ML23291A370

1 to Updated Final Safety Analysis Report, Chapter 6, Section 6.3, Emergency Core Cooling Systems

ML23291A370
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Site:	Susquehanna
Issue date:	10/12/2023
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SSES-FSAR Text Rev. 73 6.3 EMERGENCY CORE COOLING SYSTEMS 6.3.1 DESIGN BASES AND

SUMMARY

DESCRIPTION Subsection 6.3.1 provides the design bases for the Emergency Core Cooling System (ECCS) and a summary description of the several systems as an introduction to the more detailed design descriptions provided in Subsection 6.3.2 and the performance analysis provided in Subsection 6.3.3.

6.3.1.1 Design Bases 6.3.1.1.1 Performance and Functional Requirements The ECCS is designed to provide protection against postulated loss-of-coolant accidents (LOCA) caused by ruptures in primary system piping. The functional requirements, (for example, coolant delivery rates) specified in detail in Table 6.3-2B are such that the system performance under all LOCA conditions postulated in the design satisfies the requirements of 10CFR50.46. These requirements, the most important of which is that the post-LOCA peak cladding temperature be limited to 2200oF, are summarized in Subsection 6.3.3.2. In addition, the ECCS is designed to meet the following requirements:

1) Protection is provided for any primary line break up to and including the double-ended break of the largest line.

2) Two independent and diverse cooling methods (flooding and spraying) are provided to cool the core.

3) One high pressure cooling system is provided which is capable of maintaining water level above the top of the core and preventing ADS actuation for breaks of lines less than 1 inch nominal diameter.

4) With one exception, no operator action is required until 20 minutes after an accident to allow for operator assessment and decision. The only operator action assumed in the Section 6.3 ECCS analysis is that a RHR heat exchanger is placed in service within 20 minutes into the accident.

5) The ECCS is designed to satisfy all criteria specified in Section 6.3 for any normal mode of reactor operation.

6) A sufficient water source and the necessary piping, pumps and other hardware are provided so that the containment and reactor core can be flooded for possible core heat removal following a loss-of-coolant accident.

FSAR Rev. 71 6.3-1

SSES-FSAR Text Rev. 73 6.3.1.1.2 Reliability Requirements The following reliability requirements apply:

1) The ECCS conforms to all licensing requirements, and good design practices of isolation, separation, and common mode failure considerations.

2) In order to meet the above requirements, the ECCS network has built-in redundancy so that adequate cooling can be provided, even in the event of specified failures. The following equipment makes up the ECCS:

High Pressure Coolant Injection System (HPCI)

Core Spray System (CS) (2 loops)

Low Pressure Coolant Injection System (LPCI) (2 loops)

Automatic Depressurization System (ADS)

3) The system is designed so that a single active or passive component failure, including power buses, electrical and mechanical parts, cabinets, and wiring will not disable the ADS.

4) In the event of a break in a pipe that is not a part of the ECCS, no single active component failure in the ECCS prevents automatic initiation and successful operation of less than the combination of ECCS equipment shown in Table 6.3-5 for a recirculation suction break (non-ECCS line break).

5) In the event of a break in a pipe that is a part of the ECCS, no single active component failure in the ECCS prevents automatic initiation and successful operation of less than the combination of ECCS equipment shown in Table 6.3-5 for a recirculation discharge break (ECCS line break).

These are the minimum ECCS combinations which result after assuming the failures (from 4 above) and assuming that the ECCS line break disables a LPCI system loop.

6) Long-term cooling requires the removal of decay heat via the RHRSW system. In addition to the break which initiated the loss of coolant event, the system is able to sustain one failure, either active or passive, and still have at least one LPCI pump or one CS loop for makeup, and one RHR pump with a heat exchanger (including 100% RHRSW flow to the operating heat exchanger) for heat removal.

7) Off-site power is the preferred source of power for the ECCS network and every reasonable precaution is made to assure its high availability. However, on-site emergency power is provided with sufficient diversity and capacity so that all the above requirements are met even if off-site power is not available.

8) The on-site diesel fuel reserve is designed in accordance with IEEE-308 criteria as stated in Subsection 7.1.2.5.2.

9) Diesel-load configuration is 1 LPCI pump and 1 CS pump connected to a single diesel generator. (Typical for four aligned diesels in a one unit LOCA.)

FSAR Rev. 71 6.3-2

SSES-FSAR Text Rev. 73

10) Systems which interface with, but are not part of, the ECCS are designed and operated such that failure(s) in the interfacing systems do not propagate to and/or affect the performance of the ECCS.

11) Non-ECCS systems interfacing with the ECCS buses are automatically shed from and/or are initially inhibited from the ECCS buses of the affected unit when a LOCA signal exists and off-site AC power is not available.

12) No more than one storage battery is connectable to a DC power bus.

13) Each low pressure system of the ECCS including flow rate and sensing networks is capable of being tested during shutdown. All active components are capable of being tested during plant operation, including logic required to automatically initiate component action.

14) Provisions for testing the ECCS network components (electronic, mechanical, hydraulic and pneumatic, as applicable) are installed in such a manner that they are an integral and non-separable part of the design.

6.3.1.1.3 ECCS Requirements for Protection from Physical Damage The emergency core cooling system piping and components are protected against damage from movement, from thermal stresses, from the effects of the LOCA and the Safe Shutdown Earthquake. The ECCS is protected against the effects of pipe whip, which might result from piping failures up to and including the LOCA. This protection is provided by separation, pipe whip restraints, or energy absorbing materials if required. Any of these three methods will be applied to provide protection against damage to piping and components of the ECCS which otherwise could result in a reduction of ECCS effectiveness to an unacceptable level.

Mechanical separation outside the drywell is achieved as follows:

1) The ECCS shall be separated into three functional groups:

a. HPCI

b. CS(A&C) + LPCI(A&C)

c. CS(B&D) + LPCI(B&D)

2) The equipment in each group shall be separated from that in the other two groups.

In addition, the HPCI and the RCIC (which is not part of the ECCS) shall be separated.

3) Separation barriers shall be constructed between the functional groups as required to assure that environmental disturbances such as fire, pipe rupture, falling objects, etc.,

affecting one functional group will not adversely affect the remaining groups. In addition, separation barriers shall be provided as required to assure that such disturbances do not affect both RCIC and HPCI. For additional discussion, refer to Section 3.12.

FSAR Rev. 71 6.3-3

SSES-FSAR Text Rev. 73 6.3.1.1.4 ECCS Environmental Design Basis The low pressure systems of the ECCS have testable check valves in the drywell portions of their respective piping runs. These safety-related, injection/isolation valves are designed for abnormal environmental requirements.

The ECCS equipment (e.g., pumps, motors) is qualified for abnormal environmental requirements.

Abnormal environmental conditions to which these components are qualified or designed are described in Section 3.11.

For a listing of all safety-related valves located in the drywell subject to spray impingement from the containment Spray System, see Table 6.3-10. No safety-related valves become submerged because of spray from the Containment Spray System.

6.3.1.2 Summary Descriptions of ECCS The ECCS injection network comprises a high pressure coolant injection (HPCI) system, a low pressure core spray (CS) system and the low pressure coolant injection (LPCI) mode of the Residual Heat Removal System. These systems are briefly described here as an introduction to the more detailed system design descriptions provided in Subsection 6.3.2. The Automatic Depressurization System (ADS) which assists the injection network under certain conditions is also briefly described. Boiling water reactors which employ the same ECCS design are listed in Table 1.3-3.

6.3.1.2.1 High Pressure Coolant Injection The HPCI pumps water through the feedwater sparger. The primary purpose of HPCI is to maintain reactor vessel inventory after small breaks which do not depressurize the reactor vessel.

6.3.1.2.2 Core Spray The two loops pump water into peripheral ring spray spargers mounted above the reactor core.

The primary purpose of CS is to provide inventory makeup and spray cooling during large breaks in which the core is calculated to uncover. When assisted by ADS, CS also provides protection for small breaks.

6.3.1.2.3 Low Pressure Coolant Injection LPCI is an operating mode of the Residual Heat Removal System. Four pumps deliver water from the suppression pool to the recirculation lines. The primary purpose of LPCI is to provide vessel inventory makeup following large pipe breaks. When assisted by ADS, LPCI also provides protection for small breaks.

6.3.1.2.4 Automatic Depressurization System ADS utilizes a number of the reactor safety/relief valves to reduce reactor pressure during small breaks in the event of HPCI failure. When the vessel pressure is reduced to within the capacity of the low pressure systems (CS and LPCI), these systems provide inventory makeup so that acceptable post accident temperatures are maintained.

FSAR Rev. 71 6.3-4

SSES-FSAR Text Rev. 73 6.3.2 SYSTEM DESIGN More detailed descriptions of the individual systems including individual design characteristics are provided in Subsections 6.3.2.1 through 6.3.2.4. The following discussion will provide details of the combined systems; and in particular, those design features and characteristics which are common to all systems.

6.3.2.1 Schematic Piping and Instrumentation Diagrams The P&IDs and process diagrams for the ECCS are identified in Subsection 6.3.2.2.

6.3.2.2 Equipment and Component Descriptions The starting signal for the ECCS comes from at least two independent and redundant sensors of high drywell pressure, low RPV pressure, and low reactor water level. The ECCS is actuated automatically and with one exception requires no operator action during the first 20 minutes following the accident. The only operator action assumed in the Section 6.3 ECCS analysis is that a RHR heat exchanger is placed in service within 20 minutes into the accident. A time sequence for a Design Basis LOCA analysis showing starting of the systems is provided in Table 6.3-1B-2 for Unit 1 and Table 6.3-1B-3 for Unit 2.

Electric power for operation of the ECCS (except the dc powered HPCI system) is from the preferred offsite ac power supply. Upon loss of the preferred source, operation is from the onsite standby diesel generators. Four diesel generators supplying individual ac buses have sufficient diversity and capacity so that failure of one diesel satisfies ECCS requirements. Section 8.3 contains a more detailed description of the power supplies for the ECCS.

6.3.2.2.1 High Pressure Coolant Injection (HPCI) System The high pressure coolant injection (HPCI) system consists of a steam turbine driven constant-flow pump assembly, associated system piping, valves, controls, and instrumentation. The P&ID for HPCI, Dwgs. M-155, Sh. 1 and M-156, Sh. 1, shows the system components and their arrangement. The HPCI system Process Diagram, Dwg. M1-E41-4, Sh. 1, shows the design operating modes of the system.

The HPCI system equipment is installed in the reactor building. Suction piping comes from both the condensate storage tank and the suppression pool. Injection water is piped to the reactor feedwater line. Steam supply for the turbine is piped from a main steamline in the primary containment. This piping is provided with an isolation valve on each side of the primary containment. Remote controls for valve and turbine operation are provided in the main control room. The controls and instrumentation of the HPCI system are described, illustrated, and evaluated in Section 7.3.

The HPCI system is provided to ensure that the reactor core is adequately cooled to meet the design bases in the event of a small break in the reactor coolant pressure boundary (RCPB) and loss of coolant that does not result in rapid depressurization of the reactor vessel. This permits the plant to be shut down while maintaining sufficient reactor vessel water inventory until the reactor vessel is depressurized. The HPCI system continues to operate until the reactor vessel pressure is below the pressure at which LPCI operation or core spray system operation can maintain core cooling.

FSAR Rev. 71 6.3-5

SSES-FSAR Text Rev. 73 The HPCI system is designed to pump water into the reactor vessel for a wide range of pressures in the reactor vessel. Initially, demineralized water from the condensate storage tank is used instead of injecting water from the suppression pool into the reactor. Water from either source is pumped into the reactor vessel through the feedwater spargers.

The level instrumentation on the condensate storage tank is used to automatically transfer the HPCI suction from the condensate storage tank to the suppression pool at a level determined by conservative NPSH calculations. The calculations ensure adequate NSPH during the transfer process and ensure there is no unacceptable vortex formation in the suction lines during the transfer process. This suction transfer can be remotely overridden to realign suction to the CST.

The portion of the suction piping exposed to outside air temperatures is protected from cold weather effects both by heat tracing and by insulation.

The temperature of the level instrumentation is monitored by temperature instrumentation which alarms in the control room if the temperature falls below 40oF.

The pump assembly is located below the level of the condensate storage tank and below the water level in the suppression pool to ensure positive suction head to the pumps. Pump NPSH requirements are met by providing adequate suction head and adequate suction line size.

Available NPSH is calculated using the assumptions of Regulatory Guide 1.1 (12/70). The NPSH calculations are shown in Sections 6.3.2.2.1.1 and 6.3.2.2.1.2. The required NPSH is shown in Table 6.3-8. See also Figure 6.3-3a.

The HPCI turbine-pump assembly and piping are protected from detrimental physical effects of the DBA, such as pipe whip, flooding, and high temperature. The equipment is located outside the primary containment.

The HPCI turbine is driven by steam from the reactor vessel which is generated by decay and residual heat. The steam is extracted from a main steamline upstream of the main steamline isolation valves. The inboard and outboard HPCI isolation valves in the steamline to the HPCI turbine are normally open. This keeps the piping to the turbine at an elevated temperature to permit rapid startup of the HPCI system. The inboard isolation valve has a bypass line containing a normally closed valve. This bypass line permits pressure equalization and drainage around the isolation valve and downstream line warmup prior to opening of the isolation valve. Signals from the HPCI control system open or close the supply valve adjacent to the turbine.

A condensate drain pot is provided upstream of the turbine stop valve to prevent the HPCI steam supply line from filling with water. The drain pot normally routes the condensate to the main condenser, but upon receipt of a HPCI initiation signal or a loss of control air pressure, isolation valves on the condensate line automatically close.

The turbine power is controlled by a flow controller, sensing pump discharge flow and providing a variable signal (1-5 volts DC) to the turbine governor, to maintain constant pump discharge flow over the pressure range of operation. The turbine control system is capable of limiting speed overshoot to 15 percent of maximum operating speed on a quick start while driving only the pump inertia load. Limit switches are provided on the turbine control valve to indicate fully open and closed positions. Both lights shall be "on" in midposition.

As reactor steam pressure decreases, the HPCI turbine control valve opens further to pass the steam flow required to provide the necessary pump flow. The capacity of the system is selected to provide sufficient core cooling to prevent clad temperatures in excess of the limits (10CFR50.46)

FSAR Rev. 71 6.3-6

SSES-FSAR Text Rev. 73 while the pressure in the reactor vessel is above the pressure at which core spray and LPCI become effective.

Exhaust steam from the HPCI turbine is discharged to the suppression pool. A drain pot at the low point in the exhaust line collects moisture present in the steam. Collected moisture is discharged through an orifice to the barometric condenser.

The HPCI turbine gland seals are routed to the barometric condenser for cooling and containment of radioactive steam. Noncondensable gases from the barometric condenser are pumped to the Standby Gas Treatment System.

The check valves and two isolation valves are provided in the vacuum breaker line which connects the air space in the suppression chamber with the HPCI turbine exhaust line. This eliminates any possibility of water from the suppression pool being drawn into the HPCI turbine exhaust line. The isolation valve in this vacuum breaker line operates automatically via a combination of low reactor pressure and high drywell pressure. Test connections are provided on either side of the two check valves.

Startup of the HPCI system is completely independent of ac power. Only dc power from the station battery and steam extracted from the nuclear system are necessary.

The various operations of the HPCI components are summarized as follows:

The HPCI controls automatically start the system and bring it to design flowrate within 30 seconds from receipt of a reactor pressure vessel (RPV) low water level signal or a primary containment (drywell) high pressure signal. Refer to Chapter 15 for more analysis details.

The HPCI turbine is shut down automatically by any of the following signals:

1) Turbine overspeed - This prevents damage to the turbine.

2) RPV high water level - This indicates that core cooling requirements are satisfied.

3) HPCI pump low suction pressure - This prevents damage to the pump due to loss of flow.

4) HPCI turbine exhaust high pressure - This indicates a turbine or turbine control malfunction.

If an initiation signal is received after the turbine is shut down, the system will restart automatically if no shutdown signals exists.

Additionally, because the steam supply line to the HPCI turbine is part of the RCPB, certain signals automatically isolate this line, causing shutdown of the HPCI turbine. The auto isolation signal will not clear until manually reset after the clearance of all isolation signals. Automatic shutoff of the steam supply is described in Section 7.3. However, automatic depressurization and the low pressure systems of the ECCS act as backup, and automatic shutoff of the steam supply does not negate the ability of the ECCS to satisfy the safety objective.

In addition to the automatic operational features of the system, provisions are included for remote manual startup, operation, and shutdown (provided automatic initiation or shutdown signals do not exist).

FSAR Rev. 71 6.3-7

SSES-FSAR Text Rev. 73 HPCI operation automatically actuates the following valves:

1) HPCI pump discharge shutoff valves

2) HPCI steam admission valve

3) HPCI turbine stop valve

4) HPCI turbine control valve

5) HPCI steamline drain isolation valves

6) HPCI test return valve to CST if open

7) Minimum flow bypass valve Prior to startup, the turbine control system will be held at the low speed design condition. Upon receipt of an initiating signal a speed ramp generator module will automatically run the control system toward its high speed design point, thereby controlling the transient acceleration of the turbine. The flow controller will automatically over-ride the speed ramp generator and when rated flow is established, the flow controller signal adjusts the setting of the turbine control so that rated flow is maintained as nuclear system pressure decreases.

Startup of the auxiliary oil pump and proper functioning of the hydraulic control system is required to open the turbine stop and control valves. Operation of the barometric condenser components is required to prevent outleakage from the turbine shaft seals. Startup of the condenser equipment is automatic, but its failure does not prevent the HPCI system from fulfilling its core cooling objective.

A minimum flow bypass is provided for pump protection. The bypass valve automatically opens on a low flow signal if the HPCI pump discharge pressure permissive is present, and automatically closes on a high flow signal. When the bypass is open, flow is directed to the suppression pool.

A line used for system testing leads from the HPCI pump discharge line to the condensate storage tank. The shutoff valves in this line are sequenced closed upon HPCI system initiation. To prevent pumping suppression pool water to the CST, these valves are also interlocked closed when the pump suction valve from the suppression pool is open. All automatically operated valves are equipped with a remote manual functional test feature.

The HPCI system initially injects water from the condensate storage tank. When the water level in the tank falls below some predetermined level, the pump suction is automatically transferred to the suppression pool. This level was determined by conservative calculations, which ensure that no unacceptable vortex formation would occur during the transfer process. In addition a vortex breaker is located at the suction nozzle of the CST to prevent vortex formation. Preoperational testing demonstrated that vortex formation did not occur. This test was performed with the condensate storage tank level at the transfer level, with the core spray pumps operating at 6000 gpm. This transfer may also be made from the main control room using remote controls.

When the pump suction has been transferred to the suppression pool, a closed loop is established for recirculation of water escaping from a break. Suction can also be transferred to the CST if desired to access the remaining available volume.

To assure continuous core cooling, signals to isolate the containment do not operate any HPCI valves.

The HPCI system incorporates a relief valve in the pump suction line to protect the components and piping from inadvertent overpressure conditions.

FSAR Rev. 71 6.3-8

SSES-FSAR Text Rev. 73 The HPCI pump and piping are positioned to avoid damage from the physical effects of design basis accidents, such as pipe whip, missiles, high temperature, pressure, and humidity.

