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Technical Specifications Bases, Manual
	ML25356A489
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Site:	Susquehanna
Issue date:	12/04/2025
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To:	; Document Control Desk, Office of Nuclear Reactor Regulation
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of 2

SSES MANUAL Manual Name:

TSB2 Manual

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL Table Of Cont ents Issue Date :

12/03/2025 Procedure Name Rev I ssue Date Chan e ID Chane Number TEXT LOES 138 01/03/2 019

Title:

LIST OF EFFECTIVE SECTIONS TEXT TOC 25 03/ 05/ 2 01 9

Title:

TABLE OF CONTENTS TEXT 2.1.1 7

03/30/2023 Title : SAFETY LIMITS (SLS) REACTOR CORE SLS TEXT 2.1.2 1

10/04/2007 Ti t l e : SAFETY LIMITS (SLS) REACTOR COOLANT SYSTEM (RCS) PRESSURE SL TEXT 3.0 5

03/18 / 20 21 Title : LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY TEXT 3.1.1 3

04/04/2 024 Title : REACTIVITY CONTROL SYSTEMS SHUTDOWN MARGIN (SDM)

TEXT 3.1. 2 0

11/18/2002 Title : REACTIVITY CONTROL SYSTEMS REACTIVI TY ANOMALI ES TEXT 3.1. 3 5

04/04/2024 Titl e : REACTIVI TY CONTROL SYSTEMS CONTROL ROD OPERABILITY TEXT 3.1.4 5

11/16/2 016 Title : REACTIVITY CONTROL SYSTEMS CONTROL ROD SCRAM TIMES TEXT 3.1.5 2

11/16/ 201 6 Titl e : REACTIVITY CONTROL SYSTEMS CONTROL ROD SCRAM ACCUMULATORS TEXT 3.1. 6 7

04/04/2024 Title : REACTIVITY CONTROL SYSTEMS ROD PATTERN CONTROL Page 1 of 8

Report Date : 12/03/ 25

SSES MANUAL Manual Name:

TSB2 Manual

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL TEXT 3.1. 7 5

01/05/2023

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 6

03/31/2021

Title:

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

TEXT 3.2.2 6

03/30/2023

Title:

POWER DISTRIBUTION LIMITS MINIMUM CRITICAL POWER RATIO (MCPR)

TEXT 3.2.3 4

03/31/2021

Title:

POWER DISTRIBUTION LIMITS LINEAR HEAT GENERATION RATE LHGR TEXT 3.3.1.1 7

01/05/2023

Title:

INSTRUMENTATION REACTOR PROTECTION SYSTEM (RPS) INSTRUMENTATION TEXT 3.3.1.2 4

01/23/2018

Title:

INSTRUMENTATION SOURCE RANGE MONITOR (SRM) INSTRUMENTATION TEXT 3. 3. 2.1 7

04/04/2024

Title:

INSTRUMENTATION CONTROL ROD BLOCK INSTRUMENTATION TEXT 3.3.2.2 4

01/05/2023

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 3

01/05/2023

Title:

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

Page 2 of 8

Report Date: 12/03/25

SSES MANUAL Manual Name:

TSB2 Manual

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL TEXT 3.3.4.2 2

01/05/2023

Title:

INSTRUMENTATION ANTICIPATED TRANSIENT WITHOUT SCRAM RECIRCULATION PUMP TRIP (ATWS-RPT) INSTRUMENTATION TEXT 3.3:5.1 8

01/05/2023

Title:

INSTRUMENTATION EMERGENCY CORE COOLING SYSTEM (ECCS) INSTRUMENTATION TEXT 3.3.5.2 3

03/18/2021

Title:

REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL INSTRUMENTATION TEXT 3.3.5.3 1

01/05/2023

Title:

REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM INSTRUMENTATION TEXT 3.3.6.1 11 04/02/2025

Title:

INSTRUMENTATION PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION TEXT 3.3.6.2 6

03/05/2019

Title:

INSTRUMENTATION SECONDARY CONTAINMENT ISOLATION INSTRUMENTATION TEXT 3.3.7.1 4

03/05/2019

Title:

INSTRUMENTATION CONTROL ROOM EMERGENCY OUTSIDE AIR SUPPLY (CREOAS) SYSTEM INSTRUMENTATION TEXT 3.3.8.1 7

01/05/2023

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 7

12/03/2025

Title:

REACTOR COOLANT SYSTEM (RCS) RECIRCULATION LOOPS OPERATING TEXT 3.4. 2 5

12/03/2025

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: 12/03 /25

I SSES MANUAL Manual Name:

TSB2 Manual

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL TEXT 3.4. 4 1

11/16/2016 Ti t le: 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 Titl e : REACTOR COOLANT SYSTEM (RCS) RCS LEAKAGE DETECTION INSTRUMENTATION TEXT 3.4.7 3

11/16/2016 Ti t le: REACTOR COOLANT SYSTEM (RCS) RCS SPECIFIC ACTIVITY TEXT 3.4.8 3

11/16/2016 Ti t le: 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 (RCS) RESIDUAL HEAT REMOVAL (RHR) SHUTDOWN COOLING SYSTEM COLD SHUTDOWN TEXT 3. 4. 10 6

05/14/2019

Title:

REACTOR COOLANT SYSTEM (RCS) RCS PRESSURE AND TEMPERATURE (P/T) LIMITS TEXT 3.4. 11 1

11/16/ 2016 Ti tle: REACTOR COOLANT SYSTEM (RCS) REACTOR STEAM DOME PRESSURE TEXT 3.5. 1 9

01/05/2023 Ti tle: EMERGENCY CORE COOLING SYSTEMS (ECCS) REACTOR PRESSURE VESSEL (RPV) WATER I NVENTORY CONTROL AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM ECCS OPERATING TEXT 3. 5.2 7

06/09/2022

Title:

EMERGENCY CORE COOLING SYSTEMS (ECCS) REACTOR PRESSURE VESSEL (RPV) WATER I NVENTORY CONTROL AND REACTOR CORE ISOLATION COOLING (RCI C) SYSTEM ECCS OPERATING TEXT 3.5.3 7

01/05/2023

Title:

EMERGENCY CORE COOLING SYSTEMS (ECCS) REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL AND REACTOR CORE ISOLATION COOLING (RCI C) SYSTEM ECCS OPERATING Page 4 of 8

Report Date : 12/0 3/25

SSES MANUAL Manual Name:

TSB2 Manual

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL TEXT 3.6.1.1 7

12/03/2025

Title:

PRIMARY CONTAINMENT TEXT 3.6.1.2 3

01/05/2023

Title:

CONTAINMENT SYSTEMS PRIMARY CONTAINMENT AIR LOCK TEXT 3.6.1.3 20 01/05/2023

Title:

CONTAINMENT SYSTEMS PRIMARY CONTAINMENT ISOLATION VALVES (PCIVS)

TEXT 3.6.1.4 3

11/27/2023

Title:

CONTAINMENT SYSTEMS CONTAINMENT PRESSURE TEXT 3.6.1.5 2

11/16/2016

Title:

CONTAINMENT SYSTEMS DRYWELL AIR TEMPERATURE TEXT 3.6.1.6 2

01/05/2023

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 3

01/05/2023

Title:

CONTAINMENT SYSTEMS RESIDUAL HEAT REMOVAL (RHR) SUPPRESSION POOL COOLING TEXT 3.6.2.4 2

01/05/2023

Title:

CONTAINMENT SYSTEMS RESIDUAL HEAT REMOVAL (RHR) SUPPRESSION POOL SPRAY TEXT 3.6.3.1

Title:

CONTAINMENT SYSTEMS TEXT 3.6.3.2 2

4 06/13/2006 INTENTIONALLY LEFT BLANK 08/02/2021

Title:

CONTAINMENT SYSTEMS DRYWELL AIR FLOW SYSTEM Page 5 of 8

Report Date: 12/03/25

SSES MANUAL Manual Name:

TSB2 Manual

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL TEXT 3.6.3.3 4

06/18/2024

Title:

CONTAINMENT SYSTEMS PRIMARY CONTAINMENT OXYGEN CONCENTRATION TEXT 3.6.4.1 17 12/16/2020

Title:

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

Title:

CONTAINMENT SYSTEMS SECONDARY CONTAINMENT ISOLATION VALVES (SCIVS)

TEXT 3.6.4.3 7

03/05/2019

Title:

CONTAINMENT SYSTEMS STANDBY GAS TREATMENT (SGT) SYSTEM TEXT 3.7.1 10 01/05/2023

Title:

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

TEXT 3.7.2 6

01/05/2023

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 TURBINE BYPASS SYSTEM TEXT 3.7.7 2

11/16/2016

Title:

PLANT SYSTEMS SPENT FUEL STORAGE POOL WATER LEVEL TEXT 3.7.8 1

11/16/2016

Title:

MAINE TURBINE PRESSURE REGULATION SYSTEM J

Page 6 of 8

Report Date: 12/03/25

SSES MANUAL Manual Name:

TSB2 Manual

Title:

TECHNICAL SPECIFICATIONS BASES UNIT 2 MANUAL TEXT 3.8.1 18 12/03/2025

Title:

ELECTRICAL POWER SYSTEMS AC SOURCES -

OPERATING TEXT 3.8.2 2

03/18/2021

Title:

ELECTRICAL POWER SYSTEMS AC SOURCES -

SHUTDOWN TEXT 3.8.3 7

08/07/2019

Title:

ELECTRICAL POWER SYSTEMS DIESEL FUEL OIL LUBE OIL AND STARTING AIR TEXT 3.8.4 5

01/05/2023

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

Title:

ELECTRICAL POWER SYSTEMS BATTERY CELL PARAMETERS 11/16/2016 TEXT 3.8.7 9

01/05/2023

Title:

ELECTRICAL POWER SYSTEMS DISTRIBUTION SYSTEMS -

OPERATING TEXT 3.8.8 2

03/05/2019

Title:

ELECTRICAL POWER SYSTEMS DISTRIBUTION SYSTEMS -

SHUTDOWN TEXT 3.9.1 1

11/16/2016

Title:

REFUELING OPERATIONS REFUELING EQUIPMENT INTERLOCKS TEXT 3. 9.2 2

11/16/2016

Title:

REFUELING OPERATIONS REFUEL POSITION ONE-ROD-OUT INTERLOCK TEXT 3.9.3 1

11/16/2016

Title:

REFUELING OPERATIONS CONTROL ROD POSITION TEXT 3.9.4 0

11/18/2002

Title:

REFUELING OPERATIONS CONTROL ROD POSITION INDICATION Page 7 of 8

Report Date: 12/03/25

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

Title:

REFUELING OPERATIONS REACTOR PRESSURE VESSEL (RPV) WATER LEVEL TEXT 3.9.7 1

11/16/2016

Title:

REFUELING OPERATIONS RESIDUAL HEAT REMOVAL (RHR)

- HIGH WATER LEVEL TEXT 3.9.8 1

11/16/2016

Title:

REFUELING OPERATIONS RESIDUAL HEAT REMOVAL (RHR) -

LOW WATER LEVEL TEXT 3.10.1 2

03/05/2019

Title:

SPECIAL OPERATIONS INSERVICE LEAK AND HYDROSTATIC TESTING OPERATION TEXT 3.10.2 1

11/16/2016

Title:

SPECIAL OPERATIONS REACTOR MODE SWITCH INTERLOCK TESTING TEXT 3.10.3 1

11/16/2016

Title:

SPECIAL OPERATIONS SINGLE CONTROL ROD WITHDRAWAL -

HOT SHUTDOWN TEXT 3.10.4 1

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 2

03/31/2021

Title:

SPECIAL OPERATIONS CONTROL ROD TESTING -

OPERATING TEXT 3.10.8 5

04/04/2024

Title:

SPECIAL OPERATIONS SHUTDOWN MARGIN (SDM) TEST -

REFUELING Page 8 of 8

Report Date: 12/03/25

Rev. 7 Recirculation Loops Operating B 3.4.1 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.1 Recirculation Loops Operating BASES BACKGROUND The Reactor Coolant Recirculation System is designed to provide a forced coolant flow through the core to remove heat from the fuel. The forced coolant flow removes more heat from the fuel than would be possible with just natural circulation. The forced flow, therefore, allows operation at significantly higher power than would otherwise be possible. The recirculation system also controls reactivity over a wide span of reactor power by varying the recirculation flow rate to control the void content of the moderator. The Reactor Coolant Recirculation System consists of two recirculation pump loops external to the reactor vessel. These loops provide the piping path for the driving flow of water to the reactor vessel jet pumps. Each external loop contains one variable speed motor driven recirculation pump, a motor generator (MG) set to control pump speed and associated piping, jet pumps, valves, and instrumentation. The recirculation pump, piping, and valves are part of the reactor coolant pressure boundary and are located inside the drywell structure. The jet pumps are reactor vessel internals.

The recirculated coolant consists of saturated water from the steam separators and dryers that has been subcooled by incoming feedwater.

This water passes down the annulus between the reactor vessel wall and the core shroud. A portion of the coolant flows from the vessel, through the two external recirculation loops, and becomes the driving flow for the jet pumps. Each of the two external recirculation loops discharges high pressure flow into an external manifold, from which individual recirculation inlet lines are routed to the jet pump risers within the reactor vessel. The remaining portion of the coolant mixture in the annulus becomes the suction flow for the jet pumps. This flow enters the jet pump at suction inlets and is accelerated by the driving flow. The drive flow and suction flow are mixed in the jet pump throat section. The total flow then passes through the jet pump diffuser section into the area below the core (lower plenum), gaining sufficient head in the process to drive the required flow upward through the core. The subcooled water enters the bottom of the fuel channels and contacts the fuel cladding, where heat is transferred to the coolant. As it rises, the coolant begins to boil, creating steam voids within the fuel channel that continue until the coolant exits the core.

Because of reduced moderation, the steam voiding introduces negative reactivity that must be compensated for to maintain or to increase reactor power. The recirculation flow control allows operators to increase recirculation flow and sweep some of the voids from the fuel channel, SUSQUEHANNA - UNIT 2 3.4-1

BASES BACKGROUND (continued)

APPLICABLE SAFETY ANALYSES Rev. 7 Recirculation Loops Operating B 3.4.1 overcoming the negative reactivity void effect. Thus, the reason for having variable recirculation flow is to compensate for reactivity effects of boiling over a wide range of power generation without having to move control rods and disturb desirable flux patterns.

Each recirculation loop is manually started from the control room. The MG set provides regulation of individual recirculation loop drive flows. The flow in each loop is manually controlled.

The operation of the Reactor Coolant Recirculation System is an initial condition assumed in the design basis loss of coolant accident (LOCA)

(Ref. 1 ). During a LOCA caused by a recirculation loop pipe break, the intact loop is assumed to provide coolant flow during the first few seconds of the accident. The initial core flow decrease is rapid because the recirculation pump in the broken loop ceases to pump reactor coolant to the vessel almost immediately. The pump in the intact loop coasts down relatively slowly. This pump coastdown governs the core flow response for the next several seconds until the jet pump suction is uncovered (Ref. 1 ). The analyses assume that both loops are operating at the same flow prior to the accident. However, the LOCA analysis was reviewed for the case with a flow mismatch between the two loops, with the pipe break assumed to be in the loop with the higher flow. While the flow coastdown and core response are potentially more severe in this assumed case (since the intact loop starts at a lower flow rate and the core response is the same as if both loops were operating at a lower flow rate), a small mismatch has been determined to be acceptable based on engineering judgment. The recirculation system is also assumed to have sufficient flow coastdown characteristics to maintain fuel thermal margins during abnormal operational transients (Ref. 2), which are analyzed in Chapter 15 of the FSAR.

Plant specific LOCA analyses have been performed assuming only one operating recirculation loop. These analyses have demonstrated that, in the event of a LOCA caused by a pipe break in the operating recirculation loop, the Emergency Core Cooling System response will provide adequate core cooling, provided that the APLHGR limits for ATRIUM 10 and ATRIUM 11 fuel are modified.

SUSQUEHANNA - UNIT 2 3.4-2

BASES APPLICABLE SAFETY ANALYSES (continued)

LCO Rev. 7 Recirculation Loops Operating B 3.4.1 The transient analyses of Chapter 15 of the FSAR have also been performed for single recirculation loop operation and demonstrate sufficient flow coastdown characteristics to maintain fuel thermal margins during the abnormal operational transients analyzed provided the MCPR requirements are modified. During single recirculation loop operation, modification to the Reactor Protection System (RPS) average power range monitor (APRM) instrument setpoints is also required to account for the different relationships between recirculation drive flow and reactor core flow. The APLHGR, LHGR, and MCPR limits for single loop operation are specified in the COLR. The APRM Simulated Thermal Power-High setpoint is in LCO 3.3.1.1, "Reactor Protection System (RPS)

Instrumentation." In addition, a restriction on recirculation pump speed is incorporated to address reactor vessel internals vibration concerns and assumptions in the event analysis.

Recirculation loops operating satisfies Criterion 2 of the NRC Policy Statement (Ref. 5).

Two recirculation loops are required to be in operation with their flows matched within the limits specified in SR 3.4.1.1 to ensure that during a LOCA caused by a break of the piping of one recirculation loop the assumptions of the LOCA analysis are satisfied. With the limits specified in SR 3.4.1.1 not met, the recirculation loop with the lower flow must be considered not in operation. With only one recirculation loop in operation, modifications to the required APLGHR limits (LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE"), LHGR limits (LCO 3.2.3, "LINEAR HEAT GENERATION RATE (LHGR)"), MCPR limits (LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)"), and APRM Simulated Thermal Power-High setpoint (LCO 3.3.1.1) may be applied to allow continued operation consistent with the safety analysis assumptions.

Furthermore, restrictions are placed on recirculation pump speed to ensure the initial assumption of the event analysis are maintained.

The LCO is modified by a Note that allows up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months to establish the required limits and setpoints after a change from two recirculation loops operation to single recirculation loop operation. If the limits and setpoints are not in compliance with the applicable requirements at the end of this period, the ACTIONS required by the applicable specifications must be implemented. This time is provided to stabilize operation with one recirculation loop by: limiting flow in the operating loop, limiting total THERMAL POWER, monitor APRM and local power range monitor (LPRM) neutron flux noise levels; and, fully implementing and confirming the required limit and setpoint modifications.

SUSQUEHANNA - UNIT 2 3.4-3

BASES APPLICABILITY ACTIONS Rev. 7 Recirculation Loops Operating B 3.4.1 In MODES 1 and 2, requirements for operation of the Reactor Coolant Recirculation System are necessary since there is considerable energy in the reactor core and the limiting design basis transients and accidents are assumed to occur.

In MODES 3, 4, and 5, the consequences of an accident are reduced and the coastdown characteristics of the recirculation loops are not important.

A.1 When operating with no recirculation loops operating in MODE 1, the potential for thermal-hydraulic oscillations is greatly increased. Although this transient is protected for expected modes of oscillation by the OPRM system, when OPERABLE per LCO 3.3.1.1, function 2.f (Reference 3, 4 ),

the prudent response to the natural circulation condition is to preclude potential thermal-hydraulic oscillations by immediately placing the mode switch in the shutdown position.

8.1 Recirculation loop flow must match within required limits when both recirculation loops are in operation. lfflow mismatch is not within required limits, matched flow must be restored within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months . If matched flows are not restored, the recirculation loop with lower flow must be declared "not in operation." Should a LOCA occur with recirculation loop flow not matched, the core flow coastdown and resultant core response may not be bounded by the LOCA analyses. Therefore, only a limited time is allowed prior to imposing restrictions associated with single loop operation. Operation with only one recirculation loop satisfies the requirements of the LCO and the initial conditions of the accident sequence.

The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time is based on the low probability of an accident occurring during this time period, providing a reasonable time to complete the Required Action, and considering that frequent core monitoring by operators allows abrupt changes in core flow conditions to be quickly detected.

These Required Actions do not require tripping the recirculation pump in the lowest flow loop when the mismatch between total jet pump flows of the two loops is greater than the required limits. However, in cases where large flow mismatches occur, low flow or reverse flow can occur in the low flow loop jet pumps, causing vibration of the jet pumps. If zero or reverse SUSQUEHANNA - UNIT 2 3.4-4

BASES ACTIONS

( continued)

SURVEILLANCE REQUIREMENTS B.1 (continued)

Rev. 7 Recirculation Loops Operating B 3.4.1 flow is detected, the condition should be alleviated by changing recirculation pump speed to re-establish forward flow or by tripping the pump.

