ML14071A526

Susquehanna, Unit 1, Technical Specification Bases Unit 1 Manual, Revision 7

ML14071A526
Person / Time
Site:	Susquehanna
Issue date:	02/25/2014
From:	Susquehanna
To:	Gerlach R M Office of Nuclear Reactor Regulation
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Download: ML14071A526 (212)

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Feb. 25, 2014 Page 1 of 3 MANUAL HARD COPY DISTRIBUTION DOCUMENT TRANSMITTAL 2014-7381 USER INFORMATION:

GERLACH*ROSEY M EMPL#:028401 CA#: 0363 Address: NUCSA2 Phone#: 254-3194 TRANSMITTAL INFORMATION:

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PPL Rev. 7 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 I 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. 10; and, a 230 kV tap from the 500-230 kV tie line feeds the startup transformer No. 20. The term "qualified circuits," as used within TS 3.8.1, is synonymous with the term "physically independent." The two independent offsite power sources are supplied to and are shared by both units. These two electrically and physically separated circuits provide AC power, through startup transformers (ST) No. 10 and ST No. 20, to the four 4.16 kV Engineered Safeguards System (ESS)buses (A, B, C and D) for both Unit 1 and Unit 2. A detailed description of the offsite power network and circuits to the onsite Class I 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.(continued)

SUSQUEHANNA

-UNIT 1 TS / B 3.8-1 Revision 3 PPL Rev. 7 AC Sources -Operating B 3.8.1 BASES BACKGROUND ST No. 10 and ST No. 20 each provide the normal source of power to (continued) two of the four 4.16 kV ESS buses in each Unit and the alternate source of power to the remaining two 4.16 kV ESS buses in each Unit. If any 4.16 kV ESS bus loses power, an automatic transfer from the normal to the alternate occurs after the normal supply breaker trips.When off-site power is available to the 4.16 kV ESS Buses following a LOCA signal, the required ESS loads will be sequenced onto the 4.16 kV ESS Buses in order to compensate for voltage drops in the onsite power system when starting large ESS motors.The onsite standby power source for 4.16 kV ESS buses A, B, C and D consists of five DGs. DGs A, B, C and D are dedicated to ESS buses A, B, C and D, respectively.

DG E can be used as a substitute for any one of the four DGs (A, B, C.or D) to supply the associated ESS bus. Each DG provides standby power to two 4.16 kV ESS buses-one associated with Unit 1 and one associated with Unit 2. The four "required" DGs are those aligned to a 4.16 kV ESS bus to provide onsite standby power for both Unit 1 and Unit 2.A DG, when aligned to an ESS bus, starts automatically on a loss of coolant accident (LOCA) signal (i.e., low reactor water level signal or high drywell pressure signal) or on an ESS bus degraded voltage or undervoltage signal. After the DG has started, it automatically ties to its respective bus after offsite power is tripped as a consequence of ESS bus undervoltage or degraded voltage, independent of or coincident with a LOCA signal. The DGs also start and operate in the standby mode without tying to the ESS bus on a LOCA signal alone. Following the trip of offsite power, non-permanent loads are stripped from the 4.16 kV ESS Buses. When a DG is tied to the ESS Bus, loads are then sequentially connected to their respective ESS Bus by individual load timers. The individual load timers control the starting permissive signal to motor breakers to prevent overloading the associated DG.In the event of loss of normal and alternate offsite power supplies, the 4.16 kV ESS buses will shed all loads except the 480 V load centers and the standby diesel generators will connect to the ESS busses.When a DG is tied to its respective ESS bus, loads are then sequentially connected to (continued)

SUSQUEHANNA-UNIT 1 TS / B 3.8-2 Revision 2 PPL Rev. 7 AC Sources -Operating B 3.8.1 BASES BACKGROUND (continued) 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 (DBA) such as a LOCA.Certain required plant loads are returned to service in a predetermined sequence in order to prevent overloading of the DGs in the process.Within 286 seconds after the initiating signal is received, all automatic and permanently connected loads needed to recover the unit or maintain it in a safe condition are returned to service. Ratings for the DGs satisfy the requirements of Regulatory Guide 1.9 (Ref. 3).DGs A, B, C and D have the following ratings: a. 4000 kW-continuous, b. 4700 kW-2000 hours, DG E has the following ratings: a. 5000 kW-continuous, b. 5500 kW-2000 hours.APPLICABLE SAFETY ANALYSES The initial conditions of DBA 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 (continued)

SUSQUEHANNA

-UNIT 1 TS / B 3.8-3 Revision 2

.PPL Rev. 7 AC Sources -Operating B 3.8.1 BASES APPLICABLE OPERABLE during accident conditions in the event of an assumed loss SAFETY ANALYSES of all offsite power or all onsite AC power; and a worst case single failure.(continued)

AC sources satisfy Criterion 3 of the NRC Policy Statement (Ref. 6).LCO Two qualified circuits between the offsite transmission network and the onsite Class 1 E Distribution System and four separate and independent DGs (A, B, C and D) ensure availability of the required power to shut down the reactor and maintain it in a safe shutdown condition after an anticipated operational occurrence (AOO) or a postulated DBA. DG E can be used as a substitute for any one of the four DGs A, B, C or D.Qualified offsite circuits are those that are described in the FSAR, and are part of the licensing basis for the unit. In addition, the required automatic load timers for each ESF bus shall be OPERABLE.The Safety Analysis for Unit 2 assumes the OPERABILITY of some equipment that receives power from Unit I 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 supplying three of the four 4.16 kV ESS Buses.3. Acceptable offsite grid voltage, defined as a voltage that is within the grid voltage requirements established for SSES.The grid voltage requirements include both a minimum grid voltage and an allowable grid voltage drop during normal operation, and for a predicted voltage for a trip of the unit.(continued)

SUSQUEHANNA

-UNIT 1 TS / B 3.8-4 Revision 3 PPL Rev. 7 AC Sources -Operating B 3.8.1 BASES LCO The Regional Transmission Operator (PJM), and/or the (continued)

Transmission Power System Dispatcher, PPL EU, determine, monitor and report actual and/or contingency voltage (Predicted voltage) violations that occur for the SSES monitored offsite 230kV and 500kV buses.The offsite circuit is inoperable for any actual voltage violation, or a contingency voltage violation that occurs for a trip of a SSES unit, as reported by the transmission RTO or Transmission Power System Dispatcher.

The offsite circuit is operable for any other predicted grid event (i.e., loss of the most critical transmission line or the largest supply) that does not result from the generator trip of a SSES unit. These conditions do not represent an impact on SSES operation that has been caused by a LOCA and subsequent generator trip. The design basis does not require entry into LCOs for predicted grid conditions that can not result in a LOCA, delayed LOOP.The other offsite circuit is Operable when all the following conditions are met: 1. An energized ST. No. 20 transformer with the load tap changer (LTC) in automatic operation.

2. The respective circuit path including energized ESS transformers 201 and 211 and feeder breakers capable of supplying three of the four 4.16 kV ESS Buses.3. Acceptable offsite grid voltage, defined as a voltage that is within the grid voltage requirements established for SSES.The grid voltage requirements include both a minimum grid voltage and an allowable grid voltage drop during normal operation, and for a predicted voltage for a trip of the unit.The Regional Transmission Operator (PJM), and/or the Transmission Power System Dispatcher, PPL EU, determine, monitor and report actual and/or contingency voltage (Predicted voltage) violations that occur for the SSES monitored offsite 230kV and 500kV buses.(continued)

SUSQUEHANNA

-UNIT 1 TS / B 3.8-4a Revision 0 PPL Rev. 7 AC Sources -Operating B 3.8.1 BASES LCO (continued)

The offsite circuit is inoperable for any actual voltage violation, or a contingency voltage violation that occurs for a trip of a SSES unit, as reported by the transmission RTO or Transmission Power System Dispatcher.

The offsite circuit is operable for any other predicted grid event (i.e., loss of the most critical transmission line or the largest supply) that does not result from the generator trip of a SSES unit. These conditions do not represent an impact on SSES operation that has been caused by a LOCA and subsequent generator trip. The design basis does not require entry into LCOs for predicted grid conditions that can not result in a LOCA, delayed LOOP.Both offsite circuits are OPERABLE provided each meets the criteria described above and provided that no 4.16 kV ESS Bus has less than one OPERABLE offsite circuit (continued)

SUSQUEHANNA-UNIT 1 TS / B 3.8-4b Revision 0 PPL Rev. 7 AC Sources -Operating B 3.8.1 BASES LCO capable of supplying the required loads. If no OPERABLE offsite circuit (continued) is capable of supplying any of the 4.16 kV ESS Buses, one offsite source shall be declared inoperable.

Four of the five DGs are required to be Operable to satisfy the initial assumptions of the accident analyses.

Each required DG must be capable of starting, accelerating to rated speed and voltage, and connecting to its respective ESS bus on detection of bus undervoltage after the normal and alternate supply breakers open. This sequence must be accomplished within 10 seconds. Each DG must also be capable of accepting required loads within the assumed loading sequence intervals, and must continue to operate until offsite power can be restored to the ESS buses. These capabilities are required to be met from a variety of initial conditions, such as DG in standby with the engine hot and DG in normal standby conditions.

Normal standby conditions for a DG mean that the diesel engine oil is being continuously circulated and engine coolant is circulated as necessary to maintain temperature consistent with manufacturer recommendations.

Additional DG capabilities must be demonstrated to meet required Surveillances, e.g., capability of the DG to revert to standby status on an ECCS signal while operating in parallel test mode.Although not normally aligned as a required DG, DG E is normally maintained OPERABLE (i.e., Surveillance Testing completed) so that it can be used as a substitute for any one of the four DGs A, B, C or D.Proper sequencing of loads, including tripping of nonessential loads, is a required function for DG OPERABILITY.

The AC sources must be separate and independent (to the extent possible) of other AC sources. For the DGs, the separation and independence are complete.

For the offsite AC sources, the separation and independence are to the extent practical.

A circuit may be connected to more than one ESS bus, with automatic transfer capability to the other circuit OPERABLE, and not violate separation criteria.

A circuit that is not connected to an ESS bus is required to have OPERABLE automatic transfer interlock mechanisms to each ESS bus to support OPERABILITY of that offsite circuit (continued)

SUSQUEHANNA

-UNIT 1 TS / B 3.8-5 Revision 5 PPL Rev. 7 AC Sources -Operating B 3.8.1 BASES (continued)

APPLICABILITY The AC sources are required to be OPERABLE in MODES 1, 2, and 3 to ensure that: a. Acceptable fuel design limits and reactor coolant pressure boundary limits are not exceeded as a result of AOOs or abnormal transients; and b. Adequate core cooling is provided and containment OPERABILITY and other vital functions are maintained in the event of a postulated DBA.The AC power requirements for MODES 4 and 5 are covered in LCO 3.8.2, "AC Sources-Shutdown." ACTIONS A Note prohibits the application of LCO 3.0.4.b to an inoperable DG.There is an increased risk associated with entering a MODE or other specified condition in the Applicability with an inoperable DG and the provisions of LCO 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.

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

A. I To ensure a highly reliable power source remains with one offsite circuit inoperable, it is necessary to verify the availability of the remaining required offsite circuit on a more frequent basis. Since the Required Action only specifies "perform," a failure of SR 3.8.1.1 acceptance criteria does not result in a Required Action not met. However, if a second required circuit fails SR 3.8.1.1, the second offsite circuit is inoperable, and Condition C, for two offsite circuits inoperable, is entered.(continued)

SUSQUEHANNA

-UNIT I TS / B 3.8-6 Revision 3 PPL Rev. 7 AC Sources -Operating B 3.8.1 BASES ACTIONS A.2 (continued)

Required Action A.2, which only applies if one 4.16 kV ESS bus cannot be powered from any offsite source, is intended to provide assurance that an event with a coincident single failure of the associated DG does not result in a complete loss of safety function of critical systems. These features (e.g., system, subsystem, division, component, or device) are designed to be powered from redundant safety related 4.16 kV ESS buses. 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 (continued)

SUSQUEHANNA

-UNIT I TS / B 3.8-7 Revision 2 PPL Rev. 7 AC Sources -Operating B 3.8.1 BASES ACTIONS A.2 (continued) hour Completion Time takes into account the component OPERABILITY of the redundant counterpart to the inoperable required feature.Additionally, the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.A.3 According to Regulatory Guide 1.93 (Ref. 7), operation may continue in Condition A for a period that should not exceed 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. With one offsite circuit inoperable, the reliability of the offsite system is degraded, and the potential for a loss. of offsite power is increased, with attendant potential for a challenge to the plant safety systems. In this condition, however, the remaining OPERABLE offsite circuit and DGs are adequate to supply electrical power to the onsite Class 1 E Distribution System.The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time takes into account the capacity and capability of the remaining AC sources, reasonable time for repairs, and the low probability of a DBA occurring during this period.The second Completion Time for Required Action A.2 establishes a limit on the maximum time allowed for any combination of required AC power sources to be inoperable during any single contiguous occurrence of failing to meet the LCO. If Condition A is entered while, for instance, a DG is inoperable, and that DG is subsequently returned OPERABLE, the LCO may already have been not met for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. This situation could lead to a total of 144 hours0.00167 days <br />0.04 hours <br />2.380952e-4 weeks <br />5.4792e-5 months <br />, since initial failure to meet the LCO, to restore the offsite circuit. At this time, a DG could again become inoperable, the circuit restored OPERABLE, and an additional 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> (for a total of 9 days)allowed prior to complete restoration of the LCO. The 6 day Completion Time provides a limit on the time allowed in a specified condition after discovery of failure to meet the LCO. This limit is considered reasonable for situations in which Conditions A and B are entered concurrently.

The "AND" connector between the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and 6 day Completion Times means that both (continued)

SUSQUEHANNA

-UNIT 1 TS / B 3.8-8 Revision 2 PPL Rev. 7 AC Sources -Operating B 3.8.1 BASES ACTIONS A.3 (continued)

Completion Times apply simultaneously, and the more restrictive Completion Time must be met.As in Required Action A.2, the Completion Time allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." This exception results in establishing the "time zero" at the time the LCO was initially not met, instead of at the time that Condition A was entered.B. 1 To ensure a highly reliable power source remains with one required DG inoperable, it is necessary to verify the availability of the required offsite circuits on a more frequent basis. Since the Required Action only specifies "perform," a failure of SR 3.8.1.1 acceptance criteria does not result in a Required Action being not met. However, if a circuit fails to pass SR 3.8.1.1, it is inoperable.

Upon offsite circuit inoperability, additional Conditions must then be entered.B.2 Required Action B.2 is intended to provide assurance that a loss of offsite power, during the period that a DG is inoperable, does notresult in a complete loss of safety function of critical systems. These features are designed with redundant safety related divisions (i.e., single division systems are not included).

Redundant required features failures consist of inoperable features associated with a division redundant to the division that has an inoperable DG.The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities.

This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." In this Required Action the Completion (continued)

SUSQUEHANNA

-UNIT 1 TS / B 3.8-9 Revision 4 PPL Rev. 7 AC Sources -Operating B 3.8.1 BASES ACTIONS B.2 (continued)

Time only begins on discovery that both: a. An inoperable DG exists; and b. A required feature powered from another diesel generator (Division 1 or 2) is 'inoperable.

If, at any time during the existence of this Condition (one required DG inoperable), a required feature subsequently becomes inoperable, this Completion Time begins to be tracked.Discovering one required DG inoperable coincident with one or more inoperable required support or supported features, or both, that are associated with the OPERABLE DGs results in starting the Completion Time for the Required Action. Four hours from the discovery of these events existing concurrently is acceptable because it minimizes risk while allowing time for restoration before subjecting the unit to transients associated with shutdown.The remaining OPERABLE DGs and offsite circuits are adequate to supply electrical power to the onsite Class 1 E Distribution System. Thus, on a component basis, single failure protection for the required feature's function may have been lost; however, function has not been lost. The 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Completion Time takes into account the component OPERABILITY of the redundant counterpart to the inoperable required feature. Additionally, the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Completion Time takes into account the capacity and capability of the remaining AC sources, reasonable time for repairs, and low probability of a DBA occurring during this period.B.3.1 and B.3.2 Required Action B.3.1 provides an allowance to avoid unnecessary testing of OPERABLE DGs. If it can be determined that the cause of the inoperable DG does not exist on the OPERABLE DG, SR 3.8.1.7 does not have to be performed.

If the cause of inoperability exists on other DG(s), they are declared inoperable upon discovery, and Condition E of LCO 3.8.1 is entered. Once the failure is repaired, and the common cause failure no longer exists, Required Action B.3.1 is satisfied.

If the cause of the initial inoperable DG cannot be determined not to exist on the remaining DG(s), performance of SR 3.8.1.7 suffices to provide assurance of continued OPERABILITY of those DGs.(continued)

SUSQUEHANNA

-UNIT 1 TS / B 3.8-10 Revision 3 PPL Rev. 7 AC Sources -Operating B 3.8.1 BASES ACTIONS B.3.1 and B.3.2 (continued)

However, the second Completion Time for Required Action B.3.2 allows a performance of SR 3.8.1.7 completed up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to entering Condition B to be accepted as demonstration that a DG is not inoperable due to a common cause failure.In the event the inoperable DG is restored to OPERABLE status prior to completing either B.3.1 or B.3.2, the plant corrective action program will continue to evaluate the common cause possibility.

This continued evaluation, however, is no longer under the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> constraint imposed while in Condition B.According to Generic Letter 84-15 (Ref. 8), 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is a reasonable time to confirm that the OPERABLE DGs are not affected by the same problem as the inoperable DG.B.4 According to Regulatory Guide 1.93 (Ref. 7), operation may continue in Condition B for a period that should not exceed 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. In Condition B, the remaining OPERABLE DGs and offsite circuits are adequate to supply electrical power to the onsite Class 1 E Distribution System. The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time takes into account the capacity and capability of the remaining AC sources, reasonable time for repairs, and low probability of a DBA occurring during this period.The second Completion Time for Required Action B.4 establishes a limit on the maximum time allowed for any combination of required AC power sources to be inoperable during any single contiguous occurrence of failing to meet the LCO. If Condition B is entered while, for instance, an offsite circuit is inoperable and that circuit is subsequently restored OPERABLE, the LCO may already have been not met for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. This situation could lead to a total of 144 hours0.00167 days <br />0.04 hours <br />2.380952e-4 weeks <br />5.4792e-5 months <br />, since initial failure of the LCO, to restore the DG. At this time, an offsite circuit could again become inoperable, the DG restored OPERABLE, and an additional 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> (for a total of 9 days) allowed prior to complete restoration of the LCO. The 6 day Completion Time provides a limit on the time allowed in a specified (continued)

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-UNIT 1 TS / B 3.8-11 Revision 2 PPL Rev. 7 AC Sources -Operating B 3.8.1 BASES ACTIONS B.4 (continued) condition after discovery of failure to meet the LCO. This limit is considered reasonable for situations in which Conditions A and B are entered concurrently.

The "AND" connector between the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and 6 day Completion Times means that both Completion Times apply simultaneously, and the more restrictive must be met.As in Required Action B.2, the Completion Time allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." This exception results in establishing the "time zero" at the time that the LCO was initially not met, instead of the time that Condition B was entered.C.1 Required Action C.1 addresses actions to be taken in the event of concurrent inoperability of two offsite circuits.

The Completion Time for Required Action C.1 is intended to allow the operator time to evaluate and repair any discovered inoperabilities.

According to Regulatory Guide 1.93 (Ref. 7), operation may continue in Condition C for a period that should not exceed 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. This level of degradation means that the offsite electrical power system does not have the capability to effect a safe shutdown and to mitigate the effects of an accident; however, the onsite AC sources have not been degraded.

This level of degradation generally corresponds to a total loss of the immediately accessible offsite power sources.Because of the normally high availability of the offsite sources, this level of degradation may appear to be more severe than other combinations of two AC sources inoperable that involve one or more DGs inoperable.

However, two factors tend to decrease the severity of this degradation level: a. The configuration of the redundant AC electrical power system that remains available is not susceptible to a single bus or switching failure; and (continued)

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-UNIT 1 TS / 8 3.8-12 Revision 2 PPL Rev. 7 AC Sources -Operating B 3.8.1 BASES ACTIONS C.1 (continued)

b. The time required to detect and restore an unavailable offsite power source is generally much less than that required to detect and restore an unavailable onsite AC source.With both of the required offsite circuits inoperable, sufficient onsite AC sources are available to maintain the unit in a safe shutdown condition in the event of a DBA or transient.

In fact, a simultaneous loss of offsite AC sources, a LOCA, and a worst case single failur~were postulated as a part of the design basis in the safety analysis.

Thus, the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Completion Time provides a period of time to effect restoration of one of the offsite circuits commensurate with the importance of maintaining an AC electrical.power system capable of meeting its design criteria.According to Regulatory Guide 1.93 (Ref. 7), with the available offsite AC sources two less than required by the LCO, operation may continue for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. If two offsite sources are restored within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, unrestricted operation may continue.

If only one offsite source is restored within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, power operation continues in accordance with Condition A.D.1 and D.2 Pursuant to LCO 3.0.6, the Distribution System Actions would not be entered even if all AC sources to it were inoperable, resulting in de-energization.

Therefore, the Required Actions of Condition D are modified by a Note to indicate that when Condition D is entered with no AC source to any ESS bus, Actions for LCO 3.8.7, "Distribution Systems-Operating," must be immediately entered. This allows Condition D to provide requirements for the loss of the offsite circuit and one DG without regard to whether a division is de-energized.

LCO 3.8.7 provides the appropriate restrictions for a de-energized bus.According to Regulatory Guide 1.93 (Ref. 7), operation may continue in Condition D for a period that should not exceed 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. In Condition D, individual redundancy is lost in both the offsite electrical power system and the onsite AC electrical power system. Since power system redundancy is provided by two diverse sources of power, however, the (continued)

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-UNIT 1 TS / B 3.8-13 Revision 2 PPL Rev. 7 AC Sources -Operating B 3.8.1 BASES ACTIONS D.1 and D.2 (continued) reliability of the power systems in this Condition may appear higher than that in Condition C (loss of both required offsite circuits).

This difference in reliability is offset by the susceptibility of this power system configuration to a single bus or switching failure. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.Completion Time takes into account the capacity and capability of the remaining AC sources, reasonable time for repairs, and the low probability of a DBA occurring during this period.E. 1 With two or more DGs inoperable and an assumed loss of offsite electrical power, insufficient standby AC sources are available to power the minimum'required ESF functions.

Since the offsite electrical power system is the only source of AC power for the majority of ESF equipment at this level of degradation, the risk associated with continued operation for a very short time could be less than that associated with an immediate controlled shutdown. (The immediate shutdown could cause grid instability, which could result in a total loss of AC power.) Since any inadvertent unit generator trip could also result in a total loss of offsite AC power, however, the time allowed for continued operation is severely restricted.

The intent here is to avoid the risk associated with an immediate controlled shutdown and to minimize the risk associated with this level of degradation.

According to Regulatory Guide 1.93 (Ref. 7), with two or more DGs inoperable, operation may continue for a period that should not exceed 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> F.1 and F.2 If the inoperable AC electrical power sources cannot be restored to OPERABLE status within the associated Completion Time, the unit must be brought to a MODE in which the LCO does not apply. To achieve this status, the unit must be brought to at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and to MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.(continued)

SUSQUEHANNA-UNIT 1 TS / B 3.8-14 Revision 2 PPL Rev. 7 AC Sources -Operating B 3.8.1 BASES ACTIONS G.1 (continued)

Condition G corresponds to a level of degradation in which all redundancy in the AC electrical power supplies has been lost. At this severely degraded level, any further losses in the AC electrical power system will cause a loss of function.

Therefore, no additional time is justified for continued operation.

The unit is required by LCO 3.0.3 to commence a controlled shutdown.SURVEILLANCE REQUIREMENTS 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 Unit 2 by LCO 3.8.7, Distribution Systems-Operating.

The Unit I SRs required to support Unit 2 are identified in the Unit 2 Technical Specifications.

Where the SRs discussed herein specify voltage and frequency tolerances, the following summary is applicable.

The minimum steady state output voltage of 3793 V is the value assumed in the degraded voltage analysis and is approximately 90% of the nominal 4160 V output voltage. This value allows for voltage drop to the terminals of 4000 V motors whose minimum operating voltage is specified as 90% or 3600 V. It also allows for voltage drops to motors and other equipment down through the 120 V level where minimum operating voltage is also usually specified as 90% of name plate rating. The specified maximum steady state output voltage of 4400 V is equal to the (continued)

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-UNIT 1 TS / B 3'.8-15 Revision 2 PPL Rev. 7 AC Sources -Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued) maximum operating voltage specified for 4000 V motors. 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 specified minimum and maximum frequencies of the DG are 58.8 Hz and 61.2 Hz, respectively.

These values are equal to +/- 2% of the 60 Hz nominal frequency and are derived from the recommendations found in Regulatory Guide 1.9 (Ref. 3). The lower frequency limit is necessary to support the LOCA analysis assumptions for low pressure ECCS pump flow rates. (Reference 12)The Surveillance Table has been modified by a Note, to clarify the testing requirements associated with DG E. The Note is necessary to define the intent of the Surveillance Requirements associated with the integration of.DG E. Specifically, the Note defines that a DG is only considered OPERABLE and required when it is aligned to the Class 1 E distribution system. For example, if DG A does not meet the requirements of a specific SR, but DG E is substituted for DG A and aligned to the Class 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.Furthermore, the Note identifies when the Surveillance Requirements, as modified by SR Notes, have been met and performed, DG E can be substituted for any other DG and declared OPERABLE after performance of two SRs which verify switch alignment.

This is acceptable because the testing regimen defined in the Surveillance Requirement Table ensures DG E is fully capable of performing all DG requirements.

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

The 7 day Frequency is adequate since breaker position is not likely to change without the operator being aware of it and because its status is displayed in the control room.(continued)

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-UNIT 1 TS / B 3.8-16 Revision 2 PPL Rev. 7 AC Sources -Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.2 REQUIREMENTS (continued)

Not Used.SR 3.8.1.3 This Surveillance verifies that the DGs are capable of synchronizing and accepting greater than or equal to the equivalent of the maximum expected accident loads. A minimum run time of 60 minutes is required to stabilize engine temperatures, while minimizing the time that the DG is connected to the offsite source.Although no power factor requirements are established by this SR, the DG is normally operated at a power factor between 0.8 lagging and 1.0.The 0.8 value is the design rating of the machine, while 1.0 is an operational limitation to ensure circulating currents are minimized.

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

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

Note 2 modifies this Surveillance by stating that momentary transients because of changing bus loads do not invalidate this test. Similarly, momentary power factor transients do not invalidate the test.Note 3 indicates that this Surveillance should be conducted on only one DG at a time in order to avoid common cause failures that might result from offsite circuit or grid perturbations.

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

Note 5 provides the allowance that DG E, when not aligned as substitute for DG A, B, C and D but being maintained available, (continued)

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-UNIT 1 TS / B 3.8-17 Revision 2 PPL Rev. 7 AC Sources -Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.3 REQUIREMENTS (continued) may use the test facility to satisfy loading requirements in lieu of synchronization with an ESS bus.Note 6 allows a single test (instead of two tests, one for each unit) to satisfy the requirements for both units, with the DG synchronized to the 4.16 kV ESS bus of Unit 1 for one periodic test and synchronized to the 4.16 kV ESS bus of Unit 2 during the next periodic test. This is acceptable because the purpose of the test is to demonstrate the ability of the DG to operate at its continuous rating (with the exception of DG E which is only required to be tested at the continuous rating of DGs A through D) and this attribute is tested at the required Frequency.

Each unit's circuit breakers and breaker control circuitry, which are only being tested every second test (due to the staggering of the tests), historically have a very low failure rate. If a DG fails this Surveillance, the DG should be considered inoperable for both units, unless the cause of the failure can be directly related to only one unit. In addition, if the test is scheduled to be performed on the other Unit, and the other Unit's TS allowance that provides an exception to performing the test is used (i.e., the Note to SR 3.8.2.1 for the other Unit provides an exception to performing this test when the other Unit is in MODE 4 or 5, or moving irradiated fuel assemblies in the secondary containment), or it is not possible to perform the test due to equipment availabililty, then the test shall be performed synchronized to this Unit's 4.16 kV ESS bus. The 31 day Frequency for this Surveillance is consistent with Regulatory Guide 1.9 (Ref. 3).SR 3.8.1.4 This SR verifies the level of fuel oil in the engine mounted day tank is at or above the level at which fuel oil is automatically added. The level is expressed as an equivalent volume in gallons, and is selected to ensure adequate fuel oil for a minimum of 55 minutes of DG A-D and 62 minutes of DG E operation at DG continuous rated load conditions.

The 31 day Frequency is adequate to ensure that a sufficient supply of fuel oil is available, since low level alarms are provided and operators would be aware of any large uses of fuel oil during this period.(continued)

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-UNIT 1 TS / B 3.8-18 Revision 3 PPL Rev. 7 AC Sources -Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.5 Microbiological fouling is a major cause of fuel oil degradation.

There are numerous bacteria that can grow in fuel oil and cause fouling, but all must have a water environment in order to survive. Removal of water from the engine mounted day tanks once every 31 days eliminates the necessary environment for bacterial survival.

This is the most effective means of controlling microbiological fouling. In addition, it eliminates the potential for water entrainment in the fuel oil during DG operation.

Water may come from any of several sources, including condensation, ground water, rain water, contaminated fuel oil, and breakdown of the fuel oil by bacteria.

Frequent checking for and removal of accumulated water minimizes fouling and provides data regarding the watertight integrity of the fuel oil system. The Surveillance Frequencies are established by Regulatory Guide 1.137 (Ref. 11). This SR is for preventive maintenance.

The presence of water does not necessarily represent a failure of this SR provided that accumulated water is removed during performance of this Surveillance.

SR 3.8.1.6 This Surveillance demonstrates that each required fuel oil transfer pump operates and transfers fuel oil from its associated storage tank to its associated day tank. It is required to support continuous operation of standby power sources. This Surveillance provides assurance that the fuel oil transfer pump is OPERABLE, the fuel oil piping system is intact, the fuel delivery piping is not obstructed, and the controls and control systems for automatic fuel transfer systems are OPERABLE.(continued)

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-UNIT 1 TS / B 3.8-19 Revision 2 PPL Rev. 7 AC Sources -Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.6 (continued)

REQUIREMENTS The Frequency for this SR is 31 days because the design of the fuel transfer system requires that the transfer pumps operate automatically.

Administrative controls ensure an adequate volume of fuel oil in the day tanks. This Frequency allows this aspect of DG Operability to be demonstrated during or following routine DG operation.

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

To minimize the wear on moving parts that do not get lubricated when the engine is not running, this SR has been modified by Note 1 to indicate that all DG starts for these Surveillances may be preceded by an engine prelube period (which for DGs A through D includes operation of the lube oil system to ensure the DGs turbo charger is sufficiently prelubicated to prevent undo wear and tear).For the purposes of this testing, the DGs are started from standby conditions.

Standby conditions for a DG mean that the diesel engine oil is being continuously circulated and diesel engine coolant is being circulated as necessary to maintain temperature consistent with manufacturer recommendations.

The DG starts from standby conditions and achieves the minimum required voltage and frequency within 10 seconds and maintains the required voltage and frequency when steady state conditions are reached. The 10 second start requirement supports the assumptions in the design basis LOCA analysis of FSAR, Section 6.3 (Ref. 12).To minimize testing of the DGs, Note 2 allows a single test to satisfy the requirements for both units (instead of two tests, one for each unit). This is acceptable because this test is intended to demonstrate attributes of the DG that are not associated with either Unit. If the DG fails this Surveillance, the DG should be considered inoperable for both (continued)

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-UNIT 1 TS / B 3.8-20 Revision 2 PPL Rev. 7 AC Sources -Operating B 3.8.1 BASES REQUIREMENTS SR 3.8.17 (continued)

SURVEILLANCE units, unless the cause of the failure can be directly related to one unit The time for the DG to reach steady state operation is periodically monitored and the trend evaluated to identify degradation.

The 31 day Frequency is consistent with Regulatory Guide 1.9 (Ref. 3).This Frequency provides adequate assurance of DG OPERABILITY.

SR 3.8.1.8 Transfer of each 4.16 kV ESS bus power supply from the normal offsite circuit to the alternate offsite circuit demonstrates the OPERABILITY of the alternate circuit distribution network to power the shutdown loads.The 24 month Frequency of the Surveillance is based on engineering judgment taking into consideration the plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths. Operating experience has shown that these components usually pass the SR when performed on the 24 month Frequency.

Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

This SR is modified by a Note. The reason for the Note is that, during operation with the reactor critical, performance of the automatic transfer of the unit power supply could cause perturbations to the electrical distribution systems that could challenge continued steady state operation and, as a result, plant safety systems. The manual transfer of unit power supply should not result in any perturbation to the electrical distribution system, therefore, no mode restriction is specified.

This Surveillance tests the applicable logic associated with Unit 1. The comparable test specified in Unit 2 Technical Specifications tests the applicable logic associated with Unit 2. Consequently, a test must be performed within the specified Frequency for each unit. As the Surveillance represents separate tests, the Note specifying the restriction for not performing the test while the unit is in MODE 1 or 2 does not have applicability to Unit 2. The NOTE (continued)

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-UNIT I TS / B 3.8-21 Revision 2..........................................-

.,-.-..-..:.-~...

PPL Rev. 7 AC Sources -Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.8 (continued)

REQUIREMENTS only applies to Unit 1, thus the Unit 1 Surveillance shall not be performed with Unit 1 in MODE 1 or 2.SR 3.8.1.9 Each DG is provided with an engine overspeed trip to prevent damage to the engine. Recovery from the transient caused by the loss of a large load could cause diesel engine overspeed, which, if excessive, might result in a trip of the engine. This Surveillance demonstrates the DG load response characteristics and capability to reject the largest single load without exceeding predetermined voltage and frequency and while maintaining a specified margin to the overspeed trip. The largest single load for each DG is a residual heat removal (RHR) pump (1425 kW).This Surveillance may be accomplished by: a. Tripping the DG output breaker with the DG carrying greater than or equal to its associated single largest post-accident load while paralleled to offsite power, or while solely supplying the bus; or b. Tripping its associated single largest post-accident load with the DG solely supplying the bus.As recommended by Regulatory Guide 1.9 (Ref. 3), the load rejection test is acceptable if the increase in diesel speed does not exceed 75% of the difference between synchronous speed and the overspeed trip setpoint, or 15% above synchronous speed, whichever is lower. For DGs A, B, C, D and E, this represents 64.5 Hz, equivalent to 75% of the difference between nominal speed and the overspeed trip setpoint.The time, voltage, and frequency tolerances specified in this SR are derived from Regulatory Guide 1.9 (Ref. 3) recommendations for response during load sequence intervals.

The 4.5 seconds specified is equal to 60% of the 7.5 second load sequence interval between loading of the RHR and core spray pumps during an undervoltage on the bus concurrent with a LOCA. The 6 seconds specified is equal to 80% of that load sequence interval.

The voltage and frequency specified are (continued)

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-UNIT I TS / B 3.8-22 Revision 3 PPL Rev. 7 AC Sources -Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.9 (continued)

REQUIREMENTS consistent with the design range of the equipment powered by the DG.SR 3.8.1.9.a corresponds to the maximum frequency excursion, while SR 3.8.1.9.b and SR 3.8.1.9.c specify the steady state voltage and frequency values to which the system must recover following load rejection.

The 24 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3) and is intended to be consistent with expected fuel cycle lengths.To minimize testing of the DGs, a Note allows a single test to satisfy the requirements for both units (instead of two tests, one for each unit). This is acceptable because this test is intended to demonstrate attributes of the DG that are not associated with either Unit. If the DG fails this Surveillance, the DG should be considered inoperable for both units, unless the cause of the failure can be directly related to only one unit.SR 3.8.1.10 This Surveillance demonstrates the DG capability to reject a full load without overspeed tripping or exceeding the predetermined voltage limits.The DG full load rejection may occur because of a system fault or inadvertent breaker tripping.

This Surveillance ensures proper engine generator load response under the simulated test conditions.

This test simulates the loss of the total connected load that the DG experiences following a full load rejection and verifies that the DG does not trip upon loss of the load. These acceptance criteria provide DG damage protection.

While the DG is not expected to experience this transient during an event, and continues to be available, this response ensures that the DG is not degraded for future application, including reconnection to the bus if the trip initiator can be corrected or isolated.(continued)

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-UNIT 1 TS / B 3.8-23 Revision 3 PPL Rev. 7 AC Sources -Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.10 (continued)

REQUIREMENTS To minimize testing of the DGs, a Note allows a single test to satisfy the requirements for both units (instead of two tests, one for each unit). This is acceptable because this test is intended to demonstrate attributes of the DG that are not associated with either Unit. If the DG fails this Surveillance, the DG should be considered inoperable for both units, unless the cause of the failure can be directly related to only one unit.The 24 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3) and is intended to be consistent with expected fuel cycle lengths.SR 3.8.1.11 As required by Regulatory Guide !,.9 (Ref. 3), this Surveillance demonstrates the as designed operation of the standby power sources during loss of the offsite source. This test verifies all actions encountered from the loss of offsite power, including shedding of the nonessential loads and energization of the ESS buses and respective 4.16kV loads from the DG. It further demonstrates the capability of the DG to automatically achieve and maintain the required voltage and frequency within the specified time.The DG auto-start time of 10 seconds is derived from requirements of the licensed accident analysis for responding to a design basis large break LOCA. The Surveillance should be continued for a minimum of 5 minutes in order to demonstrate that all starting transients have decayed and stability has been achieved.The 24 month Frequency is consistent with the recommendation of Regulatory Guide 1.9. (Ref. 3), takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.(continued)

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-UNIT 1 TS / B 3.8-24 Revision 2 PPL Rev. 7 AC Sources -Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.11 (continued)

REQUIREMENTS This SR is modified by three Notes. The reason for Note 1 is to minimize wear and tear on the DGs during testing. Note 1 allows all DG starts to be preceded by an engine prelube period (which for DGs A through D includes operation of the lube oil system to ensure the DG's turbo charger is sufficiently prelubicated).

For the purpose of this testing, the DGs shall be started from standby conditions that is, with the engine oil being continuously circulated and engine coolant being circulated as necessary to maintain temperature consistent with manufacturer recommendations.

This SR is also modified by Note 2. The Note specifies when this SR is required to be performed for the DGs and the 4.16 kV ESS Buses. The Note is necessary because this SR involves an integrated test between the DGs and the 4.16 kV ESS Buses and the need for the testirg regimen to include DG E being tested (substituted for all DGs for both Units) with all 4.16 kV ESS Buses. To ensure the necessary testing is performed, the following rotational testing regimen has been established:

UNIT IN OUTAGE DIESEL E SUBSTITUTED FOR 2 DG E not tested 1 Diesel Generator D 2 Diesel Generator A 1 DG E not tested 2 Diesel Generator B 1 Diesel Generator A 2 Diesel Generator C 1 Diesel Generator B 2 Diesel Generator D 1 Diesel Generator C The specified rotational testing regimen can be altered to facilitate unanticipated events which render the testing regimen impractical to implement, but any alternative (continued)

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-UNIT 1 TS-/ B 3.8-25 Revision 2 PPL Rev. 7 AC Sources -Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.11 (continued)

REQUIREMENTS testing regimen must provide an equivalent level of testing. This SR does not have to be performed with the normally aligned DG when the associated 4.16 kV ESS bus is tested using DG E and DG E does not need to be tested when not substituted or aligned to the Class 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 every 24 months). Specifically, when DG E is tested with a Unit 1 4.16 kV ESS bus, the attributes of the normally aligned DG, although not tested with the Unit 1 4.16 kV ESS bus, are tested with the Unit 2 4.16 kV ESS bus within the 24 month Frequency.

The testing allowances do result in some circuit pathways which do not need to change state (i.e., cabling) not being tested on a 24 month Frequency.

This is acceptable because these components are not required to change state to perform their safety function and when substituted--normal operation of DG E will ensure continuity of most of the cabling not tested.The reason for Note 3 is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems. This Surveillance tests the applicable logic associated with Unit 1. The comparable test specified in the Unit 2 Technical Specifications tests the applicable logic associated with Unit 2. Consequently, a test must be performed within the specified Frequency for each unit. As the Surveillance represents separate tests, the Note specifying the restriction for not performing the test while the unit is in MODE 1, 2, or 3 does not have applicability to Unit 2. The Note only applies to Unit 1, thus the Unit 1 Surveillances shall not be performed with Unit 1 in MODES 1, 2 or 3.SR 3.8.1.12 This Surveillance demonstrates that the DG automatically starts and achieves the required voltage and frequency within the specified time (10 seconds) from the design basis actuation signal (LOCA signal) and operates for > 5 minutes. The 5 minute period provides sufficient time to demonstrate (continued)

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-UNIT 1 TS / B 3.8-26 Revision 2 PPL Rev. 7 AC Sources -Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.12 (continued)

REQUIREMENTS stability.

