ML19262D341

Technical Specifications Bases Manual

ML19262D341
Person / Time
Site:	Susquehanna
Issue date:	09/05/2019
From:	Susquehanna
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
Download: ML19262D341 (58)

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• MANUAL HARD COPY DISTRIBUTION DOCUMENT TRANSMITTAL 2019-13858 USER INFORMATION:

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TO: GERLACH*ROSEY M 09/05/2019 LOCATION: USNRC FROM: NUCLEAR RECORDS DOCUMENT CONTROL CENTER (NUCSA-2)

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

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~ORS.

ATI'ENTION: "REPLACE" directions do not affect the Table of Contents, Therefore no TOC will be issued with the updated material.

TSB2 - TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL REMOVE MANUAL TABLE OF CONTENTS DATE: 08/07/2019 ADD MANUAL TABLE OF CONTENTS DATE: 09/04/2019 CATEGORY: DOCUMENTS TYPE: TSB2

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• ID: TEXT 3.8.1 REMOVE: REV: 13 ADD: REV: 14 CATEGORY: DOCUMENTS TYPE: TSB2 ID: TEXT 3.8.7 ADD: REV: 7 REMOVE: REV:6 ANY DISCREPANCIES WITH THE MATERIAL PROVIDED, CONTACT DCS@ X3171 OR X3194 FOR ASSISTANCE. UPDATES FOR HARDCOPY MANUALS WILL BE DISTRIBUTED WITHIN 3 DAYS IN ACCORDANCE WITH DEPARTMENT PROCEDURES. PLEASE MAKE ALL CHANGES AND ACKNOWLEDGE COMPLETE IN YOUR NIMS INBOX UPON COMPLETION OF UPDATES. FOR ELECTRONIC MANUAL USERS, ELECTRONICALLY REVIEW THE APPROPRIATE DOCUMENTS AND ACKNOWLEDGE COMPLETE IN YOUR NIMS INBOX .

SSES MANUAL Manual Name: TSB2 Manual

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL Table Of Contents Issue Date: 09/04/2019 Procedure Name Rev Issue Date Change ID Change Number TEXT LOES 138 01/03/2019

Title:

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

Title:

TABLE OF CONTENTS TEXT 2.1.1 5 01/22/2015

Title:

SAFETY LIMITS (SLS) REACTOR CORE

Title:

REACTIVITY 11/16/2016 CONTROL ROD OPERABILITY TEXT 3 .1.4 5 11/16/2016

Title:

REACTIVITY CONTROL SYSTEMS CONTROL ROD SCRAM TIMES TEXT 3 .1.5 2 11/16/2016

Title:

REACTIVITY CONTROL SYSTEMS CONTROL ROD SCRAM ACCUMULATORS TEXT 3.1.6 4 11/16/2016

Title:

REACTIVITY CONTROL SYSTEMS ROD PATI'ERN CONTROL Page 1 of 8 Report Date: 09/05/19

SSES MANUAL Manual Name: TSB2 Manual

Title:

TECHNICAL SPECIFICATIONS BASES DNIT 2 MANUAL TEXT 3.1.7 4 11/16/2016

Title:

REACTIVITY CONTROL SYSTEMS STANDBY LIQUID CONTROL (SLC) SYSTEM TEXT 3 .1. 8 4 11/16/2016

Title:

REACTIVITY CONTROL SYSTEMS SCRAM DISCHARGE VOLUME (SDV) VENT AND DRAIN VALVES TEXT 3.2.1 5 11/16/2016

Title:

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

TEXT 3.2.2 4 11/16/2016

Title:

POWER DISTRIBUTION LIMITS MINIMUM CRITICAL POWER RATIO (MCPR)

TEXT 3.2.3 3 11/16/2016

Title:

POWER DISTRIBUTION LIMITS LINEAR HEAT GENERATION-RATE LHGR TEXT 3.3.1.1 6 11/16/2016

Title:

INSTRUMENTATION REACTOR PROTECTION SYSTEM (RPS) INSTRUMENTATION TEXT 3.3.1.2 4 01/23/2018

Title:

INSTRUMENTATION SOURCE RANGE MONITOR (SRM) INSTR'\)MENTATION TEXT 3.3.2.1 4 11/16/2016

Title:

INSTRUMENTATION CONTROL ROD BLOCK INSTRUMENTATION TEXT 3.3.2.2 3 11/16/2016

Title:

INSTRUMENTATION FEEDWATER - MAIN TURBINE HIGH WATER LEVEL TRIP INSTRUMENTATION TEXT 3.3.3.1 9 11/16/2016

Title:

INSTRUMENTATION POST ACCIDENT MONITORING (PAM) INSTRUMENTATION TEXT 3.3.3.2 2 11/16/2016

Title:

INSTRUMENTATION REMOTE SHUTDOWN SYSTEM TEXT 3.3.4.1 2 11/16/2016

Title:

INSTRUMENTATION END OF CYCLE RECIRCULATION PUMP TRIP (EOC-RPT) INSTRUMENTATION Page 2 of 8 Report Date: 09/05/19

SSES MANUAL Manual Name: TSB2 Manual

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL TEXT 3.3.4.2 1 11/16/2016

Title:

INSTRUMENTATION ANTICIPATED TRANSIENT WITHOUT SCRAM RECIRCULATION PDMP TRIP (ATWS-RPT) INSTRUMENTATION TEXT 3.3.5.1 7 03/05/2019

\

Title:

INSTRUMENTATION EMERGENCY CORE COOLING SYSTEM (ECCS) INSTRUMENTATION 2 . 03/05/2019 TEXT 3.3.5.2

Title:

REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL INSTRUMENTATION TEXT 3.3.5.3 0 03/05/2019

Title:

INSTRUMENTATION REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM INSTRUMENTATION (PREVIOUSLY TEXT 3.3.5.2 REVISION 1)

TEXT 3.3.6.1 9 03/05/2019

Title:

INSTRUMENTATION PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION

• TEXT 3.3.6.2 6 03/05/2019

Title:

INSTRUMENTATION SECONDARY CONTAINMENT ISOLATION TEXT 3.3.7.1 4 03/05/2019

,, INSTRUMENTATION

Title:

INSTRUMENTATION CONTROL ROOM EMERGENCY OUTSIDE AIR SUPPLY (CREOAS) SYSTEM_

INSTRUMENTATION TEXT 3.3.8.1 4 11/16/2016

Title:

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

Title:

INSTRUMENTATION REACTOR PROTECTION SYSTEM (RPS) ELECTRIC POWER MONITORING TEXT 3.4.1

Title:

REACTOR COOLANT SYSTEM (RCS) RECIRCULA'rION LOOPS OPERATING TEXT 3.4.2 4 11/16/2016

Title:

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

Title:

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

Page 3 of 8 Report Date: 09/05/19

I SSES MANUAL Manual Name: TSB2 Manual

Title:

TECHNICAL SPECIFICATIONS BASES DNIT 2 MANUAL TEXT 3.4.4 1 11/16/2016

Title:

REACTOR COOLANT SYSTEM (RCS) RCS OPERATIONAL LEAKAGE (

TEXT 3:4 .5 3 03/10/2010

Title:

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

Title:

