Text

Technical Specification Bases Manual, Rev 1
	ML051990398
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Site:	Susquehanna
Issue date:	07/07/2005
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To:	; Document Control Desk, Office of Nuclear Reactor Regulation
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Jul. 07, 2005 Page 1 of 3 MANUAL HARD COPY DISTRIBUTION DOCUMENT TRANSMITTAL 2005-29056 USER INFORMATI >T R LACH*RO M EMPL#:028401 CA#: 0363 Addr CSA2 Phon TRANSMITTAL INFORMATION:

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, 07/07/2005 LOCATION: 7SNRC7J-FROM: NUCLEAR RECORDS DOCUMENT CONTROL CENTER (NUCSA-2)

THE FOLLOWING CHANGES HAVE OCCURRED TO THE HARDCOPY OR ELECTRONIC MANUAL ASSIGNED TO YOU:

TSB2 - TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL REMOVE MANUAL TABLE OF CONTENTS DATE: 05/31/2005 ADD MANUAL TABLE OF CONTENTS DATE: 07/06/2005 CATEGORY: DOCUMENTS TYPE: TSB2 ID: TEXT 3.1.3 REMOVE: REV:0 ADD: REV: 1 CATEGORY: DOCUMENTS TYPE: TSB2 ID: TEXT 3.1.4 REMOVE: REV:1 zp (NQ

Jul. 07, 2005 Page 2 of 3 ADD: REV: 2 CATEGORY: DOCUMENTS TYPE: TSB2 ID: TEXT 3.1.5 REMOVE: REV:0 ADD: REV: 1 CATEGORY: DOCUMENTS TYPE: TSB2 ID: TEXT 3.3.1.1 REMOVE: REV:1 ADD: REV: 2 CATEGORY: DOCUMENTS TYPE: TSB2 ID: TEXT 3.3.3.1 REMOVE: REV:1 ADD: REV: 2 CATEGORY: DOCUMENTS TYPE: TSB2 ID: TEXT 3.3.5.1 REMOVE: REV:2 ADD: REV: 3 CATEGORY: DOCUMENTS TYPE: TSB2 ID: TEXT LOES REMOVE: REV:59 ADD: REV: 60

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SSES MANUAL I

Manual Name: TSB2 Manual

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL Table Of Contents Issue Date: 07/06/2005 Procedure Name Rev Issue Date Change ID Change Number TEXT LOES 60 07/06/2005

Title:

LIST OF EFFECTIVE SECTIONS TEXT TOC 7 04/18/2005

Title:

TABLE OF CONTENTS

- r. ' - -.

TEXT 2.1.1 1 10/27/2004

Title:

SAFETY LIMITS (SLS) REACTOR CORE SLS TEXT 2.1.2 0 11/18/2002

Title:

SAFETY LIMITS (SLS) REACTOR COOLANT SYSTEM (RCS) PRESSURE SL TEXT 3.0 1 04/18/2005 I

Title:

LIMITING CONDITION FOR OPERATION7(LCO) APPLICABILITY TEXT 3.1.1 1 7 03/24/2005

Title:

REACTIVITY CONTROL SYSTEMS SHUTDOWN MARGIN (SDM)

TEXT 3.1.2 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 mesm~~%- _ 'n n I ne SieNnna T1kXT i ... 4 z u I /U oI 4uul

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: 07/06/05 PagelI Page of of 8 8 Report Date: 07/06/05

SSES MANUAL

../

Manual Name: TSB2 Manual

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL K>--

TEXT 3.1.7 0 11/18/2002

Title:

REACTIVITY CONTROL SYSTEMS STANDBY LIQUID CONTROL (SLC) SYSTEM TEXT 3.1.8 0 11/18/2002

Title:

REACTIVITY CONTROL SYSTEMS SCRAM DISCHARGE VOLUME (SDV) VENT AND DRAIN VALVES TEXT 3.2.1 1 03/24/2005

Title:

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

TEXT 3.2.2 1 03/24/2005

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 2 07/06/2005

Title:

INSTRUMENTATION REACTOR PROTECTION SYSTEM (RPS) INSTRUMENTATION TEXT 3.3.1.2 0 11/18/2002

Title:

INSTRUMENTATION SOURCE RANGE MONITOR (SRM) INSTRUMENTATION TEXT 3.3.1.3 0 11/22/2004

Title:

OPRM INSTRUMENTATION TEXT 3.3.2.1 1 02/17/2005

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 2 07/06/2005

Title:

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

Title:

INSTRUMENTATION REMOTE SHUTDOWN SYSTEM Page 2 of 8 Report Date: 07/06/05

SSES MANUAL

\ Xanual Name: TSB2 Manual

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL TEXT 3.3.4.1 0 11/18/2002

Title:

INSTRUMENTATION END OF CYCLE RECIRCULATION PUMP TRIP (EOC-RPT) INSTRUMENTATION 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 1 11/09/2004

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 1 09/02/2004

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 2 11/22/2004'

Title:

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

Title:

REACTOR COOLANT SYSTEM (RCS) -JET PUMPSl TEXT 3.4.3 0 11/18/2002

Title:

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

Report Date: 07/06/05 Page 3 Page 3 of

. of 8 8 Report Date: 07/06/05

SSES MANUAL Manual Name: TSB2 Manual

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL

<2/

TEXT 3.4.4 0 11/18/2002

Title:

REACTOR COOLANT SYSTEM (RCS) RCS OPERATIONAL LEAKAGE TEXT 3.4.5 0 11/18/2002

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 0 11/18/2002

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 1 04/18/2005

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 0 11/18/2002

Title:

CONTAINMENT SYSTEMS PRIMARY CONTAINMENT Page 4 of 8 Report Date': 07/06/05

I I SSES MANUAL N Manual Name: TSB2 Manual

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL TEXT 3.6.1.2 0 11/18/2002

Title:

CONTAINMENT SYSTEMS PRIMARY CONTAINMENT AIR LOCK TEXT 3.6.1.3 1 05/20/2005

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 0 11/18/2002

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 0 11/18/2002

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 0 11/18/2002

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 1 04/18/2005

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 Report Date: 07/06/05 Page55 Page of of 8 8 Report Date: 07/06/05

SSES MANUAL Manual Name: TSB2 Manual

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL TEXT 3.6.4.1 2 03/01/2005

Title:

CONTAINMENT SYSTEMS SECONDARY CONTAINMENT TEXT 3.6.4.2 2 01/03/2005

Title:

CONTAINMENT SYSTEMS SECONDARY CONTAINMENT ISOLATION VALVES (SCIVS)

TEXT 3.6.4.3 2 11/09/2004

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 11/0912004

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 TEXT 3.7.4 0 11/18/2002

Title:

PLANT SYSTEMS CONTROL ROOM FLOOR COOLING SYSTEM TEXT 3.7.5 0 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 2 04/18/2005

Title:

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

Title:

ELECTRICAL POWER SYSTEMS AC SOURCES - SHUTDOWN Page 6 of 8 Report Date: 07/06/05

- -

SSES MANUAL

\ Manual Name: TSB2 Manual

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL TEXT 3.8.3 0 11/18/2002

Title:

ELECTRICAL POWER SYSTEMS DIESEL FUEL OIL, LUBE OIL, AND STARTING AIR TEXT 3.8.4 0 11/18/2002

Title:

ELECTRICAL POWER SYSTEMS DC SOURCES - OPERATING TEXT 3.8.5 0 11/18/2002

Title:

ELECTRICAL POWER SYST,EMS DC SOURCES - SHUTDOWN TEXT 3.8.6 0 11/18/2002

Title:

ELECTRICAL POWER SYST EMS BATTERY CELL PARAMETERS TEXT 3.8.7 0 11/18/2002

Title:

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

Title:

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

Title:

REFUELING C)PERATIONS REFUELING EQUIPMENT INTERLOCKS TEXT 3.9.2 0 11/18/2002

Title:

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

Title:

REFUELING C)PERATIONS CONTROL ROD POSITION TEXT 3.9.4 0 11/18/2002

Title:

REFUELING C)PERATIONS CONTROL ROD POSITION INDICATION TEXT 3.9.5 0 11/18/2002

Title:

REFUELING (OPERATIONS CONTROL ROD OPERABILITY - REFUELING TEXT 3.9.7 0 11/18/2002

Title:

REFUELING IOPERATIONS RESIDUAL HEAT REMOVAL (RHR) - HIGH WATER LEVEL Report Date: 07/06/05 Page 77 Page of of 88 Report Date: 07/06/05

I SSES MANUAL I

Manual Name: TSB2 I 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 1 03/24/2005

Title:

SPECIAL OPERATIONS CONTROL ROD TESTING - OPERATING TEXT 3.10.8 1 03/24/2005

Title:

SPECIAL OPERATIONS SHUTDOWN MARGIN (SDM) TEST - REFUELING Report Date: 07/06/05 Page8 Page 8 of of 8 8 Report Date: 07/06/05

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

Section Title Revision TOC Table of Contents 7 B 2.0 SAFETY LIMITS BASES Page TS / B2.0-1 1 PageTSIB2.0-2 2 Page TS/B2.0-3 3 PageTS/B2.0-4 4 Page TS / B2.0-5 1 Pages B 2.0-6 through B2.0-8 0 B 3.0 LCO AND SR APPLICABILITY BASES Pages B 3.0-1 through B 3.0-4 <N) 0 Pages TS / B3.0-5 through TS I B 3.0-7 I1 Pages TS / B 3.0-8 through TS / B 3.0-9 2 Pages TS / B 3.0-10 through TS / B3.0-12 1 Pages TS / B 3.0-13 through TS / B3.0-15 2 Pages TS / B 3.0-16 and TS / B3.0-17 \ " 0 B 3.1 REACTIVITY CONTROL BASES < 0 Pages B 3.1-1 through B 3.1-4 0 Page TS / B 3.1-5 ' (<\" 1 Pages TS/B3.1-6 and TS/B31- I 2 Pages B 3.1-8 through B 3 -13, 0 PageTS/B3.1-14 <( 1 Pages B 3.1-15 through'B,3.1-2>', 0 PageTS/B3.1-23/ \ '. . 1 Pages B3.1-24 ,th rnhB3.1-27 0 Page TS / B 3.128' \' 2 Page TS /X31-29 1 l Pages B-3ZA30 through B 3.1-33 0 PagesTS-/1B381,34 through TS / B 3.1-36 1 Page"S / B3.1-37 2 PageiTS/.,,3L1-38 2 (Pagesb 3.1-39 through B 3.1-51 0 B 3.2 POWER DISTRIBUTION LIMITS BASES Pages TS /B3.2-1 and TS /B3.2-2 1 Page TS /B 3.2-3 2 Page TS /B 3.2-4 1 Pages TS / B 3.2-5 and TS / B 3.2-6 3 Page TS /B3.2-7 2 Pages TS / B 3.2-8 and TS / B 3.2-9 3 Pages TS / B 3.2-10 through TS / B 3.2-17 1 Page TS / 3.2-18 2 Page TS / 3.2-19 1 SUSQUEHANNA - UNIT 2 TS / B LOES-1 Revision 60

SUSQUEHANNA STEAM ELECTRIC STATION UST OF EFFECTIVESECTIONS (TECHNICAL SPECIFICATIONS BASES)

Section Title Revision B 3.3 INSTRUMENTATION Pages TS / B 3.3-1 through TS / B 3.3-4 1 Page TS/B3.3-5 2 PageTS/B3.3-6 1 Page TS / B3.3-7 2 Pages TS / B 3.3-8 through TS / B 3.3-11 2 Page TS / B 3.3-12 2 Page TS / B 3.3-13 1 Page TS / B 3.3-14 2 Pages TS / B3.3-15 and TS / B 3.3-16 1 Pages TS / B3.3-17 and TS / B 3.3-18 2 Pages TS / B3.3-19 through TS / B 3.3-27 1 Pages TS / B3.3-28 through TS / B 3.3-30 2 Page TS / B 3.3-31 1 Page TS / B 3.3-32 3 Page Ts / B 3.3-33 2 Pages TS / B 3.3-34 through TS I B 3.3-43 1 Pages TS / B 3.3-43a though TS / B 3.3-43i 0 Pages TS / B 3.3-44 through TS / B 3.3-54 2 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 Pages TS / B 3.3-69 and TS I B 3.3-70 . 3 Pages TS / B 3.3-71 -.. 3 Pages TS / B 3.3-72 through TS / B 3.3-75 2 Page TS / B 3.3-75a 4 Pages TS/B3.3-75b and TS/B3.3-75c 4 Pages B 3.3-76 through TS / B 3.3-77 0 Page TS / B3.3-78 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 / B3.3-110 through TS /B3.3-112 1 Page TS / B 3.3-113 2 Page TS / B 3.3-114 1 Page TS / B 3.3-115 2 Pages TS / B 3.3-116 through TS / 83.3-118 2 Pages TS / B 3.3-119 through TS / 83.3-120 1 Pages TS / B 3.3-121 and TS / B 3.3-122 2 Page TS / B3.3-123 1 Page TS / B3.3-124 2 Revision 60 TS/BLOES-2 SUSQUEHANNA - UNIT SUSQUEHANNA -

UNIT 22 TS / B LOES-2 Revision 60

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

Section Title Revision

/ TS B3.3-124a Page 0 Page TS I B 3.3-125 1 Page TS B 3.3-126 2 Page TS I B3.3-127 3 Page/ TS B3.3-128 2 Pages TS / B 3.3-129 through/ TS B 3.3-131 1

/ B 3.3-132 Page TS 2 Pages TS / B 3.3-134

/ B 3.3-133 and TS 1 Pages B 3.3-135 through B 3.3-137 0 Page TS/ B3.3-138 1 Pages B 3.3-139 through B 3.3-149 0 Pages TS/ B 3.3-150 through TS/ B3.3-162 1 Page TS / B 3.3-163 2 Pages TS/ B 3.3-164 through TS I B 3.3-177 1 Page TS/ B 3.3-178 2 Page TS /B3.3-179 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 I 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/B3.3-206 1 Pages B 3.3-207 through B 3.3-220 0 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 through 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 and TS/ B3.4-17 2 Page TS/ B 3.4-18 1 Pages B 3.4-19 through B 3.4-28 0 Page TS/ B 3.4-29 1 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/B3.4-37 1 Pages B 3.4-38 through B 3.4-40 0 Page TS / B3.4-41 1 Pages B 3.4-42 through B 3.4-48 0 Page TS / B 3.4-49 2 Page TS / B 3.4-50 Page TS / B 3.4-51 2 Pages TS / B 3.4-52 and TS / B 3.4-53 1 Pages TS / B 3.4-54 and TS / B 3.4-55 2 Revision 60 TSIBLOES-3 SUSQUEHANNA - UNIT 2 SUSQUEHANNA-UNIT2 TS / B LOES-3 Revision 60

SUSQUEHANNA STEAM ELECTRIC STATION UST OF EFFECT7VESECTIONS (TECHNICAL SPECIFICATIONS BASES)

Section Title Revision Pages TS / B 3.4-56 through TS / B 3.4-60 1 B 3.5 ECCS AND RCIC BASES Pages TS / B 3.5-1 and TS / B 3.5-2 1 Page TS / B 3.5-3 2 PageTS/B3.5-4 1 Pages TS / B 3.5-5 and TS / B 3.5-6 2 Pages TS / B 3.5-7 through TS / B 3.5-10 1 PageTS / B 3.5-11 2 Pages TS / B 3.5-12 through TS / B3.5-14 1 Pages TS / B 3.5-15 through TS /8.3.5-17 2 PageTS/B3.18 1 Pages B 3.5-19 through B 3.5-24 0 Page TS / B 3.5-25 1 Pages TS / B 3.5-26 and TS / B 3.5-27 1 Pages B3.5-28 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 Pages TS / B 3.6-2 through TS / B 3.6-5 2 PageTS/B3.6-6 3 Pages TS / B 3.6-6a and TS / B 3.6-6b 2 Page TS/B3.6-6c 0 Pages B 3.6-7 through B 3.6-14 0 PageTS/B3.6-15 .... . 3 Pages TS / B 3.6-15a and TS /B 3.6-15b 0 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 /B3.6-19 1 Page TS / B 3.6-20 2 Page TS /B3.6-21 3 PagesTS/B3.6-21aandTS/B3.6-21b 0 Pages TS /B3.6-22 and TS /B3.6-23 2 Pages TS / B 3.6-24 through TS /B 3.6-26 1 Page TS/B3.6-27 3 Page TS / B3.6-28 6 Page TS/B3.6-29 3 Page TS /B 3.6-29a 0 Page TS /B3.6-30 2 Page TS / B 3.6-31 33 Page TS / B3.6-32 1 Page TS/B3.6-33 2 Page TS / B 3.6-34 - 1 Pages TS / B 3.6-35 through TS / B 3.6-37 2 Page TS /B3.6-38 1 Revision 60 UNIT 22 TS/BLOES-4 SUSQUEHANNA SUSQUEHANNA - UNIT

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TS I B LOES-4 Revision 60

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

Section Title Revision Page TS/B3.6-39 4 Pages B 3.6-40 through B 3.6-42 0 Pages TS I B 3.6-43 through TS / B 3.6-50 1 Page TS/B3.6-51 2 Pages B 3.6-52 through B 3.6-62 0 PageTS/B3.6-63 1 Pages B 3.6-64 through B 3.6-70 0 Page 8 3.6-71 0 Page TS / B 3.6-72 1 Pages B 3.6-73 through B 3.6-76 0 Page TS / B 3.6-77 1 Pages B 3.6-78 through B 3.6-82 0 Page TS / B 3.6-83 3 Pages TS / B 3.6-84 and TS / B 3.6-85 2 Pages TS / B 3.6-86 through TS / B 3.6-87a 1 Page TS / B 3.6-88 3 Page TS / B 3.6-89 1 Page TS / B 3.3-90 3 Pages TS / B 3.6-91 through TS I 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 I B 3.6-100 and TS / B 3.6-101 1 Pages TS / B 3.6-102 through TS / B 3.6-104 2 Pages TS / B 3.6-105 and TS / B 3.6-106 .*. . 1 B 3.7 PLANT SYSTEMS BASES Pages TS I B 3.7-1 through TS / B 3.7-6 2 Page TS/B3.7-6a 2 Pages TS I B 3.7-6b and TS / B 3.7-6c 0 Page TSl B 3.7-7 2 PageTS/B3.7-8 1 Pages B 3.7-9 through B 3.7-11 0 Pages TS I B 3.7-12 and TS I B 3.7-13 1 Pages TS I B 3.7-14 through TS I B 3.7-18 2 Page TS I 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 3.8-4 0 Page TS / B 3.8-5 1 Page TS/B3.8-6 1 Revision 60 UNIT 22 TS/BLOES-5 SUSQUEHANNA - UNIT

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TS / B LOES-5 Revision 60

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

Section Title Revision Pages B 3.8-7 and B 3.8-8 0 Pages TS / B 3.8-9 through TS / B 3.8-11 1 Pages B 3.8-12 through B 3.8-18 0 Page TS / B 3.8-19 1 Pages B 3.8-20 through B 3.8-22 0 Page TS/B3.8-23 1 Page B 3.8-24 o Pages TS / B 3.8-25 and TS I 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 I B 3.8-39 through TS I B 3.8-55 0 Pages TS / B 3.8-56 through TS / B 3.8-64 1 Page TS / B 3.8-65 2 Page TS / B 3.8-66 2 Pages TS / B3.8-67 through TS / B 3.8-68 1 PageTS/B3.8-69 2 Pages B 3.8-70 through B 3.8-99 0 B3.9 REFUELING OPERATIONS BASES Pages TS / B 3.9-1 and TS / B 3.9-2 1 Page TS / B 3.9-2a 1 PagesTS/B3.9-3andTS/B3.9-4 1 Pages B 3.9-5 through B 3.9-30 0 B 3.10 SPECIAL OPERATIONS BASES PageTS/B3.10-1 :. . 1 Pages B 3.10-2 through B 3.1D-32 0 Page TS / B3.10-33 2 Pages B 3.10-34 through B 3.10-38 0 Page TS I B 3.10-39 2 TSB2 LOES 5120/05 SUSQUEHANNA - UNIT 2 TS / B LOES-6 Revision 60

PPL Rev. 1 Control Rod OPERABILITY B 3.1.3 B3.1 REACTIVITY CONTROL SYSTEMS B 3.1.3 Control Rod OPERABILITY BASES BACKGROUND Control rods are components of the control rod drive (CRD) System, which is the primary reactivity controI system for the reactor. In conjunction with the Reactor Protection System, the CRD System provides the means for the reliable control of reactivity changes to ensure under conditions of normal operation, including anticipated operational occurrences, that specified acceptable fuel design limits are not exceeded. In addition, the control rods provide the capability to hold the reactor core subcritical under all conditions and to limit the potential amount and rate of reactivity increase caused by a malfunction in the CRD System. The CRD System is designed to satisfy the requirements of GDC 26, GDC 27, GDC 28, and GDC 29 (Ref. 1).

The CRD System consists of 185 locking piston control rod drive mechanisms (CRDMs) and a hydraulic control unit for each drive mechanism. The locking piston type CRDM is a double acting hydraulic piston, which uses condensate water as the operating fluid. Accumulators provide additional energy for scram. An index tube and piston, coupled to the control rod, are locked at fixed increments by a collet mechanism. The collet fingers engage notches in the index tube to prevent unintentional withdrawal of the control rod, but without restricting insertion.

This Specification, along with LCO 3.1.4, "Control Rod Scram Times," and LCO 3.1.5, "Control Rod Scram Accumulators," ensure that the performance of the control rods in the event of a Design Basis Accident (DBA) or transient meets the assumptions used in the safety analyses of References 2, 3, and 4.

APPLICABLE The analytical methods and assumptions used in the evaluations involving

.SAFETY control rods are presented in References 2, 3, and 4. The control rods ANALYSES

provide the primary means for rapid reactivity control (reactor scram), for maintaining the reactor subcritical and for limiting the potential effects of reactivity insertion events caused by malfunctions in the CRD System.

(continued)

SUSQUEHANNA - UNIT 2 TS / B3.1-13 Revision 0

PPL Rev. 1 Control Rod OPERABILITY B 3.1.3 BASES APPLICABLE The capability to insert the control rods provides assurance that the SAFETY assumptions for scram reactivity in the DBA and transient analyses are ANALYSES not violated. Since the SDM ensures the reactor will be subcritical with (continued) the highest worth control rod withdrawn (assumed single failure), the additional failure of a second control rod to insert, if required, could invalidate the demonstrated SDM and potentially limit the ability of the CRD System to hold the reactor subcritical. If the control rod is stuck at an inserted position and becomes decoupled from the CRD, a control rod drop accident (CRDA) can possibly occur. Therefore, the requirement that all control rods be OPERABLE ensures the CRD System can perform its intended function.

The control rods also protect the fuel from damage which could result in release of radioactivity. The limits protected are the MCPR Safety Limit (SL) (see Bases for SL 2.1.1, "Reactor Core SLs," and LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)"), the 1% cladding plastic strain fuel design limit (see Bases for LCO 3.2.3, "LINEAR HEAT GENERATION RATE (LHGR)," and LCO 3.2.4, "Average Power Range Monitor (APRM) Gain and Setpoints"), and the fuel damage limit (see Bases for LCO 3.1.6, "Rod Pattern Control") during reactivity insertion events.

The negative reactivity insertion (scram) provided by the CRD System provides the analytical basis for determination of planit thermal limits and provides protection against fuel damage limits during a CRDA. The Bases for LCO 3.1.4, LCO 3.1.5, and LCO 3.1.6 discuss in more detail how the SLs are protected by the CRD System.

Control rod OPERABILITY satisfies Criterion 3 of the NRC Policy Statement (Ref. 5).