SR 3.8.1.12.d and SR 3.8.1.12.e ensure that permanently connected loads and emergency loads are energized from the offsite electrical power system on a LOCA signal without loss of offsite power.The requirement to verify the connection and power supply of permanent and autoconnected loads is intended to satisfactorily show the relationship of these loads to~the loading logic for loading onto offsite power. In certain circumstances, many of these loads cannot actually be connected or loaded without undue hardship or potential for undesired operation.

For instance, ECCS injection valves are not desired to be stroked open, high pressure injection systems are not capable of being operated at full flow, or RHR systems performing a decay heat removal function are not desired to be realigned to the ECCS mode of operation.

In lieu of actual demonstration of the connection and loading of these loads, testing that adequately shows the capability of the DG system to perform these functions is acceptable.

This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.

SR 3.8.1.12.a through SR 3.8.1.12.d are performed with the DG running. SR 3.8.1.12.e can be performed when the DG is not running.The Frequency of 24 months takes into consideration plant conditions required to perform the Surveillance and is intended to be consistent with the expected fuel cycle lengths. Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency.

Therefore, the Frequency is acceptable from a reliability standpoint.

This SR is modified by two Notes. The reason for Note 1 is to minimize wear and tear on the DGs during testing. Note 1 allows all DG starts to be preceded by an engine prelube period (which for DG A through D includes operation of the lube oil system to ensure the DG's turbo-charger is sufficiently prelubicated).

For the purpose of this testing, the DGs must be started from itandby conditions that is, with the engine oil being continuously circulated and engine coolant being circulated as necessary to maintain temperature consistent with manufacturer recommendations.(continued)

SUSQUEHANNA-UNIT 1 TS / B 3.8-27 Revision 2 PPL Rev. 7 AC Sources -Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.13 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.This Surveillance demonstrates that DG non-critical protective functions (e.g., high jacket water temperature) are bypassed on an ECCS initiation test signal. The non-critical trips are bypassed during DBAs and provide an alarm on an abnormal engine condition.

This alarm provides the operator with sufficient time to react appropriately.

The DG availability to mitigate the DBA is more critical than protecting the engine against minor problems that are not immediately detrimental to emergency operation of the DG.The 24 month Frequency is based on engineering judgment, takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths. Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency.

Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

The SR is modified by two Notes. To minimize testing of the DGs, Note 1 to SR 3.8.1.13 allows a single test (instead of two tests, one for each unit) to satisfy the requirements for both units. This is acceptable because this test is intended to demonstrate attributes of the DG that are not associated with either Unit. If the DG fails this Surveillance, the DG should be considered inoperable for both units, unless the cause of the failure can be directly related to only one unit.Note 2 provides the allowance that DG E, when not aligned as a substitute for DG A, B, C, and D but being maintained available, may use a simulated ECCS initiation signal.(continued)

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-UNIT I TS / B 3.8-28 Revision 2 PPL Rev. 7 AC Sources -Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.14 Regulatory Guide 1.9 (Ref. 3), requires demonstration once per 24 months that the DGs can start and run continuously at full load capability for an interval of not less than 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />s-22 hours of which is at a load equivalent to 90% to 100% of the continuous rating of the DG, and 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of which is at a load equivalent to 105% to 110% of the continuous duty rating of the DG. SSES has taken exception to this requirement and performs the two hour run at the 2000 hour0.0231 days <br />0.556 hours <br />0.00331 weeks <br />7.61e-4 months <br /> rating for each DG. The requirement to perform the two hour overload test can be performed in any order provided it is performed during a single continuous time period.The DG starts for this Surveillance can be performed either from standby or hot conditions.

The provisions for prelube discussed in SR 3.8.1.7, and for gradual loading, discussed in SR 3.8.1.3, are applicable to this SR.A load band is provided to avoid routine overloading of the DG. Routine overloading may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY.

The 24 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3), takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.This Surveillance has been modified by four Notes. Note 1 states that momentary transients due to changing bus loads do not invalidate this test.To minimize testing of the DGs, Note 2 allows a single test (instead of two tests, one for each unit) to satisfy the requirements for both units.This is acceptable because this test is intended to demonstrate attributes of the DG that are not associated with either Unit. If the DG fails this Surveillance, the DG should be considered inoperable for both units, unless the cause of the failure can be directly related to only one unit.Note 3 stipulates that DG E, when not aligned as substitute for DG A, B, C or D but being maintained available, may use (continued)

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-UNIT 1 TS / B 3.8-29 Revision 2 PPL Rev. 7 AC Sources -Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.14 (continued)

REQUIREMENTS the test facility to satisfy the specified loading requirements in lieu of synchronization with an ESS bus.SR 3.8.1.15 This Surveillance demonstrates that the diesel engine can restart from a hot condition, such as subsequent to shutdown from full load" temperatures, and achieve the required voltage and frequency within 10 seconds. The 10 second time is derived from the requirements of the accident analysis to respond to a design basis large break LOCA.The 24 month Frequency is consistent with the recornimendation of Regulatory Guide 1.9 (Ref. 3), takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.This SR is modified by three Notes. Note 1 ensures that the test is performed with the diesel sufficiently hot. The requirement that the diesel has operated for at least 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> at full load conditions prior to performance of this Surveillance is based on manufacturer recommendations for achieving hot conditions.

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

Momentary transients due to changing bus loads do not invalidate this test.Note 2 allows all DG starts to be preceded by an engine prelube period (which for DGs A through D includes operation of the lube oil system to ensure the DGs turbo charger is sufficiently prelubricated) to minimize wear and tear on the diesel during testing.To minimize testing of the DGs, Note 3 allows a single test to satisfy the requirements for both units (instead of two tests, one for each unit). This is acceptable because this test is intended to demonstrate attributes of the DG that are not associated with either Unit. If the DG fails this Surveillance, the DG should be considered inoperable for both units, unless the cause of the failure can be directly related to only one unit.(continued)

SUSQUEHANNA

-UNIT I TS / B 3.8-30 Revision 2 S.- .. ,.--. .-;:rt~*. -x PPL Rev. 7 AC Sources -Operating-B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.16 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 his 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 24 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3), takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle-lengths.

This SR is modified by a note to accommodate the testing regimen necessary for DG E. See SR 3.8.1.11 forthe 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 (continued)

SUSQUEHANNA

-UNIT 1 TS / B 3.8-31 Revision 3 PPL Rev. 7 AC Sources -Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.17 (continued)

REQUIREMENTS 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.The 24 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3), takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.This SR is modified by a note to accommodate the testing regimen necessary for DG E. See SR 3.8.1.11 for the Bases of the Note.SR 3.8.1.18 Under accident conditions, loads are sequentially connected to the bus by individual load timers which control the permissive and starting signals to motor breakers to prevent overloading of the AC Sources due to high motor starting currents.

The load sequence time interval tolerance ensures that sufficient time exists for the AC Source to restore frequency and voltage prior to applying the next load and that safety analysis assumptions regarding ESF equipment time delays are not violated, Reference 2 provides a summary of the automatic loading of ESS buses.A list of the required timers and the associated setpoints are included in the Bases as Table B 3.8.1-1, Unit 1 and Unit 2 Load Timers. Failure of a timer identified as an offsite power timer may result in both offsite sources being inoperable.

Failure of any other timer may result in the associated DG being inoperable.

A timer is considered failed for this SR if it will not ensure that the associated load will energize within the Allowable Value in Table B 318.1-1. These conditions will require entry into applicable Conditions of this specification.

With a load timer inoperable, the load can be rendered inoperable to restore OPERABILITY to the associated AC sources. In this condition, the Condition and Required Actions of the associated specification shall be entered for the equipment rendered inoperable.

The 24 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3), takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.(continued)

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-UNIT 1 TS / B 3.8-32 Revision 3 PPL Rev. 7 AC Sources -Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.18 (continued)

REQUIREMENTS This SR is modified by a Note that-specifies that load timers associated with equipment that has automatic initiation capability disabled are not required to be Operable.

This is acceptable because if the load does not start automatically, the adverse effects of an improper loading sequence are eliminated.

Furthermore, load timers are associated with individual timers such that a single timer only affects a single load.SR 3.8.1.19 In the event of a DBA coincident with a loss of offsite power, the DGs are required to supply the necessary power to ESF systems so that the fuel, RCS, and containment design limits are not exceeded.This Surveillance demonstrates DG operation, as discussed in -the Bases for SR 3.8.1.11, during a loss of offsite power actuation test signal in conjunction with an ECCS initiation signal. In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the DG system to perform these functions is acceptable.

This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.

To simulate the non-LOCA unit 4.16 kV ESS Bus loads on the DG, bounding loads are energized on the tested 4.16 kV ESS Bus after all auto connected energizing loads are energized.

The Frequency of 24 months takes into consideration plant conditions required to perform the Surveillance and is intended to be consistent with an expected fuel cycle length. This SR is modified by three Notes. The reason for Note 1 is to minimize wear and tear on the DGs during testing.Note 1 allows all DG starts to be preceded by an engine prelube period (which for DGs A through D includes operation of the lube oil system to ensure the DG's turbo charger is sufficiently prelubricated.)'

For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine oil being continuously circulated and engine coolant being circulated as necessary to maintain temperature consistent with manufacturer recommendations.(continued)

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-UNIT 1 TS / B 3.8-33 Revision 2 PPL Rev. 7 AC Sources -Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.19 (continued)

REQUIREMENTS Note 2 is necessary to accommodate the testing regimen associated with DG E. See SR 3.8.1.11 for the Bases of the Note The reason for Note 3 is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems. This Surveillance tests the applicable logic associated with Unit 1. The comparable test specified in the Unit 2 Technical Specifications tests the applicable logic associated with Unit 2. Consequently, a test must be performed within the specified Frequency for each unit. As the Surveillance represents separate tests, the Note specifying the restriction for not performing the test while the unit is in MODE 1, 2 or 3 does not have applicability to Unit 2. The Note only applies to Unit 1, thus the Unit 1 Surveillances shall not be performed with Unit 1 in MODE 1, 2 or 3.SR 3.8.1.20 This Surveillance demonstrates that the DG starting independence has not been compromised.

Also, this Surveillance demonstrates that each engine can achieve proper speed within the specified time when the DGs are started simultaneously.

The 10 year Frequency is consistent with the recommendations of Regulatory Guide 1.9 (Ref. 3).This SR is modified by two Notes. The reason for Note 1 is to minimize wear on the DG during testing. The Note allows all DG starts to be preceded by an engine prelube period (which for DGs A through D includes operation of the lube oil system to-ensure the DG's turbo charger is-sufficiently prelubricated).

For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine oil continuously circulated and engine coolant being circulated as necessary to maintain temperature consistent with manufacturer recommendations.

Note 2 is necessary to identify that this test does not have to be performed with DG E substituted for any DG. The allowance is acceptable based on the design of the DG E transfer switches.

The transfer of control, protection, indication, (continued)

SUSQUEHANNA

-UNIT 1 TS / B 3.8-34 Revision 2 PPL Rev. 7 AC Sources -Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.20 (continued)

REQUIREMENTS and alarms is by switches at two separate locations.

These switches provide a double break between DG E and the redundant system within the transfer switch panel. The transfer of power is through circuit breakers at two separate locations for each redundant system. There are four normally empty switch gear positions at DG E facility, associated with each of the four existing DGs. Only one circuit breaker is available at this location to be inserted into one of the four positions.

At each of the existing DGs, there are two switchgear positions with only one circuit breaker available.

This design provides two open circuits between redundant power sources. Therefore, based on the described design, it can be concluded that DG redundancy and independence is maintained regardless of whether DG E is substituted for any other DG.REFERENCES

1. 10 CFR 50, Appendix A, GDC 17.2. FSAR, Section 8.2.3. Regulatory Guide 1.9.4. FSAR, Chapter 6.5. FSAR, Chapter 15.6. Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 39132).7. Regulatory Guide 1.93.8. Generic Letter 84-15.9. 10 CFR 50, Appendix A, GDC 18.10. IEEE Standard 308.11. Regulatory Guide 1.137.12. FSAR, Section 6.3.13. ASME Boiler and Pressure Vessel Code,Section XI.(continued)

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-UNIT 1 TS / B] 3.8-35 Revision 2 PPL Rev. 7 AC Sources -Operating B 3.8.1 TABLE B 3.8.1-1 (page 1 of 2)UNIT 1 AND UNIT 2 LOAD TIMERS NOMINAL DEVICE SETTING ALLOWABLE VALUE TAG NO. SYSTEM LOADING TIMER LOCATION (seconds) (seconds)62A-20102 RHR Pump 1A !A201 3 2.7 and _ 3.6 62A-20202 RHR Pump 1B 1A202 3 2! 2.7 and _ 3.6 62A-20302 RHR Pump 1C 1A203 3 "_2.7 and < 3.6 62A-20402 RHR Pump 1D 1A204 3 >2.7 and 3.6 62A-20102 RHR Pump 2A 2A201 3 >2.7 and 3.6 62A-20202 RHR Pump 2B 2A202 3 t 2.7 and _3.6 62A-20302 RHR Pump 2C 2A203 3 2.7 and !5 3.6 62A-20402 RHR Pump 2D 2A204 3 2.7 and _. 3.6 E11A-K202B RH R Pump 1C (Offsite Power Timer) 1C618 7.0 t 6.5 and 7.5 E11A-K120A RH R Pump 1C (Offsite Power Timer) 1 C617 7.0 6.5 and _ 7.5 E11A-K120B RHR Pump 1 D (Offsite Power Timer) 1C618 7.0 > 6.5 and _7.5 El1 A-K202A RHR Pump 1 D (Offsite Power Timer) 1 C617 7.0 6.5 and _ 7.5 E11A-K120A RHR Pump 2C (Offsite Power Timer) 2C617 7.0 6.5 and 7.5 El1A-K202B RHR Pump 2C (OIfsite Power Timer) 2C618 7.0 6.5 and 7.5 E11A-K120B RHR Pump 2D (Oftsite Power Timer) 2C618 7.0 > 6.5 and 7.5 E11A-K202A RHR Pump 2D (Offsite Power Timer) 2C617 7.0 :6.5 and 7.5 E21A-K116A CS Pump 1A 1C626 10.5 9.4and -11.6 E21A-K116B CS Pump 1B 1C627 10.5 9.4and_<

11.6 E21A-K125A CS Pump 1C 1C626 10.5 2_9.4and_<

11.6 E21A-K125B CS Pump ID 1C627 10.5 'a 9.4 and 11.6 E21A-K116A CS Pump 2A 2C626 10.5 _9.4 and 11.6 E21A-K116B CS Pump 2B 2C627 10.5 >9.4 and 11.6 E21 A-K1 25A CS Pump 2C 2C626 10.5 _9.4 and _ 11.6 E21A-K125B CS Pump 2D 2C627 10.5 9.4 and_< 11.6 E21A-K16A CS Pump 1A (Offsite Power Timer) 1 C626 15 i 14.0 and 16.0 E21 A-K1 68 CS Pump 1B (Offsite Power Timer) 1C627 15 _ 14.0 and < 16.0 E21A-K25A CS Pump 1C (Offsite Power Timer) 1 C626 15 14.0 and < 16.0 E21A-K25B CS Pump 1D (Offsite Power Timer) 1C627 15 > 14.0 and < 16.0 E21A-K16A CS Pump 2A (Offsite Power Timer) 2C626 15 2:14.0 and 16.0 E21A-K16B CS Pump 26 (Offsite Power Timer) 2C627 15 2 14.0 and 16.0 E21A-K25A CS Pump 2C (Offsite Power Timer) 2C626 15 _14.0 and 16.0 E21A-K25B CS Pump 2D (Offsite Power Timer) 2C627 15 14.0 and 16.0 62AX2-20108 Emergency Service Water 1A201 40 >_ 36 and 44 62AX2-20208 Emergency Service Water 1A202 40 a 36 and _ 44 62AX2-20303 Emergency Service Water 1 A203 44 :39.6 and _ 48.4 62AX2-20403 Emergency Service Water 1 A204 48 43.2 and 52.8 62X3-20404 Control Structure ChilledWater System OC877B 60 > 54 62X3-20304 Control Structure Chilled Water System OC877A 60 > 54 62X-20104 Emergency Switcligear Rm Cooler A & OC877A 60 54 RHR SW Pump H&V Fan A 62X-20204 Emergency Switchgear Rm Cooler B & OC877B 60 54 RHR SW Pump H&V Fan B 62X-5653A DG Room Exhaust Fan E3 OB565 60 >54 62X-5652A DG Room Exhausts Fan E4 OB565 60 > 54 262X-20204 Emergency Switchgear Rm Cooler B OC877B 120 >54 262-X-20104 Emergency Sw(tchgear Rm Cooler A OC877A 120 ci54 (continued)

SUSQUEHANNA

-UNIT 1 TS / B 3.8-36 Revision 2 PPL Rev. 7 AC Sources -Operating B 3.8.1 TABLE B 3.8.1-1 (page 2 of 2)UNIT 1 AND UNIT 2 LOAD TIMERS NOMINAL DEVICE SETTING ALLOWABLE VALUE TAG NO. SYSTEM LOADING TIMER LOCATION (seconds) (seconds)62X-546 DG Rm Exh.Fan D OB546 120 _54 62X-536 DG Rm Exh Fan C OB536 120 >54 62X-526 DG Rm Exh Fan B OB526 120 >_ 54 62X-516 DG Rm Exh Fan A OB516 120 >54 CRX-5652A DG Room Supply Fans El and E2 OB565 120 >54 62X2-2041 0 Control Structure Chilled Water System OC876B 180 > 54 62X1 -20304 Control Structure Chilled Water System OC877A 180 > 54 62X2-2031 0 Control Structure Chilled Water System OC876A 180 >54 62X1 -20404 Control Structure Chilled Water System OC877B 180 >54 62X2-20304 Control Structure Chilled Water System 'OC877A 210 > 54 62X2-20404 Control Structure Chilled Water System OC877B 210 _ 54 62X-K1 166 Emergency Switchgear Rm Cooling 2CB250B 260 >_ 54 Compressor B 62X-Kl1AB Emergency Switchgear Rm Cooling 2CB250A .260 >54 Compressor A SUSQUEHANNA

-UNIT 1 TS / B 3.8-37 Revision 2 SSES MANUAL Manual Name: TSB1 Manual Title: TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL Table Of Contents Issue Date: 02/24/2014 Procedure Name Rev TEXT LOES 114 Title: LIST OF EFFECTIVE SECTIONS rv CO AE'lPROLLLD Issue Date 02/24/2014 Change ID Change Number TEXT TOC Title: TABLE OF CONTENTS 22 03/28/2013 TEXT 2.1.1 5 Title: SAFETY LIMITS (SLS) REACTOR TEXT 2.1.2 1 Title: SAFETY LIMITS (SLS) REACTOR 05/06/2009 CORE SLS 10/04/2007 COOLANT SYSTEM (RCS) PRESSURE S TEXT 3.0 Title: LIMITING CONDITION 3 08/20/2009 FOR OPERATION (LCO) APPLICABILITY TEXT 3.1.1 Title: REACTIVITY TEXT 3.1.2 Title: REACTIVITY TEXT 3.1.3 Title: REACTIVITY TEXT 3.1.4 Title: REACTIVITY TEXT 3.1.5 Title: REACTIVITY TEXT 3.1.6 1 04/18/2006 CONTROL SYSTEMS SHUTDOWN MARGIN (SDM)0 11/15/2002 CONTROL SYSTEMS REACTIVITY ANOMALIES 2 01/19/2009 CONTROL SYSTEMS CONTROL ROD OPERABILITY 4 01/30/2009 CONTROL SYSTEMS CONTROL ROD SCRAM TIMES 1 07/06/2005 CONTROL SYSTEMS CONTROL ROD SCRAM ACCUMULATORS 3 02/24/2014 Title: REACTIVITY CONTROL SYSTEMS ROD PATTERN CONTROL Pagel of 8 Report Date: 02/25/14 Page I of .8 Report Date: 02/25/14 SSES MANUAL Manual Name: TSBI Manual Title: TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL TEXT 3.1.7 3 04/23/2008 Title: REACTIVITY CONTROL SYSTEMS STANDBY LIQUID CONTROL (SLC) SYSTEM TEXT 3.1. 8 Title: REACTIVITY CONTROL 3 05/06/2009 SYSTEMS SCRAM DISCHARGE VOLUME (SDV) VENT AND DRAIN VALVES TEXT 3.2.1 2 04/23/2008 Title: POWER DISTRIBUTION LIMITS AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)TEXT 3.2.2 Title: POWER DISTRIBUTION TEXT 3.2.3 Title: POWER DISTRIBUTION 3 05/06/2009 LIMITS MINIMUM CRITICAL POWER RATIO (MCPR)2 04/23/2008 LIMITS LINEAR HEAT GENERATION RATE (LHGR)TEXT 3.3.1.1 6 02/24/2014 Title: INSTRUMENTATION REACTOR PROTECTION SYSTEM (RPS) INSTRUMENTATION TEXT 3.3.1.2 2 01/19/2009 Title: INSTRUMENTATION SOURCE RANGE MONITOR (SRM) INSTRUMENTATION TEXT 3.3.2.1 4 02/24/2014 Title: INSTRUMENTATION CONTROL ROD BLOCK INSTRUMENTATION TEXT 3.3.2.2 Title: INSTRUMENTATION 2 04/05/2010 FEEDWATER MAIN TURBINE HIGH WATER LEVEL TRIP INSTRUMENTATION TEXT 3.3.3.1 9 02/28/2013 Title: INSTRUMENTATION POST ACCIDENT MONITORING (PAM) INSTRUMENTATION TEXT 3.3.3.2 1 04/18/2005 Title: INSTRUMENTATION REMOTE SHUTDOWN SYSTEM TEXT 3.3.4.1 2 02/24/2014 Title: INSTRUMENTATION END OF CYCLE RECIRCULATION PUMP TRIP (EOC-RPT)

INSTRUMENTATIOO Page 2 of 8 Report Date: 02/25/14 SSES MANUAL Manual Name: TSB1 Manual Title: TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL TEXT 3.3.4.2 0 11/15/2002 Title: INSTRUMENTATION ANTICIPATED TRANSIENT WITHOUT SCRAM RECIRCULATION PUMP TRIP (ATWS-RPT)

INSTRUMENTATION TEXT 3.3.5.1 Title: INSTRUMENTATION TEXT 3.3.5.2 Title: INSTRUMENTATION TEXT 3.3.6.1 Title: INSTRUMENTATION TEXT 3.3.6.2 Title: INSTRUMENTATION TEXT 3.3.7.1 Title: INSTRUMENTATION INSTRUMENTATION TEXT 3.3.8.1 Title: INSTRUMENTATION TEXT 3.3,8.2 Title% INSTRUMENTATION TEXT 3.4,1 Title: REACTOR COOLANT 3 08/20/2009 EMERGENCY CORE COOLING SYSTEM (ECCS) INSTRUMENTATION 0 11/15/2002 REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM INSTRUMENTATION 6 02/24/2014 PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION 4 09/01/2010 SECONDARY CONTAINMENT ISOLATION INSTRUMENTATION 2 10/27/2008 CONTROL ROOM EMERGENCY OUTSIDE AIR SUPPLY (CREOAS) SYSTEM 2 12/17/2007 LOSS OF POWER (LOP) INSTRUMENTATION 0 11/15/2002 REACTOR PROTECTION SYSTEM (RPS) ELECTRIC POWER MONITORING 4 04/27/2010 SYSTEM (RCS) RECIRCULATION LOOPS OPERATING TEXT 3.4,2 3 10/23/2013 Title% REACTOR COOLANT SYSTEM (RCS) JET PUMPS TEXT 3.4,3 Title: REACTOR COOLANT TEXT 3.4.4 Title: REACTOR COOLANT 3 01/13/2012 SYSTEM RCS SAFETY RELIEF VALVES S/RVS 0 11/15/2002 SYSTEM (RCS) RCS OPERATIONAL LEAKAGE Page~ of 8 Report Date: 02/25/14 Page .1 of 8 Report Date: 02/25/14 SSES MANUAL Manual Name: TSBl Manual Title: TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL TEXT 3.4.5 1 01/16/2006 Title: REACTOR COOLANT SYSTEM (RCS) RCS PRESSURE ISOLATION VALVE (PIV) LEAKAGE TEXT 3.4.6 4 02/19/2014 Title: REACTOR COOLANT SYSTEM (RCS) RCS LEAKAGE DETECTION INSTRUMENTATION TEXT 3.4.7 2 10/04/2007 Title: REACTOR COOLANT SYSTEM (RCS) RCS SPECIFIC ACTIVITY TEXT 3.4.8 Title: REACTOR COOLANT-HOT SHUTDOWN TEXT 3.4.9 Title: REACTOR COOLANT-COLD SHUTDOWN 2 SYSTEM (RCS)1 SYSTEM (RCS)03/28/2013 RESIDUAL HEAT REMOVAL (RHR) SHUTDOWN COOLING SYSTEM 03/28/2013 RESIDUAL HEAT REMOVAL (RHR) SHUTDOWN COOLING SYSTEM 9 TEXT 3.4.10 3 04/23/2008 Title: REACTOR COOLANT SYSTEM (RCS) RCS PRESSURE AND TEMPERATURE (P/T) LIMITS TEXT 3.4.11 0 11/15/2002 Title: REACTOR COOLANT SYSTEM (RCS) REACTOR STEAM DOME PRESSURE TEXT 3.5.1 3 02/24/2014 Title: EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR SYSTEM ECCS -OPERATING TEXT 3.5.2 0 11/15/2002 Title: EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR SYSTEM ECCS -SHUTDOWN TEXT 3.5.3 3 02/24/2014 Title: EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR SYSTEM RCIC SYSTEM CORE ISOLATION COOLING (RCIC)CORE ISOLATION COOLING (RCIC)CORE ISOLATION COOLING (RCIC)TEXT 3.6.1.1 Title: PRIMARY CONTAINMENT 5 02/24/2014 TEXT 3.6.1.2 1 04/23/2008 Title: CONTAINMENT SYSTEMS PRIMARY CONTAINMENT AIR LOCK Page4 of 8 Report Date: 02/25/14 Page 4 of .8 Report Date: 02/25/14 SSES MA.NUAL Manual Name: TSB1 Manual Title: TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL TEXT 3.6.1.3 10 05/23/2012 Title: CONTAINMENT SYSTEMS PRIMARY CONTAINMENT ISOLATION VALVES (PCIVS)TEXT 3.6.1.4 1 04/23/2008 Title: CONTAINMENT SYSTEMS CONTAINMENT PRESSURE TEXT 3.6.1.5 1 10/05/2005 Title: CONTAINMENT SYSTEMS DRYWELL AIR TEMPERATURE TEXT 3.6.1.6 0 11/15/2002 Title: CONTAINMENT SYSTEMS SUPPRESSION CHAMBER-TO-DRYWELL VACUUM BREAKERS TEXT 3.6.2.1 2 04/23/2008 Title: CONTAINMENT SYSTEMS SUPPRESSION POOL AVERAGE TEMPERATURE TEXT 3.6.2.2 0 11/15/2002 Title: CONTAINMENT SYSTEMS SUPPRESSION POOL WATER LEVEL TEXT 3.6.2.3 1 01/16/2006 Title: CONTAINMENT SYSTEMS RESIDUAL HEAT REMOVAL (RHR) SUPPRESSION POOL COOLING TEXT 3.6.2.4 0 11/15/2002 Title: CONTAINMENT SYSTEMS RESIDUAL HEAT REMOVAL (RHR) SUPPRESSION POOL SPRAY TEXT 3.6.3.1 2 06/13/2006 Title: CONTAINMENT SYSTEMS PRIMARY CONTAINMENT HYDROGEN RECOMBINERS TEXT 3.6.3.2 1 04/18/2005 Title: CONTAINMENT SYSTEMS DRYWELL AIR FLOW SYSTEM TEXT 3.6.3.3 1 02/28/2013 Title: CONTAINMENT SYSTEMS PRIMARY CONTAINMENT OXYGEN CONCENTRATION TEXT 3.6.4.1 9 12/10/2013 Title: CONTAINMENT SYSTEMS SECONDARY CONTAINMENT Page 5 of .8 Report Date: 02/25/14 SSES MANUAL Manual Name: TSBI Manual Title: TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL TEXT 3.6.4.2 8 03/28/2013 Title: CONTAINMENT SYSTEMS SECONDARY CONTAINMENT ISOLATION VALVES (SCIVS)TEXT 3.6.4.3 4 09/21/2006 Title: CONTAINMENT SYSTEMS STANDBY GAS TREATMENT (SGT) SYSTEM TEXT 3.7.1 Title: PLANT SYSTEMS ULTIMATE HEAT 4 04/05/2010 RESIDUAL HEAT REMOVAL SERVICE WATER (RHRSW) SYSTEM AND THE SINK (UHS)TEXT 3.7.2 Title: PLANT TEXT 3.7.3 Title: PLANT TEXT 3.7.4 Title: PLANT TEXT 3.7.5 Title: PLANT TEXT 3.7.6 Title: PLANT TEXT 3.7.7 Title: PLANT 2 02/11/2009 SYSTEMS EMERGENCY SERVICE WATER (ESW) SYSTEM 1 01/08/2010 SYSTEMS CONTROL ROOM EMERGENCY OUTSIDE AIR SUPPLY (CREOAS) SYSTEM 0 11/15/2002 SYSTEMS CONTROL ROOM FLOOR COOLING SYSTEM 1 10/04/2007 SYSTEMS MAIN CONDENSER OFFGAS 2 04/23/2008 SYSTEMS MAIN TURBINE BYPASS SYSTEM 1 10/04/2007 SYSTEMS SPENT FUEL STORAGE POOL WATER LEVEL TEXT 3.7.8 Title: PLANT SYSTEMS 0 04/23/2008 TEXT 3.8.1 7 02/24/2014 Title: ELECTRICAL POWER SYSTEMS AC SOURCES -OPERATING TEXT 3.8.2 0 11/15/2002 Title: ELECTRICAL POWER SYSTEMS AC SOURCES -SHUTDOWN Page .~ of 8 Report Date: 02/25/14 Page6 of _8 Report Date: 02/25/14 SSES MANUAL Manual Name: TSB1 Manual Title: TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL TEXT 3.8.3 Title: ELECTRICAL TEXT 3.8.4 Title: ELECTRICAL TEXT 3.8.5 Title: ELECTRICAL TEXT 3.8.6 Title: ELECTRICAL TEXT 3.8.7 Title: ELECTRICAL TEXT 3.8.8 Title: ELECTRICAL TEXT 3.9.1 Title: REFUELING C TEXT 3.9.2 Title: REFUELING C TEXT 3.9.3 Title: REFUELING C TEXT 3.9.4 Title: REFUELING C TEXT 3.9.5 Title: REFUELING C TEXT 3.9.6 Title: REFUELING C POWER SYST POWER SYST POWER SYST POWER SYST POWER SYST POWER SYST)PERATIONS)PERATIONS)PERATIONS)PERATIONS)PERATIONS)PERATIONS 4 10/23/2013 EMS DIESEL FUEL OIL, LUBE OIL, AND STARTING AIR 3 01/19/2009 EMS DC SOURCES -OPERATING 1 12/14/2006 EMS DC SOURCES -SHUTDOWN 1 12/14/2006 EMS BATTERY CELL PARAMETERS 1 10/05/2005 EMS DISTRIBUTION SYSTEMS -OPERATING 0 11/15/2002 EMS DISTRIBUTION SYSTEMS -SHUTDOWN 0 11/15/2002 REFUELING EQUIPMENT INTERLOCKS 1 09/01/2010 REFUEL POSITION ONE-ROD-OUT INTERLOCK 0 11/15/2002 CONTROL ROD POSITION 0 11/15/2002 CONTROL ROD POSITION INDICATION 0 11/15/2002 CONTROL ROD OPERABILITY

-REFUELING 1 10/04/2007 REACTOR PRESSURE VESSEL (RPV) WATER LEVEL Page2 of 8 Report Date: 02/25/14 Page 2 of 8 Report Date: 02/25/14 SSES MANUAL.Manual Name: TSBI Manual Title: TECHNICAL SPECIFICATION BASES UNIT 1 MANUAL TEXT 3.9.7 0 11/15/2002 Title: REFUELING OPERATIONS RESIDUAL HEAT REMOVAL (RHR) -HIGH WATER LEVEL TEXT 3.9.8 0 11/15/2002 Title: REFUELING OPERATIONS RESIDUAL HEAT REMOVAL (RHR) -LOW WATER LEVEL TEXT 3.10.1 Title: SPECIAL TEXT 3.10.2 Title: SPECIAL TEXT 3.10.3 Title: SPECIAL TEXT 3.10.4 Title: SPECIAL TEXT 3.10.5 Title: SPECIAL TEXT 3.10.6 Title: SPECIAL TEXT 3.10.7 Title: SPECIAL TEXT 3.10.8 Title: SPECIAL OPERATIONS OPERATIONS OPERATIONS OPERATIONS OPERATIONS OPERATIONS OPERATIONS OPERATIONS 1 01/23/2008 INSERVICE LEAK AND HYDROSTATIC TESTING OPERATION 0 11/15/2002 REACTOR MODE SWITCH INTERLOCK TESTING 0 11/15/2002 SINGLE CONTROL ROD WITHDRAWAL

-HOT SHUTDOWN 0 11/15/2002 SINGLE CONTROL ROD WITHDRAWAL

-COLD SHUTDOWN 0 11/15/2002 SINGLE CONTROL ROD DRIVE (CRD) REMOVAL -REFUELING 0 11/15/2002 MULTIPLE CONTROL ROD WITHDRAWAL

-REFUELING 1 04/18/2006 CONTROL ROD TESTING -OPERATING 1 04/12/2006 SHUTDOWN MARGIN (SDM) TEST -REFUELING Page~ of 8 Report Date: 02/25/14 Page 8 of 8 Report Date: 02/25/14 SUSQUEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE:SECTIONS (TECHNICAL SPECIFICATIONS BASES)Section Title Revision TOC Table of Contents 22 B 2.0 SAFETY LIMITS BASES Page B 2.0-1 0 Page TS / B 2.0-2 3 Page TS / B 2.0-3 5 Page TS / B 2.0-4 3 Page TS / B 2.0-5 5 Page TS / B 2.0-6 1 Pages TS / B 2.0-7 through TS / B 2.0-9 1 B 3.0 LCO AND SR APPLICABILITY BASES Page TS / B 3.0-1 1 Pages TS / B 3.0-2 through TS / B 3.0-4 0 Pages TS / B 3.0-5 through TS / B 3.0-7 1 Page TS / B 3.0-8 3 Pages TS / B 3.0-9 through TS / B 3.0-11 2 Page TS / B 3.0-11 a 0 Page TS / B 3.0-12 1 Pages TS / B 3.0-13 through TS / B 3.0-15 2 Pages TS / B 3.0-16 and TS / B 3.0-17 0 B:3.1 REACTIVITY CONTROLBASES Pages B 3.1-1 through B 3.1-4 0 Page TS / B 3.1-5 1 Pages TS / B 3.1-6 and TS / B 3.1-7 2 Pages B 3.1-8 through B 3.1-13 0 Page TS / B 3.1-14 1 Page B 3.1-15 0 Page TS / B 3.1-16 1 Pages B 3.1-17 through B 3.1-19 0 Pages TS / B 3.1-20 and TS / B 3.1-21 1 Page TS / B 3.1-22 0 Page TS / B 3.1-23 1 Page TS / B 3.1-24 0 Pages TS / B 3.1-25 through TS / B 3.1-27 1 Page TS / B 3.1-28 2 Page TS / B 3.1-29 1 Pages B 3.1-30 through B 3.1-33 0 Pages TS / B 3.3-34 through TS / B 3.3-36 1 Page TS / B 3.1-37 2 Page TS I B 3.1-38 3 Pages TS / B 3.1-39 and TS / B 3.1-40 2 Page TS / B 3.1-40a 0 Pages TS / B3.1-41 and TS / B 3.1-42 2 SUSQUEHANNA-UNITI TS/B LOES-1 Revision 114 SUSQUEHANNA

-UNIT 1 TS / B LOES-1 Revision 114 SUSQUEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)Section Title Revision Page TS / B 3.1.43 1 Page TS / B 3.1-44 0 Page TS / B 3.1-45 3 Pages TS / B 3.1-46 through TS / B 3.1-49 1 Page TS / B 3.1-50 0 Page TS / B 3.1-51 3 B 3.2 POWER DISTRIBUTION LIMITS BASES Page TS / B 3.2-1 2 Pages TS / B 3.2-2 and TS / B 3.2-3 3 Pages TS / B 3.2-4 and TS / B 3.2-5 2 Page TS / B 3.2-6 3 Page B 3.2-7 1 Pages TS / B 3.2-8 and TS / B 3.2-9 3 Page TS / B 3.2.10 2 Page TS / B 3.2-11 3 Page TS / B 3.2-12 1 Page TS / B 3.2-13 2 B 3.3 INSTRUMENTATION Pages TS / B 3.3-1 through TS I B 3.3-4 1 Page TS / B 3.3-5 2 Page TS / B 3.3-6 1 Page TS / B 3.3-7 3 Page TS / B 3&3-7a 1 Page TS / B 3.3-8 5 Pages TS / B 3.3-9 through TS / B 3.3-12 3 Pages TS / B 3.3-12a 1 Pages TS / B 3.3-12b and TS / B 3.3-12c 0 Page TS / B 3.3-13 1 Page TS / B 3.3-14 3 Pages TS / B 3.3-15 and TS / B 3.3-16 1 Pages TS / B 3.3-17 and TS / B 3.3-18 4 Page TS / B 3.3-19 1 Pages TS / B 3.3-20 through TS / B 3.3-22 2 Page TS / B 3.3-22a 0 Pages TS / B 3.3-23 and TS / B 3.3-24 2 Pages TS / B 3.3-24a and TS / B 3.3-24b 0 Page TS / B 3.3-25 3 Page TS / B 3.3-26 2 Page TS / B 3.3-27 1 Page TS / B 3.3-28 3 Page TS / B 3.3-29 4 Page TS / B 3.3-30 3 Page TS / B 3.3-30a 0 SUSQUEHANNA

-UNIT 1 TS / B LOES-2 'Revision 114 SUSQUEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)Section Title Revision Page TS / B 3.3-31 4 Page TS / B 3.3-32 5 Pages TS / B 3.3-32a 0 Page TS / B 3.3-32b 1 Page TS / B 3.3-33 5 Page TS / B 3.3-33a 0 Page TS / B 3.3-34 1 Pages TS / B 3.3-35 and TS / B 3.3-36 2 Pages TS / B 3.3-37 and TS / B 3.3-38 1 Page TS / B 3.3-39 2 Pages TS / B 3.3-40 through TS / B 3.3-43 1 Page TS / B 3.3-44 4 Pages TS / B 3.3-44a and TS / B 3.3-44b 0 Page TS / B 3.3-45 3 Pages TS / B 3.3-45a and TS / B 3.3-45b 0 Page'TS / B 3.3-46 3 Pages TS / B 3.3-47 2 Pages TS / B 3.3-48 through TS / B 3.3-51 3 Pages TS / B 3.3-52 and TS / B 3.3-53 2 Page TS / B 3-3-53a 0 Page TS / B 3.3-54 5 Page TS / B 3.3-55 2 Pages TS / B 3.3-56 and TS / B 3.3-57 1 Page TS / B 3.3-58 0 Page TS / B 3.3-59 1 Page TS / B 3.3-60 0 Page TS / B 3.3-61 1 Pages TS / B 3.3-62 and TS / B 3.3-63 0 Pages TS / B 3.3-64 and TS / B 3.3-65 2 Page TS / B 3.3-66 4 Page TS / B 3.3-67 3 Page TS / B 3.3-68 4 Page TS / B 3.3-69 5 Pages TS / B 3.3-70 4 Page TS / B 3.3-71 3 Pages TS / B 3.3-72 and TS / B 3.3-73 2 Page TS / B 3.3-74 3 Page TS / B 3.3-75 2 Page TS / B 3.3-75a 6 Page TS / B 3.3-75b 7 Page TS / B 3.3-75c 6 SUSQUEHANNA

