ML091380099
| ML091380099 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 05/07/2009 |
| From: | Gerlach R Susquehanna |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| 028401, 2009-21478 | |
| Download: ML091380099 (85) | |
Text
May. 07, 2009 Page 1 of 3 MANUAL HARD COPY DISTRIBUTION DOCUMENT TRANSMITTAL 2009-21478 USER INFORMATION:
GERLACH*ROSE M EMPL#:028401 CA#: 0363 Address: NUCSA2 Phone#: 254-3194 TRANSMITTAL INFORMATION:
TO: GERLACH*ROSE M 05/07/2009 LOCATION: USNRC FROM: NUCLEAR RECORDS DOCUMENT CONTROL CENTER (NUCSA-2)
THE FOLLOWING CHANGES HAVE OCCURRED TO THE HARDCOPY OR ELECTRONIC MANUAL ASSIGNED TO YOU. HARDCOPY USERS MUST ENSURE THE DOCUMENTS PROVIDED MATCH THE INFORMATION ON THIS TRANSMITTAL. WHEN REPLACING THIS MATERIAL IN YOUR HARDCOPY MANUAL, ENSURE THE UPDATE DOCUMENT ID IS THE SAME DOCUMENT ID YOU'RE REMOVING FROM YOUR MANUAL. TOOLS FROM THE HUMAN PERFORMANCE TOOL BAG SHOULD BE UTILIZED TO ELIMINATE THE CHANCE OF ERRORS.
ATTENTION: "REPLACE" directions do not affect the Table of Contents, Therefore no TOC will be issued with the updated material.
TSBl - TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL REMOVE MANUAL TABLE OF CONTENTS DATE: 05/05/2009 ADD MANUAL TABLE OF CONTENTS DATE: 05/06/2009 CATEGORY: DOCUMENTS TYPE: TSBI ltocq
May. 07, 2009 Page 2 of 3 ID: TEXT 2.1.1 ADD: REV: 5 REMOVE: REV:4 CATEGORY: DOCUMENTS TYPE: TSBI ID: TEXT 3.1.8 REMOVE: REV:2 ADD: REV: 3 CATEGORY: DOCUMENTS TYPE: TSB1 ID: TEXT 3.2.2 REMOVE: REV:2 ADD: REV: 3 CATEGORY: DOCUMENTS TYPE: TSBI ID: TEXT 3.7.1 REMOVE: REV:2 ADD: REV: 3 CATEGORY: DOCUMENTS TYPE: TSB1 ID: TEXT 3.8.1 REMOVE: REV:5 ADD: REV: 6 CATEGORY: DOCUMENTS TYPE: TSB1 ID: TEXT LOES ADD: REV: 92 REMOVE: REV:91
May. 07, 2009 Page 3 of 3 ANY DISCREPANCIES WITH THE MATERIAL PROVIDED, CONTACT DCS @ X3107 OR X3136 FOR ASSISTANCE. UPDATES FOR HARDCOPY MANUALS WILL BE DISTRIBUTED WITHIN 3 DAYS IN ACCORDANCE WITH DEPARTMENT PROCEDURES. PLEASE MAKE ALL CHANGES AND ACKNOWLEDGE COMPLETE IN YOUR NIMS INBOX UPON COMPLETION OF UPDATES. FOR ELECTRONIC MANUAL USERS, ELECTRONICALLY REVIEW THE APPROPRIATE DOCUMENTS AND ACKNOWLEDGE COMPLETE IN YOUR NIMS INBOX.
SSES MANUAL Manual Name: TSB1 Manual
Title:
TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL Table Of Contents Issue Date: 05/06/2009 Procedure Name Rev Issue Date Change ID Change Number TEXT LOES 92 05/06/2009
Title:
LIST OF EFFECTIVE.SECTIONS TEXT TOC 16 10/27/2008
Title:
TABLE OF CONTENTS TEXT 2.1.1 5 05/06/2009
Title:
SAFETY LIMITS (SLS) REACTOR CORE SLS TEXT 2.1.2 1 10/04/2007
Title:
SAFETY LIMITS (SLS) REACTOR COOLANT SYSTEM, (RCS) PRESSURE S
. TEXT 3.0 O 2 10/12 /2D006
Title:
LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY TEXT 3.1.1 /, t. 04/18/2006
Title:
REACTIVITY CONTROL SYSTEMS ,SHUTDOWN MARGIN (SDM)
TEXT 3.1.2 S" 0 11/15/2002
Title:
REACTIVITY CONTROL SYSTEMS REACTIVITY ANOMALIES TEXT 3.1.3 2 01/19/2009
Title:
REACTIVITY/CONTROL SYSTEMS CONTROL ROD OPERABILITY TEXT 3.1.4 4 01/30/2009
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 04/18/2006
Title:
REACTIVITY CONTROL SYSTEMS ROD PATTERN CONTROL Report Date: 05/06/09 Page Pagel1 of of .8 Report Date: 05/06/09
SSES MANUAL Manual Name: TSB1 Manual
Title:
TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL TEXT 3.1.7 3 04/23/2008
Title:
REACTIVITY CONTROL SYSTEMS STANDBY LIQUID CONTROL (SLC) SYSTEM TEXT 3.1.8 3 05/06/2009
Title:
REACTIVITY CONTROL SYSTEMS SCRAM DISCHARGE VOLUME (SDV) VENT AND DRAIN VALVES TEXT 3.2.1 2 04/23/2008
Title:
POWER DISTRIBUTION LIMITS AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)
TEXT 3.2.2 3 05/06/2009
Title:
POWER DISTRIBUTION LIMITS MINIMUM CRITICAL POWER RATIO (MCPR)
TEXT 3.2.3 2 04/23/2008
Title:
POWER DISTRIBUTION LIMITS LINEAR HEAT GENERATION RATE (LHGR)
TEXT 3.3.1.1 4 04/23/2008
Title:
INSTRUMENTATION REACTOR PROTECTION SYSTEM (RPS) INSTRUMENTATION TEXT 3.3.1.2 2 01/19/2009
Title:
INSTRUMENTATION SOURCE RANGE MONITOR (SRM) INSTRUMENTATION TEXT 3.3.2.1 3 04/23/2008
Title:
INSTRUMENTATION CONTROL ROD BLOCK INSTRUMENTATION TEXT 3.3.2.2 1 04/23/2008
Title:
INSTRUMENTATION FEEDWATER MAIN TURBINE HIGH WATER LEVEL TRIP INSTRUMENTATION TEXT 3.3.3.1 8 10/27/2008
Title:
INSTRUMENTATION POST ACCIDENT MONITORING (PAM) INSTRUMENTATION TEXT 3.3.3.2 1 04/18/2005
Title:
INSTRUMENTATION REMOTE SHUTDOWN SYSTEM TEXT 3.3.4.1 1 04/23/2008
Title:
INSTRUMENTATION END OF CYCLE RECIRCULATION PUMP TRIP (EOC-RPT) INSTRUMENTATIOW Report Date: 05/06/09 Page22 Page of of .8 Report Date: 05/06/09
SSES MANUAL Manual Name: TSB1 Manual
Title:
TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL TEXT 3.3.4.2 0 11/15/2002
Title:
INSTRUMENTATION ANTICIPATED TRANSIENT WITHOUT SCRAM RECIRCULATION PUMP TRIP (ATWS-RPT) INSTRUMENTATION TEXT 3.3.5.1 2 07/06/2005
Title:
INSTRUMENTATION EMERGENCY CORE COOLING SYSTEM (ECCS) INSTRUMENTATION TEXT 3.3.5.2 0 11/15/2002
Title:
INSTRUMENTATION REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM INSTRUMENTATION TEXT 3.3.6.1 4 04/23/2008
Title:
INSTRUMENTATION PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION TEXT 3.3.6.2 3 10/27/2008
Title:
INSTRUMENTATION SECONDARY CONTAINMENT ISOLATION INSTRUMENTATION TEXT 3.3.7.1 2 10/27/2008
Title:
INSTRUMENTATION CONTROL ROOM EMERGENCY OUTSIDE AIR SUPPLY (CREOAS) SYSTEM INSTRUMENTATION TEXT 3.3.8.1 2 12/17/2007
Title:
INSTRUMENTATION LOSS OF POWER (LOP) INSTRUMENTATION TEXT 3.3.8.2 0 11/15/2002
Title:
INSTRUMENTATION REACTOR PROTECTION SYSTEM (RPS) ELECTRIC POWER MONITORING TEXT 3.4.1 3 04/12/2006
Title:
REACTOR COOLANT SYSTEM (RCS) RECIRCULATION LOOPS OPERATING TEXT 3.4.2 1 04/23/2008
Title:
REACTOR COOLANT SYSTEM (RCS) JET PUMPS TEXT 3.4.3 2 04/23/2008
Title:
REACTOR COOLANT SYSTEM RCS SAFETY RELIEF VALVES S/RVS TEXT 3.4.4 0 11/15/2002
Title:
REACTOR COOLANT SYSTEM (RCS) RCS OPERATIONAL LEAKAGE Report Date: 05/06/09 Page33 Page of8 8 of Report Date: 05/06/09
SSES MANT-MI.,
Manual Name: TSB1 Manual
Title:
TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL TEXT 3.4.5 1 01/16/2006
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 2 10/04/2007
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 11/15/2002 REACTOR COOLANT SYSTEM (RCS) RESIDUAL HEAT REMOVAL (RHR) SHUTDOWN COOLING SYSTEM 0
Title:
- COLD SHUTDOWN TEXT 3.4.10 3 04/23/2008
Title:
REACTOR COOLANT SYSTEM (RCS) RCS PRESSURE AND TEMPERATURE (P/T) LIMITS TEXT 3.4.11 0 11/15/2002
Title:
REACTOR COOLANT SYSTEM (RCS) REACTOR STEAM DOME PRESSURE TEXT 3.5.1 2 01/16/2006
Title:
EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC)
SYSTEM ECCS - OPERATING TEXT 3.5.2 0 11/15/2002
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 3 04/23/2008
Title:
CONTAINMENT SYSTEMS PRIMARY CONTAINMENT TEXT 3.6.1.2 1 04/23/2008
Title:
CONTAINMENT SYSTEMS PRIMARY CONTAINMENT AIR LOCK Report Date: 05/06/09 Page44 Page of of .8 Report Date: 05/06/09
SSES MANUAL Manual Name: TSB1 Manual
Title:
TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL TEXT 3.6.1.3 8 04/23/2008
Title:
CONTAINMENT SYSTEMS PRIMARY CONTAINMENT ISOLATION VALVES (PCIVS)
LDCN 3092 TEXT 3.6.1.4 1 04/23/2008
Title:
CONTAINMENT SYSTEMS CONTAINMENT PRESSURE TEXT 3.6.1.5 1 10/05/2005
Title:
CONTAINMENT SYSTEMS DRYWELL AIR TEMPERATURE TEXT 3.6.1.6 0 11/15/2002
Title:
CONTAINMENT SYSTEMS SUPPRESSION CHAMBER-TO-DRYWELL VACUUM BREAKERS TEXT 3.6.2.1 2 04/23/2008
Title:
CONTAINMENT SYSTEMS SUPPRESSION POOL AVERAGE TEMPERATURE TEXT 3.6.2.2 0 11/15/2002
Title:
CONTAINMENT SYSTEMS SUPPRESSION POOL WATER LEVEL TEXT 3.6.2.3 1 01/16/2006
Title:
CONTAINMENT SYSTEMS RESIDUAL HEAT REMOVAL (RHR) SUPPRESSION POOL COOLING TEXT 3.6.2.4 0 11/15/2002
Title:
CONTAINMENT SYSTEMS RESIDUAL HEAT REMOVAL -(RHR) SUPPRESSION POOL SPRAY TEXT 3.6.3.1 2 06/13/2006
Title:
CONTAINMENT SYSTEMS PRIMARY CONTAINMENT HYDROGEN RECOMBINERS TEXT 3.6.3.2 1 04/18/2005
Title:
CONTAINMENT SYSTEMS DRYWELL AIR FLOW SYSTEM TEXT 3.6.3.3 0 11/15/2002
Title:
CONTAINMENT SYSTEMS PRIMARY CONTAINMENT OXYGEN CONCENTRATION TEXT 3.6.4.1 7 10/04/2007
Title:
CONTAINMENT SYSTEMS SECONDARY CONTAINMENT Report Date: 05/06/09 Page Pages5 of ~
of8 Report Date: 05/06/09
SSES MANUAL Manual Name: TSB1 Manual
Title:
TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL TEXT 3.6.4.2 2 01/03/2005
Title:
CONTAINMENT SYSTEMS SECONDARY CONTAINMENT ISOLATION VALVES (SCIVS)
TEXT 3.6.4.3 4 09/21/2006
Title:
CONTAINMENT SYSTEMS STANDBY GAS TREATMENT (SGT) SYSTEM TEXT 3. 7.1 3 05/06/2009
Title:
PLANT SYSTEMS RESIDUAL HEAT REMOVAL SERVICE WATER (RHRSW) SYSTEM AND THE ULTIMA%TE HEAT SINK (UHS)
TEXT 3.7.2 2 02/11/2009
Title:
PLANT SYSTEMS EMERGENCY SERVICE WATER (ESW) SYSTEM TEXT 3.7.3 0 11/15/2002
Title:
PLANT SYSTEMS CONTROL ROOM EMERGENCY OUTSIDE AIR SUPPLY (CREOAS) SYSTEM TEXT 3.7.4 0 11/15/2002
Title:
PLANT SYSTEMS CONTROL ROOM FLOOR COOLING SYSTEM TEXT 3. 7.5 1 10/04/2007
Title:
PLANT SYSTEMS MAIN CONDENSER OFFGAS TEXT 3ý.7.6 2 04/23/2008
Title:
PLANT SYSTEMS MAIN TURBINE BYPASS SYSTEM TEXT 3.7.7 1 10/04/2007
Title:
PLANT SYSTEMS SPENT FUEL STORAGE POOL WATER LEVEL TEXT 3.7.8 0 04/23/2008
Title:
PLANT SYSTEMS TEXT 3.8.1 6 05/06/2009
Title:
ELECTRICAL POWER SYSTEMS AC SOURCES - OPERATING TEXT 3.8.2 0 11/15/2002
Title:
ELECTRICAL POWER SYSTEMS AC SOURCES - SHUTDOWN Report Date: 05/06/09 Page Page66 of .8 Report Date: 05/06/09
SSES MA1NJTJAI Manual Name: TSB1 Manual
Title:
TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL TEXT 3.8.3 1 04/23/2008
Title:
ELECTRICAL POWER SYSTEMS DIESEL FUEL OIL, LUBE OIL, AND STARTING AIR TEXT 3.8.4 3 01/19/2009
Title:
ELECTRICAL POWER SYSTEMS DC SOURCES - OPERATING TEXT 3.8.5 1 12/14/2006
Title:
ELECTRICAL POWER SYSTEMS DC SOURCES - SHUTDOWN TEXT 3.8.6 1 12/14/2006
Title:
ELECTRICAL POWER SYSTEMS BATTERY CELL PARAMETERS TEXT 3.8.7 1. 10/05/2005
Title:
ELECTRICAL POWER SYSTEMS DISTRIBUTION SYSTEMS - OPERATING TEXT 3.8.8 0 11/15/2002
Title:
ELECTRICAL POWER SYSTEMS DISTRIBUTION SYSTEMS - SHUTDOWN TEXT 3.9.1 0 11/15/2002
Title:
REFUELING OPERATIONS REFUELING EQUIPMENT INTERLOCKS TEXT 3.9.2 0 11/15/2002
Title:
REFUELING OPERATIONS REFUEL POSITION ONE-ROD-OUT INTERLOCK TEXT 3.9.3 0 11/15/2002
Title:
REFUELING OPERATIONS .CONTROL ROD POSITION TEXT 3.9.4 0 11/15/2002
Title:
REFUELING OPERATIONS CONTROL ROD POSITION INDICATION TEXT 3.9.5 0 11/15/2002
Title:
REFUELING OPERATIONS CONTROL ROD OPERABILITY - REFUELING TEXT 3.9.6 1 10/04/2007
Title:
REFUELING OPERATIONS REACTOR PRESSURE VESSEL (RPV) WATER LEVEL Report Date: 05/06/09 Page77 Page of of 8
.8 Report Date: 05/06/09
SSES MANUAL Manual Name: TSB1 Manual
Title:
TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL TEXT 3.9.7 0 11/15/2002
Title:
REFUELING OPERATIONS RESIDUAL HEAT REMOVAL (RHR) - HIGH WATER LEVEL TEXT 3.9.8 0 11/15/2002
Title:
REFUELING OPERATIONS RESIDUAL HEAT REMOVAL (RHR) - LOW WATER LEVEL TEXT 3.10.1 1 01/23/2008
Title:
SPECIAL OPERATIONS INSERVICE.LEAK AND HYDROSTATIC-TESTING OPERATION TEXT 3.10.2 0 11/15/2002
Title:
SPECIAL OPERATIONS REACTOR MODE SWITCH INTERLOCK TESTING TEXT 3.10.3 0 11/15/2002
Title:
SPECIAL OPERATIONS SINGLE CONTROL ROD WITHDRAWAL - HOT SHUTDOWN TEXT 3.10.4
Title:
0 11/15/2002 SPECIAL OPERATIONS SINGLE CONTROL ROD WITHDRAWAL - COLD SHUTDOWN 0
TEXT 3.10.5 0 11/15/2002
Title:
SPECIAL OPERATIONS SINGLE CONTROL ROD DRIVE (CRD) REMOVAL - REFUELING TEXT 3.10.6 0 11/15/2002
Title:
SPECIAL OPERATIONS MULTIPLE CONTROL ROD WITHDRAWAL - REFUELING TEXT 3.10.7 1 04/18/2006
Title:
SPECIAL OPERATIONS CONTROL ROD TESTING - OPERATING TEXT 3.10.8 1 04/12/2006
Title:
SPECIAL OPERATIONS SHUTDOWN MARGIN (SDM) TEST - REFUELING Report Date: 05/06/09 Page Page88 of of 8
.~ Report Date: 05/06/09
SUSQUEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)