REACTOR COOLANT SYSTEM (RCS) RCS LEAKAGE DETECTION INSTRUMENTATION TEXT 3.4.7 3 11/16/2016

Title:

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

Title:

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

- HOT SHUTDOWN

~ TEXT 3 .4. 9 2 11/16/2016

Title:

REACTOR COOLANT SYSTEM (RCSJ RESIDUAL HEAT REMOVAL (RHR) SHUTDOWN COOLING SYSTEM TEXT 3.4.10

- COLD SHUTDOWN 6 05/14/2019

,Title: REACTOR COOLANT SYSTEM (RCS) RCS PRESSURE AND TEMPERATORE (P/T) LIMITS TEXT 3.4.11 1 11/16/2016

Title:

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

Title:

EMERGENCY CORE COOLING SYSTEMS (ECCS) REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM ECCS OPERATING TEXT. 3. 5. 2 5 03/05/2019

Title:

EMERGENCY CORE COOLING SYSTEMS (ECCS) REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM ECCS OPERATING TEXT 3 .5-.3 6 03/05/2019

Title:

EMERGENCY CORE C00LING SYSTEMS (ECCS) REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM ECCS OPERATING Page 4 of 8 Report Date: 09/05/19

\

SSES MANUAL

' Manual Name: TSB2 Manual

Title:

TECHNICAL SPECIFIC{\TIONS BASES UNIT 2 MANUAL TEXT 3 . 6 *. 1 . 1 6 11/16/2016

Title:

PRIMARY CONTAINMKNT TEXT 3 . 6 . 1. 2 2 11/16/2016

Title:

CONTAINMENT SYSTEMS PRIMARY CONTAINMENT AIR LOCK TEXT 3.6.1.3 17 03/05/2019

Title:

CONTAINMENT SYSTEMS PRIMARY CONTAINMENT ISOLATION VALVES (PCIVS)

\ '

TEXT 3 . fr. 1. 4 2 11/16/2016

Title:

CONTAINMENT SYSTEMS CONTAINMENT PRESSTIRE TEXT 3 . 6 . 1. 5 2 11/16/2016

Title:

CONTAINMENT SYSTEMS' DRYWELL AIR TEMPERATORE

• TEXT 3 . 6 . 1. 6 1 11/16/2016

Title:

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

Title:

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

Title:

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

Title:

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

/

Title:

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

Title:

CONTAINMENT SYSTEMS INTENTIONALLY LEFT BLANK TEXT 3.6.3.2 3 09/29/2017

Title:

CONTAINMENT SYSTEMS DRYWELL AIR FLOW SYSTEM Page 5 of 8 Report Date: 09/05/19

SSES MANUAL Manual Name : TSB2 Manual

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL l

TEXT 3.6.3.3 3 09/29/2017

Title:

CO~AINMENT SYSTEMS PRIMARY CONTAINMENT OXYGEN CONCENTI3.ATION TEXT 3.?.4.1 16 03/05/2019

Title:

CONTAINMENT SYSTEMS SECONDARY CONTAINMENT TEXT 3.6.4.2 14 03/05/2019 .

Title:

CONTAINMENT SYSTEMS SECONDARY CONTAINMENT ISOLATION VALVES (SCIVS)

TEXT-3.6.4.3 7 \ 03/05/2019

Title:

CONTAJNMENT SYSTEMS STANDBY GAS TREATMENT (SGT) SYSTEM TEXT 3.7.1 7 03/01/2017

Title:

PLANT SYSTEMS RESIDUAL HEAT REMOVAL SERVICE WATER (RlffiSW) SYSTEM AND THE ULTIMATE HEAT SINK (IDIS)

TEXT 3.7.2 3 11/16/2016

Title:

PLANT SYSTEMS EMERGENCY SERVICE WATER (ESW) SYSTEM TEXT 3.7,.3 4 03/05/2019

Title:

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

Title:

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

Title:

PLANT SYSTEMS MAIN CONDENSER OFFGAS TEXT 3.7.6 4 11/16/2016

Title:

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

Title:

PLANT SYSTEMS SPENT FUEL STORAGE POOL WATER LEVEL TEXT 3.7.8 1 11/16/2016 Page 6

Title:

MAINE TORBINE PRESSURE REGULATION SYSTEM of 8 Report Date: 09/05/19

SSES MANUAL Manual Name: TSB2 Manual

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL TEXT 3.8.1 14 09/04/2019

Title:

ELECTRICAL POWER SYSTEMS AC SOURCES - OPERATING TEXT 3.8.2 1 03/05/2019

Title:

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

Title:

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

Title:

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

Title:

ELECTRICAL POWER SYSTEMS DC SOURCES - SHUTDOWN

• TEXT 3.8.6 2 11/16/2016

Title:

ELECTRICAL POWER SYSTEMS BATTERY CELL PARAMETERS TEXT 3.8.7 7 09/04/2019

Title:

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

Title:

ELECTRICAL POWER SYSTEMS DISTRIBUTION SYSTEMS - SHUTDOWN TEXT 3.9.1 1 11/16/2016

Title:

REFUELING OPERATIONS REFUE_LING EQUIPMENT INTERLOCKS TEXT 3.9.2 2 11/16/2016

\

Title:

REFUELING OPERATIONS REFUEL POSITION ONE-ROD-OUT INTERLOCK TEX;T 3.9.3 1 11/16/2016

Title:

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

Title:

REFUELING OPERATIONS CONTROL ROD POSITION INDICATION Page 7 of 8 Report Date: 09/05/19

J '

J SSES MANUAL Manual Name: TSB2 Manual

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL TEXT 3.9.5 1 11/16/2016

Title:

REFUELING OPERATIONS CONTROL ROD OPERABILITY - REFUELING TEXT 3.9.6 2 11/16/2016 Titlez REFUELING OPERATIONS REACTOR PRESSTIRE VESSEL (RPV) WATER LEVEL TEXT 3.9.7 1 11/16/2016

Title:

REFUELING OPERATIONS RESIDUAL HEAT REMOVAL (RHR) - HIGH WATER LEVEL TEXT 3.9.8 1 11/16/2016 Titlez REFUELING OPERATIONS RESIDUAL HEAT(REMOVAL (RHR) - LOW WATER LEVEL TEXT 3.10.1 2 03/05/2019

Title:

SPECIAL OPERATIONS INSERVICE LEAK AND HYDROSTATIC TESTING OPERATION TEXT 3.10.2 1 11/16/2016

Title:

SPECIAL OPERATIONS REACTOR MODE SWITCH INTERLOCK TESTING TEXT 3.10.3 1 11/16/2016 Titlez SPECIAL OPERATIONS SINGLE CONTROL ROD WITHDRAWAL - HOT SHUTDOWN TEXT 3.10.4 1 11/16/2016

Title:

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

Title:

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

Title:

SPECIAL OPERATIONS MULTIPLE CONTROL ROD WITHDRAWAL - REFUELING TEXT 3.10.7 1 03/24/2005

Title:

SPECIAL OPERATIONS CONTROL ROD TESTING - OPERATING TEXT 3.10.8 3 11/16/2016

Title:

SPECIAL OPERATIONS SHUTDOWN MARGIN (SDM) TEST - REFUELING Page 8 of 8 Report Date: 09/05/19

Rev. 14 AC Sources-Oper:ating B 3.8.1 B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.1 AC Sources-Operating BASES BACKGROUND The unit Class 1E 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, 8, C or D. As required by 10 CFR 50, Appendix A, GDC 17 (Ref. 1), the design of the AC electrical p0wer system provides independence and redundancy to ensure an available source of power to the Engineered Safety Feature (ESF) systems.