C.1 With no recirculation loops in operation while in MODE 2 or if after going to single loop operations the required limits and setpoints cannot be established, the plant must be brought to MODE 3, where the LCO does not apply within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . In this condition, the recirculation loops are not required to be operating because of the reduced severity of DBAs and minimal dependence on the recirculation loop coastdown characteristics.

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

SR 3.4.1.1 This SR ensures the recirculation loops are within the allowable limits for mismatch. At low core flow (i.e., < 75 million lbm/hr), the MCPR requirements provide larger margins to the fuel cladding integrity Safety Limit such that the potential adverse effect of early boiling transition during a LOCA is reduced. A larger flow mismatch can therefore be allowed when core flow is < 75 million lbm/hr. The recirculation loop jet pump flow, as used in this Surveillance, is the summation of the flows from all of the jet pumps associated with a single recirculation loop.

The mismatch is measured in terms of core flow. If the flow mismatch exceeds the specified limits, the loop with the lower flow is considered inoperable. The SR is not required when both loops are not in operation since the mismatch limits are meaningless during single loop or natural circulation operation. The Surveillance must be performed within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after both loops are in operation. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.4.1.2 As noted, this SR is only applicable when in single loop operation. This SR ensures the recirculation pump limit is maintained. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SUSQUEHANNA - UNIT 2 3.4-5

BASES REFERENCES

1.

FSAR, Section 6.3.3.7.

2. FSAR, Section 5.4.1.4.

Rev. 7 Recirculation Loops Operating B 3.4.1

3.

GE NEDO-31960-A "BWROG Long Term Stability Solutions Licensing Methodology," November 1995.

4.

GE NEDO-31960-A "BWROG Long Term Stability Solutions Licensing Methodology," Supplement 1, November 1995.

5.

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

SUSQUEHANNA - UNIT 2 3.4-6

BASES Rev. 7 Recirculation Loops Operating B 3.4.1 THIS PAGE INTENTIONALLY LEFT BLANK SUSQUEHANNA - UNIT 2 3.4-7

BASES Rev. 7 Recirculation Loops Operating B 3.4.1 THIS PAGE INTENTIONALLY LEFT BLANK SUSQUEHANNA - UNIT 2 3.4-8

BASES Rev. 7 Recirculation Loops Operating B 3.4.1 THIS PAGE INTENTIONALLY LEFT BLANK SUSQUEHANNA - UNIT 2 3.4-9

Rev. 5 Jet Pumps B 3.4.2 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.2 Jet Pumps BASES BACKGROUND APPLICABLE SAFETY ANALYSES The Reactor Coolant Recirculation System is described in the Background section of the Bases for LCO 3.4.1, "Recirculation Loops Operating," which discusses the operating characteristics of the system and how these characteristics affect the Design Basis Accident (OBA) analyses.

The jet pumps are part of the Reactor Coolant Recirculation System and are designed to provide forced circulation through the core to remove heat from the fuel. The jet pumps are located in the annular region between the core shroud and the vessel inner wall. Because the jet pump suction elevation is at two-thirds core height, the vessel can be reflooded and coolant level maintained at two-thirds core height even with the complete break of the recirculation loop pipe that is located below the jet pump suction elevation.

Each reactor coolant recirculation loop contains ten jet pumps.

Recirculated coolant passes down the annulus between the reactor vessel wall and the core shroud. A portion of the coolant flows from the vessel, through the two external recirculation loops, and becomes the driving flow for the jet pumps. Each of the two external recirculation loops discharges high pressure flow into an external manifold from which individual recirculation inlet lines are routed to the jet pump risers within the reactor vessel. The remaining portion of the coolant mixture in the annulus becomes the suction flow for the jet pumps. This flow enters the jet pump at suction inlets and is accelerated by the drive flow. The drive flow and suction flow are mixed in the jet pump throat section. The total flow then passes through the jet pump diffuser section into the area below the core (lower plenum), gaining sufficient head in the process to drive the required flow upward through the core.

Jet pump OPERABILITY is an explicit assumption in the design basis loss of coolant accident (LOCA) analysis evaluated in Reference 1.

SUSQUEHANNA - UNIT 2 3.4-10

BASES APPLICABLE SAFETY ANALYSES (continued)

LCO APPLICABILITY ACTIONS Rev. 5 Jet Pumps B 3.4.2 The capability of reflooding the core to two-thirds core height is dependent upon the structural integrity of the jet pumps. If the structural system, including the beam holding a jet pump in place, fails, jet pump displacement and performance degradation could occur, resulting in an increased flow area through the jet pump and a lower core flooding elevation. This could adversely affect the water level in the core during the reflood phase of a LOCA as well as the assumed blowdown flow during a LOCA.

Jet pumps satisfy Criterion 2 of the NRC Policy Statement (Ref. 4).

The structural failure of any of the jet pumps could cause significant degradation in the ability of the jet pumps to allow reflooding to two-thirds core height during a LOCA. OPERABILITY of all jet pumps is required to ensure that operation of the Reactor Coolant Recirculation System will be consistent with the assumptions used in the licensing basis analysis (Ref. 1).

In MODES 1 and 2, the jet pumps are required to be OPERABLE since there is a large amount of energy in the reactor core and since the limiting DBAs are assumed to occur in these MODES. This is consistent with the requirements for operation of the Reactor Coolant Recirculation System (LCO 3.4.1 ).

In MODES 3, 4, and 5, the Reactor Coolant Recirculation System is not required to be in operation, and when not in operation, sufficient flow is not available to evaluate jet pump OPERABILITY.

A.1 An inoperable jet pump can increase the blowdown area and reduce the capability of reflooding during a design basis LOCA. If one or more of the jet pumps are inoperable, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems.

SUSQUEHANNA - UNIT 2 3.4-11

BASES SURVEILLANCE REQUIREMENTS SR 3.4.2.1 Rev. 5 Jet Pumps B 3.4.2 This SR is designed to detect significant degradation in jet pump performance that precedes jet pump failure (Ref. 2). This SR is required to be performed only when the loop has forced recirculation flow since surveillance checks and measurements can only be performed during jet pump operation. With no forced recirculation flow, stresses on jet pump assemblies are significantly reduced. The jet pump failure of concern is a complete mixer displacement due to jet pump beam failure. Jet pump plugging is also of concern since it adds flow resistance to the recirculation loop. Significant degradation is indicated if the specified criteria confirm unacceptable deviations from established patterns or relationships. The allowable deviations from the established patterns have been developed based on the variations experienced at plants during normal operation and with jet pump assembly failures (Refs. 2 and 3). Each recirculation loop must satisfy two of the performance criteria provided. Since refueling activities (fuel assembly replacement or shuffle, as well as any modifications to fuel support orifice size or core plate bypass flow) can affect the relationship between core flow, jet pump flow, and recirculation loop flow, these relationships may need to be re-established each cycle.

Similarly, initial entry into extended single loop operation may also require establishment of these relationships. During the initial weeks of operation under such conditions, while base-lining new "established patterns,"

engineering judgment of the daily surveillance results is used to detect significant abnormalities, which could indicate a jet pump failure.

The recirculation pump speed operating characteristics (loop drive flow versus pump speed) are determined by the flow resistance from the loop suction through the jet pump nozzles. A change in the relationship indicates a plug, flow restriction, loss in pump hydraulic performance, leakage, or new flow path between the recirculation pump discharge and jet pump nozzle. For this criterion, loop drive flow versus pump speed relationship must be verified. Note that recirculation pump speed is directly proportional to recirculation motor generator speed (Reference 5).

Therefore, recirculation motor generator speed can be used for the purposes of this surveillance.

Individual jet pumps in a recirculation loop normally do not have the same flow. The unequal flow is due to the drive flow manifold, which does not distribute flow equally to all risers. The flow (or jet pump diffuser to lower plenum differential pressure) pattern or relationship of one jet pump to the loop average is repeatable. An appreciable change in this relationship is an indication that increased (or reduced) resistance has occurred in one of the jet pumps. This may be indicated by an increase in the relative flow for a jet pump that has experienced beam cracks.

SUSQUEHANNA - UNIT 2 3.4-12

BASES SURVEILLANCE REQUIREMENTS

( continued)

REFERENCES SR 3.4.2.1 (continued)

Rev. 5 Jet Pumps B 3.4.2 The deviations from normal are considered indicative of a potential problem in the recirculation drive flow or jet pump system (Ref. 2). Normal flow ranges and established jet pump flow and differential pressure patterns are established by plotting historical data as discussed in Reference 2.

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

This SR is modified by two Notes. If this SR has not been performed in the previous 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months at the time an idle recirculation loop is restored to service, Note 1 allows 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after the idle recirculation loop is in operation before the SR must be completed because these checks can only be performed during jet pump operation. The 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is an acceptable time to establish conditions and complete data collection and evaluation.

Note 2 allows deferring completion of this SR until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after THERMAL POWER is greater than 23% of RTP. During low flow conditions, jet pump noise approaches the threshold response of the associated flow instrumentation and precludes the collection of repeatable and meaningful data.

1.

FSAR, Section 6.3.

2.

GE Service Information Letter No. 330, June 9, 1990.

3.

NUREG/CR-3052, November 1984.

4.

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

5.

FSAR, Section 7.7.

SUSQUEHANNA - UNIT 2 3.4-13

BASES THIS PAGE INTENTIONALLY LEFT BLANK SUSQUEHANNA - UNIT 2 3.4-14 Rev. 5 Jet Pumps B 3.4.2 r

I

Rev. 7 Primary Containment B 3.6.1.1 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.1 Primary Containment BASES BACKGROUND The function of the primary containment is to isolate and contain fission products released from the Reactor Primary System following a Design Basis Loss of Coolant Accident confine the postulated release of radioactive material. The primary containment consists of a steel lined, reinforced concrete vessel, which surrounds the Reactor Primary System and provides an essentially leak tight barrier against an uncontrolled release of radioactive material to the environment.

The isolation devices for the penetrations in the primary containment boundary are a part of the containment leak tight barrier. To maintain this leak tight barrier:

a.