The HPCI equipment and support structures are designed in accordance with Seismic Category I criteria (see Chapter 3). The system is assumed to be filled with water for seismic analysis.

Provisions are included in the HPCI system which will permit the HPCI system to be tested.

These provisions are:

1) A full flow test line is provided to route water to the condensate storage tank without entering the reactor pressure vessel.

2) A minimum flow bypass test line is provided to route water to the suppression pool without entering the reactor pressure vessel.

3) Instrumentation is provided to indicate system performance during normal test operations.

4) All motor-operated valves are capable of either local or remote manual operation for test purposes.

5) Drains are provided to leak test the major system valves.

The operating parameters for the components of the HPCI system, defined below, are shown on Dwg. M1-E41-4, Sh. 1.

1) One 100 percent capacity booster and main pump assembly and accessories

2) Piping, valves, and instrumentation for:

a. Steam supply to the turbine

b. Turbine exhaust to the suppression pool

c. Supply from the condensate storage tank to the pump suction

d. Supply from the suppression pool to the pump suction

e. Pump discharge to the feedwater line spargers, including a test line to the condensate storage tank, a minimum flow bypass line to the suppression pool, and a cooling water supply to accessory equipment.

The basis for the design conditions was the ASME Section III, Nuclear Power Plant Components.

The design parameters for the HPCI system components are shown in Table 6.3-8.

FSAR Rev. 71 6.3-9

SSES-FSAR Text Rev. 73 6.3.2.2.1.1 NPSH Available with Suction from the Condensate Storage Tank The available NPSH is calculated in accordance with Regulatory Guide 1.1. The following data was used in the calculation:

a. Condensate storage tank water level is conservatively assumed to be two feet below the transfer level.

b. Condensate storage tank water is at 100oF.

c. Both HPCI and RCIC are in operation.

d. NPSHA = hs - hf + ha - hvpa hs = static head hf = friction head loss ha = atmospheric pressure head hvpa = vapor pressure Unit I hs = 673.75' - 650.25' = 23.5 ft.

hf = 7.1 ft.

ha = 33.16 ft.

hvpa = 2.2 ft.

NPSHA = 47.36 ft.

Unit II hs = 673.75'-650.25' = 23.5 ft.

hf = 12.19 ft.

ha = 33.16 ft.

hvpa = 2.21 ft.

NPSHA = 42.26 ft.

NPSHR = 21 ft.

6.3.2.2.1.2 NPSH Available with Suction from the Suppression Pool The available NPSH is calculated in accordance with Regulatory Guide 1.1. The following data was used in the calculation:

a. Suppression pool is at the minimum level of El. 668.5 feet. 668.5 El. is due to pool level drop for worst case passive failure in an ECCS pump room (Subsection 6.3-6).

b. Suppression pool water is at its maximum temperature for the given operating mode, 140 F.

c. Atmospheric pressure is assumed over the suppression pool.

FSAR Rev. 71 6.3-10

SSES-FSAR Text Rev. 73

d. NPSHA = hs - hf + ha - hvpa hs = 668.5' - 650.25' = 18.25' hf = 13.23 ft.

ha = 33.16 ft.

hvpa = 6.8 ft.

NPSHA = 31.4 ft. NPSHR = 21 ft.

6.3.2.2.2 Automatic Depressurization System (ADS)

If the RCIC and the HPCI cannot maintain the reactor water level, the automatic depressurization system, which is independent of any other system of the ECCS, reduces the reactor pressure so that flow from the LPCI and CS systems enters the reactor vessel in time to cool the core and limit any increase in fuel cladding temperature.

The automatic depressurization system employs nuclear system safety/relief valves to relieve high pressure steam to the suppression pool. The design, number, location, description, operational characteristics, and evaluation of the safety/relief valves are discussed in detail in Subsection 5.2.2. The operation of the ADS is discussed in Subsection 7.3.1.1a.1.4.

6.3.2.2.3 Core Spray (CS ) System Each of the two redundant core spray systems consists of: two 50% capacity centrifugal pumps that can be powered by normal auxiliary power or the standby ac power system; a spray sparger in the reactor vessel above the core (a separate sparger for each CS system); piping and valves to convey water from the suppression pool to the sparger; and associated controls and instrumentation. Dwg. M-152, Sh. 1, the CS system P&ID, presents the system components and their arrangement. The CS system Process Diagram, Dwg. M1-E21-15, Sh. 1, shows the design operating modes of the system. A simplified system flow diagram showing system injection into the reactor vessel is presented in Dwg. M1-E21-15, Sh. 1 for the CS system.

When low water level in the reactor vessel or high pressure in the drywell is sensed, and with reactor vessel pressure low enough, the core spray system automatically starts and sprays water into the top of the fuel assemblies to cool the core. The CS injection piping enters the vessel, divides, and enters the core shroud at two points near the top of the shroud. A sparger is attached to each outlet. Nozzles are spaced around the sparger to spray the water radially over the core and into the fuel assemblies.

The CS system is designed to provide cooling to the reactor core only when the reactor vessel pressure is low, as is the case for large LOCA break sizes. However, when the CS operates in conjunction with the ADS, the effective core cooling capability of the CS is extended to all break sizes because the ADS will rapidly reduce the reactor vessel pressure to the CS operating range.

The core spray pump and all motor operated valves can be operated individually by manual switches located in the control room. Operating indication is provided in the control room by a flowmeter and valve indicator lights.

To assure continuity of core cooling, signals to isolate the containment do not operate any core spray system valves.

FSAR Rev. 71 6.3-11

SSES-FSAR Text Rev. 73 The discharge line to the reactor is provided with two isolation valves. One of these valves is a testable (with an air-operated solenoid valve) check valve located inside the drywell as close as practical to the reactor vessel. The check valve will move to the close position on loss of air and/or power. CS injection flow causes this valve to open during LOCA conditions (i.e., no power is required for valve actuation during LOCA). If the CS line should break outside the containment, the check valve in the line inside the drywell will prevent loss of reactor water outside the containment.

The other isolation valve (which is also referred to as the CS injection valve) is a motor operated gate valve located outside the primary containment as close as practical to the CS discharge line penetration into the containment. This valve is capable of opening with the maximum differential across the valve expected for any system operating mode. The valve stroke time is less than or equal to 19 seconds. This valve is normally closed to back up the inside testable check valve for containment integrity purposes.

The CS system components and piping are arranged to avoid unacceptable damage from the physical effect of design-basis accidents, such as pipe whip, missiles, high temperature, pressure and humidity.

All principal active CS equipment is located outside the primary containment.

A check valve (one per CS pump), and in each loop one flow element and restricting orifice are provided in the CS discharge line from the pump to the injection valve. The check valve is located below the minimum suppression pool water level and is provided so the piping downstream of the valve can be maintained full of water by the discharge line fill system (see Subsection 6.3.2.2.5).

The flow element is provided to measure system flow rate during LOCA and test conditions and for automatic control of the minimum low flow bypass gate valve. The measured flow is indicated in the main control room. The restricting orifice was sized during pre-operational test of the system to limit system flow to acceptable values as described on the CS system Process Diagram.

(Dwg. M1-E21-15, Sh. 1)

The CS pump (pump performance test results) characteristics, head, flow, horsepower, and required NPSH are shown in Figure 6.3-118.

A low flow bypass line with a motor operated gate valve connects to the CS discharge line upstream of the check valve on the pump discharge line. The line bypasses water to the suppression pool to prevent pump damage due to overheating when other discharge line valves are closed or reactor pressure is greater than the CS system discharge pressure following system initiation. The valve automatically closes when flow in the main discharge line is sufficient to provide required pump cooling.

CS flow passes through a motor-operated pump suction valve that is normally open. This valve can be closed by a remote manual switch (located in the control room) to isolate the CS system from the suppression pool should a leak develop in the system. This valve is located in the core spray pump suction line as close to the suppression pool penetration as practical. Because the CS conveys water from the suppression pool, a closed loop is established for the spray water escaping from the break.

The design pressure and temperature for various portions of the system were established in accordance with the ASME Section III Boiler and Pressure Vessel code and the required core spray system design specification written for this system. The original Core Spray System Process Diagram was used as input in the development of the design specification.

FSAR Rev. 71 6.3-12

SSES-FSAR Text Rev. 73 Each of the two redundant core spray systems takes suction from the suppression pool through a suction line that has two high capacity stacked disk strainers. The strainers have sufficient capacity to filter their design debris source term under worst case conditions while maintaining strainer pressure drop below the maximum value required to provide adequate NPSH and system flow. The design debris source term consists of conservative amounts of insulation, paint chips and other drywell debris that could reach the strainers after being destroyed by LOCA jet forces and transported to the suppression pool through the downcomers. This debris is assumed to be filtered by the strainers along with corrosion products that would exist in the suppression pool prior to a LOCA. Correlations between the amount of debris filtered by the strainers and strainer pressure drop are based on testing performed on one of the Susquehanna RHR strainers (which have a design similar to the CS strainers) and NRC approved methodology outlined in NEDO-32686, Utility Resolution Guide for ECCS Suction Strainer Blockage. The suppression pools are cleaned and inspected periodically to maintain corrosion product amounts at acceptable levels and to confirm the absence of miscellaneous debris that would be a strainer blockage threat.

The CS pump is located in the reactor building below the water level in the suppression pool to assure positive pump suction. Pump NPSH requirements are met with the containment at atmospheric pressure. A pressure gage is provided to indicate the suction head. The available NPSH has been calculated in accordance with NRC Regulatory Guide 1.1. The CS pump characteristics are shown in Figure 6.3-118.

The CS system incorporates relief valves to prevent the components and piping from inadvertent overpressure conditions. One relief valve, located on the pump discharge, is set at 500 psig with a capacity of 100 gpm at 10% accumulation. The second relief valve is located on the suction side of the pump and is set for 100 psig at a capacity of 10 gpm at 10% accumulation.

The CS system piping and support structures are designed in accordance with Seismic Category I criteria (see Chapter 3). The system is assumed to be filled with water for seismic analysis.

Provisions are included in the CS system which will permit the CS system to be tested.

These provisions are:

1) All active CS components are testable during normal plant operation.

2) A full flow test line is provided to route water from and to the suppression pool without entering the reactor pressure vessel.

3) A suction test line supplying reactor grade water, is provided to test pump discharge into the reactor pressure vessel during normal plant shutdown.

4) Instrumentation is provided to indicate system performance during normal and test operations.

5) All motor-operated valves and check valves are capable of operation for test purposes.

The Core Spray pump discharge check valves (152/252 F003A,B,C,&D) have local disc position indication on the valve hinge pins.

FSAR Rev. 71 6.3-13

SSES-FSAR Text Rev. 73 6.3.2.2.3.1 NPSH Available for CS The available NPSH is calculated in accordance with Regulatory Guide 1.1. The following data was used in the calculation:

a. The suppression pool is at the minimum post-accident level of El. 667.3 feet. 667-3 El. is due to suppression pool draw down assuming the worst case break (Main Steam Line break inside containment).

b. The centerline of the pump suction is at El. 646-10 5/8.

c. The suction strainers (total of two strainers for each suction line) are filtering their design debris source term. The maximum pressure loss across the strainers at maximum runout flow of 7900 gpm is 4.3 psi. The pump vendor required NPSH at runout flow is 4.0 feet.

d. Atmospheric pressure head is assumed to be equal to the vapor pressure, ha - hvp

e. The suppression pool water is assumed to be at 220°F.

f. NPSHA = hs -- hf + ha - hvp hs = static head hf = friction head loss ha = atmospheric pressure head hvp= vapor pressure Based on Section 6.3.2.2.3.1.d, NPSHA = hs - hf with hs = 20.41 feet hf = 14.66 feet NPSHA = 20.41 - 14.66 NPSHA = 5.75 feet NPSHr = 4.0 feet 6.3.2.2.4 Low Pressure Coolant Injection (LPCI) System The low pressure coolant injection system is an operating mode of the RHR system. The LPCI system is automatically actuated by low water level in the reactor or high pressure in the drywell (high pressure in the drywell must be accompanied by a reactor vessel low pressure permissive signal) and uses four motor-driven RHR pumps to draw suction from the suppression pool and inject cooling water flow into the reactor core via the recirculation loop to accomplish cooling of the core by flooding.

The LPCI system, like the CS system, is designed to provide cooling to the reactor core only when the reactor vessel pressure is low, as is the case for large LOCA break sizes. However, when the LPCI operates in conjunction with the ADS, the effective core cooling capability of the LPCI is extended to all break sizes because the ADS will rapidly reduce the reactor vessel pressure to the LPCI operating range. NPSH for these flow conditions is shown in Figure 6.3-119.

FSAR Rev. 71 6.3-14

SSES-FSAR Text Rev. 73 Dwgs. M1-E11-3, Sh. 1 and M1-E11-3, Sh. 2, show a process diagram, (and process data) of the RHR system. The LPCI System P&ID is presented in Dwgs. M-151, Sh. 1, M-151, Sh. 2, M-151, Sh. 3, and M-151, Sh. 4.

LPCI operation includes using associated valves, control, instrumentation, and pump accessories.

LPCI is normally powered from the preferred ac power source and from the standby ac power source upon a loss of preferred ac power.

In the event of a LOCA, the two halves of the LPCI system inject water into the discharge line in each recirculation loop. Since electrical power to each LPCI pump is separate, it is necessary to have a bus arrangement which permits the valves of a LPCI loop that has been disabled by a single failure of a divisional electrical supply to be energized by an alternate electrical supply. This feature preserves the ability of the LPCI to inject into the unbroken recirculation loop as well as the broken loop. See Table 6.3-5 for the LPCI pumps available during a LOCA and a limiting single failure.

To assure continuity of core cooling, signals to isolate the primary containment do not operate any RHR system valves which interfere with the LPCI mode of operation.

The process diagram, Dwgs. M1-E11-3, Sh. 1 and M1-E11-3, Sh. 2, and the P&ID, Dwgs. M-151, Sh. 1, M-151, Sh. 2, M-151, Sh. 3, and M-151, Sh. 4, indicate a great many available flow paths other than the LPCI injection line. However, the low water level or high drywell pressure signal and RPV low pressure signals which automatically initiate the LPCI mode are also used to realign containment cooling and spray modes of operation and revert other associated valves to the LPCI lineup. Inlet and outlet valves from the heat exchangers receive no automatic signals as the system is designed to provide rated flow to the vessel whether they are open or not.

A check valve in the pump discharge line is used together with a discharge line fill system (see Subsection 6.3.2.2.5) to prevent water hammer resulting from a pump start with an empty discharge line. A flow element in the pump discharge line is used to provide a measure of system flow and to originate automatic signals for control of the pump minimum flow valve. The minimum 1flow valve permits a small flow to the suppression pool in the event no discharge valve is open or in case vessel pressure is higher than pump shutoff head.

Using the suppression pool as the source of water for the LPCI establishes a closed loop for recirculation of LPCI water escaping from the break.

The design pressure and temperature for various portions of the system were established in accordance with the ASME Section III Boiler and Pressure Vessel code and the required RHR system design specification written for this system. The RHR System Process Diagram (Dwgs. M1-E11-3, Sh. 1, and M1-E11-3, Sh. 2) was used as input in the development of the design specification.

LPCI pumps and equipment are described in detail in Subsection 5.4.7, which also describes the other functions served by the same pumps if not needed for the LPCI function. The RHR heat exchangers are not associated with the emergency core cooling function. The heat exchangers are discussed in Subsection 6.2.2. The portions of the RHR required for accident protection including support structures are designed in accordance with Seismic Category I criteria (see Chapter 3). The LPCI pump characteristics are shown in Figure 6.3-119.

FSAR Rev. 71 6.3-15

SSES-FSAR Text Rev. 73 The LPCI system incorporates a relief valve on each pump suction line and the LPCI discharge header which protects the components and piping from inadvertent overpressure conditions.

These valves are set to relieve pressure at 165 psig and 450 psig, respectively.

Provisions are included in the LPCI system to permit testing of the system. These provisions are:

1) All active LPCI components are designed to be testable during normal plant operation.

2) A discharge test line is provided for the four pumps to route suppression pool water back to the suppression pool without entering the reactor pressure vessel.

3) Instrumentation is provided to indicate system performance during normal and test operations.

4) All motor-operated valves, air-operated valves and check valves are capable of operation for test purposes. The RHR Pump discharge check valves (151/251 F031A,B,C&D) have local disc position indication on the valve hinge pins.

5) Shutdown lines taking suction from the recirculation system are provided to permit testing of the pump discharge into the reactor pressure vessel after normal plant shutdown and to provide for shutdown cooling.

6) All relief valves are removable for bench testing during plant shutdown.

6.3.2.2.4.1 NPSH AVAILABLE FOR RHR The available NPSH is calculated in accordance with Regulatory Guide 1.1. The following data is used for a typical NPSH calculation:

a. The suppression pool is at the minimum post-accident level of El. 667.3 feet. 667.3 El. is due to suppression pool draw down assuming the worst case break (Main Steam Line break inside containment).

b. The centerline of the pump suction is at El. 648-1/2.

c. The suction strainers (total of two strainers for each suction line) are filtering their design debris source term. The maximum pressure loss across the strainers at maximum runout flow of 13,800 gpm is 2.5 psi. The pump vendor required NPSH at runout flow is 5.0 feet.

d. Atmospheric pressure head is assumed to be equal to the vapor pressure, ha - hvp

e. The suppression pool water is assumed to be at 220°F.

f. NPSHA = hs - hf + ha - hvp hs = static head hf = friction head loss ha = atmospheric pressure head hvp = vapor pressure FSAR Rev. 71 6.3-16

SSES-FSAR Text Rev. 73 Based on Section 6.3.2.2.4.1.d, NPSHA = hS - hf with hs = 19.26 feet hf = 11.09 feet NPSHA = 19.26 - 11.09 NPSHA = 8.17 feet NPSHr = 5.0 feet 6.3.2.2.5 Discharge Line Fill System The discharge line fill system, described in this section, serves the ECCS discharge lines (RHR, CS and HPCI) and the RCIC discharge line.

A requirement of the core cooling systems is that cooling water flow to the reactor vessel be initiated rapidly when the system is called on to perform its function. This quick-start system characteristic is provided by quick-opening valves, quick-start pumps, and a standby ac power source. The time lag between the signal to start the pump and the initiation of flow into the RPV is minimized by the ECCS and RCIC discharge line fill system which continuously keeps the core cooling pump discharge lines filled and simultaneously prevents water hammer during the rapid start transient of the ECCS and RCIC pumps.

The discharge line fill system consists of fill lines which provide a continuous supply of condensate from the condensate transfer system to the high points of the ECCS discharge piping. Following initial venting and system fill, a pressure above atmospheric pressure is maintained at the system's high points to prevent air accumulation. A minor, but continuous inflow into the discharge lines is required primarily to make up for leakage across the check or stop check valves provided near the ECCS and RCIC pumps. Past experience has shown that these valves will leak slightly, producing a small backflow. The estimated make-up for the pump discharge lines is less than 1 gpm. To ensure that the discharge lines are always filled, indication is provided in the Control Room as to whether the condensate transfer pumps are operating. An alarm will indicate low condensate transfer pump discharge pressure which can be verified on a pressure indicator in the control room.

A pressure switch is provided to initiate this low pressure alarm. Two pressure switches are provided to initiate auto start of the standby transfer pump. (Refer to FSAR Dwg. M-108, Sh. 1.)

