/2006

Title:

CONTAINMENT SYSTEMS STANDBY GAS. TREATMENT (SGT) SYSTEM TEXT 3.7.1 0 11/18/2002

Title:

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

TEXT 3.7.2 1 11/09/2004

Title:

PLANT SYSTEMS EMERGENCY SERVICE WATER (ESW) SYSTEM TEXT 3.7.3 0 11/18/2002

Title:

PLANT SYSTEMS CONTROL ROOM EMERGENCY OUTSIDE AIR SUPPLY (CREOAS) SYSTEM 0 11/18/2002 -

TEXT 3.7.4

Title:

PLANT SYSTEMS CONTROL ROOM FLOOR COOLING SYSTEM TEXT 3.7.5 10 11/18/2002

Title:

PLANT SYSTEMS MAIN CONDENSER OFFGAS TEXT 3.7.6 .1 01/17/2005

Title:

PLANT SYSTEMS MAIN TURBINE BYPASS SYSTEM TEXT 3.7.7 0 11/18/2002

Title:

PLANT SYSTEMS SPENT FUEL STORAGE POOL WATER LEVEL TEXT 3.8.1 4 04/18/2006

Title:

ELECTRICAL POWER SYSTEMS AC SOURCES - OPERATING TEXT 3.8.2 0 11/18/2002

Title:

ELECTRICAL POWER SYSTEMS AC SOURCES - SHUTDOWN TEXT 3.8.3 0 11/18/2002

Title:

ELECTRICAL POWER SYSTEMS DIESEL FUEL OIL, LUBE OIL, AND STARTING AIR Report Date: 04/19/07 Page6k Page of of ~8 Report Date: 04/19/07

SSES MANU.Al.

Manual Name: TSB2 O Manual

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL TEXT 3.8.4 2 12/14/2006

Title:

ELECTRICAL POWER SYSTEMS DC SOURCES - OPERATING TEXT 3.8.5 1 12/14/2006

Title:

ELECTRICAL POWER SYSTEMS DC SOURCES - SHUTDOWN TEXT 3.8.6 1 12/14/2006

Title:

ELECTRICAL POWER SYSTEMS BATTERY CELL PARAMETERS TEXT 3.8.7 3 03/31/2006

Title:

ELECTRICAL POWER SYSTEMS DISTRIBUTION SYSTEMS - OPERATING TEXT 3.8.8 0 11/18/2002

Title:

ELECTRICAL POWER SYSTEMS DISTRIBUTION SYSTEMS - SHUTDOWN TEXT 3.9.1 0 11/18/2002 -

Title:

REFUELING OPERATIONS- REFUELING EQUIPMENT INTERLOCKS TEXT 3.9.2 0 11/18/2002

Title:

REFUELING OPERATIONS REFUEL POSITION ONE-ROD-OUT INTERLOCK TEXT 3.9.3 0 -11/18/2002

Title:

REFUELING OPERATIONS CONTROL ROD POSITION TEXT 3.9.4 0 11/18/2002

Title:

REFUELING OPERATIONS CONTROL ROD POSITION INDICATION TEXT 3.9.5 0 11/18/2002

Title:

REFUELING OPERATIONS CONTROL ROD OPERABILITY - REFUELING TEXT 3.9.6 0 11/18/2002

Title:

REFUELING OPERATIONS REACTOR PRESSURE VESSEL (RPV) WATER LEVEL TEXT 3.9.7 0 11/18/2002

Title:

REFUELING OPERATIONS RESIDUAL HEAT REMOVAL (RHR) - HIGH WATER LEVEL Report Date: 04/19/07 Page77 Page of of 88 Report Date: 04/19/07

SSES MANUAL Manual Name: TSB2 Manual

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL TEXT 3.9.8 0 11/18/2002

Title:

REFUELING OPERATIONS RESIDUAL HEAT REMOVAL (RHR) - LOW WATER LEVEL TEXT 3.10.1 0 11/18/2002

Title:

SPECIAL OPERATIONS INSERVICE LEAK AND HYDROSTATIC TESTING OPERATION TEXT 3.10.2 0 11/18/2002

Title:

SPECIAL OPERATIONS REACTOR MODE SWITCH INTERLOCK TESTING TEXT 3.10.3 0 11/18/2002

Title:

SPECIAL OPERATIONS SINGLE CONTROL ROD WITHDRAWAL - HOT SHUTDOWN TEXT 3.10.4 0 11/18/2002

Title:

SPECIAL OPERATIONS SINGLE CONTROL ROD WITHDRAWAL - COLD SHUTDOWN TEXT 3.10.5 0 11/18/2002 _

Title:

SPECIAL OPERATIONS SINGLE CONTROL ROD DRIVE (CRD) REMOVAL - REFUELING TEXT 3.10.6 0 11/18/2002

Title:

SPECIAL OPERATIONS MULTIPLE CONTROL ROD WITHDRAWAL - REFUELING TEXT 3.10.7 103/24/2005

Title:

SPECIAL OPERATIONS CONTROL ROD TESTING - OPERATING TEXT 3.10.8 2 04/09/2007

Title:

SPECIAL OPERATIONS SHUTDOWN MARGIN (SDM) TEST - REFUELING Report Date: 04/19/07 Page88 Page of of ~8 Report Date: 04/19/07

SUSQUEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)

Section Title Revision TOC Table of Contents 11 B 2.0 SAFETY LIMITS BASES Page TS / B 2.0-1 1 Page TS / B 2.0-2 3 Page TS / B 2.0-3 4 Page TS / B 2.0-4 5 Page TS'/ B 2.0-5 1 Pages B 2.0-6 through B 2.0-8 0 B 3.0 LCO AND SR APPLICABILITY BASES Page TS / B 3.0-1 1 Pages TS / B 3.0-2 through TS / B 3.0-4 0 Pages TS / B 3.0-5 through TS / B 3.0-7 1 Pages TS / B 3.0-8 through TS / B 3.0-9 2 Page TS / B 3. 0-10 1 Page TS/ B 3.0-11 2 Page TS / B 3.0-1 la 0 Page TS / B 3.0-12 1 Pages TS / B 3.0-13 through T -/ B 30-15/ 2 Pages TS / B 3.0-16 and TS / B 3.0-w17 0 B 3.1 REACTIVITY CONTROL BASES, Pages B 3.1-1 through B 3.1-4, 0 Page TS / B 3.1-5.,, 1.

Pages TS / B 3.1-,6and TS\/-.B 3.1-7 2 Pages B 3.1-8through B,3.1-13 . 0 PageTS/B3.14, -- 1 Pages B 3.1-15 through B 3.1-21 0 PageTS /B3.1-22 0 Page TS /-B 3.1-23 1 Page TS / B 3.1-24 0 Page TS / B"3.1-25 1 Page TS / B 3.1-26 0

,Page TS / B 3.1-27 1 Page TS / B 3.1-28 2 Page TS / 3.1-29 1 Pages B 3.1-30 through B 3.1-33 0 Pages TS / B 3.1.34 through TS / B 3.1-36 1 Pages TS / B 3.1-37 and TS / B 3.1-38 2 Pages TS / B 3.1-39 through TS / B 3.1-42 1 Pages TS / B 3.1-43 and TS / B 3.1-44 0 Page TS / B 3.1-45 2 Page TS / B 3.1-46 0 Page B 3.1-47 0 Pages TS / B 3.1-48 and TS / B 3.1-49 1 SUSQUEHANNA - UNIT 2 TS / B LOES-1 Revision 85

SUSQUEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)

Section Title Revision Page B 3.1-50 0 Page TS / B 3.1-51 1 B 3.2 POWER DISTRIBUTION LIMITS BASES Page TS / B 3.2-1 2 Page TS / B 3.2-2 1 Page TS / B 3.2-3 3 Page TS / B 3.2-4 1 Pages TS / B 3.2-5 and TS / B 3.2-6 3 Page TS / B 3.2-7 2 Pages TS / B 3.2-8 and TS / B 3.2-9 4 Pages TS / B 3.2-10 through TS / B 3.2-13 1 B 3.3 INSTRUMENTATION Pages TS / B 3.3-1 through TS / B 3.3-4 1 Page TS / B 3.3-5 2 Page TS / B 3.3-6 1 Pages TS / B 3.3-7 through TS / B 3.3-12 3 Page TS / B 3.3-13 2 Page TS / B 3.3-14 3 Pages TS / B 3.3-15 and TS / B 3.3-16 2 Pages TS / B 3.3-17 and TS / B 3.3-18 3 Pages TS / B 3.3-19 through TS / B 3.3-27 2 Pages TS / B 3.3-28 through TS / B 3.3-30 3 Page TS / B 3.3-31 2-Page TSI/B 3.3 4 Page TS / B B 3.3-33 3.3-34 .. s

.2 PageTS/B 3.3-34 -- "2 Pages TS / B 3.3-34a though TS / B 3.3-34i 0 Pages TS / B 3.3-35 and TS / B 3.3-36 2 Pages TS/ B 3.3-37 through TS / B 3.3-43 1 Pages TS / B 3.3-44 through TS / B 3.3-54 3 Pages TS / B 3.3-54a through TS / B 3.3-54e 0 Pages B 3.3-55 through B 3.3-63 0 Pages TS / B 3.3-64 and TS / B 3.3-65 2 Page TS / B 3.3-66 4 Page TS / B 3.3-67 3 Page TS / B 3.3-68 4 Page TS / B 3.3.69 5 Page TS / B 3.3-70 4 Page TS / B 3.3-71 3 Pages TS / B 3.3-72 and TS / B 3.3-73 2 Page TS / B 3.3-74 3 Page TS / B 3.3-75 2 Pages B 3.3-75a through TS / B 3.3-75c 5 Pages B 3.3-76 and TS / B 3.3-77 0 SUSQUEHANNA - UNIT 2 TS / B LOES-2 Revision 85

SUSQUEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)

Section Title Revision Page TS / B 3.3-78 1 Pages B 3.3-79 through B 3.3-91 0 Pages TS / B 3.3-92 through TS / B 3.3-103 1 Page TS / B 3.3-104 2 Pages TS / B 3.3-105 and TS / B 3.3-106 1 Page TS / B 3.3-107 2 Page TS / B 3.3-108 1 Page TS/ B 3.3-109 2 Pages TS / B 3.3-110 through TS/ B 3.3-112 1 Page TS / B 3.3-113 2 Page TS / B 3.3-114 1 Page TS / B 3.3-115 through TS / B 3.3-118 2 Pages TS I B 3.3-119 through TS / B 3.3-120 1 Pages TS / B 3.3-121 and TS / B 3.3-122 2 Page TS / B 3.3-123 1 Page TS / B 3.3-124" 2 Page TS / B 3.3-124a 0 Page TS / B 3.3-125 1 Page TS / B 3.3-126 2 Page TS / B 3.3-127 3 Page TS / B 3.3-128 2 Pages TS / B 3.3-129 through TS / B 3.3-131 1 Page TS / B 3.3-132 2 Pages TS / B 3.3-133 and TS / B 3.3-134 1 Pages B 3.3-135 through B 3.3-137 0-Page TS / B 3.3-138 - 1 Pages B 3.3-139 through B 3.3-149 Pages TS/ B 3.3-150 through TS / B 3.3-16-2 1 Page TS / B 3.3-163 2 Pages TS / B 3.3-164 and TS / B 3.3-165 1 Page TS /-B 3.3-166 2 Pages TS / B 3.3-167 through TS / B 3.3-177 1 Page TS / B 3.3-178 2 Page TS / B 3.3-179 3 Page TS / B 3.3-179a 2 Page TS / B 3.3-180 1 Page TS / B 3.3-181 2 Pages TS / B 3.3-182 through TS / B 3.3-186 1 Pages TS / B 3.3-187 and TS / B 3.3-188 2 Pages TS / B 3.3-189 through TS/ B 3.3-191 1 Pages B 3.3-192 through B 3.3-205 0 Page TS / B 3.3-206 1 Pages B 3.3-207 through B 3.3-209 0 Pages TS / B 3.3-210 through TS / B 3.3-213 1 Pages B 3.3-214 through B 3.3-220 0 SUSQUEHANNA - UNIT 2 TS / BLOES-3 Revision 85

SUSQUEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)

Section Title Revision B 3.4 REACTOR COOLANT SYSTEM BASES Pages TS / B 3.4-1 and TS / B 3.4-2 1 Pages TS / B 3.4-3 and TS / B 3.4-4 4 Pages TS / B 3.4-5 and TS / B 3.4-9 3 Pages B 3.4-10 through B 3.4-14 0 Page TS / B 3.4-15 1 Pages TS / B 3.4-16 through TS / B 3.4-18 2 Pages B 3.4-19 through B 3.4-27 0 Page TS / B 3.4-28 1 Page TS / B 3.4-29 2 Pages B 3.4-30 through B 3.3-31 0 Page TS / B 3.4-32 1 Pages B 3.4-33 through B 3.4-36 0 Page TS / B 3.4-37 1 Pages B 3.4-38 through B 3.4-40 0 Page TS / B 3.4-41 1 Pages B 3.4-42 through B 3.4-48 0 Page TS / B 3.4-49 3 Pages TS / B 3.4-50 through TS / B 3.4-52 2 Page TS / B 3.4-53 1 Pages TS / B 3.4-54 and TS / B 3.4-55 2 Page TS / B 3.4 1 Page TS / B 3.4-57 2 Pages TS / B 3.4-58 through TS / B 3.4-60 1-B 3.5 ECCS AND RCIC BASES Pages TS / B 3.5-1 and TS I B 3.5-2 - 1 Pages TS / B 3.5-3 through TS / B 3.5-6 2 Pages TS / B 3.5-7 through TS / B 3.5-10 1 Pages TS/ B 3.5-11 and TS / B 3.5-12 2 Pages TS / B 3.6-13 and TS / B 3.5-14 1 Pages TS / B 3.5-15 and TS / B.3.5-16 2 Page TS / B 3.5-17 3 Page TS / B 3.5-18 1 Pages B 3.5-19 through B 3.5-24 0 Pages TS / B 3.5-25 through TS / B 3.5-27 1 Pages B 3.5-28 through B 3.5-31 0 B 3.6 CONTAINMENT SYSTEMS BASES Page TS / B 3.6-1 2 Page TS / B 3.6-1a 3 Page TS / B 3.6-2 2 Pages TS I B 3.6-3 through TS / B 3.6-5 3 Revision 85 TS/BLOES-4 SUSQUEHANNA - UNIT SUSQUEHANNA -

UNIT 22 TS / B LOES-4 Revision 85

SUSQUEHANNA STEAM ELECTRIC STATION LIST OFEFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)

Section Title Revision Page TS / B 3.6-6 4 Pages TS / B 3.6-6a and TS / B 3.6-6b 2 Page TS / B 3.6-6c 0 Pages B 3.6-7 through B 3.6-14 0 Page TS / B 3.6-15 3 Page TS / B 3.'6-15a 0 Page TS / B 3.6-15b 2 Page TS / B 3.6-16 1 Page TS / B 3.6-17 2 Page TS / B 3.6-17a 0 Pages TS / B 3.6-18 and TS I B 3.6-19 1 Page TS / B 3.6-20 2 Page TS / B 3.6-21 3 Pages TS / B 3.6-21a and TS / B 3.6-21b 0 Pages TS / B 3.6-22 and TS / B 3.6-23 2 Pages TS / B 3.6-24 and TS / B 3.6-25 1 Page TS / B 3.6-26 2 Page TS / B 3.6-27 3 Page TS / B 3.6-28 6 Page TS / B 3.6-29 4 Page TS / B 3.6-29a 0 Page TS / B 3.6-30 2 Page TS / B 3.6 3 Page TS / B 3.6-32 1 Page TS / B 3.6-3-3 2-Page TS / B 3.6-34 1 Pages TS / B 3.6-35 through TS / B 3.6-37 2 Page TS / B 3.6-38 3 Page TS / B 3.6-39 7 Pages B 3.6-40 through B 3.6-42 0 Pages TS-I B 3.6-43 and TS / B 3.6-44 1 Page TS / B 3.6-45 2 Pages TS / B 3.6-46 through TS / B 3.6-50 1 Page TS / B 3.6-51 2 Pages B 3.6-52 through B 3.6-55 0 Pages TS / B 3.6-56 and TS / B 3.6-57 1 Pages B 3.6-58 through B 3.6-62 0 Pages TS / B 3.6-63 and TS / B 3.6-64 1 Pages B 3.6-65 through B 3.6-68 0 Pages B 3.6-69 through B 3.6-71 1 Page TS / B 3.6-72 2 Pages TS / B 3.6-73 and TS / B 3.6-74 1 Pages B 3.6-75 and B 3.6-76 0 Page TS / B 3.6-77 1 Pages B 3.6-78 through B 3.6-82 0 Revision 85 SUSQUEHANNA-UNIT2 TS/BLOES-5 SUSQUEHANNA - UNIT 2 TS / B LOES-5 Revision 85

SUSQUEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)

Section Title Revision Page TS / B 3.6-83 3 Page TS / B 3.6-84 2 Page TS / B 3.6-85 4 Page TS / B 3.6-86 through TS / B 3.6-87a 2 Page TS / B 3.6-88 3 Page TS / B 3.6-89 2 Page TS / B 3.6-90 3 Pages TS / B 3.6-91 through TS / B 3.6-95 1 Page TS / B 3.6-96 2 Pages TS / B 3.6-97 and TS / B 3.6-98 1 Page TS / B 3.6-99 2 Page TS / B 3.6-99a 0 Pages TS / B 3.6-100 and TS / B 3.6-101 1 Pages TS / B 3.6-102 and TS / B 3.6-103 2 Page TS / B 3.6-104 3 Page TS / B 3.6-105 2 Page TS / B 3.6-106 3 B 3.7 PLANT SYSTEMS BASES Pages TS / B 3.7-1 through TS / B 3.7-6 2 Page TS / B 3.7-6a 2 Pages TS / B 3.7-6b and TS / B 3.7-6c 0 Page TS / B 3.7-7 2 Page TS / B 3.7-8 1 Pages B 3.7-9 through B 3.7-11 0 Pages TS / B 3.7-12 and TSI B 3.7-13 1 Pages TS / B 3.7-14 through TS / B 3.7-18 Page TS / B 3.7-18a " 0 Pages TS / B 3.7-19 through TS / B 3.7-26 1 Pages B 3.7-24 through B 3.7-26 0 Pages TS-/ B 3.7-27 through TS / B 3.7-29 2 Page TS / B 3.7-30 1 Pages B 3.7-31 through B 3.7-33 0 B 3.8 ELECTRICAL POWER SYSTEMS BASES Pages B 3.8-1 through B 3.8-3 0 Page TS / B 3.8-4 1 Pages TS / B 3.8-4a and TS / B 3.8-4b 0 Pages TS / B 3.8-5 and Page TS / B 3.8-6 1 Pages B 3.8-7 and B 3.8-8 0 Page TS / B 3.8-9 2 Pages TS / B 3.8-10 and TS / B 3.8-11 1 Pages B 3.8-12 through B 3.8-18 0 SUSQUEHANNA - UNIT 2 TS / B LOES-6 Revision 85

SUSQUEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)

Section Title Revision Page TS / B 3.8-19 1 Pages B 3.8-20 through B 3.8-22 0 Page TS / B 3.8-23 1 Page B 3.8-24 0 Pages TS / B 3.8-25 and TS / B 3.8-26 1 Pages B 3.8-27 through B 3.8-37 0 Page TS / B 3.8-38 1 Pages TS / B 3.8-39 through TS / B 3.8-55 0 Pages TS / B 3.8-56 through TS / B 3.8-64 2 Page TS / B 3.8-65 3 Page TS / B 3.8-66 4 Pages TS / B 3.8-67 and TS / B 3.8-68 3 Page TS / B 3.8-69 4 Pages TS / B 3.8-70 through TS / B 3.8-83 1 Pages TS / B 3.8-83A through TS / B 3.8-83D 0 Pages B 3.8-84 through B 3.8-85 0 Page TS / B 3.8-86 1 Page TS / B 3.8-87 2 Pages TS / B 3.8-88 through TS / B 3.8-93 1 Pages B 3.8-94 through B 3.8-99 0 B 3.9 REFUELING OPERATIONS BASES Pages TS / B 3.9-1 and TS / B 3.9-2 1 Page TS / B 3.9-2a 1 Pages TS / B 3.9-3 and TS / B 3.9-4 1-Pages B 3.9-5 through B 3.9-30 0 B 3.10 SPECIAL OPERATIONS BASES Page TS / B 3.10-1 1 Pages B 3.10-2 through B 3.10-32 0 Page TS -B 3.10-33 2 Page B 3.10-34 0 Page B 3.10-35 1 Pages B 3.10-36 and B 3.10-37 0 Page B 3.10-38 1 Page TS / B 3.10-39 2 LDCN 4473 TSB2 Text LOES.doc 4/5/07 SUSQUEHANNA - UNIT 2 TS / B LOES-7 Revision 85

PPL Rev. 5 PAM Instrumentation B 3.3.3.1 B 3.3 INSTRUMENTATION B 3.3.3.1 Post Accident Monitoring (PAM) Instrumentation BASES BACKGROUND The primary purpose of the PAM instrumentation is to display plant variables that provide information required by the control room operators during accident situations. This information provides the necessary support for the operator to take the manual actions for which no automatic control is provided and that are required for safety systems to accomplish their safety functions for Design Basis Events.

The instruments that monitor these variables are designated as Type A, Category I, and non-Type A, Category I, in accordance with Regulatory Guide 1.97 (Ref. 1).

The OPERABILITY of the accident monitoring instrumentation ensures that there is sufficient information available on selected plant parameters to monitor and assess plant status and behavior following an accident. This capability is consistent with the recommendations of Reference 1.

APPLICABLE The PAM instrumentation LCO ensures the OPERABILITY of SAFETY ANALYSES Regulatory Guide 1.97, Type A variables so that the control room operating staff can: . ..

Perform the diagnosis specified in the Emergency Operating Procedures (EOPs). These variables are restricted to preplanned actions for the primary success path of Design Basis Accidents (DBAs), (e.g., loss of coolant accident (LOCA)), and

" Take the specified, preplanned, manually controlled actions for which no automatic control is provided, which are required for safety systems to accomplish their safety function.

The PAM instrumentation LCO also ensures OPERABILITY of Category I, non-Type A, variables so that the control room operating staff can:

Determine whether systems important to safety are performing their intended functions; (continued)

SUSQUEHANNA-UNIT2 TS / B 3.3-64 Revision 2

PPL Rev. 5 PAM Instrumentation B 3.3.3.1 BASES APPLICABLE 0 Determine the potential for causing a gross breach of the barriers SAFETY ANALYSES to radioactivity release; (continued)

Determine whether a gross breach of a barrier has occurred; and

" Initiate action necessary to protect the public and for an estimate of the magnitude of any impending threat.

The plant specific Regulatory Guide 1.97 Analysis (Ref. 2 and 3) documents the process that identified Type A and Category I, non-Type A, variables.

Accident monitoring instrumentation that satisfies the definition of Type A in Regulatory Guide 1.97 meets Criterion 3 of the NRC Policy Statement. (Ref. 4) Category I, non-Type A, instrumentation is retained in Technical Specifications (TS) because they are intended to assist operators in minimizing the consequences of accidents. Therefore, these Category I variables are important for reducing public risk.

LCO LCO 3.3.3.1 requires two OPERABLE channels for all but one Function to ensure that no single failure prevents the operators from being presented with the information necessary to determine the status of the plant and to bring the plant to, and maintain- it in, a safe condition followirng that accident... . ...

Furthermore, provision of two (hannels allows a CHANNEL CHECK during the post accident phase to confirm the validity of displayed information.

The exception to the two channel requirement is primary containment isolation valve (PCIV) position. In this case, the important information is the status of the primary containment penetrations. The LCO requires one position indicator for each active PCIV. This is sufficient to redundantly verify the isolation status of each isolable penetration either via indicated status of the active valve and prior knowledge of passive valve or via system boundary (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.3-65 Revision 2

PPL Rev. 5 PAM Instrumentation B 3.3.3.1 BASES LCO status. If a normally active PCIV is known to be closed and (continUed) deactivated, position indication is not needed to determine status.