LCO The OPERABILITY of an individual control rod is based on a combination of factors, primarily, the scram insertion times, the control rod coupling integrity, and the ability to determine the control rod position. Accumulator OPERABILITY is addressed by LCO 3.1.5. The associated scram accumulator status for a control rod only affects the scram insertion times; therefore, an inoperable accumulator does not immediately require declaring a control rod inoperable. Although not all control rods are required to be OPERABLE to (continued)

SUSQUEHANNA - UNIT 2 TS / B3.1-14 Revision I

PPL Rev. 1 Control Rod OPERABILITY B 3.1.3 BASES LCO satisfy the intended reactivity control requirements, strict control over the (continued) number and distribution of inoperable control rods is required to satisfy the assumptions of the DBA and transient analyses.

APPLICABILITY In MODES I and 2, the control rods are assumed to function during a DBA or transient and are therefore required to be OPERABLE in these MODES. In MODES 3 and 4, control rods are not able to be withdrawn (except as permitted by LCO 3.10.3 and LCO 3.10.4) since the reactor mode switch is in shutdown and a control rod block is applied. This provides adequate requirements for control rod OPERABILITY during these conditions. Control rod requirements in MODE 5 are located in LCO 3.9.5, "Control Rod OPERABILITY-Refueling."

ACTIONS The ACTIONS Table is modified by a Note indicating that a separate Condition entry is allowed for each control rod. This is acceptable, since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable control rod. Complying with the Required Actions may allow for continued operation, and subsequent inoperable control rods are governed by subsequent Condition entry and application of associated Required Actions.

A.1. A.2. A.3 and A.4 A control rod is considered stuck if it will not insert by either CRD drive water or scram pressure. With a fully inserted control rod stuck, no actions are required as long as the control rod remains fully inserted. The Required Actions are modified by a Note, which allows the rod worth minimizer (RWM) to be bypassed if required to allow continued operation.

LCO 3.3.2.1, "Control Rod Block Instrumentation," provides additional requirements when the RWM is bypassed to ensure compliance with the CRDA analysis. With one withdrawn control rod stuck, the local scram reactivity rate assumptions may not be met if the stuck control rod separation criteria are not met. This separation criteria stipulates that a stuck control rod is equivalent to a "slow" control rod for purposes of separation requirements between "slow" control rods.

(continued)

SUSQUEHANNA - UNIT 2 ITS / B3.1-15 Revision 0

PPL Rev. 1 Control Rod OPERABILITY B 3.1.3 BASES ACTIONS A.1. A.2. A.3 and A.4 (continued)

Therefore, a verification that the separation criteria are met must be performed immediately. The separation criteria are not met if a) the stuck control rod occupies a position adjacent to two "slow' control rods, b) the stuck control rod occupies a position adjacent to one "slow" control rod and the one "slow" control rod is also adjacent to another "slow" control rod, or, c) if the stuck control rod occupies a location adjacent to one "slow" control rod when there is another pair of "slow" control rods adjacent to one another. Adjacent control rods include control rods that are either face or diagonally adjacent. The description of "sloW' control rods is provided in LCO 3.1.4, "Control Rod Scram Times." In addition, the associated control rod drive must be disarmed in 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months . The allowed Completion Time of 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months is acceptable, considering the reactor can still be shut down, assuming no additional control rods fail to insert, and provides a reasonable time to perform the Required Action in an orderly manner. Isolating the control rod from scram prevents damage to the CRDM. The control rod can be isolated from scram and normal insert and withdraw pressure, yet still maintain cooling water to the CRD.

Monitoring of the insertion capability of each withdrawn control rod must also be performed within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months from discovery of Condition A concurrent with THERMAL POWER greater than the low power setpoint (LPSP) of the RWM. SR 3.1.3.2 and SR 3.1.3.3 perform periodic tests of the control rod insertion capability of withdrawn control rods. Testing each withdrawn control rod ensures that a generic problem does not exist. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." The Required Action A.3 Completion Time only begins upon discovery of Condition A concurrent with THERMAL POWER greater than the actual LPSP of the RWM, since the notch insertions may not be compatible with the requirements of rod pattern control (LCO 3.1.6) and the RWM (LCO 3.3.2.1). The allowed Completion Time provides a reasonable time to test the control rods, considering the potential for a need to reduce power to perform the tests.

To allow continued operation with a withdrawn control rod stuck, an evaluation of adequate SDM is also required within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . Should a DBA or transient require a shutdown, to preserve the single failure criterion, an additional control rod would have to be assumed to fail to insert when (continued)

SUSQUEHANNA - UNIT 2 TS /B 3.1-16 Revision 0-

PPL Rev. 1 Control Rod OPERABILITY B 3.1.3 BASES ACTIONS A.1. A.2. A.3 and A.4 (continued) required. Therefore, the original SDM demonstration may not be valid.

The SDM must therefore be evaluated (by measurement or analysis) with the stuck control rod at its stuck position and the highest worth OPERABLE control rod assumed to be fully withdrawn.

The allowed Completion Time of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to verify SDM is adequate, considering that with a single control rod stuck in a withdrawn position, the remaining OPERABLE control rods are capable of providing the required scram and shutdown reactivity. Failure to reach MODE 4 is only likely if an additional control rod adjacent to the stuck control rod also fails to insert during a required scram. Even with the postulated additional single failure of an adjacent control rod to insert, sufficient reactivity control remains to reach and maintain MODE 3 conditions.

B.1 With two or more withdrawn control rods stuck, 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 . The occurrence of more than one control rod stuck at a withdrawn position increases the probability that the reactor cannot be shut down if required. Insertion of all insertable control rods eliminates the possibility of an additional failure of a control rod to insert.

The allowed Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems.

C.1 and C.2 With one or more control rods inoperable for reasons other than being stuck in the withdrawn position, operation may continue, provided the control rods are fully inserted (continued)

SUSQUEHANNA - UNIT 2 TS / B3.1-17 Revision 0

PPL Rev. 1 Control Rod OPERABILITY B 3.1.3 BASES ACTIONS C.1 and C.2 (continued) within 3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months and disarmed (electrically or hydraulically) within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

Inserting a control rod ensures the shutdown and scram capabilities are not adversely affected. The control rod is disarmed to prevent inadvertent withdrawal during subsequent operations. The control rods can be hydraulically disarmed by closing the drive water and exhaust water isolation valves. The control rods can be electrically disarmed by disconnecting power from all four directional control valve solenoids.

Required Action C.1 is modified by a Note, which allows the RWM to be bypassed if required to allow insertion of the inoperable control rods and continued operation. LCO 3.3.2.1 provides additional requirements when the RWM is bypassed to ensure compliance with the CRDA analysis.

The allowed Completion Times are reasonable, considering the small number of allowed inoperable control rods, and provide time to insert and disarm the control rods in an orderly manner and without challenging plant systems.

D.1 and D.2 Out of sequence control rods may increase the potential reactivity worth of a dropped control rod during a CRDA. At s 10% RTP, the generic banked position withdrawal sequence (BPWS) analysis requires inserted control rods not in compliance with BPWS to be separated by at least two OPERABLE control rods in all directions, including the diagonal.

Therefore, if two or more inoperable control rods are not in compliance with BPWS and not separated by at least two OPERABLE control rods, action must be taken to restore compliance with BPWS or restore the control rods to OPERABLE status. Condition D is modified by a Note indicating that the Condition is not applicable when > 10% RTP, since the BPWS is not required to be followed under these conditions, as described in the Bases for LCO 3.1.6. The allowed Completion Time of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is acceptable, considering the low probability of a CRDA occurring.

(continued)

SUSQUEHANNA - UNIT 2 TS / B3.1-18 Revision 0

PPL Rev. 1 Control Rod OPERABILITY B 3.1.3 BASES ACTIONS E.1 (continued)

In addition to the separation requirements for inoperable control rods, a BPWS assumption requires that no more than three inoperable control rods are allowed in any one BPWS group.

Therefore, with one or more BPWS groups having four or more inoperable control rods, control rods must be restored to OPERABLE status so that no BPWS group has four or more inoperable control rods. Required Action E.1 is modified by a Note indicating that the Condition is not applicable when THERMAL POWER is > 10% RTP since the BPWS is not required to be followed under these conditions, as described in the Bases for LCO 3.1.6. The allowed Completion Time of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is acceptable, considering the low probability of a CRDA occurring.

F.1 If any Required Action and associated Completion Time of Condition A, C, D, or E are not met, or there are nine or more inoperable control rods, 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 .

This ensures all insertable control rods are inserted and places the reactor in a condition that does not require the active function (i.e., scram) of the control rods. The number of control rods pemriitted to be inoperable when operating above 10% RTP (e.g., no CRDA considerations) could be more than the value specified, but the occurrence of a large number of inoperable control rods could be indicative of a generic problem, and investigation and resolution of the potential problem-should be undertaken. The allowed Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is reasonable, based on operating experience, to reach MODE 3 from full power in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.1.3.1 REQUIREMENTS The position of each control rod must be determined to ensure adequate information on control rod position is available to the operator for determining CRD OPERABILITY and controlling rod patterns. Control rod position may be (continued)

SUSQUEHANNA - UNIT 2 TS / B3.1-19 Revision 0

PPL Rev. 1 Control Rod OPERABILITY B 3.1.3 BASES SURVEILLANCE SR 3.1.3.1 (continued)

REQUIREMENTS determined by the use of OPERABLE position indicators, by moving control rods to a position with an OPERABLE indicator, or by the use of other appropriate methods. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency of this SR is based on operating experience related to expected changes in control rod position and the availability of control rod position indications in the control room.

SR 3.1.3.2 and SR 3.1.3.3 Control rod insertion capability is demonstrated by inserting each partially or fully withdrawn control rod at least one notch and observing that the control rod moves. The control rod may then be returned to its original position. This ensures the control rod is not stuck and is free to insert on

.a scram signal. These Surveillances are not required when THERMAL POWER is less than or equal to the actual LPSP of the RWM, since the notch insertions may not be compatible with the requirements of the' Banked Position Withdrawal Sequence (BPWS) (LCO 3.1.6) and the RWM (LCO 3.3.2.1). The 7 day Frequency of SR 3.1.3.2 is based on operating experience related to the changes in CRD performance and the ease of performing notch testing for fully withdrawn control rods. Partially withdrawn control rods are tested at a 31 day Frequency, based on the potential power reduction required to allow the control rod movement and considering the large testing sample of SR 3.1.3.2. Furthermore, the 31 day Frequency takes into account operating experience related to changes in CRD performance. At any time, if a control rod is immovable, a determination of that control rod's ability to trip (OPERABILITY) must be made and appropriate action taken.

SR 3.1.3.4 Verifying that the scram time for each control rod to notch position 05 is

< 7 seconds provides reasonable assurance that the control rod will insert when required during a DBA or transient, thereby completing its shutdown function. This SR is performed in conjunction with the control rod scram time testing of SR 3.1.4.1, SR 3.1.4.2, SR 3.1.4.3, and SR 3.1.4.4. The LOGIC SYSTEM FUNCTIONAL TEST in (continued)

SUSQUEHANNA - UNIT 2 TS /B 3.1-20 Revision 0

PPL Rev. 1 Control Rod OPERABILITY B 3.1.3 BASES SURVEILLANCE SR 3.1.3.4 (continued)

REQUIREMENTS LCO 3.3.1.1, "Reactor Protection System (RPS) Instrumentation," and the functional testing of SDV vent and drain valves in LCO 3.1.8, "Scram Discharge Volume (SDV) Vent and Drain Valves," overlap this Surveillance to provide complete testing of the assumed safety function.

The associated Frequencies are acceptable, considering the more frequent testing performed to demonstrate other aspects of control rod OPERABILITY and operating experience, which shows scram times do not significantly change over an operating cycle.

SR 3.1.3.5 Coupling verification is performed to ensure the control rod is connected to the CRDM and will perform its intended function when necessary. The Surveillance requires verifying a control rod does not go to the withdrawn overtravel position. The overtravel position feature provides a positive check on the coupling integrity since only an uncoupled CRD can reach the overtravel position. The verification is required to be performed any time a control rod is withdrawn to the "full out" position (notch position 48) or prior to declaring the control rod OPERABLE after work on the control rod or CRD System that could affect coupling. This includes control rods inserted one notch and then returned to the "full out" position during the performance of SR 3.1.3.2. This Frequency is acceptable, considering the low probability that a control rod will become uncoupled when it is not being moved and operating experience related to uncoupling events.

REFERENCES 1. 10 CFR 50, Appendix A GDC 26, GDC 27, GDC 28, and GDC 29.

2. FSAR, Section 4.3.2

3. FSAR, Section 4.6

4. FSAR, Section 15.

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

SUSQUEHANNA - UNIT 2 TS / B3.1-21 IRevision 0-

PPL Rev. 2 Control Rod Scram Times B 3.1.4 B3.1 REACTIVITY CONTROL SYSTEMS B 3.1.4 Control Rod Scram Times BASES BACKGROUND The scram function of the'Control Rod Drive-(CRD) System controls reactivity changes during abnormal operational transients to ensure that specified acceptable fuel design limits are not exceeded (Ref. 1). The control rods are scrammed by positive means using hydraulic pressure exerted on the CRD piston.

When a scram signal is initiated, control air is vented from the scram valves, allowing them to open by spring action. Opening the exhaust valve reduces the pressure above the main drive piston to atmospheric pressure, and opening the inlet valve applies the accumulator or reactor pressure to the bottom of the piston. Since the notches in the index tube are tapered on the lower edge, the collet fingers are forced open by cam action, allowing the index tube to move upward without restriction because of the high differential pressure across the piston. As the drive moves upward and the accumulator pressure reduces below the reactor pressure, a ball check valve opens, letting the reactor pressure complete the scram action. If the reactor pressure is low, such as during startup, the accumulator will fully insert the control rod in the required time without assistance from reactor pressure.

APPLICABLE The analytical methods and assumptions used in evaluating the control SAFETY rod scram function are presented in References 2, 3, and 4. The Design ANALYSES Basis Accident (DBA) and transient analyses assume that all of the control rods scram at a specified insertion rate. The resulting negative scram reactivity forms the basis for the determination of plant thermal limits (e.g.,

the MCPR). Other distributions of scram times (e.g., several control rods scramming slower than the average time with several control rods scramming faster than the average time) can also provide sufficient scram reactivity. Surveillance of each individual control rod's scram time ensures the scram reactivity assumed in the DBA and transient analyses can be met.

(continued)

SUSQUEHANNA - UNIT 2 B 3.1-22 Revision 0

PPL Rev. 2 Control Rod Scram Times B 3.1.4 BASES APPLICABLE* The scram function of the CRD System protects the MCPR Safety Limit SAFETY (SL) (see Bases for SL 2.1.1, "Reactor Core SLs," and LCO 3.2.2, ANALYSES "MINIMUM CRITICAL POWER RATIO (MCPR)') and the 1% cladding (continued) plastic strain fuel design limit (see Bases for.LCO 3.2.3, "LINEAR HEAT GENERATION RATE (LHGR)" and LCO 3.2.4, "Average Power Range Monitor (APRM) Gain and Setpoints"), which ensure that no fuel damage will occur if these limits are not exceeded. Above 800 psig, the scram function is designed to insert negative reactivity at a rate fast enough to prevent the actual MCPR from becoming less than the MCPR SL, during the analyzed limiting power transient. Below 800 psig, the scram function is assumed to perform during the control rod drop accident and, therefore, also provides protection against violating fuel damage limits during reactivity insertion accidents (Ref. 5) (see Bases for LCO 3.1.6, "Rod Pattern Control'). For the reactor vessel overpressure protection analysis, the scram function, along with the safety/relief valves, ensure that the peak vessel pressure is maintained within the applicable ASME Code limits.

Control rod scram times satisfy Criterion 3 of the NRC Policy Statement (Ref. 6).

LCO The scram times specified in Table 3.1;4-1 (in the accompanying LCO) are required to ensure that the scram reactivity assumed in the DBA and transient analysis is met (Ref. .7). To account for single failures and "slow" scramming control rods, the scram times specified in Table 3.1.4-1 are faster than those assumed in the design basis analysis. The scram times have a margin that allows up to approximately 7% of the control rods (e.g.,

185 x 7% = 13) to have scram times exceeding the specified limits (i.e.,

"sloW' control rods) including a single stuck control rod (as allowed by LCO 3.1.3, "Control Rod OPERABILITY") and an additional control rod failing to scram per the single failure criterion. The scram times are specified as a function of reactor steam dome pressure to account for the pressure dependence of the scram times. The scram times are specified relative to measurements based on reed switch positions, which provide the control rod position indication. The reed switch closes C'pickup') when the index tube passes a specific location and then opens ('dropout") as the index tube travels upward. Verification of the specified scram times in Table 3.1.4-1 is (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.1-23 Revision I

PPL Rev. 2 Control Rod Scram Times B 3.1.4 BASES LCO accomplished through measurement of the "dropout" times. To ensure (continued) that local scram reactivity rates are maintained within acceptable limits, no more than one "slow' control rod may occupy a face or diagonally adjacent location to any other "slow" or stuck control rod.

Table 3.1.4-1 is modified by two Notes which state that control rods with scram times not within the limits of the table are considered "slow" and that control rods with scram times > 7 seconds are considered inoperable as required by SR 3.1.3.4.

This LCO applies only to OPERABLE control rods since inoperable control rods will be inserted and disarmed (LCO 3.1.3). Slow scramming control rods may be conservatively declared inoperable and not accounted for as "slow" control rods.

APPLICABILITY In MODES 1 and 2, a scram is assumed to function during transients and accidents analyzed for these plant conditions. These events are assumed to occur during startup and power operation; therefore, the scram function of the control rods is required during these MODES. In MODES 3 and 4, the control rods are not able to be withdrawn (except as permitted by LCO 3.10.3 and LCO 3.10.4) since the reactor mode switch is in shutdown and a control rod block is applied. This provides adequate requirements for control rod scram capability during these conditions. Scram requirements in MODE 5 are contained in LCO 3.9.5, "Control Rod OPERABILITY-Refueling."

ACTIONS A.1 When the requirements of this LCO are not met, the rate of negative reactivity insertion during a scram may not be within the assumptions of the safety analyses. Therefore, 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 . The allowed Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems.

(continued)

SUSQUEHANNA - UNIT 2 B 3.1-24 Revision 0

PPL Rev. 2 Control Rod Scram Times B 3.1.4 BASES (continued)

SURVEILLANCE The four SRs of this LCO are modified by a Note stating that during a REQUIREMENTS single control rod scram time surveillance, the CRD pumps shall be isolated from the associated scram accumulator. With the CRD pump isolated, (i.e., charging valve closed) the influence of the CRD pump head does not affect the single control rod scram times. During a full core scram, the CRD pump head would be seen by all control rods and would have a negligible effect on the scram insertion times.

SR 3.1.4.1 The scram reactivity used in DBA and transient analyses is based on an assumed control rod scram time. Measurement of the scram times with reactor steam dome pressure 2 800 psig demonstrates acceptable scram times for the transients analyzed in References 3 and 4.

Maximum scram insertion times occur at a reactor steam dome pressure of approximately 800 psig because of the competing effects of reactor steam dome pressure and stored accumulator energy. Therefore, demonstration of adequate scram times at reactor steam dome pressure 2800 psig ensures that the measured scram times will be within the specified limits at higher pressures. Umits are specified as a function of reactor pressure to account for the sensitivity of the scram insertion times with pressure and to allow a range of pressures bver which scram time testing can be performed. To ensure that scram time testing is performed within a reasonable time following fuel movement within the reactor pressure vessel after a shutdown 2 120 days or longer, control rods are required to be tested before exceeding 40% RTP foUowing the shutdown.

In the event fuel movement is limited to selected core cells, it is the intent of this SR that only those CRDs associated with the core cells affected by the fuel movement are required to be scram time tested. However, if the reactor remains shutdown 2 120 days, all control rods are required to be scram time tested. This Frequency is acceptable considering the additional surveillances performed for control rod OPERABILITY, the frequent verification of adequate accumulator pressure, and the required testing of control rods affected by work on control rods or the CRD System.

(continued)

SUSQUEHANNA - UNIT 2 B 3.1-25 Revision 0

PPL Rev. 2 Control Rod Scram Times B 3.1.4 BASES SURVEILLANCE SR 3.1.4.2 REQUIREMENTS (continued) Additional testing of a sample of control rods is required to verify the continued performance of the scram function during the cycle. A representative sample contains at least 10% of the control rods. The sample remains representative if no more than 20% of the control rods in the sample tested are determined to be "slow." With more than 20% of the sample declared to be "slow" per the criteria in Table 3.1.4-1, additional control rods are tested until this 20% criterion (e.g., 20% of the entire sample size) is satisfied, or until the total number of "slow" control rods (throughout the core, from all surveillances) exceeds the LCO limit.

For planned testing, the control rods selected for the sample should be different for each test. Data from inadvertent scrams should be used whenever possible to avoid unnecessary testing at power, even if the control rods with data may have been previously tested in a sample. The 120 day Frequency is based on operating experience that has shown control rod scram times do not significantly change over an operating cycle. This Frequency is also reasonable based on the additional Surveillances done on the CRDs at more frequent intervals in accordance with LCO 3.1.3 and LCO 3.1.5, "Control Rod Scram Accumulators."

SR 3.1.4.3 When work that could affect the scram insertion time is performed on a control rod or the CRD System, testing must be done to demonstrate that each affected control rod retains adequate scram performance over the range of applicable reactor pressures from zero to the maximum permissible pressure. The scram testing must be performed once before declaring the control rod OPERABLE. The required scram time testing must demonstrate the affected control rod is still within acceptable limits.

The limits for reactor pressures < 800 psig are established based on a high probability of meeting the acceptance criteria at reactor pressures 2 800 psig. Limits for > 800 psig are found in Table 3.1.4-1. If testing demonstrates the affected control rod does not meet these limits, but is within the 7-second limit of Table 3.1.4-1, Note 2, the control rod can be declared OPERABLE and "slow."

(continued)

SUSQUEHANNA - UNIT 2 B 3.1-26 Revision 0

PPL Rev. 2 Control Rod Scram Times B 3.1.4 BASES SURVEILLANCE SR 3.1.4.3 (continued)

REQUIREMENTS Specific examples of work that could affect the scram times are (but are not limited to) the following: removal of any CRD for maintenance or modification; replacement of a control rod; and maintenance or modification of a scram solenoid pilot valve, scram valve, accumulator, isolation valve or check valve in the piping required for scram.

The Frequency of once prior to declaring the affected control rod OPERABLE is acceptable because of the capability to test the control rod over a range of operating conditions and the more frequent surveillances on other aspects of control rod OPERABILITY.

SR 3.1.4.4 When work that could affect the scram insertion time is performed on a' control rod or CRD System, testing must be done to demonstrate each affected control rod is still within the limits of Table 3:1.4-1 with the reactor steam dome pressure 2 800 psig. Where work has been performed at high reactor pressure, the requirements of SR 3.1.4.3 and SR 3.1.4.4 can be satisfied with one test. For a control rod affected by work performed while shut down, however, a zero pressure and high pressure test may be required. This testing ensures that, prior to withdrawing the control rod for continued operation, the control rod scram performance is acceptable for operating reactor pressure conditions. Altematively, a control rod scram test during hydrostatic pressure testing could also satisfy both criteria.

The Frequency of once prior to exceeding 40% RTP is acceptable because of the capability to test the control rod over a range of operating conditions and the more frequent surveillances on other aspects of control rod OPERABILITY.

REFERENCES 1. 10 CFR 50, Appendix A, GDC 10.