These pressure switches are primarily set to protect the condensate transfer pumps from operating at runout conditions. With one pump operation and approaching runout, tripping of the pressure switches will cause the second pump to start and thereby raise the pressure in the pump discharge header. The set point pressure for pump runout protection well exceeds the pump discharge pressure required for maintaining the injection lines pressurized. The fill lines for each system, therefore, are provided with pressure regulators to control the fill pressure to a few psi above atmospheric pressure at the systems high points so that entrapped air can be released through the high point vents during surveillance test. These pressure regulators have been permanently bypassed to allow the maximum available condensate transfer pressure to pass to the pump discharge headers. With the injection lines properly filled, vented, and pressurized, maintaining an adequate pump discharge header pressure will assure that the injection lines will remain filled with water.

A 2" fill line is provided for the discharge line of the HPCI train, the discharge line of the RCIC train, each of the two RHR trains, and each of the two core spray trains. The individual fill lines can be isolated to permit maintenance on the systems and on individual trains of a system without FSAR Rev. 71 6.3-17

SSES-FSAR Text Rev. 73 affecting the other train. Details are shown in the HPCI P&ID, Dwg. M-155, Sh. 1; the RHR P&ID, Dwgs. M-151, Sh. 1 and M-151, Sh. 3; the RCIC P&ID, Dwg. M-149, Sh. 1; and the CS P&ID, Dwg. M-152, Sh. 1. The condensate transfer pumps with associated instrumentation, including the low pressure alarm, are shown on the condensate and refueling water P&ID, Dwg. M-108, Sh. 1.

No level transmitters are provided to detect air bubbles upstream of injection valves.

Air pockets will be prevented by proper venting and filling and by maintaining the discharge lines continuously pressurized such that the pressure at the high points always exceeds atmospheric pressure. This will require a minor but continuous feed flow into the discharge lines to make up for valve leakage.

The presence of small, local air bubbles upstream of the injection valves will not be detrimental to the ECCS during the start transient.

Each RHR train has its own fill line and can be isolated from the other train. If one pump in an RHR train needs to be isolated for maintenance, the discharge line for the other pump will remain filled and pressurized to the isolation valve of that pump, allowing the pump to perform its function.

The condensate transfer pump discharge low pressure alarm instrumentation is tested in accordance with the Technical Requirements Manual. A channel functional test and a channel calibration are required.

A backup keepfill function is provided by the Demineralized Water System via a gravity feed system from an atmospheric tank (Refer to FSAR Section 9.2.9). The passive, backup keepfill capability provided for the ECCS & RCIC Systems assures that the systems are available for non-design basis accident events such as an Appendix R Fire (General

Reference:

PLA-4945).

The tank contains a minimum volume of 2000 gallons. The tank level is monitored on a periodic basis and is refilled as necessary. The minimum volume allows for reasonable operator response time in the event of a loss of the primary keepfill system from the Condensate Transfer System.

Surveillance tests to determine if the discharge lines for the RHR, HPCI, RCIC and CS systems are full are required by the plant Technical Specifications. The tests are performed by momentarily opening the vents at the system's high points to confirm the water fill and flow. No special fill and vent procedures are required prior to surveillance testing of these pumps.

6.3.2.3 Applicable Codes and Classification The applicable codes and classification of the ECCS are specified in Section 3.2. All piping systems and components (pumps, valves, etc.) for the ECCS comply with applicable codes, addenda, code cases, and errata in effect at the time the equipment is procured. The piping and components of each system of the ECCS within the containment and out to and including the pressure retaining injection valve are Safety Class 1. The remaining piping and components are Safety Class 2, 3, or non-code as indicated in Section 3.2, and as indicated on the individual system P&ID. The equipment and piping of the ECCS are designed to Seismic Category I requirements. This seismic designation applies to all structures and equipments essential to the core cooling function. IEEE codes applicable to the controls and power supplies are specified in Section 7.1.

FSAR Rev. 71 6.3-18

SSES-FSAR Text Rev. 73 6.3.2.4 Materials Specifications and Compatibility Materials specifications and compatibility for the ECCS are presented in Sections 6.1 and 3.2.

Nonmetallic materials such as lubricants, seals, packings, paints and primers, insulation, as well as metallic materials, etc., are selected as a result of an engineering review and evaluation for compatibility with other materials in the system and the surroundings with concern for chemical, radiolytic, mechanical and nuclear effects. Materials used are reviewed and evaluated with regard to radiolytic and pyrolytic decomposition and attendant effects on safe operation of the ECCS.

6.3.2.5 System Reliability A single failure analysis shows that no single failure prevents the starting of the ECCS when required, or the delivery of coolant to the reactor vessel. No individual system of the ECCS is single failure proof with the exception of the ADS, hence it is expected that single failures will disable individual systems of the ECCS. The most severe effects of single failures with respect to loss of equipment occur if the loss of coolant accident occurs in combination with an ECCS pipe break coincident with a loss of off-site power. The consequences of the most severe single failures are shown in Table 6.3-5.

6.3.2.6 Protection Provisions Protection provisions are included in the design of the ECCS. Protection is afforded against missiles, pipe whip, and flooding. Also accounted for in the design are thermal stresses, loadings from a LOCA, and seismic effects.

The ECCS piping and components located outside the primary containment are protected from internally and externally generated missiles by the reinforced concrete structure of the ECCS pump rooms. The pump rooms layout and protection is covered in Subsection 6.2.3.

The ECCS is protected against the effects of pipe whip, which might result from piping failures up to and including the LOCA. This protection is provided by separation, pipe whip restraints, and energy absorbing materials. These three methods are applied to provide protection against damage to piping and components of the ECCS which otherwise could result in a reduction of ECCS effectiveness to an unacceptable level. See Section 3.6 for criteria on pipe whip.

The component supports which protect against damage from movement and from seismic events are discussed in Subsection 5.4.14. The methods used to provide assurance that thermal stresses do not cause damage to the ECCS are described in Subsection 3.9.3.

The discharge lines from RHR System relief valves PSV-15106 A&B (Unit 1) and PSV-25106 A&B (Unit 2) penetrate primary containment and discharge below the surface of the suppression pool.

The corresponding line identification numbers for the discharge from these valves are 10"-HBB-120 (Unit 1) and 10"-HBB-220 (Unit 2). These lines have been designed and installed recognizing the full effect of the dynamic loads resulting from the normal water clearing of the submerged portion of the lines.

6.3.2.7 Provisions for Performance Testing Periodic system and component testing provisions for the HPCI and Core Spray System are described in Subsection 6.3.2.2 as part of the individual system descriptions. These provisions for ADS are described in Subsection 6.3.4.2.2 and for LPCI in Subsection 6.3.4.2.4.

FSAR Rev. 71 6.3-19

SSES-FSAR Text Rev. 73 6.3.2.8 Manual Actions With one exception, the ECCS is actuated automatically and requires no operator action during the first 20 minutes following the accident. The only operator action assumed in the Section 6.3 ECCS analysis is that a RHR heat exchanger is placed in service within 20 minutes into the accident.

The NPSH requirements of the CS pump and the LPCI (RHR) pump are shown in Figures 6.3-118 and 6.3-119, respectively.

During the long-term cooling period, the operator will take action as specified in Subsection 6.2.2.2 to place the containment cooling system into operation. Placing the containment cooling mode system into operation is the only manual action that the operator needs to accomplish during the course of the LOCA.

The operator has multiple instrumentation available in the control room to assist him in assessing the post-LOCA conditions. This instrumentation provides reactor vessel pressures and water levels, and containment pressure, temperature and radiation levels as well as indicating the operation of the ECCS. ECCS flow indication is the primary parameter available to assess proper operation of the system. Other indications such as position of valves, status of circuit breakers, and essential power bus voltage are also available to assist him in determining system operating status. The electrical and instrumentation complement to the ECCS is discussed in detail in Chapter 7.3. Other available instrumentation is listed in the P&IDs for the individual systems.

Much of the monitoring instrumentation available to the operator is discussed in more detail in Chapter 5 and Section 6.2.

6.3.2.9 Position Verification for Manual Valves Consideration has been given to the possibility that manual valves in the ECCS might be left in the wrong position when an accident occurs. Table 6.3-9 lists all the manually-operated valves in the ECCS (ADS, LPCI, Suppression Pool Cooling, Core Spray, and HPCI) and summarizes the methods for assuring correct valve position. The table lists only those manual valves which are related to the ECCS function of those systems. Thus, the only manual valves in the RHR system which were evaluated are those which comprise part of the LPCI and Suppression Pool Cooling modes. The boundaries of RHR for this purpose include sidestreams and connecting systems out to the first normally-closed remotely operated valve or to two check valves in series.

Many of the manual valves in these systems are vent, drain, or test connection valves which are normally closed and capped or have cam-locks where evaluated. These valves are identified in the "Function" column of Table 6.3-9. Such valves are not critical to the ECCS function; administrative controls, such as pre-startup valve lineup checks, should suffice to reasonably assure that such valves will not degrade ECCS performance.

Certain other valves are physically secured in their normal position to prevent inadvertent mispositioning. Valve manipulations are procedurally/administratively controlled in such a manner as to ensure accurate status control and proper restoration. In other cases, two isolation valves are provided in series to minimize the possibility of inter- or intra- system leakage. Again, such valves are identified in the "Function" column of Table 6.3-9.

FSAR Rev. 71 6.3-20

SSES-FSAR Text Rev. 73 Remote position indication of manual valves which are in the main flowpaths of the ECCS (except for makeup gas supply to the ADS valve accumulators) and which will be inaccessible during normal operation is provided in the control room. Proper administrative controls and/or surveillance testing are relied upon to assure the position of the remaining valves.

6.3.3 ECCS PERFORMANCE EVALUATION ECCS performance is evaluated using approved 10CFR50 Appendix K models for demonstrating conformance to the acceptance criteria of 10CFR50.46. The ECCS performance is evaluated for the entire spectrum of break sizes for postulated loss of coolant accidents. The Section 15 accidents for which ECCS operation is required are:

15.2.8 Feedwater piping break 15.6.4 Spectrum of BWR steam system failures outside of containment 15.6.5 Loss-of-Coolant Accidents.

Section 15.6.5.5 provides radiological consequences of the DBA LOCA and the Main Steam Line Break events.

Evaluations for Susquehanna Units 1 and 2 with ATRIUM-10 and ATRIUM-11 fuel under uprated reactor power conditions have been performed. The results are used in analyses specific to the fuel neutronic design to demonstrate conformance to the acceptance criteria of 10CFR50.46. The analyses assumed an analytical power level of 4031 MWt which supports nominal rated powers as high as 3952 MWt. The analyses were performed using the NRC approved methodologies EXEM BWR LOCA given in Reference 6.3-23 for ATRIUM-10 and AURORA-B LOCA for ATRIUM-11 fuel. References 6.3-25 to 6.3-27 collectively comprise the AURORA-B LOCA Evaluation Model.

6.3.3.1 ECCS Bases for Technical Specifications The maximum average planar linear heat generation rates calculated in this performance analysis provide the basis for Technical Specifications designed to ensure conformance with the acceptance criteria of 10CFR50.46. Minimum ECCS functional requirements are specified in Subsections 6.3.3.4 and 6.3.3.5, and testing requirements are discussed in Subsection 6.3.4.

Limits on minimum suppression pool water level are discussed in Section 6.2.

6.3.3.2 Acceptance Criteria for ECCS Performance The applicable acceptance criteria, extracted from 10 CFR 50.46, are listed and for each criterion, applicable parts of Subsection 6.3.3 where conformance is demonstrated are indicated.

Criterion 1, Peak Cladding Temperature - "The calculated maximum fuel element cladding temperature shall not exceed 2200oF." Conformance to Criterion 1 is shown in Table 6.3-3B-2 for Unit 1 and Unit 2.

Criterion 2, Maximum Cladding Oxidation - "The calculated total local oxidation of the cladding shall nowhere exceed 0.17 times the total cladding thickness before oxidation." Conformance to Criterion 2 is shown in Table 6.3-3B-2 for Unit 1 and Unit 2.

FSAR Rev. 71 6.3-21

SSES-FSAR Text Rev. 73 Criterion 3, Maximum Hydrogen Generation - "The calculated total amount of hydrogen generated from the chemical reaction of the cladding with water or steam shall not exceed 0.01 times the hypothetical amount that would be generated if all the metal in the cladding cylinder surrounding the fuel, excluding the cladding surrounding the plenum volume, were to react." Conformance to Criterion 3 is shown in Table 6.3-3B-2 for Unit 1 and Unit 2.

Criterion 4, Coolable Geometry - "Calculated changes in core geometry shall be such that the core remains amenable to cooling." As described in Reference 6.3-14 conformance to Criterion 4 is demonstrated by conformance to Criteria 1, 2 and 3.

Criterion 5, Long-Term Cooling - "After any calculated successful initial operation of the ECCS, the calculated core temperature shall be maintained at an acceptably low value and decay heat shall be removed for the extended period of time required by the long-lived radioactivity remaining in the core." Conformance to Criterion 5 is demonstrated generically for General Electric BWRs in Reference 6.3-2,Section III.A as modified by Reference 6.3-20. Briefly summarized, the core remains covered to at least the jet pump suction elevation and the uncovered region is cooled by spray cooling and by steam generated in the covered part of the core.

6.3.3.3 Single Failure Considerations The functional consequences of potential single failures in the ECCS are discussed in Subsection 6.3.2.5. There it is shown that all potential single failures are no more severe than one of the single failures identified in Table 6.3-5.

It is therefore only necessary to consider each of these single failures in the emergency core cooling system performance analyses.

Based on the EXEM BWR LOCA methodology (Reference 6.3-23) used for ATRIUM-10 fuel a large break in the recirculation suction piping with an LPCI single valve failure is the most severe failure.

A single failure in the ADS (one ADS valve) has no effect on large breaks. In calculations performed for the ATRIUM-10 fuel, a single failure in the ADS (one ADS valve fails to open) is explicitly evaluated as a distinct failure. For all other single failure scenarios that were analyzed, it was assumed that one ADS valve does not open.

Based on the AURORA-B LOCA methodology (References 6.3-25 to 6.3-27) used for ATRIUM-11 fuel, a 0.07 ft2 break in the recirculation discharge piping with a single failure of the backup battery (DC) power is the most severe failure.

6.3.3.4 System Performance During the Accident In general, the system response to an accident can be described as:

1) receiving an initiation signal,

2) a small lag time (to open all valves and have the pumps up to rated speed), and

3) finally the ECCS flow entering the vessel.

FSAR Rev. 71 6.3-22

SSES-FSAR Text Rev. 73 Key ECCS actuation set points and time delays for all the ECC systems are provided in Table 6.3-2B for Unit 1 and Unit 2. The minimization of the delay from the receipt of signal until the ECCS pumps have reached rated speed is limited by the physical constraints on acceleration of the diesel-generators and pumps.

Simplified piping and instrumentation and functional control diagrams for the ECCS are provided in Subsection 6.3.2. The operational sequence of ECCS for the limiting LOCA event is shown in Table 6.3-1B-2 for Unit 1 and Unit 2.

Operator action is not required, except as a monitoring function, during the short term cooling period following the LOCA. During the long-term cooling period, the operator will take action as specified in Subsection 6.2.2.2 to place the containment cooling system into operation. Long-term cooling capabilities are not impaired by a leak from the first isolation valve outside the suppression pool. Suppression pool water leakage can be made up by several methods. Leakage into the ECCS pump room will not flood high enough to communicate with other rooms. By maintaining water levels in the suppression pool, water level will eventually level out in the ECCS room stopping the leak. Making up suppression pool water can be done by either putting additional water directly into the suppression pool or into the vessel (assuming a LOCA).

6.3.3.5 Use of Dual Function Components for ECCS With the exception of the LPCI system, the systems of the ECCS are designed to accomplish only one function: to cool the reactor core following a loss of reactor coolant. To this extent, components or portions of these systems (except for pressure relief) are not required for operation of other systems which have emergency core cooling functions, or vice versa. Because either the ADS initiating signal or the overpressure signal opens the safety relief valve, no conflict exists.

The LPCI system, however, uses the RHR pumps and some of the RHR valves and piping.

When the reactor water level is low, the LPCI system has priority through the valve control logic over the other RHR subsystems for containment cooling or shutdown cooling. Immediately following a LOCA, the RHR system is directed to the LPCI mode. The LPCI system can be used to support long term containment cooling as well as its primary ECCS support function of cooling the reactor core following a loss of reactor coolant, as discussed in section 6.2.2.2 of the FSAR. The effects of this dual use for the LPCI system have been analyzed for ATRIUM-10 fuel (Reference 6.3-14) and ATRIUM-11 fuel (Reference 6.3-24).

6.3.3.6 Limits on ECCS System Parameters The limits on the ECCS system parameters are discussed in Subsections 6.3.3.1 and 6.3.3.7.1.

Any number of components in any given system may be out of service, up to and including the entire system. The maximum allowable out of service time is a function of the level of redundance and the specified test intervals as discussed in Section15A.

FSAR Rev. 71 6.3-23

SSES-FSAR Text Rev. 73 6.3.3.7 ECCS Analyses for LOCA 6.3.3.7.1 LOCA Analysis Procedures and Input Variables ATRIUM-10 Fuel The procedures approved for LOCA analysis conformance calculations are described in detail in References 6.3-14 and 6.3-15. These procedures were used in the calculations discussed in this Subsection 6.3.3 for ATRIUM-10 fuel. The EXEM BWR LOCA application methodology (Reference 6.3-23) is used to demonstrate compliance with the first three 10CFR50.46 criteria.

The methodology defines the plant-specific break spectrum using inputs and models as required by 10CRF50 Appendix K.

Three major AREVA computer codes are used to determine the LOCA response for the Susquehanna LOCA analysis. These codes are RODEX2, RELAX and HUXY. Together, these codes evaluate the reactor vessel blowdown response to a pipe rupture, the subsequent core flooding by ECCS, and the fuel cladding heatup. Figure 4.1 of Reference 6.3-14 is a flow diagram of these computer codes, indicating the major code functions and the transfer of major parameters.

The purpose of each code is described below.

FUEL PARAMETERS ANALYSIS (RODEX2)

A complete analysis for a given break starts with the specification of fuel rod parameters as determined by RODEX2. RODEX2 is first used to determine the initial stored energy for both the blowdown analysis (RELAX) system and hot channel) and the heatup analysis (HUXY). RODEX2 is also used to calculate fuel parameters such as fuel to cladding gap sizes and heat transfer coefficients for use in HUXY calculations.

BLOWDOWN ANALYSIS (RELAX)

Relax is used to calculate the system thermal hydraulic response during the blowdown phase of the LOCA. The RELAX analysis is performed from the time of the break initiation to the time the ECCS low pressure core spray flow reaches its rated value and the intact recirculation loop isolation valve is fully closed. The RELAX system blowdown calculation provides the system thermal-hydraulic conditions during this time as boundary conditions for the RELAX hot channel model and at the end of this time for use in initialing the refill/reflood analysis.

The RELAX hot channel analysis is performed to analyze the maximum power assembly of the core. The hot channel is assumed to be operating on fuel thermal limits prior to the occurrence of the postulated LOCA. The results from the RELAX hot channel calculation are heat transfer coefficients and fluid conditions that are used for input to the HUXY heatup analysis.