Section Title Revision TOC Table of Contents 16 B 2.0 SAFETY LIMITS BASES Page B 2.0-1 0 Page TS / B 2.0-2 3 Page TS / B 2.0-3 5 Page TS / B 2.0-4 3 Page TS / B 2.0-5 5 Page TS / B 2.0-6 1 Pages TS / B 2.0-7 through TS / B 2.0-9 1 B 3.0 LCO AND SR APPLICABILITY BASES Page TS / B 3.0-1 1 Pages TS / B 3.0-2 through TS / B 3.0-4 0 Pages TS / B 3.0-5 through TS / B 3.0-7 1 Pages TS / B 3.0-8 through TS / B 3.0-9 2 Page TS / B 3.0-10 1 Page TS / B 3.0-11 2 Page TS / B 3.0-1 la 0 Page TS / B 3.0-12 1 Pages TS / B 3.0-13 through TS / B 3.0-15 2 Pages TS / B 3.0-16 and TS / B 3.0-17 0 B 3.1 REACTIVITY CONTROL BASES Pages B 3.1-1 through B 3.1-4 0 Page TS / B 3.1-5 1 Pages TS / B 3.1-6 and TS / B 3.1-7 2 Pages B 3.1-8 through B 3.1-13 0 Page TS / B 3.1-14 1 Page B 3.1-15 0 Page TS / B 3.1-16 1 Pages B 3.1-17 through B 3.1-19 0 Pages TS / B 3.1-20 and TS / B 3.1-21 1 Page TS / B 3.1-22 0 Page TS / B 3.1-23 1 Page TS / B 3.1-24 0 Pages TS / B 3.1-25 through TS / B 3.1-27 1 Page TS / B 3.1-28 2 Page TS / B 3.1-29 1 Pages B 3.1-30 through B 3.1-33 0 Pages TS / B 3.3-34 through TS / B 3.3-36 1 Pages TS / B 3.1-37 and TS / B 3.1-38 2 Page TS / B 3.1-39 and TS / B 3.1-40 2 Page TS / B 3.1.40a 0 Pages TS / B 3.1.41 and TS / B 3.1-42 2 Revision 92 SUSQUEHANNA - UNIT SUSQUEHANNA -
UNIT I1 TS B LOES-I TS // B LOES-1 Revision 92
SUSQUEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)
Section Title Revision Page TS / B 3.1.43 1 Page TS / 8 3.1-44 0 Page TS / B 3.1-45 3 Pages TS / B 3.1-46 through TS / B 3.1-49 1 Page TS / B 3.1-50 0 Page TS / B 3.1-51 3 B 3.2 POWER DISTRIBUTION LIMITS BASES Page TS / B 3.2-1 2 Pages TS / B 3.2-2 and TS / B 3.2-3 3 Pages TS / B 3.2-4 and TS / B 3.2-5 2 Page TS / B 3.2-6 3 Page B 3.2-7 1 Pages TS / B 3.2-8 and TS / B 3.2-9 3 Page TS / B 3.2.10 2 Page TS / B 3.2-11 3 Page TS / B 3.2-12 1 Page TS / B 3.2-13 2 B 3.3 INSTRUMENTATION Pages TS / B 3.3-1 through TS / B 3.3-4 1 Page TS / 8 3.3-5 2 Page TS / B 3.3-6 1 Page TS / B 3.3-7 3 Page TS / B 3.3-7a 1 Page TS / B 3.3-8 4 Pages TS / B 3.3-9 through TS / 83.3-12 3 Pages TS / B 3.3-12a 1 Pages TS / B 3.3-12b and TS / B 3.3-12c 0 Page TS / B 3.3-13 1 Page TS / B 3.3-14 3 Pages TS / B 3.3-15 and TS / B 3.3-16 1 Pages TS / B 3.3-17 and TS / B 3.3-18 4 Page TS / B 3.3-19 1 Pages TS / B 3.3-20 through TS / B 3.3-22 2 Page TS / B 3.3-22a 0 Pages TS / B 3.3-23 and TS / B 3.3-24 2 Pages TS / B 3.3-24a and TS / B 3.3-24b 0 Page TS / B 3.3-25 3 Page TS / B 3.3-26 2 Page TS / B 3.3-27 1 Pages TS / B 3.3-28 through TS / B 3.3-30 3 Page TS / B 3.3-30a 0 TS/BLOES-2 Revision 92 SUSQUEHANNA - UNIT SUSQUEHANNA -
UNIT 11 TS / B LOES-2 Revision 92
SUSQUEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)
Section Title Revision Page TS / B 3.3-31 4 Page TS / B 3.3-32 5 Pages TS / B 3.3-32a 0 Page TS / B 3.3-32b 1 Page TS / B 3.3-33 5 Page TS / B 3.3-33a 0 Page TS / B 3.3-34 1 Pages TS / B 3.3-35 and TS / B 3.3-36 2 Pages TS / B 3.3-37 and TS / B 3.3-38 1 Page TS / B 3.3-39 2 Pages TS / B 3.3-40 through TS / B 3.3-43 1 Page TS / B 3.3-44 4 Pages TS / B 3.3-44a and TS / B 3.3-44b 0 Page TS / B 3.3-45 3 Pages TS / B 3.3-45a and TS / B 3.3-45b 0 Page TS / B 3.3-46 3 Pages TS / B 3.3-47 2 Pages TS / B 3.3-48 through TS / B 3.3-51 3 Pages TS / B 3.3-52 and TS / B 3.3-53 2 Page TS / B 3-3-53a 0 Page TS / B 3.3-54 4 Page B 3.3-55 1 Page B 3.3-56 0 Page B 3.3-57 1 Page B 3.3-58 0 Page B 3.3-59 1 Pages B 3.3-60 through B 3.3-63 0 Pages TS / B 3.3-64 and TS / B 3.3-65 2 Page TS / B 3.3-66 4 Page TS / B 3.3-67 3 Page TS / B 3.3-68 4 Page TS / B 3.3-69 5 Pages TS / B 3.3-70 4 Page TS / B 3.3-71 3 Pages TS / B 3.3-72 and TS / B 3.3-73 2 Page TS / B 3.3-74 3 Page TS / B 3.3-75 2 Page TS / B 3.3-75a 6 Page TS / B 3.3-75b 7 Page TS / B 3.3-75c 5 Pages B 3.3-76 through 3.3-77 0 Page TS / B 3.3-78 1 Pages B 3.3-79 through B 3.3-81 0 Page B 3.3-82 1 Revision 92 SUSQUEHANNA - UNIT SUSQUEHANNA -
UNIT 11 TS B LOES-3 TS I/ B LOES-3 Revision 92
SUSQUEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)
Section Title Revision Page B 3.3-83 0 Pages B 3.3-84 and B 3.3-85 1 Page B 3.3-86 0 Page B 3.3-87 1 Page B 3.3-88 0 Page B 3.3-89 1 Page TS / B 3.3-90 1 Page B 3.3-91 0 Pages TS / B 3.3-92 through TS / B 3.3-100 1 Pages B 3.3-101 through B 3.3-103 0 Page TS / B 3.3-104 1 Pages B 3.3-105 and B 3.3-106 0 Page TS / B 3.3-107 1 Page B 3.3-108 0 Page TS / B 3.3-109 1 Pages B 3.3-110 and B 3.3-111 0 Pages TS / B 3.3-112 and TS / B 3.3-112a 1 Pages TS / B 3.3-113 through TS / B 3.3-115 1 Page TS / B 3.3-116 2 Page TS / B 3.3-117 1 Pages B 3.3-118 through B 3.3-122 0 Pages TS / B 3.3-123 and TS / B 3.3-124 1 Page TS / B 3.3-124a 0 Page B 3.3-125 0 Pages TS / B 3.3-126 and TS / B 3.3-127 1 Pages B 3.3-128 through B 3.3-130 0 Page TS / B 3.3-131 1 Pages B 3.3-132 through B 3.3-137 0 Page TS / B 3.3-138 1 Pages B 3.3-139 through B 3.3-149 0 Pages TS / B 3.3-150 and TS / B 3.3-151 1 Pages TS / B 3.3-152 through TS / B 3.3-154 2 Page TS / B 3.3-155 1 Pages TS I B 3.3-156 through TS / B 3.3-158 2 Pages TS / B 3.3-159 through TS / B 3.3-162 1 Page TS / B 3.3-163 2 Pages TS / B 3.3-164 and TS / B 3.3-165 1 Pages TS / B 3.3-166 and TS / B 3.3-167 2 Pages TS / B 3.3-168 and TS / B 3.3-169 1 Page TS / B 3.3-170 2 Pages TS / B 3.3-171 through TS / B 3.3-177 1 Pages TS / B 3.3-178 through TS / B 3.3-179a 2 Pages TS / B 3.3-179b and TS / B 3.3-179c 0 Page TS / B 3.3-180 1 TSIBLOES-4 Revision 92 SUSQUEHANNA SUSQUEHANNA -UNIT- UNIT 11 TS / B LOES-4 Revision 92
SUSQUEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)
Section Title Revision Page TS / B 3.3-181 3 Page TS / B 3.3-182 1 Page TS / B 3.3-183 2 Page TS / B 3.3-184 1 Page TS / B 3.3-185 3 Page TS / B 3.3-186 1 Pages TS / B 3.3-187 and TS / B 3.3-188 2 Pages TS / B 3.3-189 through TS /!B3.3-191 1 Page TS / B 3.3-192 0 Page TS / B 3.3-193 1 Pages TS / B 3.3-194 and TS / B 3.3-195 0 Page TS / B 3.3-196 2 Pages TS / B 3.3-197 through TS / B 3.3-204 0 Page TS / B 3.3-205 1 Pages B 3.3-206 through B 3.3-209 0 Page TS / B 3.3-210 1 Pages B 3.3-211 through B 3.3-219 0 B 3.4 REACTOR COOLANT SYSTEM BASES Pages B 3.4-1 and B 3.4-2 0 Pages TS / B 3.4-3 and Page TS / B 3.4-4 4 Pages TS / B 3.4-5 through TS / B 3.4-9 2 Pages B 3.4-10 through B 3.4-12 0 Page B 3.4-13 1 Page B 3.4-14 0 Page TS / B 3.4-15 2 Pages TS / B 3.4-16 and TS / B 3.4-17 3 Page TS / B 3.4-18 2 Pages B 3.4-19 through B 3.4-27 0 Pages TS / B 3.4-28 and TS / B 3.4-29 1 Pages B 3.4-30 and B 3.4-31 0 Page TS / B 3.4-32 1 Pages B 3.4-33 and B 3.4-34 0 Pages TS / B 3.4-35 and TS / B 3.4-36 1 Page TS / B 3.4-37 2 Page TS / B 3.4-38 1 Pages B 3.4-39 and B 3.4-40 0 Page TS / B 3.4-41 1 Pages B 3.4-42 through B 3.4-48 0 Page TS / B 3.4-49 3 Page TS / B 3.4-50 1 Page TS / B 3.4-51 3 Page TS / B 3.4-52 2 Page TS / B 3.4-53 1 Revision 92 SUSQUEHANNA - UNIT SUSQUEHANNA - UNIT 11 TS B LOES-5 TS I/ B LOES-5 Revision 92
SUSQUEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)
Section Title Revision Pages TS / B 3.4-54 through TS / B 3.4-56 2 Page TS / B 3.4-57 3 Pages TS / B 3.4-58 through TS / B 3.4-60 1 B 3.5 ECCS AND RCIC BASES Pages B 3.5-1 and B 3.5-2 0 Page TS / B 3.5-3 2 Page TS / B 3.5-4 1 Page TS / B 3.5-5 2 Page TS / B 3.5-6 1 Pages B 3.5-7 through B 3.5-10 0 Page TS / B 3.5-11 1 Page TS / B 3.5-12 0 Page TS / B 3.5-13 1 Pages TS / B 3.5-14 and TS / B 3.5-15 0 Pages TS / B 3.5-16 through TS / B 3.5-18 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 B 3.5-28 through B 3.5-31 0 B 3.6 CONTAINMENT SYSTEMS BASES Page TS / B 3.6-1 2 Page TS / B 3.6-1a 3 Page TS / B 3.6-2 4 Page TS / B 3.6-3 3 Page TS / B 3.6-4 4 Pages TS / B 3.6-5 and TS / B 3.6-6 3.
Pages TS / B 3.6-6a and TS / B 3.6-6b 2 Page TS / B 3.6-6c 0 Pages B 3.6-7 0 Page B 3.6-8 1 Pages B 3.6-9 through B 3.6-14 0 Page TS / B 3.6-15 2 Page TS / B 3.6-15a 0 Page TS / B 3.6-15b 2 Pages TS / B 3.6-16 and TS / B 3.6-17 1 Page TS / B 3.6-17a 0 Pages TS / B 3.6-18 and TS / B 3.6-19 0 Page TS / B 3.6-20 1 Page TS / B 3.6-21 2 Page TS / B 3.6-22 1 Page TS / B 3.6-22a 0 Page TS / B 3.6-23 1 LOES-6 Revision 92 SUS UEHANNA - UNIT SUSQUEHANNA -
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Section Title Revision Pages TS / B 3.6-24 and TS / B 3.6-25 0 Pages TS / B 3.6-26 and TS / B 3.6-27 2 Page TS / B 3.6-28 7 Page TS / B 3.6-29 2 Page TS / B 3.6-30 1 Page TS / B 3.6-31 3 Page TS / B 3.6-32 0 Page TS / B 3.6-33 1 Pages TS / B 3.6-34 and TS / B 3.6-35 0 Page TS / B 3.6-36 1 Page TS / B 3.6-37 0 Page TS / B 3.6-38 3 Page TS / B 3.6-39 2 Page TS / B 3.6-40 6 Page B 3.6-41 1 Pages B 3.6-42 and B 3.6-43 3 Pages TS / B 3.6-44 and TS / B 3.6-45 1 Page TS / B 3.6-46 2 Pages TS / B 3.6-47 through TS / B 3.6-51 1 Page TS / B 3.6-52 2 Pages TS / B 3.6-53 through TS / B 3.6-56 0 Page TS / B 3.6-57 1 Page TS / 3.6-58 2 Pages B 3.6-59 through B 3.6-63 0 Pages TS / B 3.6-64 and TS / B 3.6-65 1 Pages B 3.6-66 through B 3.6-69 0 Pages TS / B 3.6-70 through TS / B 3.6-72 1 Page TS / B 3.6-73 2 Pages TS / B 3.6-74 and TS / B 3.6-75 1 Pages B 3.6-76 and B 3.6-77 0 Page TS / B 3.6-78 1 Pages B,3.6-79 through B 3.3.6-83 0 Page TS / B 3.6-84 3 Page TS / B 3.6-85 2 Page TS / B 3.6-86 4 Pages TS / B 3.6-87 through TS*/ B 3.6-88a 2 Page TS / B 3.6-89 4 Page TS / B 3.6-90 2 Page TS / B 3.6-91 3 Pages TS / B 3.6-92 through TS / B 3.6-96 1 Page TS / B 3.6-97 2 Pages TS / B 3.6-98 and TS / B 3.6-99 1 Page TS / B 3.6-100 2 Pages TS / B 3.6-101 and TS / B 3.6-102 1 Revision 92 SUSQUEHANNA - UNIT SUSQUEHANNA - UNIT 1I TS B LOES-7 TS I/ B LOES-7 Revision 92
SUSQUEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)
Section Title Revision Pages TS / B 3.6-103 and TS / B 3.6-104 2 Page TS / B 3.6-105 3 Page TS / B 3.6-106 2 Page TS / B 3.6-107 3 B 3.7 PLANT SYSTEMS BASES Pages TS / B 3.7-1 3 Page TS / B 3.7-2 4 Pages TS / B 3.7-3 through TS / B 3.7-5 3 Page TS / B 3.7-5a 0 Pages TS / B 3.7-6 and TS / B 3.7-6a 2 Page TS / B 3.7-6b 1 Page TS / B 3.7-6c 2 Page TS / B 3.7-7 3 Page TS / B 3.7-8 2 Pages TS / B 3.7-9 through TS / B 3.7-13 1 Pages TS / B 3.7-14 through TS / B 3.7-18 2 Page TS / B 3.7-18a 0 Pages TS / B 3.7-19 through TS / B 3.7-23 1 Page TS / B 3.7-24 1 Pages TS / B 3.7-25 and TS / B 3.7-26 0 Pages TS / B 3.7-27 through TS / B 3.7-29 5 Page TS / B 3.7-30 2 Page TS / B 3.7-31 1 Page TS / B 3.7-32 0 Page TS / B 3.7-33 1 Pages TS / B 3.7-34 through TS / B 3.7-37 0 B 3.8 ELECTRICAL POWER SYSTEMS BASES Page TS / B 3.8-1 3 Pages TS / B 3.8-2 and TS / B 3.8-3 2 Page TS / B 3.8-4 3 Pages TS / B 3.8-4a and TS / B 3.8-4b 0 Page TS / B 3.8-5 5 Page TS / B 3.8-6 3 Pages TS / B 3.8-7 through TS/B 3.8-8 2 Page TS / B 3.8-9 4 Page TS / B 3.8-10 3 Pages TS / B 3.8-11 and TS / B 3.8-17 2 Page TS / B 3.8-18 3 Pages TS B 3.8-19 through TS / B 3.8-21 2 Pages TS / B 3.8-22 and TS / B 3.8-23 3 Pages TS / B 3.8-24 through TS / B 3.8-37 2 Pages B 3.8-38 through B 3.8-44 0 Revision 92 SUSQUEHANNA - UNIT
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Section Title Revision Page TS / B 3.8-45 1 Pages TS / B 3.8-46 through B 3.8-48 0 Page TS / B 3.8-49 1 Pages B 3.8-50 through B 3.8-53 0 Pages TS / B 3.8-54 through TS / B 3.8-57 2 Pages TS / B 3.8-58 through TS / B 3.8-61 3 Pages TS / B 3.8-62 and TS / B 3.8-63 5 Page TS / B 3.8-64 4 Page TS / B 3.8-65 5 Pages TS / B 3.8-66 through TS / B 3.8-77 1 Pages TS / B 3.8-77A through TS I B 3.8-77C 0 Pages B 3.8-78 through B 3.8-80 0 Page TS / B 3.8-81 1-Pages B 3.8-82 through B 3.8-90 0 B 3.9 REFUELING OPERATIONS BASES Pages TS / B 3.9-1 and TS / B 3.9-la 1 Pages TS / B 3.9-2 through TS / B 3.9-4 1 Pages B 3.9-5 through B 3.9-18 0 Pages TS / B 3.9-19 through TS / B 3.9-21 1 Pages B 3.9-22 through B 3.9-30 0 B 3.10 SPECIAL OPERATIONS BASES Page TS / B 3.10-1 2 Pages TS / B 3.10-2 through TS / B 3.10-5 1 Pages B 3.10-6 through B 3.10-31 0 Page TS / B 3.10-32 2 Page B 3.10-33 0 Page TS / B 3.10-34 1 Pages B 3.10-35 and B 3.10-36 0 Page TS / B 3.10-37 1 Page TS / B 3.10-38 2 TSB1 Text LOES.doc 04/20/2009 Revision 92 SUSQUEHANNA - UNIT SUSQUEHANNA -
UNIT 11 TS B LOES-9 TS I/ B LOES-9 Revision 92
PPL Rev. 5 Reactor Core SLs B 2.1.1 B 2.0 SAFETY LIMITS (SLs)
B 2.1.1 Reactor Core SLs BASES BACKGROUND GDC 10 (Ref. 1) requires, and SLs ensure, that specified acceptable fuel design limits are not exceeded during steady state operation, normal operational transients, and anticipated operational occurrences (AOOs).