2. FSAR, Section 4.3.2.

3. FSAR, Section 4.6.

(continued)

SUSQUEHANNA - UNIT 2 B 3.1-27 Revision 0

PPL Rev. 2 Control Rod Scram Times B 3.1.4 BASES REFERENCES 4. FSAR, Section 15.0 (continued)

5. FSAR, Section 15.4.9. 1-

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

7. Letter from R. F. Janecek (BWROG) to R.W. Starostecki (NRC),

"BWR Owners Group Revised Reactivity Control System Technical Specifications," BWROG-8754,' September 17, 1987.

SUSQUEHANNA - UNIT 2 TS / B 3.1-28 Revision 2

PPL Rev. 1 Control Rod Scram Accumulators B 3.1.5 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.5 Control Rod Scram Accumulators BASES BACKGROUND The control rod scram accumulators are partof the Control Rod Drive (CRD) System and are provided to ensure that the control rods scram under varying reactor conditions. The control rod scram accumulators store sufficient energy to fully insert a control rod at any reactor vessel pressure. The accumulator is a hydraulic cylinder with a free floating piston. The piston separates the water used to scram the control rods from the nitrogen, which provides the required energy. The scram accumulators are necessary to scram the control rods within the required insertion times of LCO 3.1.4, "Control Rod Scram Times."

APPLICABLE The analytical methods and assumptions used in evaluating the control SAFETY rod scram function are presented in References 1, 2, and 3. The Design ANALYSES Basis Accident (DBA) and transient analyses assume that all of the control rods scram at a specified insertion rate. OPERABILITY of each individual control rod scram accumulator, along with LCO 3.1.3, "Control Rod OPERABILITY," and LCO 3.1.4, ensures that the scram reactivity assumed in the DBA and transient analyses can be met. The existence of an inoperable accumulator may invalidate prior scram time measurements for the associated control rod.

The scram function of the CRD System, and therefore the OPERABILITY of the accumulators, protects the MCPR Safety Limit (see Bases for SL 2.1.1, "Reactor Core SLs," and LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)") and 1% cladding plastic strain fuel design limit LCO 3.2.3 "LINEAR HEAT GENERATION RATE (LHGR)" and LCO 3.2.4, uAverage Power Range Monitor (APRM) Gain and Setpoints'),

which ensure that no fuel damage will occur if these limits are not exceeded (see Bases for LCO 3.1.4). In addition, the scram function at low reactor vessel pressure (i.e., startup conditions) provides protection against violating fuel design limits during reactivity insertion accidents (see Bases for LCO 3.1.6, "Rod Pattem Control').

Control rod scram accumulators satisfy Criterion 3 of the NRC Policy Statement (Ref. 4).

(continued)

SUSQUEHANNA - UNIT 2 TS / B3.1-29 Revision I

'PPL Rev. 1 Control Rod Scram Accumulators B 3.1.5 BASES (continued)

LCO The OPERABILITY of the control rod scram accumulators is required to ensure that adequate scram insertion capability exists when needed over the entire range of reactor pressures. The OPERABILITY of the scram accumulators is based on maintaining adequate accumulator pressure.

APPLICABILITY In MODES 1 and 2, the scram function is required for mitigation of DBAs and transients, and therefore the scram accumulators must be OPERABLE to support the scram function. In MODES 3 and 4, control rods can not be withdrawn (except as permitted by LCO 3.10.3 and LCO 3.10.4) since the reactor mode switch is in shutdown and a control rod block is applied. This provides adequate requirements for control rod scram accumulator OPERABILITY during these conditions.

Requirements for scram accumulators in MODE 5 are contained in LCO 3.9.5, "Control Rod OPERABILITY-Refueling."

ACTIONS The ACTIONS table is modified by a Note indicating that a separate Condition entry is allowed for each control rod scram accumulator. This is acceptable since the Required Actions for each Condition provide appropriate compensatory actions for each affected accumulator.

Complying with the Required Actions.may allow for continued operation and subsequent affected accumulators governed by subsequent Condition entry and application of associated Required Actions.

A.1 and A.2 With one control rod scram accumulator inoperable and the reactor steam dome pressure 2 900 psig, the control rod may be declared "slow,"

since the control rod will still scram at the reactor operating pressure but may not satisfy the required scram times in Table 3.1.4-1.

Required Action A.1 is modified by a Note indicating that declaring the control rod "slow' only applies if the associated control scram timerwas within the limits of Table 3.1.4-1 during the last scram time test.

Otherwise, the control rod would already be considered "slow" and the further degradation of scram performance with an inoperable (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.1-30 Revision 0

PPL Rev. I Control Rod Scram Accumulators B 3.1.5 BASES ACTIONS A.1 and A.2 (continued) accumulator could result in excessive scram times. In this event, the associated control rod is declared inoperable (Required Action A.2) and LCO 3.1.3 is entered. This would result in requiring the affected control rod to be fully inserted and disarmed, thereby satisfying its intended function, in accordance with ACTIONS of LCO 3.1.3.

The allowed Completion Time of 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months is reasonable, based on the large number of control rods available to provide the scram function and the ability of the affected control rod to scram only with reactor vessel at high reactor pressures.

B.1. B.2.1. and B.2.2 With two or more control rod scram accumulators inoperable and reactor steam dome pressure 2 900 psig, adequate pressure must be supplied to the charging water header. With inadequate charging water pressure, all of the accumulators could become inoperable, resulting in a potentially severe degradation of the scram performance. Therefore, within 20 minutes from discovery of charging water header pressure < 940 psig concurrent with Condition B, adequate charging water header pressure must be restored. The allowed Completion Time-of 20 minutes is reasonable, to place a CRD pump into service to restore the charging header pressure, if required. This Completion Time is based on the ability of the reactor pressure alone to fully insert all control rods.

The control rod may be declared "slow," since the control rod will still scram using only reactor pressure, but may not satisfy the times in Table 3.1.4-1. Required Action B.2.1 is modified by a Note indicating that declaring the control rod "slow' only applies if the associated control scram time is within the limits of Table 3.1.4-1 during the last scram time test. Otherwise, the control rod would already be considered "slow" and the further degradation of scram performance with an inoperable accumulator could result in excessive scram times. In this event, the associated control rod is declared inoperable (Required Action B.2.2) and LCO 3.1.3 entered. This would result in requiring the affected control rod to be fully (continued)

SUSQUEHANNA - UNIT 2 TS / B3.1-31 Revision 0

PPL Rev. 1 Control Rod Scram Accumulators B 3.1.5 BASES ACTIONS B.1. B.2.1. and B.2.2 (continued) inserted and disarmed, thereby satisfying its intended function in accordance with ACTIONS of LCO 3.1.3.

The allowed Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is reasonable, based on the ability of only the reactor pressure to scram the control rods and the low probability of a DBA or transient occurring while the affected accumulators are inoperable.

C.1 and C.2 With one or more control rod scram accumulators inoperable and the reactor steam dome pressure < 900 psig, the pressure supplied to the charging water header must be adequate to ensure that accumulators remain charged. With the reactor steam dome pressure < 900 psig, the function of the accumulators in providing the scram force becomes much more important since the scram function could become severely degraded during a depressurization event or at low reactor pressures.

Therefore, immediately upon discovery of charging water header pressure < 940 psig, concurrent with Condition C, all control rods associated with inoperable accumulators must be verified to be fully inserted. Withdrawn control rods with inoperabl6 accumulators may fail to scram under these low pressure conditions. The associated control rods must also be declared inoperable within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .. The allowed Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is reasonable for Required Action C.2, considering the low probability of a DBA or transient occurring during the time that the accumulator is inoperable.

D.1 The reactor mode switch must be immediately placed in the shutdown position if either Required Action and associated Completion Time associated with loss of the CRD charging pump (Required Actions B.1 and C.1) cannot be met. This ensures that all insertable control rods are inserted and that the reactor is in a condition that does not require the active function (i.e., scram) of the control rods. This Required Action is modified by a Note stating that the action is not applicable if all control rods associated with (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.1-32 Revision 0

PPL Rev. I Control Rod Scram Accumulators B 3.1.5 BASES ACTIONS D.1 (continued) the inoperable scram accumulators are fully inserted, since the function of the control rods has been performed.

SURVEILLANCE SR 3.1.5.1 REQUIREMENTS SR 3.1.5.1 requires that the accumulator nitrogen pressure be checked every 7 days to ensure adequate accumulator pressure exists to provide sufficient scram force. The primary indicator of accumulator OPERABILITY is the accumulator nitrogen pressure. A minimum accumulator nitrogen pressure is specified, below which the capability of the accumulator to perform its intended function becomes degraded and the accumulator is considered inoperable. The minimum accumulator nitrogen pressure of 940 psig is well below the expected pressure of approximately 1100 psig (Ref. 1). Declaring the accumulator inoperable when the minimum pressure is not maintained ensures that significant degradation in scram times does not occur. The 7 day Frequency has been shown to be acceptable through operating experience and takes into account indications available in the control room.

REFERENCES 1. FSAR, Section 4.3.2.

2. FSAR, Section 4.6.

3. FSAR, Section 15.

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

SUSQUEHANNA - UNIT 2 TS / B3.1-33 Revision 0

-PPL Rev. 1

- . .APRM Gain and Setpoints B 3.2.4 B 3.2 POWER DISTRIBUTION LIMITS B 3.2.4 Average Power Range Monitor (APRM) Gain and Setpoints BASES BACKGROUND The OPERABILITY of the APRMs and their setpoints is an initial condition of all safety analyses that assume rod insertion upon reactor scram. Applicable GDCs are GDC 10, "Reactor Design," GDC 13, "Instrumentation and Control," GDC 20, "Protection System Functions,"

and GDC 23, "Protection against Anticipated Operation Occurrences" (Ref. 1). This LCO is provided to require the APRM gain orAPRM flow biased scram setpoints to be adjusted when operating under conditions of excessive power peaking to maintain acceptable margin to the fuel transient mechanical design limit (i.e., Protection Against Power Transient (PAPT) limit).

The condition of excessive power peaking is determined by the ratio of the actual power peaking to the limiting power peaking at RTP. This ratio is equal to the ratio of the core limiting MFLPD to the Fraction 6f RTP (FRTP), where FRTP is the measured THERMAL POWER divided by the RTP. Excessive power peaking exists when:

MFLPD FRTP indicating that MFLPD is not decreasing proportionately to the overall power reduction, or conversely, that power peaking is increasing. To maintain margins similar to those at RTP conditions, the excessive power peaking is compensated by a gain adjustment on the APRMs or adjustment of the APRM setpoints. Either of these adjustments has effectively the same result as maintaining MFLPD less than or equal to FRTP to ensure the PAPT limits are not violated under steady state or transient conditions.

The normally selected APRM setpoints position the scram above the upper bound of the normal power/flow operating region that has been considered in the design of the fuel rods. The setpoints are flow biased with a slope that approximates the upper flow control line, such that an approximately constant margin is maintained between the flow biased trip level and the upper operating boundary for core flows in excess of about 45% of rated core flow. In the range of infrequent operations below 45% of rated core flow, the margin to scram is reduced because of the nonlinear core flow versus drive flow relationship. The normally selected (continued)

SUSQUEHANNA - UNIT 2 TS / B3.2-14 Revision I

PPL Rev. 1 APRM Gain and Setpoints B 3.2.4 BASES BACKGROUND APRM setpoints are supported by the analyses that concentrate on (continued) events initiated from rated conditions. Design experience has shown that minimum deviations occur within expected margins to operating limits (APLHGR, LHGR and MCPR), at rated conditions for normal power distributions. However, at other than rated conditions, control rod patterns can be established that significantly reduce the margin to thermal limits. Therefore, the flow biased APRM scram setpoints may be reduced during operation when the combination of THERMAL POWER and MFLPD indicates an excessive power peaking distribution.

The APRM neutron flux signal is also conditioned to more closely follow the fuel cladding heat flux during power transients. The APRM neutron flux signal is a measure of the core thermal power during steady state operation. During power transients, the APRM signal leads the actual core thermal power response because of the fuel thermal time constant. Therefore, on power increase transients, the APRM signal provides a conservatively high measure of core thermal power. By passing the APRM signal through an electronic filter with a time constant approximately equal to, that of the fuel thermal time constant, an APRM transient response that more. closely follows actual fuel cladding heat flux is obtained. The delayed response of the filtered APRM signal allows the flow biased APRM scram levels to be positioned closer to the upper bound of the normal power and flow range, without unnecessarily causing reactor scrams during short duration neutron flux spikes. These spikes can be caused by insignificant transients such as performance of main steam line valve surveillances or momentary flow increases of only several percent.

APPLICABLE The acceptance criteria for the APRM gain or setpoint adjustments are SAFETY ANALYSES that acceptable margins be maintained to the fuel transient mechanical design limit (PAPT).

FSAR safety analyses (Refs. 2 and 3) concentrate on the rated power condition for which the minimum expected margin to the operating limits (APLHGR, LHGR and MCPR) occurs. LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)," LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)," and LCO 3.2.3, "LINEAR HEAT GENERATION RATE (LHGR)," limit the initial margins to these operating limits at rated conditions so that specified acceptable fuel design limits are met during transients initiated from rated conditions. At initial power levels less than rated levels, the margin degradation of either the LHGR or the MCPR during a transient can be greater than at the rated condition (continued)

SUSQUEHANNA - UNIT 2 TS / B3.2-15 Revision 1

PPL Rev. I APRM Gain and Setpoints B 3.2.4 BASES APPLICABLE event. This greater margin degradation during the transient is primarily SAFETY ANALYSES offset by the larger initial margin to limits at the lower than rated power (continued) levels. However, power distributions can be-hypothesized that would result in reduced margins to the pre-transient operating limit When combined with the increased severity of certain transients at other than rated conditions, the SLs could be approached. At substantially reduced power levels, highly peaked power distributions could be obtained that could reduce thermal margins to the minimum levels required for transient events. To prevent or mitigate such situations, the MCPR margin degradation at reduced power and flow is factored into the power and flow dependent MCPR limits (LCO 3.2.2). For LHGR (Ref. 4), either the APRM gain is adjusted upward by the ratio of the core limiting MFLPD to the FRTP, or the flow biased APRM scram level is reduced by the ratio of FRTP to the core limiting MFLPD. The adjustment in the APRM gain can be performed provided it is during power ascension up to 90% of RATED THERMAL POWER, that the adjusted APRM readings do not exceed 100% of RATED THERMAL POWER, the required gain adjustment increment does not exceed 10% of RATED THERMAL POWER, and a notice of the adjustment is posted on the reactor control panel. Either of these adjustments effectively counters the increased severity of some events at other than rated conditions by proportionally increasing the APRM gain or proportionally lowering the flow biased APRM scram setpoints, dependent on the increased peaking that may be encountered.

I The APRM gain and setpoints satisfy Criteria 2 and 3 of the NRC Policy Statement (Ref. 5). I LOC Meeting any one of the following conditions ensures acceptable operating margin to the transient mechanical design limit (PAPT) for events described above:

a. Limiting excess power peaking;

b. Reducing the APRM flow biased neutron flux upscale scram setpoints by multiplying the APRM setpoints by the ratio of FRTP and the core limiting value of MFLPD; or

c. Increasing APRM gains to cause the APRM to read greater than 100 times MFLPD (in %). This condition is to account for the reduction in margin to the fuel cladding integrity SL and the fuel cladding 1% plastic strain limit.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.2-16 Revision I

PPL Rev. 1 APRM Gain and Setpoints B 3.2.4 BASES (continued)

LCO MFLPD is the ratio of the limiting LHGR to the LHGR limit for APRM (continued) setpoints for the specific bundle type. As power is reduced, if the design power distribution is maintained, MFLPD is reduced in proportion to the reduction in power. However, if power peaking increases above the design value, the MFLPD is not reduced in proportion to the reduction in power. Under these conditions, the APRM gain is adjusted upward or the APRM flow biased scram setpoints are reduced accordingly. When the reactor is operating with peaking less than the design value, it is not necessary to modify the APRM flow biased scram setpoints. Adjusting APRM gain or setpoints is equivalent to MFLPD less than or equal to FRTP, as stated in the LCO.

For compliance with LCO Item b (APRM setpoint adjustment) or Item c (APRM gain adjustment), only APRMs required to be OPERABLE per LCO 3.3.1.1, "Reactor Protection System (RPS) Instrumentation," are required to be adjusted. In addition, each APRM may be allowed to have its gain or setpoints adjusted independently of other APRMs that are having their gain or setpoints adjusted.

APPLICABILITY The MFLPD limit, APRM gain adjustment, and APRM flow biased scram and associated setdowns are provided to ensure that the fuel transient mechanical design limit (PAPT) is not violated during design basis transients. As discussed in the Bases for LCO 3.2.1, LCO 3.2.2, and LCO 3.2.3, sufficient margin to these limits exists below 25% RTP and, therefore, these requirements are only necessary when the reactor is operating at 2 25% RTP.

ACTIONS A.1 If the APRM gain or setpoints are not within limits while the MFLPD has exceeded FRTP, the margin to the fuel transient mechanical design limit (PAPT) may be reduced. Therefore, prompt action should be taken to restore the MFLPD to within its required limit or make acceptable APRM adjustments such that the plant is operating within the assumed margin of the safety analyses.

The 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Completion Time is normally sufficient to restore either the MFLPD to within limits or the APRM gain or setpoints to within limits and is acceptable based on the low probability of a transient or Design Basis Accident occurring simultaneously with the LCO not met.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.2-17 Revision 1

PPL Rev. 1 APRM Gain and Setpoints B 3.2.4 BASES ACTIONS A.1 (continued)

The APRM setpoints include the APRM Rod Block Flow Bias Neutron Flux Upscale Setpoint which is controlled in the Technical Requirements Manual 3.1.3 "Control Rod Block Instrumentation."

B.1 If MFLPD cannot be restored to within its required limits within the associated Completion Time, the plant must be brought to a MODE or other specified condition in which the LCO does not apply. To achieve this status, THERMAL POWER is reduced to < 25% RTP within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . The allowed Completion Time is reasonable, based on operating experience, to reduce THERMAL POWER to < 25% RTP in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.2.4.1 and SR 3.2.4.2 REQUIREMENTS The MFLPD is required to be calculated and compared to FRTP or APRM gain or setpoints to ensure that the reactor is operating within the assumptions of the safety analysis. These SRs are only required to determine the MFLPD and, assuming MFLPD is greater than FRTP, the appropriate gain or setpoint, and is not intended to be a CHANNEL FUNCTIONAL TEST for the APRM gain or flow biased neutron flux scram circuitry. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency of SR 3.2.4.1 is chosen to coincide with the determination of other thermal limits, specifically those for the LHGR (LCO 3.2.3). The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is based on both engineering judgment and recognition of the slowness of changes in power distribution during normal operation. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months allowance after THERMAL POWER 2 25% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels and because the MFLPD must be calculated prior to exceeding 50% RTP unless performed in the previous 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . When MFLPD is greater than FRTP, SR 3.2.4.2 must be performed. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency of SR 3.2.4.2 requires a more frequent verification when MFLPD is greater than the fraction of rated thermal power (FRTP) because more rapid changes in power distribution are typically expected.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.2-18 Revision 2

PPL Rev. I APRM Gain and Setpoints B 3.2.4 BASES (continued)

REFERENCES 1. 10 CFR 50, Appendix A, GDC 10, GDC 13, GDC 20, and GDC 23.

2. FSAR, Section 4.

3. FSAR, Section 15.

4. ANF-89-98(P)(A) Revision I and Revision 1 Supplement 1, "Generic Mechanical Design Criteria for BWR Fuel Designs,"

Advanced Nuclear Fuels Corporation, May 1995.

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

SUSQUEHANNA - UNIT 2 TS / B3.2-19 Revision I

PPL Rev. 2 RPS Instrumentation B 3.3.1.1 B 3.3 INSTRUMENTATION B 3.3.1.1 Reactor Protection System (RPS) Instrumentation BASES BACKGROUND The RPS initiates a reactor scram when one or more monitored parameters exceed their specified limits, to preserve the integrity of the fuel cladding and the Reactor Coolant System (RCS) and minimize the energy that must be absorbed following a loss of coolant accident (LOCA). This can be accomplished either automatcally or manually.

The protection and monitoring functions of the RPS have been designed to ensure safe operation of the reactor. This is achieved by specifying limiting safety system settings (LSSS) in terms of parameters directly monitored by the RPS, as well as LCOs on other reactor system parameters and equipment performance. The LSSS are defined in this Specification as the Allowable Values, which, in conjunction with the LCOs, establish the threshold for protective system action to prevent exceeding acceptable limits, including Safety Umits (SLs) during Design Basis Accidents (DBAs).

The RPS, as shown in the FSAR, Figure 7.2-1 (Ref. 1), includes sensors, relays, bypass circuits, and switches..that are necessary to cause initiation of a reactor scram. Functional diversity is provided by monitoring a wide range of dependent and independent parameters.

The input parameters to the scram logic are from instrumentation that monitors reactor vessel water level, reactor vessel pressure, neutron flux, main steam line isolation valve position, turbine control valve (TCV) fast closure trip oil pressure, turbine stop valve (TSV) position, drywell pressure, and scram discharge volume (SDV) water level, as well as reactor mode switch in shutdown position and manual scram signals. There are at least four redundant sensor input signals from each of these parameters (with the exception of the reactor mode switch in shutdown scram signal). When the setpoint is reached, the channel sensor actuates, which then outputs an RPS trip signal to the trip logic. Table B 3.3.1.1-1 summarizes the diversity of sensors capable of initiating scrams during anticipated operating transients typically analyzed.

The RPS is comprised of two independent trip systems (A and B) with two logic channels in each trip system (logic (continued)

SUSQUEHANNA - UNIT 2 TS / B3.3-1 Revision 1

PPL Rev. 2 RPS Instrumentation B 3.3.1.1 BASES BACKGROUND channels Al and A2, BI and B2) as shown in Reference 1. The (continued) outputs of the logic channels in a trip system are combined in a one-out-of-two logic so that either channel can trip the associated trip system. The tripping of both trip systems will produce a reactor scram.

This logic arrangement is referred to as a one-out-of-two taken twice logic. Each trip system can be reset by use of a reset switch. If a full scram occurs (both trip systems trip), a relay prevents reset of the trip systems for 10 seconds after the full scram signal is received. This 10 second delay on reset ensures that the scram function will be completed.

Two AC powered scram pilot solenoids are located in the hydraulic control unit for each control rod drive (CRD). Each scram pilot valve is operated with the solenoids normally energized. The scram pilot valves control the air supply to the scram inlet and outlet valves for the associated CRD. When either scram pilot valve solenoid is energized, air pressure holds the scram valves closed and, therefore, both scram pilot valve solenoids must be de-energized to cause a control rod to scram. The scram valves control the supply and discharge paths for the CRD water during a scram. One of the scram pilot valve solenoids for each CRD is controlled by trip system A, and the other solenoid is controlled by trip system B. Any trip of trip system A in conjunction with any trip in trip system B results in de-energizing both solenoids, air bleeding off, scram valves opening, and control rod scram.

The DC powered backup scram valves, which energize on a scram signal to depressurize the scram air header, are also controlled by the RPS. Additionally, the RPS System controls the SDV vent and drain valves such that when both trip systems trip, the SDV vent and drain valves close to isolate the SDV.

APPLICABLE The actions of the RPS are assumed in the safety analyses of SAFETY References 3, 4, 5 and 6. The RPS initiates a reactor scram before the ANALYSES, LCO, monitored parameter values reach the Allowable Values, specified by the and APPLICABILITY setpoint methodology and listed in Table 3.3.1.1-1 to preserve the integrity of the fuel cladding, the reactor coolant pressure boundary (RCPB), and (continued)

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

PPL Rev. 2 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE the containment by minimizing the energy that must be absorbed SAFETY following a LOCA.

ANALYSES, LCO, and APPLICABILITY RPS instrumentation satisfies Criterion 3 of the NRC Policy Statement.

