ML20323A305
| ML20323A305 | |
| Person / Time | |
|---|---|
| Site: | Watts Bar  |
| Issue date: | 10/29/2020 |
| From: | Tennessee Valley Authority |
| To: | Office of Nuclear Reactor Regulation |
| Shared Package | |
| ML20323A313 | List: |
| References | |
| WBL-20-047 | |
| Download: ML20323A305 (228) | |
Text
{{#Wiki_filter:WBN-3 TABLE OF CONTENTS Section Title Page 10.0 MAIN STEAM AND POWER CONVERSION SYSTEMS 10.1-1 10.1
SUMMARY
DESCRIPTION 10.1-1 References 10.1-2 10.2 TURBINE GENERATOR 10.2-1 10.2.1 Design Bases 10.2-1 10.2.2 Description 10.2-1 10.2.3 Turbine Rotor and Disc Integrity 10.2-4 10.2.3.1 Materials Selection - Historical Information 10.2-4 10.2.3.2 Fracture Toughness - Historical Information 10.2-8 10.2.3.3 High Temperature Properties - Historical Information 10.2-11 10.2.3.4 Turbine Disc Design - Historical Information 10.2-11 10.2.3.5 Preservice Inspection - Historical Information 10.2-12 10.2.3.5.1 Low Pressure Turbine Rotor - Historical Information 10.2-12 10.2.3.5.2 High Pressure Turbine Rotor - Historical Information 10.2-14 10.2.3.5.3 Preoperational and Initial Startup Testing - Historical Information 10.2-14 10.2.3.6 Inservice Inspection 10.2-15 10.2.3.6.1 Turbine Rotors 10.2-15 10.2.3.6.2 Turbine Overspeed Protection 10.2-15 10.2.3.6.3 Other Turbine Protection Features 10.2-18 10.2.4 Evaluation 10.2-18 References 10.2-20 10.3 MAIN STEAM SUPPLY SYSTEM 10.3-1 10.3.1 Design Bases 10.3-1 10.3.2 System Description 10.3-1 10.3.2.1 System Design 10.3-1 10.3.2.2 Material Compatibility, Codes, and Standards 10.3-2 10.3.3 Design Evaluation 10.3-2 10.3.4 Inspection and Testing Requirements 10.3-4 10.3.5 Water Chemistry 10.3-4 10.3.5.1 Purpose 10.3-4 10.3.5.2 Feedwater Chemistry Specifications 10.3-4 10.3.5.3 Operating Modes 10.3-4 10-i
WBN TABLE OF CONTENTS Section Title Page 10.3.5.4 Effect of Water Chemistry on the Radioactive Iodine Partition Coefficient 10.3-6 10.3.6 Steam Feedwater System Materials 10.3-7 10.3.6.1 Fracture Toughness 10.3-7 10.3.6.2 Materials Selection and Fabrication 10.3-7 References 10.3-7 10.4 OTHER FEATURES OF STEAM AND POWER CONVERSION SYSTEM 10.4.1 Main Condenser 10.4-1 10.4.1.1 Design Bases 10.4-1 10.4.1.2 System Description 10.4-1 10.4.1.3 Safety Evaluation 10.4-4 10.4.1.4 Inspection and Testing 10.4-5 10.4.1.5 Instrumentation 10.4-5 10.4.2 Main Condenser Evacuation System 10.4-5 10.4.2.1 Design Bases 10.4-5 10.4.2.2 System Description 10.4-5 10.4.2.3 Safety Evaluation 10.4-6 10.4.2.4 Inspection and Testing 10.4-6 10.4.2.5 Instrumentation 10.4-6 10.4.3 Turbine Gland Sealing System 10.4-7 10.4.3.1 Design Bases 10.4-7 10.4.3.2 System Description 10.4-7 10.4.3.3 Safety Evaluation 10.4-7 10.4.3.4 Inspection and Testing 10.4-7 10.4.3.5 Instrumentation 10.4-8 10.4.4 Turbine Bypass System 10.4-8 10.4.4.1 Design Bases 10.4-8 10.4.4.2 System Description 10.4-8 10.4.4.3 Safety Evaluation 10.4-9 10.4.4.4 Inspection and Testing 10.4-10 10.4.4.5 Instrumentation 10.4-10 10.4.5 Condenser Circulating Water System 10.4-10 10.4.5.1 Design Bases 10.4-11 10.4.5.2 System Description 10.4-11 10.4.5.3 Safety Evaluation 10.4-13 10.4.5.4 Inspection and Testing 10.4-14 10.4.5.5 Instrumentation Application 10.4-14 10-ii
WBN TABLE OF CONTENTS Section Title Page 10.4.6 Condensate Polishing Demineralizer System 10.4-15 10.4.6.1 Design Bases - Power Conversion 10.4-15 10.4.6.2 System Description 10.4-15 10.4.6.3 Safety Evaluation 10.4-17 10.4.6.4 Inspection and Testing 10.4-18 10.4.6.5 Instrumentation 10.4-18 10.4.7 Condensate and Feedwater Systems 10.4-19 10.4.7.1 Design Bases 10.4-19 10.4.7.2 System Description 10.4-19 10.4.7.3 Safety Evaluation 10.4-28 10.4.7.4 Inspection and Testing 10.4-29 10.4.7.5 Instrumentation 10.4-30 10.4.8 Steam Generator Blowdown System 10.4-30 10.4.8.1 Design Bases 10.4-30 10.4.8.2 System Description and Operation 10.4-31 10.4.8.3 Safety Evaluation 10.4-32 10.4.8.4 Inspections and Testing 10.4-33 10.4.9 Auxiliary Feedwater System 10.4-33 10.4.9.1 Design Bases 10.4-33 10.4.9.2 System Description 10.4-34 10.4.9.3 Safety Evaluation 10.4-35 10.4.9.4 Inspection and Testing Requirements 10.4-38 10.4.9.5 Instrumentation Requirements 10.4-38 References 10.4-39 10-iii
WBN LIST OF TABLES Number Title 10.1-1 Summary of Important Component Design Parameters 10.3-1 Main Steam Supply System; Applicable Codes, Standards, and Design Condition 10.4-1 Auxiliary Feedwater Pump Parameters 10.4-2 Failure Analysis, Steam Generator Blowdown System 10.4-3 Failure Mode and Effects Analysis Steam Supply Subsystem 10.4-4 Failure Mode and Effects Analysis Turbine-Driven Pump Subsystem 10.4-5 Failure Mode and Effects Analysis Motor-Driven (MD) Pump Subsystem 10.4-6 Auxiliary Feedwater Flow to Steam Generators Following an Accident/Transient - GPM 10-iv
WBN LIST OF FIGURES Number Title 10.1-1 Powerhouse Flow Diagram - General Plant Systems 10.1-2 Maximum Guaranteed Heat Balance 1200% MW Thermal 10.2-1 Powerhouse Unit 1 Wiring Diagram - Turbogenerator Auxiliaries Schematic Diagrams 10.2-2 Powerhouse Unit 1 - Electrical Control Diagram - Turbogenerator Cont. Sys. 10.2-2, Sh A Powerhouse Unit 2 - Electrical Control Diagram - Turbogenerator Cont. Sys. 10.2-3 Powerhouse Unit 1 - Electrical Control Diagram - Turbogenerator Cont. Sys. 10.2-3, Sh A Powerhouse Unit 2 - Electrical Control Diagram - Turbogenerator Cont. Sys. 10.2-4 Powerhouse Unit 1 - Electrical Control Diagram - Turbogenerator Cont. Sys. 10.2-4, Sh A Powerhouse Unit 2 - Electrical Control Diagram - Turbogenerator Cont. Sys. 10.3-1 Powerhouse Unit 1 - Flow Diagram - Main and Reheat Steam 10.3-1 Powerhouse Unit 2 - Flow Diagram - Main and Reheat Steam 10.3-2 Powerhouse Unit 1 - Electrical Diagram - Main Steam System 10.3-2 Powerhouse Unit 2 - Electrical Diagram - Main Steam System 10.3-3 Powerhouse Unit 1 - Electrical Control Diagram - Main Steam System 10.3-3 Powerhouse Unit 2 - Electrical Control Diagram - Main Steam System 10.3-3, Sh A Powerhouse Unit 1 - Electrical Control Diagram - Main Steam System 10.3-3, Sh A Powerhouse Unit 2 - Electrical Control Diagram - Main Steam System 10.3-4 Powerhouse Unit 1 - Electrical Control Diagram - Main Steam System 10.3-4 Powerhouse Unit 2 - Electrical Control Diagram - Main Steam System 10.3-4, Sh A Powerhouse Unit 1 - Electrical Control Diagram - Main Steam System 10.3-4, Sh A Powerhouse Unit 2 - Electrical Control Diagram - Main Steam System 10.3-5 Powerhouse Unit 1- Electrical Logic Diagram - Main and Reheat System 10.3-5 Powerhouse Unit 2- Electrical Logic Diagram - Main and Reheat System 10.3-6 Powerhouse Unit 1 - Electrical Logic Diagram - Main and Reheat System 10-v
WBN LIST OF FIGURES Number Title 10.3-6 Powerhouse Unit 2 - Electrical Logic Diagram - Main and Reheat System 10.3-7 Powerhouse Unit 1 & 2 - Electrical Logic Diagram - Main and Reheat System 10.3-8 Deleted 10.3-9 Powerhouse Units 1 & 2 - Flow Diagram - Feedwater Treatment Secondary Chemical Feed 10.4-1 Powerhouse Unit 1 - Flow Diagram - Turbine Drains and Miscellaneous Piping 10.4-1 Powerhouse Unit 2 - Flow Diagram - Turbine Drains and Miscellaneous Piping 10.4-2 General Units 1 & 2 - Flow Diagram - Condenser Circulating Water 10.4-3 Unit 1 - General Condenser Circulating Water System Flow Diagram 10.4-3 Unit 2 - General Condenser Circulating Water System Flow Diagram 10.4-4 Powerhouse Unit 1 - Electrical Control Diagram - Condenser Circulating Water System 10.4-4 Powerhouse Unit 2 - Electrical Control Diagram - Condenser Circulating Water System 10.4-5 Powerhouse Units 1 & 2 - Electrical Control Diagram - Condenser Circulating Water System 10.4-6 Powerhouse Unit 1 - Electrical Logic Diagram - Condenser Circulating Water System 10.4-6 Powerhouse Unit 2 - Electrical Logic Diagram - Condenser Circulating Water System 10.4-7 Powerhouse Unit 1 - Flow Diagram - Condensate 10.4-7 Powerhouse Unit 2 - Flow Diagram - Condensate 10.4-8 Powerhouse Unit 1 - Flow Diagram - Feedwater 10.4-8 Powerhouse Unit 2 - Flow Diagram - Feedwater 10.4-9 Powerhouse Unit 1 - Electrical Control Diagram - Condensate System 10.4-9 Powerhouse Unit 2 - Electrical Control Diagram - Condensate System 10.4-10 Powerhouse Unit 1 - Electrical Control Diagram - Condensate System 10.4-10 Powerhouse Unit 2 - Electrical Control Diagram - Condensate System 10-vi
WBN LIST OF FIGURES Number Title 10.4-11 Powerhouse Units 1 & 2 - Electrical Control Diagram - Condensate System 10.4-11A Powerhouse Units 1 & 2 - Electrical Control Diagram - Condensate System 10.4-11B Powerhouse Units 1 & 2 - Electrical Control Diagram - Condensate System 10.4-12 Powerhouse Units 1 & 2 - Logic Diagram - Condensate System 10.4-13 Powerhouse Unit 1 - Logic Diagram - Condensate System 10.4-13 Powerhouse Unit 2 - Logic Diagram - Condensate System 10.4-13A Powerhouse Unit 1 - Logic Diagram - Condensate System 10.4-13A Powerhouse Unit 2 - Logic Diagram - Condensate System 10.4-14 Powerhouse Unit 1 - Electrical Control Diagram - Main Aux. Feedwater System 10.4-14 Powerhouse Unit 2 - Electrical Control Diagram - Main Aux. Feedwater System 10.4-14, Sh A Powerhouse Unit 1 - Electrical Control Diagram - Main Aux. Feedwater System 10.4-14, Sh A Powerhouse Unit 2 - Electrical Control Diagram - Main Aux. Feedwater System 10.4-14, Sh B Powerhouse Unit 1 - Electrical Control Diagram - Main Aux. Feedwater System 10.4-14, Sh B Powerhouse Unit 2 - Electrical Control Diagram - Main Aux. Feedwater System 10.4-14, Sh C Powerhouse Unit 1 - Electrical Control Diagram - Main Aux. Feedwater System 10.4-14, Sh C Powerhouse Unit 2 - Electrical Control Diagram - Main Aux. Feedwater System 10.4-14, Sh D Powerhouse Unit 1 - Electrical Control Diagram - Main Aux. Feedwater System 10.4-14, Sh D Powerhouse Unit 2 - Electrical Control Diagram - Main Aux. Feedwater System 10.4-15 Powerhouse Unit 1 - Electrical Control Diagram - Main Aux. Feedwater System 10.4-15 Powerhouse Unit 2 - Electrical Control Diagram - Main Aux. Feedwater System 10.4-15, Sh A Powerhouse Unit 1 - Electrical Control Diagram - Main Aux. Feedwater System 10.4-15, Sh A Powerhouse Unit 2 - Electrical Control Diagram - Main Aux. Feedwater System 10.4-15, Sh A Powerhouse Unit 2 - Electrical Control Diagram - Main Aux. Feedwater System 10.4-15, Sh B Powerhouse Unit 1 - Electrical Control Diagram - Main & Aux. Feedwater System 10-vii
WBN LIST OF FIGURES Number Title 10.4-15, Sh B Powerhouse Unit 2 - Electrical Control Diagram - Main & Aux. Feedwater System 10.4-15, Sh C Powerhouse Unit 1 - Electrical Control Diagram - Main & Aux. Feedwater System 10.4-15, Sh C Powerhouse Unit 2 - Electrical Control Diagram - Main & Aux. Feedwater System 10.4-16 Powerhouse Unit 1 - Electrical Control Diagram - Main Auxiliary Feedwater System 10.4-16 Powerhouse Unit 2 - Electrical Control Diagram - Main Auxiliary Feedwater System 10.4-16A Powerhouse Unit 1 - Electrical Control Diagram - Auxiliary Feedwater System 10.4-16A Powerhouse Unit 2 - Electrical Control Diagram - Auxiliary Feedwater System 10.4-17 Powerhouse Units 1 & 2 - Electrical Logic Diagram - Feedwater Pump Turbine Auxiliaries 10.4-18 Powerhouse Units 1 & 2 - Electrical Logic Diagram - Feedwater System 10.4-19 Powerhouse Unit 1 - Electrical Logic Diagram - Auxiliary Feedwater System 10.4-19 Powerhouse Unit 2 - Electrical Logic Diagram - Auxiliary Feedwater System 10.4-20 Powerhouse Units 1 & 2 - Electrical Logic Diagram - Auxiliary Feedwater System 10.4-20A Powerhouse Units 1 & 2 - Electrical Logic Diagram - Auxiliary Feedwater System 10.4-21 Powerhouse Units 1 & 2 - Flow Diagram - Auxiliary Feedwater 10.4-21A Powerhouse Unit 1 - Flow Diagram - Main and Auxiliary Feedwater 10.4-21A Powerhouse Unit 2 - Flow Diagram - Main and Auxiliary Feedwater 10.4-22 & 23 Deleted 10.4-24 Powerhouse Units 1 & 2 - Flow Diagram - Steam Generator Blowdown System 10.4-25 & 26 Deleted 10.4-27 Powerhouse Unit 1 - Flow Diagram - High Pressure Heater Drains and Vents 10.4-28 Powerhouse Unit 1 - Flow Diagram - Low Pressure Heater Drains and Vents System 10.4-29 Powerhouse Unit 1 - Electrical Control Diagram - Heater Drains and Vents System 10-viii
WBN LIST OF FIGURES Number Title 10.4-30 Powerhouse Unit 1 - Electrical Control Diagram - Heater Drains and Vents System 10.4-31 Powerhouse Unit 1 - Electrical Control Diagram - Heater Drains and Vents System 10.4-32 Powerhouse Unit 1 - Electrical Control Diagram - Heater Drains and Vents System 10.4-33 Powerhouse Unit 1 - Mechanical Control Diagram - Heater Drains and Vents 10.4-34 Powerhouse Unit 1 - Electrical Logic Diagram - Heater Drains and Vents 10.4-35 Powerhouse Unit 1 - Electrical Logic Diagram - Heater Drains and Vents 10.4-36A Unit 1 - Turbine Building Flow Diagram - Condensate Demineralizer System 10.4-36A Unit 2 - Turbine Building Flow Diagram - Condensate Demineralizer System 10.4-36B Turbine Building Flow Diagram - Condensate Demineralizer System 10.4-36C Turbine Building Flow Diagram - Condensate Demineralizer System 10-ix
WBN 10.0 MAIN STEAM AND POWER CONVERSION SYSTEMS 10.1
SUMMARY
DESCRIPTION The steam and power conversion system is designed to convert the heat produced in the reactor to electrical energy through conversion of a portion of the energy contained in the steam supplied from the steam generators, to condense the turbine exhaust steam into water, and to return the water to the steam generator as heated feedwater. The major components of the steam and power conversion system are: turbine-generator, main condenser, vacuum pumps, turbine seal system, turbine bypass system, hotwell pumps, demineralized condensate pumps, condensate booster pumps, steam-turbine-driven and electric-motor-driven main feed pumps, main feed pump turbines (MFPT), MFPT condenser-feedwater heaters, feedwater heaters, heater drain pumps, demineralizers, and condensate storage system. Component arrangement is shown in Figure 10.1-1. The heat rejected in the main condenser is removed by the circulating water system. The saturated steam produced by the steam generators is expanded through the high pressure turbine and then exhausted to the moisture separator/reheaters. The moisture separator section removes the moisture from the steam and the two stage reheaters superheat the steam before it enters the low pressure turbines. The steam then expands through the low pressure turbines and exhausts into the main condenser where it is condensed and deaerated and then returned to the cycle as condensate. The first stage reheater is supplied with steam from the No. 1 extraction point; the condensed steam is cascaded to the No. 2 heaters. The second stage reheater is supplied with main steam. The condensed steam cascades to the No. 1 heaters. Condensate is withdrawn from the condenser hotwells by motor-driven hotwell pumps. The pumps discharge into a common header which normally carries the condensate through the nd gland steam condenser, steam generator blowdown 2 stage heat exchanger, the main feed pump turbine condensers, and then through three parallel strings of low-pressure heaters. This st flow path can also split off to the steam generator blowdown 1 stage heat exchangers. Each string consists of three stages (Nos. 7 through 5, with No. 5 the highest pressure) of low-pressure extraction feedwater heaters to the condensate booster pumps. Whenever condensate demineralization is required, the common header for the hotwell pumps carries the condensate through the demineralizers to the gland steam condenser, steam generator nd blowdown 2 stage heat exchanger, the main feed pump turbine condensers, and then to the demineralized condensate pumps. These pumps discharge to a common header which then carries the condensate through three parallel strings of low pressure heaters and to the suction of the condensate booster pumps. The condensate booster pumps discharge to a common header which divides the flow back into three parallel strings of intermediate pressure heaters, each string consisting of three stages (Nos. 4 through 2) of extraction feedwater heaters. 10.1-1
WBN The condensate from the intermediate pressure heater strings is then routed to the main feed pumps. These pumps discharge to a common header which divides and passes through three parallel strings of single-stage high pressure heaters and returns to a common line before dividing into four streams to the four steam generators. Heat for the feedwater heating cycle is supplied by the moisture separator reheater drains and by steam from the turbine extraction points. A summary description of the important components and design parameters of the steam and power conversion system is contained in Table 10.1-1. Heat balances for the steam and power conversion cycle are shown in Figure 10.1-2. REFERENCES
- 1. Westinghouse letter, WAT-D-7489, Watts Bar Nuclear Plant Units Numbers 1 and 2 -
Main Steam Safety Valves Excess Blowdown Analysis - Phase 2, August 28, 1987. 10.1-2
WBN-3 TABLE 10.1-1 (Sheet 1 of 4)
SUMMARY
OF IMPORTANT COMPONENT DESIGN PARAMETERS (All Values Nominal) VERTICAL STEAM GENERATORS UNIT 1 UNIT 2 Number 4 per unit 4 per unit Length 812.0 in. (overall) 812.0 in. (overall) Diameter 175.94 in. (maximum) OD 176.14 in. (maximum) OD Heating Surface 68,000 sq ft. 48,000 sq ft. Tubes 5,128 U-tubes - 0.75 in. OD x 4674 U-tubes - 0.75 in. OD x 0.043 nom. wall, Inconel 0.043 nom. wall, Inconel (ASME-SB-163) material (ASME-SB-163) material Operating conditions at 100 Percent Load at SG (0% SGTP) Steam flow rate - 3.847 x 106 lb/hr per SG U1 3.778 x 106 lb/hr per SG U2 Steam temperature - 548.2°F U1 542.9°F U2 Steam pressure - 1030 psia U1 986 psia U2 Steam quality - 99.90 RSG U1 99.75 OSG U2 TURBOGENERATOR Manufacturers Westinghouse Electric Corporation/Siemens Energy, Inc. Turbogenerator 1,236,239 kW (Unit 1), 1,241.2 MW (Unit 2) nameplate rating Turbine type Horizontal, reaction, tandem-compound, two stage reheat, extraction, condensing 1800-rpm single shaft - 1 HP and 3 LP turbines with 6-flow exhaust and 44 in. (LPA
& LPB) and 45 in. (LPC) (Unit 1), 45 in. (Unit 2) last-stage buckets Generator type One direct connected, Hydrogen cooled rotor, water-cooled stator, 1,411,000 kVA, and 0.9 PF, 75 psig hydrogen, 3 ph, 60 Hz, 24,000 V, 33,943 Amp, 0.6 scr, Y-connected maximum nameplate rating Exciter type and One shaft-driven, brushless - 6000 kW, 550 volt DC, 1800 rpm capacity Heat Rate (Original Westinghouse Turbine Generator Data)
Guaranteed performance based on extraction for feedwater heating, including all losses in the unit, also exciter and rheostat losses, rated throttle steam conditions, and 2.0 in. of Hg absolute exhaust pressure with zero makeup: kW Btu/kWh 1,218,225 9593 Design heat balance for 100% power case and the current heat rate are shown on Figure 10.1-
- 2. (Unit 1)
WBN-1 TABLE 10.1-1 (Sheet 2 of 4)
SUMMARY
OF IMPORTANT COMPONENT DESIGN PARAMETERS (All Values Nominal) MOISTURE SEPARATOR AND REHEATERS Number 6 per unit Type Moisture removal separator and 2-stage reheat (HP and LP) Size 45 ft - 11.75 inches length, 10 ft - 9 inches diameter (Unit 1) 51 ft - 8.25 inches length, 11 ft - 8.5 inches diameter (Unit 2) MAIN FEEDWATER PUMP TURBINE MAIN FEEDWATER PUMPS STANDBY MAIN FEEDWATER PUMPS CONDENSATE BOOSTER PUMPS (See Section 10.4.7.2) NO. 3 HEATER DRAIN PUMPS Number 3 Manufacturer Borg-Warner Corporation, Byron-Jackson Pump Division Type DSJH, single stage, double suction, double volute, centrifugal Size 8 x 10 x 18H Design Point 3600 gpm, 1200 ft head Motor Manufacturer Parsons-Peebles, Ltd. Motor Design 1500 HP, 3575 rpm, 6600 V, 3 ph, 60Hz, horizontal, constant speed NO. 7 HEATER DRAIN PUMPS Number 2 Manufacturer Borg-Warner Corporation, Byron-Jackson Pump Division Type DSJH, single stage, double suction, double volute, centrifugal Size 8 x 10 x 15L Design Point 2000 gpm, 730 ft Motor Manufacturer Parsons-Peebles, Ltd. Motor Design 450 HP, 3565 rpm, 6600 V, 3 ph, 60 Hz, horizontal, constant speed CONDENSATE HOTWELL PUMPS DEMINERALIZED CONDENSATE PUMPS (See Section 10.4.7.2)
WBN-1 TABLE 10.1-1 (Sheet 3 of 4)
SUMMARY
OF IMPORTANT COMPONENT DESIGN PARAMETERS (All Values Nominal) CONDENSER Number 1 Manufacturer Ingersoll-Rand Company Type Horizontal, single shell, triple pressure, single pass, surface, de-aerating Total surface area, sq ft - 824,000 Type - Tube data 27,410 Tubes, 114 ft 8-1/2 in. effective length, welded, 1.0 in. outside diameter, Tubes are SEA-CURE, 104 tubes are 18 BWG (in the top row), the remaining 27, 306 tubes are 22 BWG Tube Sheets Cooper bearing steel Waterboxes Divided, two inlet (102 in. dia) and two outlets (102 in. dia) bottom connections per shell Hotwell data Deaerating type, storage capacity of hotwell at normal operating level, 56,000 gal Circulating water 410,000 flow, gpm Cleanliness, 95 percent Duty, 109 Btu/hr 7.789 Design pressures Shell, psig - 25 and vacuum Hotwell, psig - 30 Waterboxes, psig - 72 AIR REMOVAL EQUIPMENT Number 3 Manufacturer Nash Engineering Company Type Mechanical, vacuum (2 stage liquid ring) Size AT-2004E Design Point Suction pressure in. of Hg absolute - 1.0, Rated capacity, each - 15 SCFM Motor Manufacturer General Electric Company Motor Design 100 HP, 514 rpm (Syn. Speed), 460 V, 3 ph, 60 HZ horizontal, constant speed FEEDWATER HEATER (See Section 10.4.7.2) SAFETY VALVES Number - 5 per steam generator Minimum flow capacity, lb/hr/steam generator - 4,160,597
WBN-1 TABLE 10.1-1 (Sheet 4 of 4)
SUMMARY
OF IMPORTANT COMPONENT DESIGN PARAMETERS (All Values Nominal) Rated Blowdown Press. Max. Press. Flow Press. In. Accumu- Expected in Steam at Set Below Steam lation Accumu- Header Pressure Set Header Press. to lation at Rated + 3% Pressure at Set fully Open Press at Relieving Accumu- to Valve Valve Mark Press. Valve max Flow Flow lation Close Closing No. (psig) % % (psig) (lb/hr) (%)[1] (psig) 47W400- 1185 3 8.4 1284 791,563 10 1066.5 A3796 47W400-101 1185 3 8.4 1284 791,563 10 1066.5 47W400- 1195 3 7.4 1284 798,163 10 1075.5 A3797 47W400-102 1195 3 7.4 1284 798,163 10 1075.5 47W400- 1205 3 6.6 1284 804,764 10 1084.5 A3798 47W400-103 1205 3 6.6 1284 804,764 10 1084.5 47W400- 1215 3 5.7 1284 811,364 10 1093.5 A3799 47W400-104 1215 3 5.7 1284 811,364 10 1093.5 47W400- 1224 3 4.9 1284 817,304 10 1101.6 A3800 47W400-105 1224 3 4.9 1284 817,304 10 1101.6 Note 1 - The licensing basis for the WBN plant is 10% maximum blowdown (See Reference [1]). This is more conservative than the 5% maximum blowdown specified by the ASME Section III requirements. Atmospheric Relief Valves Number 1 - per steam generator Minimum capacity, lb/hr/inlet pressure, psig - 64,000/85 Maximum capacity, lb/hr/inlet pressure, psig - 970,000/1185 outlet pressure, psig - 0 Turbine Bypass Valves Number of valves - 12 Flow per valve, lb/hr - 532,170 Main steam pressure at valve inlet (for above flow), psig - 900 Maximum flow per valve at 1185 psig inlet pressure, lb/hr - 970,000 Time to open (full stroke), 3 seconds Full stoke modulation, 20 seconds Failure position - Closed
C) 32 ' ? r 37.5" o.o-.~ z 37.5" O.D-.~ 8"-- 0 w z MOISTURE SE PARA TOR <,: MOTOR DRIVEN REHEATER f- FEEDWATER PUMP t. ~ A2 z ~ EL 7 62' 0" ~ 2 0 u
~-37.5" 0.0 I r7I HE ATER CS (lEL7.l6'-6 I HEATER C6 tEL727'-9 " )
CC. HEATER 87 EL 736'-6" HEATER C7 ((;_ EL 736'-6 " I o CONDENSER CONDENSER
..... ..... ...... I I I 8------ -I ZONE 8 ZONE C
.? -4" .? r ~16 ' ~10" I I ~ ~
---12*
---12* L .0. ~ 0-L .0.
t* 1 36"- :-0 STEAM GENERATOR I
~ :..~ ~ ! ! -r(cl7- j A 8 I C :" A ~ -risn- ~ lnch- ~ 24 LOOP 3 INSIDE REACTOR OUTSIDE REACTOR ~~~iRCULATING ~ ( ~ ~ E L 713.0 -~~-~==~~~~=/'/4~-~E~LL 6 8 5 ~ ~ L 685.5 - ~ - ~ ~24" 18" 16" 8" CONTAINMENT _ 'INE ,ux. FEEDWATIER PUMPS CONDENSATE BOOSTER PUMPS CONDENSER v,c. PUMPS COH~;:'~ ;~~s DRAW I NG S >--------c~ 1 1 1/2" 11
_ REFERENCE DRAWINGS: TO UNIT 2 TURBINE
.,. g:~88: SERIES ng: g ~g~~~ : ~~~~~Ls~§~~~SSYSTEMS H~~~~= SERIES FLOW FLOW D AGRAM - CONDENSER CIRCULATING ll'ATER PUMP GLAND SEAL D AGRAM - CONDENSATE DEMINERALIZER VALVE MARKER TAGS 308617 SERIES DRAWINGS-INSTRUMENTATION SYMBOLS AND IDENTIFICATIONS 47W801- FLOW D AGRAM - MAIN &. REHEAT STEAM &. STEAM GEN BLDN 47W839- FLOW D AGRAM - DIESEL STARTING AIR 47W802- FLOW D AGRAM - EXTRACTION STEAM 47W840- FLOW D AGRAM - FUEL OIL SYSTEM
!-~YARD~ - - --7 DRIVEN AUX.
-4" FEEDWATER PUMP 47W803- FLOW D AGRAM - FEEDWATER &. AUXILIARY FEEDWATER 47W841- FLOW D AGRAM - GLAND SEAL WATER 47W804- FLOW D AGRAM - CONDENSATE 47W842- FLOW D AGRAM - INSULA OIL 47W805- FLOW D AGRAM - DRA[NS &. VENTS 47W843- FLOW O AGRAM - E, FI RE PROT, & PURG SYS 47W806- FLOW D AGRAM - EXTRACTION TRAPS 47W844- FLOW D AGRAM - G WATER 47WS07- FLOW D AGRAM - DRAINS &: MISC PIPING 47W845- FLOW D AGRAM - RAW COOLING WATER 47W808- FLOW D AGRAM - DRAINS .t:. VENTS <l MISC PIPING 47W846- FLOW D AGRAM - AIR-STA SERV
~ ~
47W809- FLOW D AGRAM - & VOLUME CONTROL FLOW D AGRAM - ECOVERY SYSTEM 47W848- FLOW DIAGRAM - CONTROL AIR v STORAGE STORAGE .Nt .Nt I 47'11810-4711'811-FLOW FLOW FLOW D AGRAM D AGRAM D AGRAM DU TY TDOll'N & CHARGING HEAT REMOVAL TION 47W849-47W850-47W851-FLOW FLOW FLOW DIAGRAM DIAGRAM DIAGRAM HYDROGEN SYSTEM GEN COOLING FIRE PROT & RAW SERVICE WATER STATION DRAINAGE-RB I TANK A UNIT 1 TANK B UNIT 2 ~ ~ I ~ _.,,,-- STEAM GENERATOR I Cl I 4711'812-4711'813-FLOW FLOW D AGRAM D AGRAM CONTAI REACTO SPRAY ANT 47W852-47W853-FLOW FLOW DIAGRAM DIAGRAM STATION DRAINAGE-AB STATION DRAINAGE-TB
/ BLOWDOWN FLASH TANK I - I 4711'814- FLOW D AGRAM - ICE CO R REFRIGERATION 47W854- FLOW DIAGRAM - FEEDWATER TREATMENT SECONDARY CHEMICAL FEED FLOW D AGRAM - ICE C R REFRIGERATION-ICE CHG 47W855- FLOW DIAGRAM - FUEL POOL CLEANING&. COOLING AUX. FEEDWATER 21/2:
I 1 <.""'*: I1 I 47W815-47W816-FLOW FLOW DIAGRAM DIAGRAM AUXILI LUBRICATING OIL ILER 47W856-47W857-FLOW FLOW DIAGRAM DI,1,.GRAM DEMINERALIZED WATER CON TUBE CLEANING WATTS BAR Ul~~ ~~~ ~ 47W858- FLOW DIAGRAM - CONDENSER WATER CHLORINATION SYSTEM l~~I k 47W859- FLOW OI,1,.GRAM - COMPONENT COOLING WATER PUMP RECIRC. I O J I 47W819-47W821-FLOW DIAGRAM - PRIMARY WATER STORAGE & SUPPLY FLOW DIAGRAM - CHEMICAL CLEANING 47W860-
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# - FLOW, LB/HR M - PERCENT MOISTURE NET PLANT HEAT RATE 9976.0 BTU/KW-HR MR - MOISTURE REMOVAL REACTOR OUTPUT (MM TO TURB CYCLE) 3475.-0 M'vVTHERMAL WATTS BAR FINAL SAFETY ANALYSIS REPORT POWERHOUSE UNIT 2 MAXIMUM GUARANTEED HEAT BALANCE 100% MW THERMAL TVA DWG NO. 47K1110-1A R1 FIGURE 10.1-2(U2)
WBN-1 10.2 TURBINE-GENERATOR 10.2.1 Design Bases The purpose of the turbine generator is to use steam supplied by the pressurized water reactor (PWR) in the conversion of thermal energy to electrical energy, and to provide extraction steam for feedwater heating. The turbine generator together with its associated systems and their control characteristics are integrated with the features of the reactor and its associated systems to obtain an efficient and safe energy conversion and power generation unit. For Unit 1, the turbogenerator unit receives steam from the four steam generators and converts the thermal energy to electric energy. The Siemens (formally Westinghouse) turbine generator data is as follows: 1,236,239 kW when the steam flow is 14,590,396 at throttle steam conditions of 1018.6 psia, 0.1% (0.17% at turbine) moisture, and LPA/LPB/LPC back pressures of 1.92/2.70/3.75 inches of Hg absolute, with 0% makeup under normal conditions. At the valves wide open or stretch condition the generator is rated at 1,257,861 kW with a steam flow of 14,895,419 lb/hr at 1018.6 psia, 0.17% moisture, at LPA/LPB/LPC back pressures of 1.92/2.70/3.75 inches of Hg absolute, and 0% makeup. Actual plant operating conditions and design will differ slightly from the rated parameters given above. The design heat balance for the 100% power case is shown in Figure 10.1-2. For Unit 2, the turbogenerator unit receives steam from the four steam generators and converts the thermal energy to electric energy. The Siemens (formerly Westinghouse) turbine generator data is 1,241,200 kW when the steam flow is 14,565,293 lb/hr steam conditions of 985 psia, 0.25% (0.39% at turbine) moisture, and at a zonal back pressure of 1.92/2.70/3.75-inches of Hg absolute, with 0% makeup under normal conditions. At the valves wide open or stretch condition the generator is rated at 1,268,900 kW with a steam flow of 14,855,223 lb/hr at 985 psia, 0.31% moisture, at a zonal back pressure of 1.92/2.70/3.75-inches of Hg absolute, and 0% makeup. Actual plant operating conditions and design will differ slightly from the rated parameters given above. The design heat load balance for the 100% power case is shown in Figure 10.1-2. Under emergency conditions the turbine protection system provides the necessary protection for the turbine-generator equipment. The intended mode of operation for the unit is to be utilized primarily as a base loaded unit. 10.2.2 Description The turbine generator unit consists of the following components: turbine, generator, exciter, controls, and required support subsystems. The turbine is a tandem compound double-stage reheat unit with 44-inches (LPA & LPB), 45-inches (LPC) (Unit 1), 45-inches (Unit 2) last-stage blades. The turbine consists of a double-flow, high pressure turbine and three double-flow, low pressure turbines with extraction nozzles arranged for seven stages of feedwater heating. Exhaust steam from the unit passes through six moisture separator/reheaters before entering the low pressure turbines. The moisture separator/reheaters are shell and tube-type heat exchangers containing a section of chevron vanes for moisture separation. The chevron-type vanes alter the steam flow direction to reduce the moisture content of the steam through centrifugal separation of the moisture particles. Heating steam enters the reheater U-tube bundles to provide two stages of reheat for the steam flowing from the chevron section. 10.2-1
WBN-3 The generator is a direct-connected, hydrogen-cooled, 3 phase, 60 Hz, 24,000 volt, 1800 rpm synchronous generator rated at 1,411,000 kVA, 0.90 power factor (PF), with a short circuit ratio (scr) of 0.60. It is designed with conductor cooling of the armature winding. Hydrogen gas pressure is 75 psig and conductor coolant is demineralized water. The excitation system is rated at 6,000 kW and 550 volts. The turbogenerator and its associated systems and controls are integrated with the reactor and its associated systems and controls at all times to obtain an efficient and safe energy conversion and power generator unit. The reactor controls enable the NSSS to follow plant (turbogenerator) load changes automatically, including the acceptance of step load increases or decreases of 10% and ramp increases or decreases of 5% per minute within the load range of 15% to 100% without reactor trip or steam dump. Manual control is required below 15% load. The difference between the highest measured average reactor coolant loop temperature and the programmed reference temperature (based on turbine impulse pressure) which is processed through a lead-lag compensation unit, constitutes the primary control signal for the reactor control system. An additional control input signal to the reactor is derived from the reactor power versus turbine load mismatch signal. These signals provide input to the rod control system to control the reactor coolant temperature by regulation of the control rod bank position. The turbine control system is electrohydraulic and consists of several different control subsystems that are used to control turbine speed, plant load, speed and load rates, and other turbine features during plant startup, plant operation at rated conditions, and plant shutdown. Also, normal, pre-emergency, and emergency governing devices are incorporated into the control system to prevent turbine overspeed conditions. The following describes the turbine control system for each unit. Turbine Controls The control system consists of five major components as follows:
- 1. A solid-state electronic controller cabinet.
- 2. An operator's panel.
- 3. Steam valve servo-actuators.
- 4. A high pressure fluid control and trip system.
- 5. An interface to the Distributed Control System for Human-Machine Interface (HMI).
The electronic controller cabinet contains digital equipment for control of the turbine. It performs computations and validations on reference and turbine feedback signals and generates output signals to the steam valve actuators. The operator's panel is in the unit control center. Through various push buttons the operator can change the reference input to the controller to vary the speed or load at different rates. Similar changes can be made through the Human Machine Interface via controller XX-47-2000. Operator settings are used by the controller to position the steam valves. The position of each steam valve is controlled by an actuator which consists of a hydraulic cylinder using fluid pressure to open and spring action to close. The cylinder is connected to a control block upon which are mounted isolation, dump, and check valves. (see Figures 10.2-2, 10.2-3, and 10.2-4 for steam, actuator, and other valve numbers and system arrangements) The main stop (throttle) valve, reheat stop valve, and interceptor valve actuators position these steam valves (see FCV-1-61, -64, -67, -70, -87, -88, -94, -95, -101, -102, -123, -124, -128, -129, 10.2-2
WBN-2 -133, and -134 on Figure 10.2-3) only in the fully open or fully closed position (except for a brief period during startup when the main stop throttle valves (FCV-1-61, -64, -67, and 70) are used for initial speed control). High pressure fluid is supplied through an orifice to the area below the hydraulic cylinder piston. Fluid pressure in this area is controlled by a pilot-operated dump valve for the reheat stop and interceptor valves and by a servo- and/or pilot-operated dump valve for the main stop valves. With the turbine trip valves closed, the pilot-operated dump valves close to build up fluid pressure under the cylinder piston, opening the reheat stop and interceptor valves. Solenoid valves provided for testing of the reheat stop and interceptor valves also open the dump valves, releasing the fluid to drain, thus testing the valves capability to close. The control (governor) valve actuators position steam valves (FCV-1-62, -65, -68, and -71) in any intermediate position to proportionally regulate the steam flow to the required amount. Each control (governor) and stop (throttle) valve actuator is provided with a servo-valve and two linear variable differential transformers (LVDT). High pressure fluid is supplied to the servo-valve which controls the actuator position in response to a position signal from the digital controller. The LVDTs develop analog signals proportional to the valve position, which are fed back to the controller to complete the control loop. A signal can be introduced to the controller to test the main stop and control valves. The digital turbine controls contain redundant components for variable positioning of both the throttle and governor valves. Two LVDTs are provided for each of the valves. Their associated servo valves have two coils each. The LVDT signals and the servo coils are wired to redundant cards in the digital control system such that no single component failure can be tolerated. Failures and errors associated with this equipment are alarmed. Isolation valves permit on-line maintenance of the actuator components, including the hydraulic cylinder. Check valves prevent fluid backflow from the drain or emergency trip circuits. The function of the high pressure fluid control system is to provide a motive force which positions the turbine steam valves in response to commands from the controller, acting through the servo-actuators. The fluid is stored in a reservoir assembly on which is mounted a duplicate system of fluid pumps, controls, filters, and heat exchangers. The system is so arranged that one pump and one set of the various control components function while the duplicate set serves as a standby system. The turbine protection system has, as its basis, an emergency trip fluid system in the high pressure fluid control system (See Figures 10.2-2 and 10.2-3). A Trip Block Assembly (TBA) is provided that consists of redundant trip solenoid valves arranged in a redundant trip arrangement. The TBA includes 4 de-energize-to-trip solenoids for the Emergency Trip (ET) Header arranged in a pattern which allows testing of each solenoid while the unit is on-line. The trip block has 4 solenoids in the ET header arranged in a series/parallel configuration. To provide redundant protection, the solenoid valves are arranged into 2 independent channels with 2 solenoids per channel. Tripping occurs if at least one upstream solenoid and one downstream solenoid in either channel is de-energized. This fail-safe design provides for both reliability and testability. The ET header solenoids control the pilot pressure to the dump valves for all steam valves. Tripping of the emergency trip fluid system also causes trip closure of the extraction non-return valves (See XDV-47-27 on Figure 10.2-3). The turbine control system provides two types of overspeed protection mechanisms to isolate main steam to the turbogenerator when the rated operating speed of 1800 rpm is exceeded. During normal speed-load control, the digital controller will rapidly close the throttle, governor, reheat stop and interceptor valves in case of an overspeed condition of approximately 103% rated speed. The unit will then coast down to turning gear operation. If for some reason the 10.2-3
WBN-3 digital control system does not function and the turbine speed increases to approximately 104% of rated speed, an Independent Overspeed Protection System (IOPS) will trip closed all steam valves (throttle, governor, reheat stop, and interceptor valves) and prevent the turbine speed from exceeding 120% of rated speed. The unit will then coast down to turning gear operation. The IOPS is a fault tolerant electronic overspeed trip device utilizing speed probes that are separate from the normal turbine control system speed probes. The IOPS is configured such that a single component failure will not initiate a spurious turbine trip nor disable the turbine protection function. The turbine trip system is also equipped with solenoid-operated trip devices, which provide means to initiate direct tripping of the turbine upon receipt of appropriate electrical signals, as shown in Figure 10.2-1. Turbine governor functions and turbine control are discussed more fully in Section 7.7. For overpressure protection of the turbine exhaust hoods and the condenser, four rupture diaphragms which rupture at approximately 5 psig are provided on each turbine exhaust hood. Additional protective devices include exhaust hood high temperature alarm and manual trip. A discussion of turbine missiles is found in Section 3.5. 10.2.3 Turbine Rotor and Disc Integrity The failure of a turbine disc or rotor might produce a high energy missile that could damage a safety-related component (see Section 3.5 for turbine missile analysis). The risk from missiles from a hypothetical turbine-generator failure on safety-related systems or components is discussed in Sections 3.5.1.3.3 through 3.5.1.3.6. Integrity of the turbine discs and rotors is demonstrated by information provided in this section. 10.2.3.1 Materials Selection - Historical Information Unit 1 The detailed materials specifications, fabrication history, and chemical analysis of the disc and rotor forgings are considered proprietary information of the turbine manufacturer, Westinghouse Electric Corporation. The high pressure rotor is made of NiCrMoV alloy steel. The specified minimum mechanical properties are as follows: Tensile Strength, psi 105,000 Yield Strength, psi (0.2% offset) 90,000 Elongation in 2-inches, percent 17 Reduction of Area, percent 50 Impact Strength, Charpy V-Notch, ft-lb 50 (min. at room temperature) 50% Fracture Appearance Transition 40 Temperature, °F, max. The blade rings and the casing cover and base are made of carbon-steel castings. The specified minimum mechanical properties are as follows: Tensile Strength, psi 70,000 Yield Strength, psi 36,000 10.2-4
WBN-3 Elongation in 2-inches, percent 22 Reduction of Area, percent 35 The casing cover and base are tied together by means of more than 100 studs. The stud material is an alloy steel having the following properties: 2-1/2 inch Over 2-1/2 0ver 4 to and less to 4 inch 7 inch Tensile Strength, psi 125,000 115,000 110,000 Yield Strength, psi 105,000 95,000 85,000 (0.2% offset) Elongation in 2-inches, 16 16 16 percent Reduction of area, percent 50 50 45 The low pressure rotors are made of NiCrMoV alloy steel. The specified minimum mechanical properties are as follows: Tensile Strength, psi 115,000 Yield Strength, psi(0.2% offset) 100,000 Elongation in 2-inches, percent 17 Reduction of Area, percent 50 Impact Strength, Charpy V-Notch, ft-lb 40 (t room temperature) 50% Fracture Appearance Transition 50 Temperature F, max. The outer cylinder and the two inner cylinders are fabricated mainly of ASTM 515-GR65 material. The minimum specified properties are as follows: Tensile Strength, psi 65,000 Yield Strength, psi 35,000 Elongation in 8, percent 19 Elongation in 2, percent 23 The shrunk-on discs are made of NiCrMoV alloy steel. There are ten discs shrunk on the shaft with five per flow. These discs experience different degrees of stress when in operation. Disc No. 2, starting from the transverse centerline, experiences the highest stress, while disc No. 5 10.2-5
WBN-3 experience the lowest. The minimum specified mechanical properties for the discs are as follows: Disc 1 Disc 2 Discs 3-5 Tensile Strength, psi 130,000 140,000 120,000 Yield Strength, psi 120,000 130,000 110,000 Elongation in 2 (disc hub) 14 13 15 percent Elongation in 2 (disc rim) 16 15 17 percent Reduction of area (disc hub) 35 35 38 percent Reduction of area (disc rim) 40 40 43 percent Impact strength (hub and rim) 50 50 50 Charpy V-Notch, ft-lb (at room temp) 50% Fracture Appearance 0 0 0 Transition Temp. (disc hub and rim) °F Unit 2 The detailed materials specifications, fabrication history, and chemical analysis of the disc and rotor forgings are considered proprietary information of the turbine manufacturer, Siemens (formerly Westinghouse Electric Corporation). The high pressure rotor is made of NiCrMoV alloy steel. The specified minimum mechanical properties are as follows: Tensile Strength, psi 118,900 Yield Strength, psi (0.2% offset) 84,100 - 98,600 Elongation in 2-inches, percent 16 Reduction of Area, percent 50 Impact Strength, Charpy V Notch, ft lb 66 (min. at room temperature) 50% Fracture Appearance Transition -22 Temperature, °F, max. 10.2-6
WBN-3 The HP inner casing and guide blade carriers are made of stainless steel castings. The HP outer casing cover and base are made of carbon-steel castings. The specified minimum mechanical properties are as follows: Property Guide Blade Carriers and Outer Casing Base & Inner Casing Cover Material Modified ASTM A487 ASTM A216 Grade WCB Grade CA15 Tensile Strength, psi 78,500 - 100,00 70,000 Yield Strength, psi 51,500 36,000 Elongation in 2-inches, 18 22 percent Reduction of Area, percent 45 35 The casing cover and base are tied together by means of more than 100 studs. For most of the horizontal joints, the stud material is an alloy steel; while in the blade ring fit and gland areas, the studs are upgraded to 12 Cr stainless steel. The bolting has the following minimum properties: Property Low Alloy Steel Studs and Bolts 12 Cr Studs and Bolts 2-1/2 inch Over 2-1/2 Over 4 No Size and less to 4 inch to 7 inch Constraint ASTM A193 Grade B7 Modified AISI 616 Tensile Strength, psi 125,000 115,000 110,000 135,000 Yield Strength, 105,000 95,000 85,000 110,000 (0.2% offset), psi Elongation in 2- 16 16 16 14 inches, percent Reduction of area, 50 50 45 32 percent The low pressure rotors are made of NiCrMoV alloy steel. The specified minimum mechanical properties are as follows: Property Rotor Shaft Tensile Strength, psi 149,390 Yield Strength, psi (0.2% offset) 107,300 - 121,800 Elongation in 2-inches, percent 15 Reduction of Area, percent 45 Impact Strength, Charpy V-Notch, ft-lb (at room temperature) 74 50% Fracture Appearance Transition Temperature °F, (max.) -58 10.2-7
WBN-3 The LP outer cylinder and inner casing are fabricated mainly of carbon steel plate material. The minimum specified properties are as follows: Property Outer Cylinder Inner Casing ASTM A515 - GR65 ASTM A515- GR60, GR65, GR70* Tensile Strength, psi 65,000 56,500 - 76,900 Yield Strength, psi 35,000 26,800 - 38,400 Elongation in 8 ft, percent 19 22 Elongation in 2 ft, percent 23 22
- Note: Grade of material depends upon location within LP inner casing fabrication and plate thickness.
