Text

Amendment 27 to Updated Final Safety Analysis Report, Chapter 10, Steam and Power Conversion System
	ML22111A104
Person / Time
Site:	Saint Lucie
Issue date:	03/04/2022
From:	; Florida Power & Light Co
To:	; Office of Nuclear Reactor Regulation
Shared Package
ML22111A137	List: L-2022-018, Amendment 27 to Updated Final Safety Analysis Report, Chapter 1, Introduction and General Description of Plant; ML22063B120; ML22111A100; ML22111A101; ML22111A102; ML22111A103; ML22111A104; ML22111A105; ML22111A107; ML22111A108; ML22111A109; ML22111A112; ML22111A113; ML22111A114; ML22111A115; ML22111A116; ML22111A117; ML22111A118; ML22111A119; ML22111A120; ML22111A121; ML22111A122;
References
	L-2022-018
	Download: ML22111A104 (270)
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UFSAR/St. Lucie - 2 STEAM AND POWER CONVERSION SYSTEM CHAPTER 10 TABLE OF CONTENTS Section Title Page 10.0 STEAM AND POWER CONVERSION SYSTEM .......................................... 10.1-1 10.1

SUMMARY

DESCRIPTION ........................................................................... 10.1-1 10.2 TURBINE-GENERATOR ............................................................................... 10.2-1 10.2.1 DESIGN BASES ............................................................................................ 10.2-1 10.

2.2 DESCRIPTION

.............................................................................................. 10.2-2 10.2.3 TURBINE DISK INTEGRITY ......................................................................... 10.2-6 10.2.4 EVALUATION .............................................................................................. 10.2-10 10.2.5 TESTING AND INSPECTION...................................................................... 10.2-10 REFERENCES ............................................................................................ 10.2-11 10.3 MAIN STEAM SUPPLY SYSTEM ................................................................. 10.3-1 10.3.1 DESIGN BASES ............................................................................................ 10.3-1 10.3.2 SYSTEM DESCRIPTIONS ............................................................................ 10.3-2 10.3.3 EVALUATION ................................................................................................ 10.3-4 10.3.4 INSPECTION AND TESTING REQUIREMENTS .......................................... 10.3-6 10.3.5 SECONDARY WATER CHEMISTRY ............................................................ 10.3-7 10.3.6 STEAM AND FEEDWATER MATERIALS ................................................... 10.3-10 REFERENCES ............................................................................................ 10.3-12 10.4 OTHER FEATURES OF THE STEAM AND POWER CONVERSION SYSTEM ........................................................................................................ 10.4-1 10.4.1 MAIN CONDENSER...................................................................................... 10.4-1 10.4.2 AIR EVACUATION SYSTEM......................................................................... 10.4-5 10.4.3 TURBINE GLAND SEALING SYSTEM ......................................................... 10.4-6 10.4.4 STEAM DUMP AND BYPASS SYSTEM ....................................................... 10.4-8 10.4.5 CIRCULATING WATER SYSTEM ............................................................... 10.4-10 10.4.6 CONDENSATE CLEANUP SYSTEM .......................................................... 10.4-12 10.4.7 CONDENSATE, FEEDWATER AND HEATER DRAIN SYSTEM ............... 10.4-12 10-i Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 Section Title Page 10.4.8 STEAM GENERATOR BLOWDOWN SYSTEM (SGBS) ............................. 10.4-15 10.4.9 AUXILIARY FEEDWATER SYSTEM ........................................................... 10.4-18 10.4.9A AUXILIARY FEEDWATER SYSTEM, REQUIREMENTS EVALUATION .......................................................................................... 10.4.9A-1 10.4.9A AUXILIARY FEEDWATER SYSTEM ....................................................... 10.4.9A-2 10.4.9B AUXILIARY FEEDWATER SYSTEM RELIABILITY ANALYSIS ................10.4.9B-i 10-ii Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 STEAM AND POWER CONVERSION SYSTEM CHAPTER 10 LIST OF TABLES Table Title Page 10.2-1 DESIGN DATA FOR TURBINE-GENERATOR ........................................... T10.2-1 10.2-2 DELETED .................................................................................................... T10.2-2 10.2-3 DELETED .................................................................................................... T10.2-3 10.3-1 DESIGN DATA FOR MAIN STEAM SYSTEM PIPING AND VALVES ........ T10.3-1 10.3-2 MAIN STEAM LINE AND TURBINE EXTRACTION LINES ......................... T10.3-5 10.3-3 DELETED .................................................................................................... T10.3-7 10.3-4 DELETED .................................................................................................... T10.3-8 10.3-5 AUXILIARY EQUIPMENT STEAM REQUIREMENTS................................. T10.3-9 10.3-6 DELETED .................................................................................................. T10.3-11 10.3-7 MAIN STEAM/FEEDWATER PARAMETERS ........................................... T10.3-12 10.4-1 COMPONENT DESIGN PARAMETERS ..................................................... T10.4-1 10.4-1a AUXILIARY FEEDWATER SYSTEM MOTOR OPERATED VALVES ....... T10.4-14 10.4-2 AUXILIARY FEEDWATER MAKEUP REQUIREMENTS FOR HOT STANDBY AND HOT SHUTDOWN .......................................................... T10.4-15 10.4-3 FAILURE MODES AND EFFECTS ANALYSIS - AUXILIARY FEEDWATER SYSTEM ASSUMING A FEEDWATER OR MAIN STEAM LINE BREAK IN ST GEN. B AND LOSS OF OFF SITE POWER.............. T10.4-16 10.4-4 FAILURE MODES AND EFFECTS ANALYSIS - AUXILIARY FEEDWATER SYSTEM ASSUMING AN AUXILIARY FEEDWATER LINE BREAK AND LOSS OF OFF SITE POWER .............................................. T10.4-18 10.4-5 AUXILIARY FEEDWATER SYSTEM INSTRUMENTATION ..................... T10.4-20 10.4.9A-1 COMPARISON OF AFS SYSTEMS WITH NRC SYSTEM FLOW REQUIREMENTS .................................................................................. T10.4.9A-1 10.4.9A-2 AUXILIARY FEEDWATER SYSTEM (AFWS) ....................................... T10.4.9A-6 10.4.9A-3 DESIGN GUIDELINES FOR AFWS PUMP DRIVE AND POWER SUPPLY DIVERSITY FOR PWRS ...................................................... T10.4.9A-11 10.4.9A-4 EVALUATION OF THE SL 2 AUXILIARY FEEDWATER SYSTEM VERSUS THE NRC AFW SHORT AND LONG TERM RECOMMENDATIONS ....................................................................... T10.4.9A-13 10-iii Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 Table Title Page 10.4.9A-5 ST. LUCIE 2 LOSS OF FEEDWATER WITH OFFSITE POWER AVAILABLE - SEQUENCE OF EVENTS ............................................. T10.4.9A-25 10.4.9A-6 ST. LUCIE 2 LOSS OF FEEDWATER WITH LOSS OF OFFSITE POWER - SEQUENCE OF EVENTS .................................................. T10.4.9A-26 10.4.9A-7 ST. LUCIE 2 FEEDWATER LINE BREAK FOR HIGH Tavg CASE WITH OFFSITE 10.4.9A-28 POWER AVAILABLE - SEQUENCE OF EVENTS .............................................................................................. T10.4.9A-27 10.4.9A-8 ST. LUCIE 2 FEEDWATER LINE BREAK FOR LOW Tavg CASE WITH LOSS OF OFFSITE POWER - SEQUENCE OF EVENTS ........ T10.4.9A-28 10.4.9A-9 INITIAL CONDITIONS ......................................................................... T10.4.9A-29 10.4.9B-1 COMPONENT LIST MANUAL VALVES ................................................ T10.4.9B-1 10.4.9B-2 AFS FAILURE MODES AND EFFECTS ANALYSIS ............................. T10.4.9B-8 10.4.9B-3a CUT SETS - LOFW AUTOMATIC AUXILIARY FEEDWATER SYSTEM INITIATION .......................................................................... T10.4.9B-16 10.4.9B-3b CUT SETS - LOOP AUTOMATIC AUXILIARY FEEDWATER SYSTEM STUDY ................................................................................. T10.4.9B-24 10.4.9B-3c CUT SETS - SBLO AUTOMATIC AUXILIARY FEEDWATER SYSTEM STUDY ................................................................................. T10.4.9B-35 10.4.9B-4a CUT SETS - LOFW MANUAL AUXILIARY FEEDWATER SYSTEM STUDY................................................................................. T10.4.9B-37 10.4.9B-4b CUT SETS - LOOP MANUAL AUXILIARY FEEDWATER SYSTEM STUDY................................................................................. T10.4.9B-44 10.4.9B-4c CUT SETS - SBLO MANUAL AUXILIARY FEEDWATER SYSTEM STUDY................................................................................. T10.4.9B-53 10.4.9B-5 BASIC EVENT FAILURE RATE DATA ............................................... T10.4.9B-54 10.4.9B-6 AFS VALVES SUBJECT TO ASME SECTION XI TESTING .............. T10.4.9B-56 10.4.9B-7a DOMINANT CUT SETS - LOFW (AUTOMATIC) ................................ T10.4.9B-57 10.4.9B-7b DOMINANT CUT SETS - LOOP (AUTOMATIC) ................................. T10.4.9B-58 10.4.9B-7c DOMINANT CUT SETS - SB (AUTOMATIC) ...................................... T10.4.9B-59 10.4.9B-8a DOMINANT CUT SETS - LOFW (MANUAL)....................................... T10.4.9B-60 10.4.9B-8b DOMINANT CUT SETS - LOOP (MANUAL) ....................................... T10.4.9B-61 10.4.9B-8c DOMINANT CUT SETS - SB (MANUAL) ............................................ T10.4.9B-62 10-iv Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 STEAM AND POWER CONVERSION SYSTEM CHAPTER 10 LIST OF FIGURES Figure Title 10.1-1a FLOW DIAGRAM MAIN STEAM SYSTEM 10.1-1b FLOW DIAGRAM MAIN STEAM SYSTEM 10.1-1c FLOW DIAGRAM EXTRACTION STEAM SYSTEM 10.1-1d FLOW DIAGRAM EXTRACTION STEAM SYSTEM 10.1-1e FLOW DIAGRAM AUXILIARY STEAM SYSTEM 10.1-1f FLOW DIAGRAM AIR EVACUATION SYSTEM 10.1-1g FLOW DIAGRAM MAIN STEAM 10.1-2a FLOW DIAGRAM CONDENSATE SYSTEMS 10.1-2b FLOW DIAGRAM FEEDWATER AND CONDENSATE SYSTEMS 10.1-3a FLOW DIAGRAM HEATER DRAIN AND VENT SYSTEM 10.1-3b FLOW DIAGRAM HEATER DRAIN AND VENT SYSTEM 10.2-1 HEAT BALANCES 10.2-2 HEAT BALANCES 10.2-3 STEAM PRESSURE VARIATION WITH POWER 10.2-4 TURBINE OVERSPEED PROTECTION ELECTROHYDRAULIC SYSTEM 10.2-5 DELETED 10.2-6 TURBINE HIGH-PRESSURE ELEMENT 1800-RPM DOUBLE FLOW DESIGN 10.2-7 TURBINE INNER CASING AND GUIDE BLADE CARRIERS 10.2-8 LOW-PRESSURE ELEMENT 1800 RPM DOUBLE FLOW DESIGN 10.2-9 DELETED 10.2-10 FLOW DIAGRAM TURBINE LUBE OIL SYSTEM 10.2-11 FLOW DIAGRAM TURBINE LUBE OIL SYSTEM 10.3-1 MAIN STEAM SAFETY VALVES V8201 - V8216 8770-993 2 SHS 10.3-2 MAIN STEAM ISOLATION VALVE SH 1 OF 9 10.3-3 DELETED 10-v Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 Figure Title 10.4-1 CIRCULATING WATER SYSTEM OCEAN INTAKE AND DISCHARGE SHT. 1 10.4-2 OCEAN INTAKE AND DISCHARGE SYS SH. 2 10.4-3 OCEAN INTAKE AND DISCHARGE SYS SH. 3 10.4-4 OCEAN INTAKE AND DISCHARGE SYS SH. 4 10.4-5 FLOW DIAGRAM - STEAM GENERATOR BLOWDOWN PROCESS SYSTEM SHEET 1A & 1B 10.4-6 FLOW DIAGRAM - STEAM GENERATOR BLOWDOWN PROCESS SYSTEM SHEET 2 10.4-7 DELETED 10.4-8 FLOW DIAGRAM FEEDWATER & CONDENSATE SYSTEMS AND MAIN STEAM SYSTEM 10.4-8a UNIT 1 - UNIT 2 CONDENSATE STORAGE TANK INTERTIE 10.4-9 DELETED 10.4-10 AUXILIARY FEEDWATER REQUIREMENTS FOR SHUTDOWN 10.4-12 FLOW DIAGRAM STEAM GENERATOR BLOWDOWN COOLING SYSTEM 10.4-13 MAIN FW PIPING ISOMETRIC 10.4-14 MAIN STEAM TRESTLE 10.4-15 TRESTLE MISSILE PROTECTION 10.4-16 MAIN STEAM AND FEEDWATER PIPING - SECT & DETAILS 10.4-17 DELETED 10.4.9A-1 LOMF W/AC HOT LEG SUBCOOLING MARGIN VERSUS TIME EC 292 10.4.9A-2 LOMF W/LOOP HOT LEG SUBCOOLING MARGIN VERSUS TIME 636 10.4.9A-3 FLB W/AC STEAM GENERATOR INVENTORY VERSUS TIME 10.4.9A-4 FLB W/AC PRESSURIZER LIQUID VOLUME VERSUS TIME EC 292 10.4.9A-5 FLB W/AC PRESSURIZER PRESSURE VERSUS TIME 636 EC 10.4.9A-6 FLB W/AC HOT LEG SUBCOOLING MARGIN VERSUS TIME 292 636 10.4.9A-7 FLB W/LOOP STEAM GENERATOR INVENTORY VERSUS TIME 10.4.9A-8 FLB W/LOOP PRESSURIZER LIQUID VOLUME VERSUS TIME EC 292 636 10.4.9A-9 FLB W/LOOP PRESSURIZER PRESSURE VERSUS TIME 10-vi Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 Figure Title 10.4.9A-10 FLB W/LOOP HOT LEG SUBCOOLING MARGIN VERSUS TIME EC 292 10.4.9B-1 AFS SCHEMATIC DIAGRAM MANUAL DESIGN 636 10.4.9B-2 AFS SCHEMATIC DIAGRAM AUTOMATIC DESIGN 10.4.9B-3 FAULT TREE OF LOFW - MANUAL 10.4.9B-4 FAULT TREE OF LOOP - MANUAL 10.4.9B-5 FAULT TREE OF SB - MANUAL 10.4.9B-6 FAULT TREE OF LOFW - AUTOMATIC 10.4.9B-7 FAULT TREE OF LOOP - AUTOMATIC 10.4.9B-8 FAULT TREE OF SB - AUTOMATIC 10-vii Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 10.0 STEAM AND POWER CONVERSION SYSTEM 10.1

SUMMARY

DESCRIPTION The Steam and Power Conversion System (SPCS) includes the steam system, turbine generator, main condenser and other auxiliary subsystems. The SPCS P & I diagrams are shown on Figures 10.1-1, 2, and 3. The SPCS is designed to convert thermal energy in the form of steam into electrical energy by means of a regenerative cycle turbine generator. The turbine consists of a high pressure turbine element, four moisture-separator/ reheater assemblies, and two low pressure turbine elements all aligned in tandem. After expanding in the turbine, the exhaust steam is condensed in the main condenser and the energy which is unusable in the thermal cycle is rejected to the Circulating Water System. The condensate is collected in the condenser hotwells while the noncondensible gases in the steam are removed by the air evacuation system.

The condensate is returned to the steam generators by means of two of the condensate pumps and the two steam generator feedwater pumps. The feedwater flows through five stages of heat exchangers (i.e., high-and low-pressure heaters) arranged in two parallel trains where the feedwater is heated by extraction steam from various stages of the turbine. Extraction steam condensate drains from the first three stages of low pressure heaters and is cascaded back to the condenser hotwell. The condensate drained from the fourth stage low pressure heaters and the fifth stage high pressure heaters is returned to the feedwater system by two heater drain pumps.

Heat produced in the reactor core is transferred from the reactor coolant to the water in the steam generators producing steam for use in the turbine. In the event of a turbine trip, the heat transferred from the reactor coolant to the steam generators is dissipated through the turbine bypass system to the condenser and/or through the atmospheric dump valves and main steam safety valves.

Various portions of the Steam and Power Conversion System are designated safety-related and designed to seismic Category I requirements.

Details, including safety related design features, of the Main Steam Supply, Steam Generator Blowdown and Auxiliary Feedwater Systems are discussed in Section 10.3 and Subsections 10.4.8 and 10.4.9, respectively.

Design data as well as design codes applied to system components are provided in their respective sections.

10.1-1 Amendment No. 24 (09/17)

Referto Dwg.

2998-G-079SH 1 FLORIDAPOWER & LIGHTCOMPANY ST. LUCIE PLANT UNIT 2 FLOWDIAGRAM MAlN STEAMSYSTEM FIGURE 10.1-1a Amendment No. 10, (7/96)

Referto Dwg.

2998-G-079SH 2 FLORIDAPOWER & LIGHTCOMPANY ST. LUCIE PLANT UNIT 2 FLOWDIAGRAM MAINSTEAMSYSTEM FIGURE 10.1-1 b Amendment No. 10, (7/96)

Referto Dwg.

2998-G-079SH 3 FLORIDAPOWER & LIGHTCOMPANY ST. LUCIE PLANT UNIT 2 FLOWDIAGRAM EXTRACTION STEAMSYSTEM FIGURE 10.1-1c Amendment No. 10, (7/96)

Referto Dwg.

2998-G-079SH 4 FLORIDAPOWER & LIGHTCOMPANY ST. LUCIE PLANT UNIT 2 FLOWDIAGRAM EXTRACTION STEAMSYSTEM FIGURE 10.1-1d Amendment No. 10, (7/96)

Referto Dwg.

2998-G-079SH 5 FLORIDAPOWER & LIGHTCOMPANY ST. LUCIE PLANT UNIT 2 FLOWDIAGRAM AUXILIARY STEAMSYSTEM FIGURE 10.1-1e Amendment No. 10, (7/96)

Referto Dwg.

2998-G-079SH 6 FLORIDAPOWER & LIGHTCOMPANY ST. LUCIE PLANT UNIT 2 FLOWDIAGRAM AIR EVACUATION STEAMSYSTEM FIGURE 10.1-1f Amendment No. 10, (7/96)

Referto Drawing 2998-G-079SH 7 FLORIDAPOWER & LIGHTCOMPANY ST. LUCIE PLANT UNIT 2 FLOWDIAGRAM MAINSTEAM FIGURE 10.1-1g Amendment No. 18 (01/08)

Referto Drawings 2998-G-080SH 1A & B FLORIDAPOWER & LIGHTCOMPANY ST. LUCIE PLANT UNIT 2 FLOWDIAGRAM CONDENSATESYSTEM FIGURE 10.1-2a Amendment No. 18 (01/08)

Referto Dwg.

2998-G-080SH 2A & B FLORIDAPOWER & LIGHTCOMPANY ST. LUCIE PLANT UNIT 2 FLOWDIAGRAM FEEDWATERAND CONDENSATE SYSTEMS FIGURE 10.1-2b Amendment No. 18 (01/08)

Referto Drawings 2998-G-081SH 1A & B FLORIDAPOWER & LIGHTCOMPANY ST. LUCIE PLANT UNIT 2 FLOWDIAGRAM HEATERDRAIN& VENTSYSTEM FIGURE 10.1-3a Amendment No. 18 (01/08)

Referto Drawing 2998-G-081SH 2 FLORIDAPOWER & LIGHTCOMPANY ST. LUCIE PLANT UNIT 2 FLOWDIAGRAM HEATERDRAIN& VENTSYSTEM FIGURE 10.1-3b Amendment No. 18 (01/08)

UFSAR/St. Lucie - 2 10.2 TURBINE-GENERATOR The main turbine receives steam from the two steam generators and converts a portion of the available enthalpy into electrical energy by driving the turbine generator. The Steam and Power Conversion System P & I diagrams are shown an Figures 10.1-1(a-f), 2a, 2b, 3a and 3b. Heat balances at stretch power and rated power are shown on Figures 10.2-1 and 10.2-2 respectively.

10.2.1 DESIGN BASES The main turbine is designed for variations in steam pressure and temperature as shown on Figure 10.2-3. The system is also designed to accommodate steam, and pressure transients which will occur following a sudden loss of electrical load. Design data is presented in Table 10.2-1.

Figures 10.2-1 and 10.2-2 are retained for historical purposes and depict the projected heat loads and electrical output for normal and stretch power at the time of plant license.

Base load operation is expected for the turbine generator unit. Turbine generator gross electrical output corresponding to nominal full reactor power, and when operating at zero percent makeup with five stages of feedwater heaters in service, is 1080 MWe as shown on Figure 10.2-2a. Design data is presented in Table 10.2-1.

For the extended power uprate, the generator gross electric output is approximately 1045 MWe at a conservative NSSS power level of 3034 MWt (75F CWIT) as shown in Figure 10.2-2a.

Because the Nuclear Steam Supply System has the capability of accepting a step load change of 10 percent, and ramp load change of five percent per minute over the load range of 15 to 100 percent, the rate of load change of the turbine generator is restricted to these values although it has the capability of accepting load changes at faster rates. These load change rates can be accomplished without the operation of the turbine bypass system, described in Subsection 10.4.4.

The turbine generator is not required for operation under the stresses that could be imposed by the operating basis earthquake (OBE) or the safe shutdown earthquake (SSE); however the turbine generator is designed to function under the thermal stresses which could be imposed due to the upset, emergency, and faulted conditions as defined in ANSI N18.2, Nuclear Safety Criteria for the Design of Stationery PWRS, 1972.

The turbine-generator set and accessories are classified as non Seismic and are designed in accordance with industry standards where applicable (i.e., in accordance with ANSI codes for power piping, TEMA Standards for Heat Exchangers, NEMA standards, IEEE standards, Hydraulic Institute standards, ASME Power Test Code for Steam Turbines, ASME Code Section VIII, AWS and ASTM).

10.2-1 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 10.

2.2 DESCRIPTION

The turbine is a Siemens Energy Inc., tandem-compound, four-flow exhaust, 1800 rpm unit and has moisture separation and reheat between the high pressure and the two low pressure elements. The ac generator and brushless-type exciter are direct-connected to the turbine generator shaft. The turbine consists of one double-flow high pressure element in tandem with two double-flow low pressure elements. The generator is a hydrogen cooled, rotor- arch-stator unit rated at 1200 MVA with the capability to accept the gross rated output of the turbine at rated steam conditions. The generator shaft seals are oil sealed to prevent leakage.

10.2.2.1 Turbine Generator Auxiliary Systems There are four horizontal-axis, cylindrical-shell, combination moisture separator/reheater (MSR) assemblies located alongside the low pressure elements on the Turbine Building operating floor.

This equipment receives steam from the exhaust of the high pressure turbine element. Internal manifolds in the lower section of these assemblies distribute the wet steam and allow it to rise through a chevron-type moisture separator where the moisture is removed. Steam extracted from the main steam line, upstream of the turbine, enters each MSR assembly, passes through the reheater bundle and leaves as condensate. The steam leaving the separator rises past the reheater tube bundle where it is reheated to 515°F when operating at full power. This reheated steam passes through nozzles in the top of the assemblies, flows to the low pressure turbine elements, and finally exhausts to the condenser (see Figure 10.1-1).

The turbine lube oil system supplies oil for lubricating the turbine generator and exciter bearings. Turbine oil purification equipment is available on both the Unit 2 and Unit 1 sites for removal of water and other impurities. Both units have the capability to transfer oil to each other for purposes of purification or in cases of emergency. See Figures 10.2-10 and 10.2-11.

Hydrogen is supplied by the bulk hydrogen storage system which is located on the north side of the St. Lucie Unit 1 intake structure. It consists of a tube trailer connected in parallel with a bottle header to the distribution header. The distribution header supplies hydrogen to the Turbine Building and Auxiliary Building for both St. Lucie Unit 1 and St. Lucie Unit 2. Operating procedures provide the precautions as well as the detailed steps to prevent fires and explosions while filling and purging the generator.

The hydrogen alarm panel alerts the operator to any off-normal hydrogen condition during normal operations.

The Main Extraction and Auxiliary Steam Systems P & I diagram is shown on Figure 10.1-1.

The heating steam for the feedwater heaters is extracted from the turbine as follows: Extractions for the high pressure heaters (2-5A & 2-5B) and low pressure heaters (2-4A & 2-4B) are from the high pressure turbine element; the extractions for the remaining low pressure heaters (2-1A,-1B,-2A,-2B,-3A &-3B) are from the low pressure turbine elements. High pressure heaters 2-5A and 2-5B are drained into low pressure heaters 2-4A and 2-4B; the drains from the low pressure heaters 2-4A and 2-4B are directed to the drain coolers. The condensate accumulated in the drain coolers is then pumped by the two heater drain pumps into the condensate system upstream of the low pressure heaters 4A & 4B. Alternate drains are also provided to automatically drain all the heaters directly to the condenser when a condition of high heater water level occurs. In addition, heaters 2-5A and 2-5B collect the drains from the reheater drain collectors and heaters 2-4A and 2-4B collect the drains from the moisture-separator drain pots.

10.2-2 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 The H.P. Turbine has two stop and two control valves in each of the two steam chests. The L.P.

Turbines have one reheat stop and one interceptor valve in each of the four hot reheat lines.

Therefore, the failure of one valve to close will not affect the shutdown of the turbine. The closing time for these valves including signal time is as follows: (a) stop valve 0.260 second, (b) control valve 0.230 second, (c) reheat stop valve 0.230 second, and (d) interceptor valve 0.230 second. These valves are hydraulically operated by the electrohydraulic control system. The hydraulic pressure keeps these valves open and loss of hydraulic pressure closes these valves by spring force.

The extraction steam lines from third, fourth and fifth point are provided with reverse current valves, which close immediately on flow reversal (within one second of turbine trip). The steam quantity ahead of the reverse current valves and in the extraction steam lines to the condenser neck heaters #1 and 2 is not enough to overspeed the turbine to the design overspeed of 120 percent normal speed on a turbine trip. On a turbine trip, the reactor is also tripped. The turbine extraction steam valves are exercised every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , which meets or exceeds the manufacturer's recommendation for testing.

The analysis of turbine-generator missile probabilities and effects of other externally generated missiles is discussed in Section 3.5 Plant Structures.

10.2.2.2 Turbine Protective Devices The major protection device provided to the turbine generator set is the overspeed protection system which is completely described below. However, in addition to the overspeed trip mechanism, the turbine is provided protection for the following:

a. Low Condenser Vacuum - This tripping device is designed to trip the turbine in case of a serious rise in exhaust pressure. The unit will trip when the vacuum decreases to 18-22 inches of mercury.

b. Low Turbine Bearing Oil Pressure - The bearing oil pressure setting at normal speed is approximately 14-18 psig. However, should this pressure reach 5-6 psig the low bearing oil pressure protective device will trip the unit. EC291159 Any turbine trip causes the hydraulic trip fluid header pressure to decrease and close steam to the turbine. The Turbine Control System and trips are discussed in Subsection 7.7.1.1.10.

EC291159 10.2.2.3 Turbine Overspeed Protection System The main turbine has three overspeed protection systems;

a. Overspeed Protection Controller (OPC)

b. Two electronic, triple redundant Overspeed Protection Systems The OPC and the primary electronic overspeed system do not share any sensing device.

Overspeed Protection Control (OPC) System The OPC system is a digital electro-hydraulic control system that controls turbine overspeed in the event of a partial or complete loss of load and if the turbine reaches or exceeds 103 percent 10.2-3 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 of rated speed. It trips the turbine at 111.5 percent of rated speed. Additionally, loss of hydraulic pressure or power failure in the electro-hydraulic system due to any cause will trip the turbine and the reactor.

Turbine power input is a function of high pressure (HP) exhaust pressure; a pressure transducer provides HP exhaust pressure. A three-phase watt transducer provides generated KW information. These quantities are compared: if they differ by a preset amount protective logic is activated. The signals from the transducers are checked against high and low reference voltages to determine when a transducer fails high or low. Overspeed information (in rpm) is supplied by active (powered) pick-ups coupled magnetically to a notched wheel on the turbine rotor. These pickups generate pulses which are fed to the digital electro-hydraulic (DEH) cabinet analog section to form speed channels; a control speed channel and an OPC speed channel.

The output of the control speed channel cards is compared to an overspeed setpoint. The resulting signal indicates when the speed is above the setpoint. If the speed is above the setpoint, a signal is generated for use by the overspeed protection controller (OPC) circuitry. It is also checked against a high and low limit. If either limit is exceeded, corresponding signals are generated.

The OPC continuously monitors the protection system inputs and outputs to notify the control room operators when equipment failures are encountered.

Upon complete loss of load, the mismatch of HP pressure and megawatts occurs and the breaker opens; this condition is detected as a complete load loss. When the generator breaker opens, the load drop anticipation (LDA) is set, requesting OPC action. All governor and interceptor valves are then rapidly closed. Load drop reset time is fixed at 10 sec. The LDA load loss circuit are inoperable below 22 percent load.

OPC action also occurs when turbine speed is equal to, or greater than, 103 percent of rated speed. Governor and interceptor valves are closed until the speed drops below 103 percent.

The redundant electronic emergency trip system will de-energize triple redundant solenoids which will cause all turbine valves to trip of the turbine speed reaches 111 percent of rated speed (See Figure 10.2-4). An air pilot valve used to vent control air to close extraction steam non-return valves is also triggered by the trip systems.

10.2-4 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 Electronic Overspeed Protection System Two independent, triple redundant electronic emergency trip systems replace the original mechanical overspeed protection system. Both systems independently release the control oil pressure, tripping all turbine valves when the turbine reaches 111 percent overspeed condition.

Therefore, all valves capable of admitting steam into the turbine will close. The primary protection system uses triple redundant passive speed sensors to monitor turbine speed. The redundant protection system shares the triple redundant active (powered) speed sensors with the OPC controller. Turbine speed is also monitored by built for purpose speed cards capable of tripping the turbine independently (communication with the electronic emergency trip system controllers is not required). The resulting overspeed protection is therefore redundant and diverse.

Protective functions of the original autostop oil system are integrated into the primary electronic overspeed trip system. The turbine is tripped when any one of the pressure status manifolds detect a trip condition. Protection parameters, such as the low bearing oil pressure and low vacuum are monitored by pressure status manifolds equipped with triple redundant smart pressure transmitters. The thrust bearing is also monitored by triple redundant proximity probes, but does not provide a turbine trip. The primary protection system trips the turbine when any of these parameters exceed a setpoint specified by the turbine manufacturer. The primary protection system also provides a trip signal monitored by the redundant protection system. This results in a turbine trip from the redundant protection system. Additionally, protective logic in the original auto-stop oil system are hard wired via new tripping relay contacts, into each of the triple redundant solenoid trip circuits. (See Figure 10.2-4)

Each triple redundant electronic emergency trip system uses a testable dump manifold (TDM) to interface with the control oil system. The 2-out-of-3 solenoid logic used to provide a protective trip also provides a means to test the system automatically while on-line. The solenoids are tripped one at a time and installed pressure transmitters monitor the manifold for a detectable pressure change.

The operator has a graphic window on the Turbine Trip Status Display graphic where the operator can modify the Overspeed Trip #2 setpoint. It is normally set at 1998 rpm. During turbine run-up, a test mode can be entered which changes the overspeed trip setpoint to 1799 rpm. This test mode provides the ability to test overspeed trip capability without stressing the turbine by overspeeding. The Overspeed Trip #2 Setpoint is reset and test results are reported to the operator after completion of the test.

The Turbine Control System is discussed in Section 7.7. Upon occurrence of a turbine trip, a signal is supplied to the Reactor Protective System to trip the reactor. This is discussed in Section 7.2.

10.2-5 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 10.2.2.4 Turbine Supervisory Instrumentation Turbine supervisory instrumentation (TSI) is designed to provide optimum insight into the mechanical integrity of the turbine generator. This system utilizes a combination of monitoring, recording and logging to collect data on the operation of the turbine. The TSI system is used to sense subtle changes in the operation of the turbine generator. The items listed below are valuable in monitoring the safe starting and loading of the turbine:

a. Radial Vibration and Vibration Phase Angle

b. Rotor Eccentricity

c. Differential Expansion

d. Thrust Bearing Monitor

e. Case Expansion

f. Turbine Speed and Acceleration Historical record keeping or trending of these parameters provides a turbine mechanical maintenance program which may prove invaluable by preventing catastrophic equipment failure thereby decreasing unscheduled downtime.

Each instrument module is provided with continuous front panel indication and two levels of alarms. In addition to these local alarms, RTGB-201 contains two annunciator windows which warn the operator of abnormal turbine mechanical conditions. Parameter trending is accomplished via three, RTGB-201 mounted recorders which continuously monitor all inputs. A TSI electronic cabinet is located at elevation 43.00 feet in the RAB adjacent to the PSB-1 relay cabinet 2B. The cabinet is equipped with indication and alarms for monitoring the aforementioned Unit 2 turbine parameters. Additional monitoring is done via a recorder, displays, and an annunciator which are located on RTGB-201. The increasing margin of any one parameter's value from baseline information identifies a need for maintenance investigation and/or action depending on the severity of change.

A mimic or graphical representation of the turbine generator with all parameters monitored by the TSI system, is mounted on the rear of RTGB-201. Each parameter is depicted by an indicating light that illuminates when an alert condition is reached. The mimic furnishes the operator with a quick and accurate information about the turbine generator's mechanical condition.

10.2.3 TURBINE DISK INTEGRITY Modern manufacturing and quality control procedures have eliminated the credibility of turbine rotor failures. To ensure this, FPL complies with the turbine vendor's inspection/refurbishment recommendations.

The main turbine is a Siemens Energy Inc. unit consisting of one high pressure (HP) and two low pressure (LP) elements as shown in Figures 10.2-6 through 10.2-8.

The probability of missile generation due to disk failure is evaluated in Subsection 3.5.1.3.

10.2-6 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 For many years, Siemens Energy Inc. original design of shrunk on disk rotors, as well as the advanced disk design, have demonstrated and proven the quality of this technology. The total number of fleet operating hours is more than 2,750,000 which have led to more than 40,000,000 disk operating hours, bearing in mind that each unit consists of two to three LP turbine elements with six to ten disks each. The oldest rotors have been in operation for approximately 225,000 operating hours, and the inspections of the disks performed after more than 200,000 hours0 days 0 hours 0 weeks 0 months detected no cracks.

Various important factors have contributed to this record:

a. Factory test procedures and inspection techniques Forgings are subject to inspection and testing both at the forging supplier and at Westinghouse. Present manufacturing and inspection techniques for turbine rotor and disc forgings make the possibility of an undetected flaw extremely remote.

Current design procedures are well established and conservative, and analytical tools such as finite element and fracture mechanics techniques allow in-depth analysis of any potential trouble spots such as areas of stress concentration or inclusions which could give rise to crack propagation. Destructive testing of material specimens taken from the disc forgings and ultrasonic test of each disc following major heat treatment ensure sound discs with mechanical properties (tensile strength, yield strength, ductility and impact strength) equal to or exceeding the specified levels.

b. Redundancy in the protection system The turbine generator is provided with three overspeed protection systems, the overspeed protection controller (OPC) and two redundant electronic overspeed protection systems. The OPC (electro-hydraulic) control system and the primary electronic overspeed protection system do not share any sensing devices. These are discussed in detail in Subsection 10.2.2.

On a turbine trip, two separate main steam line valves (stop and governing valves) are tripped closed to provide a redundant system.

It should be noted that each stop, governing, reheat stop and intercept valve is spring-closed; thus, it is only necessary to dump the high pressure fluid from under the servo-actuators to close the valves.

c. Operating test procedures Routine testing of the main steam valves and the mechanical emergency overspeed protective system while the unit is carrying load serve to verify continued operability of the overspeed protection.

d. High pressure turbine construction and design The high pressure turbine element, as shown on Figure 10.2-6, is of a double flow design thus it is inherently thrust-balanced. Steam from the four control valves enters at the center of the turbine element through four inlet pipes, two in the base and two in the cover.

10.2-7 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 Steam entering the HP turbine passes through the diagonal stage and flows through four reaction stages, all mounted on the inner casing upstream of the extraction. Downstream of the extraction, steam flows through four reaction stages mounted on the guide blade carriers, shown in Figure 10.2-7. The inner casing and the guide blade carriers are mounted on the outer casing.

The high pressure rotor is made of 26NiCrMoV10-10 alloy steel. The rotating blades are made of X20Cr13 high chromium steel. The rotor with rotating blades weighs approximately 122,842 lbs.

The inner casing and guide blade carriers are GX8CrNi12 high chromium steel castings. The diagonal stage guide blades are made of X22CrMoV12-1 high chromium steel. The reaction stage guide blades are made of X20Cr13 high chromium steel. The inner casing with stationary blades weighs approximately 48,722 lbs., and each guide blade carrier with stationary blades weighs approximately 28,396 lbs.

The outer casing cover and base (upper and lower half) are held together by means of more than 100 studs. The stud material is an allow steel. Specific replacement horizontal joint plane studs and support keys are made of X19CrMoNbVN11-1 high chromium steel. Specific replacement horizontal joint plane cap nuts are made of 21CrMoV5-7 alloy steel. Studs have lengths ranging from 17 to 66 inches and diameters ranging from 2.5 inches to 4.5 inches.

All significant fragments generated by any postulated failure of the HP turbine rotor would be contained by the HP turbine inner casing, guide blade carriers, and outer casing. There is a remote possibility that some minor missiles could result from the failure of couplings or portion of rotors which extend outside the casings. These missiles would be much less hazardous than the LP disk missiles, due to low mass and energy, and therefore do not require further consideration.

e. Low pressure turbine construction and design The double flow low pressure turbine, shown on Figure 10.2-8, incorporates high efficiency blading, diffuser type exhaust and liberal exhaust hood design. The low pressure turbine cylinder is fabricated from steel plate to provide uniform wall thickness, reducing thermal distortion to a minimum. The entire outer casing is subjected to low temperature exhaust steam.

10.2-8 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 The temperature drop of the steam from its inlet to the LP turbine to its exhaust from the last rotating blades is taken across three walls; a guide blade carrier, a thermal shield, and an inner casing, as shown in Figure 10.2-8. This precludes a large temperature drop across any one wall, except the thermal shield which is not a structural element, thereby virtually eliminating thermal distortion. The fabricated inner cylinder is supported by the outer casing at the horizontal centerline and is fixed transversely at the top and bottom and axially at the centerline of the steam inlets, thus allowing freedom of expansion independent of the outer casing. The guide blade carrier is, in turn, supported by the inner casing, at the horizontal centerline and fixed transversely at the top and bottom and axially at the centerline of the steam inlets, thus allowing freedom of expansion independent of the inner casing. The inner casing is surrounded by the thermal shield. The steam leaving the last row of blades flows into the diffuser where the velocity energy is converted to pressure energy. The outer casing is fabricated mainly of ASTM 515-GR65 material. The low pressure rotors are made of NiCrMoV alloy steel. The inner casing is fabricated of ASTM A 516-GR70 and the guide blade carrier is fabricated of ASTM A 508 material.

The shrunk-on discs are made of NiCrMoV alloy steel. There are six discs shrunk on the shaft with three per flow. These discs experience different degrees of stress when in operation. Disc No. 1, starting from the transverse centerline, experiences the highest stress, while Disc No. 3 experiences the lowest.

10.2.3.1 Turbine Disk Design The turbine is designed to withstand normal conditions, anticipated transients or accidents resulting in turbine trip. The turbine disk design is based on the turbine disk design criteria in Standard Review Plan 10.2.3, II.5 (11/75) and our extent of compliance is as follows:

a. The calculated overspeed upon a loss of load is less than 115% of rated speed.

Adding 5% to this speed as required in SRP 10.2 gives approximately 120% of rated speed. The turbine rotor is designed and tested to 120% of rated speed.

b. The combined stresses of low pressure disks at design overspeed due to centrifugal forces, interference fit and thermal gradients do not exceed 0.75 of the minimum specified yield strength of the materials. Since the high pressure rotor is a solid forging and not a disk design the acceptance criteria in Section II.5 of SRP 10.2.3 does not apply.

c. The turbine shaft bearings are designed to withstand normal operating loads, anticipated transients or accidents resulting in turbine trip.

d. The rotors are designed so that the response levels at the natural critical frequency of the turbine shaft assemblies are controlled between 0 and 20 percent overspeed, so as to cause no distress to the unit during operation.

e. The rims of the low pressure disks can also be inspected. The keyways of the low pressure rotors can be inspected by means of ultrasonic techniques.

An evaluation has been made of the design, assembly and operating conditions of the low pressure turbine discs to assess the potential for stress corrosion cracking (Ref. 1).

10.2-9 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 The results of the evaluation demonstrated that the probability of stress corrosion cracking was low. However, to ensure against this event occurring, LP Turbine Discs are inspected at regular intervals and incorporated into the plant In-service Inspection Program.

10.2.4 EVALUATION The turbine generator unit as well as other steam handling components of the Steam and Power Conversion System are not expected to contain significant radioactive concentrations. Only in the event of primary-to-secondary system leakage (due to a steam generator tube leak) is it possible for the SPCS to become radioactively contaminated. In this event, monitoring of condenser air discharge will detect any contamination. Full discussions of the radiological aspects of primary-to-secondary leakage including anticipated operational concentrations, of radioactive contaminants, means of detection of the environment can be found in Sections 11.1 and 11.5. Limiting conditions for operation are a part of the Technical Specifications.

A description of the protection provided by bypassing and dumping main steam to the condenser and atmosphere in case of sudden load rejection by the turbine generator is included in Subsection 10.4.4. A description of the protection provided by exhausting steam to the atmosphere through the main steam safety valves or atmospheric dump valves in the event of a turbine generator trip with coincident failure of the Steam Dump and Bypass System is provided in Subsection 10.3.2.

Refer to Subsections 11.2.5 and 11.3.5 for discussions of radiation concentrations and expected releases of radioactivity during operation. The anticipated operating radioactive concentrations in the system do not require shielding or access control in the Turbine Building.

Details of the fracture mechanics analysis techniques applied to the St. Lucie Unit 2 turbine are given in Reference 1.

10.2.5 TESTING AND INSPECTION In-service inspection of the turbine-generator unit consists of periodic visual examinations.

Other nondestructive testing includes magnafluxing of the rotors and blades. An ultrasonic examination of the low pressure turbine rotor discs is required at approximately 100,000 operating hour intervals provided no cracks are detected. Inspection intervals shall not exceed 12 years to allow adjustments for operating cycles based on Siemens Energy Inc.

recommendations. Refer to Section 3.5.1.3 for a discussion on the justification for the 100,000 hour0 days 0 hours 0 weeks 0 months inspection interval.

The turbine throttle/stop, reheat stop and interceptor steam valves are tested in accordance with the requirements specified in Section 13.7.1.6.2. These valves are disassembled and inspected approximately every three and 1/3 years in accordance with the in-service inspection program, 10.2-10 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2

REFERENCES:

SECTION 10.2

1) CT-27455, Rev. 1, Missile Report for FPL St. Lucie Units 1&2, BB281-13.9 m2, August 31, 2009, Siemens Energy, Inc.