(continued) (Ref. 2)

Functions not specifically credited in the accident analysis are retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis.

The OPERABILITY of the RPS is dependent on the OPERABILITY of the individual instrumentation channel Functions specified in Table 3.3.1.1-1. Each Function must have a required number of OPERABLE channels per RPS trip system, with their setpoints within the specified Allowable Value, where appropriate. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions. Each channel must also respond within its assumed response time.

Allowable Values are specified for each RPS Function specified in the Table. Nominal trip setpoints are specified in the setpoint calculations.

The nominal setpoints are selected to ensure that the actual setpoints do not exceed the Allowable Value between successive CHANNEL CALIBRATIONS. Operation with a trip setpoint less conservative than the nominal trip setpoint, but within its Allowable Value, is acceptable.

A channel is inoperable if its actual trip setpoint is not within its required Allowable Value.

Trip setpoints are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., reactor vessel water level), and when the measured output value of the process parameter reaches the setpoint, the associated device changes state. The analytic limits are derived from the limiting values of the process parameters obtained from the safety analysis. The Allowable Values are derived from the analytic limits, corrected for calibration, process, and some of the instrument errors. The trip setpoints are then determined accounting for the remaining instrument errors (e.g.,

drift). The trip setpoints derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, (continued)

SUSQUEHANNA - UNIT 2 TS / B3.3-3 Revision I

PPL Rev. 2 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE instrument drift, and severe environment errors (for channels that must SAFETY function in harsh environments as defined by 10 CFR 50.49) are ANALYSES, LCO, accounted for.

and APPLICABILITY (continued) The OPERABILITY of scram pilot valves and associated solenoids, backup scram valves, and SDV valves, described in the Background section, are not addressed by this LCO.

The individual Functions are required to be OPERABLE in the MODES specified in the table, which may require an RPS trip to mitigate the consequences of a design basis accident or transient. To ensure a reliable scram function, a combination of Functions are required in each MODE to provide primary and diverse initiation signals.

The RPS is required to be OPERABLE in MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies.

Control rods withdrawn from a core cell containing no fuel assemblies do not affect the reactivity of the core and, therefore, are not required to have the capability to scram. Provided all other control rods remain inserted, the RPS function is not required. In this condition, the required SDM (LCO 3.1.1) and refuel position one-rod-out interlock (LCO 3.9.2) ensure that no event requiring RPS will occur. During normal operation in MODES 3 and 4, all control rods are fully inserted and the Reactor Mode Switch Shutdown Position control rod withdrawal block (LCO 3.3.2.1) does not allow any control rod-to be withdrawn. Under these conditions, the RPS function is not required to be OPERABLE.

The exception to this is Special Operations (LCO 3.10.3 and LCO 3.10.4) which ensure compliance with appropriate requirements.

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

Intermediate Range Monitor (IRM) 1.a. Intermediate Ranae Monitor Neutron Flux-High The IRMs monitor neutron flux levels from the upper range of the source range monitor (SRM) to the lower range of the average power range monitors (APRMs). The IRMs are capable of generating trip signals that can be used to prevent fuel (continued)

SUSQUEHANNA - UNIT 2 TS / B3.3-4 Revision 1

PPL Rev. 2 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 1.a. Intermediate Range Monitor Neutron Flux-High (continued)

SAFETY ANALYSES, LCO, damage resulting from abnormal operating transients in the and APPLICABILITY intermediate power range. In this power range, the most significant source of reactivity change is due to control rod withdrawal. The IRM provides diverse protection for the rod worth minimizer (RWM), which monitors and controls the movement of control rods at low power. The RWM prevents the withdrawal of an out of sequence control rod during startup that could result in an unacceptable neutron flux excursion (Ref. 5). The IRM provides mitigation of the neutron flux excursion. I To demonstrate the capability of the IRM System to mitigate control rod withdrawal events, generic analyses have been performed (Ref. 3) to evaluate the consequences of control rod withdrawal events during startup that are mitigated only by the IRM. This analysis, which assumes that one IRM channel in each trip system is bypassed, demonstrates that the IRMs provide protection against local control rod withdrawal errors and results in peak fuel energy depositions below the 170 cal/gm fuel failure threshold criterion.

The IRMs are also capable of limiting other reactivity excursions during startup, such as cold water injection events, although no credit is specifically assumed.

The IRM System is divided into two trip systems, with four IRM channels inputting to each trip system. The analysis of Reference 3 assumes that one channel in each trip system is bypassed. Therefore, six channels with three channels in each trip system are required for IRM OPERABILITY to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. This trip is active in each of the 10 ranges of the IRM, which must be selected by the operator to maintain the neutron flux within the monitored level of an IRM range.

The analysis of Reference 3 has adequate conservatism to permit an IRM Allowable Value of 122 divisions of a 125 division scale.

The Intermediate Range Monitor Neutron Flux-High Function must be OPERABLE during MODE 2 when control rods may be withdrawn and the potential for criticality exists. In (continued)

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

PPL Rev. 2 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE l.a. Intermediate Range Monitor Neutron Flux-High SAFETY (continued)

ANALYSES, LCO, and APPLICABILITY MODE 5, when a cell with fuel has its control rod withdrawn, the IRMs provide monitoring for and protection against unexpected reactivity excursions. In MODE 1, the APRM System and the RWM provide protection against control rod withdrawal error events and the IRMs are not required. In addition, the Function is automatically bypassed when the Reactor Mode Switch is in the Run position.

I.b. Intermediate Ranae Monitor-mnop This trip signal provides assurance that a minimum number of IRMs are OPERABLE. Anytime an IRM mode switch is moved to any position other than "Operate," the detector voltage drops below a preset level, or when a module is not plugged in, an inoperative trip signal will be received by the RPS unless the IRM is bypassed. Since only one IRM in each trip system may be bypassed, only one IRM in each RPS trip system may be inoperable without resulting in an RPS trip signal.

This Function was not specifically credited in the accident analysis but it is retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis.

Six channels of Intermediate Range Monitor-Inop with three channels in each trip system are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal.

Since this Function is not assumed in the safety analysis, there is no Allowable Value for this Function.

This Function is required to be OPERABLE when the Intermediate Range Monitor Neutron Flux-High Function is required.

(continued)

SUSQUEHANNA - UNIT 2 TS / B3.3-6 Revision 1

PPL Rev. 2 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE Average Power Range Monitor SAFETY ANALYSES, LCO, 2.a. Average Power Range Monitor Neutron Flux-High.

and APPLICABILITY Setdown (continued)

The APRM channels receive input signals from the local power range monitors (LPRMs) within the reactor core to provide an indication of the power distribution and local power changes. The APRM channels average these LPRM signals to provide a continuous indication of average reactor power from a few percent to greater than RTP. For operation at low power (i.e., MODE 2), the Average Power Range Monitor Neutron Flux-High, Setdown Function is capable of generating a trip signal that prevents fuel damage resulting from abnormal operating transients in this power range. For most operation at low power levels, the Average Power Range Monitor Neutron Flux-High, Setdown Function will provide a secondary scram to the Intermediate Range Monitor Neutron Flux-High Function because of the relative setpoints. With the IRMs at Range 9 or 10, it is possible that the Average Power Range Monitor Neutron Flux-High, Setdown Function will provide the primary trip signal for a corewide increase in power.

The Average Power Range Monitor Neutron Flux - High, Setdown Function together with the IRM - High Function provide mitigation for the control rod withdrawal event during startup (Section 15.4.1 of Ref 5). Also, the Function indirectly ensures that before the reactor mode switch is placed in the run position, reactor power does not exceed 25% RTP (SL 2.1.1.1) when operating at low reactor pressure and low core flow. Therefore, it indirectly prevents fuel damage during significant reactivity increases with THERMAL POWER < 25% RTP.

The APRM System is divided into two trip systems with three APRM channel inputs to each trip system. The system is designed to allow one channel in each trip system to be bypassed. Any one APRM channel in a trip system can cause the associated trip system to trip. Four channels of Average Power Range Monitor Neutron Flux-High, Setdown with two channels in each trip system are required to be OPERABLE to ensure that no single failure will preclude a scram from this Function on a valid signal. In addition, to provide adequate coverage of the entire core, at least 14 LPRM inputs are required for each APRM channel, with at least two (continued)

SUSQUEHANNA - UNIT 2 TS / B3.3-7 Revision 2

PPL Rev. 2 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 2.a. Average Power Ranae Monitor Neutron Flux-High, SAFETY Setdown (continued)

ANALYSES, LCO, and APPLICABILITY LPRM inputs from each of the four axial levels at which the LPRMs are located.

The Allowable Value is based on preventing significant increases in power when THERMAL POWER is < 25% RTP.

The Average Power Range Monitor Neutron Flux-High, Setdown Function must be OPERABLE during MODE 2 when control rods may be withdrawn since the potential for criticality exists. In MODE 1, the Average Power Range Monitor Neutron Flux-High Function provides protection against reactivity transients and the RWM protects against control rod withdrawal error events.

2.b. Average Power Ranae Monitor Flow Biased Simulated Thermal Power-High The Average Power Range Monitor Flow Biased Simulated Thermal Power-High Function monitors neutron flux to approximate the THERMAL POWER being transferred to the reactor coolant. The APRM neutron flux is electronically filtered with a time constant representative of the fuel heat transfer dynamics to generate a signal proportional to the THERMAL POWER in the reactor. The trip level is varied as a function of recirculation drive flow (i.e., at lower core flows, the setpoint is reduced proportional to the reduction in power experienced as core flow is reduced with a fixed control rod pattern) but is clamped at an upper limit that is always lower than the Average Power Range Monitor Fixed Neutron Flux-High Function Allowable Value. The Average Power Range Monitor Flow Biased Simulated Thermal Power-High Function is not credited in any plant Safety Analyses. The Average Power Range Monitor Flow Biased Simulated Thermal Power - High Function Limit is set above the APRM Rod Block to provide defense in depth to the APRM fixed Neutron Flux -

High for transients where THERMAL POWER increases slowly (such as loss of feedwater heating event). During these events, the THERMAL POWER increase does not significantly lag the neutron flux response and, because of a lower trip setpoint, will initiate a scram before the high neutron flux scram. For rapid neutron flux increase events, the THERMAL POWER lags the neutron flux and the Average Power Range Monitor Fixed Neutron Flux-High Function will provide a scram signal before the Average (continued)

SUSQUEHANNA - UNIT 2 TS / B3.3-8 Revision 2

PPL Rev. 2 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 2.b. Average Power Range Monitor Flow Biased Simulated SAFETY Thermal Power-High (continued)

ANALYSES, LCO, and APPLICABILITY Power Range Monitor Flow Biased Simulated Thermal Power-High Function setpoint is exceeded.

The APRM System is divided into two trip systems with three APRM inputs to each trip system. The system is designed to allow one channel in each trip system to be bypassed. Any one APRM channel in a trip system can cause the associated trip system to trip. Four channels of Average Power Range Monitor Flow Biased Simulated Thermal Power-High with two channels in each trip system arranged in a one-out-of-two logic are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. In addition, to provide adequate coverage of the entire core, at least 14 LPRM inputs are required for each APRM channel, with at least two LPRM inputs from each of the four axial levels at which the LPRMs are located. Each APRM channel receives two total drive flow signals representative of total core flow. The total drive flow signals are generated by four flow units, two of which supply signals to the trip system A APRMs, while the other two supply signals to the trip system B APRMs. Each flow unit signal is provided by summing up the flow signals from the two recirculation loops. To obtain the most conservative reference signals, the total flow signals from the two flow units (associated with a trip system-as described above) are routed to a low auction circuit associated with each APRM. Each APRM's auction circuit selects the lower of the two flow unit signals for use as the scram trip reference for that particular APRM; Each required Average Power Range Monitor Flow Biased Simulated Thermal Power-High channel only requires an input from one OPERABLE flow unit, because the function is not credited in the Safety Analyses and the individual APRM channel will perform the intended function with only one OPERABLE flow unit input. Industry standards (e.g.,

IEEE-279-1971) require that a system be single failure proof if it performs a protective function (e.g., mitigate an accident described in the SAR). A review of the Safety Analyses described in the FSAR demonstrate that the APRM Flow Biased Simulated Thermal Power -

High scram is not credited. Since the flow-biased scram is not credited it does not need to meet single failure criteria. Therefore, an inoperable flow unit does not require that the associated trip system be declared inoperable. However, if both flow units in a given trip system become inoperable, then one of the two required Average Power Range Monitor Flow Biased Simulated Thermal Power - High channels in the associated trip system must be considered inoperable.

(continued)

SUSQUEHANNA - UNIT 2 TS /B 3.3-9 Revision 2

PPL Rev. 2 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 2.b. Average Power Range Monitor Flow Biased Simulated SAFETY Thermal Power-High (continued)

ANALYSES, LCO, and APPLICABILITY The THERMAL POWER time constant of < 7 seconds is based on the fuel heat transfer dynamics and provides a signal proportional to the THERMAL POWER. The simulated thermal time constant is part of the filter circuit that simulates the relationship between neutron flux and core thermal power.

The Average Power Range Monitor Flow Biased Simulated Thermal Power-High Function and at least one flow unit per division are required to be OPERABLE in MODE I when there is the possibility of generating excessive THERMAL POWER and potentially exceeding the SL applicable to high pressure and core flow conditions (MCPR SL). During MODES 2 and 5, other IRM and APRM Functions provide protection for fuel cladding integrity.

2.c. Average Power Range Monitor Fixed Neutron Flux-High The APRM channels provide the primary indication of neutron flux within the core and respond almost instantaneously to neutron flux increases. The Average Power Range Monitor Fixed Neutron Flux-High Function is capable of generating a trip signal to prevent fuel damage or excessive RCS pressure. For the .overpressurization protection analysis of Reference 4, the Average Power Range Monitor Fixed Neutron Flux-High Function is assumed to terminate the main steam isolation valve (MSIV) closure event and, along with the safety/relief valves (S/RVs), limits the peak reactor pressure vessel (RPV) pressure to less than the ASME Code limits. The control rod drop accident (CRDA) analysis (Ref. 5) takes credit for the Average Power Range Monitor Fixed Neutron Flux-High Function to terminate the CRDA.

The APRM System is divided into two trip systems with three APRM channels inputting to each trip system. The system is designed to allow one channel in each trip system to be bypassed. Any one APRM channel in a trip system can cause the associated trip system to trip.

Four channels of (continued)

SUSQUEHANNA - UNIT 2 TS / B3.3-1 0 Revision 2

PPL Rev. 2 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 2.c. Average Power Range Monitor Fixed Neutron Flux-High SAFETY (continued)

ANALYSES, LCO, and APPLICABILITY Average Power Range Monitor Fixed Neutron Flux-High with two channels in each trip system arranged in a one-out-of-two logic are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. In addition, to provide adequate coverage of the entire core, at least 14 LPRM inputs are required for each APRM channel, with at least two LPRM inputs from each of the four axial levels at which the LPRMs are located.

The CRDA analysis assume that reactor scram occurs on Average Power Range Monitor Fixed Neutron Flux- High Function.

The Average Power Range Monitor Fixed Neutron Flux-High Function is required to be OPERABLE in MODE I where the potential consequences of the analyzed transients could result in the SLs (e.g.,

MCPR and RCS pressure) being exceeded. Although the Average Power Range Monitor Fixed Neutron Flux-High Function is assumed in the CRDA analysis, which is applicable in MODE 2, the Average Power Range Monitor Neutron Flux-High, Setdown Function conservatively bounds the assumed trip and, together with the assumed IRM trips, provides adequate protection. Therefore, the Average Power Range Monitor Fixed Neutron Flux-High Function is not required in MODE 2.

2.d. Average Power Range Monitor-Inop This signal provides assurance that a minimum number of APRMs are OPERABLE. Anytime an APRM mode switch is moved to any position other than "Operate" or the APRM has too few LPRM inputs (< 14), an I inoperative trip signal will be received by the RPS, unless the APRM is bypassed. Since only one APRM in each trip system may be bypassed, only one APRM in each trip system may be inoperable without resulting in an RPS trip signal. This Function was not specifically credited in the accident analysis, but it is retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis.

(continued)

SUSQUEHANNA - UNIT 2 TS / B3.3-11 Revision 2

PPL Rev. 2 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 2.d. Averaae Power Ranae Monitor-mnop (continued)

SAFETY

ANALYSES, LCO, and Four channels of Average Power Range Monitor-Inop with two APPLICABILITY channels in each trip system are required to be OPERABLE to ensure that no single failure will preclude a scram from this Function on a valid signal.

There is no Allowable Value for this Function.

This Function is required to be OPERABLE in the MODES where the APRM Functions are required.

3. Reactor Vessel Steam Dome Pressure-High An increase in the RPV pressure during reactor operation compresses the steam voids and results in a positive reactivity insertion. This causes the neutron flux and THERMAL POWER transferred to the reactor coolant to increase, which could challenge the integrity of the fuel cladding and the RCPB. This trip Function is assumed in the low power generator load rejection without bypass and the recirculation flow controller failure (increasing) event However, the Reactor Vessel Steam Dome Pressure-High Function initiates a scram for transients that results in a pressure increase, counteracting the pressure increase by rapidly reducing core power. For the overpressurization protection analysis of Reference 4, reactor scram (the analyses conservatively assume a scram from either the Average Power Range Monitor Fixed Neutron Flux-High signal, or the Reactor Vessel Steam Dome Pressure-High signal), along with the SIRVs, limits the peak RPV pressure to less than the ASME Section III Code limits.

High reactor pressure signals are initiated from four pressure instruments that sense reactor pressure. The Reactor Vessel Steam Dome Pressure-High Allowable Value is chosen to provide a sufficient margin to the ASME Section III Code limits during the event.

Four channels of Reactor Vessel Steam Dome Pressure- High Function, with two channels in each trip system arranged in a one-out-of-two logic, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. The Function is (continued)

SUSQUEHANNA - UNIT 2 TS / 8 3.3-12 Revision 2

PPL Rev. 2 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 3. Reactor Vessel Steam Dome Pressure-High (continued)

SAFETY ANALYSES, LCO, required to be OPERABLE in MODES 1 and 2 when the RCS is and APPLICABILITY pressurized and the potential for pressure increase exists.

4. Reactor Vessel Water Level-Low. Level 3 Low RPV water level indicates the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. Therefore, a reactor scram is initiated at Level 3 to substantially reduce the heat generated in the fuel from fission. The Reactor Vessel Water Level-Low, Level 3 Function is assumed in the analysis of the recirculation line break (Ref. 6). The reactor scram reduces the amount of energy required to be absorbed and, along with the actions of the Emergency Core Cooling Systems (ECCS), ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.

Reactor Vessel Water Level-Low, Level 3 signals are initiated from four level instruments that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel.

Four channels of Reactor Vessel Water Level--Low, Level 3 Function, with two channels in each trip system arranged in -a one-out-of-two logic, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal.

The Reactor Vessel Water Level-Low, Level 3 Allowable Value is selected to ensure that during normal operation the separator skirts are not uncovered (this protects available recirculation pump net positive suction head (NPSH) from significant carryunder) and, for transients involving loss of all normal feedwater flow, initiation of the low pressure ECCS subsystems at Reactor Vessel Water-Low Low Low, Level 1 will not be required.

The Function is required in MODES 1 and 2 where considerable energy exists in the RCS resulting in the limiting transients and accidents. ECCS initiations at Reactor Vessel Water Level-Low Low, Level 2 and Low Low Low, (continued)

SUSQUEHANNA - UNIT 2 TS / B3.313 Revision I

PPL Rev. 2 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 4. Reactor Vessel Water Level-Low. Level 3 (continued)

SAFETY ANALYSES, LCO, Level 1 provide sufficient protection for level transients in all other and APPLICABILITY MODES.

5. Main Steam Isolation Valve-Closure MSIV closure results in loss of the main turbine and the condenser as a heat sink for the nuclear steam supply system and indicates a need to shut down the reactor to reduce heat generation. Therefore, a reactor scram is initiated on a Main Steam Isolation Valve-Closure signal before the MSIVs are completely closed in anticipation of the complete loss of the normal heat sink and subsequent overpressurization transient. However, for the overpressurization protection analysis of Reference 4, the Average Power Range Monitor Fixed Neutron Flux-High Function, along with the S/RVs, limits the peak RPV pressure to less than the ASME Code limits. That is, the direct scram on position switches for MSIV closure events is not assumed in the overpressurization analysis. Additionally, MSIV closure is assumed in the transients analyzed in Reference 5 (e.g., low l steam line pressure, manual closure of MSIVs, high steam line flow).

The reactor scram reduces the amount of energy required to be absorbed and, along with the actions of the ECCS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.

MSIV closure signals are initiated from position switches located on each of the eight MSIVs. Each MSIV has two position switches; one inputs to RPS trip system A while the other inputs to RPS trip system B. Thus, each RPS trip system receives an input from eight Main Steam Isolation Valve-Closure channels, each consisting of one position switch. The logic for the Main Steam Isolation Valve-Closure Function is arranged such that either the inboard or outboard valve on three or more of the main steam lines must close in order for a scram to occur.

The Main Steam Isolation Valve-Closure Allowable Value is specified to ensure that a scram occurs prior to a significant reduction in steam flow, thereby reducing the severity of the subsequent pressure transient.

(continued)

SUSQUEHANNA - UNIT 2 TS /B 3.3-14 Revision 2

PPL Rev. 2 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 5. Main Steam Isolation Valve-Closure (continued)

SAFETY ANALYSES, LCO, Sixteen channels (arranged in pairs) of the Main Steam Isolation and APPLICABILITY Valve-Closure Function, with eight channels in each tnip system, are required to be OPERABLE to ensure that no single instrument failure will preclude the scram from this Function on a valid signal. This Function is only required in MODE 1 since, with the MSIVs open and the heat generation rate high, a pressurization transient can occur if the MSIVs close. In addition, the Function is automatically bypassed when the Reactor Mode Switch is not in the Run position. In MODE 2, the heat generation rate is low enough so that the other diverse RPS functions provide sufficient protection.

6. Drvwell Pressure-High High pressure in the drywell could indicate a break in the RCPB. A reactor scram is initiated to minimize the possibility of fuel damage and to reduce the amount of energy being added to the coolant and the drywell. The Drywell Pressure-High Function is assumed in the analysis of the recirculation line break (Ref. 6). The reactor scram reduces the amount of energy required to be absorbed and, along with the actions of Emergency Core Cooling Systems (ECCS), ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.

High drywell pressure signals are initiated from four pressure instruments that sense drywell pressure. The Allowable Value was selected to be as low as possible and indicative of a LOCA inside primary containment.

Four channels of Drywell Pressure-High Function, with two channels in each trip system arranged in a one-out-of-two logic, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. The Function is required in MODES 1 and 2 where considerable energy exists in the RCS, resulting in the limiting transients and accidents.

(continued)

SUSQUEHANNA-UNIT 2 TS / B3.3-15 Revision I

PPL Rev. 2 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 7.a. 7.b. Scram Discharge Volume Water Level - High SAFETY ANALYSES, LCO, The SDV receives the water displaced by the motion of the CRD and APPLICABILITY pistons during a reactor scram. Should this volume fill to a point where (continued) there is insufficient volume to accept the displaced water, control rod insertion would be hindered. Therefore, a reactor scram is initiated while the remaining free volume is still sufficient to accommodate the water from a full core scram. The two types of Scram Discharge Volume Water Level-High Functions are an input to the RPS logic.

No credit is taken for a scram initiated from these Functions for any of the design basis accidents or transients analyzed in the FSAR.

However, they are retained to ensure the scram function remains OPERABLE.

SDV water level is measured by two diverse methods. The level in each of the two SDVs is measured by two float type level switches and two level transmitters with trip units for a total of eight level signals.