REFILL/REFLOOD ANALYSIS (RELAX)

The RELAX code is also used to analyze the LOCA beginning with the time of both rated core spray flow and intact recirculation loop isolation valve closure. The RELAX code computes the system hydraulic response during the refill/reflood phase of a LOCA. The refill stage is the period when the lower plenum is filling due to ECCS injection. The reflood period is when the core is being reflooded with ECCS water. The principal result of a RELAX calculation is the time when the two-phase fluid reaches the hot node in the core by entrainment of the reflooding fluid, termed as the time of hot node (or core) reflood. The RELAX calculations provide HUXY with the time of hot FSAR Rev. 71 6.3-24

SSES-FSAR Text Rev. 73 node reflood and the time when the liquid has risen in the bypass to the height of the axial plane of interest (time of bypass reflood)

HEATUP ANALYSIS (HUXY)

The HUXY code is used to perform heatup calculations for the entire LOCA transient and yields peak cladding temperature and local cladding oxidation. The heat generated by metal-water reaction is included in the HUXY analysis. HUXY is used to calculate the thermal response of each fuel rod in one axial plane of the hot rod. The HUXY code implements the clad swelling and rupture models from NUREG-0630 and complies with the NRC criteria stated in 10CFR50 Appendix K for LOCA Evaluation Models.

The significant input variables used by the LOCA codes for analysis of ATRIUM-10 fuel are listed in Table 6.3-2B.

ATRIUM-11 Fuel The procedures approved for LOCA analysis conformance calculations are described in detail in Reference 6.3-24. These procedures were used in the calculations discussed in this Subsection 6.3.3 for ATRIUM-11 fuel. The AURORA-B LOCA application methodology (References 6.3-25 to 6.3-27) is used to demonstrate compliance with the first three 10CFR50.46 criteria. The methodology defines the plant-specific break spectrum using inputs and models as required by 10CRF50 Appendix K. The AURORA-B LOCA methodology employs two major computer codes to evaluate the system and fuel response during all phases of a LOCA. These are the S-RELAP5 and RODEX4 computer codes. A single S-RELAP5 model is used to calculate the response of the system, hot channels, and hot rods during all phases of the LOCA to determine the PCT and maximum local clad oxidation for each break spectrum or exposure analysis case.

A complete analysis starts with the specification of fuel parameters using RODEX4 (Reference 6.3-27). RODEX4 is used to determine the maximum initial stored energy of the fuel over the exposure range and to provide fuel properties to S-RELAP5 through a data file at specific exposures. The initial stored energy used in S-RELAP5 is increased to be higher than that calculated by RODEX4 for the power, exposure, and fuel design being considered.

6.3.3.7.2 Accident Description A detailed description of the LOCA calculation is provided in Reference 6.3-14 for the ATRIUM-10 fuel and Reference 6.3-24 for ATRIUM-11 fuel.

The LOCA analyses covered a spectrum of break sizes in the suction and discharge piping of one of the recirculation loops. For the double-ended guillotine (DEG) break, the discharge coefficients, that characterize the rate at which coolant can escape from the break, were varied to span the condition at which the maximum PCT may occur. A discharge coefficient of 1.0 corresponds to full double-ended guillotine break with an area of 7.0 ft2. For smaller pipe breaks, (longitudinal splits in the piping), areas of the opening were varied from 3.5 ft2 to 0.2 ft2. Two average axial power shapes (top peaked and mid peaked) were analyzed. Two single failure conditions were analyzed, battery failure (disabling the HPCI system) and a failure of a single injection valve in the LPCI.

FSAR Rev. 71 6.3-25

SSES-FSAR Text Rev. 73 A double ended guillotine break (1.0 DEG) of the recirculation suction line with a single LPCI valve failure using ECCS nominal delay times is the limiting break (highest PCT) for ATRIUM-10.

System hot channel and hot node response curves for the ATRIUM-10 analysis are shown in Figures 6.3-201 through 6.3-221.

For this analysis, the discharge valve in the broken recirculation loop is assumed to close when a suction side break occurs. This assumption allows credit to be taken for the LPCI flow in the failed recirculation loop.

Detailed discussion of the limiting LOCA for and system response curves for the ATRIUM-11 analysis are provided in Reference 6.3-24.

A short description of the major events during the limiting design basis accident (DBA) is included below.

At the beginning of the event the pipe break occurs, and offsite power is assumed to be unavailable. The core flow drops rapidly during the first 1 second, then pauses for the next 5 seconds before dropping to essentially zero between 10 and 20 seconds. The pause in the core flow reduction results from pressurization due to closure of MSIV. Loss of offsite power initiates the MSIV closure, which is delayed by 2 seconds. In response to the MSIV position at 85% open, a control rod scram signal is generated. The scram serves to shut down the reactor from full power operation.

During the early portion of the event, the recirculation drive flow in the broken loop ceases almost immediately. The flow in the drive line of the broken loop then reverses causing vessel inventory depletion through the jet pump nozzles and out the break. Also, at the beginning of the event, the intact loop recirculation pump is tripped due to the assumed loss of offsite power and begins to coast down. The remainder of the coastdown (after about 5 seconds) is then governed by natural circulation as the intact loop coastdown progresses, until the pressure in the lower plenum reaches the saturation pressure of the water in the lower plenum.

At around 8 seconds, the water level in the downcomer region outside the core shroud reaches the top of the jet pumps. Once the top of the jet pumps are uncovered, the core flow drops almost immediately to zero. Prior to this time, the core flow had been sustained primarily by natural circulation effects. However, once the top of the jet pumps uncover, the natural circulation flow from the downcomer region drop to zero, and the jet pumps are no longer capable of functioning in their intended manner. The result is an almost complete stagnation of core flow.

Liquid continues to be lost from the downcomer region until the break at the recirculation suction nozzle is uncovered (around 11 seconds). At this time the vessel depressurizes more rapidly as the break flow changes form primarily liquid flow to a liquid steam mixture. Shortly thereafter, the vessel pressure reaches the saturation point of the previously subcooled liquid in the lower plenum.

At this time, around 14 seconds, a significant portion of the fluid in the lower plenum flashes (vaporizes) to steam. The lower plenum flashing causes a brief but significant increase in the core flow as the vaporization displaces the liquid, and the volume expansion pushes steam and liquid into the core.

The core flow decrease due to jet pump uncovery causes the liquid mass in the bundles to drop rapidly due to the combination of the lack of core flow and the ensuing vaporization of fluid in the bundles. The lower plenum flashing provides a source of liquid to the core which is vaporized to steam within a few seconds, causing the liquid mass in the bundles to once again drop rapidly.

FSAR Rev. 71 6.3-26

SSES-FSAR Text Rev. 73 This begins the period of core uncovery, which persists until the ECC systems begin injecting coolant into the reactor vessel.

The following discussion explains the interrelationship between the thermal hydraulic phenomena and the fuel response (primarily peak cladding temperature).

Figure 6.3-221 represents the temperature versus time for the fuel rod where the maximum PCT value is observed.

The first notable occurrence affecting the PCT response occurs near the time of jet pump uncovery. At this time, the heat transfer rates in the hot channel drop dramatically. This causes a heat up in the upper nodes in the bundle as the fuel rods are exposed to a predominantly vapor mixture. Shortly after the jet pump uncovery, the lower plenum flashed. This flashing provides a surge of core flow which replenishes the bundle inventory with a predominately liquid mixture. This causes a short term improvement in heat transfer. As a result, the cladding temperature decreases for the corresponding time.

Once the flashing in the lower plenum subsides and the steam-liquid mixture in the core begins to recede, all the fuel nodes uncover and begin to heat up. This condition continues until the ECC systems begin to inject coolant into the core.

At approximately 50 seconds, core spray injection begins and coolant is sprayed over the top of the core. Some of the core spray flow will penetrate down into the fuel channels, providing spray cooling to the bundles. In some locations, the fluid will be unable to penetrate into the fuel channels due to the high steam upflow. This phenomena, termed counter current flow limitation (CCFL), may cause a build up of accumulated core spray flow in the upper plenum if the injected flow exceeds that which can drain into the core region. A portion of the fluid which accumulates in the upper plenum will drain down into the core bypass region (inside the core but outside the fuel channels). This fluid may also drain into the fuel bundles located on the core periphery, or may drain into the CCFL limited bundles as the rate of steam upflow decreases through these bundles.

The fluid which enters the core bypass region will either pass down into the lower plenum region through the leakage paths in the lower fuel support casting or lower tie plate, or may pass through the leakage paths in the channel directly into the lower portion of the fuel bundles.

The availability of coolant from the core spray system provides a direct heat transfer benefit after the end of system blowdown at about 66 seconds. Once rated core spray flow is attained credit for cooling due to core spray is taken in the ATRIUM-10 and ATRIUM-11 analyses. This approach is used since testing has demonstrated the applicability of the spray cooling coefficients provided in Appendix K of 10CFR50 to the ATRIUM-10 and ATRIUM-11 fuel designs.

The LPCI system has a failed valve and is unavailable in the intact recirculation loop. However, the full LPCI flow is available in the broken loop when the discharge valve in that loop is fully closed at 84 seconds, (Figure 6.3-210). Water introduced into the upper plenum from the CS starts passing through the core by way of the passages between the fuel channels and through lower power fuel assemblies to the lower plenum at about 66 seconds. The lower plenum continues to fill providing a water-steam mixture to the core. At about 120 seconds, the cladding temperature reaches a peak when the flow of liquid to the hot node of the core is sufficient to maintain cooling.

FSAR Rev. 71 6.3-27

SSES-FSAR Text Rev. 73 6.3.3.7.3 Break Spectrum Calculations A complete spectrum of postulated break sizes and locations is considered in the evaluation of ECCS performance.

A summary of the results of the break spectrum calculations is shown in Table 6.3-3C. These results are from References 6.3-14 and 6.3-24. Conformance to the acceptance criteria (PCT 2200°F, local oxidation 17% and core wide metal-water reaction 1%) is provided in Table 6.3-3B-2.

The peak clad temperature for the limiting break shown in Table 6.3-3B-2 differs slightly from those shown in Table 6.3-3C. Table 6.3-3B-2 results are from Reference 6.3-15, which is the analysis that establishes the MAPLHGR for the SSES Units. The results in Table 6.3-3C provide a relative comparison for the various conditions assumed for the break spectrum analyses.

For convenience in describing the LOCA phenomena, the break spectrum has been separated into two regions: small breaks and large breaks. The large breaks are those in the area range of 7.0 to 3.5 ft2, while small breaks are those smaller than 3.5 ft 2.

The small break region provides a slower depressurization of the reactor vessel, delaying the time for low pressure ECC systems to become effective. As a result, failure of high pressure coolant injection (HPCI) is expected to be involved in the most limiting single failure scenario.

The large break region provides a rapid depressurization of the reactor vessel, making the HPCI and ADS systems relatively unimportant in determining the consequences of a LOCA. As a result, a failure involving the low pressure ECC systems is expected to be involved in the most limiting single failure scenario. As discussed in Section 6.3.3.7.4, the most limiting single failure in this region is the LPCI injection valve, disabling LPCI injection to the intact loop.

As demonstrated in Table 6.3-5, plants which incorporate the LPCI modification have a different complement of ECCS components available depending on break location (recirculation discharge or suction piping) and single failure assumptions. Analyses are performed for both locations to determine at which location the limiting DBA occurs.

6.3.3.7.4 Large Recirculation Line Break Calculations In this region, the vessel depressurizes rapidly and the HPCI has an insignificant effect on the event. Consequently, failure of the core spray or LPCI is more severe.

The highest calculated PCT for large breaks corresponds to a 1.0 DEG guillotine break with the break flow at each of the two ends of the recirculation suction piping unimpeded by the other (Tables 6.3-3B-2 and 6.3-3C). The ATRIUM-10 limiting large break results are shown in Figures 6.3-201 through 6.3-221. The ATRIUM-11 limiting break results are provided in Reference 6.3-24.

6.3.3.7.5 Transition Recirculation Line Break Calculations The break sizes analyzed for the ATRIUM-10 and ATRIUM-11 fuel are characterized as large and small only.

FSAR Rev. 71 6.3-28

SSES-FSAR Text Rev. 73 6.3.3.7.6 Small Recirculation Line Break Calculations As described in Section 6.3.3.7.2, analyses were performed for two initial flow conditions, two average axial power shapes (top peaked and mid-peaked), and two single failure conditions (single LPCI valve failure and battery failure - disabling the HPCI system). Failures were assumed to occur in either the suction side or the discharge side of the recirculation loop piping.

The ATRIUM-10 analyses showed that the most limiting break for all of these conditions was a large double-ended guillotine break and that small breaks were not limiting regardless of the single failure condition, (Reference 6.3-14). The ATRIUM-11 analyses demonstrate that a small break is the most limiting break (Reference 6.3-24). See Table 6.3-3C for results with different break sizes.

6.3.3.7.7 Calculations for Other Break Locations General Electric performed analyses for non-recirculation line breaks as part of the original power uprate analysis (References 6.3-8 and 6.3-10). Events evaluated included: core spray line break, feedwater line break, steamline break inside containment, and steamline break outside containment. These analyses clearly demonstrated that these postulated events are significantly less limiting than the postulated recirculation line breaks.

Framatome analyzed the core spray line break at 4031 MWt in References 6.3-14 and 6.3-24 and confirmed that this break remains less limiting than the recirculation line breaks.

Thus, non-recirculation line breaks are not considered to be potentially limiting and are not specifically analyzed.

6.3.3.8 LOCA Analysis Conclusions Having shown compliance with the applicable acceptance criteria of Subsection 6.3.3.2, it is concluded that the ECCS will perform its function in an acceptable manner and meet all of the 10CFR50.46 acceptance criteria, given operation at or below the maximum average planar linear heat generation rates as specified in the current cycle Core Operating Limit Report (COLR) for each unit (see FSAR Section 16.3, Technical Requirements Manuals).

6.3.4 TESTS AND INSPECTIONS 6.3.4.1 ECCS Performance Tests All systems of the ECCS were tested for their operational ECCS function during the pre-operational and/or startup test program. Each component was tested for power source, range, direction of rotation, set point, limit switch setting, torque switch setting, etc. Each pump was tested for flow capacity for comparison with vendor data. (This test was also used to verify flow measuring capability.) The flow tests involved the same suction and discharge source; i.e., suppression pool or condensate storage tank.

All logic elements except sensors and relays were tested individually and then as a system to verify complete system response to emergency signals including the ability of valves to revert to the ECCS alignment from other positions.

FSAR Rev. 71 6.3-29

SSES-FSAR Text Rev. 73 Finally the entire system was tested for response time and flow capacity taking suction from its normal source and delivering flow into the reactor vessel. This last series of tests was performed with power supplied from both offsite power and onsite emergency power.

See Chapter 14 for a thorough discussion of pre-operational testing for these systems.

6.3.4.2 Reliability Tests and Inspections The average reliability of a standby (non-operating) safety system is a function of the duration of the interval between periodic functional tests. The factors considered in determining the periodic test interval of the ECCS are: the desired system availability (average reliability), the number of redundant functional system success paths, the failure rates of the individual components in the system, and the schedule of periodic tests (simultaneous versus uniformly staggered versus randomly staggered). For the ECCS the above factors were used to determine safe test intervals utilizing the methods described in Reference 6.3-1.

All of the active components of the HPCI, CS, and LPCI systems are designed so that they may be tested during normal plant operation. Full flow test capability is provided by a test line back to the suction source. The full flow test is used to verify the capacity of each ECCS pump loop while the plant remains undisturbed (except for a slight disturbance during HPCI testing) in the power generation mode. In addition, each individual valve may be tested during normal plant operation.

Input jacks are provided such that by opening the injection valve breaker, each ECCS loop can be tested for response time.

All of the active components of the ADS system are also designed so that they may be tested during normal plant operation. Tests performed every 24 months include a logic system functional test of the ADS system and manual operation of the ADS valves. ADS valves and their associated solenoid valves which have been overhauled during a plant outage are tested during the startup following that outage.

Testing of the initiating instrumentation and controls portion of the ECCS is discussed in Subsection 7.3.1. The emergency power system, which supplies electrical power to the ECCS in the event that offsite power is unavailable, is tested as described in Subsection 8.3.1. The frequency of testing is specified in the Technical Specifications. Visual inspections of all the ECCS components located outside the drywell can be made at any time during power operation subject to ALARA concerns. Components inside the drywell can be visually inspected only during periods of access to the drywell. When the reactor vessel is open, the spargers and other internals can be inspected.

6.3.4.2.1 HPCI Testing The HPCI system can be tested at full flow with condensate storage tank water at any time during plant operation except when the reactor vessel water level is low, or when the condensate level in the condensate storage tank is below the reserve level, or when the valves from the suppression pool to the pump are open. If an initiation signal occurs while the HPCI system is being tested, the system returns automatically to the operating mode except as noted below. The following actions, FSAR Rev. 71 6.3-30

SSES-FSAR Text Rev. 73 which prevent the system from automatically returning to the operating mode, can be taken during HPCI system testing:

a) The F006 (injection valve) breaker may be opened to prevent inadvertent RPV injection.

b) The F008 and F011 test line valves may be prevented from automatic closure on a HPCI initiation. This is done to prevent possible system damage that could unnecessarily occur should the valves close during the test.

c) Additionally, some HPCI testing is required to be performed with the flow controller in manual.

For all configurations, manual actions can be taken to realign the system for vessel injection.

A design flow functional test of the HPCI system over the operating pressure and flow range is performed by pumping water from the condensate storage tank and back through the full flow test return line to the condensate storage tank. The HPCI system turbine pump is driven at its rated output by steam from the reactor. The suction valves from the suppression pool and the discharge valves to the feedwater lines remain closed. These two valves are tested separately to ensure their operability.

Inservice testing of pumps and valves in the HPCI system is discussed in Section 3.9.6. The HPCI pump discharge line, as well as its tributary filling line from the condensate transfer system, is normally protected from full reactor pressure by containment isolation valves which are designated as ASME Section XI-IWV category A. These valves will be leak-rate tested in accordance with the Code. Valves HV-E41-1(2)F006, 1(2)-55-038, and B21-1(2)F010B comprise the containment isolation arrangement for the HPCI discharge line. Valve F006 is a normally-closed, motor-operated gate valve which will open automatically only upon a HPCI initiation signal (coincidence of RPV low level and/or high drywell pressure). Valve 1(2)-55-038 is a normally locked-closed manual valve. Valve F010B is a quick-closing, tilting-disk check valve.

In addition, further isolation of the HPCI discharge line from the reactor coolant pressure boundary is provided by check valve 1(2)41818B, which is designated as ASME Category A. Therefore, adequate protection of the low pressure portions of the HPCI discharge line is provided by the aforementioned valves, and leakrate testing of check valves FOO5, 1(2)-55-012, and 1(2)-55-013 is unwarranted. The HPCI test conditions are tabulated on the HPCI process flow diagram, Dwg. M1-E41-4, Sh. 1.

6.3.4.2.2 ADS Testing The ADS valves are tested every 24 months. This testing includes simulated automatic actuation of the system throughout its emergency operating sequence, but excludes actual valve actuation.

Each individual ADS valve is manually actuated.

During plant operation the ADS system can be checked as discussed in Subsection 7.3.1.1a.1.4.