10.2-11 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 TABLE 10.2-1 DESIGN DATA FOR TURBINE-GENERATOR

1. Turbine Throttle flow, max. rated, lb/hr 10,433,550 Throttle flow, max. calculated, (VWO*) lb/hr 12,242,000 Throttle pressure (rating/VWO)*, psig 840 Steam moisture, max., percent 0.40 Rating, max. guaranteed, KW 1,080,000 Rating, max calculated, KW 969,587 Turbine back-pressure, in. Hg abs 2.94 Hg No. of extractions 5 Quality Group D

2. Generator Rating, KVA 1,200,000 Power factor 0.9 Voltage, volts 22,000 Rpm/Frequency/Phase, Hz 1800/60/3 Hydrogen pressure, psig 75 Quality group D

VWO Valves wide open T10.2-1 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 THIS TABLE HAS BEEN DELETED T10.2-2 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 THIS TABLE HAS BEEN DELETED T10.2-3 Amendment No. 24 (09/17)

Referto Drawing 2998-G-056SH 1 Amendment No. 18 (01/08)

FLORIDAPOWER & LIGHTCOMPANY ST. LUCIE PLANT UNIT 2 HEATBALANCES FIGURE 10.2-1

Referto Drawing 2998-G-056SH 2 Amendment No. 18 (01/08)

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FLORIDAPOWER & LIGHTCOMPANY ST. LUCIE PLANT UNIT 2 TURBINEHIGH-PRESSURE ELEMENT 1800-RPMDoubleFlowDesign FIGURE 10.2-6 Amendment No. 21 (11/12)

G*ide .8 1 lieC.nr iB" (G FLORIDAPOWER & LIGHTCOMPANY ST. LUCIEPLANTUNIT2 TURBINEINNERCASINGAND GUIDEBLADECARRIERS FIGURE10.2-7 Amendment No. 21 (11/12)

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_j FLORIDAPOWER & LIGHTCOMPANY ST. LUCIE PLANT UNIT 2 LOW PRESSUREELEMENT 1800RPM DOUBLE-FLOWDESIGN FIGURE 10.2-8 Amendment No. 20 (05/11)

THISFIGUREHAS BEEN DELETED Amendment No. 20 (05/11)

FLORIDAPOWER & LIGHTCOMPANY ST. LUCIE PLANT UNIT 2 TYPICALLP CYLINDER FIGURE 10.2-9

Referto Drawing 2998-G - 086 SH 2 Amendment No. 18 (01/08)

FLORIDAPOWER & LIGHTCOMPANY ST. LUCIE PLANT UNIT 2 FLOWDIAGRAM TURBINELUBEOIL SYSTEM FIGURE 10.2-10

Referto Drawing 2998-G - 086 SH 3 Amendment No. 18 (01/08)

FLORIDAPOWER & LIGHTCOMPANY ST. LUCIE PLANT UNIT 2 FLOWDIAGRAM TURBINELUBEOIL SYSTEM FIGURE 10.2-11

UFSAR/St. Lucie - 2 10.3 MAIN STEAM SUPPLY SYSTEM The Main Steam System is designed to convey steam generated in the two steam generators through the containment vessel in two separate lines to the high pressure turbine and to other auxiliary equipment for power generation. Portions of the Main Steam System provide both normal and safety related functions.

The following portions of the Steam and Power Conversion System are designated safety-related and designed to seismic Category I requirements.

a. Main Steam: The main steam discharge piping from the steam generator up to and including the main steam isolation valves is designed to Quality Group B requirements.

b. The main steam supply for the auxiliary feedwater pump turbine, from the steam generators to the outermost containment isolation valves, is designated Quality Group B.

While this section addresses the entire Main Steam System, emphasis is placed on the safety-related portion of the system.

The extended power uprate impact on the Main Steam System has been analyzed and the system parameters have been added to Table 10.3-7. The uprate increases the velocity in the system piping and the existing pipe size has been determined to be adequate. Because of the extended power uprate, the moisture separator reheaters have been replaced and the capabilities of selected Heater Drain System valves, including the MSR tube drain control valves, have been increased to pass the required flow rates.

10.3.1 DESIGN BASES The safety-related portions of the Main Steam System have the following design bases:

a. Provide containment isolation in the event of a loss of coolant accident.

b. Prevent uncontrolled blowdown of both steam generators in the event of a steam line break accident.

c. Provide decay heat removal for the Reactor Coolant System in the event of a loss of offsite power.

d. Provide over-pressure protection for the steam generators and Main Steam System.

e. Withstand the adverse environmental effects of tornadoes, hurricanes, and flooding. Environmental qualification is referenced in Section 3.11.

f. Withstand pipe rupture effects as discussed in Section 3.6.

g. Withstand externally generated missiles as discussed in Section 3.5.

h. Provide source of steam supply to the auxiliary feedwater pump turbine during normal and post accident cooldowns.

10.3-1 Amendment No. 25 (04/19)

UFSAR/St. Lucie - 2 The design bases for the safety-related instrumentation in the Steam and Power Conversion System are described in the following sections:

1. Main Steam Supply System (Sections 10.3 and 7.3)

2. Condensate and Feedwater System (Subsection 10.4.7 and Section 7.3)

3. Auxiliary Feedwater Systems (Subsection 10.4.9 and Section 7.3)

4. Steam Generator Blowdown System (Subsection 10.4.8 and Section 7.7)

The criteria and basis of the normal operation instrumentation (non-safety) of the Steam and Power Conversion System is discussed in Subsections 7.7.1.1.4, 7.7.1.1.5 and 7.7.1.1.10.

Sufficient instrumentation for the Main Steam Supply, Feedwater and Condensate Systems is provided to allow the operator to properly operate these systems. The instrumentation consists of appropriate pressure, temperature and flow measuring devices to adequately monitor these systems both locally and from the control room.

10.3.2 SYSTEM DESCRIPTIONS The Main Steam System is shown in Figure 10.1-1. Design data is given in Table 10.3-1.

Each of the two steam generators supplies steam to the turbine through a separate 34 inch O.D.

main steam line. The main steam line containment penetrations are designed with the flexibility to accommodate the expansions and contractions of the containment vessel (see Subsection 3.8.2). The steam lines, which are anchored on the outside of the penetration assemblies have enough flexibility to accommodate the expansion and contractions of the steam generators and the lines up to the anchor point. At the turbine, each of the two main steam lines terminate into a common header which feeds the four admission inlets to the turbine. The high pressure turbine inlet has four automatic turbine stop valves and four governing control valves.

Each main steam line is provided with a flow venturi, eight main steam safety relief valves, one main steam isolation valve and two atmospheric dump valves. The steam supply lines to the auxiliary feedwater pump turbine are taken from each main steam line upstream of the main steam isolation valve (MSIV).

The following MS motor operated valves are subject to the requirements of NRC Generic Letter 89-10; MV-08-1A, MV-08-1B, MV-08-12, MV-08-13, MV-08-14, MV-08-15, MV-08-16, MV 17, MV-08-18A, MV-08-18B, MV-08-19A, MV-08-19B, and MV-08-3.

The Main Steam System is designed to remove the heat generated in the Nuclear Steam Supply System (NSSS) during the plant startup, hot standby, hot shutdown, and normal cooldown, and was originally designed to permit load reductions of up to 45 percent load without reactor trip by the use of the steam dump & bypass control system (SBCS).

During normal startup, shutdown, and load change operations, the SBCS uses the condenser as a heat sink and main steam is not released to the atmosphere. The SBCS consists of four dump lines and one bypass line. These lines connect to the steam lines going to the moisture-separator/reheater tube bundles and discharge through control valves to the condenser. If a large rapid reduction in power demand occurs, the SBCS bypasses a combined capacity of 10.3-2 Amendment No. 25 (04/19)

UFSAR/St. Lucie - 2 greater than 45 percent of the steam to the condenser to help mitigate the transient. If the condenser is not available, the turbine bypass valves are blocked closed and steam is exhausted to the atmosphere through the atmosphere dump valves or main steam safety valves. If the condenser is not available on large load reductions, the main steam safety valves will open.

The main steam safety valves are direct acting, spring loaded, open bonnet carbon steel valves.

The main steam safety valves are flange mounted on each of the main steam lines upstream of the steam line isolation valves, and outside containment. A schematic drawing of the main steam safety valves is given in Figure 10.3-1. The main steam safety valve design data is given in Table 10.3-1.

The main steam line isolation valves are air operated Y-type bidirectional balanced stop valves.

The valve is located outside the reactor containment structure and as near to it as practical. The isolation valve closes to prevent steam from flowing from the steam generator to the turbine inlet manifold and to prevent backflow if the steam generator pressure drops below the turbine inlet manifold pressure. The valve is shown on Figure 10.3-2.

The increased main steam flow parameters due to EPU (Table 10.3-7) are still within the design capabilities of the valve. Because of the increase in mass flow due to EPU, the steam velocity through the system is higher and thereby the pressure drop across the valve will be higher than before. Additionally, since there is no change in the Main Steam Safety Valve Set Point of 985 psig (1000 psia), the valve design criterion of closing within 5.6 seconds at 1000 psi differential is still acceptable. The valve full closure time is 6.75 seconds which is the 5.6 seconds maximum allowable valve stroke time plus 1.15 seconds for maximum allowable instrument response time.

Hence, it is concluded that the MSIVs are acceptable for EPU operation without any design changes.

The design parameters for the atmospheric dump valves are provided in Table 10.3-1, while the performance requirements are provided in Subsection 10.4.9 and Figure 10.4-9. Both atmospheric dump valves and main steam safety valves are designed in accordance with ASME code Section III, code Class 2 requirements. The design parameters for the MSIV (including design capacity, pressure, temperature, codes) is provided in Table 10.3-1.

The main steam piping (including flow elements, safety relief valves, atmospheric dump valves, and isolation valves for steam to the auxiliary feedwater pump turbine) up to and including the main steam isolation valves outside containment are safety related and are designed to meet seismic Category I and ASME Code Section III, code Class 2 requirements. Piping from downstream of the isolation valves to the Auxiliary feedwater pump turbine stop valve is designed to meet seismic category I and ASME Code,Section III, Code Class 3 requirements.

The remainder of the main steam piping downstream of the main steam isolation valves is classified as non-safety related piping and is designed to meet the requirements of ANSI B31.1.

All other valves and components in the Main Steam System are designed and fabricated in accordance with manufacturers standards and, where applicable, in accordance with ASME Code,Section VIII, AWS, IEEE, NEMA, and OSHA.

The two main steam lines are joined to a common header at the turbine inlet. Steam from the common header is supplied to the high pressure turbine leads, four moisture-separator/reheater 10.3-3 Amendment No. 25 (04/19)

UFSAR/St. Lucie - 2 assemblies, turbine gland sealing system, Auxiliary Steam System, steam jet air ejectors, and water box priming ejectors. Each steam turbine lead has an automatic turbine stop valve and a steam turbine governing control valve upstream of the turbine. The feedwater heaters do not receive steam directly from the steam generators but from extraction from various stages of the turbine.

The Main Steam System is also designed to provide an assured source of steam via a four inch branch line from each of the main steam lines for the turbine driven auxiliary feedwater pump 2C. The two branch lines are formed upstream of the main steam isolation valves and are headered just before the auxiliary turbine inlet. Refer to Table 10.3-2 for a tabulation of the branches from the main steam lines and for a listing of the various extraction line to the feedwater heaters.

The main steam isolation signal (MSIS) is a part of the Engineered Safety Features Actuation Signal (ESFAS) and is described in Section 7.3. Both main steam isolation valves close automatically on a MSIS, which is actuated on steam generator low pressure from either steam generator to prevent rapid flashing and blowdown of water in the shell side of the steam generator in the event of a steam line break, and thus avoid a rapid uncontrolled cooldown of the Reactor Coolant System. Automatic closure of both main steam isolation valves is also achieved by an MSIS signal actuated upon high containment pressure. The isolation valves prevent simultaneous release to the containment of the contents of the secondary sides of both steam generators in the event of the rupture on one main steam line inside the containment vessel, and by closing they also prevent backflow from the main steam header. The isolation valves can be remote manually operated from the control room.

The main steam and feedwater piping and support systems were evaluated to address EPU operating conditions. For main steam piping, these evaluations included an assessment of potential steam hammer loads resulting from turbine stop valve closure and main steam isolation valve closure events. For the feedwater system, these evluations included an assessment of potential water hammer loads resulting from feedwater regulating valve closure, feedwater isolation valve closure, and feedwater pump trip events. The main steam and feedwater piping and support system evaluations performed for EPU demonstrated that these systems are acceptable and will meet design basis allowable stress limits.

10.3.3 EVALUATION The Main Steam System from the steam generators up to and including the main steam line isolation valves is designed as seismic Category I. This portion of the system provides a containment isolation function in the unlikely event of a design basis accident (DBA). Each main steam line isolation valve (MSIV) receives a closure signal upon main steam isolation signal (MSIS) actuation. Further information on the isolation function of this system is given in Subsection 6.2.4.

The Main Steam System is designed to prevent blowdown of both steam generators in the event of a postulated steam line break accident. If the break should occur upstream of the main steam line isolation valves, either of the low steam generator pressure signals or the high containment pressure signal will cause closure of the main steam line isolation valves. The system is designed such that no single active failure causes both isolation valves to remain open. If the break occurs upstream of the steam line isolation valve of a steam generator, blowdown of the other steam generator by backflow is prevented by the closure of the isolation 10.3-4 Amendment No. 25 (04/19)

UFSAR/St. Lucie - 2 valve in the broken steam line. If the isolation valve fails to close, blowdown of the intact steam generator is prevented by the steam isolation valve in the unbroken steam line.

A single failure of one MSIV during a postulated main steam line break does not cause uncontrolled blowdown of more than one steam generator. For containment peak pressure/temperature analyses, the MSIV failure is postulated to occur at the faulted steam generator. This allows the steam inventory between the faulted steam generator and the closed MSIV, and all non-isolated volumes to expand into the containment. Additionally, the feedwater inventory between the main feedwater isolation valve and the faulted steam generator is assumed to flow into the steam generator and is released into the steam generator and is released into containment. Isolation of the turbine is assured by the quick acting fail closed characteristics of the turbine stop valves, and, is backed up by the closure of the turbine governor valves. Main steam and feedwater line inventories are shown in Figure 6.2-33. All additional steam and feedwater blowdowns resulting from a MSIV failure were considered in accident analyses and shown to result in peak pressures within containment design. The operable MSIV isolates the intact steam generator providing the cooling path necessary for safe reactor shutdown.

During original licensing, the NRC requested FPL to provide additional information concerning MSLB events. The following information in this paragraph was presented in response to NRC question 430.54 and is retained for historical purposes. Should the MSIV on the intact steam generator fail to close the turbine stop and governor valves, in conjunction with the operable MSIV, provide steam generator isolation. Under this condition however, certain auxiliary equipment continue to demand steam after the turbine trip and Main Steam Isolation Signal.

The equipment and their steam requirements are shown in Table 10.3-5. This table indicates that the maximum expected steam flow, including that the Turbine Driven AFWP, is well within the minimum capability of any of the Auxiliary Feedwater Pumps. Thus, even with the failure of the MSIV on the intact steam generator, generator level can be maintained and reactor cooldown initiated. Although not required, operators can elect to isolate non-essential steam demands at any time.

The main steam isolation valves are capable of stopping steam flow in either direction against full differential pressure of 1000 psi. The MSIV's close in a maximum of 5.6 seconds thereby providing containment isolation. The valve full closure time is 6.75 seconds which is the 5.6 seconds for maximum allowable valve stroke time plus 1.15 seconds for maximum allowable instrument response time. The MSIV's and their accessories required to perform containment isolation (i.e., solenoid operators, air supply accumulators, and the control systems) are designed to perform their safety function subsequent to a safe shutdown earthquake. The isolation valves fail in the open position on loss of electric power to the solenoid valve, and in the closed position on loss of air supply. An air accumulator, designed seismic Category I, is provided to hold the stop valves open for at least eight hours after a loss of normal air supply, unless the valves are tripped or closed. The isolation valves have limit switches for valve operation and open/close position indication in the control room. The pressure switch will initiate an alarm in the control room in the event of low pressure in the air accumulator system. The trip circuitry and logic for the main steam isolation valves is discussed further in Section 7.3.

The Nuclear Steam Supply System has the capability of accepting a step load change of 10 percent and a ramp load change of five percent per minute. The rate of electrical load change of the turbine generator is restricted to these values although it has the capability of accepting load changes at a faster rate. These load change rates can be accomplished without the use of the Steam Dump & Bypass Control System (SBCS).

10.3-5 Amendment No. 25 (04/19)

UFSAR/St. Lucie - 2 The SBCS consists of five air operated globe valves with a combined capacity of greater than 45 percent of the full power main steam flow. These valves are automatically initiated upon a high pressure in the steam generator in order to avoid lifting of the main steam safety valves.

The system is designed to automatically accept a maximum loss of electrical load on the generator of greater than 45 percent of full power.

The Atmospheric Dump Valve System consists of four Drag Type valves (two per steam generator) with a total combined capacity of approximately 10 percent of the full power main steam flow. The ADV's are not automatically initiated upon high steam generator pressure. The Atmospheric Dump System has remote-manual capability from the control room in order to bring the plant from hot standby conditions to the Shutdown Cooling System entry temperature.

Two atmospheric dump valves (ADVS) each of 50 percent capacity are connected to each main steam line upstream of the steam line isolation valve and are operated manually from the control room. ADVs are ASME III, Safety Class 2 and are fully qualified to function from the control room during and after a safe shutdown earthquake. Each is dual powered by independent sources of safety grade onsite AC and DC electric power. Each ADV is designed for both remote manual and automatic operation from the control room. The MSIV and ADV arrangement have the capacity to dissipate decay heat at the power level existing immediately following reactor shutdown with an adequate margin to initiate cooling at 75 F/hr (analyzed EC290592 cooldown rate) down to approximately 350 F. Using two valves, the plant can be cooled down to 350 F in about 3 1/2 hours.

The Main Steam System piping is arranged and restrained such that a rupture of one steam line cannot cause rupture of the other steam line, cannot damage containment, or prevent reactor system residual heat removal through the intact steam generator. This is done by placing of pipe whip restraints and a guard pipe around the main steam line as it penetrates the containment. Further discussion of the design and analysis of the main steam line piping is given in Section 3.6.

Safety related components in the Main Steam System are designed to perform their intended safety function in the normal and accident environment (temperature, pressure, humidity, and radiation) to which they may be subjected. Environmental design bases and qualifications are discussed in Section 3.11.

10.3.4 INSPECTION AND TESTING REQUIREMENTS Inspection and testing, including hydrostatic tests and leakage tests, are performed for all valves at the manufacturer's shops in accordance with applicable codes. The Main Steam System is hydrostatically tested in the field after installation in accordance with applicable codes.

The components are given preoperational and functional tests to ensure that they will perform in accordance with design. The closure times of the main steam isolation valves are determined during the preoperational test of the Main Steam System. This is accomplished by measuring the elapsed time from the generation of the main steam isolation signal until the valve is closed.

This test is repeated during the life of the unit as described in the Technical Specifications.

Preoperational testing is further discussed in Chapter 14.

Since all insulation on the main steam lines is removable, each main steam line weld is accessible for inservice inspection. Refer to Subsection 3.8.2.1.1.1 for a discussion of inservice inspection of the welds in that portion of the main steam line which is part of the containment 10.3-6 Amendment No. 25 (04/19)

UFSAR/St. Lucie - 2 piping penetration assembly. Guard pipes are provided on main steam piping between the secondary shield wall and containment vessel. These guard pipes are removable to facilitate inservice inspection of this piping.

10.3.5 SECONDARY WATER CHEMISTRY 10.3.5.1 Chemistry Control Basis Steam generator secondary side water chemistry control is accomplished by:

a. Control of Feedwater purity to limit the amount of impurities introduced into the steam generator

b. Minimize Feedwater oxygen content prior to entry into steam generators

c. Chemical addition to establish and maintain an environment which minimizes system corrosion

d. Continuous steam generator blowdown to reduce concentration effects within steam generator

e. Condensate polisher filter demineralizer (CPFD) system use Secondary water chemistry is based on the zero solids treatment method. This method employs the use of volatile additives to maintain system pH and to scavenge dissolved oxygen present in the feedwater.

An Oxygen scavenger, such as Hydrazine, is injected continuously into the secondary system to scavenge dissolved oxygen present in the feedwater and to promote the formation of a protective oxide layer on metal surfaces by keeping these layers in a reduced chemical state.

An excess amount of hydrazine is maintained in the feedwater which thermally breaks down into the amine ammonia (ammonium hydroxide) within the steam generators. Since ammonia is volatile, it carries over with the steam and does not concentrate in the steam generator.

Ammonia reaches an equilibrium level and establishes an alkaline condition in the steam generators and Condensate and Feedwater Systems. Oxygen scavengers (i.e., Hydrazine and/or Carbohydrazide) are also added to the steam generators during wet layup.

Secondary side pH is controlled to minimize general corrosion of ferrous material, reduce flow-accelerated corrosion and ultimately to minimize corrosion product transport to the steam generators and reduce secondary system component degradation. Neutralizing amines other than ammonia can also be injected to establish and optimize alkaline conditions. Amine additions may not be necessary during operation due to the ammonia produced from the decomposition of hydrazine. Amines may be used for pH control during wet lay-up of the steam generators and/or wet lay-up of secondary systems. Amines may also be used for pH control during plant startup.

A combination of amines is generally used to establish an effective pH control program throughout the steam, condensate and feed cycle. Dimethylamine (DMA) may be added to the secondary system to aid removal of sludge deposits from the steam generators and improve feed train pH control. DMA and ammonia have similar volatilities but may not be optimum for controlling pH and minimizing corrosion in wet steam areas. Ethanolamine (ETA) provides more 10.3-7 Amendment No. 25 (04/19)

UFSAR/St. Lucie - 2 effective pH control in wet steam areas and during plant startup and transients when ammonia levels may not yet be properly established in the feed train.

Operating and non-operating modes' chemistry limits, specifications and Action Levels for the steam generators, Feedwater System and Condensate System are established and maintained in accordance with EPRI PWR Secondary Water Chemistry Guidelines, and controlled by plant procedures.

The limits provide high quality chemistry control and yet permit operating flexibility. The normal chemistry conditions can be maintained by any plant operating with little or no condenser leakage. The action level limits are defined in the PSL Chemistry and Operations procedures to define levels of plant response when monitored parameters are observed and confirmed to be outside the normal operation value.

Polyacrylic Acid may be added to inhibit the ability of iron oxide particles to agglomerate on the secondary side of the steam generator tubes. EC284033 10.3.5.2 Corrosion Control Effectiveness Alkaline conditions in the feed train and the steam generator reduce general corrosion at elevated temperatures and decrease the release of soluble corrosion products from metal surfaces. These alkaline conditions promote the formation of a protective metal oxide film and thus reduce the corrosion products released into the steam generator.

Some oxygen scavengers also promote the formation of a metal oxide film by the reduction of ferric oxide to magnetite. Ferric oxide may be loosened from the metal surfaces and be transported by the feedwater. Magnetite, however, provides an adhesive, protective layer on carbon steel surfaces. Some oxygen scavengers also promote the formation of protective metal oxide layers on copper surfaces.

The use of boric acid to reduce the effects of steam generator tube denting and intergranular attack in steam generator crevices caused by a caustic environment has been found effective in the EPRI/NP-6237 PWR Secondary Water Chemistry Guidelines Rev 2, 12/88. A low power soak with 50 ppm boron followed by normal operation with 5-10 ppm in the steam generator blowdown is recommended if the steam generators exhibit these tube degradation mechanisms.

Wet layup of the steam generators during outages with chemically treated water is performed to minimize corrosion and oxidation during the layup period. Protection is provided by an amine for pH control and an oxygen scavenger to maintain a protective oxide film and a reducing environment.

The removal of oxygen from the condensate and feedwater is essential in reducing corrosion.

Oxygen dissolved in water causes corrosion that can result in pitting of ferrous metals, particularly carbon steel. Oxygen is removed from the steam cycle condensate in the main condenser deaerating section. Additional oxygen protection is obtained by chemical injection of an oxygen scavenger into the condensate stream. Maintaining a residual level of oxygen scavenger in the feedwater ensures that any dissolved oxygen not removed by the main condenser is scavenged before it can enter the steam generator.

10.3-8 Amendment No. 25 (04/19)

UFSAR/St. Lucie - 2 The presence of free hydroxide (OH) can cause rapid caustic stress corrosion if it is allowed to concentrate in a local area. Free hydroxide is avoided by maintaining proper pH control, and by minimizing impurity ingress into the steam generator.

Zero solids treatment is a control technique whereby both soluble and insoluble solids are excluded from the steam generator. This is accomplished by maintaining strict surveillance over the possible sources of feed train contamination (e.g., main condenser seawater leakage, air inleakage and subsequent corrosion product generation).

In addition to minimizing the sources of contaminants entering the steam generator, continuous blowdown, described in Subsection 10.4.8, is employed to minimize their concentration. With the low solid levels which result from employing the above procedures, the accumulation of scale and deposits on steam generator heat transfer surfaces and internals is limited. Scale and deposit formations can alter the thermal hydraulic performance in local regions to such an extent that they create a mechanism which allows impurities to concentrate to high levels, and thus could possibly cause corrosion. Therefore, by limiting the ingress of solids into the steam generator, the effect of this type of corrosion is reduced.

Because they are volatile, the chemical additives will not concentrate in the steam generator, and do not represent chemical impurities which can themselves cause corrosion.

10.3.5.3 Chemistry Control Effects on Iodine Partitioning System design and operating practices are directed toward the goal of corrosion protection which at the same time provides an excellent environment for the suppression of iodine emissions in steam. Secondary water chemistry will suppress the formation of volatile species of iodine in the steam generators and convert volatile iodine that may be carried over via primary to secondary leakage to nonvolatile iodine compounds.

As demonstrated in CE Topical Report entitled "Iodine Decontamination Factors During PWR Steam Generation and Steam Venting" (References 1 and 2), iodine carryover in the steam generators is a function of moisture separator performance.

10.3.5.4 Secondary Water Chemistry Surveillance Secondary Water Chemistry Surveillance is performed utilizing the Secondary Sampling System described in Subsection 9.3.2. Sample point locations and chemistry parameters sampled are dictated by plant procedures.

The Chemistry Manager is the authority responsible for data interpretation and forwarding recommendations for corrective action to the shift supervisor. When predetermined setpoints (as defined by the plant procedures) are exceeded the shift supervisor decides on the corrective action.

10.3.5.5 Condensate Polisher Filter Demineralizer (CPFD) System The Condensate Polisher Filter Demineralizer (CPFD) System is designed to filter and deionize 15,840 GPM of condensate. The CPFD System is comprised of five filter/demineralizer units, a backwash pump, a resin precoat subsystem, an air subsystem, and a battery of isolation valves.

Each filter/demineralizer unit is sized to handle maximum flow rate of 5,100 GPM and is made up of a Powdex vessel, resin trap and holdup pump. Condensate is directed through the 10.3-9 Amendment No. 25 (04/19)

UFSAR/St. Lucie - 2 Powdex vessels, through the resin trap, and then back to the condensate system. The resin trap removes any resin that may have entered the condensate flow when it passed through the Powdex vessel.

Two 24 inch headers (influent and effluent lines) connect the Condensate Polisher Demineralizer System (CPFD) with the existing condensate piping system. Condensate is normally diverted to the CPFD system prior to and during plant start-up. It also may be used during normal plant operation. The system can be connected to serve either Unit 1 or Unit 2 but not both at the same time.

Administrative controls will preclude the operation of the Backwash Treatment System if the resin becomes radioactive. However, the Backwash Treatment System is equipped with emergency provisions to handle potentially radioactive resin. After the spent resin is collected in the backwash receiver tank, the heavier solids are allowed to settle to the bottom of the tank. At a preset level in the backwash receiver tank, the backwash recovery pump will start to decant the water and process it through the PHP filter where it is cleaned of any fine resin particles.

The solids settled at the bottom of the backwash receiver tank are then processed through a portable radioactive waste solidification system. (The portable radioactive waste solidification system is not within the scope of the condensate polisher system).

10.3.6 STEAM AND FEEDWATER MATERIALS 10.3.6.1 Fracture Toughness The Quality Group B and C piping materials in the steam and feedwater systems are designed and fabricated in accordance with the requirements of Subsections NC and ND, respectively, of ASME Section III, 1971 Edition through Summer 1973 addenda.

The main steam and feedwater piping penetration assemblies are designed and fabricated in accordance with Subsection NE (class MC) of ASME Code,Section III, 1971 Edition, Winter 1973 addenda. Fracture toughness testing for these penetration assemblies is performed in accordance with the applicable sections of this edition of the code.

All pressure retaining materials used in the design and fabrication of Quality Group B and C components of the main steam and feedwater systems are in compliance with ASME Code,Section III, Appendix I. The mechanical properties of materials specified for use on Quality Group B and C components are as indicated in ASME Code,Section II, Part A, B or C. The actual material specifications and applicable codes are provided in Table 10.3-1.

10.3.6.2 Materials Selection and Fabrication Regulatory Guide 1.44, "Control of the Use of Sensitized Stainless Steel" is not applicable to the main steam and feedwater system. However, a complete discussion of Regulatory Guide 1.44 that is also applicable to this section is provided in Subsection 6.1.1.

Low-alloy steels are not utilized in any safety-related system and therefore, Regulatory Guide 1.50, "Control of Preheat Temperature for Welding of Low-Alloy Steel," is not applicable.

For Code Class 2 and 3 components, welder qualification for areas of limited accessibility does not conform with the recommendations of Regulatory Guide 1.71, "Welder Qualification for Areas of Limited Accessibility," Dec. 1973 (R0). However, the objective of the Regulatory Guide 10.3-10 Amendment No. 25 (04/19)

UFSAR/St. Lucie - 2 is adhered to by using welding supervisors to monitor welders and place an experienced welder at limited access locations.

The delta ferrite content of welds in austenitic stainless steel components is controlled, as a minimum, in accordance with the essential requirements of MTEB 5-1, "Interim Regulatory Position of Regulatory Guide 1.31." A discussion that is also applicable to this section is provided in Subsection 6.1.1.

The use of non-metallic thermal insulation on austenitic stainless steel is in complete compliance with Regulatory Guide 1.36, "Nonmetallic Thermal Insulation for Austenitic Stainless Steel," as outlined in Section 6.1 and is also applicable to this section.

See Subsection 6.1.1 for compliance with Regulatory Guide 1.37, "Quality Assurance Requirements for Cleaning of Fluid Systems and Associated Components of Water Cooled Nuclear Power Plants," and ANSI N45.2.1-73, "Cleaning of Fluid Systems and Associated Components for Nuclear Plants." ASME NQA-1-1994, Subpart 2.1 was substituted for ANSI N45.2.1 as described in the FPL Quality Assurance Topical Report discussed in Section 17.2.

10.3-11 Amendment No. 25 (04/19)

UFSAR/St. Lucie - 2 SECTION 10.3: REFERENCES

1. J A Martucci, Iodine Decontamination Factors During PWR Steam Generation and Steam Venting, Topical Report CENPD-67, Revision 1, Nuclear Power Department, Combustion Engineering, November 1974.

2. R E Mayer and E R D'Amaddio, Iodine Decontamination Factors During PWR Steam Generation and Steam Venting, Topical Report CENPD-67, Revision 1, Addendum 1, Nuclear Power Department, Combustion Engineering, November 1974.

10.3-12 Amendment No. 25 (04/19)

UFSAR/St. Lucie - 2 TABLE 10.3-1 DESIGN DATA FOR MAIN STEAM SYSTEM PIPING AND VALVES

1. Piping Design Pressure psig 985 Design Temperature, °F 550 Material Codes Main Steam* ASME-SA-155, GR KC-65 ASME Section III, Class 2 1971 Edition, Summer 73 addenda Main Steam to ASME-SA-106, GR B ASME Section III, Class 2 Auxiliary Feed 1971 Edition, Summer 73 Pump Turbine addenda Inlet Valve Balance of Piping ASTM-A-155, GR KC-65 ANSI B31.1 ASTM-A-106, GR B ASTM-A-335, GR P11 or P22

2. Main Steam Isolation Valves (HCV-08-1A,B)

Type Y-type bidirectional balances stop valves Quantity 2, 1 per main steam line Design Pressure, psia 1000 Design Temperature, °F 550 Materials:

Body ASME SA 216 GR WCC Disc Alloy Steel SA182 GR F11 Piston Carbon Steel ASME SA 216 WCB Stem ASTM A-182, Gr F6A, CL 4 Disc & Body Stellite 21 Seat Facing Code ASME Section III, Class 2, (1974 edition including summer 1974 addenda).

To first isolation valve outside containment.

T10.3-1 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.3-1 (Cont'd)

3. Main Steam Safety Valves Design Pressure, psig 1025 Design Temperature, F 550 Fluid Saturated Steam Set Pressure, psig 985, 1025 Minimum Capacity, lb/hr 11.91 X 106 Total (at 3% accumulation, each) 16 valves Type Spring Loaded Materials:

Body ASME SA 216, GR WCB Disc ASTM A458, GR 651 or equivalent Nozzle ASTM A477, GR 651 or equivalent Orifice Area, in2 16 Accumulation, % 3 Backpressure Max buildup/max 25/0 superimposed, psig Blowdown, % Maximum 8 Code ASME Section III Class 2, 1974 edition.

4. Atmospheric Steam Dump Valves Type Control Valve Quantity Two per Main Steam Line Operator Motor operated with Dual AC/DC electric power Design Press., psig 985 Design Temp., F 550 Capacity, lb/hr 54,000 (at 40 psig)

T10.3-2 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.3-1 (Cont'd)

Capacity, lb/hr 275,000 (at 970 psig)

Material Body ASME SA 105 Disc ASTM A 240-Type 410 Plug ASME SA 182-Gr F11 Stem ASTM A 276-Type 420 Code ASME III, Safety Class 2, 1980 Edition No Addenda

5. Steam Dump and Bypass Valves Type Globe (DRAG Valve)

Quantity 4 steam dump, 1 bypass Operator pneumatic, direct acting Design Pressure, psia 1015 Design Temperature, °F 550 Materials:

Body ASTM A216, GR WCB Plug ASTM A276, Type 410 Stem 17-4 PH Code ASME B16.34-2004

6. Steam Flow Elements (FE-8011, FE-8021)

Type Venturi Quantity 2 Pipe I.D., inches 31.09/31.13 Venturi Throat I.D., inches 20.40/20.40 Diameter Ratio 0.656/0.655 Area Ratio 0.430/0.430 T10.3-3 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.3-1 (Cont'd)

Materials Pipe ASME-SA-155 GR KC-65 Class I Venturi ASME-SB-168 Inconel 600 at throat ASME-SA-515 GR 70 at inlet & outlet Code ASME Section III, Class 2, 1974 Edition, Winter 1974 Addenda T10.3-4 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.3-2 MAIN STEAM LINE AND TURBINE EXTRACTION LINES

1. Auxiliary Feedwater Pump Turbine Pipe size, in./schedule 4/80 Material ASME SA-106 GR B Design pressure, psig 985 Design temperature, F 550 Codes ASME Section III, Class 2 1971 Edition, Summer 1973 addenda

2. Auxiliary Services Pipe sizes, in./schedule 2,2.5,3,4,6/80 Material ASTM A-106 GR B Design pressure, psig 985 Design temperature, F 550 Code ANSI B 31.1

3. Lines to Moisture Separator Reheaters Pipe sizes, in./schedule 8/40, 16/80, 20/80 Material ASTM A-106 GR B Design pressure, psig 985 Design temperature, F 550 Code ANSI B 31.1

4. Extraction to Heaters Heater 5 Heater 4 Heater 3 Heater 2 Heater 1 Line Size, in. 12/16 20 24 24(2) 32(4)

Wall Thickness, 0.375 0.375 0.375 0.375 0.375 in.

Material A106GRB A106GRB & A106GRB A106GRB A106GRB A335P11 A335P22 or P22 T10.3-5 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.3-2 (Cont'd)

4. Extraction to Heaters (Cont'd)

Heater 5 Heater 4 Heater 3 Heater 2 Heater 1 Design Pressure, 475 300 75 50 50 psig Design Temp, F 550 425 320 300 300 Code ANSI ANSI ANSI ANSI ANSI B 31.1 B 31.1 B 31.1 B 31.1 B 31.1 T10.3-6 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.3-3 Deleted T10.3-7 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.3-4 Deleted T10.3-8 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.3-5 AUXILIARY EQUIPMENT STEAM REQUIREMENTS (1)

Type of Closure Motive or Branch-off Normal Max Valve/ Size of Time of Source of Actuation Power Quality Piping Steam Flow Normal Valve Valve Actuating Mechanism Source Group Design

____Function____ _(Lbs/Hr)._ _Position_ __(In)__ (Sec)_ __Signal_ _of Valve_ of Valve of Valve _Code_ __Remarks__

Four (4) 0 Globe/ 10x12 60 - Motor AC/DC B ASME III Atmospheric Dump Valves Vent Lines Closed (ADVs) are manually con-to Atm. trolled to reject decay heat.

Sixteen (16) 0 Relief/ 6x10 - - - - B ASME III Open only to relieve Relief Lines Closed overpressure condition.

Steam to 16,275* Gate/ 4 10 AFAS Motor DC B ASME III Open on low Steam Gener-Turbine Closed ator Level to initiate Driven AFWP Auxiliary Feedwater Flow.

Gland Steam 5,544 Self-reg- 4 - - Diaphragm Air D ANSI B31.1 Self-regulating control Seal Supply ulating/ valves maintain steam Open flow to Gland Sealing System.

Four (4) steam 728,213 Globe/ 8 - Reheater Diaphragm Air D ANSI B31.1 Valves and controls lines to Moisture Open Temperature designed to maintain reheat Separator Reheat- Controls steam Temperature for LP era (MSRs) turbine.

Five (5) Turbine 0 Globe/ 4-10 3 High Steam Diaphragm Air D ANSI B31.1 Valves and Controls are Steam Bypass Closed 1-8 Generator designed to maintain to Condenser Pressure Steam Generator Pressure constant and avoid lift-ing of the Safety Refief Valves.

Ten (10) Main 24,200 Globe/ 1 1/2 - - - - D ANSI B31.1 Only water (no steam)

Steam Drain Closed is drained to condenser.

Lines Through Flow is intermittent.

Traps to Condenser

After the initiation of the Auxiliary Feedwater Actuation Signal.

T10.3-9 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.3-5 (Cont'd)

Type of Closure Motive or Branch-off Normal Max Valve/ Size of Time of Source of Actuation Power Quality Piping Steam Flow Normal Valve Valve Actuating Mechanism Source Group Design

____Function____ _(Lbs/Hr)._ _Position __(In)__ (Sec)_ __Signal_ _of Valve_ of Valve of Valve _Code_ __Remarks__

Globe/ 2 1/2 - - - - D ANSI B31.1 Used during startup Closed to establish condenser vaccum.

Priming 0 Globe/ 2 - - - - D ANSI B31.1 Used during startup only Ejectors Closed to deaerate condensate.

Aux Priming 4,000 Globe/ 1 - - Diaphragm Air D ANSI B31.1 Self regulating valve Ejectors Open maintains condenser to deareate condensate.

Steam Jet 3,130 Globe 1 - - Diaphragm Air D ANSI B31.1 Self-regulating valve Air Ejectors Open maintains condenser vaccum during normal.

power operation.

Heating Steam 40,600 Globe/ 3 - - Diaphragm Air D ANSI B31.1 Concentrators used only to Waste & Boric Open intermittently.

Acid Concentrators Note: Miscellaneous vents, drains & instrumentation taps, which are normally closed, are neglected.

Summary Max. Steam Flow following Turbine Trip & failure of Main Steam Isolation Valve to close:

Turbine Driven AFWP 16,275 Gland Seal System 5,544 Drain Lines 24,200 Aux Priming Ejectors 4,000 Steam Jet Air Ejectors 3,130 Concentrators 40,600 93,749 Lbs/hr = 190 GPM Note (1): Information in this table was provided to the NRC during original licensing (PSAR Amendment 14) in response to NRC question 430.54. This information is historical and has not been updated to reflect current plant configuration.

T10.3-10 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.3-6 Deleted T10.3-11 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.3-7 MAIN STEAM/FEEDWATER PARAMETERS 100% LOAD EPU MAIN STEAM (2560 MWT) OSG (3040 MWT)

Flow (lbm/hr) 11,172,200 13,266,000 Pressure (psia) 815 888 Temperature (°F) 520.3 530 Specific Volume (ft3/lbm) .55776 0.5347 FEEDWATER Flow (lbm/hr) 11,172,200 13,364,000 Pressure (psia) 1256 1,120 Temperature 380.5 437 T10.3-12 Amendment No. 24 (09/17)

Referto Drawing 2998-2381 FLORIDAPOWER & LIGHTCOMPANY ST. LUCIE PLANT UNIT 2 MAINSTEAMSAFETYVALVES V8201- V8216 8770-9932 SHS FIGURE 10.3-1 Amendment No. 18 (01/ 08)

Referto Drawing 2998-1011 FLORIDAPOWER & LIGHTCOMPANY ST. LUCIE PLANT UNIT 2 MAINSTEAMISOLATION VALVESH 1 OF 9 FIGURE 10.3-2 Amendment No. 18 (01/08)

DELETED Amendment No. 19(06/09)

FLORIDAPOWER & LIGHTCOMPANY ST. LUCIE PLANT UNIT 2 FIGURE 10.3-3

UFSAR/St. Lucie - 2 10.4 OTHER FEATURES OF THE STEAM AND POWER CONVERSION SYSTEM This section describes the main condenser, main condenser evacuation system, gland seal system, Steam Dump and Bypass System, Circulating Water System, Condensate, Feedwater and Heater Drain Systems, Steam Generator Blowdown System and Auxiliary Feedwater System.

Except for a portion of the Feedwater System piping and the Auxiliary Feedwater System, the features, components, and systems described in this section serve no safety function.

10.4.1 MAIN CONDENSER The main condenser serves no safety function and is classified as nonseismic. Refer to Figures 10.1-1 through 10.1-3 and the design data in Table 10.4-1. The two shell, single pressure, main condenser provides a continuous heat sink for the exhaust from the two tandem-compound low pressure turbines and for miscellaneous flows, drains and vents during normal plant operation.

The main condenser also provides a heat sink for the steam dump & bypass control system (SBCS) during the initial phase of plant cooldown (after reactor shutdown).

10.4.1.1 Design Bases The main condenser is constructed in accordance with the Heat Exchanger Institute Standards for steam surface condensers.

The main condenser was originally designed to:

a. Condense 100 percent of the full load main steam flow and deaerate the condensate before it leaves the condenser hot well.

b. Condense at least 45 percent of the full load main steam flow bypassed directly to the condenser by the turbine bypass system, which bounds the steam dump and bypass control system capabilities as described in Section 7.7.1.1.5. This condition occurs in case of a sudden load rejection by the turbine generator, a turbine trip, or during start-up and shutdown, as described in Subsection 10.4.4.

c. Provide for removal of noncondensable gases from the condensing steam through the main condenser evacuation system, as described in Subsection 10.4.2.

10.4.1.2 System Description The main condenser functions as the steam cycle heat sink and collection point for the following flows:

a. Low-pressure turbines exhaust.

b. Low-pressure turbines last stage moisture removal drains.

c. Feedwater heater drains and vents.

10.4-1 Amendment No. 27 (03/22)

UFSAR/St. Lucie - 2

d. Steam seal regulator leak-off.

e. Gland steam condenser drains.

f. Condensate minimum flow recirculation.

g. Condensate pumps minimum flow recirculation.

h. Steam generator feedwater pumps minimum recirculation.

i. Feedwater recirculation start-up.

j. Turbine bypass.

k. Demineralized water makeup.

l. Miscellaneous equipment drains and vents.

The main condenser consists of two 50 percent capacity, divided water box, surface condensers of the single-pass type with tubes arranged perpendicular to the turbine shaft. Cooling water for the condensers is provided by, the Circulating Water System. The condensers are of the deaerating type and are sized to condense exhaust steam from the main turbine under full load conditions. The hot well storage is located below the bottom row of tubes in each condenser shell.

The condenser hot wells serve as a storage reservoir for deaerated condensate which supplies the condensate pumps. The storage capacity of the hot wells (41,000 gallons each), can provide sufficient feedwater for four minutes of operation at maximum throttle flow with some additional volume for surge protection. Condensate makeup from the condensate storage tank is admitted by gravity or by the condensate transfer pumps into the condenser. This automatic makeup is performed through a level control valve which receives a low water level signal from the condenser. There is a bypass valve around this level control valve for manual backup as well as for plant start-up filling. On high water level in one hot well, during normal plant operation, an airoperated valve is opened automatically to reject condensate to the condensate storage tank.

Three condensate outlets from the shell are provided to the condensate pumps.

Each condenser shell is connected to two separate circulating water inlet and outlet line through its respective water box. The circulating water flow path is shown in Figure 9.2-1.

Two 8 inch diameter connections are provided on each shell for noncondensable gas evacuation. The design parameters (including air leakage requirements) for the main condenser Air Evacuation System are provided in Subsection 10.4.2.

A provision is made for mounting each of the one-half capacity low pressure heaters 1A/1B and 2A/2B in the neck of each of the condenser shells. A 36 inch diameter hot well equalizing pipe is provided between the two hot wells.

A 117 inch diameter crossover pipe is provided between the two condenser shells for equalizing the exhaust steam flow. Belt-type rubber expansion joints are provided for the exhaust connections from low pressure turbines.