The outputs of these devices are arranged so that there is a signal.

from a level switch and a level transmitter with trip unit to each RPS logic channel. The level measurement instrumentation satisfies the recommendations of Reference 8.

The Allowable Value is chosen low enough to ensure that there is sufficient volume in the SDV to accommodate-the water from a full scram.

Four channels of each type of Scram Discharge Volume Water Level-High Function, with two channels of each type in each trip system, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from these Functions on a valid signal. These Functions are required in MODES 1 and 2, and in MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies, since these are the MODES and other specified conditions when control rods are withdrawn. At all other times, this Function may be bypassed.

8. Turbine Stop Valve-Closure Closure of the TSVs results in the loss of a heat sink that produces reactor pressure, neutron flux, and heat flux transients that must be limited. Therefore, a reactor scram is initiated at the start of TSV closure in anticipation of (continued)

SUSQUEHANNA - UNIT 2 TS / B3.3-16 Revision I

PPL Rev. 2 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 8. Turbine Stop Valve-Closure (continued)

SAFETY ANALYSES, LCO, the transients that would result from the closure of these valves. The and APPLICABILITY Turbine Stop Valve-Closure Function is the primary scram signal for the turbine trip event analyzed in Reference 5. For this event, the I reactor scram reduces the amount of energy required to be absorbed and, along with the actions of the End of Cycle Recirculation Pump Trip (EOC-RPT) System, ensures that the MCPR SL is not exceeded.

Turbine Stop Valve-Closure signals are initiated from position switches located on each of the four TSVs. Two independent position switches are associated with each stop valve. One of the two switches provides input to RPS trip system A; the other, to RPS trip system B.

Thus, each RPS trip system receives an input from four Turbine Stop Valve-Closure channels, each consisting of one position switch. The logic for the Turbine Stop Valve-Closure Function is such that three or more TSVs must be closed to produce a scram. This Function must be enabled at THERMAL POWER 2 30% RTP. This is accomplished automatically by pressure instruments sensing turbine first stage pressure. Because an increase in the main turbine bypass flow can affect this function non-conservatively, THERMAL POWER is derived from first stage pressure. The main turbine bypass valves must not cause the trip Function to be bypassed when THERMAL POWER is

Ž 30% RTP.

The Turbine Stop Valve-Closure Allowable-Value is selected to be high enough to detect imminent TSV closure, thereby reducing the severity of the subsequent pressure transient.

Eight channels (arranged in pairs) of Turbine Stop Valve-Closure Function, with four channels in each trip system, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function if any three TSVs should close. This Function is required, consistent with analysis assumptions, whenever THERMAL POWER is 2 30% RTP. This Function is not required when THERMAL POWER is < 30% RTP since the Reactor Vessel Steam Dome Pressure-High and the Average Power Range Monitor Fixed Neutron Flux-High Functions are adequate to maintain the necessary safety margins.

(continued)

SUSQUEHANNA - UNIT 2 TS / 83.3-17 Revision 2

PPL Rev. 2 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 9. Turbine Control Valve Fast Closure. Trip Oil SAFETY Pressure-Low ANALYSES, LCO, and APPLICABILITY Fast closure of the TCVs results in the loss of a heat sink that (continued) produces reactor pressure, neutron flux, and heat flux transients that must be limited. Therefore, a reactor scram is initiated on TCV fast closure in anticipation of the transients that would result from the closure of these valves. The Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Function is the primary scram signal for the generator load rejection event analyzed in Reference 5. For this I event, the reactor scram reduces the amount of energy required to be absorbed and, along with the actions of the EOC-RPT System, ensures that the MCPR SL is not exceeded.

Turbine Control Valve Fast Closure, Trip Oil Pressure-Low signals are initiated by the electrohydraulic control (EHC) fluid pressure at each control valve. One pressure instrument is associated with each control valve, and the signal from each transmitter is assigned to a separate RPS logic channel. This Function must be enabled at THERMAL POWER 2 30% RTP. This is accomplished automatically by pressure instruments sensing turbine first stage pressure. Because an increase in the main turbine bypass flow can affect this function non-conservatively, THERMAL POWER is derived from first stage pressure. The main turbine bypass valves must not cause the trip Function to be bypassed when THERMAL POWER is 2 30% RTP.

The Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Allowable Value is selected high enough to detect imminent TCV fast closure.

Four channels of Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Function with two channels in each trip system arranged in a one-out-of-two logic are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. This Function is required, consistent with the analysis assumptions, whenever THERMAL POWER is 2 30% RTP. This Function is not required when THERMAL POWER is

< 30% RTP, since the Reactor Vessel Steam Dome Pressure-High and the Average Power Range Monitor Fixed Neutron Flux-High Functions are adequate to maintain the necessary safety margins.

(continued)

SUSQUEHANNA - UNIT 2 TS / B3.3-18 Revision 2

PPL Rev. 2 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 10. Reactor Mode Switch-Shutdown Position SAFETY ANALYSES, LCO, The Reactor Mode Switch-Shutdown Position Function provides and APPLICABILITY signals, via the manual scram logic channels, to each of the four RPS (continued) logic channels, which are redundant to the automatic protective instrumentation channels and provide manual reactor trip capability.

This Function was not specifically credited in the accident analysis, but it is retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis.

The reactor mode switch is a single switch with four channels, each of which provides input into one of the RPS logic channels.

There is no Allowable Value for this Function, since the channels are mechanically actuated based solely on reactor mode switch position.

Four channels of Reactor Mode Switch-Shutdown Position.

Function, with two channels in each trip system, are available and required to be OPERABLE. The Reactor Mode Switch-Shutdown Position Function is required to be OPERABLE in MODES 1 and 2, and MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies, since these are the MODES and other specified conditions when control rods are withdrawn.

11. Manual Scram The Manual Scram push button channels provide signals, via the manual scram logic channels, to each of the four RPS logic channels, which are redundant to the automatic protective instrumentation channels and provide manual reactor trip capability. This Function was not specifically credited in the accident analysis but it is retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis.

There is one Manual Scram push button channel for each of the four RPS logic channels. In order to cause a scram it is necessary that at least one channel in each trip system be actuated.

(continued)

SUSQUEHANNA - UNIT 2 TS /B 3.3-19 Revision 1

PPL Rev. 2 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 11. Manual Scram (continued)

SAFETY ANALYSES, LCO, There is no Allowable Value for this Function since the channels are and APPLICABILITY mechanically actuated based solely on the position of the push buttons.

Four channels of Manual Scram with two channels in each trip system arranged in a one-out-of-two logic are available and required to be OPERABLE in MODES I and 2, and in MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies, since these are the MODES and other specified conditions when control rods are withdrawn.

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

A.1 and A.2 Because of the diversity of sensors available to provide trip signals and the redundancy of the RPS design, an allowable out of service time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months has been shown to be acceptable (Ref. 9) to permit restoration of any inoperable channel to OPERABLE status. However, this out of service time is only acceptable provided the associated Function's inoperable channel is in one trip system and the Function still maintains RPS trip capability (refer to Required Actions B.1, B.2, and C.1 Bases). If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel or the associated trip system must be placed in the tripped (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.3-20 Revision 1

PPL Rev. 2 RPS Instrumentation B 3.3.1.1 BASES ACTIONS A.1 and A.2 (continued) condition per Required Actions A.1 and A.2. Placing the inoperable channel in trip (or the associated trip system in trip) would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue.

Alternatively, if it is not desired to place the channel (or trip system) in trip (e.g., as in the case where placing the inoperable channel in trip would result in a full scram), Condition D must be entered and its Required Action taken.

B.1 and B.2 Condition B exists when, for any one or more Functions, at least one required channel is inoperable in each trip system. In this condition, provided at least one channel per trip system is OPERABLE, the RPS still maintains trip capability for that Function, but cannot accommodate a single failure in either trip system.

Required Actions B.1 and B.2 limit the time the RPS scram logic, for any Function, would not accommodate single failure in both trip systems (e.g., one-out-of-one and one-out-of-one arrangement for a typical four channel Function). The reduced reliability of this logic arrangement was not evaluated in Reference 9 for the 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Completion Time. Within the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months allowance, the associated Function will have all required channels OPERABLE or in trip (or any combination) in one trip system.

Completing one of these Required Actions restores RPS to a reliability level equivalent to that evaluated in Reference 9, which justified a 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowable out of service time as presented in Condition A. The trip system in the more degraded state should be placed in trip or, alternatively, all the inoperable channels in that trip system should be placed in trip (e.g., a trip system with two inoperable channels could be in a more degraded state than a trip system with four inoperable channels if the two inoperable channels are in the same Function while the four inoperable channels are all in different Functions). The decision of which trip system is in the more degraded state should be based on prudent judgment and take into account current plant conditions (i.e., what MODE the plant is in).

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.3-21 Revision 1

PPL Rev. 2 RPS Instrumentation B 3.3.1.1 BASES ACTIONS B.1 and B.2 (continued)

If this action would result in a scram, it is permissible to place the other trip system or its inoperable channels in trip.

The 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Completion Time is judged acceptable based on the remaining capability to trip, the diversity of the sensors available to provide the trip signals, the low probability of extensive numbers of inoperabilities affecting all diverse Functions, and the low probability of an event requiring the initiation of a scram.

Alternately, if it is not desired to place the inoperable channels (or one trip system) in trip (e.g., as in the case where placing the inoperable channel or associated trip system in trip would result in a scram),

Condition D must be entered and its Required Action taken.

C.1 Required Action C.1 is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same trip system for the same Function result in the Function not maintaining RPS trip capability. A Function is considered to be maintaining RPS trip capability when sufficient channels are OPERABLE or in trip (or the associated trip system is in trip), such that:both trip systems will generate a trip signal from the given Function-on a valid signal. For the typical Function with one-out-of-two taken twice logic, this would require both trip systems to have one channel OPERABLE or in trip (or the associated trip system in trip). For Function 5 (Main Steam Isolation Valve-Closure), this would require both trip systems to have each channel associated with the MSIVs in three main steam lines (not necessarily the same main steam lines for both trip systems)

OPERABLE or in trip (or the associated trip system in trip).

For Function 8 (Turbine Stop Valve-Closure), this would require both trip systems to have three channels, each OPERABLE or in trip (or the associated trip system in trip).

The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. The (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.3-22 Revision 1

PPL Rev. 2 RPS Instrumentation B 3.3.1.1 BASES ACTIONS C.1 (continued) 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.

D.1 Required Action D.1 directs entry into the appropriate Condition referenced in Table 3.3.1.1-1. The applicable Condition specified in the Table is Function and MODE or other specified condition dependent and may change as the Required Action of a previous Condition is completed. Each time an inoperable channel has not met any Required Action of Condition A, B, or C and the associated Completion Time has expired, Condition D will be entered for that channel and provides for transfer to the appropriate subsequent Condition.

E.1. F.1. and G.1 If the channel(s) is not restored to OPERABLE status or placed in trip (or the associated trip system placed in trip) within the allowed Completion Time, the plant must be placed in a MODE or other specified condition in which the LCO does not apply. The allowed Completion Times are reasonable, based on operating experience, to reach the specified condition from full power conditions in an orderly manner and without challenging plant systems. In addition, the Completion Time of Required Action E.1 is consistent with the Completion Time provided in LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)."

H.1 If the channel(s) is not restored to OPERABLE status or placed in trip (or the associated trip system placed in trip) within the allowed Completion Time, the plant must be placed in a MODE or other specified condition in which the LCO does not apply. This is done by immediately initiating action to fully insert all insertable control rods in core cells containing one or more fuel assemblies. Control rods in core cells containing no fuel assemblies do not affect (continued)

SUSQUEHANNA - UNIT 2 TS /B 3.3-23 Revision 1

PPL Rev. 2 RPS Instrumentation B 3.3.1.1 BASES ACTIONS H.1 (continued) the reactivity of the core and are, therefore, not required to be inserted. Action must continue until all insertable control rods in core cells containing one or more fuel assemblies are fully inserted.

SURVEILLANCE As noted at the beginning of the SRs, the SRs for each RPS REQUIREMENTS instrumentation Function are located in the SRs column of Table 3.3.1.1-1.

The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , provided the associated Function maintains RPS trip capability. Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Ref. 9) assumption of the average time, required to perform channel Surveillance. That analysis demonstrated that the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance does not significantly reduce the probability that the RPS will trip when necessary.

SR 3.3.1.1.1 Performance of the CHANNEL CHECK once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between 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.

(continued)

SUSQUEHANNA - UNIT 2 TS / B3.3-24 Revision 1

PPL Rev. 2 RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.1 (continued)

REQUIREMENTS Agreement criteria which are determined by the plant staff based on an investigation of a combination of the channel instrument uncertainties, may be used to support this parameter comparison and include indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit, and does not necessarily indicate the channel is Inoperable.

The Frequency is based upon operating experience that demonstrates channel failure is rare. The CHANNEL CHECK supplements less formal checks of channels during normal operational use of the displays associated with the channels required by the LCO.

SR 3.3.1.1.2 To ensure that the APRMs are accurately indicating the true core average power, the APRMs are calibrated to the reactor power calculated from a heat balance. LCO 3.2.4, "Average Power Range Monitor (APRM) Gain and Setpoints," allows the APRMs to be reading greater than actual THERMAL POWER to compensate for localized power peaking. When this adjustment is made, the requirement for the APRMs to indicate within 2% RTP of calculated power is modified to require the APRMs to indicate within 2% RTP of calculated MFLPD times 100. The Frequency of once per 7 days is based on minor changes in LPRM sensitivity, which could affect the APRM reading between performances of SR 3.3.1.1.8.

A restriction to satisfying this SR when < 25% RTP is provided that requires the SR to be met only at 2 25% RTP because it is difficult to accurately maintain APRM indication of core THERMAL POWER consistent with a heat balance when < 25% RTP. At low power levels, a high degree of accuracy is unnecessary because of the large, inherent margin to thermal limits (MCPR, LHGR and APLHGR). At

> 25% RTP, the Surveillance is required to have been satisfactorily performed within the last 7 days, in accordance with SR 3.0.2. A Note is provided which allows an increase in THERMAL POWER above 25% if the 7 day Frequency is not met per SR 3.0.2. In this event, the SR must be performed within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after reaching or exceeding 25% RTP. Twelve hours is based on operating (continued)

SUSQUEHANNA - UNIT 2 TS / B3.325 Revision 1

PPL Rev. 2 RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.2 (continued)

REQUIREMENTS experience and in consideration of providing a reasonable time in which to complete the SR.

SR 3.3.1.1.3 The Average Power Range Monitor Flow Biased Simulated Thermal Power-High Function uses the recirculation loop drive flows to vary the trip setpoint. This SR verifies proper operation of the total loop drive flow signals from the drive flow units used to vary the setpoint of the APRM. The components operation is verified in two steps. The first step is a CHANNEL CHECK performed by reading the output of the four drive flow units. This gross check ensures that all drive flow units are within a tolerance defined by station staff. The second step is a verification that the flow signal from the APRM readout (which is the lowest flow signal from two associated drive flow units) is conservative with respect to the total core flow/drive flow relationship.

This two step process ensures that the drive flow signal is consistent with the actual total core flow. If the flow unit signal is not within the limit, one required APRM that receives an input from the inoperable flow unit must be declared inoperable. If instruments are found within tolerance, adjustments are not required.

The Frequency of 7 days is based on engineering judgment, operating experience, and the reliability of this instrumentation.

SR 3.3.1.1.4 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function.

As noted, SR 3.3.1.1.4 is not required to be performed when entering MODE 2 from MODE 1, since testing of the MODE 2 required IRM and APRM Functions cannot be performed in MODE 1 without utilizing jumpers, lifted leads, or movable links. This allows entry into MODE 2 if the 7 day Frequency is not met per SR 3.0.2. In this event, the SR must be (continued)

SUSQUEHANNA - UNIT 2 TS / B3.326 Revision 1

PPL Rev. 2 RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.4 (continued)

REQUIREMENTS performed within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after entering MODE 2 from MODE 1.

Twelve hours is based on operating experience and in consideration of providing a reasonable time in which to complete the SR.

A Frequency of 7 days provides an acceptable level of system average unavailability over the Frequency interval and is based on reliability analysis (Ref. 9).

SR 3.3.1.1.5 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. A Frequency of 7 days provides an acceptable level of system average availability over the Frequency and is based on the reliability analysis of Reference 9. (The Manual Scram Function's CHANNEL FUNCTIONAL TEST Frequency was credited in the analysis to extend many automatic scram Functions' Frequencies.)

SR 3.3.1.1.6andSR 3.3.1.1.7 These Surveillances are established to ensure that no gaps in neutron flux indication exist from subcritical to power operation for monitoring core reactivity status.

The overlap between SRMs and IRMs is required to be demonstrated to ensure that reactor power will not be increased into a neutron flux region without adequate indication. The overlap is demonstrated prior to fully withdrawing the SRMs from the core. Demonstrating the overlap prior to fully withdrawing the SRMs from the core is required to ensure the SRMs are on-scale for the overlap demonstration.

The overlap between IRMs and APRMs is of concern when reducing power into the IRM range. On power increases, the system design will prevent further increases (by initiating a rod block) if adequate overlap is not maintained. Overlap between IRMs and APRMs exists when sufficient IRMs and APRMs concurrentiy have onscale readings such that the transition between MODE 1 and MODE 2 can be made without eitherAPRM downscale rod block, or IRM upscale rod block. Overlap (continued)

SUSQUEHANNA - UNIT 2 TS / B3.3-27 Revision 1

PPL Rev. 2 RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.6 and SR 3.3.1.1.7 (continued)

REQUIREMENTS between SRMs and IRMs similarly exists when, prior to fully withdrawing the SRMs from the core, IRMs are above mid-scale on range 1 before SRMs have reached the upscale rod block.

As noted, SR 3.3.1.1.7 is only required to be met during entry into MODE 2 from MODE 1. That is, after the overlap requirement has been met and indication has transitioned to the IRMs, maintaining overlap is not required (APRMs may be reading downscale once in MODE 2).

If overlap for a group of channels is not demonstrated (e.g.,

IRM/APRM overlap), the reason for the failure of the Surveillance should be determined and the appropriate channel(s) declared inoperable. Only those appropriate channels that are required in the current MODE or condition should be declared inoperable.

A Frequency of 7 days is reasonable based on engineering judgment and the reliability of the IRMs and APRMs.

SR 3.3.1.1.8 LPRM gain settings are determined from the local flux profiles that are either measured by the Traversing Incore Probe (TIP) System at all functional locations or calculated for TIP locations that are not functional. The methodology used to develop the power distribution limits considers the uncertainty for both measured and calculated local flux profiles. This methodology assumes that all the TIP locations are functional for the first LPRM calibration following a refueling outage, and a minimum of 25 functional TIP locations for subsequent LPRM calibrations. The calibrated LPRMs establish the relative local flux profile for appropriate representative input to the APRM System. The 1000 MWD/MT Frequency is based on operating experience with LPRM sensitivity changes.

SR 3.3.1.1.9andSR 3.3.1.1.12 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. The 92 day Frequency of SR 3.3.1.1.9 is based on the reliability analysis of Reference 9.

(continued)

SUSQUEHANNA - UNIT 2 TS / B3.3-28 Revision 2

PPL Rev. 2 RPS Instrumentation B3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.9 and SR 3.3.1.1.12 (continued)

REQUIREMENTS SR 3.3.1.1.9 is modified by a Note that provides a general exception to the definition of CHANNEL FUNCTIONAL TEST. This exception is necessary because the design of instrumentation does not facilitate functional testing of all required contacts of the relay which input into the combinational logic. (Reference 10) Performance of such a test could result in a plant transient or place the plant in an undo risk situation. Therefore, for this SR, the CHANNEL FUNCTIONAL TEST verifies acceptable response by verifying the change of state of the relay which inputs into the combinational logic. The required contacts not tested during the CHANNEL FUNCTIONAL TEST are tested under the LOGIC SYSTEM FUNCTIONAL TEST, SR 3.3.1.1.15. This is acceptable because operating experience shows that the contacts not tested during the CHANNEL FUNCTIONAL TEST normally pass the LOGIC SYSTEM FUNCTIONAL TEST, and the testing methodology minimizes the risk of unplanned transients.

The 24 month Frequency of SR 3.3.1.1.12 is based on the need to perform this Surveillance 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. Operating experience has shown that these components usually pass the Surveillance when performed at the 24 month Frequency.

SR 3.3.1.1.10, SR 3.3.1.1.11 and SR 3.3.1.1.13 A CHANNEL CALIBRATION verifies that the channel responds to the measured parameter within the necessary range and accuracy.

CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.

Note 1 states that neutron detectors are excluded from CHANNEL CALIBRATION because they are passive devices, with minimal drift, and because of the difficulty of simulating a meaningful signal.

Changes in neutron detector sensitivity are compensated for by performing the 7 day calorimetric calibration (SR 3.3.1.1.2) and the 1000 MWD/MT LPRM calibration against the TIPs (SR 3.3.1.1.8). A second Note is provided that requires the APRM and IRM SRs to be performed within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months of entering MODE 2 from MODE 1. Testing of the MODE 2 APRM and IRM Functions cannot be performed in (continued)

SUSQUEHANNA - UNIT 2 TS / B3.329 Revision 2

PPL Rev. 2 RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.10. SR 3.3.1.1.11 and SR 3.3.1.1.13 REQUIREMENTS (continued)

MODE 1 without utilizing jumpers, lifted leads, or movable links. This Note allows entry into MODE 2 from MODE 1 if the associated Frequency is not met per SR 3.0.2. Twelve hours is based on operating experience and in consideration of providing a reasonable time in which to complete the SR.

The Frequency of SR 3.3.1.1.11 is based upon the assumption of a 184 day calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis. The Frequency of 92 days for SR 3.3.1.1.12 and 24 months for SR 3.3.1.1.13 is based upon the assumptions in the determination of the magnitude of equipment drift in the setpoint analysis.

SR 3.3.1.1.14 The Average Power Range Monitor Flow Biased Simulated Thermal Power-High Function uses an electronic filter circuit to generate a signal proportional to the core THERMAL POWER from the APRM neutron flux signal. This filter circuit is representative of the fuel heat transfer dynamics that produce the relationship between the neutron flux and the core THERMAL POWER. The Surveillance filter time constant must be verified to be < 7 seconds to ensure that the channel is accurately reflecting the desired parameter.

The Frequency of 24 months is based on engineering judgment considering the reliability of the components.

SR 3.3.1.1.15 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required trip logic for a specific channel. The functional testing of control rods (LCO 3.1.3), and SDV vent and drain valves (LCO 3.1.8), overlaps this Surveillance to provide complete testing of the assumed safety function.

The 24 month Frequency is based on the need to perform portions of this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.3-30 Revision 2

PPL Rev. 2 RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.15 (continued)

REQUIREMENTS transient if the Surveillance were performed with the reactor at power.

Operating experience has shown that these components usually pass the Surveillance when performed at the 24 month Frequency.

SR 3.3.1.1.16 This SR ensures that scrams initiated from the Turbine Stop Valve-Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Functions will not be inadvertently bypassed when THERMAL.

POWER is 2 30% RTP. This is performed by a Functional check that ensures the scram feature is not bypassed at 2 30% RTP. Because main turbine bypass flow can affect this function nonconservatively (THERMAL POWER is derived from turbine first stage pressure), the opening of the main turbine bypass valves must not cause the trip Function to be bypassed when Thermal Power is > 30% RTP.

If any bypass channel's trip function is nonconservative (i.e., the Functions are bypassed at 2 30% RTP, either due to open main turbine bypass valve(s) or other reasons), then the affected Turbine Stop Valve-Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure Low Functions are considered inoperable. Altematively, the bypass channel can be placed in the conservative condition (nonbypass). If placed in the nonbypass condition, this SR is met and the channel is considered OPERABLE.