All penetrations required to be closed during accident conditions are either:

1.

capable of being closed by an OPERABLE automatic containment isolation system, or

2.

closed by manual valves, blind flanges, or de-activated automatic valves secured in their closed positions, except as provided in LCO 3.6.1.3, "Primary Containment Isolation Valves (PCIVs)";

b.

The primary containment air lock is OPERABLE, except as provided in LCO 3.6.1.2, "Primary Containment Air Lock"; and

c.

All equipment hatches are closed.

Several instruments connect to the primary containment atmosphere and are considered extensions of the primary containment. The leak rate tested instrument isolation valves identified in the Leakage Rate Test Program should be used as the primary containment boundary when the instruments are isolated and/or vented. Table B 3.6.1.1-1 contains the listing of the instruments and isolation valves.

SUSQUEHANNA - UNIT 2 3.6-1

BASES BACKGROUND

( continued)

APPLICABLE SAFETY ANALYSES Rev. 7 Primary Containment B 3.6.1.1 The H2O2 Analyzer lines beyond the PCIVs, up to and including the components within the H2O2 Analyzer panels, are extensions of primary containment (i.e., closed system), and are required to be leak rate tested in accordance with the Leakage Rate Test Program. The H2O2 Analyzer closed system boundary is identified in the Leakage Rate Test Program, and consists of components, piping, tubing, fittings, and valves, which meet the design guidance of Reference 7. Within the H2O2 Analyzer panels, the boundary ends at the first normally closed valve. The closed system boundary between PASS and the H2O2 Analyzer system ends at the Seismic Category I boundary between the two systems. This boundary occurs at the process sampling solenoid operated isolation valves (SV-22361, SV-22365, SV-22366, SV-22368, and SV-22369).

These solenoid operated isolation valves do not fully meet the guidance of Reference 7 for closed system boundary valves in that they are not powered from a Class 1 E power source. Based upon a risk determination, operating these valves as closed system boundary valves is not risk significant. These normally closed valves are required to be leakage rate tested in accordance with the Leakag~ Rate Test Program, since they form part of the closed system boundary for the H2O2 Analyzers. These valves are "closed system boundary valves" and may be opened under administrative control, as delineated in Technical Requirements Manual (TRM) Bases 3.6.4. Opening of these valves to permit testing of PASS in Modes 1, 2, and 3 is permitted in accordance with TRO 3.6.4.

When the H2O2 Analyzer panels are isolated and/or vented, the panel isolation valves identified in the Leakage Rate Test Program should be used as the boundary of the extension of primary containment.

Table B 3.6.1.1-2 contains a listing of the affected H2O2 Analyzer penetrations and panel isolation valves.

This Specification ensures that the performance of the primary containment, in the event of a Design Basis Accident (OBA), meets the assumptions used in the safety analyses of References 1 and 2.

SR 3.6.1.1.1 leakage rate requirements are in conformance with 10 CFR 50, Appendix J, Option B and supporting documents (Ref. 3, 4 and 5), as modified by approved exemptions.

The safety design basis for the primary containment is that it must withstand the pressures and temperatures of the limiting OBA without exceeding the design leakage rate.

SUSQUEHANNA - UNIT 2 3.6-2

BASES APPLICABLE SAFETY ANALYSES

( continued)

LCO APPLICABILITY Rev. 7 Primary Containment B 3.6.1.1 The OBA that postulates the maximum release of radioactive material within primary containment is a LOCA. In the analysis of this accident, it is assumed that primary containment is OPERABLE such that release of fission products to the environment is controlled by the rate of primary containment leakage.

Analytical methods and assumptions involving the primary containment are presented in References 1 and 2. The safety analyses assume a nonmechanistic fission product release following a OBA, which forms the basis for determination of offsite and control room doses. The fission product release is, in turn, based on an assumed leakage rate from the primary containment. OPERABILITY of the primary containment ensures that the leakage rate assumed in the safety analyses is not exceeded.

The maximum allowable leakage rate for the primary containment (La) is 1.0% by weight of the containment air per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months at the design basis LOCA maximum peak containment pressure (Pa) of 48.6 psig.

Primary containment satisfies Criterion 3 of the NRC Policy Statement.

(Ref. 6)

Primary containment OPERABILITY is maintained by limiting leakage to

1.0 La, except prior to each startup after performing a required Primary Containment Leakage Rate Testing Program leakage test. At this time, applicable leakage limits must be met. Compliance with this LCO will ensure a primary containment configuration, including equipment hatches, that is structurally sound and that will limit leakage to those leakage rates assumed in the safety analyses.

Individual leakage rates specified for the primary containment air lock are addressed in LCO 3.6.1.2.

Leakage requirements for MSIVs and Secondary containment bypass are addressed in LCO 3.6.1.3.

In MODES 1, 2, and 3, a OBA could cause a release of radioactive material to primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, primary containment is not required to be OPERABLE in MODES 4 and 5 to prevent leakage of radioactive material from primary containment.

SUSQUEHANNA - UNIT 2 3.6-3

BASES ACTIONS SURVEILLANCE REQUIREMENTS A.1 Rev. 7 Primary Containment B 3.6.1.1 In the event primary containment is inoperable, primary containment must be restored to OPERABLE status within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time provides a period of time to correct the problem commensurate with the importance of maintaining primary containment OPERABILITY during MODES 1, 2, and 3. This time period also ensures that the probability of an accident (requiring primary containment OPERABILITY) occurring during periods where primary containment is inoperable is minimal.

8.1 and B.2 If primary containment cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SR 3.6.1.1.1 Maintaining the primary containment OPERABLE requires compliance with the visual examinations and leakage rate test requirements of the Primary Containment Leakage Rate Testing Program. The primary containment concrete visual examinations may be performed during either power operation, e.g., performed concurrently with other primary containment inspection-related activities, or during a maintenance or refuel outage. The visual examinations of the steel liner plate inside primary containment are performed during maintenance or refueling outages since this is the only time the liner plate is fully accessible.

Failure to meet air lock leakage testing (SR 3.6.1.2.1) or resilient seal primary containment purge valve leakage testing (SR 3.6.1.3.6) does not necessarily result in a failure of this SR. The impact of the failure to meet these SRs must be evaluated against the Type A, B, and C acceptance criteria of the Primary Containment Leakage Rate Testing Program. As left leakage prior to each startup after performing a required leakage test is required to be < 0.6 La for combined Type B and C leakage, and ~ 0. 75 La for overall Type A leakage. At all other times between required leakage rate tests, the acceptance criteria is based on an overall Type A leakage limit of ~ 1.0 La. At ~ 1.0 La the offsite and control room dose consequences are bounded by the assumptions of the safety analysis.

The Frequency is required by the Primary Containment Leakage Rate Testing Program.

SUSQUEHANNA - UNIT 2 3.6-4

BASES SURVEILLANCE REQUIREMENTS

( continued)

SR 3.6.1.1.1 (continued)

Rev. 7 Primary Containment B 3.6.1.1 SR Frequencies are as required by the Primary Containment Leakage Rate Testing Program. These periodic testing requirements verify that the primary containment leakage rate does not exceed the leakage rate assumed in the safety analysis.

As noted in Table B 3.6.1.3-1, an exemption to Appendix J is provided that isolation barriers which remain filled or a water seal remains in the line post-LOCA are tested with water and the leakage is not included in the Type B and C 0.60 La total.

SR 3.6.1.1.2 Maintaining the pressure suppression function of primary containment requires limiting the leakage from the drywell to the suppression chamber.

Thus, if an event were to occur that pressurized the drywell, the steam would be directed through the downcomers into the suppression pool.

This SR measures drywell to suppression chamber leakage to ensure that the leakage paths that would bypass the suppression pool are within allowable limits. The allowable limit is 10% of the acceptable SSES Nk design value. For SSES, the Nk design value is.0535 ft2.

Satisfactory performance of this SR can be achieved by establishing a known differential pressure between the drywell and the suppression chamber and determining the leakage. The leakage test is performed when the 10 CFR 50, Appendix J, Type A test is performed in accordance with the Primary Containment Leakage Rate Testing Program. This testing Frequency was developed considering this test is performed in conjunction with the Integrated Leak rate test and also in view of the fact that component failures that might have affected this test are identified by other primary containment SRs. Two consecutive test failures, however, would indicate unexpected primary containment degradation; in this event, as the Note indicates, increasing the Frequency to once every 24 months is required until the situation is remedied as evidenced by passing two consecutive tests.

SUSQUEHANNA - UNIT 2 3.6-5

BASES SURVEILLANCE REQUIREMENTS

( continued)

REFERENCES SR 3.6.1.1.3 Rev. 7 Primary Containment B 3.6.1.1 Maintaining the pressure suppression function of primary containment requires limiting the leakage from the drywell to the suppression chamber.

Thus, if an event were to occur that pressurized the drywell, the steam would be directed through downcomers into the suppression pool. This SR measures suppression chamber-to-drywell vacuum breaker leakage to ensure the leakage paths that would bypass the suppression pool are within allowable limits. The total allowable leakage limit is 30% of the SR 3.6.1.1.2 limit. The allowable leakage per set is 12% of the SR 3.6.1.1.2 limit.

The leakage is determined by establishing a 4.3 psi differential pressure across the drywell-to-suppression chamber vacuum breakers and verifying the leakage. A Note is provided which allows this Surveillance not to be performed when SR 3.6.1.1.2 is performed. This is acceptable because SR 3.6.1.1.2 ensures the OPERABILITY of the pressure suppression function including the suppression chamber-to-drywell vacuum breakers. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

1.

FSAR, Section 6.2.

2.

FSAR, Section 15.

3.

1 O CFR 50, Appendix J, Option B.

4.

Nuclear Energy Institute, 94-01.

5.

ANSI/ANS 56.8-2020.

6.

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

7.

Standard Review Plan 6.2.4, Rev. 1, September 1975.