The fuel cladding integrity SL is set such that no significant fuel damage is calculated to occur if the limit is not violated. Because fuel damage is not directly observable, a stepback approach is used to establish an SL, such that the MCPR is not less than the limit specified in Specification 2.1.1.2 for Siemens Power Corporation fuel. MCPR greater than the specified limit represents a conservative margin relative to the conditions required to maintain fuel cladding integrity.
The fuel cladding is one of the physical barriers that separate the radioactive materials from the environs. The integrity of this cladding barrier is related to its relative freedom from perforations or cracking.
Although some corrosion or use related cracking may occur during the life of the cladding, fission product migration from this source is incrementally cumulative and continuously measurable. Fuel cladding perforations, however, can result from thermal stresses, which occur from reactor operation significantly above design conditions.
While fission product migration from cladding perforation is just as measurable as that from use related cracking, the thermally caused cladding perforations signal a threshold beyond which still greater thermal stresses may cause gross, rather than incremental, cladding deterioration.
Therefore, the fuel cladding SL is defined with a margin to the conditions that would produce onset of transition boiling (i.e., MCPR = 1.00). These conditions represent a significant departure from the condition intended by design for planned operation. The MCPR fuel cladding integrity SL ensures that during normal operation and during AOOs, at least 99.9% of the fuel rods in the core do not experience transition boiling.
(continued)
SUSQUEHANNA - UNIT 1 TS / B] 2.0-1 Revision 0
PPL Rev. 5 Reactor Core SLs B 2.1.1 BASES BACKGROUND Operation above the boundary of the nucleate boiling regime could (continued) result in excessive cladding temperature because of the onset of transition boiling and the resultant sharp reduction in heat transfer coefficient. Inside the steam film, high cladding temperatures are reached, and a cladding water (zirconium water) reaction may take place. This chemical reaction results in oxidation of the fuel cladding to a structurally weaker form. This weaker form may lose its integrity, resulting in an uncontrolled release of activity to the reactor coolant.
APPLICABLE The fuel cladding must not sustain damage as a result of normal SAFETY ANALYSES operation and AOOs. The reactor core SLs are established to preclude violation of the fuel design criterion that an MCPR limit is to be established, such that at least 99.9% of the fuel rods in the core would not be expected to experience the onset of transition boiling.
The Reactor Protection System setpoints (LCO 3.3.1.1, "Reactor Protection System (RPS) Instrumentation"), in combination with the other LCOs, are designed to prevent any anticipated combination of transient conditions for Reactor Coolant System water level, pressure, and THERMAL POWER level that would result in reaching the MCPR limit.
2.1.1.1 Fuel Cladding Integrity The use of the SPCB (Reference 4) correlation is valid for critical power calculations at pressures > 571.4 psia and bundle mass fluxes
> 0.087 x 106 lb/hr-ft2. For operation at low pressures or low flows, the fuel cladding integrity SL is established by a limiting condition on core THERMAL POWER, with the following basis:
Provided that the water level in the vessel downcomer is maintained above the top of the active fuel, natural circulation is sufficient to ensure a minimum bundle flow for all fuel assemblies that have a relatively high power and potentially can approach a critical heat flux condition.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 2.0-2 Revision 3
PPL Rev. 5 Reactor Core SLs B 2.1.1 BASES APPLICABLE 2.1.1.1 Fuel Cladding Integrity (continued)
SAFETY ANALYSES For the FANP ATRIUM-10 design, the minimum bundle flow is > 28 x 103 lb/hr. For the ATRIUM-10 fuel design, the coolant minimum bundle flow and maximum area are such that the mass flux is always > .25 x 106 lb/hr-ft2. Full scale critical power test data taken from various SPC and GE fuel designs at pressures from 14.7 psia to 1400 psia indicate the fuel assembly critical power at 0.25 x 106 lb/hr-ft2 is approximately 3.35 MWt. At 23% RTP, a bundle power of approximately 3.35 MWt corresponds to a bundle radial peaking factor of approximately 2.8, which is significantly higher than the expected peaking factor. Thus, a THERMAL POWER limit of 23% RTP for reactor pressures < 785 psig is conservative and for conditions of lesser power would remain conservative.
2.1.1.2 MCPR The MCPR SL ensures sufficient conservatism in the operating MCPR limit that, in the event of an AOO from the limiting condition of operation, at least 99.9% of the fuel rods in the core would be expected to avoid boiling transition. The margin between calculated boiling transition (i.e., MCPR = 1.00) and the MCPR SL is based on a detailed statistical procedure that considers the uncertainties in monitoring the core operating state. One specific uncertainty included in the SL is the uncertainty in the critical power correlation. References 2, 4, and 5 describe the methodology used in determining the MCPR SL.
The SPCB critical power correlation is based on a significant body of practical test data. As long as the core pressure and flow are within the range of validity of the correlations (refer to Section B.2.1.1.1), the assumed reactor conditions used in defining the SL introduce conservatism into the limit because bounding high radial power factors and bounding flat local peaking distributions are used to estimate the number of rods in boiling transition. These conservatisms and the inherent accuracy of the SPCB correlation provide a reasonable degree of assurance that during sustained operation at the MCPR SL there would be no transition boiling in the core.
(continued)
SUSQUEHANNA- UNIT 1 TS / B 2.0-3 Revision 5
PPL Rev. 5 Reactor Core SLs B 21.1 BASES APPLICABLE 2.1.1.2 MCPR (continued)
SAFETY ANALYSES If boiling transition were to occur, there is reason to believe that the integrity of the fuel would not be compromised.
Significant test data accumulated by the NRC and private organizations indicate that the use of a boiling transition limitation to protect against cladding failure is a very conservative approach. Much of the data indicate that BWR fuel can survive for an extended period of time in an environment of boiling transition.
SPC Atrium -10 fuel is monitored using the SPCB Critical Power Correlation. The effects of channel bow on MCPR are explicitly included in the calculation of the MCPR SL. Explicit treatment of channel bow in the MCPR SL addresses the concerns of NRC Bulletin No. 90-02 entitled "Loss of Thermal Margin Caused by Channel Box Bow."
Monitoring required for compliance with the MCPR SL is specified in LCO 3.2.2, Minimum Critical Power Ratio.
2.1.1.3 Reactor Vessel Water Level During MODES 1 and 2 the reactor vessel water level is required to be above the top of the active fuel to provide core cooling capability.
With fuel in the reactor vessel during periods when the reactor is shut down, consideration must be given to water level requirements due to the effect of decay heat. If the water level should drop below the top of the active irradiated fuel during this period, the ability to remove decay heat is reduced. This reduction in cooling capability could lead to elevated cladding temperatures and clad perforation in the event that the water level becomes < 2/3 of the core height.
The reactor vessel water level SL has been established at the top of the active irradiated fuel to provide a point that can be (continued)
SUSQUEHANNA - UNIT I TS / B 2.0-4 Revision 3
PPL Rev. 5 Reactor Core SLs B 2.1.1 BASES APPLICABLE 2.1.1.3 Reactor Vessel Water Level (continued)
SAFETY ANALYSES monitored and to also provide adequate margin for effective action.
SAFETY LIMITS The reactor core SLs are established to protect the integrity of the fuel clad barrier to the release of radioactive materials to the environs.
SL 2.1.1.1 and SL 2.1.1.2 ensure that the core operates within the fuel design criteria. SL 2.1.1.3 ensures that the reactor vessel water level is greater than the top of the active irradiated fuel in order to prevent elevated clad temperatures and resultant clad perforations.
APPLICABILITY SLs 2.1.1.1, 2.1.1.2, and 2.1.1.3 are applicable in all MODES.
SAFETY LIMIT Exceeding an SL may cause fuel damage and create a potential for VIOLATIONS radioactive releases in excess of regulatory limits. Therefore, it is required to insert all insertable control rods and restore compliance with the SLs within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time ensures that the operators take prompt remedial action and also ensures that the probability of an accident occurring during this period is minimal.
REFERENCES 1. 10 CFR 50, Appendix A, GDC 10.
- 2. ANF 524 (P)(A), Revision 2, "Critical Power Methodology for Boiling Water Reactors," Supplement 1 Revision 2 and Supplement 2, November 1990.
- 3. Deleted.
- 4. EMF-2209(P)(A), "SPCB Critical Power Correlation,"
Framatome ANP, [See Core Operating Limits Report for Revision Level].
- 5. EMF-2158(P)(A), Revision 0, "Siemens Power Corporation Methodology for Boiling Water Reactors: Evaluation and Validation of CASMO-4/Microburn-B2," October 1999.
(continued)
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PPL Rev. 5 Reactor Core SLs B 2.1.1 BASES THIS PAGE INTENTIONALLY LEFT BLANK SUSQUEHANNA - UNIT 1 TS / B 2.0-6 Revision 1
PPL Rev. 3 SDV Vent and Drain Valves B 3.1.8 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.8 Scram Discharge Volume (SDV) Vent and Drain Valves BASES BACKGROUND The SDV vent and drain valves are normally open and discharge any accumulated water in the SDV to ensure that sufficient volume is available at all times to allow a complete scram. During a scram, the SDV vent and drain valves close to contain reactor water. The SDV is a volume of header piping that connects to each hydraulic control unit (HCU) and drains into an instrument volume. There are two SDVs (headers) and two instrument volumes, each receiving approximately one half of the control rod drive (CRD) discharges. The two instrument volumes are connected to a common drain line with two valves in series. Each header is connected to a common vent line with two valves in series. The header piping is sized to receive and contain all the water discharged by the CRDs during a scram. The design and functions of the SDV are described in Reference 1.
APPLICABLE The Design Basis Accident and transient analyses assume all of the SAFETY control rods are capable of scramming. The acceptance criteria for the ANALYSES SDV vent and drain valves are that they operate automatically to:
- a. Close during scram to limit the amount of reactor coolant discharged so that adequate core cooling is maintained and offsite and control room doses remain within regulatory limits; and
- b. Open on scram reset to maintain the SDV vent and drain path open so that there is sufficient volume to accept the reactor coolant discharged during a scram.
Isolation of the SDV can also be accomplished by manual closure of the SDV valves. Additionally, the discharge of reactor coolant to the SDV can be terminated by scram reset or closure of the HCU manual isolation valves. For a bounding leakage case, the offsite and control room doses are well within regulatory limits, and adequate core cooling is maintained (Ref. 3). The SDV vent and drain valves allow continuous drainage of the SDV during normal plant operation (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.1-47 Revision 1
PPL Rev. 3 SDV Vent and Drain Valves B 3.1.8 BASES APPLICABLE to ensure that the SDV has sufficient capacity to contain the reactor SAFETY coolant discharge during a full core scram. To automatically ensure this ANALYSES capacity, a reactor scram (LCO 3.3.1.1, "Reactor Protection System (RPS)
(continued) Instrumentation") is initiated if the SDV water level in the instrument volume exceeds a specified setpoint. The setpoint is chosen so that all control rods are inserted before the SDV has insufficient volume to accept a full scram.
SDV vent and drain valves satisfy Criterion 3 of the NRC Policy Statement (Ref. 4).
LCO The OPERABILITY of all SDV vent and drain valves ensures that the SDV vent and drain valves will close during a scram to contain reactor water discharged to the SDV piping. The SDV vent and drain valves are required to be open to ensure the SDV is drained. Since the vent and drain lines are provided with two valves in series, the single failure of one valve in the open position will not impair the isolation function of the system. Additionally, the valves are required to open on scram reset to ensure that a path is available for the SDV piping to drain freely at other times.
APPLICABILITY In MODES 1 and 2, scram may be required; therefore, the SDV vent and drain valves must be OPERABLE. 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 controls to ensure that only a single control rod can be withdrawn. Also, during MODE 5, only a single control rod can be withdrawn from a core cell containing fuel assemblies.
Therefore, the SDV vent and drain valves are not required to be OPERABLE in these MODES since the reactor is subcritical and only one rod may be withdrawn and subject to scram.
I ACTIONS The ACTIONS table is modified by Note 1 indicating that a separate Condition entry is allowed for the SDV vent line and the SDV drain line. This is acceptable, since the (continued)
SUSQUEHANNA-UNIT 1 TS / B 3.1-48 Revision 1
PPL Rev. 3 SDV Vent and Drain Valves B 3.1.8 BASES ACTIONS Required Actions for each Condition provide appropriate compensatory (continued) actions for each inoperable SDV line. Complying with the Required Actions may allow for continued operation, and subsequent inoperable SDV lines are governed by subsequent Condition entry and application of associated Required Actions.
The ACTIONS table is modified by a second note stating that a isolated line may be unisolated under administrative control to allow draining and venting of the SDV. When a line is isolated, the potential for an inadvertent scram due to high SDV level is increased. During these periods, the line may be unisolated under administrative control. This allows any accumulated water in the line to be drained, to preclude a reactor scram on high SDV level. This is acceptable since administrative controls ensure the valve can be closed quickly, if a scram occurs with the valve open.
A. 1 When one SDV vent or drain valve is inoperable in one or more lines, the associated line must be isolated to contain the reactor coolant during a scram. The 7 day Completion Time is reasonable, given the level of redundancy in the lines and the low probability of a scram occurring while the valve(s) are inoperable and the line is not isolated. The SDV is still isolable since the redundant valve in the affected line is OPERABLE.
During these periods, the single failure criterion is not preserved, and a higher risk exists to allow reactor water out of the primary system during a scram.
B.1 If both valves in a line are inoperable, the line must be isolated to contain the reactor coolant during a scram.
The 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> Completion Time to isolate the line is based on the low probability of a scram occurring while the line is not isolated and unlikelihood of significant CRD seal leakage.
C. 1 If any Required Action and associated Completion Time is not met, the plant must be brought to a MODE in which the LCO (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.1-49 Revision 1
PPL Rev. 3 SDV Vent and Drain Valves B 3.1.8 BASES ACTIONS C.1 (continued) does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The allowed Completion Time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems.
SURVEILLANCE SR 3.1.8.1 REQUIREMENTS During normal operation, the SDV vent and drain valves should be in the open position (except when performing SR 3.1.8.2) to allow for drainage of the SDV piping. Verifying that each valve is in the open position ensures that the SDV vent and drain valves will perform their intended functions during normal operation. This SR does not require any testing or valve manipulation; rather, it involves verification that the valves are in the correct position.
The 31 day Frequency is based on engineering judgment and is consistent with the procedural controls governing valve operation, which ensure correct valve positions.
SR 3.1.8.2 During a scram, the SDV vent and drain valves should close to contain the reactor water discharged to the SDV piping. Cycling each valve through its complete range of motion (closed. and open) ensures that the valve will function properly during a scram. The 92 day Frequency is based on operating experience and takes into account the level of redundancy in the system design.
SR 3.1.8.3 SR 3.1.8.3 is an integrated test of the SDV vent and drain valves to verify total system performance. After receipt of a simulated or actual scram signal, the closure of the SDV vent and drain valves is verified. The closure time of (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.1-50 Revision 0
PPL Rev. 3 SDV Vent and Drain Valves B 3.1.8 BASES SURVEILLANCE SURVEQIR NENS SR 3.1.8.3 (continued)
REQUIREMENTS 30 seconds after receipt of a scram signal is based on the bounding leakage case evaluated in the accident analysis based on the requirements of Reference 2. Similarly, after receipt of a simulated or actual scram reset signal, the opening of the SDV vent and drain valves is verified. The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.1.1 and the scram time testing of control rods in LCO 3.1.3 overlap 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 transient if the Surveillance were performed with the reactor at power. Operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency; therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
REFERENCES 1. FSAR, Section 4.6.
- 2. 10 CFR 50.67
- 3. NUREG-0803, "Generic Safety Evaluation Report Regarding Integrity of BWR Scram System Piping," August 1981.
- 4. Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 39132).
- 5. TSTF-404-A, Rev. 0.
SUSQUEHANNA - UNIT 1 TS / B 3.1-51 Revision 3
PPL Rev. 3 MCPR B 3.2.2 B 3.2 POWER DISTRIBUTION LIMITS B 3.2.2 MINIMUM CRITICAL POWER RATIO (MCPR)
BASES BACKGROUND MCPR is a ratio of the fuel assembly power that would result in the onset of boiling transition to the actual fuel assembly power. The MCPR Safety Limit (SL) is set such that 99.9% of the fuel rods avoid boiling transition if the limit is not violated (refer to the Bases for SL 2.1.1.2).
The operating limit MCPR is established to ensure that no fuel damage results during anticipated operational occurrences (AOOs). Although fuel damage does not necessarily occur if a fuel rod actually experienced boiling transition (Ref. 1), the critical power at which boiling transition is calculated to occur has been adopted as a fuel design criterion.