The Class 1E 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 tne onsite Class 1E AC Electrical Power Distribution System are supported by two independent offsite power sources. A 230 kV line from the Susquehanna T1 O 230 kV switching station feeds start-up transformer No. 1O; 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 alld 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 1E ESS bus or buses .

• SUSQUEHANNA - UNIT 2 3.8-1

0 Rev. 14 AC Sources-Operating B 3.8.1 BASES BACKGROUND ST No. 1O 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 signaQ 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 indMdual 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 the ESS bus by indMdual load timers which control the permissive and starting signals to motor breakers to prevent overloading the DG .

• SUSQUEHANNA - UNIT 2 3.8-2

Rev. 14 AC Sources-Operating B 3.8.1 BASES BACKGROUND In the event of a loss of normal and alternate offsite power supplies, the (continued) 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 (OBA) such as a LOCA.

Certain required plant loads are returned to service in a predetennined 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 SAFETY ANALYSES The initial conditions of OBA and transient analyses in the FSAR, 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 OPERABLE during accident conditions in the event of an assumed loss of all offsite power or all onsite AC power; and a worst case single failure.

AC sources satisfy Criterion 3 of the NRC Policy statement (Ref. 6) .

• SUSQUEHANNA - UNIT 2 3.8-3

Rev. 14 AC Sources-Operating B 3.8.1 BASES LCO Two qualified circuits between the offsite transmission network and the onsite Class 1E 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 OBA DG E can be used as a subsl:iMe 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 1E 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 ccmditions are met:

1. An energized ST. No. 1O transformer with the load tap changer (LTC) in automatic operation.

2. The respective circuit path including energized ESS transfom,ers 101 and 111 and feeder breakers capable of supplying three of the four 4. 16kV 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 nom,al 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 .

• SUSQUEHANNA - UNIT 2 3.8-4

Rev. 14 AC Sources-Operating B 3.8.1 BASES LCO The offsite circuit is inoperable for any actual voltage violation, (continued) 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 cannot result in a LOCA, delayed LOOP.

The other offsite circuit is Operable when all the following conditions are met

1. An energized ST. No. 20 transformer with the load tap changer (LTC) in automatic operation .

• 2. The respective circuit path including energized ESS transformers 201 and 211 and feeder breakers capable of supplying three of the four 4.16kV 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.

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.

• SUSQUEHANNA - UNIT 2 3.8-5

Rev. 14 AC Sources-Operating B 3.8.1 BASES LCO The offsite circuit is operable for any other predicted grid (continued) 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 LGOs for predicted grid conditions that cannot result in a LOCA, delay9<! LOOP.

Both offsite circuits are OPERABLE provided each meets the criteria described above and provided that no 4.16kV ESS Bus has less than one OPERABLE offsite circuit capable of supplying the required loads. If no OPERABLE offsite circuit is capable of supplying any of the 4.16 kV ESS Buses, one offsite source shall be declared inoperable. Unit 2 also requires Unit 1 offsite circuits to be OPERABLE.

If a Unit 1 4.16 kV bus is de-energized solely for the purpose of performing maintenance, it is not required to declare an offsite source or

• diesel generator inoperable .

Four of the fiVe DGs are required to be Operable to satisfy the initial assumptiofls 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. If a Unit 1 4.16 kV bus is isolated from its DG solely for the performance of bus maintenance, the DG is not required to be declared inoperable. 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 Eis 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, 8, C or D .

SUSQUEHANNA - UNIT 2 3.8-6

Rev. 14 AC-Sources-Operating B 3.8.1 BASES LCO Proper sequencing of loads, including tripping of nonessential loads, is a (continued) 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 If a Unit 1 - 4.16 kV bus is de-energized solely for the purpose of perfomiing maintenance, automatic transfer interlock mechanisms for the de-energized bus are not required to be operable.

APPLICABILITY The AC sources are required to be OPERABLE in MODES 1, 2, and 3 to ensure that

• a.

b.

Acceptable fuel design limits and reactor coolant pressure boundary limits are not exceeded as a result of AOOs or abnormal transients; and Adequate core cooling is provided and containment OPERABILITY and other vital functions are maintained in the event of a postulated OBA.

The AC power requirements for MODES 4 and 5 are covered in LCO 3.8.2, "AC Source&-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 .

• SUSQUEHANNA - UNIT 2 3.8-7

Rev. 14 AC Sources-Operating B 3.8.1 BASES ACTIONS The ACTIONS are modified by a Note which allows entry into associated (continued) 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 distributic:>n 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 substiMion of a required diesel generator will not or can not be completed.

When Note 3 is in effect, the following restrictions (Reference 14) shall occur::

1.) No maintenance or testing that affects the reliability of the remaining OPERABLE Unit 1 and Unit 2 4160 V subsystems shall be scheduled. If any testing or maintenance activities must be performed during this time, an evaluation shall be performed in accordance with Trtle 1O to the Code of Federal Regulations (10 CFR) Section 50.65(a)(4) .

• 2.)

3.)

The required systems, subsystems, trains, components, and devices that depend on the remaining 4160 V buses shall be verified OPERABLE.

The Unit 2 safety-related HPCI and RCIC pumps shall be controlled as "protected equipment" and not taken out of service for planned maintenance while a Unit 1 4160 V bus is out of service for extended maintenance.

Note 3 modifies the ACTIONS by allowing a Unit 1 4160 V subsystem (4.16 kV bus) to be de-energized for bus maintenance when Unit 1 is in Modes 4 or 5 and Unit 2 is in Modes 1, 2, or 3 without requiring either offsite circuit or the associated diesel generator to be declared inoperable. Only entry into LCO 3.8.7 Condition C is required for this maintenance activity. While in this configuration, immediate entry into LCO 3.8.1 is required for any offsite circuit or DG that becomes inoperable. Note 3 no longer applies .

• SUSQUEHANNA - UNIT 2 3.8-8

Rev. 14 AC Sources-Operating B 3.8.1 BASES ACTIONS (continued)

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.

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. Redundant 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 1E 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 .

• SUSQUEHANNA - UNIT 2 3.8-9

Rev. 14 AC Sources-Operating B 3.8.1 BASES ACTIONS A.2 (continued)

(continued)

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, sililgle failure protection may have been lost for the required feature's function; however, function is not lost. 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 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 OBA occurring during this period.

Q 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 />. Wrth one offsite circuit inoperable, the reliability of the offslte system is degraded, and the potential for a loss of offsite pov,.,er 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 electlical power to the onsite Class 1E 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 OBA occurring during this period.

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 .

• SUSQUEHANNA - UNIT 2 3.8-10

Rev. 14 AC Sources-Operating B 3.8.1 BASES ACTIONS (continued)

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 0.e., single dMsion 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 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 OPERA8LE DGs and offsite circuits are adequate to supply electrical power to the onsite Class 1E 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 OBA occurring during this period .