SUSQUEHANNA-UNIT 2 3.6-6

BASES TABLE B 3.6.1.1-1 Rev. 7 Primary Containment B 3.6.1.1 INSTRUMENT ISOLATION VALVES (Page 1 of 2)

PENETRATION INSTRUMENT INSTRUMENT ISOLATION NUMBER VALVE X-3B PSH-C72-2N002A IC-PSH-2N002A PSH L C72-2N004 IC-PSHL-2N004 PS-E11-2N010A IC-PS-2N010A PS-E11-2N011A IC-PS-2N011A PSH-C72-2N002B IC-PSH-2N002B PS-E11-2N01 0C IC-PS-2N010C PS-E11-2N011C IC-PS-2N011 C PSH-25120C IC-PSH-25120C X-32A PSH-C72-2N002D IC-PSH-2N002D PS-E11-2N010B IC-PS-2N010B PS-E11-2N011 B IC-PS-2N011 B PSH-C72-2N002C IC-PSH-2N002C PS-E11-2N010D IC-PS-2N010D PS-E11-2N011 D IC-PS-2N011 D PSH-25120D IC-PSH-25120D X-39A FT-25120A IC-FT-25120A HIGH and IC-FT-25120A LOW X-39B FT-25120B IC-FT-25120B HIGH and IC-FT-25120B LOW X-90A PT-25709A IC-PT-25709A PT-25710A IC-PT-2571 0A PT-25728A1 IC-PT-25728A 1 X-90D PT-25709B IC-PT-25709B PT-25710B IC-PT-2571 OB PT-25728A IC-PT-25728A SUSQUEHANNA - UNIT 2 3.6-6a

BASES TABLE B 3.6.1.1-1 Rev. 7 Primary Containment B 3.6.1.1 INSTRUMENT ISOLATION VALVES (Page 2 of 2)

PENETRATION INSTRUMENT INSTRUMENT ISOLATION NUMBER VALVE X-204A/205A FT-25121A IC-FT-25121A HIGH and IC-FT-25121A LOW X-2048/2058 FT-25121 B IC-FT-25121 B HIGH and IC-FT-25121 BLOW X-219A LT-25775A IC-L T-25775A REF and IC-LT-25775A VAR LSH-E41-2N015A 255027 and 255031 LSH-E41-2N0158 255029 and 255033 X-223A PT-25702 IC-PT-25702 X-232A LT-25776A IC-L T-25776A REF and IC-LT-25776A VAR PT-25729A IC-PT-25729A X234A L T-257758 IC-L T-257758 REF and IC-L T-257758 VAR X-235A LT-257768 IC-L T-257768 REF and IC-LT-257768 VAR PT-257298 IC-PT-257298 Ll-2577682 IC-Ll-2577682 REF and IC-Ll-2577682 VAR SUSQUEHANNA - UNIT 2 3.6-6b

Rev. 7 Primary Containment B 3.6.1.1 BASES TABLE B 3.6.1.1-2 H2O2 ANALYZER PANEL ISOLATION VALVES PENETRATION NUMBER PANEL ISOLATION VALVE<a>

X-60A, X-88B, X-221A, X-238A 257138 257139 257140 257141 257142 X-80C, X-221 B, X-238B 257149 257150 257151 257152 257153 (a)

Only those valves listed in this table with current leak rate test results, as identified in the Leakage Rate Test Program, may be used as isolation valves.

SUSQUEHANNA-UNIT 2 3.6-6c

Rev. 18 AC Sources - Operating B 3.8.1 B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.1 AC Sources - Operating BASES BACKGROUND The unit Class 1 E AC Electrical Power Distribution System AC sources consist of two offsite power sources (preferred power sources, normal and alternate), and the onsite standby power sources (diesel generators (DGs) A, B, C and D). A fifth diesel generator, DG E, can be used as a substitute for any one of the four DGs A, B, C or D. As required by 10 CFR 50, Appendix A, GDC 17 (Ref. 1), the design of the AC electrical power system provides independence and redundancy to ensure an available source of power to the Engineered Safety Feature (ESF) systems.

The Class 1 E AC distribution system is divided into redundant load groups, so loss of any one group does not prevent the minimum safety functions from being performed. Each load group has connections to two preferred offsite power supplies and a single DG.

The two qualified circuits between the offsite transmission network and the onsite Class 1 E AC Electrical Power Distribution System are supported by two independent offsite power sources. A 230 kV line from the Susquehanna T10 230 kV switching station feeds start-up transformer No. 1 O; and, a 230 kV tap from the 500-230 kV tie line feeds the startup transformer No. 20. The term "qualified circuits", as used within TS 3.8.1, is synonymous with the term "physically independent".

The two independent offsite power sources are supplied to and are shared by both units. These two electrically and physically separated circuits provide AC power, through startup transformers (ST) No. 10 and ST No. 20, to the four 4.16 kV Engineered Safeguards System (ESS) buses (A, B, C and D) for both Unit 1 and Unit 2. A detailed description of the offsite power network and circuits to the onsite Class 1 E ESS buses is found in the FSAR, Section 8.2 (Ref. 2).

An offsite circuit consists of all breakers, transformers, switches, automatic tap changers, interrupting devices, cabling, and controls required to transmit power from the offsite transmission network to the onsite Class 1 E ESS bus or buses.

SUSQUEHANNA - UNIT 2 3.8-1

BASES BACKGROUND

( continued)

Rev. 18 AC Sources - Operating B 3.8.1 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.

When off-site power is available to the 4.16 kV ESS Buses following a LOCA signal, the required ESS loads will be sequenced onto the 4.16 kV ESS Buses in order to compensate for voltage drops in the onsite power system when starting large ESS motors.

The onsite standby power source for 4.16 kV ESS buses A, B, C and D consists of five DGs. DGs A, B, C and D are dedicated to ESS buses A, B, C and D, respectively. DG E can be used as a substitute for any one of the four DGs (A, B, C or D) to supply the associated ESS bus. Each DG provides standby power to two 4.16 kV ESS buses-one associated with Unit 1 and one associated with Unit 2. The four "required" DGs are those aligned to a 4.16 kV ESS bus to provide onsite standby power for both Unit 1 and Unit 2.

A DG, when aligned to an ESS bus, starts automatically on a loss of coolant accident (LOCA) signal (i.e., low reactor water level signal or high drywell pressure signal) or on an ESS bus degraded voltage or undervoltage signal. After the DG has started, it automatically ties to its respective bus after offsite power is tripped as a consequence of ESS bus undervoltage or degraded voltage, independent of or coincident with a LOCA signal. The DGs also start and operate in the standby mode without tying to the ESS bus on a LOCA signal alone. Following the trip of offsite power, non-permanent loads are stripped from the 4.16 kV ESS Buses.

When a DG is tied to the ESS Bus, loads are then sequentially connected to their respective ESS Bus by individual load timers. The individual load timers control the starting permissive signal to motor breakers to prevent overloading the associated DG.

In the event of loss of normal and alternate offsite power supplies, the 4.16 kV ESS buses will shed all loads except the 480 V load centers and the standby diesel generators will connect to the ESS busses. When a DG is tied to its respective ESS bus, loads are then sequentially connected to the ESS bus by individual load timers which control the permissive and starting signals to motor breakers to prevent overloading the DG.

In the event of a loss of normal and alternate offsite power supplies, the ESS electrical loads are automatically connected to the DGs in sufficient time to provide for safe reactor shutdown and to mitigate the consequences of a Design Basis Accident (OBA) such as a LOCA.

SUSQUEHANNA - UNIT 2 3.8-2

BASES BACKGROUND

( continued)

APPLICABLE SAFETY ANALYSES LCO Rev. 18 AC Sources - Operating B 3.8.1 Certain required plant loads are returned to service in a predetermined sequence in order to prevent overloading of the DGs in the process. Within 286 seconds after the initiating signal is received, all automatic and permanently connected loads needed to recover the unit or maintain it in a safe condition are returned to service. Ratings for the DGs satisfy the requirements of Regulatory Guide 1.9 (Ref. 3).

DGs A, B, C and D have the following ratings:

a.

4000 kW - continuous,

b.

4700 kW - 2000 hours0.0231 days 0.556 hours 0.00331 weeks 7.61e-4 months , DG E has the following ratings:

a.

5000 kW - continuous,

b.

5500 kW - 2000 hours0.0231 days 0.556 hours 0.00331 weeks 7.61e-4 months .

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).

Two qualified circuits between the offsite transmission network and the onsite Class 1 E Distribution System and four separate and independent DGs (A, B, C and D) ensure availability of the required power to shut down the reactor and maintain it in a safe shutdown condition after an anticipated operational occurrence (AOO) or a postulated OBA. DG E can be used as a substitute for any one of the four DGs A, B, C or D.

Qualified offsite circuits are those that are described in the FSAR, and are part of the licensing basis for the unit. In addition, the required automatic load timers for each ESF bus shall be OPERABLE.

SUSQUEHANNA-UNIT 2 3.8-3

BASES LCO (continued)

Rev. 18 AC Sources - Operating B 3.8.1 The Safety Analysis for Unit 2 assumes the OPERABILITY of some equipment that receives power from Unit 1 AC Sources. Therefore, Unit 2 Technical Specifications establish requirements for the OPERABILITY of the DG(s) and qualified offsite circuits needed to support the Unit 1 onsite Class 1 E AC electrical power distribution subsystem(s) required by LCO 3.8.7, Distribution Systems-Operating.

Each offsite circuit must be capable of maintaining rated frequency and voltage, and accepting required loads during an accident, while connected to the ESS buses.

One OPERABLE offsite circuit exists when all of the following conditions are met:

1. An energized ST. No. 10 transformer with the load tap changer (LTC) in automatic operation.

2. The respective circuit path including energized ESS transformers 101 and 111 and feeder breakers capable of

~upplying 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.

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.

SUSQUEHANNA - UNIT 2 3.8-4

BASES LCO (continued)

Rev. 18 AC Sources - Operating B 3.8.1 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 (L TC) 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.

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.

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.

SUSQUEHANNA - UNIT 2 3.8-5

BASES LCO (continued)

Rev. 18 AC Sources - Operating B 3.8.1 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 assumptions of the accident analyses. Each required DG must be capable of starting, accelerating to rated speed and voltage, and connecting to its respective ESS bus on detection of bus undervoltage after the normal and alternate supply breakers open. This sequence must be accomplished within 10 seconds. 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 E is normally maintained OPERABLE (i.e., Surveillance Testing completed) so that it can be used as a substitute for any one of the four DGs A, B, C or D.

Proper sequencing of loads, including tripping of nonessential loads, is a required function for DG OPERABILITY.

The manual synchronization circuit is used to synchronize an offsite source from the normal circuit to the alternate circuit, as tested by SR 3.8.1.8. The manual synchronization circuit is also used to synchronize a bus that is powered by a DG with an offsite power source on a restoration of offsite power, as tested by SR 3.8.1.16. An inoperable manual synchronization circuit does not render an offsite circuit or a DG inoperable.