The shrunk-on discs are made of NiCrMoV alloy steel. There are six discs shrunk on the shaft with three per flow. The minimum specified mechanical properties for the discs are as follows: Disc 1 Discs 2 and 3 Tensile Strength, psi 146,500 153,700 Yield Strength, psi 113,100 - 123,300 118,900 - 129,100 Elongation in 2 ft (disc hub) percent 15 15 Elongation in 2 ft (disc rim) percent 15 15 Reduction of area (disc hub) percent 50 50 Reduction of area (disc rim) percent 50 50 Impact strength (hub and rim) Charpy V- 96 96 Notch, ft-lb (at room temp) 50% Fracture Appearance Transition Temp. -112 -112 (disc hub and rim) °F (max) 10.2.3.2 Fracture Toughness - Historical Information Unit 1 Fracture mechanics analysis by Westinghouse (reference "Techniques for Fracture Mechanics Analysis of Nuclear Turbine Discs" by G. T. Campbell, dated September1974) indicates that a very large initial defect would have to be present in the low pressure turbine discs to cause bursting during normal operation after a nominal 2000 cycles of startup and shutdown. Preservice and inservice inspection procedures will assure that no such large defects are present in these discs. A description of the analytical method employed is given in the following paragraphs. First, the critical flaw size is determined using the equation for a semi-elliptical surface flaw with the major axis of the crack normal to the applied stress: KIC Q a CR = ( )2 ( ) t 1.21 10.2-8
WBN-3 where aCR = Critical flaw size KIC = Critical Stress Intensity factor t = Applied tangential stress (highest stresses present in a disc) Q = Flaw shape parameter By using conservative values for t, KIC, and Q (80KSI, 170KSI in 1/2 and 1.0 respectively) it was determined that aCR = 1.19-inch. Hence, the disc would have to have a crack 1.19-inch deep by 11.9-inches long present at the bore before bursting. Once aCR is known, it is possible to determine the initial flaw size (ai) which would grow to the critical size in a given number of stress cycles (i.e. number of startups and shutdowns of a turbine). This is done by solving the generalized cyclic life expression developed by W. K. Wilson (DCC Report AD 801005, June 24, 1966) for ai. Using the value of 1.19-inch developed above for aCR and a conservative value of 2000 cycles yields a value for ai of 0.93-inch. Since the tangential stresses are highest at the bore of the disc, this is the initial flaw size for a flaw at the bore. Therefore, values of ai at other locations in the disc would be smaller than this value. It must be noted for any given condition the evaluation of ai is conservative because it is assumed that the initial defect is crack like and will behave as a fatigue crack. This is a conservative assumption , in general, natural flaws are not expected to act as sharp cracks and a finite number of cycles will be required prior to the initiation of a fatigue crack which will obey the equation for crack growth. Keyways are employed on turbines to maintain the position of a disc on the rotor shaft. These keyways represent a localized stress concentration which affects the stress intensity factor associated with a given size defect. Several methods are available for analysis of such a situation. The most conservative method and easiest to use from a computational standpoint is the technique where the depth of the keyway is assumed to act as part of the defect and hence KIC = 1.9497 t (a+ R) / Q) where R is the radius of the keyway and t is the nominal bore stress. In the case of the modern tough materials employed by Westinghouse for nuclear turbine discs, this method suffices to evaluate discs which experience little crack growth from cyclic stresses. For a keyway radius of 0.375-inch (using the same conservative values for KIC, t, and Q used above), it was determined that aCR = 0.813-inch for the keyway. Hence, the defect on the keyway which would cause failure for the given conditions is 0.813-inch deep by 11.9-inches long. As with the smooth bore, a defect can be expected to undergo cyclic growth with the startup and shutdown of the turbine unit. Essentially the same procedure is used to evaluate ai on the keyway as is used on the smooth bore. The procedure is as follows: 10.2-9
WBN-3
- 1. Determine aCR
- 2. Determine ai for selected number of cycles
- 3. Subtract radius of keyway (R) from ai.
Again, for a conservative 2000 cycles, ai = 0.63-inch. As the shape factor assumed is 1 the defect on the keyway which would lead to failure under the conditions given is 0.63-inch deep by 10-inches long. Unit 2 Fracture mechanics analysis by the Siemens Methodology is described in the missile report (Section 3.5 [Ref. 13]). A brief description of the analytical method employed is given in the following paragraphs. First, the critical flaw size is determined using the equation for a semi-elliptical surface flaw with the major axis of the crack normal to the applied stress: Q K IC 2 aCR = ( ) 1.21 eff where aCR = Critical flaw size KIC = Fracture toughness eff = Effective tangential bore stress Q = Flaw shape parameter Stress corrosion cracking (SCC) rate is assumed to be independent of the stress intensity level. The main parameters influencing the SCC rate are temperature, material yield strength and water chemistry. Based on field measurements and laboratory test data, empirical equations for SCC rates were developed. For the probabilistic analysis, the following SCC rate is used: da 7302
= exp (4.968 + 0.0278 )
dt + 460 Where: (da/dt) = SCC rate given in inches/hour T = Temperature in °F y = Yield strenth in ksi 10.2-10
WBN-3 For probabilistic computations, Siemens has developed a numerical Monte-Carlo simulation code, PDBURST. As a failure condition, the brittle fracture mode is assumed: t acr (K Ic , y , ,,k) ai a (y , T)dt 0 Where: acr = Critical crack size, a = Current crack size, ai = Initial crack size, t = Operating time duration, N = Crack shape factor (crack depth to crack length ratio), Klc = Fracture toughness, k = Branching factor,
= Applied load due to tangential stress at bore, y = Yield strength, T = Temperature.
For probabilistic analysis the critical crack size is defined as that given by the equation shown or 100 mm whichever is smaller. The 100 mm limit is purely based on the applicability limitation of linear-elastic fracture mechanics concept and does not necessarily represent an imminent burst condition. In the Monte-Carlo simulation, disc property inputs include disc metal temperature, disc tangential bore stress, fracture toughness, disc yield strength, disc crack initiation probability based on historical data and standard deviation values. Typically, one million simulations are run to determine how many failures occur as a result of crack initiation and growth to critical crack size. 10.2.3.3 High Temperature Properties - Historical Information The stress-rupture properties of the high pressure rotor material are considered to be proprietary information of the turbine manufacturer, Westinghouse Electric Corporation for Unit 1, and Siemens for Unit 2. 10.2.3.4 Turbine Disc Design - Historical Information Unit 1 Information on the tangential and radial stresses in the low pressure discs and high pressure rotors is considered proprietary information of the turbine manufacturer, Westinghouse Electric Corporation. However, the actual maximum tangential stresses are less than those assumed previously in Section 10.2.3.2 Unit 2 Information on the tangential and radial stresses in the low pressure discs and low pressure rotors is considered proprietary information of the turbine manufacturer, Siemens. 10.2-11
WBN-3 10.2.3.5 Preservice Inspection - Historical Information 10.2.3.5.1 Low Pressure Turbine Rotor Unit 1 The low pressure turbine rotor and discs are heat treated nickel-chromium-molydenum-vanadium alloy steel procured to specifications that define the manufacturing method, heat treating process, and the test and inspection methods. Specific tests and test documentation, in addition to dimensional requirements, are specified for the forging manufacturer. The low pressure turbine rotor has the following inspections and tests conducted at the forging manufacturer's plant:
- 1. A ladle analysis of each heat of steel for chemical composition is to be within the limits defined by the specification.
- 2. Following preliminary machining and heat treatment for mechanical properties but prior to stress relief, all rotor diameters and faces are subjected to ultrasonic tests defined in detail by a Westinghouse specification which is similar to the requirements of ASTM A-418.
- 3. After all heat treatment has been completed, the rotor forging is subjected to a thermal stability test defined by a Westinghouse specification which is more restrictive than the requirements of ASTM A-472.
- 4. The end faces of the main body and the fillet areas joining the body to the shaft ends of the machined forging are subjected to a magnetic particle surface inspection as defined by ASTM A-275.
- 5. After the bore of the rotor is finish machined, the bore is given a visual examination followed by a wet magnetic particle inspection defined in detail by a Westinghouse specification which exceeds the requirements of ASTM A-275.
- 6. Utilizing specimens removed from the rotor forging at specified locations, tensile, Charpy V Notch impact and FATT properties are determined following the test methods defined by ASTM A-370.
In addition, after the rotor body is finished machined, the rotor surface is given a fluorescent magnetic particle examination as defined by a Westinghouse specification which is similar to ASTM E-138. The low pressure turbine rotor discs have the following inspections and tests conducted at the forging manufacturer's plant:
- 1. The ladle analysis of each heat of steel is to be within the composition limits defined by the specification.
- 2. After all heat treatment, rough machining and stress relief operations, the hub and rim areas of the completed disc forging are subjected to ultrasonic examinations. These ultrasonic tests are defined by a Westinghouse specification which exceeds the requirements of ASTM A-418.
10.2-12
WBN-3
- 3. The tensile, Charpy V Notch impact and FATT properties are determined from specimens removed from the discs at specific locations. The test methods used for determining these mechanical properties are defined by ASTM A-370.
In addition, after the discs are finish machined, the disc surfaces, except blade grooves, are given a fluorescent magnetic particle examination as defined by a Westinghouse specification which is similar to ASTM E-138. After the preheated discs are assembled to the rotor body to obtain the specified interference fit, holes are drilled and reamed for axial locking pins at the rotor and disc interface. These holes are given a fluorescent penetrate inspection defined by a Westinghouse specification which is similar to ASTM E-165. Prior to shipping, each fully bladed rotor is balanced and tested to 120% of rated speed in a shop heater box. Unit 2 The low pressure turbine rotor and discs are heat treated nickelchromium-molydenum-vanadium alloy steel procured to specifications that define the manufacturing method, heat treating process, and the test and inspection methods. Specific tests and test documentation, in addition to dimensional requirements, are specified for the forging manufacturer. The low pressure turbine rotor has the following inspections and tests conducted at the forging manufacturer's plant:
- 1. A ladle analysis of each heat of steel for chemical composition is to be within the limits defined by the specification.
- 2. Following preliminary machining and heat treatment for mechanical properties but prior to stress relief, all rotor diameters and faces are subjected to ultrasonic tests defined in detail by a Siemens specification which is similar to the requirements of ASTM A-418.
- 3. After all heat treatment has been completed, the rotor forging is subjected to a thermal stability test defined by a Siemens specification which is more restrictive than the requirements of ASTM A-472.
- 4. The end faces of the main body and the fillet areas joining the body to the shaft ends of the machined forging are subjected to a magnetic particle surface inspection as defined by ASTM A-275.
- 5. Utilizing specimens removed from the rotor forging at specified locations, tensile, Charpy V Notch impact and FATT properties are determined following the test methods defined by ASTM A-370.
The low pressure turbine rotor discs have the following inspections and tests conducted at the forging manufacturer's plant:
- 1. The ladle analysis of each heat of steel is to be within the composition limits defined by the specification.
- 2. After all heat treatment, rough machining and stress relief operations, the hub and rim areas of the completed disc forging are subjected to ultrasonic examinations. These ultrasonic tests are defined by a Siemens specification which exceeds the requirements of ASTM A-418.
10.2-13
WBN-3
- 3. The tensile, Charpy V Notch impact and FATT properties are determined from specimens removed from the discs at specific locations. The test methods used for determining these mechanical properties are defined by ASTM A-370.
- 4. If ultrasonic examination shows indications in the near surface area of the disc bore, a magnetic particle inspection is required.
- 5. During heat treatment of the disc, special requirements are applied to ensure that compressive residual stresses shall be induced in the bore by intensive cooling.
After the preheated discs are assembled to the rotor body to obtain the specified interference fit, Disc 1 holes are drilled and reamed for axial locking pins at the rotor and disc interface. Discs 2 and 3 rely upon shrink fit only. Prior to shipping, each fully bladed rotor is balanced and tested to 120% of rated speed in a shop heater box. 10.2.3.5.2 High Pressure Turbine Rotor The high pressure turbine rotor for low temperature light water reactor applications has the same basic material composition as the low pressure rotors. This nickel-chromium-molybdenum-vanadium alloy steel forging is procured, processed, and subjected to test and inspection requirements the same as the low pressure rotor, which include:
- 1. Ladle analysis
- 2. Ultrasonic tests
- 3. Magnetic particle inspection
- 4. Thermal stability test
- 5. Bore Inspection
- 6. Tensile and impact mechanical properties
- 7. Fluorescent magnetic particle inspection
- 8. Heater box and 120% speed test 10.2.3.5.3 Preoperational and Initial Startup Testing These tests are documented in Chapter 14.0 10.2-14
WBN-1 10.2.3.6 Inservice Inspection 10.2.3.6.1 Turbine Rotors To help guard against possible failure of low pressure nuclear steam turbine discs, Siemens has developed an ultrasonic inservice inspection method for these discs. The program includes methods and hardware for field inspection of LP turbine discs for incipient cracking located at the bore surface and particularly at the keyways. Nondestructive examination (NDE) of low pressure (LP) turbine rotor discs is performed to confirm that, if cracks exist, they do not pose an unacceptable risk for continued operation. Assessment of the NDE data is performed to determine the next required inspection interval. This assessment may be based on approved deterministic or probabilistic methods. Unit 1 For LPA and LPB, the inspection intervals recommended by Siemens and based on NRC criterion vary with the construction and makeup of each rotor (and discs). The recommended Westinghouse inspection interval is approximately every five years based on actual operating time or the Westinghouse inspection interval based on the NRC criterion, whichever provides the lesser inspection interval. For LPC, the inspection intervals recommended by Siemens and based on NRC criterion are 100,000 operating hours. In addition, if there is evidence of significant corrosion found during any of the low pressure turbine rotor inspections, Siemens will be consulted and the inspection intervals adjusted accordingly. If measurable cracks are detected, the inspection intervals will be adjusted after considering Siemens recommendations. The disc inspection will be performed by personnel that are expert and highly skilled in their field. For LPC, the inspection intervals recommended by Siemens and based on NRC criterion are 100,000 operating hours. Note: Low Pressure Turbine A rotor disc inspection is deferred from U1R14 to U1R15 refueling outage. This is a one time deferral and does not alter disc inspection frequencies in future outages on the low pressure turbine rotors. Unit 2 The inspection intervals recommended by Siemens and based on NRC criterion are 100,000 operating hours. In addition, if there is evidence of significant corrosion found during any of the low pressure turbine rotor inspections, Siemens will be consulted and the inspection intervals adjusted accordingly. If measurable cracks are detected, the inspection intervals will be adjusted after considering Siemens recommendations. The disc inspection will be performed by personnel that are expert and highly skilled in their field. 10.2.3.6.2 Turbine Overspeed Protection Unit 1 In order to assure that the Turbine Overspeed Protection System (TOPS) continues to carry out its design function in a highly reliable manner, a rigorous program of inspecting, testing, maintaining, and calibrating the various parts of the TOPS has been developed. The development of this program has considered the recommendations of Siemens. Various aspects of the TOPS inspection program such as scope and frequency of test, inspections, and other pertinent items are described in the following paragraphs. 10.2-15
WBN-3 The TOPS include the following major component groups:
- a. Turbine valves which control or prevent steam admission into either the high pressure or low pressure turbines.
- b. The control valve emergency trip, stop valve emergency trip, and emergency oil trip systems which include the DEH electrical overspeed trip and the independent overspeed protection system (See Section 10.2.2 for additional details).
The throttle valves, governor valves, reheat stop valves and reheat intercept valves will be tested and visually checked after each turbine startup and at intervals of approximately 6 months to verify complete freedom of valve stem travel. The interval of valve testing may be changed based on plant conditions or overall TVA power system conditions. For example, if equipment necessary to shut the unit down is inoperable, the valve testing would be postponed to avoid the potential for tripping the unit. Also, if the demand for power on the TVA system is large enough that the loss of a unit would create a shortage of power to the system, the testing would wait until more favorable conditions exist. The interval for testing turbine valves shall not exceed 1.25 times the required test interval without prior approval of the plant manager, and no more than two consecutive tests shall be deferred without the prior review and approval by the Plant Operations Review Committee (PORC). Extraction and moisture separator reheater (MSR) drain non-return valves will be tested monthly. Additionally, one or more of each valve type will be disassembled and inspected during outages with all throttle and governor valves being disassembled and inspected initially at least once every four refueling cycles with the interval being reevaluated later if there are no significant valve problems or defects. Reheat stop and reheat intercept valves will be disassembled and inspected at least once every six refueling cycles. MSR drain non-return valves will be disassembled and inspected at least once every 60 operating months (once every three refueling cycles). Extraction non-return valves will be disassembled and inspected at least once every 90 operating months (once every five refueling cycles). If during the inspection of one type of valve a problem or defect is noted, all similar valves will be disassembled and inspected. These inspections will consist of detailed dimensional and related checks to assure that critical clearances and fits are maintained with the manufacturer's recommendations. Additionally, during the unit startup immediately following a refueling outage and prior to synchronizing the unit, if the turbine remote and overspeed trips have not been tested prior to the refueling outage, the DEH electrical overspeed trip and the Independent overspeed protection system (IOPS) will each be actuated to verify proper turbine and valve action. The overspeed trip tests will trip the turbine and close all throttle, governor, reheat intercept and reheat stop valves. These tests are also repeated following maintenance on the turbine front standard that affects the TOPS. The DEH system monitors speed with the use of 3 speed probes. A median of these 3 speed signals determines if the overspeed trip setpoint has exceeded. Three redundant channels monitor turbine speed and use a two out of three voting logic to initiate a turbine trip. The DEH system performs self-monitoring to detect a deviation or failure of a channel or component and provides an alarm upon detection. The IOPS is initially tested at the calibrated setting of 104% of rated speed. Subsequent periodic functional testing may be performed at a temporary lower speed setting in accordance with the plant administrative procedures. The IOPS, in the test mode, will allow the overspeed setting to be lowered for a specified duration, once this time has been reached the setpoint value is automatically returned to the calibrated setting. 10.2-16
WBN-3 Unit 2 In order to assure that the Turbine Overspeed Protection System (TOPS) continues to carry out its design function in a highly reliable manner, a rigorous program of inspecting, testing, maintaining, and calibrating the various parts of the TOPS has been developed. The development of this program has considered the recommendations of Siemens. Various aspects of the TOPS inspection program such as scope and frequency of test, inspections, and other pertinent items are described in the following paragraphs. The TOPS include the following major component groups:
- a. Turbine valves which control or prevent steam admission into either the high pressure or low pressure turbines.
- b. The control valve emergency trip, stop valve emergency trip, and emergency oil trip systems which include the DEH electrical overspeed trip and the independent over speed protection system (See Section 10.2.2 for additional details).
The throttle valves, governor valves, reheat stop valves and reheat intercept valves will be tested and visually checked after each turbine startup and at intervals of approximately 6 months to verify complete freedom of valve stem travel. The interval of valve testing may be changed based on plant conditions or overall TVA power system conditions. For example, if equipment necessary to shut the unit down is inoperable, the valve testing would be postponed to avoid the potential for tripping the unit. Also, if the demand for power on the TVA system is large enough that the loss of a unit would create a shortage of power to the system, the testing would wait until more favorable conditions exist. The interval for testing turbine valves shall not exceed 1.25 times the required test interval without prior approval of the plant manager, and no more than two consecutive tests shall be deferred without the prior review and approval by the Plant Operations Review Committee (PORC). Extraction and moisture separator reheater (MSR) drain non-return valves will be tested monthly. Additionally, one or more of each valve type will be disassembled and inspected during outages with all throttle and governor valves being disassembled and inspected initially at least once every four refueling cycles with the interval being reevaluated later if there are no significant valve problems or defects. Reheat stop and reheat intercept valves will be disassembled and inspected at least once every six refueling cycles. MSR drain non-return valves will be disassembled and inspected at least once every 60 operating months (once every three refueling cycles). If during the inspection of one type of valve a problem or defect is noted, all similar valves will be disassembled and inspected. These inspections will consist of detailed dimensional and related checks to assure that critical clearances and fits are maintained with the manufacturer's recommendations. Additionally, during unit startup immediately following a refueling outage and prior to synchronizing the unit, if the turbine remote and overspeed trips have not been tested prior to the refueling outage, the DEH electrical overspeed trip and the independent overspeed protection system (IOPS) will each be actuated to verify proper turbine and valve action. The overspeed trip tests will trip the turbine and close all throttle, governor, reheat intercept and reheat stop valves. These tests are also repeated following maintenance on the turbine standard that affects TOPS. The DEH system monitors speed with the use of 3 speed probes. A median of these 3 speed signals determines if the overspeed trip setpoint has been exceeded. Three redundant system performs self-monitoring to detect a deviation or failure of a channel or component and provides an alarm upon detection. The IOPS is initially tested at the calibrated setting of 104% of rated speed. Subsequent periodic functional testing may be performed at a temporary lower speed setting in accordance with the plant administrative procedures. The IOPS, in the test mode, will allow the overspeed 10.2-17
WBN-3 setting to be lowered for a specified duration, once this time has been reached the setpoint valve is automatically returned to the calibrated setting. 10.2.3.6.3 Other Turbine Protection Features There are other turbine protection features which serve to trip the turbine during abnormal operation (see Section 10.2.4 for a list of mechanical and electrical turbine trips). Inspections, tests, maintenance, and calibrations of these components will be based on Westinghouse for Unit 1 and Siemens for Unit 2 recommendations. 10.2.4 Evaluation The following operational occurrences can be caused by operation of turbine, generator, or distribution system protection equipment:
- 1. Turbine trip due to turbine abnormalities.
- 2. Turbine trip due to generator abnormalities.
- 3. Transients due to rapid load changes or system abnormalities.
Turbogenerator protective trips that will automatically trip the turbine due to turbine (mechanical) and generator (electrical) abnormalities are tabulated below. Reactor trip and AMSAC signals will also automatically trip the turbine. I. Automatic Turbine Trips Due To Turbine (Mechanical) Abnormalities
- 1. Low Bearing Oil Pressure Trip
- 2. Low Vacuum Trip
- 3. High Thrust Bearing Wear Trip
- 4. Low Differential Water Pressure Across Generator Stator Coils Trip (Alarm only below 15% power)
- 5. High Stator Coil Outlet Water Temperature Trip (Alarm only below 15% power)
- 6. 103% Rated Speed Electrical Overspeed Trip
- 7. 104% Rated Speed Independent Overspeed Protection System Trip
- 8. EHC dc Power Failure Trip
- 9. Loss of Both Main Feedwater Turbines Trip
- 10. Steam Generator High-High Level Trip
- 11. Failure to Detect Speed Trip
- 12. Power-Up Trip II. Automatic Turbine Trips Due To Generator (Electrical) Abnormalities
- 1. Generator Differential Current Trip
- 2. Generator System Ground Fault Trip
- 3. Generator Time Overcurrent (Voltage Supervised) Trip
- 4. Generator Negative Sequence Trip
- 5. Generator Backup and Main Transformer Feeder Differential Trip
- 6. Generator Loss of Field Trip
- 7. Generator Over-volts per hertz trip
- 8. Generator Reverse Power Trip
- 9. Unit Station Service Transformer A Overcurrent Trip
- 10. Unit Station Service Transformer B Overcurrent Trip 10.2-18
WBN-3
- 11. Main Transformer Sudden Pressure Trip
- 12. Main and Unit Station Service Transformers Differential Trip
- 13. Unit 1 500 kV Breaker Failure Trip
- 14. Unit 1, 500 kV Bus 2 Differential Trip (trips both units if Bus 1 is de-energized)
- 15. Unit 2 500 kV Breaker Failure Trip
- 16. Unit 2, 500 kV Bus 1 Differential Trip (trips both units if Bus 2 is de-energized)
- 17. 1 and/or 2 Generator Breaker Open The analyses of the consequences of the most severe of these events with respect to reactor safety are discussed in Chapter 15.
There can be any number of component or system operational abnormalities that can be postulated to produce a turbogenerator load transient. However, since the effects of such abnormalities can be no worse than a turbine or generator trip, these occurrences are not formally listed. Any noble gas activity in the secondary system as well as the particulate activity present due to moisture carryover from the steam generators enters the high pressure turbine. The subsequent activity entering the low pressure turbine is reduced due to the moisture separation that occurs between the exit of the high pressure turbine and the entrance to the low pressure turbines. Radiation monitors are installed to monitor steam generator blowdown and condenser vacuum pump exhaust flows for particulate and airborne radioactivity. Details of the radiological evaluation of the condenser evacuation system are contained in Chapter 11. Activity levels in the turbine are expected to be very low and all necessary shielding is provided by the piping, turbine casing, and other components. If any additional shielding is required in local areas, it will be provided so that unlimited access to the turbine area is possible. Shielding design is discussed further in Section 12.3.2. The main steam stop (throttle) and control (governor) and reheat stop and interceptor valves are capable of fast closure upon receipt of a closure signal. Each of the four throttle valves is arranged with a paired governor valve and each of the six reheat stop valves is arranged in series with an interceptor valve. If the turbine should overspeed at approximately 103% of rated speed, protection is provided by a turbine trip initiated from the MicroNet Turbine Control System by depressurizing the Emergency Trip (ET) header by opening four solenoid valves (1-FSV-47-27A,B,C,D) in a Westinghouse Trip Block Assembly. Depressurizing the emergency trip header will result in the closing the Turbine Throttle, Governor, Reheat Stop and Interceptor Valves. The speed is determined with the use of 3 passive speed probes. A median of these 3 speed signals determines if the trip setpoint has exceeded. The trip setpoint is selected such that the probability of an overspeed event challenging the maximum speed of 120% is unlikely. The 4 trip solenoid valves are de-energize to trip and are connected in a 1-out-of-2 twice fashion to drain the ET Header. This configuration ensures the trip block trip solenoid valves are redundant such that a single failure will not initiate a trip nor will it prevent a trip. The solenoids are connected to separate circuits for tripping of the turbine. Any single failure of the trip logic will neither cause the turbine to trip nor result in a failure of the turbine to trip when demanded. If a single trip solenoid were to become de-energized, this condition can be detected and alarmed by monitoring the Trip Block test pressure transmitters. Redundancy for turbine overspeed protection is provided by the turbine independent overspeed protection system (IOPS). The Independent overspeed protection is a fault tolerant system using a Woodward ProTech GII. The ProTech has three channels (A, B, and C). Speed 10.2-19
WBN-3 information is provided to each channel through connection to a dedicated passive speed probe (one speed probe for each channel). The three channels are connected via a backplane and motherboard which provides two out of three voting on the speed. If overspeed is detected at approximately 104% of rated speed, the IOPS will de-energize trip relays whose contacts are hardwired into the trip string to the trip block assembly solenoid valves that dumps the EHC fluid in the ET Header initiating closure of the steam valves and tripping the turbine. The ProTech trip relays are separate from the MicroNet trip relays and de-energize the four trip block solenoid valves independently of the MicroNet system. With the ProTech trip setpoint of 104% rated speed, the probability of an overspeed event challenging the maximum speed of 120% unlikely. A turbine trip signal also generates an electrical trip signal which deenergizes the solenoid dump valves on the power assist non-return valves in the Number 1, 2, 3, and 4 extraction lines and the MSR drain lines. When the above solenoid dump valves as deenergized, a quick exhauster vent the air from the power assist non-return valve cylinder allowing a spring loaded piston to provide positive force to close the non-return valves. Concurrently, the above turbine trip signal also activates a fluid operated air pilot valve, XDV-47-27 (See Figure 10.2-3). If the above solenoid dump valves fail to deenergize, this valve (XDV-47-27) will vent the air from the non-return valve cylinders causing the non-return valves to close. In either of the above cases, the non-return valves will close prior to flow reversal occurring these extraction and MSR drain lines. Consequently, the above heaters and MSR drains cannot flashback and cause or significantly contribute to a turbine overspeed situation. Since heaters 5, 6, and 7 are located in the condenser neck, physical piping arrangements and economic considerations prohibit the use of non- return valves in the extraction lines. However, anti-flash baffles in the heater shells (sized in accordance with the turbine manufacturer's recommendations) restrict the reverse flow from these heaters to a sufficiently low flow so that it cannot adversely affect turbine overspeed or thermally shock the LP turbine. REFERENCES None 10.2-20
,,,..,_ lf-l-.,.,.=1 =-F~+'-f~-,i\l~5 =-R=7=1 /=R=S=-------t----------, i-1;,11-i--rRAlN A ISOLATION BOX IN R-71
----0 l'.)
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( 1-45W600-47-37) 11 L-792 TB.3-241
~I -f-----~ TURB VIB CLOSES ON
+I ALARM RELAY
- 1 RL Y-47-ALM (45N1635-82)
TURB/GEN HI-HI VIB SIGNAL L-792 TBJ-242 14 R HS-47-24 G HS-47-24 RESET TRIP I I 0 N
'-------+-------:__j (R-71) S 27 L1 TTA CLOGR TDPU 10 SEC (R-71)
GE12HEAS18 216 RELAY L2 ON JB 673 SHOWN IN RESET POSITION TTN ALL CONTACTS FORM 'C' ( HAND RESET) SEE NOTE 7 TRAIN A (NOTE 3} 250V DC TURBINE TRIP BUS "A" IN R-70 NOTES: r-------7 1. FOR GENERAL NOTES AND REFERENCES, SEE 1-45W600-47-1 I 1M112 1
- 2. FOR LIMIT SWITCH CONTACT DIAGRAMS, SEE 1-45W600-47-3 TRAIN B I }
- 3. SAFETY RELATED CIRCUITS EXTENDING INTO NON-SEISMIC AREA WILL BE ISOLATI~~F~~: ~~R;~~~;--1 1N~2A TURB TRIP BUS B ANNUNCIATION CKT 7 PROTECTED BY BEST AVAILABLE MEANS. PHYSICAL AND ELECTRICAL SEPARATION SIMILAR TO THAT IN SEISMICALLY QUALIFIED AREAS.
I TTPP
- 4. NOT USED.
- 5. NOT USED.
- 6. ALL COMPONENT UNIT PREFIXES ARE UNIT "1" UNLESS OTHERWISE NOTED.
- 7. THE DENOTED FUSES ARE 5 AMPERE BUSSMANN TYPE MIS-5D.C, MK #PNQ-31, FOR UNIT 1 .
- 8. NOT USED
- 9. THIS EQUIPMENT INTERFACES WITH THE REACTOR SOLID STATE PROTECTION RC {R-178)
AMSAC OUTPUT SYSTEM AND IS SUBJECT TO AUGMENTED QA REQUIREMENTS PER NJ-47-4002.
- 10. NOT USED CLOSES TO TRIP TURBINE 11 NOT USED.
( 1-45\YSOO-J-15)
- 12. FOR INPUTS TO THE PLANT COMPUTER, THE COMPUTER POINT IS EQUIVALENT TO THE WIRE NUMBER WITHOUT THE "+" OR '-" SIGN.
SYMBOLS: DEVICE LOCATED IN UNIT CONTROL ROOM al [ --- DEVICE LOCATED IN CENTRALIZED LOCAL CONTROL STATION r m ~--- ~~~~~N~~R~?~A~H~§~ DEVICE IS CONNECTED. LETTER SPECIFIES "O< 0
--- DEVICE LOCATED IN AUX INSTR ROOM MISC RELAY PANEL
>J a: --- DEVICE LOCATED ON A LOCAL INSTRUMENT PANEL
~~ TTBB --- DEVICE LOCATED IN NSSS LOGIC RELAY RACK IN AUX INSTR ROOM 5' ---
~I DEVICE LOCATED ON RELAY BOARD IN RELAY ROOM l
b.. --- DEVICE LOCATED IN AMSAC PANEL IN AUXILIARY INSTRUMENT ROOM
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DIGITAL OUTPUT 27A1 I27A2I27A3I27A4 (PROTECTION SYSTEM TRIP A I l I I TT33 ALARM) FROM PNL~1'-----"R_:-5:.:6'------'c-.------'-1M,c1c,3"--3 I I M2 M2 t.12 M2 I CFTMl 05A I I I I 1-L-792 THRUST TBJ-50 K7 ANN "THRUST I I I I T2 T2 T2 T2TT51 EH 01/27 BFTM1048 UFSAR AMENDMENT 3 1 I PRE-TRIP BRG WEAR D0/7 PRE-TRIP ALARM" 2781 I27B2I27B3I2784 (PROTECTION I (45N1635-82) TB3-51 SYSTEM TRIP 8 I ANN WOW I 2A-23D .__.__.,__._T~TS=O ALARM) I ( 1-45B655-2A) M2 M2 t.12 M2 I WATTS BAR l I 1NM2A
//
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I DIGIT AL OUTPUT FINAL SAFETY A 0-,/*-')C,-H I FROM PNL 1-R-56 ANALYSIS REPORT l TTRNN TTNN
----0
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TBJ-59 1M168 20A TRAIN 8 (NOTE 3) ( 1-L-792) BENTLY NEVADA PNL Y21020* CABINET RT 1-L-792 CABINET POWERHOUSE 1-L-792 T83-2 ~ 250V DC TURBINE TRIP BUS "B" TEMPERATURE HIGH ( 45N1 635-82) I TBJ-60 ___ 1NM28 TEMPERATURE HI-HI 2A-23F (1-458655-2A) UN IT 1 l TURB/GEN HI 1 WIRING DIAGRAM l
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VIBRATION
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( 45N1 635-82) FUSE ALARM CONT ACTS FUSE ALARM CONTACTS Y2102D-TBJ-J 1 NM2A 27 1 1 1 112 (1-L-792) {1-L-792) {1-L-792) {1-L-792) {1-L-792) TB2-1 lt.1161 BENTLY NEVADA TURBO-GENERATOR AUXILIARIES R6 Ml l l ANN "TURBINE TFRAIIPLUBRUE~ A 27 TTB l t.1 ANN "TU RBI NE TRIP BUS 8 CABINET DC POWER RACK 1 OK RACK 2 OK RACK 3 OK TEMPERATURE HI PNL 1-L-792 MALFUNCTION SCHEMATIC DIAGRAMS (R-71) VTR T z-w> m
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R4 RS 1NM2A ANN. WOW. 2A-27A ( 1-45B655-2A) 2 Rl R2 RJ
~-.__.__.__.__.__.____
R4 RS RS 1NM2A ~~~:u:5;. 2A-28A ( 1-45B655-2A) SUPPLIES OK (45N1635-82) {45N1635-82) ( 45N 1635-B2) {45N1635-B2) {45N1635-82)
- - - - - - - - - + - - - - - + - - - - - - - - - - - - - - + - - - - + T _ B _ 2 - _ 2_ _ _1_N_M2_B_
2A-22F ( 1-458655-2A) TVA DWG NO. 1-45W600-47-2 R41 4 ~ 1 NM4C
~~ FIGURE 10.2-1
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( HAND RESET) TTN
----0 SEE NOTE 7 TRAIN A 0-FU-290-1264/FJ 250V DC TURBINE TRIP BUS "A" NOTES:
- 1. FOR GENERAL NOTES AND REFERENCES, SEE 2-45W60D-47-1 2-FU-275-R70/RS 2. NOT USED.
TTRPP 3. NOT USED.
- 4. NOT USED
- 5. NOT USED TTP
- 6. NOT USED.
- 7. THE DENOTED FUSES ARE 5 AMPERE BUSSMANN TYPE MIS-5D.C, MK #PNQ-31, FOR UNIT 2.
- 8. NOT USED
- 9. NOT USED.
I;
- 10. NOT USED.
< RC (2-R-178)
AMSAC OUTPUT 11. NOT USED.
'- CLOSES TO TRIP TURBINE 12. FOR INPUTS TO THE PLANT COMPUTER, THE COMPUTER POINT IS EQUIVALENT
.,. (2-45W600-J-15) TO THE WIRE NUMBER WITHOUT THE "+" OR '-" SIGN.
r
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~
ND (2-R-71 l SYMBOLS: DEVICE LOCATED IN UN IT CONTROL ROOM _27_ _ [ --- DEVICE LOCATED IN CENTRALIZED LOCAL CONTROL STATION 1f r*r1 ~ TTA 2 4 0--- iR~~AN~~R~?~ArH~§~ DEVICE IS CONNECTED. LETTER SPECIFIES
--- DEVICE LOCATED IN AUX INSTR ROOM MISC RELAY PANEL r ex--- DEVICE LOCATED ON A LOCAL INSTRUMENT PANEL I r u --- DEVICE LOCATED IN NSSS LOGIC RELAY RACK IN AUX INSTR ROOM
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~
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DEVICE LOCATED ON RELAY BOARD IN RELAY ROOM l::,,. --- DEVICE LOCATED IN AMSAC PANEL IN AUXILIARY INSTRUMENT ROOM
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I i i UFSAR AMENDMENT 3 I i I i 27 I i I i TTB 0 WATTS BAR Ii i FINAL SAFETY TTN Ii 1 i Ii Ii
'ill"!'° ANALYSIS REPORT l
Ii 250V DC TURBINE TRIP BUS "A"
----o,,.-l---._o-----.j'-----xr--j-0-¢=========;!:======='~0~'--'--"-"----__.__----..l..-----i..__---__JL-_ _ _ _ _ ___J POWERHOUSE TB2-8~
1?:-:~:7_9_?_ 1?:-:~:7_9_?_ z LL.I _J TRAIN B DIGITAL OUTPUT FROM PNL~2-_R-_S_6-',.---~2~M.c,1'"'-J UN IT 2 2-L-792 TURB VIB TURB VIB ~~ 250V DC TURBINE TRIP BUS "B" WIRING DIAGRAM l ADC-47-792/104 ADC-47-792/205 ID> TRAIN A ISLN BOX TRAIN B ISLN BOX l ( 2-45N2635-133) ( 2-45N2635-133) ~- TB2-9 T82-57 2NM2A 1-::c FUSE ALARM CONTACTS 2M111 FUSE ALARM CONT ACTS 2M112 2-ZE-47-1678 TURBO-GENERATOR AUXILIARIES 7
~
2M393 ANN "TURBINE TRIP BUS A ANN "TURBINE TRIP BUS 8 ADC-47-792/2D7 PNL 2-L-792 K7 DD/7 ANN "THRUST BRG WEAR PRE-TRIP ALARM' SCHEMATIC DIAGRAMS (2-R-71) VTR {45N2686-1) ~ T R1 R2 RJ R4 RS R5 2NM2A FAILURE" ANN. WOW. 2A-27A Rl R2 R3 R4 RS R5 2NM2A FAILURE" ANN. WOW. 2A-28A ANN WOW ZA-ZJD (2-458655-ZA) TVA DWG NO. 2-45W600-47-2 R21 a 2NM4C (2-45B655-2A) (2-45B655-2A) 2NM2A FIGURE 10.2-1 (U2)
Cl TABLE A1 TABLE B1 z DIGITAL COMPUTER POINTS ANALOG COMPUTER POINTS 3' POINT ID DESCRIPTION POINT ID DESCRIPTION <( Y0335D UNIT ON LINE Q2801 A UNIT STA SERV TRANSFORMER 28 MW Q:'. Y2003D TURB TRIP-OVERSPEED CAUS Q2800A UNIT STA SERV TRANSFORMER 2A MW 0 Y2004D TURB TRIP-STATOR COOLANT Q0340A UNIT GENERATOR GROSS MW 0 Y2007D TURB TRIP-MFPT A &. B TRIPPED Y2801A GEN STATOR CURRENT (B PHASE) w z Y2009D TURB HYO FLUID LEVEL Y2800A MAIN TRANSFORMER AMP (B PHASE) Q2823A GENERATOR MVAR <( f- Y2407D SSPS TURBINE TRIP TRAIN A z Y2417D SSPS TURBINE TRIP TRAIN 8 Y2801D GEN DIFF BEARING LIFT OIL Y2802D BUS BKR FAILURE PUMP MOTOR Y2803D GEN NEG PHASE SEQ 0 <( TURNING Y2804D GEN BACKUP a: MN XFMR FDR DIFF JOG REMOTE/LOCAL GEAR u
,-----1-----1----7 I I I I I
I 1, I I 10 I I
@o I I
@: I I
Y2805D Y2806D Y2807D Y28080 Y2809D GEN PRIMARY AND/OR SECONDARY RLY FAIL GEN OVERCURRENT GEN REVERSE POWER MAIN XFMR DIFF-SUD PRESS USS XFMR DIFF-PRESS-OC-NEUT OC I I L---------+--------+----------------~ I NOTES, L----7 I 2-45W600-47-16 I I I 1. XX-47-1000 IS EH OPERATOR'S PANEL (LOWER SECTION) I I
- 2. XX-47-2000 IS EH OPERATOR'S PANEL (UPPER SECTION)
- - ~ MA-PL T-1 OO~----------------------------r---------------+-------.------ 1 -------------
7
<2-45W600-47-18, TYP~---7
~ A
---7 ----7
@,,@,,@c
---7 ----7
~ ©/; -~ ~
2 iI I I I PSV l------J2-47W600-47-37 l~.- - - - - - - - ~
)
- 3. EHC CONTROL LOGIC IS LOCATED IN RACK R56. EHC CONTROL PANELS XX-47-1000 AND XX-47-2000 INTERFACE WITH RACK R56.
SPAREY51F
'y;1J ~1A I MTR-047-0110 I L--------1 I
- 4. ALL COMPONENT UNIT PREFIXES ARE UNIT "2' UNLESS OTHERWISE NOTED.
I L ___ _ I L __ _ I L___ I L___ I L __ _ I i : l-"'c:i::-,.,,_~7 5. THE 3 ACCUMULATORS ON SHEET 2 ARE ACUM-47-901,902 AND 903.
~
L-----~ THE ASSOCIATED 1 ACCUMULATOR IS ACUM-47-904. I 6, NOT APPLICABLE, I I I I 7. FOR A LIST OF POINT ID'S ASSOCIATED WITH THE VOLTAGE REGULATOR, SEE DWG I 2-47W610-47-4 I I 8. NOT APPL I CABLE. I I
- 9. 2-SPV-047-623 WITHDRAWS/INSERTS THE PLUG, 2-SPV-047-620
~
I I ROTATES TO SELECT EITHER, OR BOTH COOLERS. I I I
--------1 I
I I I I I REFERENCE DRAWINGS, I TURNING GEAR DISENGAGED I TVA 2-47W610-1 SERIES - MAIN STEAM CONTROL DIAGRAMS PS I I 2-47W610-2 SERIES - CONDENSATE CONTROL DIAGRAMS rt--~----147 * - - - - - - - - - - - - - - - - - - - - - - - - ....- - - - - - - - - - - - - - - - - - - - - - - - 7 47W601-7 SERIES - TURBINE TRAPS a: DRAINS 2-47W610-24 SERIES - RAW COOLING WATER 2-47W610-35 SERIES - GENERATOR HYDROGEN SYSTEM 2-47W610-46 SERIES - FEEDWATER CONTROL SYSTEM 2-47W610-47 SERIES - TURBOGENERATOR CONTROL SYSTEM WEC 723J597 ------------ STEAM TURBINE E.H. TBG 4601001 ------------ PIPING - STEAM DRAIN & GLAND DIAGRAM
------------------------, 726J672 ------------
4605D32 ------------ WIRING PEDESTAL GOVERNOR WIRING TERMINAL BOX D AND E LOG ~ : 4605D36 ------------ E.H. RESERVOIR WIRING MA-PLT -1 000 ---------BLANK I NG PLATE KIT, MYSTERY BOX Y2108D l.!1.=+/---J : b. SIEMENS L583002 SERIES - DIGITAL E.H., CONTRACT 8344 I I L------
! 0-2
_J PS 47-113
~~4 ~
u I I yo'I MTR ISIV-047-0113 I OR-047-0614 I : PMP-D47
' L RTV-047-0112A LEGEND
- EMERGENCY TRIP FLUID FOR MAIN STEAM AND REHEAT VALVES f-~--'---- g1tRrn~ ~o~i S - ON SHEET 2 - EH FLUID SUPPLY BEARINGS R2 - ON SHEET 2 - EH FLUID RETURN l---7 Rl SSPS
- ON SHEET 1 - LUBE OIL RETURN
- SOLID STATE PROTECTION SYSTEM
- ~
! ~
OR-047-0611
@it'I ir;;{s
- ~3-CKV-047-0061 HIGH PRESSURE SEAL : +-------
2-47W610-35-3, COOR G-4-~-~ ' I OIL BACKUP Rl _..,.III _____ __III STN-047-0603N I I I I I UFSAR AMENDMENT 3 I MOTOR _________ ....._ ___ _ WATTS BAR FINAL SAFETY TURNING GEAR OIL ~D EMERGENCY OIL 2-47W610-20-1, COOR C-10 ANALYSIS REPORT L..11,=l--J r-- 1 LOG Y2105D I L _ _ _ _ .. 00 1"-,':'1 : 2A-25D I I
~
*---------< 2-47W610-35-3, COOR C-9 > POWERHOUSE L--~
i::I8J
,ck, MTR-047-0099 : jQ ~ UN IT 2 I
I lmmru :~ ELECTRICAL t--- 1
---------~6 COMP AN ION DRAWi NGS, CONTROL DIAGRAM 2-47W610-47-SERIES I
I 2-47W610-47-1, COOR F-8 TURBO GENERATOR CONT SYS LOG Y2005D CKV-047-0099 TVA DWG NO. 2-47W610-47-1 R12 LUBE OIL RESERVOIR FIGURE 10.2-2 SH A
TABLE A1 (SEE NOTE 7) TABLE B1 ( SEE NOTE 7) DIGITAL COMPUTER POINTS ANALOG COMPUTER POINTS POINT ID DESCRIPTION POINT ID DESCRIPTION Y0335D UNIT ON LINE 02801A UN1T STA SERV TRANSFORMER 18 MW Y2003D TURB TRIP-OVERSPEED CAUS 02800A UNlT STA SERV TRANSFORMER 1A MW Y2004D TURB TRIP-STATOR COOLANT 00340A UNlT GENERATOR GROSS MW Y2007D TURB TRIP-MFPT A ll. 8 TRIPPED Y2801A GEN STATOR CURRENT {8 PHASE) Y2009D TURB HYO FLUID LEVEL Y2800A MAlN TRANSFORMER AMP (8 PHASE) 02823A GENERATOR MVAR Y2407D SSPS TURBINE TRIP TRAIN A Y2417D SSPS TURBINE TRIP TRAIN 8 Y2801D GEN DIFF NOTES: BEARING Y2802D BUS BKR FAILURE 1. XX-47-1000 IS EH OPERATOR'S PANEL (LOWER SECTION) LIFT OIL Y2803D GEN NEG PHASE SEQ PUMP MOTOR 2. XX-47-2000 IS EH OPERATOR'S PANEL (UPPER SECTION) D Y2804D GEN BACKUP &. MN XFMR FDR DIFF <( TURNING 3. EHC CONTROL LOGIC IS LOCATED IN RACK R56. EHC CONTROL GEAR Y2805D GEN PRIMARY AND/OR SECONDARY RLY FAIL PANELS XX-47-1000 AND XX-47-2000 INTERFACE WITH RACK R56. u Y2806D GEN OVERCURRENT 4. ALL COMPONENT UNIT PREFIXES ARE UNIT "1" UNLESS OTHERWISE NOTED. Y2807D GEN REVERSE POWER 5. THE 4 ACCUMULATORS ON SHEET 2 ARE ACUM-47-900,901,902 AND 903.
,-----1-----1----7 Y2808D MAIN XFMR 0IFF-SUD PRESS THE ASSOCIATED 1 ACCUMULATOR IS ACUM-47-904.
I I I I I Y2809D USS XFMR D IFF -PRESS-DC-NEUT QC 6. NOT APPL !CABLE I I I 7. FOR A LIST OF POINT ID'S ASSOCIATED WITH THE VOLTAGE REGULATOR. I SEE DWG 1-47W610-47-4. L----11-45W600-47-16 8. NOT APPLICABLE.
- 9. 1-SPV-047-623 WITHDRAWS/INSERTS THE PLUG, 1-SPV-047-620 ROTATES TO SELECT EITHER, OR BOTH COOLERS.
- 10. NOT APPLICABLE.