The Frequency of 24 months is based on engineering judgment and reliability of the components.

SR 3.3.1.1.17 This SR ensures that the individual channel response times are less than or equal to the maximum values assumed in the accident analysis. This test may be performed in one measurement or in overlapping segments, with verification that all components are tested.

The RPS RESPONSE TIME acceptance criteria are included in Reference 11.

(continued)

SUSQUEHANNA - UNIT 2 TS I B 3.3-31 Revision I

PPL Rev. 2 RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.17 (continued)

REQUIREMENTS As noted, neutron detectors are excluded from RPS RESPONSE TIME testing because the principles of detector operation virtually ensure an instantaneous response time.

RPS RESPONSE TIME tests are conducted on an 24 month STAGGERED TEST BASIS. Note 3 requires STAGGERED TEST BASIS Frequency to be determined based on 4 channels per trip system, in lieu of the 8 channels specified in Table 3.3.1.1-1 for the MSIV Closure Function because channels are arranged in pairs. This Frequency is based on the logic interrelationships of the various channels required to produce an RPS scram signal. The 24 month Frequency is consistent with the typical industry refueling cycle and is based upon plant operating experience, which shows that random failures of instrumentation components causing serious response time degradation, but not channel failure, are infrequent occurrences.

SR 3.3.1.1.17 for Function 2.c confirms the response time of that function, and also confirms the response time of components common to Function 2.c and other RPS Functions. (Reference 14)

REFERENCES 1. FSAR, Figure 7.2-1.

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

3. NEDO-23842, "Continuous Control Rod Withdrawal in the Startup Range," April 18,1978.

4. FSAR, Section 5.2.2.

5. FSAR, Chapter 15.

6. FSAR, Section 6.3.3.

7. Not used.

8. P. Check (NRC) letter to G. Lainas (NRC), "BWR Scram Discharge System Safety Evaluation," December 1, 1980.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.3-32 Revision 3

PPL Rev. 2 RPS Instrumentation B 3.3.1.1 BASES REFERENCES 9. NEDO-30851-P-A, 'Technical Specification Improvement (continued) Analyses for BWR Reactor Protection System," March 1988.

10. NRC Inspection and Enforcement Manual, Part 9900: Technical Guidance, Standard Technical Specification 1.0 Definitions, Issue date 12/08/86.

11. FSAR, Table 7.3-28.

12. NEDO-32291-A "System Analyses for Elimination of Selected Response Time Testing Requirements," October 1995.

13. NRC Safety Evaluation Report related to Amendment No. 171 for License No. NPF 14 and Amendment No. 144 License No. NPF 22.

14. NEDO 32291-A, Supplement 1, System Analyses for the Elimination of Selected Response Time Testing Requirements,"

October 1999.

SUSQUEHANNA - UNIT 2 TS / B3.3-33 Revision 2

PPL Rev. 2 RPS Instrumentation B 3.3.1.1 Table 8 3.3.1.1-1 (page 1 of 1)

RPS Instrumentation Sensor Diversity Scram Sensors for Initiating Events RPV Variables Antici atory Fuel Initiation Events (a) ((c) (d) (e) M(g)

MSIV Closure X X X X Turbine Trip (wlbypass) X X X x Generator Trip (wlbypass) X X X Pressure Regulator Failure X X X X X (primary pressure decrease)

(MSiV closure trip)

Pressure Regulator Failure X X X (primary pressure decrease)

(Level 8 trip)

Pressure Regulator Failure X X (primary pressure increase)

Feedwater Controller Failure X X X X (high reactor water level)

Feedwater Controller Failure X X X (low reactor water level)

Loss of Condenser Vacuum X X X X Loss of AC Power (loss of X X X X transformer)

Loss of AC Power (loss of X X X X X X grid connections)

(a) Reactor Vessel Steam Dome Pressure-High (b) Reactor Vessel Water Leve-High, Level 8 (c) Reactor Vessel Water Level-Low, Level 3 (d) Turbine Control Valve Fast Closure (e) Turbine Stop Valve-Closure (f) .Main Steam Isolation Valve-Closure (g) Average Power Range Monitor Neutron Flux-High SUSQUEHANNA - UNIT 2 TS / B 3.3-34 Revision I

PPL Rev. 2 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 - UNIT 2 TS / B 3.3-64 Revision 2

PPL Rev. 2 PAM Instrumentation B 3.3.3.1 BASES APPLICABLE

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 following that accident.

Furthermore, provision of two channels 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 / B3.365 Revision 2

PPL Rev. 2 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 - UNIT 2 TS / B3.3-66 Revision 4

PPL Rev. 2 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

PPLRev.2 PAM Instrumentation B 3.3.3.1 BASES LCO 5. Primary Containment High 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 penetration flow path is not needed to determine status. Therefore, the position indication for valves in an isolated penetration flow path 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. 2 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) which consist of 6 channels that output to four control room recorders (one for channels A and C, one for channels B and D, one for channel E and one for channel F) provide reliable neutron flux measurement from 0% to 125% of full power. The PAM function for neutron flux is satisfied by any one channel of APRMs in each division (channels A,C, E comprise division one, channels B,D,F comprise division two). 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. Containment Hydrogen and Oxygen Analyzers The drywell and suppression chamber hydrogen and oxygen concentrations are Type A, Category 1, variables. Two independent gas analyzers monitor hydrogen and oxygen concentration to detect unsafe combustible gas levels in primary containment. The analyzers are capable of determining hydrogen concentration in the range of 0 to 30% by volume and oxygen concentration in the range of 0 to 10% by volume, and each provide control room indication and output to a control room recorder. Each gas analyzer must be capable of sampling either the drywell or the suppression chamber. The recorders are the primary method of indication available for use by the l operator during an accident, therefore the PAM Specification deals specifically with this portion of the instrument channel. The gas analyzer piping is provided with heat tracing to reduce the buildup of condensation in the system. H202 Analyzers can be considered OPERABLE for accident monitoring (TS 3.3.3.1) for up to 100 days with their heat tracing INOPERABLE.

(continued}

SUSQUEHANNA-UNIT 2 .TS/ B3.3-69 Revision 3

PPL Rev. 2 PAM Instrumentation B 3.3.3.1 BASES LCO 9. Drvwell 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 dhannel OPERABLE. The outputs for the temperature sensors are displayed on two independent indicators in the control room and recorded on the monitoring units located in the control room on a.back panel. 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 I B 3.3-70 Revision 3

PPL Rev. 2 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 restored 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. 2 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. 2 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 / IJ3.3-73 Revision 2

PPL Rev. 2 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 92 days for the containment Hydrogen and Oxygen Analyzers or 24 months for the other Functions 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 CHANNEL CALIBRATION for the hydrogen analyzers, use a sample gas containing: a) Nominal zero volume percent hydrogen, balance nitrogen and b) Nominal thirty volume percent hydrogen, balance nitrogen.

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

(continued)

SUSQUEHANNA - UNIT 2 TS I B 3.3-74 Revision 2-

PPL Rev. 2 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 / B3.375 Revision 2

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

Instrurnent/Variable Element Transmitter Recorder Indicator

1. Reactor Steam N/A PT.24201A LP/PR-24201A PI-24202A Dome Pressure (blue pen)' Pl-24202A1 PI-24204A N/A PT-24201 B LR/PR-24201 B Pl-242028 (left side)

(blue pen)' Pl-2420281 (left side)

P1-242048 (left side) 2 Reactor Vessel N/A LT-24201A LRIPR-24201A LI-24201A (left side)

Water Level (Wide Range) (red pen)' LI-24201A1 (left side)

LI-24203A (left side)

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

(Wide Range) (red pen)' LI-24201 BI (left side)

LI-24203B (left side)

N/A LT-24203A N/A LI-24201A (rightside)"')

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

LI-24203A (right side)

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

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

LI-24203B (right side)

N/A LT-24202A LR-24202- N/A (Fuel Zone Range) (red pen),

N/A LT-24202B N/A U-24205B (Fuel Zone Range)

3. Suppression N/A LT-25776A LR-25776A N/A Chamber Water Level (Wide Range) (red pen)'

N/A LT-2S776B LR-25776B N/A (Wide Range) (red pen)

N/A LT-25T75A LR-25776A LI-2M575A (Narrow Range) (blue pen)

N/A LT-25775B LR-25776B Ll-25775B (Narrow Range) (blue pen)

SUSQUEHANNA - UNIT 2 TS / B 3.3-75a Revision 4

PPL Rev. 2 PAM Instrumentation B 3.3.3.1 TABLE B 3.3.3.1-1 Post Accident Instruments (Page 2 of 3) instsument/Varlable Eiernent Transmitter Recorder Indicator

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

NIA PT-25709B UR-25701 B (Dark Blue)' N1A I (to250psig)

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

. (15 to65 vsg)

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

(-15 to 65 psIg)

5. Prnmary Containment RE-25720A RITS-25720A RR-25720A NiA High Radiation RE-25720B RITS-25720B RR-25720B1 N/A

6. PCIV Position See Technical Specification Bases Table B 3.6.1.- 1 for PCIV that require position Indication to be OPERABLE

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

N/A APRM-B NR-C51-2R603B N/A (red pen)_

N/A APRM-C NR-C51-2R603A N/A (blue pen)'

N/A APRM-D NR-C51-2R603B N/A (blue pen)'

N/A APRM-E NR-C51-2R603C N/A (red pen)'

N/A APRM-F NR-C51 -2R603D N/A (red pen),

8. Containment AE-25745A AT-25745A UR-25701A (Blue Violet) N/A Oxygen and (Hydrogen) UR-25701A (Vlolet)' I Hydrogen Analyzer AE-25745B AT-25745B UR25701 B (VBolet)V N/A (Hydrogen)UR201B(oet I AE-25746A AT-25746A UR-25701A (Orange) NWA I .

(Oxygen)

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

SUSQUEHANNA - UNIT 2 TS / B 3.3-75b . Revision 4

PPL Rev. 2 PAM Instrumentation B 3.3.3.1 TABLE B3.3.3.1-1 Post Accident Instruments (Page 3 of 3)

Insrument/Variable Element Transmitter Recorder Indicator

9. Drywell Atmosphere TE-25790A TT-25790A UR-25701A (Brown)- WA I Temperature TR-25790A (point# 1)

TE-257908 TT-25790B UR-25701B (Brown)' WA I TR-25790B (point#1)

10. Suppression Chamber TE-25753 TX-25751 WA TIAH-25751P Water Temperature TE-25755 TI-25751 TE-25757 TE-25759 TE-25763 TE-25765 TE-25767 TE-2S769 TE-25752 TX-25752 WA TIAH-25752 TE.25754 TI-25752 TE-25758 TE-25760 TE-25762 TE-25766 TE-25768 TE-25770 Indicates that the Instrument (and associated components Inthe Mnstrument 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-24201 B be used as acceptance criteria, however LI-24201Al, U-24201 B1, LI-24203A. or LI-24203B may be used Intheir 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 IRevision 4

PPL Rev. 3 ECCS Instrumentation B 3.3.5.1 B 3.3 INSTRUMENTATION B 3.3.5.1 Emergency Core Cooling System (ECCS) Instrumentation BASES BACKGROUND The purpose of the ECCS instrumentation is to initiate appropriate responses from the systems to ensure that the fuel is adequately cooled in the event of a design basis accident or transient.

For most anticipated operational occurrences and Design Basis Accidents (DBAs), a wide range of dependent and independent parameters are monitored.

The ECCS instrumentation actuates core spray (CS), low pressure coolant injection (LPCI), high pressure coolant injection (HPCI),

Automatic Depressurization System (ADS), the diesel generators (DGs) and other features described in the DG background. The equipment involved with each of these systems with exception of the DGs and other features, is described in the Bases for LCO 3.5.1, "ECCS-Operating ."

Core Sprav System The CS System may be initiated by either automatic or manual means.

Automatic initiation occurs for conditions of Reactor Vessel Water Level Low, Low, Low, Level 1 or Drywell Pressure - High concurrent with Reactor Pressure - Low. Each of these diverse variables is monitored by four redundant instruments. The initiation logic for one CS loop is arranged in a one-out-of-two-twice network using level and pressure instruments which will generate a signal when:

(1) both level sensors are tripped, or (2) two high drywell pressure sensors and two low reactor vessel pressure sensors are tripped, or (3) a combination of one channel of level sensor and one of the other channels of high drywell pressure sensor together with its associated low reactor vessel pressure sensor (i.e.,

Channel A level sensor and Channel C high drywell pressure sensor and low reactor vessel pressure sensor).

(continued)

SUSQUEHANNA - UNIT 2 TS / B3.3-1 01 Revision I

PPL Rev. 3 ECCS Instrumentation B 3.3.5.1 BASES BACKGROUND Core Spray System (continued)

Once an initiation signal is received by the CS control circuitry, the signal is sealed in until manually reset. The logic can also be initiated by use of a manual push button (one push button per subsystem).

Upon receipt of an initiation signal, the CS pumps are started 15 seconds after initiation signal if normal offsite power is available and 10.5 seconds after diesel generator power is available.

The CS test line isolation valve, which is also a primary containment isolation valve (PCIV), is closed on a CS initiation signal to allow full system flow assumed in the accident analyses and maintain primary containment isolated. The CS System also monitors the pressure in the reactor to ensure that, before the injection valves open, the reactor pressure has fallen to a value below the CS System's maximum design pressure. The variable is monitored by four redundant instruments.

The instrument outputs are connected to relays whose contacts are arranged in a one-out-of-two taken twice logic.

Low Pressure Coolant Iniection System The LPCI is an operating mode of the Residual Heat Removal (RHR)

System, with two LPCI subsystems. The LPCI subsystems may be initiated by automatic or manual means. Automatic initiation occurs for conditions of Reactor Vessel Water Level Low, Low, Low, Level 1 or Drywell Pressure - High concurrent with Reactor Pressure - Low. Each of these diverse variables is monitored by four instruments in two divisions. Each division is arranged in a one-out-of-two-twice network using level and pressure instruments which will generate a signal when:

(1) both level sensors are tripped, or (2) two high drywell pressure sensors and two low reactor vessel pressure sensors are tripped, or (3) a combination of one channel of level sensor and one of the other channel of high drywell pressure sensor together with its associated low reactor vessel pressure sensor (i.e., Channel A level sensor and Channel C high drywell and low reactor vessel pressure sensor).

(continued)

SUSQUEHANNA - UNIT 2 TS /B 3.3-102 Revision 1

PPL Rev. 3 ECCS Instrumentation B 3.3.5.1 BASES BACKGROUND Low Pressure Coolant Iniection System (continued)

The initiation logic is cross connected between divisions (i.e., either start signal will start all four pumps and open both loop's injection valves). Once an initiation signal is received by the LPCI control circuitry, the signal is sealed in until manually reset The cross division start signals for the pumps affect both the opposite division's start logic and the pump's 4KV breaker start logic. The cross division start signal to the opposite division's start logic is for improved reliability. The cross division start signals to the pump's 4KV breaker start logic is needed to ensure specific control power failures do not prevent the start of an adequate number of LPCI pumps.

Upon receipt of an initiation signal, all LPCI pumps start after a 3 second time delay when normal AC power is lost and standby diesel generator power is available. If normal power is available, LPCI pumps A and B will start immediately and pumps C and D will start 7.0 seconds after initiation signal to limit loading of the offsite sources.

The RHR test line and spray line are also isolated on a LPCI initiation signal to allow the full system flow assumed in the accident analyses and for those valves which are also PCIVs maintain primary containment isolated.

The LPCI System monitors the pressure in the reactor to ensure that, before an injection valve opens, the reactor pressure has fallen to a value below the LPCI System's maximum design pressure. The variable is monitored by four redundant instruments. The instrument outputs are connected to relays whose contacts are arranged in a one-out-of-two taken twice logic.

Logic is provided to close the recirculation pump discharge valves to ensure that LPCI flow does not bypass the core when it injects into the recirculation lines. The logic consists of an initiation signal (Low reactor water level and high drywell pressure in a one out of two taken twice logic) from both divisions of LPCI instruments and a pressure permissive. The pressure variable is monitored by four redundant instruments. The instrument outputs are connected to relays whose contacts are arranged in a one-out-of-two taken twice logic.

(continued)

-SUSQUEHANNA - UNIT 2 TS / B3.3-103 Revision 1

PPL Rev. 3 ECCS Instrumentation B 3.3.5.1 BASES BACKGROUND Hiah Pressure Coolant Iniection System (continued)

The HPCI System may be initiated by either automatic or manual means. Automatic initiation occurs for conditions of Reactor Vessel Water Level-Low Low, Level 2 or Drywell Pressure-High. Each of these variables is monitored by four redundant instruments. The instrument outputs are connected to relays whose contacts are .

arranged in a one-out-of-two taken twice logic for each Function.

The HPCI System also monitors the water level in the condensate storage tank (CST). HPCI suction is normally maintained on the CST until it transfers to the suppression pool on low CST level or is manually transferred by the operator. Reactor grade water in the CST is the normal source. Upon receipt of a HPCI initiation signal, the CST suction valve is automatically signaled to open (it is normally in the open position) unless the suppression pool suction valve is open. If the water level in the CST falls below a preselected level, first the suppression pool suction valve automatically opens, and then the CST suction valve automatically closes. Two level switches are used to detect low water level in the CST. Either switch can cause the suppression pool suction valve to open and the CST suction valve to close. To prevent losing suction to the pump, the suction valves are interlocked so that one suction path must be open before the other automatically closes.

The HPCI provides makeup water to the reactor until the reactor vessel water level reaches the Reactor Vessel Water Level-High, Level 8 trip, at which time the HPCI turbine trips, which causes the turbine's stop valve, minimum flow valve, the cooling water isolation valve, and the injection valve to close. The logic is two-out-of-two to provide high reliability of the HPCI System. The HPCI System automatically restarts if a Reactor Vessel Water Level-Low Low, Level 2 signal is subsequently received.

(continued)

SUSQUEHANNA - UNIT 2 TS I B3.3-104 Revision 2

PPL Rev. 3 ECCS Instrumentation B 3.3.5.1 BASES BACKGROUND Automatic Depressurization System (continued)

The ADS may be initiated by either automatic or manual means.

Automatic initiation occurs when signals indicating Reactor Vessel Water Level-Low Low Low, Level 1; Drywell Pressure-High or ADS Drywell Bypass Actuation Timer, confirmed Reactor Vessel Water Level-Low, Level 3; and CS or LPCI Pump Discharge Pressure-High are all present and the ADS Initiation Timer has timed out. There are two instruments each for Reactor Vessel Water Level-Low Low Low, Level 1 and Drywell Pressure-High, and one instrument for confirmed Reactor Vessel Water Level-Low, Level 3 in each of the two ADS trip systems. Each of these instruments drives a relay whose contacts form the initiation logic.

Each ADS trip system includes a time delay between satisfying the initiation logic and the actuation of the ADS valves. The ADS Initiation Timer time delay setpoint is chosen to be long enough that the HPCI system has sufficient operating time to recover to a level above Level 1, yet not so long that the LPCI and CS Systems are unable to adequately cool the fuel if the HPCI fails to maintain that level. An alarm in the control room is annunciated when either of the timers is timing. Resetting the ADS initiation signals resets the ADS Initiation Timers. The ADS also monitors the discharge pressures of the four LPCI pumps and the four CS pumps. Each ADS trip system includes two discharge pressure permissive instruments from both CS pumps in the division and from either of the two LPCI pumps in the associated Division (i.e., Division 1 LPCI pumps A or C input to ADS trip system A, and Division 2 LPCI pumps B or D input to ADS trip system B). The signals are used as a permissive for ADS actuation, indicating that there is a source of core coolant available once the ADS has depressurized the vessel. With both CS pumps in a division or one of the LPCI pumps operating sufficient flow is available to permit automatic depressurization.

The ADS logic in each trip system is arranged in two strings. Each string has a contact from each of the following variables: Reactor Vessel Water Level-Low Low Low, Level 1; Drywell Pressure-High; or Drywell Pressure Bypass Actuation Timer. One of the two strings in each trip system must also have a confirmed Reactor Vessel Water Level-Low, Level 3. All contacts in both logicstrings must close, the ADS initiation timer must time out, and a (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.3-105 Revision I

PPL Rev. 3 ECCS Instrumentation B 3.3.5.1 BASES BACKGROUND Automatic Depressurization System (continued) loop of CS or LPCI pump discharge pressure signal must be present to initiate an ADS tiip system. Either the A or B trip system will cause all the ADS relief valves to open. Once the Drywell Pressure-High signal, the ADS Drywell Pressure Bypass Actuation Timer, or the ADS initiation signal is present, it is individually sealed in until manually reset.

Manual inhibit switches are provided in the control room for the ADS; however, their function is not required for ADS OPERABILITY (provided ADS is not inhibited when required to be OPERABLE).

Diesel Generators and Other Initiated Features The DGs may be initiated by either automatic or manual means.

Automatic initiation occurs for conditions of Reactor Vessel Water Level-Low Low Low, Level 1 or Drywell Pressure High. The DGs are also initiated upon loss of voltage signals (Refer to the Bases for LCO 3.3.8.1, "Loss of Power (LOP) Instrumentation," for a discussion of these signals.) The initiation logic is arranged in a one-out-of-two-twice network using level and pressure instruments which will generate a signal when:

(1) both level sensors are tripped, or (2) both high drywell pressure sensors are tripped, or (3) a combination of one level sensor and one high drywell pressure sensor is tripped.

DGs A and B receive their initiation signal from CS system initiation logic Division I and Division II respectively. DGs C and D receive their initiation signals from either LPCI systems initiation logic Division I or Division II. The DGs can also be started manually from the control room and locally from the associated DG room. The DG initiation signal is a sealed in signal and must be manually reset. The DG initiation logic is reset by resetting the associated ECCS initiation logic.

Upon receipt of a loss of coolant accident (LOCA) initiation signal, each DG is automatically (continued)

SUSQUEHANNA - UNIT 2 TS / B3.3-106 Revision 1

PPL Rev. 3 ECCS Instrumentation B 3.3.5.1 BASES BACKGROUND Diesel Generators and Other Initiated Features (continued) started, is ready to load in approximately 10 seconds, and vill run in standby conditions (rated voltage and speed, with the DG output breaker open). The DGs will only energize their respective Engineered Safety Feature buses if a loss of offsite power occurs. (Refer to Bases for LCO 3.3.8.1.).

In addition to DG initiation, the ECCS instrumentation initiates other design features. Signals from the CS System logic initiate (1) the reset of two Emergency Service Water (ESW) timers, (2) the reset of the degraded grid timers for the 4kV buses on both units, (3) LOCA load shed schemes, and (4) the trip of Drywell Cooling equipment. Signals from the LPCI System logic initiate (1) the reset of two Emergency Service Water (ESW) timers, (2) the trip of turbine building chillers, and (3) the trip of reactor building chillers. The ESW pump timer reset feature assures the ESW pumps do not start concurrently with the CS or LPCI pumps. If one or both ESW pump timer resets in a division or reactor building/turbine building chiller trips are inoperable; two offsite circuits with the 4kV buses aligned to their normal configuration are required to be OPERABLE. If one or both ESW pump timer resets in a division or reactor building/turbine building chiller trips are inoperable; the effects on one offsite circuit have not been analyzed; and therefore, the offsite circuit is assumed not to.be capable of accepting the required loads during certain accident events, The ESW pump timer reset is not required in MODES 4 and 5 because concurrent pump starts, on a LOCA signal, of the ESW pumps (initiated by the DG start circuitry) with CS or LPCI pumps cannot occur in these MODES.

APPLICABLE The actions of the ECCS are explicitly assumed in the safety analyses SAFETY of References 1 and 2. The ECCS is initiated to preserve the integrity ANALYSES, LCO, of the fuel cladding by limiting the post LOCA peak cladding and APPLICABILITY temperature to less than the 10 CFR 50.46 limits.