Therefore, the position indication for valves in this state is not required to be OPERABLE.

The following list is a discussion of the specified instrument Functions listed in Table 3.3.3.1-1 in the accompanying LCO. Table B3.3.3.1-1 provides a listing of the instruments that are used to meet the operability requirements for the specific functions.

1. Reactor Steam Dome Pressure Reactor steam dome pressure is a Type A, Category 1, variable provided to support monitoring of Reactor Coolant System (RCS) integrity and to verify operation of the Emergency Core Cooling Systems (ECCS). Two independent pressure channels, consisting of three wide range control room indicators and one wide range control room recorder per channel with a range of 0 psig to 1500 psig, monitor pressure. The wide range recorders are the primary method of indication available for use by the operators during an accident, therefore, the PAM Specification deals specifically with this portion of the -instrument channel. -

2. Reactor Vessel Water Level Reactor vessel water level is a Type A, Category 1, variable provided to support monitoring of core cooling and to verify operation of the ECCS. A combination of three different level instrument ranges, with two independent channels each, monitor Reactor Vessel Water Level.

The extended range instrumentation measures from -150 inches to 180 inches and outputs to three control room level indicators per channel. The wide range instrumentation measures from -150 inches to 60 inches and outputs to one control room recorder and three control room indicators per channel. The fuel zone range instrumentation measures from -310 inches to -110 inches and outputs to a control room recorder (one channel) and a control room indicator (one channel). These three ranges of instruments combine to provide level indication from the bottom of the Core to above the main steam line. The wide range level recorders, the fuel zone level indicator and level recorder, and one inner ring extended range level indicator per channel are the primary method of indication available for use by the operator during an accident, therefore the PAM (continued)

SUSQUEHANNA-UNIT2 TS / B 3.3-66 Revision 4

PPL Rev. 5 PAM Instrumentation B 3.3.3.1 BASES LCO 2. Reactor Vessel Water Level (continued)

Specification deals specifically with this portion of the instrument channel.

3. Suppression Chamber Water Level Suppression chamber water level is a Type A, Category 1, variable provided to detect a breach in the reactor coolant pressure boundary (RCPB). This variable is also used to verify and provide long term surveillance of ECCS function. A combination of two different level instrument ranges, with two independent channels each, monitor Suppression chamber water level. The wide range instrumentation measures from the ECCS suction lines to approximately the top of the chamber and outputs to one control room recorder per channel. The wide range recorders are the primary method of indication available for use by the operator during an accident, therefore the PAM Specification deals specifically with this portion of the instrument channel.

4. Primary Containment Pressure Primary Containment pressure is a Type A, Category 1, variable provided to detect a breach of the RCPB and to verify ECCS functions that operate to maintain RCS integrity. A combination of two-different pressure instrument ranges, with two independent channels each, monitor primary containment pressure. The LOCA range measures from -15 psig to 65 psig and outputs to one control room recorder per channel. The accident range measures from 0 psig to 250 psig and outputs to one control room recorder per channel (same recorders as the LOCA range). The recorders (both ranges) are the primary method of indication available for use by the operator during an accident, therefore the PAM Specification deals specifically with this portion of the instrument channel.

5. Primary Containment High Radiation Primary containment area radiation (high range) is provided to monitor the potential of significant radiation releases (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.3-67 Revision 3

PPL Rev. 5 PAM Instrumentation B 3.3.3.1 BASES LCO 5. Primary Containment Hiqh Radiation (continued) and to provide release assessment for use by operators in determining the need to invoke site emergency plans. Two independent channels, which output to one control room recorder per channel with a range of 100 to 1X1 08 R/hr, monitor radiation. The PAM Specification deals specifically with this portion of the instrument channel.

6. Primary Containment Isolation Valve (PCIV) Position PCIV position is provided for verification of containment integrity. In the case of PCIV position, the important information is the isolation status of the containment penetration. The LCO requires a channel of valve position indication in the control room to be OPERABLE for an active PCIV in a containment penetration flow path, i.e., two total channels of PCIV position indication for a penetration flow path with two active valves. For containment penetrations with only one active PCIV having control room indication, Note (b) requires a single channel of valve position indication to be OPERABLE. This is sufficient to redundantly verify the isolation status of each isolable penetration via indicated status of the active valve, as applicable, and prior knowledge of passive valve or system boundary status. If a penetration flow path is isolated, position indication for the PCIV(s) in the associated penetfation flow path is not needed to determine status. Therefore, the position indication for valves in an isolated penetration flowpath is not required to be OPERABLE. Those valves which require position indication are specified in Table B 3.6.1.3-1. Furthermore, the loss of position indication does not necessarily result in the PCIV being inoperable.

The PCIV position PAM instrumentation consists of position switches unique to PCIVs, associated wiring and control room indicating lamps (not necessarily unique to a PCIV) for active PCIVs (check valves and manual valves are not required to have position indication). Therefore, the PAM Specification deals specifically with these instrument channels.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.3-68 Revision 4

PPL Rev. 5 PAM Instrumentation B 3.3.3.1 BASES LCO 7. Neutron Flux (continued)

Wide range neutron flux is a Category I variable provided to verify reactor shutdown. The Neutron Monitoring System Average Power Range Monitors (APRM) provides reliable neutron flux measurement from 0% to 125% of full power. The APRM consists of four channels each with their own chassis powered with redundant power supplies.

The APRM sends signals to the analog isolator module which in turn sends individual APRM signals to the recorders used for post accident monitoring. The PAM function for neutron flux is satisfied by having two channels of APRM provided for post accident monitoring. The PAM Specification deals specifically with this portion of the instrument channel.

The Neutron Monitoring System (NMS) was evaluated against the criteria established in General Electric NEDO-31558A to ensure its acceptability for post-accident monitoring. NEDO-31558A provides alternate criteria for the NMS to meet the post-accident monitoring guidance of Regulatory Guide 1.97. Based on the evaluation, the NMS was found to meet the criteria established in NEDO-31558A.

The APRM sub-function of the NMS is used to provide the Neutron Flux monitoring identified in TS 3.3.3.1 (Ref. 5 and 6).

8. Not Used.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.3-69 Revision 5

PPL Rev. 5

.PAM Instrumentation B 3.3.3.1 BASES LCO 9. Drywell Atmosphere Temperature (continued)

Drywell atmosphere temperature is a Category I variable provided to verify RCS and containment integrity and to verify the effectiveness of ECCS actions taken to prevent containment breach. Two independent temperature channels, consisting of two control room recorders per channel with a range of 40 to 440 degrees F, monitor temperature.

The PAM Specification deals specifically with the inner ring temperature recorder portion of the instrument channel.

10. Suppression Chamber Water Temperature Suppression Chamber water temperature is a Type A, Category 1, variable provided to detect a condition that could potentially lead to containment breach and to verify the effectiveness of ECCS actions taken to prevent containment breach. The suppression chamber water temperature instrumentation allows operators to detect trends in suppression chamber water temperature in sufficient time to take action to prevent steam quenching vibrations in the suppression pool.

Two channels are required to be OPERABLE. Each channel consists of eight sensors of which a minimum of four sensors (one sensor in each quadrant) must be OPERABLE to consider a channel OPERABLE. The outputs for the temperature sensors are displayed on tw6 independent indicators in the control room and recorded 6n the monitoring unitslocated on control room panel 2C60-1. The temperature indicators are the primary method of indication-available for use by the operator during an accident, therefore the PAM Specification deals specifically with this portion of the instrument channel.

APPLICABILITY The PAM instrumentation LCO is applicable in MODES 1 and 2.

These variables are related to the diagnosis and preplanned actions required to mitigate DBAs. The applicable DBAs are assumed to occur in MODES 1 and 2. In MODES 3, 4, and 5, plant conditions are such that the likelihood of an event that would require PAM instrumentation is extremely low; therefore, PAM instrumentation is not required to be OPERABLE in these MODES.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.3-70 Revision 4

PPL Rev. 5 PAM Instrumentation B 3.3.3.1 BASES (continued)

ACTIONS A Note has been provided to modify the ACTIONS related to PAM 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 PAM instrumentation channels provide appropriate compensatory measures for separate Functions. As such, a Note has been provided that allows separate Condition entry for each inoperable PAM Function.

A.1 When one or more Functions have one required channel that is inoperable, the required inoperable channel must be restored to OPERABLE status within 30 days. The 30 day Completion Time is based on operating experience and takes into account the remaining OPERABLE channels, the passive nature of the instrument (no critical automatic action is assumed to occur from these instruments), and the low-probability of an event requiring PAM instrumentation during this interval.

B.1 If a channel has not been rest6red to OPERABLE status in 30 days, this Required Action specifies initiation of action in accordance with Specification 5.6.7, which requires a written report to be submitted to the NRC. This report discusses the results of the root cause evaluation of the inoperability and identifies proposed restorative actions.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.3-71 Revision 3

PPL Rev. 5 PAM Instrumentation B 3.3.3.1 BASES ACTIONS B.1 (continued)

This action is appropriate in lieu of a shutdown requirement because alternative actions are identified before the written report is submitted to the NRC, and given the likelihood of plant conditions that would require information provided by this instrumentation.

C.1 When one or more Functions have two required channels that are inoperable (i.e., two channels inoperable in the same Function), one channel in the Function should be restored to OPERABLE status within 7 days. The Completion Time of 7 days is based on the relatively low probability of an event requiring PAM instrument operation and the availability of alternate means to obtain the required information. Continuous operation with two required channels inoperable in a Function is not acceptable because the alternate indications may not fully meet all performance qualification requirements applied to the PAM instrumentation. Therefore, requiring restoration of one inoperable channel of the Function limits the risk that the PAM Function will be in a degraded condition should an accident occur.

D.1 This Required Action directs entry into the appropriate Condition referenced in Table 3.3.3.1-1:.-The applicable Condition referenced in the Table is Function dependent. Each time an inoperable channel has not met any Required Action of Condition-C, as applicable, and the associated Completion Time has expired, Condition D is entered for that channel and provides for transfer to the appropriate subsequent Condition.

E.1 For the majority of Functions in Table 3.3.3.1-1, if any Required Action and associated Completion Time of Condition C are not met, the plant must be brought to a MODE in which the LCO not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.3-72 Revision 2

PPL Rev. 5 PAM Instrumentation B 3.3.3.1 BASES ACTIONS E.1 (continued) from full power conditions in an orderly manner and without challenging plant systems.

F. 1 Since alternate means of monitoring primary containment area radiation have been developed and tested, the Required Action is not to shut down the plant, but rather to follow the directions of Specification 5.6.7. These alternate means will be temporarily installed if the normal PAM channel cannot be restored to OPERABLE status within the allotted time. The report provided to the NRC should discuss the alternate means used, describe the degree to which the alternate means are equivalent to the installed PAM channels, justify the areas in which they are not equivalent, and provide a schedule for restoring the normal PAM channels.

SURVEILLANCE The following SRs apply to each PAM instrumentation Function in REQUIREMENTS Table 3.3.3.1-1.

SR-3.3.3.1.1 Performance of the CHANNEL CHECK once every_31 days ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel against 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 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 between 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 (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.3-73 Revision 2

PPL Rev. 5 PAM Instrumentation B 3.3.3.1 BASES SURVEILLANCE SR 3.3.3.1.1 (continued)

REQUIREMENTS 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, and does not necessarily indicate the channel is Inoperable.

The Frequency of 31 days is based upon plant operating experience, with regard to channel OPERABILITY and drift, which demonstrates that failure of more than one channel of a given Function in any 31 day interval is rare. The CHANNEL CHECK supplements less formal checks of channels during normal operational use of those displays associated with the required channels of this LCO.

SR 3.3.3.1.2 and SR 3.3.3.1.3 A CHANNEL CALIBRATION is performed every 24 months except for the PCIV Position Function. The PCIV Position Function is adequately demonstrated by the Remote Position Indication performed in accordance with 5.5.6, "Inservice Testing Program". CHANNEL CALIBRATION verifies that the channel responds to measured parameter with the necessary range and accuracy, and does not include alarms.