-UNIT I TS/BLOES-3 Revision 114 SUSQUEHANNA

-UNIT 1 TS / B LOES-3 Revision 114 SUSQUEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)Section Title Revision Pages B 3.3-76 through B 3.3-77 0 Page TS / B 3.3-78 1 Pages B 3.3-79 through B 3.3-81 0 Page TS / B 3.3-82 2 Page B 3.3-83 0 Pages B 3.3-84 and B 3.3-85 1 Page B 3.3-86 0 Page B 3.3-87 1 Page B 3.3-88 0 Page B 3.3-89 1 Page TS / B 3.3-90 1 Page B 3.3-91 0 Pages TS I B 3.3-92 through TS / B 3.3-100 1 Pages TS / B 3.3-101 through TS / B 3.3-103 0 Page TS / B 3.3-104 2 Pages TS / B 3.3-105 and TS / B 3.3-106 0 Page TS / B 3.3-107 1 Page TS / B 3.3-108 0 Page TS / B 3.3-109 1 Pages TS / B 3.3-110 and TS / B 3.3-111 0 Pages TS / B 3.3-112 and TS / B 3.3-112a 1 Pages TS / B 3.3-113 through TS/B 3.3-115 1 Page TS / B 3.3-116 3 Page TS / B 3.3-117 1 Pages TS / B 3.3-118 through TS / B 3.3-122 0 Pages TS / B 3.3-123 and TS I B 3.3-124 1 Page TS / B 3.3-124a 0 Page TS / B 3.3-125 0 Pages TS / B 3.3-126 and TS / B 3.3-127 1 Pages TS / B 3.3-128 through TS/ B 3.3-130 0 Page TS / B 3.3-131 1 Pages TS / B 3.3-132 through TS I B 3.3-134 0 Pages B 3.3-135 through B 3.3-137 0 Page TS / B 3.3-138 1 Pages B 3.3-139 through B 3.3-149 0 Pages TS / B 3.3-150 and TS / B 3.3-151 1 Pages TS / B 3.3-152 through TS / B 3.3-154 2 Page TS / B 3.3-155 1 Pages TS / B 3.3-156 through TS / B 3.3-158 2 Pages TS / B 3.3-159 and TS I B 3.3-160 1 Page TS / B 3.3-161 2 Page TS / B 3.3-162 1 Page TS / B 3.3-163 2 Page TS / B 3.3-164 1 Pages TS / B 3.3-165 through TS / B 3.3-167 2 SUSQUEHANNA

-UNIT 1 TS/BLOES-4 Revision 114 SUSQUEHANNA

-UNIT 1 TS / B LOES-4 Revision 114 SUSQUEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)Section Title Revision Pages TS / B 3.3-168 and TS / B 3.3-169 1 Page TS / B 3.3-170 2 Pages TS / B 3.3-171 through TS / B 3.3-177 1 Pages TS / B 3.3-178 through TS / B 3.3-179a 2 Pages TS / B 3.3-179b and TS / B 3.3-179c 0 Page TS / B 3.3-180 1 Page TS / B 3.3-181 3 Page TS / B 3.3-182 1 Page TS / B 3.3-183 2 Page TS / B 3.3-184 1 Page TS / B 3.3-185 4 Page TS / B 3.3-186 1 Pages TS / B 3.3-187 and TS I B 3.3-188 2 Pages TS / B 3.3-189 through TS / B 3.3-191 1 Page TS / B 3.3-192 0 Page TS / B 3.3-193 1 Pages TS / B 3.3-194 and TS / B 3.3-195 0 Page TS / B 3.3-196 2 Pages TS / B 3.3-197 through TS / B 3.3-204 0 Page TS I B 3.3-205 1 Pages B 3.3-206 through B 3.3-209 0 Page TS / B 3.3-210 1 Pages B 3.3-211 through B 3.3-219 0 8 3.4 REACTOR COOLANT SYSTEM BASES Pages B 3.4-1 and B 3.4-2 0 Pages TS / B 3.4-3 and Page TS / B 3.4-4 4 Page TS / B 3.4-5 3 Pages TS / B 3.4-6 through TS / B 3.4-9 2 Page TS / B 3.4-10 1 Pages TS / 3.4-11 and TS / B 3.4-12 0 Page TS / B 3.4-13 2 Page TS / B 3.4-14 1 Page TS / B 3.4-15 2 Pages TS / B 3.4-16 and TS / B 3.4-17 4 Page TS / B 3.4-18 2 Pages B 3.4-19 through B 3.4-27 0 Pages TS / B 3.4-28 and TS / B 3.4-29 1 Page TS / B 3.4-30 2 Page TS / B 3.4-31 1 Pages TS / B 3.4-32 and TS / B 3.4-33 2 Page TS / B 3.4-34 1 Page TS / B 3.4-34a 0 Pages TS / B 3.4-35 and TS / B 3.4-36 1 SUSQUEHANNA

-UNIT 1 TSIB LOES-5 Revision 114 SUSQUEHANNA

-UNIT 1 TS / B LOES-5 Revision 114 SUSQUEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)Section Title Revision Page TS / B 3.4-37 2 Page TS / B 3.4-38 1 Pages B 3,4-39 and B 3.4-40 0 Page TS / B 3.4-41 2 Pages TS / 8 3.4-42 through TS / B 3.4-45 0 Page TS / B 3.4-46 1 Pages TS B 3.4-47 and TS / B 3.4-48 0 Page TS / B 3.4-49 3 Page TS / B 3.4-50 1 Page TS / B 3.4-51 3 Page TS / B 3.4-52 2 Page TS / B 3.4-53 1 Pages TS / B 3.4-54 through TS / B 3.4-56 2 Page TS / B 3.4-57 3 Pages TS / B 3.4-58 through TS / B 3.4-60 1 B 3.5 ECCS AND RCIC BASES Pages B 3.5-1 and B 3.5-2 0 Page TS / B 3.5-3 3 Page TS / B 3.5-4 1 Page TS / B 3.5-5 2 Page TS / B 3.5-6 1 Pages B 3.5-7 through B 3.5-10 0 Page TS / B 3.5-11 1 Page TS / B 3.5-12 0 Page TS / B 3.5-13 2 Pages TS / B 3.5-14 and TS / B 3.5-15 0 Page TS / B 3.5-16 1 Page TS / B 3.5-17 2 Page TS / B 3.5-18 1 Pages B 3.5-19 through B 3.5-24 0 Page TS / B 3.5-25 1 Page TS / B 3.5-26 and TS / B 3.5-27 2 Page TS / B 3.5-28 0 Page TS / B 3.5-29 1 Pages TS / B 3.5-30 and TS / B 3.5-31 0 B 3.6 CONTAINMENT SYSTEMS BASES Page TS / B 3.6-1 2 Page TS / B 3.6-1a 3 Page TS / B 3.6-2 4 Page TS / B 3.6-3 3 Page TS /B 3.6-4 4 Pages TS / B 3.6-5 and TS / B 3.6-6 3 SUSQUEHANNA

-UNIT 1 TS / B LOES-6 Revision 114 SUSQUEHANNA

-UNIT 1 TS / B LOES-6 Revision 114 SUSQUEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)Section Title Revision Page TS / B 3.6-6a 2 Page TS / B 3.6-6b 4 Page TS / B 3.6-6c 0 Page B 3.6-7 0 Page B 3.6-8 1 Pages B 3.6-9 through B 3.6-14 0 Page TS / B 3.6-15 3 Page TS / B 3.6-15a 0 Page TS / B 3.6-15b 2 Pages TS / B 3.6-16 and TS / B 3.6-17 2 Page TS / B 3.6-17a 1 Pages TS / B 3.6-18 and TS / B 3.6-19 0 Page T.S / B 3.6-20 1 Page TS / B 3.6-21 2 Page TS / B 3.6-22 1 Page TS / B 3.6-22a 0 Page TS / B 3.6-23 1 Pages TS / B 3.6-24 and TS / B 3.6-25 0 Pages TS / B 3.6-26 and TS / B 3.6-27 2 Page TS / B 3.6-28 7 Page TS / B 3.6-29 2 Page TS / B 3.6-30 1 Page TS / B 3.6-31 3 Pages TS / B 3.6-32 and TS / B 3.6-33 1 Pages TS / B 3.6-34 and TS / B 3.6-35 0 Page TS / B 3.6-36 1 Page TS / B 3.6-37 0 Page TS / B 3.6-38 3 Page TS / B 3.6-39 2 Page TS / B 3.6-40 6 Page TS / B 3.6-40a 0 Page B 3.6-41 1 Pages B 3.6-42 and B 3.6-43 3 Pages TS / B 3.6-44 and TS / B 3.6-45 1 Page TS / B 3.6-46 2 Pages TS / B 3.6-47 through TS / B 3.6-51 1 Page TS / B 3.6-52 2.Pages TS / B 3.6-53 through TS / B 3.6-56 0 Page TS / B 3.6-57 1 Page TS / 3.6-58 2 Pages B 3.6-59 through B 3.6-63 0 Pages TS / B 3.6-64 and TS / B 3.6-65 1 Pages B 3.6-66 through B 3.6-69 0 SUSQUEHANNA

-UNIT 1 SUSQUEHANNA

-UNIT 1 TS/BLOES-7 Revision 114 TS / B LOES-7 Revision 114 SUSQUEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)Section Title Revision Pages TS / B 3.6-70 through TS / B 3.6-72 1 Page TS / B 3.6-73 2 Pages TS / B 3.6-74 and TS / B 3.6-75 1 Pages B 3.6-76 and B 3.6-77 0 Page TS / B 3.6-78 1 Pages B 3.6-79 and B 3.3.6-80 0 Page TS / B 3.6-81 1 Pages TS / B 3.6-82 and TS / B 3.6-83 0 Page TS / B 3.6-84 4 Page TS / B 3.6-85 2 Page TS / B 3.6-86 4 Pages TS / B 3.6-87 through TS / B 3.6-88a 2 Page TS / B 3.6-89 5 Page TS / B 3.6-90 3 Page TS / B 3.6-90a 0 Pages TS / B 3.6-91 and TS / B 3.6-92 3 Page TS / B 3.6-93 2 Pages TS / B 3.6-94 through TS / B 3.6-96 1 Page TS / B 3.6-97 2 Page TS / B 3.6-98 1 Page TS / B 3.6-99 2 Pages TS / B 3.6-100 and TS / B 3.6-100a 5 Page TS / B 3.6-100b 3 Pages TS / B 3.6-101 and TS / B 3.6-102 1 Pages TS / B 3.6-103 and TS / B 3.6-104 2 Page TS / B 3.6-105 3 Page TS / B 3.6-106 2 Page TS / B 3.6-107 3 B 3.7 PLANT SYSTEMS BASES Pages TS / B 3.7-1 3 Page TS / B 3.7-2 4 Pages TS / B 3.7-3 through TS / B 3.7-5 3 Page TS / B 3.7-5a 1 Page TS / B 3.7-6 3 Page TS / B 3.7-6a 2 Page TS / B 3.7-6b 1 Page TS / B 3.7-6c 2 Page TS / B 3.7-7 3 Page TS / B 3.7-8 2 Pages TS / B 3.7-9 through TS / B 3.7-11 1 Pages TS / B 3.7-12 and TS / B 3.7-13 2 Pages TS / B 3.7-14 through TS / B 3.7-18 3 SUSQUEHANNA

-UNIT 1 TSIBLOES-8 Revision 114 SUSQUEHANNA

-UNIT I TS / B LOES-8 Revision 114 SUSQUEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)Section Title Revision Page TS / B 3.7-18a 1 Pages TS / B 3.7-18b through TS / B 3.7-18e 0 Pages TS / B 3.7-19 through TS / B 3.7-23 1 Page TS / B 3.7-24 1 Pages TS / B 3.7-25 and TS / B 3.7-26 0 Pages TS / B 3.7-27 through TS / B 3.7-29 5 Page TS / B 3.7-30 2 Page TS / B 3.7-31 1 Page TS / B 3.7-32 0 Page TS / B 3.7-33 1 Pages TS / B 3.7-34 through TS / B 3.7-37 0 B 3.8 ELECTRICAL POWER SYSTEMS BASES Page TS / B 3.8-1 3 Pages TS / B 3.8-2 and TS / B 3.8-3 2 Page TS / B 3.8-4 3 Pages TS / B 3.8-4a and TS / B 3.8-4b 0 Page TS / B 3.8-5 5 Page TS / B 3.8-6 3 Pages TS / B 3.8-7 through TS/B 3.8-8 2 Page TS / B 3.8-9 4 Page TS / B 3.8-10 3 Pages TS / B 3.8-11 and TS / B 3.8-17 2 Page TS / B 3.8-18 3 Pages TS / B 3.8-19 through TS / B 3.8-21 2 Pages TS / B 3.8-22 and TS / B 3.8-23 3 Pages TS / B 3.8-24 through TS / B 3.8-30 2 Pages TS / B 3.8-31 and TS / B 3.8-32 3 Pages TS / B 3.8-33 through TS / B 3.8-37 2 Pages B 3.8-38 through B 3.8-44 0 Page TS / B 3.8-45 3 Pages TS / B 3.8-46 through TS / B 3.8-48 0 Pages TS / B 3.8-49 and TS / B 3.8-50 3 Page TS / B 3.8-51 1 Page TS / B 3.8-52 0 Page TS / B 3.8-53 1 Pages TS / B 3.8-54 through TS / B 3.8-57 2 Pages TS / B 3.8-58 through TS / B 3.8-61 3 Pages TS / B 3.8-62 and TS / B 3.8-63 5 Page TS / B 3.8-64 4 Page TS / B 3.8-65 5 Pages TS / B 3.8-66 through TS / B 3.8-77 1 Pages TS / B 3.8-77A through TS / B 3.8-77C 0 Pages B 3.8-78 through B 3.8-80 0 Page TS / B 3.8-81 1 Pages B 3.8-82 through B 3.8-90 0 SUSQUEHANNA

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-UNIT I TS/BLOES-9 Revision 114 TS / B LOES-9 Revision 114 SUSQUEHANNA STEAM ELECTRIC STATION LIST OF EFFECTIVE SECTIONS (TECHNICAL SPECIFICATIONS BASES)Section Title Revision B 3.9 REFUELING OPERATIONS BASES Pages TS / B 3.9-1 and TS / B 3.9-la 1 Pages TS / B 3.9-2 through TS / B 3.9-5 1 Pages TS / B 3.9-6 through TS / B 3.9-8 0 Pages B 3.9-9 through B 3.9-18 0 Pages TS / B 3.9-19 through TS / B 3.9-21 1 Pages B 3.9-22 through B 3.9-30 0 B 3.10 SPECIAL OPERATIONS BASES Page TS / B 3.10-1 2 Pages TS / B 3.10-2 through TS / B 3.10-5 1 Pages B 3.10-6 through B 3.10-31 0 Page TS / B 3.10-32 2 Page B 3.10-33 0 Page TS / B 3.10-34 1 Pages B 3.10-35 and B 3.10-36 0 Page TS / B 3.10-37 1 Page TS / B 3.10-38 2 TSB1 Text LOES.doc 2/21/14 SUSQUEHANNA

-UNIT 1 TS / B LOES-1 0 Revision 114 PPL Rev. 3 Rod Pattern Control B 3.1.6 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.6 Rod Pattern Control BASES BACKGROUND Control rod patterns during startup conditions are controlled by the operator and the rod worth minimizer (RWM) (LCO 3.3.2.1, "Control Rod Block Instrumentation"), so that only specified control rod sequences and relative positions are allowed over the operating range of all control rods inserted to 10% RTP. The sequences limit the potential amount of reactivity addition that could occur in the event of a Control Rod Drop Accident (CRDA).This Specification assures that the control rod patterns are consistent with the assumptions of the CRDA analyses of References 1 and 2.APPLICABLE SAFETY ANALYSES The analytical methods and assumptions used in evaluating the CRDA are summarized in References 1 and 2. CRDA analyses assume that the reactor operator follows prescribed withdrawal sequences.

These sequences define the potential initial conditions for the CRDA analysis.The RWM (LCO 3.3.2.1) provides backup to operator control of the withdrawal sequences to ensure that the initial conditions of the CRDA analysis are not vi6lated.Prevention or mitigation of positive reactivity insertion events is necessary to limit the energy deposition in the fuel, thereby preventing significant fuel damage which could result in the undue release of radioactivity.

Since the failure consequences for U0 2 have been shown to be insignificant below fuel energy depositions of 300 cal/gm (Ref. 3), the fuel damage limit of 280 cal/gm provides a margin of safety from significant core damage which would result in release of radioactivity (Refs. 4 and 5). Generic evaluations (Ref. 1 & 6) of a design basis CRDA have shown that the maximum reactor pressure will be less than the required ASME Code limits (Ref.7). The offsite doses are calculated each cycle using the.methodology in reference 1 to demonstrate that the calculated offsite doses will be well within the required limits (Ref. 5). Control rod patterns analyzed in Reference 1 follow the banked position withdrawal sequence (BPWS). The BPWS is applicable from the condition of all control rods fully inserted to 10% RTP (Ref. 2). For the BPWS, the control rods are required to be moved in groups, with all control rods assigned to a specific group required to be within specified banked positions (continued)

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-UNIT 1 TS / B 3.1-34 Revision I PPL Rev. 3 Rod Pattern Control B 3.1.6 BASES APPLICABLE SAFETY ANALYSES (continued)(e.g., between notches 08 and 12). The banked positions are established to minimize the maximum incremental control rod worth without being overly restrictive during normal plant operation.

For each reload cycle the CRDA is analyzed to demonstrate that the 280 cal/gm fuel damage limit will not be violated during a CRDA while following the BPWS mode of operation for control rod patterns.

These analyses consider the effects of fully inserted inoperable and OPERABLE control rods not withdrawn in the normal sequence of BPWS, but are still in compliance with the BPWS requirements regarding out of sequence control rods. These requirements allow a limited number (i.e., eight) and distribution of fully inserted inoperable control rods.When performing a shutdown of the plant, an optional BPWS control rod sequence (Ref. 9) may be used provided that all withdrawn control rods have been confirmed to be coupled prior to reaching THERMAL POWER of 10% RTP. The rods may be inserted without the need to stop at intermediate positions since the possibility of a CRDA is eliminated by the confirmation that withdrawn control rods are coupled. When using the Reference 9 control rod sequence for shutdown, the RWM may be reprogrammed to enforce the requirements of the improved BPWS control rod insertion, or may be bypassed and the improved BPWS shutdown sequence implemented under LCO 3.3.2.1, Condition D controls.In order to use the Reference 9 BPWS shutdown process, an extra check is required in order to consider a control rod to be "confirmed" to be coupled. This extra check ensures that no Single Operator Error can result in an incorrect coupling check. For purposes of this shutdown process, the method for confirming that control rods are coupled varies depending on the position of the control rod in the core. Details on this coupling confirmation requirement are provided in Reference 9, which requires that any partially inserted control rods, which have not been confirmed to be coupled since their last withdrawal, be fully inserted prior to reaching THERMAL POWER of 10% RTP. If a control rod has been checked for coupling at notch 48 and the rod has since only been moved inward, this rod is in contact with it's drive and is not required to be fully inserted prior to reaching THERMAL POWER of 10% RTP. However, if it cannot be confirmed that the control rod has been moved inward, then that rod shall be fully inserted prior to reaching the THERMAL POWER of<10% RTP. This extra check may be performed as an administrative check, by examining logs, previous (continued)

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-UNIT 1 TS / B 3.1-35 Revision 1 PPL Rev. 3 Rod Pattern Control B 3.1.6 BASES APPLICABLE surveillance's or other information.

If the requirements for use of the SAFETY BPWS control rod insertion process contained in Reference 9 are ANALYSES followed, the plant is considered to be in compliance-with the BPWS (continued) requirements, as required by LOC 3.1.6.Rod pattern control satisfies Criterion 3 of the NRC Policy Statement (Ref. 8).LCO Compliance with the prescribed control rod sequences minimizes the potential consequences of a CRDA by limiting the initial conditions to those consistent with the BPWS. This LCO only applies to OPERABLE control rods. For inoperable control rods required to be inserted, separate requirements are specified in LCO 3.1.3, "Control Rod OPERABILITY," consistent with the allowances for inoperable control rods in the BPWS.APPLICABILITY In MODES 1 and 2, when THERMAL POWER is < 10% RTP, the CRDA is'a Design Basis Accident and, therefore, compliance with the assumptions of the safety analysis is required.

When THERMAL POWER is> 10% RTP, there is no credible control rod configuration that results in a control rod worth that could exceed the 280 cal/gm fuel damage limit during a CRDA (Ref. 2). In MODES 3, 4, and 5, since the reactor is shut down and only a single control rod can be withdrawn from a core cell containing fuel assemblies, adequate SDM ensures that the consequences of a CRDA are acceptable, since the reactor will remain subcritical with a single control rod withdrawn.

ACTIONS A.1 and A.2 With one or more OPERABLE control rods not in compliance with the prescribed control rod sequence, actions may be taken to either correct the control rod pattern or declare the associated control rods inoperable within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. Noncompliance with the prescribed sequence may be the result of "double notching," drifting from a control rod drive cooling water transient, leaking scram valves, or a power reduction to < 10% RTP before establishing the correct control rod pattern. The number of OPERABLE control rods not in compliance with the prescribed sequence is limited to eight, to prevent the operator from attempting to correct a control rod pattern that significantly deviates from the prescribed sequence.

When the control (continued)

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-UNIT 1 TS / B 3.1-36 Revision 1 PPL Rev. 3 Rod Pattern Control B 3.1.6 BASES ACTIONS A.1 and A.2 (continued) rod pattern is not in compliance with the prescribed sequence, all control rod movement should be stopped except for moves needed to correct the rod pattern, or scram if warranted.

Required Action A.1 is modified by a Note which allows the RWM to be bypassed to allow the affected control rods to be returned to their correct position.

LCO 3.3.2.1 requires verification of control rod movement by a qualified member of the technical staff. This ensures that the control rods will be moved to the correct position.

A control rod not in compliance with the prescribed sequence is not considered inoperable except as required by Required Action A.2. OPERABILITY of control rods is determined by compliance with LCO 3.1.3, "Control Rod OPERABILITY," LCO 3.1.4,"Control Rod Scram Times," and LCO 3.1.5, "Control Rod Scram Accumulators." The allowed Completion Time of 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> is reasonable, considering the restrictions on the number of allowed out of sequence control rods and the low probability of a CRDA occurring durihg the time the control rods are out of sequence.B.1 and B.2 If nine or more OPERABLE control rods are out of sequence, the control rod pattern significantly deviates from the prescribed sequence.

Control rod withdrawal should be suspended immediately to prevent the potential for further deviation from the prescribed sequence.

Control rod insertion to correct control rods withdrawn beyond their allowed position is allowed since, in general, insertion of control rods has less impact on control rod worth than withdrawals have. Required Action B.1 is modified by a Note which allows the RWM to be bypassed to allow the affected control rods to be returned to their correct position.

LCO 3.3.2.1 requires verification of control rod movement by a qualified member of the technical staff.When nine or more OPERABLE control rods are not in compliance with BPWS, the reactor mode switch must be placed in the shutdown position within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. With the mode switch in shutdown, the reactor is shut down, and as such, does not meet the applicability requirements of this LCO. The allowed Completion Time of 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> is reasonable to allow insertion of control rods to restore compliance, and is appropriate relative to the low probability (continued)

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-UNIT 1 TS I B 3.1-37 Revision 2 PPL Rev. 3 Rod Pattern Control B 3.1.6 BASES ACTIONS B.1 and B.2 (continued) of a CRDA occurring with the control rods out of sequence.SURVEILLANCE SR 3.1.6.1 REQUIREMENTS The control rod pattern is verified to be in compliance with the BPWS at a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency to ensure the assumptions of the CRDA analyses are met. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency was developed considering that the primary check on compliance with the BPWS is performed by the RWM (LCO 3.3.2.1), which provides control rod blocks to enforce the required sequence and is required to be OPERABLE when operating at<10% RTP.REFERENCES

1. XN-NF-80-19(P)(A)

Volume 1 and Supplements 1 and 2, "Exxon Nuclear Methodology for Boiling Water Reactors," Exxon Nuclear Company, March 1983.2. "Modifications to the Requirements for Control Rod Drop Accident Mitigating System," BWR Owners Group, July 1986.3. NUREG-0979, Section 4.2.1.3.2, April 1983.4. NUREG-0800, Section 15.4.9, Revision 2, July 1981.5. 10 CFR 100.11.6. NEDO-21778-A, "Transient Pressure Rises Affected Fracture Toughness Requirements for Boiling Water Reactors," December 1978.7. ASME, Boiler and Pressure Vessel Code.8. Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 39132).9. NEDO 33091-A, Revision 2, "Improved BPWS Control Rod Insertion Process," July 2004.SUSQUEHANNA

-UNIT 1 TS / B 3.1-38 Revision 3 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 B 3.3 INSTRUMENTATION B 3.3.1,1 Reactor Protection System (RPS) Instrumentation BASES BACKGROUND The RPS initiates a reactor scram when one or more monitored parameters exceed their specified limits, to preserve the integrity of the fuel cladding and the Reactor Coolant System (RCS) and minimize the energy that must be absorbed following a loss of coolant accident (LOCA).This can be accomplished either automatically or manually.The protection and monitoring functions of the RPS have been designed to ensure safe operation of the reactor. This is achieved by specifying limiting safety system settings (LSSS) in terms of parameters directly monitored by the RPS, as well as LCOs on- other reactor system parameters and equipment performance, The LSSS are defined in this Specification as the Allowable Values, which, in conjunction with the LCOs, establish the threshold for protective system action to prevent exceeding acceptable limits, including Safety Limits (SLs) during Design Basis Accidents (DBAs).The RPS, as shown in the FSAR, Figure 7.2-1 (Ref. 1), includes sensors, relays, bypass circuits, and switches that are necessary to cause initiation of a reactor scram. Functional diversity is provided by monitoring a wide range of dependent and independent parameters.

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

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-UNIT 1 TS / B 3.3-1 Revision 1 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES BACKGROUND (continued) channels Al and A2, B1 and 82) as shown in Reference

1. The outputs of the logic channels in a trip system are combined in a one-out-of-two logic so that either channel can trip the associated trip system. The tripping of both trip systems will produce a reactor scram. This logic arrangement is referred to as a one-out-of-two taken twice logic. Each trip system can be reset by use of a reset switch. If a full scram occurs (both trip systems trip), a relay prevents reset of the trip systems for 10 seconds after the full scram signal is received.

This 10 second delay on reset ensures that the scram function will be completed.

Two AC powered scram pilot solenoids are located in the hydraulic control unit for each control rod drive (CRD). Each scram pilot valve is operated with the solenoids normally energized.

The scram pilot valves control the air supply to the scram inlet and outlet valves for the associated CRD.When either scram pilot valve solenoid is energized, air pressure holds the scram valves closed and, therefore, both scram pilot valve solenoids must be de-energized to cause a control rod to scram. The scram valves control the supply and discharge paths for the CRD water during a scram.One of the scram pilot valve solenoids for each CRD is controlled by trip system A, andthe other solenoid is controlled by trip system B. Any trip of trip system A in conjunction with any trip in trip system B results in de-energizing both solenoids, air bleeding off, scram valves opening, and control rod scram.The DC powered backup scram valves, which energize on a scram signal to depressurize the scram air header, are also controlled by the RPS.Additionally, the RPS System controls the SDV vent and drain valves such that when both trip systems trip, the SDV vent and drain valves close to isolate the SDV.APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY The actions of the RPS are assumed in the safety analyses of References 3, 4, 5 and 6. The RPS initiates a reactor scram before the monitored parameter values reach the Allowable Values, specified by the setpoint methodology and listed in Table 3.3.1.1-1 to preserve the integrity of the fuel cladding, the reactor coolant pressure boundary (RCPB), and (continued)

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-UNIT 1 TS / B 3.3-2 Revision 1 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE the containment by minimizing the energy that must be absorbed following SAFETY a LOCA.ANALYSES, LCO, and RPS instrumentation satisfies Criterion 3 of the NRC Policy Statement.

APPLICABILITY (Ref. 2)(continued)

Functions not specifically credited in the accident analysis are retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis.The OPERABILITY of the RPS is dependent on the OPERABILITY of the individual instrumentation channel Functions specified in Table 3.3.1.1-1.

Each Function must have a required number of OPERABLE channels per RPS trip system, with their setpoints within the specified Allowable Value, where appropriate.

The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions.

Each channel must also respond within its assumed response time.Allowable Values are specified for each RPS Function specified in the Table. Nominal trip setpoints are specified in the setpoint calculations.

The nominal setpoints are selected to ensure that the actual setpoints do not exceed the Allowable Value between successive CHANNEL CALIBRATIONS.

Operation with a trip setpoint less conservative than the nominal trip setpoint, but within its Allowable Value, is acceptable.

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

The Allowable Values are derived from the analytic limits, corrected for calibration, process, and some of the instrument errors. The trip setpoints are then determined accounting for the remaining instrument errors (e.g., drift). The trip setpoints derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, (continued)

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-UNIT 1 TS / B 3.3-3 Revision 1 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE instrument drift and severe environment errors (for channels that must, SAFETY function in harsh environments as defined by 10 CFR 50.49) are ANALYSES, accounted for.LCO, and APPLICABILITY The OPERABILITY of scram pilot valves and associated solenoids, (continued) backup scram valves, and SDV valves, described in the Background section, are not addressed by this LCO.The individual Functions are required to be OPERABLE in the MODES specified in the table, which may require an RPS trip to mitigate the consequences of a design basis accident or transient.

To ensure a reliable scram function, a combination of Functions are required in each MODE to provide primary and diverse initiation signals.The RPS is required to be OPERABLE in MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies.

Control rods withdrawn from a core cell containing no fuel assemblies do not affect the reactivity of the core and, therefore, are not required to have the capability to scram. Provided all other control rods remain inserted, the RPS function is not required.

In this condition, the required SDM (LCO 3.1.1) and refuel position one-rod-out interlock (LCO 3.9.2) ensure that no event requiring RPS will occur. During normal operation in MODES 3 and 4, all control rods are fully inserted and the Reactor Mode Switch Shutdown Position control rod withdrawal block (LCO 3.3.2.1) does not allow any control rod to be withdrawn.

Under these conditions, the RPS function is not required to be OPERABLE.

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

The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis.Intermediate Range Monitor (IRM)1.a. Intermediate Range Monitor Neutron Flux-High The IRMs monitor neutron flux levels from the upper range of the source range monitor (SRM) to the lower range of the average power range monitors (APRMs). The IRMs are capable of generating trip signals that can be used to prevent fuel (continued)

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-UNIT 1 TS / B 3.3-4 Revision 1 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY l.a. Intermediate Range Monitor Neutron Flux-High (continued) damage resulting from abnormal operating transients in the intermediate power range. In this power range, the most significant source of reactivity change is due to control rod withdrawal.

The IRM provides diverse protection for the rod worth minimizer (RWM), which monitors and controls the movement of control rods at low power. The RWM prevents the withdrawal of an out of sequence control rod during startup that could result in an unacceptable neutron flux excursion (Ref. 5). The IRM provides mitigation of the neutron flux excursion.

To demonstrate the capability of the IRM System to mitigate control rod withdrawal events, generic analyses have been performed (Ref. 3) to evaluate the consequences of control rod withdrawal events during startup that are mitigated only by the IRM. This analysis, which assumes that one IRM channel in each trip system is bypassed, demonstrates that the IRMs provide protection against local control rod withdrawal errors and results in peak fuel energy depositions below the 170 cal/gm fuel failure threshold criterion.

The IRMs are also capable of limiting other reactivity excursions during startup, such as cold water injection events, although no credit is specifically assumed.The IRM System is divided into two trip systems, with four IRM channels inputting to each trip system. The analysis of Reference 3 assumes that one channel in each trip system is bypassed.

Therefore, six channels with three channels in each trip system are required for IRM OPERABILITY to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. This trip is active in each of the 10 ranges of the IRM, which must be selected by the operator to maintain the neutron flux within the monitored level of an IRM range.The analysis of Reference 3 has adequate conservatism to permit an IRM Allowable Value of 122 divisions of a 125 division scale..The Intermediate Range Monitor Neutron Flux-High Function must be OPERABLE during MODE 2 when control rods may be withdrawn and the potential for criticality exists. In (continued)

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-UNIT 1 TS / B 3.3-5 Revision 2 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY 1.a. Intermediate Rangie Monitor Neutron Flux-Higqh (continued)

MODE 5, when a cell with fuel has its control rod withdrawn, the IRMs provide monitoring for and protection against unexpected reactivity excursions.

In MODE 1, the APRM System and the RWM provide protection against control rod withdrawal error events and the IRMs are not required.

In addition, the Function is automatically bypassed when the Reactor Mode Switch is in the Run position.1.b. Intermediate Ranae Monitor-InoD This trip signal provides assurance that a minimum number of IRMs are OPERABLE.

Anytime an IRM mode switch is moved to any position other than "Operate," the detector voltage drops below a preset level, or when a module is not plugged in, an inoperative trip signal will be received by the RPS unless the IRM is bypassed.

Since only one IRM in each trip system may be bypassed, only one IRM in each RPS trip system may be inoperable without resulting in an RPS trip signal.This Function was not specifically credited in the accident analysis but it is retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis.Six channels of Intermediate Range Monitor-Inop with three channels in each trip system are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal.Since this Function is not assumed in the safety analysis, there is no Allowable Value for this Function.This Function is required to be OPERABLE when the Intermediate Range Monitor Neutron Flux-High Function is required.(continued)

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-UNIT 1 TS / B 3.3-6 Revision 1 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

Average Power Range Monitor (APRM)The APRM channels provide the primary indication of neutron flux within the core and respond almost instantaneously to neutron flux increases.

The APRM channels receive input signals from the local power range monitors (LPRMs) within the reactor core to provide an indication of the power distribution and local power changes. The APRM channels average these LPRM signals to provide a continuous indication of average reactor power from a few percent to greater than RTP. Each APRM channel also includes an Oscillation Power Range Monitor (OPRM) Upscale Function which monitors small groups of LPRM signals to detect thermal-hydraulic instabilities.

The APRM trip System is divided into four APRM channels and four 2-out-of-4 Voter channels.

Each APRM channel provides inputs to each of the four voter channels.

The four voter channels are divided into two groups of two each with each group of two providing inputs to one RPS trip system. The system is designed to allow one APRM channel, but no voter channels, to be bypassed.

A trip from any one unbypassed APRM will result in a "half-trip" in all four of the voter channels, but no trip inputs to either RPS trip system.APRM trip Functions 2.a, 2.b, 2.c, and 2.d are voted independently from OPRM Trip Function 2.f. Therefore, any Function 2.a, 2.b, 2.c, or 2.d trip from any two unbypassed APRM channels will result in a full trip in each of the four voter channels, which in turn results in two trip inputs into each RPS trip system logic channel (Al, A2, B1, and 82), thus resulting in a full scram signal. Similarly, a Function 2.f trip from any two unbypassed APRM channels will result in a full trip from each of the four voter channels.Three of the four APRM channels and all four of the voter channels are required to be OPERABLE to ensure that no single failure will preclude a scram on a valid signal. In addition, to provide adequate coverage of the entire core consistent with the design bases for the APRM Functions 2.a, 2.b, and 2.c, at least [20] LPRM inputs with at least three LPRM inputs from each of the fouraxial levels at which the LPRMs are located must be OPERABLE for each APRM channel, with no more than [9], LPRM detectors declared inoperable since the most recent APRM gain calibration.

Per Reference 23, the minimum input requirement for an APRM channel with 43 LPRM inputs is determined given that the total number of LPRM outputs used as-inputs to an APRM channel that may be bypassed shall not exceed twenty-three (23). Hence, (20) LPRM inputs (continued)

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-UNIT 1 TS / B 3.3-7 Revision 3 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY Average Power Range Monitor (APRM) (continued) needed to be operable.

For the OPRM Trip Function 2.f, each LPRM in an APRM channel is further associated in a pattern of OPRM "cells," as described in .References 17 and 18. Each OPRM cell is capable of producing a channel trip signal.2.a. Average Power Range Monitor Neutron Flux-Hiqh (Setdown)For operation at low power (i.e., MODE 2), the Average Power Range Monitor Neutron Flux-High (Setdown)

Function is capable of generating a trip signal that prevents fuel damage resulting from abnormal operating transients in this power range. For most operation at low power levels, the Average Power Range Monitor Neutron Flux-High (Setdown)

Function will provide a secondary scram to the Intermediate Range Monitor Neutron Flux-High Function because of the relative setpoints.

With the IRMs at Range 9 or 10, it is possible that the Average Power Range Monitor Neutron Flux- High (Setdown)

Function will provide the primary trip signal for a corewide increase in power.The Average Power Range Monitor Neutron Flux -High (Setdown)Function together with the IRM -High Function provide mitigation for the control rod withdrawal event during startup (Section 15.4.1 of Ref. 5).Also, the Function indirectly ensures that before the reactor mode switch is placed in the run position, reactor power does not exceed 23% RTP (SL 2.1.1.1) when operating at low reactor pressure and low core flow.Therefore, it indirectly prevents fuel damage during significant reactivity increases with THERMAL POWER <-23% RTP.(continued)

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-UNIT 1 TS / B 3.3-7a Revision 1 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 2.a. Average Power Range Monitor Neutron Flux-Hi-gh (Setdown)SAFETY (continued)

ANALYSES, LCO, and The Allowable Value is based on preventing significant increases in power APPLICABILITY when THERMAL POWER is< 23% RTP.The Average Power Range Monitor Neutron Flux -High (Setdown)

Function must be OPERABLE during MODE 2 when control rods may be withdrawn since the potential for criticality exists. In MODE 1, the Average Power Range Monitor Neutron Flux -High Function provides protection against reactivity transients and the RWM protects against control rod withdrawal error events.There are provisions in the design of the NUMAC PRNM that given certain circumstances, such as loss of one division of RPS power, an individual APRM will default to a 'run' mode condition logic. If the plant is in mode 2 when this occurs, the individual APRM will be in a condition where the 'run'mode setpoint (Function 2.c) and not the 'setdown' setpoint (Function 2.a)will be applied. If this condition occurs while in reactor mode 2 condition, the appropriate LCO condition per Table 3.3.1.1-1 needs to be entered.2.b. Average Power Range Monitor Simulated Thermal Power -High The Average Power Range Monitor Simulated Thermal Power -High Function monitors neutron flux to approximate the THERMAL POWER being transferred to the reactor coolant. The APRM neutron flux is electronically filtered with a time constant representative of thefuel heat transfer dynamics to generate a signal proportional to the THERMAL POWER in the reactor. The trip level is varied as a function of recirculation drive flow (i.e., at lower core flows, the setpoint is reduced proportional to the reduction in power experienced as core flow is reduced with a fixed control rod pattern) but is clamped at an upper limit that is always lower than the Average Power Range Monitor Neutron Flux -High Function Allowable Value. The Average Power Range Monitor Simulated Thermal Power -High Function is not credited in any plant Safety Analyses.

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

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-UNIT 1 TS / B 3.3-8 Revision 5 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 2.b. Average Power Range Monitor Simulated Thermal Power -High SAFETY (continued)

ANALYSES, LCO, and Power Range Monitor Simulated Thermal Power -High Function setpoint APPLICABILITY is exceeded.The Average Power Range Monitor Simulated Thermal Power -High Function uses a trip level generated based on recirculation loop drive flow (W) representative of total core flow. Each APRM channel uses one total;recirculation drive flow signal. The total recirculation drive flow signal is generated by the flow processing logic, part of the APRM channel, by summing the flow calculated from two flow transmitter signal inputs, one from each of the two recirculation drive flow loops. The flow processing logic OPERABILITY is part of the APRM channel OPERABILITY requirements for this Function.The adequacy of drive flow as a representation of core flow is ensured through drive flow alignment, accomplished by SR 3.3.1.1.20.

A note is included, applicable when the plant is in single recirculation loop operation per LCO 3.4.1, which requires reducing by AW the recirculation flow value used in the APRM Simulated Thermal Power -High Allowable Value equation.

The Average Power Range Monitor, Scram Function varies as a function of recirculation loop drive flow (W). AW is defined as the difference in indicated drive flow (in percent of drive flow, which produces rated core flow) between two-loop and single-loop operation at the same core flow. The value of AW'is established to conservatively bound the inaccuracy created in the core flow/drive flow correlation due to back flow in the jet pumps associated with the inactive recirculation loop.(This adjusted Allowable'Value thus maintains thermal margins essentially unchanged from those for two-loop operation.(continued)

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-UNIT 1 TS / B 3.3-9 Revision 3 -

PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY 2.b. Average Power Range Monitor Simulated Thermal Power- Hiqh (continued)

The THERMAL POWER time constant of < 7 seconds is based on the fuel heat transfer dynamics and provides a signal proportional to the THERMAL POWER. The simulated thermal time constant is part of filtering logic in the APRM that simulates the relationship between neutron flux and core thermal power.The Average Power Range Monitor Simulated Thermal Power -High Function is required to be OPERABLE in MODE 1 when there is the possibility of generating excessive THERMAL POWER and potentially exceeding the SL applicable to high pressure and core flow conditions (MCPR SL). During MODES 2 and 5, other IRM and APRM Functions provide protection for fuel cladding integrity.