The turbine by-pass blowdown lines discharge into the condenser through spray pipes located in the condenser neck at a level sufficiently higher than the condenser tubes. The spray pipes 10.4-2 Amendment No. 27 (03/22)

UFSAR/St. Lucie - 2 help to diffuse the high energy discharge away from the tubes and thus preclude tube failures due to impingement. All other high temperature drains either discharge through spray pipes or baffles are provided to deflect the discharge away from the tubes and minimize impingement effect on condenser tubes.

10.4.1.3 System Evaluation The main condenser is normally used to remove residual heat from the Reactor Coolant System (RCS) during the initial cooling period after plant shutdown when the main steam is bypassed to the condenser by the steam dump & bypass control system (SBCS). The condenser is also used to condense a portion of the main steam bypassed to the condenser by the turbine generator in the event of sudden load rejection or a turbine trip.

In the event of a load rejection greater than 45 percent (e.g., 100 percent load rejection due to turbine trip), the condenser will condense 45 percent of full-load main steam flow bypassed to it by the SBCS, and the motor operated atmospheric dump valves or spring loaded safety valves will discharge the remaining main steam flow to the atmosphere to effect safe reactor shutdown.

If the main condenser becomes unavailable during normal plant shutdown, sudden load rejection or turbine generator trip, the spring loaded safety valves will discharge full main steam flow to the atmosphere and effect a safe shutdown condition. Nonavailability of the main condenser considered here includes failure of circulating water pumps to supply cooling water, failure of condenser evacuation system to remove noncondensable gases, excessive leakage of air through turbine gland packings due to failure of the turbine gland sealing system, or failure of the condenser due to other reasons. If the turbine steam bypass valves to the main condenser are open, they will close automatically in the event of loss of condenser shell vacuum.

Failure of the condenser does not result in flooding of any safety related equipment.

During normal operation and shutdown, the main condenser does not contain radioactive contaminants. Radioactive contaminants can only be present through primary-to-secondary system leakage due to a steam generator tube leak. Non-condensable gases are monitored for radioactivity prior to being discharged to the atmosphere. The radiological aspects of primary-to-secondary leakage are discussed in Section 11.5. Anticipated operating concentrations of radioactive contaminants, is included in Section 11.3.

During normal plant operation gaseous hydrogen is not added to the secondary system.

However, if there is primary coolant leakage in the steam generator tubes, minute quantities of gaseous hydrogen are carried over to the main condenser. As described in Subsection 10.4.2, the main condenser Air Evacuation System removes any noncondensable gases from the condenser. Therefore, no hydrogen buildup in the main condenser is anticipated.

Cooling water inleakage to the condenser is detected by conductivity detection equipment located in the Chemical Analyzer Cubicle (see Subsections 10.3.5 and 10.4.8). The affected condenser section is removed from service when inleakage is observed, drained of cooling water and the leaking tubes located and plugged. This condenser section is returned to service when repairs are completed. The main cause of inleakage of cooling water into the condenser is due to tube-to-tube sheet joint failure resulting from excessive vibration of tubes. In the St. Lucie Unit 2 condenser design, these problems are minimized by the following provisions:

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a. Adequate number of tube support plates have been provided to minimize tube vibration.

b. Tubes are roller expanded into the tube sheet and the tube sheet is integrally grooved and provided with a pressurized water seal to prevent inleakage of cooling water into the condenser at the tube-to-tube sheet joint.

Measures are taken to prevent loss of vacuum in the condenser are as follows:

a. A continuous flow of cooling water is maintained through the condenser tubes by the four circulating water pumps, to condense the exhaust steam and all condensible gases flowing into the condenser from the LP turbine exhaust. This system is discussed in Subsection 10.4.5.

b. A continuously operating Air Evacuation System consisting of two hogging ejectors (for startup evacuation) and one steam jet air ejector originally designed for maintaining vacuum at 3.58" Hg during normal operation is provided. A discussion of this system is provided in Subsection 10.4.2.

c. A turbine gland sealing system is provided to prevent intrusion of atmospheric air into the turbine casing and the condenser. This system is discussed in Subsection 10.4.3.

d. Two steam operated auxiliary priming ejectors and a priming ejector are provided to evacuate and maintain the water seal in the condenser water boxes.

e. The condensate pumps which are connected to the condenser and operate under vacuum conditions are provided with water sealed glands to prevent intrusion of air through the glands into the condenser.

Measures are provided to minimize corrosion/erosion of condenser tubes and components, as follows:

a. Titanium tubes are used in the condenser, which has excellent corrosion resistance to sea water. The tube sheets are of aluminum bronze which has good corrosion resistance in sea water.

b. Cathodic protection is provided on the condenser water box to prevent galvanic corrosion between the carbon steel water box, the aluminum bronze tube sheet and the stainless steel components installed as part of the condenser tube cleaning system which are in contact with sea water.

c. A moderate water velocity (approximately 7 ft/sec) is maintained in the condenser tubes to prevent high velocity erosion of tubes. The condenser tubes are continuously cleaned with rubber sponge balls and periodically with carborundum coated sponge balls. Tests demonstrate that the titanium tubes are highly durable against mechanical cleaning methods including carborundum coated sponge balls.

d. Cooling water (sea water) is chlorinated and the tubes are continuously cleaned using rubber sponge balls to minimize biofouling and resultant corrosion of tubes.

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UFSAR/St. Lucie - 2 10.4.1.4 Tests and Inspections The surface condenser water boxes are shop tested hydrostatically to 30 psig. After installation, the condenser is tested for leak tightness by filling with water to a level above the turbine exhaust flange. Field tests run to demonstrate performance are governed by the provisions of ASME Power Test Code for Steam-Condensing Apparatus.

10.4.1.5 Instrumentation Applications Water level gages are provided at the hotwells and level control devices for water level control are located at the condenser "2B" hotwell.

A sampling system measures the conductivity of the condensate to provide an indication of any condenser tube inleakage and high conductivity is annunciated in the Control Room.

Local indication of LP heater pressure and control room indication for monitoring pressures in the condenser shells are provided.

A hotwell water high and low water level alarm is provided in the control room. Condenser shell vacuum is indicated and annunciated on low vacuum in the control room. A loss or decrease of vacuum to 18-22 inches of mercury will trip the turbine and cause a reactor trip. This is discussed in Subsections 7.2.1.1.1 and 10.2.2.2.

10.4.2 AIR EVACUATION SYSTEM The Air Evacuation System has no safety related function and is classified as nonseismic.

10.4.2.1 Design Bases The Air Evacuation System (AES), shown on Figure 10.1-1f is designed to remove noncondensable gases and inleakage air from the steam space of the condenser shells during plant startup, cooldown, and normal operation.

10.4.2.2 System Description The AES consists of two hogging ejectors, a steam jet air ejector with associated inter-and after-condensers, manifolds, valves and piping. The system is designed to establish and maintain condenser vacuum during startup and normal operation.

During startup, the two hogging ejectors evacuate a combined turbine and main condenser (empty hot well) steam space of 142,000 cu ft within a period of 60 minutes and thereafter maintain a condenser pressure of five inch Hg absolute. The steam-air mixture from the hogging ejectors is discharged to the atmosphere via discharge silencers. As startup progresses, condenser evacuation is maintained by the two stage, twin-element, steam jet air ejector. The steam jet air ejector was originally designed to achieve a condenser vacuum of 3.58 inch Hg absolute (abs) during normal operation.

Shop hydrostatic tests and field functional tests are performed on the main condenser to assure leak tightness. The entrapped air is removed from the condenser by the steam jet air ejector system. Each element of the steam jet air ejector system is capable of entraining 25 cfm of air at one inch Hg (abs) and 71.5 F when supplied with 1565 lbs/hr of main steam at 400 psig.

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UFSAR/St. Lucie - 2 The steam jet ejector passes the evacuated mixture of air and water vapor through its inter-and after-condensers where most of the water vapor is condensed and the remaining noncondensable gases are discharged to the plant vent.

10.4.2.3 System Evaluation The preclusion of the existence of an explosive mixture is inherent in the design of the condenser as hydrogen is not normally present. In the event of a primary to secondary steam generator leakage, small amounts of hydrogen may be released to the condenser and subsequently discharged to the atmosphere via the condenser evacuation system. Therefore, a noncondensable gas concentration capable of supporting combustible mixture is not considered credible.

The noncondensable gases from the steam jet air ejector are monitored for radioactivity prior to being discharged to the plant vent. The presence of radioactivity would indicate a primary to-secondary system leak in the steam generators (refer to Section 11.5). Radiological aspects of primary-to-secondary leakage and anticipated radioactive releases to the environment during normal operation of the system are discussed in Section 11.5.

Loss of condenser vacuum causes a turbine trip as discussed in Section 10.2.2.2.

10.4.2.4 Tests and Inspections Preoperational testing insures the proper operation of valves and verifies the pressure switch setpoints.

Testing of the AES during normal operation is unnecessary since the system is being used. The system can be shut down for short periods of time during plant operation for inspection if required, without adversely affecting condenser performance.

10.4.2.5 Instrumentation Applications A process radiation monitor continuously samples the Steam Jet Air Ejector noncondensable gas exhaust header. The presence of radioactivity would indicate a primary-to-secondary system leak in the steam generators. Gases are discharged through the plant vent.

10.4.3 TURBINE GLAND SEALING SYSTEM The turbine gland sealing system provides sealing of the turbine shaft against leakage of air into the turbine casings and escape of steam into the Turbine Building. The system is shown on Figure 10.1-1b. The system has no safety related function, and is classified as nonseismic.

10.4.3.1 Design Bases The turbine gland sealing system is designed to prevent atmospheric air leakage into the turbine casings and main condenser, and steam leakage out of the casings of the turbine generator.

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UFSAR/St. Lucie - 2 10.4.3.2 System Description The turbine gland sealing system controls the steam pressure to the turbine glands in order to maintain adequate seating under all conditions of turbine operation. The system consists of individually controlled diaphragm-operated valves, relief valves, and a gland steam condenser.

Gland steam is supplied from the Main Steam System. At high plant loads, the spillage from the high pressure turbine element glands provides more steam than the low pressure turbine element glands require. The excess steam is relieved to the turbine condenser through a pressure-regulating valve. The leak-off steam and air mixture then flows to the gland steam condenser which is maintained at a pressure slightly below atmospheric so as to prevent escape of steam from the ends of glands. The gland steam condenser returns seal leakage to the main condenser as condensate.

Each of the low pressure turbine glands has a gland steam supply regulator. Both high pressure turbine glands are supplied from one regulator. A spillover valve in the high pressure turbine gland seal provides pressure regulation for the dumping of excess turbine gland leakage to the main condenser.

Exhauster vacuum on the low pressure side of the seals can be maintained with either blower in operation.

10.4.3.3 System Evaluation The design of the diaphragm-operated valves is such that failure of any valve will not endanger the turbine. The valves controlling the supply of steam to the gland seals fail (on loss of instrument air) in an open position thus allowing uninterrupted steam sealing. The valve controlling the return flow from the gland seals fails closed thereby maintaining required steam sealing pressure. Thus, steam sealing is maintained in the event of a diaphragm-operated valve failure.

Noncondensable gases from the gland steam condenser may be monitored for radioactivity at the same discharage point as the main condenser evacuation system, these gases are routed up the plant stack.

10.4.3.4 Tests and Inspections Operation of two full capacity gland steam condenser vent blowers is alternated periodically.

The system, is tested in accordance with written procedures during the initial testing and operation program, and is readily available for inservice inspection. The system is normally in use when the plant is operating and thus special tests are not required to insure operability.

10.4.3.5 Instrumentation Applications Pressure indicators for the gland steam condenser and the main steam supply are provided locally and in the control room in order to monitor system performance. Radiation detectors are provided on the noncondensable gas exhaust header as discussed in Subsection 10.4.2.5.

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UFSAR/St. Lucie - 2 10.4.4 STEAM DUMP AND BYPASS SYSTEM The steam dump and bypass system which is a subsystem of Distributed Control System (DCS) has no safety design bases and is classified as nonseismic. Refer to Figures 10.1-1 through 10.1-3 and also to the design data in Table 10.3-1. The Steam Dump and Bypass System is designed to accomplish the following functions:

a. Accommodate load rejections meeting the original design basis of 45 percent of the full load main steam flow and mitigate challenges to pressurizer and steam generator safety valves.

b. Maintain the Reactor Coolant System at hot zero power conditions.

c. Provide a control element assembly automatic withdrawal prohibit signal subsequent to a demanded steam bypass system operation.

d. Provide a means for manual control of the RCS temperature during heatup or cooldown.

e. Provide a condenser interlock which will block steam bypass flow when unit condenser pressure exceeds a preset limit.

10.4.4.1 System Description The Steam Dump and Bypass System which is a subsystem of the DCS consists of the Steam Dump and Bypass Control System, the steam dump and bypass valves, and associated piping and instrumentation. The Steam Dump and Bypass Control System is described in Subsection 7.7.1.1.5. Four steam dump valves and one turbine bypass valve located downstream of the main steam isolation valves, connect the main steam header outside containment directly to the main condenser.

The bypass and steam dump valves are air operated globe valves. The original system design flow capacity of 45% was restored as part of the Extended Power Uprate. The system is designed to mitigate challenges to the pressurizer and steam generator safety valves during large load rejections. The valves are normally controlled by the Steam Dump and Bypass Control System via the M/A station or flat panel displays on RTGB-202 but are capable of remote or local manual operation. The system is capable of controlling at flows as low as 28,000 lb/hr in order to permit operation at hot standby.

The steam dump and bypass system is designed to remove excess heat from the Nuclear Steam Supply System (NSSS) during load reductions, after unit trips and anytime conditions exist which may result in high secondary system pressure. If the turbine cannot accept all the steam being produced in the steam generators (for example in the event of a turbine trip or partial loss of electrical load on the generator), an alternate heat removal path is provided to cool down the reactor coolant and to remove the reactor decay heat to limit the pressure rise in the steam generators. Steam dump and bypass valves, located downstream of the main steam isolation valves, connect the main steam header outside containment directly to the main condenser and are programmed to bypass steam directly to the condenser when such a high pressure condition occurs. The system is designed to enable the plant to accept a loss of electrical load on the generator of the original design basis of 45 percent of full power while mitigating challenges to the pressurizer and steam generator safety valves.

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UFSAR/St. Lucie - 2 On a load rejection the steam dump and bypass valves are modulated in sequence to control main steam pressure to a fixed setpoint. A quick opening signal is generated as a function of the magnitude and rate of change of the load rejection determined by monitoring both the steam flow and the turbine load. The duration of the quick opening signal is proportional to the flow magnitude and rate of change. Once the signal is removed the valves revert back to the modulation control. The quick opening signal on a reactor trip is generated when both the measured reactor coolant average temperature and the main steam pressure exceed their preset threshold values.

During plant shutdown with off site power available, the required number of valves may be remote manually positioned to remove reactor decay heat, pump heat and Reactor Coolant system sensible heat to reduce the reactor coolant temperature at the design cooldown rate until shutdown cooling is initiated. For plant shutdown without offsite power, the atmospheric dump valves located upstream of the main steam isolation valves may be used for removal of reactor decay heat and cooldown by venting steam from the steam generators directly to atmosphere.

10.4.4.2 System Evaluation The steam dump and bypass valves are designed to fail closed to prevent uncontrolled flow of steam from the steam generator. Should the bypass valves fail to open on command, the atmospheric dump valves provide a means for a controlled cooldown of the Reactor Coolant System. The main steam safety valves provide main steam line overpressure protection.

Because the ASME Code Main steam safety valves provide the ultimate overpressure protection for the steam generators, the Steam Dump and Bypass system has no safety function and therefore is not designed to the requirements applicable to protection systems.

The steam dump and bypass valves discharge to the main condenser and do not affect essential safety systems. Should the condenser not be available as a heat sink, an interlock prevents opening, or if open, closes the steam dump and bypass valves. The main steam isolation signal protects the Reactor Coolant System from overcooling if the steam dump and bypass flow becomes higher than design.

There are four steam dump lines and one turbine bypass line which bypasses steam to the condenser in the event of a turbine trip. All these lines are routed below the turbine deck. It is highly improbable that a break in any of these lines will damage the overspeed protection devices most of which are located above the turbine deck. The only portion of the overspeed protection system that is likely to be affected by a break in the turbine bypass line will be the electrohydraulic fluid lines routed below the turbine deck. A drop of hydraulic pressure in the electrohydraulic system due to a pipe break or any other reason will result in a turbine trip and the closure of the turbine stop and control valves, thus precluding the chances of a turbine overspeed. Turbine overspeed protection system is discussed in Subsection 10.2.2.2.

Failure of the Steam Dump and Bypass Control System has no detrimental effects on the Reactor Coolant System. Operation of this system has no adverse effects on the environment since steam is bypassed to the condenser, the heat sink in use during normal operation.

10.4.4.3 Inspection and Testing Requirements Before the Steam Dump and Bypass System is placed in service, system valves are tested to assure operability and are periodically verified. The steam dump and bypass valves are capable 10.4-9 Amendment No. 27 (03/22)

UFSAR/St. Lucie - 2 of being tested while the main turbine is in operation. System piping and valves are accessible for in-service inspection.

10.4.4.4 Instrumentation Requirements The instrumentation and control are discussed in Subsection 7.7.1.1.5.

10.4.5 CIRCULATING WATER SYSTEM The Circulating Water System is a nonsafety, nonseismic system. The Circulating Water System is shown schematically on Figure 9.2-1. The general plan and profile of the system is shown on Figures 10.4-1 through 10.4-4.

10.4.5.1 Design Bases The Circulating Water System is designed to provide a heat sink for the main condenser under normal operating and shutdown conditions. The system serves as the primary source of water for the ultimate heat sink.

10.4.5.2 System Description The St. Lucie Unit 2 Circulating Water System consists of four circulating water pumps, four debris filters, the condenser intake, four continuous on-line condenser tube cleaning systems, the condenser discharge, a headwall and an ocean discharge line. The discharge canal from the seal well to the headwall is shared with St. Lucie Unit 1. The Intake Cooling Water System is described in Subsection 9.2.1. The intake and discharge canals and the plant cooling water requirements are discussed further in subsections 2.4.8, 2.4.9 and 2.4.11.

The suction bells for the circulating water pumps are at elevation - 16.0 feet thereby providing suction submergence for the required pump NPSH (6 feet). The circulating water pumps discharge into four buried pipes to the condenser. The water leaving the condenser flows from the condenser discharge water boxes through concrete tunnels and pipes to the seal well. From the seal well, the discharged condenser cooling water travels about 2000 feet in the shared canal to a discharge headwall structure, located on the west side of the sand dune. From the discharge canal headwall, the cooling water is carried through the ocean discharge pipe to multiport diffusers.

10.4.5.3 System Evaluation The four circulating water pumps are each sized to provide 25 percent of the cooling water flow for the condenser. The pumps are sized for the maximum condenser heat load and provide sufficient head to overcome system frictional losses.

The Circulating Water System may be used for a normal plant shutdown. Water to the steam generators is supplied from the Auxiliary or Main Feedwater System. Steam then flows through the Turbine Bypass System and discharges into the main condenser. During this mode of operation the Turbine Bypass System has the capability of passing greater than 45 percent of the full power main steam flow into the main condenser (see Subsection 10.4.4).

Any transient or reduction of the circulating water flow results in partial loss of condenser vacuum. The main condenser was originally designed to be normally operational at a condenser 10.4-10 Amendment No. 27 (03/22)

UFSAR/St. Lucie - 2 vacuum of 3.58 inches Hg absolute. Should the condenser vacuum reach the low vacuum setpoint, the turbine protection system automatically trips the turbine. The turbine protection system and setpoints are discussed in Section 10.2.

The Circulating Water System piping is located entirely underground in the yard except at the main condenser. The main condenser is located in the lowest elevation of the Turbine Building.

There is no safety-related equipment housed in the Turbine Building, and, thus, a failure in the circulating water piping to the main condenser will not result in potential malfunction of any safety-related components.

The Turbine Building is a totally open structure which houses the secondary side components.

Any leakage in the Main Steam, Feedwater or Circulating Water Systems would be directed to either the building floor drains or the site storm drainage system. Any leakage local to the condenser will be directed to the condenser sump. Since there is no safety related equipment in this area, an essential leak detection system is not provided for this area. Appendix 3.6F describes the piping failure analysis considered.

10.4.5.4 Environmental Control Chlorine in the form of sodium hypochlorite or alternate biocide is used to control biological EC293500 fouling in the Circulating Water System by use of a hypochlorite system serving both St. Lucie Units 1 and 2. EC293500 The hypochlorite solution or alternate biocide is mixed with the water coming into the intake structure in order to control biofouling. The solution in the Circulating and Intake Cooling Water Systems is added in regulated quantities so that the residual chlorine in the discharge canal will EC293500 not exceed the limits as defined in applicable plant permits. As the hypochlorite solution or alternate biocide is mixed with the water coming into the intake structure in regulated quantities, adverse corrosive effects are not expected.

A continuous on-line condenser tube cleaning system (CTCS) that employs sponge balls to scrub the condenser tubes on the circulating water side is also used to control biological fouling.

The Florida Department of Environmental Protection identified to FPL concerns regarding CTCS sponge ball loss and the potential for consumption by sea turtles. In the several responses to the State, FPL was able to demonstrate that the combination of system design features and Good Management Practices will minimize sponge ball loss to the Atlantic Ocean.

10.4.5.5 Testing and Inspection Shop hydrostatic tests on the pump casings are made at a minimum of 150 percent of the maximum operating pressure.

Prior to installation in the system, each component is inspected and cleaned.

Preoperational testing consists of calibrating the instruments, testing the automatic controls for actuation at the proper setpoints, and checking the operability and limits of alarm functions.

Automatic actuation of system components is tested periodically to confirm operability. The Circulating Water System is in service during normal plant operation. System performance is monitored and data taken periodically to confirm heat transfer characteristics. (Note: For economic considerations, a routine heat rate assessment is performed. This assessment provides an overall indication of thermal efficiency and monitors system performance).

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UFSAR/St. Lucie - 2 10.4.5.6 Instrumentation Application The Circulating Water System is continuously monitored by measuring the condenser inlet and outlet temperature. Grab samples are used to monitor residual chlorine content.

10.4.6 CONDENSATE CLEANUP SYSTEM Feedwater recirculation filtration, chemical addition and steam generator blowdown are used to maintain the secondary water chemistry. The Condensate Polisher Filter Demineralizer System (CPFD) is available for condensate cleanup on either Unit 1 or Unit 2. Two 24 inch headers (influent and effluent lines) connect the CPFD with the existing condensate piping system.

Condensate is normally diverted to the CPFD system prior to and during plant start-up. It also may be used during normal plant operation.

The interconnecting piping is provided with double isolation valves on both the inlet and outlet of the CPFD with interlocks which insure that the CPFD is not connected simultaneously to both units. A bypass around the CPFD is provided with full flow capability and a bypass flow control valve. The bypass valve is controlled manually and also opens automatically to maintain normal condensate flow in case of CPFD trouble.

10.4.7 CONDENSATE, FEEDWATER AND HEATER DRAIN SYSTEM The Condensate, Feedwater and Heater Drain System, shown on Figures 10.1-2a, 2b and 10.1-3a, 3b, draws water from the condenser hotwells and feedwater heaters and pumps it to the steam generators feed nozzles. Design data for the condensate pumps, heater drain pumps, feedwater pumps and feedwater heater are given in Table 10.4-1.

The feedwater parameters for 100 percent load, and extended power uprate (EPU) are presented on Table 10.3-7.

The Heater Drain Pumps 2A & 2B and Feedwater Pumps 2A and 2B are tripped upon SIAS.

The evaluation of the extended power operation on the condensate, feedwater, and heater drain systems demonstrated that modifications on the condensate pumps, feedwater pumps, heater drain pumps, feedwater flow control valve, feedwater heaters 5A and 5B, and various heater drain system valves were required to operate the plant at the extended power level (3034 MWt).

10.4.7.1 Design Basis The only part of the Condensate, Feedwater, and Heater Drain Systems that is safety related is the portion of the main feedwater system from and including the feedwater isolation valves located outside the containment to the steam generator feed nozzles, and is designed to Quality Group B and seismic Category I requirements. The Condensate and Feedwater System from the condenser hotwell up to these feedwater isolation valves, located outside containment, is designated non-nuclear safety and is classified as non-seismic.

The safety related portions of the Feedwater Systems have the following design bases:

a. Provide feedwater to the steam generators during normal, shutdown and transient operations.

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UFSAR/St. Lucie - 2

b. Provide automatic containment isolation in the event of a loss of coolant accident.

c. Withstand pipe rupture effects as discussed in Section 3.6.

d. Withstand the adverse environmental effects of tornadoes, hurricanes and flooding as discussed in Sections 3.3 and 3.11.

e. Be protected against externally generated missiles as discussed in Section 3.5.

f. Design to preclude hydraulic instabilities, (e.g. water hammer).

g. Trip the Heater Drain Pumps 2A & 2B and Feedwater Pumps 2A and 2B upon SIAS via SR ESFAS relays as shown in Table 7.3.-2.

10.4.7.2 System Description The feedwater cycle is a closed regenerative system with deaeration accomplished in the main condenser. Condensate from the hotwell is pumped by two of the three condensate pumps through the steam jet air ejector inter- and after- condensers, the gland steam condenser, three stages of low pressure heaters, the low pressure drain coolers, and through the fourth stage low pressure heaters, (two parallel heater strings) to the suction of two feedwater pumps operating in parallel. The feedwater is then pumped through two parallel strings of the fifth stage high pressure feedwater heaters to the steam generators.

The condensate and feedwater system supplies full load feedwater flow plus steam generator blowdown flow and cycle losses at the expected steam generator pressures during normal plant operations (refer to Figure 10.2-1). In addition, the system provides the required flow to the steam generators during transient plant load changes, turbine and reactor trip. During these transient conditions the turbine bypass system is utilized when condenser backpressure is available, or the atmosphere dump valves are used should condenser vacuum reach its trip setpoint (refer to Subsection 10.4.4).

Each condensate pump is protected from overheading during startup and reduced load operation by a minimum recirculation flow control valve which discharges directly to the main condenser. In addition to these individual pump recirculations, minimum condensate system flow is maintained during low power levels by recirculating condensate from downstream of the gland steam condenser to the main condenser. Each feedwater pump is protected from overheating during startup and reduced load operation by a minimum recirculation flow control valve which discharges to the main condenser.

The feedwater heaters are of the U-tube type and are arranged in two parallel strings. Each string carries approximately half of the feedwater flow and consists of four low pressure heaters and one high pressure heater. The two lowest pressure heaters are mounted in the neck of the main condenser and are arranged in parallel strings. Bypasses and crossties between the split strings are provided for flexibility of operation.

Surveillance on the quality of the secondary water, in the form of regular sampling of the feedwater supply and the steam generator blowdown, is provided (refer to Subsection 10.3.5.2 and 9.3.2.2).

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UFSAR/St. Lucie - 2 Startup cleaning, and deaeration to exclude oxygen and noncondensable gases in the condensate and feedwater system is provided. A feedwater recirculation line is provided upstream of the feedwater control valve, which includes a feedwater recirculation filter, two safety and relief valves, flow restriction orifices and necessary connections to the condenser.

Each feedwater line is provided with a check valve located inside containment to preclude backflow from the steam generators. Details of containment isolation provisions are contained in Tables 6.2-52 and 53.

The design of the main feedwater line penetration assemblies is discussed in Subsection 3.8.2.

10.4.7.3 Evaluation The Condensate and Feedwater Systems are capable of reduced load operation with one condensate pump, both heater drain pumps, one steam generator feedwater pump, or one heater string, out of service.

A loss of normal feedwater flow results in a reduced capability for steam generator heat removal. In the event of such an occurrence, the Auxiliary Feedwater System ensures a sufficient supply of cooling water to the steam generators (refer to Subsection 10.4.9).

In case of malfunction of heater shells, the isolation valves for the malfunctioning feedwater heater(s) are manually closed, thus permitting flow to be bypassed around the out-of-service feedwater heater(s).

Each feedwater line is provided with two redundant main feedwater isolation valves which are designed to Quality Group B, seismic Category I requirements. These isolation valves are provided with electro hydraulic operators that enable both fast valve closure (4.2 seconds) during the accident mode. All four main feedwater isolation valves close automatically upon receipt of a MSIS signal from either channel SA or channel SB. In addition, an AFAS signal will also close the main feedwater isolation valves associated with the steam generator(s) which is(are) receiving auxiliary feedwater. Refer to Section 7.3. The AFAS signal may be manually overriden by the control room operator and the valves re-opened. Since the valve was designed and tested to close in a maximum of four seconds, the feedwater isolation response time has been revised for stretch power from 5.35 seconds to 5.15 seconds, assuming an instrumentation delay time of 1.15 seconds.

The increased feedwater flow rate due to EPU (see Table 10.3-7) is still within the design capabilities of the valve and therefore, the MFIVs are acceptable for EPU operation without any design change.

In the event of primary-to-secondary system leakage due to a steam generator tube leak, it is possible for the condensate and feedwater system to become radioactively contaminated. A full discussion of the radiological aspects of primary-to-secondary leakage is included in Chapters 11 and 12.

The steam generator feedwater spargers are designed to prevent draining during a steam generator low-level transient. The steam generator design is described in Section 5.4. The design provisions for the prevention of feedwater instability (i.e., water hammer) are discussed in Subsection 10.4.9.3. Transients involving loss of heat removal by the secondary system are described in Section 15.2.

10.4-14 Amendment No. 27 (03/22)

UFSAR/St. Lucie - 2 10.4.7.4 Tests and Inspections The steam generator feedwater pumps, heater drain pumps and the condensate pumps are tested at the manufacturer's shops to demonstrate successful operation and performance of the equipment.

Preoperational testing is performed to verify the design adequacies of the steam generator sparger rings and J-tubes, piping layout and operation of pumps and valves. Preoperational and functional testing is outlined in Chapter 14.

ASME Code Section III feedwater piping is furnished with removable insulation to allow in-service inspection of welds. The in-service inspection program is a part of the Technical Specification.

10.4.7.5 Instrumentation Applications The water level in each of the steam generators is obtained by the measurement of the downcomer water level for the Distributed Control System (DCS). The steam generator steam flow signal and feedwater flow signal are compared with this level signal in a three-element control in DCS. The DCS output of the three-element control actuates the 100 percent capacity main feedwater regulating valves to effect the desired feedwater flow to each steam generator.

In addition to the feedwater regulating valves, there is a remote manually operated 15 percent capacity bypass valve and a 100 percent capacity motor operated bypass valve for backup in case of outage of the regulating unit. The 15 percent low flow bypass valve is used during startup and shutdown operations. A Low Power Feedwater Control System (LPFCS) which is an extension of the Feedwater Regulating System will maintain steam generator level at setpoint value during unit start-up in the range of approximately 2 to 15% load. Refer to Section 7.7 for a complete description of feedwater flow control system.

In addition to the existing venturi method of measuring feedwater flow, the Leading Edge Flow Meter (LEFM) System is installed as part of a Measurement Uncertainty Recapture (MUR) effort for the Extended Power Uprate. The LEFM is a highly sophisticated feedwater mass flow rate measurement system. It employs the ultrasonic transit time method to determine path sound velocity and axial fluid velocity. It also contains an automatic self-checking system to continuously verify if it is performing properly and to initiate alarms at the Control Room when unsatisfactory conditions are detected. The LEFM system will support determination of secondary calorimetric thermal power with an accuracy of approximately +/- 0.3% of Rated Thermal Power (RTP) when PSL Unit 2 is operating between 95% RTP and 100% RPT.

10.4.8 STEAM GENERATOR BLOWDOWN SYSTEM (SGBS)

The Steam Generator Blowdown System (SGBS) is utilized in conjunction with the Chemical Feed and Secondary Sampling Systems (Subsection 10.3.5 and 9.3.2, respectively) to control the chemistry of the steam generator secondary side water.

The SGBS flow diagrams are shown on Figures 9.5-6, 10.4-5, and 10.4-6. The design data are given in Table 10.4-1.

10.4-15 Amendment No. 27 (03/22)

UFSAR/St. Lucie - 2 10.4.8.1 Design Basis The safety related portion of the SGBS, from the steam generator blowdown nozzle up to the outermost containment isolation valve, is designed to Quality Group B and seismic Category I requirements. The remainder of the system is designated non nuclear safety and non seismic.

The non-safety related portion of the SGBS, from the outermost containment isolation valve to the check valve (V23107 and V23132) is designed to Quality Group D and Seismic Category I requirements.

The SGBS is designed to fulfill the following requirements:

a. To control steam generator secondary side water chemistry as discussed in Subsection 10.3.5.

b. Monitor secondary side radioactivity for any primary to secondary leakage.

c. Reduce the steam generator blowdown contaminants to an acceptable level prior to discharge to the environment.

d. Provide a continuous blowdown rate of 0.2 percent of the total original main steam flow during normal operating conditions.

e. Permit a maximum blowdown rate of 1.0 percent of the total original main steam flow during periods of abnormal condenser inleakage.

f. Provide blowdown system containment isolation capability.

g. Protected against the dynamic effects of pipe rupture as outlined in Section 3.6.

h. Protected against externally generated missiles as discussed in Section 3.5.

10.4.8.2 System Description The Steam Generator Blowdown System (SGBS) consists of a closed blowdown cooling loop and an open blowdown cooling subsystem. The thermal energy from the blowdown stream is transmitted to the closed loop via the closed blowdown heat exchangers. The closed loop acts as a barrier between the process stream and the environment. The heat is transported from the closed loop to the Intake Cooling Water System via the open blowdown heat exchangers. The Intake Cooling Water System dissipates this thermal energy into the discharge canal.

Each steam generator has two blowdown lines that merge and discharge to the SGBS. During normal plant operation, the SGBS is capable of processing a total flow from both steam generators of 18,900 lbs/hr. Should condenser inleakage occur, the SGBS is designed to process a total flow of 94,500 lbs/hr in order to maintain the feedwater chemistry limits specified in Subsection 10.3.5.

Steam generator blowdown is extracted from each steam generator at full load temperature and pressure. The blowdown is initially subcooled by the piping configurations and is further subcooled in the closed blowdown heat exchangers to 120 F, which is compatible with the ion exchanger process. The blowdown cooling loop is shown in Figure 10.4-12. The blowdown is then passed through a pressure-reducing valve and flow control station and then is discharged to the Steam Generator Blowdown Treatment Facility.

10.4-16 Amendment No. 27 (03/22)

UFSAR/St. Lucie - 2 The Steam Generator Blowdown Treatment Faculty (SGBTF), which was licensed on the St Lucie Unit 1 docket (Docket No. 50-335) and is shown on Figures 9.5-6, 10.4-5, and 10.4-6, is a common facility shared between St Lucie Units 1 and 2. The SGBTF has been analyzed for the seismic forces as outlined in Subsection 3.7-2.

There are three process streams in the SGBTF, each consisting of its own process filter demineralizer, monitor storage tank and pump. Each process stream has the capability of handling the maximum blowdown rate from one unit (two steam generators) with one process stream acting as a spare. The system was originally designed for automatic monitoring of the process effluent for radioactivity within the SGBTF. Indication of radioactivity from the SGBTF monitors would have initiated automatic closure of the isolation valves discharging to the canal when the radioactivity was above a preset limit. This design feature is no longer utilized.

Additionally, effluent from the monitor storage tanks is no longer pumped to the discharge canal.

Automatic isolation function to the SGBTF is currently performed by RM-26-5 & RM-26-6. Plant controls and procedures govern processing of effluent prior to return to the condenser. During normal plant operation, blowdown entering the SGBTF is monitored for radioactivity by RM-26-5

& RM-26-6, and is either recycled or released to the discharge canal. For recycling, the blowdown is passed through a blowdown filter to remove suspended solids, through the demineralizer train to the monitor storage tank. Any ionic impurities are then removed by ion exchange in a cation demineralizer and a mixed-bed demineralizer connected in series. The cation resin used in the cation and mixed-bed demineralizer is a high capacity, strong acid exchange resin in the H+ form. The anion resin used in the mixed-bed demineralizer is a high capacity strong-base exchange resin in the OH- form. A temperature control valve (TCV-23-8) is provided as a protection for the demineralizer resins. If the temperature of the blowdown exceeds a specified limit, the valve will close and a high temperature alarm will annunciate in the control room to initiate operator action.

The effluent from the ion exchanges is collected in any one of three monitor storage tanks where it is recirculated, sampled and analyzed for radioactivity and conductivity. In the event that the radioactivity discharge limits cannot he met, the blowdown is either reprocessed or held up. Any one of the three storage tanks can be recirculated for reprocessing by any one of the three discharge pumps. Furthermore, the system was originally designed such that one tank can be recirculated, one tank discharged to the canal, and one tank discharged for reprocessing by their respective discharge pumps at the same time. Current plant procedures prevent effluent discharge from the monitor storage tanks to the discharge canal.

10.4.8.3 System Evaluation The Steam Generator Blowdown System has no safety related function, with the exception of the containment isolation. The valves and piping which constitute the containment boundary are discussed in Subsection 6.2.4. The isolation valves outside containment close automatically upon receipt of a CIAS or a Steam Generator Blowdown System high radiation Signal. The CIAS or High Radiation signals may be remote manually overridden and the valves re-opened by the Control Room operator. These isolation valves, as well as the isolation valves inside containment, are closed within 7 seconds of a steam generator blowdown pipe rupture. This maintains a mild environment in the RAB penetration area as evaluated in Section 3.1.3.3 of the Environmental Qualification Report and Guidebook (2998-A-451-1000).

The steam generator blowdown is continuously monitored for radioactivity. Radiation monitors are provided on each steam generator blowdown line (RM-26-5 & RM-26-6). In the event that the fluid being processed in the system is radioactive, additional processing of the effluent will 10.4-17 Amendment No. 27 (03/22)

UFSAR/St. Lucie - 2 be performed to reduce the activity to acceptable levels prior to return to the condenser. This has the effect of concentrating the activity in the blowdown filters and the demineralizer resins which is then discharged to the Solid Waste Management System described in Section 11.4.

The Steam Generator Blowdown Monitor Storage Tanks have a vent that exhausts directly to the atmosphere. The operation of these tanks will be within the guidelines of 10 CFR 50, Appendix I (Offsite Dose Calculation Manual - ODCM), regarding the release from the vent. The radioactivity of the water entering the tanks will be monitored per the ODCM. In addition, upon high radiation in the blowdown line, the tanks can be isolated to prevent contamination from accumulating.

In the event of contamination of the liquid inventory in the Monitor Storage Tanks (MST), all tanks are provided with local level indication and high level alarm to prevent spillage. In addition, the MST overflow and drains are routed to the Equipment Drain Tank in the Liquid Waste Management System.

Failure of any component in the Steam Generator Blowdown System does not affect safe shutdown of the plant.

10.4.8.4 Testing and Inspection Those portions of the SGBS performing containment isolation are tested under conditions of normal operation in accordance with the procedure outlined in Chapter 14 to ensure that all valves close properly and that the design leakage requirements are met. The remaining portions of the SGBS is also functionally tested during normal operation to ensure satisfactory performance.

Periodic sampling is required as a performance check on some of the process equipment and to alert the operator to any abnormal condition that may be developing.

10.4.8.5 Instrumentation and Controls Instrumentation and controls ensure operation within design parameters and monitor effluent conductivity, radioactivity, blowdown flow rate, and monitor tank low water level. Procedures and Controls allow recycling and allow flow to be discharged or used as makeup water.

10.4.9 AUXILIARY FEEDWATER SYSTEM The function of the Auxiliary Feedwater System (AFWS) is to ensure a sufficient supply of cooling water to the steam generators when main feedwater is not available. The Auxiliary Feedwater System P&ID is provided in Figures 10.1-1a and 10.1-2b. The system component design data is provided in Table 10.4-1.

The original system sizing calculations of the Auxiliary Feedwater System (CST and ADVs included) have conservatively assumed 2754 MWt power level, (as discussed in Table 10.4.9A-1). The extended power uprate analyses were performed for a core power level of 3020 MWt. The system is capable of operating safely at extended power.

10.4-18 Amendment No. 27 (03/22)

UFSAR/St. Lucie - 2 10.4.9.1 Design Bases The design bases of the Auxiliary Feedwater System are as follows:

a. AFWS supplies sufficient cooling water to either one or both steam generators to ensure the following:

1. provide sufficient capability for the removal of decay heat from the reactor core,

2. reduce the Reactor Coolant System temperature to entry temperature for actuating the Shutdown Cooling System (SDCS),

3. prevent lifting of the pressurizer safety valves when considered in conjunction of the PORV.

b. The AFWS delivers feedwater against the maximum steam generator pressure.

c. The Auxiliary Feedwater System is designated Quality Group C except as follows:

The Auxiliary Feedwater supply from the outermost containment isolation valves to the steam generators is designated Quality Group B.

The steam supply for the auxiliary feedwater pump turbine, from the main steam line upstream of the main steam isolation valve to the outermost containment isolation valves, is designated Quality Group B.

d. The seismic Category I condensate storage tank stores sufficient demineralized water for the AFWS to hold the reactor at a hot standby condition for at least two hours followed by an orderly cooldown until the SDCS is actuated. Refer to Subsection 9.2.6.

e. The AFWS is designed to operate with loss of offsite and onsite ac power.

f. Two full capacity ac powered motor driven pumps and one greater than full capacity steam turbine driven pump ensure system performance with redundant and diverse power sources.

g. The AFWS is designed to preclude hydraulic instabilities.

h. The AFWS is able to perform its design functions following design basis phenomena (see Sections 2.4, 3.3, 3.4, 3.5, 3.6, 3.7 and 3.8).

i. The AFWS is designed to withstand pipe rupture effects (see section 3.6).

10.4.9.2 System Description During normal operation, feedwater is supplied to the steam generators by the Feedwater System. The Auxiliary Feedwater System (AFWS) may be utilized during normal plant startup, hot standby, and cooldown. During plant startup and hot standby, the system can provide a source of water inventory for the steam generators. During cooldown, the AFWS can provide a means of heat removal to bring the Reactor Coolant System to the shutdown cooling system 10.4-19 Amendment No. 27 (03/22)

UFSAR/St. Lucie - 2 activation temperature. With offsite power and the main condenser available, the condenser may be used as a heat sink.

The major active components of the system consist of one steam driven pump with greater than full flow capacity and two full flow capacity motor driven auxiliary feedwater pumps. Both electrical and steam driven AFWS pumps are centrifugal units with horizontal split casings and are designed in accordance with ASME Code,Section III and Quality Group C requirements.

The larger pump is driven by a noncondensing steam turbine. The turbine receives steam from upstream of the main steam isolation valves, and exhausts to the atmosphere. The pumps take suction from the condensate storage tank and discharge to the steam generators. The turbine-driven pump is capable of supplying auxiliary feedwater flow to the steam generators for the total expected range of steam generator pressure by means of a turbine driver controlled by a variable speed mechanical governor.

Each motor-driven pump supplies feedwater to one steam generator. A cross connection is provided to enable the routing of the flow of the two motordriven pumps to one steam generator.

The turbine-driven pump supplies feedwater to both steam generators by means of two separate lines each with its own control valve and each sized to pass the full flow. AFW valves needed for system operation under design bases events have control switches in the control room and locally as well. Each of the motor driven auxiliary feedwater pumps utilize a Class 1E ac power supply (4.16 kV safety related bus). The turbine driven pump train relies strictly on a dc power supply.

10.4.9.3 Safety Evaluation The AFWS can remove sensible and decay heat from the Reactor Coolant System during hot standby and cooldown for initiation of shutdown cooling. For events in which main feedwater flow is unavailable, (e.g., loss of main feedwater pump, loss of offsite power, and main steam line break), the AFWS is automatically initiated to provide hot standby and/or cooldown heat removal, following a specified time delay period (see Section 10.4.9.5).

The condensate storage tank (CST) discussed in Subsection 9.2.6, provides the water supply for the Auxiliary Feedwater System. The CST is sized to provide 150,000 gallons of demineralized water for St. Lucie Unit 2 for hot standby and cooldown operations; an additional 130,500 gallons is reserved in the St. Lucie Unit 2 CST only in the event that a vertical tornado missile somehow ruptures the St. Lucie Unit 1 CST and the water contained therein (130,500 gallons per St. Lucie Unit 1 Technical Specifications) is unavailable to St Lucie Unit 1. A cross-tie is provided between Units for this unlikely event. As a result, the cross-tie is designed and installed as Quality Group D, non-seismic (Ref. PSL-ENG-SEMS-97-064). The minimum stored volume in the CST is 307,000 gallons, which is below the lowest non-seismically qualified nozzle. This accounts for the following volumes.