11 . FOR APPLICABLE CYBER SECURITY REQUIREMENTS SEE TVA DRAWING 1-47W640-1A. 0
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I I L-------7 I I I I L__ _ r----------7
- @' SE-47-151A I
L ___ _
---7
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----7 L___ I L___
---7
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I L __ _
---7 I
----7 SPARE L - - - - - - - - - - - - - - - i 1-45W600-47-18, TYP REFERENCE DRAWINGS:
TVA 1-47W610-1 SERIES - MAIN STEAM CONTROL DIAGRAMS 1-47W610-2 SERIES - CONDENSATE CONTROL DIAGRAMS
------------------------, 47W601-7 SERIES - TURBINE TRAPS .t. DRAINS
~
1-47W610-24 SERIES - RAW COOLING WATER LOG : 1-47W610-35 SERIES - GENERATOR HYDROGEN SYSTEM 1-47W610-46 SERIES - FEEDWATER CONTROL SYSTEM Y21080 Ll2;iJ : b,. 1-47W610-47 SERIES - TURBOGENERATOR CONTROL SYSTEM I I WEC 723J597 ------------ STEAM TURBINE E.H. TBG L------ _.J PS 4601001 ------------ PIPING - STEAM DRAIN &. GLAND DIAGRAM 47-113 726J672 ------------ WIRING PEDESTAL GOVERNOR
~~-2 4605D32 ------------ WIRING TERMINAL BOX D AND E
~
4605036 ------------ E.H. RESERVOIR WIRING
§~4 o I YOB ISIV-047-0113 MA-PLT-1000 ---------BLANKING PLATE KIT, MYSTERY BOX SIEMENS L583001 SERIES - DIGITAL E.H., CONTRACT 8344 I I MTR-47-108 I
I
'[:,
I PMP-047-0108 OR-047-0614 SYMBOLS:
+-------+---------- 6, ---DEVICE MOUNTED ON OR NEAR ASSOCIATED EQUIPMENT RTV-047-0112A f - ~ - - ' - - - - gjtRi~~
BEARINGS
~i~i LEGEND E - EMERGENCY TRIP FLUID FOR MAIN STEAM AND REHEAT VALVES S - ON SHEET 2 - EH FLUID SUPPLY R2 - ON SHEET 2 - EH FLUID RETURN R1 - ON SHEET 1 - LUBE OIL RETURN SSPS - SOLID STATE PROTECTION SYSTEM 1-47W610-35-3, COOR G ~ - ~
OIL BACKUP R1 STN-047-0603N UFSAR AMENDMENT 3
~ N 2A-24D WATTS BAR 9
FINAL SAFETY I TURNING GEAR OIL
~ :
EMERGENCY OIL 1-47W610-20-1, COORD C-10 QE[J2A-25C ANALYSIS REPORT 2A-24E LS 47-104A r-- I LOG Y2105D ~---l ~ POWERHOUSE L_ __ I
~
___DBE] I i---------<1-47W610-35-3, COORD C-9 i::IED 2A-25D
,cixn MTR-047-0099 :~ ~ UN IT 1 I
I lmmm I HS COMPANION DRAWi NGS: 1-47W610-4 7-SERIES ELECTRICAL
+--- ___ _....,__ 47-106 CONTROL DIAGRAM I
I TURBO-GENERATOR CONT SYS 1-47W610-47-1, COORD F-8 LOG Y2DDSD CKV-047-0099 TVA DWG NO. 1-47W610-47-1 R40 LUBE OIL RESERVOIR FIGURE 10.2-2
MAIN r-----------------------------------, 2-XX-47-3000 Cl z I SSPS CH1 I STEAM ISSP~ CH4 I r-------------------------------------------------------t-------------------------------------------------------~ : 6w 6w 6w I I I I "y I I I 3' 47~ 47y <( Q:'. ZT ZT I t-+----~;-,----,::xx--~:----H I r-rr1-----------r--------- 2-45W600-47-3 2-45W600-47-26 2-45W600-47-3 2-45W600-47-26 r-.-TT-----------,.------7 I : I I I I I I I 0 7-28A 7- I I I
~-~~!~]~]+< I !II ! L_.,_i
@ @ 1 FSV FSV 2-45W600-47-39 )
0 <~2~-~45=W~60=0--4~7~-2=0~--~~-- w I z ISV-047-0802 L __ 2-45W600-47-3 2-45W600-47-25 <( I NOTE 2 NOTE 2 I f- I I CKV-047-1024 z LOG LOG OR-047-0918 Y0391D Y0394D CKV 047-0639 047-0810 I 0 I <( r--- --- I s u r----,----7 I ZT 7-29A 7-ZT ZT 35A ZT 47-358
--i 2-45W600-47-19 )
Q I R-56 ISV-047-0815~-56 CKV-047-0646 T 47-49 (~2~-~45=W~60=0--4~7--1~9--~~-- - -::i><h---Cl!:]-----,,1"--,,----'.ji I I I ISV-047-0803 I CKV-047-0641 I I I I I CKV-047-0632 I ISV-047-0822 I L_ H P TURBINEINOTE J) 5W600-47-3 SWS00-47-26 ZT ZT 3A 47-338
--i 2-45W600-47-19 ISV-047-0808 CKV-047-0642 I
7-1018 I OR-047-1017 E I I I R2---1/4'--9,!4----'---~(IL-----'----C><l-_.S I IssPs1cH2 I Iss~s CH3 I I L_rTT _____ _
--- --- I I r--G-~'._©~-=:_'~~0-47-20) I I I I I I I I I I I ZT ZT FCV ZT ZT : 'I' 11-+----;l----ll:x xx------;1- - - + l 7-J0A 7- l 47-32A 47-32A 47-328 :
( 2-45W600-47-20
~---~--~
ISV-047-0805
~--+-
S-c;;;l><h---C/!:J-----,,1"--,,----'.ji
@ I NOTE 2 L... _ _ _ _.,_ _ _J TURBINE DRAIN VALVES 2-47W610-7-1 COOR E-3 EXTRACTION RTV-047-0179A LOG l+ci:l#-1-<l2~-4+/-,71w!61~~-f,-j,:;:;,c~oo~*((-~sD RZ ---wc-,4----'----, tc----,/;~~----
N N-RETURN VALVES Y0392D ~:7-0820 CKV-0-47-1021 TO PS-7-12 (_CK~:;:~649 MAIN STEAM
<_2_-4_5_w_,o_o_-4_7_-_,2_ _ _ ~r-J 2-47W610-47-5 2-RTV-007-0012A 1 CKV-047-0044 ISV-047-0826 S----<-1><1--1"-~f------'
TO SOLID STATE 2-47W610-47-5 PROTECTION SYSTB.4 (CHANNEL II INPUT>------- TO SOLID STATE PROTECTION SYSTEM ~
~ 3 NOTES:
( CHANNEL I INPUT>------ 1 TS LOCATED AT 480V UNIT BOARDS 2A &. 28.
- 2. THIS EQUIPMENT INTERFACES WITH THE REACTOR SOLID STATE PROTECTION SYSTEM ANO IS SUBJECT TO AUGMENTED QA REQUIREMENTS PER N3-47-4002.
TO SOLID STATE @NOTE f:::. 3. GOVERNOR AND THROTTLE VALVES ARE SHOWN SCHEMATICALLY. FOR CONF I GU RAT ION PROTECTION SYSTEM 1 2 PS OF GOVERNOR AND THROTTLE VALVES AND STEAM CHEST SEE DETAIL A2. ( CHANNEL III INPUT>------
- 4. ACCUMULATOR 2-ACUM-047-0900 HAS BEEN REMOVED. THE ASSOCIATED ISV'S, ORV'S, AND RTV'S ARE STILL IN PLACE. INLET AND OUTLET LINES TO THE PREVIOUS LOCATION OF THE ACCUMULATOR ARE CAPPED. DOWNSTREAM OF 2-RTV-47-310A IS CAPPED ANO NO GAUGE IS INSTALLED, PT 47-27C 7
I I I L-------12-45W600-47-32, COOR H-4) 2-47W610-47-5, COOR 0-5 UFSAR AMENDMENT 3 WATTS BAR DET A2 FINAL SAFETY L-262 ANALYSIS REPORT 47-8 I
'-]------~--------~
II I ACCUMULATOR SEE NOTE -4 DR VLV A DRV-0-47-0832A
!SOL VLV B ISV-0-47-0830A RUPTURE DISK POWERHOUSE I
I FOXBORO OCS 2--47W610-98-11A, COOR F4 L ., (FBM-98-R121A04, ACUM-0-47-0901 ACUM-0-4 7 -0902 DRV-0-47-08328 DRV-0-47-0832C ISV-0-47-08308 ISV-0-47-0830C WBN-2-RPD--47-901 WBN-2-RPD-47-902 UN IT 2 I I CH 2) 2--47W610-98-11A. COOR F10 TS--47-BA ACUM-0-4 7 -0903 DRV-0-47-08320 TABLE A ISV-0-47-0830D WBN-2-RP0-4 7-903 ELECTRICAL I (FBM-98-R121A08, CH 5) -------------, CONTROL DIAGRAM I 1 2 SMV-0-47-0025A
~----1-r----VENT ( 2-47W610-47-2 COOR H-1 ~--_J I 2--47W610-98-11A, COOR F10 ~~.:.~-
(FBM-98-R121A08, CH 6) A RTV-47 8 ISV-47
-310
-310
-311
-311
-312
-312
-313
-313
-314 4 TURBO-GENERATOR CONT SYS LOGIC REF 08F802403-F0-2823 C ISV-47 -310 -311 TABLE
-312 1
-313 -314 TVA DWG NO. 2-47W610-47-2 R21 FIGURE 10.2-3 SH A
MAIN ISSPS CH1 I STEAM ISSPS CH4 I r------------------------------------------------------,-----------------------------------------------------------, TO MSR A-2 TO MSR 8-2 I TO MSR C-2 I I I r-----, I I I ----r----- I I ZT ZT I I
! ZT ZT 1 -45W600-47-3 1-45W600-47-26 1 -45W600-47-3 1-45W600-47-26 I
I i-iTT __________ T _________ 1-45W600-47-3 1-45W600-47-25
<~1~-~*s=*~'=oo~-~*'~-~'=o-~r--
ISV- 47-0802 47-28A 47 t+---~,----<XXJt--7,------H 4A 47-34B
-~ 1-45W600-47-20 I SV-04 7 -0806
~
47y Qxx-G§ 47~ 1-M-2 47-49C I I I I I I I I I I NOTE 2 I NOTE 2 I I ,--- ---- ---- --4
~-~--~--~-~ I LOG LOG L~ 1-45W600-47-39 ) r ___ j Y0391D Y0394D
,,,1::::F---_j_-l'-J_-'....,.,_:_'"_-..,-'-_-_7-- :
I I 0 I <t: -----,---7 u ! ZT 47-29A ZT 47 ISV-047-0815 I CKV-047-0646@ R-56
<~1~-~*s=*~'=oo~-~*'~-~'='-~r- TT lSV-047-0803 47-49C I
I I I I CKV-047-0636 SWG00-47-3
----- 5W600-47-26 r----
ZT ZT ZT ZT 47-31A 47 3A 47-33B ( 1-45W600-47-19 ~- 1-45W600-47-19 ISV-047-0804 ISV-047-0808 CKV-047-0642 I I ISV-047-0824 I I
- R2---',f/'-J,!,.__j__ _~(IL---_,_----(:1<J-___,
ISSPSI CH2 I ISSPSI CH3 I '-r--r-, I I I -r--r-,------ r-----,----, I I I I I I I I I I
'I' I I I
<~1~-~*s=*~'=o~-~*'~-~'=o-~r ZT 47-30A ZT 47 I
IH------;l----l(xxr-71---+II I
'I'
@ TO MSR B-1 @ @
'I' lSV-047-0805 TURBINE DRAIN VALVES TO MSR A-1 1-47W610-7-1 COORD E-3 TO MSR C-1
~TE2 NOT~
I I EXTRACTION lc+cii-lt,1<]1~-f*,~*~s~1o~-fs-j1~.c~oo~,o~o-~sD R2_--',f/~,._~_, t,---,.j,__,__ _ __ LOG Y0392D LOG Y0393D NON-RETURN VALVES
~! (_CKV~~:;:;649 7 - 08 2 0 OR-047-0941 CKV-047-0D44 ISV-047-D826 MAIN STEAM S --'-l><H,,f-~
1-47W610-47-5[ET],COORD 8-5 1-RTV-7-12A1 NOTES:
- 1. OTS LOCATED AT 480V UNIT BOARDS 1A & 18.
- 2. THIS EQUIPMENT INTERFACES WITH THE REACTOR SOLID STATE PROTECTION SYSTEM AND TO PS-7-12 IS SUBJECT TD AUGMENTED QA REQUIREMENTS PER N3-47-4002.
1-47W610-7-1,COORO F-3 J. THE EH RESERVOIR SHOWN FUNCTIONALLY INCLUDES THE SEPARATE AUXILIARY EH RESERVOIR. VALVES ORV-047-1033A AND ISV-47-1313 EXIST OFF THE AUXILIARY EH RESERVOIR.
- 4. GOVERNOR AND THROTTLE VALVES ARE SHOWN SCHEMATICALLY. FOR CONFIGURATION OF GOVERNOR AND THROTTLE VALVES AND STEAM CHEST SEE DETAIL A2.
- 5. FOR TURBINE RUNBACK SEE DWG. 1-47W61D-1-3A.
- 6. FOR GENERAL NOTES (INCLUDING LEGEND & SYMBOLS). SEE SHEET 1.
- 7. FOR DESCRIPTIONS OF COPCl,[ETl.[DV-1l,[DV-2l. SEE SHEET 5.
1-RTV-7-12A2 1-47W610-47-5,[DV-2l,COORD C4 UFSAR AMENDMENT 3 2A-248 WATTS BAR 1-47W610-47-5[0V-1].COORD 0-4 FINAL SAFETY 62 ANALYSIS REPORT 47-8 ACCUMULATOR OR VLV A ISOL VLV 8 POWERHOUSE ACUM-04 7 -0900 ACUM-047-0901 DRV-047-0832A DRV-047-08328 ISV-047-0BJOA ISV-047-08308 UN IT 1 LOG LOG ACUM-04 7-0902 ACUM-04 7 -0903 DRV-047-0832C DRV-047-0832D ISV-047-0BJOC ISV-047-0830D DET A2 ELECTRICAL I I Y2117D Y2118D TABLE A CONTROL DIAGRAM ______________ J I I HIGH LOW TURBO-GENERATOR CONT SYS TVA DWG NO. 1-47W610-47-2 R53 FIGURE 10.2-3
Cl z 3' <( Q:'. 0 0 w z <( f- l<EYPHASOR SIGNAL z FRCJ.ITSI
--< COORO A-1 0
<( u
,--+---l.---7
~
Y2/107
~
- e2128 I I t-- 7
©© © r--+--7 VT BA 47-1288 1
I: I I ZDE 8-7 I I I I I L I I I
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I I I TE
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- ~1808~
TV-47-195A1 7 I w
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47-195 I
- ©:
- mt 3Q OR-047-
- mt 3Q GENERATOR 0293 :mt ;Q I
- mt 3Q i UFSAR AMENDMENT 3
- @~----~- WATTS BAR I
I' I II I FINAL SAFETY L---------+ AO A1 ISIV-047-01968/1 ISIV-047-0196B/2 ANALYSIS REPORT TO ATMOSPHERIC A2 ISIV-047-01 968/3 CON DR TANK A3 ISIV-047-01988/1 A4 ISIV-047-01 988/3 AS ISIV-047-01 98B/2 POWERHOUSE AS A7 ISIV-047-02008/3 ISIV-047-0200B/2 UN IT 2 LOG T2041A AB A9 ISIV-047-0202B/2 ISIV-047-0202B/3 ELECTRICAL A10 A11 ISIV-047-02048/1 ISIV-047-02048/3 LP-A OESC/POS LP-8 DESC/POS LP-C DESC/POS CONTROL DIAGRAM A12 A13 ISIV-047-0204B/2 ISIV-047-02068/2 2-VE-Ofl-LPA/001 2-VE-047-LPA 002 LP-2A PRIMARY/TE LP-2A PRIMARY E 2-VE-0+7-LPB/001 2-VE-047-LPB 002 LP-28 PRIMARY/TE LP-2B PRIMARY/GE 2-VE-o+7-LPC/001 2-VE-047-LPC 002 LP-2C PRIMARY/TE LP-2C PRIMARY/GE TURBOGENERATOR CONT. SYS MFPT CON DRAIN TABLE "A" 2-VE-0+7-LPA/OOJ LP-2A ALTERNATE/TE 2-VE-047-LPB/00J LP-28 ALTERNATE/TE 2-VE-0+7-LPC/00J LP-2C ALTERNATE/TE TVA DWG NO. 2-47W610-47-3 R15 TANK 2-VE-047-LPA/004 LP-2A ALTERNATE/GE 2-VE-047-LPB/004 TABLE "B" LP-28 ALTERNATE/GE 2-VE-047-LPC/004 LP-2C ALTERNATE/GE FIGURE 10.2-4 SH A
WBN 10.3 MAIN STEAM SUPPLY SYSTEM 10.3.1 Design Bases The main steam supply system is designed to conduct steam from the steam generator outlets to the high pressure turbine and to the condenser steam dump system. This system also supplies steam to the feedwater pump turbines, an auxiliary feedwater pump turbine, moisture-separator reheaters, and the turbine seals. The main steam supply system includes self-actuating safety valves to provide emergency pressure relief for the steam generators and atmospheric relief valves to provide the means for plant cooldown by steam discharge to atmosphere if the turbine bypass (condenser steam dump) system is not available. The main steam supply system is designed to the classifications indicated on flow diagram Figure 10.3-1 and specified in Section 3.2.2. Pipe failures or malfunctions of any portion of the system have been considered and protection provided. System design assures that a postulated main steam line break coincident with a single active failure will not develop consequences outside the current plant design bases. 10.3.2 System Description 10.3.2.1 System Design The main steam supply system is shown schematically in Figure 10.3-1. The control and logic diagrams for this system are presented in Figures 10.3-2 through 10.3-7. The steam is conducted from each of four steam generators through the containment and out through the main steam line isolation valves. Each steam generator outlet nozzle contains an internal multiple venturi type flow restrictor which, in the event of a steam line break, will act to limit the maximum flow and the resulting thrust. The steam generator safety valves and atmospheric relief valves are located upstream of the main steam line isolation valve. There are five safety valves per steam generator. The steam generator safety valves provide emergency pressure relief in the event that steam generation exceeds steam consumption. The safety valve settings are provided in Table 10.1-1. There is one atmospheric relief valve per steam generator. Each valve has a minimum capacity and a maximum capacity based upon steam generator pressure. These atmospheric relief valves provide the means for plant cooldown by steam discharge to the atmosphere if the condenser steam dump is not available. The valves will also provide a means of steam generator pressure control if the condenser steam dump is not available, and will thus preclude unnecessary lifting of steam generator safety valves. Pressure setting of these valves is based on a slow and rapid rate of steam generator pressure increase. 10.3-1
WBN The maximum actual capacity at a steam pressure of 1185 psig of any single safety or atmospheric relief valve does not exceed a flow of 970,000 lb/hr. This limits steam release if any one valve is inadvertently stuck open. Steam supply for the auxiliary feedwater pump turbine is provided by one connection each on two of the main steam lines upstream of the main steam line isolation valves. This arrangement provides both redundancy and dependability of supply. Each of the two main steam chests includes two turbine stop valves and two turbine control valves. The steam lines are cross-connected upstream of the turbine stop valves. The cross connections provide both an entrance to the condenser steam dump system and a distribution manifold for the turbine stop valves. The turbine is described in Section 10.2 and the turbine bypass system is described in Section 10.4. 10.3.2.2 Material Compatibility, Codes, and Standards All pressure containing components in the main steam supply system are in accordance with applicable codes or standards. Applicable codes, standards, and design conditions (pressure and temperature) are shown in Table 10.3-1. The materials for piping and fittings in the TVA Class B Portion of the system are impact tested as required by ASME Section III for Class 2 components. 10.3.3 Design Evaluation The portion of the main steam supply system designed to TVA Class B requirements is Category I seismically qualified (see Table 3.2-2a). This portion of the system is protected from internal missiles as discussed in Section 3.5.1. Redundant electrical power and air supplies to critical components assure reliable system operation and safe shutdown capability. Redundant steam supply connections are provided for the turbine-driven auxiliary feedwater pump. The safety valves provide 100% relieving capacity to protect the system from overpressure. The capacity provided by the atmospheric relief valves is over and above the safety valve capacity. The atmospheric relief valves, which have a set pressure slightly lower than the safety valves, prevent unnecessary opening of the safety valves. Four atmospheric relief valves have been provided per unit (one per steam generator). Bidirectional steam line isolation valves are installed to protect the plant during the following accident situations: 10.3-2
WBN
- 1. Break in the steam line piping either inside or outside the containment.
- 2. Break in the feedwater piping downstream of the last check valve before the steam generator.
- 3. Steam generator tube rupture.
The main steam line isolation valves are 32-inch wye type bidirectional globe, straight through flow, air to open, spring to close. These valves are capable of closing within 6 seconds after receipt of a closure signal on a 'high-high' containment pressure signal, low steamline pressure in any steamline, or high steamline negative pressure rate in any steamline as shown in Figures 7.3-3, Sheet 3 and 10.3-5. For accident situation No. 1, inside containment, the steam generator associated with the damaged line discharges completely into the Containment. The other steam generators would act to feed steam through the interconnecting header to reverse flow into the damaged line and then release into the Containment. The approximate 6-second closing time for the isolation valves in the other three lines will limit containment pressure rise below design pressure. If any of these three valves fail to close, protection is provided by closure of the valve in the broken line. Hence, redundancy is provided to allow for a single failure of any one isolation valve. For accident situation No. 1, outside containment, the four main steam isolation valves act similarly to prevent the uncontrolled blowdown of more than one steam generator, even after the failure of any one main steam isolation valve. This prevents any of the system transients from exceeding those described in Chapter 15. For accident situation No. 2, the isolation valve closure time requirement is not as critical as it is for situation No. 1. Hence, the isolation valve arrangement is satisfactory for requirements resulting from this situation. Valve redundancy to shut off flow in the forward direction is not required. For accident situation No. 3, valve closure time is not limiting. A fast acting valve is not required nor is valve redundancy. The isolation valve serves to limit the total amount of primary coolant leakage during the shutdown period by isolating the damaged steam generator after pressure is reduced below steam generator shell side design pressure. See Section 3.11 for Environmental Design of the main steam supply system. 10.3-3
WBN 10.3.4 Inspection and Testing Requirements Performance tests of individual components and periodic performance tests of the actuation circuitry and mechanical components assures reliable performance. Surveillance test requirements are given in Chapter 16. The main steam supply system complies with ASME Section XI. Inspection and Testing Requirements are given in Chapter 3. Preoperational test requirements are given in Chapter 14 (historical information). 10.3.5 Water Chemistry 10.3.5.1 Purpose Water chemistry control in the secondary systems such as the steam generator steam side, feedwater, and condensate for various operating modes and conditions has been established to minimize corrosion and damage to the steam generators and to minimize fouling of steam generator heat transfer surfaces. 10.3.5.2 Feedwater Chemistry Specifications The plant chemistry program establishes the steam generator steam side and feedwater chemistry specifications for normal power operations. This program is based on the EPRI PWR secondary water chemistry guidelines as detailed in the plant chemistry program. Experience with steam generators using all volatile treatment (AVT) method has indicated that corrosion and fouling have been effectively controlled. 10.3.5.3 Operating Modes Unit 1
- 1. Power Operation:
During normal power operation the feedwater and secondary side steam generator chemistry is maintained in accordance with the plant chemistry program. Prompt action is taken to correct any problem indicated by transient excursion outside these guidelines. Feedwater chemistry is maintained within the specified guidelines by providing make-up water of adequate purity and continuously supplying oxygen scavenging and pH control agent(s). Independent chemical systems inject their respective solutions into the condensate system downstream of the condensate demineralizer. These chemical addition systems are shown in Figure 10.3-9. Steam generator steam side chemistry during power operations is controlled by steam generator blowdown (Section 10.4.8) and the presence of residual pH control agent(s) and oxygen scavenging agent(s) from the feedwater. 10.3-4
WBN-1
- a. Blowdown. The blowdown system removes contaminants (particulates and dissolved solids) introduced into the steam generators by the feedwater system or fission products that may leak into the steam generators via steam generator tube leak. The quality of water in the steam generators is controlled by maintaining a minimum blowdown rate of 5 gpm per steam generator. At full power the maximum flow rate is approximately 87.5 gpm per steam generator. In the event of primary to secondary leakage or condenser in-leakage, higher blowdown rates may be employed to help keep the steam generator chemistry within limits.
Blowdown may help to control radioactive iodine present in the event of primary to secondary leakage.
- b. pH control and oxygen scavenging agents. The pH control agent(s) and Polyacrylic Acid (PAA)* supplied by the secondary chemical feed system are transported through the main feedwater lines to the steam generator and are carried along with steam through the piping, feedwater heaters, and turbines.
Oxygen scavenging agent is supplied by the secondary chemical feed system and reacts with any oxygen in the feedwater. Consequently, corrosion is inhibited in these components due to the pH control afforded by pH control agent(s). Boric acid* is supplied by the secondary chemical feed system to the condensate system to buffer the solution within the steam generator. These additional systems are shown in Figure 10.3-9.
- Plant Chemistry controls the supply of Polyacrylic Acid (PAA) boric acid to the Replacement Steam Generators (RSGs) in accordance with EPRI and Westinghouse guidelines.
- 2. Cold Shutdown/Wet Layup:
Oxygen scavenger(s) and pH control agent(s) are used during wet layup of the steam generators. The layup chemicals are injected into the steam generators during cold shutdown, sampled using existing steam generator sample line(s).
- 3. Auxiliary System Support:
The oxygen scavenger(s) and pH control agent(s) are capable of being fed to the auxiliary boiler feedwater pump suction. Thus, corrosion inhibitors are available to the auxiliary boiler system. Unit 2
- 1. Power Operation:
During normal power operation, the feedwater and secondary side steam generator chemistry is maintained in accordance with the plant chemistry program. Prompt action is taken to correct any problem indicated by transient excursion outside these guidelines. Feedwater chemistry is maintained within the specified guidelines by providing make-up water of adequate purity and continuously supplying hydrazine, ethanolamine (ETA) and ammonia to the condensate system. Independent hydrazine, ammonia, ETA, ammonium chloride and boric acid systems inject their respective solutions into the condensate system downstream of the condensate demineralizer. These chemical addition systems are shown in Figure 10.3-9. 10.3-5
WBN Steam generator steam side chemistry during power operations is controlled by steam generator blowdown (Section 10.4.8) and the presence of residual ammonia, ETA and hydrazine from the feedwater.
- a. Blowdown. The blowdown system removes contaminants (particulates and dissolved solids) introduced into the steam generators by the feedwater system or fission products that may leak into the steam generators via steam generator tube leak. The quality of water in the steam generators is controlled by maintaining a minimum blowdown rate of 5 gpm per steam generator. At full power the maximum flow rate is approximately 87.5 gpm per steam generator. In the event of primary to secondary leakage or condenser in-leakage, higher blowdown rates may be employed to help keep the steam generator chemistry within limits. Blowdown may help to control radioactive iodine present in the event of primary to secondary leakage.
- b. Ammonia, ETA, ammonium chloride, boric acid and hydrazine. The ammonia, ETA and ammonium chloride supplied by the secondary chemical feed system are transported through the main feedwater lines to the steam generator and are carried along with steam through the piping, feedwater heaters, and turbines.
Hydrazine is supplied by the secondary chemical feed system and reacts with any oxygen in the feedwater. Consequently, corrosion is inhibited in these components due to the pH control afforded by ammonia. Boric acid* is supplied by the secondary chemical feed system to the condensate system to buffer the solution within the steam generator. These additional systems are shown in Figure 10.3-9.
- 2. Cold Shutdown/Wet Layup:
Hydrazine and ammonia hydroxide are used during wet layup of the steam generators. The layup chemicals are injected into the steam generators during cold shutdown, sampled using existing steam generator sample line(s), and completely mixed by bubbling nitrogen through the bottom of the steam generator or completely cover the steam generator tubes with a greater than 25ppm hydrazine layup solution.
- 3. Auxiliary System Support:
The hydrazine and ammonia additions are capable of being fed to the auxiliary boiler feedwater pump suction. Thus, corrosion inhibitors are available to the auxiliary boiler system. 10.3.5.4 Effect of Water Chemistry on the Radioactive Iodine Partition Coefficient As a result of the basicity of the secondary side water, the radioiodine partition coefficients for both the steam generator and the air ejector system are increased (i.e., a greater portion of radioiodine remains in the liquid phase). However, the lack of data on the exact iodine species and concentrations present prevents a quantitative determination of the coefficient increase for these systems. The partition coefficients used for site boundary dose calculations due to secondary side releases are those given in NUREG-0800, Revision 2. For the steam generators, a partition coefficient of 0.01 was used. 10.3-6
WBN 10.3.6 Steam and Feedwater System Materials 10.3.6.1 Fracture Toughness Requirements of the ASME Boiler and Pressure Vessel Code, Section III, Articles NC-2310 and ND-2310 of the summer of 1973 Addenda for fracture toughness for ferritic materials are met in all Class 2 and 3 components. Impact testing is not specified for the auxiliary feedwater piping because the pipe wall thicknesses do not exceed 5/8-inch. 10.3.6.2 Materials Selection and Fabrication Code class pressure boundary materials in this system are included in Appendix I to ASME Code Section III. Austenitic stainless steel pressure boundary components may be used in these systems. Therefore, this system conforms to Regulatory Guides 1.31, 1.36, and 1.44. Topical Report TVA-NQA-PLN89 contains TVAs position for the cleaning and handling of Class 2 and 3 components in accordance with Regulatory Guide 1.37. Cleaning and cleanness of fluid systems and components are in accordance with ANSI N45-2-1-1973, or later. With the exception of Regulatory Position C-1(b), C-2, and C-4, this system complies with Regulatory Guide 1.50, Control of Preheat Temperature for Welding of Low-Alloy Steels. With the exception of Regulatory Position C-1 and C-2.a, this system complies with Regulatory Guide 1.71, "Welder Qualification for Areas of Limited Accessibility." REFERENCES None 10.3-7
WBN TABLE 10.3-1 MAIN STEAM SUPPLY SYSTEM APPLICABLE CODES, STANDARDS, AND DESIGN CONDITION Steam Generator Shell
- a. Design pressure, 1185 psig
- b. Design temperature, 600°F
- c. Code, ASME BOILER AND PRESSURE VESSEL Code, Section III, Division 1, Class 1 Main Steam Piping
- a. Design pressure, 1185 psig
- b. Design temperature, 600°F
- c. TVA Class B - Code, ASME Boiler and Pressure Vessel Code, Section III, Class 2 TVA Class H - Code, ANSI B31.1, Code for Pressure Piping Main Steam Isolation Valves
- a. Design pressure, 1185 psig
- b. Design temperature, 600°F
- c. Code, ASME Boiler and Pressure Vessel Code, Section III, Class 2 Main Steam Safety Valves
- a. Design pressure, 1185 psig
- b. Design temperature, 600°F
- c. Code, ASME Boiler and Pressure Vessel Code, Section III, Class 2 Main Steam Atmospheric Relief Valves
- a. Design pressure, 1185 psig
- b. Design temperature, 600°F
- c. Code, Boiler and Pressure Vessel Code, section III, Class 2
t!l z 0::: 0 0 w z 1-z
- i;;
0 t.) L 729.0' DETAIL 81 DRAIN HOOkUI" SCHEMATIC TVl"ICAL + LOOl'S-2 UNITS {ALL DRAIN LINES ARE TVA CLASS C) 1-1153
---- 38" MAIN STEMI STEJH GENERATOR SAFETY VALVES SETTING DATA 1 VAL
- 1115 l'SIG 1 VAL
- 1115 PSIG 1-552 1 VAL e 1205 l"SIG 1 VAL
- 1215 l'SIG 1 VAL
- 122 l'SIG TOTAL -3,975,200 l"l"H/GENEIIATOR L.P. TURBINE C (i EL 751'-II" NOTES:
- 1. ALL VALVES ARE THE SAME SIZE AS THE PIPING UNLESS OTHERWISE NOTED.
Z, ALL PRESSURE GAI.E VALVES ARE I" GLASS UNLESS OTHERIISE NOTED,
- 3. ALL VALVE NUMBUS SHALL BE P'REf'IXEO 11TH THE UNIT NIMBEIL
+. ALL PIPINC TV" CLASS H, PER DIC 471121-1, EXCEl'T AS NOTED, INTERCEPT 5. [] ETC, DENOTES DESIGN PRESSURE NG TDPERATUIIE AS i.IVEN IN THE VALVE TAIILE ON THIS DIIAtINC.
fi. HYDROSTATIC TESTINC SHALL BE: IN ACCOROAICE 11TH THE Al"l"LICABLE CODES. lf'Olt HYDRO l'RESSURES SEE NOTE I),
- 7. THE DESICN PIIESSUR£ AND TElll'ERATURE Cf' ALL DRAIN AND VENT LINES
.. THRCIUCH THE LAST ISOLATION VALVE SHA.LL B£ THE SAME AS THE l'ROC£SS LINE, 1' TltAl'l'ED DRAIN SEE DETAIL A1 {TYi')
0 0 r.i
~r I" DRAIN t, FOR TVA CLASS 8 Pil"INC, ALL l"Il"INC OOINSTltEAM OF THE LAST 10.
ISOLATION VAL VE ON LOCAL DRAINS, VENTS AND TEST CONl£CTIONS IS TVA Cl.ASS C.. 11, ELECTRIC l"OIER IS ltENOVEO FROI VALVES 1-fCV-1 7, -1 8, -1 1 Al()
-150 BY ADMINISTRATIVE CONTROL <:Ii HS-1-1478, -118, -1 98 AN) 1-534 SEE NOTE 11 -1608 DURINC IQQIAL l"OIER OP'EltATION TO l"ltEVENT Sl"URIOUS OPENINC L.C. DUE TO APl"ENDIX R FIRE.
- 12. UNLESS OTHERWISE NOTED, ALL ROOT VALVES HAVE AN "A" SUFFIX IF NOT SHOWN IN THE ADDRESS.
- 13. THIS EQUll'NIENT INTERFACES WlTH THE REACTOR SOLID STATE P'ROTECTJON SYSTEM AN) IS SUBJECT TO AUGMENTED Q\ REQUIREMENTS PEit N3- 7-002.
~ ~
USED 2" DRAIN STEAM CEN I tao~!z~PI CLASS C a.ASS a llli"M12"
- rm""ERIC CTYPI ITYPJ r ~E .°EllJk 11, TYP d V 14,-~ -,,...---,~,,.-tt-MD" m VALVES 17. THE SECONJARY CHN,EER OF THE STEAM GENERATORS (SHELL SIDE) ARE BUILT TO TVA CLASS A. AL THOUGH THE SHELL SIDE OF THE STEAM GENERATORS FUNCTIONS ONLY DICTATE A TVA CLASS B, THEY WERE PROCURED 10 aJil'LY WITH TVA CLASS A.
PIPING CONNECTED TO THE TVA CLASS A STEAM GENERATORS 15 TVA CLASS B CLASS
- I CLASS H EXCEPT AS NOTED.
MOISTURE SEPARATOR REHEATERS TABLE A (IUFICE TABLE B 1-510 1" DRAIN WATTS BAR SYSTEM PRESSURE - TUl'ERA~E DATA TRAP 1-200 1-200 FINAL SAFETY ND. DESIGN ,,... DESIGN 1-201 1-201
;,,I ANALYSIS REPORT CL~\~~)NE PRESS PSIG ABOVE SEAT DRAIN 1-202 1-202 11115 SEE 1-7H07-1
~
1-%03 CO{IID A-3 1-203 1-20+ 1-201 1-20, 1-200
~
165 250 110
,oo 1-207 1-207 THROTTll~ I ORIFICES~!___[!] POWERHOUSE 1-%011 1-2011
,----""" ~ l ~ UNIT 1 LS . .... C D E F LEVEL Silla-I VALVES G H [ J K L
" N 1-201 D
1-20, p D m: rf~J/* SEE 1-7WII07-1 COORD A-J 1* 5.,!.
~
FLOW DIAGRAM 1-200
..."' "" ..,..,"" ......,,."'"' ......"'"'"' "'"'"" .,...."""" ......"'"'"'"' ...""""° ...
....,."" .......°, ......"'"'"' ......"""" ......"'"'
1-201 ll40 320A 321A 32DB 321B 913A 923A m m 910 917 922 DET C1 1-202 "3 322A me 933A m
'" REFERENCE """"""'
71110[1-1 ---------- FLOI DIAGIWH.ENERAL P'LANT SYSTEM VAL VE ROOM MAIN & REHEAT STEAM 1-203 323A 32JB 9UA ,01 952 MFPT TEST SOUTH 1-204 HZOIS 1-207 1-2011 1-209 670 HO
.. 1 671 H1 m
673 671 32A 326A 3211A 321A 3248 3278 3218 953A H3A 97" 9113A 993A m
..."' 977 117 9119 990 1000 '" ....
ee1 991 1001 912 l7Z 992 1002 PI PE CONNECTION SEE DIG 1-47W815-J 1" 8Y-l"ASS 1-109 78101-1 SERIES ---- 308617 SERIES ------ l-71611-1 -------- 71400-1/5 -------- 1-71610-1 -------- INSTIUNENT TABULATION INSfflllENTATION SYIBJ..S NII IDENTirICATI<JI MAIN STEMI LOCIC DIAGRAM MAIN STEAM SYSTEM Pil"INC MAIN STEMI-CONTftQl OIAGltN,I TVA DWG NO. 1-47W801-1 R46 FIGURE 10.3-1 A DRAIN 71 15-1 ---------- MAIN STEAM RELIEF AND SN'ETY VALVE VENTS 711101-100 SERIES -- STRESS ANALYSIS l"MmLEM BOUNDARY
Cl z MOISTURE SEPARATOR-REHEATERS 3= <( Q:'. 0 0 [It] w z TEST CONNECTION STOP I FC VALVE 1-94 I - INSIDE REACTOR OUTSIDE REACTOR CONTAINMENT 1' TRAPPED DRAIN SEE DETAIL A1 {TYP 9 PLACES) DETAIL B1 DRAIN HOOKUP SCHEMATIC TYPICAL 4 LOOPS-2 UNITS (ALL DRAIN LINES ARE TVA CLASS G) STEAM GENERATOR SAFETY VALVES SETTING DATA CONDENSER 1 VALVE OPENS e 1185 PSIG ZONE C 1 VALVE OPENS* 1195 PSIG 1~~~~~ g~~~~:e 1~n ~~rn 1 VALVE OPENS 1224 PSIG TOTAL CAPACITY-3,975,200 PPH/GENERATOR
. P. TURBINE C ct,EL 758'-6' NOTES:
- 1. ALL VALVES ARE THE SAME SIZE AS THE PIPING UNLESS OTHERWISE NOTED.
- 2. ALL PRESSURE GAGE VALVES ARE 1" GLOBE UNLESS OTHERWISE NOTED.
- 3. ALL VALVE NUMBERS SHALL BE PREFIXED WITH THE UNIT NUMBER.
- 4. ALL PIPING CLASS H PER DRAWING, EXCEPT AS NOTED AND TURBINE IMPULSE PRESSURE TRANSMITTER SENSING LINES, WHICH ARE CLASS P PER WB-DC-40-36.
- 5. II] ETC, DENOTES DESIGN PRESSURE ANO TEMPERATURE AS GIVEN IN THE TABLE ON THIS DRAWING.
0 6. NOT USED.
- 7. THE DESIGN PRESSURE AND TEMPERATURE CF ALL DRAIN AND VENT LINES THROUGH THE LAST ISOLATION VALVE SHALL BE THE SAME AS THE PROCESS LINE.
- 8. NOT USED.
- 9. FOR TVA CLASS 8 PIPING, ALL PIPING DOWNSTREAM CF THE LAST ISOLATION VALVE ON LOCAL DRAINS, VENTS ANO TEST CONNECTIONS IS TVA CLASS G.
- 10. WATER FROM THE MSR DRAIN TANK SHALL NOT BACK-UP INTO THE l.4SR VESSELS AS STATED IN THE SYSTEM DESCRIPTION FOR SYSTEM 006, SECTION 3.5 WARNING.
- 11. STEAM DUMP VALVES WBN-2-FCV-1-103,-104. -105. -106,-107 .-108, -1 09,-110. -111. -112,-113, ANO
-114 ARE INCLUDED IN THE AUGMENTED QA PROGRAtr.1 (032), ALL PRESSURE RETAINING PARTS SHALL BE PROCURED TO QA LEVEL 1 REOUIREt.ENTS, NON-PRESSURE RETAINING COMPONENTS SHALL BE PROCURED TO OA LEVEL 3 AS A MINIMUM.
DESIGN CRITERIA/SYSTEM DESCRIPTION REFERENCE DOCUMENTS. (USE THE LATEST REVISIONS ON ALL WORK UNLESS OTHERWISE SPECIFIED. SEE THE LATEST REVISION OF THE 47821 SERIES DRAWINGS
':e~L~~4i1\T:~-c~~~~1Fs\i~1Ii~~~kM
- 13. ELECTRIC POWER IS REMOVED FROM VALVES IBN 2-FCV-1-147, -1411, -149 AND -150 BY ADMINISTRATIVE CONTROL OF IBN-2-HS-1-147, -148, -149 AND -150 DURING NORMAL POWER OPERATION TO PREVENT SPURIOUS OPENING DUE TO APPENDIX R FIRE.
- 14. UNLESS OTHERWISE NOTED. ALL ROOT VALVES HAVE AN "A" SUFFIX IF NOT SHOWN IN THE ADDRESS.
~ 15. THIS EQUIPMENT INTERFACES WITH THE REACTOR SOLID STATE PROTECTION SYSTEM AND IS SUBJECT TO AUGMENTED QA REQUIREMENTS PER WBN-SOD-N3-47-40D2.
- 16. VALVES DENOTED AS L.C. ARE LOCKED CLOSED DURING NORMAL PLANT OPERATION.
ROTOR GLAND STM 17. THE SECONDARY CHAMBER OF THE STEAM GENERATORS (SHELL SIDE) ARE BUILT TO TVA CLASS A. SEAL (H.P.) 1-690
\..U
- ~~~O~~~~~~D S~~L~ 0 ~~~~ ~T~H~v!T~t~s~E~~R~I~~:GF~2~~g~~~ ~~L iH~l~~:T~Lr~~ ~L~~~A~* THEY GENERATORS IS TVA CLASS 8 EXCEPT AS NOTED.
0 Ww REFERENCE DRAWINGS: CLASS G CLASS B zu 471800-1 ----------- FLOW DIAGRAM-GENERAL PLANT SYSTEM 0 I (TYP) (TYP)
<(
0...,J 471611-1 ----------- 47821-1 ------------ MAIN STEAM LOGIC DIAGRAM PIPING SYSTEMS CLASSIFICATION
~ ATMOSPHERIC Zo... 471400-SERIES ------ MAIN STEAM SYSTEM PIPING w I
<( 471610-1 ----------- MAIN STEAM-CONTROL DIAGRAM d RELIEF VA mz
<( ~
WBN-SDO-N3-1-4D02 -- DESIGN CRITERIA FOR MAIN STEAM SYSTEM PIPING (THROUGH ISOLATION VALVE) WB-DC-40-36--------- CLASSIFICATION CF PIPING.PUMPS.VALVES. a. VESSELS 471415-1 .t. 2 ------- MAIN STEAM RELIEF AND SAFETY VALVE VENTS 47W400-10D ,1. -200 SERIES -- STRESS ANALYSIS PROBLEM BOUNDARY STEAM GENERA TOR LOOP NO. 2 TfoiiR> ~ UFSAR AMENDMENT 3 TABLE A 1-580 1 " DRAIN WATTS BAR TRAP 1-200 ORIFICE STRAINER 1-200 1-200 ABOVE SEAT DRAIN FINAL SAFETY 1-201 1-201 1-201 SYSTEM PRESSURE-
~Rs-:~~8D7-1 ANALYSIS REPORT
~
1-202 1-202 1-202 TEMPERATURE DATA 1-203 1-203 1-203 NO. DESIGN DESIGN PRESS(PSIG) TEMP(°F) THRDTTLIN~I 1-204 1-204 1-204 1-206 1-206 1-206 1185 600
----°'~IFICES~~
POWERHOUSE STEAM GENERATOR LOOP NO. 3 1-207 1-208 1-207 1-208 1-207 1-208 ~rn~ r~~~~a~l
- SEE2-47W807-1
!.:.. ~
",' UN IT 2 1-209 1-209 1-209 COORD A-2 I
~
LS
/2" FLOW DIAGRAM 1-200 639 640 641 642 643 J20A 3208 91JA 914 915 916 917 918 919 920 921 922 1-201 1-202 1-203 644 m 600 654 646 601 647 652 657 648 J21A J22A 323A 3218 J22B J2JB 92JA 9JJA 94JA 924 9J4 944 925 926 945 946 927 947 928 9JO 929 9J9 949 930 940 950 931 941 951 932 942 1 " BY-PASS MAIN & REHEAT STEAM 1-204 1-206 609 664 660 661 666 662 667 "'
663 668 J24A J26A 3248 3268 95JA 96JA 954 964 955 965 956 966 957 967 958 968 959 969 960 970 961 971 "' 962 972
._DRAIN DET C1 TVA DWG NO. 2-47W801-1 R38 1-207 1-208 669 674 670 675 671 676 672 677 673 678 J27A 328A 3278 3288 973A 983A 974 984 975 985 976 986 977 987 978 988 979 989 980 990 981 991 982 992 SOUTH VAL VE ROOM FIGURE 10.3-1 (U2) 1-209 679 680 681 682 994 995 996 997 998 999
"' 329A 3298 993A 1000 1001 1002
NOTES:
- 1. STEAM FLOW FROM EACH GENERATOR IS MEASURED BY FLOW RESTRICTORS FE-1-3,
-516 FE-1-10, FE-1-21, ANO FE-1-28. MASS FLOW RATE FROM EACH FLOW ELEMENT IS DERIVED BY REDUNDANT CHANNELS OF INSTRUMENTATION. SAFETY INJECTION AND
---------------------------------7 --------------------------------7 FEEDWATER CONTROL SIGNALS ARE DERIVED FROM THESE CHANNELS OF T-512 I INSTRUMENTATION.
I I 2. THE MAIN STEAM ISOLATION VALVES (FCV-1-4, FCV-1-11, FCV-1-22, AND FCV-1-29) ARE ACTUATED BY HI-HI CONTAINMENT PRESSURE, STEAM LINE BREAK, OR MANUALLY. L-940 3. THE POWER RELIEF VALVES (PCV-1-5, PCV-1-12, PCV-1-23 AND PCV-1-30) ARE PT OPERATED EITHER MANUALLY FROM THE MAIN CONTROL ROOM OR AUTOMATICALLY FROM THEIR ASSOCIATED INSTRUMENT FAMILIES (PT-1-6, PT-1-13, PT-1-24 I I l- 2 ~T-S 1 S EAI-99-0701 (CH3) AND PT-1-31). PT-1-28 I R-3 R=J___ _J. _____ ~cc~-=-~6ec~~~~1 2- - - - ~
~c'~7
- 4. THE STEAM DUMP VALVES (FCV-1-103 THROUGH FCV-1-114) ARE CONTROLLED AUTOMATICALLY FROM THE TURBINE IMPULSE CHAMBER PRESSURE ANO MAIN STEAM COOR A-9 -----------------------------------------~---- CH2 CH2 I HEADER PRESSURE. EACH DUMP VALVE HAS POSITION INDICATING LIGHTS IN THE
[ PQ-514 PQ-515 I MA IN CONTROL ROOM. I/E 5. INSTRUMENTS ASSOCIATED WITH BACKUP CONTROL ANO MARKED WITH AN ASTERISK R~ ~R-7 ( .. ) WILL BE LOCATED ON THE APPROPRIATE 480-V MOV 6.9-KV SHUTDOWN CHJ ~ PP/51 SA -5148 R-7 PP/51~ 4- BOARDS. OTHER INSTRUMENTS ASSOCIATED WITH BACKUP CONTROL WILL BE LOCATED IN THE AUXILIARY CONTROL ROOM ON PANEL INDICATED ON THE DIAGRAM. PQY-51 SA D 6. LEVEL SWITCHES LS-1-200 THROUGH 209 ARE UTILIZED TO DETECT A LEVEL <( BUILDUP IN STEAM LINE TRAPS ANO ACTIVATE COMMON ANNUNCIATOR WINDOW. R-7 R-3 R-3 R-7 u CHANNEL F-511/513 CHANNEL F-510/512 EAGLE-21 CHANNEL P-514 LOCALLY MOUNTED INDICATOR LIGHTS XI-1-200 THROUGH 209 INDICATE WHICH LEVEL SWITCHES HAVE BEEN ACTUATED. STMFD LP1 STMFD LP1 LCP-99-0311 STM PRESS LP1 7. THIS INPUT TO THE PLANT COMPUTER REPRESENTS TOTAL STEAM FLOW FROM THE FM-3-358 FM-3-JSA PM-1-2A RESPECTIVE STEAM GENERATORS ATMOSPHERIC RELIEF VALVES. P-514 STM PRESS 9. COMPONENT IS NOT CLASS "1E" BUT IS CONNECTED TO CLASS "1E" POWER SOURCE.
- 10. SEE ELECTRICAL DESIGN STANDARD E18.3.3 FOR SYMBOLS DEFINITION.
11 THE CONTACT SIDE OF PSs FOR WATER HAMMER IS DISCONNECTED.
- 12. NOT USED.
- 13. REFER TO TABLE A1 FOR ADDITIONAL DIGITAL COMPUTER POINTS (POWER AVAILABLE, SWITCH POSITION, ETC.).
D/A D/A DAC- D/A DAC- D/A DAC- D/A 99-0315 99-0315 14. TO OBTAIN THE COMPUTER POINT IDENTIFIER FOR A CORRESPONDING EAGLE-21 99-0715 TEST POINT OR TVA UNID SEE TABLE 1 ON 1-47W610-99-6. E/I E/I 15. LOG E/I E/I P0496A R-3 R-3 E/I E/I CH2 CH1 R-7 R-7 R-7 R-7 FP/513D
~-+ t----,
R-7 FP/513A
~_J I
R-3 ~ FP/sµg__-=! I R-3 4--.JT FP/51~ FOXBORO DCS 1-47W610-98-8 COOR A-2 -PM-1-2A PY-514C R-3 A'jl_4 PY-514 R-3 Apl_4 CH2 PY-515C Ap]__,. CH1 PY-515 4-- 1 CH3 PY-515C1 I (FBM-98-Rl 95A03, CH 1) ~ -----7 PP/51~ I PP/51~ I R-7 PP/51 SC'i I R-7 PP/51~1
~-4 I LOG I
~-4 n:1iG7 I
,--,I PS/51 SA PS/515C
~
Fl-513 I
- F0406A FOXBORO DCS I Fl-512
~
1-47W610-98-8 COOR A-5 (FBM-98-R195A04, CH 1) 1-47W610-98-8A COOR A-4
-PM-1-28
~1 ----7 I I
I LOG I I I I ,---- I 1 I 68-25 I
)Ei---,--\J:7
__Lm 68-29 I __Lm
)Ei---,--\J:7
~:~:J LOG II (FBM-98-L984A01, CH 1) P0-1-00A I
_,.:_F~-_!::~~J
~:~]
1-47W610-98-2A COORD D-9 M-4~I P0401A I (F8M-98-L984A01, CH 2) (FBM-98-L981A05, CH 1) (FBM-98-L984A01, CH 3) i-- - 7 MPI -~ I 1-2 I PI-515 P2 L.!_-f_M.:_1.:_J_L ;~:~~:!~~::~!~/og~ 1 ~-7 LOGIC REF (FBM-98-L984A01, (FBM-98-L984A01, 1-47W610-98-8A COOR A-5 CH CH 4) 5) I I I PI-514 1-2 P1
,-----,I I L-38@
r-----+ LDG LDG 08F734235-FD-1104 I PI II M- PR~ P04050 P0402D (FBM-98-L984A01, CH 9) {FBM-98-L984A01, CH 10) ~-4 I 1-2D : 1-2P001 PT L-943 (FBM-98-L984A01, CH 11) I PI-514B I PR-515 IV 1-5 I PT-516 R-12 (FBM-98-L984A01, CH 12) (FBM-98-L984A01, CH 13) {FBM-98-L984A01, CH 14) 1-47W610-98-8A COOR A-8 7 I L _________ _J I I I t------ CH1 (FBM-98-L984A03, CH 1) I _ _ _ _ _ _ _ _ _ _ _ _ _ _JI REFERENCE DRAWINGS: PQ-516 {FBM-98-L984A03, CH 2)
- _...J 47W400-1 THRU -------------- MECHANICAL MAIN STEAM PIPING (FBM-98-L984A03, CH 3) 1-47W801-1 --------------------- MAIN AND REHEAT STEAM FLOW DIAGRAM 478601 SERIES ---------------- INSTRUMENT TABULATIONS 1-47W610-98-8 COORO A-11 ,.!_P mmooo*-------------------~ 1-47W611-1-1 AND ----------- ELECTRICAL MAIN STEAM LOGIC DIAGRAM (FBM-98-R195807, CH 9) 47W427-1 THRU -------------- MECHANICAL AUX FEEDWATER PIPING 1-47W610-98-8A COORD C-5 1-47W610-90-5 ------------------ ELECTRICAL RAD MON CONTROL DIAGRAM (FBM-98-L984A05, CH 1) 1:._PCV-1-5 108D408-SERIES (CONTR 54114-1) - PROCESS CONTROL BLOCK DIAGRAM (EAGLE 21)
--7 EAGLE-21 (FBM-98-L984A06, CH 1) 478601-55-SERIES --------------- INSTRMENT TABULATIONS (TRIP STATUS LIGHTS)
LCP-99-1211 478601-99-SERIES --------------- INSTRUMENT TABULATIONS 1-PM-1-5 1-47W610-98-8 COORD A-7 (FBM-98-R195805, CH 1) 1-47W610-99-SERIES ------------- OICC' S I NCORP OICC-0805 REACTOR PROTECTION SYSTEM CONTROL DIAGRAMS SYMBOLS: P-516 LOGIC REF FOR EAGLE 21 SYMBOLS, SEE 1-47W610-99-1 08F7 34235-FD-1300 OICC-0785 STM PRESS OICC-0784 OICC-0779 OICC-0778 OPEN ITEM OICC-0651-INCORP (ECN 6396 IN PROCESS) TABLE A1
,-----------------+--7
© I INSTRUMENT ID DIGITAL COMPUTER POINTS POINT IO DESCRIPTION E/1 I (E!]~-11B I AUX R-12 I©: XS ~-11A FEEDWATER 1-FCV-001-0015 FD2048 AUX FWPT STM SUP FROM SG1 FCV CH1 PY-516A I ~-4 I HS jr 1-6 XS 1-6 A PUMP TURB 1-FCV-001-0015 FD2047 AUX FWPT STM SUP FROM SG1 FCV
- 1-6 - I r----- IZI 1-FCV-001-0016 FD2050 AUX FWPT STM SUP FROM SG4 FCV I [2] d.iill L __ ...