2.c. Average Power Range Monitor Neutron Flux -High The Average Power Range Monitor Neutron Flux -High Function is capable of generating a trip signal to prevent fuel damage or excessive RCS pressure.

For the overpressurization protection analysis of Reference 4, the Average Power Range Monitor Neutron Flux-High Function is assumed to terminate the main steam isolation valve (MSIV)closure event and, along with the safety/relief valves (S/RVs), limit the peak reactor pressure vessel (RPV) pressure to less than the ASME Code limits. The control rod drop accident (CRDA) analysis (Ref. 5) takes credit for the Average Power Range Monitor Neutron Flux -High Function to terminate the CRDA.(continued)

SUSQUEHANNA-UNIT 1 TS / B 3.3-10 Revision 3 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 2.c. Average Power Range Monitor Neutron Flux -High (continued)

SAFETY ANALYSES, The CRDA analysis assumes that reactor scram occurs on Average Power LCO, and Range Monitor Neutron Flux -High Function.APPLICABILITY The Average Power Range Monitor Neutron Flux -High Function is required to be OPERABLE in MODE 1 where the potential consequences of the analyzed transients could result in the SLs (e.g., MCPR and RCS pressure) being exceeded.

Although the Average Power Range Monitor Neutron Flux -High Function is assumed in the CRDA analysis, which is applicable in MODE 2, the Average Power Range Monitor Neutron Flux -High (Setdown)

Function conservatively bounds the' assumed trip and, together with the assumed IRM trips, provides adequate protection.

Therefore, the Average Power Range Monitor Neutron Flux -High Function is not required in MODE 2.2.d. Average Power Range Monitor -Inop Three of the four APRM channels are required to be OPERABLE for each of the APRM Functions.

This Function (Inop) provides assurance that the minimum number of APRM clhannels are OPERABLE.For any APRM channel, any time its mode switch is not in the "Operate" position, an APRM module required to issue a trip is unplugged, or the automatic self-test system detects a critical fault with the APRM channel, an Inop trip is sent to all four voter channels.

Inop trips from two or more unbypassed APRM channels result in a trip output from each of the four voter channels to its associated trip system.This Function was not specifiQally credited in the accident analysis, but it is retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis.(continued)

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-UNIT 1 TS / B 3.3-11 Revision 3 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 2.d. Average Power Range Monitor-Inop (continued)

SAFETY ANALYSES, There is no Allowable Value for this Function.LCO, and APPLICABILITY This Function is required to be OPERABLE in the MODES where the APRM Functions are required.2.e. 2-out-of-4 Voter The 2-out-of-4 Voter Function provides the interface between the APRM Functions, including the OPRM Trip Function, and the final RPS trip system logic. As such, it is required to be OPERABLE in the MODES where the APRM Functions are required and is necessary to support the safety analysis applicable to each of those Functions.

Therefore, the 2-out-of-4 Voter Function is required to be OPERABLE in MODES 1 and 2.All four voter channels are required to be OPERABLE.

Each voter channel includes self-diagnostic functions.

If any voter channel detects a critical fault in its own processing, a trip is issued from that voter channel to the associated RPS trip system.The Two-out-of-Four Logic Module includes both the 2-out-of-4 Voter hardware and the APRM Interface hardware.

The 2-out-of-4 Voter Function 2.e votes APRM Functions 2.a, 2.b, 2.c, and 2.d independently of Function 2.f. This voting is accomplished by the 2-out-of-4 Voter hardware in the Two-out-of-Four Logic Module. The voter includes separate outputs to RPS for the two independently voted sets of Functions, each of which is redundant (four total outputs).

The analysis in Reference 15 took credit for this redundancy in the justification of the 12-hour Completion Time for Condition A, so the voter Function 2.e must be declared inoperable if any of its functionality is inoperable.

The voter Function 2.e does not needto be declared inoperable due to any failure affecting only the APRM Interface hardware portion of the Two-out-of-Four Logic Module.There is no Allowable Value for this Function.2.f. Oscillation Power Range Monitor (OPRM) Trip The OPRM Trip Function provides compliance with GDC 10, "Reactor Design," and GDC 12, "Suppression of Reactor Power Oscillations" thereby providing protection from exceeding the fuel MCPR safety limit (SL) due to anticipated thermal-hydraulic power oscillations.(continued)

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-UNIT 1 TS / B 3.3-12 Revision 3 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY 2.f. Oscillation Power Range Monitor (OPRM) Trip (continued)

References 17, 18 and 19 describe three algorithms for detecting thermal-hydraulic instability related neutron flux oscillations:

the period~based detection algorithm (confirmation count and cell amplitude), the amplitude based algorithm, and the growth rate algorithm.

All three are implemented in the OPRM Trip Function, but the safety analysis takes credit only for the period based detection algorithm.

The remaining algorithms provide defense in depth and additional protection against unanticipated oscillations.

OPRM Trip Function OPERABILITY for Technical Specification purposes is based only on the period based detection algorithm.

The OPRM Trip Function receives input signals from the local power range monitors (LPRMs) within the reactor core, which are combined into "cells" for evaluation by the OPRM algorithms.

Each channel is capable of detecting thermal-hydraulic instabilities, by detecting the related neutron flux oscillations, and issuing a trip signal before the MCPR SL is exceeded.

Three of the four channels are required to be OPERABLE.The OPRM Trip is automatically enabled (bypass removed) when THERMAL POWER is >_ 25% RTP, as indicated by the APRM Simulated Thermal Power, and reactor core flow is < the value defined in the COLR, as indicated by APRM measured recirculation drive flow. This is the operating region where actual thermal-hydraulic instability and related neutron flux oscillations are expected to occur. Reference 21 includes additional discussion of OPRM Trip enable region limits.These setpoints, which are sometimes referred to as the "auto-bypass" setpoints, establish the boundaries of the OPRM Trip enabled region. The APRM Simulated Thermal Power auto-enable setpoint has 1% deadband while the drive flow setpoint has a 2% deadband.

The deadband for these setpoints is established so that it increases the enabled region once the region is entered.The OPRM Trip Function is required to be OPERABLE when the plant is at 2! 23% RTP. The 23% RTP level is selected to provide margin in the unlikely event that a reactor power increase transient occurring without operator action while the plant is operating below 25% RTP causes a power increase to or beyond the 25% APRM Simulated Thermal Power OPRM Trip auto-enable setpoint.

This OPERABILITY requirement assures that the OPRM Trip auto-enable function will be OPERABLE when required.(continued)

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-UNIT 1 TS / B 3.3-12a Revision I PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 2.f. Oscillation Power Range Monitor (OPRM) Trip (continued)

SAFETY ANALYSES, An APRM channel is also required to have a minimum number of OPRM LCO, and cells OPERABLE for the Upscale Function 2.f to be OPERABLE.

The APPLICABILITY OPRM cell operability requirements are documented in the Technical Requirements Manual, TRO 3.3.9, and are established as necessary to support the trip setpoint calculations performed in accordance with methodologies in Reference 19.An OPRM Trip is issued from an APRM channel when the period based detection algorithm in that channel detects oscillatory changes in the neutron flux, indicated by the combined signals of the LPRM detectors in a cell, with period confirmations and relative cell amplitude exceeding specified setpoints.

One or more cells in a channel exceeding the trip conditions will result in a channel OPRM Trip from that channel. An OPRM Trip is also issued from the channel if either the growth rate or amplitude-based algorithms detect oscillatory changes in the neutron flux for one or more cells in that channel. (Note: To facilitate placing the OPRM Trip Function 2.f in one APRM channel in a "tripped" state, if necessary to satisfy a Required Action, the APRM equipment is conservatively designed to force an OPRM Trip output from the APRM channel if an APRM Inop condition occurs, such as when the APRM chassis keylock switch is placed in the Inop position.)

There are three "sets" of OPRM related setpoints or adjustment parameters:

a) OPRM Trip auto-enable region setpoints for STP and drive flow; b) period based detection algorithm (PBDA) confirmation count and amplitude setpoints; and c) period based detection algorithm tuning parameters.

The first set, the OPRM Trip auto-enable setpoints, as discussed in the SR 3.3.1.1.19 Bases, are treated as nominal setpoints with no additional margins added. The settings are defined in the Technical Requirements Manual, TRO 3.3.9, and confirmed by SR 3.3.1.1.19.

The second set, the OPRM PBDA trip setpoints, are established in accordance with methodologies defined in Reference 19, and are documented in the COLR. There are no allowable values for these setpoints.

The third set, the OPRM PBDA "tuning" parameters, are established or adjusted in accordance with and controlled by requirements in the Technical Requirements Manual, TRO 3.3.9.(continued)

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-UNIT 1 TS / B 3.3-12b Revision 0 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY 3.. Reactor Vessel Steam Dome Pressure-Hiqh An increase in the RPV pressure during reactor operation compresses the steam voids and results in a positive reactivity insertion.

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

The Reactor Vessel Steam Dome Pressure-High Allowable Value is chosen to provide a sufficient margin to the ASME Section III Code limits during the event.Four channels of Reactor Vessel Steam Dome Pressure-High Function, with two channels in each trip system arranged in a one-out-of-two logic, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. The Function is (continued)

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-UNIT 1 TS / B 3.3-12c Revision 0 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE

3. Reactor Vessel Steam Dome Pressure-Hiqh (continued)

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

4. Reactor Vessel Water Level-Low, Level 3 Low RPV water level indicates the capability to cool the fuel may be threatened.

Should RPV water level decrease too far, fuel damage could result. Therefore, a reactor scram is initiated at Level 3 to substantially reduce the heat generated in the fuel from fission. The Reactor Vessel Water Level-Low, Level 3 Function is assumed in the analysis of the recirculation line break (Ref. 6). The reactor scram reduces the amount of energy required to be absorbed and, along with the actions of the Emergency Core Cooling Systems (ECCS), ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.Reactor Vessel Water Level-Low, Level 3 signals are initiated from four level instruments that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel.Four channels of Reactor Vessel Water Level-Low, Level 3 Function, with two channels in each trip system arranged in a one-out-of-two logic, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal.The Reactor Vessel Water Level-Low, Level 3 Allowable Value is selected to ensure that during normal operation the separator skirts are not uncovered (this protects available recirculation pump net positive suction head (NPSH) from significant carryunder) and, for transients involving loss of all normal feedwater flow, initiation of the low pressure ECCS subsystems at Reactor Vessel Water-Low Low Low, Level 1 will not be required.The Function is required in MODES 1 and 2 where considerable energy exists in the RCS resulting in the limiting transients and accidents.

ECCS initiations at Reactor Vessel Water Level-Low Low, Level 2 and Low Low Low, (continued)

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-UNIT 1 TS / B 3.3-13 Revision 1 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE

4. Reactor Vessel Water Level-Low, Level 3 (continued)

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

5. Main Steam Isolation Valve-Closure MSIV closure results in loss of the main turbine and the condenser as a heat sink for the nuclear steam supply system and indicates a need to shut down the reactor to reduce heat generation.

Therefore, a reactor scram is initiated on a Main Steam Isolation Valve-Closure signal before the MSIVs are completely closed in anticipation of the complete loss of the normal heat sink and subsequent overpressurization transient.

However, for the overpressurization protection analysis of Reference 4, the Average Power Range Monitor Neutron Flux-High Function, along with the S/RVs, limits the peak RPV pressure to less than the ASME Code limits. That is, the direct scram on position switches for MSIV closure events is not assumed in the overpressurization analysis.

Additionally, MSIV closure is assumed in the transients analyzed in Reference 5 (e.g., low steam line pressure, manual closure of MSIVs, high steam line flow). The reactor scram reduces the amount of energy required to be absorbed and, along with the actions of the ECCS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.MSIV closure signals are initiated from position switches located on each of the eight MSIVs. Each MSIV has two position switches; one inputs to RPS trip system A while the other inputs to RPS trip system B. Thus, each RPS trip system receives an input from eight Main Steam Isolation Valve-Closure channels, each consisting of one position switch. The logic for the Main Steam Isolation Valve-Closure Function is arranged such that either the inboard or outboard valve on three or more of the main steam lines must close in order for a scram to occur.The Main Steam Isolation Valve-Closure Allowable Value is specified to ensure that a scram occurs prior to a significant reduction in steam flow, thereby reducing the severity of the subsequent pressure transient.(continued)

SUSQUEHANNA-UNIT 1 TS / B 3.3-14 Revision 3 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY

5. Main Steam Isolation Valve-Closure (continued)

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

In MODE 2, the heat generation rate is low enough so that the other diverse RPS functions provide sufficient protection.

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

The Allowable Value was selected to be as low as possible and indicative of a LOCA inside primary containment.

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

SUSQUEHANNA-UNIT 1 TS / B 3.3-15 Revision 1 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) 7.a, 7.b. Scram Discharge Volume Water Level -High The SDV receives the water displaced by the motion of the CRD pistons during a reactor scram. Should this volume fill to a point where there is insufficient volume to accept the displaced water, control rod insertion would be hindered.

Therefore, a reactor scram is initiated while the remaining free volume is still sufficient to accommodate the water from a full core scram. The two types of Scram Discharge Volume Water Level -High Functions are an input to the RPS logic. No credit is taken for a scram initiated from these Functions for any of the design basis accidents or transients analyzed in the FSAR. However, they are retained to ensure the scram function remains OPERABLE.SDV water level is measured by two diverse methods. The level in each of the two SDVs is measured by two float type level switches and two level transmitters with trip units for a total of eight level signals. The outputs of these devices are arranged so that there is a signal from a level switch and a level transmitter with trip unit to each RPS logic channel. The level measurement instrumentation satisfies the recommendations of Reference 8.The Allowable Value is chosen low enough to ensure that there is sufficient volume in the SDV to accommodate the water from a full scram.Four channels of each type of Scram Discharge Volume Water Level-High Function, with two channels of each type in each trip system, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from these Functions on a valid signal. These Functions are required in MODES 1 and 2, and in MODE 5 with any control rod Withdrawn from a core cell containing one or more fuel assemblies, since these are the MODES and other specified conditions when control rods are withdrawn.

At all other times, this Function may be bypassed.8. Turbine Stoo Valve-Closure Closure of the TSVs results in the loss of a heat sink that produces reactor pressure, neutron flux, and heat flux transients that must be limited.Therefore, a reactor scram is initiated at the start of TSV closure in anticipation of (continued)

SUSQUEHANNA-UNIT 1 TS / B 3.3-16 Revision 1 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY

8. Turbine Stop Valve-Closure (continued) the transients that would result from the closure of these valves. The Turbine Stop Valve-Closure Function is the primary scram signal for the turbine trip event analyzed in Reference

5. For this event, the reactor scram reduces the amount of energy required to be absorbed and, along with the actions of the End of Cycle Recirculation Pump Trip (EOC-RPT)System, ensures that the MCPR SL is not exceeded.

Turbine Stop Valve-Closure signals are initiated from position switches located on each of the four TSVs. Two independent position switches are associated with each stop valve. One of the two switches provides input to RPS trip system A;the other, to RPS trip system B. Thus, each RPS trip system receives an input from four Turbine Stop Valve-Closure channels, each consisting of one position switch. The logic for the Turbine Stop Valve -Closure Function is such that three or more TSVs must be closed to produce a scram. This Function must be enabled at THERMAL POWER> 26% RTP. This is accomplished automatically by pressure instruments sensing turbine first stage pressure.

Because an increase in the main turbine bypass flow can affect this function non-conservatively, THERMAL POWER is derived from first stage pressure.

The main turbine bypass valves must not cause the trip Function to be bypassed when THERMAL POWER is >_ 26% RTP.The Turbine Stop Valve-Closure Allowable Value is selected to be high enough to detect imminent TSV closure, thereby reducing the severity of the subsequent pressure transient.

Eight channels (arranged in pairs) of Turbine Stop Valve-Closure Function, with four channels in each trip system, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function if any three TSVs should close. This Function is required, consistent with analysis assumptions, whenever THERMAL POWER is> 26% RTP. This Function is not required when THERMAL POWER is < 26% RTP since the Reactor Vessel Steam Dome Pressure-High and the Average Power Range Monitor Neutron Flux-High Functions are adequate to maintain the necessary safety margins.(continued)

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-UNIT 1 TS / B 3.3-17 Revision 4 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

9. Turbine Control Valve Fast Closure, Trio Oil Pressure-Low Fast closure of the TCVs results in the loss of a heat sink that produces reactor pressure, neutron flux, and heat flux transients that must be limited. Therefore, a reactor scram- is initiated on TCV fast closure in anticipation of the transients that would result from the closure of these valves. The Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Function is the primary scram signal for the generator load rejection event analyzed in Reference

5. For this event, the reactor scram reduces the amount of energy required to be absorbed and, along with the actions of the EOC-RPT System, ensures that the MCPR SL is not exceeded.Turbine Control Valve Fast Closure, Trip Oil Pressure-Low signals are initiated by the electrohydraulic control (EHC) fluid pressure at each control valve. One pressure instrument is associated with each control valve, and the signal from each transmitter is assigned to a separate RPS logic channel. This Function must be enabled at THERMAL POWER_> 26% RTP. This is accomplished automatically by pressure instruments sensing turbine first stage pressure.

Because an increase in the main turbine bypass flow can affect this function non-conservatively, THERMAL POWER is derived from first stage pressure.

The main turbine bypass valves must not cause the trip Function to be bypassed when THERMAL POWER is _> 26% RTP.The Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Allowable Value is selected high enough to detect imminent TCV fast closure.Four channels of Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Function with two channels in each trip system arranged in a one-out-of-two logic are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. This Function is required, consistent with the analysis assumptions, whenever THERMAL POWER is >_ 26% RTP. This Function is not required when THERMAL POWER is < 26% RTP, since the Reactor Vessel Steam Dome Pressure-High and the Average Power Range Monitor Neutron Flux-High Functions are adequate to maintain the necessary safety margins.(continued)

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-UNIT 1 TS / B 3.3-18 Revision 4 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

10. Reactor Mode Switch-Shutdown Position The Reactor Mode Switch-Shutdown Position Function provides signals, via the manual scram logic channels, to each of the four RPS logic channels, which are redundant to the automatic protective instrumentation channels and provide manual reactor trip capability.

This Function was not specifically credited in the accident analysis, but it is retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis.The reactor mode switch is a single switch with four channels, each of which provides input into one of the RPS logic channels.There is no Allowable Value for this Function, since the channels are mechanically actuated based solely on reactor mode switch position.Four channels of Reactor Mode Switch-Shutdown Position.

Function, with two channels in each trip system, are available and required to be OPERABLE.

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

11. Manual Scram The Manual Scram push button channels provide signals, via the manual scram logic channels, to each of the four RPS logic channels, which are redundant to the automatic protective instrumentation channels and provide manual reactor trip capability.

This Function was not specifically credited in the accident analysis but it is retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis.There is one Manual Scram push button channel for each of the four RPS logic channels.

In order to cause a scram it is necessary that at least one channel in each trip system be actuated.(continued)

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-UNIT 1 TS / B 3.3-19 Revision 1 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE

11. Manual Scram (continued)

SAFETY ANALYSES, There is no Allowable Value for this Function since the channels are LCO, and mechanically actuated based solely on the position of the push buttons.APPLICABILITY Four channels of Manual Scram with two channels in each trip system arranged in a one-out-of-two logic are available and required to be OPERABLE in MODES 1 and 2, and in MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies, since these are the MODES and other specified conditions when control rods are withdrawn.

ACTIONS A Note has been provided to modify the ACTIONS related to RPS instrumentation channels.

Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition.

Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition.

However, the Required Actions for inoperable RPS instrumentation channels provide appropriate compensatory measures for separate inoperable channels.

As such, a Note has been provided that allows separate Condition entry for each inoperable RPS instrumentation channel.A.1 and A.2 Because of the diversity of sensors available to provide trip signals and the redundancy of the RPS design, an allowable out of service time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> has been shown to be acceptable (Refs. 9, 15 and 16) to permit restoration of any inoperable channel to OPERABLE status. However, this out of service time is only acceptable provided the associated Function's inoperable channel is in one trip system and the Function still maintains RPS trip capability (refer to Required Actions B. 1, B.2, and C. 1 Bases). If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel or the associated trip system must be placed in the tripped (continued)

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-UNIT 1 TS / B 3.3-20 Revision 2 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES ACTIONS A.1 and A.2 (continued) condition per Required Actions A.1 and A.2. Placing the inoperable channel in trip (or the associated trip system in trip) would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue.

Alternatively, if it is not desired to place the channel (or trip system) in trip (e.g., as in the case where placing the inoperable channel in trip would result in a full scram), Condition D must be entered and its Required Action taken.As noted, Action A.2 is not applicable for APRM Functions 2.a, 2.b, 2.c, 2.d, or 2.f. Inoperability of one required APRM channel affects both trip systems. For that condition, Required Action A.1 must be satisfied', and is the only action (other than restoring OPERABILITY) that will restore capability to accommodate a single failure. Inoperability of more than one required APRM channel of the same trip function results in loss of trip capability and entry into Condition C, as well as entry into Condition A for each channel.B.1 and B.2 Condition B exists when, for any one or more Functions, at least one required channel is inoperable in each trip system. In this condition, provided at least one channel per trip system is OPERABLE, the RPS still maintains trip capability for that Function, but cannot accommodate a single failure in either trip system.Required Actions B.1 and B.2 limit the time the RPS scram logic, for any Function, would not accommodate single failure in both trip systems (e.g., one-out-of-one and one-out-of-one arrangement for a typical four channel Function).

The reduced reliability of this logic arrangement was not evaluated in Reference 9, 15 or 16 for the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Completion Time.Within the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> allowance, the associated Function will have all required channels OPERABLE or in trip (or any combination) in one trip system.Completing one of these Required Actions restores RPS to a reliability level equivalent to that evaluated in Reference 9, 15 and 16, which justified a 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowable out of service time as presented in Condition A. The trip system in the more degraded state should be placed in trip or, alternatively, all the inoperable channels in that trip system should be placed in trip (e.g., a trip system with two inoperable channels could be in a more degraded state than a trip system with four inoperable channels if the two inoperable channels are in the same Function while the four inoperable channels are all in different Functions).

The decision of which trip system is in the more degraded state should be based on prudent judgment and take into account current plant conditions (i.e., what MODE the plant is in).(continued)

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-UNIT 1 TS / B 3.3-21 Revision 2 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES ACTIONS B.1 and B.2 (continued)

If this action would result in a scram, it is permissible to place the other trip system or its inoperable channels in trip.The 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> Completion Time is judged acceptable based on the remaining capability to trip, the diversity of the sensors available to provide the trip signals, the low probability of extensive numbers of inoperabilities affecting all diverse Functions, and the low probability of an event requiring the initiation of a scram.Alternately, if it is not desired to place the inoperable channels (or one trip system) in trip (e.g., as in the case where placing the inoperable channel or associated trip system in trip would result in a scram), Condition D must be entered and its Required Action taken.As noted, Condition B is not applicable for APRM Functions 2.a, 2.b, 2.c, 2.d, or 2.f. Inoperability of an APRM channel affects both trip systems and is not associated with a specific trip system as are the APRM 2-out-of-4 Voter (Function 2.e) and other non-APRM channels for which Condition B applies. For an inoperable APRM channel, Required Action A. 1 must be satisfied, and is the only action (other than restoring OPERABILITY) that will restore capability to accommodate a single failure. Inoperability of a Function in more than one required APRM channel results in loss of trip capability for that Function and entry into Condition C, as well as entry into Condition A for each channel. Because Conditions A and C provide Required Actions that are appropriate for the inoperability of APRM Functions 2.a, 2.b, 2.c, 2.d, or 2.f, and because these Functions are not associated with specific trip systems as are the APRM 2-out-of-4 Voter and other non-APRM channels, Condition B does not apply.C.1 Required Action C. 1 is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same trip system for the same Function result in the Function not maintaining RPS trip capability.

A Function is considered to be maintaining RPS trip capability when sufficient channels are OPERABLE or in trip (or the associated trip system is in trip), such that both trip systems will generate a trip signal from the given Function on a valid signal. For the typical Function with one-out-of-two taken twice logic, this would require both trip systems to have one channel OPERABLE or in trip (or the associated trip system in trip). For Function 5 (Main Steam (continued)

SUSQUEHANNA-UNIT 1 TS / B 3.3-22 Revision 2 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES ACTIONS C.1 (continued)

Isolation Valve-Closure), this would require both trip systems to have each channel associated with the MSIVs in three main steam lines-,(not necessarily the same main steam lines for both trip systems) OPERABLE or in trip (or the associated trip system in trip).For Function 8 (Turbine Stop Valve-Closure), this would require both trip systems to have three channels, each OPERABLE or in trip (or the associated trip system in trip).The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities.

The (continued)

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-UNIT 1 TS / B 3.3-22a Revision 0 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES ACTIONS C.1 (continued) 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Completion Time is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.D.1 Required Action D. 1 directs entry into the appropriate Condition referenced in Table 3.3.1.1-1.

The applicable Condition specified in the Table is Function and MODE or other specified condition dependent and may change as the Required Action of a previous Condition is completed.

Each time an inoperable channel has not met any Required Action of Condition A, B, or C and the associated Completion Time has expired, Condition D will be entered for that channel and provides for transfer to the appropriate subsequent Condition.

E.1, F.1, G.1, and J.1 If the channel(s) is not restored to OPERABLE status or placed in trip (or the associated trip system placed in trip) within the allowed Completion Time, the plant must be placed in a MODE or other specified condition in which the LCO does not apply. The allowed Completion Times are reasonable, based on operating experience, to reach the specified condition from full power conditions in an orderly manner and without challenging plant systems. In addition, the Completion Time of Required Actions E.1 and J.1 are consistent with the Completion Time provided in LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)." H.1 If the channel(s) is not restored to OPERABLE status or placed in trip (or the associated trip system placed in trip) within the allowed Completion Time, the plant must be placed in a MODE or other specified condition in which the LCO does not apply. This is done by immIediately initiating action to fully insert all insertable control rods in core cells containing one or more fuel assemblies.

Control rods in core cells containing no fuel assemblies do not affect (continued)

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-UNIT 1 TS / B 8.3-23 Revision 2 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES ACTIONS H.1 (continued) the reactivity of the core and are, therefore, not required to be inserted.Action must continue until all insertable control rods in core cells containing one or more fuel assemblies are fully inserted.1.1 and 1.2 Required Actions 1.1 and 1.2 are intended to ensure that appropriate actions are taken if more than two inoperable or bypassed OPRM channels result in not maintaining OPRM trip capability.

In the 4-OPRM channel configuration, any 'two' of the OPRM channels out of the total of four and one 2-out-of-4 voter channels in each RPS trip system are required to function for the OPRM safety trip function to be accomplished.

Therefore, three OPRM channels assures at least two OPRM channels can provide trip inputs to the 2-out-of-4 voter channels even in the event of a single OPRM channel failure, and the minimum of two 2-out-of-4 voter channels per RPS trip system assures at least one voter channel will be operable per RPS trip system even in the event of a single voter channel failure.References 15 and 16 justified use of alternate methods to detect and suppress oscillations under limited conditions.

The alternate methods are consistent with the guidelines identified in Reference

20. The alternate-methods procedures require increased operator awareness and monitoring for neutron flux oscillations when operating in the region where oscillations are possible.

If operator observes indications of oscillation, as described in Reference 20, the operator will take the actions described by procedures, which include manual scram of the reactor. The power/flow map regions where oscillations are possible are developed based on the methodology in Reference

22. The applicable regions are contained in the COLR.The alternate methods would adequately address detection and mitigation in the event of thermal hydraulic instability oscillations.

Based on industry operating experience with actual instability oscillations, the operator would be able to recognize instabilities during this time and take action to suppress them through a manual scram. In addition, the OPRM system may still be available to provide alarms to the operator if the onset of oscillations were to occur.The 12-hour allowed Completion Time for Required Action 1.1 is based on engineering judgment to allow orderly transition to the alternate methods (continued)

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-UNIT 1 TS / B 3.3-24 Revision 2 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES ACTIONS 1.1 and 1.2 (continued) while limiting the period of time during which no automatic or alternate detect and suppress trip capability is formally in place. Based on the small probability of an instability event occurring at all, the 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is judged to be reasonable.

The 120-day allowed Completion Time, the time that was evaluated in References 15 and 16, is considered adequate because with operation minimized in regions where oscillations may occur and implementation of the alternate methods, the likelihood of an instability event that could not be adequately handled by the alternate methods during this 120-day period was negligibly small.The primary purpose of Required Actions 1. 1 and 1.2 is to allow an orderly completion, without undue impact on plant operation, of design and verification activities required to correct unanticipated equipment design or functional problems that cause OPRM Trip Function INOPERABILITY in all APRM channels that cannot reasonably be corrected by normal maintenance or repair actions. These Required Actions are not intended and were not evaluated as a routine alternative to returning failed or inoperable equipment to OPERABLE status.SURVEILLANCE As noted at the beginning of the SRs, the SRs for each RPS REQUIREMENTS instrumentation Function are located in the SRs column of Table 3.3.1.1-1.

The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, provided the associated Function maintains RPS trip capability.

Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Refs. 9, 15 and 16) assumption of the average time required to perform channel Surveillance.

That analysis demonstrated that the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> testing allowance does not significantly reduce the probability that the RPS will trip when necessary.(continued)

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-UNIT 1 TS / B 3.3-24a Revision 0 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.1 and SR 3.3.1.1.2 REQUIREMENTS Performance of the CHANNEL CHECK ensures that a gross failure of instrumentation has not occurred.

A CHANNEL CHECK is normallya comparison of the parameter indicated on one channel to a similar parameter on other channels.

It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.(continued)

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-UNIT 1 TS / B 3.3-24b Revision 0 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.1 and SR 3.3.1.1.2 (continued)

REQUIREMENTS Agreement criteria which are determined by the plant staff based on an investigation of a combination of the channel instrument uncertainties, may be used to support this parameter comparison and include indication and readability.

If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit, and does not necessarily indicate the channel is Inoperable.

The Frequency of once every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for SR 3.3.1.1.1 is based upon operating experience that demonstrates that channel failure is rare. The Frequency of once every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for SR 3.3.1.1.2 is based upon operating experience that demonstrates that channel failure is rare and the evaluation in References 15 and 16. The CHANNEL CHECK supplements less formal checks of channels during normal operational use of the displays associated with the channels required by the LCO.SR 3.3.1.1.3 To ensure that the APRMs are accurately indicating the true core average power, the APRMs are calibrated to the reactor power calculated from a heat balance. The Frequency of once per 7 days is based on minor changes in LPRM sensitivity, which could affect the APRM reading between performances of SR 3.3.1.1.8.

A restriction,to satisfying this SR when < 23% RTP is provided that requires the SR to be met only at > 23% RTP because it is difficult to accurately maintain APRM indication of core THERMAL POWER consistent with a heat balance when < 23% RTP. At low power levels, a high degree of accuracy is unnecessary because of the large, inherent margin to thermal limits (MCPR, LHGR and APLHGR). At >_ 23% RTP, the Surveillance is required to have been satisfactorily performed within the last 7 days, in accordance with SR 3.0.2. A Note is provided which allows an increase in THERMAL POWER above 23% if the 7 day Frequency is not met per SR 3.0.2. In this event, the SR must be performed within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after reaching or exceeding 23% RTP. Twelve hours is based on operating experience and in (continued)

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-UNIT 1 TS / B 3.3-25 Revision 3 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.3 (continued)

REQUIREMENTS consideration of providing a reasonable time in which to complete the SR.SR 3.3.1.1.4 A CHANNEL FUNCTJONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function.As noted, SR 3.3.1.1.4 is not required to be performed when entering MODE 2 from MODE 1, since testing of the MODE 2 required IRM Functions cannot be performed in MODE 1 without utilizing jumpers, lifted leads, or movable links., This allows entry into MODE 2 if the 7 day Frequency is not met per SR 3.0.2. In this event, the SR must be (continued)

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-UNIT 1 TS / B 3.3-26 Revision 2 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.4 (continued)

REQUIREMENTS performed within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after entering MODE 2 from MODE 1. Twelve hours is based on operating experience and in consideration of providing a reasonable time in which to complete the SR.A Frequency of 7 days provides an acceptable level of system average unavailability over the Frequency interval and is based on reliability analysis (Ref. 9).SR 3.3.1.1.5 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function.

A Frequency of 7 days provides-an acceptable level of system average availability over the Frequency and is based on the reliability analysis of Reference

9. (The Manual Scram Function's CHANNEL FUNCTIONAL TEST Frequency was credited in the analysis to extend many automatic scram Functions' Frequencies.)

SR 3.3.1.1.6 and SR 3.3.1.1.7 These Surveillances are established to ensure that no gaps in neutron flux indication exist from subcritical to power operation for monitoring core reactivity status.The overlap between SRMs and IRMs is required to be demonstrated to ensure that reactor power will not be increased into a neutron flux region without adequate indication.

The overlap is demonstrated prior to fully withdrawing the SRMs from the core. Demonstrating the overlap prior to fully withdrawing the SRMs from the core is required to ensure the SRMs are on-scale for the overlap demonstration.

The overlap between IRMs and APRMs is of concern when reducing power into the IRM range. On power increases, the system design will prevent further increases (by initiating a rod block) if adequate overlap is not maintained.

Overlap between IRMs and APRMs exists when sufficient IRMs and APRMs concurrently have onscale readings such that the transition between MODE 1 and MODE 2 can be made without either APRM downscale rod block, or IRM upscale rod block. Overlap (continued)

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-UNIT 1 TS / B 3.3-27 Revision 1 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.6 and SR 3.3.1.1.7 (continued)

REQUIREMENTS between SRMs and IRMs similarly exists when, prior to fully withdrawing the SRMs from the core, IRMs are above mid-scale on range 1 before SRMs have reached the upscale rod block.As noted, SR 3.3.1.1.7 is only required to be met during entry into MODE 2 from MODE 1. That is, after the overlap requirement has been met and indication has transitioned to the IRMs, maintaining overlap is not required (APRMs may be reading downscale once in MODE 2).If overlap for a group of channels is not demonstrated (e.g., IRM/APRM overlap), the reason for the failure of the Surveillance should be determined and the appropriate channel(s) declared inoperable.

Only those appropriate channels that are required in the current MODE or condition should be declared inoperable.

A Frequency of 7 days is reasonable based on engineering judgment and the reliability of the IRMs and APRMs.SR 3.3.1.1.8 LPRM gain settings are determined from the local flux profiles that are either measured by the Traversing Incore Probe (TIP) System at all functional locations or calculated for TIP locations that are not functional.

The methodology used to develop the power distribution limits considers the uncertainty for both measured and calculated local flux profiles.

This methodology assumes that all the TIP locations are functional for the first LPRM calibration following a refueling outage, and a minimum of 25 functional TIP locations for subsequent LPRM calibrations.

The calibrated LPRMs establish the relative local flux profile for appropriate representative input to the APRM System. The 1000 MWD/MT Frequency is based on operating experience with LPRM sensitivity changes.SR 3.3.1.1.9 and SR 3.3.1.1.14 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the (continued)

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-UNIT 1 TS / B 3.3-28 Revision 3 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.9 and SR 3.3.1.1.14 (continued)

REQUIREMENTS intended function.

The 92 day Frequency of SR 3.3.1.1.9 is based on the reliability analysis of Reference 9.SR 3.3.1.1.9 is modified by a Note that provides a general exception to the definition of CHANNEL FUNCTIONAL TEST. This exception is necessary because the design of instrumentation does not facilitate functional testing of all required contacts of the relay which input into the combinational logic. (Reference

10) Performance of such a test could result in a plant transient or place the plant in an undo risk situation.

Therefore, for this SR, the CHANNEL FUNCTIONAL TEST verifies acceptable response by verifying the change of state of the relay which inputs into the combinational logic. The required contacts not tested during the CHANNEL FUNCTIONAL TEST are tested under the LOGIC SYSTEM FUNCTIONAL TEST, SR 3.3.1.1.15.

This is acceptable because operating experience shows that the contacts not tested during the CHANNEL FUNCTIONAL TEST normally pass the LOGIC SYSTEM FUNCTIONAL TEST, and the testing methodology minimizes the risk of unplanned transients.

The 24 month Frequency of SR 3.3.1.1.14 is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass the Surveillance when performed at the 24 month Frequency.

SR 3.3.1.1.10, SR 3.3.1.1.11, SR 3.3.1.1.13, and SR 3.3.1.1.18 A CHANNEL CALIBRATION verifies that the channel responds to the measured parameter within the necessary range and accuracy.CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.

Note 1 for SR 3.3.1.1.18 states that neutron detectors are excluded from CHANNEL CALIBRATION because they are passive devices, with minimal drift, and because of the difficulty of simulating a meaningful signal.Changes in neutron detector sensitivity are compensated for by performing the 7 day calorimetric calibration (SR 3.3.1.1.3) and the 1000 MWD/MT LPRM (continued)

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-UNIT 1 TS / B 3.3-29 Revision 4 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.10, SR 3.3.1.1.11, SR 3.3.1.1.13 and SR 3.3.1.1.18 REQUIREMENTS (continued) calibration against the TIPs (SR 3.3.1.1.8).

A Note is provided for SR 3.3.1.1.11 that requires the IRM SRs to be performed within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> of entering MODE 2 from MODE 1. Testing of the MODE 2 APRM and IRM Functions cannot be performed in MODE 1 without utilizing jumpers, lifted leads, or movable links. This Note allows entry into MODE 2 from MODE 1 if the associated Frequency is not met per SR 3.0.2. Twelve hours is based on operating experience and in consideration of providing a reasonable time in which to complete the SR.A second note is provided for SR 3.3.1.1.18 that requires that the recirculation flow (drive flow) transmitters, which supply the flow signal to the APRMs, be included in the SR for Functions 2.b and 2.f. The APRM Simulated Thermal Power-High Function (Function 2.b) and the OPRM Trip Function (Function 2.0 both require a valid drive flow signal. The APRM Simulated Thermal Power-High Function uses drive flow to vary the trip setpbint.

The OPRM Trip Function uses drive flow to automatically enable or bypass the OPRM Trip output to the RPS. A CHANNEL CALIBRATION of the APRM drive flow signal requires both calibrating the drive flow transmitters and the processing hardware in the APRM equipment.

SR 3.3.1.1.20 establishes a valid drive flow/ core flow relationship.

Changes throughout the cycle in the drive flow / core flow relationship due to the changing thermal hydraulic operating conditions of the core are accounted for in the margins included in the bases or analyses used to establish the setpoints for the APRM Simulated Thermal Power-High Function and the OPRM Trip Function.The Frequency of 184 days for SR 3.3.1.1.11, 92 days for SR 3.3.1.1.12 and 24 months for SR 3.3.1.1.13 and SR 3.3.1.1.18 is based upon the assumptions in the determination of the magnitude of equipment drift in the setpoint analysis.(continued)

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-UNIT 1 TS / B 3.3-30 Revision 3 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.12 REQUIREMENTS A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function.

For the APRM Functions, this test supplements the automatic self-test functions that operate continuously in the APRM and voter channels.

The scope of the APRM CHANNEL FUNCTIONAL TEST is that which is necessary to test the hardware.

Software controlled functions are tested as part of the initial Verification and validation and are only incidentally tested as part of the surveillance testing. Automatic self-test functions check the EPROMs in which the software-controlled logic is defined.Changes in the EPROMs will be detected by the self-test function and alarmed via the APRM trouble alarm. SR 3.3.1.1.1 for the APRM functions includes a step to confirm that the automatic self-test function is still operating.

The APRM CHANNEL FUNCTIONAL TEST covers the APRM channels (including recirculation flow processing

-- applicable to Function 2.b and the auto-enable portion of Function 2.f only), the 2-out-of-4 Voter channels, and the interface connections into the RPS trip systems from the voter channels.Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

The 184-day Frequency of SR 3.3.1.1.12 is based on the reliability analyses of References 15 and 16. (NOTE: The actual voting logic of the 2-out-of-4 Voter Function is tested as part of SR 3.3.1.1.15.

The auto-enable setpoints for the OPRM Trip are confirmed by SR 3.3.1.1.19.)

A Note is provided for Function 2.a that requires this SR to be performed within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> of entering MODE 2 from MODE 1. Testing of the MODE 2 APRM Function cannot be performed in MODE I without utilizing jumpers or lifted leads. This Note allows entry into MODE 2 from MODE I if the associated Frequency is not met per SR 3.0.2.A second Note is provided for Functions 2.b and 2.f that-clarifies that the CHANNEL FUNCTIONAL TEST for Functions 2.b and 2.f includes testing of the recirculation flow processing electronics, excluding the flow transmitters.