Unusable Volume All water stored below a line 8 inches above the suction point is considered unusable. This quantity of 9,200 gallons is considered in the determination of the minimum required stored volume. No credit is taken for the height of water in the tank in the evaluation of the Net Positive Suction Head available to the Auxiliary Feedwater Pumps.

10.4-20 Amendment No. 27 (03/22)

UFSAR/St. Lucie - 2 Unit 1 Shutdown Volume A volume of 130,500 gallons is maintained for use by Unit 1 in the event the St. Lucie Unit 1 CST is ruptured by a tornado missile. This amount is more than sufficient for shutdown purposes. Unit 1 Technical Specification level is 153,400 gallons.

Unit 2 Shutdown Volume A volume of 150,000 gallons is maintained to shutdown Unit 2 as outlined below.

Instrument Error The instrumentation error of 4,230 gallons is based on a CST level loop uncertainty of 0.9 percent of the instrumentation span. This uncertainty has been added to the total of the above volumes.

Working Volume The total of the above volumes, including allowance for instrumentation error, amounts to 294,000 gallons. The maximum working (available) volume is equal to the minimum stored volume (307,000 gallons) minus the 9,200 gallons of unusable volume. Therefore, the St. Lucie Unit 2 CST capacity of 297,800 gallons is available when no tornado warnings are in effect.

Should a vertical tornado missile disable the Unit 1 Condensate Storage Tank (CST), Unit 1 operators will be alerted to the loss of auxiliary feedwater by the redundant safety grade low-level alarm and level indicators (LIS-12-11, 12) located in the Unit 1 Control Room. Once alerted, Unit 1 operators initiate procedures to obtain auxiliary feedwater water supply via the CST cross-tie between Units. These procedures require Unit 1 operators to alert Unit 2 to the need to intertie the CSTs. The Unit 1 operators open (as necessary) the intertie isolation valves (E&F on Figure 10.4-8a). Unit 2 operators open isolation valves (A&D) or (B or C, and D). If Unit 1 requires auxiliary feedwater before or concurrently with Unit 2, procedures require the opening of valves A and D. If Unit 2 has previously consumed the feedwater required for shutdown, valves (B or C and D) would be opened. A misalignment of valves causing a loss of suction to the Auxiliary Feedwater Pumps would be evidenced by the safety grade flow indicators located in the control room.

The quantity of water required for St. Lucie Unit 2 cooldown has been determined assuming a worst case condition wherein the unit is brought to hot standby conditions and held there for approximately two hours then cooled down at the maximum rate until the shutdown cooling window is reached. Under this scenario, each Auxiliary Feedwater Pump has the capability of achieving an orderly shutdown consisting of two hours of hot standby followed by a regulated cooldown to the shutdown cooling entry point within the next five hours. The quantity of condensate required for this scenario is approximately 139,000 gallons as shown on Table 10.4-2 (Case 2) and Figure 10.4-10.

The condensate storage requirements for the Auxiliary Feedwater System were compared with the requirements of Regulatory Guide 1.139, "Guidance for Residual Heat Removal." Under this scenario, the unit is brought to hot standby conditions and held there for four hours then cooled down at the analyzed cooldown rate of 75°F/hour until the shutdown cooling window of 350°F is reached. The condensate storage requirement for this scenario is 150,000 gallons as shown on Table 10.4-2 (Case 1) and Figure 10.4-10.

10.4-21 Amendment No. 27 (03/22)

UFSAR/St. Lucie - 2 During station blackout conditions (except the hypothetical tornado missile which drains the St.

Lucie Unit 1 CST) there is sufficient water in the CST to allow hot standby operation for 23 hours2.662037e-4 days 0.00639 hours 3.80291e-5 weeks 8.7515e-6 months and a subsequent cooldown to 294°F over 3.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months (see Table 10.4-2 and Figure 10.4-10). The condensate requirements and the auxiliary feedwater flow rate, based on the limiting accident condition, are discussed in Appendix 10.4.9A.

The steam generated during decay heat removal and cooldown after a loss of offsite power is discharged through the atmospheric dump valves, except for the steam used by the turbine driven auxiliary feed pump. There are two ac/dc motor operated atmospheric dump valves (ADVs) located on each main steam line. The ADVs are capable of automatic modulating service using ac power and are capable of open/close service from the control room using dc power only. Each ADV is sized to pass 50 percent of the flow required to bring the Reactor Coolant System to the shutdown cooling system entry temperature, assuming that only 125,000 gallons of condensate is available from the condensate storage tank.

The auxiliary feedwater pumps are located underneath the steam trestle. The AFWS is designed to withstand natural phenomena as described in Sections 3.3 and 3.5. The condensate storage tank is a seismic Category I structure. It is surrounded by a structural barrier which provides missile and tornado protection for the tank. Components in the AFWS are protected from flooding as components are located above the probable maximum flood level (refer to Section 3.4). The design provisions utilized to protect the AFWS against the dynamic effects of pipe rupture and jet impingement effects are provided in Section 3.6. The Auxiliary Feedwater System piping layout and the steam trestle configuration is provided on Figures 10.4-14, 10.4-15, 10.4-16, 3.8-61, and 3.8-62. The suction lines for the Auxiliary Feedwater Pumps are protected over their entire length from the Condensate Storage Tank (CST) to the trestle. From the CST to the turbine building and from the turbine building to the trestle the lines are totally enclosed in a pipe trench. The pipe trench is designed to withstand the effects of seismic events and tornados. Within the turbine building the suction lines are buried in concrete.

The basemat and steel superstructure of the turbine building has been designed to withstand the effects of a Safe Shutdown Earthquake (SSE). This insures the safety of all essential components in the vicinity of the turbine building by eliminating the possibility of catastrophic failure. The local failure of non-seismic components located in the turbine building cannot adversely affect plant safety since no essential equipment is located there.

The potential for hydraulic instability is also considered in the design of the Feedwater System and Auxiliary Feedwater System Piping. Routing of the feedwater piping is such that draining of the feedwater line is minimized. The 32 feet drop in the feedwater piping immediately outside the feedwater nozzle and the existence of two check valves between the steam generator and the feed pumps provides adequate assurance that the piping will not drain. Design provisions are incorporated into the feedwater sparger to minimize the rate of draining and are discussed in Section 5.4. Refer to Figure 10.4-13 for a main feedwater piping isometric from the steam generators to the restraint of the upstream side of the feedwater isolation valves.

The St. Lucie Unit 1 and 2 motor operated valves reviewed for IE Bulletin 85-03 are slow acting valves (see Table 10.4-1a and FPL letter L-88-19). The valve closure times and piping lengths were surveyed to determine the most limiting system configuration and valve operating characteristics with respect to water hammer. An evaluation was performed to verify that the worst case system configuration and valve operating characteristics would not cause significant water hammer loading due to valve closure.

10.4-22 Amendment No. 27 (03/22)

UFSAR/St. Lucie - 2 The following AFW MOVs are subject to the requirements of NRC Generic Letter (GL) 89-10:

MV-09-9, MV-09-10, MV-09-11, and MV-09-12. The requirements of GL 89-10 supersede those of IE Bulletin 85-03.

Diverse power sources are utilized to ensure that the Auxiliary Feedwater System is capable of performing its intended safety function. The design features incorporated into the Auxiliary Feedwater System to assure diversity in power sources are: a) each motor driven auxiliary feedwater pump is aligned to a separate diesel generator with its associated motor-operated isolation valves being fed from the same diesel as the pump, and b) the turbine driven pump and its associated suction and discharge isolation valves are fed from a dc power supply. This arrangement ensures sufficient supply due to total loss of both offsite and onsite ac power supply. The diversity in power supply is shown schematically on Figure 10.4-8.

The Auxiliary Feedwater System is designed such that no single active failure coupled with loss of offsite power prevents plant cooldown.

A failure mode and effects analysis of the Auxiliary Feedwater System, assuming a main steam or feedwater line break accident and loss of offsite power, is presented in Table 10.4-3. The failure mode and effects analysis of the AFWS assuming an auxiliary feedwater line break coincident with loss of offsite power is presented on Table 10.4-4. Figure 10.4-8 provides the auxiliary feedwater flow schematic for the single failure analysis.

Gas Accumulation and Air Intrusion Similar to the issues discussed in NRC Generic Letter 2008-01 and SER 2-05, the presence of unanticipated gas voids within the AFW System can challenge the ability of the system to perform its design functions due to issues such as gas binding, water hammer, injection delay times, etc. The AFW system has little opportunity for gas to enter the pump suction piping, but it may be possible for system leaks to result in voiding in the discharge piping or the Unit 1 and Unit 2 CST crosstie.

10.4.9.4 Testing and Inspection Auxiliary feedwater pumps are functionally tested at the manufacturer's shop to demonstrate successful operation and performance of the equipment. The operability assurance program is described in Subsection 3.9.3. Motor operated valves previously identified will be tested (as required) using differential (d/p) stroke testing or other available and approved techniques to address NRC Generic Letter 89-10 requirements.

Monitoring of fluid conditions within the AFW system is performed on a regular basis to preclude a steam binding condition. Should such a condition exist, additional procedures are provided to restore the AFW system to operable status. These inspections and procedures are provided in accordance with the IE Bulletin 85-01, "Steam Binding of Aux Feedwater Pumps".

Preoperational functional testing was performed and the system is tested periodically as described in the Technical Specifications.

10.4-23 Amendment No. 27 (03/22)

UFSAR/St. Lucie - 2 10.4.9.5 Instrumentation Application Display information related to the Auxiliary Feedwater System is discussed in Section 7.5.

Status of active components during system operation is displayed for the operator in the control room and locally. See Table 10.4-5 for a list of instrumentation and controls provided.

During startup, hot standby and cooldown the AFWS is controlled manually by the operator from the control room. Means are provided to throttle the control valve from the main control room in each AFWS train to permit the operator to adjust the auxiliary feedwater flow rates into the steam generators. Steam generator pressure and water level indication is provided to inform the operator when the AFWS can be shutdown. Means are provided to start/stop each pump or to open/close the AFWS isolation and turbine steam stop valves from the control room.

The Auxiliary Feedwater System is provided with complete sensor and control instrumentation to enable the system to automatically respond to a loss of steam generator inventory. Upon low steam generator level, an Auxiliary Feedwater Actuation Signal (AFAS) time delay is actuated.

Actuation of the AFAS is delayed for a preselected period of time. If steam generator water level increases to reset the low level actuation bistable before the AFAS time delay expires, the time delay resets and the AFWS is not actuated. If the AFAS time delay expires while steam generator level is below the AFAS low level actuation bistable (first) reset, then the AFWS receives an AFAS. This signal starts the auxiliary feedwater pumps and fully opens the redundant isolation valves automatically providing a minimum feedwater flow of 357 gpm to a steam generator pressure of 900 psi. The AFWS supplies water to the steam generator until the steam generator level increases to the second AFAS reset setpoint, where the AFWS pump discharge valve automatically closes thereby diverting flow from the Steam Generators to the condensate storage tank. The MOVs have Limitorque SMB operators designed for severe duty while the solenoid valves utilize the Target Rock operators that have been designed for an extended life cycle. All valve operators are qualified to IEEE-323-74, 344-75 and 382-72.

To reach high-level from the normal level it takes approximately another three minutes with all valves fully open. To be on the conservative side these numbers were computed without assuming steaming through the Safety Relief Valves, and assuming all three pumps were running and both Steam Generators were available after initiating the AFWS on low-level.

The AFAS logic employs four channels of initiating signals to provide a two out of three actuation sequence of system components. A separate AFAS is generated for each steam generator, AFAS 1 for generator 2A and AFAS 2 for generator 2B. An AFAS 1 will indicate that SG 2A requires feedwater and thus, will start auxiliary feedwater pumps 2A and 2C and will open isolation valves MV-09-9 & 11 and SE-09-2 & 4, steam inlet valves MV-08-12 and MV-08-13 and close MFIV HCV-09-1A, 1B. Similarly, an AFAS 2 will indicate that SG 2B requires feedwater and thus will start pumps 2B and 2C and will open isolation valves MV-09-10 & 12 and SE-09-3 & 5, steam inlet valves MV-08-12 and MV-08-13 and close MFIV HCV-09-2A, 2B.

Both "latched" and "unlatched" signals are generated by an AFAS. The pumps, whose operation is initiated and never interrupted, receive latched signals. The feedwater isolation valves, which open on low steam generator level and close on high level, receive unlatched signals.

Additionally, using four channel pressure instrumentation on the main steam and feedwater lines, the system has the ability to identify and isolate a faulted steam generator or ruptured feedwater line. Should a differential pressure of approximately 275 psid between the steam generators or 150 psid between the AFW supply headers be detected, auxiliary feedwater flow 10.4-24 Amendment No. 27 (03/22)

UFSAR/St. Lucie - 2 to the loop with the lower pressure is isolated. This is done by closing the applicable auxiliary feedwater isolation valves. Redundant isolation valves are provided to assure that feedwater does not enter a faulted loop even after a single active failure. A complete description of the AFAS logic circuitry is provided in Subsection 7.3.1.1.8. This complies with SRP 10.4.9 (Rev 1) and BTP ASB 10-1 (Rev 1) as identified in Subsection 10.4.9A.

Verification of system operation is provided in the control room by a redundant safety related flow indication and recording for each Auxiliary Feedwater pump. For Pump A, the indicator is powered from safety bus SA and the recording is powered from safety bus SB. For Pump B, the indicator is powered from safety bus SB and the recording is powered from safety bus SA. For Pump C, the indicator is powered from bus SAB and recorder is powered from safety bus SA.

In addition, redundant feedwater header pressure indicators are provided in the control room for each steam generator. These pressure indicators in conjuntion with the steam generator level and auxiliary feedwater pump discharge flow indicators, provide the operator with a reliable means to determine system operation status.

10.4-25 Amendment No. 27 (03/22)

UFSAR/St. Lucie - 2 TABLE 10.4-1 COMPONENT DESIGN PARAMETERS

1. Main Condenser Type Two shell, single pass with divided water boxes, surface condenser Design duty, BTU/hr 5.850 x 109 Maximum duty, BTU/hr 6.10 x 109 Heat transfer area, ft2 546,000 Design pressure:

Shell, psig/in. Hg 15 psig/30 in. Hg vacuum Water Box, psig 25 Total flow to condenser, 7,812,473 max. guaranteed, lb/hr Total flow to condenser, 8,195,683 max. expected, lb/hr Material Shell ASTM A-285, GR C Tubes ASTM B-338-73 Titanium Tube Sheets Aluminum bronze with pressurized integral grooves Codes Heat Exchanger Institute Standards for Steam Surface Condensers, NNS

2. Steam Jet Air Ejector

a. Inter-Condenser Type Single pass Heat Transfer Area, 415 ft2 Design Pressure:

Tube side, psig 750 Shell side, psig 25 and full vacuum T10.4-1 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4-1 (Cont'd)

2. Steam Jet Air-Ejector (Cont'd)

Material:

Shell ASTM-A285, GR C Tubes 316 S.S. ASTM A249 Tube Sheets 316 S.S. ASTM A240 Codes Heat Exchange Institute Steam Jet Ejector Standard, NNS

b. After-Condenser:

Type Single pass Heat Transfer Area, ft2 160 Design Pressure:

Tube side, psig 750 Shell side, psig 25 and full vacuum Material:

Shell ASTM-A285, GR C Tube 316 S.S. ASTM A249 Tube Sheets 316 S.S. ASTM A240 Codes Heat Exchange Institute Steam Jet Ejector Standard.

3. Circulating Water System

a. Circulating Water Pumps Type Single stage, vertical removable element, mixed flow Quantity 4 Capacity, each, gpm 122,650 Head, feet 40 T10.4-2 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4-1 (Cont'd)

3. Circulating Water System (Cont'd)

Material:

Case 2 percent Ni-Cast Iron, ASTM-A-48 Cl-30 Impeller ASTM A-296 CF3M Shaft ASTM A-276 Type 316 SS Motor Constant speed, 1500 hp, 4000v, 60 hz, 3 phase, 360 rpm (nominal), with 1.15 Service Factor Enclosure WP II Codes NEMA, Standards of the Hydraulic Institute, ASME Section VIII, NNS

b. Traveling Water Screens Type Vertical, through-flow Quantity 4 Screen velocity, ft/min 10 & 20 Material:

Screen Stainless Steel Frame Stainless Steel & Fiberglass

c. Screen Wash Pumps Type Five stage, vertical, turbine wet pit Quantity 2 Capacity, each, gpm 1060 Head, feet 250 Material:

Case 2 percent NI cast iron Impeller Type 316 SS, ASTM-A 296 Shaft Type 316 SS, ASTM-A 276 T10.4-3 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4-1 (Cont'd)

3. Circulating Water System (Cont'd)

Motor 100 hp, 460 V, 3 phase, 60 hz, 1800 rpm (nominal)

Enclosure TEFC Codes NEMA, Standards of the Hydraulic Institute, ASME Section VIII, NNS

d. Debris Filters Type Automatic (Self Cleaning)

Quantity 4 Pressure, psig 50 Temperature, F 125 Design Diff. Press., psid 45 Shell Material ASTM-A-240, Type 316 Perforation Size, mm 5 Code ASTM-F1199

e. Ball Strainers (Condenser Tube Cleaning System)

Type Inverted "V" Quantity 4 Pressure, psig 50 Temperature, F 125 Design Diff. Press., psid 20 Shell Material ASTM-A-240, Type 316 Strainer Grill Spacing, mm ASTM-F1199 Code 5 T10.4-4 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4-1 (Cont'd)

3. Circulating Water System (Cont'd)

f. Ball Recirculation Pumps (Condenser Tube Cleaning System)

Type Single Stage, non-clogging Centrifugal Quantity 4 Capacity, each, gpm 270 Head, feet 56 Case/Impeller Material AL6XN Motor 7.5 hp, 460 v, 3 phase, 60 hz, 1750 rpm Enclosure TEFC (Submersible)

Codes NEMA, Standards of the Hydraulic Institute

g. Ball Collector (Condenser Tube Cleaning System)

Type Manual Quantity 4 Pressure, psig 50 Temperature, °F 125 Shell Material ASTM-A-285, Grade C (Rubberlined)

Code AD-Merkblatter Series B (German)

h. Piping, Fittings and Valves Pressure, psig 50 Temperature, °F 135 (max.)

Pipe material*

Below ground Concrete Above ground Cast iron, cement lined, ASTM B675 (UNS #08367), Reinforced Thermosetting Resin (RTR) Fiberglass, PVC, CPVC and Monel Valves 3 inches and above Cast iron, flanged, rubber lined, steel, flanged, rubber lined or wafer, PVC/CPVC 2-1/2 inches and under Bronze, screwed or flanged, PVC/CPVC

Note: All pipes 3 inches and above.

T10.4-5 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4-1 (Cont'd)

4. Main Feedwater Pumps Type Two-stage centrifugal, horizontally split case, single suction, double volute Quantity 2 Capacity each, gpm 15,500 Head, feet 1,750 Fluid temperature, F 385 Material:

Case ASTM A487, Gr. CA6NM Impeller ASTM A487, Gr. CA6NM T10.4-6 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4-1 (Cont'd)

4. Main Feedwater Pumps (Cont'd)

Shaft ASTM A-276, Type 410 HT Driver Constant Speed, 3-ph, 60 cycle Electric Motor, 7000 hp, 3575 rpm, 6600 V, 1.15 Service Factor (S.F.)

Codes ASME Section VIII, NNS

5. Condensate Pumps Type Vertical centrifugal, 5-stage, can type Quantity 3 Capacity, each gpm 9,400 Head, feet 1,370 Fluid Temperature, F 117.3 Material:

Case A216 Gr. WCB Impeller A487/A743 Gr. CA6NM Shaft 410 SS Driver Constant speed, 3-ph, 60 cycle, electric motor, 4000 hp, 1180 rpm, 4000 V, 1.15 S.F.

Codes ASME Section VIII, NNS

6. Heater Drain Pumps Type Vertical centrifugal 7-stage, can type Quantity 2 Capacity each, gpm 4750 (required minimum flow of 1500 gpm)

Head, feet 850 Fluid temperature, F 450 T10.4-7 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4-1 (Cont'd)

6. Heater Drain Pumps (Cont'd)

Material:

Case ASTM A 296 CA 6 NM Impeller ASTM A-487 Gr. CA6NM Shaft ASTM A276 TY 410 SS Driver Constant speed, 3-ph, 60 cycle, electric motor,1250 hp, 1780 rpm or 1500 hp, 1785 rpm, 4000 V, 1.15 S.F Codes ASME Section VIII, NNS API STD 682 ANSI Sections B16.5, B31.1

7. Feedwater Heaters Heaters Numbers 2-1A&1B 2-2A&2B 2-4A&4B 2-5A&5B 2-3A&3B Type Closed, U-tube Closed, U-tube Closed, U-tube Material:

Shell ASME SA-515-70 ASME SA-387-11-2 ASME SA-387-11-2 Tubes ASTM-SA-688, ASTM-SA-688, ASTM-SA-688, TP304 TP-316L TP316L Tube sheets ASME-SA-516-70 ASME-SA-336-F11-3 ASME-SA-350-LF2 Feedwater flow 7,812,473 13,443,564 13,306,000 lb/hr (total for both heaters)

Codes ASME Section VIII, NNS 2-4A/B: 2010 Edition, No Addenda 2-5A/B: 2007 Edition, No Addenda Heat Exchange Institute Standards for Closed Feedwater Heaters T10.4-8 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4-1 (Cont'd)

8. Drain Coolers Coolers Numbers 2-A&B Type Straight Tube Material:

Shell ASME-SA-516-70 Tubes ASTM-SA-688, TP304 Tube sheets ASME-SA-516-70 Feedwater flow (lb/hr) 7,812,473 Codes ASME Section VIII, NNS Heat Exchange Institute Standards for Closed Feedwater Heaters Heater Design duty Heat Transfer No. each Design press. (psig) Design temp. (F) area each (BTU/hr) Shell Tube Shell Tube (ft2) 2-1A,1B 213.3 x 106 50 & Full Vac. 750 300 300 20,484 2-2A,2B 166.2 x 106 50 & Full Vac. 750 300 300 14,839 2-3A,3B 219.7 x 106 75 & Full Vac. 750 320 320 14,452 2-4A,4B 528.0 x 106 300 750 425 450 23,895 2-5A,5B 421.4 x 106 475 2025* 550 500 27,254 Drain Cooler No.

2-A,B 130.2 x 106 300 750 422 422 5,058

HP Heater 2-5A/2-5B tube side is conservatively designed to 2025 psig. The system design pressure is 1875 psig and therefore the tube side relief valves set point is 1875 psig.

T10.4-9 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4-1 (Cont'd)

9. Piping and Valves

a. Piping: Material Codes Feedwater* ASME-SA-106, GR B ASME Section III, Class 2 Balance of Piping ASTM-A-155, GR KC-65 ANSI B31.1 ASTM A-106, GR B ASTM-A-312/376 Tp. 316L**

Auxiliary Feed-water Piping Suction (above- ASME-SA-106, Gr B ASME Section III, ground) Class 3 Suction (under- ASME-SA-358, CL II ASME Section III, ground GR. Tp. 316 SS Class 3 Discharge ASME-SA-106, GR B ASME Section III, Class 2/Class 3 as applicable

b. Main Feedwater Isolation Valves:

Type Gate Valve Quantity Two per Feedwater Line Operator Electro-Hydraulic Actuator Design Press., psig 1875 Design Temp., F 500°F Design Flow, lbs/hr 5.9 x 106

10. Steam Generator Blowdown System

a. Filters:

Quantity 3 Code ASME Section VIII, NNS Type Replaceable Cartridge Material Stainless Steel Design Flow, gpm 300

To Outermost Containment Isolation Valve.

- Only used in pipe whose design temperature is 200°F or less.

T10.4-10 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10-4-1 (Cont'd)

10. Steam Generator Blowdown System (Cont'd)

Particular, Retention, 5 Microns Design Pressure, psig 200 Design Temperature, F 150

b. Demineralizers:

Quantity 6, 2 per Train Code ASME Section VIII, NNS Type One Cation Bed and One Mixed Bed per Train Material Stainless Steel Resins:

Cation Acidic Polystyrene-divinyl benzene (H+)

Mixed Bed Basic Quartenary Ammonia Cross Linked, Polystyrene divinyl Type I (OH-)

Design Pressure, psig 200 Design Flow, gpm 300 Design Temperature, F 150 C. Tanks: Monitor-Storage Spent Resin Storage Quantity 3 1 Internal Volume, 180,000 9,300 gallons Design Pressure Atmospheric Atmospheric Design Temperature, F 150 50 Materials Carbon Steel-Epoxy Stainless Steel Lined Code AWWA, b-100, NNS ASME VIII, Div 1, NNS T10.4-11 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4-1 (Cont'd)

10. Steam Generator Blowdown System (Cont'd)

Closed Monitor Tank Sluice Resin Blowdown

d. Pumps Discharge Water Transfer Cooling Quantity 3 1 1 2 Type Centrifugal Centrifugal Centrifugal Centrifugal Design Pressure, psig 150 150 150 150 Design Temperature, F 150 150 150 150 Capacity, gpm 400 200 100 1400 Design Head, ft 230 195 37 155 Wetted Material Stainless Stainless Stainless Bronze Steel Steel Steel Horsepower 50 20 3 100 Code ASME VIII, ASME VIII, ASME VIII, ASME VIII, Div 1, NNS Div 1, NNS Div 1, NNS Div 1, NNS Closed Blowdown Open Blowdown

e. Heat Exchangers: Cooling Cooling Quantity 3 2 Type Counter Flow-Single Pass Counter-Flow-Single Pass Material: Tubes ASTM B-163 (Monel) ASTM B-111,Alloy CDA-687 Shell ASTM A515 (GR-70) ASTM A515 GR-70 Duty, Btu/hr 34.6 x 106 69.2 x 106 Flow, tube side (lb/hr) 79,025 2.8 x 106 Flow, shell side (lb/hr) 350,000 700,000 Code ASME VIII, TEMAC ASME VIII, TEMA C CBCS Surge Tank CBCS Chemical Blowdown Drain

f. Tanks Feed Pot Collection Tank Quantity 1 1 1 Volume, Gallons 440 25 480 T10.4-12 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4-1 (Cont'd)

f. Tanks (Cont'd) CBCS Chemical Blowdown Drain CBCS Surge Tank Feed Pot Collection Tank Design Pressure ATMOS ATMOS ATMOS Design Temp, F 150 150 550 Material Carbon Steel 316 SS Carbon Steel Code ASME VIII, AWWA, ASME VIII AWWA, ASME VIII AWWA API API API

11. Auxiliary Feedwater Pumps Motor Driven Steam Turbine Driven Type Single suction, horizontally split, horizontal centrifugal Stages 10 7 Quantity 2 1 Capacity each, gpm 300* 570**

Head, feet 2660 2660 Fluid temperature, F 120 120 Material:

Case ASME SA 487 CA 6 NM ASME SA 487 CA 6 NM Impeller ASTM A-296 CA 6 NM *** ASTM A 296 CA 6 Nm (248-302 BHN) (248-302 BN)

Shaft ASTM A-276 Type 410 ASTM A-276 Type 410 HT Cond. T Cond. T Driver Constant speed Single stage, non-3-Phase 60 cycle, condensing steam turbine, electric motor, 556 hp, 1875 to 3750 rpm 350 hp, 3570 rpm, with saturated steam from 4000 V, 1.15 S.F. 50 psig to 985 psig re-spectively.

Seismic I I Safety Class 3 3 Codes ASME III, 1974 Edition, Winter 1974 Addenda Note: *includes minimum recirculation flow of 50 gpm

- includes minimum recirculation flow of 70 gpm

- - Alternate material (ASTM A-487 GR CA 6 NM (IR 805)) has been approved for use.

T10.4-13 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4-1a AUXILIARY FEEDWATER SYSTEM MOTOR OPERATED VALVES (IE BULLETIN 85 HISTORICAL)

DESIGN BASIS P TAG NUMBER VALVE FUNCTION OPEN/CLOSE I-MV-09-9 AFWP 2A Discharge to SG 2A 1375 psi/1375 psi I-MV-09-10 AFWP 2B Discharge to SG 2B 1375 psi/1375 psi I-MV-09-11 AFWP 2C Discharge to SG 2A 1332 psi/1332 psi I-MV-09-12 AFWP 2C Discharge to SG 2B 1332 psi/1332 psi I-MV-09-13 AFWP 2A Discharge to SG 2B 1385 psi/1385 psi I-MV-09-14 AFWP 2B Discharge to SG 2A 1385 psi/1385 psi I-MV-08-12 AFWP 2C Steam Isolation 1085 psi/1085 psi I-MV-08-13 AFWP 2C Steam Isolation 1085 psi/1085 psi I-MV-08-3 AFWP 2C Trip & Throttle 1085 psi/1085 psi T10.4-14 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4-2 AUXILIARY FEEDWATER MAKEUP REQUIREMENTS FOR HOT STANDBY AND HOT SHUTDOWN Condition Length of Condition Auxiliary Feedwater (hours) Required (gallons)

(*Note 1) (*Note 1)

Case 1 Hot Standby 4 60,400 Cooldown (@ 75 F per hour) 4 89,200 Total condensate required to initiate shutdown cooling 149,600 Case 2 Hot Standby 2 35,800 Cooldown 4.5 93,200 Total condensate - 129,000 required to initiate shutdown cooling Case 3 Hot Standby 23 224,500 Cooldown 4 71,000 Total condensate 295,500 required to initiate shutdown cooling Total condensate available (minimum) 297,600 Note 1: This table was determined at pre-EPU conditions. For EPU, Case 1 was reanalyzed, taking 11.4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to reach shutdown cooling initiation, requiring a total of 150,000 gallons. For EPU, Case 2 was reanalyzed, taking 7.6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to reach shutdown cooling initiation, requiring a total of 132,000 gallons. For EPU, Case 3 was recalculated, taking 26.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months to reach shutdown cooling initiation, requiring a total of 293,000 gallons.

T10.4-15 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4-3 FAILURE MODES AND EFFECTS ANALYSIS - AUXILIARY FEEDWATER SYSTEM ASSUMING A FEEDWATER OR MAIN STEAM LINE BREAK IN ST GEN. B AND LOSS OF OFFSITE POWER Component Identification Failure Effect on Method of and Quantity Mode System Detection Monitor(2) Remarks Offsite Power Lost Main Feedwater flow is Various loss of power CRI One full capacity motor driven pump unavailable alarms. powered from the emergency diesel generator sets and one greater than full capacity steam-driven turbine pump are available to supply feedwater to steam generator 2A. Flow control valves SE-09-3, SE-09-5, MV-09-10 and MV-09-12 are closed to isolate auxiliary feedwater flow to steam generator 2B.

Steam turbine driven Fails to close No effect, Turbine attains Valve status indication CRI Flow control valves SE-09-3, SE-09-5, pump steam inlet full speed. Mechanical MV-09-10, and MV-09-12 are valve (MV-08-3) overspeed protection still closed to isolate auxiliary feedwater available. flow to steam generator 2B. AFW pumps 2A and 2C available for automatic initiation of feedwater flow to SG-2A.

Steam Supply Valve Fails to open No steam supply from steam Valve status indication CRI Flow control valves SE-09-3, SE-09-5, to Turbine Driven generator 2A. and steam supply line MV-09-10, and MV-09-12 are pump (MV-08-13) pressure indication. closed to isolate auxiliary feedwater flow to SG-2B. AFW pump 2A available for automatic initiation of feedwater flow to SG-2A.

Motor Driven Pump 2A Fails to start Motor driven pump associated Motor status lights CRI Flow control valves SE-09-3, SE-09-5, with intact SG is not discharge line flow or MV-09-10, and MV-09-12 are available. pres sure indication. closed to isolate feedwater flow to steam generator 2B and full flow established to steam generator 2A via the steam turbine driven pump.

Flow control valve Fails to open Motor driven auxiliary Valve status indication CRI Flow control valves SE-09-3, SE-09-5, (MV-09-9) or feedwater pump to steam MV-09-10, and MV-09-12 are (SE-09-2) generator 2A not available. closed to isolate feedwater flow to steam generator 2B and full flow established to steam generator 2A via the steam turbine driven pump.

Flow control valve Valve fails to open Steam turbine driven pump Valve status indication CRI Flow control valves SE-09-3, SE-09-5, (MV-09-11) or cannot deliver required MV-09-10, and MV-09-12 are closed (SE-09-4) flow to steam generator 2A. to isolate feedwater flow to steam generator 2B. Full flow established to SG-2A from AFW pump 2A.

T10.4-16 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4-3 (Cont'd)

Component Identification Failure Effect on Method of and Quantity Mode System Detection Monitor(2) Remarks Flow control valve One valve fails to No effect, redundant valve Valve status indication CRI Flow control valves closed to isolate (SE-09-3) or close after flow is isolates faulted SG-2B. auxiliary feedwater flow to SG-2B.

(MV-09-10) established Full flow established to SG-2A from AFW pumps 2A or 2C.

(SE-09-5) or One valve fails to No effect, redundant valve Valve status Indication CRI Flow control valves closed to isolate (MV-09-12) close after flow is isolates faulted SG-2B. auxiliary feedwater flow to SG-2B.

established Full flow established for SG-2A.

AFW pumps 2A or 2C.

Diesel Generator B Fails to start Loss of AFW pump 2B. Valves Motor status lights, CRI Steam turbine driven and 2A motor MV-09-10 and SE-09-3 do discharge line flow, or driven pumps available to supply feed-not operate. pressure indication. water to SG-2A. Valves MV-09-12 and SE-09-5 close and SE-09-3 fails closed to isolate feedwater flow to SG-2B.

Diesel Generator A Fails to start Loss of AFW pump 2A. Valves Motor status lights, CRI Steam turbine driven pump available MV-09-9 and SE-09-2 do discharge line flow, or to supply feedwater to SG-2A. Valves not operate. pressure indication. SE-09-03, SE-09-5, MV-09-10 and MV-09-12 close to isolate feedwater flow to SG-2B.

Failure of 125V dc Lost Motor driven pump B is un- Various loss of power CRI 2A motor driven pumps available.

B bus available (due to B diesel alarms valve controllers. Valves MV-09-10 and SE-09-3 close failure to start). Valves and SE-09-5 fails closed to isolate MV-08-13, MV-09-11, feedwater flow to SG-2B.

MV-09-10, SE-09-4, and SE-09-3 do not operate Failure of 125V dc Lost Motor driven pump A is un- Various loss of power CRI Steam turbine driven pump available.

A bus available (due to A diesel alarms, valve controllers. Valves MV-09-10 and SE-09-2 close failure to start). Valves and SE-09-5 fails closed to isolate MV-09-9, SE-09-2, feedwater flow to SG-2B.

MV-09-12, MV-08-12, and SE-09-5 do not operate.

1. To facilitate analysis, the feedwater or main steam line break is assumed to occur in the B system. Faulted steam generator is detected by low steam generator water level, low steam generator or feedwater header differential pressure. Validity of analysis is not changed if break is assumed for the A system.

2. CRI - Control Room Indication.

T10.4-17 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4-4 FAILURE MODES AND EFFECTS ANALYSIS - AUXILIARY FEEDWATER SYSTEM ASSUMING AN AUXILIARY FEEDWATER LINE BREAK(1) AND LOSS OF OFF SITE POWER Component Identification Failure Effect on Method of and Quantity Mode System Detection Monitor(2) Remarks Offsite Power Lost Main Feedwater flow is Various loss of power CRI Two full capacity motor driven pumps unavailable alarms powered from the emergency diesel generator sets are available to supply feedwater to either SG. System check valves isolate main feedwater lines from ruptured auxiliary feedwater line One of two motor Fails to start One motor driven pump is Motor status lights, CRI Alternate motor driven pump is avail-driven pumps unavailable discharge line flow or able to supply feedwater to associated pressure indication SG. System check valves isolate main feedwater lines from ruptured auxiliary feedwater line.

Flow control valve Fails to open Motor driven auxiliary Valve status indication CRI Motor driven pump 2B is available to (MV-09-9) or feed-water to steam and no motor driven pump supply feedwater to SG-2B. System (SE-09-2) generator 2A not available 2A discharge flow. check valves isolate main feedwater lines from ruptured auxiliary feed-water line.

Flow control valve Fails to open Motor driven auxiliary Valve status indication CRI Motor driven pump 2A is available to (MV-09-10) or feed-water flow to steam and no motor driven pump supply feedwater to SG-2A. System (SE-09-3) generator 2B is not available 2B discharge flow. check valves isolate main feedwater lines from ruptured auxiliary feed-water line.

Diesel Generator B Fails to start Loss of AFW pump 2B. Motor status lights, CRI Motor driven pump 2A is available to Valves MV-09-10 and discharge line flow, or supply feedwater to SG-2A. System SE-09-3 do not operate. pressure indication. check valves isolate main feedwater lines from ruptured auxiliary feed-water line.

Diesel Generator A Fails to start Loss of AFW pump 2A. Motor status lights, CRI Motor driven pump 2B is available to Valves MV-09-9 and discharge line flow or supply feedwater to SG-2B. System SE-09-2 do not operate. pressure indication. check valves isolate main feedwater lines from ruptured auxiliary feed-water line.

Failure of 125V dc Lost Motor driven pump B is Various loss of power CRI Motor driven pump 2A is available to B bus unavailable (due to B diesel alarms, valve controllers supply feedwater to SG-2B. System failure to start). Valves check valves isolate main feedwater MV-09-10, MV-09-11, lines from ruptured auxiliary feed-SE-09-3 and SE-09-4 water line.

do not operate.

T10.4-18 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4-4 (Cont'd)

Component Identification Failure Effect on Method of and Quantity Mode System Detection Monitor(2) Remarks Failure of 125V dc Lost Motor driven pump A is Various loss of power CRI Motor driven pump 2B is available to A bus unavailable (due to A diesel alarms, valves controllers supply feedwater to SG-2B. System failure to start). Valves check valves isolate main feedwater MV-09-12, SE-09-5, lines from ruptured auxiliary feedwater line MV-09-9, SE-09-2 do water line.

1. To facilitate analysis the worst case break of an AFW pump 2C discharge line break is assumed. Operator manually stops pump.

2. CRI - Control Room Indication T10.4-19 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4-5 AUXILIARY FEEDWATER SYSTEM INSTRUMENTATION Indication Alarm Normal (3)

Control Control Control Rm Control Instrument Operating Instrument(3)

System Parameter & Location Tag No. Local Room Room Recording Function Range Range Accuracy Condensate Storage Tank Level (1) LC-12-9

Regulates flow 33-44 ft LIS-12-10

from deminerali-LIS-12-11A

Low, Low-Low zed water system LIS-12-11B

Low to maintain min-LS-12-8 Low-Low, Hi, Low imum condensate tank level.

Auxiliary Feedwater Pumps

1. Steam pressure at turbine PI-08-5

985-50 psig inlet(2) PS-08-6

Low

2. Pumps suction pressure PI-12-18A, B, C

11.5 psig PS-12-17A, B, C

Low

3. Pump discharge pressure PI-09-8A, B, C

1200 psig PI-09-7A, B, C *

4. Pump discharge flow FI-09-2A

Flow is 320 gpm regulated FI-09-2B

from control rm 320 gpm FI-09-2C

500 gpm

5. Header A Flow FR-09-2A *

320 gpm Header B Flow FR-09-2B/2C *

320 gpm Header C Flow FR-09-2B/2C *

320 gpm Steam Generators

1. Level LIC-9013A,B,

C,D LIC-9023A,B,

C,D UR-09-2 *

2. Pressure PI-8013A,B,

985-50 psig C,D PI-8023A,B,

C,D UR-09-2

T10.4-20 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4-5 (Cont'd)

Indication Alarm Normal Control Control Control Rm Control Instrument(3) Operating Instrument(3)

System Parameter & Location Tag No. Local Room Room Recording Function Range Range Accuracy Feedwater Header

1. Pressure PT-09-9A, Isolates ruptured 1050 psig B,C,D feedwater header 1050 psig PT-09-10A, via AFAS logic.

B,C,D (1) Low-low, high and low level alarms are provided in control room; high and low level alarms provided on water treatment panel.

(2) For turbine driven pump only.

(3) Instrument ranges are selected in accordance with standard engineering practices. Instrument accuracies are selected such that existing instrument loop performance and safety analysis assumptions remain valid. Where applicable, instrument accuracies are also evaluated for their impact on setpoints in accordance with the FPL Setpoint Methodology.

T10.4-21 Amendment No. 24 (09/17)

Referto Drawing 2998-G-663SH 1 FLORIDAPOWER & LIGHTCOMPANY ST. LUCIE PLANT UNIT 2 CIRCULATING WATERSYSTEM OCEANINTAKEAND DISCHARGE SHT. 1 FIGURE 10.4-1 Amendment No. 18 (01/08)

Referto Drawing 2998-G-663SH 2 FLORIDAPOWER & LIGHTCOMPANY ST. LUCIE PLANT UNIT 2 OCEAN INTAKE AND DISCHARGESYS SH. 2 FIGURE 10.4-2 Amendment No. 18 (01/08)

Referto Drawing 2998-G-663SH 3 FLORIDAPOWER & LIGHTCOMPANY ST. LUCIE PLANT UNIT 2 OCEAN INTAKE AND DISCHARGESYS SH. 3 FIGURE 10.4-3 Amendment No. 18 (01/08)

Referto Drawing 2998-G-663SH 4 FLORIDAPOWER & LIGHTCOMPANY ST. LUCIE PLANT UNIT 2 OCEAN INTAKE AND DISCHARGESYS SH. 4 FIGURE 10.4-4 Amendment No. 18 (01/08)

Referto Dwg.

3509-G-115SH 1A & 1 B Amendment No. 12, (12/98)

FLORIDAPOWER & LIGHTCOMPANY ST. LUCIE PLANT UNIT 2 FLOWDIAGRAM-STEAMGENERATORSLOWDOWN PROCESSSYSTEM SHEET1A & 18 FIGURE 10.4-5

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3509-G-115SH 2 Amendment No. 12, (12/98)

FLORIDAPOWER & LIGHTCOMPANY ST. LUCIE PLANT UNIT 2 FLOWDIAGRAM-STEAMGENERATORSLOWDOWN PROCESSSYSTEM SHEET2 FIGURE 10.4-6

DELETED FLORIDAPOWER & LIGHTCOMPANY ST. LUCIE PLANT UNIT 2 FIGURE 10.4-7 Amendment No. 18 (01/08)

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Referto Drawing 2998-G-149SH 2 FLORIDAPOWER & LIGHTCOMPANY ST. LUCIE PLANT UNIT 2 MAINSTEAM& FEEDWATERPIPING-SECT & DETAILS FIGURE 10.4-16 Amendment No. 18 (01/08)

DELETED FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 2 FIGURE 10.4-17 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 APPENDIX 10.4.9A AUXILIARY FEEDWATER SYSTEM REQUIREMENTS EVALUATION 10.4.9A-1 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 10.4.9A AUXILIARY FEEDWATER SYSTEM An evaluation of the St. Lucie Unit 2 (SL-2) Auxiliary Feedwater System has been finalized and compared with the NRC's requirement basis provided to all operating license applicants (letter from D. F. Ross, NRC, to all pending operating license applicants of NSSS designed by Westinghouse and Combustion Engineering dated March 10, 1980). The technical evaluation is provided in the following sections:

a) Section 10.4.9A.1 - Basis for AFS Flow Requirements b) Table 10.4.9A-1 - Comparison of AFS with NRC Flow Requirements c) Table 10.4.9A-2 - SL-2 AFS Comparison with SRP 10.4.9 (Rev 1) d) Table 10.4.9A-3 - SL-2 AFS Comparison with BTP ASP 10-1 (Rev 1) e) Table 10.4.9A-4 - Evaluation of SL-2 AFS vs NRC Short and Long Term Requirements f) Appendix 10.4.9B - AFS Reliability Report 10.4.9A.1 Basis for Auxiliary Feedwater System Flow Requirements The design bases for the Auxiliary Feedwater System flow rate is to supply sufficient cooling water to either one or both steam generators to ensure the following:

a. Provide sufficient capability for removal of decay heat from the reactor core

b. Reduce the RCS temperature to entry temperatures for activating the shutdown cooling system

c. Prevent lifting of the pressurizer safety valves when considered in conjunction with the PORVs 10.4.9A.2 System Sizing Criteria Minimum system flow rate requirements corresponding to the AFWS design functions have been determined based on worst case plant heat loads.