6.3.4.2.3 CS Testing The CS pump and valves are tested periodically during reactor operation. With the injection valve closed and the return line open to the suppression pool, full flow pump capability is demonstrated.

The injection valve and the check valve are tested in a manner similar to that used for the LPCI FSAR Rev. 71 6.3-31

SSES-FSAR Text Rev. 73 valves. The system test conditions during reactor shutdown are shown on the CS system process diagram, Dwg. M1-E21-15, Sh. 1. The portion of the CS outside the drywell may be inspected for leaks during tests.

Inservice testing of pumps and valves in the Core Spray system is discussed in Section 3.9.6.

The core spray pump discharge lines are protected from full reactor pressure by containment isolation valves which are designated as ASME Category A. These valves will be leak-rate tested in accordance with the Code. Valves HV-E21-1(2) F005 A and B, 1(2) F006 A and B, and 1(2) F037A and B comprise the containment isolation arrangement for the core spray injection lines. Normally-closed, motor-operated valve F005A(B) is interlocked such that it will open automatically upon receipt of a LOCA signal only if reactor pressure is below core spray system design pressure. This design configuration is considered to conform with the criteria set forth in NRC Standard Review plan (NUREG 75-087) Section 6.3, Paragraph III.11.a.

6.3.4.2.4 LPCI Testing Each LPCI loop can be tested during reactor operation. The test conditions are tabulated in Dwgs. M1-E11-3, Sh. 1 and M1-E11-3, Sh. 2. During plant operation, this test does not inject cold water into the reactor because the injection line check valve is held closed by the recirculation loop pressure, which is higher than the pump pressure, and because of the normally closed injection valve (F015). The injection line portion is verified not to be obstructed whenever the Shutdown Cooling (SDC) Mode of the RHR System is placed in service. Verification during operation in the SDC Mode in lieu of an additional test minimizes thermal stresses.

To test a LPCI pump at rated flow, the test line valve to the suppression pool is required to be open, the pump suction valve from the suppression pool is required to be open (this valve is normally open), and the pumps are started using the remote/manual switches in the control room.

Correct operation is determined by observing the instruments in the control room.

If an initiation signal occurs during the test, the RHR system returns to the LPCI mode. The valves in the test bypass lines are closed automatically to assure that the LPCI pump discharge is correctly routed to the recirculation loop.

6.3.5 INSTRUMENTATION REQUIREMENTS Design details including redundancy and logic of the ECCS instrumentation are discussed in Section 7.3.

All instrumentation required for automatic and manual initiation of the HPCI, CS, LPCI and ADS is discussed in Subsection 7.3.2 and is designed to meet the requirements of IEEE 279 and other applicable regulatory requirements. The HPCI, CS, LPCI and ADS can be manually initiated from the control room.

The HPCI System is automatically initiated on low reactor water level or high drywell pressure.

CS and LPCI are automatically initiated on a low reactor water level or high drywell pressure initiation signal and the high drywell pressure initiation must be accomplished by a reactor vessel low pressure permissive signal. (See Table 6.3-2B for specific initiation levels for each system.)

The ADS is automatically actuated by sensed variables for reactor vessel low water level and drywell high pressure plus the indication that at least one LPCI pump or both CS pumps in the same loop are operating. The CS and LPCI automatically return from system flow test modes to FSAR Rev. 71 6.3-32

SSES-FSAR Text Rev. 73 the emergency core cooling mode of operation following receipt of an automatic initiation signal.

HPCI will realign except for the conditions discussed in Section 6.3.4.2.1. The CS and LPCI system injection into the RPV begin when reactor pressure decreases to system discharge shutoff pressure.

HPCI injection begins as soon as the HPCI turbine pump is up to speed and the injection valve is opened since the HPCI is capable of injecting water into the RPV over a pressure range from 150 psig to 1210 psig.

6.3.6 NPSH MARGIN AND VORTEX FORMATION AFTER A PASSIVE FAILURE IN A WATER TIGHT ECCS PUMP ROOM NPSH calculations for ECCS pumps have shown adequate margin to assure capability of proper pump operation after a pool level drop due to a worst case passive failure in an ECCS water tight pump room. This capability was initially verified during preoperational testing in SSES Units 1 and

2. The tests assumed a passive failure in the ECCS pump room resulting in the lowest pool level with subsequent operation of the ECCS pump with the smallest NPSH margin above NPSH required. Subsequent capability, due to regulatory driven changeout of strainers, was verified by full scale tests of the Unit 1 strainers at the EPRI Evaluation Center. These strainers were tested for vortexing potential and NPSH impact on existing margins and were shown to satisfy all system requirements, including a passive leak in an ECCS pump room. Even though the Unit 2 strainers were not tested, the effect of the changeout on Unit 2 margins is verifiable by hydraulic similitude through system and structure similarity between the two units. ECCS pump data is presented in Figures 6.3-118 and 6.3-119. Figures 6.3-120 and 6.3-121 are provided for reference information, actual performance is defined by Test Procedures.

The pool level drop has been determined assuming a passive failure in a ECCS water tight pump room with operator action 10 minutes after an alarm in the room indicating high water level. Vortex tests of ECCS pumps taking suction from the suppression pool (or condensate storage tank) were performed at the design basis minimum suppression pool (or condensate storage tank) water level during the Unit 1 preoperational testing. These tests showed no vortex formation, abnormal noise levels or signs of abnormal suction flow. However, as discussed above, new strainers replaced the original and these were tested for vortexing effect on the system by full scale tests at the EPRI Evaluation Center. The results of the tests indicated no visible vortexing. Since these tests were performed in a full scale test environment, only modified to observe vortex formation/air entrainment, similar performance results are expected with the equipment installed in the suppression pool. Also, since the tests were done only for Unit 1 strainers, differences are not expected in Unit 2 system margins due to hydraulic similitude through system and structure similarity between the two units as was the situation for NPSH.

FSAR Rev. 71 6.3-33

SSES-FSAR Text Rev. 73 6.

3.7 REFERENCES

6.3-1 H. M. Hirsch, "Methods for Calculating Safe Test Intervals and Allowable Repair Times for Engineered Safeguard Systems," January 1973 (NEDO-10739).

6.3-2 "General Electric Company Analytical Model for Loss-of-Coolant Analysis in Accordance with 10 CFR 50, Appendix K," NEDO-20566A, September 1986.

6.3-3 Delete 6.3-4 Delete 6.3-5 Delete 6.3-6 Delete 6.3-7 Delete 6.3-8 Diefenderfer, S. B., and D. C. Pappone, "Susquehanna Steam Electric Station Units 1 and 2 SAFER/GESTR-LOCA Loss-of-Coolant Accident Analysis," NEDC-32071P, General Electric Nuclear Engineering Department.

6.3-9 Delete 6.3-10 "SAFER/GESTR-LOCA Analysis Basis Documentation for Susquehanna Steam Electric Station Units 1 and 2," NEDC-32281P, September 1993.

6.3-11 Delete 6.3-12 Delete 6.3-13 Delete 6.3-14 Susquehanna LOCA Break Spectrum Analysis for ATRIUM-10 Fuel and Extended Power Uprate Framatome ANP EMF-3242(P), Rev. 1, March 2006.

6.3-15 Susquehanna LOCA MAPLHGR Analysis for ATRIUM-10 Fuel and Extended Power Uprate, Framatome ANP EMF-3243 (P), Rev. 0, November 2005.

6.3-16 System Analyses for Elimination of Selected Response Time Testing Requirements, NEDO-32291, January 1994.

6.3-17 PL-NF-98-010, Rev. 0, Susquehanna SES Unit 1 Cycle 11 Core Operating Limits Report, July 1998.

6.3-18 SSES Unit 2 Cycle 9 Core Operating Limits Report, PL-NF-97-005, Rev. 0, April 1997.

6.3-19 NEDO-32686, Utility Resolution Guide For ECCS Suction Strainer Blockage, GE Nuclear Energy, October 1998.

6.3-20 GE Position Summary: Long-Term Post-LOCA Adequate Core Cooling FSAR Rev. 71 6.3-34

SSES-FSAR Text Rev. 73 Requirements, DRF-E22-00135-01, Revision 0, November 2000.

6.3-21 Delete 6.3-22 Delete 6.3-23 EXEM BWR-2000 ECCS Evaluation Model, EMF-2361 (P) (A) Framatome ANP, May 2001.

6.3-24 Susquehanna Units 1 and 2 LOCA Analysis for ATRIUM-11 Fuel, Framatome ANP-3784P Rev. 0, June 2019.

6.3-25 AURORA-B: An Evaluation Model for Boiling Water Reactors; Application to Loss of Coolant Accident Scenarios, Framatome ANP-10332P-A Rev. 0, March 2019.

6.3-26 Exxon Nuclear Company ECCS Cladding Swelling and Rupture Model, Exxon Nuclear Company XN-NF-82-07(P)(A) Rev. 1, November 1982.

6.3-27 Realistic Thermal-Mechanical Fuel Rod Methodology for Boiling Water Reactors, Framatome BAW-10247PA Rev. 0, February 2008.

FSAR Rev. 71 6.3-35

Table Rev. 3 SSES FSAR TABLE 6.3-1B-2 Unit 1 and Unit 2 EVENT TIMES FOR THE HIGHEST PCT CASE FROM THE TLO RECIRCULATION LINE BREAK SPECTRUM ANALYSIS ATRIUM-10 Fuel ATRIUM-11 Fuel Limiting Event: 0.07 ft2 break in the Limiting Event: Large break in the recirculation Time (sec) recirculation discharge piping with a Time (sec) suction piping with an LPCI single valve failure single failure of the backup battery (DC) power Initiate Break 0.0 Initiate Break 0.0 Initiate Scram 2.5 Initiate MSIV closure 2.0 MSIV closed 5.0 Initiate scram (MSIV < 85% open) 2.5 L2 low water level, HPCI signaled 5.7 MSIV fully closed 5.0 L1 low water level, DG signaled 7.7 L2 Low-low liquid level, HPCI signaled 34.5 Jet pump suction uncovers 8.4 L1 Low-low-low liquid level, DG signaled 129.9 Recirc suction uncovers 11.5 DG power to valves 164.3 Lower plenum flashes 14.5 HPCI flow starts N/A DG power at ESS bus 32.8 LPCI pumps to rated speed 166.8 LPCI pump starts 36.8 LPCI valve starts to open 372.1 HPCI flow starts 39.8 LPCI flow starts 408.5 CS pump starts 44.3 LPCS pumps to rated speed 170.3 CS valve opens 44.4 LPCS valve starts to open 372.1 Intact loop LPCI valve opens NA LPCS flow starts 397.4 Intact loop LPCI flow starts NA ADS valve starts to open 250.3 Broken Loop valve opens 44.4 RDIV closure starts 438.3 Broken Loop flow starts 44.5 RDIV 471.3 CS flow starts 47.8 End of blowdown 565.2 Recirc Discharge valve closure starts 51.3 Bypass reflood None End of Blowdown 65.5 Begin rated spray 65.5 Recirc Discharge valve closure complete 84.3 Core reflood 118.0 PCT 118.0 ADS valve opens 127.7 Bypass reflood 129.2 FSAR Rev. 70 Page 1 of 1

SSES-FSAR Table Rev. 4 TABLE 6.3-2B Unit 1 and Unit 2 SIGNIFICANT INPUT PARAMETERS TO THE LOSS-OF-COOLANT ACCIDENT ANALYSIS PLANT PARAMETERS:

Core Thermal Power 4031 MWt (ATRIUM-10 / ATRIUM-11 Fuel)

Vessel Steam Dome Pressure 1054 psia (ATRIUM-10 / ATRIUM-11 Fuel)

Maximum Recirculation Line Break Area (ft2) 7.0(1) (ATRIUM-10 / ATRIUM-11 Fuel)

Recirculation Line Break Area for Small and 3.5 to 0.05 (ATRIUM-10 / ATRIUM-11 Fuel)

Intermediate Breaks (ft2)

FUEL PARAMETERS:

Fuel Types ATRIUM-10 / ATRIUM-11 Number of fuel rods 91 (8 are part length) (ATRIUM-10 Fuel) 112 (20 are part length) (ATRIUM-11 Fuel)

Peak Technical Specification 13.4 (ATRIUM-10 Fuel)

Linear Heat 13.6 (ATRIUM-11 Fuel)

Generation Rate (kw/ft)

A more detailed list of inputs to the model and its source is presented for ATRIUM-10 fuel in References 6.3-14 and 6.3-15, and for ATRIUM-11 in Reference 6.3-24.

FSAR Rev. 71 Page 1 of 4

SSES-FSAR Table Rev. 4 TABLE 6.3-2B Unit 1 and Unit 2 SIGNIFICANT INPUT PARAMETERS TO THE LOSS-OF-COOLANT ACCIDENT ANALYSIS EMERGENCY CORE COOLING SYSTEM PARAMETERS:

Low Pressure Coolant Injection System Vessel Pressure at which flow may psid (vessel to drywell) 270 commence Minimum Rated Flow at Vessel GPM/psid (vessel to drywell) Fig. 6.3-80C Pressure (ATRIUM-10 /

ATRIUM-11 Fuel)

Initiating signals:

low water level ft. above top of active fuel 0.06 (ATRIUM-10 /

or ATRIUM-11 Fuel) high drywell pressure plus low reactor psig 2.0 pressure permissive(6) psig 380(7)

Maximum allowable time delay from sec 36.6(2) initiating signal to pumps at rated speed Pressure at which injection valve may psig 380(7) open (vessel pressure)

Pressure at which recirculation psig 200 discharge valve signaled to close Maximum allowed recirculation sec 33 discharge valve closing time Core Spray System Vessel pressure at which flow may psid (vessel to drywell) 303 (ATRIUM-10 Fuel) commence 298 (ATRIUM-11 Fuel)

Minimum rated flow at Vessel GPM/Core Spray Loop psid Fig. 6.3-79C(3)

Pressure (vessel to drywell)

FSAR Rev. 71 Page 2 of 4

SSES-FSAR Table Rev. 4 TABLE 6.3-2B Unit 1 and Unit 2 SIGNIFICANT INPUT PARAMETERS TO THE LOSS-OF-COOLANT ACCIDENT ANALYSIS Initiating signals:

low water level ft. above top of active fuel 0.06 (ATRIUM-10 /

or ATRIUM-11 Fuel) high Drywell Pressure plus psig 2.0 low reactor pressure permissive(6) psig 380(7)

Maximum allowed (runout) flow GPM/ Core Spray Loop 6885 (ATRIUM-10 Fuel) 6785 (ATRIUM-11 Fuel)

Fig. 6.3-79C Maximum allowed delay time from sec 40.1(4) initiating signal to pump at rated speed Pressure at which injection valve may psig 380(7) open (vessel pressure)

High Pressure Coolant Injection Vessel pressure at which flow may psia 1225 to 165 commence Minimum rated flow available at vessel GPM 4500 pressure psid (vessel to pump 1210 to 165 psid (ATRIUM-suction) 10 / ATRIUM-11 Fuel)

Initiating Signals:

low water level ft above top of active fuel 7.65 (ATRIUM-10 /

or ATRIUM-11 Fuel) high Drywell Pressure(6) psig 2.0 Maximum allowed delay time from sec 35 initiating signal to rated flow available and injection valve wide open FSAR Rev. 71 Page 3 of 4

SSES-FSAR Table Rev. 4 TABLE 6.3-2B Unit 1 and Unit 2 SIGNIFICANT INPUT PARAMETERS TO THE LOSS-OF-COOLANT ACCIDENT ANALYSIS Automatic Depressurization System Total number of valves installed 6 Number of valves used in analysis 6 (ATRIUM-10 /

ATRIUM-11 Fuel)(5)

Minimum Flow Capacity of lbm/hr 4.0 x 106 any 5 valves at vessel pressure psig (vessel to suppression 1125 pool)

Initiating Signals:

low water level ft above top of active fuel 0.06 (ATRIUM-10 /

and ATRIUM-11 Fuel) high Drywell Pressure psig 2.0 and Signal that at least 1 LPCI pump or 1 psig (CS) 115 to 175 CS loop (2 pumps per loop) are running (pump discharge pressure) psig (LPCI) 100 to 150 Delay time from all initiating signals sec 120 (ATRIUM-10 /

completed to the time valves are open ATRIUM-11 Fuel)

(1) Calculation of maximum line break area is based on maximum area at the break location. Break flow rate will be limited by the minimum flow area encountered in break path.

(2) Analysis assumes a 24 second LPCI valve opening time.

(3) Accounts for 100 gpm leakage in the piping connection between the vessel nozzle and the shroud.

(4) Analysis assumes a 19 second CS valve opening time.

(5) For calculations in which the single failure of interest is the ADS, only 5 valves are operable.

(6) Calculations for ATRIUM-10 fuel also performed to justify an additional 5 second of delay time. No credit is assumed for the start of HPCI, CS, or LPCI due to high drywell pressure.

(7) Atrium 10 LOCA analyses were performed at 400 psig but confirmed valid at 380 psig with no impacts to peak cladding temperature acceptance criterion.

FSAR Rev. 71 Page 4 of 4

SSES FSAR Table Rev. 2 TABLE 6.3-3B-2 Unit 1 and UNIT 2 RESULTS FOR LIMITING TWO LOOP OPERATION RECIRCULATION LINE BREAK 1.0 DEG PUMP SUCTION SF-LPCI TOP-PEAKED AXIAL 102% POWER (4031 MWt) 80 Mlbs/HR FLOW Peak Cladding Temperature, ºF 1844ºF Local Cladding Oxidation (Max%) 0.80%

Total Hydrogen Generated <0.2%

(% of Total Hydrogen Possible)

FSAR Rev. 64 Page 1 of 1

SSES FSAR Table Rev. 4 TABLE 6.3-3C Unit 1 and Unit 2 RECIRCULATION LINE BREAK RESULTS HIGHEST PCT CASES Axial Power Shape Mid-Peaked Top-Peaked Break Size PCT Break Size PCT Single Failure and Location (ºF) and Location (ºF)

ATRIUM-10 108 Mlb/hr Flow 102% Power (4031 MWt)

SF-BATT 0.6 DEG pump suction 1648 0.7 ft2 pump discharge 1706 SF-LPCI 1.0 DEG pump suction 1698 0.8 DEG pump suction 1730 ATRIUM-10 80 Mlb/hr Flow 102% Power (4031 MWt)

SF-BATT 0.6 DEG pump suction 1671 1.0 DEG pump discharge 1684 SF-LPCI 1.5 ft.2 pump discharge 1728 1.0 DEG pump discharge 1803 ATRIUM-11 108 Mlb/hr Flow 102% Power (4031 MWt)

SF-BATT 0.06 ft2 pump suction 1734 0.07 ft2 pump discharge 1771 SF-LOCA 1.0 DEG pump suction 1588 1.0 DEG pump suction 1639 ATRIUM-11 99 Mlb/hr Flow 102% Power (4031 MWt)

SF-BATT 0.08 ft2 pump discharge 1732 0.06 ft2 pump discharge 1759 SF-LOCA 1.0 DEG pump suction 1578 0.3 ft2 pump discharge 1631 FSAR Rev. 70 Page 1 of 1

SSES-FSAR Table Rev. 55 TABLE 6.3-5 SINGLE FAILURES AND AVAILABLE SYSTEMS FOR SUSQUEHANNA Assumed Failure") Recirculation Suction Break Recirculation Discharge Break Svstems Remainim1"' Svstems Remainim:i Opposite Unit False LOCA ADs<3l, HPCI, 1 cs system (2 pumps), 2 ADS, HPCI, 1 CS system (2 pumps),

Signal LPCI pumps (one in each loop) 1 LPCI pump Batter/4l ADS, 1 CS system (2 pumps), 3 LPCI ADS, 1 CS system (2 pumps),

pumps 1 LPCI pump LPCI Injection Valve ADS, HPCI, 2 CS systems (4 pumps), 2 ADS, HPCI, 2 CS systems (4 pumps)

LPCI pumps (in one loop)

Diesel-Generator(4l ADS, HPCI, 1 CS system (2 pumps), 3 ADS, HPCI, 1 CS system (2 pumps),

LPCI pumps 1 LPCI pump HPCI ADS, 2 CS systems (4 pumps) 4 LPCI ADS, 2 CS systems (4 pumps),

pumps (2 in each loop) 2 LPCI pumps (in one loop)

ADs<3l 5 of 6 ADS valves, HPCI, 2 CS systems 5 of 6 ADS valves; HPCI, 2 CS (SPC ATRIUM' -10 Fuel) (4 pumps), 4 LPCI pumps (2 in each systems (4 pumps), 2 LPCI pumps loop) (in one loop)

(1)

Other postulated failures are not specifically considered because they all result in at least as much ECCS capacity as one of the above assumed failures.