SR 3.3.1.1.15 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required-trip logic for a specific channel. The functional testing of control rods (LCO 3.1.3), and SDV vent (continued)

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-UNIT 1 TS / B 3.3-30a Revision 0 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 13ASES SURVEILLANCE SR 3.3.1.1.15 (continued)

REQUIREMENTS and drain valves (LCO 3.1.8), overlaps this Surveillance to provide complete testing of the assumed safety function.The LOGIC SYSTEM FUNCTIONAL TEST for APRM Function 2.e simulates APRM and OPRM trip conditions at the 2-out-of-4 Voter channel inputs to check all combinations of two tripped inputs to the 2-out-of-4 logic in the voter channels and APRM-related redundant RPS relays.The 24 month Frequency is based on the need to perform portions of this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass the Surveillance when performed at the 24 month Frequency.

SR 3.3.1.1.16 This SR ensures that scrams initiated from the Turbine Stop Valve-Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Functions will not be inadvertently bypassed when THERMAL POWER is> 26% RTP. This is performed by a Functional check that ensures the scram feature is not bypassed at _> 26% RTP. Because main turbine bypass flow can affect this function nonconservatively (THERMAL POWER is derived from turbine first stage pressure), the opening of the main turbine bypass valves must not cause the trip Function to be bypassed when Thermal Power is _ 26% RTP.If any bypass channel's trip function is nonconservative (i.e., the Functions are bypassed at _> 26% RTP, either due to open main turbine bypass valve(s) or other reasons), then the affected Turbine Stop Valve-Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Functions are considered inoperable.

Alternatively, the bypass channel can be placed in the conservative condition (nonbypass).

If placed in the nonbypass condition, this SR is met and the channel is considered OPERABLE.The Frequency of 24 months is based on engineering judgment and reliability of the components.

SR 3.3.1.1.17 This SR ensures that the individual channel response times are less than or equal to the maximum values assumed in the accident analysis.

This test may be performed in one (continued)

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-UNIT 1 TS / B 3.3-31 Revision 4 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.17 (continued)

REQUIREMENTS measurement or in overlapping segments, with verification that all components are tested. The RPS RESPONSE TIME acceptance criteria are included in Reference 11.RPS RESPONSE TIME for the APRM 2-out-of-4 Voter Function (2.e)includes the APRM Flux Trip output relays and the OPRM Trip output relays of the voter and the associated RPS relays and contactors.(Note: The digital portion of the APRM, OPRM and 2-out-of-4 Voter channels are excluded from RPS RESPONSE TIME testing because self-testing and calibration checks the time base of the digital electronics.

Confirmation of the time base is adequate to assure required response times are met. Neutron detectors are excluded from RPS RESPONSE TIME testing because the principles of detector operation virtually ensure an instantaneous response time. See References 12 and 13).RPS RESPONSE TIME tests are conducted on an 24 month STAGGERED TEST BASIS. Note 3 requires STAGGERED TEST BASIS Frequency to be determined based on 4 channels per trip system, in lieu of the 8 channels specified in Table 3.3.1.1-1 for the MSIV Closure-Function because channels are arranged in pairs.This Frequency is based on the logic interrelationships of the various channels required to produce an RPS scram signal. The 24 month Frequency is consistent with the typical industry refueling cycle and is based upon plant operating experience, which shows that random failures of instrumentation components causing serious response time degradation, but not channel failure, are infrequent occurrences.

SR 3.3.1.1.17 for Function 2.e confirms the response time of that function, and also confirms the response time of components to Function 2.e and other RPS functions. (Reference 14)Note 3 allows the STAGGERED TEST BASIS Frequency for Function 2.e" to be determined based on 8 channels rather than the 4 actual 2-out-of-4 Voter channels.

The redundant outputs from the 2-out-of-4 Voter channel (2 for APRM trips and 2 for OPRM trips) are considered part of the same channel, but the OPRM and APRM outputs are considered to be separate channels for application of SR 3.3.1.1.17, so N = 8. The note further requires that testing of OPRM and APRM outputs from a 2-out-of-4 Voter be alternated.

In addition to these commitments, References 15 and 16 require that the testing of inputs to each RPS Trip System alternate.(continued)

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-UNIT 1 TS / B 3.3-32 Revision 5 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE REQUIREMENTS SR 3.3.1.1.17 (continued)

Combining these frequency requirements, an acceptable test sequence is one that: a. Tests each RPS Trip System interface every other cycle, b. Alternates the testing of APRM and OPRM outputs from any specific 2-out-of-4 Voter Channel c. Alternates between divisions at least every other test cycle.The testing sequence shown in the table below is one sequence that satisfies these requirements.

Function 2.e Testing Sequence for SR 3.3.1.1.17"Staggering" 24- Voter Month Output Voter Al Voter A2 Voter B1 Voter RPS Trip Cycle Tested Output Output Output B2 System Division_ _Output 1 st OPRM A1 OPRM A 1 2nd APRM B1 APRM B 1 3rd OPRM A2 OPRM A 2 4th APRM B2 APRM B 2 5th APRM Al APRM A 1 6 t OPRM B1 OPRM B 1 7 th APRM A2 APRM A 2 8th oPRM B2 OPRM B 2 After 8 cycles, the sequence repeats.Each test of an OPRM or APRM output tests each of the redundant outputs from the 2-out-of-4 Voter channel for that Function and each of the corresponding relays in the RPS. Consequently, each of the RPS relays is tested every fourth cycle. The RPS relay testing frequency is twice the frequency justified by References 15 and 16.(continued)

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-PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.19 REQUIREMENTS This surveillance involves confirming the OPRM Trip auto-enable setpoints.

The auto-enable setpoint values are considered to be nominal values as discussed in Reference

21. This surveillance ensures that the OPRM Trip is enabled (not bypassed) for the correct values of APRM Simulated Thermal Power and recirculation drive flow. Other surveillances ensure that the APRM Simulated Thermal Power and recirculation drive flow properly correlate with THERMAL POWER (SR 3.3.1.1.2) and core flow (SR 3.3.1.1.20), respectively.

If any auto-enable setpoint is nonconservative (i.e., the OPRM Trip is bypassed when APRM Simulated Thermal Power >_ 25% and recirculation drive flow < value equivalent to the core flow value defined in the COLR, then the affected channel is considered inoperable for the OPRM Trip Function.

Alternatively, the OPRM Trip auto-enable setpoint(s) may be adjusted to place the channel in a conservative condition (not bypassed).

If the OPRM Trip is placed in the not-bypassed condition, this SR is met, and the channel is considered OPERABLE.For purposes of this surveillance, consistent with Reference 21, the conversion from core flow values defined in the COLR to drive flow values used for this SR can be conservatively determined by a linear scaling assuming that 100% drive flow corresponds to 100 Mlb/hr core flow, with no adjustment made for expected deviations between core flow and drive flow below 100%.The Frequency of 24 months is based on engineering judgment and reliability of the components.

SR 3.3.1.1.20 The APRM Simulated Thermal Power-High Function (Function 2.b) uses drive flow to vary the trip setpoint.

The OPRM Trip Function (Function 2.D uses drive flow to automatically enable or bypass the OPRM Trip output to RPS. Both of these Functions use drive flow as a representation of reactor core flow. SR 3.3.1.1.18 ensures that the drive flow transmitters and processing electronics are calibrated.

This SR adjusts the recirculation drive flow scaling factors in each APRM channel to provide the appropriate drive flow/core flow alignment.(continued)

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-UNIT 1 TS / B 3.3-32b Revision 1 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE REQUIREMENTS SR 3.3.1.1.20 The Frequency of 24 months considers that any change in the core flow to drive flow functional relationship during power operation would be gradual and the maintenance of the Recirculation System and core components that may impact the relationship is expected to be performed during refueling outages. This frequency also considers the period after reaching plant equilibrium conditions necessary to perform the test, engineering judgment of the time required to collect and analyze the necessary flow data, and engineering judgment of the time required to enter and check the applicable scaling factors in each of the APRM channels.

This timeframe is acceptable based on the relatively small alignment errors expected, and the margins already included in the APRM Simulated Thermal Power -High and OPRM Trip Function trip -enable setpoints.

REFERENCES

1. FSAR, Figure 7.2-1.2. Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 39132).3. NEDO-23842, "Continuous Control Rod Withdrawal in the Startup Range," April 18, 1978.4. FSAR, Section 5.2.2.5. FSAR, Chapter 15.6. FSAR, Section 6.3.3.(continued)

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7. Not used.(continued)

8. P. Check (NRC) letter to G. Lainas (NRC), "BWR Scram Discharge System Safety Evaluation," December 1, 1980.9. NEDO-30851-P-A, "Technical Specification Improvement Analyses for BWR Reactor Protection System," March 1988.10. 'NRC Inspection and Enforcement Manual, Part 9900: Technical Guidance, Standard Technical Specification 1.0 Definitions, Issue date 12/08/86.11. FSAR, Table 7.3-28.12. NEDO-32291A "System Analyses for Elimination of Selected Respobse Time Testing Requirements," October 1995.13. NRC Safety Evaluation Report related to Amendment No. 171 for License No. NPF 14 and Amendment No. 144 for License No. NPF 22.14. NEDO-32291-A Supplement 1 "System Analyses for the Elimination of Selected Response Time Testing Requirements," October 1999.15. NEDC-32410P-A, "Nuclear Measurement Analysis and Control Power Range Neutron Monitor (NUMAC PRNM) Retrofit Plus Option III Stability Trip Function," October 1995.16. NEDC-32410P-A Supplement 1, "Nuclear Measurement Analysis and Control Power Range Neutron Monitor (NUMAC PRNM) Retrofit Plus Option III Stability Trip Function," November 1997.17. NEDO-31960-A, "BWR Owners' Group Long-Term Stability Solutions Licensing Methodology," November 1995.18. NEDO-31960-A, Supplement 1, "BWR Owners' Group Long-Term Stability Solutions Licensing Methodology," November 1995.19. NEDO-32465-A, "BWR Owners' Group Long-Term Stability Detect and Suppress Solutions Licensing Basis Methodology and Reload Applications," August 1996.SUSQUEHANNA

-UNIT 1 TS / B 3.3-33 Revision 5 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 BASES REFERENCES (continued)

20. BWROG Letter BWROG 9479, L. A. England (BWROG) to M. J. Virgilio, "BWR Owners' Group Guidelines for Stability Interim Corrective Action," June 6, 1994.21. BWROG Letter BWROG 96113, K. P. Donovan (BWROG)to L. E. Phillips (NRC), "Guidelines for Stability Option III'Enable Region' (TAC M92882)," September 17, 1996.22. EMF-CC-074(P)(A), Volume 4, "BWR Stability Analysis: Assessment of STAIF with Input from MICROBURN-B2." 23. GE Letter to PPL, GE-2005-EMC426, "Susquehanna 1 & 2 Minimum LPRM Input Requirement for NUMAC APRM 4-Channel Design," April 26, 2005.SUSQUEHANNA

-UNIT 1 TS / B 3.3-33a Revision 0 PPL Rev. 6 RPS Instrumentation B 3.3.1.1 Table B 3.3.1.1-1 (page 1 of 1)RPS Instrumentation Sensor Diversity Scram Sensors for Initiating Events RPV Variables Anticipatory Fuel Initiation Events (a) (b) (c) (d) (e) M (g)MSIV Closure X X X X Turbine Trip (w/bypass)

X X X X Generator Trip (w/bypass)

X X X Pressure Regulator Failure (primary X X X X X pressure decrease) (MSIV closure trip)Pressure Regulator Failure (primary X X X pressure decrease) (Level 8 trip)Pressure Regulator Failure (primary X X pressure increase)Feedwater Controller Failure (high X X X X reactor water level)Feedwater Controller Failure (low X X X reactor water level)Loss of Condenser Vacuum X X X X Loss of AC Power (loss of transformer)

X X X X Loss of AC Power (loss of grid X X X X X X connections)(a)(b)(c)(d)(e)(f)(g)Reactor Vessel Steam Dome Pressure-High Reactor Vessel Water Level-High, Level 8 Reactor Vessel Water Level-Low, Level 3 Turbine Control Valve Fast Closure Turbine Stop Valve-Closure Main Steam Isolation Valve-Closure Average Power Range Monitor Neutron Flux-High SUSQUEHANNA

-UNIT 1 TS / B 3.3-34 Revision 1 PPL Rev. 4 Control Rod Block Instrumentation B 3.3.2.1 B 3.3 INSTRUMENTATION B 3.3.2.1 Control Rod Block Instrumentation BASES BACKGROUND Control rods provide the primary means for control of reactivity changes.Control rod block instrumentation includes channel sensors, logic circuitry, switches, and relays that are designed to ensure that specified fuel design limits are not exceeded for postulated transients and accidents.

During high power operation, the rod block monitor (RBM)provides protection for control rod withdrawal error events. During low power operations, control rod blocks from the rod worth minimizer (RWM)enforce specific control rod sequences designed to mitigate the consequences of the control rod drop accident (CRDA). During shutdown conditions, control rod blocks from the Reactor Mode Switch-Shutdown Position Function ensure that all control rods remain inserted to prevent inadvertent criticalities.

The Nominal Trip Setpoint (NTSP) is a predetermined setting for a protective device chosen to ensure automatic actuation prior to the process variable reaching the Analytical Limit and thus ensuring that the Safety Limit (SL) would not be exceeded.

The NTSP accounts for various uncertainties.

As such, the NTSP meets the definition of a Limiting Safety System Setting (LSSS) because the protective instrument channel actuates to protect a reactor core or RCS pressure boundary Safety Limit. Rod Block Monitor functions la, lb and 1c are LSSSs.Technical Specifications contain values related to the OPERABILITY of equipment required for safe operation of the facility.

OPERABLE is defined in Technical Specifications as "...being capable of performing its specified safety function(s)." For automatic protective devices related to SLs, the required safety function is to ensure that a SL is not exceeded and therefore the NTSP is the LSSS, as defined by 10 CFR 50.36.However, use of the NTSP to define OPERABILITY in Technical Specifications would be an overly restrictive requirement if it were applied as an OPERABILITY limit for the "as-found" value during a Surveillance.

This would result in Technical Specification compliance problems, as well as reports and corrective actions required by the rule which are not necessary to ensure safety.Use of the NTSP to define "as-found" OPERABILITY under the expected circumstances described above would result in actions required by both the rule and Technical Specifications that are not warranted.

However, there is also some point beyond which the device would have not been able to perform its function due, for example, to greater than expected drift. This (continued)

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-UNIT 1 TS / B 3.3-44 Revision 4 PPL Rev. 4 Control Rod Block Instrumentation B 3.3.2.1 BASES BACKGROUND value needs to be specified in the Technical Specifications in order to (continued) define OPERABILITY of the devices and is designated as the Allowable Value which, is the least conservative value of the as-found setpoint that a channel can have during testing.The Allowable Value specified in SR 3.3.2.1.7 is the least conservative value of the as-found setpoint that a channel can have when tested, such that a channel is OPERABLE if the setpoint is found conservative with respect to the Allowable Value during the CHANNEL CALIBRATION.

The purpose of the RBM is to limit control rod withdrawal if localized neutron flux exceeds a predetermined setpoint during control rod manipulations.

It is assumed to function to block further control rod withdrawal to preclude a MCPR Safety Limit violation.

The RBM supplies a trip signal to the Reactor Manual Control System (RMCS) to appropriately inhibit control rod withdrawal during power operation above the low power range setpoint.

The RBM has two channels, either of which can initiate a control rod block when the channel output exceeds the control rod block setpoint.

One RBM channel inputs into one RMCS rod block circuit and the other RBM channel inputs into the second RMCS rod block circuit. The RBM channel signal is generated by averaging a set of local power range monitor (LPRM) signals at various core heights surrounding the control rod being withdrawn.

A simulated thermal power signal from one of the four redundant average power range monitor (APRM) channels supplies a reference signal for one of the RBM channels and a simulated thermal power signal from another of the APRM channels supplies the reference signal to the second RBM channel. This reference signal is used to determine which RBM range setpoint (low, intermediate, or high) is enabled. If the APRM simulated thermal power is indicating less than the low power range setpoint, the RBM is automatically bypassed.

The RBM is also automatically bypassed if a peripheral control rod is selected (Ref. 2).The purpose 9f the RWM is to control rod patterns during startup, such that only specified control rod sequences and relative positions are allowed over the operating range from all control rods inserted to 10% RTP. The sequences effectively limit the potential amount and rate of reactivity increase during a CRDA. Prescribed control rod sequences are stored in the RWM, which will initiate control. rod withdrawal and insert blocks when the actual sequence deviates beyond allowances from the stored sequence.

The RWM determines the actual sequence based position indication for each control rod.The RWM also uses (continued)

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-UNIT 1 TS / B 3.3-44a Revision 0 PPL Rev. 4 Control Rod Block Instrumentation B 3.3.2.1 BASES BA.CKGROUND steam flow signals to determine when the reactor power is above the (continued) preset power level at which the RWM is automatically bypassed (Ref. 1).The RWM is a single channel system that provides input into RMCS rod block channel 2.The function of the individual rod sequence steps (banking steps) is to minimize the potential reactivity increase from postulated CRDA at low power levels. However, if the possibility for a control rod to drop can be eliminated, then banking steps at low power levels are not needed to ensure the applicable event limits can not be exceeded.

The rods may be inserted without the need to stop at intermediate positions since the possibility of a CRDA is eliminated by the confirmation that withdrawn control rods are coupled.To eliminate the possibility of a CRDA, administrative controls require that any partially inserted control rods, which have not been confirmed to be coupled since their last withdrawal, be fully inserted prior to reaching the THERMAL POWER of_10% RTP. If a control rod has been checked for coupling at notch 48 and the rod has not been moved inward, this rod is in contact with it's drive and is not required to be fully inserted prior to reaching the THERMAL POWER of 10% RTP. However, if it cannot be confirmed that the control rod has been moved inward, then that rod shall be fully inserted prior to reaching the THERMAL POWER of <10% RTP.The remaining control rods may then be inserted without the need to stop at intermediate positions since the possibility of a CRDA has been eliminated.

With the reactor mode switch in the shutdown position, a control rod withdrawal block is applied to all control rods to ensure that the shutdown condition is maintained.

This Function prevents inadvertent criticality as the result of a control rod withdrawal during MODE 3 or 4, or during MODE 5 when the reactor mode switch is required .to be in the shutdown position.

The reactor mode switch has two channels, each inputting into a separate RMCS rod block circuit. A rod block in either RMCS circuit will provide a control rod block to all control rods.APPLICABLE Allowable Values are specified for each applicable Rod Block Function SAFETY listed in Table 3.3.2.1-1.

The NTSPs (actual trip setpoints) are selected ANALYSES, to ensure that the setpoints are conservative with respect to the LCO, and Allowable Value. A channel is inoperable if its actual trip setpoint is non-APPLICABILITY conservative with respect to its required Allowable Value.(continued)

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-UNIT 1 TS / B 3.3-44b Revision 0 PPL Rev. 4 Control Rod Block Instrumentation B 3.3.2.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

NTSPs are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., reactor power), and when the measured output value of the process parameter exceeds the setpoint, the associated device (e.g., trip unit) changes state. The Analytical Limits are derived from the limiting values of the process. parameters obtained from the safety analysis.

The Allowable Values are derived from the Analytical Limits, corrected for calibration, process, and some of the instrument errors. The NTSPs are then determined, accounting for the remaining channel uncertainties.

The trip setpoints derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, and drift are accounted for.The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis.1. Rod Block Monitor The RBM is designed to prevent violation of the MCPRSL and the cladding 1% strain Fuel design limit that may result from a single control rod withdrawal (RWE) event.The RBM is designed to limit control rod withdrawal if localized neutron flux exceeds a predetermined setpoint.

The analytical methods and assumptions used in evaluating the RWE event are summarized in Reference

14. The fuel thermal performance as a function of RBM Allowable Value is determined from the analysis.

The NTSP and Allowable Values are chosen as a function of power level. NTSP operating limits are established based on the specified Allowable Values.The RBM function satisfies Criterion 3 of the NRC Policy Statement (Ref. 7).Two channels of the RBM are required to be OPERABLE, with their setpoints within the appropriate Allowable Value for the associated power range, to ensure that no single instrument failure can preclude a rod block for this Function.

The actual setpoints are calibrated consistent with applicable setpoint methodology.

Nominal trip setpoints are specified in the setpoint calculations.

The nominal setpoints are selected to ensure that the setpoints do not exceed the Allowable Values between successive CHANNEL CALIBRATIONS.(continued)

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-UNIT 1 TS / B 3.3-45 Revision 3 PPL Rev. 4 Control Rod Block Instrumentation B 3.3.2.1 BASES APPLICABLE Nominal trip setpoints are those predetermined values of output at which SAFETY an action should take place. The trip setpoints are compared to the ANALYSES, actual process parameter, the calculated RBM flux (RBM channel signal).LCO, and When the normalized RBM flux value exceeds the applicable trip APPLICABILITY setpoint, the RBM provides a trip output.(continued)

The analytic limits are derived from the limiting values of the process parameters.

Using the GE setpoint methodology, based on ISA RP 67.04, Part II "Methodologies for the Determination of Setpoints for Nuclear Safety-Related Instrumentation" setpoint calculation Method 2, the RBM Allowable Values are determined from the analytical limits using the statistical combination of the RBM input signal calibration error, process measurement error, primary element accuracy and instrument accuracy under trip conditions.

Accounting for these'errors assures that a setpoint found during calibration at the Allowable Value has adequate margin to protect the analytical limit thereby protecting the Safety Limit.For the digital RBM, there is a normalization process initiated.upon rod selection, so that only RBM input signal drift over the interval from the rod selection to rod movement needs to be considered in determining the nominal trip setpoints.

The RBM has no drift characteristic with no as-left or as-found tolerances since it only performs digital calculations on the digitized input signals provided by the APRMs.The RBM Allowable Value demonstrates that the analytical limit would not be exceeded, thereby protecting the safety limit. The Nominal trip setpoints and Allowable Values determined in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, instrument drift, and environment errors are accounted for and appropriately applied for the RBM. There are no margins applied to the RBM nominal trip setpoint calculations which could mask RBM degradation.

The RBM will function when operating greater than or equal to 28% RTP.Below this power level, the RBM is not required to be OPERABLE.The RBM selects one of three different RBM flux trip setpoints to be applied based on the current value of THERMAL POWER. THERMAL POWER is indicated to each RBM channel by a simulated thermal power (STP) reference signal input from an associated reference APRM channel. The OPERABLE range is divided into three "power ranges," a"low power (continued)

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-UNIT 1 TS / B 3.3-45a Revision 0 PPL Rev. 4 Control Rod Block Instrumentation B 3.3.2.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) range," an "intermediate power range," and a "high power range." The RBM flux trip setpoint applied within each of these three power ranges is, respectively, the "low trip setpoint," the "intermediate trip setpoint," and the "high trip setpoint" (Allowable Values for which are defined in the COLR). To determine the current power range, each RBM channel compares its current STP input value to three power setpoints, the "low power setpoint", (28%), the "intermediate power setpoint" (current value defined in the COLR), and the "high power setpoint" (current value defined in the COLR), which define, respectively, the lower limit of the low power range, the lower limit of the intermediate power range, and the lower limit of the high power range. The trip setpoint applicable for each power range is more restrictive than the corresponding setpoint for the lower power range(s).

When STP is below the low power setpoint, the RBM flux trip outputs are automatically bypassed but the low trip setpoint continues to be applied to indicate the RBM flux setpoint on the NUMAC RBM displays.The calculated setpoints and applicable power ranges are bounding values. In the equipment implementation, it is necessary to apply a"deadband" to each setpoint.

The deadband is applied to the RBM trip setpoint selection logic and the RBM trip automatic bypass logic such that the setpoint being applied is always equal to or more conservative than the required setpoint.

Since the RBM flux trip setpoint applicable to the higher power ranges are more conservative than the dorresponding trip setpoints for lower power ranges, the trip setpoint applicable to the higher power range (high power range or intermediate power range) continues to be applied when STP decreases below the lower limit of that range until STP is below the power range Setpoint bya value exceeding the deadband.

Similarly, when STP decreases below the low power setpoint, the automatic bypass of RBM flux trip outputs will not be applied until STP decreases below the trip setpoint a value exceeding the deadband.The RBM channel uses THERMAL POWER, as represented by the STP input value from its reference APRM channel, to automatically enable RBM flux trip outputs (remove the automatic bypass) and to select the RBM flux trip setpoint to be applied. However, the RBM Upscale function is only required to be OPERABLE when the MCPR values are less than the values defined in the COLR, depending on the THERMAL POWER level. Therefore, even though the RBM Upscale Function is implemented in each RBM channel as a single trip function with a selected trip setpoint, it is characterized in Table 3.3.2.1-1 as three Functions, the Low Power.(continued)

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-UNIT 1 TS / B 3.3-45b Revision 0 PPL Rev. 4 Control Rod Block Instrumentation B 3.3.2.1 BASES APPLICABLE SAFETY ANALYSES, LCO,' and APPLICABILITY (continued)

Range -Upscale Function, the Intermediate Power Range -Upscale Function, and the High Power Range -Upscale Function, to facilitate correct definition of the OPERABILITY requirements for the Functions.

Each Function corresponds to one of the RBM power ranges. Due to the deadband effects on the determination of the current power range, the transition between these three Functions will occur at slightly different THERMAL POWER levels for increasing power versus decreasing power.2. Rod Worth Minimizer The RWM enforces the banked position withdrawal sequence (BPWS)to ensure that the initial conditions of the CRDA analysis are not violated.(continued)

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-UNIT 1 TS / B 3.3-46 Revision 3 PPL Rev. 4 Control Rod Block Instrumentation B 3.3.2.1 BASES APPLICABLE The analytical methods and assumptions used in evaluating the CRDA SAFETY are summarized in References 2, 3, 4, and 5. The BPWS requires that ANALYSES, control rods be moved in groups, with all control rods assigned to a LCO, and specific group required to be within specified banked positions.

APPLICABILITY Requirements that the control rod sequence is in compliance with the (continued)

BPWS are specified in LCO 3.1.6, "Rod Pattern Control." When performing a shutdown of the plant, an optional BPWS control rod sequence (Ref. 7) may be used if the coupling of each withdrawn control rod has been confirmed.

The rods may be inserted without the need to stop at intermediate positions.

When using the Reference 11 control rod insertion sequence for shutdown, the rod worth minimizer may be reprogrammed to enforce the requirements of the improved BPWS control rod insertion, or may be bypassed and the improved BPWS shutdown sequence implemented under the controls in Condition D.The RWM Function satisfies Criterion 3 of the NRC Policy Statement.(Ref. 7)Since the RWM is designed to act as a backup to operator control of the rod sequences, only one channel of the RWM is available and required to be OPERABLE (Ref. 6). Special circumstances provided for in the Required Action of LCO 3.1.3, "Control Rod OPERABILITY," and LCO 3.1.6 may necessitate bypassing the RWM to allow continued operation with inoperable control rods, or to allow correction of a control rod pattern not in compliance with the BPWS. The RWM may be bypassed as required by these conditions, but then it must be considered inoperable and the Required Actions of this LCO followed.Compliance with the BPWS, and therefore OPERABILITY of the RWM, is required in MODES 1 and 2 when THERMAL POWER is < 10% RTP.When THERMAL POWER is > 10% RTP, there is no possible control rod configuration that results in a control rod worth that could exceed the 280 cal/gm fuel damage limit during a CRDA (Refs. 4 and 6). In MODES 3 and 4, all control rods are required to be inserted into the core (except as provided in 3.10 "Special Operations");

therefore, a CRDA cannot occur. In MODE 5, since only a single control rod can be withdrawn from a core cell containing fuel assemblies, adequate SDM ensures that the consequences of a CRDA are acceptable, since the reactor will be subcritical.(continued)

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-UNIT 1 TS / B 3.3-47 Revision 2 PPL Rev. 4 Control Rod Block Instrumentation B 3.3.2.1 BASES APPLICABLE SAFETY ANALYSES LCO, and APPLICABILITY (continued)

3. Reactor Mode Switch-Shutdown Position During MODES 3 and 4, and during MODE 5 when the reactor mode switch is required to be in the shutdown position, the core is assumed to be subcritical; therefore, no positive reactivity insertion events are analyzed.

The Reactor Mode Switch-Shutdown Position control rod withdrawal block ensures that the reactor remains subcritical by blocking control rod withdrawal, thereby preserving the assumptions of the safety analysis.The Reactor Mode Switch-Shutdown Position Function satisfies Criterion 3 of the NRC Policy Statement. (Ref. 7)Two channels are required to be OPERABLE to ensure that no single channel failure, will preclude a rodblock when required.

There is no Allowable Value for this Function since the channels are mechanically actuated based solely on reactor mode switch position.During shutdown conditions (MODE 3, 4, or 5), no positive reactivity insertion events are analyzed because assumptions are that control rod withdrawal blocks are provided to prevent criticality.

Therefore, when the reactor mode switch is in the shutdown position, the control rod withdrawal block is required to be OPERABLE.

During MODE 5 with the reactor mode switch in the refueling position, the refuel position one-rod-out interlock (LCO 3.9.2) provides the required control rod withdrawal blocks.ACTIONS A.1 With one RBM channel inoperable, the remaining OPERABLE channel is adequate to perform the control rod block function; however, overall reliability is reduced because a single failure in the remaining OPERABLE channel can result in no control rod block capability for the RBM. For this reason, Required Action A.1 requires restoration of the inoperable channel to OPERABLE status. The Completion Time of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is based on the low probability of an event occurring coincident with a failure in the remaining OPERABLE channel.(continued)

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-UNIT 1 TS / B 3.3-48 Revision 3 PPL Rev. 4 Control Rod Block Instrumentation B 3.3.2.1 BASES ACTIONS B. 1 (continued)

If Required Action A.1 is not met and the associated Completion Time has expired, the inoperable channel must be placed in trip within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.If both RBM channels are inoperable, the RBM is not capable of performing its intended function; thus, one channel must also be placed in trip. This initiates a control rod withdrawal block, thereby ensuring that the RBM function is met.The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities and is acceptable because it minimizes risk while allowing time for restoration or tripping of inoperable channels.C.1, C.2.1.1, C.2.1.2, and C.2.2 With the RWM inoperable during a reactor startup, the operator is still capable of enforcing the prescribed control rod sequence.

However, the overall reliability is reduced because a single operator error can result in violating the control rod sequence.

Therefore, control rod movement must be immediately suspended except by scram. Alternatively, startup may continue if at least 12 control rods have already been withdrawn, or a reactor startup with an inoperable RWM was not performed in the last calendar year, i.e., the last 12 months. Required Actions C.2.1.1 and C.2.1.2 require verification of these conditions by review of plant logs and control room indications.

A reactor startup with an inoperable RWM is defined as rod withdrawal during startup when the RWM is required to be OPERABLE.

Once Required Action C.2.1.1 or C.2.1.2 is satisfactorily completed, control rod withdrawal may proceed in accordance with the restrictions imposed by Required Action C.2.2. Required Action C.2.2 allows for the RWM Function to be performed manually and requires a double check of compliance with the prescribed rod sequence by a second licensed operator (Reactor Operator or Senior Reactor Operator)or other qualified member of the technical staff. The RWM may be bypassed under these conditions to allow continued operations.

In addition, Required Actions of LCO 3.1.3 and LCO 3.1.6 may require bypassing the RWM, during which time the RWM must be considered inoperable with Condition C entered and its Required Actions taken.(continued)

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-UNIT 1 TS / B 3.3-49 Revision 3 PPL Rev. 4 Control Rod Block Instrumentation B 3.3.2.1 BASES ACTIONS D.l (continued)

With the RWM inoperable during a reactor shutdown, the operator is still capable of enforcing the prescribed control rod sequence.

Required Action D.1 allows for the RWM Function to be performed manually and requires a double check of compliance with the prescribed rod sequence by a second licensed operator (Reactor Operator or Senior Reactor Operator) or other qualified member of the technical staff. The RWM may be bypassed under these conditions to allow the reactor shutdown to continue.E.1 and E.2 With one Reactor Mode Switch-Shutdown Position control rod withdrawal block channel inoperable, the remaining OPERABLE channel is adequate to perform the control rod withdrawal block function.However, since the Required Actions are consistent with the normal action of an OPERABLE Reactor Mode Switch-Shutdown Position Function (i.e., maintaining all control rods inserted), there is no distinction between having one or two channels inoperable.

In both cases (one or both channels inoperable), suspending all control rod withdrawal and initiating action to fully insert all insertable control rods in core cells containing one or more fuel assemblies will ensure that the core is subcritical with adequate SDM ensured by LCO 3.1.1. Control rods in core cells containing no fuel ,assemblies do not affect the reactivity of the core and are therefore not required to be inserted.

Action must continue until all insertable control rods in core cells containing one or more fuel assemblies are fully inserted.SURVEILLANCE As noted at the beginning of the SRs, the SRs for each Control Rod REQUIREMENTS Block instrumentation Function are found in the SRs column of Table 3.3.2.1-1.

The Surveillances are modified by a Note to indicate that when an RBM channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided the associated Function maintains control rod block capability.

Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Refs. 9, 12 and 13).(continued)

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-UNIT 1 TS / B 3.3-50 Revision 3 PPL Rev. 4 Control Rod Block Instrumentation 3.3.2.1 BASES SURVEILLANCE assumption of the average time required to perform channel Surveillance.

REQUIREMENTS That analysis demonstrated that the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> testing allowance does not (continued) significantly reduce the probability that a control rod block will be initiated when necessary.

SR 3.3.2.1.1 A CHANNEL FUNCTIONAL TEST is performed for each RBM channel to ensure that the entire channel will perform the intended function.

It includes the Reactor Manual Control Multiplexing System input. The Frequency of 184 days is based on reliability analyses (Refs. 8, 12 and 13).SR 3.3.2.1.2 and SR 3.3.2.1.3 A CHANNEL FUNCTIONAL TEST is performed for the RWM to ensure that the entire system will perform the intended function.

The CHANNEL FUNCTIONAL TEST for the RWM is performed by attempting to withdraw a control rod not in compliance with the prescribed sequence and verifying a control rod block occurs and by verifying proper indication of the selection error of at least one out-of-sequence control rod. As noted in the SRs, SR 3.3.2.1.2 is not required to be performed until 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> after any control rod is withdrawn in MODE 2. As noted, SR 3.3.2.1.3 is not required to be performed until 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> after THERMAL POWER is< 10% RTP in MODE 1. This allows entry into MODE 2 for SR 3.3.2.1.2, and entry into MODE 1 when THERMAL POWER is < 10% RTP for SR 3.3.2.1.3, to perform the required Surveillance if the 92 day Frequency is not met per SR 3.0.2. The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> allowance is based on operating experience and in consideration of providing a reasonable time in which to complete the SRs. The Frequencies are based on reliability analysis (Ref. 8).SR 3.3.2.1.4 The RBM setpoints are automatically varied as a function of Simulated Thermal Power. Three control rod block Allowable Values are specified in Table 3.3.2.1-1, each within a specific power range. The power at which the control rod block Allowable Values automatically change are based on the APRM signal's input to each RBM channel. Below the minimum power setpoint, the RBM is automatically bypassed.

These control rod block NTSPs must be verified periodically to be less than or equal to the specified Allowable Values. If any power range setpoint is non-conservative, then the affected RBM channel is considered inoperable.

As noted, neutron detectors are excluded from the Surveillance because they are passive devices, with minimal drift, and because of the difficulty of simulating a meaningful signal. Neutron detectors are adequately tested in SR 3.3.1.1.3 and SR 3.3.1.1.8.

The 24 month Frequency is based on the actual trip setpoint methodology utilized for these channels.(continued)

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-UNIT 1 TS / B 3.3-51 Revision 3 PPL Rev. 4 Control Rod Block Instrumentation 3.3.2.1 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.3.2.1.5 The RWM is automatically bypassed when power is above a specified value. The power level is determined from steam flow signals. The automatic bypass setpoint must be verified periodically to be not bypassed _< 10% RTP. This is performed by a Functional check. If the RWM low power setpoint is nonconservative, then the RWM is considered inoperable.

Alternately, the low power setpoint channel can be placed in the conservative condition (nonbypass).

If placed in the nonbypassed condition, the SR is met and the RWM is not considered inoperable.

The Frequency is based on the need to perform the Surveillance during a plant start-up.SR 3.3.2.1.6 A CHANNEL FUNCTIONAL TEST is performed for the Reactor Mode Switch-Shutdown Position Function to ensure that the entire channel will perform the intended function.

The CHANNEL FUNCTIONAL TEST for the Reactor Mode Switch-Shutdown Position Function is performed by attempting to withdraw any control rod with the reactor mode switch in the shutdown position and verifying a control rod block occurs.As noted in the SR, the Surveillance is not required to be performed until 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> after the reactor mode switch is in the shutdown position, since testing of this interlock with the reactor mode switch in any other position cannot be performed without using jumpers, lifted leads, or movable 0 (continued)

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-UNIT 1 TS / B 3.3-52 Revision 2 PPL Rev. 4 Control Rod Block Instrumentation B 3.3.2.1 BASES SURVEILLANCE SR 3.3.2.1.6 (continued)

REQUIREMENTS links. This allows entry into MODES 3 and 4 if the 24 month Frequency is not met per SR 3.0.2. The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> allowance is based on operating experience and in consideration of providing a reasonable time in which to complete the SRs.The 24 month Frequency is based on the need to perform portions of this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency.

SR 3.3.2.1.7 CHANNEL CALIBRATION is a test that verifies the channel responds to the measured parameter with the necessary range and accuracy.CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibration consistent with the plant specific setpoint methodology.

As noted, neutron detectors are excluded from the CHANNEL CALIBRATION because they are passive devices, with minimal drift,.and because of the difficulty of simulating a meaningful signal, Neutron detectors are adequately tested in SR 3.3.1.1.2 and SR 3.3.1.1.8.

The Frequency is based upon the assumption of a 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.SR 3.3.2.1.7 for the RBM Functions is modified by two Notes as identified in Table 3.3.2.1-1.

The RBM Functions are Functions that are LSSSs for reactor core Safety Limits. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is not the NTSP but is conservative with respect to the Allowable Value. For digital channel components, no as-found tolerance or as-left tolerance can be specified.

Evaluation of instrument performance will verify that the instrument will .continue to behave in accordance with design-basis assumptions.

The purpose of the assessment is to ensure confidence in the instrument performance prior to returning the instrument to service. These channels will also be identified in the Corrective Action Program.(continued)

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-UNIT 1 TS / B 3.3-53 Revision 2 PPL Rev. 4 Control Rod Block Instrumentation B 3.3.2.1 BASES SURVEILLANCE REQUIREMENTS (continued)

Entry into the Corrective Action Program will ensure required review and documentation of the condition for continued OPERABILITY.

The second Note requires that the as-left setting for the instrument be returned to the NTSP. If the as-left instrument setting cannot be returned to the NTSP, then the instrument channel shall be declared inoperable.

The second Note also requires that the NTSP and NTSP methodology are to be contained in a document controlled by 10 CFR 50.59.SR 3.3.2.1.8 The RWM will only enforce the proper control rod sequence if the rod sequence is properly input into the RWM computer.

This SR ensures that the proper sequence is loaded into the RWM so that it can perform its intended function.

The Surveillance is performed once prior to declaring RWM OPERABLE following loading of sequence into RWM, since this is when rod sequence input errors are possible.(continued)

Revision 0 SUSQUEHANNA

-UNIT 1 TS / B 3.3-53a PPL Rev. 4 Control Rod Block Instrumentation B 3.3.2.1 BASES (continued)

REFERENCES

1. FSAR, Section 7.7.1.2.8.

2. FSAR, Section 7.6.1.a.5.7

3. NEDE-2401 1-P-A-9-US, "General Electrical Standard Application for Reload Fuel," Supplement for United States, Section S 2.2.3.1, September 1988.4. "Modifications to the Requirements for Control Rod Drop Accident Mitigating Systems," BWR Owners' Group, July 1986.5. NEDO-21231, "Banked Position Withdrawal Sequence," January 1977.6. NRC SER, "Acceptance of Referencing of Licensing Topical Report NEDE-2401 1-P-A," "General Electric Standard Application for Reactor Fuel, Revision 8, Amendment 17," December 27, 1987.7. Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 32193)8. NEDC-30851-P-A, "Technical Specification Improvement Analysis for BWR Control Rod Block Instrumentation," October 1988.9. GENE-770-06-1, "Addendum to Bases for changes to Surveillance Test Intervals and Allowed Out-of-Service Times for Selected Instrumentation, Technical Specifications," February 1991.10. FSAR, Section 15.4.2.11. NEDO 33091-A, Revision 2, "Improved BPWS Control Rod Insertion Process," July 2004.12. N EDC-32410P-A, "Nuclear Measurement Analysis and Control Power Range Neutron Monitor (NUMAC PRNM) Retrofit Plus Option III Stability Trip Function," October 1995.13. NEDC-32410P-A Supplement 1, "Nuclear Measurement Analysis and Control Power Range Neutron Monitor (NUMAC PRNM) Retrofit Plus Option III Stability Trip Function," November 1997.14. XN-NF-80-19(P)(A)

Volume 4, Revision 1, "Exxon Nuclear Methodology for Boiling Water Reactors:

Application of the ENC Methodology to BWR Reloads," Exxon Nuclear Company, June 1986.SUSQUEHANNA

-UNIT 1 TS / B 3.3-54 Revision 5 PPL Rev. 2 EOC-RPT Instrumentation B 3.3.4.1 B 3.3 INSTRUMENTATION B 3.3.4.1 End of Cycle Recirculation Pump Trip (EOC-RPT)

Instrumentation BASES BACKGROUND The EOC-RPT instrumentation initiates a recirculation pump trip (RPT) to reduce the peak reactor pressure and power resulting from turbine trip or generator load rejection transients to provide additional margin to core thermal MCPR Safety Limits (SLs).The need for the additional negative reactivity in excess of that normally inserted on a scram reflects end of cycle reactivity considerations.