I 1-FCV-001-0016 FD2049 AUX FWPT STM SUP FROM SG4 FCV I L-~.J 1-FCV-001-0017 F02046 STEAM FLOW TO AUX FWPT ISO VLV FEEDWATER CONTROL (1-47W610-46-1,COORD G-6>--- 1 -HS-001 -0017 A HD2003 STEAM FLOW TO AUX FWPT ISO VLV 1-FCV-001-0017 FD2045 STEAM FLOW TO AUX FWPT ISO VLV FEEDWATER CONTROL
-----------<1-47W610-46-1 ,COORD H-6) 1-FCV-001-0018 FD2198 STEAM FLOW TO AUX FWPT ISO VLV
©: 1-HS-001 -001 SA HD2037 STEAM FLOW TO AUX FWPT ISO VLV m LDG _[j]D {rs) ~ M-4 1-FCV-001-0018 FD2197 STEAM FLOW TO AUX FWPT ISO VLV 0 1-FCV-001-0051 FD2350 STEAM FLOW TO AFPT
- -- F9049A - - - ~ ~~--:?8 '?A (1-47W610-1-3A,
§ : I fi"{_ I 1-FCV-001-0051 FD2349 STEAM FLOW TO AFPT 1-17 :----------r--------+--- -~- __ J STEAM LOG
[2]@xR-137 i © 1JBl
~
PD2D02 GEN NO. 1 1-17 fT\ W ~c RE 90-421 ~--YA ___L___ /xs't__ J
~-4 UFSAR AMENDMENT 3
.~,
©1:
WATTS BAR MAIN STEAM SYSTEM FINAL SAFETY i ,<£11-47W61~0-1-1'. 1 ~'.@00RD~~'. 1-47W610-1-2A,COORO F-8 ANALYSIS REPORT
......... I 1 XS XS J;.,c;;:;t 1 1-4 i 1-4
,!U_)!U~[Z] I [2]1 [.iii POWERHOUSE LAY UP WATER TREATMENT M-4 6D__~--l...-L-l-.------ L___ l © : [ill UN IT 1
~ I I VENT
/1\ -- -L- _/xs\". _ (HS\M-4 1-47W862-1 .COORD C-3 OR 1-47W830-6 COORD 88 &. D8 [2][.iil : 0--, : W--7
~
ELECTRICAL STEAM GEN SLOWDOWN 1-47W610-15-1,COORD A-1 FROM STEAM GENERATOR LOOP 2 1-47W610-1-1A,COORD F-1 l@s ~s, L 1-4D I 1-4
,~-~
'* CONTROL DIAGRAM
~C MAIN STEAM SYSTEM I ---------- COMPANION DRAWINGS:
[.iii: [2] I 1-47W610-1, -1A, -2, II
~-------------------------------------
-@ H 1-4J VENT -2A, -3, &. -3A, 4 TVA DWG NO. 1-47W610-1-1 R38 FIGURE 10.3-2
-576 r.!l -------------------------7 -----------------------7 NOTES:
z I 4
- s
< -196 Ct: T A EAI-99-0701 (CH3) 2. THE MAIN STEAM ISOLATION VALVES (FCV-1-4, FCV-1-11, FCV-1-22, AND II PQY-515A FCV-1-29) ARE ACTUATED BY HI-HI CONTAltt-lENT PRESSURE, STEAM LINE BREAK, w - +-- - - OR MANUALLY. z I --j2-+7W610-1-1. COORD A-2) < ,-------------------------~ 1/E I J. THE POWER RELIEF VALVES (PCV-1-5. PCV-1-12. PCV-1-23 ANO PCV-1-30) ARE OPERATED EITHER MANUALLY FRCM THE MAIN CONTROL ROCM OR AUTCMATICALLY 1- I/E FRCM THEIR ASSOCIATED INSTRUIIENT FAMILIES (PT-1-6. PT-1-13, PT-1-24 z R-7 Apl..... AND PT-1-31). PP/515~ -4. THE STEAM DUMP VALVES (FCV-I-103 THROUGH FCV-1-1I-4) ARE CONTROLLED
- AUTOMATICALLY FROM THE TURBINE IMPULSE CHAMBER PRESSURE AND MAIN STEAM HEADER PRESSURE. EACH DWP VALVE HAS POSITION INDICATING LIGHTS IN THE R-7 R-3 R-3 R-7 MAIN CONTROL ROC...
CHANNEL F-511/513 CHANNEL F-510/512 EAGLE-21 CHANNEL P-51-4 EAGLE-21 CHANNEL P-515 u sr-..=-o LPl SHED LP1 LCP-99-0311 STM PRESS LP 1 LCP-99-0711 STM PRESS LPl 5. INSTRWENTS ASSOCIATED WITH BACKUP CONTROL AND MARKED WITH AN ASTERISK l*) WILL BE LOCATED ON THE APPROPRIATE -480-V MDV 6.9-KV SHUTDOWN PM-1-2B FM-3-35B FM-J-JSA P-514 PM-1-2A
~~ 1 ~RESS~=.,.:;.;= BOARDS. OTHER INSTRUMENTS ASSOCIATED WITH BACKUP CONTROL WILL BE STM PRESS LOCATED IN THE AUXILIARY CONTROL RCl'.M ON PANEL INDICATED DN THE DIAGRAM.
- 6. LEVEL SWITCHES LS-1-200 THROUGH 209 ARE UTILIZED TO DETECT A LEVEL BUILDUP IN STEAM LINE TRAPS ANO ACTIVATE Cct,NJN ANNUNCIATOR WINDOW.
LOCALLY K>UNTEO INDICATOO LIGHTS Xl-1-200 THROUGH 209 INDICATE WHICH LEVEL SWITCHES HAVE BEEN ACTUATED.
- 7. NOT USED
- 8. NOT USED
- 9. THIS INPUT TO THE PLANT C~PUTER REPRESENTS TOTAL STEAM FLOW FRCM THE RESPECTIVE STEAM GENERATORS ATMOSPHERIC RELIEF VALVES.
- 11. SEE ELECTRICAL DESIGN STANDARD EIS.3.3 FOR SYMBOLS DEFINITION.
R-3 E 1J. NOT USED. R-7 /EAO-I~ E/I R-7 R-7
~~~mc1I CH2 99-0713 CHI CH3 H. TO OBTAIN THE CCMPUTER POINT IDENTIFIER FOR A CORRESPONDING EACLE-21 PY-515C PY-515 PY-515CI TEST POINT OR TVA UNID SEE TABLE 1 ON 2-47W610-99-6.
I HS I
~*l**sa-i ~*/*1~i -2 Hi. NOT USED.
6B-1
~+~ m-t 6B-5 LID.
I II I I PS/51 SA 611;35 _j_ ~ m-611;39 m-PS/515C _j_ ~
- 16. COMPONENT IS NOT CLASS "1E" BUT 15 CONNECTED TO CLASS "IE" POWER SOURCE.
-~*
--G7 --G7 2-L-11A I 'CI? I 'CI?
~- - 7 ,-,£-:;" - - 7 L ___fxi.;\_ FOXBORO DCS ~pM - r-+ ~--7 ,...£-:;"--7 FOXBORO DCS
*- 2-471610-98-8,COOR0 C-2 (FEIM-98-RI 4,1001,CH 1) ~6B-11~6AI rn6e-,2~0A 1 ~
2-471610-98-15,COORD 8-6 (FEIM-98-L906A0-4,CH -4) 2-471610-98-15A,COORO E-5
- ~: ~6B-11~6AI rnse-12~0AI
,- - i~:::::~1:m:g~ n 2471610-98-8B,COORD E-4 (FBM-98-M018I05,CH I)
LOG P0404D LOG P0-4010 IZI (fEIM-98-L916B07 ,CH 1) 2-471610-98-15,COORD 9-11 (FEIM-98-L906906,CH 1) II 7 I L __/pj"\ L-10 l--7
@M-41 LOG P0405D LOG P0402D 1
~-*
2471610-98-8B,COORD E-4 (FBM-98-M018!03,CH 1) CFEIM-98-MOI SIOJ,CH 2)
,- - 2-471610-98-15,COORD (FEIM-98-L916A03,CH (FEIM-98-L916A03,CH (FEIM-98-L916A03,CH G-2 5) 6)
7)
~
r----...l
,~~roo,I I REFERENCE DRAWINGS, 2--471-400-1 THRU ------------- MECHANICAL MAIN STEAM PIPING 2--471801 - - - - - - - - - - - - - MAIN AND REHEAT STE FL DIAGRAM
~
(FBM-98-M018I03,CH 3) 1 ml 2--471611-1-1 AND ------------ AL MAIN STE L C DIAGRAM PT L-102 (FEIM-98-M018I03,CH 4) 2-471610-98-15,COORD D-2
!1 2--471-427-1 THRU ------------- AL AUX FEED IPING 1-5 I I
(FEIM-98-MOl 8103,CH 5) 2471610-98-8B,COORD E-4 (FBM-98-M018!03,CH 9) FOXBORO OCS 2--4716I0-98-8,COORO C-5 (FBM-98-R1-41D02,CH 1) f1f 10 (FEIM-98-L916A02,CH (FEIM-98-L916A02,CH (FEIM-98-L916A02,CH 1) 2)
- 3) ~: 2-471610-90-5 -------------------
l~~~:gf;;~~:!~~Rrn~N~~-~~?:~?:~::::: CAL RAD MON fil~ ~i~rng~I~~ DIAGRAM
~lQGMllT~~tGbiAmMS L_
- <FBM-98-M018ID3,CH 101 (FBM-98-M018ID3 ,CH 111 (FBM-98-M018I03,CH 12I (FBM-98-M018IOJ.CH 13)
LOGIC REF 08F802403-FD-2300 I I CFBM-98-L916A02,CH (FBM-98-L916A02,CH 2-471610-98-15,COORD (FBM-98-L916A02,CH
-4) 5)
D-2 9) I I FOXBORO DCS 2--47W610-98-8,COORO C-7 SYMBOLS: FOR EAGLE 21 SYMBOLS. SEE 2-47W610-99-1 (FBM-98-M018IOJ,CH 14) (FBM-98-R1+1DD3,CH 1) I EAGLE-21 R-12 2-471610-98-SA.COORD D-8 (FBM-98-R125A08, CH 5) 2-471610-98-8B,COORD C-10 (FEIM-98-M01 BH07 ,CH 1) f,- 2-PS-1-6
---------7 I
L_
- (FBM-98-L916A02,CH CFBM-98-L916A02,CH (FBM-98-L916AD2,CH (FBM-98-L916A02,CH 10) 111 12) 13 I LOCIC REF 08F802+03-FD-2300 CHANNEL P-516 I (FBM-98-L916A02,CH 1-4)
LCP-99-1 211 STM PRESS LP1 (FEIM-98-MOI BHOB CH 1) PM-1-5 I LOGIC REF I LOGIC REF 08F80240J-FD-2300 08F8D24D3-FD-2950 I P-518 r--- STM PRESS E/I R-12 CH1 PY-516A _ _ _ _ _ _ _ _ _ _ _J HS A._
-~
R-12 l-5 FEEOWATER CONTROL PP/51~ I PS/516C 2-47W610-46-1 ,COORD G-6 / - - r~ IFi:aAI 60-11 I ~ L_ ------------7 FEEDWATER CONTROL I FOXBORO DCS
--------12-47W610-46-1,COORD H-6 I
~T'CI?
r.k-,
~ JC-590 L---7 I
I r-----------------~-- 2--471610-98-11B,COORD B-J (FBM-98-R1J7A03,CH -4)
~~
I.~~2AI: I riJiii7 I t:E:IIfilse-12~0*
~-----@:~1:_a~~
1-5 1-5 m
~
mm
~
~
r
~
~
~
__ _J 1
~
9 1 Y, ~~ 7B @s
-17A M-<
LOGIC REF 08F 802+0J-FD-2896
@' r----
0 LOG P040JD
§ ~8 §
. " -' --------~------L--~s*_J
~m m O< <
<2-HW610-1-JA. COORD A-7 r n I 1-H CISP I I I I G
~~
M-6 E-J.
-~
c,o z-W 0 r
"'~. ..
0 IZI /T\ t:rJ ~@GR HS* 7
~~ z ~ 1 1-17C STEAM GEN M-+ <
U>N
" N' NO. 1
~~1*1 IZlwill ('09 ~ ~~GHS~ -4 L-118 I Yxs\_ __ +_-1:D.. y~--"1 1-lBA
~ ,JJ rev ,----1---~
r---L-11A --------- I wl~~
@s $ _, I ~
AMENDMENT I ____f'xs"\ FCV LS 1-200 )O!(
>;,(.
M-+~s* 1-l5A - -1 --*- will rt\,I ~~ HS* t"\l..:!.ai 1-1 will '\IJ FCV iI _"\t:;.9CI _/xl\ ~~~ I -18C WATTS BAR 1-181 HS
- I I MAIN STEAM SYSTEM L----J..>-1,,"1--+i4""----<:Z:2-~*[z1~16!]120-~1~-~2At.'.QGOORQ!!J~D]F:C:-sv FINAL SAFETY r ~ 3C-58E 1-1 SC L_...r::TI&J ANALYSIS REPORT I t:EEJ ~
FOXBORO OCS I SEE NOTE 6 IZI I 2-471610-98-BA,COORD B-2 L~~- 9R8E~Rl 2 SAOl,CH S) r-T ___ ....J FLOOD MOOE BLOWOOIN VENT POWERHOUSE L oeFao2+0,-Fo-2as6 __ J ~ FROM STEAM GENERATOR LOOP 2 r---------L-....lL...-.L-.L-<J2::;-*~1:!*i61[!0[::-1[:-}1IA,1c]!oo!i!R!QDJF'.:-]1 UNIT 2 ELECTRICAL STEAM GEN BLOWOOIN
-471610-15-1 COORO B-2 VENT COMPANION DRAWINGS:
2-HW610-1-1A, -2. CONTROL DIAGRAM
-2A, -3, & -3A, 4 MAIN STEAM SYSTEM TVA DWG NO. 2-47W61O-1-1 R36 FIGURE 1O.3-2(U2)
NOTES:
- 1. FOR GENERAL NOTES SEE 1-47W610-1-1.
,-----------------7 ,------------------7 ,----------------------7
,------------------------------7 : ~:i=~9:g:2 (CH 3)
- ~:i=~g:g~02 CH J I
I R-12
- 2. ALL COMPONENT UNIT PREFIXES ARE UNIT 1 UNLESS OTHERWISE NOTED.
J. TO OBTAIN THE COMPUTER POINT IDENTIFIER FOR A CORRESPONDING EAGLE-21 I
-P~T_-~1-~2~7A ~ - - - - ,
---<(!-47W61D-3-2A,COORD A-51
- - - - - , - - - - - - - ~ 1-47W610-3-2A,C00RD A-2) R-8 CH2 -----~------~1_-4_7_W_61_D_-,_-_2_A_,c_oo_,_D_D_-~2
,------- CH2 PQ-546 TEST POINT OR TVA UNID SEE TABLE 4 ON 1-47W610-99-6.
1 PQ-545 I I FOXBORO DCS PP/s:5~ 1-47W610-98-11A COORD 8-2 (FBM-98-L985801, CH 1) EAGLE-21 CHANNEL P-544 R-4 R-8 EAGLE-21 R-12 CHANNEL P-546 1 (FBM-98-L985801, CH 2) (FBM-98-L985801, CH 3) (FBM-98-L985801, CH 4) R-4 LCP-99-0411 STM PRESS LP4 EAGLE-21 CHANNEL P-545 LCP-99-1211 LCP-99-0811 STM PRESS LP4 I (FBM-98-L985801, CH 5) P-544 PM-1-27A STM PRESS LP4 PM-1-30 EAGLE-21 CHANNEL F-540/542 P-545 PM-1-278 I 1-47W610-98-11A COORD 8-3 LCP-99-0411 STM PRESS STMFD LP4 STM PRESS (FBM-98-L985801, CH 9) FM-3-103A (FBM-98-L985801, CH 10) (FBM-98-L985801, CH 11) D <( (FBM-98-L985801, CH 12) u (FBM-98-L985801, CH 13) (FBM-98-L985801, CH 14) I 1-47W610-98-11A COORD 8-6 L __ (FBM-98-L985803, CH 1) D/A D/A (FBM-98-L985BOJ, CH 2) D/A D/A (FBM-98-L985BOJ, CH 3) E/1 E/1 R-4 R-4 E/1 E/1 CH4 CH3 R-8 E/1 PY-544C PY-544 CH4 PY-545C R-44 I LOGIC REF I I P/544C '-'-!T j 08F734235-FD-1303 R-44---4 R I FP/542D~ I FP/542A~ I I
~"-4
>-----7 I
I I I 'I I
\8sAFI-542 I I
I I I I L"!..::~~~ FOXBORO DCS 1-47W610-98-5A COOR D-9 (FBM-98-L981 05, CH 1)
@ I M-4 A
PI-544A 1-47W610-98-5A COOR D-6 1-FM-1-288 (FBM-98-L981D06, CH 1) ---7 1] LOGIC REF 08F734235-FD-1104
,-----------7 PT-1-278 FOXBORO DCS 1-47W610-98-12A COOR C-1 I
,--<1-47W610-3-2A,COORD A-71 (FBM-98-L983E01, CH 1)
I (FBM-98-L983E01, CH 2) I I 1/E g* (FBM-98-L983E01, CH 3) (FBM-98-L983E01, CH 4)
~R-8
-VPP/545A 1~-7 (FBM-98-L983E01, CH 5) 1-47W610-98-12A COOR C-3 R-177 I 4 (FBM-98-L983E01, CH 9)
I (FBM-98-L983E01, CH 10) EAGLE-21 LCP-99-0811 R-8 CHANNEL F -541 /543 STMFD LP4 FM-3-1038 I I (FBM-98-L983E01. CH 11 l (FBM-98-L983E01, CH 12) (FBM-98-L983E01, CH 13) (FBM-98-L983E01, CH 14) 1-47W610-98-12A COOR C-4 r--~- 1 I I ~1D 0 (FBM-98-L983E03, CH 1) z
- @I I XI
"-4 (FBM-98-L983E03, CH 2)
(FBM-98-L983E03, CH 3) 1-47W610-98-12 COOR E-8 _1, TS001 OOJ3A --ffi
~,c-~- z w
~
1
- 1-33 (FBM-98-R196805, CH 9) I I 1-47W610-98-12 COOR E-8 _1 :i:,;~0_1,0_1c,2~@ 2 I TURBINE R-l~-+
I I (FBM-98-R196805, CH 10) 1-47W610-98-12 COOR E-8 (FBM-98-R196805, CH 11) f-- 1 TS001 00330 --ffi L--~- 1-47W610-98-12 COOR E-8 _1 :i:,;_1co_1,0_1c,2~@ 2 : E/1 IMPULSE PRESS I (FBM-98-R196805, CH 12) R-8 CH4 FY-543A EA0-99-0414 (CH5)
~-47W610-1-3A COOR H-7}-...J I 1-47W610-98-12 COORD A-7 (FBM-98-R196A04, CH 1) i--
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I L-183 610-1-1, COORD G-10 I L_ B FT-543 N61s0T_E,A_M2AH,s-da-;R9DA H-7 L___________ II PT-545 "' STEAM GEN N0.4 L-940 r-------- 1
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I ~ UFSAR AMENDMENT 3 0
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L-l,A 1-47W610-43-5,COORD A-12 (xs"\ L -11 8 ~A ~8 t- q:~ ~ ,.-~'
~ ~ y2 y84 r- ____________'Y'0 ..._ ____'Y~ ....__r--L I WATTS BAR
~~! ___ +I ____ t_ 7 SAMPLING FINAL SAFETY
~184 I I 1-47W610-43-5,COORD A-12 I i--0 I I
[2Hiiil : : ~ (HS\ _J : 36" STEAM HEADER ANALYSIS REPORT
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I I COMPANION DRAWINGS: r ________ _JI I 1-47W610-1-1, 1A, 2, 3, 3A, 4 UN IT 1 L _____ _ ELECTRICAL
~ L_______________
1 I L_ S -4 1-29A I I~ cj I I L ____________________________ _ ZS 1-29F ___ ...J VENT I CONTROL DIAGRAM MS TO FCV-15-212 0 [:;jji I5 I M-6 ~ r---1---- MAIN STEAM SYSTEM TEST CONN TVA DWG NO. 1-47W610-1-2A R25
!~ J 1-47W610-1-1, COORD G-J
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R-4 LCP-99-0411 P-544 STM PRESS LP4 PM-1-27A LCP-99-1211 I 2-471610-98-12C,COORD G-J EAGLE-21 CHANNEL F-540/542 (FBM-98-M018NOJ. CH 1) LCP-99-0411 STM PRESS STMFD LP4 C (FBM-98-M018N03, CH 2) FM--J-103A (FBM-98--ti<<)18N03, CH 3) (FBM-98-M018NOJ, CH 4) (FBM-98-M018N03, CH 5) IL __ 2-471610-98-12C,COORD G-J (FBM-98-MOl BNOJ, CH 9) (FBM-98-M018N03, CH 10) (FBM-98-M018NOJ. CH 11) (FBM-98-M018N03, CH 12) DDC- (FBM-98-M018N03, CH 13) 99-0814 (FBM-98-M018N03, CH 14) R-4 R E/1 CH4 E/1 EAO-~ R-4 99-0413 CH3 0/0 R-8 E / EAO-1 § R-8 ~~~ E/1 tr~~:~~-:18 2~~6~i~ ~,1 1 ~- PY-544C PY-544 CH4 PY-545C 99-0813 CH3 PY-545 1r:~;~~-:1 82~~6~t~ fo~I ~ I R-4..4.l_-t R-44--.J PP/544--.:.:.r I ~8-4 8-8 *-*A_-t PP/S45C~
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- Id l1 FOXBORO DCS 2-+7W810-98-11,COORO C-9
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';I FOXBORO DCS sHmW=iast 08F802403-FD-2006 L- (FBM-98-R124AD1, CH 1) "'L- 2-47W610-98-11,COORD D-9 PT-1-278 (FBM--98-R124A02, CH 1)
LOGIC REF LCCIC REF 8 FOXBORO DCS r--<2-+7W610-1-2A,COORO A-71 r---------- OSFS02403-F0-230J _ _ _ _ _ _ _ _ _J ,. 2-47161D-98-16,COORD B-6 08F802403-FD-2303 I (FBM-98-L907A04,CH 5) _ _ _ ____/pi\L-10 FOXBORO DCS c2r:~~~ t~t :ta~ ~) 1 1 5
-- 2-471610-98-11,CCXJRD D-7 (FBM-98-Rl 24A03, CH 1 I 2-47W610-98-11B,COORD E-9 2-471610-98-16,CIJJRO B-11 (FBM-98-L907806,CH 2) -
f- '\!38C FOR MANUAL NITROGEN CONTROLS SEE I F8M-98-M01 8M05, CH 1 ) (F8M-98-M018M05, CH 2) lr3L!\ a--cC1 i&,c~~l~ g;2 10 DWG 47W600-221 B EAGLE-21 LCP-99-0811 r ( FBM-98-MOI 8M05, CH 3) (FBM-98-L916C03.CH (FBM-98-L916C03 ,CH 6) 7) I 2- 71610-98-118,COORD (F8M-98-M018M03, CH 1) E-3 0 2-471610-98-16,CCJllm D-2
~--
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~ ( FBM-98-MOI 8M03, CH 2) (FBM-98-L916C02,CH 11 CFBM-98-M01 8M03, CH 3) (FBM-98-L916C02,CH 2)
A ( FBM-98-M01 8M03, CH 4) (FBM-98-L916C02,CH 3I ( FBM-98-MOl 8M03, CH 5) (FBM-98-L916C02,CH 41 2-47W610-3-2C,COORO 0-4 (FBM-98-L916C02,CH 5) I 2- 71610-98-118,COORD E-3 2-471610-98-1&,caJm 0-2 ( FBM-98-MOl 8M03, CH 9) I L
- (F8M-98-M018M03, CH 10)
I F8M-98-M01 8M03, CH 11 l ( FBM-98-M01 8M03, CH 1 2) (FBM-98-M018M03, CH 13) FBM-98-L916C02,CH tFl:i~:t~1~~8~:8U 1?1 ff:J:it:~:aggt2u ni 91 (FBM-98-M018M03, CH 14) (FBM-98-L916C02,CH 14) LOGIC REF 2-471610-98-118 COORD B-10 ~ 08F802+03-FD-2953
<FBM-98-R137A07. CH 5) 2-471610-98-118,COORD E-11 IFBM-98-M018M07, CH I)
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iL _______________ _ L -------- L ______ _ NOTES:
- 1. FOR GENERAL NOTES SEE 2-471810-1-1.
L __________________________________________ _ ---------------------------7 2. ALL CCN>artENT UNIT PREFIXES ARE UNIT 2 UN...ESS OTHERWISE NOTED. 1------------------------7 3. TO CETAIN THE CCll"UTER POINT IDENTIFIER FOR A CORRESPONDING EAGLE-21 TEST POINT OR TVA UNID SEE TAII..E 4 ON 2-47W610-99-6. L... 7 I p I I ES I L_ IL __________ II _ L-940
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Cl z ,--------------- 7 LPF-1-218
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,---i!-47W610-1-2,COORD A-9)
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FEEOWATER CONTROL 1-47W610-46-4, COORD 8-6 NOTES:
- 1. FOR GENERAL NOTES AND REFERENCE DRAWINGS SEE 1-47W610-1-1.
- 2. ALL COMPONENT UNIT PREFIXES ARE UNIT 1 UNLESS FEEOWATER CONTROL OTHERWISE SPECIFIED.
I I ( 1-471610-46-4, COORD 8-6 >-7 3. TO OBTAIN THE COMPUTER POINT IDENTIFIER FOR A CORRESPONDING EAGLE-21 TEST POINT OR TVA UNIO I SEE TABLE 3 ON 1-47W610-99-6. L---4-- FCV FEEDWATER CONTROL : 1 _ 39 --{1-471610-46-J, COORD B-6) : FCV FEEDWATER CONTROL I l-JB --<1-47W610-46-J, COORD B-6) L FEEDWATER CONTROL (1-47W610-46-4, COOR D-6 }--7 I FEEDWATER CONTROL I LOGIC REF 08F73+235-FD-1302 ( 1-47W610-46-4, COORD D-6 }-7 I I FEEDWATER CONTROL : I TO STEAM DUMP
--{1-47W610-46-J, COOR 0-6) I 1-47W610-1-3 COORO F-4 I
FCV FEE WATER CONTROL I 1 _ 36 --{1-471610-46-J, COOR 0-6) L
---f l-33 PT I 1-48~
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I I:1-R-125 ~_X - ....., I 1 160 I I I I I I UFSAR AMENDMENT 3 I TEST CONN. I I I MAIN STEAM TO HP TURB 1-47W610-1-3A, COOR B-5 WATTS BAR I I VENT MAIN STEAM GEN FINAL SAFETY I I L_ NOS. 1, 2, 3 1-47W610-1-2A, COORD 0-10 ANALYSIS REPORT 1 POWERHOUSE VENT UN IT 1 ELECTRICAL COMPANION DRAWINGS: 1-47W610-1-1, 1A, 2A, 3, 3A, 4 CONTROL DIAGRAM MAIN STEAM SYSTEM 1-47W862-1, COORD C-3 OR 1-47W830-6, 88 & D8 TVA DWG NO. 1-47W610-1-2 R32 FIGURE 10.3-3
() PT-1-20A PT-1-208 LPF-1-21A LPF-1-218 z ,--------7 r------------7 EAI-99-0401 ICH 3) r-----------7 EAI-99-0702 ( CH 3) ...... r--i2-47W610-1-2,COORD A-7) r--i2-47W610-1-2,COORO A-9>
- - - - -t2-47W610-1-2,COORD A-2) - - - --t2-471610-1-2,COORD A-4)
I/E I/E I/E I/E a::: R-4.Apl._ [ ~ R-4 R-7.A__ ____J:::,.,.R-7 R-4A_ R-7.....:L C, FP/5328~ PP/5J4A FP/5338~ ----i:,v-PP/535A PP /534B ~ PP/5358-.....:..:::r-C, w R-4 R-7 R-4 R-7 z EAGLE-21 CHANNEL F-530/532 EAGLE-21 EAGLE-21 CHANNEL P-534 EAGLE-21 CHANNEL P-535 ...... LCP-99-0411 Sll.FD LPJ LCP-99-0711 CHANNEL F-531/533 STt.FO LP3 LCP-99-o+ 11 STM PRESS LP3 LCP-99-0711 STM PRESS LP3 < FM-J-90A FM-3-908 P-534 PM-1-20A P-535 PM-1-208 EAGLE-21 1- STM PRESS STM PRESS z LCP-99-1111 ...... P-536 STM PRESS
- IE FM-3-90A FM-3-908 C, 2-471610-J-2A,COORD 0-5 2-471610-3-V.,CXIORD 0-u 0/A 0/A E/I E/I E/I E/I R-4 R-4 R-7 R-7 CHS CH2 CHO CH4 fY-532D FY-5J2A FY-SJJO FY-5JJA E /EAO- I ~ R-11 0/0 R-7Api_ 99-1115 CH2 FP/5330~1 PY-536A r _____ _j I ff!},-*
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! 1-23 ~POD1 PR-536 r 2-47W610-98-15A,CXXR> E-8 FBM-98-L916806 CH 8 2-471610-98-15,COCRD 8-11 (FBM-98-L906B06,CH 2) REHEAT STEAM FROM 2-471610-1-4, COOROA-5 lF~!\~°:~81ilb~~ f1 2 (FEIM-98-L916A0J,CH 2)
(FBM-98-L916A0J,CH J) 2-471610-98-15,COORD D-4 p p (FBM-9S-L916A01,CH (FBM-98-l916A01,CH (FBM-98-L916A01,CH 11 21 3I TEST FEEDWATER CONTROL 2-4'71610-46-4,, COORD B-6 l- -7TEST NOTES: 1
- FOR GENERAL NOTES AND REFERENCE ORAIINGS SEE 2-+7W610-1-1.
- 2. ALL CCMPONENT UNIT PREFIXES ARE UNIT 2 UNLESS (FBM-98-L916A01,CH 41 IFBM-98-l916A01,CH 2-471610-98-15,COORO 51 D-4 FEEOWATER CONTROL 2-471110-46-4, COORD 8-6 l-i III OTHERWISE SPECIFIED.
- 3. TO OBTAIN THE Cot.f'UTER POINT IOENTIFIER FOR A CORRESPONOING EAGLE-21 TEST POINT OR TVA UNID L (FBM-9a-L916A01,CH (FBM-98-l916A01,CH (FBM--98-L916A01,CH 91 10) 11)
_jFEEOWATER CONTROL 7 2-4-71610-46-3, COORD B-6 II SEE TABLE 3 ON 2-471610-99-6. IFBM--98-L916A01.CH 12) (FBM--98-L916A01.CH 13) (FBM--98-L916A01.CH 14) _jFEEDWATER CONTROL L LOGIC REF 08f80240J-FD-2952 7 2-47161D-46-3, C00RD B-6 L-3188 b. FEEDWATER CONTROL 2-471610-46-4, COORD D-6 j L7 UQiD_ _/zr'\__ _/ZE\ I
~-'133--~3 FEEDWATER CO.TROLh I 2-471610-46-4. COOR() D-fi I
_j FEEDWATER CONTROL I TO STEAM OLWP 7 2-411610- 6-3. C<XR> o-6 I 2-471fi10-1-3 ~D G-4 I _jFEEDWATER CONTROL L 7 2-471610-46-3, COORD 0-6 FOXBORO DCS 2-471610-98-11,COORD B-9 p CFBM-98-R124A01 CH 5) TEST LOGIC REF 08F802403-FD-2896 SAMPLING 2-471610-43-1, COORD B-3 w zu 0< C, _, STEAM zc... GEN < N0.3 rnz
-----r-1 I
I I UFSAR AMENDMENT I TO KlISTURE SEP Al ,81. I. Cl
+--
1 2-471610-1-4, COORO 0-1 WATTS BAR I I MAIN STEAM TO HP TURB FINAL SAFETY I I VENT 2-47161~1-3A, Co:JtD B-5 MAIN STEAM GEN ANALYSIS REPORT I NOS. 1, 2, 3 L 2-47181~1-lA. COORO D-12 SAMPLING 2-471610-43-5 COORO 8-9 POWERHOUSE VENT UNIT 2 fis\ ELECTRICAL
\!;PO will CONTROL DIAGRAM CCMPANION DRAWINGS:
MAIN STEAM SYSTEM 2-471810-1-1, 1A, 2A. J. JA, 4 TVA DWG NO. 2-47W61O-1-2 R35 FIGURE 1O.3-3(U2)
(.!) z a::: C, ( 1-47W610-1-1. COOR0 F-7 ) ( 1-47W610-1-IA. COOR0 0-9 ) I I I I I I I I C, I I I I I w z !§~§!§!§!§ ~§~§~§~§~§ NOTES: < ~~ ~~ ~~ ~~ ~~ g-177 ~~ ~~ .!.~ ~~ ~~
- 1. FOR GENERAL NOTES SEE l--47W610-1-I.
- 2. THIS EQUIPMENT INTERFACES WITH THE REACTOR SOLID I-z
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- E ~~ ~~ ~~ ~~ ~~ I ~~ ~~ ~~ ~~ ~~ R-177 SEE TABLE 5 ON 1--471610-99-6.
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CHANNEL P-505 EAGLE-ZI TURB I ... PR PM-1-72 ~
~ ~ ~ ~
LCP-99-<H-11 TURB IW' PR PM-1-7J FOXBORO DCS 1--47W610-j8-6 COORD G--4 (FIM-98-R19J008, a-t 8) LOGIC REF 015F7J-4235-F0-1012 Oil PY-508A1 N E/1 EAO-~ 99-0414
~H1 E/ls**
PY-50 5D EAO-99--0414 cH5 PY-505A 0/ll R-+ CHJ PY-505A1
~-t TP I PP/5050 II R-4 A...JI PP/505A'<,r
~ I WATTS BAR
~ FINAL SAFETY
@*-* 7 Pl-505 /
)I ROO OONTROL ANALYSIS REPORT
~ ~~6~~1-2A}
~*~~~oo=*o~oc~s~==~~---~
1--471610-98-7 COORD D-2 ~ /
/
POWERHOUSE (FBM-98-R19-4COI. CH -4) 1--471610-98-6 COORD D-2 ~ ~ 00 /
/
UN IT 1 (FBM-98-R19JDOI, CH I) 1-1-71610-98-7 COORD D-+ ,~~- ______________________________________ J T2301A // ELECTRICAL (FBM-98-R19-4C02, CH -4) PT-+7-13 CONTROL DIAGRAM 1--471610-98-7 COORO A-3 (FBM-98-R19-4AOJ, CH 1)
- - --<1-47W610-47-2 COOR0 C-4! MAIN STEAM SYSTEM LOOIC REF 08F7~42~5-FD-1202 TVA DWG NO. 1-47W610-1-3A R8 08f7J-4235-FD-101 2 FIGURE 10.3-4 SH A
() z ...... ( 2-47W610-1-1, COORD F-7 ) a::: ;:; i ;:; i ~ i ;:; i ;:; i
~~~~~~~~~~
C, NOTES:
- 1. FOR GENERAL NOTES SEE 2-47W610-1-1.
C, w ;:;
- 2. THIS EQUIPMENT INTERFACES WITH THE REACTOR SOLID z STATE PROTECTION SYSTEM AND IS SUBJECT TO
...... I I I I I AU~NTED QA REQUIREMENTS PER N3--47-4002
- 1-0 z
0 z 3. TO OBTAIN THE CCM"UTER POINT IDENTIFIER FOR A CORRESPONDING EAGLE-21 TEST POINT OR TVA UNID z SEE TABLE 5 ON 2--471610-99-6.
- E C,
(.J TABLE 1 ALARM RELAY ASSOCIATED LOG WDULE POINT 2-XS-1-300A f09J01 2-XS-1-3008 f09302 2-XS-1-300D f0930J 2-XS-1-J00E FD9304 2-XS-1-JOOF FD9305 2-XS-1-30IA f"D9J11 2-XS-1-3018 F093l2 2-XS-1-3010 F093l3 2-XS-1-301 E F09314
~
u' .:: J 2-XS-1-301F 2-XS-1-302A FD9315 FD9321
~ ~
~1'1 v,§ u u 2-XS-1-3028 F09322 2-XS-1-302D F09323 itBi f f 2-XS-1-302E F09324
~ ~
2-XS-1-JOZF
~ ~
FD9325 2-XS-1-303A FD9331
~:o i i M,.
m~
~ .
=>'
z i l z i l 2-XS-1-3038 2-XS-1-303D FD9332 FD9333 2-XS-1-303E F09334 2-XS-1-J03F F09335 l-109 PT L-110 f-471810-3-0,COORD.B-9"- - - - 1-314 HEJi:, l~JTIS - - 471610-3-8,COOR0.8-3> AIISAC NOTE 2 L-110 NOTE 2~-109 PT PT 1-72 1-73 II I I PT-506
-J l iilo ~o' u . ;t J J
PT-505
~s ~~
. ~" If I I su i!;u u
~
z, z*
- ~
I-::
~o i~ ~ ~ ~ ~
atANNEL P-508 TURB nr PR PM-1-72
! ,_~ z
~
z z EACLE-21 LCP-lli-0411 CHANNEL P-505 TUltB IMP PR PM-1-7]
"' N "' "'
/3'=1-ll_
FOXBORO DCS 2-471610-98-7, COORD E-2
- -,-1_~ ~
(FBM-98-R024C01,CH 1) rd;;,, rTiicl
. ~F~~~1~::~1::..a~~ g) 2 _,~~
p
~~-;LZA_
I 2-471610-98-6, CDJRD H-4 2-(FBM-98-R016807 ,CH 5) I 2-471610-98-7, COORD E-5 I r-- ( FEIM-98-R024C02, CH 1) I I I l ::!1 I.'. 2-471610-98-7, COORD (FBM-98-R024807 .CH (FBM-98-R024B08,CH C-10 6) 6) p M-1-72B1
----7 E/1
~g E/1 PY-506A r::-7 ~=
~PY-506D E/1 ~~Hl
~PY-5050 E/1 r::-1~:
~PY-SOSA D/0 R-4 CH3 PY-5D5A.1
- 2-471610-98-7, COORD D-6 I
( FEIM-98-R024COJ, CH
- 2-471610-98-7, COORD 1)
D-3 I ~4 ~P'5o6D<t8- .JI 4&--tI I r (FBM-98-R024C01,CH 6)
,_ I =P,506A I *-* *-* A_ .l UFSAR AMENDMENT I ~~,,,.I I t---7 PP/505D PP/505,\~
2-471610-98-7, COORD F-7 I
~@
(FEIM-98-R024C07 ,CH 14) I 2-471610-98-7, COORD (FEIM-98-R024C07 ,CH E-7 9) 2-
~~I 6 I PM-1 7282 L----, ~* ruk-, WATTS BAR I 2-471610-98-7, COORD F-7 2-!!"'!!:.I ~ Y2-41ws10-1-2A COORD c-11)1
\tW ~ PI M-4 I
( FEIM-98-R024C07 ,CH 2-471610-98-7, COORD 15) E-7
~ I 1-7]
FINAL SAFETY I ( FEIM-98-R024C07, CH L(X;IC REF
- 10) Pj:!7:!}L~
~ I ANALYSIS REPORT I mF802-403-FD-2202 RUNBACKI I mF802-403-FD-2304 I I
,-t __________________________
I mF802-403-FD-2012 JI POWERHOUSE UNIT 2 I!~---------------------------------------------------~ ELECTRICAL IL-------------------------------------------------------------------------- L---------------------------------------------------------------------------------------- CONTROL DIAGRAM MAIN STEAM SYSTEM TVA DWG NO. 2-47W610-1-3A R17 FIGURE 10.3-4 SH A(U2)
() z a::: C, C, w z ...... ~ ~ 1- ;;;' ;;;' NOTES:
- 1. FOR GENERAL NOTES SEE 1-471610-1-1.
z ...... ~M-4 2. FOR ANNUNCIATION DATA SEE 1-47'611-1-2 *
- E
~M-4 6Ll
~3D
~---+
C,
,-------- W
(.J SEE NOTE 2 I I ~u I I 2 I I I I I I '--- I I I LP TURBINE A
~-4 I ~1,1--4 LP TURBINE B LP TURBINE C
~
~
m' ~-+-~B
~ ~ ~ IZI will gu g I CONDENSER CONDENSER CONDENSER
<f <f
~ ~
ZONE A ZONE 8 ZONE C
~ ~
I r I r.
~
~
~
~
------r---- --- -------+
e
~6~* *I TYP lLOG 201OOO----zs-1-1O.3 LOG ZD1002 ~
LOG ZD1004 ~ LOG ZD1006 ~ LOG ZD1008 ~ LOG ZD 1010 ---- LOG ZD1O12---- LOG ZDIOH---- LOG ZD1O16---- LOGZD1O18---- LOG 2D1O22---- 104 105 106 107 108 109 110 111 112 114
~ _________ ~
ZS-1-103 ZS-1-109} TURBINE CONTROL SYS ZS-1-104 ZS-1-110
----r, TYP { ZS-1-105 ZS-1-111 M--4
©-r
--<1-47W610-47-2, COClllD C-6) ZS-1-106 ZS-1-112 I L ZS-1-107 ZS-1-114 TURBINE CONTROL SYS 1-47W610-47-2, COORD C-8 I
I I
'r.<
.>!{
~NN 3C-58E 4-14 SEE NOTE 6 J ZS-1-108 I_/XI\
TURBINE CONTROL SYS
~ 3C-58E
-<1-47W610-4-7-2, COORO D-6 L~sB TURBINE CONTROL SYS SEE NOTE 6 1-47W610--47-2, COORD D-8 TURBINE CONTROL SYS n
' (1-471610-47-2, COORD C-10r I
I TURBINE CONTROL SYS
~ I "<r (1-471610-47-2, COORO D-10r
©-t I I
z
~
~
FOXBORO OCS WATTS BAR FINAL SAFETY ANALYSIS REPORT L FM-1-103 1-+71610-98-12 COORO C-2 I ----- (FBM-98-R196B01, CH 1) 3C-58E
~4- J (FBM-98-R196802, CH 1) M SEE NOTE 6 1-47W610-98-12A. ca:im c-114-!.:~:.!:.!~~-___@
(FBM-98-L983E05, CH 2) ~D POWERHOUSE LOGIC REF OBF7J42J5-FD-1J04 UN IT 1 ELECTRICAL CONTROL DIAGRAM MAIN STEAM SYSTEM 1-47W610-1-3 R11 FIGURE 10.3-4
() z ...... 0
- ,,, ~ ~
~ ~
a::: C, u u C, w -f -f z
~ ~ NOTES,
< ~ . 0' 0' 1. FOR GENERAL NOTES SEE 2-+7W610-1-1. m z ~ 1- z
~
~ ~
z T
" T I
~
N N < D
- E r--------- ~---+M-4
~ul $
C, SEE NOTE 2 (.J 1 I I 2 I I r-- I 1 I I I I I '----+I I I
,.....J....., ,....L.. M-4 I M-4
~I~
< m LP TURBINE A
~-t-~e LP TURBINE B LP TURBINE C IZI I wil CONDENSER CONDENSER ZONE B ZONE C J LOG zo10oo~zs-1-103 LOG 201002~ 104 LOG 201004- ---- 105 LOG 201006 ---- 106 LOG 201008 ---- 107 TYP LOG 201010---- 108 LOG 201012 ---- 109 LOG 20101-4----- 110 LOG 201016---- 111 LOG 201018---- 112 LOG 201022 ---- 114 Lfo'\J ZS-1-103 ZS-1-104 ZS-1-109}
ZS-1-110
---r, *-* ~ 'y' TYP { ZS-1-105 ZS-1-111 M-4
~--
_j TURBINE CONTROL SYS ZS-1-106 ZS-1-112 l L- - - - ~ ZS-1-107 ZS-1-114
/7,\__r _________ J 2-47W610-47-2, COORD C-6 I 3C-58E ZS-1-108 TURBINE CONTROL SYS I );;;,( LEI]
2-47W610-47-2, COORD C-8
.>!{
_j TURBINE CONTROL SYS L__17,'\ I SEE NOTE 6 (SHT. 1) 1 *-* r-:diir-i 3C-58E THIS DRAWING SUPERSEDES SEE NOTE 6 l 2-+1W610-47-2, COORD 0-6 ~aB t::E!:l DRAWING 47W610-1-3 REV. 10 (SHT. 1) TURBINE CONTROL SYS SEE NOTE 6 (SHT. 1) TURBINE CONTROL SYS L 2-+7W610-47-2, COORD C-10J I I
~ I TURBINE CONTROL SYS L UFSAR AMENDMENT I
I 2-47W610-47-2. COORD D-10 j WATTS BAR I I FINAL SAFETY 3C-58E~-J
*-* I C
C ANALYSIS REPORT
~ § SEE NOTE 6 (SHT. 1) POWERHOUSE UNIT 2 ELECTRICAL CONTROL DIAGRAM MAIN STEAM SYSTEM 2-47W61O-1-3 RB FIGURE 1O.3-4(U2)
,----------------------------------------------------------7 Cl P>SP z CONTROL SW IN CLOSE HS-1-22A CONTROL SW IN CLOSE HS-1-11A FOR MANUAL NITROGEN STEAM GEN LOOP 3 STEAM GEN LOOP 2 3' CONTROLS SEE GANGED SWITCH
<( DWG 47W600-221 A (SEE NOTE J) Q:'. r-----------------7 TRAIN 8 TEST A
------------------------7 0 I I (OVER HS-1-4D) I I I STEAM LINE I I I BREAK SIGNAL I 0 CHANNEL A I w ZS w (1-47W611-63-1} I z 0 I 1-4J I
<( f-VENT NORMAL HI-HI CNTMT I z AFTER I ~~~~~~~EA I OPEN (1-47W611-88-1} I r TYP !CAL MDV CONTROL VENT FOXBORO DCS 1-2218124-US14728-FD-1XNS-0001-1 TO FCV-1-11, r-,----+----, FCV-1-22 &. FCV-1-29 TRAIN B LOGIC
) &. TEST SWITCHES SAME AS TRAIN A ~PART OF SSPS
________________________________________ TRAIN A ____________ _ NOTES: 00_
~----*
MAIN STEAM ISOLATION SIGNAL. TRAIN A
- 1. FOR SYMBOLS SEE INSTRUMENTATION AND IDENTIFICATION STANDARDS, LATEST ISSUE.
SEE 1-47W611-63-1 AND 1-47W611-88-1 2. FOR COMPLETE INSTRUMENTATION AND COMPONENT SEPARATION DESIGNATIONS SEE CONTROL DIAGRAM, 1-47W610-1-1, 2, 3, 4.
- 3. HS-1-6 & HS-1-4A HAND SWITCHES HAVE A BARRIER TO SEPARATE THE SWITCHES INTO TWO SECTIONS TO PROVIDE BOTH TRAIN A &. TRAIN B FUNCTIONS.
- 4. RESET POSITION ON HS-1-4A ONLY. All 4 STEAM GEN LOOPS ARE OPEN CLOSE OPEN CLOSE FROM STEAM RESET BY PLACING HS-1-4A. HS-1-11A, HS-1-22A &. HS-1-29A IN GENERATOR CLOSE POSITION AND ACTUATING RESET ON HS-1-4A.