The onset of transition boiling is a phenomenon that is readily detected during the testing of various fuel bundle designs. Based on these experimental data, correlations have been developed to predict critical bundle power (i.e., the bundle power level at the onset of transition boiling) for a given set of plant parameters (e.g., reactor vessel pressure, flow, and subcooling). Because plant operating conditions and bundle power levels are monitored and determined relatively easily, monitoring the MCPR is a convenient way of ensuring that fuel failures due to inadequate cooling do not occur.
APPLICABLE The analytical methods and assumptions used in evaluating the AOOs SAFETY to establish the operating limit MCPR are presented in References 2 ANALYSES through 10. To ensure that the MCPR SL is not exceeded during any transient event that occurs with moderate frequency, limiting transients have been analyzed to determine the largest reduction in critical power ratio (CPR). The types of transients evaluated are loss of flow, increase in pressure and power, positive reactivity insertion, and coolant temperature decrease. The limiting transient yields the largest change in CPR (ACPR). When the largest ACPR is added to the MCPR SL, the required operating limit MCPR is obtained.
The MCPR operating limits derived from the transient analysis are dependent on the operating core flow and power (continued)
SUSQUEHANNA- UNIT I TS / B 3.2-5 Revision 2
PPL Rev. 3 MCPR B 3.2.2 BASES APPLICABLE state to ensure adherence to fuel design limits during the worst transient SAFETY that occurs with moderate frequency. These analyses may also ANALYSES consider other combinations of plant conditions (i.e., control rod scram (continued) speed, bypass valve performance, EOC-RPT, cycle exposure, etc.).
Flow dependent MCPR limits are determined by analysis of slow flow runout transients.
The MCPR satisfies Criterion 2 of the NRC Policy Statement (Ref. 11).
LCO The MCPR operating limits specified in the COLR are the result of the Design Basis Accident (DBA) and transient analysis. The operating limit MCPR is determined by the larger of the flow dependent MCPR and power dependent MCPR limits.
APPLICABILITY The MCPR operating limits are primarily derived from transient analyses that are assumed to occur at high power levels. Below 23% RTP, the reactor is operating at a minimum recirculation pump speed and the moderator void ratio is small. Surveillance of thermal limits below 23% RTP is unnecessary due to the large inherent margin that ensures that the MCPR SL is not exceeded even if a limiting transient occurs.
Studies of the variation of limiting transient behavior have been performed over the range of power and flow conditions. These studies encompass the range of key actual plant parameter values important to typically limiting transients. The results of these studies demonstrate that a margin is expected between performance and the MCPR requirements, and that margins increase as power is reduced to 23% RTP. This trend is expected to (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.2-6 Revision 3
PPL Rev. 3 MCPR B 3.2.2 BASES APPLICABILITY continue to the 5% to 15% power range when entry into MODE 2 occurs.
(continued) When in MODE 2, the intermediate range monitor provides rapid scram initiation for any significant power increase transient, which effectively eliminates any MCPR compliance concern. Therefore, at THERMAL POWER levels < 23% RTP, the reactor is operating with substantial margin to the MCPR limits and this LCO is not required.
ACTIONS A.1 If any MCPR is outside the required limits, an assumption regarding an initial condition of the design basis transient analyses may not be met.
Therefore, prompt action should be taken to restore the MCPR(s) to within the required limits such that the plant remains operating within analyzed conditions. The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time is normally sufficient to restore the MCPR(s) to within its limits and is acceptable based on the low probability of a transient or DBA occurring simultaneously with the MCPR out of specification.
B. 1 If the MCPR 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 must be reduced to < 23% RTP within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The allowed Completion Time is reasonable, based on operating experience, to reduce THERMAL POWER to < 23% RTP in an orderly, manner and without challenging plant systems.
SURVEILLANCE SR 3.2.2.1 REQUIREMENTS The MCPR is required to be initially calculated within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after THERMAL POWER is Ž 23% RTP and then every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> thereafter.
Additionally, MCPR must be calculated prior to exceeding 44% RTP unless performed in the previous 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. MCPR is compared to the specified limits in the (continued)
SUSQUEHANNA - UNIT 1 B 3.2-7 Revision 1
PPL Rev. 3 MCPR B 3.2.2 BASES SURVEILLANCE SR 3.2.2.1 (continued)
REQUIREMENTS COLR to ensure that the reactor is operating within the assumptions of the safety analysis. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 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 <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> allowance after THERMAL POWER _>23% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels and because the MCPR must be calculated prior to exceeding 44% RTP.
SR 3.2.2.2 Because the transient analysis takes credit for conservatism in the scram time performance, it must be demonstrated that the specific scram time is consistent with those used in the transient analysis.
SR 3.2.2.2 compares the average measured scram times to the assumed scram times documented in the COLR. The COLR contains a table of scram times based on the LCO 3.1.4 "Control Rod Scram Times" and the realistic scram times, both of which are used in the transient analysis. If the average measured scram times are greater than the realistic scram times then the MCPR operating limits corresponding to the Maximum Allowable Average Scram Insertion Time must be implemented. Determining MCPR operating limits based on interpolation between scram insertion times is not permitted. The average measured scram times and corresponding MCPR operating limit must be determined once within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> after each set of scram time tests required by SR 3.1.4.1, SR 3.1.4.2, SR 3.1.4.3 and SR 3.1.4.4 because the effective scram times may change during the cycle. The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time is acceptable due to the relatively minor changes in average measured scram times expected during the fuel cycle.
REFERENCES 1. NUREG-0562, June 1979.
- 2. XN-NF-80-19(P)(A) Volume 1 and Supplements 1 and 2, "Exxon Nuclear Methodology for Boiling Water Reactors," Exxon Nuclear Company, March 1983.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.2-8 Revision 3
PPL Rev. 3 MCPR B 3.2.2 BASES REFERENCES 3. XN-NF-80-19(P)(A) Volume 3 Revision 2, "Exxon Nuclear (continued) Methodology for Boiling Water Reactors, THERMEX: Thermal Limits Methodology Summary Description," Exxon Nuclear Company, January 1987.
- 4. ANF-913(P)(A) Volume 1 Revision 1 and Volume Supplements 2, 3, and 4, "COTRANSA2: A Computer Program for Boiling Water Reactor Transient Analyses," Advanced Nuclear Fuels Corporation, August 1990.
- 5. XN-NF-80-19 (P)(A), Volume 4, Revision 1, "Exxon Nuclear Methodology for Boiling Water Reactors: Application of the ENC Methodology to BWR Reloads," Exxon Nuclear Company, June 1986.
- 6. NE-092-001, Revision 1, "Susquehanna Steam Electric Station Units 1 & 2: Licensing Topical Report for Power Uprate with Increased Core flow," December 1992, and NRC Approval Letter:
Letter from T. E. Murley (NRC) to R. G. Byram (PP&L),
"Licensing Topical Report for Power Uprate With Increased Core Flow, Revision 0, Susquehanna Steam Electric Station, Units 1 and 2 (PLA-3788) (TAC Nos. M83426 and M83427)," November 30,1993.
- 7. EMF-2209(P)(A), "SPCB Critical Power Correlation," Framatome ANP, [See Core Operating Limits Report for Revision Level].
- 8. XN-NF-79-71(P)(A) Revision 2, Supplements 1, 2, and 3, "Exxon Nuclear Plant Transient Methodology for Boiling Water Reactors,"
March 1986.
- 9. XN-NF-84-105(P)(A), Volume 1 and Volume 1 Supplements 1 and 2, "XCOBRA-T: A Computer Code for BWR Transient Thermal-Hydraulic Core Analysis," February 1987.
- 10. ANF-1358(P)(A), "The Loss of Feedwater Heating Transient in Boiling Water Reactors," Framatome ANP, [See Core Operating Limits Report for Revision Level].
- 11. Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 39132).
SUSQUEHANNA - UNIT 1 TS / B 3.2-9 Revision 3
PPL Rev. 3 RHRSW System and UHS B 3.7.1 B 3.7 PLANT SYSTEMS B 3.7.1 Residual Heat Removal Service Water (RHRSW) System and the Ultimate Heat Sink (UHS)
BASES BACKGROUND The RHRSW System is designed to provide cooling water for the Residual Heat Removal (RHR) System heat exchangers, required for a safe reactor shutdown following a Design Basis Accident (DBA) or transient. The RHRSW System is operated whenever the RHR heat exchangers are required to operate in the shutdown cooling mode or in the suppression pool cooling or spray mode of theRHR System.
The RHRSW System consists of two independent and redundant subsystems. Each subsystem is made up of a header, one pump, a suction source, valves, piping, heat exchanger, and associated instrumentation. Either of the two subsystems is capable of providing the required cooling capacity to maintain safe shutdown conditions. The two subsystems are separated so that failure of one subsystem will not affect the OPERABILITY of the other subsystem. One Unit 1 RHRSW subsystem and the associated (same division) Unit 2 RHRSW subsystem constitute a single RHRSW loop. The two RHRSW pumps in a loop can each, independently, be aligned to either Unit's heat exchanger. The RHRSW System is designed with sufficient redundancy so that no single active component failure can prevent it from achieving its design function.
The RHRSW System is described in the FSAR, Section 9.2.6, Reference 1.
Cooling water is pumped by the RHRSW pumps from the UHS through the tube side of the RHR heat exchangers. After removing heat from the RHRSW heat exchanger, the water is discharged to the spray pond (UHS) by way of the UHS return loops. The UHS return loops direct the return flow to a network of sprays that dissipate the heat to the atmosphere or directly to the UHS via a bypass header.
The system is initiated manually from the control room except for the spray array bypass manual valves that are operated locally in the event of a failure of the spray array bypass valves. The system can be started any time the LOCA signal is manually overridden or clears.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.7-1 Revision 3
PPL Rev. 3 RHRSW System and UHS B 3.7.1 BASES BACKGROUND The ultimate heat sink (UHS) system is composed of approximately (continued) 3,300,000 cubic foot spray pond and associated piping and spray risers.
Each UHS return loop contains a bypass line, a large spray array and a small spray array. The purpose of the UHS is to provide both a suction source of water and a return path for the RHRSW and ESW systems.
The function of the UHS is to provide water to the RHRSW and ESW systems at a temperature less than the 970 F design temperature of the RHRSW and ESW systems. UHS temperature is maintained less than the design temperature by introducing the hot return fluid from the RHRSW and ESW systems into the spray loops and relying on spray cooling to maintain temperature. The UHS is designed to supply the RHRSW and ESW systems with all the cooling capacity required during a combination LOCA/LOOP for thirty days without fluid addition. The UHS is described in the FSAR, Section 9.2.7 (Reference 1).
APPLICABLE The RHRSW System removes heat from the suppression pool to, limit the SAFETY suppression pool temperature and primary containment pressure following ANALYSES a LOCA. This ensures that the primary containment can perform its function of limiting the release of radioactive materials to the environment following a LOCA. The ability of the RHRSW System to support long term cooling of the reactor or primary containment is discussed in the FSAR, Chapters 6 and 15 (Refs. 2 and 3, respectively). These analyses explicitly assume that the RHRSW System will provide adequate cooling support to the equipment required for safe shutdown. These analyses include the evaluation of the long term primary containment response after a design basis LOCA.
The safety analyses for long term cooling were performed for various RHRSW and UHS configurations. As discussed in the FSAR, Section 6.2.2 (Ref. 2) for these analyses, manual initiation of the OPERABLE RHRSW subsystem and the associated RHR System is required. The maximum suppression chamber water temperature and pressure are analyzed to be below the design temperature of 220°F and maximum allowable pressure of 53 psig.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.7-2 Revision 4
PPL Rev. 3 RHRSW System and UHS B 3.7.1 BASES APPLICABLE The UHS design takes into account the cooling efficiency of the spray SAFETY arrays and the evaporation losses during design basis environmental ANALYSES conditions. The spray array bypass header provides the flow path for the (continued) ESW and RHRSW system to keep the spray array headers from freezing.
The small and/or large spray arrays are placed, in service to dissipate heat returning from the plant. The UHS return header is comprised of the spray array bypass header, the large spray array, and the small spray array.
The spray array bypass header is capable of passing full flow from the RHRSW and ESW systems in each loop. The large spray array is capable of passing full flow from the RHRSW and ESW systems in each loop. The small spray array supports heat dissipation when low system flows are required.
The RHRSW System, together with the UHS, satisfy Criterion 3 of the NRC Policy Statement. (Ref. 4)
LCO Two RHRSW subsystems are required to be OPERABLE to provide the required redundancy to ensure that the system functions to remove post accident heat loads, assuming the worst case single active failure occurs coincident with the loss of offsite power.
An RHRSW subsystem is considered OPERABLE when:
- a. One pump is OPERABLE; and
- b. An OPERABLE flow path is capable of taking suction from the UHS and transferring the water to the RHR heat exchanger and returning it to the UHS at the assumed flow rate, and
The OPERABILITY of the UHS is based on having a minimum water level at the overflow weir of 678 feet 1 inch above mean sea level and a maximum water temperature of 85 0 F; unless either unit is in MODE 3. If a unit enters MODE 3, the time of entrance into this condition determines the appropriate maximum ultimate heat sink fluid temperature. If the earliest unit to enter MODE 3 has been in that condition for less than twelve (12) hours, the peak temperature to maintain OPERABILITY of the ultimate heat sink remains at 85 0 F. If either unit has been in MODE 3 for more than twelve (12) hours but less than twenty-four (24) hours, the OPERABILITY temperature of the ultimate heat sink becomes 87 0 F. If either unit has been in MODE 3 for twenty-four (24) hours or more, the OPERABILITY temperature of the ultimate heat sink becomes 88 0 F.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.7-3 Revision 3
PPL Rev. 3 RHRSW System and UHS B 3.7.1 BASES LCO In addition, the OPERABILITY of the UHS is based on having sufficient (continued) spray capacity in the UHS return loops. Sufficient spray capacity is defined as one large and one small spray array in one loop.
This OPERABILITY definition is supported by analysis and evaluations performed in accordance with the guidance given in Regulatory Guide 1.27.
APPLICABILITY In MODES 1, 2, and 3, the RHRSW System and the UHS are required to be OPERABLE to support the OPERABILITY of the RHR System for primary containment cooling (LCO 3.6.2.3, "Residual Heat Removal (RHR)
Suppression Pool Cooling," and LCO 3.6.2.4, "Residual Heat Removal (RHR) Suppression Pool Spray") and decay heat removal (LCO 3.4.8, "Residual Heat Removal (RHR) Shutdown Cooling System-Hot Shutdown"). The Applicability is therefore consistent with the requirements of these systems.
In MODES 4 and 5, the OPERABILITY requirements of the RHRSW System are determined by the RHR shutdown cooling subsystem(s) it supports (LCO 3.4.9, "Residual Heat Removal (RHR) Shutdown Cooling System - Cold Shutdown"; LCO 3.9.7, "Residual Heat Removal (RHR) -
High Water Level"; and LCO 3.9.8, "Residual Heat Removal (RHR) - Low Water Level").
In MODES 4 and 5, the OPERABILITY requirements of the UHS is determined by the systems it supports.
ACTIONS The ACTIONS are modified by a Note indicating that the applicable Conditions of LCO 3.4.8, be entered and Required Actions taken if the inoperable RHRSW subsystem results in inoperable RHR shutdown cooling (SDC) (i.e., both the Unit 1 and Unit 2 RHRSW pumps in a loop are inoperable resulting in the associated RHR SDC system being inoperable). This is an exception to LCO 3.0.6 because the Required Actions of LCO 3.7.1 do not adequately compensate for the loss of RHR SDC Function (LCO 3.4.8).
Condition A is modified by a separate note to allow separate Condition entry for each valve. This is acceptable since the Required Action for this Condition provides appropriate compensatory actions.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.7-4 Revision 3
PPL Rev. 3 RHRSW System and UHS B 3.7.1 BASES I ACTIONS A.1, A.2, and A.3 (continued)
With one spray array bypass valve not capable of being closed on demand, the associated Unit 1 and Unit 2 RHRSW subsystems cannot use the spray cooling function of the affected UHS return loop. As a result, the associated RHRSW subsystem must be declared inoperable.
With one spray array loop bypass valve not capable of being opened on demand, a return flow path is not available. As a result, the associated RHRSW subsystems must be declared inoperable.
With one spray array bypass manual valve not capable of being closed, the associated Unit 1 and Unit 2 RHRSW subsystems cannot use the spray cooling function of the affected UHS return path if the spray array bypass valve fails to close. As a result, the associated RHRSW subsystems must be declared inoperable.
With one spray array bypass manual valve not open, a return flow path is not available. As a result, the associated RHRSW subsystems must be declared inoperable.
With one large spray array valve not capable of being opened on demand, the associated Unit 1 and Unit 2 RHRSW subsystems cannot use the full required spray cooling capability of the affected UHS return path. With one large spray array valve not capable of being closed on demand, the associated Unit 1 and Unit 2 RHRSW subsystems cannot use the small spray array when loop flows are low as the required spray nozzle pressure is not achievable for the small spray array. As a result, the associated RHRSW subsystems must be declared inoperable.
With one small spray array valve not capable of being opened on demand, the associated Unit 1 and Unit 2 RHRSW subsystems cannot use the spray cooling function of the affected UHS return path for low loop flow rates. For a single failure of the large spray array valve in the closed position, design bases LOCA/LOOP calculations assume that flow is reduced on the affected loop within 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> after the event to allow use of the small spray array. With one small spray array valve not capable of being closed on demand, the associated Unit 1 and Unit 2 RHRSW subsystems cannot use the large spray array for a flow path as the required nozzle pressure is not achievable for the large spray array. As a result, the associated RHRSW subsystems must be declared inoperable.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.7-5 Revision 3
PPL Rev. 3 RHRSW System and UHS B 3.7.1 BASES ACTIONS A.1, A.2, and A.3 (continued)
With any UHS return path valve listed in Tables 3.7.1-1, 3.7.1-2, or 3.7.1-3 inoperable, the UHS return path is no longer single failure proof.
For combinations of inoperable valves in the same loop, the UHS spray capacity needed to support the OPERABILITY of the associated Unit 1 and Unit 2 RHRSW subsystems is affected. As a result, the associated RHRSW subsystems must be declared inoperable.
The 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> completion time to establish the flow path provides sufficient time to open a path and de-energize the appropriate valve in the open position.
The 72-hour completion time is based on the fact that, although adequate UHS spray loop capability exists during this time period, both units are affected and an additional single failure results in a system configuration that will not meet design basis accident requirements.