• SUSQUEHANNA - UNIT 2 3.&-11

Rev. 14 AC Sources-Operating B 3.8.1 BASES ACTIONS B.3.1 and B.3.2 (continued)

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 8.3.1 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. However, the second Completion llme 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.

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 1E 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 OBA occurring during this period .

• SUSQUEHANNA - UNIT 2 3.8-12

Rev. 14 AC Sources-Operating B 3.8.1 BASES ACTIONS (continued)

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

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 OBA or transient. In fact, a simultaneous loss of offsite AC sources, a LOCA, and a worst ~se single failure were postulated as a part of the d8$ign 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.

SUSQUEHANNA - UNIT 2 3.8-13

Rev. 14 AC Sources-Operating B 3.8.1 BASES ACTIONS D.1 and D.2 (continued)

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 A~ons 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 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.

• Wrth 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 ~uld 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 /> .

SUSQUEHANNA - UNIT 2 3.8-14

Rev. 14 AC Sources-Operating B 3.8.1 BASES ACTIONS F.1 and F.2 (continued)

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.

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. As Noted at the beginning of the SRs, SR 3.8.1.1 through SR 3.8.1.20 are applicable to the Unit 2 AC sources and SR 3.8.1.21 is applicable to the Unit 1 AC sources .

• SUSQUEHANNA - UNIT 2 3.8-15

Rev. 14 AC Sources-Operating B 3.8.1 BASES SURVEILLANCE Where the SRs discussed herein specify voltage and frequency REQUIREMENTS tolerances, the following summary is applicable. The minimum steady (continued) state output voltage of 4000 V represents the value that will allow the degraded voltage relays to reset after actuation. This value is based on the upper value of the degraded voltage relay reset voltage of 3938 V, representing 94.68% of 4160 V, plus the worst-case voltage drop from the DG to an associated 4.16 kV switchgear bus. The specified maximum steady state output voltage of 4400 V is equal to the maximum operating voltage specified for 4000 V. It ensures that for a lightly loaded

<:lisbibution system, the voltage at the terminals of 4000 V motors is no more than the maximum rated operating voltages.

The minimum frequency value is derived from the recommendations found in Regulatory Guide 1.9 (Ref. 3). The allowable steady state frequency for all DGs is 60 Hz +/-2%. DG E is also required to maintain a frequency of not less than 57 Hz during transient conditions. To provide additional margin for DG E to meet the 57 Hz criteria, the 2%

margin allowed for steady state frequency is further reduced to 1%, or 0.6 Hz. This value, added to the tolerance allowed for the DG's

• electronic governor (0.1 Hz) provides the 59.3 Hz minimum frequency value applicable for all DGs.

The maximum frequency is derived from analysis based on an iterative approach using voltage and frequency variations of the DG to determine the maximum continuous loading on the DG such that the DG loading does not exceed its continuous rating and still performs its design function. Through a qualitative estimation and a dynamic transient simulation, the maximum frequency meeting the iterative approach is 60.5 Hz.

The Surveillance Table has been mo<:lified 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 1E 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 1E disbibution 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

• SUSQUEHANNA - UNIT 2 3.8-16

Rev. 14 AC Sources-Operating B 3.8.1 BASES SURVEILLANCE substiMed for any other DG and declared OPERABLE after perfom,ance REQUIREMENTS of two SRs which verify switch alignment. This is acceptable because (continued) the testing regimen defined ih the Surveillance Requirement Table ensures DG E is fully capable of perfom,ing all DG requirements.

SR 3.8.1.1 This SR ensures proper circuit continuity for the offsite AC erectrical 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 Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.8.1.2 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 rninutes 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 .

• SUSQUEHANNA - UNIT 2 3.8-17

Rev. 14 AC Sources-Operating 8 3.8.1 BASES SURVEILLANCE SR 3.8.1.3 (continued)

REQUIREMENTS (continued) 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 perfom,ance of this SR.

A successful DG start must precede this test to credit satisfactory perfom,ance.

• Note 5 provides the allowance that DG E, when not aligned as substitute for DG A, 8, C and D but being maintained available, may use the test facility to satisfy loading requirements in lieu of synchronization with an

(;SS bus.

Note 6 allows a single test 0nstead 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 thru 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 perfom,ed 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 perfom,ing 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 perfom, the test due to equipment availability, then the test shall be performed synchronized to this Unit's 4.16 kV ESS bus. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program .

• SUSQUEHANNA - UNIT 2 3.8-18

Rev. 14 AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.4 REQUIREMENTS (continued) 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 Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.8.1.5 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 periodically 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 Frequency is controlled under the Surveillance Frequency Control Program.

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.

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

• SUSQUEHANNA - UNIT 2 3.8-19

Rev. 14 AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.7 REQUIREMENTS (continued) This SR helps to ensure the availability of the standby elecbical 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 DG's 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 coolant and oil are being continuously circulated and temperature is being maintained consistent with manufacturer recommendations.

The DG starts from standby conditions and achieves the minimum required voltage and frequency within 1O seconds and maintains the required voltage and frequency when steady state conditions are reached. The ten second start requirement support the assumptions in the design bases 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 0nstead 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 one unit.

The time for the DG to reach steady state operation is periodically monitored and the trend evaluated to identify degradation.

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

SR 3.8.1.8 Transfer of each 4.16 kV ESS bus power supply from the nonnal offsite circuit to the alternate offsite circuit demonstrates the OPERABILITY of

.the alternate circuit distribution network to power the shutdown loads.

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

SUSQUEHANNA - UNIT 2 3.8-20

Rev. 14 AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.8 (continued)

REQUIREMENTS (continued) This SR is modified by a Note. The reason for tlle Note is tllat, during operation witll the reactor critical, performance of tlle automatic transfer of 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, tllerefore, no mode restriction is specified. This Surveillance tests the applicable logic associated with Unit 2. The comparable test specified in Unit 1 Technical Specifications tests the applicable logic associated with Unit 1. Consequently, a test must be performed within the specified Frequency for each unit As the Surveillance represents separate tests, tlle Note specifying the restriction for not performing the test while the unit is In MODE 1 or 2 does not have applicability to Unit 1. The NOTE only applies to Unit 2, tllus the Unit 2 Surveillance shall not be performed with Unit 2 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 tlle 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 a 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 canying 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 setpoinl

• SUSQUEHANNA - UNIT 2 3.8-21

Rev. 14 AC Sources~Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.9 (continued)

REQUIREMENTS (continued) 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 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 Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

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 Mure application, including reconnection to the bus if the trip initiator can be corrected or isolated .

• SUSQUEHANNA - UNIT 2 3.8-22

Rev. 14 AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.1 O (continued)

REQUIREMENTS (continued) 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

,I 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 Surveillance Frequency Is controlled under the Surveillance Frequency Control Program.

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 4.16 kV 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 Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

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 DG's A through D includes operation of the lube oil system to ensure the DGs turbo charger is sufficiently prelubricated). 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 .

• SUSQUEHANNA - UNIT 2 3.8-23

Rev. 14 AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.11 (continued)

REQUIREMENTS (continued) The reason for Note 2 is that perfonning 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 2. The comparable test specified in the Unit 1 Technical Specifications tests the applicable logic associated with Unit 1. Consequently, a test must be perfonned 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 1. The Note only applies to Unit 2, thus the Unit 2 Surveillances shall not be performed with Unit 2 in MODES 1, 2 or 3.