IN-MANUAL PULL P-AUTO LOOP 2 5. DIGITAL AND ANALOG LOGIC SYMBOLS ARE USED ON LOGIC DIAGRAMS TO (SAME AS LOOP 1) CONTINUED ON FUNCTIONALLY DESCRIBE THE PROCESS CONTROL. REFER TO THE ASSOCIATED 1-47W611 2 WIRING SCHEMATIC FOR THE ELECTRICAL COMPONENTS USED TO IMPLEMENT NOR. NOR. FROM STEAM GENERATOR THE CONTROL SCHEME. STEAM LOOP 3 6. ELECTRIC POWER IS REMOVED FROM VALVES GENERATOR ( SAME AS LOOP 1 ) 1-FCV-147, -148. -149 AND -150 BY LOOP 1 ADMINISTRATIVE CONTROL OF HS-1-1478, AUX AUX
-1488, -1498 AND -1508 DURING NORMAL FROM STEAM POWER OPERATION TO PREVENT SPURIOUS GENERATOR OPENING DUE TO APPENDIX R FIRE.
PWR LOOP 4 OFF ( SAME AS LOOP 1 ) 7. OPEN TORQUE SWITCH AND OPEN BY-PASS SWITCH REMOVED FROM 1-FCV-1-17 AND 1-FCV-1-18 CIRCUITS. OPEN CLOSE OPEN CLOSE t) COMPANION DRAWINGS: 1-47W611-1-2 & 3 - - - - LOGIC DIAGRAM REFERENCE DRAWINGS: 1-47W611-0 - - - - - LOGIC DIAGRAM INDEX &. SYMBOLS 1-47W610-1-1,2,3,4 - - - CONTROL DIAGRAM 478601-1-SERIES- - - - - INSTRUMENT TABULATION 1-47W801 - - - - - - FLOW DIAGRAM HI TEMP IN AUX FEEDWATER TURBINE ROOM TS-1-17A HI TEMP IN AUX FEEDWATER TURBINE ROOM TS-1-178
-----------------~-
OPEN OPEN CLOSE TYP MDV CONTROL TYP MDV CONTROL
~-~--------------------
TYP MDV CONTROL SEE NOTE 7 OPEN CLOSE OPEN CLOSE
~~----------------------
FROM STGEN NO. 4 SAME AS STGEN NO. 1 I I EN CLOSE AUX FEEDWATER PUMP TURBINE UFSAR AMENDMENT 3 r- -7 WATTS BAR PUMP DISCHARGE PRESSURE LOW PS-3-138A 40 S I CONTROL SAME AS LFCV-1-17 _____ J I SEE NOTE 7 FINAL SAFETY (1-47W611-3-4} ANALYSIS REPORT PERMISSIVE FOR T&.T VALVE CLOSE TURBINE UT ] : OPEN ( 1-47W611-3-4) VALVE (1-47W611-3-4) POWERHOUSE HIGH TEMP IN AUX FEEDWATER TURBINE ROOM TS-1-1 BA HIGH TEMP IN AUX FEEDWATER TURBINE ROOM TS-1-188 UN IT 1 FCV-1-16 ELECTRICAL FULLY OPEN LOGIC DIAGRAM MAIN AND REHEAT STEAM TVA DWG NO. 1-47W611-1-1 R17 FIGURE 10.3-5
(.!) z 3= <( 0:: Cl TR A TEST FOXBORO DCS Cl w z <(
,oaF8D2403-FD-2950 I
+ I TR B TEST (OVER HS-1-4B~
,------------- 7 1-z I FOXBORO DCS 08F802403-FD-2JOO (OVER HS-1-40~
PUSH TO TEST (MOMENTARY) I (NOTE 8} VENT CONTROL SW IN CLOSE Cl <( I HS-1-22A STEAM GEN LOOP3 u I fi,a, EAGLE 21 {2-PM-1-2A- - 2-PM-1 7 7 I CONTROL SW IN CLOSE HS-1-29A STEAM I GEN LOOP+ I II ' I II L_ II SEE
- DERIVED FROM UNIQUE LIMIT AND TORQUE SI REQ Of VL V II NOTE +
TYPICAL MOV CONTROL 11 II FOXBORO DCS I OBF802403-FD-2300 I II __] I I l<111Ej __ :'.J L~~ LPART-;-SSPS L- _ _ _ _ _ _ _ _ _ _ _ _ TRAIN A_ _j L, STEAM SAFETY RELEASE VALVES I NOTES:
@f--------~
- 1. FOR SYMBOLS SEE INSTRUMENTATION AND IDENTIFICATION STANDARDS, LATEST ISSUE.
- 2. FOR COMPLETE INSTRLMENTATION AND COMPONENT SEPARATION DESIGNATIONS SEE CONTROL DIAGRAM 2-471610-1-1,2,3,4.
- 3. NOT USED FROM STEAM 4. HS-1-6 l: HS-1-4A HAND SWITCHES HAVE A BARRIER TO SEPARATE GENERATOR THE SWITCHES INTO TWO SECTIONS TO PROVIDE BOTH TRAIN A l:
LOOP 2 _____.,.. TRAIN B FUNCTIONS. (SAME AS LOOP 1 J CONTINUED ON 5. RESET POSITION ON HS-1-4A ONLY. All 4 STEAM GEN LOOPS ARE FROM STEAM 2-471611-1-2 RESET BY PLACING HS-1-+A, HS-1-11A, HS-1-22A a. HS-1-29A IN GENERATOR CLOSE POSITION. LOOP 3 ~ (SAME AS
- 6. *DIC IT Al AND ANALCC LOCIC SYMBOLS ARE USED ON LOGIC DIAGRAMS LOOP 1) TO FUNCTIONALLY DESCRIBE THE PROCESS CONTROL. REFER TO THE ASSOCIATED WIRING SCHEMATIC FOR ELECTRICAL CCl.PONENTS USED STEAM FROM STEAM TO IMPLEMENT THE CONTROL SCHEME.
GENERATOR GENERATOR LOOP 1 LOOP+ ~ 7. NOT USED (SAME AS LOOP 1 l
- 8. FOR STEAM GENERATOR 2,3,4 REFER TO 08F8D2405-FD-2JOl,2,J.
- 9. ELECTRIC POWER IS REMOVED FROM VALVES FCV-1-147, -148, -149 AND -1,0 BY ADMINISTRATIVE CONTROL Of HS-1-147B, -148B,
-149B ANO 15OB DURING NORMAL POWER OPERATION TO PREVENT SPURIOUS OPENING DUE TO APPENDIX R FIRE.
HI TEMP IN AUX FW
~-;__._,--, TURBINE ROOM TS-1-17A.
~...,-..,_---' HI TEMP IN AUX FW TURBINE ROOM TS-1-178 CCMPANION DRAWINGS:
2-471610-1-1.2,3.+----------CONTROL DIAGRAM 2-471801-1-1----------------flOI DIAGRAM OPEN CLOSE OPEN CLOSE TYP KN CONTROL TYP MOV CONTROL OPEN OPEN
~-----------D~----f'~--,-------------1.,?]f-----.-e--------j ~~~
1 1
- ~E:~E~~Nc:~* N6. 1
'-------,---,-------------------l>i<::i-------------------c~----- lttf:artr~:~ l~:~
WATTS BAR PUWJ DISCHARGE FINAL SAFETY PRESSURE LOW PS-3-138A ( 2-471611-3-4) ANALYSIS REPORT PERMISSIVE FOR CLOSE TURBINE ~ POWERHOUSE r2~+Jw::~~:i-~rEN L-J'-.rL...a...-l 2~+lw~:~~i-+) UNIT 2 HIGH TEMP IN AUX rw HIGH TEW IN AUX rw ELECTRICAL TURBINE ROCM TS-1-1 BA TURBINE RCXlM TS-1-18B LOGIC DIAGRAM MAIN AND REHEAT STEAM TVA DWG NO. 2-47W611-1-1 R15 FIGURE 10.3-5(U2)
c., z
- s
°" c:, FOXBORO OCS 1-0006J673-08F73423 S-f'0-1 DOS, -1012, -1202, -1304 NOTES,
- 1. FOR SYl.l:IOLS AND GENERAL NOTES, SEE SHEET 1.
c:, 2. MEt.ORY RETURNS TO OFF UPON LOSS OF POWER. w I 3. CONTRQ. LOGIC FOR STEAM DUMP VALVES TO CONDENSER ZONES 8 AND C IS z 111 SIMILAR TO CONTROL LOGIC FOR DUMP VALVES TO CONDENSER ZONE A.. 111 I PRESSURE < SET POINT 4. STEAM OUW VALVES ARE OPENED SEQUENTIALLY BY THEIR RESPECTIVE < 111 I FROM COND ZONE B SPLIT RANGE CONTROLLERS WHICH OPERATE OVER THE FOLLOWINC PORTIONS 1- OF FM-1-1D3'S 3-15 PSIG OUTPUT: FC 103A;3-6 PSIG z r------------------~11 I FC 1038;6-9 PSIG REACTOR TRIP < 11 I FC 1030;9-12 PSIG FC 103E;12-15 PSIG
- i;;
r------------------~1 I TRAIN A TRAIN B ,---------------------------7 5. ANNUNCIATOR POINTS ON LOGIC DIA.GRAMS ARE INDICATED BY GIVING THE ANNUNCIATOR PANEL NWBER A.ND THE WINDOW NUMBER AS GIVEN c:, I I ON ORA.WING 1-458655-SERIES. I tJ r-----------------J I I D z D z D z D z
- 6. THIS EQUIPMENT INTERFACES WITH THE REACTOR SOLID STATE PROTECTION SYSTEM AND IS SUBJECT TO AUGMENTED QA REQUIREMENTS PER N3-47-4D02.
- 7. STEAM DUMP VALVES FCV-001-0104.-0105.-0106.-0108.-0109.-D11D.-0112.-D113.
I I on
-0114 MAY BE USED FOR UNIT COOLDOWN IN CCMBINATION WITH THE COOLOOWN I '-----------7 on D on VALVES (FCV-001-0103,-0107, A.ND -0111) BELOI AN AVERA.GE REACTOR COOLANT SYSTEM TEMPERATURE OF 350-F. TO ENABLE THESE VALVES BELOW 35Q* F.
TO REHEATERS on REFER TO 1-45W600-1-1 FOR DETAILED INFORMATION CONCERNING IA-2, 1B-2, IC-2 ON w THE PROCEDURAL DISABLEMENT or THE PROTECTIVE INTERLOCK (P-12). COND CIRC {1-4-7W611-3-1) WATER PUMP "' 8. FOXBORO DCS IO POINT NAME. RUNNING OFF HS~ BYPASS PS TA.VG 1-103A INTERLOCK RESET (KIMENTARY) 2-18 SEE 1-471610-+7 LO LO AVERAGE TEMPERATURE TS-68-2J LOOP 1
,. ._. .,_, , . . ___.....,____=II'-1 LO LO AVERAGE f~~:i~~!~RE LOOP 2 LO LO AVERAGE
=-e+----+I+---~==-- f~~~,~~l~RE LP TURBINE 1A LOOP 3
l-=e-,=e+----+1-+.----=IJz:~
LO LO AVERAGE f~~:i~~l~RE LOOP 4 COND ZONE A DUMP VALVES TRAIN A ASSOCIATED SOLENOIDS 2/4 P-12 I I _ _ _ _ _ _ _ _JI IL _______ _ ,-------- 1 TO DUMP VALVES TO OUW VALVES I
- - FSV-1-107 a. FSV-1-111 FSV-1-107, I - - - - - - - - - . - - - FSV-1-108, I FSV-1-111, AND
_ _ _ _ _ _ _ _ _ _ _ _ _J FSV-1-112
~
Q ~ TO FCV-1-108,
.- ] ___ FCV-1-112 I SAME AS I
~l~1~~~~:
L_________________________ ------- I/P CONDENSER DUW VALVE m
+
D
+
D
- m -
'o ~ -'
TO FCV-1-107, FCV-1-111
~ ~ ~
TO DUMP VALVES FSV-1-109, FSV-1-110,
- 8 ~ 8 FSV-1-113 .t. FSV-1-114 D m <
,n ,n CO I
I C l"l 0
,n 0
I.- I UFSAR AMENDMENT
> > I >
Ill Ill O 1/1 1 - - - - - T O REHEATERS IA-1, 18-1 ~ lC-1 LL 0 0 LL t- t- t- t-LL 0 LL 0 WATTS BAR r- FINAL SAFETY
~~~E~~ER DWP VALVE I
I ANALYSIS REPORT CONDENSER DUW VALVE C LFSV__.=-!..="~~__J TO FCV-1-109, POWERHOUSE TO FCV-1-110, FCV-1-114 FCV-1-113 UNIT 1 18 LP IC TO .t. TURBINES ELECTRICAL (SM.£ AS IA) LOGIC DIAGRAM MAIN AND REHEAT STEAM TVA DWG NO. 1-47W611-1-2 R17 FIGURE 10.3-6
c., z
- s
°" c:, c:, FOXBORO DCS w 08F802403-FD-2005, 2012, 2202, 2304 z < 111 FOXBORO DCS NOTES: 1- 08F802403-FD-2801, 2810 z 111 1. FOR SYMBOLS AND GENERAL NOTES, SEE 2-47W611-1-1. 111 2. MEt.ORY RETURNS TO OH UPON LOSS OF POWER.
- i;; r-------------------~11 REACTOR TRIP 3. CONTROL LOGIC FOR STEAM DUMP VAL YES TO CONDENSER 28 c:,
11 TRAIN A COND. CIRC. WATER PUMP RUNNING AND 2C IS IDENTICAL TO CONTROL LOGIC FOR DI.MP VALVES TRAIN B < r------------------~1 :/> TO CONDENSER 2A. tJ I I -4. STEAM DUMP VALVES ARE OPENED SEQUENTIALLY BY THEIR I ,-------------------J RESPECTIVE SPLIT RANGE CONTROLLERS WITH OPERATE OVER THE FOLLOWING PORTIONS CF FM-1-lOJ'S 3-15 PSIG OUTPUT: I I FC-1-103A: 3-6 PSIG I I FC-1-103B: 6-9 PSIG I I TO REHEATERS FC-1-103D: 9-12 PSIG I I 2A-2,2B-2,2C-2 (SEE 2-+7W611-3-1) r ___ _J...J FC-1-103E; 12-15 PSIG
- 5. ANNUNCIATOR POINTS ON LOGIC DIAGRAMS ARE INDICATED BY GIVING THE ANNUNCIATOR PANEL NUMBER AND THE WINDOW I NLMBER AS GIVEN ON TVA DRAWING 2-458655-SERlES.
I I
,-------+---J L--~-----7 6. STEAM DUMP VALVES FCV-001-0104, -0105, -0106, -0108,
-0109, -0110, -0112, -0113, -011+ MAY BE USED FOR UNIT COOLDOWH IN COMBINATION WITH THE COOLDOIN VALVES I '--, * (FCV-001-0103, -0107, ANO -0111) BELOW AN AVERAGE REACTOR COOLANT SYSTEM TEMPERATURE OF 350- F. TO ENABLE THESE VALVES BELOW 350- F. REFER TD 1-+5W600-1-1 FOR DETAILED INFORMATION CONCERNING THE PT PT (TYP SEE PROCEDURAL DISABLEMENT OF THE PROTECTIVE INTERLOCK 1-72 1-73 I NOTE 5) (P-12).
I
~
~
!.?
~ ~
r _J I I I I I - TO DUMP VALVES FSV-1-107 A FSV-1-111 I I TO DUl.f' VALVES I ------....-FSV-1-108.AND I FSV-1-112
~
~ I i
i,,! I I I IL _______ _ I L __ _ TO FCV-1-108, FCV-1-112 _______ J L ____________________ _ __,,,__ _,,,_ ----,f'- 10 FEEDWATER rr~f1JUf1
,~
8!r~4 COORO. E-5) TO DUMP VALVES fCV-1-109, FCV-1-110 FCV-1-113 AND FCV-1-114 TO REHEATERS ZA-1,28-1, &. 2C-1 (SAME AS REHEATER 2A-2 ON 2-4-7W611-1-3)
~
r SAME AS CONDENSER 7 I
~o's7 DUMP VAL VE I LFCV~::.!_O.:_~
CONDENSER DUMP J"'"*TO FCV-1-109, VALVE 1,+..FCV-1-113 _ . . __ _ _ _ _TO LP TURBINES 28 A 2C (SAME AS 2A) WATTS BAR FINAL SAFETY ANALYSIS REPORT POWERHOUSE UNIT 2 ELECTRICAL LOGIC DIAGRAM MAIN AND REHEAT STEAM TVA DWG NO. 2-47W611-1-2 R11 FIGURE 1O.3-6(U2)
MFWP TURBINE A &. B TRIPPED, Cl AMSAC SAFETY INJECTION, z BLACKOUT, BLACKOUT SAFETY INJECTION TEST, LO-LO LEVEL 3= ANY STEAM GENERATOR OR LO-LO <( LEVEL 2/4 STEAM GENERATOR oc: 0 3 SEC 0 w TDAFWP T/T VALVE z FCV-1-51 HALF OPEN <( 18-8 t-z OPEN CLOSE 1-141A 0 <( u 1-FCV-1-284 FULL OPEN NOTE 1) CONTAINMENT ( SEE EHC CONTROL [ ISOLATION SOFTWARE PHASE A 1-478630-47-0)
- - - - [ 1-FCV-1-7 FROM MAIN CONTAINNEMT] FULLY OPEN STEAM HEADER ISOLATION PHASE A MOISTURE SEPARATOR TO REHEATERS REHEATER A-1 8-1 &. C-1 UNIT 2 (TYPICAL FOR 8-1 C-1,A-2,8-2 &.
C-2) BLOWDOWN LINE FROM STEAM GENERATOR #1 TO STEAM GENERATOR (1-47W611-1-1, X SLOWDOWN COOR G-1) SLOWDOWN ISOLATION VALVE I BLOWDOWN LINE FROM STEAM GENERATOR #2 ]'--1-1------l<J (SAME 1 A~ct~c~~~-181) 1-FCV-1-14 (SAME AS 1-FCV-1-7) FROM TURBINE EXTRACT ION STEAM (SEE 1-47W611-1-2) BLOWDOWN LINE FROM STEAM GENERATOR #3 ]1-- ~1-----l<J 1 1 (SAME 1 A~Ct~c~~t181) 1-FCV-1-25 (SAME AS 1-FCV-1-7) BLOWDOWN LINE FROM 1-FCV-1-184 I STEAM GENERATOR #4 (SAME AS 1-FCV-1-181) 1-FCV-1-32 (SAME AS 1-FCV-1-7) I OPEN CLOSE ii8~~~~~~~;R-7 I ( SEE EHC CONTROL I I SOFTWARE I
~-4786301-47-0) _J I
NOTES:
- 1. HS-1-7/181 AND HS-1-181/7 ARE SEPARATE PORTIONS OF A DUAL SWITCH MODULE WHICH HAS A BARRIER TO SEPARATE THE SWITCHES INTO TWO CONT AINNEMT SECTIONS TO PROVIDE BOTH TRAIN A AND TRAIN 8 FUNCTIONS.
ISOLATION PHASE A 2. THE INPUT FOR "AFW PMP STARTED" IS THE TRAINED PUMP THAT
, - - - - - - - - - - - - - - - - - -7 CORRESPONDS TO THE TRAIN DESIGNATION OF THE ASSOCIATED VALVE.
I I I I I I I I I I HOODED I I
~~~L5§uRE : I I I I I L----------------------~
TO FLOOR DRAIN COLLECTOR TANK SAMPLE LINE FROA SG #4
~ 1-FCV-43-63A
~ S A M E AS 1-FCV-43-54A)
\-- ___.._
SAMPLE LINE FROA SG #3 l C 1-FCV-43-59A
~ S A M E AS 1-FCV-43-54A)
\-- ___.._ UFSAR AMENDMENT 2 SAMPLE LINE FRCM SG #2
~ 1-FCV-43-56A
~ S A M E AS 1-FCV-f3-54Al
\-- 1-FCV-43-56D (SAME AS 1-FCV-f3-5f0)
___.._ WATTS BAR SAMPLE LINE FINAL SAFETY FRCM SG #1 I ANALYSIS REPORT I I 1-PCV-+3-1317 I IL _________ _ POWERHOUSE INSIDE CONTAINMENT UN IT 1 ELECTRICAL LOGIC DIAGRAM MAIN AND REHEAT STEAM TVA DWG NO. 1-47W611-1-3 R12 FIGURE 10.3-7
Cl MFWP TURBINE A & 8 TRIPPED, z AMSAC SAFETY INJECTION, BLACKOUT, BLACKOUT SAFETY INJECTION TEST, LO-LO LEVEL 3' ANY STEAM GENERATOR OR LO-LO <( LEVEL 2/4 STEAM GENERA TOR Q:'. 0 3 SEC 0 w z TDAFWP T/T VALVE FCY-1-51 HALF OPEN <( AFW PUMP 28-8 f- STARTED z OPEN CLOSE 1-141A 0 <( u OPEN 2-FCV-1-284 FULL OPEN CONTAINMENT (SEE EHC C O N T R O L f - - - - - - - - - ~ [ ISOLATION SOFTWARE PHASE A 2-478630-47-0) 2-FCV-1-7 FROM MAIN CONTAINNEMT] ~ - - - [ FULLY OPEN STEAM HEADER ISOLATION PHASE A MOISTURE SEPARATOR REHEATER A-1 (TYPICAL FOR 8-1 C-1,A-2,8-2 & UNIT 1 C-2) NOTES: SLOWDOWN LINE FROM STEAM GENERATOR #1 TO STEAM GENERA TOR 1. 2-HS-1-7/181 ANO 2-HS-1-181/7 ARE SEPARATE PORTIONS OF A DUAL ( 2-47W611-1-1, X SLOWDOWN SWITCH MODULE WHICH HAS A BARRIER TO SEPARATE THE SWITCHES INTO COOR E-1) SLOWDOWN ISOLATION VALVE I TWO SECTIONS TO PROVIDE BOTH TRAIN A AND TRAIN 8 FUNCTIONS. BLOWDOWN LINE FROM STEAM GENERATOR #2 ]~-1-1--~<J (SAME 2 A~c~=~c~~f-,a,) 2-FCV-1-14 (SAME AS 2-FCV-1-7) FROM TURBINE EXTRACT ION STEAM {SEE 2-47W611-1-2)
- 2. THE INPUT FOR "AFW PMP STARTED" IS THE TRAINED PUMP THAT CORRESPONDS TO THE TRAIN DESIGNATION OF THE ASSOCIATED VALVE.
]' - - - - - ~ <J(SAMEAS2-FCV-1-181)
SLOWDOWN LINE FROM 2-FCV-1-183 III STEAM GENERATOR #3 2-FCV- 1 -25 ( SAME AS 2-FCV-1 -7) SLOWDOWN LINE FROM 2-FCV-1-184 ~ STEAM GENERA TOR #4 ( SAME AS 2-FCY-1-181), ~ , 2-FCV-1-32 (SAME AS 2-FCV-1-7) I OPEN CLOSE TDAFWP T/T VALVE it8~~~~AT---7 I SEE EHC CONTROL I FCV-1-51 HALF OPEN I SOFTWARE I L2-47863o o _ _J CLOSE I TYPICAL TO REHEAT I CONTROL VALVES I 2-FCV-1-275 2-FCV-1-277 2-FCV-1-279 2-FCV-1-291 2-FCV-1-298
, - - - - - - - - - - - - - - - - - -7 I I I I I I I I I I HOODED I I
~~~rMuRE I I I I I I L----------------------~
SAMPLE LINE ~ 2-FCV-43-63A \-- 2-PCV-43-64 ol 2-PCV-43-1320 SAME AS FROM SG #4 ~ S A M E AS 2-FCV-43-54A) (2-PCV-43-55 a. 2-PCV-43-1317) SAMPLE LINE ~ 2-FCV-43-59A \-- 2-PCV-43-61 & 2-PCV-43-1319 UFSAR AMENDMENT 3 SAME AS FROM SG #3 ~ S A M E AS 2-FCV-43-54A) ( 2-PCV-43-55 a. 2-PCV-43-1317) SAMPLE LINE ~ 2-FCV-43-56A FROM SG #2 ~ S A M E AS 2-FCV-43-54A)
\-- 2-FCV-43-56D
- ~ - - - - - - \ ( S A M E AS 2-FCV-43-54D) 2-PCV-43-58 a. 2-PCV-43-1318 SAME AS (2-PCV-43-55 a. 2-PCV-43-1317)
WATTS BAR FINAL SAFETY SAMPLE LINE FROM SG #1 I ANALYSIS REPORT I I I IL _________ _ 2-PCV-43-1317 POWERHOUSE INSIDE CONTAINMENT UN IT 2 ELECTRICAL LOGIC DIAGRAM MAIN AND REHEAT SYSTEM TVA DWG NO. 2-47W611-1-3 R9 FIGURE 1O.3-7(U2)
FIGURE 10.3-8 DELETED
(.!) z
- s Ct
1-~(VENT) ROOF FROM CONDENSATE POLISHER AMMONIUM
~ - - - - < HYDROXIDE TANK 1-471838-2 COORD A-4 Cl Cl NOTES, w
- 1. PREFIX VALVE NUMBERS AND EQUIPMENT AND INSTRUMENT REFERENCE DESIGNATIOfr6 z WITH THE UNIT NUMBER (1 OR 2) AND THE SYSTEM NUMBER (36) AS FOLLOWS, (0-36-29; 1-36-29; 2-36-29; ETC.) 0- FOR COMMON USE, BOTH UNITS
< AMMONIA 1-FOR UNIT 1 I- 2-FOR UNIT 2 z STORAGE TANK 2. ALL Pl.MPS ARE EQUIPPED WITH BALL CHECK VALVES ON SUCTION AND DISCHARGE. O-TANK-36-37 < ,m 3. ALL PRESSURE GAUGE VALVES ARE 1/Z- GLOBE VALVES UNLESS OTHERWISE NOTED. viz..-::c 1-. ALL VALVES ARE THE SAME SIZE AS PIPING UNLESS OTHERWISE NOTED.
- i;; CAP 625 GAL o:o 5. PRESSURE CAUCES ARE PROVIDED WITH CLEANOUT-TYPE CHEMICAL CAL.ICE Zl-r-,.11::: PROTECTORS.
Cl ~j 0-ISV-37AI
<z:,c-0
~8~8 0-ISV-1-081
- 6. ALL VALVES SHALL HAVE MARKER TAGS.
<B:>
(.J YARD_ _ __ TURBINE BLDG 0-658
- 7. INDICATES TVA PIPE CLASSIFICATION AS SHOWN ON 47821-1.
1-1/r 8. ALL TANKS, VENTS, DRAINS .. Pl.MP SUCTION PIPING DESIGNED FOR AUOSPHERIC 0-503 PRESSURE e AMBIENT TEti.l'ERATURE. TEST TO 15 PSIG. 0-501 HYDROSTATIC TEST PRESSURE DATA IS HISTORICAL INFORMATION AND NO 0-SMV--42C4 LONGER MA.INT AI NED AS DESIGN OUTPUT.
- 9. ALL SUPPLY PIPING FRCM PUMPS TO CONDENSATE SYSTEM DESIGNED FOR 1-00 PSIG 0-ISV-42C3 130-ISV-42C2
/s*
- AMBIENT TEti.l'ERATURE. TEST TO 600 PSIG.
HYDROSTATIC TEST PRESSURE DATA IS HISTORICAL INFOOMATION AND NO 0-SMV-32C5 LONGER MA.INT AI NED AS DESICN OUTPUT.
- 10. ALL SUPPLY PIPING FRCM PUMPS TO AUXILIARY BOILER AND WET LAYUP RECIRCULATION PUMPS DESIGNED F~ 100 PSIG
- AMBIENT TEMPERATURE.
TEST TO 150 PSIG. HYDROSTATIC TEST PRESSURE DATA IS HISTORICAL INFORMATION AND NO LONGER MAINTAINED AS DESIGN OUTPUT. AMMONIA 11. ALL CONDENSATE PIPING SUPPLYING TANKS &. PUMPS DESIGNED FOO 100 PSIG
- At.EIENT TEMPERATURE. TEST TO 150 PSIG.
0-508 ___,.. 0-509 GRADUATED CYLINDER HYDROSTATIC TEST PRESSURE DATA IS HISTORICAL INFORMATION AND NO l l __!_".__CONDENSATE LONGER MAINTAINED AS DESIGN OUTPUT.
- 12. RELIEF VALVES ON HYDRAZINE I. At.l.lONIA PUMPS 9-IALL BE SET BY THE FIELD AS FOLLOWS:
O-LG- PUii' RELIEF VALVE SETTING 1-36-&94 36-42C 1A 400 m~E~E~~RFACE 7,.1~'.1--1--,~- B 400 2A 400 SUPPLIED ETA SKID 1-36-696 C 100
- - ---1--1-_--------;....__ 0-ISV-42C1 D 1DO 0-36-602 , 3 * ~~\~G~HiRl~1i~'Y1Ii1\~J.E~r~II~iR~E~t~ifl o~~~tti~1 SEE THE LATEST REVISION OF THE 47821 SERIES DRAWINGS *PIPI~ SYSTEM 5 SPECIFIED.
0-633 SYSTEM INTERFACE WITH ENOOR SUPPLIED CLASSIFICATION.*): YORAZJNE EClJIPtr.ENT
~ N3-36-40D2-----SECONDARY CHEMICAL FEED SYSTEM 1-36-689 14.ALL CLOSED MANUAL VALVES WHICH ARE HARD INTERFACE POINTS MUST HAVE THE
~
HANO WHEELS REl.OVEO, EXCEPT THOSE THAT FORM PART CF THE ABSCE BOUNDARY WHICH SHALL BE LOCKED CLOSED.
- 15. (((D .t. [!]!] DENOTES UNIT 1 a:. 2 INTERFACE POINTS.
- 16. jABSCE j - DENOTES ITEM IS REQUIRED TO REMAIN IN DESIGN CONFIGURATION AS SHOWN TO PROTECT THE PRESSURE BOUNDARY OF THE ABSCE.
- 17. VALVES MUST REMAIN CLOSED (LOCKED) SINCE WET LAYUP RECIRCULATION IS NO LONGER USED TO SUPPORT UNIT 1 OPERATION.
2-36-689 18. RELIEF VALVES 1-RFV-036-0808A AND -08088 ON THE PAA SKID SHALL BE SET AT 2-36-688 SYSTEM INTERFACE WITH 670 PSIG. THIS PRESSURE IS BASED ON THE 400 PSIC DESIGN PRESSURE OF THE VENDOR SUPPLIED HYDRAZINE EQUIPMENT ¥6~~gA~hi~~~I~~~ ~ll 0s~~T~~L0~0 1 IN THE SECONDARY CHEMICAL FEED SYSTEM.
!~~v~~§l~M~f s ~~6 0 ~~~E T~~I!~~o!~~~701 DRAWINCS:
0-527 ---------FLOW DIAGRAM - WET LAYUP SYS
~S~s~f= 0~~tWuM HYDROOJXE TANK 1-=!lJ~
>-----~
j~..' 1----------FLOW DIAGRAM - FEEDWATER
---------FLOW DIAGRAM - AUXILIARY FEED'fATER DRAIN 4'7W838-2 1,2 ---------FLOW DIAGRAM - CONDENSATE COORD C-... ~ 0-47W815-1----------FLOW DIAGRAM - AUXILIARY BOILER 2-36-696 2-36-694 1,2-471841-1----------FLOW DIAGRAM - GLAND SEAL WATER 6 SYSTEM INTERFACE WITH VENDOR 47W610-36 SERIES------INSTRUMENT AND CONTROL DIAGRAM SUPP LI ED ET A SK IO 47W611-36 SERIES------LOGIC DIAGRAM 1-TANK-36-693 47W495 SERIES---------FEED'fATER TREATMENT SECONDARY DIEMICAL FEED SYSTEM PIPING VENDOR SUPPLIED ETA PORTABLE TOTE BIN CONTROLLED SYSTEM INTERFACE BY CHEMISTRY WITH VENDOR SUPPLIED MOLAR RATIO EQUIPMENT SYSTEM INT[TRFACE 2-36-698 WITH VENDOR VENDOR SUPPLIED SUPPLIED PAA ETA SKID EQUIPMENT CONTROLLED BY SYSTEM DIEMISTRY INTERFACE WITH ETA 1-36-695 2-PkG-36-693 EQUIPMENT 2-572 2-573
.)_fl' 1/2" 0-575 - - -
VENDOR SUPPL I ED
..OLAR RATIO SKID FRCM DE..UN WATER CONTROLLED BY SYSTEM 0-47W856-1 CHEMISTRY COORD 0-10 2-PKG-36-699 FRCM DEMIN WATER SYSTEM 0-471856-1 AUX BOILER A COORD D-10 CLASS H TURBINE BLDG AUXIL IA.RY BLOC CLASS G UFSAR AMENDMENT
----...!:==...!.;;!~~!.l...--------1------..-_-_-_-_-_-_-_-_-_-_-_-_-_-_-_-_-..,-_, ____ WATTS BAR
- j ----~! FINAL SAFETY VENDOR SUPPLIED HYDRAZINE SKID 1-650 1-652 1-655 ANALYSIS REPORT CONTROLLED BY 1" 1-654 CHEMISTRY WET LAYUP 2-PKG-36-687 1-649
._,.:::+----- ~~JRf~~T~g~
1-471862-2 G-9 3 POWERHOUSE WET LAYUP UNITS 1 & 2 VENDOR SUPPL I ED HYDRAZINE SKID 1-61-8 RECIRCULATION PUMP LOOP NO. 2 1-1-7W862-2 C-9 WET LAYUP RECIRCULATION PUMP LOOP NO. 4 FLOW DIAGRAM CON TROLL ED BY CHEMISTRY 471862-2 C-4 FEEDWATER TREATMENT 1-PKG-36-687 WET LAYUP SECONDARY CHEMICAL FEED RECIRCULATION PUMP LOOP NO. 4 TVA DWG NO. 0-47W854-1 R4 1-71862-2 C-4 FIGURE 10.3-9
WBN 10.4 OTHER FEATURES OF STEAM AND POWER CONVERSION SYSTEM 10.4.1 Main Condenser 10.4.1.1 Design Bases Unit 1 The design basis for the main condenser is to provide a heat removal rate of at least 7.789 x 109 Btu/hr per unit for the steam system by condensing the steam from the turbine exhaust. There are three pressure zones with back pressures of 1.63 (Low Pressure, LP), 2.38 (Intermediate Pressure, IP), and 3.40 (High Pressure, HP) inches of mercury, absolute when operating at rated turbine output with 70°F cooling water and 95% clean tubes. A tube cleaning system is provided to keep the condenser operating at peak performance. For purposes of guarantees and calculations, the steam flow is considered to be equally divided between these three zones. During a cold startup, the condenser must also deaerate the initial inventory of water contained within the condensate and feedwater system. Unit 2 The design basis for the main condenser is to provide a heat removal rate of at least 7.789 x 109 Btu/hr per unit for the steam system by condensing the steam from the turbine exhaust. There are three pressure zones with back pressures of 1.92 (Low Pressure, LP), 2.70 (Intermediate Pressure, IP), and 3.75 (High Pressure, HP) inches of mercury, absolute when operating at rated turbine output with 70° F cooling water and 95% clean tubes. A tube cleaning system is provided to keep the condenser operating at peak performance. For purposes of guarantees and calculations, the steam flow is considered to be equally divided between these three zones. During a cold startup, the condenser must also deaerate the initial inventory of water contained within the condensate and feedwater system. 10.4.1.2 System Description To provide sufficient capability to meet the functional requirements stated in Section 10.4.1.1, the main condenser has the following specifications (some data listed below represents one set of variables and may vary based on ambient temperature and cleanliness and required maintenance tube plugging): Total surface area, sq. ft. 824,000 Circulating water quantity, gpm 410,000 Circulating water temperature 70.5 (yearly average), °F Circulating water temperature rise, °F 38 Number of shells 1 Number of passes 1 10.4-1
WBN-2 Tubes: Overall length, ft. 115 OD size, inches 1 Birmingham Wire Gauge (BWG) 18 and 22 Material SEA-CURE Number (18 BWG, top- row) 104 tubes (22 BWG, balance of tubes) 27,306 tubes Cleanliness, % 95 Duty, 109 Btu/hr 7.789 Overall dimensions: Length, ft. 137.5 Height, ft 62.5 Width, ft. 27.0 Design pressure: Shell, psig 25 and vacuum Hotwell, psig 30 Waterboxes, psig 72 Hotwell storage (normal), gallons 56,000 Oxygen content of condensate, cc/liter 0.005 Steam Flowrate to condenser, lb/hr Maximum guaranteed condition 8,100,000 Valves-wide-open condition 8,500,000 Bypass system: Flow, lb/hr 6,057,000 Pressure (at nozzle), psig 250 Enthalpy, Btu/lb 1191.3 Air inleakage, scfm 24 The main condenser has a rubber belt type expansion joint in the neck and the required impingement baffles to protect the tubes from incoming drains and steam dumps. A condenser seal trough-arrangement maintains the rubber belt expansion joints flooded with seal water for minimizing air inleakage through the expansion joint in the event of a pin hole in the seal. Operating experience indicates flooding the rubber belts with seal water contributes to seal degradation over time. Therefore, the seal water supply is normally isolated to prevent degradation. Portions of the U2 Zone B water trough were irreparably damaged. Therefore, the seal water line to this zone has been capped and can no longer be supplied to this Zone. The hotwell of the condenser has a water storage capacity equivalent to approximately 3 1/2 minutes of full-load operation. Provisions have been made for mounting three, 1/3 capacity, low pressure extraction feedwater heaters in the neck of each condenser pressure zone. 10.4-2
WBN The condenser is designed to remove dissolved gases from the condensate, limiting oxygen content to 0.005 cc per liter at any load during normal operation. During startup, the initial inventory of water contained within the condensate and feedwater system may be deaerated using steam piped from the auxiliary steam system along with that steam flowing through the turbine exhaust from the shaft sealing system. A recirculation line is run from immediately upstream of the feedwater isolation valves to a perforated pipe running across the condenser hotwell (see Section 10.4.7). Recirculated condensate is distributed across the condenser hotwell below the low water level and can be deaerated with auxiliary steam sprayed up through it from steam sparger nozzles located in a header arrangement in the hotwell, if necessary (also below the low water level). The condenser can accept a bypass steam flow of approximately 40% of maximum guaranteed steam generator flow, without exceeding the turbine high back pressure trip point or exceeding the exhaust hood temperature limits when starting from design circulating water inlet temperature and condenser back pressure conditions. This bypass steam dump to the condenser is in addition to the normal duty expected with a throttle flow of 60% of maximum guaranteed steam generator flow. The flow is distributed to the three pressure zones of the condenser by twelve, 10-inch perforated pipes which are designed to ensure that no high velocity steam jet can impinge on the tubes. Supports for these perforated pipes were designed for the dynamic loading which the bypass flow will impose. The correct secondary cycle water inventory is maintained by the automatic dumpback-makeup condensate system. The level controller, which is sensitive to the hotwell level, positions the dumpback valve or makeup valve (to or from condensate storage) as required to maintain the hotwell water level within normal limits. Separate makeup and return lines further provide the capability to clean up or maintain the condensate storage tank water quality during startup by continuously recirculating through this piping and the condensate system demineralizers, if required. Each condenser is equipped with a sampling system that monitors the cation conductivity. A given increase in cation conductivity at one or more of the nine sampling points after unit startup or during steady-state operation may indicate condenser cooling water inleakage. The nine sampling points were located in such a manner that the operator could determine (1) which tube bundle is leaking, (2) where the leak is located within the three condenser pressure zones, and (3) whether the leak is in the area of the tube-to-tube sheet joint, and if so, which of the four tube sheets is leaking. The condenser is divided into two sections and one section can be isolated during unit operation if it is found to be leaking. Each unit has the capability of operating at a reduced power level while one-half of its condenser waterboxes are isolated. By isolating one-half of the condenser waterboxes at a time, repairs and/or plugging of defective tubes can be accomplished within the action times specified for each action level in the Secondary Water Chemistry Program. The condensate polishing demineralizer system (CPDS) has sufficient ion exchange capacity to maintain condensate/feedwater quality within specified limits during periods of condenser inleakage. How long the unit can operate after condenser inleakage starts is a direct function of the quality of the raw water leaking into the condenser and the required secondary chemistry limits. 10.4-3
WBN The condenser tubes are SEA-CURE (UNS S44660), which is a ferritic stainless steel highly alloyed with chromium and molybdenum. The alloy additions are used to provide a high level of resistance where chloride induced pitting, crevice, and stress corrosion cracking may be encountered. The high modulus of elasticity of SEA-CURE results in tubing highly resistant to steam-induced vibration. The high strength of SEA-CURE also gives a very high fatigue endurance limit as added insurance against vibration induced failure. Also, the condenser tube cleaning system (Amertap) provides additional protection against pitting attack by keeping sediment and other particulate matter cleaned from the inside tube surfaces. 10.4.1.3 Safety Evaluation The inventory of radioactive contaminants in the main condensers is a function of the percentage of defective fuel rods, the escape rate coefficients, the steam generator primary-to-secondary leak rate, and considers the steam generator and condenser partitioning coefficients. Primary-to-secondary leakage has the potential for supplying measurable quantities of hydrogen to the condensate system. However, for large primary-to-secondary leakage rates (1.0 gpm), the rate of hydrogen release would be less than 0.01 scfm. This rate is small when compared to the normal two pump condenser evacuation system capacity of 24 scfm. Thus, hydrogen entering the condenser is effectively exhausted via the condenser evacuation system and the potential for hydrogen buildup is negligible. The condenser could become ineffective because of the loss of some or all of its cooling water and/or excessive air inleakage. Either of these conditions will cause the condenser pressure to increase, and upon reaching the Westinghouse recommended limits the units would be manually or automatically tripped, in accordance with operations instructions. The residual heat during the above conditions is removed by dumping steam to the condenser through the turbine bypass valves when the condenser pressure is below approximately 6.5-inches Hg absolute and at least one circulating water pump is operating. At a condenser pressure of approximately 6.5-inches Hg absolute or higher or when no circulating water pumps are operating, the turbine bypass valve will automatically trip closed if open (and be prevented from opening if closed). The residual heat will then be removed by dumping steam to the atmosphere through the power operated atmospheric relief valves and/or the ASME code safety valves. There is no interface between the loss of main condenser vacuum and the MSIVs because the turbine bypass valves provide isolation of the steam source. The Turbine Building does not contain any Engineered Safety Features (ESF); hence, no ESF would be directly affected by failure of a condenser shell, or hotwell, or by loss of condenser vacuum. The condenser is in its own pit, with a free volume much greater than the hotwell/condensate water volume. The effects of the failure of a condenser waterbox or circulating water piping are discussed in Section 10.4.5. 10.4-4
WBN 10.4.1.4 Inspection and Testing The condenser has been tested for leaks by completely filling the shell with condensate. The waterboxes have been leak tested by filling them with raw water. Manways provide access to water boxes, tube sheets, lower steam inlet section, shell, and hotwell for purposes of inspection, repair or tube plugging. 10.4.1.5 Instrumentation Sufficient level controllers, level switches, pressure switches, temperature switches, etc., are provided to permit personnel to conveniently and safely operate the condenser system. The condenser instrumentation is included in the control diagrams for the condensate system, Figures 10.4-9 through 10.4-11A. 10.4.2 Main Condenser Evacuation System 10.4.2.1 Design Bases The design basis for the main condenser evacuation system is the capability to create and maintain condenser back pressure at 1.0-inch mercury absolute, by removing noncondensable gas and air inleakage. The design evacuation rate is 24 scfm. The condenser evacuation system piping is designed in accordance with ANSI B31.1 1973 Edition through Summer 1973 Addenda. 10.4.2.2 System Description The main condenser evacuation system is shown in Figures 10.4-7, 10.4-9, 10.4-10, and 10.4-12. These figures show the flow, control, and logic diagrams, respectively, for the condensate system. To provide sufficient capability to meet the functional requirements as stated in Section 10.4.2.1, the main condenser evacuation system has been designed with the following specifications which meet the requirements of the Heat Exchange Institute for steam surface condensers: Type of evacuating equipment Mechanical vacuum pump Number of vacuum pumps, per unit 3 Air capacity at suction pressure 15 of 1-inch Hg absolute, per pump at normal operation,scfm Air capacity at suction pressure 800 of 15-inch Hg absolute, per pump at startup, scfm 10.4-5
WBN The vacuum pumps are two stage, liquid ring type pumps. Two pumps, operating in parallel, are adequate for the removal of the maximum expected air inleakage of 24 scfm. The third vacuum pump is arranged to start automatically on increasing condenser back pressure. 10.4.2.3 Safety Evaluation One of the three vacuum pumps is a backup unit. This unit automatically starts when the condenser back pressure increases to approximately 4.6-inches Hg absolute. Should the back pressure continue to increase (because of inadequate air removal capability), the turbine would trip and, consequently, cause a reactor trip. The turbine trip would automatically occur at approximately 6 to 12 inches Hg absolute. Details of the radiological evaluation of the condenser evacuation system are contained in Chapter 11. 10.4.2.4 Inspection and Testing A flowmeter is provided with each vacuum pump for condenser inleakage measurement. Periodic readings of these flowmeters will indicate whether or not the air inleakage to the condenser is within acceptable limits. These readings will also indicate the effectiveness of the operating vacuum pumps. Preoperational test requirements are given in Chapter 14. 10.4.2.5 Instrumentation Unit 1 Pressure switches are provided to automatically start a standby vacuum pump(s) as required. The vacuum pump exhaust to atmosphere has two types of radiation monitors. The normal range monitors give early indication of primary to secondary steam generator tube leakage and annunciates in the Main Control Room (MCR) when the radiation level reaches limits specified in the WBN Offsite Dose Calculation Manual (ODCM). An accident range monitor is employed to monitor this flow path subsequent to a design basis accident. The instrumentation for this system is shown on the electrical control diagram for the condensate system, Figure 10.4-10. Unit 2 Pressure switches are provided to automatically start the standby vacuum pump. The vacuum pump exhaust to atmosphere has three types of radiation monitors. The normal range monitor, sampling vacuum pump exhausts, gives early indication of primary-to-secondary steam tube leakage and annunciates in the Main Control Room when radiation level reaches limits specified in the WBN Offsite Dose Calculation Manual (ODCM). Two accident range monitors are employed to monitor this flow path subsequent to a design bases accident. Each is an area radiation monitor mounted directly on the exterior of the Condenser Vacuum Exhaust pipe. The mid-range, mounted area radiation monitor includes a Gieger-Mueller tube detector. The high range, mounted area radiation monitor includes a gas-filled gamma ionization chamber detector. Additional information regarding these three radiation monitors is provided in Section 11.4.2.2.2. The instrumentation for this system is shown on the electrical control diagram for the condensate system, Figure 10.4-10. 10.4-6
WBN-3 10.4.3 Turbine Gland Sealing System 10.4.3.1 Design Bases The turbine gland sealing system is designed to seal the main turbine shafts and valve stems and the main feed pump turbine shafts using steam from upstream of the turbine stop valves. The sealing can be accomplished automatically with steam supply of pressure 185 psia or more, and manually with steam supply pressure between 108 psia and 185 psia. The turbine gland sealing system is designed in accordance with ANSI B31.1 1973 Edition through Summer 1973 Addenda. 10.4.3.2 System Description The turbine gland sealing system is shown on Figure 10.4-1. The purpose of the gland steam sealing system is to prevent leakage of air into the turbine casing, and conversely, prevent the leakage of steam into the turbine room when the turbine casing is pressurized. The system utilizes metallic labyrinth type shaft seals. Each seal is equipped with two annular chambers which are located among the packing rings. The inner chamber nearest the turbine casing is maintained at a pressure of approximately 16 psia by the admission of sealing steam or the controlled leak-off of higher pressure steam. The outer chamber is maintained at a slight vacuum (approximately 3- to 5-inches water) by the gland steam exhauster system. The vacuum causes the sealing steam to leak outward and mix with any inward leaking air. This mixture flows to the gland steam condenser where most of the steam is condensed and returned to the secondary cycle. The noncondensibles are forced by the exhauster through piping to the outside of the Turbine Building. 10.4.3.3 Safety Evaluation Since this is a PWR, radioactive steam in the steam seal system is of very small consequence. The exhauster discharge is piped outside of the building to prevent the possible accumulation of radioactive particles in a stagnant building area. In the event one exhauster is lost, the ineffective exhauster is isolated and the spare one started. Should both exhausters fail, seal steam will leak into the turbine room. If the steam seal supply fails, excess air leakage will probably trip the turbine because of high condenser back pressure. A number of safety valves and rupture diaphragms are installed on this system to protect the various components against high pressure. The radiological effects of this system are negligible during normal operation. A radiological evaluation of the loss of the system is presented in Chapter 11. 10.4.3.4 Inspection and Testing This equipment will be tested by the vendor in accordance with the various applicable code requirements. 10.4-7
WBN 10.4.3.5 Instrumentation Sufficient instrumentation has been provided to satisfy all system functional requirements and to permit safe, convenient operation by plant personnel. System performance is constantly monitored by measuring gland steam exhauster vacuum and supply header pressure. 10.4.4 Turbine Bypass System 10.4.4.1 Design Bases The turbine bypass system is designed to reduce the magnitude of nuclear system transients following large turbine load reductions by dumping throttle steam directly to the main condenser, thereby creating an artificial load on the reactor. The turbine bypass system has the following functional requirements:
- 1. Permit a direct bypass flow to the main condenser of 40% of rated turbine flow, thereby allowing a turbine step load reduction of 50% without a resultant reactor trip or actuating the steam generator safety valves (MSSVs).
- 2. Permit turbine trip (accompanied by reactor trip) from full load without opening steam generator safety valves.
- 3. Provide plant flexibility during operation by allowing turbine load changes in excess of the base NSSS design, without reactor trip.
- 4. Provide controlled cooldown of the NSSS.
- 5. Assist in achieving stable startup and cooldown of the plant.