If an additional RHRSW subsystem on either Unit is inoperable, cooling capacity less than the minimum required for response to a design basis event would exist. Therefore, an 8-hour Completion Time is appropriate.
The 8-hour Completion Time provides sufficient time to restore inoperable equipment and there is a low probability that a design basis event would occur during this period.
B.1 Required Action B.1 is intended to ensure that appropriate actions are taken if one Unit 1 RHRSW subsystem is inoperable. Although designated and operated as a unitized system, the associated Unit 2 subsystem is directly connected to a common header, which can supply the associated RHR heat exchanger in either unit. The Unit 2 subsystems are considered capable of supporting Unit 1 RHRSW subsystem when the Unit 2 subsystem is OPERABLE and can provide the assumed flow to the Unit 1 heat exchanger. A Completion time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, when one Unit 2 RHRSW subsystem is not capable of supporting the Unit 1 RHRSW subsystems, is allowed to restore the Unit 1 RHRSW subsystem to OPERABLE status. In this configuration, the remaining OPERABLE Unit 1 RHRSW subsystem is adequate to perform the RHRSW heat removal function. However, the overall reliability is reduced because a single failure in the OPERABLE RHRSW subsystem (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.7-5a Revision 0
PPL Rev. 3 RHRSW System and UHS B 3.7.1 BASES ACTIONS B.1 (continued) could result in loss of RHRSW function. The Completion Time is based on the redundant RHRSW capabilities afforded by the OPERABLE subsystem and the low probability of an event occurring requiring RHRSW during this period.
With one RHRSW subsystem inoperable, and both of the Unit 2 RHRSW subsystems capable of supporting their respective Unit 1 RHRSW subsystems, the design basis cooling capacity for both units can still be maintained even considering a single active failure. However, the configuration does reduce the overall reliability of the RHRSW System.
Therefore, provided both of the Unit 2 subsystems remain capable of supporting their respective Unit 1 RHRSW subsystems, the inoperable RHRSW subsystem must be restored to OPERABLE status within 7 days.
The 7-day Completion Time is based on the remaining RHRSW System heat removal capability.
C.1 Required Action C. 1 is intended to ensure that appropriate actions are taken if both Unit 1 RHRSW subsystems are inoperable. Although designated and operated as a unitized system, the associated Unit 2 subsystem is directly connected to a common header, whidh can supply the associated RHR heat exchanger in either unit. With both Unit 1 RHRSW subsystems inoperable, the RHRSW system is still capable of performing its intended design function. However, the loss of an additional RHRSW subsystem on Unit 2 results in the cooling capacity to be less than the minimum required for response to a design basis event.
Therefore, the 8-hour Completion Time is appropriate. The 8-hour Completion Time for restoring one RHRSW subsystem to OPERABLE status is based on the Completion Times provided for the RHR suppression pool spray function.
With both Unit 1 RHRSW subsystems inoperable, and both of the Unit 2 RHRSW subsystems capable of supporting their respective Unit 1 RHRSW subsystem, if no additional failures occur which impact the RHRSW System, the remaining OPERABLE Unit 2 subsystems and flow paths provide adequate heat removal capacity following a design basis LOCA. However, capability for this alignment is not assumed in long term containment response analysis and an additional single failure in the RHRSW System could reduce the system capacity below that assumed in the safety analysis.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.7-6 Revision 2
PPL Rev. 3 RHRSW System and UHS B 3.7.1 BASES ACTIONS C.1 (continued)
Therefore, continued operation is permitted only for a limited time. One inoperable subsystem is required to be restored to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time for restoring one inoperable RHRSW subsystem to OPERABLE status is based on the fact that the alternate loop is capable of providing the required cooling capability during this time period.
D.1 and D.2 If the RHRSW subsystems cannot be restored to OPERABLE status within the associated Completion Times, or the UHS is determined to be inoperable, the unit must be placed in a MODE in which the LCO does not apply. To achieve this status, the unit must be placed in at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.
SURVEILLANCE SR 3.7.1.1 REQUIREMENTS This SR verifies the water level to be sufficient for the proper operation of the RHRSW pumps (net positive suction head and pump vortexing are considered in determining this limit). The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Frequency is based on operating experience related to trending of the parameter variations during the applicable MODES.
SR 3.7.1.2 Verification of the UHS temperature, which is the arithmetical average of the UHS temperature near the surface, middle and bottom levels, ensures that the heat removal capability of the ESW and RHRSW Systems are within the assumptions of the DBA analysis. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is based on operating experience related to trending of the parameter variations during the applicable MODES.
(continued)
SUSQUEHANNA-UNIT 1 TS / B 3.7-6a Revision 2
PPL Rev. 3 RHRSW System and UHS B 3.7.1 BASES SURVEILLANCE REQUIREMENTS SR 3.7.1.3 (continued)
Verifying the correct alignment for each manual, power operated, and automatic valve in each RHRSW subsystem flow path provides assurance that the proper flow paths will exist for RHRSW operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position, since these valves are verified to be in the correct position prior to locking, sealing, or securing. A valve is also allowed to be in the nonaccident position, and yet considered in the correct position, provided it can be realigned to its accident position. This is acceptable because the RHRSW System is a manually initiated system.
This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves.
The 31-day Frequency is based on engineering judgment, is consistent with the procedural controls governing valve operation, and ensures correct valve positions.
SR 3.7.1.4 The UHS spray array bypass valves are required to actuate to the closed position for the UHS to perform its design function. These valves receive an automatic signal to open upon emergency service water (ESW) or residual heat removal service water (RHRSW) system pump start and are required to be operated from the control room or the remote shutdown panel. A spray bypass valve is considered to be inoperable when it cannot be closed on demand. Failure of the spray bypass valve to close on demand puts the UHS at risk to exceed its design temperature. The failure of the spray bypass valve to open on demand makes one return path unavailable, and therefore the associated RHRSW subsystems must be declared inoperable. This SR demonstrates that the valves will move to their required positions when required. The 92-day Test Frequency is based upon engineering judgment and operating/testing history that indicates this frequency gives adequate assurance that the valves will move to their required positions when required.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.7-6b Revision 1
PPL Rev. 3 RHRSW System and UHS B 3.7.1 BASES SURVEILLANCE SR 3.7.1.5 REQUIREMENTS (continued)
The UHS return header large spray array valves are required to open in order for the UHS to perform its design function. These valves are manually actuated from either the control room or the remote shutdown panel, under station operating procedure, when the RHRSW system is required to remove energy from the reactor vessel or suppression pool.
This SR demonstrates that the valves will move to their required positions when required. The 92-day Test Frequency is based upon engineering judgment and operating/testing history that indicates this frequency gives adequate assurance that the valves will move to their required positions when required.
SR 3.7.1.6 The small spray array valves HV-01224A2 and B2 are required to operate in order for the UHS to perform its design function. These valves are manually actuated from the control room or the remote shutdown panel, under station operating procedure, when the RHRSW system is required to remove energy from the reactor vessel or suppression pool. This SR demonstrates that the valves will move to their required positions.when required. The 92-day Test Frequency is based upon engineering judgment and operating/ testing history that indicates this frequency gives adequate assurance that the valves will move to their required positions when required.
SR 3.7.1.7 The spray array bypass manual valves 012287A and B are required to operate in the event of a failure of the spray array bypass valves to close in order for the UHS to perform its design function.
REFERENCES 1. FSAR, Section 9.2.
- 2. FSAR, Chapter 6.
- 3. FSAR, Chapter 15.
- 4. Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 39132).
SUSQUEHANNA - UNIT 1 TS / B 3.7-6c Revision 2
PPL Rev. 6 AC Sources Operating B 3.8.1 B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.1 AC Sources - Operating BASES BACKGROUND The unit Class 1 E AC Electrical Power Distribution System AC sources consist of two offsite power sources (preferred power sources, normal and alternate), and the onsite standby power sources (diesel generators (DGs) A, B, C and D). A fifth diesel generator, DG E, can be used as a substitute for any one of the four DGs A, B, C or D. As required by 10 CFR 50, Appendix A, GDC 17 (Ref. 1), the design of the AC electrical power system provides independence and redundancy to ensure an available source of power to the Engineered Safety Feature (ESF) systems.
The Class 1 E AC distribution system is divided into redundant load groups, so loss of any one group does not prevent the minimum safety functions from being performed. Each load group has connections to two preferred offsite power supplies and a single DG.
The two qualified circuits between the offsite transmission network and the onsite Class 1E AC Electrical Power Distribution System are supported by two independent offsite power sources. A 230 kV line from the Susquehanna T10 230 kV switching station feeds start-up transformer No. 10; and, a 230 kV tap from the 500-230 kV tie line feeds the startup transformer No. 20. The term "qualified circuits", as used within TS 3.8.1, is synonymous with the term "physically independent".
The two independent offsite power sources are supplied to and are shared by both units. These two electrically and physically separated circuits provide AC power, through startup transformers (ST) No. 10 and ST No. 20, to the four 4.16 kV Engineered Safeguards System (ESS) buses (A, B, C and D) for both Unit 1 and Unit 2. A detailed description of the offsite power network and circuits to the onsite Class 1E ESS buses is found in the FSAR, Section 8.2 (Ref. 2).
An offsite circuit consists of all breakers, transformers, switches, automatic tap changers, interrupting devices, cabling, and controls required to transmit power from the offsite transmission network to the onsite Class 1 E ESS bus or buses.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.8-1 Revision 3
PPL Rev. 6 AC Sources - Operating B 3.8.1 BASES BACKGROUND ST No. 10 and ST No. 20 each provide the normal source of power to (continued) two of the four 4.16 kV ESS buses in each Unit and the alternate source of power to the remaining two 4.16 kV ESS buses in each Unit.
If any 4.16 kV ESS bus loses power, an automatic transfer from the normal to the alternate occurs after the normal supply breaker trips.
When off-site power is available to the 4.16 kV ESS Buses following a LOCA signal, the required ESS loads will be sequenced onto the 4.16 kV ESS Buses in order to compensate for voltage drops in the onsite power system when starting large ESS motors.
The onsite standby power source for 4.16 kV ESS buses A, B, C and D consists of five DGs. DGs A, B, C and D are dedicated to ESS buses A, B, C and D, respectively. DG E can be used as a substitute for any one of the four DGs (A, B, C or D) to supply the associated ESS bus. Each DG provides standby power to two 4.16 kV ESS buses-one associated with Unit 1 and one associated with Unit 2.
The four "required" DGs are those aligned to a 4.16 kV ESS bus to provide onsite standby power for both Unit 1 and Unit 2.
A DG, when aligned to an- ESS bus, starts automatically on a loss of coolant accident (LOCA) signal (i.e., low reactor water level signal or high drywell pressure signal) or on an ESS bus degraded voltage or undervoltage signal. After the DG has started, it automatically ties to its respective bus after offsite power is tripped as a consequence of ESS bus undervoltage or degraded voltage, independent of or coincident with a LOCA signal. The DGs also start and operate in the standby mode without tying to the ESS bus on a LOCA signal alone.
Following the trip of offsite power, non-permanent loads are stripped from the 4.16 kV ESS Buses. When a DG is tied to the ESS Bus, loads are then sequentially connected to their respective ESS Bus by individual load timers. The individual load timers control the starting permissive signal to motor breakers to prevent overloading the associated DG.
In the event of loss of normal and alternate offsite power supplies, the 4.16 kV ESS buses will shed all loads except the 480 V load centers and the standby diesel generators will connect to the ESS busses. When a DG is tied to its respective ESS bus, loads are then sequentially connected to (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.8-2 Revision 2
PPL Rev. 6 AC Sources - Operating B 3.8.1 BASES BACKGROUND the ESS bus by individual load timers which control the permissive and (continued) starting signals to motor breakers to prevent overloading the DG.
In the event of a loss of normal and alternate offsite power supplies, the ESS electrical loads are automatically connected to the DGs in sufficient time to provide for safe reactor shutdown and to mitigate the consequences of a Design Basis Accident (DBA) such as a LOCA.
Certain required plant loads are returned to service in a predetermined sequence in order to prevent overloading of the DGs in the process.
Within 286 seconds after the initiating signal is received, all automatic and permanently connected loads needed to recover the unit or maintain it in a safe condition are returned to service. Ratings for the DGs satisfy the requirements of Regulatory Guide 1.9 (Ref. 3).
DGs A, B, C and D have the following ratings:
- a. 4000 kW-continuous,
- b. 4700 kW-2000 hours, DG E has the following ratings:
- a. 5000 kW-continuous,
- b. 5500 kW-2000 hours.
APPLICABLE The initial conditions of DBA and transient analyses in the FSAR, SAFETY ANALYSES Chapter 6 (Ref. 4) and Chapter 15 (Ref. 5), assume ESF systems are OPERABLE. The AC electrical power sources are designed to provide sufficient capacity, capability, redundancy, and reliability to ensure the availability of necessary power to ESF systems so that the fuel, Reactor Coolant System (RCS), and containment design limits are not exceeded. These limits are discussed in more detail in the Bases for Section 3.2, Power Distribution Limits; Section 3.4, Reactor Coolant System (RCS); and Section 3.6, Containment Systems.
The OPERABILITY of the AC electrical power sources is consistent with the initial assumptions of the accident analyses and is based upon meeting the design basis of the unit and supporting safe shutdown of the other unit. This includes maintaining the onsite or offsite AC sources (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.8-3 Revision 2
PPL Rev. 6 AC Sources - Operating B 3.8.1 BASES APPLICABLE OPERABLE during accident conditions in the event of an assumed SAFETY ANALYSES loss of all offsite power or all onsite AC power; and a worst case single failure.
(continued)
AC sources satisfy Criterion 3 of the NRC Policy Statement (Ref. 6).
LCO Two qualified circuits between the offsite transmission network and the onsite Class 1 E Distribution System and four separate and independent DGs (A, B, C and D) ensure availability of the required power to shut down the reactor and maintain it in a safe shutdown condition after an anticipated operational occurrence (AOO) or a postulated DBA. DG E can be used as a substitute for any one of the four DGs A, B, C or D.
Qualified offsite circuits are those that are described in the FSAR, and are part of the licensing basis for the unit. In addition, the required automatic load timers for each ESF bus shall be OPERABLE.
The Safety Analysis for Unit 2 assumes the OPERABILITY of some equipment that receives power from Unit 1 AC Sources. Therefore, Unit 2 Technical Specifications establish requirements for the OPERABILITY of the DG(s) and qualified offsite circuits needed to support the Unit 1 onsite Class 1 E AC electrical power distribution subsystem(s) required by LCO 3.8.7, Distribution Systems-Operating.
Each offsite circuit must be capable of maintaining rated frequency and voltage, and accepting required loads during an accident, while connected to the ESS buses.
One OPERABLE offsite circuit exists when all of the following conditions are met:
- 2. The respective circuit path including energized ESS transformers 101 and 111 and feeder breakers capable of supplying three of the four 4.16 kV ESS Buses.
- 3. Acceptable offsite grid voltage, defined as a voltage that is within the grid voltage requirements established for SSES.
The grid voltage requirements include both a minimum grid voltage and an allowable grid voltage drop during normal operation, and for a predicted voltage for a trip of the unit.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.8-4 Revision 3
PPL Rev. 6 AC Sources - Operating B 3.8.1 BASES LCO The Regional Transmission Operator (PJM), and/or the (continued) Transmission Power System Dispatcher, PPL EU, determine, monitor and report actual and/or contingency voltage (Predicted voltage) violations that occur for the SSES monitored offsite 230kV and 500kV buses.
The offsite circuit is inoperable for any actual voltage violation, or a contingency voltage violation that occurs for a trip of a SSES unit, as reported by the transmission RTO or Transmission Power System Dispatcher.
The offsite circuit is operable for any other predicted grid event (i.e., loss of the most critical transmission line or the largest supply) that does not result from the generator trip of a SSES unit. These conditions do not represent an impact on SSES operation that has been caused by a LOCA and subsequent generator trip. The design basis does not require entry into LCOs for predicted grid conditions that can not result in a LOCA, delayed LOOP.
The other offsite circuit is Operable when all the following conditions are met:
- 2. The respective circuit path including energized ESS transformers 201 and 211 and feeder breakers capable of supplying three of the four 4.16 kV ESS Buses.
- 3. Acceptable offsite grid voltage, defined as a voltage that is within the grid voltage requirements established for SSES.
The grid voltage requirements include both a minimum grid voltage and an allowable grid voltage drop during normal operation, and for a predicted voltage for a trip of the unit.
The Regional Transmission Operator (PJM), and/or the Transmission Power System Dispatcher, PPL EU, determine, monitor and report actual and/or contingency voltage (Predicted voltage) violations that occur for the SSES monitored offsite 230kV and 500kV buses.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.8-4a Revision 0
PPL Rev. 6 AC Sources - Operating B 3.8.1 BASES LCO The offsite circuit is inoperable for any actual voltage (continued) violation, or a contingency voltage violation that occurs for a trip of a SSES unit, as reported by the transmission RTO or Transmission Power System Dispatcher.
The offsite circuit is operable for any other predicted grid event (i.e., loss of the most critical transmission line or the largest supply) that does not result from the generator trip of a SSES unit. These conditions do not represent an impact on SSES operation that has been caused by a LOCA and subsequent generator trip. The design basis does not require entry into LCOs for predicted grid conditions that can not result in a LOCA, delayed LOOP.
Both offsite circuits are OPERABLE provided each meets the criteria described above and provided that no 4.16 kV ESS Bus has less than one OPERABLE offsite circuit (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.8-4b Revision 0
PPL Rev. 6 AC Sources - Operating B 3.8.1 BASES LCO capable of supplying the required loads. If no OPERABLE offsite (continued) circuit is capable of supplying any of the 4.16 kV ESS Buses, one offsite source shall be declared inoperable.