The CHANNEL CALIBRATION for the Containment High- Radiation instruments shall consist of an electronic calibration of the channel, not including the detector, for range decades above 10 R/hr and a one point calibration check of the detector below 10 R/hr with an- installed or portable gamma source.

The Frequency is based on operating experience and for the 24 month Frequency consistency with the industry refueling cycles.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.3-74 Revision 3

PPL Rev. 5 PAM Instrumentation B 3.3.3.1 BASES (continued)

REFERENCES 1. Regulatory Guide 1.97 Rev. 2, "Instrumentation for Light Water Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident," February 6, 1985.

2. Nuclear Regulatory Commission Letter A. Schwencer to N. Curtis, Emergency Response Capability, Conformance to R.G. 1.97, Rev. 2, dated February 6, 1985.

3. PP&L Letter (PLA-2222), N. Curtis to A. Schwencer, dated May 31, 1984.

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

5. NEDO-31558A, BWROG Topical Report, Position on NRC Reg.

Guide 1.97, Revision 3 Requirements for Post Accident Neutron Monitoring System (NMS).

6. Nuclear Regulatory Commission Letter from C. Poslusny to R.G.

Byram dated July 3, 1996.

SUSQUEHANNA - UNIT 2 TS / B 3.3-75 Revision 2

PPL Rev. 5 PAM Instrumentation B 3.3.3.1 TABLE B 3.3.3.1-1 Post Accident Instruments (Page 1 of 3)

Instrument/Variable Element Transmitter Recorder Indicator

1. Reactor Steam N/A PT-24201 A UR-24201A PI-24202A Dome Pressure (Red)* PI-24202A1 PI-24204A N/A PT-24201 B UR-24201 B PI-24202B (left side)

(Red)* PI-24202B1 (left side)

PI-24204B (left side)

2. Reactor Vessel N/A LT-24201A UR-24201A LI-24201A (left side)

Water Level (Wide Range) (Blue)* LI-24201A1 (left side)

LI-24203A (left side)

N/A LT-24201B UR-24201A LI-24201 B (left side)

(Wide Range) (Blue)* LI-24201 B1 (left side)

LI-24203B (left side)

N/A LT-24203A N/A LI-24201A (right side)*(')

(Extended Range) LI-24201A1 (right side)

LI-24203A (right side)

N/A LT-24203B N/A LI-24201 B (right side)*0)

(Extended Range) LI-24201 B1 (right side)

LI-24203B (right side)

N/A LT-24202A UR-24201 A N/A (Fuel Zone Range) (Bfown)*

N/A LT-24202B UR-24201 B (Fuel Zone Range) (Brown)*

3. Suppression N/A LT-25776A UR-25776A N/A Chamber Water Level (Wide Range) (Red)*

N/A LT-25776B UR-25776B N/A (Wide Range) (Red)*

N/A LT-25775A UR-25776A LI-25775A (Narrow Range) (Blue)

N/A LT-25775B UR-25776B LI-25775B (Narrow Range) (Blue)

SUSQUEHANNA - UNIT 2 TS / B 3.3-75a Revision 5

PPL Rev. 5 PAM Instrumentation B 3.3.3.1 TABLE B 3.3.3.1-1 Post Accident Instruments (Page 2 of 3)

Instrument/Variable Element Transmitter Recorder Indicator

4. Primary N/A PT-25709A UR-25701A (Dark Blue)* N/A Containment Pressure (0 to 250 psig)

N/A PT-25709B UR-25701B (Dark Blue)* N/A (0 to 250 psig)

N/A PT-25710A UR-25701A (Red)- N/A

(-15 to 65 psig)

N/A PT-25710B UR-25701 B (Red)* N/A

(-15 to 65 psig)

5. Primary Containment RE-25720A RITS-25720A UR-25776A N/A High Radiation (Green)*

RE-25720B RITS-25720B UR-25776B N/A (Green)*

6. PCIV Position See Technical Specification Bases Table B 3.6.1.3-1 for PCIV that require position indication to be OPERABLE

7. Neutron Flux -N/A APRM-1 NR-C51-2R603A N/A (red pen)*

N/A APRM-2 NR-C51-2R603B ---- "- N/A (red pen)*

N/A APRM-3 NR-C51-2R603C N/A (red pen)*

N/A APRM-4 NR-C51-2R603D N/A

_(red pen)*

8. Containment AE-25745A AT-25745A UR-25701A (Blue Violet)* N/A Oxygen and (Hydrogen) UR-25701A (Violet)*

Hydrogen Analyzer AE-25745B AT-25745B UR-25701 B (Blue Violet)*

N/A (Hydrogen) UR-25701 B (Violet)*

AE-25746A AT-25746A UR-25701A (Orange)* N/A (Oxygen)

AE-25746B AT-25746B UR-25701 B (Orange)* N/A (Oxygen)

SUSQUEHANNA - UNIT 2 TS / B 3.3-75b Revision 5

PPL Rev. 5 PAM Instrumentation B 3.3.3.1 TABLE B 3.3.3.1-1 Post Accident Instruments (Page 3 of 3)

Instrument/Variable Element Transmitter Recorder Indicator

9. Drywell Atmosphere TE-25790A TT-25790A UR-25701A (Brown)* N/A Temperature TR-25790A (point # 1)

TE-257908 TT-25790B UR-25701B (Brown)* N/A TR-25790B (point # 1)

10. Suppression Chamber TE-25753 TX-25751 TIAH-25751* TI-25751 Water Temperature TE-25755 TE-25757 TE-25759 TE-25763 TE-25765 TE-25767 TE-25769 TE-25752 TX-25752 TIAH-25752* TI-25752 TE-25754 TE-25758 TE-25760 TE-25762 TE-25766 TE-25768 TE-25770 Indicates that the instrument (and associated components in the instrument channel) is considered as instrument channel surveillance acceptance criteria.

(1) In the case of the inner ring indicators for extended range level, it is recommended that LI-24201A and LI-24201B be used as acceptance criteria, however LI-24201A1, LI-24201B1, LI-24203A. or LI-24203B may be used in their place provided that surveillance requirements are satisfied. Only one set of these instruments needs to be OPERABLE.

SUSQUEHANNA - UNIT 2 TS / B 3.3-75c Revision 5

PPL Rev. 2 RCS PIV Leakage B 3.4.5 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.5 RCS Pressure Isolation Valve (PIV) Leakage BASES BACKGROUND The function of RCS PlVs is to separate the high pressure RCS from an attached low pressure system. This protects the RCS pressure boundary described in 10 CFR 50.2, 10 CFR 50.55a(c), and GDC 55 of 10 CFR 50, Appendix A (Refs. 1, 2, and 3). RCS PIVs are defined as any two normally closed valves in series within the reactor coolant pressure boundary (RCPB). PIVs are designed to meet the requirements of Reference 4. During their lives, these valves can produce varying amounts of reactor coolant leakage through either normal operational wear or mechanical deterioration.

The RCS PIV LCO allows RCS high pressure operation when leakage through these valves exists in amounts that do not compromise safety.

The PIV leakage limit applies to each individual valve. Leakage through these valves is not included in any allowable LEAKAGE specified in LCO 3.4.4, "RCS Operational LEAKAGE."

Although this specification provides a limit on allowable PIV leakage rate, its main purpose is to prevent overpressure failure of the low pressure portions of connecting systems. The leakage limit is an indication that the PIVs between the RCS and the connecting systems are degraded or degrading. PIV leakage could lead to overpressure-ofthe low pre-esure piping or components. Failure consequences could be a loss of coolant accident (LOCA) outside of containment, an unanalyzed event that could degrade the ability for low pressure injection.

A study (Ref. 5) evaluated various PIV configurations to determine the probability of intersystem LOCAs. This study concluded that periodic leakage testing of the PIVs can substantially reduce intersystem LOCA probability.

(continued)

SUSQUEHANNA - UNIT 2 B 3.4-24 Revision 0

PPL Rev. 2 RCS PIV Leakage B 3.4.5 BASES BACKGROUND PIVs are provided to isolate the RCS from the following typically (continued) connected systems:

a. Residual Heat Removal (RHR) System; and

b. Core Spray System.

The PIVs are listed in Table B 3.4.5-1 "Pressure Isolation Valve".

APPLICABLE Reference 5 evaluated various PIV configurations, leakage testing of the SAFETY valves, and operational changes to determine the effect on the probability ANALYSES of intersystem LOCAs. This study concluded that periodic leakage testing of the PIVs can substantially reduce the probability of an intersystem LOCA.

PIV leakage is not considered in any Design Basis Accident analyses.

This Specification provides for monitoring the condition of the RCPB to detect PIV degradation that has the potential to cause a LOCA outside of containment. RCS PIV leakage satisfies Criterion 2 of the NRC Policy Statement (Ref. 6).

LCO RCS PIV leakage is-leakage into closed systems connected'to the RCS.

Isolation valve leakage is usually on the order of dr0p. 1ier minute.

Leakage that increases significantly suggests that something is operationally wrong and corrective action must be taken. Violation of this LCO could result in continued degradation of a PIV, which could lead to overpressurization of a low pressure system and the loss of the integrity of a fission product barrier.

The LCO PIV leakage limit is 0.5 gpm per nominal inch of valve size with a maximum limit of 5 gpm (Ref. 4).

APPLICABILITY In MODES 1, 2, and 3, this LCO applies because the PIV leakage potential is greatest when the RCS is pressurized. In MODE 3, valves in the RHR shutdown cooling flow path are not required to meet the requirements of this LCO when in, (continued)

SUSQUEHANNA- UNIT2 B 3.4-25 Revision 0

PPL Rev. 2 RCS PIV Leakage B 3.4.5 BASES APPLICABILITY or during transition to or from, the RHR shutdown cooling mode of (continued) operation. This is because RHR shutdown cooling will be placed in operation only below the current pressure permissive setpoint when the high to low pressure interface does not exist.

in MODES 4 and 5, leakage limits are not provided because the lower reactor coolant pressure results in a reduced potential for leakage and for a LOCA outside the containment. Accordingly, the potential for the consequences of reactor coolant leakage is far lower during these MODES.

ACTIONS The ACTIONS are modified by two Notes. Note 1 has been provided to modify the ACTIONS related to RCS PIV flow paths. Section 1.3, Completion Times, specifies 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 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 the Condition of RCS PIV leakage limits exceeded provide appropriate compensatory measures for separate affected RCS PIV flow paths. As such, a Note has been provided that allows separate Condition entry for each affected RCS PIV flow path. -Note 2 requitres an evaluation of affected systems if a PIV is inoperable. The leakage may have affected system OPERABILITY, or isolation of a leaking flow path with an alternate valve may have degraded the ability of the interconnected system to perform its safety function. As a result, the applicable Conditions and Required Actions for systems made inoperable by PIVs must be entered. This ensures appropriate remedial actions are taken, if necessary, for the affected systems.

A.1 If leakage from one or more RCS PIVs is not within limit, the flow path must be isolated by at least one closed manual, deactivated automatic, or check valve within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

(continued)

SUSQUEHANNA - UNIT 2 B 3.4-26 Revision 0

PPL Rev. 2 RCS PIV Leakage B 3.4.5 BASES ACTIONS A.1 (continued)

Required Action A.1 is modified by a Note stating that the valves used for isolation must meet the same leakage requirements as the PIVs and must be on the RCPB or the high pressure portion of the system.

Four hours provides time to reduce leakage in excess of the allowable limit and to isolate the flow path if leakage cannot be reduced while corrective actions to reseat the leaking PIVs are taken. The 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months allows time for these actions and restricts the time of operation with leaking valves.

B.1 and B.2 If leakage cannot be reduced or the system isolated, 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 MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . This action may reduce the leakage and also reduces the potential for a LOCA outside the containment. The Completion Times are reasonable, based on operating experience, to achieve the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.4.5.1 REQUIREMENTS Performance of leakage testing on each RCS PIV is required to verify that leakage is below the specified limit and to identify each leaking valve.