The turbine bypass system piping is designed in accordance with ANSI B31.1 1973 Edition through Summer 1973 Addenda. 10.4.4.2 System Description The turbine bypass system and its instrumentation and controls are shown on Figures 10.3-1 through 10.3-7, which are the flow, control and logic diagrams for the main and reheat steam. The capability for meeting the functional requirements of Section 10.4.4.1 has been provided by designing the equipment to the following specifications: Number of valves - 12 Flow per valve - 532,170 lb/hr Main steam pressure at valve inlet (for above flow) - 900 psig Maximum flow per valve at 1185 psig inlet pressure - 970,000 lb/hr Time to open (full stroke) - 3 seconds Full stroke modulation - 20 seconds Failure position - Closed 10.4-8
WBN The steam leads from the four steam generators are cross-connected immediately upstream of the turbine stop valves. Piping is run from this header to the 12 turbine bypass valves and then to the condenser. Eight valves discharge into the low pressure zone of the condenser, three valves discharge into the intermediate pressure zone, and one valve discharges into the high pressure zone. This arrangement helps to prevent exceeding of the differential backpressure/temperature limits between low pressure turbines during steam dump operation. The turbine bypass valves are operated in one of the two control modes: (1) TAVG Mode, (2) steam pressure mode. The TAVG Mode is normally used during plant operation. The Steam Pressure Mode is normally used during plant startup and shutdown. Refer to Section 7.7.1.8 for detailed description of the turbine bypass valve control. The bypass valves are built in accordance with ASME Section III, Class 2, which invokes ANSI Standard B16.5. All piping in the steam bypass system is in accordance with ANSI Standard B31.1. 10.4.4.3 Safety Evaluation The turbine bypass valves are blocked from operating if any of the following abnormal process conditions exists: 1) condenser is unavailable (high absolute pressure), 2) no condenser circulating water pumps operating, or 3) low-low reactor coolant average temperature. If the above process conditions are normal, the following conditions will arm the control system and allow turbine bypass valve operation: 1) reactor trip signal, 2) turbine load rate change greater than setpoint, or 3) control mode hand switch placed in the Steam Pressure Mode. A manual hand switch is used to block the low-low reactor coolant average temperature signal (P-12) to allow operation of the three turbine bypass cooldown valves. An alternate method of RCS cooldown, below 350°F (i.e., delay RHR cut-in), is provided via the turbine bypass valves. The alternate method provides for disabling the P-12 interlock during cooldown after entering Mode 4. The temporary disablement can be performed procedurally with no permanent hardware modifications to the unit. Permanent control board indication of the bypassed condition is not provided nor is the bypass automatically removed when the permissive conditions are no longer met. The use of all twelve turbine bypass valves is optional for the Operator. The turbine bypass valves are controlled using the steam pressure controller before and after the protective interlock is disabled. The interlock disablement procedure for utilization of all twelve valves is performed only after shutdown (and subsequent cooldown) has been initiated and therefore, does not present a reactor trip hazard. An analysis has been performed to assess the cooldown potential following failure of the steam dump controller after placing all turbine bypass valves in service. It was determined that the three turbine bypass cooldown valves spuriously opening at the protective interlock setpoint of 550°F can produce a cooldown rate that far exceeds that of all twelve turbine bypass valves opening at 350°F (temperature below which additional valve use is permitted). 10.4-9
WBN Loss of the control air supply to the diaphragms of the bypass valves will prevent the valves from opening, or, if the valves are open, will trip them closed. In the event of loss of the turbine bypass valves, the steam generators will still be protected during all transients by the ASME code safety valves. Steam generator cooldown capability will be available through use of the power operated relief valves (atmospheric dump). Inadvertent or accidental opening of any one bypass valve during power operation will not subject the reactor coolant system to an uncontrolled cooldown. Cooldown consequences may be minimized by operation of the rod control system and/or the overpower T runback function. Failure of the turbine bypass system can result in discharge of steam to the atmosphere through the steam generator safety valves. If tube leaks are present prior to the incident, some radioactivity accumulated in the steam generator shell side water would be discharged through the safety valves. This radioactivity will be well within limits established by 10 CFR 100. Failure of the turbine bypass system will not affect, directly or indirectly, any engineered safety feature system. 10.4.4.4 Inspection and Testing This equipment will be tested in accordance with the various code requirements. Periodic tests will be performed to assure that the system remains capable of its functional requirements. Inservice inspection in accordance with ASME Section XI is not required. Preoperational test requirements are given in Chapter 14. 10.4.4.5 Instrumentation Sufficient instrumentation has been provided to permit this system to:
- 1. Satisfy all its functional requirements,
- 2. Protect the reactor (from low-low T-average),
- 3. Protect the turbine (from high condenser pressure).
The instrumentation for this system is shown on Figures 10.3-5 through 10.3-7, the logic diagrams for the main and reheat steam. 10.4.5 Condenser Circulating Water System This section covers the design and operating aspects of the condenser circulating water (CCW) system, including the circulating water pumps, the circulating water conduits, the main condenser, the hyperbolic natural draft cooling towers, the yard holding pond, the desilting basin, and the supplemental CCW (SCCW). The primary function of the CCW system is to provide cooling water to the condensers for the main steam turbines. The system provides an efficient means of dissipating waste heat from the power generation cycle into the ambient surroundings while meeting all applicable chemical and thermal effluent criteria. Because of the capacity and convenience, the blowdown from the CCW system is used to dilute and dispense the low-level radioactive liquid wastes from the radwaste, steam generator blowdown, and condensate polishing demineralizer systems. 10.4-10
WBN-1 10.4.5.1 Design Basis
- 1. The CCW system provides a design flow of approximately 410,000 gpm to the main condenser. The main condenser flows result in a temperature rise of 38°F for the circulation water through the condensers in the process of receiving approximately 7.8 x 109 Btu/hr of waste heat. This water flow is a sufficient quantity to condense the steam at an optimum main condenser back pressure and to dissipate all rejected heat.
- 2. The CCW system provides a means of meeting all applicable water thermal criteria by dissipating the waste heat directly to the atmosphere by means of a single hyperbolic natural draft cooling tower for each unit and to the river via the SCCW.
- 3. The CCW system provides for dilution and dispersion of low-level radioactive liquid wastes. The upper limits on the activity levels are discussed in Section 11.2.
10.4.5.2 System Description The flow diagram for the CCW system is shown in Figures 10.4-2 and 10.4-3. The system control and logic diagrams are shown in Figures 10.4-4 through 10.4-6. A single loop CCW system is employed for each of the two units. The system is designed so that the cooling tower, conduits, circulating water pumps, and main condenser constitute a cooling loop. The CCW pumping station is an independent structure located in the yard between the Turbine Building and the cooling towers. Four pumps for each unit are provided in this pumping station to operate in parallel and circulate water from the cooling tower cold water basin, through the condenser, and back to the heat exchanger section of the cooling tower. The eight condenser circulating water pumps are of the electric-motor-driven, vertical, dry pit, single-stage, double-suction, centrifugal, volute type. Each pump has a capacity of 102,500 gpm at a design head of 102.5 feet such that each group of four pumps supplies the full flow requirements of one generating unit. System required head is 98 feet. Adequate positive pressure is maintained on the pump suction by the available static head between the normal water level in the cooling tower basin, elevation 730.0, and the centerline elevation of the pump suction, Elevation 715.25. Normal water level can be maintained by operation of the raw cooling water (RCW) bypass strainer, and low level is alarmed in the main control room. The main condenser is of the single shell, triple pressure type with a divided water box, as described in Section 10.4.1. An Amertap condenser tube cleaning system is provided for automatic continuous cleaning of the condenser tubes during normal operation. Tandem, metal expansion joints are provided on both inlets and both outlets of the main condenser to accommodate the thermal expansion of the condenser shell and tubes resulting from the differing temperatures encountered during various modes of operation. A motor-operated butterfly valve is located in each inlet and outlet line to the condenser. These valves provide for isolation of either half of the condenser and the related expansion joint or tube cleaning system. 10.4-11
WBN Each of the two hyperbolic natural draft, counterflow cooling towers is designed to reject the full-load waste heat of a single unit main condenser to the atmosphere by evaporation as the CCW passes through the film-type heat exchange section. The cooling towers are designed to cool the circulating water to 73.5°F based on a mean annual design wet bulb temperature of 52.3°F and a mean annual design dry bulb temperature of 57.0°F. Cooling tower blowdown (CTB) water is extracted from the discharge flume of each cooling tower and can be returned directly to the reservoir through a system of multiport diffusers. The blowdown rate is determined by the height of the water level in the flume over the crest of a blowdown weir; therefore, it is directly related to the control of the makeup flow. Blowdown can be continuously discharged to the reservoir during normal operation of the circulating water system as long as the river flow rate is not below 3500 cfs. The river flow past the plant is determined by the measurement of flow release through the hydro units of Watts Bar Dam. The flow rate through a single hydro unit at minimum operating lake level is 3500 cfs, which is the minimum flow that can be accurately determined. Whenever river flow drops below 3500 cfs, it becomes necessary to withhold blowdown to avoid violation of thermal or chemical discharge standards. Under this situation the blowdown will continue to be discharged from the cooling towers; however, the diffusers will be isolated and the blowdown will be diverted to the yard holding pond. This pond will serve as a storage area for the blowdown until such time as the river flow again becomes sufficient to accept the discharge. The duration of low river flow generally does not exceed 12 hours during which time less than half the 190 acre-feet volume of the pond would be required for storage of blowdown. Upon resumption of sufficient river flow, the blowdown from the two towers and the water stored in the holding pond will be discharged into the river through the diffuser. The diffuser system has been designed to provide the proper dilution of the discharge into the river for the various combinations of two unit operation and draw down of the holding pond, while remaining within the limits of all applicable effluent standards. Whenever blowdown water is being discharged to the river, the blowdown serves as the source of dilution flow for the discharge from the plant radioactive waste disposal system and for radioactively contaminated regenerative waste (if it is within the discharge specification described in Section 10.4.6). Refer to Section 11.2 for a detailed description of the liquid waste management systems. The cooling tower blowdown system will also serve as an alternate source for disposal of blowdown from the steam generators as described in Section 10.4.8. Discharge of low level radioactive waste into the cooling tower blowdown to the reservoir or yard holding pond is discontinued when either the blowdown flow rate is not sufficient for proper dilution or upon high radiation signal. 10.4-12
WBN Evaporation, drift, and blowdown losses from the system are replaced by the ERCW discharge, and raw cooling water (RCW) discharge, as required. To enable the raw cooling water system to be utilized to the fullest extent, a bypass line with modulating valve is provided from the RCW supply to RCW discharge headers. This line will permit that portion of RCW system flow in excess of the RCW component requirements to bypass the Turbine Building and serve as additional makeup to the CCW system. Refer to Sections 9.2.1.2, and 9.2.8.2, for additional discussion of the cooling tower makeup. Chemical additives including biocide injection and corrosion inhibitors are added as required for biological and corrosion control. Chemicals may also be periodically injected into the CCW system as necessary to prevent organic fouling. When chemicals are introduced into the CCW system, the chemicals may be injected into the CCW conduits on the suction side of the CCW pumps, the hot water return to the cooling tower, or the cooling tower basin. Provisions are made to comply with the requirements of the National Pollutant Discharge Elimination System (NPDES) permit. Water discharged into the CCW system, including initial filling and makeup, comes from the river via the ERCW, RCW, and SCCW systems. Provisions made in the ERCW and RCW to control the introduction of Asiatic clams will also prevent their introduction into the CCW loop. Refer to Sections 9.2.1.6 and 9.2.8.2 for a description of these provisions. 10.4.5.3 Safety Evaluation The Cooling Towers, Condenser Cooling Water Pumping Station, pumps and motors, associated conduits, and the SCCW are not required to be designed to Seismic Category I, tornadic wind, or maximum flood requirements, since they are not required for safe shutdown of plant. The Cooling Towers are located such that the towers' structural failure due to a seismic event, a tornado, or any other natural phenomenon could not damage any safety-related structure, system, or component. The WBN Turbine Building has been shown to be seismically rugged and not pose a collapse or falling interaction concern under safe shutdown earthquake (SSE) loading. Within the Turbine Building, the steam surface condenser (and associated anchorage) and the 102-inch condenser inlet and outlet piping have been determined to be seismically robust and therefore capable of maintaining structural and pressure boundary integrity. However, the auxiliary connections to the CCW system are not capable of maintaining their structural and pressure boundary integrity. The operator will be alerted via MCR annunciation to a rising water level in the Turbine Building condenser pit area due to one or more flood level instruments located in the atmospheric condensate drain tank pump area of each unit mounted at Elevation 673.5) due to a rupture of the CCW piping inside the Turbine Building. The power supply to the CCW pumps and valves are provided with diverse remote trip and isolation capabilities to allow the operator to trip the pumps upon rising water in the Turbine Building. 10.4-13
WBN-2 All penetrations and passageways from the Turbine or Service Buildings to the Auxiliary or Control Buildings are sealed for flooding up to a minimum Elevation 711.0 in the Service and Turbine Buildings. This requirement applies to all doorways, electrical penetrations, and mechanical piping penetrations. The 711.0 foot elevation exceeds the maximum expected flood level resulting from a condenser circulating water system rupture in the Turbine Building (See Section 3.8.4.4.1). Also, there is no equipment essential to plant safety located either in the Turbine or Service Buildings. Consequently, water from a CCW system rupture cannot endanger any safety-related equipment, including essential electrical systems. Figure 1.2-5 shows the personnel passageways below Elevation 729.0 that connect the Turbine and Service Buildings to the Control and Auxiliary Buildings. Piping of any system which conveys flow (makeup) to the heat rejection system has provisions to prevent back flow of the condenser circulating water into any area where flooding of safety-related components would result from a failure of the system providing the flow. The seismic ruggedness of the 102-inch CCW piping in the Turbine Building will limit the size of a break such that sufficient time exists for the break to be isolated by manual operator action prior to flooding the Turbine Building above the 708.0 elevation. 10.4.5.4 Inspection and Testing Although not required from a safety standpoint, for each of the WBN plant units, the CCW sub-systems for that unit undergo hydrostatic and performance tests prior to operation of those sub-systems to ensure the adequacy of the system to meet operational requirements. For each unit, once the unit becomes operational, routine visual inspection of the system components and instrumentation should be sufficient to verify continued operability. 10.4.5.5 Instrumentation Application Since low level radioactive liquid waste from the waste disposal system, the CPDS, and, at times, the steam generator blowdown are discharged into the CTB, provisions are made to isolate these discharges when adequate dilution does not exist or upon high radiation signal. Specifically, a flow element is provided in the CCW blowdown line upstream of the diffusers. If there is not at least 30,000 gpm passing through the blowdown line or if the waste source exceeds a predetermined high radiation level setpoint, based on dilution, valves in the discharge lines from the three waste sources are automatically closed. (See Sections 10.4.6, 10.4.8 and 11.2). The CPDS and SGB may be released with the CTB dilution flow < 30,000 gpm provided the requirements of Section 11.2.4 are satisfied. As described in Section 10.4.5.2, a signal of less than 3500 cfs flow through the hydro units of the upstream dam will result in cessation of blowdown discharge to the river by closing the valving in the diffuser flowpath to the river. If the diffuser flowpath is isolated, then the diffuser flow element will drop below 30,000 gpm causing the valves in the waste disposal system, steam generator blowdown system, and the CPDS discharge lines to close in order to preclude the possibility of discharging radioactive waste in the yard holding pond. See above for conditions permitting discharge when flow is less than 30,000 gpm. 10.4-14
WBN 10.4.6 Condensate Polishing Demineralizer System 10.4.6.1 Design Bases - Power Conversion The function of the CPDS of each unit is to remove dissolved and suspended impurities from the secondary system. The CPDS removes corrosion products which are carried over from the turbine, condenser, feedwater heaters (after startup), and piping. The removal of impurities and corrosion products in the secondary system reduces corrosion damage to the secondary system equipment. The CPDS also removes impurities which might enter the system in the makeup water, and removes radioisotopes which are then carried over to the secondary cycle in the event of a primary-to-secondary steam generator tube leak. The CPDS will also be used to remove impurities which enter the secondary system due to condenser circulating water tube leaks. The continuous steam generator blowdown flow may be processed through the CPDS in normal operation, or it may be discharged when the radioactivity level is low. The blowdown will be treated by the CPDS when radioactivity levels exceeding release limits determined in accordance with ODCM are detected in this stream. The CPDS will polish condensate before startup, during restarts, and power generation as required. Prior to the startup mode, the steam generators are isolated from the feedwater. This will assure that the feedwater chemistry quality is acceptable before steam generation begins. Before feedwater is introduced into the steam generators, the CPDS demineralizer service vessel (CDSV) effluent quality will be such that the Feedwater Chemistry Specification can be met. The CPDS has the capability of polishing the full flow of condensate. The CPDS CDSV design temperature is 140°F and the design pressure is 300 psig. The pressure drop across the CPDS demineralizer service vessels does not normally exceed 60 psi. When this pressure differential across the vessels is exceeded, the major part of the condensate flow will automatically bypass the demineralizer. The function of the condensate startup (Red Iron) filters are used during startup and as required for removal of the hematite and other corrosion products from the condensate system. These startup filters (12 filters total) are essential to achieve rapid cleanup of the condensate system. Range of flow per filter is 650 gpm to 750 gpm. Maximum design pressure for the Condensate Startup Filters is 300 psig. 10.4.6.2 System Description The CPDS for each unit consists of six mixed-bed CDSVs; the number of polishers in service varies with system conditions. The system also includes an external regeneration facility and equipment to handle regenerate wastes. The regeneration subsystem consists of a resin separation/cation regeneration tank, anion regeneration tank, and resin storage tank. The concentrated chemicals used in regeneration are supplied from the makeup water treatment plant acid and caustic storage tanks. 10.4-15
WBN Additional equipment is provided in the regeneration system to promote efficiency in the process. A hot water tank supplies hot dilution water at the caustic mixing tee. An ammonium hydroxide tank and a pump are provided to inject ammonium hydroxide into the resin separation/cation regeneration tank and anion regeneration tank prior to and during regeneration. The regenerant chemicals and the high conductivity rinse water containing regenerant chemicals flow to the batch neutralization tank or, alternatively, to the nonreclaimable waste tank. Both the neutralization tank and nonreclaimable waste tank are provided with the capability of adjusting the Ph of the regenerant chemical waste. If the inventory of these tanks is radioactive, it may be discharged to the cooling tower blowdown if the radioactivity level is within ODCM limits. When ODCM limits are exceeded, the inventory is processed by a vendor (See Section 11.2). If the inventory of these tanks contains no gamma emitting radionuclides, it is pumped to the Turbine Building sump and subsequently discharged through the holding pond or, alternately, it is discharged to the CTB. The wash, rinse, and resin sluicing waters of low conductivity are collected in two high crud tanks. If the inventory of the high crud tanks contains no gamma emitting radionuclides, it is pumped to the Turbine Building sump and subsequently discharged through the holding pond or, alternately, it is discharged to the CTB if radioactivity levels are within ODCM limits. When ODCM limits are exceeded, the inventory may be processed by a mobile demineralizer (See Section 11.2). Flow diagrams for the CDSVs, regeneration equipment and waste handling equipment are shown in Figures 10.4-36A, 10.4-36B and 10.4-36C, respectively. For each unit, the CPDS CDSVs and regeneration equipment are located within the Turbine Building. The six CDSVs are arranged in three shielded compartments (two to a compartment). Regeneration vessels and chemical reclaim tanks are arranged in individual compartments. The hot water tank is also in the Turbine Building. The acid and caustic storage tanks are located in a separate structure near the Turbine Building. The tanks in the CPDS are rubber-lined to prevent corrosion except the hot water tank (Keysite lined), the acid storage tank (unlined), and ammonium hydroxide tank (unlined). CPDS tanks are closed and are designed and fabricated in accordance with the ASME Code for Unfired Pressure Vessels Section VIII, 1974 edition. The CPDS is not a safety-related system and is not required for the orderly shutdown of the reactor. The Turbine Building housing the CPDS equipment is a nonseismic structure; piping, piping hangers, and equipment in the CPDS are nonseismic. The system piping is in accordance with ANSI Standard B31.1. The CPDS CDSVs for each unit are arranged in parallel and are supplied by the condenser hotwell pumps via the inlet header. An outlet header collects the effluent from the CDSVs and supplies suction flow to either the condensate booster pumps or demineralized condensate pumps (see Section 10.4.7.1). The bypass valve is located across the influent and effluent headers in parallel with the CDSVs. Outlet piping from each service vessel is equipped with a resin trap. 10.4-16
WBN The CPDS operates in either of three modes as determined by the water quality and the pressure differential across the CDSVs.
- 1. Mode 1 - Full flow polishing (bypass valve closed), is the operating mode during which the unit's CDSVs bypass valve is manually selected for the close position
- 2. Mode 2 - Modulating bypass (bypass valve partially open), is the operating mode during automatic control when the pressure differential across the CDSV influent and effluent headers is less than setpoint. In this mode, the major part of the condensate flow will be bypassed around the CDSVs. Only a minimum flow will be processed through the CDSVs which is enough to maintain the resin beds in a compact, standby condition.
- 3. Mode 3 - Full bypass (bypass valve fully open), is the operating mode in the event the CPDS experiences loss of control air and/or electrical failure, or when the pressure differential across the CDSV influent and effluent headers exceeds the setpoint.
The CPDS bypass valve may be operated under automatic control. Override is provided for manually positioning the bypass valve in the 'open' and 'close' positions. Modulating bypass protects the CDSVs from excessive pressure drop. The bypass valve may be manually placed in the full bypass position (and the CDSV inlet valves closed) when the inlet condensate temperature exceeds operational limits in order to protect the functional characteristics of the ion exchange resins. Continued operation in the bypass mode is dependent upon influent condensate water quality. 10.4.6.3 Safety Evaluation Radionuclides are released to the secondary system when there is a steam generator tube leak. The radionuclides have essentially no effect on the resin ion exchange capacity. Also, filtered suspended solids do not affect ion exchange capacity. Although the radionuclide concentrations have no effect on resin capacity, potential activity levels in the CDSVs and associated regeneration equipment make it necessary to shield the CPDS equipment. Liquid radwaste is processed by the waste disposal system. Chapter 11 describes the radioactivity level and removal of radioactive material from the CPDS. 10.4-17
WBN 10.4.6.4 Inspection and Testing For each unit the CPDS undergoes a preoperational test prior to startup (refer to Chapter 14). After startup and during shutdowns, each vessel in the system can be separately isolated for testing and visual inspection. The CPDS is designed so that CDSVs, regeneration equipment, and most valves can be isolated from the system if testing or inspection is required, with no curtailment or interruption of power generation. Isolation valves on inlet and outlet of CDSVs and system bypass valves can be tested and inspected during shutdowns if required. 10.4.6.5 Instrumentation Instrumentation and controls are provided to perform the following functions:
- 1. Measure, indicate, and record condensate conductivity in the effluent line of each CDSV.
High conductivity downstream of a particular CDSV indicates resin exhaustion. Conductivity values are annunciated at the CPDS local control panel.
- 2. Measure differential pressure between the CDSV battery influent and effluent headers, and open the valve bypassing the CDSVs on high differential pressure signal when the bypass valve is under automatic control.
- 3. High differential pressure across the CDSVs is annunciated on the CPDS local control panel. Opening of the battery CDSV bypass valve is indicated on the CPDS local control panel and in the MCR.
- 4. Measure and indicate condensate temperature at the influent header. High influent condensate temperature is alarmed at the CPDS local control panel.
- 5. Measure, record, and indicate flow rates through individual CDSVs. The difference in flow rates through each CDSV indicates the extent of crud loading on each CDSV resin bed.
- 6. Annunciate at the CPDS local control panel high differential pressure across each resin trap strainer.
- 7. Measure, indicate, and record the dissolved sodium content in the effluent of the selected CDSV and in the effluent condensate header. High level sodium content is annunciated at the CPDS local control panel.
10.4-18
WBN 10.4.7 Condensate and Feedwater Systems 10.4.7.1 Design Bases The condensate and feedwater systems are designed to supply a sufficient quantity of feedwater to the steam generator secondary side inlet during all normal operating conditions and to guarantee that feedwater will not be delivered to the steam generators when feedwater isolation is required. A complete discussion of feedwater isolation is included in Chapter 15. The condensate and feedwater systems pumps take condensate from the main condenser hotwells and deliver water to the steam generators at an elevated temperature and pressure. These systems are capable of delivering water to the steam generators at the rated thermal. 10.4.7.2 System Description The flow diagrams for the condensate and feedwater systems are presented in Figures 10.4-7 and 10.4-8. Figures 10.4-9 through 10.4-15 and 10.4-17 and 10.4-18 provide the control and logic diagrams for this system. The ability to meet the design requirements of Section 10.4.7.1 is provided by the following equipment (per unit):
- 1. Hotwell Pumps Number - 3 Manufacturer - Borg-Warner Corporation, Byron Jackson Pump Division Type - VMT, four stages, single suction, vertical process Size - 28KXFH Design Point - 6700 gpm, 600 feet head Motor Manufacturer - Parsons-Peebles, Ltd.
Motor Design - 1250 hp, 1180 rpm, 6600 V, 3 phase, 60 Hz, vertical, constant speed 10.4-19
WBN
- 2. Condensate Booster Pumps Number - 3 Manufacturer - Borg-Warner Corporation, Byron Jackson Pump Division Type - DVDSR, single stage, double suction, double volute, centrifugal Size - 14 x 14 x 15H Design Point - 9000 gpm, 680 feet head Motor Design - 1750 hp, 3584 rpm, 6600 V, 3 phase, 60 Hz, horizontal, constant speed Motor Manufacturer - Parsons-Peebles, Ltd.
- 3. Main Feedwater Pumps Number - 2 Manufacturer - Borg-Warner Corporation, Byron Jackson Pump Division Type - HDR, single stage, double suction, double volute centrifugal Size - 20 x 20 x 18B Design Point - 23,600 gpm, 1890 feet head Service Conditions - Pump suitable for continuous service to deliver up to 17,630 gpm at 402.3°F against a total head of approximately 2012 feet at 5012 rpm, while operating with a minimum net positive suction head of 200 feet.
- 4. Standby Main Feedwater Pumps Number - 1 Manufacturer - Borg-Warner Corporation, Byron Jackson Pump Division Type - DVS, single stage, double suction, double volute, centrifugal Size - 12 x 12 x 16 10.4-20
WBN Design Point - 6100 gpm, 1890 feet head Motor Design - 3700 hp, 3584 rpm, 6600 V, 3 phase, 60 Hz horizontal Motor Manufacturer - Parsons-Peebles, Ltd. Speed Increaser - Lufkin Model N1400C, 1.5:1 ratio
- 5. Demineralized Condensate Pumps Number - 3 Manufacturer - Ingersoll-Rand Company Type - A, single stage, single suction, end suction process Size - 10 x 18AA Design Point - 6700 gpm, 150 feet head Motor Manufacturer - Westinghouse Motor Design - 350 hp, 1770 rpm, 460 V, 3 phase, 60 Hz, horizontal, constant speed
- 6. Main Feedwater Pump Turbine Number - 2 Manufacturer - Westinghouse Electric Corporation Type and Speed - EMM-32AIN, Multi-stage, dual inlet, 5460 rpm Throttle Pressure - LP steam, 146 psig HP steam, 995 psig Throttle Temperature - LP steam, 513°F HP steam, 546°F Back Pressure - 6.9 in of Hg absolute Number of Stages - 6 Extraction Points - None Rated Horsepower - 12,200 hp 10.4-21
WBN
- 7. Main Feedwater Pump Turbine Condenser Number - 2 Manufacturer - Westinghouse Electric Corporation Tube Material - ASME SA688, 304 SST Channel Design pressure - 350 psi Channel Design temperature - 259°F Shell Design Pressure - 20 psig and 30 in. mercury vacuum, Shell Design temperature - 160°F
- 8. Gland Steam Condenser Number - 1 Manufacturer - Westinghouse Electric Corporation Tube Material - ASTM A249, TP 316 Stainless Steel Channel Design pressure - 400 psig Channel Design temperature - 125°F Shell Design Pressure - 400 psig Shell Design Temperature - 125°F
- 9. Feedwater Heaters Number - 21 (3 strings of 7 heaters)
Manufacturers - Nos. 1 and 2: Yuba Heat Transfer Corp. Nos. 3 and 4: Foster Wheeler Energy Corp. Nos. 5, 6, and 7: McQuay-Perfex Incorp. Type - Closed, horizontal, U-tube Tube Material - 304 SST 10.4-22
WBN-3 Channel Design Shell Design Channel Design Shell Design Heater No. Pressure (psi) Pressure, psig Temp (°F) Temp, (F) 1 2000 545 480 480 2 2000 355 440 440 3 725 232 380 380 4 725 75 300 U1 450 U2 385 5 350 50 300 U1 300 U2 285 6 350 50 300 220 7 350 50 300 180 Feedwater heaters are designed in accordance with HEI standards for closed feedwater heaters and the ASME Boiler and Pressure Vessel Code, Section VIII. All piping and valves from the condenser hotwell to the feedwater isolation valve are designed in accordance with ANSI B31.1, while the remainder of the feedwater system is designed in accordance with the ASME Boiler and Pressure Vessel Code, Section III, Class 2. The system boundaries extend from the condenser hotwell to the inlet of the steam generator. Condensate is taken from the main condenser hotwells by three vertical, centrifugal, motor-driven hotwell pumps. The head imparted by these pumps is sufficient to provide adequate NPSH to the main feedwater pumps during unit startup and low load operation. A signal that NPSH to the main feedwater pumps is approaching a preset minimum level (signal provided by differential pressure between main feed pump suction and No. 2 feedwater heater shell at approximately 50% unit guaranteed load) alarms in the main control room. The three horizontal, centrifugal, motor-driven condensate booster pumps are started manually. These pumps, when operating in series with the hotwell pumps, are capable of delivering required flow with sufficient NPSH to the main feedwater pumps under all normal operating conditions as long as the condensate demineralizers are being by-passed. However, when the condensate demineralizers are in service at higher loads, additional pumps are needed to provide sufficient NPSH to the main feedwater pumps. The demineralizer condensate pumps provide this capability. The condensate demineralizers will act to keep condensate water quality within guidelines as specified in Section 10.3.5 for the steam generator feedwater. During normal operation, all flow except for approximately 1100 gpm per service vessel in operation is bypassed around the demineralizer. See Section 10.4.6 for details of condensate polisher operation. 10.4-23
WBN This small flow acts to keep the resin beds compacted so that their filtration capability is not momentarily unavailable in the event of a condenser tube leak and the subsequent switch from the bypass mode to full flow condensate demineralization. Conductivity recorders in the hotwell detect the tube leakage and provide annunciation. The demineralizers may be manually placed on full flow operation either during startup or normal operation, as water chemistry requirements dictate. The two turbine driven, variable speed main feedwater pumps are capable of delivering feedwater to the four steam generators under all expected operating conditions. During certain times of the year, to improve plant efficiency, the standby main feedwater pump is used to supplement MFP flow at high plant loads. Also, the standby main feedwater pump will automatically start if one of the MFPs trip above 85% power. The standby main feedwater pump was originally used for plant startup and shutdown. However, since the standby main feedwater pump does not have a trip circuit to automatically start the AFW pumps, it can no longer be used for normal plant startup and shutdown in Modes 2 and 1. The standby main feedwater pump can be used as needed in Mode 3 for items such as system cleanup and pressure testing. The AFW System pump(s) along with the Turbine Driven MFP(s) are used for plant startup, shutdown, and low power operation along with use of the feedwater bypass headers. The small bypass feedwater control valves provide increased sensitivity for flow regulation (i.e., rangeability) during low-load operations, as compared to the larger main control valves. Feed pump speed is automatically adjusted to meet system demands. (Unit 1 Only) The feed pump speed control system consists of three inter-related parts:
- 1. The setpoint calculators sum the four steam flows, provide the lag on setpoint changes, and contain the basic scaling adjustments.
- 2. The differential pressure controller compares the steam header pressure, feedwater header pressure, and calculated setpoints to determine the speed signal required.
- 3. The feed pump manual/auto stations to provide the operator with the flexibility of choosing various operating modes. The unit operator will have the options to operate either or both pumps on manual speed control to base load his operation, to operate one pump on manual with the other automatically swinging with plant load changes, or to let both pumps swing with the load changes.
(Unit 2 Only) The main feedwater pump speed control program maintains a programmed differential pressure between the main steam header and the main feedwater pump discharge header. The programmed dp setpoint is determined by the average of the steam flow from all four steam generators. The feed pump manual/auto stations provide the operator with the flexibility of choosing various operating modes. The unit operator will have the options to operate either or both pumps on manual speed control to base load his operation, to operate one pump on manual with the other automatically swinging with plant load changes, or to let both pumps swing with the load changes. At high power levels, i.e., above 22% feedwater flow on increasing power and down to 14% feedwater flow on decreasing power, feedwater flows through each main feedwater line into the lower section of each steam generator. Flow is controlled automatically by adjustment of a feedwater control valve in each line. Each main feedwater control valve is positioned as a function of nuclear power by a three element controller using inputs from feedwater flow, steam flow and steam generator level. Single element control using steam generator level is provided if the feedwater flow or steam flow signals are unavailable. The single element controller output 10.4-24
WBN can also be modified by inputs from wide range steam generator level and feedwater temperature for density compensation. At low power levels, i.e., below 22% feedwater flow on increasing power and below 14% feedwater flow on decreasing power, each main feedwater control valve and feedwater isolation valve are closed, and for each steam generator, feedwater is routed through a small bypass line directly into the upper section of the steam generator. The required steam generator water level is maintained by automatically controlling the position of the feedwater bypass control valve in each feedwater bypass line. The feedwater bypass control valve is positioned as a function of nuclear power by a three element controller using inputs from feedwater flow, steam flow and steam generator level. Single element control using steam generator level is provided for very low power levels or if the feedwater flow or steam flow signals are unavailable. The single element controller output can also be modified by inputs from wide range steam generator level and feedwater temperature for density compensation. (Unit 2 Only) Each Unit 2 feedwater bypass control valve is used to maintain a tempering flow into the upper section of the respective Unit 2 steam generator during normal power operation when feedwater is flowing through the lower section of the respective Unit 2 steam generator. Tempering flow may be terminated temporarily to allow for valve maintenance. Switchover from the feedwater bypass lines to the main feedwater lines on increasing power is manually performed. On decreasing power, changeover from the main feedwater lines to the bypass lines is achieved by manually switching on the automatic bypass controller. Manual control of the main feedwater control valves or feedwater bypass control valves is possible in any mode of operation. Both the main feedwater control valves and the feedwater bypass control valves are pneumatically operated and are designed to fail close on loss of air. During startup of either unit, the low-load automatic feedwater control system is used to approximately 22% of full feedwater flow. (Unit 1 Only) Before switching to the lower feedwater nozzle, the feedwater must be at least 250° F to limit the number of feedwater system induced transients and the minimum temperature of continuous feedwater flow to the Unit 1 steam generator preheater region. (Unit 2 Only) Before switching to the lower feedwater nozzle, the feedwater in the line to the lower (main) nozzle is warmed to not less than 250°F in order to minimize the potential for waterhammer (steam bubble collapse) in the steam generator preheater. Waterhammer could occur if cold feedwater were injected into the Unit 2 steam generators. Feedwater line warming is accomplished by flushing the cold water in the line downstream of the main feedwater regulator valves through the deaeration line to the condenser. This forward flush operation is accomplished at 20 to 22% feedwater flow by flowing hot feedwater through this flow path to the condenser until temperature instrumentation in the feedwater line upstream of the junction with the deaeration line indicates a temperature greater than 250°F (nominal). During forward flush, the isolation valves upstream of each main feedwater regulator valve are closed and the bypass around each of these valves is opened. This procedure will cause the pressure upstream of the closed main feedwater isolation valves to be lower than the steam generator pressure. Consequently, no cold water in the main feedwater line can leak into the steam generator and cause waterhammer (bubble collapse) in the steam generator pre-heater. 10.4-25
WBN (Unit 2 Only) The remaining portion of the main feedwater line from the junction with the deaeration line to the steam generator is purged of cold water by flowing hot water from the steam generators back through the main feedwater lines to the condenser via the deaeration line. This backflush operation is continued until temperature instrumentation in the main feedwater line downstream of the junction with the deaeration line indicates a temperature greater than 250°F nominal. Backflush flow is limited to 80,000 lb/hr per steam generator to prevent steam bubbles in the steam generator from entering the feedwater lines which could cause waterhammer from the bubbles collapsing, due to cooling. (Unit 2 Only) The forward/back flush operation is accomplished manually by the operator using a single switch in the control room. The switch aligns the feedwater valves in forward flush mode then in back flush mode. Status lights are located in the control room so that the operator knows the position of the valves and knows when feedwater lines for each steam generator are warmed. The systems for either unit normally operate at full load with three hotwell, three condensate booster, three condensate demineralizers, and two main feed pumps in service. Unit load can be continuously maintained at 85% guaranteed load with one main feed pump and the standby main feed pump in operation. Heating of the condensate and feedwater is accomplished by passing it through a series of closed heat exchangers. A summary of secondary cycle heat exchangers used to preheat the condensate and feedwater are described below:
- 1. Gland Steam Condenser - This exchanger condenses the steam leak off from turbine shaft seals and removes the non-condensibles (the result of shaft inleakage of air) from this steam. An externally connected, weighted check valve is provided to ensure minimum required flow through the condenser at low condensate flow conditions and to minimize pressure drop through the condenser during high condensate flow conditions.
- 2. Main Feed Pump Turbine Condensers - Each main feed pump turbine is equipped with an individual surface type condenser. Control valves in the inlet and outlet condensate piping to these condensers provide the ability to isolate condenser if its associated drive turbine is rendered inoperative and to force 100% condensate flow through the operating condenser, thus allowing maximum power operation of the remaining drive turbine.
- 3. Steam Generator Blowdown Heat Exchangers - Two steam generator blowdown heat exchangers (dual shell first stage and single shell second stage) are provided to continuously subcool blowdown such that it may be processed and returned to the secondary cycle or discharged via cooling tower blowdown (see Section 10.4.8).
10.4-26
WBN
- 4. Feedwater Heaters - Three parallel strings (A, B, and C) of heaters, each consisting of three low pressure feedwater heaters, three intermediate pressure feedwater heaters, and one high pressure feedwater heater are provided. The heaters are numbered from 1 to 7, with the highest pressure heater designated as No. 1. Motor operated isolation valves are provided at the inlet to each No. 7 heater and the outlet of each No. 5 heater, the inlet to each No. 4 heater and the outlet of each No. 2 heater, and at the inlet and outlet of each No. 1 heater. High-high water level in a heater shell will cause the isolation of the group of heaters in the stream in which the high-high level occurred (either the 5, 6, and 7 heaters, 2, 3, and 4 heaters, or No. 1 heater in either the A, B, or C streams).
With all pumps in service, a complete string of 7 heaters can be out of service and full unit load can be maintained. Tubes for the heaters are 304 SST. Tube-to-tube sheet joints in the feedwater heaters are expanded and welded. Minimum flow bypasses are provided for equipment protection. The condensate system minimum flow bypass is located immediately upstream of the No. 7 heaters. The bypass control valve receives its operating signal from the station flow nozzle located upstream of the gland steam condenser. The valve plug's position is modulated to maintain at least 5500 gpm nominal flow through the flow nozzle. This flow is sufficient to protect the hotwell pumps and demineralized condensate pumps, to provide adequate cooling water to the gland steam condenser and MFPT condensers and to keep the demineralizer beds compacted at all times. The condensate booster pumps are protected by automatic recirculation control (ARC) valves. The checking elements of these valves are calibrated to actuate pilot valves which, in turn, open or close the recirculation valves to maintain the minimum required flow through each pump. The feedwater system has a minimum flow bypass line originating downstream of each feedwater pump to permit direct recirculation back to the main condensers. The bypass control valve receives its operating signal from its associated turbine driven main feedwater pump discharge flow transmitter; and modulates to maintain a minimum flow of 4000 gpm at rated speed. However, for extended periods of operation at recirculation flows, due to high vibration signature caused by high speed and low flow, the pump can be throttled to approximately 3300 rpm at which time flow should be approximately 2650 gpm and vibration signature would be acceptable. Minimum flow for the standby main feed pump when it is operating is 1500 gpm (vendor evaluation has determined that minimum flows as low as 1100 gpm are acceptable). Piping is also provided around the main feed pumps to allow filling the steam generators without operating the main feed pumps. An additional recirculation line is provided from each main feedwater loop, between the feedwater control valve and motor operated isolation valve, back to the main condenser. This deaeration line is used to deaerate and improve the water chemistry of the condensate and feedwater systems during startup using the hotwell pumps. (Unit 1 Only) The modified long cycle recirculation flow path may be established just prior to using the deaeration line provided flow is maintained below approximately 3000 gpm through each MFP recirculationline when the water is less than 125° F. 10.4-27
WBN (Unit 2 only) As described previously, for Unit 2 this deaeration line is used to provide a path for warming flow during the warming of the main feedwater piping loops prior to switching from the upper feedwater bypass loops. 10.4.7.3 Safety Evaluation The feedwater system from the steam generator back through the motor operated isolation valves and check valves is a safety system and is designed to TVA Class B. This portion of the feedwater system is an integral part of the auxiliary feedwater system. Feedwater flow to the steam generators is interrupted within 6.5 seconds of initiation of a feedwater isolation signal (FWI) (the direct result of high-high level in a steam generator, high flood level detection in either the South or North MSV vault rooms, safety injection signal, or a reactor trip coincident with reactor coolant low Tavg). This isolation is accomplished by closure of redundant valves in the piping to each steam generator. The feedwater regulator valves will close within 6.5 seconds after initiation of a FWI signal. The signal to initiate closure of the regulation valves is available from both power Train A and power Train B. The Class 2, motor operated containment feedwater isolation valves will close within 6.5 seconds after power is available. The isolation valves associated with steam generator Nos. 1 and 3 are connected to power Train A while those associated with steam generator Nos. 2 and 4 are connected to power Train B. Closure of the startup valves bypassing the feedwater regulator valves is also guaranteed within 6.5 seconds. Each feedwater bypass isolation valve can be closed by Train "A" or Train "B" of the feedwater isolation signal. Each feedwater bypass regulator valve can be closed by a Train A signal for steam generator Nos. 2 and 4 or Train B signal for steam generator Nos. 1 and 3. The feedwater bypass isolation valve is a backup to the feedwater bypass regulator valve. For additional protection, a feedwater isolation signal also trips the standby main feedwater pump and both turbine driven main feedwater pumps (from either Train A or Train B), the condensate booster pumps and all demineralized condensate pumps. Trips of these pumps will reduce the condensate system pressure to a pressure less than 400 psig and initiate an orderly shutdown of the remainder of the condensate and feedwater system, except the hotwell pumps which are left on line to facilitate restart of the unit. On feedwater isolation trips of both main feedwater pumps, at least one main feedwater pump condenser is left unisolated. This allows the condensate system to continue to operate with hotwell pumps running on the short cycle recirculation to condenser mode with flow through the gland steam condenser and demineralizers and eventually the modified long cycle recirculation flowpath through the MFP recirculation valves may be established just prior to full long cycle recirculation. With all heater drains being pumped forward, the condensate demineralizer in the bypass mode, and the heater banks in service, each hotwell pump and each condensate booster pump is capable of delivering 50% of the unit guaranteed flow while imparting sufficient head to the feedwater to meet system demands. With the demineralizer in the full flow mode, two of the three demineralized condensate pumps are sufficient to meet system demands. Thus, loss of any one of the three condensate booster pumps and/or any one of the demineralized condensate pumps simply results in flow being transferred to the remaining operational pumps with the reactor coolant system being unaffected. 10.4-28
WBN Activation of the No. 3 heater drain tank high level switch coincident with low flow and turbine power greater than 85% initiates the No. 3 heater drain tank pump logic for a turbine runback preventing the unit from operating above 85% power. Thus, the loss of a hotwell pump and/or a condensate booster pump during this mode of operation will not affect the reactor coolant system. However, with expected pump degradation of the above indicated pumps, the unit may be reduced in power or pumps operated in the service factor of the pump motors. If the unit is operating below 67% guaranteed load, loss of one main feed pump has no effect on the reactor coolant system, since one main feed pump is capable of delivering 67% guaranteed flow. If the unit is operating above 85% guaranteed load and loss of one main feed pump occurs, feedwater flow to the steam generators must be restored to 85% guaranteed flow within 20 seconds to prevent a reactor trip. This is accomplished by the following:
- 1. Automatic start signal to the electric motor driven standby main feedwater pump, if not in operation.
- 2. Isolation of the condensate flow through the main feed pump turbine condenser associated with the tripped pump. Thus, 100% condensate flow is passed through the active main feed pump turbine condenser allowing maximum power operation of the active feed pump turbine.
- 3. Acceleration of the active drive turbine to its 'high speed stop' speed.
- 4. Main turbine runback is initiated and unit load is decreased to below 85%.
If the unit is operating at above 67% but below 85% load, the above actions occur except that no unit load runback is required. Insufficient NPSH at the main feed pump suction can result in a decrease in steam generator level. Low NPSH at the main feed pump suction is annunciated in the MCR, thereby alerting the unit operator of the need for a load runback or adjustment of system pressure to avoid a reactor coolant system transient. The feedwater piping layout has been optimized to prevent water hammer induced by the piping system. 10.4.7.4 Inspection and Testing Unit 1 The feedwater heaters have been designed and built as required by applicable sections of the Heat Exchange Institute Standards for Closed Feedwater Heaters; Standards of Feedwater Heater Manufacturers Association, Incorporated; and Section VIII, Unfired Pressure Vessels of the ASME Boiler Code. Heater tubes have been tested as required by ASME SA 688. The main feed pump turbine condenser channel and tubes are designed and built in accordance with applicable sections of the Heat Exchange Institute Standards for Closed Feedwater Heaters and Section VIII, Unfired Pressure Vessels, of the ASME Boiler Code. 10.4-29
WBN Manways or removable heads are provided on the heat exchangers to provide access to the tube sheet for inspection, repair, or tube plugging. Inservice inspection requirements are given in Chapter 3. Preoperational test requirements are given in Chapter 14 (historical information). Surveillance test requirements are given in Chapter 16. Unit 2 The operating characteristics for each system pump are established throughout the operating range by factory tests. Each hotwell, demineralized condensate and condensate booster pump casing are tested hydrostatically in accordance with the appropriate codes and standards. All parts of each turbine driven main feed pump and motor driven standby main feed pump subject to hydraulic pressure in service are hydrostatically tested in accordance with the appropriate codes and standards. All parts and assemblies of parts of the feedwater heaters are hydrostatically tested and tested otherwise as required by applicable sections of the Heat Exchange Institute Standards for Closed Feedwater Heaters; Standards of Feedwater Heater Manufacturers Association, Incorporated; and Section VIII, Unfired Pressure Vessels of the ASME Boiler Code. Heater tubes are tested as required by ASME SA 688. Hydrostatic and other testing of the parts and assemblies of parts of the main feed pump turbine condenser channel and tubes are in accordance with applicable sections of the Heat Exchange Institute Standards for Closed Feedwater Heaters and Section VIII, Unfired Pressure Vessels, of the ASME Boiler Code. Manways or removable heads are provided on the heat exchangers to provide access to the tube sheet for inspection, repair, or tube plugging. Inservice inspection requirements are given in Chapter 3. Preoperational test requirements are given in Chapter 14. Surveillance test requirements are given in Chapter 16. 10.4.7.5 Instrumentation Sufficient level controllers, flow controllers, level switches, limit switches, temperature switches, etc., are provided to permit personnel to conveniently and safely operate the condensate and feedwater system. 10.4.8 Steam Generator Blowdown System 10.4.8.1 Design Bases The design bases for the steam generator blowdown system (SGBS) are:
- 1. To achieve optimum effectiveness in the control of steam generator water chemistry, continuous blowdown along with continuous all volatile treatment (AVT) will be maintained for each steam generator during normal plant operation. The minimum blowdown flow rate will be 5 gpm per steam generator.
- 2. Facilities are provided to treat up to approximately 350 gpm of cooled blowdown from one unit (approximately 87.5 gpm per SG). The maximum blowdown flow to the CTB is 262 gpm.
10.4-30
WBN
- 3. Blowdown may be discharged to the CTB without treatment provided that the radioactivity concentration of the blowdown effluent does not exceed the ODCM limits.
In this mode of operation, makeup water will have to be supplied to the condensate system from the condensate storage tanks.
- 4. The discharge stream from the blowdown system is monitored continuously for the radioactivity. The blowdown is diverted to the condensate demineralizers automatically if the radioactivity concentration reaches a variable setpoint consistent with the value determined in accordance with the ODCM. The design temperature for these demineralizers is 140°F, but the heat added to the condensate by this blowdown is not sufficient to endanger the demineralizers.
- 5. Blowdown system discharge is sampled and analyzed for radioactivity in accordance with the ODCM. When blowdown is being treated, analyses are performed as often as necessary for evaluation of equipment performance.