Four of the five DGs are required to be Operable to satisfy the initial assumptions of the accident analyses. Each required DG must be capable of starting, accelerating to rated speed and voltage, and connecting to its respective ESS bus on detection of bus undervoltage after the normal and alternate supply breakers open. This sequence must be accomplished within 10 seconds. Each DG must also be capable of accepting required loads within the assumed loading sequence intervals, and must continue to operate until offsite power can be restored to the ESS buses. These capabilities are required to be met from a variety of initial conditions, such as DG in standby with the engine hot and DG in normal standby conditions. Normal standby conditions for a DG mean that the diesel engine oil is being continuously circulated and engine coolant is circulated as necessary to maintain temperature consistent with manufacturer recommendations. Additional DG capabilities must be demonstrated to meet required Surveillances, e.g., capability of the DG to revert to standby status on an ECCS signal while operating in parallel test mode.
Although not normally aligned as a required DG, DG E is normally maintained OPERABLE (i.e., Surveillance Testing completed) so that it can be used as a substitute for any one of the four DGs A, B, C or D.
Proper sequencing of loads, including tripping of nonessential loads, is a required function for DG OPERABILITY.
The AC sources must be separate and independent (to the extent possible) of other AC sources. For the DGs, the separation and independence are complete. For the offsite AC sources, the separation and independence are to the extent practical. A circuit may be connected to more than one ESS bus, with automatic transfer capability to the other circuit OPERABLE, and not violate separation criteria. A circuit that is not connected to an ESS bus is required to have OPERABLE automatic transfer interlock mechanisms to each ESS bus to support OPERABILITY of that offsite circuit.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.8-5 Revision 5
PPL Rev. 6 AC Sources - Operating B 3.8.1 BASES (continued)
APPLICABILITY The AC sources are required to be OPERABLE in MODES 1, 2, and 3 to ensure that:
- a. Acceptable fuel design limits and reactor coolant pressure boundary limits are not exceeded as a result of AOOs or abnormal transients; and
- b. Adequate core cooling is provided and containment OPERABILITY and other vital functions are maintained in the event of a postulated DBA.
The AC power requirements for MODES 4 and 5 are covered in LCO 3.8.2, "AC Sources-Shutdown."
ACTIONS A Note prohibits the application of LCO 3.0.4.b to an inoperable DG.
There is an increased risk associated with entering a MODE or other specified condition in the Applicability with an inoperable DG and the provisions of LCO 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.
The ACTIONS are modified by a Note which allows entry into associated Conditions and Required Actions to be delayed for up to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> when an OPERABLE diesel generator is placed in an inoperable status for the alignment of diesel generator E to or from the Class 1E distribution system. Use of this allowance requires both offsite circuits to be OPERABLE. Entry into the appropriate Conditions and Required Actions shall be made immediately upon the determination that substitution of a required diesel generator will not or can not be completed.
A.1 To ensure a highly reliable power source remains with one offsite circuit inoperable, it is necessary to verify the availability of the remaining required offsite circuit on a more frequent basis. Since the Required Action only specifies "perform," a failure of SR 3.8.1.1 acceptance criteria does not result in a Required Action not met.
However, if a second required circuit fails SR 3.8.1.1, the second offsite circuit is inoperable, and Condition C, for two offsite circuits inoperable, is entered.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.8-6 Revision 3
PPL Rev. 6 AC Sources - Operating B 3.8.1 BASES ACTIONS A.2 (continued)
Required Action A.2, which only applies if one 4.16 kV ESS bus cannot be powered from any offsite source, is intended to provide assurance that an event with a coincident single failure of the associated DG does not result in a complete loss of safety function of critical systems. These features (e.g., system, subsystem, division, component, or device) are designed to be powered from redundant safety related 4.16 kV ESS buses. Redundanf required features failures consist of inoperable features associated with an emergency bus redundant to the emergency bus that has no offsite power. The Completion Time for Required Action A.2 is intended to allow time for the operator to evaluate and repair any discovered inoperabilities.
This Completion Time also allows an exception to the normal "time zero" for beginning the allowed outage time "clock." In this Required Action, the Completion Time only begins on discovery that both:
- a. A 4.16 kV ESS bus has no offsite power supplying its loads; and
- b. A redundant required feature on another 4.16 kV ESS bus is inoperable.
If, at any time during the existence of this Condition (one offsite circuit inoperable) a required feature subsequently becomes inoperable, this Completion Time would begin to be tracked.
Discovering no offsite power to one 4.16 kV ESS bus on the onsite Class 1 E Power Distribution System coincident with one or more inoperable required support or supported features, or both, that are associated with any other emergency bus that has offsite power, results in starting the Completion Times for the Required Action. Twenty-four hours is acceptable because it minimizes risk while allowing time for restoration before the unit is subjected to transients associated with shutdown.
The remaining OPERABLE offsite circuits and DGs are adequate to supply electrical power to the onsite Class 1E Distribution System. Thus, on a component basis, single failure protection may have been lost for the required feature's function; however, function is not lost. The 24 (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.8-7 Revision 2
PPL Rev. 6 AC Sources - Operating B 3.8.1 BASES ACTIONS A.2 (continued) hour Completion Time takes into account the component OPERABILITY of the redundant counterpart to the inoperable required feature. Additionally, the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.
A.3 According to Regulatory Guide 1.93 (Ref. 7), operation may continue in Condition A for a period that should not exceed 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. With one offsite circuit inoperable, the reliability of the offsite system is degraded, and the potential for a loss of offsite power is increased, with attendant potential for a challenge to the plant safety systems. In this condition, however, the remaining OPERABLE offsite circuit and DGs are adequate to supply electrical power to the onsite Class 1 E Distribution System.
The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time takes into account the capacity and capability of the remaining AC sources, reasonable time for repairs, and the low probability of a DBA occurring during this period.
The second Completion Time for Required Action A.2 establishes a limit on the maximum time allowed for any combination of required AC power sources to be inoperable during any single contiguous occurrence of failing to meet the LCO. If Condition A is entered while, for instance, a DG is inoperable, and that DG is subsequently returned OPERABLE, the LCO may already have been not met for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. This situation could lead to a total of 144 hours0.00167 days <br />0.04 hours <br />2.380952e-4 weeks <br />5.4792e-5 months <br />, since initial failure to meet the LCO, to restore the offsite circuit. At this time, a DG could again become inoperable, the circuit restored OPERABLE, and an additional 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> (for a total of 9 days) allowed prior to complete restoration of the LCO. The 6 day Completion Time provides a limit on the time allowed in a specified condition after discovery of failure to meet the LCO. This limit is considered reasonable for situations in which Conditions A and B are entered concurrently.
The "AND" connector between the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and 6 day Completion Times means that both (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.8-8 Revision 2
PPL Rev. 6 AC Sources - Operating B 3.8.1 BASES ACTIONS A.3 (continued)
Completion Times apply simultaneously, and the more restrictive Completion Time must be met.
As in Required Action A.2, the Completion Time allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." This exception results in establishing the "time zero" at the time the LCO was initially not met, instead of at the time that Condition A was entered.
B.1 To ensure a highly reliable power source remains with one required DG inoperable, it is necessary to verify the availability of the required offsite circuits on a more frequent basis. Since the Required Action only specifies "perform," a failure of SR 3.8.1.1 acceptance criteria does not result in a Required Action being not met. However, if a circuit fails to pass SR 3.8.1.1, it is inoperable. Upon offsite circuit inoperability, additional Conditions must then be entered.
B.2 Required Action B.2 is intended to provide assurance that a loss of offsite power, during the period that a DG is inoperable, does not result in a complete loss of safety function of critical systems. These features are designed with redundant safety related divisions (i.e.,
single division systems are not included). Redundant required features failures consist of inoperable features associated with a division redundant to the division that has an inoperable DG.
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." In this Required Action the Completion (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.8-9 Revision 4
PPL Rev. 6 AC Sources - Operating B 3.8.1 BASES ACTIONS B.2 (continued)
Time only begins on discovery that both:
- a. An inoperable DG exists; and
- b. A required feature powered from another diesel generator (Division 1 or 2) is inoperable.
If, at any time during the existence of this Condition (one required DG inoperable), a required feature subsequently becomes inoperable, this Completion Time begins to be tracked.
Discovering one required DG inoperable coincident with one or more inoperable required support or supported features, or both, that are associated with the OPERABLE DGs results in starting the Completion Time for the Required Action. Four hours from the discovery of these events existing concurrently is acceptable because it minimizes risk while allowing time for restoration before subjecting the unit to transients associated with shutdown.
The remaining OPERABLE DGs and offsite circuits are adequate to supply electrical power to the onsite Class 1 E Distribution System.
Thus, on a component basis, single failure protection for the required feature's function may have been lost; however, function has not been lost. The 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Completion Time takes into account the component OPERABILITY of the redundant counterpart to the inoperable required feature. Additionally, the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Completion Time takes into account the capacity and capability of the remaining AC sources, reasonable time for repairs, and low probability of a DBA occurring during this period.
B.3.1 and B.3.2 Required Action B.3.1 provides an allowance to avoid unnecessary testing of OPERABLE DGs. If it can be determined that the cause of the inoperable DG does not exist on the OPERABLE DG, SR 3.8.1.7 does not have to be performed. If the cause of inoperability exists on other DG(s), they are declared inoperable upon discovery, and Condition E of LCO 3.8.1 is entered. Once the failure is repaired, and the common cause failure no longer exists, Required Action B.3.1 is satisfied. If the cause of the initial inoperable DG cannot be determined not to exist on the remaining DG(s), performance of SR 3.8.1.7 suffices to provide assurance of continued OPERABILITY of those DGs.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.8-10 Revision 3
PPL Rev. 6 AC Sources - Operating B 3.8.1 BASES ACTIONS B.3.1 and B.3.2 (continued)
However, the second Completion Time for Required Action B.3.2 allows a performance of SR 3.8.1.7 completed up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to entering Condition B to be accepted as demonstration that a DG is not inoperable due to a common cause failure.
In the event the inoperable DG is restored to OPERABLE status prior to completing either B.3.1 or B.3.2, the plant corrective action program will continue to evaluate the common cause possibility. This continued evaluation, however, is no longer under the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> constraint imposed while in Condition B.
According to Generic Letter 84-15 (Ref. 8), 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is a reasonable time to confirm that the OPERABLE DGs are not affected by the same problem as the inoperable DG.
B.4 According to Regulatory Guide 1.93 (Ref. 7), operation may continue in Condition B for a period that should not exceed 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. In Condition B, the remaining OPERABLE DGs and offsite circuits are adequate to supply electrical power to the onsite Class 1 E Distribution System. The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time takes into account the capacity and capability of the remaining AC sources, reasonable time for repairs, and low probability of a DBA occurring during this period.
The second Completion Time for Required Action B.4 establishes a limit on the maximum time allowed for any combination of required AC power sources to be inoperable during any single contiguous occurrence of failing to meet the LCO. If Condition B is entered while, for instance, an offsite circuit is inoperable and that circuit is subsequently restored OPERABLE, the LCO may already have been not met for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. This situation could lead to a total of 144 hours0.00167 days <br />0.04 hours <br />2.380952e-4 weeks <br />5.4792e-5 months <br />, since initial failure of the LCO, to restore the DG. At this time, an offsite circuit could again become inoperable, the DG restored OPERABLE, and an additional 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> (for a total of 9 days) allowed prior to complete restoration of the LCO. The 6 day Completion Time provides a limit on the time allowed in a specified (continued)
SUSQUEHANNA -UNIT 1 TS / B 3.8-11 Revision 2
PPL Rev. 6 AC Sources - Operating B 3.8.1 BASES ACTIONS B.4 (continued) condition after discovery of failure to meet the LCO. This limit is considered reasonable for situations in which Conditions A and B are entered concurrently. The "AND" connector between the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and 6 day Completion Times means that both Completion Times apply simultaneously, and the more restrictive must be met.
As in Required Action B.2, the Completion Time allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." This exception results in establishing the "time zero" at the time that the LCO was initially not met, instead of the time that Condition B was entered.
C.1 Required Action C.1 addresses actions to be taken in the event of concurrent inoperability of two offsite circuits. The Completion Time for Required Action C.1 is intended to allow the operator time to evaluate and repair any discovered inoperabilities.
According to Regulatory Guide 1.93 (Ref. 7), operation may continue in Condition C for a period that should not exceed 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. This level of degradation means that the offsite electrical power system does not have the capability to effect a safe shutdown and to mitigate the effects of an accident; however, the onsite AC sources have not been degraded. This level of degradation generally corresponds to a total loss of the immediately accessible offsite power sources.
Because of the normally high availability of the offsite sources, this level of degradation may appear to be more severe than other combinations of two AC sources inoperable that involve one or more DGs inoperable. However, two factors tend to decrease the severity of this degradation level:
- a. The configuration of the redundant AC electrical power system that remains available is not susceptible to a single bus or switching failure; and (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.8-12 Revision 2
PPL Rev. 6 AC Sources - Operating B 3.8.1 BASES ACTIONS C.1 (continued)
- b. The time required to detect and restore an unavailable offsite power source is generally much less than that required to detect and restore an unavailable onsite AC source.
With both of the required offsite circuits inoperable, sufficient onsite AC sources are available to maintain the unit in a safe shutdown condition in the event of a DBA or transient. In fact, a simultaneous loss of offsite AC sources, a LOCA, and a worst case single failure were postulated as a part of the design basis in the safety analysis.
Thus, the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Completion Time provides a period of time to effect restoration of one of the offsite circuits commensurate with the importance of maintaining an AC electrical power system capable of meeting its design criteria. According to Regulatory Guide 1.93 (Ref. 7), with the available offsite AC sources two less than required by the LCO, operation may continue for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. If two offsite sources are restored within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, unrestricted operation may continue. If only one offsite source is restored within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, power operation continues in accordance with Condition A.
D.1 and D.2 Pursuant to LCO 3.0.6, the Distribution System Actions would not be entered even if all AC sources to it were inoperable, resulting in de-energization. Therefore, the Required Actions of Condition D are modified by a Note to indicate that when Condition D is entered with no AC source to any ESS bus, Actions for LCO 3.8.7, "Distribution Systems-Operating," must be immediately entered. This allows Condition D to provide requirements for the loss of the offsite circuit and one DG without regard to whether a division is de-energized. LCO 3.8.7 provides the appropriate restrictions for a de-energized bus.
According to Regulatory Guide 1.93 (Ref. 7), operation may continue in Condition D for a period that should not exceed 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. In Condition D, individual redundancy is lost in both the offsite electrical power system and the onsite AC electrical power system. Since power system redundancy is provided by two diverse sources of power, however, the (continued)
SUSQUEHANNA - UNIT 1 TS / B] 3.8-13 Revision 2
PPL Rev. 6 AC Sources - Operating B 3.8.1 BASES ACTIONS D.1 and D.2 (continued) reliability of the power systems in this Condition may appear higher than that in Condition C (loss of both required offsite circuits). This difference in reliability is offset by the susceptibility of this power system configuration to a single bus or switching failure. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
Completion Time takes into account the capacity and capability of the remaining AC sources, reasonable time for repairs, and the low probability of a DBA occurring during this period.
E.1 With two or more DGs inoperable and an assumed loss of offsite electrical power, insufficient standby AC sources are available to power the minimum required ESF functions. Since the offsite electrical power system is the only source of AC power for the majority of ESF equipment at this level of degradation, the risk associated with continued operation for a very short time could be less than that associated with an immediate controlled shutdown. (The immediate shutdown could cause grid instability, which could result in a total loss of AC power.) Since any inadvertent unit generator trip could also result in a total loss of offsite AC power, however, the time allowed for continued operation is severely restricted. The intent here is to avoid the risk associated with an immediate controlled shutdown and to minimize the risk associated with this level of degradation.
According to Regulatory Guide 1.93 (Ref. 7), with two or more DGs inoperable, operation may continue for a period that should not exceed 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> F.1 and F.2 If the inoperable AC electrical power sources cannot be restored to OPERABLE status within the associated Completion Time, the unit must be brought to a MODE in which the LCO does not apply. To achieve this status, the unit must be brought to at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and to MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.8-14 Revision 2
PPL Rev. 6 AC Sources - Operating B 3.8.1 BASES ACTIONS G. 1 (continued)
Condition G corresponds to a level of degradation in which all redundancy in the AC electrical power supplies has been lost. At this severely degraded level, any further losses in the AC electrical power system will cause a loss of function. Therefore, no additional time is justified for continued operation. The unit is required by LCO 3.0.3 to commence a controlled shutdown.
SURVEILLANCE The AC sources are designed to permit inspection and testing of all REQUIREMENTS important areas and features, especially those that have a standby function, in accordance with 10 CFR 50, GDC 18 (Ref. 9). Periodic component tests are supplemented by extensive functional tests during refueling outages (under simulated accident conditions). The SRs for demonstrating the OPERABILITY of the DGs are in accordance with the recommendations of Regulatory Guide 1.9 (Ref. 3), and Regulatory Guide 1.137 (Ref. 11), as addressed in the FSAR.
The Safety Analysis for Unit 2 assumes the OPERABILITY of some equipment that receives power from Unit 1 AC Sources. Therefore, Surveillance requirements are established for the Unit 1 onsite Class 1E AC electrical power distribution subsystem(s) required to support Unit 2 by LCO 3.8.7, Distribution Systems-Operating. The Unit 1 SRs required to support Unit 2 are identified in the Unit 2 Technical Specifications.
Where the SRs discussed herein specify voltage and frequency tolerances, the following summary is applicable. The minimum steady state output voltage of 3793 V is the value assumed in the degraded voltage analysis and is approximately 90% of the nominal 4160 V output voltage. This value allows for voltage drop to the terminals of 4000 V motors whose minimum operating voltage is specified as 90% or 3600 V. It also allows for voltage drops to motors and other equipment down through the 120 V level where minimum operating voltage is also usually specified as 90% of name plate rating. The specified maximum steady state output voltage of 4400 V is equal to the (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.8-15 Revision 2
PPL Rev. 6 AC Sources - Operating B 3.8.1 BASES SURVEILLANCE maximum operating voltage specified for 4000 V motors. It ensures REQUIREMENTS that for a lightly loaded distribution system, the voltage at the terminals (continued) of 4000 V motors is no more than the maximum rated operating voltages. The specified minimum and maximum frequencies of the DG are 58.8 Hz and 61.2 Hz, respectively. These values are equal to
+ 2% of the 60 Hz nominal frequency and are derived from the recommendations found in Regulatory Guide 1.9 (Ref. 3). The lower frequency limit is necessary to support the LOCA analysis assumptions for low pressure ECCS pump flow rates. (Reference 12)
The Surveillance Table has been modified by a Note, to clarify the testing requirements associated with DG E. The Note is necessary to define the intent of the Surveillance Requirements associated with the integration of DG E. Specifically, the Note defines that a DG is only considered OPERABLE and required when it is aligned to the Class 1 E distribution system. For example, if DG A does not meet the requirements of a specific SR, but DG E is substituted for DG A and aligned to the Class 1E distribution system, DG E is required to be OPERABLE to satisfy the LCO requirement of 4 DGs and DG A is not required to be OPERABLE because it is not aligned to the Class 1 E distribution system. This is acceptable because only 4 DGs are assumed in the event analysis. Furthermore, the Note identifies when the Surveillance Requirements, as modified by SR Notes, have been met and performed, DG E can be substituted for any other DG and declared OPERABLE after performance of two SRs which verify switch alignment. This is acceptable because the testing regimen defined in the Surveillance Requirement Table ensures DG E is fully capable of performing all DG requirements.