(continued)

SUSQUEHANNA - UNIT 2 TS / B3.3-107 Revision 2

PPL Rev. 3 ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE ECCS instrumentation satisfies Criterion 3 of the NRC Policy SAFETY Statement (Ref. 4). Certain instrumentation Functions are retained for ANALYSES, LCO, other reasons and are described below in the individual Functions and APPLICABILITY discussion.

(continued)

The OPERABILITY of the ECCS instrumentation is dependent upon the OPERABILITY of the individual instrumentation channel Functions specified in Table 3.3.5.1-1. Each Function must have a required number of OPERABLE channels, with their setpoints within the specified Allowable Values, where appropriate. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions. Each ECCS subsystem must also respond within its assumed response time. Table 3.3.5.1-1, footnotes (b) and (c), are added to show that certain ECCS instrumentation Functions are also required to be OPERABLE to perform DG initiation and actuation of other Technical Specifications (TS) function.

Allowable Values are specified for each ECCS Function specified in the table. Nominal trip setpoints are specified in the setpoint calculations. The nominal setpoints are selected to ensure that the setpoints do not exceed the Allowable Value between CHANNEL CALIBRATIONS. Operation with a trip setpoint less conservative than the nominal trip setpoint, but within its Allowable Value, is acceptable.

A channel is inoperable if its actual trip setpoint is not within its required Allowable Value. Trip setpoints are-those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., reactor vessel water level), and when the measured output value of the process parameter reaches the setpoint, the associated device changes state.

The analytic limits are derived from the limiting values of the process parameters obtained from the safety analysis. The Allowable Values are derived from the analytic limits, corrected for calibration, process, and some of the instrument errors. The trip setpoints are then determined, accounting for the remaining instrument errors (e.g., drift).

The trip setpoints derived in this manner (continued)

SUSQUEHANNA - UNIT 2 TS / B3.3-1 08 Revision 1

PPL Rev. 3 ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE provide adequate protection because instrumentation uncertainties, SAFETY ANALYSES process effects, calibration tolerances, instrument drift, and severe LCO, and environment errors (for channels that must function in harsh APPLICABILITY environments as defined by 10 CFR 50.49) are accounted for.

(continued)

An exception to the methodology described to derive the Allowable Value is the methodology used to determine the Allowable Values for the ECCS pump start time delays and HPCI CST Level 1 - Low.

These Allowable Values are based on system calculations and/or engineering judgement which establishes a conservative limit at which the function should occur.

In general, the individual Functions are required to be OPERABLE in the MODES or other specified conditions that may require ECCS (or DG) initiation to mitigate the consequences of a design basis transient or accident. To ensure reliable ECCS and DG function, a combination of Functions is required to provide primary and secondary initiation signals. The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis.

Core Sprav and Low Pressure Coolant Iniection Systems l.a 2.a. Reactor Vessel Water Level-Low Low Low. Level 1 Low reactor pressure vessel (RPV) water level indicates that the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. The low pressure ECCS and associated DGs are initiated at Level 1 to ensure that core spray and flooding functions are available to prevent or minimize fuel damage. The Reactor Vessel Water Level-Low Low Low, Level 1 is one of the Functions assumed to be OPERABLE and capable of initiating the ECCS during the transients analyzed in References 2. In addition, the Reactor Vessel Water Level-Low Low Low, Level 1 Function is directly assumed in the analysis of the recirculation line break (Ref. 1). The core cooling function of the ECCS, along with the scram action of the Reactor Protection System (RPS), ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.

(continued)

SUSQUEHANNA - UNIT 2 TS / B3.3109 Revision 2

PPL Rev. 3 ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE 1.a. 2.a. Reactor Vessel Water Level-Low Low Low. Level 1 SAFETY (continued)

ANALYSES, LCO, and APPLICABILITY Reactor Vessel Water Level-Low Low Low, Level 1 signals are initiated from four level instruments that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel.

The Reactor Vessel Water Level-Low Low Low, Level I Allowable Value is chosen to allow time for the low pressure core flooding systems to activate and provide adequate cooling.

The initiation logic for LPCI pumps and injection valves is cross connected such that either division's start signal will start all four pumps and open both loop's injection valves. This cross division logic is required in MODES 1, 2, and 3. In MODES 4 and 5, redundancy in the initiation circuitry is not required. Therefore, in MODES 4 and 5 for LPCI, only one division of initiation logic is required.

DGs C and D which are initiated from the LPCI LOCA initiation are cross connected such that both DGs receive an initiation signal from

-both Divisions of the LPCI LOCA initiation circuitry. This cross connected logic is only required in MODES 1, 2, and 3. In MODES 4 and 5, redundancy in the DG initiation circuitry is not required.

Therefore, in MODES 4 and 5 for DGs C and D only one division of ECCS initiation logic is required.

Four channels of Reactor Vessel Water Level-Low Low Low, Level 1 Function are only required to be OPERABLE when the ECCS or DG(s) are required to be OPERABLE to ensure that nio single instrument failure can preclude ECCS and DG initiation. Refer to LCO 3.5.1 and LCO 3.5.2, "ECCS-Shutdown," for Applicability Bases for the low pressure ECCS subsystems; LCO 3.8.1, "AC Sources-Operating";

and LCO 3.8.2, "AC Sources-Shutdown," for Applicability Bases for the DGs.

(continued)

SUSQUEHANNA - UNIT 2 TS / B3.3-1 10 Revision 1

PPL Rev. 3 ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE 1.b. 2.b. Drywell Pressure-High SAFETY

ANALYSES, LCO, and High pressure in the drywell could indicate a break in the reactor APPLICABILITY coolant pressure boundary (RCPB). The low pressure ECCS (continued) (provided a concurrent low reactor pressure signal is present) and associated DGs, without a concurrent low reactor pressure signal, are initiated upon receipt of the Drywell Pressure-High Function in order to minimize the possibility of fuel damage. The Drywell Pressure-High Function, along with the Reactor Water Level-Low Low Low, Level 1 Function, is directly assumed in the analysis of the recirculation line break (Ref. 1). The core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.

High drywell pressure signals are initiated from four pressure instruments that sense drywell pressure. The Allowable Value was selected to be as low as practical and be indicative of a LOCA inside primary containment. The Drywell Pressure-High Function is required to be OPERABLE when the ECCS or DG is required to be OPERABLE in conjunction with times when the primary containment is required to be OPERABLE. Thus, four channels of the CS and LPCI Drywell Pressure-High Function are required to be OPERABLE in MODES 1, 2, and 3 to ensure that no single instrument failure can preclude ECCS and DG initiation. In MODES 4 and 5, the Drywell Pressure-High Function is not required, since there is insufficient energy in the reactor to pressurize the primary containment to Drywell Pressure-High setpoint. Refer to LCO 3.5.1 for Applicability Bases for the low pressure ECCS subsystems and to LCO 3.8.1 for Applicability Bases for the DGs.

1.c. I.d. 2.c. 2.d Reactor Steam Dome Pressure-Low Low reactor steam dome pressure signals are used as permissives for the low pressure ECCS subsystems. The low reactor pressure permissive is provided to prevent a high drywell pressure condition which is not accompanied by low reactor pressure, i.e. a false LOCA signal, from disabling two RHR pumps on the other unit. The low reactor steam dome pressure permissive also ensures that, prior to opening the injection valves of the low pressure ECCS subsystems, the reactor pressure has fallen to a value below these (continued)

SUSQUEHANNA - UNIT 2 TS /B 3.3-1 11 Revision 1

PPL Rev. 3 ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE l.c. l.d. 2.c. 2.d Reactor Steam Dome Pressure-Low SAFETY (continued)

ANALYSES, LCO, and APPLICABILITY subsystems' maximum design pressure. The Reactor Steam Dome Pressure Low is one of the Functions assumed to be OPERABLE and capable of permitting initiation of the ECCS during the transients analyzed in Reference 2. In addition, the Reactor Steam Dome Pressure-Low Function is directly assumed in the analysis of the recirculation line break (Ref. 1). The core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.

The Reactor Steam Dome Pressure-Low signals are initiated from four pressure instruments that sense the reactor dome pressure.

The pressure instruments are set to actuate between the Upper and Lower Allowable Values on decreasing reactor dome pressure.

The Upper Allowable Value is low enough to ensure that the reactor dome pressure has fallen to a value below the Core Spray and RHR/LPCI maximum design pressures to preclude overpressurization.

The Lower Allowable Value is high enough to ensure that the ECCS injection prevents the fuel peak cladding temperature from exceeding the limits of 10 CFR 50.46.

DGs C and D which are initiated from the LPCI LOCA initiation are cross connected such that both DGs receive an initiation signal from both Divisions of the LPCI LOCA initiation circuitry. This cross connected logic is only required in MODES 1, 2, and 3. In MODES 4 and 5, redundancy in the DG initiation circuitry is not required.

Therefore, in MODES 4 and 5 for DGs C and D only one division of ECCS initiation logic is required.

Four channels of Reactor Steam Dome Pressure-Low Function are required to be OPERABLE only when the ECCS is required to be OPERABLE to ensure that no single instrument failure can preclude ECCS initiation. Refer to LCO 3.5.1 and LCO 3.5.2 for Applicability Bases for the low pressure ECCS subsystems..

(continued)

SUSQUEHANNA - UNIT 2 TS / B3.3-112 Revision 1

PPL Rev. 3 ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE 1.e. 2.f. Manual Initiation SAFETY ANALYSES LCO, and The Manual Initiation push button channels introduce signals into the APPLICABILITY appropriate ECCS logic to provide manual initiation capability and are (continued) redundant to the automatic protective instrumentation. There is one push button for each of the CS and LPCI subsystems (i.e., two for CS and two for LPCI).

The Manual Initiation Function is not assumed in any accident or transient analyses in the FSAR. However, the Function is retained for overall redundancy and diversity of the low pressure ECCS function as required by the NRC in the plant licensing basis.

There is no Allowable Value for this Function since the channels are mechanically actuated based solely on the position of the push buttons. Each channel of the Manual Initiation Function (one channel per subsystem) is required to be OPERABLE only when the associated ECCS is required to be OPERABLE. Refer to LCO 3.5.1 and LCO 3.5.2 for Applicability Bases for the low pressure ECCS subsystems.

2.e. Reactor Steam Dome Pressure-Low (Recirculation Discharge Valve Permissive)

Low reactor steam dome pressure signals are used as permissives for recirculation discharge and bypass valves closure. This ensures that the LPCI subsystems inject into the proper RPV location assumed in the safety analysis. The Reactor Steam Dome Pressure-Low is one of the Functions assumed to be OPERABLE and capable of closing the valves during the transients analyzed in Reference 2. The core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46. The Reactor Steam Dome Pressure-Low Function is directly assumed in the analysis of the recirculation line break (Ref. 1).

The Reactor Steam Dome Pressure-Low signals are initiated from four pressure instruments that sense the reactor dome pressure.

The Allowable Value is chosen to ensure that the valves close prior to commencement of LPCI injection flow into the core, as assumed in the safety analysis.

(continued)

SUSQUEHANNA-UNIT2R TS / B3.3-113 Revision 2

PPL Rev. 3 ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE 2.e. Reactor Steam Dome Pressure-LoW (Recirculation SAFETY Discharge Valve Permissive) (continued)

ANALYSES, LCO, and APPLICABILITY Four channels of the Reactor Steam Dome Pressure-Low Function are only required to be OPERABLE in MODES 1, 2, and 3 with the associated recirculation pump discharge valve open. With the valve(s) closed, the function instrumentation has been performed; thus, the Function is not required. In MODES 4 and 5, the loop injection location is not critical since LPCI injection through the recirculation loop in either direction will still ensure that LPCI flow reaches the core (i.e.,

there is no significant reactor steam dome back pressure).

HPCI System 3.a Reactor Vessel Water Level - Low Low. Level 2 Low RPV water level indicates that the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. Therefore, the HPCI System is initiated at Level 2 to maintain level above the top of the active fuel. The Reactor Vessel Water Level-Low Low, Level 2 is one of the Functions assumed to be OPERABLE analyzed in Reference 2. Additionally, the Reactor Vessel Water Level-Low Low, Level 2 Function associated with HPCI is directly assumed in the analysis of the recirculation line break (Ref. 2).

The core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.

Reactor Vessel Water Level-Low Low; Level 2 signals are initiated from four level instruments that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel.

The HPCI Reactor Vessel Water Level-Low Low, Level 2 Allowable Value is chosen to be consistent with the Reactor Core Isolation Cooling (RCIC) System Reactor Vessel Water Level - Low Low, Level 2 Allowable value.

Four channels of Reactor Vessel Water Level-Low Low, Level 2 Function are required to be OPERABLE only when HPCI is required to be OPERABLE to ensure that no single instrument failure can preclude HPCI initiation. Refer to LCO 3.5.1 for HPCI Applicability Bases.

(continued)

SUSQUEHANNA - UNIT 2 TS /B B 3.3-114 Revision 1

PPL Rev. 3 ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE 3.b. Drywell Pressure-High SAFETY

ANALYSES, LCO, and High pressure in the drywell could indicate a break in the RCPB. The APPLICABILITY HPCI System is initiated upon receipt of the Drywell Pressure-High (continued) Function in order to minimize the possibility of fuel damage. The Drywell Pressure-High Function, along with the Reactor Water Level-Low Low, Level 2 Function, is directly assumed in the analysis of the recirculation line break (Ref. 1). The core cooling function of the l ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.

High drywell pressure signals are initiated from four pressure instruments that sense drywell pressure. The Allowable Value was selected to be as low as possible to be indicative of a LOCA inside primary containment.

Four channels of the Drywell Pressure-High Function are required to be OPERABLE when HPCI is required to be OPERABLE to ensure that no single instrument failure can preclude HP.CI initiation. Refer to LCO 3.5.1 for the Applicability Bases for the HPCI System.

3.c. Reactor Vessel Water Level-High. Level 8 High RPV water level indicates that sufficient cooling water inventory exists in the reactor vessel such that there is no danger to the fuel.

Therefore, the Level 8 signal is used to trip the HPCI turbine to prevent overflow into the main steam lines (MSLs). The Reactor Vessel Water Level-High, Level 8 Function is not assumed in the accident and transient analyses. It was retained since it is a potentially significant contributor to risk.

Reactor Vessel Water Level-High, Level 8 signals for HPCI are initiated from two level instruments. Both Level 8 signals are required in order to trip HPCI. This ensures that no single instrument failure can preclude an HPCI initiation or trip. The Reactor Vessel Water Level-High, Level 8 Allowable Value is chosen to prevent flow from the HPCI System from overflowing into the MSLs.

(continued)

SUSQUEHANNA - UNIT 2 TS /B 3.3-115 Revision 2

PPL Rev. 3 ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE 3.c. Reactor Vessel Water Level-High. Level 8 (continued)

SAFETY ANALYSES, LCO, Two channels of Reactor Vessel Water Level--High, Level 8 Function and APPLICABILITY are required to be OPERABLE only when HPCI is required to be OPERABLE. Refer to LCO 3.5.1 and LCO 3.5.2 for HPCI Applicability Bases.

3.d. Condensate Storage Tank Level--Low The Condensate Storage Tank-Low signal indicates that a conservatively calculated NPSH-available limit is being approached.

Normally the suction valves between HPCI and the CST are open and, upon receiving a HPCI initiation signal, water for HPCI injection would be taken from the CST. However, if the water level in the CST falls below a preselected level, first the suppression pool suction valve automatically opens, and then the CST suction valve automatically.

closes. This ensures that an adequate suction head for the pump and an uninterrupted supply of makeup water is available to the HPCI pump. To prevent losing suction to the pump, the suction valves are interlocked so that the suppression pool suction Valves must be open before the CST suction valve automatically closes. The Function is implicitly assumed in the accident and transient analyses (which take credit for HPCI) since the analyses -assume that the HPCI suction source is the suppression pool.

Condensate Storage Tank Level--Low signals are initiated from two level instruments. The logic is arranged such that either level switch can cause the suppression pool suction valves to open and the CST suction valve to close. The Condensate Storage Tank Level--Low Function Allowable Value is high enough to ensure adequate pump suction head while water is being taken from the CST.

Two channels of the Condensate Stora ge Tank Level--Low Function are required to be OPERABLE only when HPCI is required to be OPERABLE to ensure that no single instrument failure can preclude HPCI swap to suppression pool source. Refer to LCO 3.5.1 for HPCI Applicability Bases.

(continued)

SUSQUEHANNA - UNIT 2 T/3316Rvso TS / B 3.3-116 Revision 2

PPL Rev. 3 ECCS Instrumentation B 3.3.5.1

.BASES I

I I

3.e. Manual Initiation I The Manual Initiation push button channel introduces signals into the HPCI logic to provide manual initiation capability and is redundant to the automatic protective instrumentation. There is one push button for the HPCI System.

(continued)

SUSQUEHANNA - UNIT 2 TS IB 3.3-117 Revision 2

PPL Rev. 3 ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE 3. e. Manual Initiation (continued)

SAFETY ANALYSES, LCO, The Manual Initiation Function is not assumed in any accident or and APPLICABILITY transient analyses in the FSAR. However, the Function is retained for overall redundancy and diversity of the HPCI function as required by the NRC in the plant licensing basis.

There is no Allowable Value for this Function since the channel is mechanically actuated based solely on the position of the push button.

One channel of the Manual Initiation Function is required to be OPERABLE only when the HPCI System is required to be OPERABLE. Refer to LCO 3.5.1 for HPCI Applicability Bases.

Automatic Depressurization System 4.a. 5.a. Reactor Vessel Water Level-Low Low Low. Level 1 Low RPV water level indicates that the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. Therefore, ADS receives one of the signals necessary for initiation from this Function. The Reactor VesselWater Level--Low Low Low, Level 1 is one of the Functions assumed to be OPERABLE and capable of initiating the ADS during the accident analyzed in Reference 1. The core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.

Reactor Vessel Water Level-Low Low Low, Level 1 signals are initiated from four level instruments that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels of Reactor Vessel Water Level-Low Low'Low, Level 1 Function are required to be OPERABLE only when ADS is required to be OPERABLE to ensure that no single instrument failure can preclude ADS initiation. Two channels input to ADS trip system A, while the other two channels input to ADS trip system B. Refer to LCO 3.5.1 for ADS Applicability Bases.

(continued)

SUSQUEHANNA - UNIT 2 TS /B 3.3-1 18 Revision 2

PPL Rev. 3 ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE 4.a, 5.a. Reactor Vessel Water Level-Low Low Low. Level 1 SAFETY (continued)

ANALYSES, LCO, and APPLICABILITY The Reactor Vessel Water Level-Low Low Low, Level 1 Allowable Value is chosen to allow time for the low. pressure core flooding systems to initiate and provide adequate cooling.

4.b. 5.b Drvwell Pressure - High High pressure in the drywell could indicate a break in the RCPB.

Therefore, ADS receives one of the signals necessary for initiation from this Function in order to minimize the possibility of fuel damage.

The Drywell Pressure-High is assumed to be OPERABLE and capable of initiating the ADS during the accidents analyzed in Reference 2. The core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.

Drywell Pressure-High signals are initiated from four pressure instruments that sense drywell pressure. The Allowable Value was selected to be as low as possible and be indicative of a LOCA inside primary containment.

Four channels of Drywell Pressure-High Function are only required to be OPERABLE when ADS is required to be OPERABLE to ensure that no single instrument failure can preclude ADS initiation. Two channels input to ADS trip system A, while the other two channels input to ADS trip system B. Refer to LCO 3.5.1 for ADS Applicability Bases.

4.c. 5.c. Automatic DeDressurization System Initiation Timer The purpose of the Automatic Depressurization System Initiation Timer!

is to delay depressurization of the reactor vessel to allow the HPCI System time to maintain reactor vessel water level. Since the rapid depressurization caused by ADS operation is one of the most severe transients on the reactor vessel, its occurrence should be limited. By delaying initiation of the ADS Function, the operator is given the chance to monitor the success or failure of the HPCI System to maintain water level, and then to decide whether or not to allow ADS to initiate, to delay initiation further by (continued)

SUSQUEHANNA-UNIT 2 TS / B 3.3-119 Revision 1

PPL Rev. 3 ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE 4.c. 5.c. Automatic Depressurization System Initiation Timer SAFETY (continued)

ANALYSES, LCO, and APPLICABILITY recycling the timer, or to inhibit initiation permanently. The Automatic Depressurization whether or not to allow ADS to initiate, to delay initiation. System Initiation Timer Function is assumed to be OPERABLE for the accident analyses of Reference 1 that require ECCS initiation and assume failure of the HPCI System.

There are two Automatic Depressurization System Initiation Timer relays, one in each of the two ADS trip systems. The Allowable Value for the Automatic Depressurization System Initiation Timer is chosen so that there is still time after depressurization for the low pressure ECCS subsystems to provide adequate core cooling.

Two channels of the Automatic Depressurization System Initiation Timer Function are only required to be OPERABLE when the ADS is required to be OPERABLE to ensure that no single instrument failure can preclude ADS initiation. (One channel inputs to ADS trip system A, while the other channel inputs to ADS trip system B. Refer to LCO 3.5.1 for ADS Applicability Bases.

4.d. 5.d. Reactor Vessel Water Level-Low; Level 3 The Reactor Vessel Water Level-Low, Level 3 Function is used by the ADS only as a confirmatory low.water level signal. ADS receives one of the signals necessary for initiation from Reactor Vessel Water Level-Low Low Low, Level 1 signals. In order to prevent spurious initiation of the ADS due to spurious Level 1 signals, a Level 3 signal must also be received before ADS initiation commences.

Reactor Vessel Water Leve-Low, Level 3 signals are initiated from two level instruments that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. The Allowable Value for Reactor Vessel Water Level-Low, Level 3 is selected at the RPS Level 3 scram Allowable Value for convenience.

Refer to LCO 3.3.1.1, "Reactor Protection System (RPS)

Instrumentation," for the Bases discussion of this Function.

(continued)'

SUSQUEHANNA - UNIT 2 TS /B 3.3-120 Revision 1

PPL Rev. 3 ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE 4.d. 5.d. Reactor Vessel Water Level-Low. Level 3 (continued)

SAFETY ANALYSES LCO, and Two channels of Reactor Vessel Water Level-Low, Level 3 Function APPLICABILITY are required to be OPERABLE only when the ADS is required to be OPERABLE to ensure that no single instrument failure can preclude ADS initiation. One channel inputs to ADS trip system A, while the other channel inputs to ADS trip system B. Refer to LCO 3.5.1 for ADS Applicability Bases.

4.e. 4.f. 5.e. 5.f. Core Sprav and Low Pressure Coolant Iniection Pump Discharge Pressure - Low The Pump Discharge Pressure-High signals from the CS and LPCI pumps are used as permissives for ADS initiation, indicating that there is a source of low pressure cooling water available once the ADS has depressurized the vessel. Pump Discharge Pressure-High is one of the Functions assumed to be OPERABLE and capable of permitting ADS initiation during the events analyzed in Reference 1 with an assumed HPCI failure. For these events the ADS depressurizes the reactor vessel so that the low pressure ECCS can perform the core cooling functions. This core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR'50.46.

Pump discharge pressure signals are initiatedcfrom twelve pressure instruments, two on the discharge side of each of the four LPCI pumps and one on the discharge of each of CS pumps. In order to generate an ADS permissive in one trip system, it is necessary that only one LPCI pump or one CS subsystem indicate the high discharge pressure condition. The Pump Discharge Pressure High Allowable Value is less than the pump discharge pressure when the pump is operating in a full flow mode and high enough to avoid any condition that results in a discharge pressure permissive when the CS and LPCI pumps are aligned for injection and the pumps are not running. The actual operating point of this function is not assumed in any transient or accident analysis.