Best estimate transient analyses of the Loss of Main Feedwater (LOMF) and Feedwater Line Break (FLB) events were performed to demonstrate the acceptable performance of the Auxiliary Feedwater (AFW) system. Both events were analyzed to meet the intent of NUREG-0737 and SRP 10.4.9 which require the demonstration of adequate AFW system performance not only for the LOMF event but under any postulated accident scenario. In the case of St. Lucie Unit 2, the EC292636 LOMF is the limiting event in terms of reactor coolant system decay heat removal by the AFW system. By analyzing both events, it demonstrated the acceptability of the AFW system EC292636 performance and the adequacy of the Reactor Coolant System (RCS) response for a low probability transient (FLB) and for a higher probability event (LOMF). Each event was analyzed with and without offsite power available to ensure the limiting conditions were evaluated for both AFW system performance and RCS response.

The results of the analyses demonstrate that the performance of the AFW system at St. Lucie Unit 2 is adequate in maintaining at least one steam generator as a heat sink for the LOMF and FLB transients, both with and without offsite power available. The LOMF event was analyzed assuming a single active failure of the turbine driven AFW pump. The turbine driven pump is the highest capacity pump in the AFW system and the inability to credit this pump results in the 10.4.9A-2 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 lowest AFW flow rate to the steam generators for the LOMF event. The 2A and 2B motor driven AFW pumps were available to supply condensate storage tank water to the 2A and 2B steam generators, respectively. The analysis concludes the AFW system is capable of maintaining a secondary system heat sink for the LOMF event.

The FLB event was analyzed assuming a single active failure of the turbine driven AFW pump, and a 1.23 ft2 non-isolable break between the 2A steam generator and the feedwater line check valve. Under this scenario, only the 2B motor driven pump is available to supply water to the 2B steam generator.

The event results in the lowest capacity AFW pump supplying water to the intact steam generator for heat removal. The analysis concludes that one motor driven pump with a capacity of 275 gpm at 1000 psia steam generator pressure is capable of maintaining one steam generator as an adequate heat sink.

EC292636 The analyses were performed using a constant AFW flow rate and a maximum Auxiliary Feedwater Actuation Signal (AFAS) logic time delay of 330 seconds.

The following sections provide the results of the LOMF and FLB analyses:

Loss of Main Feedwater With Offsite Power Available The sequence of events for this transient is provided in Table 10.4.9A-5. For this event, the AFW system performance is adequate to maintain each steam generator as a heat sink.

Following reactor trip on low SG level, the Power Operated Relief Valves (PORVs) actuate. The EC292636 Main Steam Safety Valves (MSSVs) open to relieve high pressure in the steam generators. The steam bypass control system automatically removes steam and regulates steam generator pressure at 900 psia thereby controlling both secondary and primary system temperatures. The pressurizer level and pressure control systems automatically controlled variations in those EC292636 parameters. A secondary system heat sink was maintained throughout the transient in each steam generator. The results of the analysis indicate that the AFW system performance was adequate. This event is the limiting case with respect to LOMF events and steam generator liquid inventory. Figure 10.4.9A-1 provides the hot leg subcooling margin as a function of time. EC292636 Since the maximum pressurizer water volume is less than the total pressurizer volume and subcooling margin is maintained for the LOMF event, the analysis examined herein demonstrates that the auxiliary feedwater system is sufficiently sized to remove the decay heat and pump heat of the system.

Loss of Main Feedwater Without Offsite Power Available The analysis of this event is similar to the case with offsite power available with the following exceptions. Subsequent to the turbine trip, offsite power is unavailable resulting in the tripping of the Reactor Coolant Pumps (RCPS) and the loss of automatic control systems.

EC292636 Following reactor trip, the MSSVs remove steam and control steam generator pressure at approximately 1030 psia. Natural circulation was established and a secondary heat sink was maintained in each steam generator. The liquid inventories are greater than in the previous case due to the natural circulation condition. This condition resulted in reduced secondary inventory vaporization due the decreased primary to secondary heat transfer, due to the increased primary system average temperature, and due to the lack of RCP heat input. Although 10.4.9A-3 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 automatic control systems are unavailable, the Power Operated Relief Valves (PORVS) opened EC292636 briefly to discharge steam to control pressurizer pressure early into the transient.

The auxiliary feedwater system performance was adequate to remove decay heat and to initiate restoration of steam generator level while the primary system response was well controlled for the natural circulation conditions.

EC292636 The sequence of events for this transient is provided in Table 10.4.9A-6 and Figure 10.4.9A-2 provides the hot leg subcooling margin as a function of time.

Feedwater Line Break With Offsite Power Available The sequence of events for this transient is provided in Table 10.4.9A-7. The FLB is a severe transient of very low frequency. Although this transient was severe, the AFW system performance was adequate to maintain a secondary system heat sink and the RCS responded in a controlled manner.

At the start of the transient, main feedwater was instantaneously lost. The break was assumed to discharge saturated liquid when the steam generator downcomer level was above the feedline nozzle. As the nozzle uncovers, two phase discharge was assumed with the quality increasing until it becomes saturated steam when the downcomer level falls below the feed nozzle. Eventually, the affected steam generator dries out and only steam from the intact steam generator was discharged. A Main Steam Isolation Signal (MSIS) was generated on low pressure closing the Main Steam Isolation Valves (MSIVs) of both steam generators causing the steam bypass valves to be unavailable. This resulted in the intact steam generator repressurizing to the MSSV setpoint causing the primary system to heatup and repressurize as EC292636 the affected steam generator dried out. Operator action is assumed at 20 minutes to manually trip the RCPs.

The initial RCS cooldown and the resulting contraction caused the pressurizer level to decrease.

The maximum pressurizer water volume calculated (1519ft3) is less than the total pressurizer EC292636 volume of 1520 ft3. No liquid inventory is released. The combination of the additional heat load (due to the EPU) and the delayed AFW initiation causes an increased pressurizer volume during the long term portion of the event and a lower unfaulted SG inventory. However, AFW is received by the unfaulted generator in enough time such that the inventory is maintained and pressurizer overfill is precluded.

The AFW flow, together with a slow depletion of steam generator liquid inventory, is adequately sized to remove decay heat and to maintain stable primary system conditions. Maintaining EC292636 sufficient water mass in the unfaulted generator ensures that a secondary side heat sink remains available throughout the event. The results of the analysis indicate AFW system performance is sufficient to maintain a secondary system heat sink and that the primary system response is adequate to maintain RCS subcooling. This event is the limiting case with respect to FLB events and steam generator liquid inventory. Figures 10.4.9A-3 through 10.4.9A-6 provide EC292636 steam generator liquid inventories, pressurizer liquid volume, pressurizer pressure and hot leg subcooling margin as a function of time. The sequence of events for this transient is provided in Table 10.4.9A-7.

EC292636 10.4.9A-4 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 Feedwater Line Break Without Offsite Power Available This case is similar to the above case except following the turbine trip offsite power is unavailable. The loss of offsite power resulted in the tripping of the RCPs and the unavailability of automatic control systems. Following the trip of the RCPs, natural circulation was established.

The lower primary system flow resulted in decreased primary to secondary system heat transfer and higher average RCS temperatures.

As in the previous case, the primary system initially heats up and pressurizes with a resultant EC292636 increase in pressurizer level. The minimum pressurizer level is higher than the previous case due to the higher RCS temperatures associated with natural circulation. Following the dryout of the affected steam generator (SG 1) and the re-pressurization of the intact steam generator (SG 2), the primary system heats up and pressurizes a second time. Since the pressurizer level and pressure control systems are unavailable, the PORVs cycle to control primary system EC292636 pressure. The pressurizer liquid volume rises to a maximum of about 1416 ft3 during the primary system heatup and re-pressurization.

EC292636 A secondary heat sink is maintained throughout the transient. The results of the analysis indicate that the AFW system performance is adequate to maintain a secondary heat sink and that the primary system response is sufficient to maintain RCS subcooling. Figures 10.4.9A-7 EC292636 through 10.4.9A-10 provide steam generator liquid inventories, pressurizer liquid volume, pressurizer pressure and hot leg subcooling margin as a function of time. The sequence of events for this transient is provided in Table 10.4.9A-8.

EC292636 The initial conditions assumed for the LOMF and FLB events are provided in Table 10.4.9A-9.

The limiting design basis event has been determined to be 75°F/hr plant analyzed cooldown rate. Under this event, 275 gpm is initially required to be delivered to one steam generator in order to maintain the steam generator inventory.

10.4.9A-5 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 TABLE 10.4.9A-1 COMPARISON OF AFS SYSTEMS WITH NRC SYSTEM FLOW REQUIREMENTS As a result of recent staff operating plant Auxiliary Feedwater Systems (AFWS), the staff concluded that the design bases and criteria pro-vided by licenses for establishing AFWS requirements for flow to the steam generator(s) to assure adequate removal of reactor decay heat are not well defined or documented. The following is a comparison of the SL-2 AFS vs.

the staff's flow requirements:

1. a. Identify the plant transient and accident conditions considered in 1. a. The design bases for the Auxiliary Feedwater System (AFS) are establishing AFWS flow requirements, including the following events: described in Subsection 10.4.9. The adequacy of the AFS during transient and accident conditions is shown in Chapter 15, for each event where AFS is required to function.

1. Loss of Main Feedwater (LMFW) 1. Although not a limiting design base event, a LMFW group is described in the Infrequent Category of the Decrease in Heat Removal by the Secondary System.

No event in this LMFW event group is as severe as the Loss of Condenser Vacuum with Fast Transfer Failure event. Section 15.2 shows the required flow rates to be adequate assuming manual initiation. This analysis is more conservative than consideration of automatic initiation.

2. LMFW With Loss of Offsite AC Power 2. For this event the required flow rate is less than that for the LMFW event since the reactor trip is not delayed until secondary inventory is decreased to the low level setpoint.

3. LMFW With Loss of Onsite and Offsite AC Power 3. For this event the required flow rate is identical to that required for LMFW with a loss of offsite power. In the remote case of failure of both onsite and offsite AC power, the required flow is then delivered by the turbine driven AFW pump.

4. Plant Cooldown 4. As a limiting design base event, each AFW pump (1 turbine pump or 1 motor pump) has sufficient capacity to maintain the plant in a hot standby condition for two hours followed by an orderly cooldown to the shutdown cooling window within the next five hours.

5. Turbine Trip With and Without Bypass 5. Although not a limiting design base event for determining AFW pump capacity, the adequacy of AFW flow for turbine trip without bypass is shown for a more limiting event in Section 15.2. A turbine trip with the steam bypass system available will not result in actuation of the AFWS.

6. Main Steam Isolation Valve Closure. 6. This transient is similar to and produces effects no more adverse than the Loss of Condenser Vacuum discussed in Item 1.a.1 above.

T10.4.9A-1 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 TABLE 10.4.9A-1 (Cont'd)

1. a. 7. Main Feedline Break (MFLB) 1. a. 7. The MFLB is a limiting design base event for the Auxiliary Feedwater System. When considered in conjunction with the single failure of the turbine driven pump only the motor driven pump associated with the intact steam generator is available without operator action. Figures 10.4.9A-3 through 10.4.9A-10 show that one motor driven pump with a capacity of 275 gpm will maintain the steam generator as an adequate heat sink based upon the best estimate transient analyses provided in Section 10.4.9A.2.

8. Main Steam Line Break 8. The Main Steam Line Break (MSLB) accidents are analyzed in Section 15.1.The rapid depressurization of the affected steam generator results in the actuation of a Main Steam Isolation Signal (MSIS). This MSIS results in closure of the Main Steam Isolation Valves and the Main Feedwater Isolation Valves, isolates the unaffected steam generator from blowdown, and effectively assures the unaffected steam generator's capability as a heat sink. The UFSAR analyses show manual operation of AFWS to the intact Steam Generator at greater than 600 seconds after the initiating event to be adequate. With respect to heat removal, that analysis is more conservative than consideration of automatic initiation.

9. Small Break LOCA 9. This transient produces effects no more adverse on the secondary than the LMFW trip event, since primary energy inventory is partly released through the break and reactor occurs prior to a steam generator low level condition.

10. Other Transient or Accidents Not Listed Above 10. a. Plant Startup AFW flow requirement is less than that required for plant cooldown.

b. Hot Standby and Hot Shutdown.

Although not a design base event for determining AFW pump capacity, the AFW system is placed in operation to maintain steam generator water level. Pump flow requirement is less than that required for plant cooldown

1. b. Describe the plant protection acceptance criteria and 1. b.

corresponding technical bases used for each initiating event identified above. The acceptance criteria should address the following plant limits:

1. RCS Pressure 1. The Reactor Coolant Pressure Boundary (RCPB) is designed to accommodate the system pressures and temperatures attained under all expected modes of unit operation, including all anticipated transients, and to maintain the stresses within applicable limits. The design meets the requirements of the ASME Code,Section III, Division 1. The following specific criteria evolve from the ASME Code requirements.

T10.4.9A-2 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 TABLE 10.4.9A-1 (Cont'd)

1. b. 1. RCS Pressure (Cont'd) 1. b. 1. (Cont'd)

Level B - Upset Condition - the maximum stress will not exceed 110% of the design value.

Level C - Emergency Condition - the maximum stress will not ex-ceed 120% of the design value.

For the events discussed in 1.a, above, in all cases except the Main Feed Line Break the maximum RCS pressure result in stresses below the level B limit.

2. Fuel Temperature of Damage Limits 2. Response to item 1.a has shown that adequate system cooling is provided by the AFWS.

Therefore, the fuel temperature or damage limits as described in Chapter 15 are not approached.

3. RCS Cooling Rate 3. The RCS is designed to withstand the cyclic loads generated by the pressure and temperature transients of normal startup and shut-down.

The AFWS assessment performed here is based on assumed maximum loads to ensure the ability of the AFWS to maintain cooling. An analysis concerning excessive primary shrinkage would entail assumptions of minimum heat loads which are not germane to sizing the AFWS. The operator will adjust the AFW flow rate, as required, to match the heat load.

4. Steam Generator Water Level 4. Steam generator water level is not an explicit acceptance criterion of the UFSAR analyses.

However, analyses shows the sufficient steam generator water level is maintained in either or both steam generator(s) until the RCS temperature is reduced to the shutdown cooling, initiation threshold. At inventories less than 30,000 lbm some increase in primary temperatures will occur due to the reduced heat transfer area.

2. Describe the analyses and assumptions and corresponding technical 2.

justification used with plant conditions considered in 1.a. above including:

a. Maximum reactor power (including instrument error allowance) a. The reactor power, including instrument error, at the time of the initiating event is at the time of the initiating transient or accident. conservatively assumed to be 3030 MWt, with uncertainty.

b. The delay from initiating event to reactor trip. b. The time delay from the initiating event to the reactor trip for the MFLB is 18.50 seconds for Low Tavg with AC Power case and 18.50 seconds for Low Tavg with LOOP case.

T10.4.9A-3 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 TABLE 10.4.9A-1 (Con't)

c. Plant parameter(s) which initiates AFWS flow and time delay c. For the current plant design, AFWS time delay is initiated on low between initiating event and introduction of AFWS into steam steam generator level signal. If level is not restored above the generator(s). actuation bistable (first) reset when the time delay expires, the AFWS actuates to restore steam generator level. AFW flow is assumed to reach the steam generator within 420 seconds after the AFWS is actuated.

d. Minimum steam generator water and when initiating event occurs. d. The minimum water level in the unfaulted SG does not reach a dry-out condition for all cases.

2. e. Initial steam generator water inventory and depletion rate before 2. e. For the MFLB event, the initial inventory and depletion rates are and after AFWS flow commences - identify reactor decay heat rate immaterial since the water level must reach the low level setpoint used. prior to the reactor trip occurring. Once the AFW flow reaches the steam generator(s), sufficient AFW pump capacity exists to remove decay heat and maintain an appropriate steam generator water level assuming decay heat for a full-power history.

f. Maximum pressure at which steam is released from generator(s) f. The maximum steady state steam generator pressure expected is against which the AFW pump must develop sufficient head. 1000 psia.

g. Minimum number of steam generators that must receive AFW flow; g. Only one steam generator is required to remove sensible and decay e.g. 1 out of 2? heat during all operational transients and accidents.

h. RC flow condition - continued operation of RC pumps or natural h. For the case with AC power available, all RCPs are assumed to be circulation. manually tripped at 15 minutes into the event. For the case with the LOOP, the RCP trip occurs as a result of the LOOP following reactor trip.

i. Maximum AFW inlet temperature. i. 120F

j. Following a postulated steam or feedline break, time delay j. For postulated steam line breaks an early reactor trip and MSIS assumed to isolate break and direct AFW flow to intact steam occurs on low steam generator pressure. This minimizes the time to generator(s). AFW pump flow capacity allowance to accommodate isolate the break. The ensuing pressure difference between steam the time delay and maintain minimum steam generator level. Also generators will isolate the AFW from the break and direct it to the identify credit taken from primary system heat removal due to unaffected steam generator when actuated.

blowdown.

For feedline breaks the reactor trip and AFAS occur early on low level due to two-phase flow out of the break. This minimizes time before delivery of AFW flows. The absence of a pressure differential until the low pressure setpoint is reached means that AFW flow is delivered to both steam generators, preserving the heat sink. When the low pressure setpoint is reached all AFW flow will be delivered to the unaffected steam generator.

k. Volume and maximum temperature of water in main feedlines between k. The initial main feedwater temperature is assumed to be 441.0oF. For steam generator(s) and AFWS connection to main feedline. the MFLB case main feedwater is assumed to be unavailable to both steam generators. When AFW flow is assumed to enter the steam generator, no credit is taken for the volume of feedwater than would normally be available ln the feedline between the steam generator and the AFW system connection.

T10.4.9A-4 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 TABLE 10.4.9A-1 (Cont'd)

l. Operating condition of steam generator normal blowdown l. There is a constant SG blowdown flowrate of 120 gpm/SG following initiating event. following initiating event.

m. Primary and secondary system water and metal sensible heat used m. 1,309,000 BTU/oF for cooldown and AFW flow sizing.

n. Time of hot standby and time to cooldown RCS to RHR system cut n. The condensate storage tank water volume of 307,000 gal is adequate in temperature to size AFW water source inventory. to ensure plant sensible heat removal in addition to 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months of decay heat removal.

Assuming a maximum cooldown time of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , this allow for four hours at hot standby. (See Table 10.4-2).

3. Verify that the AFW pumps in your plant will supply the necessary 3. The AFW system calculations performed to determine the total delivered flow to the steam generator(s) as determined by items 1 and 2 above flow have utilized conservative assumptions to account for pump recircu-considering a single failure. Identify the margin in sizing the lation flow, seal leakage and any future pump wear. Conservative piping pump flow to allow for pump recirculation flow, seal leakage and resistances were used in order to maximize the total system head loss.

pump wear. Also, no credit was taken for the positive effects of the fluid height of water in the condensate. The final system calculations, utilizing the conservatisms outlined above, predict a total margin of approximately 6% (see note 1) above the required flow, which is adequate to account for any future pump wear.

Note 1: The 2B AFW pump was identified as performing below the manufacturer pump curves during initial startup testing. As a result, the field data taken was used to re-analyze the AFW system for the degraded condition. The results, as presented in Appendix A to calculation NSSS-014, demonstrated the continued acceptability of the pump prior to initial plant operation. However, the analysis shows that only 2.7% margin remained for future pump degradation for motor driven AFW pump 2B.

AFW pumps 2A and 2C retained the original design margin of 6.5% prior to initial plant operation.

0738W-1 T10.4.9A-5 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 TABLE 10.4.9A-2 DOCUMENT: SRP 10.4.9 (REV. 1) AUXILIARY FEEDWATER SYSTEM (AFWS) Sheet 1 of 5 ACCEPTANCE CRITERIA COMPLIANCE ALTERNATE COMPLIANCE REMARKS Acceptability of the design of the auxiliary feed- The Unit 2 Auxiliary Feedwater water system, as described in the applicants System (AFWS) is designed to pro-safety analysis report (SAR), is based on specific vide for automatic initiation.

general design criteria and regulatory guides. The following is a review of the Listed below are the specific criteria as they AFWS which describes how the sys-relate to the AFS. tem meets SRP 10.4.9 and BTP ASB 10-1.

1. General Design Criterion 2, as related to 1. The Auxiliary Feedwater System, structures housing the system and the system including the instrumentation itself being capable of withstanding the and controls are designated effects of natural phenomena such as earth- seismic Category I, designed quakes, tornadoes, hurricanes and floods. to withstand tornadoes and hurricanes and are located at an elevation above the proba-ble maximum flood level. See Subsection 10.4.9.

2. General Design Criterion 4, with respect to 2. The AFWS is located in the structures housing the system and the system protected areas of the main-itself being capable of withstanding the steam trestles. Tornado effects of external missiles and internally shielding is provided to generated missiles, pipe whip, and jet completely enclose the AFWS, impingement forces associated with pipe protecting it from all postu-breaks. lated tornado missiles. High energy lines are restrained to protect the AFWS from pipe whip and jet impingement effects.

3. General Design Criterion 5, as related to the 3. The Unit 2 AFWS has no struc-capability of shared systems and components tures, systems or components important to safety to perform required safety important to safety which are functions. shared with Unit 1. However, a Condition of License for Unit 1 included a commitment to provide an intertie with the Unit 2 Condensate Storage Tank (CST). Thus, the only "shared" component in the AFWS is the Unit 2 CST (capacity 400,000 gallons).

A connection from the Unit 2 CST is provided to the suction 0738W-2 T10.4.9A-6 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 TABLE 10.4.9A-2 (Cont'd)

DOCUMENT: SRP 10.4.9 (REV. 1) (Cont'd) Sheet 2 of 5 ACCEPTANCE CRITERIA COMPLIANCE ALTERNATE COMPLIANCE REMARKS

3. (Cont'd) of the Unit 1 AFWS pumps for the unlikely event that a tornado missile penetrates the top of the Unit 1 CST and destroys that source of water.

4. General Design Criterion 19, as related to 4. Adequate instrumentation and 4. The AFWS is designed such the design capability of system instru- controls are provided to as- that an Automatic Feedwater mentation and controls for prompt hot shut- sure the plant is brought to Actuation Signal (AFAS-1 and down of the reactor and potential capability a hot standby condition and AFAS-2) automatically starts for subsequent cold shutdown. subsequent cold shutdown dur- all three AFWS pumps and opens ing both normal operation and the valves for both trains to under accident conditions, in- both SG(s). In the event of a cluding a LOCA. The control Main Feedwater line rupture, of AFWS flow and SG level is or an AFWS line break, the accomplished by control room AFAS will automatically iso-operated valves; however, late the affected SG and will local control stations are automatically feed to the in-also provided. Instrumenta- tact SG(s).

tion is also provided at the The operator has the capability remote Hot Shutdown Panel, as to control AFW valves MV-09-9, indicated at Section 7.4 10,11,12 prior to AFAS. The which provided capability for operator can manually control a prompt hot shutdown and these valves after an AFAS capability for a subsequent has been initiated and the cold shutdown using appro- valves reach their fully priate procedures. opened position.

5. General Design Criterion 44, to assure: 5a. During normal operation, the the AFWS provides a water

a. The capability to transfer heat loads inventory to the SGs for from the reactor system to a heat sink removal of decay and sensible under both normal operating and accident heat to the Steam Dump and conditions. Bypass System (SDBS). Under accident conditions heat removal is via the Atmospheric Dump Valves (ADV). Two dc powered ADVs are provided on each steam generator for heat removal purposes.

T10.4.9A-7 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 TABLE 10.4.9A-2 (Cont'd)

DOCUMENT: SRP 10.4.9 (REV. 1) (Cont'd) Sheet 3 of 5 ACCEPTANCE CRITERIA COMPLIANCE ALTERNATE COMPLIANCE REMARKS

b. Redundancy of components so that under 5b. The AFWS is designated as accident conditions the safety function seismic Category I, Safety can be performed assuming a single active Class 3 and capable of with-component failure. (This may be coincident standing a single active with the loss of offsite power for certain component failure. A failure events.) mode and effects analysis of the AFWS, including a high energy line break with loss of offsite power, is provided in Tables 10.4-3 and 10.4-4.

c. The capability to isolate components, sub- 5c. Sufficient remote-manual fea-systems, or piping if required so that the tures are provided to permit system safety function will be maintained. isolation of failed components and maintain AFW flow to the steam generators. The AFAS logic will detect a rupture in a MFW line or AFWS line and automatically isolate that line so that AFW flow is maintained to the intact steam generator(s).

6. General Design Criterion 45, as related to 6. Design provisions are provided design provisions made to permit periodic to assure periodic ISI of the inservice inspection of system components system as required. Removable and equipment. insulation is provided on com-ponent welds which require examination. Access ports or temporary scaffolding is provided for examination of required welds.

7. General Design Criterion 46, as related to 7. Design provisions are provided design provisions made to permit appropriate to assure that the Auxiliary functional testing of the systems and compon- Feedwater System can be tested.

ents to assure structural integrity and leak- Each pump is provided with a tightness, operability and performance of recirculation line permitting active components, and capability of the in- verification of pump operability.

tegrated systems to function as intended Pressure and flow indi-during normal, shutdown, and accident condi- cators are provided for moni-tions. toring system performance.

All active components can be remotely operated using indi-cation instrumentation to verify component functionality.

T10.4.9A-8 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 TABLE 10.4.9A-2 (Cont'd)

DOCUMENT: SRP 10.4.9 (REV. 1) (Cont'd) Sheet 4 of 5 ACCEPTANCE CRITERIA COMPLIANCE ALTERNATE COMPLIANCE REMARKS

8. Regulatory Guide 1.26, as related to the 8. The AFWS is designed Quality quality group classification of system Group C in accordance with components. R. G. 1.26. Those portions of AFWS connected to the Main Feedwater line are QG B to the isolation valve(s).

9. Regulatory Guide 1.29, as related to the 9. The AFWS is designated seismic seismic design classification of system Category I in accordance with components. R.G. 1.29.

10. Regulatory Guide 1.62, as related to design 10. The AFWS complies with the provisions made for manual initiation of requirements of Regulatory each protective action. Guide 1.62. The operator may manually initiate the Auto-matic Feedwater Acutation Signal (AFAS) from the con-trol room. Manual initiation ensures that protective action goes to completion.

11. Regulatory Guide 1.102, as related to struc- 11. All AFWS components are locat-tures, systems, and components important to ed above the maximum probable safety from the effects of flooding. flood level.

12. Regulatory Guide 1.117, as related to the 12. The AFWS is located within protection of structures, systems and com- the barrier of the main steam ponents important to safety from the effects trestle which is completely of tornado missiles. protected from the effects of tornado missiles. The conden-sate storage tank is enclosed in a structure which protects the tank from tornado missiles.

13. Branch Technical Positions ASB 3-1 and MEB 13. The AFWS is classified as a 3-1, as related to breaks in high and moder- high energy system and is ate energy piping systems outside containment. protected from the dynamic effects of pipe rupture and jet impingement.

T10.4.9A-9 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 TABLE 10.4.9A-2 (Cont'd)

Sheet 5 of 5 ACCEPTANCE CRITERIA COMPLIANCE ALTERNATE COMPLIANCE REMARKS

14. Branch Technical Position ASB 10-1, as 14. The AFWS consists of three related to auxiliary feedwater pump drive Independent subsystems. Two and power supply diversity. motor driven pumps are pro-vided, each powered from an independent source of ac power. One turbine driven pump is provided which is wholly independent of ac power and fails safe (attains full speed operation) on loss of dc power to the dc powered throttle valve.

T10.4.9A-10 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 TABLE 10.4.9A-3 DESIGN GUIDELINES FOR AFWS PUMP DRIVE AND POWER SUPPLY DIVERSITY FOR PWRS BRANCH TECHNICAL POSITION COMPLIANCE ALTERNATE COMPLIANCE REMARKS

1. The auxiliary feedwater system should con- 1. The Auxiliary Feedwater System sist of at least two full-capacity, inde- (AFWS) consists of two full pendent systems that include diverse capacity motor-operated pumps power sources. in one system and another redun-dant greater than full capacity turbine driven pump in the other system. One system is ac powered and the other is steam/dc power.

2. Other powered components of the auxiliary 2. The motor driven systems (pumps, feedwater system should also use the con- valves) are powered by independent cept of separate and multiple sources of ac systems whereas the turbine motive energy. An example of the re- driven system (pumps, valves) will quired diversity would be two separate be wholly powered by the dc auxiliary feedwater trains, each capa- system and steam. Each train pro-ble of removing the afterheat load of vides sufficient capability of the reactor system, having one sepa- cooling the RCS to the temperature rate train powered from either of two and pressure required for initia-ac sources and the other train wholly tion of shutdown cooling.

powered by steam and dc electric power.

3. The piping arrangement, both intake 3. The piping arrangement, both in- 3. Power diversity is ar-and discharge, for each train should take and discharge, permits feed- ranged such that motor-be designed to permit the pumps to water to any combination of SGs. driven AFWS train "A" supply feedwater to any combination No single active failure and/or is powered by ac safety of steam generators. This arrange- any high energy line failure bus "SA" which is auto-ment should take into account pipe can prevent the AFWS from auto- matically loaded on failure, active component failure, matically delivering flow to diesel generator 2A; power supply failure, or control either steam generator. the similar train "B" system failure that could prevent is on bus "SB" and system function. One arrangement loaded on DG 2B. The that would be acceptable is cross- turbine-driven pump over piping containing valves that control circuits and can be operated by remote control flow control valves are from the control room, using the powered from 125VDC busses.

power diversity principle for the valve operators and actuation sys-tems.

T10.4.9A-11 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 TABLE 10.4.9A-3 (Cont'd)

DOCUMENT: BTP ASB 10-1 (REV. 1) (Cont'd)

BRANCH TECHNICAL POSITION COMPLIANCE ALTERNATE COMPLIANCE REMARKS

4. The Auxiliary Feedwater System should 4. The AFWS is designed such that no be designed with suitable redundancy single active failure can prevent to offset the consequences of any the AFWS from automatically deliv-single active component failure, how- ering flow to either steam genera-ever, each train need not contain re- tor.

dundant active components.

5. When considering a high energy line 5. No high energy line break (with break, the system should be so ar- loss of offsite power) in conjunc-ranged as to assure the capability tion with any single active fail-to supply necessary emergency feed- ure can prevent the AFWS from water to the steam generators, de- automatically delivering flow to spite the postulated rupture of the intact steam generator. The any high energy section of the sys- AFWS piping is arranged such that tem, assuming a concurrent single a full capacity motor driven pump active failure. can feed its respective steam generator. In addition, one tur-bine driven pump and cross-connect piping is provided to feed both steam generators.

T10.4.9A-12 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 TABLE 10.4.9A-4 EVALUATION OF THE SL 2 AUXILIARY FEEDWATER SYSTEM VERSUS THE NRC AFW SHORT AND LONG TERM RECOMMENDATIONS A. Short Term Recommendations ACCEPTANCE CRITERIA COMPLIANCE

1) 5.2.1 Technical Specification Time Limit on AFW System Train Outage Concern - Several of the plants reviewed have Technical Specifications that permit one of the AFW system trains to be out of service for an indefinite time period.

Indefinite outage of one train reduces the defense-in-depth provided by multiple AFW system trains.

Recommendation GS The licensee should propose modifica- The Auxiliary Feedwater System tions to the Technical Specifications to limit the time that limiting conditions for opera-one AFW system pump and its associated flow train and essential tion and surveillance require-instrumentation can be inoperable. The outage time limit and ments will be that an inoperable subsequent action time should be as required in current AFS train be restored to operable Standard Technical Specifications; i.e., 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , respec- status in 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or be in hot tively. shutdown within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

This is in accordance with current

2) 5.2.2 Technical Specification Administrative standard Technical Specifications.

Controls on Manual Valves - Lock and Verify Position Concern - Several of the plants reviewed use a single manual valve or multiple valves in series in the common suction piping between the primary water source and the AFW system pump suction. At some plants the valves are locked open, while at others, they are not locked in position. If the valves are inadvertently left closed, the AFW system would be inoperable, because the water supply to the pumps would be isolated. Since there is no remote valve position in-dication for these valves, the operator has no immediate means of determining valve position.

Further, the Technical Specifications for plants with locked-open manual do not require periodic inspection to verify that T10.4.9A-13 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 TABLE 10.4.9A-4 (Cont'd)

ACCEPTANCE CRITERIA COMPLIANCE the valves are locked in the correct position. For most Not applicable. The Auxiliary plants where the valves are not locked open, valve position Feedwater System has redundant, is verified on some periodic basis. parallel flow paths (piping and valves) such that there is no Recommendation GS The licensee should lock open single single valve which if left closed, valves or multiple valves in series in the AFW pump suction could interrupt all flow.

piping and lock open other single valves or multiple valves in series that could interrupt all AFW flow. Monthly in- All manually operated valves in spections should be performed to verify that these are locat- AFS suction are locked open.

ed in the open position. These inspections should be pro-posed for incorporation into the surveillance requirements of the plant Technical Specifications. See Recommendation GL-2 for the longer-term resolution of this concern.

3) 5.2.3 AFW System Flow Throttling-Water Hammer Concern - Several of the plants reviewed apparently throttle down the AFW system initial flow to eliminate or reduce the potential for water hammer. In such cases, the overall re-liability of the AFW system can be adversely affected.

Recommendation GS The licensee has stated that it The Auxiliary Feedwater System does throttles AFW system flow to avoid water hammer. The licen- not throttle flow to avoid water see should re-examine the practice of throttling AFW system hammer. The AFS will supply on de-flow to avoid water hammer. mand sufficient initial flow to assure adequate decay heat removal.

The licensee should verify that the AFW system will supply on Water hammer considerations have demand sufficient initial flow to the necessary generators to been taken into account in the final assure adequate decay heat removal following loss of main feed- design by the use of steam generator water flow and reactor trip from 100% power. In cases where sparger and "J" tube design and the this reevaluation results in an increase in initial AFW system feedwater piping design.

flow, the licensee should provide sufficient information to demonstrate that the required initial AFW system flow will not result in plant damage due to water hammer.

4) 5.2.4 Emergency Procedures for Initiating Backup Water Supplies Concern - Most of the plants do not have written procedures for transferring to alternate sources of AFW supply if pri-mary supply is unavailable or exhausted. Without specific criteria and procedures for an operator to follow to trans-fer to alternate water sources, the primary supply could be exhausted and result in pump damage or a long interrup-tion of AFW flow.

T10.4.9A-14 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 TABLE 10.4.9A-4 (Cont'd)

ACCEPTANCE CRITERIA COMPLIANCE Recommendation GS Emergency procedures for transferring 1) The Auxiliary Feedwater Pump suctions are to alternate sources of AFW supply should be available to the maintained filled with water at all times.

plant operators. These procedures should include criteria to The only valves in the suction lines are manually inform the operator when, and in what order, the transfer to operated and are maintained locked open. Thus alternate water sources should take place. The following AFW supply to the pump is always assured without cases should be covered by the procedures: the need for operator intervention.

(1) The case in which the primary water supply is initi- 2) The primary AFW supply for SL-2 is the Condensate ally available. The procedures for this case should Storage Tank (CST). The CST is a seismic Category I, include any operator action required to protect the Safety Class 3 structure which is entirely enclosed AFW system pumps against self-damage before water to protect it from the effects of tornado missiles.

flow is initiated. This tank maintains at all times sufficient con-densate to bring both Units I and 2 to shutdown cooling (2) The case in which the primary water supply is being entry conditions. Additional tank margin is available depleted. The procedure for this case should pro- to satisfy normal plant operational requirements. The vide for transfer to the alternate water sources CST is provided with qualified and redundant level prior to draining of the primary water supply. alarms to ensure that sufficient water is available at all times to shutdown Units I and 2. An adequate source of cooling water is thus assured under all postulated conditions.

Should an alternate AFW source be desired the Primary Water and City Water Storage Tanks are available on site. The contents of these tanks could be transferred to the CST using temporary hose connections in conjunction with either a diesel driven or motor driven fire pump. The motor driven pump(s) can be powered from the emergency power source. Note - the pumps are powered from Unit 1 ESF busses; thus, under LOOP conditions for Unit 1, they may be started, if needed, after 35 seconds.

5) 5.2.5 Emergency Procedures for Initiating AFW Flow Following a Complete loss of Alternating Current Power Concern - Some operating plants depend on ac power for all sources of AFW system supply including turbine-driven pump train. In the event of loss of offsite and onsite ac power, ac-dependent lube oil supply or lube oil cooling for the pump will stop, and/or manual actions are required to initiate AFW flow from the turbine-driven pump by manually opening the turbine steam admission valve and/or AFW sys-tem flow control valves. There are no procedures avail-able to the plant operators for AFW system initiation and control under these conditions. This could result in a considerable time delay for AFW system initiation, since the operators would not be guided by procedures dealing with this event.

T10.4.9A-15 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 TABLE 10.4.9A-4 (Cont'd)

ACCEPTANCE CRITERIA COMPLIANCE Recommendation GS The as-built plant should be capable The AFS turbine driven pump is of providing the required AFW flow for at least two hours independent of ac power. Lube from one AFW pump train, independent of any ac power oil and cooling water supply is source. If manual AFW system initiation or flow control internal to the pump and there-is required following a complete loss of ac power, emer- fore requires no safety related gency procedures should be established for manually initi- ac powered oil pump.

ating and controlling the system under these conditions.

Since the water for cooling of the lube oil for the turbine-driven pump bearings may he dependent on ac power, design or procedural changes shall be made to eliminate The turbine steam supply valves this dependency as soon as practicable. Until this is are powered by dc power each from a redundant done, the emergency procedures should provide for an in- vital dc bus. (Solenoid valves are used in dividual to be stationed at the turbine-driven pump in the bypass line.)

the event of the loss of all ac power to monitor pump T10.4.9A-16 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 TABLE 10.4.9A-4 (Cont'd)

ACCEPTANCE CRITERIA COMPLIANCE bearing and/or lube oil temperatures. If necessary, this The AFS system pipeline from the operator would operate the turbine-driven pump in an on-off turbine driven pump to the steam mode until ac power is restored. Adequate lighting powered generator consists of two branches, by direct current (dc) power sources and communications at each with an isolation valve and a local stations should also be provided if manual initiation flow control valve. These valves are and control of the AFW system is needed. (See Recommenda- controlled by redundant, Class 1E 125V tion GL-3 for the longer term resolution of this concern.) dc buses.

6) 5.2.6 AFW System Flow Path Verification Concern - Periodic testing of the AFW system is accomplished by testing of individual components of one flow train (peri-odic pump recirculation flow test or automatic valve actua-tion), thus altering the normal AFW system flow path(s).

The flow capability of the entire AFW system, or at least one integral AFW system train, is only demonstrated on system demand following a transient, or if the AFW system is used for normal plant startup or shutdown.

Recent Licensee Event Reports indicate a need to improve the quality of system testing and maintenance. Specifically, periodic testing and maintenance procedures inadvertently result in (1) more than one AFW system flow train being un-available during the test, or (2) the AFW system flow train under test not being properly restored to its operable con-dition following the test or maintenance work. The Office of Inspection and Enforcement has taken action to correct Item (1): the recommendation below is made to correct Item (2).

Recommendation GS The licensee should confirm flow path availability of an AFW system flow train that has been out of service to perform periodic testing or maintenance as follows:

(1) Procedures should be implemented to require an 1) AFS system testing is accomplished operator to determine that the AFW system valves by allowing the AFW pumps to deliver are properly aligned and a second operator to flow back to the CST through the min-independently verify that the valves are properly imum flow recirculation line. This aligned. is carried out in normal system alignment, and none of the measure-ments to be taken affect pump opera-tion. If a system demand occurred during the test, the pumps would continue to run. Thus, an operator is not required to verify valve align-ment after system testing. Mainten-ance procedures will be implemented requiring operator to determine that the AFS are properly aligned and a T10.4.9A-17 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 TABLE 10.4.9A-4 (Cont'd)

ACCEPTANCE CRITERIA COMPLIANCE second operator to independent-ly verify that the valves are properly aligned after system maintenance.

(2) The licensee should propose Technical Specifica- (2) Technical Specifications will be proposed tions to assure that, prior to plant startup to assure that, prior to plant startup following an extended cold shutdown, a flow test following any cold shutdown 30 days or would be performed to verify the normal flow path longer, or where an AFS flow train has from the primary AFW system water source to the been out of service for testing or main-steam generators. The flow test should be con- tenance, a test will be performed to ver-ducted with AFW system valves in their normal ify the normal flow path from the primary alignment. AFS water source to the steam generators.

This flow test will be conducted during cold shutdown, with AFS valves in the normal alignment for the AFS flow from the primary water source to the steam generators.

7) 5.2.7 Non-Safety Grade, Non-Redundant AFW System Automatic Initiation Signals Concern - Some plants with an automatically initiated AFW system utilize some initiation signals that are not safety-grade do not meet the single failure criterion, and are not required by the Technical Specification to be tested period-ically. This can result in reduced reliability of the AFW system Recommendation GS The licensee should verify that the The Auxiliary Feedwater System signals automatic start AFW system signals and associated circuitry and circuits all safety related Class 1E.

are safety-grade. If this cannot be verified, the AFW system The AFS is in accordance with Recommen-automatic initiation system should be modified in the short- dation GS-7.

term to meet the functional requirements listed below. For the longer-term, the automatic initiation signals and circuits should be upgraded to meet safety-grade requirements, as in-dicated in Recommendation GL-5.

(1) The design should provide for the automatic ini-tiation of the AFW system flow.

(2) The automatic initiation signals and circuits should be designed so that a single failure will not result in the loss of AFW system function.

(3) Testability of the initiation signals and circuits shall be a feature of the design.

T10.4.9A-18 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 TABLE 10.4.9A-4 (Cont'd)

ACCEPTANCE CRITERIA COMPLIANCE (4) The initiation signals and circuits should be powered from the emergency buses.

(5) Manual capability to initiate the AFW system from the control room should be retained and should be implemented so that a single failure in the manual circuits will not result in the loss of system function.

(6) The ac motor-driven pumps and valves in the AFW system should be included in the automatic actu-ation (simultaneous and/or sequential) of the loads to the emergency buses.

(7) The automatic initiation signals and circuits shall be designed so that their failure will not result in the loss of manual capability to initiate the AFW system from control room.

8) 5.2.8 Automatic Initiation of AFW Systems Concern - For plants with a manually initiated AFW system, there is the potential for failure of the operator to man-ually actuate the system following a transient in time to maintain the steam generator water level high enough to re-assure reactor decay heat removal via the steam generator(s).

While IE bulletin 79-06A requires a dedicated individual for W-designed operating plants with a manually initiated AFW system, further action should be taken in the short-term.

This concern is identical to Item 2.1.7a of NUREG-0578.

Recommendation GS The licensee should install a system to The Auxiliary Feedwater System is automatically initiate AFW system flow. This system need not automatically initiated. The AFS be safety-grade; however, in the short-term, it should meet design is in accordance with Re-the criteria listed below, which are similar to Item 2.1.7a commendation GS-8.

of NUREG-0578. For the longer-term, the automatic initiation signals and circuits should be upgraded to meet safety-grade requirements, as indicated in Recommendation GL-2.

(1) The design should provide for the automatic initiation of the AFW system flow.

(2) The automatic initiation signals and circuits should be designed so that a single failure will not result in the loss of AFW system function.

(3) Testability of the initiating signals and circuits should be a feature of the design.

T10.4.9A-19 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 TABLE 10.4.9A-4 (Cont'd)

ACCEPTANCE CRITERIA COMPLIANCE (4) The initiating signals and circuits should be powered from the emergency buses.

(5) Manual capability to initiate the AFW system from the control room should be retained and should be implemented so that a single failure in the manual circuits will not result in the loss of system function.

(6) The ac motor-driven pumps and valves in the AFW system should be included in the automatic actu-ation (simultaneous and/or sequential) of the loads to the emergency buses.

(7) The automatic initiation signals and circuits should be designed so that their failure will not result in the loss of manual capability to initiate the AFW system from the control room.

9) 5.3.1 Primary AFW Water Source Low Level Alarm Concern - Plants which do not have level indication and alarm for the primary water source may not provide the operator with sufficient information to properly operate the AFW system.