This SR is also modified by Note 3. The Note specifies when this SR is required to be perfonned 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 perfonned, two rotational testing regimens have been established; one for components that are required to be tested every 24 months and one for components that have had their test frequency extended to 24 months on a STAGGERED TEST BASIS or 48 months in accordance with the Surveillance Frequency Control Program. The two rotational testing regimens are given below. The second testing regimen is referred to as the 48 Month Testing Regimen for simplicity but is also applicable to components that are tested at 24 months on a STAGGERED TEST BASIS.

24 Month Testing Regimen 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 SUSQUEHANNA - UNIT 2 3.8-24

Rev. 14 AC Sources-Operating B 3.8.1

'BASES SURVEILLANCE SR 3.8.1.11 (continued)

REQUIREMENTS (continued) 48 Month Testing Regimen UNIT IN OUTAGE DIESEL E SUBSTITUTED FOR 2 DG E not t~sted 1 Diesel Generator A 2 DG E not tested 1 DG E not tested 2 Diesel Generator B 1 Diesel Generator C 2 DG E not tested 1 DG E not tested 2 Diesel Generator D 1 DG E not tested 2 DG E not tested 1 Diesel Generator B 2 DG E not tested 1 DG E not tested 2 Diesel Generator A 1 Diesel Generator D 2 DG E not tested 1 DG E not tested 2 Diesel Generator C 1 DG E not tested The specified rotational testing regimens can be altered to facilitate unanticipated events which render the testing regimens impractical to implement, but any alternative 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 at~

frequency controlled under the Surveillance Frequehcy Control Program). The testing allowances do result in some circuit pathways which do not need to change state (i.e., cabling) not being tested at the

• SUSQUEHANNA - UNIT 2 3.8-25

Rev. 14 AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.11 (continued)

REQUIREMENTS (continued) frequency established in accordance with the Surveillance Frequency Control Program. This is acceptable because these components are not required to change state to perfonn their safety function and when substiMed-nonnal operation of DG E will ensure continuity of most of the cabling not tested.

SR 3.8.1.12 This Surveillance demonstrates that the DG automatically starts and achieves the required voltage and frequency within the specified time (1 O seconds) from the design basis actuation signal (LOCA signaQ and operates for ;;c: 5 minutes. The 5 minute period provides sufficient time to demonstrate stability. SR 3.8.1.12.d and SR 3.8.1.12.e ensure that pennanently 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 vetify the connection and power supply of pennanent and auto connected 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 Surveillance Frequency is controlled under the Surveillance Frequency Control Program .

• SUSQUEHANNA - UNIT 2 3.8-26

Rev. 14 AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.12 (continued)

REQUIREMENTS (continued) 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 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.

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 1E 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 and 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 .

SR 3.8.1.13 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 OBA is more critical than protecting the engine against minor problems that are not immediately detrimental to emergency operation of the DG.

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

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 .

• SUSQUEHANNA - UNIT 2 3.8-27

Rev. 14 AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.13 (continued)

REQUIREMENTS (continued) Note 2 provides the allowance that DG E, when not aligned as a substiMe for DG A, B, C, and D but being maintained available, may use a simulated ECCS initiation signal.

SR 3.8.1.14 Regulatory Guide 1.9 (Ref. 3), requires demonstration periodically that the DGs can start and run continuously at full load capability for an interval of not less than 24 hoUrs-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 1

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 Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

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

• SUSQUEHANNA - UNIT 2 3.8-28

Rev. 14 AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.14 (continued)

REQUIREMENTS (continued) Note 3 stipulates that DG E, when not aligned as substitute for DG A, B, C or D but being maintained available may use 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 1O seconds. The 10 second time is derived from the requirements of the accident analysis to respond to a design basis large break LOCA The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

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 DG's turbocharger 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.

• SUSQUEHANNA- UNIT 2 3.8-29

Rev. 14 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.

In order to meet this Surveillance Requirement, the Operators must have the capability to manually transfer loads from the D/Gs to the offsite sources. Therefore, in order to accomplish this transfer and meet this Surveillance Requirement, the synchronizing selector switch must be functional. (See ACT-1723538).

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

• 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

• SUSQUEHANNA - UNIT 2 3.8-30

Rev. 14 AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.17 (continued)

REQUIREMENTS (continued) after the DG Is tripped, the offsite source originally in parallel with the DG, remains connected to the affected 4.16 kV ESS Bus. SR 3.8.1.12 is perfonned separately to verify the proper offsite loading sequence.

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

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 indMdual 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 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 specified in Table B 3.8.1-1. These conditions will require entry into applicable Condition 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 Conditions and Required Actions of the associated specification shall be entered for the equipment rendered inoperable.

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

This SR is modified by a Note that specifies that load timers associated with equipment that has automatic Initiation capability di~abled 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. Furthennore, load timers are associated with indMdual timers such that a single timer only affects a single load .

SUSQUEHANNA- UNIT 2 3.8-31

Rev. 14 AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.19 REQUIREMENTS (continued) In the event of a OBA 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 emergency loads are energized.

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

• 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 011 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 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 2. The comparable test specified in the Unit 1 Technical Specifications tests the applicable logic associated with Unit 1. 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 1s in MODE 1, 2 or 3 does not have applicability to Unit 1. The Note only applies to Unit 2, thus the Unit 2 Surveillances shall not be performed with Unit 2 in MODE 1, 2 or 3 .

SUSQUEHANNA - UNIT 2 3.8-32

Rev. 14 AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.20 REQUIREMENTS (continued) 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 Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

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 DG's 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, 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 nomially empty switchgear 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 Eis substituted for any other DG .

• SUSQUEHANNA - UNIT 2 3.8-33

Rev. 14

• • BASES AC Sources-Operating B 3.8.1 SURVEILLANCE SR 3.8.1.21 REQUIREMENTS (contihued) This Surveillance Is provided to direct that the appropriate Surveillances for Unit 1 AC sources required to support Unit 2 are governed by the Unit 2 Technical Specifications. With the exception of this Surveillance, all other Surveillances of this Specification (SR 3.8.1.1 through SR 3.8.1.20) are applicable to the Unit 2 AC sources only. Meeting the SR requirements of Unit 1 LCO 3.8.1 will satisfy all Unit 2 requirements for Unit 1 AC sources. However, six Unit 1 LCO 3.8.1 SRs, if not required to support Unit 1 OPERABILITY requirements, are not required when demonstrating Unit 1 sources are papable of supporting Unit 2.

SR 3.8.1.8 is not required tf only one Unit 1 offsite circuit is required by the Unit 2 Specification. SR 3.8.1.12, SR 3.8.1.13, SR 3.8.1.17, and SR 3.8.1.19 are not required since these SRs test the Unit 2 ECCS initiation signal, which is not needed for the AC sources to be OPERABLE on Unit 2. SR 3.8.1.20 is not required since starting independence is not required with the DG(s) not required to be OPERABLE.

The Frequency required by the applicable Unit 1 SR also governs performance of that SR for Unit 2.

As Noted, if Unit 1 is in MODE 4 or 5, the Note to Unit 1 SR 3.8.2.1 is applicable. This ensures that a Unit 2 SR will not require a Unit 1 SR to be performed, when the Unit 1 Technical Specifications do not require performance of a Unit 1 SR. (However, as stated in the Unit 2 SR 3.8.2.1 Note, while performance of an SR is not required, the SR still must be met) .