The leakage limit of 0.5 gpm per inch of nominal valve diameter up to 5 gpm maximum applies to each valve. Leakage testing requires a stable pressure condition. For the two PIVs in series, the leakage requirement applies to each valve individually and not to the combined leakage across both valves. If the PIVs are not individually leakage tested, one valve may have failed completely and not be detected if the other valve in series meets the leakage requirement. In this situation, the protection provided by redundant valves would be lost.

(continued)

SUSQUEHANNA - UNIT 2 B 3.4-27 Revision 0

PPL Rev. 2 RCS PIV Leakage B 3.4.5 BASES SURVEILLANCE SR 3.4.5.1 (continued)

REQUIREMENTS The 24 month Frequency required by the Inservice Testing Program is within the ASME OM Code Frequency requirement and is based on the need to perform this Surveillance during an outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

This SR is modified by a Note that states the leakage Surveillance is not required to be performed in MODE 3. Entry into MODE 3 is permitted for leakage testing at high differential pressures with stable conditions not possible in the lower MODES.

REFERENCES 1. 10 CFR 50.2.

2. 10 CFR 50.55a(c).

3. 10 CFR 50, AppendixA, GDC 55.

4. ASME Operation and Maintenance Code.

5. NUREG&0677, May 1980.

6. Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 39132).

SUSQUEHANNA - UNIT 2 TS / B 3.4-28 Revision 1

PPL Rev. 2 RCS PIV Leakage B 3.4.5 BASES (continued)

TABLE B 3.4.5-1 REACTOR COOLANT SYSTEM PRESSURE ISOLATION VALVES 1st Isolation 2nd Isolation Valve(s) Number(s) Valve(s) Number(s) Service HV-252F006A HV-252F005A Core Spray Injection HV-252F037A HV-252F006B HV-252F005B Core Spray Injection HV-252F037B HV-251F050A HV-251F015A LPCI Injection HV-251F122A 251130 HV-251 F050B HV-251 F01 5B LPCI Injection HV-251F122B 251130 HV-251 F022 HV-251 F023 Head Spray HV-251 F009 HV-251 F008 Shutdown Cooling SUSQUEHANNA- UNIT 2 TS / B 3.4-29 Revision 2

PPL Rev. 6 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 PCIVs, in combination with other accident mitigation systems, 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 DBA.

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 DBA 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 systerms-are dis6usýsed 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 H2 0 2 Analyzers, the lines, up to and including the first normally closed valves within the H 20 2 (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.6-15 Revision 3

PPL Rev. 6 PCIVs B 3.6.1.3 BASES BACKGROUND Analyzer panels, are extensions of primary containment (continued) (i.e., closed system), and are required to be leak rate tested in accordance with the Leakage Rate Test Program. The H20 2 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 H20 2 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).

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 1 E 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 H20 2 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 valves to permit testing of PASS in Modes 1, 2, and 3 is permitted in accordance with TRO 3.6.4.

Each H20 2 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 H20 2 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.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.6-15a Revision 0

PPL Rev. 6 PCIVs B 3.6.1.3 BASES BACKGROUND The drywell vent and purge lines are 24 inches in diameter; (continued) 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 line containment penetrations

{X-13A(B)}are provided with a normally closed gate valve

{HV-251F015A(B)} and a normally open globe valve

{HV-251F017A(B)} outside containment and a testable check valve {HV-251 F050A(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.

The design of these containment penetrations is unique in that some 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 -

HV-251 FO.-5A(B) and the closed system outside containment are the only barriers tested in accordance with the Leakage Rate Test Program. Since these containment penetrations {X-13A and X-13B} include a containment isolation valve outside containment that is tested in accordance with 10 CFR-50 Appendix J require-ments and a closed system outside containment that meets the requirements of USNRC Standard Review Plan 6.2.4 (September 1975), paragraph 11.3.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-251 F122A(B), and HV-251 F01 5A(B) valves are used to meet this requirement and are tested in accordance with the pressure test program.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.6-15b Revision 2

PPL Rev. 6 PCIVs B 3.6.1.3 BASES APPLICABLE The PCIVs LCO was derived from the assumptions related SAFETY ANALYSES to minimizing the loss of reactor coolant inventory, and establishing the 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 (including primary containment purge valves) are minimized. Of the events analyzed in Reference 1, the MSLB is the most limiting event due to radiological consequences. The closure time of the main steam isolation valves (MSIVs) 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.

The DBA analysis assumes that within the required isolation-time leakage is terminated, except for the tMaximum allowable leakage rate, La. I The single failure criterion required to be imposed in the conduct of unit safety analyses was considered inthe 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 Note 2 of SR 3.6.1.3.1. In this case, the single failure criterion remains applicable to the primary containment purge valve (continued)

SUSQUEHANNA- UNIT 2 TS / B 3.6-16 Revision 1

PPL Rev. 6 PCIVs B 3.6.1.3 BASES APPLICABLE due to failure in the control circuit associated with each SAFEETY ANALYSIS valve. The primary containment purge valve design precludes (continued) a single failure from compromising the primary containment boundary as long as the system is operated in accordance with this LCO.

Both H20 2 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 H 2 0 2 Analyzer penetrations is satisfied by virtue of the combination of the associated PCIVs and the closed system formed by the H20 2 Analyzer piping system as discussed in the BACKGROUND section above.

The closed system boundary between PASS and the H20 2 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 H20 2 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.-170.

PCIVs satisfy Criterion 3 of the NRC Policy Statement. (Ref. 2)

LCO PCIVs form a part of the primary containment boundary. The PCIV safety function is related to minimizing the loss of reactor coolant inventory and establishing the primary containment boundary during a DBA.

The power operated, automatic isolation valves are required to have isolation times within limits and actuate on an (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.6-17 Revision 2

PPL Rev. 6 PCIVs B 3.6.1.3 BASES LCO automatic isolation signal. The valves covered by this (continued) LCO are listed in Table B 3.6.1.3-1.

The normally closed 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.

Purge valves with resilient seals, secondary containment bypass valves, MSIVs, 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.

APPLICABILITY In MODES 1, 2, and 3, a DBA 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,. most PCIVs are not required to be . . .

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.6-17a Revision 0

PPL Rev. 6 PCIVs B 3.6.1.3 BASES APPLICABILITY OPERABLE and the primary containment purge valves are (continued) not required to be closed in MODES 4 and 5. Certain valves, however, are required to be OPERABLE to prevent inadvertent reactor vessel draindown. These valves are those whose associated instrumentation is required to be OPERABLE per LCO 3.3.6.1, "Primary Containment Isolation Instrumentation."

(This does not include the valves that isolate the associated instrumentation.)

ACTIONS The ACTIONS are modified by a Note allowing penetration flow path(s) to be unisolated intermittently 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 With one or more penetration flow paths with one PCIV inoperable except for purge valve leakage not within limit, (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.6-18 Revision 1

PPL Rev. 6 PCIVs B 3.6.1.3 BASES ACTIONS A.1 and A.2 (continued) 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 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time (8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months for main steam lines). The Completion Time of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months 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 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time is allowed. The Completion Time of 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months for the main steam lines allows a period of time to restore the MSIVs 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.

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 Jonqer.

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 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.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.6-19 Revision 1

PPL Rev. 6 PCIVs B 3.6.1.3 BASES ACTIONS A.1 and A.2 (continued)

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 H20 2 Analyzer penetrations. For penetration flow paths with one PCIV, Condition C provides the appropriate Required Actions. For the H 2 0 2 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 With 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 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The method of isolation must include the use of at least one isolation barrier that

-cannotbe 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 blindflange.__ The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 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 H20 2 Analyzer penetrations. For penetration flow paths with one PCIV, Condition C provides the appropriate Required Actions. For the H20 2 Analyzer penetrations, Condition D provides the appropriate Required Actions.

C. 1 and C.2 With one or more penetration flow paths with one PCIV inoperable, the inoperable valve must be restored to (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.6-20 Revision 2

PPL Rev. 6 PCIVs B 3.6.1.3 BASES ACTIONS C.1 and C.2 (continued)

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 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time. The Completion Time of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 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 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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.

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 H 2 0 2 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 (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.6-21 Revision 3

PPL Rev. 6 PCIVs B 3.6.1.3 BASES ACTIONS C.1 and C.2 (continued) 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 H 2 0 2 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 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time. The Completion Time of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is reasonable considering the unique design of the H 2 0 2 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 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 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.

When an H20 2 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.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.6-21 a Revision 0

PPL Rev. 6 PCIVs B 3.6.1.3 BASES ACTIONS D.1 and D.2 (continued)

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 H 2 0 2 Analyzer penetrations.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.6-21 b Revision 0

PPL Rev. 6 PCIVs B 3.6.1.3 BASES ACTIONS E. 1 (continued)

With 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 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . 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 lesser actual pathway leakage of the two devices. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months 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.

F. 1 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 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 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.

G.1 and G.2 If any Required Action and associated Completion Time cannot be met in MODE 1, 2, or 3, 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 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . 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.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.6-22 Revision 2

PPL Rev. 6 PCIVs B 3.6.1.3 BASES ACTIONS H.1 and H.2 (continued)

If any Required Action and associated Completion Time cannot be met, the unit must be placed in a condition in which the LCO does not apply. If applicable, action must be immediately initiated to suspend operations with a potential for draining the reactor vessel (OPDRVs) to minimize the probability of a vessel draindown and subsequent potential for fission product release. Actions must continue until OPDRVs are suspended or valve(s) are restored to OPERABLE status. If suspending an OPDRV would result in closing the residual heat removal (RHR) shutdown cooling isolation valves, an alternative Required Action is provided to immediately initiate action to restore the valve(s) to OPERABLE status. This allows RHR to remain in service while actions are being taken to restore the valve.

SURVEILLANCE SR 3.6.1.3.1 REQUIREMENTS 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 also modified by Note 1, stating that primary containment purge valves are only required to be closed in MODES 1, 2, and 3. If a" LOCA inside primay_

containment occurs in these MODES, the purge valves may not be capable of closing before the pressure pulse affects systems downstream of the purge valves, or the release of radioactive material will exceed limits prior to the purge valves closing. At other times when the purge valves are required to be capable of closing (e.g., during handling of irradiated fuel), pressurization concerns are not present and the purge valves are allowed to be open. The SR is modified by Note 2 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 (continued)

SUSQUEHANNA - UNIT 2 TS / B 3-6-23 Revision 2

PPL Rev. 6 PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.1 (continued)

REQUIREMENTS a LOCA. Therefore, these valves are allowed to be open for limited periods of time. The 31 day Frequency is consistent with other PCIV requirements discussed in SR 3.6.1.3.2.

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. Since verification of valve position for PCIVs outside primary containment is relatively easy, the 31 day Frequency was chosen to provide added assurance that the PCIVs are in the correct positions.

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 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 beern 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 (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.6-24 Revision 1

PPL Rev. 6 PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.3 (continued)

REQUIREMENTS 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 performed 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 verified 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 31 day Frequency is based on operating experience that has demonstrated the reliability of the explosive charge continuity.

SR 3.6.1.3.5 Verifying the isolation time of each power operated and each automatic PCIV is within limits is required to demonstrate (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.6-25 Revision 1

PPL Rev. 6 PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.5 (continued)

REQUIREMENTS 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 Inservice 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 SR is modified by a Note stating that the primary containment purge valves are only required to meet leakage rate testing requirements in MODES 1, 2, and 3. If a LOCA inside primary containment occurs in these MODES, purge valve leakage must be minimized to ensure offsite radiological release is within limits.

At other times when the purge valves are required to be capable of closing (e.g., during handling of irradiated fuel), pressurization concerns are not present and the purge valves are not required to meet any specific leakage criteria.

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 DBA analyses. This ensures that the calculated radiological consequences of these events remain within 10 CFR 100 limits.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.6-26 Revision 2

PPL Rev. 6 PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.7 REQUIREMENTS (continued) The Frequency of this SR is in accordance with the requirements of the Inservice 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 DBA. 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 24 month Frequency was developed considering it is prudent that some of these Surveillances be performed only during a unit outage since isolation of penetrations could eliminate cooling water flow and disrupt the normal operation of some critical components. Operating experience has shown that these components usually pass this Surveillance when performed at the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

SR 3.6.1.3.9 This SR requires a demonstration that a 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 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 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 24 month Frequency is based on the need to perform some of these Surveillances under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. 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 Inservice 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 problem with a specific type or application of EFCV is (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.6-27 Revision 3

PPL Rev. 6 PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.9 (continued)

REQUIREMENTS 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 Frequency of 24 months on a STAGGERED TEST BASIS is considered adequate given the administrative controls on replacement charges and the frequent checks of circuit continuity (SR 3.6.1.3.4).