- 6. Blowdown system components will be designed in accordance with Section 3.2.2:
10.4.8.2 System Description and Operation A flow diagram of the SGBS is shown in Figure 10.4-24. The blowdown flow from the four steam generators is piped to the Turbine Building where it is cooled in a stacked and second stage heat exchanger units. Cooling water is supplied from the condensate system and thus the heat given up by the blowdown is returned to the cycle. After the blowdown is cooled, it maybe discharged to the condensate line upstream of the CDSV where any impurities are removed. If blowdown is not routed to the CDSV, it may be sent to the CTB. When dumping to the CTB, the blowdown is automatically diverted back to the CDSV on loss of CTB flow or if the radiation level of the blowdown exceeds the value determined in accordance with the ODCM. For Unit 1, from the cold shutdown to the hot standby, plant operating modes, when steam generator pressure is not high enough to provide flow through the heat exchanger flow path (approximately 0 to 295 psig), the blowdown may be routed to the blowdown flash tank. The water remaining in the flash tank is pumped to either the CDSVs, CTB, or the condenser hotwell. The maximum blowdown flow rates when using the flash tank flow path is approximately 50 gpm from one unit (12.5 gpm per steam generator). The Unit 2 SGBS does not include any blowdown path that routes flow to or from a flash tank. Unit 2 SGBS piping has no connection to any inlet or outlet line of any blowdown flash tank Individual blowdown sample lines from each steam generator may be monitored for radioactivity so that a leaking steam generator can be identified. A blowdown sampling system to analyze the blowdown chemistry is provided. The radioactive waste treatment, and process and effluent radiological monitoring aspects of the SGBS are described in Section 11.2. 10.4-31
WBN There is a temperature sensor located at the entrance to the demineralizer beds, which alarms at a local control panel and operator action initiates manual bypass of the beds if the temperature exceeds the maximum allowable for demineralizer resins. The blowdown control valve, located in the common line downstream of the heat exchangers, is used to regulate the blowdown flow rate. The manual throttling valves, located in the individual lines from each steam generator, are used to proportion the flow as required. Main condenser inleakage may result in full-flow condensate demineralizer operation as described in Section 10.4.6.2. Steam generator blowdown may not need to be increased for this mode of operation. 10.4.8.3 Safety Evaluation The blowdown system described in Section 10.4.8.2 provides sufficient capacity for treating radioactive blowdown liquid. It also minimizes release of radioactivity, and permits recycle of most of the water in the blowdown stream. Capacity The present system provides capacity for treating up to approximately 350 gpm of blowdown liquid per unit. This is sufficient to treat the highest expected blowdown flow rate from the steam generators. Water chemistry requirements are discussed in Section 10.3.5. Radioactivity Releases Radioactivity releases due to normal operation of the SGBS are discussed in Section 11.2. Unusual Design Condition In the event of a flood above plant grade, the normal blowdown paths are isolated and the blowdown is released to the roof of the south main steam valve room. The system is capable of operating for 100 days in this mode and with only emergency diesel power available (refer to Section 2.4.14). System Performance During Abnormally High Primary-to-Secondary Leakage Abnormally high primary-to-secondary leakage has no significant effect on the blowdown. A leak rate in excess of the Technical Specification limit requires shutdown of the unit. The blowdown system is capable of operating with a leak rate approaching 1 gpm. A 1 gpm leak rate would not require that the blowdown rate be increased above 262 gpm in order to maintain specified secondary system water chemistry unless it occurred at a time when condenser inleakage was high. With a 1 gpm leak, radiation levels in the vicinity of the blowdown system equipment would be higher than normal operating radiation levels, but would be within acceptable limits. In the event of a primary-to-secondary leak in excess of 1 gpm, the blowdown system could be operated after unit shutdown in order to clean the secondary system. 10.4-32
WBN Failure Analysis of System Components Analyses of various failures in the system are given in Table 10.4-2. 10.4.8.4 Inspections and Testing Unit 1 Routine inspections and maintenance is performed on system components. Preoperational test requirements are given in Chapter 14 (historical information). Surveillance test requirements are given in Chapter 16. Unit 2 Prior to operation of the steam generator blowdown system, instruments are calibrated and interlocks and controls are tested to verify that they function properly. The performance of the heat exchangers, tank and demineralizers is determined during tests of the secondary system. Routine inspections and maintenance are performed on system components. Preoperational test requirements are given in Chapter 14. Surveillance test requirements are given in Chapter 16. 10.4.9 Auxiliary Feedwater System 10.4.9.1 Design Bases The auxiliary feedwater (AFW) system supplies, in the event of a loss of the main feedwater supply, sufficient feedwater to the steam generators to remove primary system stored and residual core energy. It may also be required in some other circumstances such as the evacuation of the MCR, cooldown after a LOCA for a small break, maintaining a water head in the steam generators following a LOCA, a flood above plant grade, Anticipated Transient Without Scram (ATWS) event, and 10 CFR 50, Appendix R, Fires. The system is designed to start automatically in the event of a loss of offsite electrical power, a trip of both turbine driven main feedwater pumps, a safety injection signal, an ATWS Mitigation System Actuation Circuitry (AMSAC) signal, or low-low steam generator water level, any of these conditions will result in, may be coincident with, or may be caused by a reactor trip. The AFW will supply sufficient feedwater to prevent the relief of primary coolant through the pressurizer safety valves and the uncovering of the core. It has adequate capacity to maintain the reactor at hot standby for two hours and then cool the RCS to the temperature at which the residual heat removal (RHR) system may be placed in operation, but it cannot supply sufficient feedwater for power generation. Note that with reactor power less than 50%, the AFW start signal generated by lo-lo steam generator level is delayed by the trip time delay logic. See Section 7.2 for details. Engineered Safety Feature (ESF) standards are met for the AFW System except for the condensate water supply, the AFW supply tank (AFWST), and the piping from the AFWST to the condensate system, which is backed up by the essential raw cooling water (ERCW). The ESF grade portion of the system is designed for seismic conditions and single failure requirements, including consideration that the rupture of a feedwater line could be the initiating event. It will provide the required flow to two or more steam generators regardless of any single active or passive failure in the long term. 10.4-33
WBN-2 Seismic and quality group classifications of the AFW system are shown in Figures 10.4-21 and 10.4-21A. The industry codes and standards corresponding to these TVA classifications are given in Section 3.2. 10.4.9.2 System Description The two reactor units have separate AFW systems, as shown in Figure 10.4-21. Each system has two electric motor-driven pumps and one turbine-driven pump. Each of the electric pumps serves two steam generators; the turbine pump serves all four. All three pumps supporting a unit automatically deliver rated flow within one minute upon a trip of both turbine driven main feedwater pumps, loss of offsite power, an AMSAC signal, a safety injection signal or low-low steam generator water level. The motor driven pumps (MDPs) start on a two-out-of-three low-low level signal in any steam generator and the turbine driven pump starts on a two-out-of-three low-low level signal in any two steam generators. Each pump supplies sufficient water for evaporative heat removal to prevent operation of the primary system relief valves or the uncovering of the core. The operator has the capability to open an additional recirculation line on the MDPs when there is low decay heat required to be removed from the SG. These lines contain a normally closed valve that closes on an accident signal. The valve is operable after the accident signal, but if an additional accident signal occurs, the valve would be reclosed. This ensures that the forward flow requirements to remove decay heat have been satisfied. Significant pump design parameters are given in Table 10.4-1. Each of the two motor driven auxiliary feedwater pumps on Unit 1, are provided with a cavitating venturi to protect the pumps from runout. When the pumps approach runout flow, vapor bubbles start forming in the venturi and physically limit flow before runout is reached. The preferred sources of water for the auxiliary feedwater pumps are the two 395,000 gallon condensate storage tanks. A minimum of 200,000 gallons in each tank is reserved for the AFW Systems by means of a standpipe through which other systems are supplied. The two CSTs are normally isolated from each other, with one CST dedicated to each unit. The AFW safety analyses take no credit for the ability to crosstie the CSTs. Additionally, the 500,000 gallon AFW supply tank serves as an additional condensate grade source of water. The AFWST is normally isolated from the condensate piping, which provides water to the AFW Pump suctions, by an AOV. The AOV will open upon a low pressure signal from the upstream condensate piping, a loss of AC power, or a loss of control air. This sequence is not an Engineered Safety Feature and is not credited in the Safety Analysis. As an unlimited backup water supply for each unit, a separate ERCW system header feeds each motor-driven pump. The turbine-driven pump can receive backup water from either ERCW header. The ERCW supply is automatically (or remote-manually) initiated on a two-out-of-three low pressure signal in the AFW system suction lines. Pump protection during the automatic transfer to the ERCW supplies is assured by providing sufficient suction head and flow to the pumps and is verified by system analysis. Since the ERCW system supplies poor quality water, it is not used except when the condensate supply is unavailable. In addition, the high pressure fire protection (HPFP) system which is cross-connected to the discharge of each motor driven AFW pump can be aligned to supply unlimited raw water directly to the steam generators, in the unlikely event of a flood above plant grade. Water from the HPFP system is supplied by four high pressure, vertical turbine, motor-driven, Seismic Category I pumps conforming to the requirements of ASME B&PV Code Section III, Class 3 with each having a rating of 1590 gpm at 300 feet head. These pumps are installed in the Seismic Category I Intake Pumping Station with motors above the maximum possible flood level. Each pump is capable of supplying 100% of the auxiliary feedwater demands for both units during a flood above plant grade. The four pumps are supplied from normal and emergency power with two pumps assigned to each of the two emergency power trains. Each pair of pumps on the 10.4-34
WBN-2 same power train takes suction from a common sump which receives water through a settling baffle arrangement for all normal, and flood reservoir levels. The AFW system is designed to deliver 40°F to 120°F water from the condensate system to the secondary side of the steam generators at a pressure ranging from the RHR system cut-in point of 350°F in the RCS (equivalent to 110 psig in the steam generators) to the lowest MSSV set pressure, plus 3% set error, plus 7 psi for accumulation and pressure drop between the SG and MSSV (1228 psig). The water from the safety-related ERCW system may exceed 120°F subsequent to a Large Break Loss of Coolant Accident due to the discharge flow from the Containment Spray Heat Exchangers. The temperature of 130°F has been evaluated for this condition and matches the ERCW design temperature. The ERCW temperature will be 120°F or lower for all other design basis events. Separate ESF power subsystems and control air subsystems serve each motor driven AFW pump and its associated valves. The valves associated with the turbine-driven pump are served by one of the two electric and control air subsystems. The turbine driven pump valves associated with SG 1 and SG 2 are served by Train B and the valves associated with SG 3 and SG 4 are served by Train A. The turbine-driven pump receives control power from a third dc electric channel that is distinct from the channels serving the motor driven pumps. Note: Each Unit's AFW system is independent of the other with no shared components that are considered important to safety, supporting structure (i.e., the Auxiliary Building) and supporting systems (i.e., ERCW, HPFP, DC power supply and Emergency Diesels) are shared. 10.4.9.3 Safety Evaluation For the design bases considerations discussed in Section 10.4.9.1, sufficient feedwater can be provided over the required pressure range even if the failure of a feedwater line is the initiating event, any one AFW pump fails to start, and no operator action is taken for 12 minutes. The 'Loss of Normal Feedwater and loss of offsite power analyses in Chapter 15 demonstrate that the auxiliary feedwater system satisfies the design bases described in this section. In the event that loss of offsite power (LOOP) occurs, 410 gpm of AFW delivered to two steam generators within one minute will prevent relief of reactor coolant via the pressurizer safety valves. Water levels in the steam generators will remain above the required minimum tube sheet coverage. The AFW system meets these requirements even when the single failure criterion is applied. In the event of a feedwater line break, essentially the same requirements are imposed and act as for the LOOP case. Other cases discussed in Section 10.4.9.1 impose less stringent conditions. Following a loss-of-coolant accident (LOCA) for a small break with offsite power, the RCS pressure and temperature decrease at a relatively slow rate. The AFW system provides sufficient flow to the steam generators so that RCS cooldown can proceed. In this case, the AFW system function is similar to its function following other events described in Section 10.4.9.1, such as loss of offsite electrical power. In contrast, the AFW system serves a distinctly different function during a large break LOCA, where steam generator tube leaks may be present. A large LOCA causes a rapid depressurization of the RCS so that the secondary side pressure and temperature exceed primary pressure and temperature, and consequently any fission products in the RCS cannot escape to the secondary side. Subsequent cooling of the secondary side fluid could eventually reduce the secondary side pressure to atmospheric, 10.4-35
WBN-2 permitting any fission products in the RCS to escape into the secondary system. The AFW system is used to maintain sufficient water level on the steam generator secondary side so that static head prevents primary-to-secondary tube leakage and prevents the escape of any fission products. Whenever a flood above plant grade is anticipated, an orderly shutdown to hot shutdown and a cooldown to cold shutdown will be initiated immediately. In a little more than 5 hours after reactor shutdown, the secondary system pressure will be reduced to approximately 100 psig. Within 27 hours after reactor shutdown, the fire-protection system piping will be aligned to the auxiliary feedwater motor driven pump discharge trains by opening the isolation valves (1-ISV-003-1002A and 1-ISV-026-1475A and 1-ISV-003-1012B and 1-ISV-026-1476B) in the cross-connect piping. The secondary system pressure will be maintained 125 psia. Operator action is taken, during a flood transient at 17 hours, to reduce SG operating pressure to 80 psig, to facilitate the supply of cooling water from the HPFP system in the event of the failure of 0-PCV-26-18 to close. Valve 0-PCV-26-18 is mounted in the HPFP pump recirculation line to the river and is non-safety grade. This pressure is sufficient for decay heat removal. When the flood exceeds plant grade, the auxiliary feedwater pumps will be inoperable, and the fire protection pumps, which are located above the maximum possible flood elevation, will supply feedwater. Appropriate portions of the HPFP system are designed to function under normal conditions as well as for the maximum possible flood with the coincident or subsequent loss of the upstream and/or downstream dams. The HPFP pumps are located in the intake station above the flood line and are arranged to supply water directly to the steam generators in the event the auxiliary feedwater pumps are flooded. The portion of the HPFP system which supplies auxiliary feedwater to the steam generators is ASME Section III, Class 3, Seismic Category I with the exception of the fire pumps discharge relief valve. These valves are replaced by ASME Section III, Class 3 blind flanges during flood mode preparations to ensure the integrity of the ASME Section III, Class 3 auxiliary feedwater supply piping during flood mode operation. The AFW system is required to be available in the event of an ATWS event. The most severe ATWS scenarios have been determined to be those in which there is a complete loss of normal feedwater (Reference WCAP-10858). The design basis events for the AMSAC are Loss of Normal Feedwater/ATWS and Loss of Load/ATWS. Since there is a complete loss of normal feedwater during both of these transients, the accident analysis of both transients (Chapter 15) assumed AFW reaches full flow within 60 seconds after the initiating event for long term reactor protection. Also, the Loss of Normal Feedwater transient assumed a turbine trip within 30 seconds after the initiating event to maintain short term pressures below ASME Service Level C pressure limits. Normally these features will be actuated by the RPS. However, if a common mode failure to the RPS incapacitates AFW initiation and/or turbine trip in addition to prohibiting a scram, then an alternate method of providing AFW flow and a turbine trip is required to maintain RCS pressure below ASME Service Level C pressure limits. These two functions, turbine trip and AFW flow actuation, are provided via the AMSAC. The AFW piping system layout has been optimized to prevent water hammer occurrences induced by the piping system. Minimum flow rate requirements are met by the system for the design transients or accident conditions shown in Table 10.4-6, even if the worst case single active failure occurs simultaneously. The single active failures considered in the table are listed below: A. Alternating current train failure 10.4-36
WBN-2 B. Turbine-driven pump (TDP) failure C. Motor-driven pump (MDP) failure D. Pressure control valve failure (MDP -runout protection) (Unit 2 ONLY) E. Level control valve failure for TDP F. Level control valve failure for MDP G. Pressure switch failures H. AFW System check valve failure (failure to close on reverse flow) I. Flow controller failure (TDP-runout protection) Operator intervention within 10 minutes is required in order to meet the maximum flow requirements for the main steamline break inside containment, or within 12 minutes to meet the minimum flow requirements for the feedline rupture. In addition to using high quality components and materials, the AFW system provides complete redundancy in pump capacity and water supply for all cases for which the system is required. Under all credible accident conditions, at least one AFW pump is available to supply two steam generators not affected by the accident with the required feedwater. Only two steam generators are required to be usable for any credible accident condition. Redundant electrical power and air supplies assure reliable system initiation and operation. The electric motor-driven pumps and associated controls, valves, and other supporting systems are powered by offsite or onsite ac sources. The exceptions are the MDP level control valves and the control circuits supplied by trained dc power. The TDP and associated valves, controls, and other supporting systems are powered by steam and dc electric power, except for four 480V ac power operated valves in the steam supply lines to the pump turbine which are included to satisfy pipe rupture criteria. Steam for the TDP is provided from either of two of the four main steam loops as controlled by two of these valves. They assure that only one steam source is available at a time, and, in the event of a pipe rupture, prevent two steam generators from blowing down simultaneously. The other two valves simply isolate in the event of a pipe rupture (due to high temperatures in TDP room). Four of these are motor operated, fail as is, and all but the one isolating the standby steam source are normally open. This assures that a steam supply to the turbine will be available for design basis events and a LOOP event (see Table 10.4-4, Items 2, 4, and 5). Failure modes and effects analyses for the AFW System are presented in Tables 10.4-3, 10.4-4, and 10.4-5. A backup source of compressed nitrogen has been provided to allow manual control of the LCVs for station blackout. No electric power is required for the operation of this backup nitrogen source. The valve associated with this backup source must be manually operated to align the high pressure nitrogen bottles and associated piping to take local manual control of the LCVs. The LCV position is adjusted upon orders from either the Control Room or the Auxiliary Control Room, based on the observed water level in the steam generators being controlled. A nonqualified nitrogen gas backup source from the nitrogen low pressure header fed by the liquid nitrogen storage tank contained within the Gaseous Waste Disposal System has been provided to allow continued automatic control capability of these valves for Appendix R. A secondary backup source of compressed nitrogen has been provided to allow manual control of the TDAFW steam generator level control valves for station blackout and Appendix R fire. No electric power is required for the operation of this secondary backup nitrogen source. Valves associated with this backup source must be manually operated to align the high pressure nitrogen bottles and associated piping to take local manual control of the LCVs. The LCV position is adjusted upon orders from either the Control or the Auxiliary Control Room, based on the observed water level in the steam generators being controlled. This manual control capability is not credited within the Appendix R analysis. 10.4-37
WBN 10.4.9.4 Inspection and Testing Requirements A comprehensive test program is followed for the AFW system. The program consists of periodic tests of the activation circuitry and mechanical components to assure reliable performance throughout the life of the plant. During plant operation, the system can be tested by pumping condensate storage water to the condensate storage tank. ERCW and HPFP water will not be fed to the steam generators during tests, but separate tests on the ERCW and HPFP system will assure the availability of the alternate water supplies. Test requirements are given in Chapter 14. Surveillance test requirements are given in Chapter 16. Inservice inspection requirements are given in Chapter 3. 10.4.9.5 Instrumentation Requirements The three pumps start automatically on a loss of offsite power, trip of both turbine driven main feedwater pumps, a safety-injection signal, or a AMSAC signal. The electric-motor-driven pumps also start automatically on a two-out-of-three low-low level signal from any steam generator, and the turbine driven pump starts automatically on a two-out-of-three low-low level signal from any two steam generators. All pumps can be started remote-manually. A modulating level control valve (which is normally closed) between each pump and each steam generator fed by the pump receives an opening signal on a low-low water level in the steam generator. For the motor driven pumps, two modulating level control valves, a 4-inch and a parallel 2-inch, (which are normally closed) between each pump and each steam generator fed by the pump receives an opening signal on a low-low water level in the steam generator. For the motor driven pumps these valves will continue to modulate and automatically maintain steam generator water level. After the steam generator decreases in pressure to a certain setpoint the 4-inch valve will close to protect it from cavitation damage. The 2-inch LCV is designed for extended operation at low flows and high pressure drops. The system may be controlled manually. If the system is being tested in the manual mode and an automatic start signal is received, the control will revert to automatic. After an accident, the operator can take manual control by blocking the accident signal with the handswitch. However, if another accident signal occurs (such as would happen if the operator allowed the steam generator water level to drop to the low-low level) the control will again revert to automatic. As discussed in 10.4.9.3, there are postulated events when the turbine driven AFW pump LCV may be under local manual control. Automatic operation during these events will not be possible. Figures 10.4-16, 10.4-19 and 10.4-20 give details of the control and logic of the AFW system. REFERENCES None 10.4-38
WBN-1 TABLE 10.4-1 AUXILIARY FEEDWATER PUMP PARAMETERS Total Number Per Unit 3 Electric Driven 2 Turbine Driven 1 Design Flow Rate, gpm Electric Driven, each 450 Turbine Driven 790 Design Pressure, psig 1600 Design Temperature, °F 40 to 120 when supplied by the Condensate System 40 to 130 when supplied by the ERCW (Reference 10.4.9.2) Design Head, feet Electric Driven (as tested) 3250.5 Turbine Driven 3350
WBN TABLE 10.4-2 Failure Analysis, Steam Generator Blowdown System Failure Consequences Action
- 1. Rupture of blowdown line between Hot water under pressure partially flashes to When containment pressure reaches the high pressure steam generator and blowdown isolation steam. Pressure in lower compartment setpoint, reactor is automatically scrammed, and Phase valves inside containment and break increases, and vapor passes through ice beds. A containment isolation valves close. Main feedwater between blowdown isolation valves and Water level in affected steam generator lines isolate, blowdown isolation valves close, and containment penetration. increases initially and then drains. auxiliary feedwater pumps start. Charging pumps start Radioactivity present in steam generator and pump borated water into the primary system.
remains inside containment. When it is determined that the fault is not in the primary system, it is put into hot shutdown operation. If the break happens between the isolation valve and the containment penetration, automatic closure of the isolation valves initiated by the containment pressure signal terminates the release. If the break is ahead of the isolation valve when the cause of the fault is identified, auxiliary feedwater to the affected steam generator is cut off and the steam generator is allowed to boil and drain itself dry.
- 2. Rupture of blowdown line from outside Hot water under pressure escapes into main When the leak is discovered, the operator closes all containment penetration to blowdown steam valve vault, outside the building, or blowdown isolation valves and then opens them one at control valve downstream of heat inside the turbine building and partially flashes a time to locate the leak. The unit is shut down as exchanger. to steam. Some of radioactive material in necessary to repair the leak.
blowdown will escape directly to atmosphere or be carried out with turbine building ventilation exhaust, depending on where the rupture occurs.
- 3. Rupture of blowdown line downstream of Water under pressure escapes into turbine Same as (2) the blowdown control valve in the heat building and is collected by liquid waste exchanger flow path. system.
- 4. Failure of blowdown control valve. Flow will increase to maximum value allowed When the failure is discovered, the containment by manual throttling valves. isolation valves will be closed so that the control valve can be repaired.
- 5. Tube rupture in a heat exchanger Blowdown water escapes into the heat When the failure is discovered, the containment exchanger cooling water channel. isolation valves will be closed so that the heat exchanger can be repaired.
- 6. Failure of Containment Isolation Valves None Redundant valve ensures containment isolation is achieved.
WBN TABLE 10.4-3 (Sheet 1 of 2) FAILURE MODE & EFFECTS ANALYSIS STEAM SUPPLY SUBSYSTEM Mode of Operation: 1-Hot Standby, 2-Startup, 3-Power Operation, 4-Normal Shutdown, 5-Emergency Shutdown, 6-Design Basis Event (Listed in Remarks Column) MODE OF OPER. FAILURE METHOD EFFECT ON COMPONENT FUNCTION 1 2 3 4 5 6 MODE OF DET. SUBSYSTEM SYSTEM REMARKS*
- 1. Main Steam Source of Steam X X X X X x --- --- --- See pipe failure Piping analysis
- 2. FCV 1-16 Provides two X X X X X Fails Closed Control Room Loss of one of two None Redundant steam (FCV 1-15) different steam Fails Open (Valve Position steam sources. source available from supplies, but to X X X X X (Ind.) No effect unless other SG prevent blow-down pipe rupture, then Motor-Driven pumps of two SG in event blow- down of one would provide req'd of pipe rupture, SG and loss of feedwater flow.
only one steam flow from TD pump. source is available at one time. Isolation Valve only
- 3. Check Valve Prevents reverse X X X X X Fails Closed None unless Loss of one of two None Redundant steam (1-892, 1-891) flow and blowdown Fails Open valve FCV 1-16 steam sources source available from in case of pipe X X X X X open, the If pipe rupture the SG and Motor-rupture. control room could close both Driven pumps would Ind., control steam sources and provide req'd flow.
room, from thus flow from TD Motor-Driven pumps effect on pump. would provid req'd. subsystem (no flow. feedwater flow).
- 4. FCV 1-18 Isolates in case of X X X Fails Closed Control Room Loss of steam None Motor-driven pumps pipe rupture. X X X Fails Open (Valve Position supply. would Isolation Valve Ind.) None provide req'd. flow.
only If isolation req'd redundant FCV-1-17 would provide this feature
- 5. FCV 1-17 Isolates in case of X X Fails Closed Control Room Loss of steam None Motor-driven pumps
WBN TABLE 10.4-3 (Sheet 2 of 2) FAILURE MODE & EFFECTS ANALYSIS STEAM SUPPLY SUBSYSTEM pipe rupture. X X Fails Open (Valve Position supply wouldprovide req'd Ind.) None flow. If isolation req'd redundant FCV-1-18 would provide this feature
- 6. FCV 1-51 Trip & throttle X X Fails Closed Control Room Turbine Trip and None Motor-driven pumps valve Fails Open (Valve Position loss of Aux. FW would provide req'd X X Ind.) Flow from TD flow.
pump. In the event of a loss of load (pipe break) governor valve would limit pump speed.
- 7. FCV 1-52 Governor Valve X X Fails Closed Control Room Turbine Trip and None Motor-driven pumps X X Fails Open (Valve Position loss would Ind.) of Aux. FW Flow provide req'd flow.
from TD pump.
- 8. Turbine Drives pump X X TURBINE Control Room None None Motor-driven pumps Failure (no FW Flow) would provide req'd flow.
All Components All Functions X X X X X X All modes Visual/Control None None Since postulated Room accidents are (1-8) considered only for the design basis event, a single component failure (during mode 1-5 operation) will be less severe than the failures considered above and will not affect the ability of the Aux. FW system to perform its intended design function.
- Consequences for design basis events are not listed for mode 6 operation unless otherwise noted. Also, see footnote for turbine-driven (T-D) pump subsystem.
WBN TABLE 10.4-4 (Sheet 1 of 6) UNIT 1 FAILUER MODE & EFFECTS ANALYSIS TURBINE-DRIVEN (TD) PUMP SUBSYSTEM (Steam Generator (SG) - Loop No. 4 Typical) TRAIN S FAILURE MODES AND EFFECTS ANALYSIS Cooldown for Stage 1 of DBE Flood Main Feed Line Break with LOOP Loss of Normal Feedwater with LOOP Large Break LOCA with LOOP Main Steam Line Break with LOOP FAILURE POTENTIAL METHOD OF EFFECT EFFECT ITEM NO. COMPONENT FUNCTION MODE CAUSE DETECTION ON SYSTEM ON PLANT REMARKS
- 1. Check valve Isolates the safety- Stuck closed. Mechanical failure. Control Room Loss of TDP None. MDP 1A-A & 1B-1-3-810. related suction line indication via B provides flow for the TDP flow indicator FI- to all 4 SG's.
1A-S from its non- 3-142A safety water Mechanical failure. source Stuck open. No method Degradation of None. TDP will still be available. flow from operable; TDAFW pump however, MDP's if supplied from are still available ERCW. to all SG's.
- 2. TDP 1A-S Provides Fails to start. Mechanical failure, Control Room Loss of flow to None. MDP's 1A-A &
Feedwater flow to spurious control indication via all four SG's. 1B-B provides all four SG's. signal. indicator FI flow to all 4 142A. SG's. Seal fails. Mechanical failure. Control Room TDP 1A-S None. MDP's 1A-A & indication pump flow is 1B-B will provide reduced flow via diminished. flow to all four FI-3-142A. SG's.
WBN TABLE 10.4-4 (Sheet 2 of 6) UNIT 1 FAILUER MODE & EFFECTS ANALYSIS TURBINE-DRIVEN (TD) PUMP SUBSYSTEM (Steam Generator (SG) - Loop No. 4 Typical) TRAIN S FAILURE MODES AND EFFECTS ANALYSIS Cooldown for Stage 1 of DBE Flood Main Feed Line Break with LOOP Loss of Normal Feedwater with LOOP Large Break LOCA with LOOP Main Steam Line Break with LOOP FAILURE POTENTIAL METHOD OF EFFECT EFFECT ITEM NO. COMPONENT FUNCTION MODE CAUSE DETECTION ON SYSTEM ON PLANT REMARKS
- 3. Check Valve Maintains water Stuck closed. Mechanical failure. Control Room Loss of flow to None. MDP's 1A-A &
1-3-864 inventory in indication via all four SG's. 1B-B provides downstream piping flow indicator flow to all 4 of TDP 1A-S by FI-3-142A. SG's. preventing reverse flow. Stuck open. Mechanical failure. None. None, if TDP 1A- None. No loss of S is running. If pump.* pump is not running, (no initiating event), water would be maintained in the pump A discharge piping up to LCV's 3-172,-173, -174 &
-175 by pressure of the min reserve water in the CST (EL 745'-6.365") plus the atmospheric pressure above the water in the tank.
- 4. AOV Regulates AFW Fails to open. Control failure. Control Room Loss of AFW None. MDP 1B-B will flow to SG 4 from indication via flow to SG 4. provide flow to LCV-3-175 (fails TDP 1A-S. control switch SG 4.
in closed HS-3-175A. position) spring Fails to close. Control failure. Control Room AFW flow to SG None. Operator action
WBN TABLE 10.4-4 (Sheet 3 of 6) UNIT 1 FAILUER MODE & EFFECTS ANALYSIS TURBINE-DRIVEN (TD) PUMP SUBSYSTEM (Steam Generator (SG) - Loop No. 4 Typical) TRAIN S FAILURE MODES AND EFFECTS ANALYSIS Cooldown for Stage 1 of DBE Flood Main Feed Line Break with LOOP Loss of Normal Feedwater with LOOP Large Break LOCA with LOOP Main Steam Line Break with LOOP FAILURE POTENTIAL METHOD OF EFFECT EFFECT ITEM NO. COMPONENT FUNCTION MODE CAUSE DETECTION ON SYSTEM ON PLANT REMARKS to close air to indication via 4 unregulated. required to open control switch Diminished flow isolate TDP 1A-HS-3-175A. to SG's 1, 2 & 3. S to prevent SG 4 overfill. AFW flow to SG Stuck open. Mechanical failure. Control Room 4 unregulated. None. Operator action indication of SG Diminished flow required to 4 level. High to SG's 1, 2 & 3. isolate TDP 1A-level via XA S to prevent SG Loss of AFW 3C-63B. 4 overfill. flow to SG 4. Stuck closed. Mechanical failure. Control Room None. MDP 1B-B will indication via provide flow to control switch SG 4. HS-3-175A.
- 5. Condensate Water Supply Tank Discharge Mechanical failure. Control Room Loss of None. On loss of Storage Tank Plugged Alarm (Loss of condensate condensate suction water supply. supply, the pressure). essential raw cooling water (ERCW) system supply is automatically provided.
- 6. Check valve Prevents reverse Stuck Closed. Mechanical failure. Control Room Loss of TDP 1A- None. MDP 1B-B will flow in TDP 1A-S indication via S flow to SG 4. provide flow to 1-3-874 discharge line to flow indicators SG 4.
SG 4. FI-3-142A & - 170A. Not a problem if Stuck open. Mechanical failure. None. TDP 1A-S is None.
- running, if not
WBN TABLE 10.4-4 (Sheet 4 of 6) UNIT 1 FAILUER MODE & EFFECTS ANALYSIS TURBINE-DRIVEN (TD) PUMP SUBSYSTEM (Steam Generator (SG) - Loop No. 4 Typical) TRAIN S FAILURE MODES AND EFFECTS ANALYSIS Cooldown for Stage 1 of DBE Flood Main Feed Line Break with LOOP Loss of Normal Feedwater with LOOP Large Break LOCA with LOOP Main Steam Line Break with LOOP FAILURE POTENTIAL METHOD OF EFFECT EFFECT ITEM NO. COMPONENT FUNCTION MODE CAUSE DETECTION ON SYSTEM ON PLANT REMARKS LCV-3-175 will prevent reverse flow thru pump discharge piping.
- 7. Check valve Prevents Stuck closed. Mechanical failure. Control Room Loss of AFW to AFW flow blowdown of SG 4 indication via SG 4. None. required to only 1-3-644 in case of an AFW flow indicator two SG's.
line break inside FI-3-170A. In containment. addition to SG Stuck open. Mechanical failure. None. Check None.* level None. valve 1-3-645 instrumentation. will prevent blowdown of SG None. 4.
- 8. Check valve Backup valve to 1- Stuck closed. Mechanical failure. Control Room Loss of AFW to None. AFW flow 3-644 (same indication via SG 4. required to only 1-3-645 function) flow indicator two SG's.
FI-3-170A. In addition to SG level instrumentation. Stuck open. None. None. Valve 1- None. None.* Mechanical failure. CKV-3-644 will prevent blowdown of SG 4.
- 9. TDP 1A-S min Prevents backflow Stuck closed. Mechanical failure. TDP Could cause None. MDP's 1A-A &
flow recirc line to from CST to TDP overheating as TDP 1A-S to 1B-B will provide
WBN TABLE 10.4-4 (Sheet 5 of 6) UNIT 1 FAILUER MODE & EFFECTS ANALYSIS TURBINE-DRIVEN (TD) PUMP SUBSYSTEM (Steam Generator (SG) - Loop No. 4 Typical) TRAIN S FAILURE MODES AND EFFECTS ANALYSIS Cooldown for Stage 1 of DBE Flood Main Feed Line Break with LOOP Loss of Normal Feedwater with LOOP Large Break LOCA with LOOP Main Steam Line Break with LOOP FAILURE POTENTIAL METHOD OF EFFECT EFFECT ITEM NO. COMPONENT FUNCTION MODE CAUSE DETECTION ON SYSTEM ON PLANT REMARKS CST check valve 1A-S discharge indicated by TI overheat and flow to all four 3-818. piping. 3-149 (local TI). become SG's. inoperable preventing AFW flow to all four SG's (only if flow demand is low). No effect on Stuck open. Mechanical failure. No method of system if TDP detection. None. Will not affect 1A-S is running. recirc flow to If TDP 1A-S is CST. not running, system resistance would prevent backflow from occurring. Control failure Control Room
- 10. MOVs Isolation between Either fails to Train B ERCW None. Flow from indication via (77) FCV-3-179A Train B of ERCW open will be blocked Train A of the control switches FCV-3-179B and TDP 1B and from TDP 1A-S ERCW to TD or HS-3-179A and (78) TDP 1A-S suction. Mechanical failure. suction. pump suction will (fail as is) HS-3-179B.
Either sticks Automatic allow pump to closed. transfer to Train operate. A. Both valves fail Control Room Control or power Train B ERCW None. TDP 1A-to open indication via failure. Mechanical will be blocked S would take or control switches failure from TDP 1A-S suction from HS-3-179A and Both valves suction. ERCW Train A, HS-3-179B. stuck closed. provides flow to Automatic SGs 3 and 4.
WBN TABLE 10.4-4 (Sheet 6 of 6) UNIT 1 FAILUER MODE & EFFECTS ANALYSIS TURBINE-DRIVEN (TD) PUMP SUBSYSTEM (Steam Generator (SG) - Loop No. 4 Typical) TRAIN S FAILURE MODES AND EFFECTS ANALYSIS Cooldown for Stage 1 of DBE Flood Main Feed Line Break with LOOP Loss of Normal Feedwater with LOOP Large Break LOCA with LOOP Main Steam Line Break with LOOP FAILURE POTENTIAL METHOD OF EFFECT EFFECT ITEM NO. COMPONENT FUNCTION MODE CAUSE DETECTION ON SYSTEM ON PLANT REMARKS transfer to Train A. Control failure Control Room
- 11. MOVs Isolation between Either fails to Train A ERCW None. Flow from indication via (71) FCV-3-136A Train A of the open will be blocked Train B of the control switches FCV-3-136B ERCW and TDP from TDP 1A-S ERCW to TD or HS-3-136A and (72) 1A-S of suction. Mechanical failure. suction. pump suction will (fail as is) HS-3-136B.
Either sticks Automatic allow pump to closed. transfer to Train operate. B. Both valves fail Control or power Control Room Train A ERCW None TDP 1A-S to open failure. Mechanical indication via will be blocked would take or failure control switches from TDP 1A-S suction from HS-3-136A and Both valves suction. ERCW Train B, HS-3-136B. stuck closed. Automatic providing flow to transfer to Train SGs 1 and 2. B.
- For the failure of these check valves in the open position, reverse flow from the steam generator to the individual pump casings is prevented by other redundant series check valves.
WBN TABLE 10.4-4 (Sheet 1 of 6) UNIT 2 FAILUER MODE & EFFECTS ANALYSIS TURBINE-DRIVEN (TD) PUMP SUBSYSTEM (Steam Generator (SG) - Loop No. 4 Typical) TRAIN S FAILURE MODES AND EFFECTS ANALYSIS Cooldown for Stage 1 of DBE Flood Main Feed Line Break with LOOP Loss of Normal Feedwater with LOOP Large Break LOCA with LOOP Main Steam Line Break with LOOP FAILURE POTENTIAL METHOD OF EFFECT EFFECT ITEM NO. COMPONENT FUNCTION MODE CAUSE DETECTION ON SYSTEM ON PLANT REMARKS
- 1. Check valve Isolates the safety- Stuck closed. Mechanical failure. Control Room Loss of TDP None. MDP 2A-A & 2B-2-3-810. related suction line indication via B provides flow for the TDP flow indicator FI- to all 4 SG's.
2A-S from its non- 3-142A safety water Mechanical failure. source Stuck open. No method Degradation of None. TDP will still be available. flow from operable; TDAFW pump however, MDP's if supplied from are still available ERCW. to all SG's.
- 2. TDP 2A-S Provides Fails to start. Mechanical failure, Control Room Loss of flow to None. MDP's 2A-A &
Feedwater flow to spurious control indication via all four SG's. 2B-B provides all four SG's. signal. indicator FI flow to all 4 142A. SG's. Seal fails. Mechanical failure. Control Room TDP 2A-S None. MDP's 2A-A & indication pump flow is 1B-B will provide reduced flow via diminished. flow to all four FI-3-142A. SG's.
WBN TABLE 10.4-4 (Sheet 2 of 6) UNIT 2 FAILUER MODE & EFFECTS ANALYSIS TURBINE-DRIVEN (TD) PUMP SUBSYSTEM (Steam Generator (SG) - Loop No. 4 Typical) TRAIN S FAILURE MODES AND EFFECTS ANALYSIS Cooldown for Stage 1 of DBE Flood Main Feed Line Break with LOOP Loss of Normal Feedwater with LOOP Large Break LOCA with LOOP Main Steam Line Break with LOOP FAILURE POTENTIAL METHOD OF EFFECT EFFECT ITEM NO. COMPONENT FUNCTION MODE CAUSE DETECTION ON SYSTEM ON PLANT REMARKS
- 3. Check Valve Maintains water Stuck closed. Mechanical failure. Control Room Loss of flow to None. MDP's 2A-A &
2-3-864 inventory in indication via all four SG's. 2B-B provides downstream piping flow indicator flow to all 4 of TDP 2A-S by FI-3-142A. SG's. preventing reverse flow. Stuck open. Mechanical failure. None. None, if TDP 2A- None. No loss of S is running. If pump.* pump is not running, (no initiating event), water would be maintained in the pump A discharge piping up to LCV's 3-172,-173, -174 &
-175 by pressure of the min reserve water in the CST (EL 745'-6.365") plus the atmospheric pressure above the water in the tank.
- 4. AOV Regulates AFW Fails to open. Control failure. Control Room Loss of AFW None. MDP 2B-B will flow to SG 4 from indication via flow to SG 4. provide flow to LCV-3-175 (fails TDP 2A-S. control switch SG 4.
in closed HS-3-175A. position) spring Fails to close. Control failure. Control Room AFW flow to SG None. Operator action
WBN TABLE 10.4-4 (Sheet 3 of 6) UNIT 2 FAILUER MODE & EFFECTS ANALYSIS TURBINE-DRIVEN (TD) PUMP SUBSYSTEM (Steam Generator (SG) - Loop No. 4 Typical) TRAIN S FAILURE MODES AND EFFECTS ANALYSIS Cooldown for Stage 1 of DBE Flood Main Feed Line Break with LOOP Loss of Normal Feedwater with LOOP Large Break LOCA with LOOP Main Steam Line Break with LOOP FAILURE POTENTIAL METHOD OF EFFECT EFFECT ITEM NO. COMPONENT FUNCTION MODE CAUSE DETECTION ON SYSTEM ON PLANT REMARKS to close air to indication via 4 unregulated. required to open control switch Diminished flow isolate TDP 2A-HS-3-175A. to SG's 1, 2 & 3. S to prevent SG 4 overfill. Stuck open. Mechanical failure. Control Room AFW flow to SG None. Operator action indication of SG 4 unregulated. required to 4 level. High Diminished flow isolate TDP 2A-level via XA to SG's 1, 2 & 3. S to prevent SG 3C-63B. 4 overfill. Stuck closed. Mechanical failure. Control Room None. Loss of AFW MDP 2B-B will indication via flow to SG 4. provide flow to control switch SG 4. HS-3-175A.
- 5. Condensate Water Supply Tank Discharge Mechanical failure. Control Room Loss of None. On loss of Storage Tank Plugged Alarm (Loss of condensate condensate suction water supply. supply, the pressure). essential raw cooling water (ERCW) system supply is automatically provided.
- 6. Check valve Prevents reverse Stuck Closed. Mechanical failure. Control Room Loss of TDP 2A- None. MDP 2B-B will flow in TDP 2A-S indication via S flow to SG 4. provide flow to 2-3-874 discharge line to flow indicators SG 4.
SG 4. FI-3-142A & - 170A. Not a problem if Stuck open. Mechanical failure. None. TDP 2A-S is None. running, if not
WBN TABLE 10.4-4 (Sheet 4 of 6) UNIT 2 FAILUER MODE & EFFECTS ANALYSIS TURBINE-DRIVEN (TD) PUMP SUBSYSTEM (Steam Generator (SG) - Loop No. 4 Typical) TRAIN S FAILURE MODES AND EFFECTS ANALYSIS Cooldown for Stage 1 of DBE Flood Main Feed Line Break with LOOP Loss of Normal Feedwater with LOOP Large Break LOCA with LOOP Main Steam Line Break with LOOP FAILURE POTENTIAL METHOD OF EFFECT EFFECT ITEM NO. COMPONENT FUNCTION MODE CAUSE DETECTION ON SYSTEM ON PLANT REMARKS LCV-3-175 will prevent reverse flow thru pump discharge piping. None.
- 7. Check valve Prevents Stuck closed. Mechanical failure. Control Room Loss of AFW to AFW flow blowdown of SG 4 indication via SG 4. required to only 2-3-644 in case of an AFW flow indicator two SG's.
line break inside FI-3-170A. In None. containment. addition to SG Stuck open. Mechanical failure. None. Check None.* level valve 2-3-645 instrumentation. will prevent blowdown of SG None. 4.
- 8. Check valve Backup valve to 2- Stuck closed. Mechanical failure. Control Room Loss of AFW to None. AFW flow 3-644 (same indication via SG 4. required to only 2-3-645 function) flow indicator two SG's.
FI-3-170A. In addition to SG level instrumentation Stuck open. None. None. Check None. None.* Mechanical failure. Valve 2-3-644 will prevent blowdown of SG 4.
- 9. TDP 2A-S min Prevents backflow Stuck closed. Mechanical failure. TDP Could cause None. MDP's 2A-A &
flow recirc line to from CST to TDP overheating as TDP 2A-S to 2B-B will provide
WBN TABLE 10.4-4 (Sheet 5 of 6) UNIT 2 FAILUER MODE & EFFECTS ANALYSIS TURBINE-DRIVEN (TD) PUMP SUBSYSTEM (Steam Generator (SG) - Loop No. 4 Typical) TRAIN S FAILURE MODES AND EFFECTS ANALYSIS Cooldown for Stage 1 of DBE Flood Main Feed Line Break with LOOP Loss of Normal Feedwater with LOOP Large Break LOCA with LOOP Main Steam Line Break with LOOP FAILURE POTENTIAL METHOD OF EFFECT EFFECT ITEM NO. COMPONENT FUNCTION MODE CAUSE DETECTION ON SYSTEM ON PLANT REMARKS CST check valve 2A-S discharge indicated by TI overheat and flow to all four 3-818. piping. 3-149 (local TI). become SG's. inoperable preventing AFW flow to all four SG's (only if flow demand is low). No effect on Stuck open. Mechanical failure. No method of system if TDP detection. None. Will not affect 2A-S is running. recirc flow to If TDP 2A-S is CST. not running, system resistance would prevent backflow from occurring. Control failure Control Room
- 10. MOVs Isolation between Either fails to Train B ERCW None. Flow from indication via (77) FCV-3-179A Train B of ERCW open will be blocked Train A of the control switches FCV-3-179B and TDP 2A-S from TDP 2A-S ERCW to TD or HS-3-179A and (78) suction. Mechanical failure. suction. pump suction will (fail as is) HS-3-179B.
Either sticks Automatic allow pump to closed. transfer to Train operate. A. Both valves fail Control Room Control or power Train B ERCW None. TDP 2A-to open indication via failure. Mechanical will be blocked S would take or control switches failure from TDP 1A-S suction from HS-3-179A and Both valves suction. ERCW Train A, HS-3-179B. stuck closed. provides flow to Automatic SGs 3 and 4. transfer to Train
WBN TABLE 10.4-4 (Sheet 6 of 6) UNIT 2 FAILUER MODE & EFFECTS ANALYSIS TURBINE-DRIVEN (TD) PUMP SUBSYSTEM (Steam Generator (SG) - Loop No. 4 Typical) TRAIN S FAILURE MODES AND EFFECTS ANALYSIS Cooldown for Stage 1 of DBE Flood Main Feed Line Break with LOOP Loss of Normal Feedwater with LOOP Large Break LOCA with LOOP Main Steam Line Break with LOOP FAILURE POTENTIAL METHOD OF EFFECT EFFECT ITEM NO. COMPONENT FUNCTION MODE CAUSE DETECTION ON SYSTEM ON PLANT REMARKS A. Control failure Control Room
- 11. MOVs Isolation between Either fails to Train A ERCW None. Flow from indication via (71) FCV-3-136A Train A of the open will be blocked Train B of the control switches FCV-3-136B ERCW and TDP from TDP 2A-S ERCW to TD or HS-3-136A and (72) 2A-S of suction. Mechanical failure. suction. pump suction will (fail as is) HS-3-136B.
Either sticks Automatic allow pump to closed. transfer to Train operate. B. Both valves fail Control or power Control Room Train A ERCW None TDP 2A-S to open failure. indication via will be blocked would take or control switches from TDP 2A-S suction from Mechanical failure HS-3-136A and Both valves suction. ERCW Train B, HS-3-136B. stuck closed. Automatic providing flow to transfer to Train SGs 3 and 4. B.
- For the failure of these check valves in the open position, reverse flow from the steam generator to the individual pump casings is prevented by other redundant series check valves.
WBN-2 TABLE 10.4-5 (Sheet 1 of 8) UNIT 1 FAILURE MODE & EFFECTS ANALYSIS MOTOR DRIVEN (MD) PUMP SUBSYSTEM (Steam Generator (SG) Loop No. 4 - Typical) TRAIN B FAILURE MODES AND EFFECTS ANALYSIS Cooldown for Stage 1 of DBE Flood Main Feed Line Break with LOOP Loss of Normal Feedwater with LOOP Large Break LOCA with LOOP Main Steam Line Break with LOOP FAILURE POTENTIAL METHOD OF EFFECT EFFECT ITEM NO. COMPONENT FUNCTION MODE CAUSE DETECTION ON SYSTEM ON PLANT REMARKS
- 1. Check valve Isolates the Stuck Mechanical Control Room Loss of flow None. TD 1A-S 1-3-806 safety-related closed. failure. indication via from MDP provides flow suction line for pressure 1B-B. to SG's 3 & 4.
MDP 1B-B from gage PDI its non-safety 132A. water source. Control Room Stuck open. Mechanical Reduction or failure. indication via loss of flow if None. TD 1A-S pressure MDP 1B-B provides flow gage PDI flow is from to SG's 3 & 4. 132A the ERCW.
- 2. MOV'S Isolation valves Either fails to Control failure. Control Room Loss of AFW None. TDP 1A-S FCV-3-126A between open or indication via flow to SG's provides ERCW and Either stuck Mechanical control 3 & 4. flows to SG's
- 3. FCV-3-126B. MDP 1B-B switches HS (fail as is) closed. failure. 3 & 4.
suction. 126A & HS 126B. Loss of AFW None. TDP 1A-S Both valves Control or Control Room indication via flow to SG's provides fail to open power failure. 3 & 4. flows to SG's or control Mechanical switches HS 3 & 4. Both valves failure. 126A & HS stuck closed. 126B.
- 4. MDP 1B-B Provides Fails to start. Mechanical Control Room Loss of Train None. TDP 1A-S
WBN-2 TABLE 10.4-5 (Sheet 2 of 8) UNIT 1 FAILURE MODE & EFFECTS ANALYSIS MOTOR DRIVEN (MD) PUMP SUBSYSTEM (Steam Generator (SG) Loop No. 4 - Typical) TRAIN B FAILURE MODES AND EFFECTS ANALYSIS Cooldown for Stage 1 of DBE Flood Main Feed Line Break with LOOP Loss of Normal Feedwater with LOOP Large Break LOCA with LOOP Main Steam Line Break with LOOP FAILURE POTENTIAL METHOD OF EFFECT EFFECT ITEM NO. COMPONENT FUNCTION MODE CAUSE DETECTION ON SYSTEM ON PLANT REMARKS Feedwater flow failure. indication via B. provides flow to SG's 3 & 4. control switch to SG's 3 & 4. HS-3-128A & pressures differential indicator PDI-3-132A. Control Room TDP 1A-S Seal fails. Mechanical indication MDP 1B-B None. provides flow failure. reduced flow capability is to SG's 3 & 4. via FI-3-147B diminished.
& FI-3-170A.
- 5. Condensate Storage Tank (For details, see this heading in Table 10.4-4, Sheet 4).
- 6. Check Valve None N/A N/A N/A N/A None Valve 1-3-821 Internals have been removed.