Flux shapes at the end of cycle are such that the control rods may not be able to ensure that thermal limits are maintained by inserting sufficient negative reactivity during the first few feet of rod travel upon a scram caused by Turbine Control Valve (TCV) Fast Closure, Trip Oil Pressure-Low or Turbine Stop Valve (TSV)-Closure.

The physical phenomenon involved is that the void reactivity feedback due to a pressurization transient can add positive reactivity at a faster rate than the control rods can add negative reactivity.

The EOC-RPT instrumentation, as shown in Reference 1, is composed of sensors that detect initiation of closure of the TSVs or fast closure of the TCVs, combined with relays, logic circuits, and fast acting circuit breakers that interrupt power from the recirculation pump motor generator (MG) set generators to each of the recirculation pump motors. When the setpoint is reached, the channel output relay actuates, which then outputs an EOC-RPT signal to the trip logic. When the RPT breakers trip open, the recirculation pumps coast down under their own inertia. The EOC-RPT has two identical trip systems, either of which can actuate an RPT.Each EOC-RPT trip system is a two-out-of-two logic for each Function;thus, either two TSV-Closure or two TCV Fast Closure, Trip Oil Pressure-Low signals are required for a trip system to actuate. The Turbine Stop Valve -Closure functions such that: (1) The closing of one Turbine Stop Valve will not cause an RPT trip.(continued)

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-UNIT 1 B 3.3-81 Revision 0 PPL Rev. 2 EOC-RPT Instrumentation B 3.3.4.1 BASES BACKGROUND (continued)

(2) The closing of two Turbine Stop Valves may or may not cause an RPT trip depending on which stop valves are closed.(3) The closing of three or more Turbine Stop Valves will always yield an RPT trip.If either trip system actuates, both recirculation pumps will trip. There are two RPT breakers in series per recirculation pump. One trip system trips one of the two RPT breakers for each recirculation pump, and the second trip system trips the other RPT breaker for each recirculation pump.APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY The TSV-Closure and the TCV Fast Closure, Trip Oil Pressure-Low Functions are designed to trip the recirculation pumps in the event of a turbine trip or generator load rejection to mitigate the neutron flux, heat flux, and pressure transients, and to increase the margin to the MCPR SL.The analytical methods and assumptions used in evaluating the turbine trip and generator load rejection, as well as other safety analyses that take credit for EOC-RPT, are summarized in References 2 and 3.To mitigate pressurization transient effects, the EOC-RPT must trip the recirculation pumps after initiation of closure movement of either the TSVs or the TCVs. The combined effects of this trip and a scram reduce fuel bundle power more rapidly than a scram alone, resulting in an increased margin to the MCPR SL. Alternatively, MCPR limits for an inoperable EOC-RPT, as specified in the COLR, are sufficient to mitigate pressurization transient effects. The EOC-RPT function is automatically disabled when turbine first stage pressure is < 26% RTP.EOC-RPT instrumentation satisfies Criterion 3 of the NRC Policy Statement. (Ref. 6)The OPERABILITY of the EOC-RPT is dependent on the OPERABILITY of the individual instrumentation channel Functions.

Each Function must have a required number of OPERABLE channels in each trip system, with their setpoints within the specified Allowable Value of SR 3.3.4.1.2.

The actual setpoint is calibrated consistent with applicable (continued)

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-UNIT 1 TS / B 3.3-82 Revision 2 PPL Rev. 2 EOC-RPT Instrumentation B 3.3.4.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) setpoint methodology assumptions.

Channel OPERABILITY also includes the associated RPT breakers.

Each channel (including the associated RPT breakers) must also respond within its assumed response time.Allowable Values are specified for each EOC-RPT Function specified in the LCO. Nominal trip setpoints are specified in the setpoint calculations.

A channel is inoperable if its actual trip setpoint is not within its required Allowable Value. The nominal setpoints are selected to ensure that the setpoints do not exceed the Allowable Value between successive CHANNEL CALIBRATIONS.

Operation with a trip setpoint less conservative than the nominal trip setpoint, but within its Allowable Value, is acceptable.

Each Allowable Value specified is more conservative than the analytical limit assumed in the transient and accident analysis in order to account for instrument uncertainties appropriate to the Function.

Trip setpoints are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., TSV position), and when the measured output value of the process parameter reaches the setpoint, the associated device changes state. The analytic limits are derived from the limiting values of the process parameters obtained from the safety analysis.

The Allowable Values are derived from the analytic limits, corrected for calibration, process, and some of the instrument errors. The trip setpoints are then determined accounting for the remaining instrument errors (e.g., drift).The trip setpoints derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, instrument drift, and severe environment errors (for channels that must function in harsh environments as defined by 10 CFR 50.49) are accounted for.Alternatively, since this instrumentation protects against a MCPR SL violation, with the instrumentation inoperable, modifications to the MCPR limits (LCO 3.2.2) may be applied to allow this LCO to be met. The MCPR penalty for the EOC-RPT inoperable condition is specified in the COLR.The specific Applicable Safety Analysis, LCO, and Applicability discussions are listed below on a Function by Function basis.(continued)

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-UNIT 1 B 3.3-83 Revision 0 PPL Rev. 2 EOC-RPT Instrumentation B 3.3.4.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

Turbine Stop Valve-Closure Closure of the TSVs and a main turbine trip result in the loss of a heat sink that produces reactor pressure, neutron flux, and heat flux transients that must be limited. Therefore, an RPT is initiated on TSV-Closure in anticipation of the transients that would result from closure of these valves. EOC-RPT decreases reactor power and aids the reactor scram in ensuring that the MCPR SL is not exceeded during the worst case transient.

Closure of the TSVs is determined by measuring the position of each valve. There are two separate position switches associated with each stop valve, the signal from each switch being assigned to a separate trip channel. The logic for the TSV-Closure Function is such that two or more TSVs must be closed to produce an EOC-RPT. This Function must be enabled at THERMAL POWER >_ 26% RTP. This is accomplished automatically by pressure instruments sensing turbine first stage pressure.Because an increase in the main turbine bypass flow can affect this function nonconservatively (THERMAL POWER is derived from first stage pressure), the main turbine bypass valves must not cause the trip Functions to be bypassed when thermal power is _> 26% RTP. Four channels of TSV-Closure, with two channels in each trip system, are available and required to be OPERABLE to ensure that no single instrument failure will preclude an EOC-RPT from this Function on a valid signal. The TSV-Closure Allowable Value is selected to detect imminent TSV closure.This protection is required, consistent with the safety analysis assumptions, whenever THERMAL POWER is > 26% RTP. Below 26% RTP, the Reactor Vessel Steam Dome Pressure-High and the Average Power Range Monitor (APRM) Fixed Neutron Flux-High Functions of the Reactor Protection System (RPS). are adequate to maintain the necessary safety margins.Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Fast closure of the TCVs during a generator load rejection results in the loss of a heat sink that produces reactor pressure, neutron flux, and heat flux transients that must be limited. Therefore, an RPT is initiated on TCV Fast Closure, Trip Oil Pressure-Low in anticipation of the transients that would result from the closure of these valves. The EOC-RPT decreases reactor power and aids the (continued)

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-UNIT 1 B 3.3-84 Revision 1 PPL Rev. 2 EOC-RPT Instrumentation B 3.3.4.1 BASES APPLICABLE Turbine Control Valve Fast Closure, Trip Oil Pressure-Low (continued)

SAFETY ANALYSES, reactor scram in ensuring that the MCPR SL is not exceeded during the LCO, and worst case transient.

APPLICABILITY Fast closure of the TCVs is determined by measuring the electrohydraulic control fluid pressure at each control valve. There is one pressure instrument associated with each control valve, and the signal from each instrument is assigned to a separate trip channel..

The logic for the TCV Fast Closure, Trip Oil Pressure-Low Function is such that two or more TCVs must be closed (pressure instrument trips) to produce an EOC-RPT.This Function must be enabled at THERMAL POWER > 26% RTP. This is accomplished automatically by pressure instruments sensing turbine first stage pressure.

Because an increase in the main turbine bypass flow can affect this function nonconservatively (THERMAL POWER is derived from first stage pressure) the main turbine bypass valves must not cause the trip Functions to be bypassed when thermal power is > 26% RTP.Four channels of TCV Fast Closure, Trip Oil Pressure-Low, with two channels in each trip system, are available and required to be OPERABLE to ensure that no single instrument failure will preclude an EOC-RPT from this Function on a valid signal. The TCV Fast Closure, Trip Oil Pressure-Low Allowable Value is selected high enough to detect imminent TCV fast closure.This protection is required consistent with the safety analysis whenever THERMAL POWER is _ 26% RTP. Below 26% RTP, the Reactor Vessel Steam Dome Pressure-High and the APRM Fixed Neutron Flux-High Functions of the RPS are adequate to maintain the necessary safety margins.ACTIONS A Note has been provided to modify the ACTIONS related to EOC-RPT instrumentation channels.

Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition.

Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition.

However, the Required Actions for (continued)

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-UNIT 1 B 3.3-85 Revision 1 PPL Rev. 2 EOC-RPT Instrumentation B 3.3.4.1 BASES ACTIONS inoperable EOC-RPT instrumentation channels provide appropriate (continued) compensatory measures for separate inoperable channels.

As such, a Note has been provided that allows separate Condition entry for each inoperable EOC-RPT instrumentation channel.A.1. A.2, and A.3 With one or more channels inoperable, but with EOC-RPT trip capability maintained (refer to Required Actions B.1 and B.2 Bases), the EOC-RPT System is capable of perf6rming the intended function.

However, the reliability and redundancy of the EOC-RPT instrumentation is reduced" such that a single failure in the remaining trip system could result in the inability of the EOC-RPT System to perform the intended function.Therefore, only a limited time is allowed to restore compliance with the LCO. Because of the diversity of sensors available to provide trip signals, the low probability of extensive numbers of inoperabilities affecting all diverse Functions, and the low probability of an event requiring the initiation of an EOC-RPT, 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> is provided to restore the inoperable channels (Required Action A.1). Alternately, the inoperable channels may be placed in trip (Required Action A.2) or Required Action A.3 MCPR Limits for inoperable EOC-RPT can be applied since these would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue.

As noted, placing the channel in trip with no further restrictions is not allowed if the inoperable channel is the result of an inoperable breaker, since this may not adequately compensate for the inoperable breaker (e.g., the breaker may be inoperable such that it will not open). If it is not desired to place the channel in trip (e.g., as in the case where placing the inoperable channel in trip would result in an RPT, or if the inoperable channel is the result of an inoperable breaker), Condition C must be entered and its Required Actions taken.B.1 and B.2 Required Actions B. 1 and B.2 are intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same Function result in the Function not maintaining EOC-RPT trip capability.

A Function is considered to be maintaining EOC-RPT trip (continued)

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-UNIT 1 B 3.3-86 Revision 0 PPL Rev. 2 EOC-RPT Instrumentation B 3.3.4.1 BASES ACTIONS B.1 and B.2 (continued) capability when sufficient channels are OPERABLE or in trip, such that the EOC-RPT System will generate a trip signal from the given Function on a valid signal and both recirculation pumps can be tripped. This requires two channels of the Function in the same trip system, to each be OPERABLE or in trip, and the associated RPT breakers to be OPERABLE or in trip. Alternately, Required Action B.2 requires the MCPR limit for inoperable EOC-RPT, as specified in the COLR, to be applied. This also restores the margin to MCPR assumed in the safety analysis.The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time is sufficient time for the operator to. take corrective action, and takes into account the likelihood of an event requiring actuation of the EOC-RPT instrumentation during this period. It is also consistent with the 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time provided in LCO 3.2.2 for Required Action A. 1, since this instrumentation's purpose is to preclude a MCPR violation.

C.1 and C.2 With any Required Action and associated Completion Time not met, THERMAL POWER must be reduced to < 26% RTP within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.Alternately; the associated recirculation pump may be removed from service, since this performs the intended function of the instrumentation.

The allowed Completion Time of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> is reasonable, based on operating experience, to reduce THERMAL POWER to < 26% RTP from full power conditions in an orderly manner and without challenging plant systems.SURVEILLANCE REQUIREMENTS The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided the associated Function maintains EOC-RPT trip capability.

Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Ref. 4)assumption of the average (continued)

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-UNIT 1 B 3.3-87 Revision 1 PPL Rev. 2 EOC-RPT Instrumentation B 3.3.4.1 BASES SURVEILLANCE time required to perform channel Surveillance.

That analysis REQUIREMENTS demonstrated that the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> testing allowance does not significantly (continued) reduce the probability that the recirculation pumps will trip when necessary.

SR 3.3.4.1.1 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function, This SR is modified by a Note that provides.

a general exception to the definition of CHANNEL FUNCTIONAL TEST. This exception is necessary because the design of instrumentation does not facilitate functional testing of all required contacts of the relay which input into the combinational logic. (Reference

7) Performance of such a test could result in a plant transient or place the plant in an undo risk situation.

Therefore, for this SR, the CHANNEL FUNCTIONAL TEST verifies acceptable response by verifying the change of state of the relay which inputs into the combinational logic. The required contacts not tested during the CHANNEL FUNCTIONAL TEST are tested under the LOGIC SYSTEM FUNCTIONAL TEST, SR 3.3.4.1.3.

This is acceptable because operating experience shows that the contacts not tested during the CHANNEL FUNCTIONAL TEST normally pass the LOGIC SYSTEM FUNCTIONAL TEST, and the testing methodology minimizes the risk of unplanned transients.

The Frequency of 92 days is based on reliability analysis of Reference 5.SR 3.3.4.1.2 CHANNEL CALIBRATION verifies that the channel responds to the measured parameter within the necessary range and accuracy.CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.(continued)

SUSQUEHANNA-UNIT 1 B 3.3-88 Revision 0 PPL Rev. 2 EOC-RPT Instrumentation B 3.3.4.1 BASES SURVEILLANCE URVEQUIR NENS SR 3.3.4.1.2 (continued)

REQUIREMENTS The Frequency is based upon the assumption of an 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.SR 3.3.4.1.3 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required trip logic, for a specific channel. The system functional test of the pump breakers is included as a part of this test, overlapping the LOGIC SYSTEM FUNCTIONAL TEST, to provide complete testing of the associated safety function.

Therefore, if a breaker is incapable of operating, the associated instrument channel(s) would also be inoperable.

The 24 month Frequency is based on the need to perform portions of this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.Operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency.

SR 3.3.4.1.4 This SR ensures that an EOC-RPT initiated from the TSV-Closure and TCV Fast Closure, Trip Oil Pressure-Low Functions will not be inadvertently bypassed when THERMAL POWER is _> 26% RTP. This is performed by a Functional check that ensures the EOC-RPT Function is not bypassed.

Because increasing the main turbine bypass flow can affect this function nonconservatively (THERMAL POWER is derived from first stage pressure) the main turbine bypass valves must not cause the trip Functions to be bypassed when thermal power is > 26% RTP. If any functions are bypassed at >_ 26% RTP, either due to open main turbine bypass valves or other reasons, the affected TSVL--Closure and TCV Fast Closure, Trip Oil Pressure-Low Functions are considered inoperable.

Alternatively, the bypass channel can be placed in the conservative condition (nonbypass).

If placed in the nonbypass condition, this SR is met with the channel considered OPERABLE.(continued)

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-UNIT 1 B 3.3-89 Revision 1 PPL Rev. 2 EOC-RPT Instrumentation B 3.3.4.1 BASES SURVEILLANCE SR 3.3.4.1.4 (continued)

REQUIREMENTS The Frequency of 24 months has shown that channel bypass failures between successive tests are rare.SR 3.3.4.1.5 This SR ensures that the individual channel response times are less than or equal to the maximum values assumed in the accident analysis.

The EOC-RPT SYSTEM RESPONSE TIME acceptance criteria are included in Reference 5.A Note to the Surveillance states that breaker interruption time may be assumed from the most recent performance of SR 3.3.4.1.6.

This is allowed since the time to open the contacts after energization of the trip coil and the arc suppression time are short and do not appreciably change, due to the design of the breaker opening device and the fact that the breaker is not routinely cycled.EOC-RPT SYSTEM RESPONSE TIME tests are conducted on an 24 month STAGGERED TEST BASIS. For this SR, STAGGERED TEST BASIS means that each 24 month test shall include at least the logic of one type of channel input, turbine control valve fast closure or turbine stop valve closure such that both types of channel inputs are tested at least one per 48 months. Response times cannot be determined at power because operation of final actuated devices is required.

Therefore, the 24 month Frequency is consistent with the typical industry refueling cycle and is based upon plant operating experience, which shows that random failures of instrumentation components that cause serious response time degradation, but not channel failure, are infrequent occurrences.

SR 3.3.4.1.6 This SR ensures that the RPT breaker interruption time (arc suppression time plus time to open the contacts) is provided to the EOC-RPT SYSTEM RESPONSE TIME test. The 60 month Frequency of the testing is based on the difficulty of performing the test and the reliability of the circuit breakers.(continued)

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-UNIT 1 TS / B 3.3-90 Revision 1 PPL Rev. 2 EOC-RPT Instrumentation B 3.3.4.1 BASES REFERENCES

1. FSAR, Figure 7.2-1-4 (EOC-RPT logic diagram).2. FSAR, Sections 15.2 and 15.3.3. FSAR, Sections 7.1 and 7.6.4. GENE-770-06-1, "Bases For Changes To Surveillance Test Intervals And Allowed Out-Of-Service Times For Selected Instrumentation Technical Specifications," February 1991.5. FSAR Table 7.6-10.6. Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 32193).7. NRC Inspection and Enforcement Manual, Part 9900: Technical Guidance, Standard Technical Specification Section 1.0 Definitions, Issue date 12/08/86.SUSQUEHANNA

-UNIT 1 B 3.3-91 Revision 0 PPL Rev. 6 Primary Containment Isolation Instrumentation B 3.3.6.1 B 3.3 INSTRUMENTATION B 3.3.6.1 Primary Containment Isolation Instrumentation BASES BACKGROUND The primary containment isolation instrumentation automatically initiates closure of appropriate primary containment isolation valves (PCIVs). The function of the PCIVs, in combination with other accident mitigation systems, is to limit fission product release during and following postulated Design Basis Accidents (DBAs). Primary containment isolation within the time limits specified for those isolation valves designed to close automatically ensures that the release of radioactive material to the environment will be consistent with the assumptions used in the analyses for a DBA.The isolation instrumentation includes the sensors, relays, and instruments that are necessary to cause initiation of primary containment and reactor coolant pressure boundary (RCPB) isolation.

When the setpoint is reached, the sensor actuates, which then outputs an isolation signal to the isolation logic. Functional diversity is provided by monitoring a wide range of independent parameters.

The input parameters to the isolation logics are (a) reactor vessel water level, (b) area ambient and emergency cooler temperatures, (c) main steam line (MSL) flow measurement, (d) Standby Liquid Control (SLC) System initiation, (e) condenser vacuum, (f) main steam line pressure, (g) high pressure coolant injection (HPCI) and reactor core isolation cooling (RCIC) steam line A pressure, (h) SGTS Exhaust radiation, (i) HPCI and RCIC steam line pressure, (j) HPCI and RCIC turbine exhaust diaphragm pressure, (k) reactor water cleanup (RWCU) differential flow and high flow, (I) reactor steam dome pressure, and (m) drywell pressure.

Redundant sensor input signals from each parameter are provided for initiation of isolation.

The only exception is SLC System initiation.

In addition, manual isolation of the logics is provided.Primary containment isolation instrumentation has inputs to the trip logic of the isolation functions listed below.(continued)

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-UNIT 1 TS / B 3.3-147 Revision 0 PPL Rev. 6 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES BACKGROUND

1. Main Steam Line Isolation (continued)

Most MSL Isolation Functions receive inputs from four channels.

The outputs from these channels are combined in a one-out-of-two taken twice logic to initiate isolation of all main steam isolation valves (MSIVs).The outputs from the same channels are arranged into two two-out-of-two logic trip systems to isolate all MSL drain valves. The MSL drain line has two isolation valves with one two-out-of-two logic system associated with each valve.The exceptions to this arrangement are the Main Steam Line Flow-High Function.

The Main Steam Line Flow-High Function uses 16 flow channels, four for each steam line. One channel from each steam line inputs to one of the four trip strings. Two trip strings make up each trip system and both trip systems must trip to cause an MSL isolation.

Each trip string has four inputs (one per MSL), any one of which will trip the trip string. The trip strings are arranged in a one-out-of-two taken twice logic. This is effectively a one-out-of-eight taken twice logic arrangement to initiate isolation of the MSIVs. Similarly, the 16 flow channels are connected into two two-out-of-two logic trip systems (dffectively, two one-out-of-four twice logic), with each trip system isolating one of the two MSL drain valves.2. Primary Containment Isolation Most Primary Containment Isolation Functions receive inputs from four channels.

The outputs from these channels are arranged into two two-out-of-two logic trip systems. One trip system initiates isolation of all inboard primary containment isolation valves, while the other trip system initiates isolation of all outboard primary containment isolation valves.Each logic closes one of the two valves on each penetration, so that operation of either logic isolates the penetration.

The exceptions to this arrangement are as follows. Hydrogen and Oxygen Analyzers which isolate Division I Analyzer on a Division I isolation signal, and Division II Analyzer on a Division II isolation signal.This is to ensure monitoring capability is not lost. Chilled Water to recirculation pumps and Liquid Radwaste Collection System isolation valves (continued)

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-UNIT 1 TS / B 3.3-1.48 Revision 0 PPL Rev. 6 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES BACKGROUND

2. Primary Containment Isolation (continued) where both inboard and outboard valves will isolate on either division providing the isolation signal. Traversing incore probe ball valves and the instrument gas to the drywell to suppression chamber vacuum breakers only have one isolation valve and receives a signal from only one division.3., 4. Higqh Pressure Coolant Iniection System Isolation and Reactor Core Isolation Coolingq System Isolation Most Functions that isolate HPCI and RCIC receive input from two channels, with each channel in one trip system using a one-out-of-one logic. Each of the two trip systems in each isolation group is connected to one of the two valves on each associated penetration.

The exceptions are the HPCI and RCIC Turbine Exhaust Diaphragm Pressure-High and Steam Supply Line Pressure-Low Functions.

These Functions receive inputs from four turbine exhaust diaphragm pressure and four steam supply pressure channels for each system. The outputs from the turbine exhaust diaphragm pressure and steam supply pressure channels are each connected to two two-out-of-two trip systems. Each trip system isolates one valve per associated penetration.

5. Reactor Water Cleanup System Isolation The Reactor Vessel Water Level-Low Low, Level 2 Isolation Function receives input from four reactor vessel water level channels.

The outputs from the reactor vessel water level channels are connected into two two-out-of-two trip systems. The Differential Flow-High, Flow-High, and SLC System Initiation Functions receive input from two channels, with each channel in one trip system using a one-out-of-one logic. The temperature isolations are divided into three Functions.

These Functions are Pump Area, Penetration Area, and Heat Exchanger Area.Each area is monitored by two temperature monitors, one for each trip system. These are configured so that any one input will trip the associated trip system. Each of the two trip systems is connected to one of the two valves on each RWCU penetration.(continued)

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-UNIT 1 TS / B 3.3-149 Revision 0 PPL Rev. 6 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES BACKGROUND

6. Shutdown Cooling System Isolation (continued)

The Reactor Vessel Water Level-Low, Level 3 Function receives input from four reactor vessel water level channels.

The outputs from the reactor vessel water level channels are connected to two two-out-of-two trip systems. The Reactor Vessel Pressure-High Function receives input from two channels, with each channel in one trip system using a one-out-of-one logic. Each of the two trip systems is connected to one of the two valves on each shutdown cooling penetration.

7. Traversing Incore Probe System Isolation The Reactor Vessel Water Level-Low, Level 3 Isolation Function receives input from two reactor vessel water level channels.

The Drywell Pressure-High Isolation Function receives input from two drywell pressure channels.

The outputs from the reactor vessel water level channels and drywell pressure channels are connected into one two-out-of-two logic trip system.When either Isolation Function actuates, the TIP drive mechanisms will withdraw the TIPs, if inserted, and close the inboard TIP System isolation ball valves when the proximity probe senses the TIPs are withdrawn into the shield. The TIP System isolation ball valves are only open when the TIP System is in use. The outboard TIP System isolation valves are manual shear valves.APPLICABLE The isolation signals generated by the primary containment isolation SAFETY instrumentation are implicitly assumed in the safety analyses of ANALYSES, References 1 and 2 to initiate closure of valves to limit offsite doses.LCO, and Refer to LCO 3.6.1.3, "Primary Containment Isolation Valves (PCIVs)," APPLICABILITY Applicable Safety Analyses Bases for more detail of the safety analyses.Primary containment isolation instrumentation satisfies Criterion 3 of the NRC Policy Statement. (Ref. 8) Certain instrumentation Functions are retained for other reasons and are described below in the individual Functions discussion.(continued)

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-UNIT 1 TS / B 3.3-150 Revision 1 PPL Rev. 6 Primary Containment Isolation Instrumentation B '3.3.6.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

The OPERABILITY of the primary containment instrumentation is dependent on the OPERABILITY of the individual instrumentation channel Functions specified in Table 3.3.6.1-1.

Each Function must have a required number of OPERABLE channels, with their setpoints within the specified Allowable Values, where appropriate.

A channel is inoperable if its actual trip setpoint is not within its required Allowable Value. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions.

Each channel must also respond within its assumed response time, where appropriate.

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

The nominal setpoints are selected to ensure thatfthe setpoints do not exceed the Allowable Value between.CHANNEL CALIBRATIONS.

Operation with a trip setpoint less conservative than the nominal trip setpoint, but within its Allowable Value, is acceptable.

Trip setpoints are those predetermined values of output at'which an action should take place. The setpoints are compared to the actual process parameter (e.g., reactor vessel water level), and when the measured output value of the process parameter reaches the setpoint, the associated device changes state. The analytic limits are derived from the limiting values of the process parameters obtained from the safety analysis.

The Allowable Values are derived from the analytic limits, corrected for calibration, process, and some of the instrument errors. The trip setpoints are then determined accounting for the remaining instrument errors (e.g., drift). The trip setpoints derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, instrument drift, and severe environment errors (for channels that must function in harsh environments as defined by 10 CFR 50.49) are accounted for.In general, the individual Functions are required to be OPERABLE in MODES 1, 2, and 3 consistent with the Applicability for LCO 3.6.1.1,"Primary Containment." Functions that have different Applicabilities are discussed below in the individual Functions discussion.

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

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-UNIT 1 TS / B 3.3-151 Revision 1 PPL Rev. 6 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE The penetrations which are isolated by the below listed functions can be SAFETY determined by referring to the PCIV Table found in the Bases of LCO ANALYSES, 3.6.1.3, "Primary Containment Isolation Valves." LCO, and APPLICABILITY Main Steam Line Isolation (continued) 1.a. Reactor Vessel Water Level-Low Low Low, Level 1 Low reactor pressure vessel (RPV) water level indicates that the capability to cool the fuel may be threatened.

Should RPV water level decrease too far, fuel damage could result. Therefore, isolation of the MSIVs and other interfaces with the reactor vessel occurs to prevent offsite dose limits from being exceeded.

The Reactor Vessel Water Level-Low Low Low, Level 1 Function is one of the many Functions assumed to be OPERABLE and capable of providing isolation signals. The Reactor Vessel Water Level-Low Low Low, Level I Function associated with isolation is assumed in the analysis of the recirculation line break (Ref. 1). The isolation of the MSLs on Level 1 supports actions to ensure that offsite dose limits are not exceeded for a DBA.Reactor vessel water level signals are initiated from four level instruments that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels of Reactor Vessel Water Level-Low Low Low, Level 1 Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.The Reactor Vessel Water Level-Low Low Low, Level 1 Allowable Value is chosen to be the same as the ECCS Level 1 Allowable Value (LCO 3.3.5.1) to ensure that the MSLs isolate on a potential loss of coolant accident (LOCA) to prevent offsite and control room doses from exceeding regulatory limits.(continued)

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-UNIT 1 TS / B 3.3-152 Revision 2 PPL Rev. 6 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) 1.b. Main Steam Line Pressure-Low Low MSL pressure indicates that there may be a problem with the turbine pressure regulation, which could result in a low reactor vessel water level condition and the RPV cooling down more than 100°F/hr if the pressure loss is allowed to continue.

The Main Steam Line Pressure-Low Function is directly assumed in the analysis of the pressure regulator failure (Ref. 2). For this event, the closure of the MSIVs ensures that the RPV temperature change limit (1O 0°F/hr) is not reached. In addition, this Function supports actions to ensure that Safety Limit 2.1.1.1 is not exceeded. (This Function closes the MSIVs prior to pressure decreasing below 785 psig, which results in a scram due to MSIV closure, thus reducing reactor power to < 23% RTP.)The MSL low pressure signals are initiated from four instruments that are connected to the MSL header. The instruments are arranged such that, even though physically separated from each other, each instrument is able to detect low MSL pressure.

Four channels of Main Steam Line Pressure-Low Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.The Main Steam Line Pressure-Low trip will only occur after a 500 milli-second time delay to prevent any spurious isolations.

The Allowable Value was selected to be high enough to prevent excessive RPV depressurization.

The Main Steam Line Pressure-Low Function is only required to be OPERABLE in MODE 1 since this is when the assumed transient can occur (Ref. 2).1.c. Main Steam Line Flow-Hiah Main Steam Line Flow-High is provided to detect a break of the MSL and to initiate closure of the MSIVs. If the steam were allowed to continue flowing out of the break, the reactor would depressurize and the core could uncover. If the RPV water level decreases too far, fuel damage could occur. Therefore, the isolation is initiated on high flow to prevent or minimize core damage. The Maih Steam Line Flow-High Function is (continued)

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-UNIT 1 TS / B 3.3-153 Revision 2 PPL Rev. 6 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 1.c. Main Steam Line Flow-High (continued)

SAFETY ANALYSES, directly assumed in the analysis of the main steam line break (MSLB)LCO, and (Ref. 1). The isolation action, along with the scram function of the APPLICABILITY Reactor Protection System (RPS), ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46 and offsite and control room doses do not exceed regulatory limits.The MSL flow signals are initiated from 16 instruments that are connected to the four MSLs. The instruments are arranged such that, even though physically separated from each other, all four connected to one MSL would be able to detect the high flow. Four channels of Main Steam Line Flow-High Function for each unisolated MSL (two channels per trip system) are available and are required to be OPERABLE so that no single instrument failure will preclude detecting a break in any individual MSL.1.d. Condenser Vacuum-Low The Allowable Value is chosen to ensure that offsite dose limits are not exceeded due to the break.The Condenser Vacuum-Low Function is provided to prevent overpressurization of the main condenser in the event of a loss of the main condenser vacuum. Since the integrity of the condenser is an assumption in offsite dose calculations, the Condenser Vacuum-Low Function is assumed to be OPERABLE and capable of initiating closure of the MSIVs. The closure of the MSIVs is initiated to prevent the addition of steam that would lead to additional condenser pressurization and possible rupture of the diaphragm installed to protect the turbine exhaust hood, thereby preventing a potential radiation leakage path following an accident.Condenser vacuum pressure signals are derived from four pressure instruments that sense the pressure in the condenser.

Four channels of Condenser Vacuum-Low Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.(continued)

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-UNIT 1 TS / B 3.3-154 Revision 2 PPL Rev. 6 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY 1.d. Condenser Vacuum-Low (continued)

The Allowable Value is chosen to prevent damage to the condenser due to pressurization, thereby ensuring its integrity for offsite dose analysis.As noted (footnote (a) to Table 3.3.6.1-1), the channels are not required to be OPERABLE in MODES 2 and 3 when all main turbine stop valves (TSVs) are closed, since the potential for condenser overpressurization is minimized.

Switches are provided to manually bypass the channels when all TSVs are closed.i.e. Reactor Building Main Steam Tunnel Temperature-High Reactor Building Main Steam Tunnel temperature is provided to detect a leak in the RCPB and provides diversity to the high flow~instrumentation.

The isolation occurs when a very small leak has occurred.

If the small leak is allowed to continue without isolation, offsite dose limits may be reached. However, credit for these instruments is not taken in any transient or accident analysis in the FSAR, since bounding analyses are performed for large breaks, such as MSLBs.Area temperature signals are initiated from thermocouples located in the area being monitored.

Four channels of Reactor Building Main Steam Tunnel Temperature-High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.The reactor building main steam tunnel temperature trip will only occur after a one second time delay.The temperature monitoring Allowable Value is chosen to detect a leak equivalent to approximately 25 gpm of water.1.f. Manual Initiation The Manual Initiation push button channels introduce signals into the MSL isolation logic that are redundant to the automatic protective instrumentation and provide manual isolation capability.

There is no specific FSAR safety analysis that takes credit for this Function.

It is retained for the overall redundancy and diversity of the isolation function as required by the NRC in the plant licensing basis.(continued)

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-UNIT 1 TS / B 3.3-155 Revision 1 PPL Rev. 6 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 1.f. Manual Initiation (continued)

SAFETY ANALYSES, There are four push buttons for the logic, two, manual initiation push LCO, and button per trip system. There is no Allowable Value for this Function APPLICABILITY since the channels are mechanically actuated based solely on the position of the push buttons.Two channels of Manual Initiation Function are available and are required to be OPERABLE in MODES 1, 2, and 3, since these are the MODES in which the MSL isolation automatic Functions are required to be OPERABLE.Primary Containment Isolation 2.a. Reactor Vessel Water Level -Low, Level 3 Low RPV water level indicates that the capability to cool the fuel may be threatened.

The valves whose penetrations communicate with the primary containment are isolated to limit the release of fission products.The isolation of the primary containment on Level 3 supports actions to ensure that offsite and control room dose regulatory limits are not exceeded.

The Reactor Vessel Water Level-Low, Level 3 Function associated with isolation is implicitly assumed in the FSAR analysis as these leakage paths are assumed to be isolated post LOCA.Reactor Vessel Water Level-Low, Level 3 signals are initiated from level instruments that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels of Reactor Vessel Water Level-Low, Level 3 Function are available and are required to be OPERABLE to ensure that no single instrument failure.can preclude the isolation function.The Reactor Vessel Water Level-Low, Level 3 Allowable Value was chosen to be the same as the RPS Level 3 scram Allowable Value (LCO 3.3.1.1), since isolation of these valves is not critical to orderly plant shutdown.(continued)

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-UNIT 1 TS / B 3.3-156 Revision 2 PPL Rev. 6 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) 2.b. Reactor Vessel Water Level-Low Low, Level 2 Low RPV water level indicates that the capability to cool the fuel may be threatened.

The valves whose penetrations communicate with the primary containment are isolated to limit the release of fission products.The isolation of the primary containment on Level 2 supports actions to ensure that offsite and control room dose regulatory limits are not exceeded.

The Reactor Vessel Water Level-Low Low, Level.;2 Function associated with isolation is implicitly assumed in the FSAR analysis as these leakage paths are assumed to be isolated post LOCA.Reactor Vessel Water Level-Low Low, Level 2 signals are initiated from level instruments that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level .(variable leg) in the vessel. Four channels of Reactor Vessel Water Level-Low Low, Level 2 Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.The Reactor Vessel Water Level-Low Low, Level 2 Allowable Value was chosen to be the same as the ECCS Level 2 Allowable Value (LCO 3.3.5.1), since this may be indicative of a LOCA.2.c. Reactor Vessel Water Level-Low Low Low, Level 1 Low reactor pressure vessel (RPV) water level indicates that the capability to cool the fuel may be threatened.

Should RPV water level decrease too far, fuel damage could result. The valves whose penetrations communicate with the primary containment are isolated to limit the release of fission products.

The isolation of the primary containment on Level 1 supports actions to ensure the offsite and control room dose regulatory limits are not exceeded.

The Reactor Vessel Water Level -Low Low Low, Level 1 Function associated with isolation is implicitly assumed in the FSAR analysis as these leakage paths are assumed to be isolated post LOCA.(continued)

SUSQUEHANNA

-UNIT 1 TS / B 3.3-157 Revision 2 PPL Rev. 6 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY 2.c. Reactor Vessel Water Level-Low Low Low, Level 1 (continued)

Reactor vessel water level signals are initiated from four level instruments that sense the difference between the pressure due to a.constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels of Reactor Vessel Water Level-Low Low Low, Level 1 Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.The Reactor Vessel Water Level-Low Low Low, Level 1 Allowable Value is chosen to be the same as the ECCS Level 1 Allowable Value (LCO 3.3.5.1) to ensure that the associated penetrations isolate on a potential loss of coolant accident (LOCA) to prevent offsite and control room doses from exceeding regulatory limits.2.d. Drywell Pressure-HiQh High drywell pressure can indicate a break in the RCPB inside the primary containment.

The isolation of some of the primary containment isolation valves on high drywell pressure supports actions to ensure that offsite and control room dose regulatory limits are not exceeded.

The Drywell Pressure-High Function, associated with isolation of the primary containment, is implicitly assumed in the FSAR accident analysis as these leakage paths are assumed to be isolated post LOCA.High drywell pressure signals are initiated from pressure instruments that sense the pressure in the drywell. Four channels of Drywell Pressure-High per Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.The Allowable Value was selected to be the same as the ECCS Drywell Pressure-High Allowable Value (LCO 3.3.5.1), since this may be indicative of a LOCA inside primary containment.(continued)

SUSQUEHANNA

-UNIT 1 TS / B 3.3-158 Revision 2 PPL Rev. 6 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) 2.e. SGTS Exhaust Radiation-High High SGTS Exhaust radiation indicates possible gross failure of the fuel cladding.

Therefore, when SGTS Exhaust Radiation High is detected, an isolation is initiated to limit the release of fission products.

However, this Function is not assumed in any accident or transient analysis in the FSAR because other leakage paths (e.g., MSIVs) are more limiting.The SGTS Exhaust radiation signals are initiated from radiation detectors that are located in the SGTS Exhaust. Two channels of SGTS Exhaust Radiation-High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.The Allowable Value is low enough to promptly detect gross failures in the fuel cladding.2.f. Manual Initiation The Manual Initiation push button channels introduce signals into the primary containment isolation logic that are redundant to the automatic protective instrumentation and provide manual isolation capability.

There is no specific FSAR safety analysis that takes credit for this Function.

It is retained for overall redundancy and diversity of the isolation function as required by the NRC in the plant licensing basis.There are two push buttons for the logic, one manual initiation push button per trip system. There is no Allowable Value for this Function since the channels are mechanically actuated based solely on the position of the push buttons.Two channels of the Manual Initiation Function are available and are required to be OPERABLE in MODES 1, 2, and 3, since these are the MODES in which the Primary Containment Isolation automatic Functions are required to be OPERABLE.(continued)

SUSQUEHANNA

-UNIT 1 TS / B 3.3-159 Revision 1 PPL Rev. 6 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

High Pressure Coolant Iniection and Reactor Core Isolation Cooling Systems Isolation 3.a.. 4.a. HPCI and RCIC Steam Line A Pressure-High Steam Line A Pressure High Functions are. provided to detect a break of the RCIC or HPCI steam lines and initiate closure of the steam line isolation valves of the appropriate system. If the steam is allowed to continue flowing out of the break, the reactor will depressurize and the core can uncover. Therefore, the isolations are initiated on high flow to prevent or minimize core damage. The isolation action, along with the scram function of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46. Specific credit for these Functions is not assumed in any FSAR accident analyses since the bounding analysis is performed for large breaks such as recirculation and MSL breaks. However, these instruments prevent the RCIC or HPCI steam line breaks from becoming bounding.The HPCI and RCIC Steam Line A Pressure -High signals are initiated from instruments (two for HPCI and two for RCIC) that are connected to the system steam lines. Two channels of both HPCI and RCIC Steam Line A pressure-High Functions are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.The steam line A Pressure -High will only occur after a 3 second time delay to prevent any spurious isolations.