SR 3.8.1.1 This SR ensures proper circuit continuity for the offsite AC electrical power supply to the onsite distribution network and availability of offsite AC electrical power. The breaker alignment verifies that each breaker is in its correct position to ensure that distribution buses and loads are connected to an Operable offsite power source and that appropriate independence of offsite circuits is maintained. The 7 day Frequency is adequate since breaker position is not likely to change without the operator being aware of it and because its status is displayed in the control room.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.8-16 Revision 2
PPL Rev. 6 AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.2 REQUIREMENTS (continued) Not Used.
SR 3.8.1.3 This Surveillance verifies that the DGs are capable of synchronizing and accepting greater than or equal to the equivalent of the maximum expected accident loads. A minimum run time of 60 minutes is required to stabilize engine temperatures, while minimizing the time that the DG is connected to the offsite source.
Although no power factor requirements are established by this SR, the DG is normally operated at a power factor between 0.8 lagging and 1.0. The 0.8 value is the design rating of the machine, while 1.0 is an operational limitation to ensure circulating currents are minimized. The load band is provided to avoid routine overloading of the DG. Routine overloading may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY.
Note 1 modifies this Surveillance to indicate that diesel engine runs for this Surveillance may include gradual loading, as recommended by the Cooper Bessemer Service Bulletin 728, so that mechanical stress and wear on the diesel engine are minimized.
Note 2 modifies this Surveillance by stating that momentary transients because of changing bus loads do not invalidate this test. Similarly, momentary power factor transients do not invalidate the test.
Note 3 indicates that this Surveillance should be conducted on only one DG at a time in order to avoid common cause failures that might result from offsite circuit or grid perturbations.
Note 4 stipulates a prerequisite requirement for performance of this SR. A successful DG start must precede this test to credit satisfactory performance.
Note 5 provides the allowance that DG E, when not aligned as substitute for DG A, B, C and D but being maintained available, (continued)
SUSQUEHANNA - UNIT 1 TS-/ B 3.8-17 Revision 2
PPL Rev. 6 AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.3 REQUIREMENTS (continued) may use the test facility to satisfy loading requirements in lieu of synchronization with an ESS bus.
Note 6 allows a single test (instead of two. tests, one for each unit) to satisfy the requirements for both units, with the DG synchronized to the 4.16 kV ESS bus of Unit .1 for one periodic test and synchronized to the 4.16 kV ESS bus of Unit 2 during the next periodic test. This is acceptable because the purpose of the test is to demonstrate the ability of the DG to operate at its continuous rating (with the exception of DG E which is only required to be tested at the continuous rating of DGs A through D) and this attribute is tested at the required Frequency. Each unit's circuit breakers and breaker control circuitry, which are only being tested every second test (due to the staggering of the tests), historically have a very low failure rate. If a DG fails this Surveillance, the DG should be considered inoperable for both units, unless the cause of the failure can be directly related to only one unit.
In addition, if the test is scheduled to be performed on the other Unit, and the other Unit's TS allowance that provides an exception to performing the test is used (i.e., the Note to SR 3.8.2.1 for the other Unit provides an exception to performing this test when the other Unit is in MODE 4 or 5, or moving irradiated fuel assemblies in the secondary containment), or it is not possible to perform the test due to equipment availabililty, then the test shall be performed synchronized to this Unit's 4.16 kV ESS bus. The 31 day Frequency for this Surveillance is consistent with Regulatory Guide 1.9 (Ref. 3).
SR 3.8.1.4 This SR verifies the level of fuel oil in the engine mounted day tank is at or above the level at which fuel oil is automatically added. The level is expressed as an equivalent volume in gallons, and is selected to ensure adequate fuel oil for a minimum of 55 minutes of DG A-D and 62 minutes of DG E operation at DG continuous rated load conditions.
The 31 day Frequency is adequate to ensure that a sufficient supply of fuel oil is available, since low level alarms are provided and operators would be aware of any large uses of fuel oil during this period.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.8-18 Revision 3
PPL Rev. 6 AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.5 REQUIREMENTS (continued) Microbiological fouling is a major cause of fuel oil degradation. There are numerous bacteria that can grow in fuel oil and cause fouling, but all must have a water environment in order to survive. Removal of water from the engine mounted day tanks once every 31 days eliminates the necessary environment for bacterial survival. This is the most effective means of controlling microbiological fouling. In addition, it eliminates the potential for water entrainment in the fuel oil during DG operation. Water may come from any of several sources, including condensation, ground water, rain water, contaminated fuel oil, and breakdown of the fuel oil by bacteria. Frequent checking for and removal of accumulated water minimizes fouling and provides data regarding the watertight integrity of the fuel oil system. The Surveillance Frequencies are established by Regulatory Guide 1.137 (Ref. 11). This SR is for preventive maintenance. The presence of water does not necessarily represent a failure of this SR provided that accumulated water is removed during performance of this Surveillance.
SR 3.8.1.6 This Surveillance demonstrates that each required fuel oil transfer pump operates and transfers fuel oil from its associated storage tank to its associated day tank. It is required to support continuous operation of standby power sources. This Surveillance provides assurance that the fuel oil transfer pump is OPERABLE, the fuel oil piping system is intact, the fuel delivery piping is not obstructed, and the controls and control systems for automatic fuel transfer systems are OPERABLE.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.8-19 Revision 2
PPL Rev. 6 AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.6 (continued)
REQUIREMENTS The Frequency for this SR is 31 days because the design of the fuel transfer system requires that the transfer pumps operate automatically.
Administrative controls ensure an adequate volume of fuel oil in the day tanks. This Frequency allows this aspect of DG Operability to be demonstrated during or following routine DG operation.
SR 3.8.1.7 This SR helps to ensure the availability of the standby electrical power supply to mitigate DBAs and transients and maintain the unit in a safe shutdown condition.
To minimize the wear on moving parts that do not get lubricated when the engine is not running, this SR has been modified by Note 1 to indicate that all DG starts for these Surveillances may be preceded by an engine prelube period (which for DGs A through D includes operation of the lube oil system to ensure the DGs turbo charger is sufficiently prelubicated to prevent undo wear and tear).
For the purposes of this testing, the DGs are started from standby conditions. Standby conditions for a DG mean that the diesel engine oil is being continuously circulated and diesel engine coolant is being circulated as necessary to maintain temperature consistent with manufacturer recommendations. The DG starts from standby conditions and achieves the minimum required voltage and frequency within 10 seconds and maintains the required voltage and frequency when steady state conditions are reached. The 10 second start requirement supports the assumptions in the design basis LOCA analysis of FSAR, Section 6.3 (Ref. 12).
To minimize testing of the DGs, Note 2 allows a single test to satisfy the requirements for both units (instead of two tests, one for each unit).
This is acceptable because this test is intended to demonstrate attributes of the DG that are not associated with either Unit. If the DG fails this Surveillance, the DG should be considered inoperable for both (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.8-20 Revision 2
PPL Rev. 6 AC Sources - Operating B 3.8.1 BASES REQUIREMENTS SR 3.8.17 (continued)
SURVEILLANCE units, unless the cause of the failure can be directly related to one unit The time for the DG to reach steady state operation is periodically monitored and the trend evaluated to identify degradation.
The 31 day Frequency is consistent with Regulatory Guide 1.9 (Ref. 3). This Frequency provides adequate assurance of DG OPERABILITY.
SR 3.8.1.8 Transfer of each 4.16 kV ESS bus power supply from the normal offsite circuit to the alternate offsite circuit demonstrates the OPERABILITY of the alternate circuit distribution network to power the shutdown loads. The 24 month Frequency of the Surveillance is based on engineering judgment taking into consideration the plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths. Operating experience has shown that these components usually pass the SR when performed on the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
This SR is modified by a Note. The reason for the Note is that, during operation with the reactor critical, performance of the automatic transfer of the unit power supply could cause perturbations to the electrical distribution systems that could challenge continued steady state operation and, as a result, plant safety systems. The manual transfer of unit power supply should not result in any perturbation to the electrical distribution system, therefore, no mode restriction is specified.
This Surveillance tests the applicable logic associated with Unit 1. The comparable test specified in Unit 2 Technical Specifications tests the applicable logic associated with Unit 2. Consequently, a test must be performed within the specified Frequency for each unit. As the Surveillance represents separate tests, the Note specifying the restriction for not performing the test while the unit is in MODE 1 or 2 does not have applicability to Unit 2. The NOTE (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.8-21 Revision 2
PPL Rev. 6 AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.8 (continued)
REQUIREMENTS only applies to Unit 1, thus the Unit 1 Surveillance shall not be performed with Unit 1 in MODE 1 or 2.
SR 3.8.1.9 Each DG is provided with an engine overspeed trip to prevent damage to the engine. Recovery from the transient caused by the loss of a large load could cause diesel engine overspeed, which, if excessive, might result in a trip of the engine. This Surveillance demonstrates the DG load response characteristics and capability to reject the largest single load without exceeding predetermined voltage and frequency and while maintaining a specified margin to the overspeed trip. The largest single load for each DG is a residual heat removal (RHR) pump (1425 kW). This Surveillance may be accomplished by:
- a. Tripping the DG output breaker with the DG carrying greater than or equal to its associated single largest post-accident load while paralleled to offsite power, or while solely supplying the bus; or
- b. Tripping its associated single largest post-accident load with the DG solely supplying the bus.
As recommended by Regulatory Guide 1.9 (Ref. 3), the load rejection test is acceptable if the increase in diesel speed does not exceed 75%
of the difference between synchronous speed and the overspeed trip setpoint, or 15% above synchronous speed, whichever is lower. For DGs A, B, C, D and E, this represents 64.5 Hz, equivalent to 75% of the difference between nominal speed and the overspeed trip setpoint.
The time, voltage, and frequency tolerances specified in this SR are derived from Regulatory Guide 1.9 (Ref. 3) recommendations for response during load sequence intervals. The 4.5 seconds specified is equal to 60% of the 7.5 second load sequence interval between loading of the RHR and core spray pumps during an undervoltage on the bus concurrent with a LOCA. The 6 seconds specified is equal to 80% of that load sequence interval. The voltage and frequency specified are (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.8-22 Revision 3
PPL Rev. 6 AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.9 (continued)
REQUIREMENTS consistent with the design range of the equipment powered by the DG.
SR 3.8.1.9.a corresponds to the maximum frequency excursion, while SR 3.8.1.9.b and SR 3.8.1.9.c specify the steady state voltage and frequency values to which the system must recover following load rejection.
The 24 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3) and is intended to be consistent with expected fuel cycle lengths.
To minimize testing of the DGs, a Note allows a single test to satisfy the requirements for both units (instead of two tests, one for each unit). This is acceptable because this test is intended to demonstrate attributes of the DG that are not associated with either Unit. If the DG fails this Surveillance, the DG should be considered inoperable for both units, unless the cause of the failure can be directly related to only one unit.
SR 3.8.1.10 This Surveillance demonstrates the DG capability to reject a full load without overspeed tripping or exceeding the predetermined voltage limits. The DG full load rejection may occur because of a system fault or inadvertent breaker tripping. This Surveillance ensures proper engine generator load response under the simulated test conditions.
This test simulates the loss of the total connected load that the DG experiences following a full load rejection and verifies that the DG does not trip upon loss of the load. These acceptance criteria provide DG damage protection. While the DG is not expected to experience this transient during an event, and continues to be available, this response ensures that the DG is not degraded for future application, including reconnection to the bus if the trip initiator can be corrected or isolated.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.8-23 Revision 3
PPL Rev. 6 AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.10 (continued)
REQUIREMENTS To minimize testing of the DGs, a Note allows a single test to satisfy the requirements for both units (instead of two tests, one for each unit). This is acceptable because this test is intended to demonstrate attributes of the DG that are not associated with either Unit. If the DG fails this Surveillance, the DG should be considered inoperable for both units, unless the cause of the failure can be directly related to only one unit.
The 24 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3) and is intended to be consistent with expected fuel cycle lengths.
SR 3.8.1.11 As required by Regulatory Guide 1.9 (Ref. 3), this Surveillance demonstrates the as designed operation of the standby power sources during loss of the offsite source. This test verifies all actions encountered from the loss of offsite power, including shedding of the nonessential loads and energization of the ESS buses and respective 4.16kV loads from the DG. It further demonstrates the capability of the DG to automatically achieve and maintain the required voltage and frequency within the specified time.
The DG auto-start time of 10 seconds is derived from requirements of the licensed accident analysis for responding to a design basis large break LOCA. The Surveillance should be continued for a minimum of 5 minutes in order to demonstrate that all starting transients have decayed and stability has been achieved.
The 24 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3), takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.8-24 Revision 2
PPL Rev. 6 AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.11 (continued)
REQUIREMENTS This SR is modified by three Notes. The reason for Note 1 is to minimize wear and tear on the DGs during testing. Note 1 allows all DG starts to be preceded by an engine prelube period (which for DGs A through D includes operation of the lube oil system to ensure the DG's turbo charger is sufficiently prelubicated). For the purpose of this testing, the DGs shall be started from standby conditions that is, with the engine oil being continuously circulated and engine coolant being circulated as necessary to maintain temperature consistent with manufacturer recommendations.
This SR is also modified by Note 2. The Note specifies when this SR is required to be performed for the DGs and the 4.16 kV ESS Buses.
The Note is necessary because this SR involves an integrated test between the DGs and the 4.16 kV ESS Buses and the need for the testing regimen to include DG E being tested (substituted for all DGs for both Units) with all 4.16 kV ESS Buses. To ensure the necessary testing is performed, the following rotational testing regimen has been established:
UNIT IN OUTAGE DIESEL E SUBSTITUTED FOR 2 DG E not tested 1 Diesel Generator D 2 Diesel Generator A 1 DG E not tested 2 Diesel Generator B 1 Diesel Generator A 2 Diesel Generator C 1 Diesel Generator B 2 Diesel Generator D 1 Diesel Generator C The specified rotational testing regimen can be altered to facilitate unanticipated events which render the testing regimen impractical to implement, but any alternative (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.8-25 Revision 2
PPL Rev. 6 AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.11 (continued)
REQUIREMENTS testing regimen must provide an equivalent level of testing. This SR does not have to be performed with the normally aligned DG when the associated 4.16 kV ESS bus is tested using DG E and DG E does not need to be tested when not substituted or aligned to the Class 1E distribution system. The allowances specified in the Note are acceptable because the tested attributes of each of the five DGs and each unit's four 4.16 kV ESS buses are verified at the specified Frequency (i.e., each DG and each 4.16 kV ESS bus is tested every 24 months). Specifically, when DG E is tested with a Unit 1 4.16 kV ESS bus, the attributes of the normally aligned DG, although not tested with the Unit 1 4.16 kV ESS bus, are tested with the Unit 2 4.16 kV ESS bus within the 24 month Frequency. The testing allowances do result in some circuit pathways which do not need to change state (i.e., cabling) not being tested on a 24 month Frequency. This is acceptable because these components are not required to change state to perform their safety function and when substituted--normal operation of DG E will ensure continuity of most of the cabling not tested.
The reason for Note 3 is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems. This Surveillance tests the applicable logic associated with Unit 1. The comparable test specified in the Unit 2 Technical Specifications tests the applicable logic associated with Unit 2. Consequently, a test must be performed within the specified Frequency for each unit. As the Surveillance represents separate tests, the Note specifying the restriction for not performing the test while the unit is in MODE 1, 2, or 3 does not have applicability to Unit 2. The Note only applies to Unit 1, thus the Unit 1 Surveillances shall not be performed with Unit 1 in MODES 1, 2 or 3.
SR 3.8.1.12 This Surveillance demonstrates that the DG automatically starts and achieves the required voltage and frequency within the specified time (10 seconds) from the design basis actuation signal (LOCA signal) and operates for _ 5 minutes. The 5 minute period provides sufficient time to demonstrate (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.8-26 Revision 2
PPL Rev. 6 AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.12 (continued)
REQUIREMENTS stability. SR 3.8.1.12.d and SR 3.8.1.12.e ensure that permanently connected loads and emergency loads are energized from the offsite electrical power system on a LOCA signal without loss of offsite power.
The requirement to verify the connection and power supply of permanent and autoconnected loads is intended to satisfactorily show the relationship of these loads to the loading logic for loading onto offsite power. In certain circumstances, many of these loads cannot actually be connected or loaded without undue hardship or potential for undesired operation. For instance, ECCS injection valves are not desired to be stroked open, high pressure injection systems are not capable of being operated at full flow, or RHR systems performing a decay heat removal function are not desired to be realigned to the ECCS mode of operation. In lieu of actual demonstration of the connection and loading of these loads, testing that adequately shows the capability of the DG system to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified. SR 3.8.1.12.a through SR 3.8.1.12.d are performed with the DG running. SR 3.8.1.12.e can be performed when the DG is not running.
The Frequency of 24 months takes into consideration plant conditions required to perform the Surveillance and is intended to be consistent with the expected fuel cycle lengths. Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency. Therefore, the Frequency is acceptable from a reliability standpoint.