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 SUSQUEHANNA - UNIT 2 3.8-6

BASES LCO (continued)

APPLICABILITY ACTIONS Rev. 18 AC Sources - Operating B 3.8.1 circuit. If a Unit 1 - 4.16 kV bus is de-energized solely for the purpose of performing maintenance, automatic transfer interlock mechanisms for the de-energized bus are not required to be operable.

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

a.

Acceptable fuel design limits and reactor coolant pressure boundary limits are not exceeded as a result of AOOs or abnormal transients; and

b.

Adequate core cooling is provided and containment OPERABILITY and other vital functions are maintained in the event of a postulated OBA.

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

A Note prohibits the application of LCO 3.0.4.b to an inoperable DG.

There is an increased risk associated with entering a MODE or other specified condition in the Applicability with an inoperable DG and the provisions of LCO 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.

The ACTIONS are modified by a Note which allows entry into associated Conditions and Required Actions to be delayed for up to 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months when an OPERABLE diesel generator is placed in an inoperable status for the alignment of diesel generator E to or from the Class 1 E distribution system.

Use of this allowance requires both offsite circuits to be OPERABLE. Entry into the appropriate Conditions and Required Actions shall be made immediately upon the determination that substitution of a required diesel generator will not or can not be completed.

SUSQUEHANNA - UNIT 2 3.8-7

BASES ACTIONS (continued)

Rev. 18 AC Sources - Operating B 3.8.1 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 Title 10 to the Code of Federal Regulations (10 CFR) Section 50.65(a)(4).

2.)

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

3.)

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.

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.

SUSQUEHANNA-UNIT 2 3.8-8

BASES ACTIONS

( continued)

A.2 Rev. 18 AC Sources - Operating B 3.8.1 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 1 E Power Distribution System coincident with one or more inoperable required support or supported features, or both, that are associated with any other emergency bus that has offsite power, results in starting the Completion Times for the Required Action. Twenty-four hours is acceptable because it minimizes risk while allowing time for restoration before the unit is subjected to transients associated with shutdown.

The remaining OPERABLE offsite circuits and DGs are adequate to supply electrical power to the onsite Class 1 E Distribution System. Thus, on a component basis, single failure protection may have been lost for the required feature's function; however, function is not lost. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time takes into account the component OPERABILITY of the redundant counterpart to the inoperable required feature. Additionally, the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 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.

SUSQUEHANNA-UNIT 2 3.8-9

BASES Rev. 18 AC Sources - Operating B 3.8.1 ACTIONS A.3 (continued)

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 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . Alternatively, a Completion Time can be determined in accordance with the Risk Informed Completion Time Program. With one offsite circuit inoperable, the reliability of the offsite system is degraded, and the potential for a loss of offsite power is increased, with attendant potential for a challenge to the plant safety systems. In this condition, however, the remaining OPERABLE offsite circuit and DGs are adequate to supply electrical power to the onsite Class 1 E Distribution System.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 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.

B.1 To ensure a highly reliable power source remains with one required DG inoperable, it is necessary to verify the availability of the required offsite circuits on a more frequent basis. Since the Required Action only specifies "perform," a failure of SR 3.8.1.1 acceptance criteria does not result in a Required Action being not met. However, if a circuit fails to pass SR 3.8.1.1, it is inoperable. Upon offsite circuit inoperability, additional Conditions must then be entered.

B.2 Required Action 8.2 is intended to provide assurance that a loss of offsite power, during the period that a DG is inoperable, does not result in a complete loss of safety function of critical systems. These features are designed with redundant safety related divisions (i.e., single division systems are not included). Redundant required features failures consist of inoperable features associated with a division redundant to the division that has an inoperable DG.

The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." In this Required Action the Completion 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.

SUSQUEHANNA - UNIT 2 3.8-1 0

BASES ACTIONS

( continued)

B.2 ( continued)

Rev. 18 AC Sources - Operating B 3.8.1 If, at any time during the existence of this Condition ( one required DG inoperable), a required feature subsequently becomes inoperable, this Completion Time begins to be tracked.

Discovering one required DG inoperable coincident with one or more inoperable required support or supported features, or both, that are associated with the OPERABLE DGs results in starting the Completion Time for the Required Action. Four hours from the discovery of these events existing concurrently is acceptable because it minimizes risk while allowing time for restoration before subjecting the unit to transients associated with shutdown.

The remaining OPERABLE DGs and offsite circuits are adequate to supply electrical power to the onsite Class 1 E Distribution System. Thus, on a component basis, single failure protection for the required feature's function may have been lost; however, function has not been lost. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time takes into account the component OPERABILITY of the redundant counterpart to the inoperable required feature. Additionally, the 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months 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.

B.3.1 and B.3.2 Required Action B.3.1 provides an allowance to avoid unnecessary testing of OPERABLE DGs. If it can be determined that the cause of the inoperable DG does not exist on the OPERABLE DG, SR 3.8.1.7 does not have to be performed. If the cause of inoperability exists on other DG(s),

they are declared inoperable upon discovery, and Condition E of LCO 3.8.1 is entered. Once the failure is repaired, and the common cause failure no longer exists, Required Action B.3.1 is satisfied. If the cause of the initial inoperable DG cannot be determined not to exist on the remaining DG(s),

performance of SR 3.8.1.7 suffices to provide assurance of continued OPERABILITY of those DGs. However, the second Completion Time for Required Action B.3.2 allows a performance of SR 3.8.1.7 completed up to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 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 0.00667 hours 3.968254e-5 weeks 9.132e-6 months constraint imposed while in Condition B.

SUSQUEHANNA - UNIT 2 3.8-11

BASES ACTIONS (continued)

B.3.1 and 8.3.2 (continued)

Rev. 18 AC Sources - Operating B 3.8.1 According to Generic Letter 84-15 (Ref. 8), 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 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 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . In Condition B, the remaining OPERABLE DGs and offsite circuits are adequate to supply electrical power to the onsite Class 1 E Distribution System. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 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. Alternatively, a Completion Time can be determined in accordance with the Risk Informed Completion Time Program.

C. 1 Required Action C.1 addresses actions to be taken in the event of concurrent inoperability of two offsite circuits. The Completion Time for Required Action C.1 is intended to allow the operator time to evaluate and repair any discovered inoperabilities.

According to Regulatory Guide 1.93 (Ref. 7), operation may continue in Condition C for a period that should not exceed 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . 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 OGs 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.

SUSQUEHANNA - UNIT 2 3.8-12

BASES ACTIONS (continued)

C.1 (continued)

Rev. 18 AC Sources - Operating B 3.8.1 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 case single failure were postulated as a part of the design basis in the safety analysis. Thus, the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 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 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . If two offsite sources are restored within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , unrestricted operation may continue. If only one offsite source is restored within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , power operation continues in accordance with Condition A Alternatively, a Completion Time can be determined in accordance with the Risk Informed Completion Time Program.

D.1 and D.2 Pursuant to LCO 3.0.6, the Distribution System Actions would not be entered even if all AC sources to it were inoperable, resulting in de-energization. Therefore, the Required Actions of Condition Dare 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 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . 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 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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. Alternatively, a Completion Time can be determined in accordance with the Risk Informed Completion Time Program.

SUSQUEHANNA - UNIT 2 3.8-13

BASES ACTIONS

( continued)

E.1 Rev. 18 AC Sources - Operating B 3.8.1 With two or more DGs inoperable and an assumed loss of offsite electrical power, insufficient standby AC sources are available to power the minimum required ESF functions. Since the offsite electrical power system is the only source of AC power for the majority of ESF equipment at this level of degradation, the risk associated with continued operation for a very short time could be less than that associated with an immediate controlled shutdown. (The immediate shutdown could cause grid instability, which could result in a total loss of AC power.) Since any inadvertent unit generator trip could also result in a total loss of offsite AC power, however, the time allowed for continued operation is severely restricted. The intent here is to avoid the risk associated with an immediate controlled shutdown and to minimize the risk associated with this level of degradation.

According to Regulatory Guide 1.93 (Ref. 7), with two or more DGs inoperable, operation may continue for a period that should not exceed 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

F.1 and F.2 If the inoperable AC electrical power sources cannot be restored to OPERABLE status within the associated Completion Time, the unit must be brought to a MODE in which the LCO does not apply. To achieve this status, the unit must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

G.1 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.

SUSQUEHANNA - UNIT 2 3.8-14

BASES ACTIONS

( continued)

SURVEILLANCE REQUIREMENTS H.1 Rev. 18 AC Sources - Operating B 3.8.1 The manual synchronization circuit is made up of a synchroscope, a bus differential voltmeter, and 37 synchronization selector switches ("sync selector switches"). Eight of the sync selector switches are for the DGs, 16 are for the primary and alternate supply of the 4.16 kV ESS Buses, and the remaining 13 switches are for the 13.8 kV Buses. All of the selector switches utilize the same synchronization bus; therefore, only one sync selector switch can be turned on at a time without blowing fuses. The sync selector switches are only utilized for manual transfers.

The automatic transfers that occur between the 4.16 kV ESS Buses or the automatic start and load of the DG during a LOOP are not impacted by the failure of a sync selector switch.

When the manual synchronization circuit is inoperable, the manual transfer function of all Class 1 E ESS Buses is eliminated and operators cannot perform surveillance testing on any bus. However, inoperability of the manual transfer function does not impact the ability of the DGs to start and load on demand, nor does it impact any of the automatic transfer functions for the ESS buses. Thus, all DGs and ESS buses are available to perform their safety functions. Required Action H.1 is intended to require restoration of the manual synchronization circuit to an OPERABLE status in a timeframe commensurate with the safety significance of the condition.

The 14 day Completion Time takes into account the OPERABILITY of the automatic transfer functions of all Class 1 E ESS Buses during the period of inoperability. Additionally, the 14 day Completion Time takes into account the capacity and capability of the AC sources, a reasonable time for repairs, and the low probability of a OBA occurring during the period.

The AC sources are designed to permit inspection and testing of all 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 1 E AC electrical power distribution subsystem(s) required to support SUSQUEHANNA - UNIT 2 3.8-15

BASES SURVEILLANCE REQUIREMENTS (continued)

Rev. 18 AC Sources - Operating B 3.8.1 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.