The Allowable Values are chosen to be low enough to ensure that the trip occurs to prevent fuel damage and maintains the MSLB event as the bounding event, and high enough to be above the maximum transient steam flow during system startup.(continued)

SUSQUEHANNA

-UNIT 1 TS / B 3.3-160 Revision 1 PPL Rev. 6 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) 3.b., 4.b. HPCI and RCIC Steam Supply Line Pressure-Low Low MSL pressure indicates that the pressure of the steam in the HPCI or RCIC turbine may be too low to continue operation of the associated system's turbine. These isolations are for equipment protection and are not assumed in any transient or accident analysis in the FSAR.However, they also provide a diverse signal to indicate a possible system break. These instruments are included in Technical Specifications (TS) because of the potential for risk due to possible failure of the instruments preventing HPCI and RCIC initiations (Ref. 3).The HPCI and RCIC Steam Supply Line Pressure-Low signals are initiated from instruments (four for HPCI and four for RCIC) that are connected to the system steam line. Four channels of both HPCI and RCIC Steam Supply Line Pressure-Low Functions are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.The Allowable Values are selected to be high enough to prevent damage to the system's turbine.3.c.. 4.c. HPCI and RCIC Turbine Exhaust Diaphraqm Pressure-Hiqh High turbine exhaust diaphragm pressure indicates that a release of steam into the associated compartment is possible.

That is, one of two exhaust diaphragms has ruptured.

These isolations are to prevent steam from entering the associated compartment and are not assumed in any transient or accident analysis in the FSAR. These instruments are included in the TS because of the potential for risk due to possible failure of the instruments preventing HPCI and RCIC initiations (Ref. 3).The HPCI and RCIC Turbine Exhaust Diaphram Pressure-High signals and initiated from instruments (four for HPCI and four for RCIC) that are connected to the area between the rupture diaphragms on each system's turbine exhaust line. Four channels of both HPCI and RCIC Turbine Exhaust Diaphragm Pressure-High Functions are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.(continued)

SUSQUEHANNA-UNIT 1 TS / B 3.3-161 Revision 2 PPL Rev. 6 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY.

3.c., 4.c. HPCI and RCIC Turbine Exhaust Diaphragqm Pressure-High (continued)

The Allowable Values is low enough to identify a high turbine exhaust pressure condition resulting from a diaphragm rupture, or a leak in the diaphragm adjacent to the exhaust line and high enough to prevent inadvertent system isolation.

3.d., 4.d. Drvwell Pressure-Hiqh High drywell pressure can indicate a break in the RCPB. The HPCI and RCIC isolation of the turbine exhaust vacuum breaker line is provided to prevent communication with the wetwell when high drywell pressure exists. A potential leakage path exists via the turbine exhaust. The isolation is delayed until the system becomes unavailable for injection (i.e., low steam supply line pressure).

The isolation of the HPCI and RCIC turbine exhaust vacuum breaker line by Drywell Pressure-High is indirectly assumed in the FSAR accident analysis because the turbine exhaust vacuum breaker line leakage path is not assumed to contribute to offsite doses and is provided for long term containment isolation.

High drywell pressure signals are initiated from pressure instruments that sense the pressure in the drywell. Four channels of both HPCI and RCIC Drywell Pressure-High Functions are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.The Allowable Value was selected to be the same as the ECCS Drywell Pressure-High Allowable Value (LCO 3.3.5.1), since this is indicative of a LOCA inside primary containment.(continued)

SUSQUEHANNA

-UNIT 1 TS /B 3.3-162 Revision 1 PPL Rev. 6 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) 3.e., 3.f., 3..., 4.e., 4.f., 4.q., HPCI and RCIC Area and Emergency Cooler Temperature-High HPCI and RCIC Area and Emergency Cooler temperatures are provided to detect a leak from the associated system steam piping. The isolation occurs when a small leak has occurred and is diverse to the high flow instrumentation.

If the small leak is allowed to continue without isolation, offsite dose limits may be reached. These Functions are not assumed in any FSAR transient or accident analysis, since bounding analyses are performed for large breaks such as recirculation or MSL breaks.Area and Emergency Cooler Temperature-High signals are initiated from thermocouples that are appropriately located to protect the system that is being monitored.

Two Instruments monitor each area. Two channels for each HPCI and RCIC Area and Emergency Cooler Temperature-High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.The HPCI and RCIC Pipe Routing area temperature trips wilI.only Ioccur after a 15 minute time delay to prevent any spurious temperature isolations due to short temperature increases and allows operators sufficient time to determine which system is leaking. The other ambient temperature trips will only occur after a one second time delay to prevent any spurious temperature isolations.

The Allowable Values are set low enough to detect a leak equivalent to 25 gpm, and high enough to avoid trips at expected operating temperature.(continued)

SUSQUEHANNA

-UNIT 1 TS / B 3.3-163 Revision 2 PPL Rev. 6 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) 3.h., 4.h. Manual Initiation The Manual Initiation push button channels introduce signals into the HPCI and RCIC systems' isolation logics that are redundant to the automatic protective instrumentation and provide manual isolation capability.

There is no specific FSAR safety analysis that takes credit for these Functions.

They are retained for overall redundancy and diversity of the isolation function as required by the NRC in the plant licensing basis There is one manual initiation push button for each of the'HPCI and RCIC systems. One isolation pushbutton per system will introduce an isolation to one of the two trip systems. There is no Allowable Value for these Functions, since the channels are mechanically actuated based solely on the position of the push buttons.Two channels of both HPCI and RCIC Manual Initiation Functions are available and are required to be OPERABLE in MODES 1, 2, and 3 since these are the MODES in which the HPCI and RCIC systems'Isolation automatic Functions are required to be OPERABLE.Reactor Water Cleanup System Isolation 5.a. RWCU Differential Flow-Hiqh The high differential flow signal is provided to detect a break in the RWCU System. This will detect leaks in the RWCU System when area temperature would not provide detection (i.e., a cold leg break). Should the reactor coolant continue to flow out of the break, offsite dose limits may be exceeded.

Therefore, isolation of the RWCU System is initiated when high differential flow is sensed to prevent exceeding offsite doses.A 45 second time delay is provided to prevent spurious trips during most RWCU operational transients.

This Function is not assumed in any FSAR transient or accident analysis, since bounding analyses are performed for large breaks such as MSLBs.(continued)

SUSQUEHANNA

-UNIT 1 TS / B 3.3-164 Revision 1 PPL Rev. 6 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY 5.a. RWCU Differential Flow-High (continued)

The high differential flow signals are initiated from instruments that are connected to the inlet (from the recirculation suction) and outlets (to condenser and feedwater) of the RWCU System. Two channels of Differential Flow-High Function are available and are ,required to be OPERABLE to ensure that no single instrument failure downstream of the common summer can preclude the isolation function.The Differential Flow-High Allowable Value ensures that a break of the RWCU piping is detected.5.b. 5.c. 5.d RWCU Area TemDeratures-Hiah RWCU area temperatures are provided to detect a leak from the RWCU System. The isolation occurs even when small leaks have occurred and is diverse to the high differential flow instrumentation for the hot portions of the RWCU System. If the small leak continues without isolation, offsite dose limits may be reached. Credit for these instruments is not taken in any transient or accident analysis in the FSAR, since bounding analyses are performed for large breaks such as recirculation or MSL breaks.Area temperature signals are initiated from temperature elements that are located in the area that is being monitored.

Six thermocouples provide input to the Area Temperature-High Function (two per area). Six channels are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.The area temperature trip will only occur after a one second time to prevent any spurious temperature isolations.

The Area Temperature-High Allowable Values are set low enough to detect a leak equivalent to 25 gpm.(continued)

SUSQUEHANNA

-UNIT 1 TS / B 3.3-165 Revision 2 PPL Rev. 6 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 5.e. SLC System Initiation SAFETY ANALYSES, The isolation of the RWCU System is required when the SLC System LCO, and has been initiated to prevent dilution and removal of the boron solution APPLICABILITY by the RWCU System (Ref. 4). SLC System initiation signals are (continued) initiated from the two SLC pump start signals.There is no Allowable Value associated with this Function since the channels are mechanically actuated based solely on the position of the SLC System initiation switch.Two channels (one from each pump) of the SLC System Initiation Function are available and are required to be OPERABLE only in MODES 1, 2, and 3 which is consistent with the Applicability for the SLC System (LCO 3.1.7).As noted (footnote (b) to Table 3.3.6.1-1), this Function is only required to close the outboard RWCU isolation valve trip systems.5.f. Reactor Vessel Water Level-Low Low, Level 2 Low RPV water level indicates that the capability to cool the fuel may be threatened.

Should RPV water level decrease too far, fuel damage could result. Therefore, isolation of some interfaces with the reactor vessel occurs to isolate the potential sources of a break. The isolation of the RWCU System on Level 2 supports actions to ensure that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.The Reactor Vessel Water Level-Low Low, Level 2 Function associated with RWCU isolation is not directly assumed in the FSAR safety analyses because the RWCU System line break is bounded by breaks of larger systems (recirculation and MSL breaks are more limiting).

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

SUSQUEHANNA

-UNIT 1 TS / B 3.3-166 Revision 2 PPL Rev. 6 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 5.f. Reactor Vessel Water Level-Low Low, Level 2 (continued)

SAFETY ANALYSES, Reactor Vessel Water Level-Low Low, Level 2 Function are available LCO, and and are required to be OPERABLE to ensure that no single instrument APPLICABILITY failure can preclude the isolation function.The Reactor Vessel Water Level-Low Low, Level 2 Allowable Value was chosen to be the same as the ECCS Reactor Vessel Water Level-Low Low, Level 2 Allowable Value (LCO 3.3.5.1), since the capability to cool the fuel may be threatened.

5.g. RWCU Flow -High RWCU Flow-High Function is provided to detect a break of the RWCU System. Should the reactor coolant continue to flow out of the break, offsite dose limits may be exceeded.

Therefore, isolation is initiated on high flow to prevent or minimize core damage. The isolation action, along with the scram function of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.Specific credit for this Function is not assumed in any FSAR accident analyses since the bounding analysis is performed for large breaks such as recirculation and MSL breaks.The RWCU Flow-High signals are initiated from two instruments.

Two channels of RWCU Flow-High Functions are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.The RWCU flow trip will only occur after a 5 second time delay to prevent spurious trips.The Allowable Value is chosen to be low enough to ensure that the trip occurs to prevent fuel damage and maintains the MSLB event as the bounding event.5.h. Manual Initiation The Manual Initiation push button channels introduce signals into the RWCU System isolation logic that are redundant to (continued)

SUSQUEHANNA

-UNIT 1 TS / B 3.3-167 Revision 2 PPL Rev. 6 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 5.h. Manual Initiation (continued)

SAFETY ANALYSES, the automatic protective instrumentation and provide manual isolation LCO, and capability.

There is no specific FSAR safety analysis that takes credit APPLICABILITY for this Function.

It is retained for overall redundancy and diversity of the isolation function as required by the NRC in the plant licensing basis.There are two push buttons for the logic, one manual initiation push button per trip system. There is no Allowable Value for this Function, since the channels are mechanically actuated based solely on the position of the push buttons.Two channels of the Manual Initiation Function are available and are required to be OPERABLE in MODES 1, 2, and 3 since these are the MODES in which the RWCU System Isolation automatic Functions are required to be OPERABLE.Shutdown Cooling System Isolation 6.a. Reactor Steam Dome Pressure-High The Reactor Steam Dome Pressure-High Function is provided to isolate the shutdown cooling portion of the Residual Heat Removal (RHR) System. This interlock is provided only for equipment protection to prevent an intersystem LOCA scenario, and credit for the interlock is not assumed in the accident or transient analysis in the FSAR.The Reactor Steam Dome Pressure-High signals are initiated from two instruments.

Two channels of Reactor Steam Dome Pressure-High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

The Function is only required to be OPERABLE in MODES 1, 2, and 3, since these are the only MODES in which the reactor can be pressurized with the exception of Special Operations LCO 3.10.1; thus, equipment protection is needed. The Allowable Value was chosen to be low enough to protect the system equipment from overpressurization.(continued)

SUSQUEHANNA

-UNIT 1 TS / B 3.3-168 Revision 1 PPL Rev. 6 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) 6.b. Reactor Vessel Water Level-Low.

Level 3 Low RPV water level indicates that the capability to cool the fuel may be threatened.

Should RPV water level decrease too far, fuel damage could result. Therefore, isolation of some reactor vessel interfaces occurs to begin isolating the potential sources of a break. The Reactor Vessel Water Level-Low, Level 3 Function associated with RHR Shutdown Cooling System isolation is not directly assumed in safety analyses because a break of the RHR Shutdown Cooling System is bounded by breaks of the recirculation and MSL.The RHR Shutdown Cooling System isolation on Level 3 supports actions to ensure that the RPV water level does not drop below the top of the active fuel during a vessel draindown event caused by a leak (e.g., pipe break or inadvertent valve opening) in the RHR Shutdown Cooling System.Reactor Vessel Water Level-Low, Level 3 signals are initiated from four level instruments that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels (two channels per trip system) of the Reactor Vessel Water Level-Low, Level 3 Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

As noted (footnote (c) to Table 3.3.6.1-1), only two channels of the Reactor Vessel Water Level-Low, Level 3 Function are required to be OPERABLE in MODES 4 and 5 (and must input into the same trip system), provided the RHR Shutdown Cooling System integrity is maintained.

System integrity is maintained provided the piping is intact and no maintenance is being performed that has the potential for draining the reactor vessel through the system.The Reactor Vessel Water Level-Low, Level 3 Allowable Value was chosen to be the same as the RPS Reactor Vessel Water Level-Low, Level 3 Allowable Value (LCO 3.3.1.1), since the capability to cool the fuel may be threatened.

The Reactor Vessel Water Level-Low, Level 3 Function is only required to be OPERABLE in MODES 3, 4, and 5 to prevent this potential flow path from lowering the reactor vessel level to the top of the fuel.(continued)

SUSQUEHANNA

-UNIT 1 TS / B 3.3-169 Revision 1 PPL Rev. 6 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 6.b. Reactor Vessel Water Level-Low, Level 3 (continued)

SAFETY ANALYSES, In MODES 1 and 2, another isolation (i.e., Reactor Steam Dome LCO, and Pressure-High) and administrative controls ensure that this flow path APPLICABILITY remains isolated to prevent unexpected loss of inventory via this flow path.6.c Manual Initiation The Manual Initiation push button channels introduce signals to RHR Shutdown Cooling System isolation logic that is redundant to the automatic protective instrumentation and provide manual isolation capability.

There is no specific FSAR safety analysis that takes credit for this Function.

It is retained for overall redundancy and diversity of the isolation function as required by the NRC in the plant licensing basis.There are two push buttons for the logic, one manual initiation push button per trip system. There is no Allowable Value for this Function since the channels are mechanically actuated based solely on the position of the push buttons.Two channels of the Manual Initiation Function are available and are required to be OPERABLE in MODES 3, 4, and 5, since these are the MODES in which the RHR Shutdown Cooling System Isolation automatic Function are required to be OPERABLE.Traversing Incore Probe System Isolation 7.a Reactor Vessel Water Level -Low, Level 3 Low RPV water level indicates that the capability to cool the fuel may be threatened.

The valves whose penetrations communicate with the primary containment are isolated to limit the release of fission products.The isolation of the primary containment on Level 3 supports actions to ensure that offsite and control room dose regulatory limits are not exceeded.

The Reactor Vessel Water Level -Low, Level 3 Function associated with isolation is implicitly assumed in the FSAR analysis as these leakage paths are assumed to be isolated post LOCA.(continued)

SUSQUEHANNA

-UNIT 1 TS / B 3.3-170 Revision 2 PPL Rev. 6 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY 7.a Reactor Vessel Water Level -Low, Level 3 (continued)

Reactor Vessel Water Level -Low, Level 3 signals are initiated from level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Two channels of Reactor Vessel Water Level -Low, Level 3 Function are available and are required to be OPERABLE to ensure that no single instrument failure can initiate an inadvertent isolation actuation.

The isolation function is ensured by the manual shear valve in each penetration.

The Reactor Vessel Water Level -Low, Level 3 Allowable Value was chosen to be the same as the RPS Level 3 scram Allowable Value (LCO 3.3.1.1), since isolation of these valves is not critical to orderly plant shutdown.7.b. Drywell Pressure -High High drywell pressure can indicate a break in the RCPB inside the primary containment.

The isolation of some of the primary containment isolation valves on high drywell pressure supports actions to ensure that offsite and control room dose regulatory limits are not exceeded.

The Drywell Pressure -High Function, associated with isolation of the primary containment, is implicitly assumed in the FSAR accident analysis as these leakage paths are assumed to be isolated post LOCA.High drywell pressure signals are initiated from pressure transmitters that sense the pressure in the drywell. Two channels of Drywell Pressure -High per Function are available and are required to be OPERABLE to ensure that no single instrument failure can initiate an inadvertent actuation.

The isolation function is ensured by the manual shear valve in each penetration.

The Allowable Value was selected to be the same as the ECCS Drywell Pressure -High Allowable Value (LCO 3.3.5.1), since this may be indicative of a LOCA inside primary containment.(continued)

Revision 1 SUSQUEHANNA

-UNIT 1 TS / B 3.3-171 PPL Rev. 6 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES ACTIONS The ACTIONS are modified by two Notes. Note 1 allows penetration flow path(s) to be unisolated intermittently under administrative controls.These controls consist of stationing a dedicated operator at the controls of the valve, who is in continuous communication with the control room.In this way, the penetration can be rapidly isolated when a need for primary containment isolation is indicated.

Note 2 has been provided to modify the ACTIONS related to primary containment isolation instrumentation channels.

Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition.

Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition.

However, the Required Actions for inoperable primary containment isolation instrumentation channels provide appropriate compensatory measures for separate inoperable channels.

As such, a Note has been provided that allows separate Condition entry for each inoperable primary containment isolation instrumentation channel.A.1 Because of the diversity of sensors available to provide isolation signals and the redundancy of the isolation design, an allowable out of service-time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for Functions 2.a, 2.d, 6.b, 7.a, and 7.b and 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for Functions other than Functions 2.a, 2.d, 6.b, 7.a, and 7.b-has been shown to be acceptable (Refs. 5 and 6) to permit restoration of any inoperable channel to OPERABLE status. This out of service time is only acceptable provided the associated Function is still maintaining isolation capability (refer to Required Action B.1 Bases). If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per Required Action A.1. Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue with no further restrictions.

Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing the inoperable channel in trip would result in an isolation), Condition C must be entered and its Required Action taken.(continued)

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-UNIT 1 TS / B 3.3-172 Revision 1 PPL Rev. 6 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES ACTIONS B.1 and B.2 (continued)

Required Action B.1 is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same Function result in redundant automatic isolation capability being lost for the associated penetration flow path(s). The MSL Isolation Functions are considered to be maintaining isolation capability when sufficient channels are OPERABLE or in trip, such that both trip systems will generate a trip signal from the given Function on a valid signal. The other isolation functions are considered to be maintaining isolation capability when sufficient channels are OPERABLE or in trip, such that one trip system will generate a trip signal from the given Function on a valid signal. This ensures that one of the two PCIVs in the associated penetration flow path can receive an isolation signal from the given Function.

For Functions 1.a,l.b, 1.d, and 1.e, this would require both trip systems to have one channel OPERABLE or in trip. For Function 1 .c, this would require both trip systems to have one channel, associated with each MSL, OPERABLE or in trip. Therefore, this would require both trip systems to have one channel per location OPERABLE or in trip. For Functions 2.a, 2.b, 2.c, 2.d, 3.b, 3.c, 3.d, 4.b, 4.c, 4.d, 5.f, and 6.b, this would require one trip system to have two channels, each OPERABLE or in trip. For Functions 2.e, 3.a, 3.e, 3.f, 3.g, 4.a, 4.e, 4.f, 4.g, 5.a, 5.b, 5.c, 5.d, 5.e, 5.g, and 6.a, this would require one trip system to have one channel OPERABLE or in trip. The Condition does not include the Manual Initiation Functions (Functions 1.f, 2.f, 3.h, 4.h, 5.h, and 6.c), since they are not assumed in any accident or transient analysis.

Thus, a total loss of manual initiation capability for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (as allowed by Required Action A.1) is allowed.The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities.

The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Completion Time is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.(continued)

SUSQUEHANNA

-UNIT 1 TS / B 3.3-173 Revision 1 PPL Rev. 6 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES ACTIONS C. 1 (continued)

Required Action C.1 directs entry into the appropriate Condition referenced in Table 3.3.6.1-1.

The applicable Condition specified in Table 3.3.6.1-1 is Function and MODE or other specified condition dependent and may change as the Required Action of a previous Condition is completed.

Each time an inoperable channel has not met any Required Action of Condition A or B and the associated Completion Time has expired, Condition C will be entered for that channel and provides for transfer to the appropriate subsequent Condition.

D.1, D.2.1, and D.2.2 If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, the plant must be placed in a MODE or other specified condition in which the LCO does not apply.This is done by placing the plant in at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> (Required Actions D.2.1 and D.2.2).Alternately, the associated MSLs may be isolated (Required Action D.1), and, if allowed (i.e., plant safety analysis allows operation with an MSL isolated), operation with that MSL isolated may continue.

Isolating the affected MSL accomplishes the safety function of the inoperable channel. The 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.E.1 If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, the plant must be placed in a MODE or other specified condition in which the LCO does not apply.This is done by placing the plant in at least MODE 2 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.The allowed Completion Time of 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> is reasonable, based on operating experience, to reach MODE 2 from full power conditions in an orderly manner and without challenging plant systems.(continued)

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-UNIT 1 TS / B 3.3-174 Revision 1 PPL Rev. 6 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES ACTIONS F. 1 (continued)

If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, plant operations may continue if the affected penetration flow path(s) is isolated.

Isolating the affected penetration flow path(s) accomplishes the safety function of the inoperable channels.If it is not desired to isolate the affected penetration flow path(s) (e.g., as in the case where isolating the penetration flow path(s) could result in a reactor scram), Condition H must be entered and its Required Actions taken.The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Completion Time is acceptable because it minimizes risk while allowing sufficient time fof plant operations personnel to isolate the affected penetration flow path(s).G.1 If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, plant operations may continue if the affected penetration flow path(s) is isolated.

Isolating the affected penetration flow path(s) accomplishes the safety function of the inoperable channels.

The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Completion Time is acceptable due to the fact that these Functions are either not assumed in any accident or transient analysis in the FSAR (Manual Initiation) or, in the case of the TIP System isolation, the TIP System penetration is a small bore (0.280 inch), its isolation in a design basis event (with loss of offsite power)would be via the manually operated shear valves, and the ability to manually isolate by either the normal isolation valve or the shear valve is unaffected by the inoperable instrumentation.

It should be noted, however, that the TIP System is powered from an auxiliary instrumentation bus which has an uninterruptible power supply and hence, the TIP drive mechanisms and ball valve control will still function in the event of a loss of offsite power. Alternately, if it is not desired to isolate the affected penetration flow path(s) (e.g., as in the case where isolating the penetration flow path(s) could result in a reactor scram), Condition H must be entered and its Required Actions taken.(continued)

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-UNIT 1 TS / B 3.3-175 Revision I PPL Rev. 6 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES ACTIONS H.1 and H.2 (continued)

If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, or any Required Action of Condition F or G is not met and the associated Completion Time has expired, the plant must be placed in a MODE or other specified condition in which the LCO does not apply. This is done by placing the plant in at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.1.1 and 1.2 If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, the associated SLC subsystem(s) is declared inoperable or the RWCU System is isolated.

Since this Function is required to ensure that the SLC System performs its intended function, sufficient remedial measures are provided by declaring the associated SLC subsystems inoperable or isolating the RWCU System.The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Completion Time is acceptable because it minimizes risk while allowing sufficient time for personnel to isolate the RWCU System.J.1 and J.2 If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, the associated penetration flow path should be closed. However, if the shutdown cooling function is needed to provide core cooling, these Required Actions allow the penetration flow path to remain unisolated provided action is immediately initiated to restore the channel to OPERABLE status or to isolate the RHR Shutdown Cooling System (i.e., provide alternate decay heat removal capabilities so the penetration flow path can be isolated).

Actions must continue until the channel is restored to OPERABLE status or the RHR Shutdown Cooling System is isolated.(continued)

SUSQUEHANNA

-UNIT 1 TS / B 3.3-176 Revision 1 PPL Rev. 6 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES SURVEILLANCE As noted at the beginning of the SRs, the SRs for each Primary REQUIREMENTS Containment Isolation instrumentation Function are found in the SRs column of Table 3.3.6.1-1.

The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided the associated Function maintains trip capability.

Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Refs. 5 and 6) assumption of the average time required to perform channel surveillance.

That analysis demonstrated that the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> testing allowance does not significantly reduce the probability that the PCIVs will isolate the penetration flow path(s) when necessary.

SR 3.3.6.1.1 Performance of the CHANNEL CHECK once every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> ensures that a gross failure of instrumentation has not occurred.

A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels.

It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or of something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.

Agreement criteria which are determined by the plant staff based on an investigation of a combination of the channel instrument uncertainties, may be used to support this parameter comparison and include indication and readability.

If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit, and does not necessarily indicate the channel is Inoperable.

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

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-UNIT 1 TS / B 3.3-177 Revision 1 PPL Rev. 6 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES SURVEILLANCE SR 3.3.6.1.2 REQUIREMENTS (continued)

A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function.The 92 day Frequency of SR 3.3.6.1.2 is based on the reliability analysis described in References 5 and 6.This SR is modified by two Notes. Note 1 provides a general exception to the definition of 6HANNEL FUNCTIONAL TEST. This exception is necessary because the design of instrumentation does not facilitate functional testing of all required contacts of the relays which input into the combinational logic. (Reference

11) Performance of such a test could result in a plant transient or place the plant in an undo risk situation.

Therefore, for this SR, the CHANNEL FUNCTIONAL TEST verifies acceptable response by verifying the change of state of the relay which inputs into the combinational logic. The required contacts not tested during the CHANNEL FUNCTIONAL TEST are tested under the LOGIC SYSTEM FUNCTIONAL TEST, SR 3.3.6.1.5.

This is acceptable because operating experience shows that the contacts not tested during the CHANNEL FUNCTIONAL TEST normally pass the LOGICSYSTEM FUNCTIONAL TEST, and the testing methodology minimizes the risk of unplanned transients.

Note 2 provides a second specific exception to the definition of CHANNEL FUNCTIONAL TEST. For Functions 2.e, 3.a, and 4.a, certain channel relays are not included in the performance of the CHANNEL FUNCTIONAL TEST. These exceptions are necessary because the circuit design does not facilitate functional testing of the entire channel through to the coil of the relay which enters the combinational logic. (Reference

11) Specifically, testing of all required relays would require rendering the affected system (i.e., HPCI or RCIC)inoperable, or require lifting of leads and inserting test equipment which could lead to unplanned transients.

Therefore, for these circuits, the CHANNEL FUNCTIONAL TEST verifies acceptable response by verifying the actuation of circuit devices up to the point where further testing could result in an unplanned transient. (References 10 and 12)The required relays not tested during the CHANNEL FUNCTIONAL TEST are tested under the LOGIC SYSTEM FUNCTIONAL TEST, SR 3.3.6.1.5.

This exception (continued)

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-UNIT 1 TS / B 3.3-178 Revision 2 PPL Rev. 6 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES SURVEILLANCE SR 3.3.6.1.2 (continued)

REQUIREMENTS is acceptable because operating experience shows that the devices not tested during the CHANNEL FUNCTIONAL TEST normally pass the LOGIC SYSTEM FUNCTIONAL TEST, and the testing methodology minimizes the risk of unplanned transients.

SR 3.3.6.1.3 and SR 3.3.6.1.4 A CHANNEL CALIBRATION verifies that the channel responds to the measured parameter within the necessary range and accuracy.CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.

The Frequency of SR 3.3.6.1.3 is based on the assumption of a 92 day calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

The Frequency of SR 3.3.6.1.4 is based on the assumption of an 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.It should be noted that some of the primary containment High Drywell pressure instruments, although only required to be calibrated on a 24 month Frequency, are calibrated quarterly based on other TS requirements.

SR 3.3.6.1.5 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required isolation logic for a specific channel. The system functional testing performed on PCIVs in LCO 3.6.1.3 overlaps this Surveillance to provide complete testing of the assumed safety function.

The 24 month Frequency is based on the need to perform portions of this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency.(continued)

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-UNIT 1 TS / B 3.3-179 Revision 2 PPL Rev. 6 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES SURVEILLANCE SR 3.3.6.1.6 REQUIREMENTS (continued)

This SR ensures that the individual channel response times are less than or equal to the maximum values assumed in the accident analysis.Testing is performed only on channels where the guidance given in Reference 9 could not be met, which identified that degradation of response time can usually be detected by other surveillance tests.As stated in Note 1, the response time of the sensors for Functions 1.b, is excluded from ISOLATION SYSTEM RESPONSE TIME testing.Because the vendor does not provide a design instrument response time, a penalty value to account for the sensor response time is included in determining total channel response time. The penalty value is based on the historical performance of the sensor. (Reference

13) This allowance is supported by Reference 9 which determined that significant degradation of the sensor channel response time can be detected during performance of other Technical Specification SRs and that the sensor response time is a small part o.4the overall ISOLATION RESPONSE TIME testing.Function l.a and 1 .c channel sensors and logic components are excluded from response time testing in accordance with the provisions of References 14 and 15.As stated in Note 2, response time testing of isolating relays is not required for Function 5.a. This allowance is supported by Reference 9.These relays isolate their respective isolation valve after a nominal 45 second time delay in the circuitry.

No penalty value is included in the response time calculation of this function.

This is due to the historical response time testing results of relays of the same manufacturer and model number being less than 100 milliseconds, which is well within the expected accuracy of the 45 second time delay relay.ISOLATION SYSTEM RESPONSE TIME acceptance criteria are included in Reference

7. This test may be performed in one measurement, or in overlapping segments, with verification that all components are tested.ISOLATION SYSTEM RESPONSE TIME tests are conducted on an 24 month STAGGERED TEST BASIS. The 24 month Frequency is consistent with the typical industry refueling cycle and is based upon plant operating experience that shows that random failures of instrumentation (continued)

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-UNIT 1 TS / B 3.3-179a.Revision 2 PPL Rev. 6 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES SURVEILLANCE SR 3.3.6.1.6 (continued)

REQUIREMENTS components causing serious response time degradation, but not channel failure, are infrequent occurrences.

REFERENCES

1. FSAR, Section 6.3.2. FSAR, Chapter 15.3. NEDO-31466, "Technical Specification Screening Criteria Application and Risk Assessment," November 1987.4. FSAR, Section 4.2.3.4.3.

5. NEDC-31677P-A, "Technical Specification Improvement Analysis for BWR Isolation Actuation Instrumentation," July 1990.6. NEDC-30851 P-A Supplement 2, "Technical Specifications Improvement Analysis for BWR Isolation Instrumentation Common to RPS and ECCS Instrumentation," March 1989.7. FSAR, Table 7.3-29.8. Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 39132).9. NEDO-32291-A "System Analyses for Elimination of Selected Response Time Testing Requirements," October 1995.10. PPL Letter to NRC, PLA-2618, Response to NRC INSPECTION REPORTS 50-387/85-28 AND 50-388/85-23, dated April 22, 1986.11. NRC Inspection and Enforcement Manual, Part 9900: Technical Guidance, Standard Technical Specification Section 1.0 Definitions, Issue date 12/08/86.12. Susquehanna Steam Electric Station NRC REGION I COMBINED INSPECTION 50-387/90-20; 50-388/90-20, File R41-2, dated March 5, 1986.13. NRC Safety Evaluation Report related to Amendment No. 171 for License No. NPF-14 and Amendment No. 144 for License No. NPF-22.14. NEDO 32291-A, Supplement 1, "System Analyses for the Elimination of Selected Response Time Testing Requirements," October 1999.(continued)

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-UNIT 1 TS / B 3.3-179b Revision 0 PPL Rev. 6 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES REFERENCES (continued)

15. NEDO 32291, Supplement 1, Addendum 2, "System Analyses for the Elimination of Selected Response Time Testing Requirements," September 5, 2003.SUSQUEHANNA

-UNIT 1 TS / B 3.3-179c Revision 0 PPL Rev. 3 ECCS-Operating B 3.5.1 B 3.5 B 3.5.1 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM ECCS-Operating BASES BACKGROUND The ECCS is designed, in conjunction with the primary and secondary containment, to limit the release of radioactive materials to the environment following a loss of coolant accident (LOCA). The ECCS uses two independent methods (flooding and spraying) to cool the core during a LOCA. The ECCS network consists of the High Pressure Coolant Injection (HPCI) System, the Core Spray (CS) System, the low pressure coolant injection (LPCI) mode of the Residual Heat Removal (RHR)System, and the Automatic Depressurization System (ADS). The suppression pool provides the required source of water for the ECCS.Although no credit is taken in the safety analyses for the condensate storage tank (CST), it is capable of providing a source of water for the HPCI and CS systems.On receipt of an initiation signal, ECCS pumps automatically start;simultaneously, the system aligns and the pumps inject water, taken either from the CST or suppression pool, into the Reactor Coolant System (RCS)as RCS pressure is overcome by the discharge pressure of the ECCS pumps. Although the system is initiated, ADS action is delayed, allowing the operator to interrupt the timed sequence if the .system is not needed.The HPCI pump discharge pressure quickly exceeds that of the RCS, and the pump injects coolant into the vessel to cool the core. If the break is small, the HPCI System will maintain coolant inventory as well as vessel level while the RCS is still pressurized.

If HPCI fails, it is backed up by ADS in combination with LPCI and CS. In this event absent operator action, the ADS timed sequence would time out and open the selected safety/relief valves (S/RVs) depressurizing the RCS, thus allowing the LPCI and CS to overcome RCS pressure and inject coolant into the vessel. If the break is large, RCS pressure initially drops rapidly and the LPCI and CS cool the core.Water from the break returns to the suppression pool where it is-used again and again. Water in the suppression pool is circulated through a heat exchanger cooled by the RHR Service Water System. Depending on the location and size of (continued)

SUSQUEHANNA

-UNIT 1 B 3.5-1 Revision 0 PPL Rev. 3 ECCS-Operating B 3.5.1 BASES BACKGROUND the break, portions of the ECCS may be ineffective; however the overall (continued) design is effective in cooling the core regardless of the size or location of the piping break. Although no credit is.taken in the safety analysis for the RCIC System, it performs a similar function as HPCI, but has reduced makeup capability.

Nevertheless, it will maintain inventory and cool the core while the RCS is still pressurized following a reactor pressure vessel (RPV) isolation.

All ECCS subsystems are designed to ensure that no single active component failure will prevent automatic initiation and successful operation of the minimum required ECCS equipment.

The CS System (Ref. 1) is composed of two independent subsystems.

Each sbbsystem consists of two motor driven pumps, a spray sparger above the core, and piping and valves to transfer water from the suppression pool to the sparger. The CS System is designed to provide cooling to the reactor core when reactor pressure is low. Upon receipt of an initiation signal, the CS pumps in both subsystems are automatically started when AC power is available.

When the RPV pressure drops sufficiently, CS System flow to the RPV begins. A full flow test line is provided to route water from and to the suppression pool to allow testing of the CS System without spraying water in the RPV.LPCI is an independent operating mode of the RHR System. There are two LPCI subsystems (Ref. 2), each consisting of two motor driven pumps and piping and valves to transfer water from the suppression pool to the RPV via the corresponding recirculation loop. The two LPCI subsystems can be interconnected via the RHR System cross tie valves; however, at least one of the two cross tie valves is maintained closed with its power removed to prevent loss of both LPCI subsystems during a LOCA. The LPCI subsystems are designed to provide core cooling at low RPV pressure.

Upon receipt of an initiation signal, all four LPCI pumps are automatically started. RHR System valves in the LPCI flow path are automatically positioned to ensurethe proper flow path for water from the suppression pool to inject into the recirculation loops. When the RPV pressure drops sufficiently, the LPCI flow to the RPV, via the corresponding recirculation loop, begins. The water then enters the reactor through the jet pumps.(continued)

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-UNIT 1 B 3.5-2 Revision 0 PPL Rev. 3 ECCS-Operating B 3.5.1 BASES BACKGROUND Full flow test lines are provided for each LPCI subsystem to route water (continued) from the suppression pool, to allow testing of the LPCI pumps without injecting water into the RPV. These test lines also provide suppression pool cooling capability, as described in LCO 3.6.2.3, "RHR Suppression Pool Cooling." The HPCI System (Ref. 3) consists of a steam driven turbine pump unit, piping, and valves to provide steam to the turbine, as well as piping and valves to transfer water from the suction source to the core via the feedwater system line, where the coolant is distributed within the RPV through the feedwater sparger. Suction piping for the system is provided from the CST and the suppression pool. Pump suction for HPCI is normally aligned to the CST source to minimize injection of suppression pool water into the RPV. Whenever the CST water supply is low, an automatic transfer to the suppression pool water source ensures an adequate suction head for the pump and an uninterrupted water supply for continuous operation of the HPCI System. The steam supply to the HPCI turbine is piped from a main steam line upstream of the associated inboard main steam isolation valve.The HPCI System is designed to provide core cooling for a wide range of reactor pressures (165 psia to 1225 psia). Upon receipt of an initiation signal, the HPCI turbine stop valve and turbine control valve open and the turbine accelerates to a specified speed. As the HPCI flow increases, the turbine control valve is automatically adjusted to maintain design flow.Exhaust steam from the HPCI turbine is discharged to the suppression pool. A full flow test line is provided to route water to the CST to allow testing of the HPCI System during normal operation without injecting water into the RPV.The ECCS pumps .are provided with minimum flow bypass lines, which discharge to the suppression pool. The valves in these lines automatically open to prevent pump damage due to overheating when other discharge line valves are closed. To ensure rapid delivery of water to the RPV and to minimize water hammer effects, all ECCS pump discharge lines are filled with water. The HPCI, LPCI and CS System discharge lines are kept full of water using a "keep fill" system that is supplied using the condensate transfer system.(continued)

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-UNIT 1 TS / B 3.5-3 Revision 3 PPL Rev. 3 ECCS-Operating B 3.5.1 BASES BACKGROUND (continued)

The ADS (Ref. 4) consists of 6 of the 16 S/RVs. It is designed to provide depressurization of the RCS during a small break LOCA if HPCI fails or is unable to maintain required water level in the RPV. ADS operation reduces the RPV pressure to within the operating pressure range of the low pressure ECCS subsystems (CS and LPCI), so that these subsystems can provide coolant inventory makeup. Each of the S/RVs used for automatic depressurization is equipped with two gas accumulators and associated inlet check valves. The accumulators provide the pneumatic power to actuate the valves.APPLICABLE SAFETY ANALYSES The ECCS performance is evaluated for the entire spectrum of break sizes for a postulated LOCA. The accidents for which ECCS operation is required are presented in References 5, 6, and 7. The required analyses and assumptions are defined in Reference

8. The results of these analyses are also described in Reference 9.This LCO helps to ensure that the following acceptance criteria for the ECCS, established by 10 CFR 50.46 (Ref. 10), will be met following a LOCA, assuming the worst case single active component failure in the ECCS: a. Maximum fuel element cladding temperature is < 2200°F;b. Maximum cladding oxidation is _< 0.17 times the total cladding thickness before oxidation;

c. Maximum hydrogen generation from a zirconium water reaction is< 0.01 times the hypothetical amount that would be generated if all of the metal in the cladding surrounding the fuel, excluding the cladding surrounding the plenum volume, were to react;d. The core is maintained in a coolable geometry; and e. Adequate long term cooling capability is maintained.(continued)

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-UNIT 1 TS /B 3.5-4 Revision 1 PPL Rev. 3 ECCS-Operating B 3.5.1 BASES APPLICABLE SPC performed LOCA calculations for the SPC ATRIUM T M-10 fuel design.SAFETY The limiting single failures for the SPC analyses are discussed in ANALYSES Reference

11. For a large break LOCA, the SPC analyses identify the (continued) recirculation loop suction piping as the limiting break location.

The SPC analysis identifies the failure of the LPCI injection valve into the intact recirculation loop as the most limiting single failure.For a small break LOCA, the SPC analyses identify the recirculation loop discharge piping as the limiting break location, and a battery failure as the most severe single failure. One ADS valve failure is analyzed as a limiting single failure for events requiring ADS operation.