This SR is modified by two Notes. The reason for Note 1 is to minimize wear and tear on the DGs during testing. Note 1 allows all DG starts to be preceded by an engine prelube period (which for DG A through D includes operation of the lube oil system to ensure the DG's turbo-charger is sufficiently prelubicated). For the purpose of this testing, the DGs must be started from standby conditions that is, with the engine oil being continuously circulated and engine coolant being circulated as necessary to maintain temperature consistent with manufacturer recommendations.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.8-27 Revision 2
PPL Rev. 6 AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.13 REQUIREMENTS (continued) The reason for Note 2 is to allow DG E, when not aligned as substitute for DG A, B, C or D to use the test facility to satisfy loading requirements in lieu of aligning with the Class 1 E distribution system.
When tested in this configuration, DG E satisfies the requirements of this test by completion of SR 3.8.1.12.a, b and c only. SR 3.8.1.12.d ind 3.8.1.12.e may be performed by any DG aligned with the Class 1E distribution system or by any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.
This Surveillance demonstrates that DG non-critical protective functions (e.g., high jacket water temperature) are bypassed on an ECCS initiation test signal. The non-critical trips are bypassed during DBAs and provide an alarm on an abnormal engine condition. This alarm provides the operator with sufficient time to react appropriately.
The DG availability to mitigate the DBA is more critical than protecting the engine against minor problems that are not immediately detrimental to emergency operation of the DG.
The 24 month Frequency is based on engineering judgment, takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.
Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
The SR is modified by two Notes. To minimize testing of the DGs, Note 1 to SR 3.8.1.13 allows a single test (instead of two tests, one for each unit) to satisfy the requirements for both units. This is acceptable because this test is intended to demonstrate attributes of the DG that are not associated with either Unit. If the DG fails this Surveillance, the DG should be considered inoperable for both units, unless the cause of the failure can be directly related to only one unit.
Note 2 provides the allowance that DG E, when not aligned as a substitute for DG A, B, C, and D but being maintained available, may use a simulated ECCS initiation signal.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.8-28 Revision 2
PPL Rev. 6 AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.14 REQUIREMENTS (continued) Regulatory Guide 1.9 (Ref. 3), requires demonstration once per 24 months that the DGs can start and run continuously at full load capability for an interval of not less than 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />s-22 hours of which is at a load equivalent to 90% to 100% of the continuous rating of the DG, and 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of which is at a load equivalent to 105% to 110% of the continuous duty rating of the DG. SSES has taken exception to this requirement and performs the two hour run at the 2000 hour0.0231 days <br />0.556 hours <br />0.00331 weeks <br />7.61e-4 months <br /> rating for each DG. The requirement to perform the two hour overload test can be performed in any order provided it is performed during a single continuous time period.
The DG starts for this Surveillance can be performed either from standby or hot conditions. The provisions for prelube discussed in SR 3.8.1.7, and for gradual loading, discussed in SR 3.8.1.3, are applicable to this SR.
A load band is provided to avoid routine overloading of the DG.
Routine overloading may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY.
The 24 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3), takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.
This Surveillance has been modified by four Notes. Note 1 states that momentary transients due to changing bus loads do not invalidate this test.
To minimize testing of the DGs, Note 2 allows a single test (instead of two tests, one for each unit) to satisfy the requirements for both units.
This is acceptable because this test is intended to demonstrate attributes of the DG that are not associated with either Unit. If the DG fails this Surveillance, the DG should be considered inoperable for both units, unless the cause of the failure can be directly related to only one unit.
Note 3 stipulates that DG E, when not aligned as substitute for DG A, B, C or D but being maintained available, may use (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.8-29 Revision 2
PPL Rev. 6 AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.14 (continued)
REQUIREMENTS the test facility to satisfy the specified loading requirements in lieu of synchronization with an ESS bus.
SR 3.8.1.15 This Surveillance demonstrates that the diesel engine can restart from a hot condition, such as subsequent to shutdown from full load temperatures, and achieve the required voltage and frequency within 10 seconds. The 10 second time is derived from the requirements of the accident analysis to respond to a design basis large break LOCA.
The 24 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3), takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.
This SR is modified by three Notes. Note 1 ensures that the test is performed with the diesel sufficiently hot. The requirement that the diesel has operated for at least 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> at full load conditions prior to performance of this Surveillance is based on manufacturer recommendations for achieving hot conditions. The load band is provided to avoid routine overloading of the DG. Routine overloads may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY.
Momentary transients due to changing bus loads do not invalidate this test.
Note 2 allows all DG starts to be preceded by an engine prelube period (which for DGs A through D includes operation of the lube oil system to ensure the DGs turbo charger is sufficiently prelubricated) to minimize wear and tear on the diesel during testing.
To minimize testing of the DGs, Note 3 allows a single test to satisfy the requirements for both units (instead of two tests, one for each unit). This is acceptable because this test is intended to demonstrate attributes of the DG that are not associated with either Unit. If the DG fails this Surveillance, the DG should be considered inoperable for both units, unless the cause of the failure can be directly related to' only one unit.
(continued)
SUSQUEHANNA-UNIT 1 TS / 8 3.8-30 Revision 2
PPL Rev. 6 AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.16 REQUIREMENTS (continued) As required by Regulatory Guide 1.9 (Ref. 3), this Surveillance ensures that the manual synchronization and automatic load transfer from the DG to the offsite source can be made and that the DG can be returned to ready-to-load status when offsite power is restored. It also ensures that the auto-start logic is reset to allow the DG to reload if a subsequent loss of offsite power occurs. The DG is considered to be in ready-to-load status when the DG is at rated speed and voltage, the DG controls are in isochronous and the output breaker is open.
The 24 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3), takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.
This SR is modified by a note to accommodate the testing regimen necessary for DG E. See SR 3.8.1.11 for the Bases of the Note.
SR 3.8.1.17 Demonstration of the test mode override ensures that the DG availability under accident conditions is not compromised as the result of testing. Interlocks to the LOCA sensing circuits cause the DG to automatically reset to ready-to-load operation if an ECCS initiation signal is received during operation in the test mode. Ready-to-load operation is defined as the DG running at rated speed and voltage, the DG controls in isochronous and the DG output breaker open. These provisions for automatic switchover are required by IEEE-308 (Ref. 10), paragraph 6.2.6(2).
The requirement to automatically energize the emergency loads with offsite power is essentially identical to that of SR 3.8.1.12. The intent in the requirements associated with SR 3.8.1.17.b is to show that the emergency loading is not affected by the DG operation in test mode. In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the emergency loads to perform these functions is acceptable. This test is performed by verifying that after the DG is tripped, the offsite source originally in parallel with the DG, remains connected to the (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.8-31 Revision 2
PPL Rev. 6 AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.17 (continued)
REQUIREMENTS affected 4.16 kV ESS Bus. SR 3.8.1.12 is performed separately to verify the proper offsite loading sequence.
The 24 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3), takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.
This SR is modified by a note to accommodate the testing regimen necessary for DG E. See SR 3.8.1.11 for the Bases of the Note.
SR 3.8.1.18 Under accident conditions, loads are sequentially connected to the bus by individual load timers which control the permissive and starting signals to motor breakers to prevent overloading of the AC Sources due to high motor starting currents. The load sequence time interval tolerance ensures that sufficient time exists for the AC Source to restore frequency and voltage prior to applying the next load and that safety analysis assumptions regarding ESF equipment time delays are not violated. Reference 2 provides a summary of the automatic loading of ESS buses. A list of the required timers and the associated setpoints are included in the Bases as Table B 3.8.1-1, Unit 1 and Unit 2 Load Timers. Failure of a timer identified as an offsite power timer may result in both offsite sources being inoperable. Failure of any other timer may result in the associated DG being inoperable. A timer is considered failed for this SR if it will not ensure that the associated load will energize within the Allowable Value in Table B 3.8.1-1. These conditions will require entry into applicable Conditions of this specification. With a load timer inoperable, the load can be rendered inoperable to restore OPERABILITY to the associated AC sources. In this condition, the Condition and Required Actions of the associated specification shall be entered for the equipment rendered inoperable.
The 24 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3), takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.8-32 Revision 2
PPL Rev. 6 AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.18 (continued)
REQUIREMENTS This SR is modified by a Note that specifies that load timers associated with equipment that has automatic initiation capability disabled are not required to be Operable. This is acceptable because if the load does not start automatically, the adverse effects of an improper loading sequence are eliminated. Furthermore, load timers are associated with individual timers such that a single timer only affects a single load.
SR 3.8.1.19 In the event of a DBA coincident with a loss of offsite power, the DGs are required to supply the necessary power to ESF systems so that the fuel, RCS, and containment design limits are not exceeded.
This Surveillance demonstrates DG operation, as discussed in the Bases for SR 3.8.1.11, during a loss of offsite power actuation test signal in conjunction with an ECCS initiation signal. In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the DG system to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified. To simulate the non-LOCA unit 4.16 kV ESS Bus loads on the DG, bounding loads are energized on the tested 4.16 kV ESS Bus after all auto connected energizing loads are energized.
The Frequency of 24 months takes into consideration plant conditions required to perform the Surveillance and is intended to be consistent with an expected fuel cycle length. This SR is modified by three Notes. The reason for Note 1 is to minimize wear and tear on the DGs during testing. Note 1 allows all DG starts to be preceded by an engine prelube period (which for DGs A through D includes operation of the lube oil system to ensure the DG's turbo charger is sufficiently prelubricated.) For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine oil being continuously circulated and engine coolant being circulated as necessary to maintain temperature consistent with manufacturer recommendations.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.8-33 Revision 2
PPL Rev. 6 AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.19 (continued)
REQUIREMENTS Note 2 is necessary to accommodate the testing regimen associated with DG E. See SR 3.8.1.11 for the Bases of the Note.
The reason for Note 3 is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems. This Surveillance tests the applicable logic associated with Unit 1. The comparable test specified in the Unit 2 Technical Specifications tests the applicable logic associated with Unit 2. Consequently, a test must be performed within the specified Frequency for each unit. As the Surveillance represents separate tests, the Note specifying the restriction for not performing the test while the unit is in MODE 1, 2 or 3 does not have applicability to Unit 2. The Note only applies to Unit 1, thus the Unit 1 Surveillances shall not be performed with Unit 1 in MODE 1, 2 or 3.
SR 3.8.1.20 This Surveillance demonstrates that the DG starting independence has not been compromised. Also, this Surveillance demonstrates that each engine can achieve proper speed within the specified time when the DGs are started simultaneously. The 10 year Frequency is consistent with the recommendations of Regulatory Guide 1.9 (Ref. 3).
This SR is modified by two Notes. The reason for Note 1 is to minimize wear on the DG during testing. The Note allows all DG starts to be preceded by an engine prelube period (which for DGs A through D includes operation of the lube oil system to ensure the DG's turbo charger is sufficiently prelubricated). For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine oil continuously circulated and engine coolant being circulated as necessary to maintain temperature consistent with manufacturer recommendations.
Note 2 is necessary to identify that this test does not have to be performed with DG E substituted for any DG. The allowance is acceptable based on the design of the DG E transfer switches.
The transfer of control, protection, indication, (continued)
SUSQUEHANNA- UNIT 1 TS / B 3.8-34 Revision 2
PPL Rev. 6 AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.20 (continued)
REQUIREMENTS and alarms is by switches at two separate locations. These switches provide a double break between DG E and the redundant system within the transfer switch panel. The transfer of power is through circuit breakers at two separate locations for each redundant system. There are four normally empty switch gear positions at DG E facility, associated with each of the four existing DGs. Only one circuit breaker is available at this location to be inserted into one of the four positions.
At each of the existing DGs, there are two switchgear positions with only one circuit breaker available. This design provides two open circuits between redundant power sources. Therefore, based on the described design, it can be concluded that DG redundancy and independence is maintained regardless of whether DG E is substituted for any other DG.
REFERENCES 1. 10 CFR 50, Appendix A, GDC 17.
- 2. FSAR, Section 8.2.
- 4. FSAR, Chapter 6.
- 5. FSAR, Chapter 15.
- 6. Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 39132).
- 10. IEEE Standard 308.
- 12. FSAR, Section 6.3.
- 13. ASME Boiler and Pressure Vessel Code,Section XI.
(continued)
SUSQUEHANNA - UNIT 1 TS / B 3.8-35 Revision 2
PPL Rev. 6 AC Sources - Operating B 3.8.1 TABLE B 3.8.1-1 (page 1 of 2)
UNIT 1 AND UNIT 2 LOAD TIMERS NOMINAL DEVICE SETTING ALLOWABLE VALUE TAG NO. SYSTEM LOADING TIMER LOCATION (seconds) (seconds) 62A-20102 RHR Pump 1A 1A201 3 2.7 and _<3.6 62A-20202 RHR Pump I B 1A202 3 >2.7 and c 3.6 62A-20302 RHR Pump 1C 1A203 3 > 2.7 and* 3.6 62A-20402 RHR Pump 1D 1A204 3 > 2.7 and !53.6 62A-20102 RHR Pump 2A 2A201 3 Ž 2.7 and
- 3.6 62A-20202 RHR Pump 2B 2A202 3 > 2.7 and < 3.6 62A-20302 RHR Pump 2C 2A203 3 Ž 2.7 and _3.6 62A-20402 RHR Pump 2D 2A204 3 2.7 and 3.6 E11A-K202B RH R Pump 1C (Offsite Power Timer) 1C618 7.0 >6.5 and _7.5 E11A-K120A RHR Pump 1C (Offsite Power Timer) 1C617 7.0 > 6.5 and *7.5 E11A-K120B RHR Pump 1D (Offsite Power Timer) 1C618 7.0 Ž:6.5 and *7.5 E11A-K202A RHR Pump 1D (Offsite Power Timer) 1C617 7.0 >6.5 and*_< 7.5 E11A-K120A RHR Pump 2C (Offsite Power Timer) 2C617 7.0 2!6.5 and *<7.5 E11 A-K202B RHR Pump 2C (Offsite Power Timer) 2C618 7.0 > 6.5 and 5 7.5 El 1A-K120B RHR Pump 2D (Offsite Power Timer) 2C618 7.0 Ž_6.5 and < 7.5 E11A-K202A RHR Pump 2D (Offsite Power Timer) 2C617 7.0 Ž 6.5 and
- 7.5 E21A-K116A CS Pump 1A 1C626 10.5 _>9.4 and :5 11.6 E21A-K116B CS Pump 1B 1C627 10.5 >Ž9.4 and *511.6 E21A-K125A CS Pump 1C 1C626, 10.5 > 9.4 and _<11.6 E21A-K125B CS Pump 1D 1C627 10.5 >_9.4 and !_ 11.6 E21A-K116A CS Pump 2A 2C626 10.5 2!9.4and*5 11.6 E21A-K116B CS Pump 2B 2C627 10.5 > 9.4and!< 11.6 E21A-K125A CS Pump 2C 2C626 10.5 > 9.4 and
- 11.6 E21A-K125B CS Pump 2D 2C627 10.5 >9.4 and !5 11.6 E21A-K16A CS Pump 1A (Offsite Power Timer) 1C626 15 Ž14.0 and *16.0 E21A-K16B CS Pump 1B (Offsite Power Timer) 1C627 15 > 14.0 and* 16.0 E21A-K25A CS Pump 1C (Offsite Power Timer) 1C626 15 >14.0 and* 16.0 E21A-K25B CS Pump 1D (Offsite Power Timer) 1C627 15 Ž14.0 and *16.0 E21A-K16A CS Pump 2A (Offsite Power Timer) 2C626 15 _ 14.0 and < 16.0 E21A-K16B CS Pump 28 (Offsite Power Timer) 2C627 15 > 14.0 and _<16.0 E21A-K25A CS Pump 2C (Offsite Power Timer) 2C626 15 2! 14.0 and < 16.0 E21A-K25B CS Pump 2D (Offsite Power Timer) 2C627 15 Ž 14.0 and < 16.0 62AX2-201 08 Emergency Service Water 1A201 40 _ 36 and _ 44 62AX2-20208 Emergency Service Water 1A202 40 _36 and* 44 62AX2-20303 Emergency Service Water 1A203 44 >39.6 and _< 48.4 62AX2-20403 Emergency Service Water 1A204 48 _ 43.2 and < 52.8 62X3-20404 Control Structure Chilled Water System OC877B 60 > 54 62X3-20304 Control Structure Chilled Water System OC877A 60 _54 62X-20104 Emergency Switchgear Rm Cooler A & OC877A 60 54 RHR SW Pump H&V Fan A 62X-20204 Emergency Switchgear Rm Cooler B & OC877B 60 >_54 RHR SW Pump H&V Fan B 62X-5653A DG Room Exhaust Fan E3 OB565 60 _54 62X-5652A DG Room Exhausts Fan E4 OB565 60 > 54 262X-20204 Emergency Switchgear Rm Cooler B OC877B 120 _54 262X-20104 Emergency Switchgear Rm Cooler A OC877A 120 _54 (continued)
SUSQUEHANNA - UNIT 1 TS / B 3.8-36 Revision 2
PPL Rev. 6 AC Sources - Operating B 3.8.1 TABLE B 3.8.1-1 (page 2 of 2)
UNIT 1 AND UNIT 2 LOAD TIMERS NOMINAL DEVICE SETTING ALLOWABLE VALUE TAG NO. SYSTEM LOADING TIMER LOCATION (seconds) (seconds) 62X-546 DG Rm Exh Fan D OB546 120 > 54 62X-536 DG Rm Exh Fan C OB536 120 >Ž54 62X-526 DG Rm Exh Fan B OB526 120 >54 62X-516 DG Rm Exh Fan A OB516 120 Ž54 CRX-5652A DG Room Supply Fans El and E2 OB565 120 Ž54 62X2-2041 0 Control Structure Chilled Water System OC876B 180 _ 54 62X1l-20304 Control Structure Chilled Water System OC877A 180 > 54 62X2-2031 0 Control Structure Chilled Water System OC876A 180 > 54 62X1 -20404 Control Structure Chilled Water System OC877B 180 _54 62X2-20304 Control Structure Chilled Water System OC877A 210 > 54 62X2-20404 Control Structure Chilled Water System OC877B 210 > 54 62X-Kl 1BB Emergency Switchgear Rm Cooling 2CB250B 260 >54 Compressor B 62XK1 AB Emergency Switchgear Rm Cooling 2CB250A 260 Ž54 62X-K1__IAB Compressor A SUSQUEHANNA - UNIT 1 TS / B 3.8-37 Revision 2