Recommendation - The licensee should provide redundant The Condensate Storage Tank (CST) level indication and low level alarms in the control the primary EFS water source, has room for the AFW system primary water supply, to allow redundant, safety grade level in-the operator to anticipate the need to make up water dication and low level alarms in or transfer to an alternate water supply and prevent the control room. The low level a low pump suction pressure condition from occurring. alarm setpoint is at the Techni-The low level alarm setpoint should allow at least cal Specifications minimum volume 20 minutes for operator action, assuming that the (307,000 gal). A low-low level largest capacity AFW pump is operating. alarm is initiated in the control room when the water inventory in the CST is depleted to 14,000 gal-lons (above dead volume). This amount is sufficient to supply water to one 500 gpm capacity turbine driven pumps for at least 25 minutes.

10) 5.3.2 AFW Pump Endurance Test Concern - Since it may be necessary to rely on the AFW system to remove decay heat for extended periods of time, it should be demonstrated that the AFW pumps have the capability for continuous operation over an extended period without failure.

T10.4.9A-20 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 TABLE 10.4.9A-4 (Cont'd)

ACCEPTANCE CRITERIA COMPLIANCE Recommendation - The licensee should perform a 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months endur- A 48 hour5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months endurance test will be performed ance test on all AFW system pumps, if such a test or continu- on the Auxiliary Feedwater pumps. Test ous period of operation has not been accomplished to date. results will be submitted to the NRC.

Following the 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months pump run, the pumps should be shut down and cooled down and then restarted and run for one hour.

Test acceptance criteria should include demonstrating that the pumps remain within design limits with respect to bearing/

bearing oil temperatures and vibration and that pump room ambient conditions (temperature, humidity) do not exceed en-vironmental qualification limits for safety related equipment in the room.

11) 5.3.3 Indication of AFW Flow to the Steam Generators Concern - Indication of AFW flow to the steam generators is considered important to the manual regulation of AFW flow to maintain the required steam generator water level.

This concern is identical to Item 2.1.7.b of NUREG-0578.

Recommendation - The licensee should implement the follow- Safety grade Auxiliary Feedwater ing requirements as specified by Item 2.1.7.b on page A-32 flow indication and safety grade, of NUREG-0578: redundant steam generator level indication is available to the (1) Safety-grade indication of AFW flow to each steam operator in the control room.

generator should be provided in the control room. These instrument loops are powered by the 120V ac Class 1E power source.

(2) The AFW flow instrument channels should be powered from the emergency buses consistent with satisfy-ing the emergency power diversity requirements for the AFW system set forth in Auxiliary Systems Branch Technical Position 10-1 of the Standard Review Plan, Section 10.4.9.

12) 5.3.4 AFW System Availability During Periodic Surveillance Testing Concern - Some plants require local manual realignment of valves to conduct periodic pump surveillance tests on one AFW system train. When such plants are in this test mode and there is only one remaining AFW system train available to respond to a demand for initiation of AFW system opera-tion, the AFW system redundancy and ability to withstand a single failure are lost.

Recommendation - Licensees with plants which require local Not applicable. Local manual re-manual realignment of valves to conduct periodic tests on alignment of valves to conduct one AFW system train and which have only one remaining AFW periodic pump surveillance tests train available for operation should propose Technical on AFS trains is not required.

T10.4.9A-21 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 TABLE 10.4.9A-4 (Cont'd)

ACCEPTANCE CRITERIA COMPLIANCE Specifications to provide that a dedicated individual who (Refer to response to short term is in communication with the control room be stationed at recommendation GS-6).

the manual valves. Upon instruction from the control room, this operator would realign the valves in the AFW system from the test mode to its operational alignment.

B. 5.4 Long-Term Recommendations

1) 5.4.1 Automatic Initiation of AFW Systems Concern - This concern is the same as short-term generic recommendation GS-8; namely, failure of an operator to actuate a manual start AFW in time to maintain steam generator water level high enough to assure decay heat removal via the steam generator(s).

Recommendation GL For plants with a manual AFW system, Not applicable. The AFS initiation the licensee should install a system to automatically initi- is automatic, safety grade, and re-ate the AFW system flow. This system and associated automatic dundant.

initiation signals should be designed and installed to meet safety-grade requirements. Manual AFW system start and control capability should be retained with manual start serving as backup to automatic AFW system initiation.

2) 5.4.2 Single Valves in the AFW System Flow Path Concern - This is the same short-term generic recommen-dation GS namely, AFW system inoperability due to an inadvertently closed manual valve that could interrupt all AFW system flow.

Recommendation GL Licensees with plant design in which Not applicable. The AFS system has all (primary and alternate) water supplies to the AFW systems redundant, parallel flow paths pass through valves in the single flow path should install (piping and valves) so that there is redundant parallel flow paths (piping and valves). no single valve which if left closed, could interrupt all flow. All manually Licensees with plant designs in which the primary AFW operated valves in AFS suction are system water supply passes through valves in a single locked open.

flow path, but the alternate AFW system water supplies connect to the AFW system pump suction piping downstream of the above valve(s), should install redundant valves parallel to the above valve(s) or provide automatic open-ing of the valve(s) from the alternate water supply upon low pump suction pressure.

The licensee should propose Technical Specifications to incorporate appropriate periodic inspections to verify the valve positions into the surveillance requirements.

T10.4.9A-22 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 TABLE 10.4.9A-4 (Cont'd)

ACCEPTANCE CRITERIA COMPLIANCE

3) 5.4.3 Elimination of AFW System Dependency on Alternating Current Power Following A Complete Loss of Alternating Current Power Concern - This concern is the same as short-term generic recommendation GS-5 namely, delay in initiation of AFW system operation or maintaining AFW system operation following a postulated loss of onsite and offsite ac power; i.e., ac power blackout.

Recommendation GL At least one AFW system pump and its The AFS turbine driven pump is dc associated flow path and essential instrumentation should controlled and capable of being automatically initiate AFW system flow and be capable of operated independently of ac power being operated independently of any ac power source for at for at least two hours. The tur-least two hours. Conversion of dc power to ac power is bine steam supply valves are motor acceptable. operated, powered by dc power, each from a redundant vital dc bus. (Solenoid valves are used in the bypass line.)

The AFS system pipeline from the turbine driven pump to each steam generator consists of two branches, each with an isolation valve and a flow control valve. These valves are controlled by redundant, Class 1E, 125V dc buses.

4) 5.4.4 Prevention of Multiple Pump Damage due to Loss of Suction Resulting From Natural Phenomena Concern - In many of the operating plants, the normal water supply to the AFW system pumps (including the interconnected piping) is not protected from earthquakes or tornadoes. Any natural phenomenon severe enough to result in a loss of the water supply could also be severe enough to cause a loss of offsite power with loss of main feedwater, resulting in an automatic initiation signal to start the AFW system pumps. The pumps would start without any suction head, leading to cavitation and multiple pump damage in a short period of time, possibly too short for the operators to take action that would protect the pumps.

This may lead to unacceptable consequences for some plants, due to a complete loss of feedwater (main and auxiliary).

Recommendation GL Licensees having plants with un- The CST is housed in a separate protected normal AFW system water supplied should evaluate seismic Category I structure which the design of their AFW systems to determine if automatic has been designed to withstand the protection of the pumps is necessary following a seismic effects of tornados or tornado in-event or a tornado. The time available before pump damage, duced missiles.

the alarms and indications available to the control room T10.4.9A-23 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 TABLE 10.4.9A-4 (Cont'd)

ACCEPTANCE CRITERIA COMPLIANCE operator, and the time necessary for assessing the problem The AFS pumps, piping valves and and taking action should be considered in determining associated circuitry are designed whether operator action can be relied on to prevent pump seismic Category I and are located damage. Consideration should be given to providing pump in the seismic Category I steam protection by means such as automatic switchover of the trestle structure which has been pump suctions to the alternate safety-grade source of water, designed to withstand the effects automatic pump trips on low suction pressure, or upgrading of tornado induced missile.

the normal source of water to meet seismic Category I and tornado requirements.

5) 5.4.5 Non-Safety Grade, Non-Redundant AFW System Automatic Initiation Signals Concern - This concern is the same as short-term generic recommendation GS namely, reduced AFW system reliability as a result of use of non-safety-grade, non-redundant signals, which are not periodically tested, to automatically initiate the AFW system.

Recommendation GL The licensee should upgrade the AFW The AFS automatic initiation system automatic initiation signals and circuits to meet signals and circuits are safety-safety-grade requirements. grade.

T10.4.9A-24 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 Table 10.4.9A-5 St. Lucie 2 Loss of Feedwater With Offsite Power Available Sequence of Events Time (seconds) Event Setpoint/Value 0.0 Loss of main feedwater EC 292 40.8 SG1 Low level reactor trip setpoint reached 15.5 % NR 636 41.9 Reactor trip breakers open 1.15 second delay 42.0 Low level setpoint for AFW initiation reached 13.0 % NR 42.7 Rod motion begins 0.74 second delay 44.2 Turbine trip on reactor trip 372.0 AFW reaches the steam generators 275 gpm/SG 559.2 PORV actuation 2411 psia 1200.0 Operators trip RCPs 1376.0 Maximum pressurizer liquid volume 1510.7 ft3 1884.0 Minimum subcooling 5.2 °F 3600.0 Simulation ended T10.4.9A-25 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 Table 10.4.9A-6 St. Lucie 2 Loss of Feedwater With Loss of Offsite Power Sequence of Events Time (seconds) Event Setpoint/Value EC 0.0 Loss of main feedwater 292 636 40.8 SG Low level reactor trip setpoint reached 15.5 % NR 41.9 Reactor trip breakers open 1.15 second delay 42.0 Low level setpoint for AFW initiation reached 13.0 % NR 42.7 Rod motion begins 0.74 second delay 44.2 Turbine trip on reactor trip 44.2 Loss of offsite power 44.2 RCPs trip on LOOP 313.1 PORV actuation 2411 psia 372.0 AFW reaches the steam generators 275 gpm/SG 798.0 Maximum pressurizer liquid volume 1382.7 ft3 1916.0 Minimum subcooling 20.6 °F 3600.0 Simulation ended T10.4.9A-26 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 Table 10.4.9A-7 EC St. Lucie 2 Feedwater Line Break for High Tavg with Offsite Power Available 292 Sequence of Events 636 EC Time (seconds) Event Setpoint/Value 292 636 Instantaneous loss of feedwater to both SGs; FLB 0.0 occurs in the MFW line between the Loop 1 SG and 1.23 ft2 the last check valve 10.04 Low SG level setpoint reached 4.0% NR 11.20 Reactor Trip on Low SG level 1.15 second delay 11.95 CEA release 0.74 second delay 2.0 second delay +

13.47 Turbine trip 0.26 sec. closure time

~48 Loop 1 SG dryout < 500 lbm Loop 2 SG level reaches AFW actuation setpoint 48.68 4% NR (AFAS) 59.73 Loop 2 SG reaches MSI setpoint 487 psia 7.0 second delay 66.73 MSIVs completely closed (stroke time + signal processing time)

~90 Minimum pressurizer liquid volume ~3.97 ft3 250 Loop 2 SG minimum inventory ~0 lbm 378.7 AFW reaches Loop 2 SG 330 second delay 1800 Maximum pressurizer volume 1519 ft3 1800 Loop 2 SG liquid inventory at end of transient ~710 lbm Operator takes actions to stabilize the plant (1800 1800 sec. after transient initiation)

T10.4.9A-27 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 Table 10.4.9A-8 EC St. Lucie 2 Feedwater Line Break for High Tavg with Loss of Offsite Power 292 636 Sequence of Events EC Time (seconds) Event Setpoint/Value 292 636 Instantaneous loss of feedwater to both SGs; FLB 0.0 occurs in the MFW line between the Loop 1 SG and 1.23 ft2 the last check valve 10.04 Low SG level setpoint reached 4.0% NR 11.20 Reactor Trip on Low SG level 1.15 second delay 11.95 CEA release 0.74 second delay 13.47 Turbine trip 2.0 second delay 13.47 Loss of Offsite Power Coincident with TT 33.65 Loop 2 SG reaches MSI setpoint 487 psia 43.81 Loop 2 SG level reaches AFW actuation setpoint 4% NR 7.0 second delay 40.65 MSIVs completely closed (stroke time + signal processing time) 48.50 Loop 1 SG dryout < 500 lbm 62.50 Minimum pressurizer liquid volume ~377 ft3 373.85 AFW reaches Loop 2 SG 330 second delay 1800 Loop 2 SG inventory 718 lbm 1800 Maximum pressurizer volume 1416 ft3 Operator takes actions to stabilize the plant (1800 1800 sec. after transient initiation)

T10.4.9A-28 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 Table 10.4.9A-9 InitialConditions Both nominal and biased initial conditions are assumed. Any differences between the assumed initial EC 292 conditions and actual plant values are insignificant in terms of the anticipated analysis results. The initial 636 conditions are as follows.

Parameter Value Core Power 3029.1 MWt Reactor Coolant Pump Heat 14.2 MWt (4 pumps)

Moderator Temperature Coefficient 0 pcm/°F Doppler Temperature Coefficient -0.8 pcm/°F Primary Flow 370,000 gpm Core Inlet Temperature Low Nominal 535 °F High Nominal 551 °F Pressurizer Pressure 2250 psia Pressurizer Level 63 % NRS Steam Generator Level 65 % Span Steam Generator Blowdown 120 gpm/SG Main Feedwater Flow* SG1 SG2 Low Tavg 1854.4 lbm/s 1851.4 lbm/s High Tavg 1861.6 lbm/s 1859.2 lbm/s Main Feedwater Temperature 436 °F

Note that for initial conditions, the main feedwater flow is set equal to the steam flow.

T10.4.9A-29 Amendment No. 26 (09/20)

EC 292 636 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 2 FIGURE 10.4.9A-1 LOMF W/AC Hot Leg Subcooling EC 292 Margin versus Time 636 Amendment No. 26 (09/20)

EC 292 636 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 2 FIGURE 10.4.9A-2 EC LOMF W/LOOP Hot Leg Subcooling 292 Margin versus Time 636 Amendment No. 26 (09/20)

EC 292 636 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 2 FIGURE 10.4.9A-3 FLB W/AC Steam Generator Inventory versus Time Amendment No. 26 (09/20)

EC 292 636 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 2 FIGURE 10.4.9A-4 FLB W/AC Pressurizer Liquid EC 292 Volume versus Time 636 Amendment No. 26 (09/20)

EC 292 636 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 2 FIGURE 10.4.9A-5 FLB W/AC Pressurizer Pressure versus Time Amendment No. 26 (09/20)

EC 292 636 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 2 FIGURE 10.4.9A-6 FLB W/AC Hot Leg EC 292 Subcooling Margin versus Time 636 Amendment No. 26 (09/20)

EC 292 636 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 2 FIGURE 10.4.9A-7 FLB W/LOOP Steam Generator Inventory versus Time Amendment No. 26 (09/20)

EC 292 636 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 2 FIGURE 10.4.9A-8 FLB W/LOOP EC 292 Pressurizer Liquid Volume versus Time 636 Amendment No. 26 (09/20)

EC 292 636 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 2 FIGURE 10.4.9A-9 FLB W/LOOP Pressurizer Pressure versus Time Amendment No. 26 (09/20)

EC 292 636 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 2 FIGURE 10.4.9A-10 FLB W/LOOP Hot Leg EC 292 Subcooling Margin versus Time 636 Amendment No. 26 (09/20)

UFSAR/St. Lucie - 2 APPENDIX 10.4.9B AUXILIARY FEEDWATER SYSTEM RELIABILITY ANALYSIS The information contained in this section provides the original AFW system reliability analysis.

This information summarizes the results of a reliability study of the St. Lucie Unit 2 AFW system required by the NRC in NRC Generic Letter 80-20, issued via a letter from D. Ross to all Westinghouse and CE operating license applicants dated 3/10/80. This information is maintained in the FSAR for Historical purposes.

10.4.9B-i Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 APPENDIX 10.4.9B TABLE OF CONTENTS Section Title Page 10.4.9B.1 Introduction ............................................................................................. 10.4.9B-1 10.4.9B.2 System Definition ................................................................................... 10.4.9B-1 10.4.9B.2.1 Top Event ............................................................................................... 10.4.9B-1 10.4.9B.2.2 System Boundaries ................................................................................ 10.4.9B-2 10.4.9B.2.3 Basic Events Considered ....................................................................... 10.4.9B-2 10.4.9B.3 System Model Construction ................................................................... 10.4.9B-4 10.4.9B.3.1 Failure Modes and Effects Analysis (Independent Failure Considerations) ...................................................................................... 10.4.9B-4 10.4.9B.3.1.1 Component ............................................................................................. 10.4.9B-5 10.4.9B.3.1.2 Component State ................................................................................... 10.4.9B-5 10.4.9B.3.1.3 Effect ...................................................................................................... 10.4.9B-5 10.4.9B.3.1.4 Inherent Compensation .......................................................................... 10.4.9B-5 10.4.9B.3.2 Common Cause Failure Consideration .................................................. 10.4.9B-5 10.4.9B.3.3 Fault Tree ............................................................................................... 10.4.9B-7 10.4.9B.4 System Model Qualitative Analysis ........................................................ 10.4.9B-8 10.4.9B.5 System Model Quantitative Analysis ...................................................... 10.4.9B-8 10.4.9B.5.1 Event Causes and Probabilities ............................................................. 10.4.9B-8 10.4.9B.5.2 System Failure Probability Analysis ..................................................... 10.4.9B-14 10.4.9B.6 Discussion of Results ........................................................................... 10.4.9B-15 10.4.9B.7 Conclusions .......................................................................................... 10.4.9B-17 10.4.9B-ii Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 APPENDIX 10.4.9B LIST OF TABLES Table Title Page 10.4.9B-1 Component List Manual Valves ............................................................ T10.4.9B-1 10.4.9B-2 AFS Failure Modes & Effect Analysis ................................................... T10.4.9B-8 10.4.9B-3a Cut Sets - LOFW Automatic Auxiliary Feedwater System Study ........ T10.4.9B-16 10.4.9B-3b Cut Sets - LOOP Automatic Auxiliary Feedwater System Study ......... T10.4.9B-24 10.4.9B-3c Cut Sets - SBLO Automatic Auxiliary Feedwater System Study ......... T10.4.9B-35 10.4.9B-4a Cut Sets - LOFW Manual Auxiliary Feedwater System Study............. T10.4.9B-37 10.4.9B-4b Cut Sets - LOOP Manual Auxiliary Feedwater System Study ............ T10.4.9B-44 10.4.9B-4c Cut Sets - SBLO Manual Auxiliary Feedwater System Study ............. T10.4.9B-53 10.4.9B-5 Basic Event Failure Rate Data ........................................................... T10.4.9B-54 10.4.9B-6 AFS Valves Subject to ASME Section XI Testing ............................... T10.4.9B-56 10.4.9B-7a Dominant Cut Sets - LOFW (Automatic) ............................................ T10.4.9B-57 10.4.9B-7b Dominant Cut Sets - LOOP (Automatic) ............................................. T10.4.9B-58 10.4.9B-7c Dominant Cut Sets - SB (Automatic) .................................................. T10.4.9B-59 10.4.9B-8a Dominant Cut Sets - LOFW (Manual) ................................................. T10.4.9B-60 10.4.9B-8b Dominant Cut Sets - LOOP (Manual) ................................................. T10.4.9B-61 10.4.9B-8c Dominant Cut Sets - SB (Manual) ...................................................... T10.4.9B-62 10.4.9B-iii Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 APPENDIX 10.4.9B LIST OF FIGURES Figure No. Title 10.4.9B-1 AFS Schematic Diagram Manual Design 10.4.9B-2 AFS Schematic Diagram Automatic Design 10.4.9B-3 Fault Tree of LOFW - Manual 10.4.9B-4 Fault Tree of LOOP - Manual 10.4.9B-5 Fault Tree of SB - Manual 10.4.9B-6 Fault Tree of LOFW - Automatic 10.4.9B-7 Fault Tree of LOOP - Automatic 10.4.9B-8 Fault Tree of SB - Automatic 10.4.9B-iv Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 10.4.9B.1 Introduction This report summarizes the results of a reliability study of the St Lucie 2 Auxiliary Feedwater System (AFS) required by the NRC in Reference 1. The primary purpose of this study is to assess the system availability to function on demand and identify any areas where changes in design, operating procedures and/or system testing/maintenance practice could result in significant availability improvements. The analysis and results are presented for both a manually actuated system and for the current AFS design which now incorporates automatic initiation features as described in FSAR Subsection 10.4.9. The (baseline) manually actuated system represents the design approved at the construction permit (CP) stage. This comparison provides a means of assessing the relative improvement in system reliability offered by this design change. The steps in this study were:

SYSTEM DEFINITION: The objectives of the study and its scope and limitations are clearly defined.

SYSTEM MODEL CONSTRUCTION: A Failure Modes and Effects Analysis for each component and Common Cause Analysis are performed and used to construct a system fault tree for each condition to be analyzed.

SYSTEM MODEL QUALITATIVE ANALYSIS: The system model is examined to determine the combination of events (minimal cut sets) which can lead to system unavailability on demand.

SYSTEM MODEL QUANTITATIVE ANALYSIS: Probabilities of occurrence are determined for the basic events in the fault tree, and are used to calculate the overall system availability and to weigh the relative importance of the events and event combinations as failure contributors.

ANALYSIS OF RESULTS: The results of the qualitative analysis are reviewed to determine if any changes in design, modes of Automatic or Manual Initiation, operating procedures and/or system testing/ maintenance practice could result in significant availability improvements.

The details of the actual study are described herein.

10.4.9B.2 System Definition 10.4.9B.2.1 Top Event The purpose of the analysis is to determine the availability of the AFS to perform it's design function on a demand produced by a Loss of Main Feedwater (LOFW), LOFW with Loss of Offsite Power (LOOP), and LOFW with Station Blackout (SB). Operation under main steam or feedwater line break or LOCA conditions were not considered. Each of the conditions under consideration requires the same minimum function of the AFS, i.e., to deliver a total of at least 320 gpm to the steam generator(s) to maintain the reactor in the hot standby condition, so the top event is the same for all three conditions.

It is known that the basic failure events to be considered have small probabilities. Thus, to minimize round off error in numerical calculations, the system model will be constructed in fault 10.4.9B-1 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 tree as opposed to success tree fashion. The top event will then be failure to deliver at least 320 gpm AFS flow to the steam generator(s), or "320 gpm AFS flow to SG's."

The scope of the top event spans only the availability of the system to start on demand for the transients under consideration and does not include the reliability of the system to carry out this mission through the required duration several hours), consistent with the NRC request in Reference 1. However, it is believed that for the events analyzed, the system undependability is dominated by the unavailability to start on demand.

10.4.9B.2.2 System Boundaries The AFS simplified flow diagram for the manual and automatic schemes are shown on Figure 10.4.9B-1 and Figure 10.4.9B-2 respectively. For this analysis, the system consists of the AFS flow path from the Condensate Storage Tank (CST) to the normal flow connections with the Main Feedwater System (MFWS), inclusive of interconnections with other systems.

Support systems/ components considered in the anlaysis not shown on the figure are pump and valve control circuits, power supplies and AFAS logic. More detail on the types of failures considered is given in Subsection 10.4.9B.2.3.

10.4.9B.2.3 Basic Events Considered The types of events considered in the FMEA and their possible causes are listed by component.

It should be noted that in some cases events which obviously were not failure events were not fully developed in the FMEA. Also, not all the possible causes listed under each component type are applicable to each event for the component.

MANUAL VALVE

Events:

- Open (able to pass flow)

- Closed (unable to pass flow)

Possible Causes:

- Plugging (flow path blocked)

- In wrong position due to test or maintenance on another component at the time of demand

- Normal or proper position CHECK VALVE

Events:

- Open against forward current

- Open against reverse current 10.4.9B-2 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2

- Closed against forward current

- Closed against reverse current

Possible Causes:

- Frozen in wrong position due to mechanical binding

- In test or maintenance

- Proper position POWER OPERATED VALVE

Events:

- Remains OPEN on demand close signal

- Remains CLOSED on demand open signal

- CLOSED and receives no automatic signal

- OPEN and receives no automatic signal

Possible Causes:

- Mechanical binding

- Control circuit failure

- Actuating signal failure

- Motive force failure

- Left in wrong position (if valves receives no confirmatory automatic signal) after test or maintenance action

- In test or maintenance PUMP

Events:

- Fails to deliver the required flow

Possible Causes:

- Mechanical binding

- Control circuit failure

- Actuating signal failure 10.4.9B-3 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2

- Motive force failure ACTUATING LOGIC

Events:

- Signal not generated when required

Possible Causes:

- Unspecified electronics failure

- In test or maintenance POWER SUPPLY

Events:

- Does not supply AC power

- Does not supply DC control power

Possible Causes:

- DG failure to start

- DG in test or maintenance

- Battery failure The following events were not considered:

- Passive fluid boundary failures or valve disc stem separations.

- Spurious control circuit or actuation circuit logic commands.

Common cause failures considered as basic events are discussed in Subsection 10.4.9B.3.2.

Common cause failures not considered were sabotage or those of a physical layout nature, such as non seismic systems falling on AFS components, high energy line breaks in other systems affecting the AFS, etc. The dynamic effects of high energy piping failures is discussed in FSAR Section 3.6.

10.4.9B.3 System Model Construction 10.4.9B.3.1 Failure Modes and Effects Analysis A Failure Modes and Effects Analysis (FMEA) was developed as a first step in the system model construction to identify the effects that individual component actions have on subsystem and overall system operation. The FMEA describes the effect on the system of every component action regardless of whether or not the action contributed to system failure, and is a necessary complement to the fault tree for this reason. The structure and rationale behind the details of the FMEA is discussed below. The FMEA is given in Table 10.4.9B-2.

10.4.9B-4 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 10.4.9B.3.1.1 Component Each component selected in accordance with the criteria of Subsections 10.4.9B.2.2 and 10.4.9B.2.3 appears in the FMEA, with the exception of vent and drain valves. These were not included because the system is kept continually full of water by the CST/MFWS, so it is not considered credible that a vent or drain valve could be left open without being quickly noticed and corrected.

For simplicity in this study, each component considered was assigned to a two digit identification (ID) number. A list of all components considered, along with a description of the component, it's two digit ID number and actual ID number is given in Table 10.4.9B-1.

10.4.9B.3.1.2 Component State Each component was considered in it's extreme states within the limitations of Subsection 10.4.9B.2.3 for the purpose of analyzing it's effects. For example, valves were considered in both the open and closed state. Actuation signals were analyzed only for failure to be generated when required, but not for spurious generation.

10.4.9B.3.1.3 Effect The effect of the component being in the state under study on the functional block of which it is a part of is analyzed. The following general guidelines were used in analyzing the effect of the component states:

a. Valves: can impair system operation in the closed position by blocking flow where flow is desired, or in the open position by diverting flow or permitting flow where not desirable.

b. Pumps: can impair system operation by not pumping fluid as required and by providing a possible flow diversion path for parallel pumps.

c. Valve/Pump Control Circuits: can cause a pump not to start or valve to not change position when required, leading to the same system impairments discussed under Pump and Valves above.

d. Actuating Logic: can fail to issue a command to the pump or valve control circuits, leading to the same system impairments discussed above.

e. Power Supplies: can fail to provide motive force or control power to pumps or valves, leading to the same system impairments discussed above.

10.4.9B.3.1.4 Inherent Compensation Any inherent provisions in the system which compensate for the degradation brought about by the component state under study is listed to assist in the fault tree construction.

10.4.9B.3.2 Common Cause Failure Consideration Several events were assessed for their potential to induce common cause failures in the AFS, as discussed below.

10.4.9B-5 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2

a. LOSS OF INSTRUMENT AIR: A loss of instrument air would have no effect on the system as the valves in the AFWS are either DC motor operated, AC motor operated or solenoid operated. Thus, loss of instrument air has no adverse effect on system operation for the transients under consideration.

b. LOSS OF COMPONENT COOLING WATER (CCW): The AFS does not rely on Component Cooling Water. The AFS pumps, unlike the HPSI pumps, handle a relatively cool fluid which is itself sufficient for pump cooling, so no CCW is required.

c. LOSS OF AC POWER: The Motor Driven Pump (MDP) are powered from independent AC power sources. The Turbine Driven Pump (TDP) and all power operated valves associated with its flow and steam supply paths are independent of ac power. No TDP auxiliary functions, including lubrication, are dependent upon ac power. The AFS is located in the Main Steam trestle area which has been designed for natural circulation cooling, thereby, eliminating the need for an AC Cooling or Ventilation System.

d. POOR WATER QUALITY CONTROL: If very low quality water were used for extended periods in the AFS, it could conceivably cause corrosion/ particle deposition in the system, perhaps binding the moving parts of the pumps and valves. However, it is not credible that this would occur to any extent in the AFS for the following reasons:

1. Only condensate or demineralized quality water is used in the AFS.

2. The system is periodically treated with Ammonia/Hydrazine as necessary to control water chemistry.

3. The system is periodically flow tested, which not only provides some system flushing, but assures that water quality has not affected the pumps.

4. The valves are periodically stroke tested, which would detect any loss of function due to corrosion or particle deposition.

TESTING: As discussed in Subsection 10.4.9B.5.1.1, system testing has no potential for causing common mode failures.

e. MAINTENANCE: As discussed in Subsection 10.4.9B.5.1.1, maintenance operation has no potential for causing a system common mode failure.

f. CONDENSATE STORAGE TANK: The CST is the only dedicated source of water to the AFS, so it is assessed for it's potential to cause AFS failure.

1. Tank Vent Clogging: The CST is a carbon steel tank which is completely enclosed in a seismic Category I structure which has been designed to withstand the dynamic effects of tornado missiles. The CST utilizes an 8 inch water seal hydraulic vent system.

There is no isolation valve on the line, and there are no known sources of debris which could clog such a vent system. Accidental crimping of the thick 10.4.9B-6 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 walled pipe is not considered credible. As such, failure of the tank due to a restricted vent line is not considered credible.

2. Low Tank Level: The CST is also used as a water supply for the turbine cycle losses. The tank is equipped with redundant, safety grade level indicators and the operators are required to verify that tank level is within allowable limits every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . As such, it is not considered credible that tank level would be out of limits when a system demand occurred.

3. Pump Suction Flashing: The CST water remains at outside ambient temperatures, usually below 90F. There are no lines from hot, interfacing system which connect to the lines between the CST and pump suction. Thus, flashing of the pump suction source is not considered a credible common cause failure mechanism.

10.4.9B.3.3 Fault Tree The fault tree was constructed from the FMEA (independent failure analysis) and the common cause failure analysis. The failures and combinations of failures that could defeat operation of the functional block were combined using conventional AND and OR gates. Then the blocks were arranged through logic which related them to the "top event" specified in Subsection 10.4.9B.2.1. The last step was particularly complex for the AFS due to it's extensive interconnection of redundant trains and the multiple ways in which it can successfully perform it's function.

To simplify the fault tree, only the (failure contributing) component states (or events) from the FMEA, and not all possible causes of the state were incorporated into the fault tree. For example, if a valve being closed (unable to pass fluid) was a contributor in the fault tree, "VALVE XX CLOSED" was included as the event in the fault tree rather than placing an OR gate in the tree with event inputs such as "VALVE XX CLOSED DUE TO MAINT", "VALVE XX CLOSED DUE TO ERROR", "VALVE XX PLUGGED WITH DEBRIS," etc. The latter would generate an unmanageable number of cut sets, and would produce a computer analysis output which focused on causes of concern as opposed to component of concern, which is more useful. A complete listing of the causes and probabilities of each event along with the rationale for their selection is given in Subsection 10.4.9B.5.1.

The fault tree was not constructed to take advantage of "fortuitous failures," e.g., where a failed or misoperated components negates the effect of another failure or misoperation. This does result in some physically unrealistic failure combinations, but constructing the fault tree to eliminate them would unduly complicate the fault tree without significant improvement in predicted system reliability.

Certain components can contribute to system failure by being in one state (e.g., valve open) under certain conditions and by being in the opposite state (valve closed) under different conditions. The fault tree could have been constructed to prevent the possible generation of cut sets including such mutually exclusive conditions by using NOT and AND gate combinations.

However, this could not be done because the computer program used in the fault tree analysis will not accept a NOT gate, so such cases were handled by manually culling the cut sets of such combinations, as discussed in Subsection 10.4.9B.4.

10.4.9B-7 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 Any failure which could affect more than one component, including common mode failures, were factored into the fault tree at the level at which the effect is seen, as opposed to being factored in a failure mode to each individual component. For example, the AFAS1 "A" logic failure, which could incapacitate both SG1 flow paths by not opening a valve on each path, was not entered as a failure to each valve individually, but rather was entered in an OR gate along with other events/event combinations which would incapacitate both SG1 flow paths. This approach was used because it permits use of the fault tree as a visual tool to readily identify the system level effects of certain failures. Treatment of operator error in the fault tree analysis is discussed in Subsection 10.4.9B.5.1.

A single fault tree including all components considered in the study was first generated. This fault tree represented the system under LOFW/LOOP, Manual Initiation and is shown on Figure 10.4.9B-4. For the other cases, the fault tree was reviewed to eliminate components which could not play a role due to differing initial condition assumptions.

The fault tree for different cases are as follows:

Figure 10.4.9B-3 Fault Tree (LOFW - Manual)

Figure 10.4.9B-4 Fault Tree (Loop - Manual)

Figure 10.4.9B-5 Fault Tree (SB - Manual)

Figure 10.4.9B-6 Fault Tree (LOFW - Auto)

Figure 10.4.9B-7 Fault Tree (Loop - Auto)

Figure 10.4.9B-8 Fault Tree (SB - Auto) 10.4.9B.4 System Model Qualitative Analysis The purpose of the system qualitative analysis is to determine the "minimal cut sets," or minimum combinations of events which can lead to the top event. Since it was expected that most of the failure events were of relatively low probability (10-2 or less), it was decided that only the minimal cut sets containing three or less events would be of interest. Events containing more than three events would be of such low probability that it would not be meaningful to pursue them.

The PREP Code was chosen to perform the qualitative analysis because its combinational (trial and error) method of fault tree analysis is generally efficient when three event minimal cut sets are desired.

The results for Case 2 and Case 5 (LOOP) contained some cut sets with both emergency diesel generators failing. Since this condition is Case 3 and Case 6 (SB) by definition it was not appropriate to include them in Case 2 or Case 5. Therefore, these cut sets were manually culled from the (prep) output for those cases.

Each fault tree was individually analyzed to determine its three or less event minimal cut sets.

The cut sets for each case are listed on Tables 10.4.9B-3a, 3b, 3c and 10.4.9B-4a, 4b, 4c.

10.4.9B.5 System Model Quantitative Analysis 10.4.9B.5.1 Event Causes and Probabilities To determine overall system unavailability, a probability of occurrence had to be established for each of the basic events on the fault tree. This was accomplished by identifying the applicable causes (from Subsection 10.4.9B.2.3) of each event, assigning probabilities to each cause, and 10.4.9B-8 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 summing the cause probabilities to obtain the event probability. Simple arithmetic summing of the cause probabilities was used because the "bracketing" correction terms would be insignificant because of the small numbers involved. The causes and probabilities of each event entering into the fault tree are given in Table 10.4.9B-6.

With the exception of testing and maintenance, selection of applicable causes for each event was straightforward using the data provided in reference 1. Applicability of test/maintenance causes to each event was determined on a case by case basis through a review of anticipated plant test and maintenance actions. This review is described in detail in Subsection 10.4.9B.5.1.1.

It should be noted that some of the causes of certain events are not expected to occur simultaneously with some causes of other events done appearing in the same cut sets. For example, if the "A" MDP was in maintenance during power operation, the Technical Specifications would not allow TDP maintenance without a plant shutdown. Performing the analysis to account for this would have unduly complicated the analysis without significantly improving the predicted overall system reliability, so this was conservatively ignored.

10.4.9B.5.1.1 Unavailability Due to Testing and Maintenance System testing/maintenance can contribute to unavailability by two means:

OUTAGE: Components/system are being tested/maintained in an inoperable state at the time operation is demanded.

ERROR: Components realigned for the test/maintenance operation were not restored to their proper state following the operation by the test/maintenance crew.

A review of the proposed Technical Specifications, ASME Section XI, equipment vendor maintenance manuals, system operating procedures, etc, was conducted to identify testing/maintenance operations, their expected frequency and their potential for unavailability contribution from either outage or error. The sections herein on testing and maintenance summarize this review.

SYSTEM TESTING A review of system tests revealed that there is no unavailability contribution due to testing, primarily because:

a. All tests involve putting the component in its operational state, so that it is ready if system response is demanded during the test.

b. No realignment of manual valves is required for any system tests.

A discussion of system tests and their potential for unavailability contributions is given below:

PUMPS: The motor driven and turbine driven pumps must be tested in accordance with ASME Section XI Subsection IWP, which requires a monthly test for speed, inlet pressure, p, flowrate, vibration and bearing temperature. The Technical Specification requirement to measure pump discharge pressure every 31 days is consistent with the Section XI tests.

10.4.9B-9 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 To perform these tests, the pump is started manually from the control room and allowed to deliver flow back to the CST through the minimum flow recirculation line. This is carried out in normal system alignment, and none of the measurements to be taken affect pump operation. If a system demand occurred during the test, the motor driven pumps would continue to run if offsite power were available, or would be tripped and restarted by their associated diesel generator load sequencing relays if offsite power were unavailable. The turbine driven pump would continue to run in any case. As such, the monthly tests are not deemed to contribute to unavailability either by outage or error done.

For the alternate (automatic) system design, the Technical Specifications will also require that the pumps be verified to start on an automatic start signal every 18 months (i.e., during a refueling shutdown). This test will be performed for each automatic start channel and observing that the appropriate pumps start. No system valve realignment or temporary wiring arrangements are required. The test is terminated by clearing the back up manual start signal and stopping the pump. Since the test is performed during plant shutdown and with no system realignment, there is no potential for unavailability from the test either due to outage or error.

VALVES: The inservice testing program for SL2 has not been completed. However, the valves that are expected to be subject to such testing under ASME Section XI, Subsection IWP, are listed in Table 10.4.9B-6.

Subsection IWP requires that these valves be exercised to the position required to fulfill their function every three months. For power operated valves, this includes timing the stroke to assure that valve closure time is within acceptable limits. The plant Technical Specifications will envelope the ASME XI testing requirements.

For the power operated valves, the test involves opening the valve by turning the control switch to "open" and measuring the time the valve requires to open as observed by the valve position indicator. The valve is returned to its original position by turning the control switch to "close. If a system demand occurs while the valve is being closed, the valve would reverse itself and go to the operational state. Thus, exercise testing of the power operated valves does not contribute to system unavailability.

Each check valve that can be exercised during normal plant operation will be exercised during the testing of the pumps and power operated valves. If a system demand were to occur either during or after testing, the check valve would be returned to its proper position by the fluid forces of system operation. AFS system check valves that cannot be exercised during normal plant operation will be full stroked exercised during cold shutdown. Thus, testing of the check valves does not contribute to unavailability either by outage or errors.

CONTROL: The Section XI test for pumps and power operated valves is also a CIRCUITS control circuit test. This is a monthly test for pumps and quarterly test for valves.

As with the pump and valve tests, there is no contribution to system unavailability.

10.4.9B-10 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 ACTUAT- Details of the testing of the automatic start logic for the ING alternate design are given is FSAR Section 7.3. As demonstrated LOGIC: there, these tests do not affect generation of the automatic start on demand and thus do not contribute to AFS unavailability.

DIESEL: Details of the standby diesel generator testing are given in FSAR GENERA- Section 8.3. As demonstrated there, tests do not affect the TORS ability of the diesel generators to respond on demand, and thus do not contribute to AFS unavailability.

SYSTEM MAINTENANCE Routine periodic maintenance may be performed on system pumps and power operated valves during plant operation. No maintenance on manual valves or check valves is expected during power operation. In addition, certain power operated valves cannot be repaired during plant operation, so maintenance on these components has no potential for causing unavailability.

Details of how maintenance contributes to unavailability for each component is discussed below.

PUMP: NUREG 0635 provides a calculational method for estimating main-MAINTEN- tenance unavailability for active components. Based on this ANCE methodology, the following formula is applicable to the Auxiliary Feedwater System pumps:

= 2.1 x 10-3 To check the validity of this estimate, a review was made of routine maintenance performed on the St. Lucie Unit 1 Auxiliary Feedwater System pumps. These pumps undergo semi-annual maintenance procedures during which the pumps are unavailable. A review of the maintenance records for the period November 1977 through July 1980 (approximately 2.3 x 104 hours0.0012 days 0.0289 hours 1.719577e-4 weeks 3.9572e-5 months ) indicates that the motor driven pumps A and B were undergoing maintenance for 71 and 55 hours6.365741e-4 days 0.0153 hours 9.093915e-5 weeks 2.09275e-5 months respectively and the turbine driven pump was under maintenance for 106 hours0.00123 days 0.0294 hours 1.752645e-4 weeks 4.0333e-5 months .

Assuming half of this semi-annual maintenance took place during plant shutdown, this yields the following estimates for pump unavailability during power operation:

MDP A: QMAINT = = 1.5 x 10 -3 MDP B: QMAINT = = 1.2 x 10 -3 TDP C: QMAINT = = 2.3 x 10 -3 Since these valves are in reasonable agreement with the estimate provided by NUREG 0635, a value of 2 x 10-3 was used to estimate maintenance unavailability for all pumps.

VALVE: Certain AFS valves are not accessible for maintenance during plant operation 10.4.9B-11 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 MAINTEN- because they directly interface with pressurized systems. A fault in such valves ANCE might require a plant shutdown in accordance with the LCO's which, while undesirable from an operations standpoint, virtually precludes the chance of maintenance on these valves from contributing to unavailability. These valves are 67, 68, 69 and 70 (TDP steam supply valves). However, for conservatism it is assumed that maintenance can be performed on all MOV's and solenoid operated valves during plant operation.

No routine maintenance is anticipated for manual valves and check valves. For motor operated and solenoid operated valves, the calculational method described in NUREG 0635 was used to estimate maintenance unavailability as follows:

=2.1 x 10-3 As indicated in Table 10.4.9B-5, this value was rounded to 2 x 10-3 and used for motor operated and solenoid operated valve maintenance unavailability.

DIESEL For the loss of offsite power case, diesel generator unavailability GENERATOR was included as the dominant cause of loss of ac power to MAINTEN- either of the motor driven pumps and associated ac power motor ANCE: operated valves. From WASH 1400, a value of 3 x 10-2 was used to estimate probability of failure to start on demand. In addition, diesel generator maintenance unavailability was estimated using the NUREG 0635 calculational method as follows:

QMAINT = 6.4 x 10-3 This value was rounded to 6 x 10-3 and combined with the probability of failure to start on demand (3x10-2) to yield an estimate of 3.6 x 10-2 for total diesel generator unavailability on demand as indicated in Table 10.4.9B-5.

10.4.9B-12 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 OTHER a) Regular Water Treatment - Hydrazine for cleaning is MAINTEN- intermittently injected into the Main Feedwater line through ANCE: one inch lines via check valve 53, 54 and manual valve 23, 24 as necessary to maintain water quality. These two lines are isolated by two normally closed globe valves in series from the AFS. Diversion of AFW flow to this chemical injection lines is unlikely.

b) AFS Water Treatment - This operation injects hydrazine into the normally stagnant AFS as necessary to maintain water quality, and may be conducted during plant operation. The isolation valves in series which are 25 and 26, 27 and 28, 29 and 30, 31 and 32 can be opened for chemical injection. Should these isolation be left open erroneously, diversion of flow to the main AFW discharge is very limited as they are one inch in diameter and further stopped by the check valve 53, 54 in the feed lines.

c) Random operator error - There exists a possibility that a manual valve could be left out of position following a test or maintenance outage. The probability of this occurring is calculated using the formula provided in NUREG-0635, Table III-2, Item III.A.1(a), middle column with local walk around and double check procedures with X taken as 15, the number of manual valves in the major AFS flow path.

OPERATOR ERRORS Four classes of operator errors were included as basic events in the base line (manual) system analysis. These are identified on the system fault tree and are defined as follows:

OE1 - Failure to take any operator action to operate system on demand.

OE2 - Omission of a step in the actuation sequence for the turbine driven pump and failure to take corrective action.

OE3 - Failure to switch AB dc bus to B dc power source upon failure of A dc power source.

OE4 - Failure to correctly utilize motor driven pump discharge cross tie to circumvent failures in a motor driven pump steam generator feed line.