The remaining OPERABLE ECCS subsystems provide the capability to adequately cool the core and prevent excessive fuel damage.The ECCS satisfy Criterion 3 of the NRC Policy Statement (Ref. 15).LCO Each ECCS injection/spray subsystem and six ADS valves are required to be OPERABLE.

The ECCS injection/spray subsystems are defined as the two CS subsystems, the two LPCI subsystems, and one HPCI System.The low pressure ECCS injection/spray subsystems are defined as the two CS subsystems and the two LPCI subsystems.

With less than the required number of ECCS subsystems OPERABLE, the potential exists that during a limiting design basis LOCA concurrent with the worst case single failure, the limits specified in Reference 10 could be exceeded.

All ECCS subsystems must therefore be OPERABLE to satisfy the single failure criterion required by Reference 10.LPCI subsystems may be considered OPERABLE during alignment and operation for decay heat removal when below the actual RHR cut in permissive pressure in MODE 3, if capable of being manually realigned (remote or local) to the LPCI mode and not otherwise inoperable.

At these low pressures and decay heat levels, a reduced complement of ECCS subsystems should provide the required core cooling, thereby allowing operation of RHR shutdown cooling when necessary.(continued)

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-UNIT 1 TS / B 3.5-5 Revision 2 PPL Rev. 3 ECCS-Operating B 3.5.1 BASES (continued)

APPLICABILITY All ECCS subsystems are required to be OPERABLE during MODES 1, 2, and 3, when there is considerable energy in the reactor core and core cooling would be required to prevent fuel damage in the event of a break in the primary system piping. In MODES 2 and 3, when reactor steam dome pressure is _ 150 psig, ADS and HPCI are not required to be OPERABLE because the low pressure ECCS subsystems can provide sufficient flow below this pressure.

ECCS requirements for MODES 4 and 5 are specified in LCO 3.5.2, "ECCS-Shutdown." ACTIONS A Note prohibits the application of LCO 3.0.4.b to an inoperable HPCI subsystem.

There is an increased risk associated with entering a MODE or other specified condition in the Applicability with an inoperable HPCI subsystem 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.

A.1 If any one low pressure ECCS injection/spray subsystem is inoperable for reasons other than Condition B, the inoperable subsystem must be restored to OPERABLE status within 7 days. In fhis Condition, the remaining OPERABLE subsystems provide adequate core cooling during a LOCA. However, overall ECCS reliability is reduced, because a single failure in one of the remaining OPERABLE subsystems, concurrent with a LOCA, may result in the ECCS not being able to perform its intended safety function.

The 7 day Completion Time is based on a reliability study (Ref. 12) that evaluated the impact on ECCS availability, assuming various components and subsystems were taken out of service. The results were used to calculate the average availability of ECCS equipment needed to mitigate the consequences of a LOCA as a function of allowed outage times (i.e., Completion Times).B.1 If one LPCI pump in one or both LPCI subsystems is inoperable, the inoperable LPCI pumps must be restored to OPERABLE status within 7 days. In this Condition, the remaining OPERABLE LPCI pumps and at least one CS subsystem (continued)

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-UNIT 1 TS / B 3.5-6 Revision 1 PPL Rev. 3 ECCS-Operating B 3.5.1 BASES ACTIONS B.1 (continued) provide adequate core cooling during a LOCA. However, overall ECCS reliability is reduced, because a single failure in one of the remaining OPERABLE subsystems, concurrent with a LOCA, may result in the ECCS not being able to perform its intended safety function.

A 7 day Completion Time is based on a reliability study cited in Reference 12 and has been found to be acceptable through operating experience.

C.1 and C.2 If the inoperable low pressure ECCS subsystem or LPCI pump(s) cannot be restored to OPERABLE status within the associated 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 <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and to MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.D.1 and D.2 If the HPCI System is inoperable and the RCIC System is verified to be OPERABLE, the HPCI System must be restored to OPERABLE status within 14 days. In this Condition, adequate core cooling is ensured by the OPERABILITY of the redundant and diverse low pressure ECCS injection/spray subsystems in conjunction with ADS. Also, the RCIC System will automatically provide makeup water at most reactor operating pressures.

Verification of RCIC OPERABILITY is therefore required when HPCI is inoperable.

This may be performed as an administrative check by examining logs or other information to determine if RCIC is out of service for maintenance or other reasons. It does not mean to perform the Surveillances needed to demonstrate the OPERABILITY of the RCIC System. If the OPERABILITY of the RCIC System cannot be verified, however, Condition H must be immediately entered. If a single active component fails concurrent with a design basis LOCA, there is a potential, depending on the specific failure, that the minimum required ECCS equipment (continued)

SUSQUEHANNA

-UNIT 1 TS / B 3.5-7 Revision 0 PPL Rev. 3 ECCS-Operating B 3.5.1 BASES ACTIONS D.1 and D.2 (continued) will not be available.

A 14 day Completion Time is based on a reliability study cited in Reference 12 and has been found to be acceptable through operating experience.

E.1 and E.2 IfCondition A or Condition B exists in addition to an inoperable HPCI System, the inoperable low pressure ECCS injection/spray subsystem or the LPCI pump(s) or the HPCI System must be restored to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. In this Condition, adequate core cooling is ensured by the OPERABILITY of the ADS and the remaining low pressure ECCS subsystems.

However, the overall ECCS reliability is significantly reduced because a single failure in one of the remaining OPERABLE subsystems concurrent with a design basis LOCA may result in the ECCS not being able to perform its intended safety function.

Since both a high pressure system (HPCI) and a low pressure subsystem are inoperable, a more restrictive Completion Time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> is required to restore either the HPCI System or the low pressure ECCS injection/spray subsystem to OPERABLE status. This Completion Time is based on a reliability study cited in Reference 12 and has been found to be acceptable through operating experience.

F. 1 The LCO requires six ADS valves to be OPERABLE in order to provide the ADS function.

Reference 11 contains the results of an analysis that evaluated the effect of one ADS valve being out of service. Per this analysis, operation of only five ADS valves will provide the required depressurization.

However, overall reliability of the ADS is reduced, because a single failure in the OPERABLE ADS valves could result in a reduction in depressurization capability.

Therefore, operation is only allowed for a limited time. The 14 day Completion Time is based on a reliability study cited in Reference 12 and has been found to be acceptable through operating experience.(continued)

SUSQUEHANNA

-UNIT 1 TS / B 3.5-8 Revision 0 PPL Rev. 3 ECCS-Operating B 3.5.1 BASES ACTIONS G.1 and G.2 (continued)

If Condition A or Condition B exists in addition to one inoperable ADS valve, adequate core cooling is ensured by the OPERABILITY of HPCI and the remaining low pressure ECCS injection/spray subsystem.

However, overall ECCS reliability is reduced because a single active component failure concurrent with a design basis LOCA could result in the minimum required ECCS equipment not being available.

Since both a high pressure system (ADS) and a low pressure subsystem are inoperable, a more restrictive Completion Time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> is required to restore either the low pressure ECCS subsystem or the ADS valve to OPERABLE status. This Completion Time is based on a reliability study cited in Reference 12 and has been found to be acceptable through operating experience.

H.1 and H.2 If any Required Action and associated Completion Time of Condition D, E, F, or G is not met, or if two or more ADS valves are inoperable, the plant must be brought to a condition in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and reactor steam dome pressure reduced to < 150 psig within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.1.1 When multiple ECCS subsystems are inoperable, as stated in Condition I, LCO 3.0.3 must be entered immediately.

SURVEILLANCE SR 3.5.1.1 REQUIREMENTS The flow path piping has the potential to develop voids and pockets of entrained air. Maintaining the pump discharge lines of the HPCI System, CS System, and LPCI subsystems (continued)

I.SUSQUEHANNA

-UNIT 1 TS / B 3.5-9 Revision 0 PPL Rev. 3 ECCS-Operating B 3.5.1 BASES SURVEILLANCE SR 3.5.1.1 (continued)

REQUIREMENTS full of water ensures that the ECCS will perform ,properly, injecting its full capacity into the RCS upon demand. This will also prevent a water hammer following an ECCS initiation signal. One acceptable method of ensuring that the lines are full is to vent at the high points. The 31 day Frequency is based on the gradual nature of Void buildup in the ECCS piping, the procedural controls governing system operation, and operating experience.

SR 3.5.1.2 Verifying the correct alignment for manual, power operated, and automatic valves in the ECCS flow paths provides assurance that the proper flow paths will exist for ECCS operation.

This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these were verified to be in the correct position prior to locking, sealing, or securing.A valve that receives an initiation signal is allowed to be in a nonaccident position provided the valve will automatically reposition in the proper stroke time. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of potentially being mispositioned are in the correct position.

This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves. For the HPCI System, this SR also includes the steam flow path for the turbine and the flow controller position.The 31 day Frequency of this SR was derived from the Inservice Testing Program requirements for performing valve testing at least once every 92 days. The Frequency of 31 days is further justified because the valves are operated under procedural control and because improper valve position would only affect a single subsystem.

This Frequency has been shown to be acceptable through operating experience.

This SR is modified by a Note that allows LPCI subsystems to be considered OPERABLE during alignment and operation for decay heat removal with reactor steam dome pressure less than the RHR cut in permissive pressure in MODE 3, if capable of being manually realigned (remote or local) to the (continued)

SUSQUEHANNA

-UNIT 1 TS / B 3.5-10 Revision 0 PPL Rev. 3 ECCS-Operating B 3.5.1 BASES SURVEILLANCE SR 3.5.1.2 (continued)

REQUIREMENTS LPCI mode and not otherwise inoperable.

This allows operation in the RHR shutdown cooling mode during MODE 3, if necessary.

SR 3.5.1.3 Verification every 31 days that ADS gas supply header pressure is> 135 psig ensures adequate gas pressure for reliable ADS operation.

The accumulator on each ADS valve provides pneumatic pressure for valve actuation.

The design pneumatic supply pressure requirements for the accumulator are such that, following a failure of the pneumatic supply to the accumulator, at least one valve actuations can occur with the drywell at 70% of design pressure.The ECCS safety analysis assumes only one actuation to achieve the depressurization required for operation of the low pressure ECCS. This minimum required pressure of _ 135 psig is provided by the containment instrument gas system. The 31 day Frequency takes into consideration administrative controls over operation of the gas system and alarms associated with the containment instrument gas system.SR 3.5.1.4 Verification every 31 days that at least one RHR System cross tie valve is closed and power to its operator is disconnected ensures that each LPCI subsystem remains independent and a failure of the flow path in one subsystem will not affect the flow path of the other LPCI subsystem.

Acceptable methods of removing power to the operator include opening the breaker, or racking out the breaker, or removing the breaker. If both RHR System cross tie valves are open or power has not been removed from at least one closed valve operator, both LPCI subsystems must be considered inoperable.

The 31 day Frequency has been found acceptable, considering that these valves are under strict administrative controls that will ensure the valves continue to remain closed with motive power removed.(continued)

SUSQUEHANNA

-UNIT 1 TS / B 3.5-11 Revision 1 PPL Rev. 3 ECCS-Operating B 3.5.1 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.5.1.5 Verification every 31 days that each 480 volt AC swing bus transfers automatically from the normal source to the alternate source on loss of power. while supplying its respective bus demonstrates that electrical power is available to ensure proper operation of the associated LPCI inboard injection and minimum flow valves and the recirculation pump discharge and bypass valves. Therefore, each 480 volt AC swing bus must be OPERABLE for the associated LPCI subsystem to be OPERABLE.

The test is performed by actuating the load test switch or by disconnecting the preferred power source to the transfer switch and verifying that swing bus automatic transfer is accomplished.

The 31 day Frequency has been found to be acceptable through operating experience.

S ? 3.5.1.6 Cycling the recirculation pump discharge and bypass valves through one complete cycle of full travel demonstrates that the valves are mechanically OPERABLE and provides assurance that the valves will close when required to ensure the proper LPCI flow path is established.

Upon initiation of an automatic LPCI subsystem injection signal, these valves are required to be closed to ensure full LPCI subsystem flow injection in the reactor via the recirculation jet pumps. De-energizing the valve in the closed position will also ensure the proper flow path for the LPCI subsystem.

Acceptable methods of de-energizing the valve include opening the breaker, or racking out the breaker, or removing the breaker.The specified Frequency is once during reactor startup before THERMAL POWER is > 25% RTP. However, this SR is modified by a Note that states the Surveillance is only required to be performed if the last performance was more than 31 days ago. Therefore, implementation of this Note requires this test to be performed during reactor startup before exceeding 25% RTP. Verification during reactor startup prior to reaching> 25% RTP is an exception to the normal Inservice Testing Program generic valve cycling Frequency of 92 days, but is considered acceptable due to (continued)

SUSQUEHANNA

-UNIT 1 TS / B 3.5-12 Revision 0 PPL Rev. 3 ECCS-Operating B 3.5.1 BASES SURVEILLANCE SR 3.5.1.6 (continued)

REQUIREMENTS the demonstrated reliability of these valves. If the valve is inoperable and in the open position, the associated LPCI subsystem must be declared inoperable.

SR 3.5.1.7, SR 3.5.1.8, and SR 3.5.1.9 The performance requirements of the low pressure ECCS pumps are determined through application of the 10 CFR 50, Appendix K criteria (Ref. 8). This periodic Surveillance is performed (in accordance with the ASME OM Code requirements for the ECCS pumps) to verify that the ECCS pumps will develop the flow rates required by the respective analyses.

The low pressure ECCS pump flow rates ensure that adequate core cooling is provided to satisfy the acceptance criteria of Reference 10.The pump flow rates are verified against a system head equivalent to the RPV pressure expected during a LOCA. The total system pump outlet pressure is adequate to overcome the elevation head pressure between the pump suction and the vessel discharge, the piping friction losses, and RPV pressure present during a LOCA. These values may be established during preoperational testing.The flow tests for the HPCI System are performed at two different pressure ranges such that system capability to provide rated flow is tested at both the higher and lower operating ranges of the system. Additionally, adequate steam flow must be passing through the main turbine or turbine bypass valves to continue to control reactor pressure when the HPCI System diverts steam flow. Reactor steam pressure is considered adequate when > 920 psig to perform SR 3.5.1.8 and _> 150 psig to perform SR 3.5.1.9. However, the requirements of SR 3.5.1.9 are met by a successful performance at any pressure -< 165 psig. Adequate steam flow is represented by at least 1.25 turbine bypass valves open.Therefore, sufficient time is allowed after adequate pressure and flow are achieved to perform these tests. Reactor startup is allowed prior to performing the low pressure Surveillance test because the reactor pressure is low and the time allowed to satisfactorily perform the Surveillance test is short. The reactor pressure is allowed to be increased to normal operating pressure since it is assumed that the low pressure test has been satisfactorily (continued)

SUSQUEHANNA

-UNIT 1 TS / B 3.5-13 Revision 2 PPL Rev. 3 ECCS-Operating B 3.5.1 BASES SURVEILLANCE SR 3.5.1.7, SR 3.5.1.8, and SR 3.5.1.9 (continued)

REQUIREMENTS completed and there is no indication or reason to believe that HPCI is inoperable.

Therefore, SR 3.5.1.8 and SR 3.5.1.9 are modified by Notes that state the Surveillances are not required to be performed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after the reactor steam pressure and flow are adequate to perform the test.The Frequency for SR 3.5.1.7 and SR 3.5.1.8 is in accordance with the Inservice Testing Program requirements.

The 24 month Frequency for SR 3.5.1.9 is based on the need to perform the Surveillance under the conditions that apply just prior to or during a startup from a plant outage.Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

SR 3.5.1.10 The ECCS subsystems are required to actuate automatically to perform their design functions.

This Surveillance verifies that, with a required system initiation signal (actual or simulated), the automatic initiation logic of HPCI, CS, and LPCI will cause the systems or subsystems to operate as designed, including actuation of the system throughout its emergency operating sequence, automatic pump startup and actuation of all automatic valves to their required positions.

This functional test includes the LPCI and CS interlocks between Unit 1 and Unit 2 and specifically requires the following:

A functional test of the interlocks associated with the LPCI and CS pump starts in response to an automatic initiation signal in Unit 1 followed by a false automatic initiation signal in Unit 2;A functional test of the interlocks associated with the LPCI and CS pump starts in response to an automatic initiation signal in Unit 2 followed by a false automatic initiation signal in Unit 1; and (continued)

SUSQUEHANNA

-UNIT 1 TS / B 3.5-14 Revision 0 PPL Rev. 3 ECCS-Operating B 3.5.1 BASES SURVEILLANCE SR 3.5.1.10 (continued)

REQUIREMENTS A functional test of the interlocks associated with the LPCI and CS pump starts in response to simultaneous occurrences of an automatic initiation signal in both Unit 1 and Unit 2 and a loss of Offsite power condition affecting both Unit 1 and Unit 2.The purpose of this functional test (preferred pump logic) is to assure that if a false LOCA signal were to be received on one Unit simultaneously with an actual LOCA signal on the second Unit, the preferred LPCI and CS pumps are started and the non-preferred LPCI and CS pumps are tripped for each Unit. This functional test is performed by verifying that the non-preferred LPCI and CS pumps are tripped. The verification that preferred LPCI and CS pumps start is performed under a separate surveillance test. Only one division of LPCI preferred pump logic is required to be OPERABLE for each Unit, because no additional failures needs to be postulated with a false LOCA signal. If the preferred or non-preferred pump logic for CS is inoperable, the associated CS pumps shall be declared inoperable and the pumps should not be operated to ensure that the opposite Unit's CS pumps or 4.16 kV ESS Buses are protected.

This SR also ensures that the HPCI System will automatically restart on an RPV low water level (Level 2) signal received subsequent to an RPV high water level (Level 8) trip and that the suction is automatically transferred from the CST to the suppression pool. The LOGIC SYSTEM FUNCTIONAL TEST performed in LCO 3.3.5.1 overlaps this Surveillance.

This SR can be accomplished by any series of sequential overlapping or total steps such that the entire channel is tested.The 24 month Frequency is acceptable because operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

This SR is modified by a Note that excludes vessel injection/spray during the Surveillance.

Since all active components are testable and full flow can be demonstrated by recirculation through the test line, coolant injection into the RPV is not required during the Surveillance.(continued)

SUSQUEHANNA

-UNIT I TS / B 3.5-15 Revision 0 PPL Rev. 3 ECCS-Operating B 3.5.1 BASES SR 3.5.1.11 SURVEILLANCE REQUIREMENTS (continued)

The ADS designated S/RVs are required to actuate automatically upon receipt of specific initiation signals. A system functional test is performed to demonstrate that the mechanical portions of the ADS function (i.e., solenoids) operate as designed when initiated either by an actual or simulated initiation signal, causing proper actuation of all the required components.

SR 3.5.1.12 and the LOGIC SYSTEM FUNCTIONAL TEST performed in LCO 3.3.5.1 overlap this Surveillance to provide complete testing of the assumed safety function.The 24 month Frequency is based on the need to perform portions of the Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

This SR is modified by a Note that excludes valve actuation.

This prevents an RPV pressure blowdown.SR 3.5.1.12 A manual actuation of each ADS valve is performed to verify that the valve and solenoid are functioning properly.

This is demonstrated by one of the two methods described below. Proper operation of the valve tailpipes is ensured through the use of foreign material exclusion during maintenance.

One method is by manual actuation of the ADS valve under hot conditions.

Proper functioning of the valve and solenoid is demonstrated by the response of the turbine control or bypass valve or by a change in the measured flow or by any other method suitable to verify steam flow.Adequate reactor steam dome pressure must be available to perform this test to avoid damaging the valve due to seat impact during closure. Also, adequate steam flow must be passing through the main turbine or turbine bypass valves to continue to control reactor pressure when the ADS valves divert steam flow upon opening. Sufficient time is therefore allowed after the required pressure and flow are achieved to perform this SR. Adequate pressure at which this SR is to be performed is 150 psig.However, the requirements of SR 3.5.1.12 are met by a successful performance at any pressure.

Adequate steam flow is represented by at least 1.25 turbine bypass valves open. Reactor startup is allowed prior to performing this SR by this method because valve OPERABILITY and the setpoints for (continued)

SUSQUEHANNA

-UNIT 1 TS / B 3.5-16 Revision 2 PPL Rev. 3 ECCS-Operating B 3.5.1 BASES SURVEILLANCE SR 3.5.1.12 (continued)

REQUIREMENTS overpressure protection are verified, per ASME requirements, prior to valve installation.

Therefore, this SR is modified by a Note that states the Surveillance is not required to be performed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after reactor steam pressure and flow are adequate to perform the test. The 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowed for manual actuation after the required pressure is reached is sufficient to achieve stable conditions and provides adequate time to complete the Surveillance.

Another method is by manual actuation of the ADS valve at atmospheric temperature and pressure during cold shutdown.

When using this method, proper functioning of the valve and solenoid is demonstrated by visual observation of actuator movement.

Actual disc travel is measured during valve refurbishment and testing per ASME requirements.

Lifting the valve at atmospheric pressure requires controlling the actuator to set the valve disc softly on its seat to prevent valve damage. Lifting the valve at atmospheric pressure is the preferred method because lifting the valves with steam flow increases the likelihood that the. valve will leak. The Note.that modifies this SR is not needed when this method is used because the SR is performed during cold shutdown.SR 3.5.1.11 and the LOGIC SYSTEM FUNCTIONAL TEST performed in LCO 3.3.5.1 overlap this Surveillance to provide complete testing of the assumed safety function.

The Frequency of 24 months on a STAGGERED TEST BASIS ensures that both solenoids for each ADS valve are alternately tested. The Frequency is based on the need to perform the Surveillance under the conditions that apply just prior to or during a startup from a plant outage. Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

SR 3.5.1.13 This SR ensures that the ECCS RESPONSE TIME for each ECCS injection/spray subsystem is less than or equal to the maximum value assumed in the accident analysis.

Response Time testing acceptance criteria are included in Reference

13. This SR is modified by a Note that allows the instrumentation portion of the response time to be assumed to be based on historical response time data and therefore, is excluded from the ECCS RESPONSE TIME testing. This is allowed since the instrumentation response time is a small part of the ECCS RESPONSE TIME (e.g., sufficient margin exists in the diesel generator start time when compared to the instrumentation response time) (Ref. 14).(continued)

SUSQUEHANNA

-UNIT 1 TS I B 3.5-17 Revision 2 PPL Rev. 3 ECCS-Operating B 3.5.1 BASES SURVEILLANCE REQUIREMENTS SR 3.5.1.13 (continued)

The 24-month Frequency is consistent with the typical industry refueling cycle and is acceptable based upon plant operating experience.

REFERENCES

1. FSAR, Section 6.3.2.2.3.

2., FSAR, Section 6.3.2.2.4.

3. FSAR, Section 6.3.2.2.1.

4. FSAR, Section 6.3.2.2.2.

5. FSAR, Section 15.2.4.6. FSAR, Section 15.2.5.7. FSAR, Section 15.2.6.8. 10 CFR 50, Appendix K.9. FSAR, Section 6.3.3.10. 10 CFR 50.46.11. FSAR, Section 6.3.3.12. Memorandum from R.L. Baer (NRC) to V. Stello, Jr. (NRC),"Recommended Interim Revisions to LCOs for ECCS Components," December 1, 1975.13. FSAR, Section 6.3.3.3.14. NEDO 32291-A, "System Analysis for the Elimination of Selected Response Time Testing Requirements, October 1995.15. Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 39132).SUSQUEHANNA-UNIT 1 TS / B 3.5-18 Revision I PPL Rev. 3 RCIC System B 3.5.3 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM B 3.5.3 RCIC System BASES BACKGROUND The RCIC System is not part of the ECCS; however, the RCIC System is included with the ECCS section because of their similar functions.

The RCIC System is designed to operate either automatically or manually following reactor pressure vessel (RPV) isolation accompanied by a loss of coolant flow from the feedwater system to provide adequate core cooling and control of the RPV water level. Under these conditions, the High Pressure Coolant Injection (HPCI) and RCIC systems perform similar functions.

The RCIC System design requirements ensure that the criteria of Reference 1 are satisfied.

The RCIC System (Ref. 2) consists of a steam driven turbine pump unit, piping, and valves to provide steam to the turbine, as well as piping and valves to transfer water from the suction source to the core via the feedwater system line, where the coolant is distributed within the RPV through the feedwater sparger. Suction piping is provided from the condensate storage tank (CST) and the suppression pool. Pump suction is normally aligned to the CST to minimize injection of suppression pool water into the RPV. However, if the CST water supply is low, an automatic transfer to the suppression pool water source ensures an adequate suction head for the pump and an uninterrupted water supply for continuous operation of the RCIC System. The steam supply to the turbine is piped from a main steam line upstream of the associated inboard main steam line isolation valve.The RCIC System is designed to provide core cooling for a wide range of reactor pressures (165 psia to 1225 psia). Upon receipt of an initiation signal, the RCIC turbine accelerates to a specified speed. As the RCIC flow increases, the turbine control valve is automatically adjusted to maintain design flow. Exhaust steam from the RCIC turbine is discharged to the suppression pool. A full flow test line is provided to route water to the CST to allow testing of the RCIC System during normal operation without injecting water into the RPV.(continued)

SUSQUEHANNA

-UNIT 1 TS / B 3.5-25 Revision 1 PPL Rev. 3 RCIC System B 3.5.3 BASES BACKGROUND (continued)

The RCIC pump is provided with a minimum flow bypass line, which discharges to the suppression pool. The valve in this line automatically opens to prevent pump damage due to overheating when other discharge line valves are closed. To ensure rapid delivery of water to the RPV and to minimize water hammer effects, the RCIC System discharge piping is kept full of water. The RCIC System is normally aligned to the. CST. The RCIC discharge line is kept full of water using a "keep fill" system supplied by the condensate transfer system.APPLICABLE SAFETY ANALSES The function of the RCIC System is to respond to transient events by providing makeup coolant to the reactor. The RCIC System is not an Engineered Safety Feature System and no credit is taken in the Design Basis Loss of Coolant Accident (LOCA) safety analysis'for RCIC System operation.

The RCIC System is credited in other accident analyses (See Chapter 15 of the FSAR). Based on its contribution to the reduction of overall plant risk, however, the system is included in the Technical Specifications, as required by the NRC Policy Statement (Ref. 4).LCO The OPERABILITY of the RCIC System provides adequate core cooling such that actuation of any of the low pressure ECCS subsystems is not required in the even of RPV isolation accompanied by a loss of feedwater flow. The RCIC System has sufficient capacity for maintaining RPV inventory during an isolation event.APPLICABILITY The RCIC System is required to be OPERABLE during MODE 1, and MODES 2 and 3 with reactor steam dome pressure > 150 psig, since RCIC is the primary non-ECCS water source for core cooling when the reactor is isolated and pressurized.

In MODES 2 and 3 with reactor steam dome pressure _< 150 psig, and in MODES 4 and 5, RCIC is not required to be OPERABLE since the low pressure ECCS injection/spray subsystems can provide sufficient flow to the RPV.ACTIONS A Note prohibits the application of LCO 3.0.4.b to an inoperable RCIC system. There is an increased risk associated with entering a MODE or other specified condition in the Applicability with an inoperable RCIC system 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.(continued)

SUSQUEHANNA

-UNIT 1 TS / B 3.5-26 Revision 2 PPL Rev. 3 RCIC System B 3.5.3 BASES ACTIONS A.1 and A.2 (continued)

If the RCIC is inoperable during MODE 1, or MODE 2 or 3 with reactor steam dome pressure > 150 psig, and the HPCI System is verified to be OPERABLE, the RCIC System must be restored to OPERABLE status within 14 days. In this Condition, loss of the RCIC System will not affect the overall plant capability to provide makeup inventory at high reactor pressure since the HPCI System is the only high pressure system assumed to function during a loss of coolant accident (LOCA).OPERABILITY of HPCI is therefore verified immediately when the RCIC System is inoperable.

This may be performed as an administrative check, by examining logs or other information, to determine if HPCI is out of service for maintenance or other reasons. It does not mean it is necessary to perform the Surveillances needed to demonstrate the OPERABILITY of the HPCI System. If the OPERABILITY of the HPCI System cannot be verified, however, Condition B must be immediately entered. For transients and certain abnormal events with no LOCA, RCIC (as opposed to HPCI) is the preferred source of makeup coolant because of its relatively small capacity, which allows easier control of the RPV water level. Therefore, a limited time is allowed to restore the inoperable RCIC to OPERABLE status.The 14 day Completion Time is based on a reliability study (Ref. 3) that evaluated the impact on ECCS availability, assuming various components and subsystems were taken out of service. The results were used to calculate the average availability of ECCS equipment needed to mitigate the consequences-of a LOCA as a function of allowed outage times (AOTs). Because of similar functions of HPCI and RCIC, the AOTs (i.e., Completion Times) determined for HPCI are also applied to RCIC.B.1 and B.2 If the RCIC System cannot be restored to OPERABLE status within the associated Completion Time, or if the HPCI System is simultaneously inoperable, the plant must be brought to a condition in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and reactor steam dome pressure reduced to < 150 psig within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times (continued)

SUSQUEHANNA

-UNIT 1 TS / B 3.5-27 Revision 2 PPL Rev. 3 RCIC System B 3.5.3 BASES ACTIONS B.1 and B.2 (continued) are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in a orderly manner and without challenging plant systems.SURVEILLANCE SR 3.5.3.1 REQUIREMENTS The flow path piping has the potential to develop voids and pockets of entrained air. Maintaining the pump discharge line of the RCIC System full of water ensures that the system will perform properly, injecting its full capacity into the Reactor Coolant System upon demand. This will also prevent a water hammer following an initiation'signal.

One acceptable method of ensuring the line is full is to vent at the high points. The 31 day Frequency is based on the gradual nature of void buildup in the RCIC piping, the procedural controls governing system operation, and operating experience.

SR 3.5.3.2 Verifying the correct alignment for manual, power operated, and automatic valves in the RCIC flow path provides assurance that the proper flow path will exist for RCIC operation.

The SR does not apply to valves that are locked, sealed, or otherwise secured in position since these valves were verified to be in the correct position prior to locking, sealing, or securing.A valve that receives an initiation signal is allowed to be in a nonaccident position provided the valve will automatically reposition in the proper.stroke time. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of potentially being mispositioned are in the correct position.

This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves. For the RCIC System, this SR also includes the steam- flow path for the turbine and the flow controller position.The 31 day Frequency of this SR was derived from the Inservice Testing Program requirements for performing valve testing at least once every 92 days. The Frequency of (continued)

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-UNIT 1 TS / B 3.5-28 Revision 0 PPL Rev. 3 RCIC System B 3.5.3 BASES SURVEILLANCE SR 3.5.3.2 (continued)

REQUIREMENTS 31 days is further justified because the valves are operated under procedural control and because improper valve position would affect only the RCIC System. This Frequency has been shown to be acceptable through operating experience.

SR 3.5.3.3 and SR 3.5.3.4 The RCIC pump flow rates ensure that the system can maintain reactor coolant inventory during pressurized conditions with the RPV isolated.The flow tests for the RCIC System are performed at two different pressure ranges such that system capability to provide rated flow is tested both at the higher and lower operating ranges of the system. Additionally, adequate steam flow must be passing through the main turbine or turbine bypass valves to continue to control reactor pressure when the RCIC System diverts steam flow. Reactor steam pressure is considered adequate when _> 920 psig to perform SR 3.5.3.3 and >_ 150 psig to perform SR 3.5.3.4. However, the requirements of SR 3.5.3.4 are met by a successful performance at any pressure < 165 psig. Adequate steam flow is represented by at least 1.25 turbine bypass valves open.Therefore, sufficient time is allowed after adequate pressure and flow are achieved to perform these SRs. Reactor startup is allowed prior to performing the low pressure Surveillance because the reactor pressure is low and the time allowed to satisfactorily perform the Surveillance is short.The reactor pressure is allowed to be increased to normal operating pressure since it is assumed that the low pressure Surveillance has been satisfactorily completed and there is no indication or reason to believe that RCIC is inoperable.

Therefore, these SRs are modified by Notes that state the Surveillances are not required to be performed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after the reactor steam pressure and flow are adequate to perform the test.The Frequency for SR 3.5.3.3 is determined by the Inservice Testing Program requirements.

The 24 month Frequency for SR 3.5.3.4 is based on the need to perform the Surveillance under conditions that apply just prior to or during a startup from a plant outage. Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency, which is based on the refueling (continued).

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-UNIT 1 TS / B 3.5-29 Revision 1 PPL Rev. 3 RCIC System B 3.5.3 BASES SURVEILLANCE SR 3.5.3.3 and SR 3.5.3.4 (continued)

REQUIREMENTS cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

SR 3.5.3.5 The RCIC System is required to actuate automatically in order to verify its design function satisfactorily.

This Surveillance verifies that, with a required system initiation signal (actual or simulated), the automatic initiation logic of the RCIC System will cause the system to operate as designed, including actuation of the system throughout its emergency operating sequence; that is, automatic pump startup and actuation of all automatic valves to their required positions.

This test also ensures the RCIC System will automatically restart on an RPV low water level (Level 2)signal received subsequent to an RPV high water level (Level 8) trip and that the suction is automatically transferred from the CST to the suppression pool. The LOGIC SYSTEM FUNCTIONAL TEST performed in LCO 3.3.5.2 overlaps this Surveillance to provide complete testing of the assumed safety function.The 24 month Frequency is based on the need to perform portions of the Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

This SR is modified by a Note that excludes vessel injection during the Surveillance.

Since all active components are testable and full flow can be demonstrated by recirculation through the test line, coolant injection into the RPV is not required during the Surveillance.

REFERENCES

1. 10 CFR 50, Appendix A, GDC 33.2. FSAR, Section 5.4.6.(continued)

SUSQUEHANNA-UNIT 1 TS / B 3.5-30 Revision 0 PPL Rev. 3 RCIC System B 3.5.3 BASES REFERENCES

3. Memorandum from R. L. Baer (NRC) to V. Stello, Jr. (NRC), (continued) "Recommended Interim Revisions to LCOs for ECCS Components," December 1, 1975.4. Final Policy Statement on Technical Specifications Improvements, July 22, 1993 (58 FR 39132).SUSQUEHANNA

-UNIT 1 TS / B 3.5-31 Revision 0 PPL Rev. 5 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 and to 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.(continued)

SUSQUEHANNA-UNIT 1 TS / B 3.6-1 Revision 2 PPL Rev. 5 Primary Containment B 3.6.1.1 BASES BACKGROUND (continued)

The H 2 0 2 Analyzer lines beyond the PCIVs, up to and including the components within the H 2 0 2 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 H 2 0 2 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 H 2 0 2 Analyzer panels, the boundary ends at the first normally closed valve. The closed system boundary between PASS and the H 2 0 2 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-12361, SV-12365, SV-12366, SV-12368, and SV-12369).

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 1E 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 Leakage Rate Test Program, since they form part of the closed system boundary for the H 2 0 2 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 H 2 0 2 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 H 2 0 2 Analyzer penetrations and panel isolation valves.This Specification ensures that the performance of the primary containment, in the event of a Design Basis Accident (DBA), 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.(continued)

Revision 3 SUSQUEHANNA

-UNIT 1 TS / B 3.6-1 a PPL Rev. 5 Primary Containment B 3.6.1.1 BASES (continued)

APPLICABLE The safety design basis for the primary containment is that SAFETY ANALYSES it must withstand the pressures and temperatures of the limiting DBA without exceeding the design leakage rate.The DBA 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 DBA, which forms the basis for determination of offsite'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 <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 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)LCO 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.(continued)

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-UNIT 1 TS / B 3.6-2 Revision 4 PPL Rev. 5 Primary Containment B 3.6.1.1 BASES (continued)

APPLICABILITY In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to primary containment.

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

ACTIONS A.1 In the event primary containment is inoperable, primary containment must be restored to OPERABLE status within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> 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.B.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 <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and to MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.SURVEILLANCE SR 3.6.1.1.1 REQUIREMENTS 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 refueling 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.(continued)

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-UNIT I TS / B 3.6-3 Revision 3 PPL Rev. 5 Primary Containment B 3.6.1.1 BASES SURVEILLANCE SR 3.6.1.1.1 (continued)

REQUIREMENTS 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.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 water 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 AN/k design valve. For SSES, the A/k design value is.0535 ft 2.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 (continued)

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-UNIT 1 TS / B 3.6-4 Revision 4 PPL Rev. 5 Primary Containment B 3.6.1.1 BASES SURVEILLANCE SR 3.6.1.1.2 (continued)

REQUIREMENTS 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.SR 3.6.1.1.3 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. The leakage test is performed every 24 months. The 24 month Frequency was developed considering the surveillance must be performed during a unit outage. 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.REFERENCES

1. FSAR, Section 6.2.2. FSAR, Section 15.3. 10 CFR 50, Appendix J, Option B.4. Nuclear Energy Institute, 94-01 (continued)

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-UNIT 1 TS / B 3.6-5 Revision 3 PPL Rev. 5 Primary Containment B 3.6.1.1 BASES REFERENCES (continued)

5. ANSI/ANS, 56.8-1994 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 1 TS / B 3.6-6 Revision 3 PPL Rev. 5 Primary Containment B 3.6.1.1 TABLE B 3.6.1.1-1 INSTRUMENT ISOLATION VALVES (Page 1 of 2)PENETRATION INSTRUMENT ISOLATION NUMBER VALVE X-3B PSH-C72-1 N002A IC-PSH-1 N002A PSH L C72-1N004 IC-PSHL-1N004 PS-E11-1 N010A IC-PS-I N010A PS-E11-1NO11A IC-PS-1 N01 1A PSH-C72-1 N002B IC-PSH-lN002B PS-E11-1NO10C IC-PS-1N010C PS-E1-1NO11C IC-PS-1N011C PSH-15120C IC-PSH-15120C X-32A PSH-C72-1N002D IC-PSH- 1N002D PS-E11-1NO10B IC-PS-1 N010B PS-E11-lNO11B IC-PS-lN011B PSH-C72-1 N002C IC-PSH-l N002C PS-ElI-INO10D IC-PS-i N010D PS-E11-1NO11D IC-PS-1N011D PSH-15120D IC-PSH-15120D X-39A FT-15120A IC-FT-15120A HIGH and IC-FT-15120A LOW X-39B FT-15120B IC-FT-15120B HIGH and IC-FT-15120B LOW X-90A PT-1 5709A IC-PT-15709A PT-15710A IC-PT-15710A PT-1 5728A IC-PT-15728A X-90D PT-15709B IC-PT-15709B PT-15710B IC-PT-15710B PT-15728B IC-PT-15728B SUSQUEHANNA

-UNIT 1 TS / B 3.6-6a Revision 2 PPL Rev. 5 Primary Containment B 3.6.1.1 TABLE B 3.6.1.1-1 INSTRUMENT ISOLATION VALVES (Page 2 of 2)PENETRATION INSTRUMENT ISOLATION NUMBER VALVE X-204A/205A FT-15121A IC-FT-15121A HIGH and IC-FT-15121A LOW X-204B/205B FT-15121B IC-FT-15121B HIGH and IC-FT-15121B LOW X-219A LT-15775A IC-LT-15775A REF and IC-LT-15775A VAR LSH-E41-1N015A 155027 and 155031 LSH-E41-1N015B 155029 and 155033 X-223A PT-1 5702 IC-PT-15702 X-232A LT-15776A IC-LT-15776A REF and IC-LT-1 5776A VAR PT-1 5729A IC-PT-15729A LI-15776A2 IC-LI-15776A2 REF and IC-LI-15776A2 VAR X234A LT-15775B IC-LT-15775B REF and IC-LT-15775B VAR X-235A LT-15776B IC-LT-15776B REF and IC-LT-15776B VAR PT-15729B IC-PT-15729B SUSQUEHANNA

-UNIT 1 TS / B 3.6-6b Revision 4 PPL Rev. 5 Primary Containment B 3.6.1.1 TABLE B 3.6.1.1-2 H 2 0 2 ANALYZER PANEL ISOLATION VALVES PENETRATION NUMBER PANEL ISOLATION VALVE(a)X-60A, X-88B, X-221A, X-238A 157138 157139 157140 157141 157142 X-80C, X-233, X-238B 157149 157150 157151 157152 157153 (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 1 TS / B 3.6-6c Revision 0 PPL Rev. 7 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 I 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. 10; and, a 230 kV tap from the 500-230 kV tie line feeds the startup transformer No. 20. The term "qualified circuits," as used within TS 3.8.1, is synonymous with the term "physically independent." The two independent offsite power sources are supplied to and are shared by both units. These two electrically and physically separated circuits provide AC power, through startup transformers (ST) No. 10 and ST No. 20, to the four 4.16 kV Engineered Safeguards System (ESS)buses (A, B, C and D) for both Unit I 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.(continued)

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-UNIT 1 TS / B 3.8-1 Revision 3