Where the SRs discussed herein specify voltage and frequency tolerances, the following summary is applicable. The minimum steady 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 distribution 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 modified by a Note, to clarify the testing requirements associated with DG E. The Note is necessary to define the intent of the Surveillance Requirements associated with the integration of DG E. Specifically, the Note defines that a DG is only considered OPERABLE and required when it is aligned to the Class 1 E distribution system. For example, if DG A does not meet the requirements of a specific SR, but DG E is substituted for DG A and aligned to the Class 1 E distribution system, DG E is required to be OPERABLE to satisfy the LCO requirement of 4 DGs and DG A is not required to be OPERABLE because it is not aligned to the Class 1 E distribution system. This is acceptable because only 4 DGs are assumed in the event analysis.

SUSQUEHANNA-UNIT 2 3.8-16

BASES SURVEILLANCE REQUIREMENTS

( continued)

Rev. 18 AC Sources - Operating B 3.8.1 Furthermore, the Note identifies when the Surveillance Requirements, as modified by SR Notes, have been met and performed, DG E can be substituted for any other DG and declared OPERABLE after performance of two SRs which verify switch alignment. This is acceptable because the testing regimen defined in the Surveillance Requirement Table ensures DG E is fully capable of performing all DG requirements.

SR 3.8.1.1 This SR ensures proper circuit continuity for the offsite AC electrical power supply to the onsite distribution network and availability of offsite AC electrical power. The breaker alignment verifies that each breaker is in its correct position to ensure that distribution buses and loads are connected to an Operable offsite power source and that appropriate independence of offsite circuits is maintained. The 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 minutes is required to stabilize engine temperatures, while minimizing the time that the DG is connected to the offsite source.

Although no power factor requirements are established by this SR, the DG is normally operated at a power factor between 0.8 lagging and 1.0. The 0.8 value is the design rating of the machine, while 1.0 is an operational limitation to ensure circulating currents are minimized. The load band is provided to avoid routine overloading of the DG. Routine overloading may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY.

Note 1 modifies this Surveillance to indicate that diesel engine runs for this Surveillance may include gradual loading, as recommended by the Cooper Bessemer Service Bulletin 728, so that mechanical stress and wear on the diesel engine are minimized.

Note 2 modifies this Surveillance by stating that momentary transients because of changing bus loads do not invalidate this test. Similarly, momentary power factor transients do not invalidate the test.

SUSQUEHANNA - UNIT 2 3.8-17

BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.3 (continued)

Rev. 18 AC Sources - Operating B 3.8.1 Note 3 indicates that this Surveillance should be conducted on only one DG at a time in order to avoid common cause failures that might result from offsite circuit or grid perturbations.

Note 4 stipulates a prerequisite requirement for performance of this SR. A successful DG start must precede this test to credit satisfactory performance.

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

Note 6 allows a single test (instead of two tests, one for each unit) to satisfy the requirements for both units, with the DG synchronized to the 4.16 kV ESS bus of Unit 1 for one periodic test and synchronized to the 4.16 kV ESS bus of Unit 2 during the next periodic test. This is acceptable because the purpose of the test is to demonstrate the ability of the DG to operate at its continuous rating (with the exception of DG E which is only required to be tested at the continuous rating of DGs A 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 performed on the other Unit, and the other Unit's TS allowance that provides an exception to performing the test is used (i.e., the Note to SR 3.8.2.1 for the other Unit provides an exception to performing this test when the other Unit is in MODE 4 or 5, or moving irradiated fuel assemblies in the secondary containment), or it is not possible to perform the test due to equipment 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.

SR 3.8.1.4 This SR verifies the level of fuel oil in the engine mounted day tank is at or above the level at which fuel oil is automatically added. The level is expressed as an equivalent volume in gallons, and is selected to ensure adequate fuel oil for a minimum of 55 minutes of DG A-0 and 62 minutes of DG E operation at DG continuous rated load conditions.

SUSQUEHANNA - UNIT 2 3.8-18

BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.4 (continued)

Rev. 18 AC Sources - Operating B 3.8.1 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. Periodic removal of water from the engine-mounted day tanks 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.

SR 3.8.1.7 This SR helps to ensure the availability of the standby electrical power supply to mitigate DBAs and transients and maintain the unit in a safe shutdown condition.

SUSQUEHANNA - UNIT 2 3.8-19

BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.7 (continued)

Rev. 18 AC Sources - Operating B 3.8.1 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 10 seconds and maintains the required voltage and frequency when steady state conditions are reached. The 10 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 (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 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 normal 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

BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.8 (continued)

Rev. 18 AC Sources - Operating B 3.8.1 This SR is modified by a Note. The reason for the Note is that, during operation with the reactor critical, performance of the automatic transfer of the unit power supply could cause perturbations to the electrical distribution systems that could challenge continued steady state operation and, as a result, plant safety systems. The manual transfer of unit power supply should not result in any perturbation to the electrical distribution system, therefore, no mode restriction is specified. This Surveillance tests the applicable logic associated with Unit 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, the Note specifying the restriction for not performing the test while the unit is in MODE 1 or 2 does not have applicability to Unit 1. The NOTE only applies to Unit 2, thus 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 the transient caused by the loss of a large load could cause diesel engine overspeed, which, if excessive, might result in a trip of the engine. This Surveillance demonstrates the DG load response characteristics and capability to reject the largest single load without exceeding predetermined voltage and frequency and while maintaining a specified margin to the overspeed trip. The largest single load for each DG is a residual heat removal (RHR) pump (1429 kW). This Surveillance may be accomplished by:

a.

Tripping the DG output breaker with the DG carrying greater than or equal to its associated single largest post-accident load while paralleled to offsite power, or while solely supplying the bus; or

b.

Tripping its associated single largest post-accident load with the DG solely supplying the bus.

As recommended by Regulatory Guide 1.9 (Ref. 3), the load rejection test is acceptable if the increase in diesel speed does not exceed 75% of the difference between synchronous speed and the overspeed trip setpoint, or 15% above synchronous speed, whichever is lower. For DGs A, B, C, D and E, this represents 64.5 Hz, equivalent to 75% of the difference between nominal speed and the overspeed trip setpoint.

SUSQUEHANNA - UNIT 2 3.8-21

BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.9 (continued)

Rev. 18 AC Sources - Operating B 3.8.1 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 future application, including reconnection to the bus if the trip initiator can be corrected or isolated.

SUSQUEHANNA-UNIT 2 3.8-22

BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.10 ( continued)

Rev. 18 AC Sources - Operating B 3.8.1 To minimize testing of the DGs, a Note allows a single test to satisfy the requirements for both units (instead of two tests, one for each unit). This is acceptable because this test is intended to demonstrate attributes of the DG that are not associated with either Unit. If the DG fails this Surveillance, the DG should be considered inoperable for both units, unless the cause of the failure can be directly related to only one unit.

The 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

BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.11 (continued)

Rev. 18 AC Sources - Operating B 3.8.1 The reason for Note 2 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 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 performed for the DGs and the 4.16 kV ESS Buses. The Note is necessary because this SR involves an integrated test between the DGs and the 4.16 kV ESS Buses and the need for the testing regimen to include DG E being tested (substituted for all DGs for both units) with all 4.16 kV ESS Buses. To ensure the necessary testing is performed, the following rotational testing regimen has been established:

UNIT IN OUTAGE 2

1 2

1 DIESEL E SUBSTITUTED FOR DG E not tested Diesel Generator A DG E not tested DG E not tested Diesel Generator B Diesel Generator C DG E not tested DG E not tested Diesel Generator D DG E not tested DG E not tested Diesel Generator B DG E not tested DG E not tested Diesel Generator A Diesel Generator D DG E not tested DG E not tested Diesel Generator C DG E not tested SUSQUEHANNA - UNIT 2 3.8-24

BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.11 (continued)

Rev. 18 AC Sources - Operating B 3.8.1 The specified rotational testing regimen can be altered to facilitate unanticipated events which render the testing regimen 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 1 E 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 a frequency controlled under the Surveillance Frequency 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 frequency established in accordance with the Surveillance Frequency Control Program. This is acceptable because these components are not required to change state to perform their safety function and when substituted--normal operation of DG E will ensure continuity of most of the cabling not tested.

SR 3.8.1.12 This Surveillance demonstrates that the DG automatically starts and achieves the required voltage and frequency within the specified time (10 seconds) from the design basis actuation signal (LOCA signal) and operates for ~ 5 minutes. The 5 minute period provides sufficient time to demonstrate stability. SR 3.8.1.12.d and SR 3.8.1.12.e ensure that permanently connected loads and emergency loads are energized from the offsite electrical power system on a LOCA signal without loss of offsite power.

The requirement to verify the connection and power supply of permanent and 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 SUSQUEHANNA - UNIT 2 3.8-25

BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.12 (continued)

Rev. 18 AC Sources - Operating B 3.8.1 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.

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 1 E distribution system. When tested in this configuration, DG E satisfies the requirements of this test by completion of SR 3.8.1.12.a, b and c only. SR 3.8.1.12.d and 3.8.1.12.e may be performed by any DG aligned with the Class 1 E 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.

SUSQUEHANNA - UNIT 2 3.8-26

BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.13 ( continued)

Rev. 18 AC Sources - Operating B 3.8.1 The SR is modified by two Notes. To minimize testing of the DGs, Note 1 to SR 3.8.1.13 allows a single test (instead of two tests, one for each unit) to satisfy the requirements for both units. This is acceptable because this test is intended to demonstrate attributes of the DG that are not associated with either Unit. If the DG fails this Surveillance, the DG should be considered inoperable for both units, unless the cause of the failure can be directly related to only one unit.

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

SR 3.8.1.14 Regulatory Guide 1.9 (Ref. 3), requires demonstration that the DGs can start and run continuously at full load capability for an interval of not less than 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months - 22 hours2.546296e-4 days 0.00611 hours 3.637566e-5 weeks 8.371e-6 months of which is at a load equivalent to 90% to 100%

of the continuous rating of the DG, and 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months 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 0.556 hours 0.00331 weeks 7.61e-4 months rating for each DG. The requirement to perform the two hour overload test can be performed in any order provided it is performed during a single continuous time period.

The DG starts for this Surveillance can be performed either from standby or hot conditions. The provisions for prelube discussed in SR 3.8.1.7, and for gradual loading, discussed in SR 3.8.1.3, are applicable to this SR.