• SUSQUEHANNA - UNIT 2 3.8-34

Rev. 14 AC Sources-Operating B 3.8.1 BASES REFERENCES 1. 10CFR 50, Appendix A, GDC 17.

2. FSAR, Section 8.2.

3. Regulatory Guide 1.9.

4. FSAR, Chapter 6.

5. FSAR, Chapter 15.

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

7. Regulatory Guide 1 93.

8. Generic Letter 84-15.

9. 10 CFR 50, Appendix A, GDC 18.

• 10 . IEEE Standard 308.

11.

12.

Regulatory Guide 1.137.

FSAR, Section 6.3.

13. ASME Boiler and Pressure Vessel Code,Section XI.

14. Letter from R. V. Guzman (USNRC) to B. T. McKinney (PPL)

"Susquehanna Steam Electric Station, Unit 2 - Issuance of Amendment Re: Electrical Power Systems Technical Specification 3.8.1 (T.A.C. MD4766)", dated February 19, 2008 .

• SUSQUEHANNA - UNIT 2 3.8-35

Rev. 14 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 TAG NO. SYSTEM LOADING TIMER LOCATION (seconds) VALUE (seconds) 62A-20102 RHRPump 1A 1A201 3  :<: 2.7 and 5 3.6 62A-20202 RHR Pump 18 1A202 3 <! 2.7 and 5 3.6 62A-20302 RHRPump 1C 1A203 3  :<: 2.7 ancl 5 3 6 62A-20402 RHR Pump 1D 1A204 3  :<: 2.7 and 5 3.6 62A-20102 RHRPump2A 2A201 3 <! 2.7 and 5 3 6 62A-20202 RHRPumo28 2A202 3  :<: 2.7 and 5 3 6 62A-20302 RHR Pump2C 2A203 3 <! 2.7 and 5 3.6 62A-20402 RHRPumo2D 2A204 3 ~ 2.7 and 5 3 6 E11A-K2D28 RHR Pump 1C (Offsrte Power llmerl 1C618 7.0 ;e: 6 5 and 5 7.5 E11A-K120A RHR Pump 1C (Offslte PO'i,'0fTuner) 1C817 7.0 ;e: 6.5 and 5 7.5 E11A-K1208 RHR Pump 1D (Offsrte Power Trrnerl 1C618 70  :<: 6.5 and 5 7.5 E11A-K2D2A RHR Pump 1D (Offslte Power llmer) 1C617 70  :<: 6.5 and 5 7.5 E11A-K120A RHR Pumo 2C (Offsrte Power Tbnen 2C617 7.0 ;e: 6.5 and 5 7.5 E11A-K2D2S RHR Pump 2C (Offsrte Power Tbnerl 2C618 7.0 ;e: 6.5 and 5 7.5 E11A-K1208 RHR Pl:lfllP 2D (Offslte Power llmerl 2C618 7.0 ;e: 6.5 and 5 7.5 E11A-K202A RHR Pump 2D (Offslte Power Timer) 2C617 7.0 ;e:65and57.5 E21A-K116A CS Pump 1A 1C626 10 5  :<: 9.4 and 511.6 E21A-K1168 CS Pump 1B 1C627 10 5 ~ 9.4 and 5 11 6 E21A-K125A CS Pump 1C 1C626 10.5  :<:94and:s:116 E21A-K1258 CS Pump 1D 1C627 10.5  :<: 9.4 and :s: 11.6 E21A-K116A CSPump2A 2C626 10.5 ~ 9.4 and 5 11 6 E21A-K116B CSPump2B 2C627 10.5 ~ 9.4 and 511.6 E21A-K125A CSPump2C 2C626 10.5  :<: 9.4 and 511.6 E21A-K1258 CSPump2D 2C627 10.5 ~ 9.4 and 5 11.6 E21A-K16A CS Pump 1A (Offslte Power Timer) 1C626 16 <! 14 0 and 5 16.0 E21A-K168 CS Pump 18 (Offslte Power llrnerl 1C627 15 <! 14.0 end 5 16.0 E21A-K25A CS Pump 1C (Offstte Power Timer} 1C626 15 ~ 14.0 and 516.0 E21A-K258 CS Pump 1D (Offstte Power Tbner) 1C627 15 ~ 14.0 and 5 16 0 E21A-K16A CS Pump 2A (Offslte Power Tl1Tl0rl 2C626 15 ~ 14.0 and 5 16.0 E21A-K16B CS Pump 2B (Offslte Power llmer) 2C627 15  :<: 14.0 and 5 16.0 E21A-K25A CS Pump 2C (Offslte PCJVv'81' Tbnen 2C626 15  :<: 14.0 and 516.0 E21A-K258 CS Pump 2D (Offslte Power llmer) 2C627 15  :<: 140 and516.0 62AX2-20108 Erneroencv Service Water 1A201 40 ~36and544 62AX2-20208 Ememencv Service Water 1A202 40 ~36and544 62AX2-20303 Emeraencv Service Water 1A203 44  :<: 39.6 and s 48.4 62AX2-20403 Ememency Service Water 1A204 48 ~ 43 2 and 5 52.8 B2X3-20404 Control Structure Chllled Water Svstem OC877B 60 ~54 62X3-20304 Control Structure Chilled Water Svstem OC877A 60 ;e:54 Emergency Switchgear Rm Cooler A & RHR 62X-20104 OC677A 60 ~54 SN Pump H&V Fan A Emergency Switchgear Rm Cooler 8 & RHR 62X-20204 OCB77B 60 ~54 SN Pump H&V Fan 8 62X-5653A DG Room Exhaust Fan E3 08565 60 ~54 62X-6652A DG Room Exhausts Fan E4 08565 60 ~54 262X-20204 -

01 -~* SwrtchoearRm Cooler 8 OC877B 120 <! 54 262X-20104 Ememencv ::;-,,i= ~ar Rm Cooler A OC877A 120 ~54 B2X-546 DG Rm Exh Fan D 08546 120 ~54

• SUSQUEHANNA - UNIT 2 3.8-36

Rev. 14 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 TAG NO. SYSTEM LOADING TIMER LOCATION (seconds) VALUE (seconds) 62X-536 DG Rm Exh Fan C 08536 120 254 62X-526 DG Rm Exh Fan B 08526 120 254 62X-516 DG Rm Exh Fan A 08516 120 ~54 CRX-5652A DG Room Sunnlv Fans E1 and E2 08565 120 ~54 62X2-20410 Control Structure ChDled Water Svstem OC8768 180 254 62X1-20304 Control Structure ChDled Water Svstem OC877A 180 254 62X2-20310 Control structure Chilled Water Svstem OC876A 180 254 62X1-20404 Control Structure CtJJJed Water Svstem OC8778 180 254 62X2-20304 Control Structure Chilled Wat.er Svstern ~A 210 254 62X2-20404 Control structure Chilled Water System OC8778 210 . 254 Emergency Switchgear Rm Coo11119 62X-K11BB 2CB2508 260 254 Comoressor B Emergency Sv.ttchgear Rm Coollng 62X-K11AB 2CB250A 260 ~54 C..,,, ~* D0"'1! A

• SUSQUEHANNA - UNIT 2 3.8-37

Rev. 14 AC Sources-Operating B 3.8.1 THIS PAGE INTENTIONALLY LEFT BLANK

• SUSQUEHANNA - UNIT 2 3.8-38

Rev 7 Distribution Systems-Operating B 3.8.7 B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.7 Distribution Systems-Operating BASES BACKGROUND The onsite Class ~ E AC and DC electrical power distribution system is divided into redundant and independent AC and DC electrical power distribution subsystems and a DG E electrical power distribution subsystem.