(2)

Systems remaining, as identified in this table, are applicable to all non-ECCS line breaks. For a LOCA from an ECCS line break, the systems remaining are those listed for the recirculation suction line break, less the ECCS in which the break is assumed.

(3)

For FANP ATRIUM'-10 fuel, a single failure in the ADS is modeled in separate calculations.

(4)

One additional CS pump (50% flow) would also be available if DG failure was C or D diesel. Note, no additional CS pump would be available if DG failure was A or B diesel. The analyses assume no core spray cooling or inventory makeup credit for this pump.

FSAR Rev. 61 Page 1 of 1

SSES-FSAR Table Rev. 56 TABLE 6.3-8 HPCI SYSTEM DESIGN PARAMETERS (values in parenthesis are those used for the original design analyses, before power uprate)

HPCI PUMP Total Pump Design Flow 5070 GPM NPSHR 21 feet Developed Head, Maximum 3060 feet @ 1225 psia reactor pressure (2940 feet @ 1172 psia reactor pressure) 525 feet @ 165 psia reactor pressure Brake Horsepower 4800 HP @ 3060 feet developed head (not to exceed 4621 HP @ 2940 feet developed head) 1000 HP @ 525 feet developed head Design Pressure 1500 psig Water Temperature Range 40°F to 140°F HPCI TURBINE High Pressure Low Pressure Reactor Pressure 1225 psia 165 psia (1172 psia)

Steam Inlet Pressure 1210 psia 150 psia (1157 psia)

Turbine Exhaust 25 to 65 psia 25 to 65 psia Pressure, Maximum Design Inlet Pressure 1250 psig + Saturated Temperature Design Exhaust Pressure 200 psig + Saturated Temperature HPCI ORIFICE SIZING Coolant Loop orifices. Sized to obtain the required flow split between the lube oil cooler and the gland seal condenser.

Minimum Flow Orifices. Sized to ensure a minimum flow or 500 gpm with the pump minimum flow bypass valve open.

Test Return Orifice. Sized to simulate pump discharge pressure required when the HPCI System is injecting design glow with the reactor vessel pressure at 165 psia. A second orifice for normal system testing with the reactor vessel at 1015 psia may be provided to avoid a high pressure drop across the pump test return valve.

Leak-off Orifices. Sized for 1/8 inch diameter minimum, 3/16 inch diameter maximum.

Steam Exhaust Drain Pot Orifice. Sized for 1/8 inch diameter minimum, 3/16 inch diameter maximum.

FSAR Rev. 65 Page 1 of 3

SSES-FSAR Table Rev. 56 TABLE 6.3-8 HPCI SYSTEM DESIGN PARAMETERS (values in parenthesis are those used for the original design analyses, before power uprate)

HPCI VALVES Steam Supply Valve - Open and/or close against full pressure within 20 seconds.

Pump Discharge Valves - Open and/or close against full pressure within 20 seconds.

Pump Minimum Flow Bypass Valve - Open and/or close against full pressure within 10 seconds.

Steam Supply Isolation Valves - Close against full pressure at a minimum rate of 12 inches per minute.

Cooling Water Pressure Control Valve - Self-contained downstream sensing control valve capable of maintaining constant downstream pressure of 75 psia.

Pump Suction Relief Valve - 100 psig Relief Setting, 10 gpm @ 10% Accumulation.

Cooling Water Relief Valve - Size to prevent over pressurizing piping, valves and equipment in the coolant loop in the event of failure of pressure control valves.

Pump Test Return Valve - Capable of throttling against 1000 psi differential pressure.

Relief Valve, Barometric Condenser - Capable of retaining 10 inches of mercury vacuum at 140°F ambient, with a set pressure of 5-7 psig and flow gpm at 10 percent accumulation.

Turbine Exhaust Isolation Valve - Open and/or close against 50 psi differential pressure at a temperature of 360°F. Physically located at the highest point in the exhaust line on a horizontal run and as close to the containment as practicable.

Check Valve - Located at the highest point in the line on a horizontal run, with adjacent piping arranged to provide a continuous downward slope from the upstream side of the check valve to the turbine exhaust drain pot and downstream of the check valve to the suppression pool.

Isolation Valve, Steam Warmup/Drain Line - Open and/or close against differential pressure of 1210 psi with minimum travel of 12 inches per minute. The valve and valve associated equipment shall be capable of proper functional operation during maximum ambient conditions.

Vacuum Breaker, Isolation Valves - Open and/or close against a differential pressure of 200 psi at a minimum rate of 12 inches per minute.

Vacuum Breaker, Check Valves - Open with a minimum pressure drop (less than 0.5 psi) across the valve seat.

Rupture Disk Assemblies - Utilized for turbine casing protection, shall include a mated vacuum support to prevent rupture disc reversing under vacuum conditions.

Rupture Pressure: 175 psig +/- 10 psig Flow Capacity: 750,000 lb/hr at 200 psig DC MOTOR POWER, MAXIMUM Hydraulic Oil Pump Motor: 7.5 Hp Gland Seal Condenser Vacuum Pump Motor: 1.5 Hp Gland Seal Condenser Drain Pump Motor: 3.0 Hp FSAR Rev. 65 Page 2 of 3

SSES-FSAR Table Rev. 56 TABLE 6.3-8 HPCI SYSTEM DESIGN PARAMETERS (values in parenthesis are those used for the original design analyses, before power uprate)

CONDENSATE STORAGE 135,000 Gallons Total reserve storage, per unit, for both HPCI and RCIC Systems.

TURBINE EXHAUST VERTICAL REACTION FORCE Unbalanced pressure due to discharge under the suppression pool water level, which requires vertical hold down, is 20 psi.

AMBIENT CONDITIONS Temperature Relative Humidity Normal Plant Operation 60 to 100°F 95%

Accident Mode 148°F 100%

FSAR Rev. 65 Page 3 of 3

SSES-FSAR Table Rev. 56 TABLE 6.3-9 MANUAL VALVES IN THE ECCS DWG./

SYSTEM VALVE NUMBER SIZE/TYPE FUNCTION LOCATION (UNIT 2) METHOD OF ASSURING CORRECT POSITION FIGURE Containment M-126, 126015 1 GB Maintenance RB-749 Locked open.

Instrument Gas Sh.1 (ADS Valve M-126, 126017 1 GB Maintenance RB-749 Locked open.

Pneumatic Supply) Sh.2 M-2126, 126020 1 GB Test Vent RB-749 If valve is left inadvertently open and the vent Sh. 1 uncapped, an abnormal demand will be placed on the affected ADS supply header. Low header pressure will automatically open the supply valve from the high pressure nitrogen storage bottles and isolate the compressor from the header.

Loss of nitrogen from the storage bottles will eventually result in actuation of the low pressure alarm in the control room. At that point, plant operating personnel will be alerted to take appropriate action.

126021 1 GB Test Conn. DW-752 Locked closed. Also see 126020.

126022 1 GB Header isol. DW-752 None 126024G 1 GB Isolation DW-752 None 126024J 1 GB Isolation DW-752 None 126024M 1 GB Isolation DW-752 None 126026 1 GB Maintenance RB-719 (749) Locked open.

126028 1 GB Maintenance RB-719 (749) Locked open.

126030 1 GB Test Vent RB-719 See 126020 126031 1 GB Test conn. DW-719 (738) Locked closed. Also see 126020 126032 1 GB Header isol. DW-719 (738) None 126034K 1 GB Isolation DW-752 None 126034L 1 GB Isolation DW-752 None 126034N 1 GB Isolation DW-752 None 126063 1 GB Charging conn. RB-749 Double isolation. Also see 126196.

126064 1 GB Charging conn. RB-749 Double isolation. Also see 126196.

126065 1 GB Charging conn. RB-719 (749) Double isolation. Also see 126196.

126066 1 GB Charging conn. RB-719 (749) Double isolation. Also see 126196.

126078 thru 090 1 GB Maintenance RB-749 None; only one of 26 high pressure nitrogen 126091 thru 100 1 GB Maintenance RB-733 (749) bottles would be lost if valve inadvertently closed.

126153 1 GB Test conn. DW-719 (738) See 126020.

126155 1 GB Test conn. DW-752 See 126020.

126159 1 GB Maintenance RB-719 (749) See 126078.

FSAR Rev. 71 Page 1 of 9

SSES-FSAR Table Rev. 56 TABLE 6.3-9 MANUAL VALVES IN THE ECCS DWG./

SYSTEM VALVE NUMBER SIZE/TYPE FUNCTION LOCATION (UNIT 2) METHOD OF ASSURING CORRECT POSITION FIGURE Containment 126160 1 GB Maintenance RB-719 (749) See 126078.

Instrument Gas 126161 1 GB Maintenance RB-719 (749) See 126078.

(ADS Valve 126162 1 GB Test vent RB-749 See 126020.

Pneumatic Supply) 126163 1 GB Test vent RB-719 (749) See 126020.

(continued) 126196 1 GB Charging/Vent RB-749 (226176) Double isolation. If valves left inadvertently open, an abnormal demand will be placed on the affected ADS supply header. Loss of nitrogen from the storage bottles will eventually result in actuation of the low pressure alarm in the control room. At that point, plant operating personnel will be alerted to take appropriate action.

126197 1 GB Charging/Vent RB-749 (226177) See 126196.

226175 1 GB Charging/Vent (U2 only) RB-749 Administrative controls. (Normally open).

226176 1 GB Charging/Vent (126196) RB-779 See 126196.

226177 1 GB Charging/Vent (126197) RB-779 See 126196.

Nuclear Boiler - M-141, 141007G, 1 GB Drain DW-752 See 126020.

Automatic Sh.1 K,J,L,M & N Depressurization M-141, 141801, 807, 816, 1 GB Vent DW-739 None System (ADS) Sh.2 811, 806, 817 RHR - Low Pressure M-151, 151011 1 GB Drain RB-645 Administrative controls.

Coolant Injection Mode Sh.1 151012 1 GB Drain RB-645 Administrative controls.

(LPCI) and Suppression M-151, 151013 1 GB Vent RB-645 Administrative controls.

Pool Cooling Modes Sh.2 151014 1 GB Vent RB-645 Administrative controls.

M-151, 151015 1 GB Vent RB-670 Administrative controls.

Sh.3 151016 1 GB Vent RB-683 Administrative controls.

M-151, 151017 1 GB Test conn. RB-683 Administrative controls.

Sh.4 151018 1 GB Drain RB-683 Administrative controls.

M-2151, 151024 1 GB Test conn. DW-719 Double isolation.

Sh. 1 151026 1 GB Test conn. DW-719 Double isolation.

M-2151, 151028 1 GB Drain RB-683 Administrative controls.

Sh. 3 151029 1 GB Vent RB-749 Administrative controls.

151030 1 GB Vent RB-645 Administrative controls.

151031 1 GB Vent RB-645 Administrative controls.

FSAR Rev. 71 Page 2 of 9

SSES-FSAR Table Rev. 56 TABLE 6.3-9 MANUAL VALVES IN THE ECCS DWG./

SYSTEM VALVE NUMBER SIZE/TYPE FUNCTION LOCATION (UNIT 2) METHOD OF ASSURING CORRECT POSITION FIGURE RHR - Low Pressure 151032 1 GB Drain RB-645 Administrative controls.

Coolant Injection Mode 151033 1 GB Drain RB-645 Administrative controls.

(LPCI) and Suppression 151034 1 GB Vent RB-670 Administrative controls.

Pool Cooling Modes 151035 1 GB Vent RB-683 Administrative controls.

(continued) 151036 1 GB Test conn. RB-683 Administrative controls.

151037 1 GB Drain RB-683 Administrative controls.

151048 1 GB Drain RB-645 Administrative controls.

151049 1 GB Vent RB-683 Administrative controls.

151051 1 GB Test conn. DW-719 Double isolation.

151053 1 GB Test conn. DW-719 Double isolation.

151056 1 GB Vent RB-683 Administrative controls.

151058 1 GB Drain RB-683 Administrative controls.

151065 1 GB Vent RB-683 Administrative controls.

151070 12 GB Isolation RB-683 Locked closed; double isolation.

151075 1 GB Drain RB-645 Administrative controls.

151084 1 GB Inst. Conn. RB-749 Locked open.

151085 1 GB Inst. Conn. RB-749 Locked open.

151086 1 GB Inst. Conn. RB-749 Locked open.

151087 1 GB Inst. Conn. RB-749 Locked open.

151091 thru 92 1 GB Vent RB-683 (U1 only) Administrative controls. Double isolation.

151097 1 GB Sample conn. RB-683 (251101) Administrative controls. (Normally open) 151098 1 GB Sample conn. RB-683 (251102) Administrative controls. (Normally open) 151101 1 GB Vent DW-719 (251113) Administrative controls. Double isolation.

151102 1 GB Vent DW-719 (251114) Closed capped. Double isolation.

151103 1 GB Drain DW-704 Locked closed. Double isolation.

151104 1 GB Drain DW-704 Closed capped. Double isolation.

151105 1 GB Drain RB-683 Administrative controls. Double isolation.

151106 1 GB Drain RB-683 Closed capped. Double isolation.

151107 1 GB Vent DW-719 Administrative controls. Double isolation 151108 1 GB Vent DW-719 Closed capped. Double isolation.

151109 1 GB Drain DW-704 Locked closed. Double isolation.

151110 1 GB Drain DW-704 Closed capped. Double isolation.

151111 1 GB Drain RB-683 Administrative controls. Double isolation.

151112 1 GB Drain RB-683 Closed capped. Double isolation.

151119A thru D 3/8 BV Vent RB-645 Administrative controls.

151120A thru D 1 BV Vent RB-645 Administrative controls.

151806 1 GB Test Conn. RB -683 Closed capped. Double isolation.

FSAR Rev. 71 Page 3 of 9

SSES-FSAR Table Rev. 56 TABLE 6.3-9 MANUAL VALVES IN THE ECCS DWG./

SYSTEM VALVE NUMBER SIZE/TYPE FUNCTION LOCATION (UNIT 2) METHOD OF ASSURING CORRECT POSITION FIGURE RHR - Low Pressure 151807 1 GB Test Conn. RB -683 Administrative controls. Double isolation.

Coolant Injection Mode 151808 1 GB Test Conn. RB -683 Administrative controls. Double isolation.

(LPCI) and Suppression 151809 1 GB Test Conn. RB -683 Closed capped. Double isolation.

Pool Cooling Modes 151810 1 GB Drain RB -683 Administrative controls.

(continued) 151815 1 GB Vent RB-683 Administrative controls.

151821 1/2 BV Vent RB-749 Administrative controls.

1F018A thru 18D 4 GT Maintenance RB-645 Locked open.

1F034A thru 034D 20 GT Maintenance RB-645 Locked open.

1F045A thru 045D 1 GB Drain RB-645 Administrative controls.

1F058A,B 1 GB Vent & Test RB-683 Administrative controls. Double isolation 1F058B 1 GB Vent & Test RB-683 Administrative controls. Double isolation 1F059A 1 GB Vent & Test RB-683 Administrative controls. Double isolation 1F059B 1 GB Vent & Test RB-683 Administrative controls. Double isolation 1F060A 24 GB Block DW-719 Locked open, position indication on 1C601.

1F060B 24 GB Block DW-683 Locked open, position indication on 1C601.

1F071A thru 071D 1 GB Drain RB-645 Administrative controls 1F072A thru 072D 1 GB Drain RB-645 Administrative controls 1F082 2 GB Isolation RB-683 Double isolation..

1F102A thru 102D 1 GB Vent RB-645 & Administrative controls.

RB-670 1F124A, B 1 GB Drain RB-645 Administrative controls.

1F128A, B 1 GB Drain RB-670 Administrative controls.

1F018A thru 018D 4 GT Min. Flow RB-645 Administrative controls RVPP15102A thru 1 GB Inst. Conn. RB-645 & Closed, plugged.

102D RB-683 251093 1 GB Vent (U2 only) RB-683 Administrative controls. Double isolation.

251094 1 GB Vent (U2 only) RB-683 Administrative controls. Double isolation.

251101 1 GB Sample conn. (151097) RB-683 Administrative controls.

251102 1 GB Sample conn. (151098) RB-683 Administrative controls.

251113 1 GB Vent (151101) DW-719 Administrative controls. Double isolation.

251114 1 GB Vent (151102) DW-719 Closed capped. Double isolation.

151125 1 GB Isolation DW-704 Administrative controls.

151126 1 GB Isolation DW-704 Administrative controls.

151127 1 GB Isolation DW-704 Administrative controls.

151128 1 GB Isolation DW-704 Administrative controls.

151129 1 GB Isolation DW-704 Administrative controls.

151131 1 GB Drain DW-704 Administrative controls.

FSAR Rev. 71 Page 4 of 9

SSES-FSAR Table Rev. 56 TABLE 6.3-9 MANUAL VALVES IN THE ECCS DWG./

SYSTEM VALVE NUMBER SIZE/TYPE FUNCTION LOCATION (UNIT 2) METHOD OF ASSURING CORRECT POSITION FIGURE RHR - Low Pressure 151132 1 GB Drain DW-704 Administrative controls.

Coolant Injection Mode (LPCI) and Suppression Pool Cooling Modes (continued)

Fuel Pool Cooling & M-153, 153070A 8 GB Isolation RB-799 Double isolation (with 151070).

Cleanup (crosstie to Sh. 1 153070B 8 GB Isolation RB-799 Double isolation (with 151070).

LPCI) 153808 1 GB Vent RB-749 Closed plugged.

Core Spray M-152, 152001 thru 004 1 GB Drain RB-645 Administrative controls.

Sh.1 152006 1 GB Test conn. RB-670 Administrative controls.

152007 1 GB Test conn. RB-670 Administrative controls.

152008 1 GB Drain RB-683 Administrative controls.

152009 1 GB Drain RB-683 Administrative controls.

152010 1 GB Vent RB-749 Administrative controls.

152011 1 GB Test conn. DW-752 Double isolation.