Twelve channels of Core Spray and Low Pressure Coolant Injection Pump Discharge Pressure-High Function are only required to be OPERABLE when the ADS is required to be OPERABLE to ensure that no single instrument failure can preclude ADS initiation. Two CS channels associated with CS pumps A and C and four LPCI channels associated with LPCI pumps A and C are required for trip system A.

Two CS channels associated with CS pumps B and D and four LPCI channels (continued)

SUSQUEHANNA - UNIT 2 TS /B 3.3-121 Revision 2

PPL Rev. 3 ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE 4.e. 4.f. 5.e 5.f. Core Sprav and Low Pressure-Coolant Iniection SAFETY Pump Discharge Pressure - Low (continued)

ANALYSES, LCO, and APPLICABILITY associated with LPCI pumps B and D are required for trip system B.

Refer to LCO 3.5.1 for ADS Applicability Bases.

4.g. 5.a. Automatic Deoressurization System Drvwell Pressure Bypass Actuation Timer One of the signals required for ADS initiation is Drywell Pressure-High. However, if the event requiring ADS initiation occurs outside the drywell (e.g., main steam line break outside containment), a high drywell pressure signal may never be present. Therefore, the Automatic Depressurization System Drywell Pressure Bypass Actuation Timer is used to bypass the Drywell Pressure-High Function after a certain time period has elapsed. Operation of the Automatic Depressurization System Drywell Pressure Bypass Actuation Timer Function is not assumed in any accident analysis.

The instrumentation is retained in the TS because ADS is part of the primary success path for mitigation of a DBA.

There are four Automatic Depressurization System Drywell Pressure Bypass Actuation Timer relays, two in each of.the two ADS trip systems. The Allowable Value for-the Automatic Depressurization System Low Water Level Actuation Timer is chosen to ensure that there is still time after depressurization for the low pressure ECCS subsystems to provide adequate core cooling.

Four channels of the Automatic Depressurization System Drywell Pressure Bypass Actuation Timer Function are required to be OPERABLE only when the ADS is required to be OPERABLE to ensure that no single instrument failure can preclude ADS initiation.

Refer to LCO 3.5.1 for ADS Applicability Bases.

4.h. 5.h. Manual Initiation The Manual Initiation push button channels introduce signals into the ADS logic to provide manual initiation capability and are redundant to the automatic protective instrumentation. There are two push buttons for each ADS trip system for a total of four.

(continued)

SUSQUEHANNA - UNIT 2 TS /B 3.3-122 Revision 2

PPL Rev. 3 ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE 4.h. 5.h. Manual Initiation (continued)

SAFETY ANALYSES, LCO, The Manual Initiation Function is not assumed in any accident or and APPLICABILITY transient analyses in the FSAR. However, the Function is retained for overall redundancy and diversity of the ADS functions as required by the NRC in the plant licensing basis.

There is no Allowable Value for this Function since the channels are mechanically actuated based solely on the position of the push buttons. Four channels of the Manual Initiation Function (two channels per trip system) are only required to be OPERABLE when the ADS is required to be OPERABLE. Refer to LCO 3.5.1 for ADS Applicability Bases.

ACTIONS A Note has been provided to modify the ACTIONS related to ECCS 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 ECCS instrumentation channels provide appropriate compensatory measures for separate inoperable Condition entry for each inoperable ECCS instrumentation channel.

A.1 Required Action A.1 directs entry into the appropriate Condition referenced in Table 3.3.5.1-1. The applicable Condition referenced in the table is Function dependent. Each time a channel is discovered inoperable, Condition A is entered for that channel and provides for transfer to the appropriate subsequent Condition.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.3-123 Revision I

PPL Rev. 3 ECCS Instrumentation B 3.3.5.1 BASES ACTIONS B.1. B.2. and B.3 (continued)

Required Actions B.1 and B.2 are intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same Function result in redundant automatic initiation capability being lost for the feature(s). Required Action B.1 features would be those that are initiated by Functions 1.a, 1.b, 1.c, 2.a, 2.b, and 2.c (e.g., low pressure ECCS). The Required Action B.2 system would be HPCI.

For Required Action B.1, redundant automatic initiation capability is lost if (a) one Function 1.a, 1.b, 1.c, 2.a, or2.b is inoperable and untripped with only one offsite source OPERABLE, or (b) one or more Function 1.a or Function 2.a channels in both divisions are inoperable and untripped, or (c) one or more Function 1.b or Function 2.b channels in both divisions are inoperable and untripped, or (d) one or more Function 1.c or Function 2.c channels in both divisions are inoperable and untripped.

For (a) above (Function 1.a, 1.b, 1.c, 2.a, or 2.b is inoperable and untripped with only one offsite source OPERABLE), the ESW pump timer resets may not receive a reset signal and the Reactor Building chillers, Turbine Building chillers and the Drywell cooling equipment may not receive a trip signal. Without the reset of the ESW pump timers and without the trip of the Reactor Building and Turbine Building chillers, the OPERABLE offsite circuit may not be capable of accepting starts of the ESW pumps concurrently with CS or.LPCI pumps. For this situation, both the OPERABLE offsite circuit and the DG, that would not be capable of starting, should be declared inoperable.

ACTIONS required by LCO 3.8.1 "AC Sources Operating" or LCO 3.8.2 UAC Sources Shutdown" should be taken or disable the affected reactor building/turbine building chillers and disable the affected ESW pumps automatic initiation capability and take the ACTIONS required by LCO 3.7.2 "ESW System".

For the Drywell cooling equipment trip, inoperability of this feature would require that the associated drywell cooling fans be declared inoperable in accordance with LCO 3.6.3.2 "Drywell Air Flow System".

With two offsite sources OPERABLE and one Function 1.a, 1.b, 1.c, 2.a or 2.b inoperable and untripped, sufficient ECCS equipment is available to meet the design basis accident analyses.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.3-124 Revision 2

PPL Rev. 3 ECCS Instrumentation B 3.3.5.1 BASES ACTIONS B.1, B.2, and B.3 (continued)

For (b), (c) and (d)above, for each Division, since each inoperable channel would have Required Action B.1 applied separately (refer to ACTIONS Note), each inoperable channel would only require the affected portion of the associated system of low pressure ECCS, DGs, and associated features to be declared inoperable. However, since channels in both Divisions are inoperable and untripped, and the Completion Times started concurrently for the channels in both subsystems, this results in the affected portions in the associated low pressure ECCS and DGs being concurrently declared inoperable.

For Required Action B.2, redundant automatic initiation capability is lost if two Function 3.a or two Function 3.b channels are inoperable and untripped in the same tiip system. In this situation (loss of redundant automatic initiation capability), the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months allowance of Required Action B.3 is not appropriate and the feature(s) associated with the inoperable, untripped channels must be declared inoperable within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . As noted (Note 1 to Required Action B.1), Required Action B.1 is only applicable in MODES 1, 2, and 3. In MODES 4 and 5, the specific initiation time of the low pressure ECCS is not assumed and the probability of a LOCA is lower. .Thus, a total loss of initiation capability for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months (as allowed by Required Action B.3) is allowed during MODES 4 and 5. There is no similar Note provided for Required Action B.2 since HPCI instrumentation is not required in MODES 4 and 5; thus, a Note is not necessary. Notes are also provided (Note 2 to Required Action B.1 and the Note to Required Action B.2) to (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.3-124a Revision 0

PPL Rev. 3 ECCS Instrumentation B 3.3.5.1 BASES ACTIONS B.1 B.2. and B.3 (continuedi delineate which Required Action is applicable for each Function that requires entry into Condition B if an associated channel is inoperable.

This ensures that the proper loss of initiation capability check is performed.

The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." For Required Action B.1, the Completion Time only begins upon discovery that a redundant feature in both Divisions (e.g., both CS subsystems) cannot be automatically initiated due to inoperable, untripped channels within the same Function as described in the paragraph above. For Required Action B.2, the Completion Time only begins upon discovery that the HPCI System cannot be automatically initiated due to two inoperable, untripped channels for the associated Function in the same trip system. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.

Because of the diversity of sensors available to provide initiation signals and the redundancy of the ECCS design, an allowable out of service time of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months has been shown to be acceptable (Ref. 3) to permit restoration of any inoperable channel to OPERABLE status. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per Required Action B.3. Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue. Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing the inoperable channel in trip would result in an initiation), Condition G must be entered and its Required Action taken.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.3-125 Revision I

PPL Rev. 3 ECCS Instrumentation B 3.3.5.1 BASES ACTIONS C.1 and C.2 (continued)

INTERIM ADMINISTRATIVE DIRECTION Technical Specification Table 3.3.5.1-1, UHPCI System, Function 3.e, Conditions Referenced from Required Action A.1" contains a typographical error (CR 620823). The "D" referenced should be "C."

In accordance with Administrative Letter 98-10, direction is provided until proposed TS change (LDCN 3798) is approved by the NRC.

Required Action C.1 is intended to ensure that appropriate actions are taken if multiple, inoperable channels within the same Function result in redundant automatic initiation capability being lost for the feature(s).

Required Action C.1 features would be those that are initiated by Functions 1.d, 2.d, and 2.e (i.e., low pressure ECCS). Redundant automatic initiation capability is lost if either (a) two or more Function 1.d channels are inoperable such that the trip system loses initiation capability, (b) two or more Function 2.d channels are inoperable in the same trip system such that the trip system loses initiation capability, or (c) two or more Function 2.e channels are inoperable affecting LPCI pumps in different subsystems. In this situation (loss of redundant automatic initiation capability), the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months allowance of Required Action C.2 is not appropriate and the feature(s) associated with the inoperable channels must be declared inoperable within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . Since each inoperable channel would have Required Action C.1 applied separately (refer to ACTIONS Note), each inoperable channel would only require the affected portion of the associated system to be declared inoperable. However, since channels for both low pressure ECCS subsystems are inoperable (e.g., both CS subsystems), and the Completion Times started concurrently for the channels in both subsystems, this results in the affected portons in both subsystems being concurrently declared inoperable. For Functions 1.d, 2.d, and 2.e, the affected portions are the associated low pressure ECCS pumps. As noted (Note 1), Required Action C.1 is only applicable in MODES 1, 2, and 3. In MODES 4 and 5, the specific initiation time of the ECCS is not assumed and the probability of a LOCA is lower.

Thus, a total loss of automatic initiation capability for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months (as allowed by Required Action C.2) is allowed during MODES 4 and 5.

Note 2 states that Required Action C.1 is only applicable for Functions 1.d, 2.d, and 2.e. Required Action C.1 is not applicable to Functions 1.e, 2.f, and 3.e (which also require bntry into this Condition if a channel in these Functions is inoperable), since they are the Manual Initiation Functions and are not assumed in any accident or transient (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.3-126 Revision 2

PPL Rev. 3 ECCS Instrumentation B 3.3.5.1 BASES ACTIONS C.1 and C.2 (continued) analysis. Thus, a total loss of manual initiation capability for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months (as allowed by Required Action C.2) is allowed. Required Action C.1 is also not applicable to Function 3.c (which also requires entry into this Condition if a channel in this Function is inoperable), since the loss of one channel results in a loss of the Function (two-out-of-two logic).

This loss was considered during the development of Reference 3 and considered acceptable for the 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months allowed by Required Action C.2.

The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." For Required Action C.1, the Completion Time only begins upon discovery that the same feature in both subsystems (e.g., both CS subsystems) cannot be automatically initiated due to inoperable channels within the same Function as described in the paragraph above. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration of channels.

Because of the diversity of sensors available to provide initiation signals and the redundancy of the ECCS design, an allowable out of service time of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months has been shown to be acceptable (Ref. 3) to permit restoration of any inoperable channel to OPERABLE status. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, Condition G must be entered and its Required Action taken. The Required Actions do not allow placing the channel in trip since this action would either cause the initiation or it would not necessarily result in a safe state for the channel in all events.

D.1. D.2.1. and D.2.2 INTERIM ADMINISTRATIVE DIRECTION Technical Specification Table 3.3.5.1-1, UHPCI System, Function 3.e, Conditions Referenced from Required Action A.1" contains a typographical error (CR 620823). The "D" referenced should be UC.N In accordance with Administrative Letter 98-10, direction is provided until proposed TS change (LDCN 3798) is approved by the NRC.

Required Action D.1 is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same Function result in a complete loss of automatic component initiation capability for (continued)

SUSQUEHANNA - UNIT 2 TS / B3.3-127 Revision 3

7 PPL Rev. 3 ECCS Instrumentation B 3.3.5.1 BASES ACTIONS D.1. D.2.1. and D.2.2 continued) the HPCI System. Automatic component initiation capability is lost if two Function 3.d channels are inoperable and untripped. In this situation (loss of automatic suction swap), the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months allowance of Required Actions D.2.1 and D.2.2 is not appropriate and the HPCI System must be declared inoperable within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months after discovery of loss of HPCI initiation capability. A Note identifies that Required Action D.1 is only applicable if the HPCI pump suction is not aligned to the suppression pool, since, if aligned, the Function is already performed. This allows the HPCI pump suction to be realigned to the Suppression Pool within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , if desired.

The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." For Required Action D.1, the Completion Time only begins upon discovery that the HPCI System cannot be automatically aligned to the suppression pool due to two inoperable, untripped channels in the same Function. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration or tripping of channels. Because of the diversity of sensors available to provide initiation signals and the redundancy of the ECCS design, an allowable out of service time of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months has been shown to be acceptable (Ref. 3) to permit restoration of any inoperable channel to OPERABLE status. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the trpped condition per Required Action D.2.1 or the suction source must be aligned to the suppression pool per Required Action D.2.2. Placing the inoperable channel in trip performs the intended function of the channel (shifting the suction source to the suppression pool). Performance of either of these two Required Actions will allow operation to continue. If it is not desired to perform Required Actions D.2.1 and D.2.2, Condition G must be entered and its Required Action taken.

E.1 and E.2 Required Action E.1 is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within similar ADS trip system A and B Functions result in redundant automatic initiation capability being lost for the ADS. Redundant automatic initiation capability (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.3-128 Revision 2

PPL Rev. 3 ECCS Instrumentation B 3.3.5.1 BASES ACTIONS E.1 and E.2 (continued) is lost if either (a) one Function 4.a channel and one Function 5.a channel are inoperable and untripped, (b) one Function 4.b channel and one Function 5.b channel are inoperable and untripped, or (c) one Function 4.d channel and one Function 5.d channel are inoperable and untripped.

In this situation (loss of automatic initiation capability), the 96 hour0.00111 days 0.0267 hours 1.587302e-4 weeks 3.6528e-5 months or 8 day allowance, as applicable, of Required Action E.2 is not appropriate and all ADS valves must be declared inoperable within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months after discovery of loss of ADS initiation capability.

The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." For Required Action E.1, the Completion Time only begins upon discovery that the ADS cannot be automatically initiated due to inoperable, untripped channels within similar ADS trip system Functions as described in the paragraph above. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.

Because of the diversity of sensors available to provide initiation signals and the redundancy of the ECCS design, an allowable out of service time of 8 days has been shown to be acceptable (Ref. 3) to permit restoration of any inoperable channel to OPERABLE status if both HPCI and RCIC are OPERABLE. If either HPCI or RCIC is inoperable, the time is shortened to 96 hours0.00111 days 0.0267 hours 1.587302e-4 weeks 3.6528e-5 months . If the status of HPCI or RCIC changes such that the Completion Time changes from 8 days to 96 hours0.00111 days 0.0267 hours 1.587302e-4 weeks 3.6528e-5 months , the 96 hours0.00111 days 0.0267 hours 1.587302e-4 weeks 3.6528e-5 months begins upon discovery of HPCI or RCIC inoperability. However, the total time for an inoperable, untripped channel cannot exceed 8 days. If the status of HPCI or RCIC changes such that the Completion Time changes from 96 hours0.00111 days 0.0267 hours 1.587302e-4 weeks 3.6528e-5 months to 8 days, the "time zero" for beginning the 8 day "clock" begins upon discovery of the inoperable, untripped channel. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per Required Action E.2. Placing the inoperable channel in trip would conservatively compensate for the (continued)

SUSQUEHANNA - UNIT 2 TS / B 3.3-129 Revision 1

PPL Rev. 3 ECCS Instrumentation B 3.3.5.1 BASES ACTIONS E.1 and E.2 (continued) inoperability, restore capability to accommodate a single failure, and allow operation to continue. Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing the inoperable channel in trip would result in an initiation), Condition G must be entered and its Required Action taken.

F.1 and F.2 Required Action F.1 is intended to ensure that appropriate actions are taken if multiple, inoperable channels within similar ADS trip system Functions result in automatic initiation capability being lost for the ADS.

Automatic initiation capability is lost if either (a) one Function 4.c channel and one Function 5.c channel are inoperable, (b) a combination of Function 4.e, 4.f, 5.e, and 5.f channels are inoperable such that both ADS trip systems lose initiation capability, or (c) one or more Function 4.g channels and one or more Function 5.g channels are inoperable.

In this situation (loss of automatic initiation capability), the 96 hour0.00111 days 0.0267 hours 1.587302e-4 weeks 3.6528e-5 months or 8 day allowance, as applicable, of Required Action F.2 is not appropriate, and all ADS valves must be declared inoperable within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months after discovery of loss of ADS initiation capability. The Note to Required Action F.1 states that Required Action F.1 is only applicable for Functions 4.c, 4.e, 4.f, 4.g, 5.c, 5.e, 5.f, and 5.g. Required Action F.1 is not applicable to Functions 4.h and 5.h (which also require entry into this Condition if a channel in these Functions is inoperable), since they are the Manual Initiation Functions and are not assumed in any accident or transient analysis. Thus, a total loss of manual initiation capability for 96 hours0.00111 days 0.0267 hours 1.587302e-4 weeks 3.6528e-5 months or 8 days (as allowed by Required Action F.2) is allowed.

The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." For Required Action F.1, the Completion Time only begins upon discovery that the ADS cannot be automatically initiated due to inoperable channels within similar ADS trip system Functions as described in the paragraph above. The (continued)

SUSQUEHANNA - UNIT 2 TS I B 3.3-130 Revision I

PPL Rev. 3 ECCS Instrumentation B 3.3.5.1 BASES ACTIONS F.1 and F.2 (continued) 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.

Because of the diversity of sensors available to provide initiation.

signals and the redundancy of the ECCS design, an allowable out of service time of 8 days has been shown to be acceptable (Ref. 3) to permit restoration of any inoperable channel to OPERABLE status if both HPCI and RCIC are OPERABLE (Required Action F.2). If either HPCI or RCIC is inoperable, the time shortens to 96 hours0.00111 days 0.0267 hours 1.587302e-4 weeks 3.6528e-5 months . If the status of HPCI or RCIC changes such that the Completion Time changes from 8 days to 96 hours0.00111 days 0.0267 hours 1.587302e-4 weeks 3.6528e-5 months , the 96 hours0.00111 days 0.0267 hours 1.587302e-4 weeks 3.6528e-5 months begins upon discovery of HPCI or RCIC inoperability. However, the total time for an inoperable channel cannot exceed 8 days. If the status of HPCI or RCIC changes such that the Completion Time changes from 96 hours0.00111 days 0.0267 hours 1.587302e-4 weeks 3.6528e-5 months to 8 days, the "time zero" for beginning the 8 day "clock" begins upon discovery of the inoperable channel. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, Condition G must be entered and its Requifed Action taken. The Required Actions do not allow placing the channel in trip since this action would not necessarily result in a safe state for the channel in all events.

G.1 With any Required Action and associated Completion Time not met, the associated supported feature(s) may be incapable of performing the intended function, and those associated with inoperable untripped channels must be declared inoperable immediately.

SURVEILLANCE As noted in the beginning of the SRs, the SRs for each ECCS REQUIREMENTS instrumentation Function are found in the SRs column of Table 3.3.5.1-1.

The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to (continued)

SUSQUEHANNA- UNIT 2 TS /B 3.3-131 R Revision 1

PPL Rev. 3 ECCS Instrumentation B 3.3.5.1 BASES SURVEILLANCE 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months as follows: (a) for Function 3.c and 3.f; and (b) for Functions REQUIREMENTS other than 3.c and 3.f provided the associated Function or redundant (continued) Function maintains ECCS initiation capability. Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Ref. 3) assumption of the average time required to perform channel surveillance. That analysis demonstrated that the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance does not significantly reduce the probability that the ECCS will inmate when necessary.

In addition, for Functions 1.a, 1.b, 1.c, 2.a, and 2.b, the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months allowance is acceptable provided both offsite sources are OPERABLE.

SR 3.3.5.1.1 Performance of the CHANNEL CHECK once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the instrument channels could be an-indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK guarantees that undetected channel failure is limited to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ; thus, it is key to verifying the instrumentation continues fo 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 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 necessary indicate the channel is Inoperable.

The Frequency is based upon operating experience that demonstrates channel failure is rare. The CHANNEL CHECK supplements less formal checks of channels during normal operational use of the displays associated with the channels required by the LCO.

(continued)

SUSQUEHANNA - UNIT 2 TS /B 3.3132 Revision 2

PPL Rev. 3 ECCS Instrumentation B 3.3.5.1 BASES SURVEILLANCE SR 3.3.5.1.2 REQUIREMENTS (continued) A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. The Frequency of 92 days is based on the reliability analyses of Reference 3.

This SR is modified by a Note that provides a general exception to the definition of CHANNEL FUNCTIONAL TEST. This exception is necessary because the design of instrumentation does not facilitate functional testing of all required contacts of the relay which input into the combinational logic. (Reference 5) Performance of such a test could result in a plant transient or place the plant in an undo risk situation. Therefore, for this SR, the CHANNEL FUNCTIONAL TEST verifies acceptable response by verifying the change of state of the relay which inputs into the combinational logic. The required contacts not tested during the CHANNEL FUNCTIONAL TEST are tested under the LOGIC SYSTEM FUNCTIONAL TEST, SR 3.3.5.1.5. This is acceptable because operating experience shows that the contacts not tested during the CHANNEL FUNCTIONAL TEST normally pass the LOGIC SYSTEM FUNCTIONAL TEST, and the testing methodology minimizes the risk of unplanned transients.

SR 3.3.5.1.3 and SR 3.3.5.1.4 A CHANNEL CALIBRATION is a complete check that verifies the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.

The Frequency of SR 3.3.5.1.3 is based upon the assumption of a 92 day calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

The Frequency of SR 3.3.5.1.4 is based upon the assumption of a 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

(continued)

SUSQUEHANNA - UNIT 2 TS / B 3.3-133 Revision 1

PPL Rev. 3 ECCS Instrumentation B 3.3.5.1 BASES SURVEILLANCE SR 3.3.5.1.5 REQUIREMENTS The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required initiation logic for a specific channel.

The system functional testing performed in LCO 3.5.1, LCO 3.5.2, LCO 3.8.1, and LCO 3.8.2 overlaps this Surveillance to complete testing of the assumed safety function. The LOGIC SYSTEM FUNCTIONAL TEST tests the operation of the initiation logic up to but not including the first contact which is unique to an individually supported feature such as the starting of a DG.

The 24 month Frequency is based on the need to perform portions of this Surveillance 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. Operating experience has shown that these components usually pass the Surveillance when performed at the 24 month Frequency.

REFERENCES 1. FSAR, Section 6.3.

2. FSAR, Chapter 15.

3. NEDC-30936-P-A, "BWR Owners' Group Technical Specification Improvement Analyses for ECCS Actuation Instrumentation, Part 2," December 1988.

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

5. NRC Inspection and Enforcement Manual, Part 9900: Technical Guidance, Standard Technical Specification Section 1.0 Definitions, Issue date 12108/86.

SUSQUEHANNA - UNIT 2 TS / B3.3-134 Revision 1

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