A load band is provided to avoid routine overloading of the DG. Routine overloading may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY.

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

This Surveillance has been modified by three Notes. Note 1 states that momentary transients due to changing bus loads do not invalidate this test.

SUSQUEHANNA-UNIT 2 3.8-27

BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.14 (continued)

Rev. 18 AC Sources - Operating B 3.8.1 To minimize testing of the DGs, Note 2 allows a single test (instead of two tests, one for each unit) to satisfy the requirements for both units. This is acceptable because this test is intended to demonstrate attributes of the DG that are not associated with either Unit. If the DG fails this Surveillance, the DG should be considered inoperable for both units, unless the cause of the failure can be directly related to only one unit.

Note 3 stipulates that DG E, when not aligned as substitute for DG A, B, C or D but being maintained available may use the test facility to satisfy the specified loading requirements in lieu of synchronization with an ESS bus.

SR 3.8.1.15 This Surveillance demonstrates that the diesel engine can restart from a hot condition, such as subsequent to shutdown from full load temperatures and achieve the required voltage and frequency within 10 seconds. The 10 second time is derived from the requirements of the accident analysis to respond to a design basis large break LOCA.

The 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 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months 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 3.8-28

BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.16 Rev. 18 AC Sources - Operating B 3.8.1 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 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 performed separately to verify the proper offsite loading sequence.

SUSQUEHANNA - UNIT 2 3.8-29

BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.17 (continued)

Rev. 18 AC Sources - Operating B 3.8.1 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 individual load timers which control the permissive and starting signals to motor breakers to prevent overloading of the AC Sources due to high motor starting currents. The load sequence time interval tolerance ensures that sufficient time exists for the AC Source to restore frequency and voltage prior to applying the next load and that safety analysis assumptions regarding ESF equipment time delays are not violated. Reference 2 provides a summary of the automatic loading of ESS buses. A list of the required timers and the associated setpoints are included in the Bases as Table B 3.8.1-1, Unit 1 and Unit 2 Load Timers. Failure of a timer identified as an offsite power timer may result in both offsite sources being inoperable. Failure of any other timer may result in the associated DG being inoperable. A timer is considered failed for this SR if it will not ensure that the associated load will energize within the Allowable Value in Table B 3.8.1-1. These conditions will require entry into applicable Conditions of this specification. With a load timer inoperable, the load can be rendered inoperable to restore OPERABILITY to the associated AC sources. In this condition, the 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 disabled are not required to be Operable. This is acceptable because if the load does not start automatically, the adverse effects of an improper loading sequence are eliminated. Furthermore, load timers are associated with individual timers such that a single timer only affects a single load.

SUSQUEHANNA - UNIT 2 3.8-30

BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.19 Rev. 18 AC Sources - Operating B 3.8.1 In the event of a DBA coincident with a loss of offsite power, the DGs are required to supply the necessary power to ESF systems so that the fuel, RCS, and containment design limits are not exceeded.

This Surveillance demonstrates DG operation, as discussed in the Bases for SR 3.8.1.11, during a loss of offsite power actuation test signal in conjunction with an ECCS initiation signal. In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the DG system to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified. To simulate the non-LOCA unit 4.16 kV ESS Bus loads on the DG, bounding loads are energized on the tested 4.16 kV ESS Bus after all auto connected 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 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 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 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 MODE 1, 2 or 3.

SUSQUEHANNA - UNIT 2 3.8-31

BASES SURVEILLANCE REQUIREMENTS

( continued)

SR 3.8.1.20 Rev. 18 AC Sources - Operating B 3.8.1 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 normally 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 E is substituted for any other DG.

SUSQUEHANNA - UNIT 2 3.8-32

BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.21 Rev. 18 AC Sources - Operating B 3.8.1 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 capable of supporting Unit 2. SR 3.8.1.8 is not required if only one Unit 1 offsite circuit is required by the Unit 2 Specification.

SR 3.8.1.12, 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 3.8-33

BASES REFERENCES

1.

10 CFR 50, Appendix A, GDC 17.

2.

FSAR, Section 8.2.

3.

Regulatory Guide 1.9.

4.

FSAR, Chapter 6.

5.

FSAR, Chapter 15.

Rev. 18 AC Sources - Operating B 3.8.1

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.

Regulatory Guide 1.137.

12.

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, ~008.

SUSQUEHANNA - UNIT 2 3.8-34

DEVICE TAG NO.

62A-20102 62A-20202 62A-20302 62A-20402 62A-20102 62A-20202 62A-20302 62A-20402 E11A-K202B E11A-K120A E11A-K120B E11A-K202A E11A-K120A E11A-K202B E11A-K120B E11A-K202A E21A-K116A E21A-K116B E21A-K125A E21A-K125B E21A-K116A E21A-K116B E21A-K125A E21A-K125B E21A-K16A E21A-K16B E21A-K25A E21A-K25B E21A-K16A E21A-K16B E21A-K25A E21A-K25B 62AX2-20108 62AX2-20208 62AX2-20303 62AX2-20403 62X3-20404 62X3-20304 62X-20104 62X-20204 62X-5653A 62X-5652A 262X-20204 262X-20104 TABLE B 3.8.1-1 (page 1 of 2)

UNIT 1 AND UNIT 2 LOAD TIMERS NOMINAL SETTING SYSTEM LOADING TIMER LOCATION (seconds)

RHR Pump 1A 1A201 3

RHR Pump 1B 1A202 3

RHR Pump 1C 1A203 3

RHR Pump 1D 1A204 3

RHR Pump 2A 2A201 3

RHR Pump 2B 2A202 3

RHR Pump 2C 2A203 3

RHR Pump 2D l2A204 3

RHR Pump 1 C (Offsite Power Timer) 1C618 7.0 RHR Pump 1C (Offsite Power Timer) 1C617 7.0 RHR Pump 1 O (Offsite Power Timer) 1C618 7.0 RHR Pump 10 (Offsite Power Timer) 1C617 7.0 RHR Pump 2C (Offsite Power Timer) 2C617 7.0 RHR Pump 2C (Offsite Power Timer) 2C618 7.0 RHR Pump 2D (Offsite Power Timer) l2C618 7.0 RHR Pump 2D (Offsite Power Timer) 2C617 7.0 CS Pump 1A 1C626 10.5 CS Pump 1B 1C627 10.5 CS Pump 1C 1C626 10.5 CS Pump 10 1C627 10.5 CS Pump2A 2C626 10.5 CS Pump2B

[2C627 10.5 CS Pump2C 2C626 10.5 CS Pump20 2C627 10.5 CS Pump 1A (Offsite Power Timer) 1C626 15 CS Pump 1 B (Offsite Power Timer) 1C627 15 CS Pump 1 C (Offsite Power Timer) 1C626 15 CS Pump 10 (Offsite Power Timer) 1C627 15 CS Pump 2A (Offsite Power Timer) 2C626 15 CS Pump 2B (Offsite Power Timer) 2C627 15 CS Pump 2C (Offsite Power Timer) 2C626 15 CS Pump 20 (Offsite Power Timer) 2C627 15 Emergency Service Water 1A201 40 Emergency Service Water 1A202 40 Emergency Service Water 1A203 44 Emergency Service Water 1A204 48 Control Structure Chilled Water System OC877B 60 Control Structure Chilled Water System OC877A 60 Emergency Switchgear Rm Cooler A & RHR OC877A 60 SW Pump H&V Fan A Emergency Switchgear Rm Cooler B & RHR OC877B 60 SW Pump H&V Fan B OG Room Exhaust Fan E3 OB565 60 DG Room Exhausts Fan E4 OB565 60 Emergency Switchgear Rm Cooler B OC877B 120 Emergency Switchgear Rm Cooler A OC877A 120 SUSQUEHANNA - UNIT 2 3.8-35 Rev. 18 AC Sources - Operating B 3.8.1 ALLOWABLE VALUE (seconds)

~ 2.7 and s 3.6

> 2.7 and s 3.6

~ 2.7 and s 3.6

~ 6.5 and s 7.5

> 6.5 and < 7.5

~ 6.5 and s 7.5

~ 9.4 and s 11.6

~ 9.4and s 11.6

~ 9.4 and s 11.6

~ 9.4and s 11.6

~ 9.4 and s 11.6

> 9.4 and s 11.6

~ 14.0 and s 16.0

> 14.0 and s 16.0

~ 14.0 and s 16.0

~ 14.0and s 16.0

> 14.0 and s 16.0

> 36 and s 44

~ 36 and s 44

> 39.6 and s 48.4

~ 43.2 and s 52.8*

~ 54

DEVICE TAG NO.

62X-546 62X-536 62X-526 62X-516 CRX-5652A 62X2-20410 62X1-20304 62X2-20310 62X1-20404 62X2-20304 62X2-20404 62X-K11BB 62X-K11AB TABLE B 3.8.1-1 (page 2 of 2)

UNIT 1 AND UNIT 2 LOAD TIMERS NOMINAL SETTING SYSTEM LOADING TIMER LOCATION (seconds)

DG Rm Exh Fan D OB546 120 DG Rm Exh Fan C OB536 120 DG Rm Exh Fan B OB526 120 DG Rm Exh Fan A OB516 120 DG Room Supply Fans E1 and E2 OB565 120 Control Structure Chilled Water System OC876B 180 Control Structure Chilled Water System OC877A 180 Control Structure Chilled Water System OC876A 180 Control Structure Chilled Water System OC877B 180 Control Structure Chilled Water System OC877A 210 Control Structure Chilled Water System OC877B 210 Emergency Switchgear Rm Cooling 2CB250B 260 Comoressor B Emergency Switchgear Rm Cooling 2CB250A 260 Comoressor A SUSQUEHANNA - UNIT 2 3.8-36 Rev. 18 AC Sources - Operating B 3.8.1 ALLOWABLE VALUE (seconds)

~ 54

BASES Rev. 18 AC Sources - Operating B 3.8.1 THIS PAGE INTENTIONALLY LEFT BLANK SUSQUEHANNA - UNIT 2 3.8-37

BASES Rev. 18 AC Sources - Operating B 3.8.1 THIS PAGE INTENTIONALLY LEFT BLANK SUSQUEHANNA - UNIT 2 3.8-38

ML25356A489

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