152012 1 GB Test conn. DW-752 Double isolation.

152013 1 GB Test conn. DW-752 Double isolation.

152014 1 GB Test conn. DW-752 Double isolation.

152015 1 GB Vent RB-749 Administrative controls 152016 1 GB Vent RB-645 Double isolation.

152021 16 GT Isolation RB-645 Locked closed; double isolation 152024 1 GB Drain RB-645 Administrative controls.

152025 1 GB Drain RB-645 Administrative controls.

152026 1 GB Drain RB-645 Administrative controls.

152027 1 GB Drain RB-645 Administrative controls.

152028 3 GB Isolation RB-670 Double Isolation (in combination with check valve 152005) 152029 1 GB Bypass RB-749 Locked closed.

152030 1 GB Bypass RB-749 Locked closed.

1F002A 16 GT Isolation RB-645 Locked closed; double isolation 1F002B 16 GT Isolation RB-645 Locked closed; double isolation 1F007A 12 GT Block DW-752 Locked open; position indication on 1C601.

1F007B 12 GT Block DW-752 Locked open; position indication on 1C601.

1F008A 1 GB Vent RB-645 Administrative controls.

1F008B 1 GB Vent RB-645 Administrative controls.

FSAR Rev. 71 Page 5 of 9

SSES-FSAR Table Rev. 56 TABLE 6.3-9 MANUAL VALVES IN THE ECCS DWG./

SYSTEM VALVE NUMBER SIZE/TYPE FUNCTION LOCATION (UNIT 2) METHOD OF ASSURING CORRECT POSITION FIGURE Core Spray 1F010A thru 010D 3 GB Isolation RB-645 Locked open.

(continued) 1F013A 1 GB Test conn. RB-749 Double isolation.

1F013B 1 GB Test conn. RB-749 Double isolation.

1F014A 1 GB Test conn. RB-749 Locked closed; double isolation.

1F014B 1 GB Test conn. RB-749 Locked closed; double isolation.

1F016A thru 016D 1 GB Vent RB-645 Locked closed.

1F017A, B 1 GB Maintenance RB-719 If valve is inadvertently left closed, indication of reactor core differential pressure would be abnormally low.

1F020A thru 020D 2 GB Bypass Isolation RB-645 Locked closed.

1F046A thru 046D 1 GB Drain RB-645 Locked closed.

1F025A, B 1 GB Fill Sys. RB-683 Administrative controls.

1F027A, B 1 GB Fill Sys. RB-683 Administrative controls.

1F028A, B 2 GB Fill Sys. RB-683 Locked open.

1F038A (U1 Only) 2" GB Isolation RB-749 Locked open.

1F038B (U1 Only) 2" GB Isolation RB-749 Locked open.

1F039A (U1 Only) 2" GB Isolation RB-749 Locked open.

1F039B (U1 Only) 2" GB Isolation RB-749 Locked open.

152053A (U1 Only) 1" GB Vent RB-749 Locked closed.

152053B (U1 Only) 1" GB Vent RB-749 Locked closed.

152054A (U1 Only) 1" GB Test Conn. RB-749 Locked closed.

152054B (U1 Only) 1" GB Test Conn. RB-749 Locked closed.

152055A (U1 Only) 1" GB Test Conn. RB-749 Locked closed.

152055B (U1 Only) 1" GB Test Conn. RB-749 Locked closed.

RV-PP-15236A thru 1 GB Instr. Conn. RB-645 Closed / plugged.

236D 252031 and 033 1 GB Vent (U2 only) DW-752 Closed / capped; double isolation.

252032 and 034 1 GB Vent (U2 only) DW-752 Locked closed; double isolation 252035 and 037 1 GB Test Conn. (U2 only) RB-749 Locked closed /capped; double isolation 252036 and 038 1 GB Test Conn. (U2 only) RB-749 Closed / capped; double isolation.

High Pressure Coolant M-155, 155001 1 GB Drain RB-645 Double isolation.

Injection (HPCI) Sh.1 155002 1 GB Drain RB-645 Double isolation.

155003 1 GB Test conn. RB-645 Double isolation.

155004 1 GB Test conn. RB-645 Double Isolation 155007 2 GB Maintenance RB-645 Administrative controls.

155008 2 GB Maintenance RB-645 Administrative controls.

FSAR Rev. 71 Page 6 of 9

SSES-FSAR Table Rev. 56 TABLE 6.3-9 MANUAL VALVES IN THE ECCS DWG./

SYSTEM VALVE NUMBER SIZE/TYPE FUNCTION LOCATION (UNIT 2) METHOD OF ASSURING CORRECT POSITION FIGURE High Pressure Coolant 155009 1 GB Vent RB-645 Administrative controls.

Injection (HPCI) 155010 1 GB Vent RB-670 Double isolation.

(continued) 155011 1 GB Vent RB-670 Double isolation.

155014 1 GB Test conn RB-739 Double isolation.

155015 1 GB Test conn. RB-739 Double isolation.

155016 1 GB Drain RB-645 Double isolation.

155017 2 GB Fill sys. RB-645 Locked open.

155018 2 GB Fill sys. RB-719 Administrative controls.

155019 1 GB Drain RB-645 Double isolation.

M-155, 155020 1 GB Drain RB-645 Double isolation.

Sh.1 155021 1 GB Maintenance RB-670 Administrative controls.

155022 1 GB Maintenance RB-670 Administrative controls.

155023 1 GB Maintenance RB-670 Administrative controls.

155025 1 GB Vent RB-670 Administrative controls.

155026 1 GB Vent RB-670 Administrative controls.

155027 1 GB Maintenance RB-670 Administrative controls.

155028 1 GB Vent RB-670 Administrative controls.

155029 1 GB Maintenance RB-670 Administrative controls.

155030 1 GB Vent RB-670 Administrative controls.

155031 1 GB Maintenance RB-670 Administrative controls.

155032 1 GB Drain RB-670 Double isolation.

155033 1 GB Maintenance RB-670 Administrative controls.

155034 1 GB Drain RB-670 Double isolation.

155035 1 GB Maintenance RB-670 Administrative controls.

155036 1 GB Drain RB-645 Double isolation.

155037 1 GB Bypass Isolation RB-645 Administrative controls.

155038 1 GB Bypass Isolation RB-749 Locked closed.

155039 1 GB Vent RB-670 Administrative controls.

155040 1 GB Drain RB-670 Double isolation.

155800 1 GB Test conn. RB-739 Double isolation.

155801 1 GB Test conn. RB-739 Double isolation..

155802 1/4 BV Test conn. RB-670 (255052) Locked closed / plugged 1F010 16 GT Isolation RB-645 Locked open.

1F013 1 GB Test conn. RB-670 Administrative controls.

1F014 1 GB Test conn. RB-683 Double isolation.

1F015 1 GB Test conn. RB-683 Double isolation.

1F016 1 GB Test conn. RB-670 Double isolation.

FSAR Rev. 71 Page 7 of 9

SSES-FSAR Table Rev. 56 TABLE 6.3-9 MANUAL VALVES IN THE ECCS DWG./

SYSTEM VALVE NUMBER SIZE/TYPE FUNCTION LOCATION (UNIT 2) METHOD OF ASSURING CORRECT POSITION FIGURE High Pressure Coolant M-155, 1F017 1 GB Test conn. RB-670 Double isolation.

Injection (HPCI) Sh.1 1F023A thru 023D 1 GB Maintenance RB-683 Administrative controls. If valve is inadvertently (continued) left closed, a steam line high dP or instrument line break signal may be actuated, resulting in automatic closure of HPCI steam supply valve 1F002 or 1F003.

1F036 1 GB Drain RB-645 Locked open.

M-155, 1F037 1 GB Drain RB-645 Locked open.

Sh.1 1F044 1 GB Test conn. RB-645 Administrative controls.

1F055 1 GB Test conn. RB-645 Double isolation.

1F056 1 GB Test conn. RB-645 Double isolation.

1F064 1 GB Test conn. RB-645 Double isolation.

1F065 1 GB Test conn. RB-670 Double isolation.

1F090 1 GB Test conn. RB-670 Administrative controls.

1F091 1 GB Test conn. RB-670 Administrative controls.

1F092 1 GB Test conn. RB-670 Administrative controls.

255052 1/4 BV Test Conn. RB-670 (155802) Locked closed / capped HPCI Turbine-Pump M-156, 156001 3/4 GB Leakoff RB-645 Administrative controls.

Sh.1 156002 3/4 GB Leakoff RB-645 Administrative controls.

156003 3/4 GB Leakoff RB-645 Administrative controls.

156006 3/4 GB Leakoff RB-645 Administrative controls.

156007 1 GB Drain RB-645 Administrative controls.

156008 1 GB Drain RB-645 Double isolation.

156009 1 GB Drain RB-645 Double isolation.

156010A 1 GB Vent RB-645 Double isolation.

156010B 1 GB Vent RB-645 Double isolation.

156011 1 GB Drain RB-645 Administrative controls.

156018 1 GB Drain RB-645 Administrative controls.

156019 1 GB Drain RB-645 Administrative controls.

15617 1 GB Vent RB-645 Administrative controls.

1F043 1 GB Test conn. RB-645 Administrative controls.

1F058 2 GB Maintenance RB-645 Administrative controls.

M-156 1F0161A thru O61C 1 GB Vent RB-645 Administrative controls.

Sh. 1 1F063A 1 GB Vent RB-645 Double Isolation.

1F063B 1 GB Vent RB-645 Double Isolation.

FSAR Rev. 71 Page 8 of 9

SSES-FSAR Table Rev. 56 TABLE 6.3-9 MANUAL VALVES IN THE ECCS DWG./

SYSTEM I FIGURE I VALVE NUMBER I SIZE/TYPE I FUNCTION I LOCATION I (UNIT 2)

I METHOD OF ASSURING CORRECT POSITION LEGEND TYPE: GB = Globe Valve GT = Gate Valve BV = Ball Valve LOCATION: RB = Reactor Bldg.

DW = Drywell The number represents the floor elevation.

FSAR Rev. 71 Page 9 of 9

SSES-FSAR Table Rev. 56 TABLE 6.3-10 SAFETY-RELATED VALVES IN THE DRYWELL SUBJECT TO SPRAY IMPINGEMENT P&ID(1) OPR TYPE NUMBER 143 AO HV F019 143 TEST F021 143 TEST F022 143 MAN F059 151 PSV F126 141 TEST F017 141 TEST F018 141 DRN F095A 141 DRN F095B 141 DRN F096A 141 DRN F096B 141 ROOT 1RV-PP-14107A1 141 ROOT 2RV-PP-14107A1 141 ROOT 1RV-PP-14107B1 141 ROOT 2RV-PP-14107B1 141 ROOT 1RV-PP-14107A2 141 ROOT 2RV-PP-14107A2 141 ROOT 1RV-PP-14107B2 141 ROOT 2RV-PP-14107B2 141 ROOT 1RV-PP-14107A3 141 ROOT 2RV-PP-14107A3 141 ROOT 1RV-PP-14107B3 141 ROOT 2RV-PP-14107B3 144 TEST F002 144 TEST F003 149 AO HV F088 155 AO HV F100 126 CK 126072 126 CK 126152 126 CK 126154 143 CK F013A 143 CK F013B 126 TEST 126021 126 MAN 126022 126 MAN 126024G 126 MAN 126024J 126 MAN 126024M 126 TEST 126031 126 MAN 126032 126 MAN 126034K 126 MAN 126034L 126 MAN 126034N 126 TEST 126047 FSAR Rev. 68 Page 1 of 9

SSES-FSAR Table Rev. 56 TABLE 6.3-10 SAFETY-RELATED VALVES IN THE DRYWELL SUBJECT TO SPRAY IMPINGEMENT P&ID(1) OPR TYPE NUMBER 126 TEST 126073 126 TEST 126075 126 TEST 126153 126 TEST 126155 141 DRN 141006A 141 DRN 141006B 141 DRN 141006C 141 DRN 141006D 141 DRN 141006E 141 DRN 141006F 141 DRN 141006G 141 DRN 141006H 141 DRN 141006J 141 DRN 141006K 141 DRN 141006L 141 DRN 141006M 141 DRN 141006N 141 DRN 141006P 141 DRN 141006R 141 DRN 141006S 141 DRN 141007G 141 DRN 141007J 141 DRN 141007K 141 DRN 141007L 141 DRN 141007M 141 DRN 141007N 141 DRN 141008A 141 DRN 141008B 141 DRN 141008C 141 DRN 141008D 141 DRN 141014 141 DRN 141015 143 VNT F001A 143 VNT F001B 143 VNT F002A 143 VNT F002B 143 MAN F014A 143 MAN F014B 141 VNT 141800 141 VNT 141801 141 VNT 141802 141 VNT 141803 141 VNT 141804 FSAR Rev. 68 Page 2 of 9

SSES-FSAR Table Rev. 56 TABLE 6.3-10 SAFETY-RELATED VALVES IN THE DRYWELL SUBJECT TO SPRAY IMPINGEMENT P&ID(1) OPR TYPE NUMBER 141 VNT 141805 141 VNT 141806 141 VNT 141807 141 VNT 141810 141 VNT 141811 141 VNT 141812 141 VNT 141813 141 VNT 141814 141 VNT 141815 141 VNT 141816 141 VNT 141817 141 MO HV F001 141 MO HV F002 141 MO HV F005 141 ISO 141018 143 VNT F025A 143 VNT F025B 143 VNT F026A 143 VNT F026B 143 DRN F027A 143 DRN F028A (Unit 1 Only) 143 VNT F034A 143 VNT F034B (Unit 1 Only) 143 VNT F035A 143 VNT F035B (Unit 1 Only) 143 DRN F036A 143 DRN F036B 143 DRN F038A 143 DRN F038B 143 TEST 143027A 143 TEST 140327B 143 TEST 143028A 143 TEST 143028B 143 VNT 143030A 143 VNT 143030B 143 VNT 143029A 143 VNT 143029B 143 VNT 143015A 143 VNT 143015B 143 VNT 143016A 143 VNT 143016B 143 VNT 143017A 143 VNT 143017B FSAR Rev. 68 Page 3 of 9

SSES-FSAR Table Rev. 56 TABLE 6.3-10 SAFETY-RELATED VALVES IN THE DRYWELL SUBJECT TO SPRAY IMPINGEMENT P&ID(1) OPR TYPE NUMBER 143 VNT 143018A 143 VNT 140318B 143 VNT 143019A 143 VNT 143019B 143 VNT 143020A 143 VNT 143020B 143 VNT 143021A 143 VNT 143021B 143 VNT 143022A 143 VNT 143022B 143 VNT 143023A 143 VNT 143023B 143 VNT 143024A 143 VNT 143024B 143 VNT 143025A 143 VNT 143025B 143 VNT 143026A 143 VNT 143026B 144 DRN 144002A 144 DRN 144002B 151 TEST F062 151 TEST F061 151 DRN 151053 151 DRN 151051 151 AO HV F122A 151 AO HV F122B 151 TEST F063 151 TEST F064 151 VNT 151062 151 VNT 151061 151 TEST 151026 151 TEST 151024 151 VNT 151093 (Unit 1 Only) 151 VNT 151094 (Unit 1 Only) 151 DRN 151095 151 DRN 151096 2151 VNT 251097 (Unit 2 Only) 2151 VNT 251098 (Unit 2 Only) 2151 VNT 251099 (Unit 2 Only) 2151 VNT 251100 (Unit 2 Only) 152 TEST 152011 152 TEST 152012 152 TEST 152013 FSAR Rev. 68 Page 4 of 9

SSES-FSAR Table Rev. 56 TABLE 6.3-10 SAFETY-RELATED VALVES IN THE DRYWELL SUBJECT TO SPRAY IMPINGEMENT P&ID(1) OPR TYPE NUMBER 152 TEST 152014 2152 VNT 252031 (Unit 2 Only) 2152 VNT 252032 (Unit 2 Only) 2152 VNT 252033 (Unit 2 Only) 2152 VNT 252034 (Unit 2 Only) 152 AO HV F037A 152 AO HV F037B 141 CK F024A 141 CK F024B 141 CK F024C 141 CK F024D 141 CK F036A 141 CK F036B 141 CK F036C 141 CK F036D 141 CK F036E 141 CK F036F 141 CK F036G 141 CK F036H 141 CK F036J 141 CK F036K 141 CK F036L 141 CK F036M 141 CK F036N 141 CK F036P 141 CK F036R 141 CK F036S 141 CK F040G 141 CK F040J 141 CK F040K 141 CK F040L 141 CK F040M 141 CK F040N 148 CK F007 148 MAN F008 144 MAN F103 2155 VNT 255040 (Unit 2 Only) 2155 VNT 255041 (Unit 2 Only) 126 MO HV 12603 143 DRN F051A 143 DRN F051B 144 DRN F029 144 DRN F030 FSAR Rev. 68 Page 5 of 9

SSES-FSAR Table Rev. 56 TABLE 6.3-10 SAFETY-RELATED VALVES IN THE DRYWELL SUBJECT TO SPRAY IMPINGEMENT P&ID(1) OPR TYPE NUMBER 141 MAN 141016 141 MO HV F016 187 AO HV 18792B2 187 AO HV 18792B1 187 AO HV 18792A2 187 AO HV 18792A1 126 CK 126074 144 MO HV F106 144 MO HV F100 144 MO HV F101 149 MO HV F007 143 MO HV F032A 143 MO HV F032B 113 MO HV 11345 113 MO HV 11346 141 PSV F037A 141 PSV F037B 141 PSV F037C 141 PSV F037D 141 PSV F037E 141 PSV F037F 141 PSV F037G 141 PSV F037H 141 PSV F037J 141 PSV F037K 141 PSV F037L 141 PSV F037M 141 PSV F037N 141 PSV F037P 141 PSV F037R 141 PSV F037S 141 PSV 14137A 141 PSV 14137B 141 PSV 14137C 141 PSV 14137D 141 PSV 14137E 141 PSV 14137F 141 PSV 14137G 141 PSV 14137H 141 PSV 14137J 141 PSV 14137K 141 PSV 14137L 141 PSV 14137M FSAR Rev. 68 Page 6 of 9

SSES-FSAR Table Rev. 56 TABLE 6.3-10 SAFETY-RELATED VALVES IN THE DRYWELL SUBJECT TO SPRAY IMPINGEMENT P&ID(1) OPR TYPE NUMBER 141 PSV 14137N 141 PSV 14137P 141 PSV 14137R 141 PSV 14137S 151 MO HV F022 151 CK F019 144 MO HV F102 144 MO HV F001 187 AO HV 18782A2 187 AO HV 18782A1 187 AO HV 18782B2 187 AO HV 18782B1 141 PSV F013A 141 PSV F013G 141 PSV F013E 141 PSV F013C 141 PSV F013J 141 PSV F013P 141 PSV F013M 141 PSV F013S 141 PSV F013L 141 PSV F013B 141 PSV F013R 141 PSV F013H 141 PSV F013K 187 VNT 187828 187 DRN 187827 187 VNT 187830 (Unit 1 Only) 187 VNT 187817 (Unit 1 Only) 187 VNT 187816 (Unit 1 Only) 187 VNT 187826 187 VNT 187831 (Unit 1 Only) 187 VNT 187809 (Unit 1 Only) 187 VNT 187808 (Unit 1 Only) 2187 DRN 287824 (Unit 2 Only) 2187 VNT 287825 (Unit 2 Only) 2187 VNT 287823 (Unit 2 Only) 2187 VNT 287822 (Unit 2 Only) 2187 DRN - Unit 1 187829 VNT - Unit 2 287829 2187 VNT 287842 (Unit 2 Only) 2187 VNT 287843 (Unit 2 Only) 157# PSV 15704A1, B1, C1, D1, E1 FSAR Rev. 68 Page 7 of 9

SSES-FSAR Table Rev. 56 TABLE 6.3-10 SAFETY-RELATED VALVES IN THE DRYWELL SUBJECT TO SPRAY IMPINGEMENT P&ID(1) OPR TYPE NUMBER 157# PSV 15704A2, B2, C2, D2, E2 141 PSV F013F 141 PSV F013D 141 PSV F013N 155 MO HV F002 152 AO CK F006B 152 AO CK F006A 152 MAN F007B 152 MAN F007A 151 MO HV F009 151 MAN F067 151 AO CK F050A 151 AO CK F050B 151 MAN F060A 151 MAN F060B 141 CK F010A 141 CK F010B 141 MO HV F011A 141 MO HV F011B 141 AO HV F022A 141 AO HV F022B 141 AO HV F022C 141 AO HV F022D 143 MO HV F023A 143 MO HV F023B 143 MO HV F031A 143 MO HV F031B 141 VNT 141022A 141 VNT 141022B 141 VNT 141023A 141 VNT 141023B 151 VNT 151101 (Unit 1 Only) 151 VNT 151102 (Unit 1 Only) 151 DRN 151103 151 DRN 151104 151 VNT 151107 151 VNT 151108 151 DRN 151109 151 DRN 151110 2151 VNT 251113 (Unit 2 Only) 2151 VNT 251114 (Unit 2 Only) 148 TEST 148003 148 TEST 148004 FSAR Rev. 68 Page 8 of 9

SSES-FSAR Table Rev. 56 TABLE 6.3-10 SAFETY-RELATED VALVES IN THE DRYWELL SUBJECT TO SPRAY IMPINGEMENT P&ID(1) OPR TYPE NUMBER 151 ISO 151125 151 ISO 151126 151 ISO 151127 151 ISO 151128 151 ISO 151129 151 CK 151130 151 DRN 151131 151 DRN 151132 GENERAL NOTES:

1. See Table 1.8-4 for a cross-reference between P&ID and FSAR figures.

2. All above listed valves are subject to spray impingement.

3. Unit 2 valves are listed only if they are in addition to the corresponding Unit 1 valves.

4. # These items are located in the wetwell, but are subject to containment spray.