SR 3.6.1.3.11 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.

A note is added to this SR which states that these valves are only required to meet this leakage limit in MODES 1, 2, and 3. In the other MODES, the Reactor Coolant System is not pressurized and specific primary containment leakage limits are not required.

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 or < 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 (22.5 psig) or Pa (45 psig). Main Steam Line Drain Isolation, HPCI and RCIC Steam Supply Line Isolation Valves, are tested at Pa (45 psig). A note is added to this SR which states that these valves are only required to meet this leakage limit in MODES 1, 2, and 3. In the other (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.6-28 Revision 6

PPL Rev. 6 PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.12 (continued)

REQUIREMENTS conditions, the Reactor Coolant System is not pressurized and specific primary containment leakage limits are not required. 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 hydrostatically tested lines is 3.3 gpm when tested at 1.1 Pa, (49.5 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 IST Program. Therefore, these valves leakage is not included as containment leakage.

This SR has been modified by a Note that states that these valves are only required to meet the combined leakage rate in MODES 1, 2, and 3, since this is when the Reactor Coolant System is pressurized and primary containment is required. In some instances, the valves are required to be capable-of automatically closing duri ng MODES other than MODES 1, 2, and 3. However, specific leakage limits are not applicable in these other MODES or conditions.

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, "Technical Specification Improvement Analyses for BWR Reactor Protection System,"

March 1988.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.6-29 Revision 4

PPL Rev. 6 PCIVs B 3.6.1.3 BASES REFERENCES (continued) 6. Standard Review Plan 6.2.4, Rev. 1, September 1975

7. NEDO-32977-A, "Excess Flow Check Valve Testing Relaxation," June 2000 (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.6-29a Revision 0

PPL Rev. 6 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 Primary Containment Isolation Valve (Page 1 of 10)

Isolation Signal LCO Plant System Valve Number Valve Description Type of Valve 3.3.6.1 Function No.

(Maximum Isolation Time (Seconds))

Containment 2-57-199 (d) ILRT Manual N/A Atmospheric 2-57-200 (d) ILRT Manual N/A Control HV-25703 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-25704 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-25705 Containment Purge 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 Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-25714 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-25721 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-25722 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-25723 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-25724 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-25725 Containment Purge Automatic Valve 2.b, 2.d, 2.e (15)

HV-25766 (a) Suppression Pool Cleanup Automatic Valve 2.b, 2.d (35)

HV-25768 (a) Suppression Pool Cleanup Automatic Valve 2.b, 2.d (30)

SV-2571 00 A Containment Radiation Detection Automatic Valve 2.b, 2.d, 2.f Syst SV-2571 00 B Containment Radiation Detection Automatic Valve 2.b, 2.d, 2.f Syst SV-257101 A Containment Radiation Detection Automatic Valve 2.b, 2.d, 2.f Syst SV-2571 01 B Containment Radiation Detection Automatic Valve 2.b, 2.d, 2.f Syst SV-257102 A Containment Radiation Detection Automatic Valve 2.b, 2.d, 2.f Syst SV-257102 B Containment Radiation Detection Automatic Valve 2.b, 2.d, 2.f Syst SV-257103 A Containment Radiation Detection Automatic Valve_ 2.b, 2.d, 2.f Syst SV-257103 B Containment Radiation Detection Automatic Valve 2.b, 2.d; 2.f Syst SV-257104 Containment Radiation Detection Automatic Valve 2.b, 2.d, 2.f Syst SV-257105 Containment Radiation Detection Automatic Valve 2.b, 2.d, 2.f Syst 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 Syst SV-25734 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-25734 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-25736 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-25736 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-25737 Nitrogen MakeuD Automatic Valve 2.b. 2.d. 2.e SUSQUEHANNA - UNIT 2 TS / B 3.6-30 Revision 2

PPL Rev. 6 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 Primary Containment Isolation Valve (Pane 2 of 10)

Isolation Signal LCO Plant System Valve Number Valve Description Type of Valve 3.3.6.1 Function No.

(Maximum Isolation Time (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 SV-25740 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d (continued) SV-25742 A (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-25742 B (e) Containment Atmosphere Sample Automatic Valve 2.b, 2.d SV-25750 A (e) Containment Atmosphere Sample Automatic Valve 2.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 2.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 G-as Manual Check N/A Instrument Gas 2-26-074 (d) Containment Instrument Gas Manual Check N/A 2-26-152 (d) Containment Instrument Gas Manual Check N/A -

2-26-154 (d) Containment Instrument Gas Manual Check -N/A 2-26-164 (d) Containment Instrument Gas - Manual Check N/A 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 Containrhent Instrument Gas Automatic Valve 2.c, 2.d SV-22654 A Containment Instrument Gas Power Operated N/A SV-22654 B Containment Instrument Gas Power Operated N/A 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 N/A HV-252F001 B (b)(c) CS Suction Power Operated N/A HV-252F005 A CS Injection Power Operated N/A HV-252F005 B CS Injection Power Operated N/A HV-252F006 A CS Injection Air Operated N/A Check Valve HV-252F006 B CS Injection Air Operated N/A HV-252F006___B _ _Inje __tionCheck Valve HV-252F01 5 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) CS Minimum Recirculation Flow Power Operated N/A HV-252F031 B (b)(c) CS Minimum Recirculation Flow Power Operated N/A SUSQUEHANNA - UNIT 2 TS / B 3.6-31 Revision 3

PPL Rev. 6 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 Primary Containment Isolation Valve (Page 3 of 10)

Isolation Signal LCO Plant System Valve Number Valve Description Type of Valve 3.3.6.1 Function No.

(Maximum Isolation Time (Seconds))

Core Spray HV-252F037 A CS Injection Power Operated N/A (continued) (Air)

HV-252F037 B CS Injection Power Operated N/A (Air)

XV-252F01 8 A Core Spray Excess Flow N/A Check Valve XV-252F018 B Core Spray Excess Flow N/A Check Valve Demin Water 2-41-017 (d) Demineralized Water Manual N/A 2-41-018 (d) Demineralized Water Manual N/A HPCI 2-55-038 (d) HPCI Injection Manual N/A 255F046 (b) (c) (d) HPCI Minimum Recirculation Flow Manual Check N/A 255F049 (a) (d) HPCI Manual Check N/A HV-255F002 HPCI Steam Supply Automatic Valve 3.a, 3.b, 3.c, 3.e, 3.f, 3.g, (50)

HV-255F003 HPCI Steam Supply Automatic Valve 3.a, 3.b, 3.c, 3.e, 3.f, 3.g, (50)

HV-255F006 HPCI Injection Power Operated N/A HV-255F012 (b) (c) HPCI Minimum Recirculation Flow Power Operated N/A HV-255F042 (b) (c) HPCI Suction Automatic Valve 3.a, 3.b, 3.c, 3.e, 3.f, 3.g, (90)

HV-255F066 (a) HPCI Turbine Exhaust Power Operated N/A HV-255F075 HPCI Vacuum Breaker Automatic Valve 3.b, 3.d, (15)

HV-255F079 HPCI Vacuum Breaker Automatic Valve 3.b, 3.d, (15)

HV-255F100 HPCI Steam Supply Automatic Valve 3.a, 3.b, 3.c, 3.e, 3.f, 3.g, (6)

XV-255F024 A HPCI Excess Flow N/A.

-.... - Check Valve _

XV-255F024 B HPCI Excess Flow N/A Check Valve XV-255F024 C HPCI Excess Flow N/A Check Valve XV-255F024 D HPCI Excess Flow N/A Check Valve Liquid Radwaste HV-26108 Al Liquid Radwaste Automatic Valve 2.b, 2.d (15)

Collection HV-26108 A2 Liquid Radwaste Automatic Valve 2.b, 2.d (15)

HV-26116 A1 Liquid Radwaste Automatic Valve 2.b, 2.d (15)

HV-26116 A2 Liquid Radwaste Automatic Valve 2.b, 2.d (15)

Nuclear Boiler 241 F01 0 A (d) Feedwater Manual Check N/A 241 F01 0 B (d) Feedwater Manual Check N/A 241 F039 A (d) Feedwater Isolation Valve Manual Check N/A 241 F039 B (d) Feedwater Isolation Valve Manual Check N/A 241818 A (d) Feedwater Isolation Valve Manual Check N/A 1 241818 B (d) Feedwater Isolation Valve Manual Check N/A SUSQUEHANNA-UNIT2 TS / B 3.6-32 Revision 1

PPL Rev. 6 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 Primary Containment Isolation Valve Plant System Valve Number I (Page 4 of 10)

Valve Description Type of Valve Isolation Signal LCO 3.3.6.1 Function No.

(Maximumstion (Maximum Isolation Time (Seconds))

Nuclear Boiler HV-241 F016 MSL Drain Automatic Valve 1.a, i.b, 1.c, i.d, 1.e (continued) (10)

HV-241 F019 MSL Drain Automatic Valve 1.a, 1.b, 1.c, 1.d, 1.e (15)

HV-241F022 A MSIV Automatic Valve 1.a, i.b, 1.c, 1.d, i.e (5)

HV-241 F022 B MSIV Automatic Valve 1 .a, 1.b, 1 .c, 1d, 1.e (5)

HV-241 F022 C MSIV Automatic Valve 1.a, 1.b, 1 .c, 1.d, 1.e (5)

HV-241 F022 D MSIV Automatic Valve 1.a, 1 .b, 1.c, 1.d, 1.e (5)

HV-241 F028 A MSIV Automatic Valve 1.a, 1.b, 1.c, 1.d, i.e (5)

HV-241 F028 B MSIV Automatic Valve 1.a, 1 .b, 1.c, 1.d, 1.e (5)

HV-241F028 C MSIV Automatic Valve i.a, 1.b, 1.c, 1id, .e (5)

HV-241 F028 D MSIV Automatic Valve 1.a, 1 .b, 1.c, 1 .d, 1.e (5)

HV-241 F032 A Feedwater Isolation Valve Power Operated N/A Check Valves HV-241 F032 B Feedwater Isolation Valve Power Operated N/A Check Valves XV-241 F009 Nuclear Boiler EFCV Excess Flow N/A Check Valve XV-241 F070 A Nuclear Boiler EFCV Excess Flow N/A

. . Check Valve XV-241 F070 B Nuclear Boiler EFCV Excess FIow - N/A .

Check Valve' XV-241 F070 C Nuclear Boiler EFCV - Excess Flow N/A Check Valve XV-241 F070 D- Nuclear Boiler EFCV Excess Flow N/A Check Valve XV-241 F071 A Nuclear Boiler EFCV Excess Flow N/A Check Valve XV-241 F071 B Nuclear Boiler EFCV Excess Flow N/A Check Valve XV-241 F071 C Nuclear Boiler EFCV Excess Flow N/A Check Valve XV-241 F071 D Nuclear Boiler EFCV Excess Flow N/A Check Valve XV-241 F072 A Nuclear Boiler EFCV Excess Flow N/A Check Valve XV-241 F072 B Nuclear Boiler EFCV Excess Flow N/A Check Valve XV-241 F072 C Nuclear Boiler EFCV Excess Flow N/A Check Valve XV-241 F072 D Nuclear Boiler EFCV Excess Flow N/A Check Valve XV-241 F073 A Nuclear Boiler EFCV Excess Flow N/A Check Valve SUSQUEHANNA - UNIT 2 TS / B 3.6-33 Revision 2

PPL Rev. 6 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 Primary Containment Isolation Valve (Page 5 of 10)

Isolation Signal LCO 3.3.6.1 Function No.