The primary AC distribution system consists of four 4.16 kV Engineered Safeguards System (ESS) buses each having a primary and alternate offsite source of power as well as an onsite diesel generator (DG) source that supports one 4.16 kV ESS bus in each unit. Each 4.16 kV ESS bus is normally supplied by either Startup Transformer (ST) No. 1O or ST No. 20. ST No. 10 and ST No. 20 each provide the normal source of power to 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. If both offsite sources are unavailable, the onsite emergency DGs supply power to the 4.16 kV ESS buses.

There are two 250 VDC electrical power distribution subsystems; four 125 VDC electrical power distribution subsystems; and, and one 125 VDC DG E electrical power distribution subsystem, all of which support the necessary power for ESF functions.

In addition, some components required by Unit 2 receive power through Unit 1 electrical power distribution subsystems, the Unit 1 AC and DC electrical power distribution subsystems needed to support the required equipment are addressed in Unit 2 LCO 3.8.7.

Required distribution subsystems are listed in LCO 3.8.7, Table 3.8.7-1.

APPLICABLE The initial conditions of Design Basis Accident (OBA) and transient SAFETY analyses in the FSAR, Chapter 6 (Ref. 1) and Chapter 15 (Ref. 2),

ANALYSES assume ESF systems are OPERABLE. The AC and DC electrical power distribution systems are designed to provide sufficient capacity, capability, redundancy, and reliability to ensure the availability of necessary power to l=SF systems so that the fuel, Reactor Coolant System, and containment design limits are not

• SUSQUEHANNA - UNIT 2 exceeded. These limits are discussed in more detail in the Bases 3.8-84

Rev. 7

• • BASES APPLICABLE Distribution Systems-Operating B 3.8.7 for Section 3.2, Power Distribution Limits; Section 3.4, Reactor Coolant SAFETY System (RCS); and Section 3.6 Containment Systems.

ANALYSES (continued) The OPERABILITY of the AC and DC electrical power distribution subsystems is consistent with the initial assumptions of the accident analyses and is based upon meeting the design basis of the unit. This includes maintaining distribution systems OPERABLE during accident conditions in the event of:

a. An assumed loss of all offsite power or all onsite AC electrical power; and

b. A worst case single failure.

The AC and DC electrical power distribution system satisfies Criterion 3 of the NRC Policy Statement (Ref. 4).

LCO The required electrical power distribution subsystems listed in Table 3.8.7-1 ensure the availability of AC and DC electrical power for

• the systems required to shut down the reactor and maintain it in a safe condition after an anticipated operational occurrence (AOO) or a postulated DBA. The AC and DC electrical power distribution subsystems are required to be OPERABLE.

Maintaining the AC and DC electrical power distribution subsystems OPERABLE ensures that the redundancy incorporated into the design of ESF is not defeated. Therefore, a single failure within any system or within the electrical power distribution subsystems will not prevent safe shutdown of the reactor.

AC electrical power distribution subsystems require the associated buses and electrical circuits to be energized to their proper voltages. DC electrical power distribution subsystems require the associated buses to be energized to their proper voltage from either the associated battery or charger. The AC and DC electrical power distribution subsystem is only*considered Inoperable when the subsystem Is not energized to its proper voltage .

• SUSQUEHANNA - UNIT 2 3.8-85 I>

Rev. 7 Distribution Systems-Operating B 3.8.7 BASES APPLICABILITY The electrical power distribution subsystems 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 OBA.

Electrical power distribution subsystem requirements for MODES 4 and 5 are covered in the Bases for LCO 3.8.8, "Distribution Systems -

Shutdown."

ACTIONS With one or more required Unit 2 AC buses, load centers, motor control centers, or distribution panels inoperable but not resulting in a loss of

• safety function, or two Unit 1 AC electrical power distribution subsystems on one DMsion inoperable for performance of Unit 1 SR 3.8.1.19, the remaining AC electrical power distribution subsystems are capable of supporting the minimum safety functions necessary to shut down the reactor and maintain it in a safe shutdown condition, assuming no single failure. The overall reliability is reduced, however, because a single failure in the remaining power distribution subsystems could result in the minimum required ESF functions not being supported Therefore, the ,,,

required AC buses, load centers, motor control centers, and distribution panels must be restored to OPERABLE status within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.

The Condition A worst scenario is one division without AC power (i.e.,

no offsite power to the dMsion and the associated DG inoperable). In this Condition, the unit is more vulnerable to a complete loss of AC power. It is, therefore, imperative that the unit operators' attention be focused on minimizing the potential for loss of power to the remaining division by stabilizing the unit, and on restoring power to the affected division. The 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> time limit before requiring a unit shutdown in this Condition is acceptable because:

a. There is a potential for decreased safety if the attention of unit operators is diverted from the evaluations and actions necessary to restore power to the affected division to the actions associated with taking the unit to shutdown within this time limit

• SUSQUEHANNA - UNIT 2 3.8-86

Rev. 7 Distribution Systems-Operating B 3.8.7 BASES ACTIONS A.1 (continued)

(continued)

b. The potential for an event in conjunction with a single failure of a redundant component in the division with AC power. (fhe redundant component is verified OPERABLE in accordance with Specification 5.5.11, "Safety Function Determination Program

{SFDP).")

Condition A is modtfled by a Note that states that Condition A is not applicable to the DG E DC electrical power subsystem. Condition F or G is applicable to an inoperable DG E DC electrical power subsystem.

Required Action A.1 is modified by a Note that requires the applicable Conditions and Required Actions of LCO 3.8.4 "DC Sources - Operating,"

to be entered for DC subsystems made inoperable by inoperable AC electrical power distribution subsystems. This is an exception to LCO 3.0.6 and ensures the proper actions are taken for inoperable DC sources. lnoperability of a distribution subsystem can result in loss of charging power to batteries and eventual loss of DC power. This Note ensures that the appropriate attention is given to restoring charging

• power to batteries, if necessary, after loss of distribution systems .

With one or more Unit 2 DC buses inoperable, the remaining DC electrical power distribution subsystems may be capable of supporting the minimum safety functions necessary to shut down the reactor and maintain it in a safe shutdown condition, assuming no single failure. The overall reliability is reduced, however, because a single failure in one of the remaining DC electrical power distribution subsystems could result in the minimum required ESF functions not being supported. Therefore, the required DC buses must be restored to OPERABLE status within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> by powering the bus from the associated battery or charger.

Condition B represents one subsystem or multiple DC Buses without adequate DC power, potentially with both the battery significantly degraded and the associated charger non-functioning. In this situation, the plant is significantly more vulnerable to a loss of minimally required DC power. It is, therefore, imperative that the operator's attention focus on stabilizing the plant, minimizing the potential for loss of power to the remaining divisions, and restoring power to the affected division .