5. Tables do not include safety-related solenoid valves and associated air line valves to air operators since they do not perform any function required for safe shutdown.

FSAR Rev. 68 Page 9 of 9

FIGURE 6.3-1A REPLACED BY DWG. M-155, SH. 1 FSAR REV. 65 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 & 2 FINAL SAFETY ANALYSIS REPORT FIGURE 6.3-1A REPLACED BY DWG. M-155, SH. 1 FIGURE 6.3-1A, Rev. 56 AutoCAD Figure 6_3_1A.doc

FIGURE 6.3-1B REPLACED BY DWG. M-156, SH. 1 FSAR REV. 65 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 & 2 FINAL SAFETY ANALYSIS REPORT FIGURE 6.3-1B REPLACED BY DWG. M-156, SH. 1 FIGURE 6.3-1B, Rev. 55 AutoCAD Figure 6_3_1B.doc

FIGURE 6.3-2 REPLACED BY DWG. M1-E41-4, SH. 1 FSAR REV. 65 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 & 2 FINAL SAFETY ANALYSIS REPORT FIGURE 6.3-2 REPLACED BY DWG. M1-E41-4, SH. 1 FIGURE 6.3-2, Rev. 52 AutoCAD Figure 6_3_2.doc

NPSH IN FEET 20 BHP TOTAL HEAD IN FEET 10 6000 NPSH REQ"D 3000 0

,, ,, 6000 2500 4000 2000 TOTAL TORQUE ,,

,, ,, 3000 1600

, 2000 1000 1000 500...__ _ _"--_ _ _ _ _ _.......,_ _ _....__ ____._ _ _ _ _ _ ___,

1800 2200 2600 3000 3400 3800 4200 TURBINE SPEED - RPM CONSTANT 5000 GPM WITH 100 GPM BOOSTER BY-PASS FSAR REV.65 SUSQUEHANNA STEAM ELECTRIC STATION Information Used for the Original, UNITS 1 & 2 FINAL SAFETY ANALYSIS REPORT Pre-upate Design Analyses HIGH PRESSURE COOLANT INJECTION PUMP SPEED CHARACTERISTICS FIGURE 6.3-3A, Rev 50 AutoCAD: Figure Fsar 6_3_3A.dwg

FIGURE 6.3-4 REPLACED BY DWG. M-152, SH. 1 FSAR REV. 65 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 & 2 FINAL SAFETY ANALYSIS REPORT FIGURE 6.3-4 REPLACED BY DWG. M-152, SH. 1 FIGURE 6.3-4, Rev. 55 AutoCAD Figure 6_3_4.doc

FIGURE 6.3-5 REPLACED BY DWG. M1-E21-15, SH. 1 FSAR REV. 65 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 & 2 FINAL SAFETY ANALYSIS REPORT FIGURE 6.3-5 REPLACED BY DWG. M1-E21-15, SH. 1 FIGURE 6.3-5, Rev. 51 AutoCAD Figure 6_3_5.doc

350Q NPSH REQUIRED DVS SUCTION 10 3000 8000 T D 2500 ~

!5000

/ .,,,;

TOTALTORQUE /

0.

,,,.,,,,,,,. I IiiIll ., IC IL 2000 / / 4000

.,,,,,,,. IIJ

~

!i FSAR REV.65 l&I

/ / t

% m

.J / / Q UiOO 3000 :fIll

~

F /

/

TOTALTDH  ::i 0

IIC SUSQUEHANNA STEAM ELECTRIC STATION

/.,,,,,,,.

~

FIGURE 6.3-77, Rev 49

,,,. /

1000 MAIN PUMP 7111 .s-0785 2000 AutoCAD: Figure Fsar 6_3_77.dwg PUMP CHARACTERISTIC CURVES BOOSTER PUMP 711-S-0784 UNITS 1 & 2 1000 FOR HPCI PUMPS 01-_ _ _ _ __._ _ _ _ _ __,__ _ _ _ _ __.__ _ _ _ _ _-'-_ _ _ _ _ _...__ _ _ _ __.o 2000 2400 2800 3200 3600 4000 4400 FINAL SAFETY ANALYSIS REPORT TURBINE SPEED lrpml

FIGURE RENUMBERED FROM 6.3-79 TO 6.3-79A FSAR REV. 65 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 & 2 FINAL SAFETY ANALYSIS REPORT FIGURE RENUMBERED FROM 6.3-79 TO 6.3-79A FIGURE 6.3-79, Rev. 54 AutoCAD Figure 6_3_79.doc

16000 14000 -+-ATRIUM-10 1 Loop Flow Rate

--.-ATRIUM-10 2 Loop Flow Rate 12000 ATRIUM-111 Loop Flow Rate 10000 E

Q. -ATRIUM-112 Loop Flow Rate bJJ (IJ l1l 8000

°';ii:

0 u::

6000 I 4000 0 so 100 150 200 250 300 350 Vessel to Drywell delta-P, psi FSAR REV. 70 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 & 2 FINAL SAFETY ANALYSIS REPORT LOW PRESSURE CORE SPRAY FLOW VS. HEAD USED IN LOCA ANALYSIS Figure 6.3-79C, Rev 3

20000 -r-----.--------.------,------,------,------,,

-+- LPCI 2 Pumps/Loop Flow Rate

-11D- LPCI 1 Pump/Loop Flow Rate 12500 E

0.

O>

'i 0 10000 u::

0 a.

...J 7500 -

5000 - ----------------,~~-

0-l------+------1------+------+------+---~---I 0 50 100 150 200 250 300 Pressure Difference, psid FSAR REV.70 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 & 2 FINAL SAFETY ANALYSIS REPORT RHR (LPCI) FLOW VS. HEAD CHARACTERISTICS USE IN LOCA ANALYSIS

14 140 13 130 12 s0 120

~

11 110 8 w

s0 a.

10 100 6 w U)

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0 s0 9 90 4 I w

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w IL u

7 z 70

~ w 0

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2 20 I 10 IL I z I

10 NPSHAATCL 5 U) a.

SUCTION NOZZLE z

0 0 0 0 500 1000 1500 2000 2500 3000 3500 4000 4500 GALLONS PER MINUTE FSAR REV. 65 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 AND 2 FINAL SAFETY ANALYSIS REPORT CHARACTERISTIC CURVES FOR CORE SPRAY PUMP FIGURE 6.3-118, Rev. 52 Auto Cad: Figure Fsar 6_3_118.dwg

1J 130 12 l2D a:

w

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(:- 0 0 G 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 GALLONS PER MINUTE I* 10001 FSAR REV. 65 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 AND 2 FINAL SAFETY ANALYSIS REPORT CHARACTERISTIC CURVES FOR LPCI PUMP FIGURE 6.3-119, Rev. 51 Auto Cad: Figure Fsar 6_3_119.dwg

E_

- - - - - - - - - - - - - - - - - - - - - - - - - - - -..... 7000 3500 20 10 NPSH REQUIRED AT SUCTION

- 6000 3000 0 q Q = 5000 GPM NET, 5000 II I- WITH 100 GPM BOOSTER a::

(9

~ 2500 PUMP BYPASS a..

Cf) z 4000 !;j:

0

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...J z

~ 3000 ~

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1-0 1500 a::

0 2000 1-1000 MAIN PUMP 711-S-0785 BOOSTER PUMP 711-S-078*

1000 500 L----....I.----....L-----1-----.L.-----......_____ 0 1800 2000 2400 2800 3200 3600 4000 TURBINE SPEED (rpm)

FSAR REV. 65 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 AND 2 FINAL SAFETY ANALYSIS REPORT SPEED CHARACTERISTIC CURVES FOR HPCI PUMPS - UNIT 1 FIGURE 6.3-120, Rev. 54 Auto Cad: Figure Fsar 6_3_120.dwg

2l 3500 NPSH REQUIRED AT SUCTION 3000 10 6000 0

q I- 2500 Q = 5000 GPM NET,

_,,,,,. ...-"".: 5000 ~

UJ TOTALTORQUE / a::

UJ LL WITH 100 GPM BOOSTER _,,,,,. / (!)

z PUMP BYPASS

_,,,,,,. / a.

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UJ /

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/ a::

1000 MAIN PUMP 711-S-073 2000 ~

BOOSTER PUMP 711-S-0784 500 1000 0--------------------------------------------*0 2000 2400 2800 3200 3600 4000 4400 TURBINE SPEED (rpm)

FSAR REV. 65 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 AND 2 FINAL SAFETY ANALYSIS REPORT SPEED CHARACTERISTIC CURVES FOR HPCI PUMPS - UNIT 2 FIGURE 6.3-121, Rev. 54 Auto Cad: Figure Fsar 6_3_121.dwg

o a

SQ 1.0 DEG/PS TOP ATRIUM-10 SF-LPCI 102P /80F DT1

.-----.------~----..------..-------.-----~'-r------.---------,

.--N 0.... ,-

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c0 20 40 60 80 100 120 140 160 TIME (SEC)

Limiting TLO Recirculation Line Break Upper Plenum Pressure (Lower)

FSAR REV.65 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 & 2 FINAL SAFETY ANALYSIS REPORT LIMITING TLO RECIRCULATION LINE BREAK UPPER PLENUM PRESSURE (LOWER)

FIGURE 6.3-201, Rev 3 AutoCAD: Figure Fsar 6_3_201.dwg

g SQ 1.0 DEG/PS TOP ATRIUM-10 SF-LPCI 102P /80F DT1 O~---~-------~---~---~---......,_---~---~

0

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so 70 0

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0 o 1--o 0

0 oQ 20 40 60 80 100 120 140 160 TIME (SEC)

Limiting TLO Recirculation Line Break Total Break Flow Rate FSAR REV.65 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 & 2 FINAL SAFETY ANALYSIS REPORT LIMITING TLO RECIRCULATION LINE BREAK TOTAL BREAK FLOW RATE FIGURE 6.3-202, Rev 3 AutoCAD: Figure Fsar 6_3_202.dwg

g SQ 1.0 DEG/PS TOP ATRIUM-10 SF-LPCI 102P/80F DT1 0,-----,----------r----~------,----~.-----,-------,

0

("\I 0

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Limiting TLO Recirculation Line Break Core Inlet Flow Rate FSAR REV.65 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 & 2 FINAL SAFETY ANALYSIS REPORT LIMITING TLO RECIRCULATION LINE BREAK CORE INLET FLOW RATE FIGURE 6.3-203, Rev 3 AutoCAD: Figure Fsar 6_3_203.dwg

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Limiting TLO Recirculation Line Break Intact Loop Jet Pump Drive Flow Rate FSAR REV.65 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 & 2 FINAL SAFETY ANALYSIS REPORT LIMITING TLO RECIRCULATION LINE BREAK INTACT LOOP JET PUMP DRIVE FLOW RATE FIGURE 6.3-204, Rev 3 AutoCAD: Figure Fsar 6_3_204.dwg

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Limiting TLO Recirculation Line Break Broken Loop Jet Pump Drive Flow Rate FSAR REV.65 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 & 2 FINAL SAFETY ANALYSIS REPORT LIMITING TLO RECIRCULATION LINE BREAK BROKEN LOOP JET PUMP DRIVE FLOW RATE FIGURE 6.3-205, Rev 3 AutoCAD: Figure Fsar 6_3_205.dwg

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Limiting TLO Recirculation Line Break ADS Flow Rate FSAR REV.65 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 & 2 FINAL SAFETY ANALYSIS REPORT LIMITING TLO RECIRCULATION LINE BREAK ADS FLOW RATE FIGURE 6.3-206, Rev 3 AutoCAD: Figure Fsar 6_3_206.dwg

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Limiting TLO Recirculation Line Break HPCI Flow Rate FSAR REV.65 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 & 2 FINAL SAFETY ANALYSIS REPORT LIMITING TLO RECIRCULATION LINE BREAK HPCI FLOW RATE FIGURE 6.3-207, Rev 3 AutoCAD: Figure Fsar 6_3_207.dwg

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Limiting TLO Recirculation Line Break LPCS Flow Rate FSAR REV.65 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 & 2 FINAL SAFETY ANALYSIS REPORT LIMITING TLO RECIRCULATION LINE BREAK LPCS FLOW RATE FIGURE 6.3-208, Rev 3 AutoCAD: Figure Fsar 6_3_208.dwg

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Limiting TLO Recirculation Line Break Intact Loop LPCI Flow Rate FSAR REV.65 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 & 2 FINAL SAFETY ANALYSIS REPORT LIMITING TLO RECIRCULATION LINE BREAK INTACT LOOP LPCI FLOW RATE FIGURE 6.3-209, Rev 3 AutoCAD: Figure Fsar 6_3_209.dwg

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Limiting TL0 Recirculation Line Break Broken Loop LPCI Flow Rate FSAR REV.65 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 & 2 FINAL SAFETY ANALYSIS REPORT LIMITING TLO RECIRCULATION LINE BREAK BROKEN LOOP LPCI FLOW RATE FIGURE 6.3-210, Rev 3 AutoCAD: Figure Fsar 6_3_210.dwg

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Limiting TLO Recirculation Line Break Upper Downcomer Mixture Level FSAR REV.65 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 & 2 FINAL SAFETY ANALYSIS REPORT LIMITING TLO RECIRCULATION LINE BREAK UPPER DOWNCOMER MIXTURE LEVEL FIGURE 6.3-211, Rev 3 AutoCAD: Figure Fsar 6_3_211.dwg

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Limiting TLO Recirculation Line Break Lower Downcomer Mixture Level FSAR REV.65 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 & 2 FINAL SAFETY ANALYSIS REPORT LIMITING TLO RECIRCULATION LINE BREAK LOWER DOWNCOMER MIXTURE LEVEL FIGURE 6.3-212, Rev 3 AutoCAD: Figure Fsar 6_3_212.dwg

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Limiting TLO Recirculation Line Break Lower Downcomer Liquid Mass FSAR REV.65 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 & 2 FINAL SAFETY ANALYSIS REPORT LIMITING TLO RECIRCULATION LINE BREAK LOWER DOWNCOMER LIQUID MASS FIGURE 6.3-213, Rev 3 AutoCAD: Figure Fsar 6_3_213.dwg

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Limiting TLO Recirculation Line Break Upper Plenum Liquid Mass FSAR REV.65 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 & 2 FINAL SAFETY ANALYSIS REPORT LIMITING TLO RECIRCULATION LINE BREAK UPPER PLENUM LIQUID MASS FIGURE 6.3-214, Rev 3 AutoCAD: Figure Fsar 6_3_214.dwg

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Limiting TLO Recirculation Line Break Hot Channel Inlet Flow Rate FSAR REV.65 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 & 2 FINAL SAFETY ANALYSIS REPORT LIMITING TLO RECIRCULATION LINE BREAK HOT CHANNEL INLET FLOW RATE FIGURE 6.3-216, Rev 3 AutoCAD: Figure Fsar 6_3_216.dwg

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Limiting TLO Recirculation Line Break Hot Channel Outlet Flow Rate FSAR REV.65 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 & 2 FINAL SAFETY ANALYSIS REPORT LIMITING TLO RECIRCULATION LINE BREAK HOT CHANNEL OUTLET FLOW RATE FIGURE 6.3-217, Rev 3 AutoCAD: Figure Fsar 6_3_217.dwg

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Limiting TLO Recirculation Line Break Hot Channel Coolant Temperature at the Limiting Node FSAR REV.65 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 & 2 FINAL SAFETY ANALYSIS REPORT LIMITING TLO RECIRCULATION LINE BREAK HOT CHANNEL COOLANT TEMPERATURE AT THE LIMITING NODE FIGURE 6.3-218, Rev 3 AutoCAD: Figure Fsar 6_3_218.dwg

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Limiting TLO Recirculation Line Break Hot Channel Quality at the Limiting Node FSAR REV.65 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 & 2 FINAL SAFETY ANALYSIS REPORT LIMITING TLO RECIRCULATION LINE BREAK HOT CHANNEL QUALITY AT THE LIMITING NODE FIGURE 6.3-219, Rev 3 AutoCAD: Figure Fsar 6_3_219.dwg

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Limiting TLO Recirculation Line Break Hot Channel Heat Transfer Coeff.

at the Limiting Node FSAR REV.65 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 & 2 FINAL SAFETY ANALYSIS REPORT LIMITING TLO RECIRCULATION LINE BREAK HOT CHANNEL HEAT TRANSFER COEFF.

AT THE LIMITING NODE FIGURE 6.3-220, Rev 3 AutoCAD: Figure Fsar 6_3_220.dwg

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Limiting TLO Recirculation Line Break Cladding Temperatures FSAR REV.65 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 & 2 FINAL SAFETY ANALYSIS REPORT LIMITING TLO RECIRCULATION LINE BREAK CLADDING TEMPERATURES FIGURE 6.3-221, Rev 3 AutoCAD: Figure Fsar 6_3_221.dwg