Plant System Valve Number Valve Description Type of Valve (Maximumstion (Maximum Isolation Time (Seconds))

Nuclear Boiler XV-241 F073 B Nuclear Boiler EFCV Excess Flow N/A (continued) Check Valve XV-241 F073 C Nuclear Boiler EFCV Excess Flow N/A Check Valve XV-241 F073 D Nuclear Boiler EFCV Excess Flow N/A Check Valve Nuclear Boiler XV-24201 Nuclear Boiler Vessel Instrument Excess Flow N/A Vessel Check Valve Instrumentation XV-24202 Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F041 Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F043 A Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F043 B Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F045 A Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F045 B Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F047 A Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F047B Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F051 A Nuclear Boiler Vessel In~trument Excess Flow N/A Check Valve XV-242F051 B Nuclear Boiler Vessel Instrument, Excess Flow N/A Check Valve XV-242F051 C Nuclear Boiler Vessel Instrument Excess FRovi - N/A:

Check Valve XV-242F051 D Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F053 A Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F053 B Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F053 C Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F053 D Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F055 Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F057 Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F059 A Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F059 B Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve SUSQUEHANNA - UNIT 2 TS / B 3.6-34 Revision 1

PPL Rev. 6 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 Primary Containment Isolation Valve (Page 6 of 10)

Isolation Signal LCO 3.3.6.1 Function No.

Isolation Plant System Valve Number Valve Description Type of Valve (Maximum Time (Seconds))

Nuclear Boiler XV-242F059 C Nuclear Boiler Vessel Instrument Excess Flow N/A Vessel Check Valve Instrumentation XV-242F059 D Nuclear Boiler Vessel Instrument Excess Flow N/A (continued) Check Valve XV-242F059 E Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F059 F Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F059 G Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F059 H Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F059 L Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F059 M Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F059 N Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F059 P Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F059 R Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F059 S Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F059 T Nuclear Boiler Vessel Instrument Excess Flow N/A Check Valve XV-242F059 U Nuclear Boiler Vessel Instrument Excess Flow N/A

- Check Valve XV-242F061 Nuclear Boiler Vessel Instrument Excess Flovy - N/A Check Valve RB Chilled Water HV-28781 Al RB Chilled Water Automatic Valve 2.c, 2.d (40)

System HV-28781 A2 RB Chilled Water Automatic Valve 2.c, 2.d (40)

HV-28781 B1 RB Chilled Water Automatic Valve 2.c, 2.d (40)

HV-28781 B2 RB Chilled Water Automatic Valve 2.c, 2.d (40)

HV-28782 Al RB Chilled Water Automatic Valve 2.c, 2.d (12)

HV-28782 A2 RB Chilled Water Automatic Valve 2.c, 2.d (12)

HV-28782 B1 RB Chilled Water Automatic Valve 2.c, 2.d (12)

HV-28782 B2 RB Chilled Water Automatic Valve 2.c, 2.d (12)

HV-28791 Al RB Chilled Water Automatic Valve 2.c, 2.d (15)

HV-28791 A2 RB Chilled Water Automatic Valve 2.c, 2.d (15)

HV-28791 B1 RB Chilled Water Automatic Valve 2.c, 2.d (15)

HV-28791 B2 RB Chilled Water Automatic Valve 2.c, 2.d (15)

HV-28792 Al RB Chilled Water Automatic Valve 2.c, 2.d (8)

HV-28792 A2 RB Chilled Water Automatic Valve 2.c, 2.d (8)

HV-28792 B1 RB Chilled Water Automatic Valve 2.c, 2.d (8)

SUSQUEHANNA - UNIT 2 TS / B 3.6-35 Revision 2

PPL Rev. 6 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 Primary Containment Isolation Valve (Page 7 of 10)

Isolation Signal LCO 3.3.6.1 Function No.

Plant System Valve Number Valve Description Type of Valve (Maximumstion (Maximum Isolation Time (Seconds))

RB Chilled Water HV-28792 B2 RB Chilled Water Automatic Valve 2.b, 2.d (8)

System (continued)

RBCCW HV-21313 RBCCW Automatic Valve 2.c, 2.d (30)

HV-21314 RBCCW Automatic Valve 2.c, 2.d (30)

HV-21345 RBCCW Automatic Valve 2.c, 2.d (30)

HV-21346 RBCCW Automatic Valve 2.c, 2.d (30)

RCIC 2-49-020 (d) RCIC Injection Manual N/A 249F021 (b) (c) (d) RCIC Minimum Recirculation Flow Manual Check N/A 249F028 (a) (d) RCIC Vacuum Pump Discharge Manual N/A 249F040 (a) (d) RCIC Turbine Exhaust Manual N/A FV-249F019 (b) (c) RCIC Minimum Recirculation Flow Power Operated N/A HV-249F007 RCIC Steam Supply Automatic Valve 4.a, 4.b, 4.c, 4.e, 4.f, 4.g (20)

HV-249F008 RCIC Steam Supply Automatic Valve 4.a, 4.b, 4.c, 4.e, 4.f, 4.g (20)

HV-249F013 RCIC Injection Power Operated N/A HV-249F031 (b) (c) RCIC Suction Power Operated N/A HV-249F059 (a) RCIC Turbine Exhaust Power Operated N/A HV-249F060 (a) RCIC Vacuum Pump Discharge Power Operated N/A HV-249F062 RCIC Vacuum Breaker Automatic Valve 4.b, 4.d (10)

HV-249F084 RCIC Vacuum Breaker Automatic Valve 4.b, 4.d (10)

HV-249F088 RCIC Steam Supply Automatic Valve 4.a, 4.b, 4.c, 4.e, 4.f, 4.g (12)

XV-249F044 A RCIC Excess Flow N/A Check Valve XV-249F044 B RCIC Excess Flow N/A.

Check Valve XV-249F044 C RCIC Excess Flow- N/A*

Check Valve XV-249F044 D RCIC Excess Flow N/A Check Valve Reactor 243F01 3 A (d) Recirculation Pump Seal Water Manual Check N/A Recirculation 243F013-B (d) Recirculation Pump Seal Water Manual Check N/A HV-243F01 9 Reactor Coolant Sample Automatic Valve 2.b (9)

HV-243F020 Reactor Coolant Sample Automatic Valve 2.b (2)

XV-243F003 A Reactor Recirculation Excess Flow N/A Check Valve XV-243F003 B Reactor Recirculation Excess Flow N/A Check Valve XV-243F004 A Reactor Recirculation Excess Flow N/A Check Valve XV-243F004 B Reactor Recirculation Excess Flow N/A Check Valve SUSQUEHANNA - UNIT 2 TS / B 3.6-36 Revision 2

PPL Rev. 6 PCIVs B 3.6.1.3 Table BS 3.6.1.3-1 Primary Containment Isolation Valve Isolation Signal LCO 3.3.6.1 Function No.

Plant System Valve Number Valve Description Type of Valve (Maximumotion (Maximum Isolation Time (Seconds))

Reactor XV-243F009 A Reactor Recirculation Excess Flow N/A Recirculation Check Valve (continued) XV-243F009 B Reactor Recirculation Excess Flow N/A Check Valve XV-243FO09 C Reactor Recirculation Excess Flow N/A Check Valve XV-243F009 D Reactor Recirculation Excess Flow N/A Check Valve XV-243F01 0 A Reactor Recirculation Excess Flow N/A Check Valve XV-243F010 B Reactor Recirculation Excess Flow N/A Check Valve XV-243F010 C Reactor Recirculation Excess Flow N/A Check Valve XV-243F010 D Reactor Recirculation Excess Flow N/A Check Valve XV-243F01 1 A Reactor Recirculation Excess Flow N/A Check Valve XV-243F01 1 B Reactor Recirculation Excess Flow N/A Check Valve XV-243F01 1 C Reactor Recirculation Excess Flow N/A Check Valve XV-243F01 1 D Reactor Recirculation Excess Flow N/A Check Valve XV-243F012 A Reactor Recirculation Excess Flow N/A Check Valve XV-243F012 B Reactor Recirculation Excess Flow N/A

.._ Check Valve XV-243F012 C Reactor Recirculation Excess FloW - N/A.-

Check Valve _

XV-243F012 D Reactor Recirculation Excess Flow N/A Check Valve XV-243F017 A Recirculation Pump Seal Water Excess Flow N/A Check Valve XV-243F017 B Recirculation Pump Seal Water Excess Flow N/A Check Valve XV-243F040 A Reactor Recirculation Excess Flow N/A Check Valve XV-243F040 B Reactor Recirculation Excess Flow N/A Check Valve XV-243F040 C Reactor Recirculation Excess Flow N/A Check Valve XV-243F040 D Reactor Recirculation Excess Flow N/A Check Valve XV-243F057 A Reactor Recirculation Excess Flow N/A Check Valve XV-243FO57 B Reactor Recirculation Excess Flow N/A Check Valve Residual Heat HV-251F004 A (b) (c) RHR - Suppression Pool Suction Power Operated N/A Removal HV-251 F004 B (b) (c) RHR - Suppression Pool Suction Power Operated N/A Removal HV-251 F004 C (b) (c) RHR - Suppression Pool Suction Power Operated N/A SUSQUEHANNA - UNIT 2 TS / B 3.6-37 Revision 2

PPL Rev. 6 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 Primary Containment Isolation Valve (Paqe 9 of 10)

Isolation Signal LCO 3.3.6.1 Function No.

Plant System Valve Number Valve Description Type of Valve (Maximum Isolation Time (Seconds))

Residual Heat HV-251 F004 D(b) (c) RHR - Suppression Pool Suction Power Operated N/A Removal HV-251 F007 A (b) (c) RHR - Minimum Recirculation Power Operated N/A (continued) HV-251 F007 B (b) (c) RHR - Minimum Recirculation Power Operated N/A HV-251 F008 RHR - Shutdown Cooling Suction Automatic Valve 6.a, 6.b, 6.c (52)

HV-251 F009 RHR - Shutdown Cooling Suction Automatic Valve 6.a, 6.b, 6.c (52)

HV-251 F01I A (b) (d) RHR - Suppression Pool Cooling Manual N/A HV-251 F01 1 B (b) (d) RHR - Suppression Pool Cooling Manual N/A HV-251 F01 5 A (f) RHR - Shutdown Cooling Power Operated N/A Return/LPCI Injection HV-251 F01 5 B (f) RHR - Shutdown Cooling Power Operated N/A Retum/LPCI Injection HV-251 F016 A (b) RHR - Drywell Spray Automatic Valve 2.c, 2.d (90)

HV-251 F016 B (b) RHR - Drywell Spray Automatic Valve 2.c, 2.d (90)

HV-251 F022 RHR - Reactor Vessel Head Spray Automatic Valve 2.d, 6.a, 6.b, 6.c (30)

HV-251 F023 RHR - Reactor Vessel Head Spray Automatic Valve 2.d, 6.a, 6.b, 6.c (20)

HV-251 F028 A (b) RHR - Suppression Pool Automatic Valve 2.c, 2.d (90)

Cooling/Spray HV-251 F028 B (b) RHR - Suppression Pool Automatic Valve 2.c, 2.d (90)

Cooling/Spray HV-251 F050 A (g) RHR - Shutdown Cooling Air Operated N/A Return/LPCI Injection Check Valve HV-251 F050 B (g) RHR - Shutdown Cooling Air Operated N/A Retum/LPCI Injection Check Valve HV-251 F103 A (b) RHR Heat Exchanger Vent Power Operated N/A HV-251 F103 B (b) RHR Heat Exchanger Vent Power Operated N/A HV-251 F122 A (g) " RHR - Shutdown Cooling Power Operated N/A Return/LPCI Injection (Air)

HV-251 F122 B (g) RHR - Shutdown Cooling Power Operated N/A Return/LPCI Injection (Air) _

PSV-25106 A (b) (d) RHR- Relief Valve Discharge Relief Valve N/A PSV-25106 B (b) (d) RHR- Relief Valve Discharge Relief Valve N/A PSV-251 F126 (d) RHR- Shutdown Cooling Suction Relief Valve N/A XV-25109 A RHR Excess Flow N/A Check Valve XV-25109 B RHR Excess Flow N/A Check Valve XV-25109 C RHR Excess Flow N/A Check Valve XV-25109 D RHR Excess Flow N/A Check Valve RWCU HV-244F001 (a) RWCU Suction Automatic Valve 5.a, 5.b, 5.c, 5.d, 5.f, 5.g (30)

HV-244F004 (a) RWCU Suction Automatic Valve 5.a, 5.b, 5.c, 5.d, 5.e, 5.f, 5.g (30)

XV-24411 A RWCU Excess Flow N/A Check Valve XV-24411 B RWCU Excess Flow N/A

__ I I Check Valve I SUSQUEHANNA - UNIT 2 TS / B 3.6-38 Revision 3

PPL Rev. 6 PCIVs B 3.6.1.3 Table B 3.6.1.3-1 Primary Containment Isolation Valve (Paae 10 of 10)

Isolation Signal LCO 3.3.6.1 Function No.