These operator errors are listed in order of estimated increasing probability of failure. This judgment was arrived at based on a review of the availability of established procedures specifying the corrective action required and complexity of diagnosis and manual actions involved. The estimated probability for the basic event OE1 was 5 x 10-3 which is based on NUREG 0635 estimated failure data for the situation involving a non-dedicated operator with possible backup by another control room operator to actuate the auxiliary feed water system within 15 minutes. Since the action involved in OE1 is clearly specified in written procedures and is subject to periodic test as well as actual challenges, this value appears to be reasonable for failure to perform this basic function. Basic event OE2 involves the omitting of a step in the actuation sequence for the turbine driven pump given that the operator has initiated manual actuation. The manual start procedure for the motor driven pumps is much simpler than for the turbine driven pump and, given that OE1 has not occurred, it is assumed that failure to start the 10.4.9B-13 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 motor driven pumps is negligible. The OE2 error is judged to be more likely than OE1 and has been assigned a value of 1 x 10-2. Basic event OE3 involves error in failing to recognize the occurrence of a dc power source failure or errors in correctly implementing switchover procedures for transferring the AB dc power bus from one source to another. Since this involves additional complexity of diagnostic and manual actions than basic event OE2, it is assigned a higher probability of failure of 3 x 10-2. Basic event OE4 involves even further need to diagnose system failures and implement manual actions that are not fully described by procedure.

Accordingly, it is assigned a failure probability of 5 x 10-2 which is somewhat higher than the failure rate assigned to OE3.

The estimated failure probabilities for events OE1, OE2, and OE3 are applicable to the base line (manual system design), but do not contribute to the alternate (automatic) system design since they are obviated by automatic design features. Basic event OE4 applies to both the base line and alternate designs, but overall system unavailability on demand is insensitive to its assigned value. The values assigned to the operator error events are, therefore, of significance only in evaluating the degree of improvement offered by the automatic design over the manual design and will not affect the reliability estimate for the automatic design. Although the values assigned to the operator errors are based primarily on judgment, they are generally consistent with the human error estimates presented in NUREG/CR1278 considering the various modes of failure for each event. These include contributions from the use of improper procedures (3 x 10-3),

omission of a procedural step (1 x 10-3), selection of a wrong control switch (1 x 10-3),

manipulation of a wrong motor operated valve switch from among a group of switches (3 x 10-3) and failure to correctly recognize an annunciator function among a group of annunciators (1 x 10-2).

For the automatic design, an additional operation error (OE5) was included to account for failure of backup manual actuation upon failure of the automatic actuation system. The NUREG 0635 estimate of 1 x 10-2 for failure of a non dedicated operator to actuate a manual system was used as the failure rate for basic event OE5. No credit was taken for backup by other control room personnel.

10.4.9B.5.2 System Failure Probability Analysis The overall system failure probability was determined from the minimal cut sets and individual event probabilities using an option of the KITT 1 Code. In essence, the probability of each cut set is determined by multiplying the probability of each event in the cut set, and the system failure probability is determined by adding the probability of each cut set and corrections for simultaneous occurrence (i.e., bracketing) were made even though the numbers involved are quite small. The results are as follows:

Transient Unavailability Case 1 LOFW (Auto) 6.21 x 10-6 Case 2 LOOP (Auto) 1.90 x 10-5 Case 3 SB (Auto) 6.91 x 10-3 Case 4 LOFW (Manual) 5.01 x 10-3 Case 5 LOOP (Manual) 5.04 x 10-3 10.4.9B-14 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 Case 6 SB (Manual) 2.83 x 10-2 10.4.9B.6 Discussion of Results Case 1 LOFW - Automatic The dominant cut sets for Case 1 and their relative contribution to system failure are given on Table 10.4.9B-7a. The dominant cut sets fall into four basic system failure modes:

a. Failure of the CST Supply Valve (2) and other branching line valves contribute to 44 percent of the system failure. Its combination with Turbine Supply Valve 71A and TDP (Component III) are especially significant as they each account for 14.5 percent and 21 percent respectively.

b. Failure of TDP Train and other branching line valves or motor driven pumps account for 26 percent of the total system unavailability.

c. Simultaneous failure of valve 71A and other valves lead to 13 percent of the total failure probability.

d. The failure of both AFAS-1 & 2 signal (component 105, 106) and the manual start of the system contribute approximately eight percent of the system unavailability.

The above failure modes approximately account for 83 percent of the total system failure probability. The remaining 317 cut sets are of lesser importance.

The absolute value of the SL-2 AFS unavailability for Case 1 (LOFW) of 6.21 x 10-6 is in the high reliability range of Reference 1.

Case 2 LOOP - Automatic The dominant cut sets for Case 2 and their relative contribution to system failures are given in Table 10.4.9B-7b. These cut sets fall into three modes. No single major cut set of more than 10 percent contribution is found. Relatively important components are Valve 2, Valve 71A, TDP, AC buses and MDPs.

a. Closing of CST Supply Valve (2) and the combination with valve 71A or TDP (III) failure will contribute 4.75 and 6.8 percent respectively to the system unavailability.

b. Failure of valve 71A and other components account for 20 percent failure probability.

c. Failure of TDP and other components leads to 28.5 percent of the total.

The above failure modes account for 60 percent of the total system failure probability. The remaining 441 cut sets are of lesser importance which are less than or around 1 percent contribution. Owning to the loss of offsite power the major difference between Case 1 and Case 2 is the appearance of diesel generator AC power supply 101 and 102 in the cut set. Either one of them shows up in the 12 of the above 14 dominant sets.

10.4.9B-15 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 The absolute value of the SL-2 AFS unavailability for Case 2 of 1.90 x 10-5 is in the medium reliability range of Reference 1.

Case 3 SB - Automatic The dominant cut sets for Case 3 and their relative contribution to system failure are given on Table 10.4.9B-7c. As expected, there are a number of one event cut sets, since the motor driven pumps are deemed inoperable by the initial condition of Station Blackout for this case. The dominant contributions to system failure potential for this case is the turbine driven pump. Other major contributors are stream supply valve, valves in the discharge and suction side. Their relative contributions are 43, 30, 6 and one percent respectively.

The absolute value of AFS reliability for Case 3 of 6.91 x 10-3 is in the medium range of Reference 1.

Case 4 LOFW Manual The dominant cut sets for Case 4 and their relative contribution to system failure are given on Table 10.4.9B-8a. The dominant cut sets fall into three basic system failure modes:

a. Failure of proper action by operator (OE 1) is the most significant contributor to the unavailability of the system. (99.72%)

b. Plugging of the CST supply valve (2) and other branch line valves contribute .2%

of the total failure.

c. Failure of motor driven pump A or B and other components contribute .058%

system unavailability.

The above failure modes approximately account for 99.98% of the total system failure probability with the OE 1 as the single most significant factor. The remaining 257 minimal cut sets are of much lesser importance when compared to OE 1.

The absolute value of the manual AFS unavailability for Case 4 is 5.01 x 10-3.

Case 5 LOOP Manual The dominant cut sets for Case 5 and their relative contributions to system failures are given in Table 10.4.9B-8b. The dominant cut sets fall into three modes:

a. Similar to Case 4, failure to take any operator action to operate system on demand (OE1) contributes to 99.1% of the failure probability.

b. Plugging of valve 2 and other components lead to .19% of the unavailability.

c. Failure of one of the ac power supply (101, 102) and one of the motor driven pumps (110, 112) account for .44%

The above failure modes account for 99.7% of the total system failure probability. The remaining 367 cut sets are of lesser importance. In any event, the contribution of various components is relatively insignificant when compared with the OE 1.

10.4.9B-16 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 The absolute value of the manual AFS unavailability for case 5 is 5.04 x 10-3.

Case 6 SB Manual The dominant cut sets for Case 6 and their relative contribution of system failure are given on Table 10.4.9B-8c. As expected, most of the dominant cut sets are one event cut sets, since the motor driven pumps are inoperable by the initial condition of Station Blackout. The more significant contributors out of the 54 sets are OE 2, Valve 71, OE 1, Turbine driven pump 111 with relative probability of 35, 32, 17, 10% respectively. The above modes account for 95-53% of the system unavailability.

The absolute value of the manual AFS unavailability for case 6 is 2.83 x 6-2.

The SL2 AFS use of automatic actuation and the manual operation are shown here in comparison. As can be seen from Tables 10.4.9B-8a, 8b, and 8c, operator error OE 1 which fails to react on demand contributes to 99% of the failure probability in Case 5 and 6 where as OE 1 and OE 2 contribute to 65% in Case 7. The reliability of SL 2 AFS in all three accidents have been improved in order of magnitude by automation.

10.4.9B.7 Conclusions No acceptance criteria for this study were given, but as noted in the previous section the results were good when compared to the other plants studied in Reference 1. The main reasons that favorable results were achieved for the automatic system design are:

a. The active components and flow paths are redundant, so there are no single point vulnerabilities.

b. The system is automatically actuated, so no human action is required.

c. System design is such that all routine testing can be done with no incapacitating realignments or locking out of components.

d. There are few interconnections with the other systems, minimizing the potential for adverse interactions with other systems.

The analysis did not uncover any areas where minor changes could result in major reliability improvements. Reliability has always been a subjective consideration in the design and intended operating/maintenance practices for this system, and this quantitative reliability analysis confirmed that.

This study was useful in demonstrating that the SL-2 AFS is of high reliability, and that there were no major faults in the system design. However, care should be taken in applying the numerical results too literally. In particular, the unavailability reported for Case 1 & Case 2 begins to approach a judgemental lower bound on achievable unavailability for any system due to unidentified common cause failures. For this reason, there is probably little actual system reliability improvements to be gained even by major changes such as adding more pumps.

10.4.9B-17 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2

References:

1. Letter from D Ross to all Westinghouse and Combustion Engineering Operating License Applicants, dated March 10, 1980.

2. NUREG/CR-1278, "Handbook of Human Reliability Analysis with Emphasis on Nuclear Power Plant Applications," October 1980.

10.4.9B-18 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-1 COMPONENT LIST MANUAL VALVES VALVE NO. DESCRIPTION 1 2I-V12506 (612) Isolation valve on CST TDP suction line 2 2I-V12497 (612) Isolation valve on CST MDP suction line A&B 3 2I-V12801 (612) Isolation valve on line to Unit 1 water source for TDP 4 2I-V12802 (612) Isolation valve on line to Unit 1 water source for MDP A&B 5 2I-V12498 (611) Isolation valve on MDP-A Suction 6 2I-V12508 (612) Isolation valve on TDP Suction 7 2I-V12502 (611) Isolation valve on MDP-B Suction 8 2I-V9100 (326) Isolation valve on MDP-A mini-recirculation 9 2I-V9103 (327) Isolation valve on TDP mini-recirculation 10 2I-V9101 (326) Isolation valve on MDP-B mini-recirculation 11 2I-V9104 (327) Isolation valve on common mini-recirculation 12 2I-V9108 (310) Isolation valve on MDP-A discharge 13 2I-V9140 (311) Isolation valve on TDP discharge 14 2I-V9124 (310) Isolation valve on MDP-B discharge T10.4.9B-1 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-1 (Cont'd)

VALVE NO. DESCRIPTION 15 2I-V9120 (310A) Isolation valve from MDP-A to SG-1 16 2I-V9152 (310A) Isolation valve from TDP to SG-1 17 2I-V9158 (310A) Isolation valve from TDP to SG-2 18 2I-V9136 (310A) Isolation valve from MDP-B to SG-2 19 2I-V8622 (325) Isolation valve on TDP steam supply line drain 20 2-V8623 (325) Isolation valve on TDP steam supply line drain 21 2I-V8618 (324) Isolation valve on TDP stop valve drain 22 2I-V8619 (324) Isolation valve on TDP stop valve drain 23 2-V9310 (1125) Isolation valve on chem inject to main feedwater A 24 2-V9290 (1125) Isolation valve on chem inject to main feedwater B 25 2I-V9523 (1325) Isolation valve on chem inject to MDP-A 26 2I-V9291 (1325) Isolation valve on chem inject to MDP-A 27 2I-V9292 (1325) Isolation valve on chem inject to TDB train A 28 2I-V9524 (1325) Isolation valve on chem inject to TDB train A 29 2I-V9526 (1325) Isolation valve on chem inject to TDB train B 30 2I-V9284 (1325) Isolation valve on chem inject to TDB train B 31 2I-V9293 (1325) Isolation valve on to chem inject MDP-B 32 2I-V9525 (1325) Isolation valve on to chem inject MDP-B T10.4.9B-2 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10-4.9B-1 (Cont'd)

POWER OPERATED VALVE VALVE DESCRIPTION 15A* I-SE-09-2 Solenoid SA-AC Isolation valve from MDP-A to SG-1 16B* I-SE-09-4 Solenoid SB-DC Isolation valve from TDP to SG-1 17A* I-SE-09-5 Solenoid SA-DC Isolation valve from TDP to SG-2 18B* I-SE-09-3 Solenoid SB-AC Isolation valve from MDP-B to SG-2 61 I-MV-09-13 Motor SA-AC Isolation valve from MDP-A to cross-tie 62 I-MV-09-14 Motor SB-AC Isolation valve from MDP-B to cross-tie 63 I-MV-09-9 Motor SA-AC Throttle valve from MDP-A 64 I-MV-09-11 Motor SAB-DC Throttle valve from TDP to SG-1 64* I-MV-09-11 Motor SB-DC Throttle valve from TDP to SG-1 65 I-MV-09-12 Motor SAB-DC Throttle valve from TDP to SG-2 65* I-MV-09-12 Motor SA-DC Throttle valve from TDP to SG-2 66 I-MV-09-10 Motor SB-AC Throttle valve from MDP-B 67 I-MV-08-13 Motor SB-DC Isolation valve on steam supply to TDP from SG-1 67* I-MV-08-13 Motor SB-DC Isolation valve on steam supply to TDP from SG-1

in automatic initiation case T10.4.9B-3 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-1 (Cont'd)

POWER OPERATED VALVE VALVE DESCRIPTION 68 I-MV-08-12 Motor SA-DC Isolation valve on steam supply to TDP from SG-2 68 I-MV-08-12* Motor SA-DC Isolation valve on steam supply to TDP from SG-2 69 I-SE-08-2 Solenoid SA-DC Warmup valve on steam supply to TDP from SG-1 70 I-SE-08-1 Solenoid SB-DC Warm-up valve on steam supply to TDP from SG-2 71A I-MV-08-3 Motor SAB-DC Stop valve on steam supply to TDP T10.4.9B-4 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-1 (Cont'd CHECK VALVE VALVE NO DESCRIPTION 41 2I-V9305 (346) Mini-recirculation for MDP-A 42 2I-V9-9303 (347) Mini-recirculation for TDP 43 2I-V9304 (346) Mini-recirculation for MDP-B 44 2I-V9107 (350) Pump discharge, MDP-A 45 2I-V9139 (351) Pump discharge, TDP 46 2I-V9123 (350) Pump discharge, MDP-B 47 2I-V9119 (350) Discharge to SG-1 from MDP-A 48 2I-V9151 (350) Discharge to SG-1 from TDP 49 2I-V9157 (350) Discharge to SG-2 from TDP 50 2I-V9135 (350) Discharge to SG-2 from MDP-B 51 2I-V8130 (350) Steam Supply to TDP from SG-1 52 2I-V8163 (350) Steam Supply to TDP from SG-2 53 2-V9350 (1145) Chem inject to SG-1 54 2-V9287 (1145) Chem inject to SG-2 T10.4.9B-5 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-1 (Cont'd)

PUMPS PUMP CAPACITY 110: "A" MOTOR DRIVEN* MDP-A Full capacity - 320 gpm 111: TURBINE DRIVEN TDP Full capacity - 500 gpm 112: "B" MOTOR DRIVEN* MDP-B Full capacity - 320 gpm ACTUATING LOGIC SIGNAL PURPOSE 105: AFAS 1 Indicates SG 1 is intact and is in need of AFW, Actuates the following:

AFAS 1A MDP-A AFAS 1A V63 AFAS 1B V64 AFAS 1B V67 AFAS 1C V15A AFAS 1D V16B 106: AFAS 2 Indicates SG 2 is intact and is in need of AFW, Actuates the following:

AFAS 2A V65 AFAS 2A V68 AFAS 2B V66 AFAS 2B MDP-B AFAS 2C V17A AFAS 2D V18B TDP Overspeed Indicates failure of TDP speed control; closes TDP steam stop valve (Valve 71A)

TDP Speed Control Regulates TDP governor valve (Valve as necessary to maintain pump speed)

T10.4.9B-6 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10-4.9B-1 (Cont'd)

POWER SUPPLY SYSTEM SERVICED COMPONENTS 101: SA ac-4kV & 480 V "A" MDP & Valves 102: SB ac-4kV & 480 V "B" MDP & Valves 103: SA dc Battery Valves 104: SB dc Battery Valves T10.4.9B-7 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-2 AFS FAILURE MODES AND EFFECTS ANALYSIS COMPONENT COMPONENT STATE EFFECT INHERENT COMPENSATION I. CONDENSATE SUPPLY (SUCTION) TO AFS PUMPS

- Manual Valve 1 - Open Normal ----

- Closed Loss one out of two suction Another suction line available lines to AFWPs

- Manual Valve 2 - Open Normal ----

- Closed Loss one out of two suction Another suction line available lines to AFWPs

- Manual Valve 3 - Open Potential of CST draining N.C. valve downstream prevent drainage

- Closed Normal ----

- Manual Valve 4 - Open Potential of CST draining N.C. valve downstream prevent drainage

- Closed Normal ----

- Manual Valve 5 - Open Normal ----

- Closed Loss of suction line to MDP-A Lines to MDP-B & TDP available

- Manual Valve 6 - Open Normal ----

- Closed Loss of suction line to TDP Lines to MDP-A & B available

- Manual Valve 7 - Open Normal ----

- Closed Loss of suction line to MDP-B Lines to MDP-B & TDP available II-A. MOTOR DRIVEN PUMP BLOCK (MDP-A)

- Pump/Motor - Fail to start Fluid not delivered from pump None, but MDP-B & TDP not affected

- SA ac Power (4kV & 480 V) - Fail to energize motor Fluid not delivered from pump None, but MDP-B & TDP not affected

- AFAS 1a Logic - Signal not generated Loss of MDP "A" None but TDP and "B" MDP not affected

- Manual Valve 8 - Open Normal State ----

- Closed Loss of "A" MDP mini-flow recir- None, but TDP and "B" MDP not culation; no immediate effect, but affected; "A" MDP initial re-possible pump damage when SG isolation sponse not affected valves cycle closed T10.4.9B-8 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-2(Cont'd)

COMPONENT COMPONENT STATE EFFECT INHERENT COMPENSATION

- Check Valve 41 - Open (against forward Proper State ----

current)

- Closed (against Proper State reverse current)

- Open (against TDP and "B" MDP partial mini-flow ----

reverse current) recirculation through idle "A" MDP loop; No problem

- Closed (against Loss of "A" MDP mini-flow None, but TDP and "B" not forward current) recirculation; no immediate effect, affected; "A" MDP initial start but possible pump damage when SG not affected isolation valves cycle closed

- Check Valve 44 - open (against forward Proper State ----

current)

- Closed (against Proper State ----

reverse current)

- Open (against Most "B" MDP flow diverted TDP available to supply required reverse current) from SGs to recirc through idle "A" flow MDP loop; if cross tie valves are opened

- Closed (against Fluid not delivered towards header None, but TDP and "B" MDP not forward current) affected Manual Valve 12 - Open Normal State ----

- Closed Fluid not delivered towards header None, but TDP and "B" MDP not affected II.T.1 TURBINE DRIVEN PUMP STEAM SUPPLY

- Motor Valve 67 - Open Proper Operation ----

- Closed Loss of SG1 steam supply to TDP SG2 steam supply not affected

- Check Valve 51 - Open (against Proper Operation ----

forward current)

- Closed (against Loss of SG1 steam supply to TDP SG2 steam supply not affected forward current)

T10.4.9B-9 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-2(Cont'd)

COMPONENT COMPONENT STATE EFFECT INHERENT COMPENSATION

- Motor Valve 68 - Open Proper Operation ----

- Closed Loss of SG2 steam supply to TDP SG1 steam supply not affected

- Check Valve 52 - open (against forward Proper State current)

- Closed Loss of SG2 steam supply to TDP SG1 steam supply available

- Motor Op. Valve 71A - Open Normal State ----

- Closed Loss of all steam supply to TDP None, but "A" and "B" MDPs not affected AFAS-1b Logic - Failure to be generated Loss of automatic open signals MDP "A" and MDP "B" and TDP to Valve 67 available AFAS-2a Logic - Failure to be generated Loss of automatic open signals MDP "A" and MDP "B" and TDP to Valve 68 available Valve 19, 20, 21, 22 These valves are on drain lines serving the TDP steam supply line, and as such, must be evaluated for their potential to divert steam from the TDP. Because of their small size (1") they are not considered to be capable of diverting any significant quantity of steam.

II.T.2 TURBINE DRIVEN PUMP BLOCK

- Pump/Turbine - Fails to start Fluid not delivered towards header None, but "A" and "B" MDPs not affected

- Manual Valve 9 - Open Normal State

- Closed Loss of TDP mini-flow recirculation; None, but "A" and "B" MDPs no immediate effect, but possible pump not affected; TDP initial start damage when SG isolation valves cycle not affected closed

- Check Valve 42 - Open (against Proper State ----

forward current)

- Closed (against Proper State reverse current)

- Open (against "A" and "B" MDP partial mini-flow ----

reverse current) recirculation through idle TDP loop; No problem

- Closed (against Loss of TDP mini-flow recirculation; None, but "A" and "B" MDPs forward current) no immediate effect, but possible not affected; TDP initial start pump damage when SG isolation valves not affected cycle closed T10.4.9B-10 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-2(Cont'd)

COMPONENT COMPONENT STATE EFFECT INHERENT COMPENSATION

- Check Valve 45 - Open (against Proper Operation ----

forward current)

- Closed (against Proper Operation ----

reverse current)

- Closed (against Fluid not delivered towards header None, but "A" and "B" MDPs forward current) not affected

- Open (against Fluid not delivered towards header MDP "A" and "B" not affected reverse current)

- Manual Valve 13 - Open Normal State ----

- Closed Pump doesn't deliver fluid towards None, but "A" and "B" MDPs header affected II-B MOTOR DRIVEN PUMP BLOCK (MDP-8)

- Pump/Motor - Fail to Start Fluid not delivered from pump None, but MDP-B TDP not affected

- SA ac Power (4.16kV & - Fail to energize motor Fluid not delivered from pump None, but MDP-B TDP not 480 V) affected

- AFAS 2b - Signal not generated Loss of MDP 2B None, but TDP and "A" MDP not affected

- Manual Valve 10 - Open Normal State ----

- Closed Loss of "B" MDP mini-flow recir- None, but TDP and "A" MDP not culation; no immediate effect, but affected; "B" MDP initial re-possible pump damage when SG isolation sponse not affected valves cycle closed

- Check Valve 43 - Open (against forward Proper State ----

current)

- Closed (against Proper State ----

reverse current)

- Open (against TDP and "A" partial mini-flow ----

reverse current) recirculation through idle "B" MDP loop; No problem

- Closed (against Loss of "B" MDP mini-flow None, but TDP and "A" MDP not forward current) Recirculation; no immediate effect, affected; "A" MDP initial start but possible pump damage when SG not affected isolation valves cycle closed T10.4.9B-11 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-2(Cont'd)

COMPONENT COMPONENT STATE EFFECT INHERENT COMPENSATION

- Check Valve 46 - Open (against forward Proper State ----

current)

- Closed (against Proper State ----

reverse current)

- Open (against Most "A" MDP flow diverted TDP is available to supply reverse current) from SGs to recirc through idle "B" required flow MDP loop, if crosstie is in use

- Closed (against Fluid not delivered towards header None, but "A" MDP and TDP not reverse current) affected

- Manual Valve 14 - Open Normal State ----

- Closed Fluid not delivered towards header None, but "A" MDP and TDP not affected

- Manual Valve 11 - Open Normal ----

- Closed Loss of mini-flow for all three pumps; None no immediate effect, but possible pump damage when isolation valves closed III.1 STEAM GENERATOR-1 FLOW PATH

- Manual Valve 15 - Open Normal State ----

- Close Fluid not delivered towards None, but MDP-B and TDP not towards header affected

- Solenoid Valve 15A - Open on signal, Proper State ----

- fail to open No flow to SG-1 via MDP-A None, flow available to SG-1 from TDP via redundant line

- Motor Valve 63 - Open on signal Proper State ----

- fail to open No flow to SG-1 via MDP-A None, flow available from TDP via redundant line

- Check Valve 47 - Open (against forward Proper State ----

current)

- Closed (against re- Proper State ----

verse current)

- open (against re- Flow from MDP-A to SG-1 Check valve 44 closes to prevent back verse current) diverted flow

- Closed (against No flow to SG-1 By MDP-A None, flow available from TDP forward current) via redundant line T10.4.9B-12 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-2(Cont'd)

COMPONENT COMPONENT STATE EFFECT INHERENT COMPENSATION

- Manual Valve 23, 25, 26, Normally closed valve 25, 2b, 27, 28 & check valve 53 prevent diversion of flow from MDP-A & TDP, Valve 23 (N.O.) has 27, 28 slight chance to divert flow

- Check Valve 53

- Motor Valve 61 - Open on signal Proper State ----

- Fails to close on signal May divert flow Valve 62 in series N.C.

- Fails to open on signal Cannot divert flow from MDP-A to SG-2 None, MDP-B & TDP available

- Manual Valve 16 - Open Normal State ----

- Close Flow not delivered towards None, but MDP-B and TDP to header SG-2 not affected

- Solenoid Valve 16B - Open on signal Proper State ----

- Fails to open No flow to SG-1 via TDP None, flow available from MDP-A via redundant line

- Motor Valve 64 - Open on signal Proper State ----

- Fails to open No flow to SG-1 via TDP None, flow available from MDP-A via redundant line

- Check valve 48 - Open (against forward Proper State ----

current)

- Closed (against re- Proper State ----

verse current)

- Open (against re- MDP flow to SG-1 diverted Check valve 45 close to verse current) prevent back flow

- Closed (against for- No flow to SG-1 by TDP none, flow available from MDP-A ward current) via redundant line AFAS 1C Signal not generated Loss of automatic MDP "B" and TDP not affected open signal to V15A AFAS 1B Signal not generated Loss of automatic signal MDP "A" and MDP "B" not affected to V 16B AFAS 1A Signal not generated Loss of automatic signal to V 63 MDP "B" and TDP not affected AFAS 1B Signal not generated Loss of automatic signal to V 64 MDP "A" and MDP "B" not affected III.2 STEAM GENERATION-1 FLOW PATH

- Solenoid Valve 18B - Open on signal Proper State ----

- fails to open No flow to SG-1 via MDP-B None, flow available from TDP via another line T10.4.9B-13 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-2(Cont'd)

COMPONENT COMPONENT STATE EFFECT INHERENT COMPENSATION

- Motor Valve 66 - Open on signal Proper State ----

- fails to open No flow to SG-2 via MDP-B None, flow available from TDP via redundant line

- Check Valve 50 - Open (against forward Proper State ----

current)

- Closed (against re- Proper State ----

verse current)

- Open (against re- TDP flow diverted from SG-2 Check valve 46 closed to verse current) prevent back flow

- Closed (against for- No flow to SG-2 by MDP-B None, flow available from TDP via ward current) redundant line

- Manual Valve 24, 29, 30, Normally closed valve 29, 30, 31, 32 & check valve 54 present diversion of flow from MDP-A & TDP, Valve 24 (N.O.) has 31, 32 slight chance to divert flow

- Check Valve 54

- Motor Valve 62 - open on signal Proper State (N.C.) ----

- Fails to close on May divert flow Valve 61 in series N.C.

signal

- Fails to open on signal Cannot divert flow from MDP-1 to SG-2 None, MDP-2 & TDP available

- Solenoid Valve 17A - Open on signal Proper State ----

- fails to open No flow to SG-2 via TDP None, flow available from MDP-B via redundant line

- Manual Valve 17 - Open Normal State ----

- Close Flow not delivered to header None, but MDP "A" and "B" and TDP available

- Manual Valve 18 - Open Normal State ----

- Close Flow not delivered to header None, but MDP "A" and TDP avail-able

- Motor Valve 65 - Open on signal Proper State ----

- fails to open No flow to SG-2 via TDP None, flow available from MDP-B via redundant line

- Check Valve 49 - Open (against forward Proper State ----

current)

- Closed (against re- Proper State ----

verse current)

- Open (against re- Most MDP B flow diverted from SG-2 Check valve 45 closes to verse current) prevent back flow

- Closed (against for- No flow to SG-2 by TDP None, flow available from MDP-B ward current) via redundant line T10.4.9B-14 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-2(Cont'd)

COMPONENT COMPONENT STATE EFFECT INHERENT COMPENSATION AFAS 2a Signal not generated Loss of automatic None, but MDP "A" and MDP "B" open signal to V 65 not affected AFAS 2b Signal not generated Loss of automatic None, but MDP "A" and TDP not open signal to V 66 affected AFAS 2c Signal not generated Loss of automatic None, but MDP "A" and MDP "B" open signal to V 17A not affected AFAS 2d Signal not generated Loss of automatic None, but MDP "A" and TDP not open signal to V 18B affected IV. OVERALL SYSTEM FUNCTION In LOFW and LOOP system minimum function is fulfilled when a total of 320 gpm is delivered to the steam generator(s) upon ASAS. This can be accomplished if any one of the pumps is able to deliver fluid to any one steam generator. Thus, using DeMorgans theorem, system function is not fulfilled if all of the pumps are unable to deliver fluid to both steam generators, ie, "A" MDP can't deliver to SG1 AND "A" can't deliver to SG2 AND "B" MDP can't deliver to SG1 AND "B" MDP can't deliver to SG2 AND TDP can't deliver to SG1 AND TDP can't deliver to SG2.

These failure conditions effectively relate failures of the system blocks to overall system function.

T10.4.9B-15 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-3a CUT SETS - LOFW AUTOMATIC AUXILIARY FEEDWATER SYSTEM INITIATION Cut Set Component 1 F103AD F104BD 2 V2CL V71A 3 V6CL V2CL 4 V1CL V2CL 5 F111T V2CL 6 V13CL V2CL 7 V45F V2CL 8 F105 F106 OE5 9 F104BD F105 OE5 10 F103AD F106 OE5 11 F112MB V67F F103AD 12 F112MB V51F F103AD 13 V71A V15A V66F 14 V71A V15A V18B 15 V71A V15A V18 16 V71A V15 V66F 17 V71A V15 V18B 18 V71A V15 V18 19 V71A V63F V66F 20 V71A V63F V18B 21 V71A V63F V18 22 V71A F112MB F103AD 23 F110MA V68F F104BD 24 F110MA V52F F104BD 25 F110MA V71A F104BD 26 F110MA V71A F112MB 27 V2CL V68F F104BD 28 V2CL V67F F103AD 29 V2CL V67F V68F 30 V2CL V52F F104BD 31 V2CL V52F V67F 32 V2CL V51F F103AD 33 V2CL V51F V68F 34 V2CL V51F V52F 35 V7CL V67F F103AD 36 V7CL V51F F103AD 37 V7CL V71A F103AD 38 V7CL F110MA V71A 39 V46F V67F F103AD 40 V46F V51F F103AD 41 V46F V71A F103AD 42 V46F F110MA V71A 43 V14CL V67F F103AD 44 V14CL V51F F103AD T10.4.9B-16 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-3a (Cont'd)

Cut Set Component 45 V14CL V71A F103AD 46 V14CL F110MA V71A 47 V6CL V15A V66F 48 V6CL V15A V18B 49 V6CL V15A V18 50 V6CL V15 V66F 51 V6CL V15 V18B 52 V6CL V15 V18 53 V6CL V63F V66F 54 V6CL V63F V18B 55 V6CL V63F V18 56 V6CL F112MB F103AD 57 V6CL F110MA F104BD 58 V6CL F110MA F112MB 59 V6CL V7CL F103AD 60 V6CL V7CL F110MA 61 V6CL V46F F103AD 62 V6CL V46F F110MA 63 V6CL V14CL F103AD 64 V6CL V14CL F110MA 65 V1CL V15A V66F 66 V1CL V15A V18B 67 V1CL V15A V18 68 V1CL V15 V66F 69 V1CL V15 V18B 70 V1CL V15 V18 71 V1CL V63F V66F 72 V1CL V63F V18B 73 V1CL V63F V18 74 V1CL F112MB F103AD 75 V1CL F110MA F104BD 76 V1CL F110MA F112MB 77 V1CL V7CL F103AD 78 V1CL V7CL F110MA 79 V1CL V46F F103AD 80 V1CL V46F F110MA 81 V1CL V14CL F103AD 82 V1CL V14CL F110MA 83 F111T V15A V66F 84 F111T V15A V18B 85 F111T V15A V18 86 F111T V15 V66F 87 F111T V15 V18B 88 F111T V15 V18 T10.4.9B-17 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-3a (Cont'd)

Cut Set Component 89 F111T V63F V66F 90 F111T V63F V18B 91 F111T V63F V18 92 F111T F112MB F103AD 93 F111T F110MA F104BD 94 F111T F110MA F112MB 95 F111T V7CL F103AD 96 F111T V7CL F110MA 97 F111T V46F F103AD 98 F111T V46F F110MA 99 F111T V14CL F103AD 100 F111T V14CL F110MA 101 V13CL V15A V66F 102 V13CL V15A V18B 103 V13CL V15A V18 104 V13CL V15 V66F 105 V13CL V15 V18B 106 V13CL V15 V18 107 V13CL V63F V66F 108 V13CL V63F V18B 109 V13CL V63F V18 110 V13CL F112MB F103AD 111 V13CL F110MA F104BD 112 V13CL F110MA F112MB 113 V13CL V7CL F103AD 114 V13CL V7CL F110MA 115 V13CL V46F F103AD 116 V13CL V46F F110MA 117 V13CL V14CL F103AD 118 V13CL V14CL F110MA 119 V45F V15A V66F 120 V45F V15A V18B 121 V45F V15A V18 122 V45F V15 V66F 123 V45F V15 V18B 124 V45F V15 V18 125 V45F V63F V66F 126 V45F V63F V18B 127 V45F V63F V18 128 V45F F112MB F103AD 129 V45F F110MA F104BD 130 V45F F110MA F112MB 131 V45F V7CL F103AD 132 V45F V7CL F110MA T10.4.9B-18 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-3a (Cont'd)

Cut Set Component 133 V45F V46F F103AD 134 V45F V46F F110MA 135 V45F V14CL F103AD 136 V45F V14CL F110MA 137 V12CL V68F F104BD 138 V12CL V52F F104BD 139 V12CL V71A F104BD 140 V12CL V71A F112MB 141 V12CL V7CL V71A 142 V12CL V46F V71A 143 V12CL V14CL V71A 144 V12CL V6CL F104BD 145 V12CL V6CL F112MB 146 V12CL V6CL V7CL 147 V12CL V6CL V46F 148 V12CL V6CL V14CL 149 V12CL V1CL F104BD 150 V12CL V1CL F112MB 151 V12CL V1CL V7CL 152 V12CL V1CL V46F 153 V12CL V1CL V14CL 154 V12CL F111T F104BD 155 V12CL F111T F112MB 156 V12CL F111T V7CL 157 V12CL F111T V46F 158 V12CL F111T V14CL 159 V12CL V13CL F104BD 160 V12CL V13CL F112MB 161 V12CL V13CL V7CL 162 V12CL V13CL V46F 163 V12CL V13CL V14CL 164 V12CL V45F F104BD 165 V12CL V45F F112MB 166 V12CL V45F V7CL 167 V12CL V45F V46F 168 V12CL V45F V14CL 169 V44F V68F F104BD 170 V44F V52F F104BD 171 V44F V71A F104BD 172 V44F V71A F112MB 173 V44F V7CL V71A 174 V44F V46F V71A 175 V44F V14CL V71A 176 V44F V6CL F104BD T10.4.9B-19 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-3a (Cont'd)

Cut Set Component 177 V44F V6CL F112MB 178 V44F V6CL V7CL 179 V44F V6CL V46F 180 V44F V6CL V14CL 181 V44F V1CL F104BD 182 V44F V1CL F112MB 183 V44F V1CL V7CL 184 V44F V1CL V46F 185 V44F V1CL V14CL 186 V44F F111T F104BD 187 V44F F111T F112MB 188 V44F F111T V7CL 189 V44F F111T V46F 190 V44F F111T V14CL 191 V44F V13CL F104BD 192 V44F V13CL F112MB 193 V44F V13CL V7CL 194 V44F V13CL V46F 195 V44F V13CL V14CL 196 V44F V45F F104BD 197 V44F V45F F112MB 198 V44F V45F V7CL 199 V44F V45F V46F 200 V44F V45F V14CL 201 V5CL V68F F104BD 202 V5CL V52F F104BD 203 V5CL V71A F104BD 204 V5CL V71A F112MB 205 V5CL V7CL V71A 206 V5CL V46F V71A 207 V5CL V14CL V71A 208 V5CL V6CL F104BD 209 V5CL V6CL F112MB 210 V5CL V6CL V7CL 211 V5CL V6CL V46F 212 V5CL V6CL V14CL 213 V5CL V1CL F104BD 214 V5CL V1CL F112MB 215 V5CL V1CL V7CL 216 V5CL V1CL V46F 217 V5CL V1CL V14CL 218 V5CL F111T F104BD 219 V5CL F111T F112MB 220 V5CL F111T V7CL T10.4.9B-20 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-3a (Cont'd)

Cut Set Component 221 V5CL F111T V46F 222 V5CL F111T V14CL 223 V5CL V13CL F104BD 224 V5CL V13CL F112MB 225 V5CL V13CL V7CL 226 V5CL V13CL V46F 227 V5CL V13CL V14CL 228 V5CL V45F F104BD 229 V5CL V45F F112MB 230 V5CL V45F V7CL 231 V5CL V45F V46F 232 V5CL V45F V14CL 233 V17A F110MA F104BD 234 V17A V2CL F104BD 235 V17A V12CL F104BD 235 V17A V44F F104BD 237 V17A V5CL F104BD 238 V17 F110MA F104BD 239 V17 V2CL F104BD 240 V17 V12CL F104BD 241 V17 V44F F104BD 242 V17 V5CL F104BD 243 V16B F112MB F103AD 244 V16B V2CL F103AD 245 V16B V7CL F103AD 246 V16B V46F F103AD 247 V16B V14CL F103AD 248 V16B V17A V2CL 249 V16B V17 V2CL 250 V16 F112MB F103AD 251 V16 V2CL F103AD 252 V16 V7CL F103AD 253 V16 V46F F103AD 254 V16 V14CL F103AD 255 V16 V17A V2CL 256 V16 V17 V2CL 257 V65F F110MA F104BD 258 V65F V2CL F104BD 259 V65F V12CL F104BD 260 V65F V44F F104BD 261 V65F V5CL F104BD 262 V65F V16B V2CL 263 V65F V16 V2CL 264 V64F F112MB F103AD T10.4.9B-21 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-3a (Cont'd)

Cut Set Component 265 V64F V2CL F103AD 266 V64F V7CL F103AD 267 V64F V46F F103AD 268 V64F V14CL F103AD 269 V64F V17A V2CL 270 V64F V17 V2CL 271 V64F V65F V2CL 272 V50F V71A V15A 273 V50F V71A V15 274 V50F V71A V63F 275 V50F V6CL V15A 276 V50F V6CL V15 277 V50F V6CL V63F 278 V50F V1CL V15A 279 V50F V1CL V15 280 V50F V1CL V63F 281 V50F F111T V15A 282 V50F F111T V15 283 V50F F111T V63F 284 V50F V13CL V15A 285 V50F V13CL V15 286 V50F V13CL V63F 287 V50F V45F V15A 288 V50F V45F V15 289 V50F V45F V63F 290 V49F F110MA F104BD 291 V49F V2CL F104BD 292 V49F V12CL F104BD 293 V49F V44F F104BD 294 V49F V5CL F104BD 295 V49F V16B V2CL 296 V49F V16 V2CL 297 V49F V64F V2CL 298 V48F F112MB F103AD 299 V48F V2CL F103AD 300 V48F V7CL F103AD 301 V48F V46F F103AD 302 V48F V14CL F103AD 303 V48F V17A V2CL 304 V48F V17 V2CL 305 V48F V65F V2CL 306 V48F V49F V2CL 307 V47F V71A V66F 308 V47F V71A V18B T10.4.9B-22 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-3a (Cont'd)

Cut Set Component 309 V47F V71A V18 310 V47F V6CL V66F 311 V47F V6CL V18B 312 V47F V6CL V18 313 V47F V1CL V66F 314 V47F V1CL V18B 315 V47F V1CL V18 316 V47F F111T V66F 317 V47F F111T V18B 318 V47F F111T V18 319 V47F V13CL V66F 320 V47F V13CL V18B 321 V47F V13CL V18 322 V47F V45F V66F 323 V47F V45F V18B 324 V47F V45F V18 325 V47F V50F V71 326 V47F V50F V6CL 327 V47F V50F V1CL 328 V47F V50F F111T 329 V47F V50F V13CL 330 V47F V50F V45F T10.4.9B-23 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-3b CUT SETS - LOOP AUTOMATIC AUXILIARY FEEDWATER SYSTEM STUDY Cut Set Component 1 F103AD F104BD 2 V2CL V71A 3 V6CL V2CL 4 V1CL V2CL 5 F111T V2CL 6 V13CL V2CL 7 V45F V2CL 8 F105 F106 OE5 9 F104BD F105 OE5 10 F103AD F106 OE5 11 V68F F104BD F101AA 12 V67F F103AD F102BA 13 V52F F104BD F101AA 14 V51F F103AD F102BA 15 F112MB V67F F103AD 16 F112MB V51F F103AD 17 V71A V15A V66F 18 V71A V15A F102BA 19 V71A V15A V18B 20 V71A V15A V18 21 V71A F101AA V66F 22 V71A F101AA F102BA 23 V71A F101AA V18B 24 V71A F101AA V18 25 V71A V15 V66F 26 V71A V15 F102BA 27 V71A V15 V18B 28 V71A V15 V18 29 V71A V63F V66F 30 V71A V63F F102BA 31 V71A V63F V18B 32 V71A V63F V18 33 V71A F104BD F101AA 34 V71A F103AD F102BA 35 V71A F112MB F101AA 36 V71A F112MB F103AD 37 F110MA V68F F104BD 38 F110MA V52F F104BD 39 F110MA V71A F102BA 40 F110MA V71A F104BD 41 F110MA V71A F112MB 42 V2CL V68F F104BD T10.4.9B-24 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-3b (Cont'd)

Cut Set Component 43 V2CL V67F F103AD 44 V2CL V67F V68F 45 V2CL V52F F104BD 46 V2CL V52F V67F 47 V2CL V51F F103AD 48 V2CL V51F V68F 49 V2CL V51F V52F 50 V7CL V67F F103AD 51 V7CL V51F F103AD 52 V7CL V71A F101AA 53 V7CL V71A F103AD 54 V7CL F110MA V71A 55 V46F V67F F103AD 56 V46F V51F F103AD 57 V46F V71A F101AA 58 V46F V71A F103AD 59 V46F F110MA V71A 60 V14CL V67F F103AD 61 V14CL V51F F103AD 62 V14CL V71A F101AA 63 V14CL V71A F103AD 64 V14CL F110MA V71A 65 V6CL V15A V66F 66 V6CL V15A F102BA 67 V6CL V15A V18B 68 V6CL V15A V18 69 V6CL F101AA V66F 70 V6CL F101AA F102BA 71 V6CL F101AA V18B 72 V6CL F101AA V18 73 V6CL V15 V66F 74 V6CL V15 F102BA 75 V6CL V15 V18B 76 V6CL V15 V18 77 V6CL V63F V66F 78 V6CL V63F F102BA 79 V6CL V63F V18B 80 V6CL V63F V18 81 V6CL F104BD F101AA 82 V6CL F103AD F102BA 83 V6CL F112MB F101AA 84 V6CL F112MB F103AD T10.4.9B-25 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-3b (Cont'd)