• SUSQUEHANNA - UNIT 2 3.8-87

Rev. 7 Distribution Systems-Operating B 3.8.7 BASES ACTIONS B.1 (continued)

(continued)

This 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> limit is more conservative than Completion Times allowed for the majority of components that would be without power. Taking exception to LCO 3.0.2 for components without adequate DC power, which would have Required Action Completion Times shorter than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, is acceptable because of;

a. The potential for decreased safety when requiring a change In plant conditions O.e., requiring a shutdown) While not allowing stable operations to continue;

b. The potential for decreased safety when requiring entry into numerous applicable Conditions and Required Actions for components without DC power, while not providing sufficient time for the operators to perform the necessary evaluations and actions for restoring power to the affected dMsion;

c. The potential for an event in conjunction with a single failure of a redundant component

• The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time for DC buses is consistent with Regulatory Guide 1.93 (Ref. 3).

Condition B is modified by a Note that states that Condition B is not applicable to the DG E DC electrical power subsystem. Condition F or G is applicable to an inoperable DG E DC electrical power subsystem.

Wrth one Unit 1 AC electrical power distribution subsystem that support Unit 2 inoperable, the remaining Unit 1 AC electrical power distribution subsystems are capable of supporting the minimum safety functions necessary to shut down the reactor and maintain it in a safe shutdown condition, assuming no single failure. However, the overall reliability is reduced because a single failure in the remaining AC electrical power distribution subsystem could result in the minimum required ESF functions not being supported. The Completion Time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> is consistent with the Completion Times associated with LCOs for the Unit 2 and common equipment potentially affected by loss of a Unit 1 AC electrical power subsystem .

• SUSQUEHANNA - UNIT 2 3.8-88

Rev. 7 Distribution Systems-Operating B 3.8.7 BASES ACTIONS C 1 (continued)

(continued)

The Completion Time has been extended to 7 days in order to complete the replacement of the four (4) Unit 1 480 V ESS Load Center Transformers. This is a temporary extension of the Completion Time.

Upon completion of the transformer replacement, this temporary extension is no longer applicable and will expire on June 15, 2020.

Wrth two required Unit 1 AC buses, load centers, motor control centers, or distribution panels inoperable for the performance of Unit 1 SR 3.8.1.19 but not resulting in a loss of safety function, the remaining AC electrical power distribution subsystems are capable of supporting the minimum safety functions necessary to shut down the reactor and maintain it in a safe shutdown condition, assuming no single failure. The overall reliability is reduced, however, because a single failure in the remaining power distribution subsystems could result in the minimum required ESF functions not being supported. Therefore, the required AC buses, load centers, motor control centers, and distribution panels must be restored to

• OPERABLE status within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> .

E.1and E.2 If the inoperable distribution subsystem 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 plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and to MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

Ll If Diesel Generator E is not aligned to the Class 1E distribution system, the only supported safety function is for the ESW system. Therefore, under this condition, if Diesel Generator E DC power distribution subsystem is not OPERABLE, to ensure the OPERABILITY of the ESW system, actions are taken to either restore the power distribution subsystem to OPERABLE status or-shutdown Diesel Generator E and close the associated ESW valves. The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> limit is consistent with the allowed time for other inoperable DC power distribution subsystems and provides sufficient time to evaluate the condition and take the corrective actions .

• SUSQUEHANNA - UNIT 2 3.8-89

Rev. 7 Distribution Systems-Operating B 3.8.7 BASES ACTIONS (continued)

If the Diesel Generator E is aligned to the class 1E distribution system, the loss of Diesel Generator E DC power distribution subsystem will result in the loss of a on-site Class 1E power source. Therefore, under this condition, if Diesel Generator E DC power distribution subsystem is not OPERABLE actions are taken to either restore the power distribution subsystem to OPERABLE status or declare Diesel Generator E inoperable and take Actions of LCO 3.8.1. The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> limit is consistent with the allowed time for other DC sources and provides sufficient time to evaluate the condition and take the necessary corrective actions.

H.1 Condition H corresponds to a level of degradation in the electrical distribution system that causes a required safety function to be lost.

When more than one AC or DC electrical power distribution subsystem is lost, and this results in the loss of a required function, the plant is in a condition outside the accident analysis. Therefore, no additional time is justified for continued operation. LCO 3.0.3 must be entered immediately

• to commence a controlled shutdown. Entry into Condition G is not required if the loss of safety function is the result of entry into Condition A in combination with the loss of safety functions governed by LCOs other than LCO 3.8.7. In this case, enter LCO 3.8.7, Condition A, and the Condition for loss of function in the LCO that governs the safety function that is lost L1 Wrth one or more Unit 1 DC electrical power subsystems inoperable, the remaining DC electrical power distribution subsystems are capable of supporting the minimum safety functions necessary to shut down the reactor and maintain it in a safe shutdown condition, assuming no single failure. However, The overall reliability is reduced because a single failure in the remaining DC electrical power distribution subsystem could result in the minimum required ESF functions not being supported. The Completion Time of 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> is consistent with the Completion Times associated with a loss of one or more DC distribution subsystems and will allow sufficient time to restore power.

• SUSQUEHANNA - UNIT 2 3.8-90

Rev. 7 Distribution Systems'-Operating B 3.8.7 BASES ACTIONS 11 (continued)

(continued)

Completion of Required Action 1.1 causes Unit 1 loads to be powered from a Unit 2 DC electrical power subsystem. Although the corresponding Unit 2 DC elecbical power subsystem is evaluated for this condition, this condition is outside the design commitment to maintain DC power separation between unitS. To minimize the time this condition exists, Required Action 1.2 direct power to be restored from the corresponding Unit 1 DC electrical power subsystem, which restores power to the common loads, or requires that the Unit 1 and common loads be declared inoperable. The Completion Time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> provides sufficient time to restore power and acknowledges the fact that the condition, although not consistent with all design requirements, maintains all required safety systems available.

If Unit 1 and common loads required to support Unit 2 cannot be transferred to corresponding Unit 2 DC electrical power subsystem when

• Unit 1 DC sources are inoperable; or, cannot be transferred back to a Unit 1 DC source when the Unit 1 DC source becomes OPERABLE, the associated loads may be incapable of performing their intended function and must be declared inoperable immediately.

SURVEILLANCE SR 3.8.7.1 REQUIREMENTS This Surveillance verifies that the AC and DC, electrical power distribution systems are functioning properly, with the correct circuit breaker alignment. The correct breaker alignment ensures the appropriate independence of the electrical buses are maintained, and the appropriate voltage or indicated power ls available to each required bus.

This includes a verification that Unit 1 and common 125 voe loads are aligned to a Unit 1 DC power distribution subsystem. The verification of voltage availability on the buses ensures that the required voltage is readily available for motive as well as control functions for critical system loads connected to these buses. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program .

• SUSQUEHANNA - UNIT 2 3.8-91

Rev. 7 Distribution Systems-Operating B 3.8.7 BASES REFERENCES 1. FSAR, Chapter 6.

2. FSAR; Chapter 15.

3. Regulatory Guide 1.93, December 1974.

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

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• SUSQUEHANNA - UNIT 2 3.8-93