Plant System Valve Number Valve Description Type of Valve (Maximum Isolation Time (Seconds))

RWCU XV-24411 C RWCU Excess Flow N/A (continued) Check Valve XV-24411 D RWCU Excess Flow N/A Check Valve XV-244F046 RWCU Excess Flow N/A Check Valve HV-24182 A RWCU Return Power Operated N/A HV-24182 B RWCU Return Power Operated N/A SLCS 248F007 (a) (d) SLCS Manual Check N/A HV-248F006 (a) SLCS Power Operated N/A Check Valve TIP System C51-J004 A (Ball TIP Ball Valves Automatic Valve 7.a, 7.b (5)

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 TIP Ball Valves Automatic Valve 7.a, 7.b (5)

Valve)

C51-J004 E (Ball TIP Ball Valves Automatic Valve 7.a, 7.b (5)

Valve)

TIP System C51-J004 A (Shear TIP Shear Valves Squib Valve N/A (continued) Valve)

C51-J004 B (Shear TIP Shear Valves Squib Valve N/A Valve)

C51-J004 C (Shear- TIP Shear Valves Squib Valve N/A Valve)

C51-J004 D (Shear TIP Shear-Valves Squib Valve N/A Valve) .. . . ... ...._ _

C51-J004 E (Shear TIP Shear Valves Squib Valve N/A Valve)

(a) Isolation barrier remains filled or a water §eal remains in the line post-LOCA, isolation valve is tested with water.

Isolation valve leakage is not included in 0.60 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 255F046 (HPCI) when the associated PCIV, HV255F012 is closed and deactivated. Similarly, this footnote does not apply to valve 249F021 (RCIC) when its associated PCIV, FV249F019 is closed and deactivated.

(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 IST 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 deactivated and closed.

(e) The containment isolation barriers for the penetration associated with 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 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-251 F015A(B) valves and a closed system form the 10 CFR 50, Appendix J boundary. These valves form a high/low pressure interface and are pressure tested in accordance with the pressure test program.

SUSQUEHANNA - UNIT 2 TS / B 3.6-39 Revision 7

PPL Rev. 1 Suppression Pool Average Temperature B 3.6.2.1 B 3.6 CONTAINMENT SYSTEMS B 3.6.2.1 Suppression Pool Average Temperature BASES BACKGROUND The primary containment utilizes a Mark II over/under pressure suppression configuration consisting of a drywell and suppression chamber. The drywell is a steel-lined concrete truncated cone located above the steel-lined concrete cylindrical pressure suppression chamber containing a volume of water called the suppression pool. The suppression pool is designed to absorb the decay heat and sensible energy released during a reactor blowdown from safety/relief valve discharges or from Design Basis Accidents (DBAs). The suppression pool must quench all the steam released through the downcomer lines during a loss of coolant accident (LOCA). This is the essential mitigative feature of a pressure suppression containment that ensures that the peak containment pressure is maintained below the maximum allowable pressure for containment (53 psig) (Ref. 1). The suppression pool must also condense steam from steam exhaust lines in the turbine driven systems (i.e., the High Pressure Coolant Injection System and Reactor Core Isolation Cooling System). Suppression pool average temperature (along with LCO 3.6.2.2, "Suppression Pool Water Level") is a key indication of the capacity of the suppression pool to fulfill these requirements-.-

The technical concerns that lead tG the development of suppression pool average temperature limits are as follows:

a. Complete steam condensation;

b. Primary containment peak pressure and temperature;

c. Condensation oscillation loads; and

d. Chugging loads.

APPLICABLE The postulated DBA against which the primary containment performance SAFETY is evaluated is the entire spectrum of postulated pipe breaks within the ANALYSES primary containment. Inputs to the safety analyses include initial suppression pool water volume and suppression pool temperature (continued)

SUSQUEHANNA - UNIT 2 B 3.6-52 Revision 0

PPL Rev. 1 Suppression Pool Average Temperature B 3.6.2.1 BASES APPLICABLE (Reference 1 for LOCAs and Reference 2 for the pool temperature SAFETY analyses required by Reference 3). An initial pool temperature of 90°F is ANALYSES assumed for the Reference 1 and Reference 2 analyses. Reactor (continued) shutdown at a pool temperature of 11 0°F and vessel depressurization at a pool temperature of 120OF are assumed for the Reference 2 analyses.

The limit of 105 0 F, at which testing is terminated, is not used in the safety analyses because DBAs are assumed to not initiate during unit testing.

Suppression pool average temperature satisfies Criteria 2 and 3 of the NRC Policy Statement. (Ref. 4)

LCO A limitation on the suppression pool average temperature is required to provide assurance that the containment conditions assumed for the safety analyses are met. This limitation subsequently ensures that peak primary containment pressures and temperatures do not exceed maximum allowable values during a postulated DBA or any transient resulting in heatup of the suppression pool. The LCO requirements are:

a. Average temperature < 90°F when any OPERABLE intermediate range monitor (IRM) channel-is > 25/40 divisions of full scale on Range- 7 with IRMs fully inserted and no testing that adds heat to-the suppression pooLis being performed. This-requirement ensures that licensing bases initial conditions are met. .-

b. Average temperature < 105 0 F when any OPERABLE IRM channel is

> 25/40 divisions of full scale on Range 7 with -RMs fully inserted and testing that adds heat to the suppression pool is being performed.

This required value ensures that the unit has testing flexibility, and was selected to provide margin below the 11 0°F limit at which reactor shutdown is required. When testing ends, temperature must be restored to < 90°F within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months according to Required Action A.2.

Therefore, the time period that the temperature is > 90°F is short enough not to cause a significant increase in unit risk.

(continued)

SUSQUEHANNA - UNIT 2 B 3.6-53 Revision 0

PPL Rev. 1 Suppression Pool Average Temperature B 3.6.2.1 BAS ES LCO c. Average temperature _<110°F when all OPERABLE IRM channels are (continued) < 25/40 divisions of full scale on Range 7 with IRMs fully inserted. This requirement ensures that the unit will be shut down at > 1 100 F. The pool is designed to absorb decay heat and sensible heat but could be heated beyond design limits by the steam generated if the reactor is not shut down.

Note that 25/40 divisions of full scale on IRM Range 7 is a convenient measure of when the reactor is producing power essentially equivalent to 1% RTP. At this power level, heat input is approximately equal to normal system heat losses.

APPLICABILITY In MODES 1, 2, and 3, a DBA could cause significant heatup of the suppression pool. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintaining suppression pool average temperature within limits is not required in MODE 4 or 5.

ACTIONS A.1 and A.2 With the suppression- pool average temperatuFe above the slpecified limit when not performing testing that adds heat to the supp-ression pRol-and when above the specified power indication, the initial conditions-exceed the conditions assumed for the References 1 and 2 analyses. However, primary containment cooling capability still exists, and the primary containment pressure suppression function will occur at temperatures well above those assumed for safety analyses. Therefore, continued operation is allowed for a limited time. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time is adequate to allow the suppression pool average temperature to be restored below the limit. Additionally, when suppression pool temperature is > 90 0 F, increased monitoring of the suppression pool temperature is required to ensure that it remains < 11 0°F. The once per hour Completion Time is adequate based on past experience, which has shown that pool temperature increases relatively slowly except when testing (continued)

SUSQUEHANNA - UNIT 2 B83.6-54 Revision 0

PPL Rev. 1 Suppression Pool Average Temperature B 3.6.2.1 BASES ACTIONS A.1 and A.2 (continued) that adds heat to the suppression pool is being performed. Furthermore, the once per hour Completion Time is considered adequate in view of other indications in the control room, including alarms, to alert the operator to an abnormal suppression pool average temperature Condition.

B.1 If the suppression pool average temperature cannot be restored to within limits within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the power must be reduced to < 25/40 divisions of full scale on Range 7 for all OPERABLE IRMs within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Completion Time is reasonable, based on operating experience, to reduce power from full power conditions in an orderly manner and without challenging plant systems.

C.1 Suppression pool average temperature is allowed to be > 90°F when any OPERABLE IRM channel is > 25/40 divisions of full scale on Range 7, and when testing that adds heat to the suppression pool is being performed. However, if temperature is > 1050 F, all testirfg must b-e-immediately suspended to preserve the heat absorption capability of the suppression pool. With the testing suspended, Condition A is entered and the Required Actions and associated Completion Times are applicable.

D.1, D.2 and D.3 Suppression pool average temperature > 11 0°F requires that the reactor be shut down immediately. This is accomplished by placing the reactor mode switch in the shutdown position. Further cooldown to Mode 4 is required at normal cooldown rates (provided pool temperature remains <

120 0 F). Additionally, when suppression pool temperature is > 1 10°F, increased monitoring of pool temperature is required to (continued)

SUSQUEHANNA - UNIT 2 B 3.6-55 Revision 0

PPL Rev. 1 Suppression Pool Average Temperature B 3.6.2.1 BASES ACTIONS D.1, D.2 and D.3 (continued) ensure that it remains < 120 0 F. The once per 30 minute Completion Time is adequate, based on operating experience. Given the high suppression pool average temperature in this Condition, the monitoring Frequency is increased to twice that of Condition A. Furthermore, the 30 minute Completion Time is considered adequate in view of other indications available in the control room, including alarms, to alert the operator to an abnormal suppression pool average temperature condition.

E._1 If suppression pool average temperature cannot be maintained at

_<120°F, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the reactor pressure must be reduced to

< 200 psig within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , and the plant must be brought to at least MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months from the time the plant entered Condition D. 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.

Continuied addition of heat to the suppression pool with suppression.pool temperature> 1200 F.-could result in exceeding the design ba'sis maximum allowable values for primary containment temperatdr'e br-pressure:--

Furthermore, if a blowdown were to occur when the temperature was

> 120 0 F, the maximum allowable bulk and local temperatures could be exceeded very quickly.

SURVEILLANCE SR 3.6.2.1.1 REQUIREMENTS The suppression pool average temperature is regularly monitored to ensure that the required limits are satisfied. The Suppression Pool Average Temperature is determined by a SPOTMOS calculation of the simple arithmetic average of at least six OPERABLE of the eight safety related upper-level suppression pool temperature channels covering at least one (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.6-56 Revision 1

PPL Rev. 1 Suppression Pool Average Temperature B 3.6.2.1 BASES SURVEILLANCE SR 3.6.2.1.1 (continued)

REQUIREMENTS sensor in each quadrant. The bottom-level pool average temperature is determined by a SPOTMOS calculation of the simple arithmetic average of at least three OPERABLE of the four non-safety related bottom-level pool temperature channels. Bulk Pool Average Temperature is determined by a SPOTMOS calculation of the weighted average of the two previous simple arithmetic averages. Alternately, if no transients or testing that adds heat to the containment are in progress, the SPOTMOS bulk temperature calculation algorithm may be performed manually. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency has been shown, based on operating experience, to be acceptable. When heat is being added to the suppression pool by testing, however, it is necessary to monitor suppression pool temperature more frequently. The 5 minute Frequency during testing is justified by the rates at which tests will heat up the suppression pool, has been shown to be acceptable based on operating experience, and provides assurance that allowable pool temperatures are not exceeded. The Frequencies are further justified in view of other indications available in the control room, including alarms, to alert the operator to an abnormal suppression pool average temperature condition.

REFERENCES 1. FSAR, Section 6.2.

2. FSAR, Section 15.2.

3. NUREG-0783.

4. Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 39132).

SUSQUEHANNA - UNIT 2 TS / B 3.6-57 Revision 1

ML071200046

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