Cut Set Component 85 V6CL F110MA F102BA 86 V6CL F110MA F104BD 87 V6CL F110MA P112MB 88 V6CL V7CL F101AA 89 V6CL V7CL F103AD 90 V6CL V7CL F110MA 91 V6CL V46F F101AA 92 V6CL V46F F103AD 93 V6CL V46F F110MA 94 V6CL V14CL F101AA 95 V6CL V14CL F103AD 96 V6CL V14CL F110MA 97 V1CL V15A V66F 98 V1CL V15A F102BA 99 V1CL V15A V18B 100 V1CL V15A V18 101 V1CL F101AA V66F 102 V1CL F101AA F102BA 103 V1CL F101AA V18B 104 V1CL F101AA V18 105 V1CL V15 V66F 106 V1CL V15 F102BA 107 V1CL V15 V18B 108 V1CL V15 V18 109 V1CL V63F V66F 110 V1CL V63F F102BA 111 V1CL V63F V18B 112 V1CL V63F V18 113 V1CL F104BD F101AA 114 V1CL F103AD F102BA 115 V1CL F112MB F101AA 116 V1CL F112MB F103AD 117 V1CL F110MA F102BA 118 V1CL F110MA F104BD 119 V1CL F110MA F112MB 120 V1CL V7CL F101AA 121 V1CL V7CL F103AD 122 V1CL V7CL F110MA 123 V1CL V46F F101AA 124 V1CL V46F F103AD 125 V1CL V46F F110MA 126 V1CL V14CL F101AA T10.4.9B-26 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-3b (Cont'd)

Cut Set Component 127 V1CL V14CL F103AD 128 V1CL V14CL F110MA 129 F111T V15A V66F 130 F111T V15A F102BA 131 F111T V15A V18B 132 F111T V15A V18 133 F111T F101AA V66F 134 F111T F101AA F102BA 135 F111T F101AA V18B 136 F111T F101AA V18 137 F111T V15 V66F 138 F111T V15 F102BA 139 F111T V15 V18B 140 F111T V15 V18 141 F111T V63F V66F 142 F111T V63F F102BA 143 F111T V63F V18B 144 F111T V63F V18 145 F111T F104BD F101AA 146 F111T F103AD F102BA 147 F111T F112MB F101AA 148 F111T F112MB F103AD 149 F111T F110MA F102BA 150 F111T F110MA F104BD 151 F111T F110MA F112MB 152 F111T V7CL F101AA 153 F111T V7CL F103AD 154 F111T V7CL F110MA 155 F111T V46F F101AA 156 F111T V46F F103AD 157 F111T V46F F110MA 158 F111T V14CL F101AA 159 F111T V14CL F103AD 160 F111T V14CL F110MA 161 V13CL V15A V66F 162 V13CL V15A F102BA 163 V13CL V15A V18B 164 V13CL V15A V18 165 V13CL F101AA V66F 166 V13CL F101AA F102BA 167 V13CL F101AA V18B 168 V13CL F101AA V18 T10.4.9B-27 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-3b (Cont'd)

Cut Set Component 169 V13CL V15 V66F 170 V13CL V15 F102BA 171 V13CL V15 V18B 172 V13CL V15 V18 173 V13CL V63F V66F 174 V13CL V63F F102BA 175 V13CL V63F V18B 176 V13CL V63F V18 177 V13CL F104BD F101AA 178 V13CL F103AD F102BA 179 V13CL F112MB F101AA 180 V13CL F112MB F103AD 181 V13CL F110MA F102BA 182 V13CL F110MA F104BD 183 V13CL F110MA F112MB 184 V13CL V7CL F101AA 185 V13CL V7CL F103AD 186 V13CL V7CL F110MA 187 V13CL V46F F101AA 188 V13CL V46F F103AD 189 V13CL V46F F110MA 190 V13CL V14CL F101AA 191 V13CL V14CL F103AD 192 V13CL V14CL F110MA 193 V45F V15A V66F 194 V45F V15A F102BA 195 V45F V15A V18B 196 V45F V15A V18 197 V45F F101AA V66F 198 V45F F101AA F102BA 199 V45F F101AA V18B 200 V45F F101AA V18 201 V45F V15 V66F 202 V45F V15 F102BA 203 V45F V15 V18B 204 V45F V15 V18 205 V45F V63F V66F 206 V45F V63F F102BA 207 V45F V63F Vl8B 208 V45F V63F V18 209 V45F F104BD F101AA 210 V45F F103AD F102BA T10.4.9B-28 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-3b (Cont'd)

Cut Set Component 211 V45F F112MB F101AA 212 V45F F112MB F103AD 213 V45F F110MA F102BA 214 V45F F110MA F104BD 215 V45F F110MA F112MB 216 V45F V7CL F101AA 217 V45F V7CL F103AD 218 V45F V7CL F110MA 219 V45F V46F F101AA 220 V45F V46F F103AD 221 V45F V46F F110MA 222 V45F V14CL F101AA 223 V45F V14CL F103AD 224 V45F V14CL F110MA 225 V12CL V68F F104BD 226 V12CL V52F F104BD 227 V12CL V71A F102BA 228 V12CL V71A F104BD 229 V12CL V71A F112MB 230 V12CL V7CL V71A 231 V12CL V46F V71A 232 V12CL V14CL V71A 233 V12CL V6CL F102BA 234 V12CL V6CL F104BD 235 V12CL V6CL F112MB 236 V12CL V6CL V7CL 237 V12CL V6CL V46F 238 V12CL V6CL V14CL 239 V12CL V1CL F102BA 240 V12CL V1CL F104BD 241 V12CL V1CL F112MB 242 V12CL V1CL V7CL 243 V12CL V1CL V46F 244 V12CL V1CL V14CL 245 V12CL F111T F102BA 246 V12CL F111T F104BD 247 V12CL F111T F112MB 248 V12CL F111T V7CL 249 V12CL F111T V46F 250 V12CL F111T V14CL 251 V12CL V13CL F102BA 252 V12CL V13CL F104BD T10.4.9B-29 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-3b (Cont'd)

Cut Set Component 253 V12CL V13CL F112MB 254 V12CL V13CL V7CL 255 V12CL V13CL V46F 256 V12CL V13CL V14CL 257 V12CL V45F F102BA 258 V12CL V45F F104BD 259 V12CL V45F F112MB 260 V12CL V45F V7CL 261 V12CL V45F V46F 262 V12CL V45F V14CL 263 V44F V68F F104BD 264 V44F V52F F104BD 265 V44F V71A F102BA 266 V44F V71A F104BD 267 V44F V71A F112MB 268 V44F V7CL V71A 269 V44F V46F V71A 270 V44F V14CL V71A 271 V44F V6CL F102BA 272 V44F V6CL F104BD 273 V44F V6CL F112MB 274 V44F V6CL V7CL 275 V44F V6CL V46F 276 V44F V6CL V14CL 277 V44F V1CL F102BA 278 V44F V1CL F104BD 279 V44F V1CL F112MB 280 V44F V1CL V7CL 281 V44F V1CL V46F 282 V44F V1CL V14CL 283 V44F F111T F102BA 284 V44F F111T F104BD 285 V44F F111T F112MB 286 V44F F111T V7CL 287 V44F F111T V46F 288 V44F F111T V14CL 289 V44F V13CL F102BA 290 V44F V13CL F104BD 291 V44F V13CL F112MB 292 V44F V13CL V7CL 293 V44F V13CL V46F 294 V44F V13CL V14CL T10.4.9B-30 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-3b (Cont'd)

Cut Set Component 295 V44F V45F F102BA 296 V44F V45F F104BD 297 V44F V45F F112MB 298 V44F V45F V7CL 299 V44F V45F V46F 300 v44F V45F V14CL 301 V5CL V68F F104BD 302 V5CL V52F F104BD 303 V5CL V71A F102BA 304 V5CL V71A F104BD 305 V5CL V71A F112MB 306 V5CL V7CL V71A 307 V5CL V46F V71A 308 V5CL V14CL V71A 309 V5CL V6CL F102BA 310 V5CL V6CL F104BD 311 V5CL V6CL F112MB 312 V5CL V6CL V7CL 313 V5CL V6CL V46F 314 V5CL V6CL V14CL 315 V5CL V1CL F102BA 316 V5CL V1CL F104BD 317 V5CL V1CL F112MB 318 V5CL V1CL V7CL 319 V5CL V1CL V46F 320 V5CL V1CL V14CL 321 V5CL F111T F102BA 322 V5CL F111T F104BD 323 V5CL F111T F112MB 324 V5CL F111T V7CL 325 V5CL F111T V46F 326 V5CL F111T V14CL 327 V5CL V13CL F102BA 328 V5CL V13CL F104BD 329 V5CL V13CL F112MB 330 V5CL V13CL V7CL 331 V5CL V13CL V46F 332 V5CL V13CL V14CL 333 V5CL V45F F102BA 334 V5CL V45F F104BD 335 V5CL V45F F112MB 336 V5CL V45F V7CL T10.4.9B-31 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-3b (Cont'd)

Cut Set Component 337 V5CL V45F V46F 338 V5CL V45F V14CL 339 V17A F104BD F101AA 340 V17A F110MA F104BD 341 V17A V2CL F104BD 342 V17A V12CL F104BD 343 V17A V44F F104BD 344 V17A V5CL F104BD 345 V17 F104BD F101AA 346 V17 F110MA F104BD 347 V17 V2CL F104BD 348 V17 V12CL F104BD 349 V17 V44F F104BD 350 V17 V5CL F104BD 351 V16B F103AD F102BA 352 V16B F112MB F103AD 353 V16B V2CL F103AD 354 V16B V7CL F103AD 355 V16B V46F F103AD 356 V16B V14CL F103AD 357 V16B V17A V2CL 358 V16B V17 V2CL 359 V16 F103AD F102BA 360 V16 F112MB F103AD 361 V16 V2CL F103AD 362 V16 V7CL F103AD 363 V16 V46F F103AD 364 V16 V14CL F103AD 365 V16 V17A V2CL 366 V16 V17 V2CL 367 V65F F104BD F101AA 368 V65F F110MA F104BD 369 V65F V2CL F104BD 370 V65F V12CL F104BD 371 V65F V44F F104BD 372 V65F V5CL F104BD 373 V65F V16B V2CL 374 V65F V16 V2CL 375 V64F F103AD F102BA 376 V64F F112MB F103AD 377 V64F V2CL F103AD 378 V64F V7CL F103AD T10.4.9B-32 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-3b (Cont'd)

Cut Set Component.

379 V64F V46F F103AD 380 V64F V14CL F103AD 381 V64F V17A V2CL 382 V64F V17 V2CL 383 V64F V65F V2CL 384 V50F V71A V15A 385 V50F V71A F101AA 386 V50F V71A V15 387 V50F V71A V63F 388 V50F V6CL V15A 389 V50F V6CL F101AA 390 V50F V6CL V15 391 V50F V6CL V63F 392 V50F V1CL V15A 393 V50F V1CL F101AA 394 V50F V1CL V15 395 V50F V1CL V63F 396 V50F F111T V15A 397 V50F F111T F101AA 398 V50F F111T V15 399 V50F F111T V63F 400 V50F V13CL V15A 401 V50F V13CL F101AA 402 V50F V13CL V15 403 V50F V13CL V63F 404 V50F V45F V15A 405 V50F V45F F101AA 406 V50F V45F V15 407 V50F V45F V63F 408 V49F F104BD F101AA 409 V49F F110MA F104BD 410 V49F V2CL F104BD 411 V49F V12CL F104BD 412 V49F V44F F104BD 413 V49F V5CL F104BD 414 V49F V16B V2CL 415 V49F V16 V2CL 416 V49F V64F V2CL 417 V48F F103AD F102BA 418 V48F F112MB F103AD 419 V48F V2CL F103AD 420 V48F V7CL F103AD T10.4.9B-33 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-3b (Cont'd)

Cut Set Component 421 V48F V46F F103AD 422 V48F V14CL F103AD 423 V48F V17A V2CL 424 V48F V17 V2CL 425 V48F V65F V2CL 426 V48F V49F V2CL 427 V47F V71A V66F 428 V47F V71A F102BA 429 V47F V71A V18B 430 V47F V71A V18 431 V47F V6CL V66F 432 V47F V6CL F102BA 433 V47F V6CL V18B 434 V47F V6CL V18 435 V47F V1CL V66F 436 V47F V1CL F102BA 437 V47F V1CL V18B 438 V47F V1CL V18 439 V47F F111T V66F 440 V47F F111T F102BA 441 V47F F111T V18B 442 V47F F111T V18 443 V47F V13CL V66F 444 V47F V13CL F102BA 445 V47F V13CL V18B 446 V47F V13CL V18 447 V47F V45F V66F 448 V47F V45F F102BA 449 V47F V45F V18B 450 V47F V45F V18 451 V47F V50F V71A 452 V47F V50F V6CL 453 V47F V50F V1CL 454 V47F V50F F111T 455 V47F V50F V13CL 456 V47F V50F V45F T10.4.9B-34 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-3c CUT SETS - SBLO AUTOMATIC AUXILIARY FEEDWATER SYSTEM STUDY Cut Set Component 1 V71A 2 V1CL 3 V6CL 4 F111T 5 V45F 6 V13CL 7 F103AD F104BD 8 V68A F104BD 9 V67B F103AD 10 V67B V68A 11 V52F F104BD 12 V52F V67B 13 V51F F103AD 14 V51F V68A 15 V51F V52F 16 V65F F104BD 17 V64F F103AD 18 V64F V65F 19 V17A F104BD 20 V17A V64F 21 V17 F104BD 22 V17 V64F 23 V49F F104BD 24 V49F V64F 25 V16B F103AD 26 V16B V65F 27 V16B V17A 28 V16B V17 29 V16B V49F 30 V16 F103AD 31 V16 V65F 32 V16 V17A 33 V16 V17 34 V16 V49F 35 V48F F103AD 36 V48F V65F 37 V48F V17A 38 V48F V17 39 V48F V49F 40 F105 OE5 F106 41 F104BD F105 OE5 42 F103AD OE5 F106 43 V68A OE5 F106 44 V67B F105 OE5 T10.4.9B-35 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-3c (Cont'd)

Cut Set Component 45 V52F OE5 F106 46 V51F F105 OE5 47 F65F OE5 F106 48 V64F F105 OE5 49 V17A OE5 F106 50 V17 OE5 F106 51 V49F OE5 F106 52 V16B F105 OE5 53 V16 F105 OE5 54 V48F F105 OE5 T10.4.9B-36 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-4a CUT SETS - LOFW MANUAL AUXILIARY FEEDWATER SYSTEM STUDY Cut Set Component 1 OE1 2 F103AD F104BD 3 V2CL V1CL 4 V2CL V6CL 5 V2CL OE2 6 V2CL F111T 7 V2CL V71F 8 V45F V2CL 9 V13CL V2CL 10 F103AD F112MB OE3 11 V1CL F110MA F104BD 12 V1CL F110MA F112MB 13 V1CL F103AD F112MB 14 V6CL F110MA F104BD 15 V6CL F110MA F112MB 16 V6CL F103AD F112MB 17 OE2 F110MA F104BD 18 OE2 F110MA F112MB 19 OE2 F103AD F112MB 20 F111T F110MA F104BD 21 F111T F110MA F112MB 22 F111T F103AD F112MB 23 V63F V66F V1CL 24 V63F V66F V6CL 25 V63F V66F OE2 26 V63F V66F F111T 27 V71F F110MA F104BD 28 V71F F110MA F112MB 29 V71F F103AD F112MB 30 V71F V63F V66F 31 V2CL F103AD OE3 32 V2CL V67F V68F 33 V2CL V52F V67F 34 V2CL V51F V68F 35 V2CL V51F V52F 36 V7CL F103AD OE3 37 V7CL V1CL F110MA 38 V7CL V1CL F103AD 39 V7CL V6CL F110MA 40 V7CL V6CL F103AD 41 V7CL OE2 F110MA 42 V7CL OE2 F103AD T10.4.9B-37 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-4a (Cont'd)

Cut Set Component.

43 V7CL F111T F110MA 44 V7CL F111T F103AD 45 V7CL V71F F110MA 46 V7CL V71F F103AD 47 V46F F103AD OE3 48 V46F V1CL F110MA 49 V46F V1CL F103AD 50 V46F V6CL F110MA 51 V46F V6CL F103AD 52 V46F OE2 F110MA 53 V46F OE2 F103AD 54 V46F F111T F110MA 55 V46F F111T F103AD 56 V46F V71F F110MA 57 V46F V71F F103AD 58 V14CL F103AD OE3 59 V14CL V1CL F110MA 60 V14CL V1CL F103AD 61 V14CL V6CL F110MA 62 V14CL V6CL F103AD 63 V14CL OE2 F110MA 64 V14CL OE2 F103AD 65 V14CL F111T F110MA 66 V14CL F111T F103AD 67 V14CL V71F F110MA 68 V14CL V71F F103AD 69 V45F F110MA F104BD 70 V45F F110MA F112MB 71 V45F F103AD F112MB 72 V45F V63F V66F 73 V45F V7CL F110MA 74 V45F V7CL F103AD 75 V45F V46F F110MA 76 V45F V46F F103AD 77 V45F V14CL F110MA 78 V45F V14CL F103AD 79 V13CL F110MA F104BD 80 V13CL F110MA F112MB 81 V13CL F103AD F112MB 82 V13CL V63F V66F 83 V13CL V7CL F110MA 84 V13CL V7CL F103AD T10.4.9B-38 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-4a (Cont'd)

Cut Set Component 85 V13CL V46F F110MA 86 V13CL V46F F103AD 87 V13CL V14CL F110MA 88 V13CL V14CL F103AD 89 V12CL V1CL F104BD 90 V12CL V1CL F112MB 91 V12CL V6CL F104BD 92 V12CL V6CL F112MB 93 V12CL OE2 F104BD 94 V12CL OE2 F112MB 95 V12CL F111T F104BD 96 V12CL F111T F112MB 97 V12CL V71F F104BD 98 V12CL V71F F112MB 99 V12CL V7CL V1CL 100 V12CL V7CL V6CL 101 V12CL V7CL OE2 102 V12CL V7CL F111T 103 V12CL V7CL V71F 104 V12CL V46F V1CL 105 V12CL V46F V6CL 106 V12CL V46F OE2 107 V12CL V46F F111T 108 V12CL V46F V71F 109 V12CL V14CL V1CL 110 V12CL V14CL V6CL 111 V12CL V14CL OE2 112 V12CL V14CL F111T 113 V12CL V14CL V71F 114 V12CL V45F F104BD 115 V12CL V45F F112MB 116 V12CL V45F V7CL 117 V12CL V45F V46F 118 V12CL V45F V14CL 119 V12CL V13CL F104BD 120 V12CL V13CL F112MB 121 V12CL V13CL V7CL 122 V12CL V13CL V46F 123 V12CL V13CL V14CL 124 V44F V1CL F104BD 125 V44F V1CL F112MB 126 V44F V6CL F104BD T10.4.9B-39 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-4a (Cont'd)

Cut Set Component 127 V44F V6CL F112MB 128 V44F OE2 F104BD 129 V44F OE2 F112MB 130 V44F F111T F104BD 131 V44F F111T F112MB 132 V44F V71F F104BD 133 V44F V71F F112MB 134 V44F V7CL V1CL 135 V44F V7CL V6CL 136 V44F V7CL OE2 137 V44F V7CL F111T 138 V44F V7CL V71F 139 V44F V46F V1CL 140 V44F V46F V6CL 141 V44F V46F OE2 142 V44F V46F F111T 143 V44F V46F V71F 144 V44F V14CL V1CL 145 V44F V14CL V6CL 146 V44F V14CL OE2 147 V44F V14CL F111T 148 V44F V14CL V71F 149 V44F V45F F104BD 150 V44F V45F F112MB 151 V44F V45F V7CL 152 V44F V45F V46F 153 V44F V45F V14CL 154 V44F V13CL F104BD 155 V44F V13CL F112MB 156 V44F V13CL V7CL 157 V44F V13CL V46F 158 V44F V13CL V14CL 159 V5CL V1CL F104BD 160 V5CL V1CL F112MB 161 V5CL V6CL F104BD 162 V5CL V6CL F112MB 163 V5CL OE2 F104BD 164 V5CL OE2 F112MB 165 V5CL F111T F104BD 166 V5CL F111T F112MB 167 V5CL V71F F104BD 168 V5CL V71F F112MB T10.4.9B-40 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-4a (Cont'd)

Cut Set Component 169 V5CL V7CL V1CL 170 V5CL V7CL V6CL 171 V5CL V7CL OE2 172 V5CL V7CL F111T 173 V5CL V7CL V71F 174 V5CL V46F V1CL 175 V5CL V46F V6CL 176 V5CL V46F OE2 177 V5CL V46F F111T 178 V5CL V46F V71F 179 V5CL V14CL V1CL 180 V5CL V14CL V6CL 181 V5CL V14CL OE2 182 V5CL V14CL F111T 183 V5CL V14CL V71F 184 V5CL V45F F104BD 185 V5CL V45F F112MB 186 V5CL V45F V7CL 187 V5CL V45F V46F 188 V5CL V45F V14CL 189 V5CL V13CL F104BD 190 V5CL V13CL F112MB 191 V5CL V13CL V7CL 192 V5CL V13CL V46F 193 V5CL V13CL V14CL 194 V64F V65F V2CL 195 V18CL V63F V1CL 196 V18CL V63F V6CL 197 V18CL V63F OE2 198 V18CL V63F F111T 199 V18CL V71F V63F 200 V18CL V45F V63F 201 V18CL V13CL V63F 202 V50F V63F V1CL 203 V50F V63F V6CL 204 V50F V63F OE2 205 V50F V63F F111T 206 V50F V71F V63F 207 V50F V45F V63F 208 V50F V13CL V63F 209 V17CL V64F V2CL 210 V49F V64F V2CL T10.4.9B-41 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-4a (Cont'd)

Cut Set Component 211 V48F V65F V2CL 212 V48F V17CL V2CL 213 V48F V49F V2CL 214 V16CL V65F V2CL 215 V16CL V17CL V2CL 216 V16CL V49F V2CL 217 V47F V66F V1CL 218 V47F V66F V6CL 219 V47F V66F OE2 220 V47F V66F F111T 221 V47F V71F V66F 222 V47F V45F V66F 223 V47F V13CL V66F 224 V47F V18CL V1CL 225 V47F V18CL V6CL 226 V47F V18CL OE2 227 V47F V18CL F111T 228 V47F V18CL V71F 229 V47F V18CL V45F 230 V47F V18CL V13CL 231 V47F V50F V1CL 232 V47F V50F V6CL 233 V47F V50F OE2 234 V47F V50F F111T 235 V47F V50F V71F 236 V47F V50F V45F 237 V47F V50F V13CL 238 V15F V66F V1CL 239 V15F V66F V6CL 240 V15F V66F OE2 241 V15F V66F F111T 242 V15F V71F V66F 243 V15F V45F V66F 244 V15F V13CL V66F 245 V15F V18CL V1CL 246 V15F V18CL V6CL 247 V15F V18CL OE2 248 V15F V18CL F111T 249 V15F V18CL V71F 250 V15F V18CL V45F 251 V15F V18CL V13CL 252 V15F V50F V1CL T10.4.9B-42 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-4a (Cont'd)

Cut Set Component 253 V15F V50F V6CL 254 V15F V50F OE2 255 V15F V50F F111T 256 V15F V50F V71F 257 V15F V50F V45F 258 V15F V50F V13CL T10.4.9B-43 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-4b CUT SETS - LOOP MANUAL AUXILIARY FEEDWATER SYSTEM STUDY Cut Set Component 1 OE1 2 F103AD 104BD 3 V2CL V1CL 4 V2CL V6CL 5 V2CL OE2 6 V2CL F111T 7 V2CL V71F 8 V45F V2CL 9 V13CL V2CL 10 F103AD F102BA OE3 11 F103AD F112MB OE3 12 V1CL F101AA F104BD 13 V1CL F101AA F102BA 14 V1CL F112MB F101AA 15 V1CL F110MA F104BD 16 V1CL F110MA F102BA 17 V1CL F110MA F112MB 18 V1CL F103AD F102BA 19 V1CL F103AD F112MB 20 V6CL F101AA F104BD 21 V6CL F101AA F102BA 22 V6CL F112MB F101AA 23 V6CL F110MA F104BD 24 V6CL F110MA F102BA 25 V6CL F110MA F112MB 26 V6CL F103AD F102BA 27 V6CL F103AD F112MB 28 OE2 F101AA F104BD 29 OE2 F101AA F102BA 30 OE2 F112MB F101AA 31 OE2 F110MA F104BD 32 OE2 F110MA F102BA 33 OE2 F110MA F112MB 34 OE2 F103AD F102BA 35 OE2 F103AD F112MB 36 F111T F101AA F104BD 37 F111T F101AA F102BA T10.4.9B-44 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-4b (Cont'd)

Cut Set Component 38 F111T F112MB F101AA 39 F111T F110MA F104BD 40 F111T F110MA F102BA 41 F111T F110MA F112MB 42 F111T F103AD F102BA 43 F111T F103AD F112MB 44 V66F V1CL F101AA 45 V66F V6CL F101AA 46 V66F OE2 F101AA 47 V66F F111T F101AA 48 V63F V1CL F102BA 49 V63F V6CL F102BA 50 V63F OE2 F102BA 51 V63F F111T F102BA 52 V63F V66F V1CL 53 V63F V66F V6CL 54 V63F V66F OE2 55 V63F V66F F111T 56 V71F F101AA F104BD 57 V71F F101AA F102BA 58 V71F F112MB F101AA 59 V71F F110MA F104BD 60 V71F F110MA F102BA 61 V71F F110MA F112MB 62 V71F F103AD F102BA 63 V71F F103AD F112MB 64 V71F V66F F101AA 65 V71F V63F F102BA 66 V71F V63F V66F 67 V2CL F103AD OE3 68 V2CL V67F V68F 69 V2CL V52F V67F 70 V2CL V51F V68F 71 V2CL V51F V52F 72 V7CL F103AD OE3 73 V7CL V1CL F101AA 74 V7CL V1CL F110MA 75 V7CL V1CL F103AD 76 V7CL V6CL F101AA 77 V7CL V6CL F110MA 78 V7CL V6CL F103AD 79 V7CL OE2 F101AA 80 V7CL OE2 F110MA 81 V7CL OE2 F103AD 82 V7CL F111T F101AA 83 V7CL F111T F110MA 84 V7CL F111T F103AD T10.4.9B-45 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-4b (cont'd Cut Set Component 85 V7CL V71F F101AA 86 V7CL V71F F110MA 87 V7CL V71F F103AD 88 V46F F103AD OE3 89 V46F V1CL F101AA 90 V46F V1CL F110MA 91 V46F V1CL F103AD 92 V46F V6CL F101AA 93 V46F V6CL F110MA 94 V46F V6CL F103AD 95 V46F OE2 F101AA 96 V46F OE2 F110MA 97 V46F OE2 F103AD 98 V46F F111T F101AA 99 V46F F111T F110MA 100 V46F F111T F103AD 101 V46F V71F F101AA 102 V46F V71F F110MA 103 V46F V71F F103AD 104 V14CL F103AD OE3 105 V14CL V1CL F101AA 106 V14CL V1CL F110MA 107 V14CL V1CL F103AD 108 V14CL V6CL F101AA 109 V14CL V6CL F110MA 110 V14CL V6CL F103AD 111 V14CL OE2 F101AA 112 V14CL OE2 F110MA 113 V14CL OE2 F103AD 114 V14CL F111T F101AA 115 V14CL F111T F110MA 116 V14CL F111T F103AD 117 V14CL V71F F101AA 118 V14CL V71F F110MA 119 V14CL V71F F103AD 120 V45F F101AA F104BD 121 V45F F101AA F102BA 122 V45F F112MB F101AA 123 V45F F110MA F104BD 124 V45F F110MA F102BA 125 V45F F110MA F112MB 126 V45F F103AD F102BA T10.4.9B-46 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-4b (Cont'd)

Cut Set Component 127 V45F F103AD F112MB 128 V45F V66F F101AA 129 V45F V63F F102BA 130 V45F V63F V66F 131 V45F V7CL F101AA 132 V45F V7CL F110MA 133 V45F V7CL F103AD 134 V45F V46F F101AA 135 V45F V46F F110MA 136 V45F V46F F103AD 137 V45F V14CL F101AA 138 V45F V14CL F110MA 139 V45F V14CL F103AD 140 V13CL F101AA F104BD 141 V13CL F101AA F102BA 142 V13CL F112MB F101AA 143 V13CL F110MA F104BD 144 V13CL F110MA F102BA 145 V13CL F110MA F112MB 146 V13CL F103AD F102BA 147 V13CL F103AD F112MB 148 V13CL V66F F101AA 149 V13CL V63F F102BA 150 V13CL V63F V66F 151 V13CL V7CL F101AA 152 V13CL V7CL F110MA 153 V13CL V7CL F103AD 154 V13CL V46F F101AA 155 V13CL V46F F110MA 156 V13CL V46F F103AD 157 V13CL V14CL F101AA 158 V13CL V14CL F110MA 159 V13CL V14CL F103AD 160 V12CL V1CL F104BD 161 V12CL V1CL F102BA 162 V12CL V1CL F112MB 163 V12CL V6CL F104BD 164 V12CL V6CL F102BA 165 V12CL V6CL F112MB 166 V12CL OE2 F104BD 167 V12CL OE2 F102BA 168 V12CL OE2 F112MB T10.4.9B-47 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-4b (Cont'd)

Cut Set Component 169 V12CL F111T F104BD 170 V12CL F111T F102BA 171 V12CL F111T F112MB 172 V12CL V71F F104BD 173 V12CL V71F F102BA 174 V12CL V71F F112MB 175 V12CL V7CL V1CL 176 V12CL V7CL V6CL 177 V12CL V7CL OE2 178 V12CL V7CL F111T 179 V12CL V7CL V71F 180 V12CL V46F V1CL 181 V12CL V46F V6CL 182 V12CL V46F OE2 183 V12CL V46F F111T 184 V12CL V46F V71F 185 V12CL V14CL V1CL 186 V12CL V14CL V6CL 187 V12CL V14CL OE2 188 V12CL V14CL F111T 189 V12CL V14CL V71F 190 V12CL V45F F104BD 191 V12CL V45F F102BA 192 V12CL V45F F112MB 193 V12CL V45F V7CL 194 V12CL V45F V46F 195 V12CL V45F V14CL 196 V12CL V13CL F104BD 197 V12CL V13CL F102BA 198 V12CL V13CL F112MB 199 V12CL V13CL V7CL 200 V12CL V13CL V46F 201 V12CL V13CL V14CL 202 V44F V1CL F104BD 203 V44F V1CL F102BA 204 V44F V1CL F112MB 205 V44F V6CL F104BD 206 V44F V6CL F102BA 207 V44F V6CL F112MB 208 V44F OE2 F104BD 209 V44F OE2 F102BA 210 V44F OE2 F112MB T10.4.9B-48 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-4b (Cont'd)

Cut Set Component 211 v44F F111T F104BD 212 V44F F111T F102BA 213 V44F F111T F112MB 214 V44F V71F F104BD 215 v44F V71F F102BA 216 v44F V71F F112MB 217 v44F V7CL V1CL 218 V44F V7CL V6CL 219 V44F V7CL OE2 220 V44F V7CL F111T 221 V44F V7CL V71F 222 V44F V46F V1CL 223 v44F V46F V6CL 224 v44F V46F OE2 225 v44F V46F F111T 226 V44F V46F V71F 227 v44F V14CL V1CL 228 V44F V14CL V6CL 229 V44F V14CL OE2 230 V44F V14CL F111T 231 V44F V14CL V71F 232 V44F V45F F104BD 233 v44F V45F F102BA 234 V44F V45F F112MB 235 v44F V45F V7CL 236 V44F V45F V46F 237 v44F V45F V14CL 238 V44F V13CL F104BD 239 V44F V13CL F102BA 240 V44F V13CL F112MB 241 V44F V13CL V7CL 242 V44F V13CL V46F 243 V44F V13CL V14CL 244 V5CL V1CL F104BD 245 V5CL V1CL F102BA 246 V5CL V1CL F112MB 247 V5CL V6CL F104BD 248 V5CL V6CL F102BA 249 V5CL V6CL F112MB 250 V5CL OE2 F104BD 251 V5CL OE2 F102BA 252 V5CL OE2 F112MB T10.4.9B-49 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-4b (Cont'd)

Cut Set Component 253 V5CL F111T F104BD 254 V5CL F111T F102BA 255 V5CL F111T F112MB 256 V5CL V71F F104BD 257 V5CL V71F F102BA 258 V5CL V71F F112MB 259 V5CL V7CL V1CL 260 V5CL V7CL V6CL 261 V5CL V7CL OE2 262 V5CL V7CL F111T 263 V5CL V7CL V71F 264 V5CL V46F V1CL 265 V5CL V46F V6CL 266 V5CL V46F OE2 267 V5CL V46F F111T 268 V5CL V46F V71F 269 V5CL V14CL V1CL 270 V5CL V14CL V6CL 271 V5CL V14CL OE2 272 V5CL V14CL F111T 273 V5CL V14CL V71F 274 V5CL V45F F104BD 275 V5CL V45F F102BA 276 V5CL V45F F112MB 277 V5CL V45F V7CL 278 V5CL V45F V46F 279 V5CL V45F V14CL 280 V5CL V13CL F104BD 281 V5CL V13CL F102BA 282 V5CL V13CL F112MB 283 V5CL V13CL V7CL 284 V5CL V13CL V46F 285 V5CL V13CL V14CL 286 V64F V65F V2CL 287 V18CL V1CL F101AA 288 V18CL V6CL F101AA 289 V18CL OE2 F101AA 290 V18CL F111T F101AA 291 V18CL V63F V1CL 292 V18CL V63F V6CL 293 V18CL V63F OE2 294 V18CL V63F F111T T10.4.9B-50 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-4b (Cont'd)

Cut Set Component 295 V18CL V71F F101AA 296 V18CL V71F V63F 297 V18CL V45F F101AA 298 V18CL V45F V63F 299 V18CL V13CL F101AA 300 V18CL V13CL V63F 301 V50F V1CL F101AA 302 V50F V6CL F101AA 303 V50F OE2 F101AA 304 V50F F111T F101AA 305 V50F V63F V1CL 306 V50F V63F V6CL 307 V50F V63F OE2 308 V50F V63F F111T 309 V50F V71F F101AA 310 V50F V71F V63F 311 V50F V45F F101AA 312 V50F V45F V63F 313 V50F V13CL F101AA 314 V50F V13CL V63F 315 V17CL V64F V2CL 316 V49F V64F V2CL 317 V48F V65F V2CL 318 V48F V17CL V2CL 319 V48F V49F V2CL 320 V16CL V65F V2CL 321 V16CL V17CL V2CL 322 V16CL V49F V2CL 323 V47F V1CL F102BA 324 V47F V6CL F102BA 325 V47F OE2 F102BA 326 V47F F111T F102BA 327 V47F V66F V1CL 328 V47F V66F V6CL 329 V47F V66F OE2 330 V47F V66F F111T 331 V47F V71F F102BA 332 V47F V71F V66F 333 V47F V45F F102BA 334 V47F V45F V66F 335 V47F V13CL F102BA 336 V47F V13CL V66F T10.4.9B-51 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-4b (Cont'd)

Cut Set Component 337 V47F V18CL V1CL 338 V47F V18CL V6CL 339 V47F V18CL OE2 340 V47F V18CL F111T 341 V47F V18CL V71F 342 V47F V18CL V45F 343 V47F V18CL V13CL 344 V47F V50F V1CL 345 V47F V50F V6CL 346 V47F V50F OE2 347 V47F V50F F111T 348 V47F V50F V71F 349 V47F V50F V45F 350 V47F V50F V13CL 351 V15F V1CL F102BA 352 V15F V6CL F102BA 353 V15F OE2 F102BA 354 V15F F111T F102BA 355 V15F V66F V1CL 356 V15F V66F V6CL 357 V15F V66F OE2 358 V15F V66F F111T 359 V15F V71F F102BA 360 V15F V71F V66F 361 V15F V45F F102BA 362 V15F V45F V66F 363 V15F V13CL F102BA 364 V15F V13CL V66F 365 V15F V18CL V1CL 366 V15F V18CL V6CL 367 V15F V18CL OE2 368 V15F V18CL F111T 369 V15F V18CL V71F 370 V15F V18CL V45F 371 V15F V18CL V13CL 372 V15F V50F V1CL 373 V15F V50F V6CL 374 V15F V50F OE2 375 V15F V50F F111T 376 V15F V50F V71F 377 V15F V50F V45F 378 V15F V50F V13CL T10.4.9B-52 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-4c CUT SETS - SBLO MANUAL AUXILIARY FEEDWATER SYSTEM STUDY Cut Set Component 1 V1CL 2 V6CL 3 OE2 4 F111T 5 OE1 6 V71F 7 V45F 8 V13CL 9 F103AD OE3 10 F103AD F104BD 11 V67F V68F 12 V52F V67F 13 V51F V68F 14 V51F V52F 15 V64F V65F 16 V17CL V64F 17 V49F V64F 18 V48F V65F 19 V48F V17CL 20 V48F V49F 21 V16CL V65F 22 V16CL V17CL 23 V16CL V49F T10.4.9B-53 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-5 BASIC EVENT FAILURE RATE DATA Probability Component Type Basic Event Numbers Failure Mode Per Demand Manual Valve 1, 2, 5, 6, 7, 8, Plugging 1.0 x 10-4 9, 10, 12, 13, 14, Random Operator 3.3 x 10-4 15, 16, 17, 18 Error Total 4.3 x 10-4 Check Valve 44, 45, 46, 47, 48, Plugging 1 x 10-4 49, 50, 51, 52 Motor Operated 61, 62, 63, 64, 65, Mechanical Comp. 1 x 10-3 Valves 66,67 68,71 Plugging 1 x 10-4 Control Circuit 6 x 10-3 Maintenance 2 x 10-3 Total 9.1 x 10-3 DC Motor Operated Valve (LO) 71A Plugging 1 x 10-4 Maintenance 2 x 10-3 Total 2.1 x 10-3 AC Power Failure 101,102 DG Start Failure 3 x 10-2 DG Maintenance 6 x 10-3 Total 3.6 x 10-2 DC Power Failure 103,104 Battery Failure 1 x 10-4 Motor Driven 110, 112 Mechanical Comp. 1 x 10-3 Pump Control Circuit 4 x 10-3 Maintenance 2 x 10-3 Total 7 x 10-3 Turbine Driven Pump 111 Mechanical Comp. 1 x 10-3 Maintenance 2 x 10-3 Total 3 x 10-3 DC Solenoid 15A, 16B, 17A, 18B Mechanical Comp. 1 x 10-3 Valves Control Circuit 6 x 10-3 Maintenance 2 x 10-3 Total 9 x 10-3 T10.4.9B-54 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-5 (Cont'd)

Probability Component Type Basic Event Numbers Failure Mode Per Demand Automatic 105, 106 Total 7 x 10-3*

Actuation Logic Manual System OE1 Operator Error 5 x 10-3 Start Turbine Pump OE2 Operator Error 1 x 10-2 Manual Start AB dc Bus Manual OE3 Operator Error 3 x 10-2 Switchover Motor Driven Pump OE4 Operator Error 5 x 10-2 Disch Manual Crossover System Auto OE5 Operator Error 1 x 10-2 Start Manual Backup

Failure probabilities assumed for actuating logic are those of NUREG 0635. This provides results comparable with other evaluations. Reliability studies by the actuation logic vendor have shown a significantly higher reliability verifying the conservatism of this assumption.

T10.4.9B-55 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-6 AFS VALVES SUBJECT TO ASME SECTION XI TESTING Power Operated Valves Check Valves 61 I-MV-09-13 44 2I-V9107 (350) 62 I-MV-09-14 45 2I-V9139 (351) 63 I-MV-09-9 46 2I-V9123 (350) 64 I-MV-09-11 47 2I-V9119 (350) 65 I-MV-09-12 48 2I-V9151 (350) 66 I-MV-09-10 49 2I-V9157 (350) 67 I-MV-08-13 50 2I-V9135 (350) 68 I-MV-08-12 51 2I-V8130 (350) 71 I-MV-08-3 52 2I-V8163 (350) 15A I-SE-09-2 16B I-SE-09-4 17A I-SE-09-5 18B I-SE-09-3 69 I-SE-08-2 70 I-SE-08-1 T10.4.9B-56 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-7a DOMINANT CUT SETS - LOFW (AUTOMATIC)

PROBABILITY: 6.21 x 10-6 Cut Set Event Probability (10-7) % Probability 2 V2CL, V71A 9.03 14.54 3 V2CL, V6CL 1.85 2.97 4 V2CL, V1CL 1.85 2.97 5 V2CL, F111T 12.9 20.77 6 V2CL, V13CL 1.85 2.97 8 F105, F106, OE5 4.9 7.89 13 V71A, V15A, V66F 1.72 2.77 14 V71A, V15A, V18B 1.70 2.74 19 V71A, V63F, V66F 1.74 2.80 20 V71A, V63F, V18B 1.72 2.77 26 V71A, F110MA, F112MB 1.03 1.66 83 F111T, V15A, V66F 2.46 3.95 84 F111T, V15A, V18B 2.43 3.91 89 F111T, V63F, V66F 2.48 4.0 90 F111T, V63F, V18B 2.46 3.95 94 F111T, F110MA, F112MB 1.47 2.37 TOTAL 51.6 83.05 T10.4.9B-57 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-7b DOMINANT CUT SETS - LOOP (AUTOMATIC)

PROBABILITY: 1.90 x 10-5 Cut Set Event Probability (10-7) % Probability 2 V2CL, V71A 9.03 4.75 5 V2CL, F111T 12.9 6.78 18 V71A, V15A, F102BA 6.80 3.58 21 V71A, F101AA, V66F 6.88 3.62 23 V71A, F101AA, V18B 6.80 3.58 30 V71A, V63F, F102BA 6.88 3.62 35 V71A, F112MB, F101AA 5.29 2.78 39 V71A, F110MA, F102BA 5.29 2.78 130 F111T, V15A, F102BA 9.72 5.11 133 F111T, F101AA, V66F 9.83 5.17 135 F111T, F101AA, V18B 9.72 5.11 142 F111T, V63F, F102BA 9.83 5.11 147 F111T, F112MB, F101AA 7.56 3.98 149 F111T, F110,MA, F102BA 7.56 3.98 TOTAL 114.10 60.01 T10.4.9B-58 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE l0.4.9B-7c DOMINANT CUT SETS - SB (AUTOMATIC)

PROBABILITY: 6.91 x 10-3 Cut Set Event Probability (10-3) % Probability 1 V71A 2.1 30.37 2 V1CL .43 6.22 3 V6CL .43 6.22 4 F111T 3.0 43.38 5 V45F .1 1.45 6 V13CL .43 6.22

~6.49 93.86 T10.4.9B-59 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-8a DOMINANT CUT SETS - LOFW (MANUAL)

PROBABILITY: 5.01 x 10-3 Cut Set Event Probability (10-7) % Probability 1 OE1 50000 99.72 3 V2CL, V1CL 1.85 .0037 4 V2CL, V6CL 1.85 .0037 5 V2CL, OE2 43 .086 6 V2CL, F111T 12.9 .026 7 V2CL, V71F 39.13 .078 9 V2CL, V13CL 1.85 .0037 18 OE2, F110MA, F112MB 4.9 .0098 21 F111T, F110MA, F112MB 1.47 .0029 25 V63F, V66F, OE2 8.28 .0165 26 V63F, V66F, F111T 2.48 .0050 28 V71F, F110MA, F112MB 4.46 .0089 30 V71F, V63F, V66F 7.54 .0150

~50129./ 99.98 T10.4.9B-60 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-8b DOMINANT CUT SETS - LOOP (MANUAL)

PROBABILITY: 5.0 x 10-3 Cut Set Event Probability (10-6) % Probability 1 OE1 5000 99.10 5 V2CL, OE2 4.3 .085 6 V2CL, F111T 1.29 .025 7 V2CL, V71F 3.91 .077 30 OE2, F112MB, F101AA 2.52 .05 32 OE2, F110MA, F102BA 2.52 .05 46 V66F, OE2, F101AA 3.28 .065 50 V63F, OE2, F102BA 3.28 .065 58 V71F, F112MB, F101AA 2.29 .045 60 V71F, F110MA, F102BA 2.29 .045 64 V71F, V66F, F101AA 2.98 .059 65 V71F, V63F, F102BA 2.98 .059

~5031.6 99.73 T10.4.9B-61 Amendment No. 24 (09/17)

UFSAR/St. Lucie - 2 TABLE 10.4.9B-8c DOMINANT CUT SETS - SB (MANUAL)

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~27.1 95.53 T10.4.9B-62 Amendment No. 24 (09/17)

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ML22111A104

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ML22111A104

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SUMMARY

2.2 DESCRIPTION

SUMMARY

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