WBN-2 TABLE 10.4-5 (Sheet 3 of 8) UNIT 1 FAILURE MODE & EFFECTS ANALYSIS MOTOR DRIVEN (MD) PUMP SUBSYSTEM (Steam Generator (SG) Loop No. 4 - Typical) TRAIN B FAILURE MODES AND EFFECTS ANALYSIS Cooldown for Stage 1 of DBE Flood Main Feed Line Break with LOOP Loss of Normal Feedwater with LOOP Large Break LOCA with LOOP Main Steam Line Break with LOOP FAILURE POTENTIAL METHOD OF EFFECT EFFECT ITEM NO. COMPONENT FUNCTION MODE CAUSE DETECTION ON SYSTEM ON PLANT REMARKS
- 7. DELETED
- 8. AOV Regulates AFW Fails to Control failure. Control Room Loss of AFW None. TDP 1A-S flow to SG 4 open. indication via flow to SG 4. provides flow LCV-3-171 when pressure control switch (fails in open to SG 4.
is greater than HS-3-171A. position) setpoint for spring to open pressure switch Control Room air to close. Fails to Control failure. AFW flow to None. Operator PS-3-171. (4" close. indication via SG 4 action level control control switch unregulated. required to valve.) HS-3-171A. Diminished isolate MDP flow to SG 3. 1B-B to prevent SG 4 overfill. Stuck open. Mechanical Control Room AFW flow to None. failure. indication of SG 4 Operator SG 4. High unregulated. action level via XA- Diminished required to 55-3C-63B. flow to SG 3. isolate MDP 1B-B to prevent SG 4 overfill. Stuck Control Room None. closed. Mechanical Loss of AFW TDP 1A-S indication via failure. flow to SG 4. provides flow control switch
WBN-2 TABLE 10.4-5 (Sheet 4 of 8) UNIT 1 FAILURE MODE & EFFECTS ANALYSIS MOTOR DRIVEN (MD) PUMP SUBSYSTEM (Steam Generator (SG) Loop No. 4 - Typical) TRAIN B FAILURE MODES AND EFFECTS ANALYSIS Cooldown for Stage 1 of DBE Flood Main Feed Line Break with LOOP Loss of Normal Feedwater with LOOP Large Break LOCA with LOOP Main Steam Line Break with LOOP FAILURE POTENTIAL METHOD OF EFFECT EFFECT ITEM NO. COMPONENT FUNCTION MODE CAUSE DETECTION ON SYSTEM ON PLANT REMARKS HS-3-171A. to SG 4.
- 9. AOV Regulates AFW Fails to Control failure. Control Room Loss of AFW None. TDP 1A-S flow to SG 4 (2" open. indication via flow to SG 4 provides flow LCV-3-171A level control (fails in closed control switch through to SG 4.
bypass valve). HS-3-171A. LCV-3-171A. position) spring to Operator close air to Fails to Control failure. Control Room Diminished None. action open. close. indication via AFW flow to required to control switch SG 3. isolate MDP HS-3-171A. 1B-B to prevent SG 4 overfill. Stuck open. Mechanical Control Room Diminished None. failure. indication of AFW flow to Operator SG 4 level. SG 3. action High level via required to XA-55-3C- isolate MDP 63B. 1B-B to None. prevent SG 4 Stuck Mechanical Loss of AFW Control Room overfill. closed. failure. flow to SG 4 indication via through TDP 1A-S control switch LCV-3-171A. provides flow HS-3-171A. to SG 4.
WBN-2 TABLE 10.4-5 (Sheet 5 of 8) UNIT 1 FAILURE MODE & EFFECTS ANALYSIS MOTOR DRIVEN (MD) PUMP SUBSYSTEM (Steam Generator (SG) Loop No. 4 - Typical) TRAIN B FAILURE MODES AND EFFECTS ANALYSIS Cooldown for Stage 1 of DBE Flood Main Feed Line Break with LOOP Loss of Normal Feedwater with LOOP Large Break LOCA with LOOP Main Steam Line Break with LOOP FAILURE POTENTIAL METHOD OF EFFECT EFFECT ITEM NO. COMPONENT FUNCTION MODE CAUSE DETECTION ON SYSTEM ON PLANT REMARKS
- 10. Emergency Provide AC Fails. Diesel Control Room MDP 1B-B is None. Train A would power to power to MDP Generator indication. lost. be available Train B. 1B-B & all Shutdown to service MOV's in Train Board 1B-B SG's 1 & 2.
B. failure. This is acceptable condition since only 2 SG's are required to be operational for any credible accident. TDAFW pump is also available.
- 11. Check valve Prevents Stuck open. Mechanical None. Not a None. None*
reverse flow in failure. problem if 1-3-833. 4" AFW line to MDP 1B-B is SG 4. running, if not LCV 171 and - 171A will
WBN-2 TABLE 10.4-5 (Sheet 6 of 8) UNIT 1 FAILURE MODE & EFFECTS ANALYSIS MOTOR DRIVEN (MD) PUMP SUBSYSTEM (Steam Generator (SG) Loop No. 4 - Typical) TRAIN B FAILURE MODES AND EFFECTS ANALYSIS Cooldown for Stage 1 of DBE Flood Main Feed Line Break with LOOP Loss of Normal Feedwater with LOOP Large Break LOCA with LOOP Main Steam Line Break with LOOP FAILURE POTENTIAL METHOD OF EFFECT EFFECT ITEM NO. COMPONENT FUNCTION MODE CAUSE DETECTION ON SYSTEM ON PLANT REMARKS prevent reverse flow thru pump Stuck Mechanical Control Room discharge None. TDP 1A-S closed. failure. indication via piping. provides flow flow indicator to SG 4. FI-3-170A. Loss of AFW to SG 4.
- 12. MDP 1B-B Prevents Stuck Mechanical Pump/Motor MDP 1B-B to None. TDP 1A-S will min flow backflow from closed. failure. high temp as overheat and provide flow recirc line to CST to MDP indicated by become to SG's 3 & 4.
CST check 1B-B discharge TI 3-146 inoperative valve 3-815. piping. (local TI) or preventing EI-3-129A (hi AFW flow to amps). SG's 3 & 4 (only if flow Stuck open. Mechanical No method of demand is None. None failure. detection. low). No affect on system if MDP 1B-B is running. If
WBN-2 TABLE 10.4-5 (Sheet 7 of 8) UNIT 1 FAILURE MODE & EFFECTS ANALYSIS MOTOR DRIVEN (MD) PUMP SUBSYSTEM (Steam Generator (SG) Loop No. 4 - Typical) TRAIN B FAILURE MODES AND EFFECTS ANALYSIS Cooldown for Stage 1 of DBE Flood Main Feed Line Break with LOOP Loss of Normal Feedwater with LOOP Large Break LOCA with LOOP Main Steam Line Break with LOOP FAILURE POTENTIAL METHOD OF EFFECT EFFECT ITEM NO. COMPONENT FUNCTION MODE CAUSE DETECTION ON SYSTEM ON PLANT REMARKS MDP 1B-B is not running, system resistance would prevent backflow from occurring.
- 13. Check valve 1-3-644 (For details, see this heading in Table 10.4-4, Sheet 5).
- 14. Check valve 1-3-645 (For details, see this heading in Table 10.4-4, Sheet 5).
WBN-2 TABLE 10.4-5 (Sheet 8 of 8) UNIT 1 FAILURE MODE & EFFECTS ANALYSIS MOTOR DRIVEN (MD) PUMP SUBSYSTEM (Steam Generator (SG) Loop No. 4 - Typical) TRAIN B FAILURE MODES AND EFFECTS ANALYSIS Cooldown for Stage 1 of DBE Flood Main Feed Line Break with LOOP Loss of Normal Feedwater with LOOP Large Break LOCA with LOOP Main Steam Line Break with LOOP FAILURE POTENTIAL METHOD OF EFFECT EFFECT ITEM NO. COMPONENT FUNCTION MODE CAUSE DETECTION ON SYSTEM ON PLANT REMARKS
- 15. AFW pump Prevents flow Stuck open. Mechanical Control Room Loss of Train None. TDP None.
1B-B recirc. being diverted failure indication via B. 1A-S will Flow control during an flow indicator provide flow valve FCV accident from FI-3-147B to SGs 3 & 4. 359 the SGs 3 & 4. and -170A and position indicating lights assoc. with HS 359.
- For the failure of these check valves in the open position, reverse flow from the steam generator to the individual pump casings is prevented by other redundant series check valves.
WBN TABLE 10.4-5 (Sheet 1 of 9) UNIT 2 FAILURE MODE & EFFECTS ANALYSIS MOTOR DRIVEN (MD) PUMP SUBSYSTEM (Steam Generator (SG) Loop No. 4 - Typical) TRAIN B FAILURE MODES AND EFFECTS ANALYSIS Cooldown for Stage 1 of DBE Flood Main Feed Line Break with LOOP Loss of Normal Feedwater with LOOP Large Break LOCA with LOOP Main Steam Line Break with LOOP FAILURE POTENTIAL METHOD OF EFFECT EFFECT ITEM NO. COMPONENT FUNCTION MODE CAUSE DETECTION ON SYSTEM ON PLANT REMARKS
- 1. Check valve Isolates the Stuck Mechanical Control Room Loss of flow TD 2A-S None.
2-3-806 safety-related closed. failure. indication via from MDP provides flow suction line for pressure 2B-B. to SG's 3 & 4. MDP 2B-B from gage PDI its non-safety 132A. water source. Reduction or TD 1A-S Stuck open. Mechanical Control Room loss of flow if None. indication via provides flow failure. MDP 2B-B to SG's 3 & 4. pressure flow is from gage PDI the ERCW. 132A
- 2. MOV'S Isolation valves Either fails to Control failure. Control Room Loss of AFW TDP 2A-S FCV-3-126A between open or indication via flow to SG's provides None.
- 3. ERCW and control FCV-3-126B. Either stuck Mechanical 3 & 4. flows to SG's MDP 2B-B closed. failure. switches HS 3 & 4.
(fail as is) suction. 126A & HS 126B. Loss of AFW None. Both valves Control or Control Room indication via flow to SG's TDP 2A-S fail to open power failure. 3 & 4. provides or control Mechanical switches HS flows to SG's Both valves failure. 126A & HS 3 & 4. stuck closed. 126B.
WBN TABLE 10.4-5 (Sheet 2 of 9) UNIT 2 FAILURE MODE & EFFECTS ANALYSIS MOTOR DRIVEN (MD) PUMP SUBSYSTEM (Steam Generator (SG) Loop No. 4 - Typical) TRAIN B FAILURE MODES AND EFFECTS ANALYSIS Cooldown for Stage 1 of DBE Flood Main Feed Line Break with LOOP Loss of Normal Feedwater with LOOP Large Break LOCA with LOOP Main Steam Line Break with LOOP FAILURE POTENTIAL METHOD OF EFFECT EFFECT ITEM NO. COMPONENT FUNCTION MODE CAUSE DETECTION ON SYSTEM ON PLANT REMARKS
- 4. MDP 2B-B Provides Fails to start. Mechanical Control Room Loss of Train None. TDP 2A-S Feedwater flow failure. indication via B. provides flow to SG's 3 & 4. control switch to SG's 3 &
HS-3-128A & 4. pressures differential indicator PDI-3-132A. Control Room Seal fails. Mechanical indication MDP 2B-B None. failure. reduced flow capability is TDP 2A-S via FI-3-147B diminished. provides flow
& FI-3-170A. to SG's 3 &
4.
- 5. Condensate Storage Tank (For details, see this heading in Table 10.4-4, Sheet 4).
WBN TABLE 10.4-5 (Sheet 3 of 9) UNIT 2 FAILURE MODE & EFFECTS ANALYSIS MOTOR DRIVEN (MD) PUMP SUBSYSTEM (Steam Generator (SG) Loop No. 4 - Typical) TRAIN B FAILURE MODES AND EFFECTS ANALYSIS Cooldown for Stage 1 of DBE Flood Main Feed Line Break with LOOP Loss of Normal Feedwater with LOOP Large Break LOCA with LOOP Main Steam Line Break with LOOP FAILURE POTENTIAL METHOD OF EFFECT EFFECT ITEM NO. COMPONENT FUNCTION MODE CAUSE DETECTION ON SYSTEM ON PLANT REMARKS
- 6. Check Valve None N/A N/A N/A N/A None Valve 2-3-821 Internals have been removed.
- 7. AOV Prevents MDP Fails to Control failure. Control Room Loss of MDP None. TDP 2A-S 2B-B runout by open. indication via 2B-B. provides flow PCV-3-132 controlling (fails in flow to SG's 3 &
pump indicators FI- 4. closed discharge position) 3-147B & - Possibility of pressure. Fails to Control failure. 170A. MDP 2B-B spring to None. close air to close. Control Room running out TDP 2A-S open. indication via and eventual provides flow flow loss of to SG's 3 & indicators FI- pump. 4. 3-147B & - 170A Also, pressure differential Possibility of Stuck open. Mechanical indicator PDI- MDP 2B-B None. failure. 3-132A. running out and eventual TDP 2A-S Control Room loss of provides flow indication via pump. to SG's 3 & flow 4.
WBN TABLE 10.4-5 (Sheet 4 of 9) UNIT 2 FAILURE MODE & EFFECTS ANALYSIS MOTOR DRIVEN (MD) PUMP SUBSYSTEM (Steam Generator (SG) Loop No. 4 - Typical) TRAIN B FAILURE MODES AND EFFECTS ANALYSIS Cooldown for Stage 1 of DBE Flood Main Feed Line Break with LOOP Loss of Normal Feedwater with LOOP Large Break LOCA with LOOP Main Steam Line Break with LOOP FAILURE POTENTIAL METHOD OF EFFECT EFFECT ITEM NO. COMPONENT FUNCTION MODE CAUSE DETECTION ON SYSTEM ON PLANT REMARKS indicators FI-3-147B & - Loss of MDP Stuck Mechanical 170A Also, 2B-B. None. closed. failure. pressure differential indicator PDI-TDP 2A-S 3-132A. provides flow Indication via to SG's 3 & flow 4. indicators FI-3-147B & - 170A
- 8. AOV Regulates AFW Fails to Control failure. Control Room Loss of AFW None. TDP 2A-S flow to SG 4 open. indication via flow to SG 4. provides flow LCV-3-171 when pressure control switch (fails in open to SG 4.
is greater than HS-3-171A. position) setpoint for spring to pressure switch Control Room open air to Fails to Control failure. AFW flow to None. Operator PS-3-171. (4" close. indication via SG 4 action close. level control control switch unregulated. required to valve.) HS-3-171A. Diminished isolate MDP flow to SG 3. 2B-B to prevent SG 4 overfill. Control Room
WBN TABLE 10.4-5 (Sheet 5 of 9) UNIT 2 FAILURE MODE & EFFECTS ANALYSIS MOTOR DRIVEN (MD) PUMP SUBSYSTEM (Steam Generator (SG) Loop No. 4 - Typical) TRAIN B FAILURE MODES AND EFFECTS ANALYSIS Cooldown for Stage 1 of DBE Flood Main Feed Line Break with LOOP Loss of Normal Feedwater with LOOP Large Break LOCA with LOOP Main Steam Line Break with LOOP FAILURE POTENTIAL METHOD OF EFFECT EFFECT ITEM NO. COMPONENT FUNCTION MODE CAUSE DETECTION ON SYSTEM ON PLANT REMARKS Stuck open. Mechanical indication of AFW flow to None. failure. SG 4. High SG 4 Operator level via XA- unregulated. action 55-3C-63B. Diminished required to flow to SG 3. isolate MDP 2B-B to prevent SG 4 Control Room overfill. Stuck indication via None. closed. Mechanical Loss of AFW TDP 2A-S failure. control switch flow to SG 4. provides flow HS-3-171A. to SG 4.
- 9. AOV Regulates AFW Fails to Control failure. Control Room Loss of AFW None. TDP 2A-S flow to SG 4 (2" open. indication via flow to SG 4 provides flow LCV-3-171A level control (fails in control switch through to SG 4.
bypass valve). HS-3-171A. LCV-3-171A. closed position) Operator spring to Fails to Control failure. Control Room Diminished None. action close air to close. indication via AFW flow to required to open. control switch SG 3. isolate MDP HS-3-171A. 2B-B to prevent SG 4 overfill. Stuck open. Mechanical Control Room Diminished None. Operator failure. indication of AFW flow to action
WBN TABLE 10.4-5 (Sheet 6 of 9) UNIT 2 FAILURE MODE & EFFECTS ANALYSIS MOTOR DRIVEN (MD) PUMP SUBSYSTEM (Steam Generator (SG) Loop No. 4 - Typical) TRAIN B FAILURE MODES AND EFFECTS ANALYSIS Cooldown for Stage 1 of DBE Flood Main Feed Line Break with LOOP Loss of Normal Feedwater with LOOP Large Break LOCA with LOOP Main Steam Line Break with LOOP FAILURE POTENTIAL METHOD OF EFFECT EFFECT ITEM NO. COMPONENT FUNCTION MODE CAUSE DETECTION ON SYSTEM ON PLANT REMARKS SG 4 level. SG 3. required to High level via isolate MDP XA-55-3C- 2B-B to 63B. prevent SG 4 Loss of AFW Control Room None. overfill. Stuck Mechanical flow to SG 4 closed. failure. indication via through TDP 2A-S control switch LCV-3-171A. provides flow HS-3-171A. to SG 4.
- 10. Emergency Provide AC Fails. Diesel Control Room MDP 2B-B is None. Train A would power to power to MDP Generator indication. lost. be available Train B. 2B-B & all Shutdown to service MOV's in Train Board 2B-B SG's 1 & 2.
B. failure. This is acceptable condition since only 2 SG's are required to be operational for any credible accident. TDAFW
WBN TABLE 10.4-5 (Sheet 7 of 9) UNIT 2 FAILURE MODE & EFFECTS ANALYSIS MOTOR DRIVEN (MD) PUMP SUBSYSTEM (Steam Generator (SG) Loop No. 4 - Typical) TRAIN B FAILURE MODES AND EFFECTS ANALYSIS Cooldown for Stage 1 of DBE Flood Main Feed Line Break with LOOP Loss of Normal Feedwater with LOOP Large Break LOCA with LOOP Main Steam Line Break with LOOP FAILURE POTENTIAL METHOD OF EFFECT EFFECT ITEM NO. COMPONENT FUNCTION MODE CAUSE DETECTION ON SYSTEM ON PLANT REMARKS pump is also available.
- 11. Check valve Prevents Stuck open. Mechanical None. Not a None. None*
reverse flow in failure. problem if 2-3-833. 4" AFW line to MDP 2B-B is SG 4. running, if not LCV 171 and - 171A will prevent reverse flow thru pump Stuck Mechanical Control Room discharge None. TDP 2A-S closed. failure. indication via piping. provides flow flow indicator to SG 4. FI-3-170A. Loss of AFW to SG 4.
- 12. MDP 2B-B Prevents Stuck Mechanical Pump/Motor MDP 2B-B to None. TDP 2A-S will min flow backflow from closed. failure. high temp as overheat and provide flow recirc line to CST to MDP indicated by become to SG's 3 &
CST check 1B-B discharge TI 3-146 inoperative 4. valve 3-815. piping. (local TI) or preventing EI-3-129A (hi AFW flow to amps). SG's 3 & 4
WBN TABLE 10.4-5 (Sheet 8 of 9) UNIT 2 FAILURE MODE & EFFECTS ANALYSIS MOTOR DRIVEN (MD) PUMP SUBSYSTEM (Steam Generator (SG) Loop No. 4 - Typical) TRAIN B FAILURE MODES AND EFFECTS ANALYSIS Cooldown for Stage 1 of DBE Flood Main Feed Line Break with LOOP Loss of Normal Feedwater with LOOP Large Break LOCA with LOOP Main Steam Line Break with LOOP FAILURE POTENTIAL METHOD OF EFFECT EFFECT ITEM NO. COMPONENT FUNCTION MODE CAUSE DETECTION ON SYSTEM ON PLANT REMARKS (only if flow Stuck open. Mechanical No method of demand is None. failure. detection. low). None No affect on system if MDP 2B-B is running. If MDP 2B-B is not running, system resistance would prevent backflow from occurring.
- 13. Check valve 2-3-644 (For details, see this heading in Table 10.4-4,
WBN TABLE 10.4-5 (Sheet 9 of 9) UNIT 2 FAILURE MODE & EFFECTS ANALYSIS MOTOR DRIVEN (MD) PUMP SUBSYSTEM (Steam Generator (SG) Loop No. 4 - Typical) TRAIN B FAILURE MODES AND EFFECTS ANALYSIS Cooldown for Stage 1 of DBE Flood Main Feed Line Break with LOOP Loss of Normal Feedwater with LOOP Large Break LOCA with LOOP Main Steam Line Break with LOOP FAILURE POTENTIAL METHOD OF EFFECT EFFECT ITEM NO. COMPONENT FUNCTION MODE CAUSE DETECTION ON SYSTEM ON PLANT REMARKS Sheet 5).
- 14. Check valve 2-3-645 (For details, see this heading in Table 10.4-4, Sheet 5).
- 15. AFW pump Prevents flow Stuck open. Mechanical Control Room Loss of Train None. TDP None.
2B-B recirc. being diverted failure indication via B. 2A-S will Flow control during an flow indicator provide flow valve FCV accident from FI-3-147B to SGs 3 & 4. 359 the SGs 3 & 4. and -170A and position indicating lights assoc. with HS 359.
- For the failure of these check valves in the open position, reverse flow from the steam generator to the individual pump casings is prevented by other redundant series check valves.
WBN-2 TABLE 10.4-6 (Sheet 1 of 2) AUXILIARY FEEDWATER FLOW TO STEAM GENERATORS FOLLOWING AN ACCIDENT/TRANSIENT - GPM MAX FLOW ALLOWED NO OF SG'S AFW MIN (MASS & SG'S ENERGY AVAILABLE ITEM PUMPS REQ'D RELEASES) REQ'D OR OR NO. ACCIDENT REQ'D FLOW NOTE 1 (FAULTED) REQUIRED 1 LONF ANY 2 820 NA ALL 4 SG'S ARE AVAIL PUMPS ANY 2 SG'S ARE REQ'D 2 LOOP ANY 1 410 ALL 4 SG'S ARE AVAIL PUMP ANY 2 SG'S ARE REQ'D 3 MS SUDDEN DEPRESSURIZATION 3.1 MS S DEPRESS NONE N/A 2840 ALL 4 SG's ARE AVAIL SHORT TERM ANY 2 SG's ARE REQ'D 3.2 MS S DEPRESS ANY 2 820 NA ALL 4 SG's ARE AVAIL LONG TERM ANY 2 SG's ARE REQ'D 4 MAIN STEAM LINE BREAK (MSLB) WITH CONCURRENT LOOP 4.1 MSLB-SHORT NONE NA 2840 (1 FAULTED) NOT APP TERM 4.2 MSLB-LONG ANY 1 410 NA ANY 2 SG's ARE REQ'D TERM ANY 3 SG's ARE AVAIL 5 MAIN FEED LINE BREAK (MFLB) WITH CONCURRENT LOOP 5.1 MFLB-SHORT NONE NA 2840 ALL FLOW TO FAULTED TERM SG 5.2 MFLB-LONG ANY 1 410 NA ANY 2 SG's ARE REQ'D TERM MDP ANY 3 SG's ARE AVAIL 5.3 MFLB-LONG TDP 720 NA TERM 6 LOCA 6.1 LARGE BREAK ANY 2 or Note 2 NA FAULTED SG HAS TUBE LOCA TD (UNIT 1) LEAKS 2MD or TD (UNIT 2) ALL 4 SG's ARE AVAIL 6.2 SMALL BREAK 1 MD + TD 1050 NA ANY 2 SG's ARE REQ'D LOCA NOTE 5 ALL 4 SG'S ARE AVAIL 6.3 MSLB MASS & ENERGY (M&E) RELEASE CASES FOR BREAK INSIDE CONTAINMENT SHORT TERM 6.4 MSLB M&E IN NONE NA 2250 ALL FLOW TO FAULTED CASE 1 SG 6.5 MSLB M&E NONE NA 1500 ALL FLOW TO FAULTED
WBN-2 TABLE 10.4-6 (Sheet 2 of 2) AUXILIARY FEEDWATER FLOW TO STEAM GENERATORS FOLLOWING AN ACCIDENT/TRANSIENT - GPM CASES 2-4 SG 6.6 MSLB M&E CASE NONE NA 2250 ALL FLOW TO FAULTED 5 SG 7 MSLB M&E NONE NA 1500 ALL FLOW TO FAULTED CASES 6-8 SG 8 MSLB M&E CASE NONE NA 2250 ALL FLOW TO FAULTED 9 SG 9 MSLB M&E NONE NA 2040 ALL FLOW TO FAULTED CASES 10-13 SG 10 MSLB OUTSIDE NONE NA SEE NOTE 3 ANY 2 SG'S ARE CONT REQUIRED 11 TOTAL LOSS OF TDP 410 NA ANY 2 SG'S ARE ALL AC POWER REQUIRED (ONLY TDP ALL SG'S ARE AVAIL AVAIL.) NOTES:
- 1. Maximum allowed flow limit values are dictated by containment pressure and temperature requirements except for Item 10 which is governed by SG pressures.
- 2. For LOCA (Large Breaks), the only AFW flow requirement is to keep the SG's filled above the lower narrow range tap to contain RCS leakage through any failed SG tubes.
- 3. Minimum auxiliary feedwater flowrates were conservatively assumed. The AFW flowrates are based upon the minimum delivered flow assuming a failure of the highest capacity auxiliary feedwater pump. Credit was taken for increases in AFW flow resulting from a decrease in the steam generator pressure both before and after steamline isolation. A 60-second delay from the time when the setpoint is reached to the time when flow is delivered was assumed. Minimizing AFW flow and delaying AFW flow initiation results in less inventory to the steam generator and, therefore, would serve to minimize steam generator water level and expedite reaching tube bundle uncovery conditions. The auxiliary feedwater flows assumed in the safety analysis supporting the steam generator replacement are documented in TVA Letter W-7460 (NAR), Watts Bar Nuclear Plant (WBN) - Auxiliary Feedwater Input Parameters for the Non-LOCA Analyses, July 9, 1996.
- 4. Cases are defined in Section 6.2.1.3.10 and the associated WAT-D-letters.
- 5. Flow from the TDAFW pump to the two respective steam generators during a SB LOCA will be greater than flow from the MDAFW pumps to the two respective steam generators (TDAFW has a greater capacity). This flow asymmetry has been evaluated in WAT-D-12067 and LTR-LIS-13-615, Rev. 1. It was concluded that a total minimum flow rate of 1050 gpm to the steam generators is sufficient to demonstrate compliance with the SB LOCA analysis of record.
Cl z ~ 3: <C 0 NOTES:
- 1. ALL VAL THE SAME SIZE AS THE PIPING 0 UNLESS NOTED.
- 2. ALL PRE VALVES ARE 1" GLOBE w HP STOP VAL VE UNLESS NOTED.
z ABOVE SEAT DRAIN 3. ALL VAL SHALL BE PREFIXED WITH ~ ~------------------------------------------------------~ THE UNIT NUMBER. <C 4. ALL PIPING TVA CLASS H, EXCEPT AS NOTED. t- 5.[)ETC., INDICATES LINE NUMBER CORRESPONDING z TO DESIGN PRESSURE AND TEMPERATURE CHART ON ~ THIS SHEET. <C 6. DESIGN CRITERIA/SYSTEM ON REFERENCE
- a DRAWINGS (USE THE LATE WORK UNLESS OTHERWISE ON ALL SEE THE LATEST REVISION OF THE 47B21 INGS "PIPING 0 SYSTEM CLASSIFICATION"
<C 1-MSR- 1-MSR- 1-MSR-001-Al 001-81 001-Cl N3-47-4002 --- TURBOGENERATOR CONTROL AND u PROTECTION SYSTEM ( PART 1 ) AND TURBOGENERATOR SYSTEM (PART 2)
- 7. SOM ON N CHANGED AND IFFE ON OTHER DOC FOR THE ID XIMO AS TO CIDS OR A tttt 8. STRAI FOR STN-+7-0705 It. STN-47-07 OPERATION. STRAINER EL OPTIONAL MAY BE
_ _ _-_*_*_ VALVE STEM LEAK-OFF'\, RE E STRAINER ELEMENTS MUST INSTALLED FOLL ANY MODIFICATION TO THE STEAM SUPP ING SYSTEM, AND LEFT IN UNTIL THE CONVENIENT WINDOW AFTER T GH l SYSTEM CLEAN UP HAS BEEN ACHIEVED. {1-2 MONTHS OF FULL FLOW OPERATION).
- 9. ABANDONED PIPE WHERE NOTED DOES NOT REQUIRE TO 3 6' ID CROSS CONN BE BLANKED OFF PER SPP 9.3, SECTION 3.1.1.h.
DEAD ENDED PIPE IS SELF DRAINING AND MAINTAINS PRESSURE BOUNDARY ONLY. NOTES CONTINUED AT COOR H7; 1-TURB-001-LPC 1-47W849-1, COORD L A T E R > - - - - ~ 36" ID CROSS AROUND PIPING LP STOP VALVE ABOVE SEAT DRAIN FL EL 755.0 DWG 4661066 CONT ON WESTINGHOUSE DWG 4661D66 HP STOP VAL VE ABOVE SEAT DRAIN HP STEM LEAKOFF RUPTURE DISC RELIEVE o 5 PSIG
.Jl2' CONDENSER BAFFLE CONDENSER ZONE B PLATE ZONE C HOTWELL CONT ON T WESTINGHOUSE DWG 4601D01 F SEE DRAWING 1-47'#816-1 FOR OIL DISTRIBUTION.
I TO NO. 3 HTR 47-404A 09A DR TANK CONT ROOF EL 755.0 ON 1-47W805-5 COOR E-5 1:. 4" 1 :,.I LP STEAM SEAL SUPPLY 4" LS H/. FILL CAP WITH MFPT GLAND LEAK-OFF 6"- 8"- 47-293 UFSAR AMENDMENT 3 1/8"0 HOLE 3/4" DRAIN
~ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - ' - - ' / _ 2 _ *_ _1_s_v-.... 47*--0 0 5_*_~
0010 0037 ~j
~ T O WASTE DESIGN PRESSURE It. TEMPERATURE DATA g~~g~o:.:2c..--J:Ja--'.=a' CONT ON WESTINGHOUSE DWG 4601001 WATTS BAR FINAL SAFETY ANALYSIS REPORT LINE DESIGN PRESSURE DESIGN TEMPERATURE SEE DRAWING 1-47W816-1 FOR OIL DISTRIBUTION. REFERENCE DRAWINGS: NO. (PSIG) ("F) 47W800-1 1 10 130 1 /4"0 HOLE 478601-7 SERIES 47W611-7-1 FLOW DIAGRAM GENERAL PLANT SYSTEM INSTRUMENT TABULATION LOGIC DIAGRAM TURBINE DRAINS 2
3 50 50 287 20D TO WASTE POWERHOUSE 47W611-47-1 47W430 SERIES 1-47W610-7-1 LOGIC DIAGRAM TURB(X;ENERATOR CONTROL SYSTEM TURBO GENERATOR MISC DRS &. VENTS PIPING CONTROL DIAGRAM TURBINE DRAINS 4 5 90 265 350 55D DRY-002-0209C TV-002-0209 UN IT 1 1-47W610-47-1 CONTROL DIAGRAM TURBOGEN CONTROL SYSTEM 6 7 500 250 470 4D6 2" TEST CONN FLOW DIAGRAM 8 1185 600 8" VENT LINE FROM ATMOSPHERIC TURBINE DRAINS AND CONDENSATE DRAIN TANK CONT ON 1-47W805-2, COORD G-9 MISCELLANEOUS PIPING TVA DWG NO. 1-47W807-1 R43 COMPANION DRAWINGS: 47W800 SERIES FIGURE 10.4-1
NOTES:
- 1. ALL VALVES ARE THE SAME SIZE AS THE PIPING UNLESS OTHERWISE NOTEO.
- 2. DELETEO HP STOP VAL VE ABOVE SEAT DRAIN
- 4. ALL PIPING TVA CLASS H, EXCEPT AS NOTED
- MAIN STEAM BY-PASS TO .5. ~~i~* Q,/;~}~A1~~E\~NE NLM3ER CORRESPONDING TO DESIGN PRESSURE AND TEWPERATURE COND CONT ON 2-47W801 -1
- 6. SCJ,jECID'SONTHISDRAWINGHAVEBEENCHANGEDANDMAYDIFFER FRDWTHECID'S SHOWN ON OTHER DOCUMENTS FOR THE SAME COMPONENT. THE AL TERNA TE ID CAN BE ACCESSED IN WAXIt.<<l AS NECESSARY TO DETERMINE IF PREVIOUS CIDS EXISTED FOR A SPECIFIC COMPONENT.
- 7. DESIGN CRITERIA/SYSTEM OESCRIPTION REFERENCE DRAWINGS (USE THE LATEST REVISION tttt ON ALL WORK UNLESS OTHERWISE SPECIFIED. SEE THE LATEST REVISION OF THE 47821 SERIES DRAWINGS "PIPING SYSTEM CLASSIFICATION".):
N3-47-40D2 ----TURBOGENERATOR SYSTEM{PART 1) CONT ON 2-47W801-1 AND TURBOGENERATOR CONTROL AND PROTECTION SYSTEM (PART 2)
- 8. STRAINERS STN-47-7D5 & STN-47-706 ARE OPTIONAL FOR SYSTEW OPERATION. STRAINER ELEMENTS MAY BE REMOVED. THE STRAINER ELEMENTS 141ST BE REINSTALLED FOLLOWING ANY MODIFICATION TD THE GLAND STEAM SUPPLY PIPING SYSTEM, AND LEFT IN PLACE UNTIL THE FIRST CONVENIENT WINDOW AFTER THOROUGH SYSTEM CLEAN UP HAS BEEN ACHIEVED.
(1-2 t.CINTHS OF FULL FLOW OPERATION). 2" VALVE STEM LEAK-OFF 9 . r~~:~E S~~~L A::Ng~:J~E~Et~~a:~~NKg~AgF~Ng:D ~r~: ::p:~~DD~rn1i'~~ 3/4~go..Ji'NTAINS PRESSURE BOUNDARY ONLY. 36" ID CROSS CONN CONT ON 2-47W::I MAIN STEAM 2-TURB-1-LPC 36" ID CROSS AROUND PIPING 2-47W849-1 FL EL 755.0 LP STOP VAL VE ABOVE SEAT DRAIN CONT ON WESTINGHOUSE OWG 4661D66 111 CONT ON WESTINGHOUSE EXTR. f ABANDON f STEAM DWG 4661066 IN PLACE 11 HP STOP VAL VE ABOVE SEAT DRAIN CONDENSER CONDENSER ZONE B ZONE C HOTWELL REFERENCE DRAWING/DESIGN CRITERIA: LP STOP VALVE 47W800-1 BELOW SEAT DRAIN FLOW DIAGRAM GENERAL PLANT SYSTEM 47B21-1 PIPING SYSTEMS CLASSIFICATION 47W430 SERIES TURBO GENERATOR MISC DRS &. VENTS PIPING 2-47W610-7-1 CONTROL DIAGRAM TURBINE DRAINS CONT ON WESTINGHOUSE 2-47W610-47 SERIES CONTROL DIAGRAM TURBOGEN CONTROL SYSTEM DWG 4661D66 WB-DC-40-36 CLASSIFICATION OF PIPING, PUMPS, VALVES&. THV-47-518B VESSELS FILL CAP WITH 1/8"121 HOLE lJ'1-ro WASTE 4" MFPT GLAND LEAK-OFF 5*_ 4' LP STEAM SEAL SUPPLY
,. I DRV-2-209B 3/4' DRAIN UFSAR AMENDMENT WATTS BAR FINAL SAFETY ANALYSIS REPORT 3
DESIGN PRESSURE &. TEMPERATURE 2-ISV-47-87A CONT ON WESTINGHOUSE DWG 46D1D01 POWERHOUSE DATA UN IT 2 LINE NO. 1 DESIGN PRESSURE (PSIG) 10 DESIGN TEMPERATURE ("F) 1JO 1/4"0 HOLE lTO WASTE FLOW DIAGRAM 2 50 50 287 200 2-DRV-2-209C TURBINE DRAINS AND 4 5 90 265 350 550 2-TV-2-209 MISCELLANEOUS PIPING 6 7 500 250 470 406 L 8" VENT LINE FRCN ATMOSPHERIC COMPANION DRAWINGS: TVA owe NO. 2-47W807-1 R33 8 1185 600 CONDENSATE DRAIN TANK CONT ON 2-47W805-2, COOR G-9 47W800-SERIES FIGURE 10.4-1 (U2)
NOTES: 18. FOR ENVIRONMENTAL LIMITATIONS FOR THE HEAT REJECTION SYSTEM 20. SEASONAL ADJUSTMENT OF SCCW VALVES AND UNIT 2 SLOWDOWN
- 1. FOR DETAILED OPERATING INSTRUCTIONS, SEE MANUFACTURER'S INSTRUCTION MANUAL. SEE WB-OC-40-37, SECTION 3. 3. 1 . 2, ANO FOR CONDENSER GATE 2-GATE-027-0624 ARE MADE PER THE GUIDELINES OF
- 2. ALL VALVES ARE SAME SIZE AS PIPE UNLESS OTHERWISE NOTED. TUBE CLEANLINESS MAINTENANCE SEE SECTION 3.10.2. THE ENVIRONMENTAL ASSESSMENT REPORT ANO N3-77C-4001.
- 3. MAIN PROCESS SYSTEM VALVES ARE SHOWN IN THEIR NORMAL OPERATING POSITION. 19. PI PE IS HYO ROST ATI CALLY TESTED AT MANUFACTURING PLANT PER 21 . THE DIFFERENTIAL HEAD LOSS RACK UNIT 2
- 4. ALL VALVES HAVE UNIT NUMBER AND SYSTEM NUMBER IN ADDITION TO VALVE AWWA REQUIREMENTS. MECHANICAL JOINTS TO BE INSPECTED TO COOL! NG TOWER NUMBER SHOWN. EXAMPLE; 1-27-515 DESIGNATES VALVE NO. 515 IN UNIT 1 INSURE PROPER GASKET SEATING. VISUALLY INSPECT FOR LEAKAGE ~~~L~ 1~8~~0 (~~Sb~~*~ N¥E~~~e~)
CONDENSER CIRCULATING WATER SYSTEM. THE PREFIX 0- IS ON VALVES COMMON AFTER PIPELINE IS FILLED ANO VENTED. LEAKAGE PER NOTE 14 TO DE WHEN CLEAN THE TO BOTH UN ITS. IS ACCEPTABLE DIFF HEAD LOSS "
- 5. INSTRUMENTS AND VALVES (HAVING FUNCTION DESIGNATION AS FLOW CONTROL SYSTEM PRESSURE It. TEMPERATURE DATA CAL WCG-1-1994.
VALVES) SHALL BE DESIGNATED AS FOLLOWS: UN1T NO.-FUNCTION-SYSTEM-VALVE ON ACROSS THE T NUMBER, I.E., 1-FCV-27-12. LINE MAXIMUM DESIGN DESIGN HYDROSTATIC TEST RAT ABLE 1 (SCCW MK NO. WP (PSIG) PRESSURE (PSIG) TEMP ( "F) PRESSURE (PSIG) 2 ( RV ICE) IN CALCULAT I 6. 7. ALL VALVES WILL HAVE MARKER TAGS. THE RCW BYPASS LINE FCV, COOLING TOWER SLOWDOWN LINE FCV AND HOLDING PONO FCV ARE INTERLOCKED WITH RELEASE OF WATER THROUGH WATTS BAR HYDRO. 1 2 25 25 135° 37.5
- 22. NOT USED.
8. 9. THE SYSTEMS ON THIS DRAWING ARE NON-SEISMIC TVA CLASS H. MAXIMUM WORKING PRESSURES OF HORIZONTAL COMPONENTS ANO PIPING ARE BASE 3 7 10 95' 12
- 23. PORTIONS OF THE CCW AND CONDENSATE SYSTEM HAVE BEEN DETERMINED TO POSSESS AN ADDED LEVEL OF SEISMIC RUGGEDNESS.
C 1 D. SYMBOL
- ON THE CENTERLINE ELEVATION.
SIGN IF I ES HYO ROST AT IC TEST BY MANUFACTURE. SYMBOL t SIGNIFIES NO HYDROSTATIC TEST DONE, ONLY A NO LEAK TEST REQUIRED 4 5 63 65 65 63 95' 95' 94 65 ** THE MAIN CONDENSER AND ASSOCIATED WATERBOXES, THE CC'II PUMP DISCHARGE VALVES, AND THE TURBINE BUILDING PORTION OF THE 11.
- 12. ALL PIPING ON THIS DRAWING IS TVA CLASS L UNLESS OTHERWISE NOTED ON THE DRAWING OR AS INDICATED IN NOTES 13 AND 23.
6 7 72 46 72 40 135° 135° 77 (UNIT 1)/SEE MHE 25 (UNIT 2) 50 CONDENSER SUPPLY AND DISCHARGE PIPING (WITH THE EXCEPTION OF ALL CONNECTED PIPING/TUBING/TAKEOFFS) HAVE BEEN EVALUATED IN CALCULATION CDQ001 0272013000268
;;,~, , . "'"~<< ~:~A~~Z~fkD
- 13. ALL PIPING CONNECTED TO THE CONDENSER. EXCEPT FOR THE 102" ID PIPES 8 17.5 10 95' + AND DETERMINED TO BE CAPABLE OF CONNECTED TO THE WATER BOXES, IS TVA CLASS H. MAINTAINING STRUCTURAL AND PRESSURE
~4 2-FCV
- 14. HYOROSTATICALLY TEST THIS PIPING IN ACCORDANCE WITH AWWA, MANUAL M9, 9 8 10 95' SEE NOTE 14 BOUNDARY INTEGRITY DURING A SAFE 27-14°2 D CHAPTER 10. THE ACCEPTABLE LEAKAGE RATE SHALL NOT EXCEED 50 GALLONS PER 10 0 0 95' + SHUTDOWN EARTHQUAKE (SSE) 2-FC
<( INCH OF DIAMETER PER MILE OF PIPE PER 24 HOURS. A PRE-SOAK PERIOD IS 80 80 120(UNIT1)/SEEM>TE25(UNIT2) u RECOMMENDED FOR AT LEAST 24 HOURS. THE TEST PRESSURE WILL BE 1201 11 12 85 80 135° 95' 100
,-' 27-1 OF THE MAXIMUM WORKING PRESSURE. TESTS SHOULD INCLUDE ANY PERMANENT 15.
ATTACHMENTS SUCH AS MANHOLES TO PIPE. SEE THE LATEST REVISION OF THE 47B21 SERIES DRAWINGS "PIPING SYSTEM 13 14 63 79 63 80 95' 95' 105 120 ** >~",A,., CLASSIFICATION." 1 6. HYDRO STATIC TEST PRESSURE FOR THE COOL I NG TOWER SLOWDOWN IS TO BE 15 54.5 53.5 135° 55 60. MEASURED FROM THE PIPE INVERT ELEVATION AT THE LOWEST ELEVATION OF 16 12 - - SEE NOTE 14
- 17. i~fs PlfifGu:NN1G J~rJEr INTERFACE POINT. SAFETY RELATED, <In) 17 - 150 250 225
}~f~~~~~~ ~g}~fr ~~~f ~~ ~pg~~g ~~~~E~AN~o:H~~[~TiE~6~~6~ 0
- CTZfl. 18 19 25 5
30 20 95° 95° SEE NOTE 19 SEE NOTE 19 12'-0" ID CONDUIT HYDROSTATIC TEST PRESSURE (t_ 4° 46'-20" DATA IS HISTORICAL INFORMATION BEND AND NO LONGER MAINTAINED AS DESIGN OUTPUT. 4" EFF FROM SEWAGE CONT TK 30" RC'II DISCH a: RC'II BYPASS CONT ON 'r---+---, 2" DRAINS TO
~3!~4~~~~4~isg~o~~N~9
~ON 1--1-7\11845-4 COOR F 1 FOUNDATION TRENCH
~ FUTURE ACID FEED 7 1" 12 10 1-27-512 6" AIR RELEASE VALVE FROM MAKEUP DEMINERALIZER NEUTRALIZER TANK CONT ON 1-47W834-2 COOR F 1 0 - - - - ~
1 O" TEST LOOP It. RELIEF VALVE CONT ON 0-47W832-3 6" VENT COOR B 7 - - - - - CONT ON to6i~ 853 , , . ,__. . .t-, TURBINE LATER BUILDING UNIT 1 CONDENSER TOWER 48" SLOWDOWN FROM
-COOLING TOWERS WASHDOWN FROM COOLING TOWERS REFERENCE DRAWINGS:
CCW PUMPING 47WB00-1 --------------- 47B601-27 -------------- FLOW DIAGRAM-GENERAL PLANT SYSTEMS TABULATION OF INSTRUMENTS STATION 47W610-27-SERIES ------- CONTROL DIAGRAM 47W844-SERIES ---------- RCW FLOW DIAGRAM INSPECTION ACCESS FOR VALVE 18" C.S. 150# WN It. BLI NO R. F. FLANGES ( TYP, 8 PLACES) CONDENSER CIRCULATING WATER PUMPS 102,500 GPM UFSAR AMENDMENT 3 2' TELL-TALE @98' HEAD 1-TTV-027-617
~~ 12'-0" ID WARM WATER CONDUIT
- 2 4 " SUPERNATANT WATTS BAR FINAL SAFETY
+
N ANALYSIS REPORT 8" UNWATERING _ _ _ _ _ _ _ _~ DRAINS---=..:.:._:::_ FROM SUMP PUMP CONT 0 GENERAL 7 to61i~ 5 i71 0 ,-1>~=,;,-----:;=cc--7 UNITS 1 & 2 NOTES CONTINUED,
~
~~
~~
27-
~.. ~, FLOW DIAGRAM
- 24. SLOWDOWN GATE (0-GATE-27-624) ANO TRASHRACK (0-RACK-27-4) MAY BE MOVED TO EITHER UNIT TO SUPPORT RFO'S OR OTHER SITUATIONS AS NECESSARY.
- 25. FOR REASONS OF PRACTICALITY, AN IN-SERVICE LEAK TEST MAY BE DONE IN LIEU MIN W.S. EL 698.0
-------~
7 - 6~ 14g-27-611 16 DIFFUSERS COMPANION DRAWINGS: 1,2-47W831-2 CONDENSER CIRCULATING WATER TVA DWG NO. 0-47W831-1 R4 OF HYDROSTATIC TEST FOR ALL EXPOSED PIPING, INCLUDING CONDENSER. WATER BOXES ETC AS DENOTED IN THE SYSTEM PRESSURE AND TEMPERATURE DATA BLOCK.
-RIVER FLOW FIGURE 10.4-2
t!) SHUTOFF HEAD z 3' a:: EL 850.0 EL 85D.O Cl 840.0 840.0 Cl w z < 830.0 HYDRAULIC GRADIENT-4 PUMPS OPERATING 0102,500 GPM EA 830.0
~
I- CONDENSER AND PIMPS z : 251-----+---+-----+-----,4-+---,L------, DESIGN POINT WITH 4 PUMPS IN OPERATION < 820.0 ~ 820.0
- E w
Cl < ~ 20 I - - - - - + - - - + - - - - + - - + - + - + - - - - , u 810.0 ;"; 810.0 w
~
w 800.0 ~ 151-----+---+-----+-+---+-------, 800.0 8 0 790.0 < 790.0
~ 101----+---+-_,_+--+---+-------,
COOLING TOWER ~
~
780.0 780.0 770.0 770.0 TOWER DISTRIBUTION SYSTEM El 779.0 I I COOLING TOWER 760.0 100 zoo 300 ,t.QO 500 760.0 I I FLOW THROUGH CONDENSER IN THOUSANDS GPM CHARACTERISTIC FLOW CURVE FOR CONDENSER 750.0 CHLORINATION BLDG 750.0 HYDRAULIC GRADIENT-2 PUt.l'S MAXIMUM HIGH WATER i I OPERATING* 125,000 GPM EA EL 730.3 NORMAL WATER 740.0 EL 7JO.O 740.0 I TURBINE BUILDING HYDRAULIC GRAOIENT-3 PUMPS OPERATING* 115,000 GPM EA EL 731.0 FIN GRADE El 727 .o'.!: 730.0 OP TUBE 730.0 716'-11-1/B* I HYDRAULIC GRA0IENT-4 PUMPS OPERATING* 102,500 GPM EA I 720.0 720.0 EL 709.0 710.0 710.0 I 700.0 700.0 690.0 690.0
/EL 691.0 680.0 680.0 670.0 670.0 680.0 660.0 CCXJLING TOWER BASIN El 650.0 El 650.0 COOLING TOWER BASIN 12'-0' 12'-0"¢ OPEN CHANNEL FLUME 12' -0"X9 '-o* WYE REDUCER 9'-0"¢ 9' -o-x6' -0" IYE REDUCER 5*-o*x9 *-
WYE INCRE
-4'-6"X6'-0" REDUCER 4'-6"91 4 5-4" BUTTERFLY VALVE WATTS BAR FINAL SAFETY ANALYSIS REPORT GENERAL UNIT 1 PROFILE COMPANION DRAWING:
1-471831-1 FLOW DIAGRAM UNIT 1 VERT 1 "*10' CONDENSER CIRCULATING WATER SCALE { HORIZ 1 '-SO' TVA DWG NO. 1-47W831-2 R4 FIGURE 10.4-3
t!) z SHUTOFF HEAD 3' El 850.0 El 850.0 a:: Cl Cl 840.0 840.0 w z ,_, HYDRAULIC GRADIENT-4 PUMPS I-830.0 OPERATING @102,500 GPM EA 830.0 z ,_, w
~ 251-----+---+-----+------J't-+-r------,
CONDENSER AND Pl.MPS DESIGN POI NT WITH 4 PUMPS IN OPERATION
- E 820.0 820.0 Cl u ~ 20 r - - - - + - - - + - - - - + - - + - + - + - - - - - - ,
810.0 HYDRAULIC GRADIENT-3 Pl.MPS
- ': 810.0 OPERATING @115,000 GPM EA
"'z 800.0 ~ 15r----+---+----#-__,__--+------a 800.0 8
COOLING TOWER 790.0 !al 790.0
~ 10r----+---+-_,_+--+---+------,
7&0.0 I 780.0 TOWER DISTRIBUTION SYSTEM El 779. 0 770.0 770.0 I I COOLING TOWER 760.0 I I 100 200 300 4,00 500 760.0 FLOW THROUGH CONDENSER IN THOUSANDS GPM I I CHARACTERISTIC FLOW CURVE FOR CONDENSER 750.0 CHLORINATION BLDG 750.0 I TURBINE BUILDING HYDRAULIC GRADIENT-2 PUt.l'S MAXU,IJM HIGH WATER FIN GRADE El 727 .0 +/-I OPERATING* 125,000 GPM EA EL 730.3 740.0 I NORMAL WATER 740.0 CCW PUt.l'ING I EL 730.0 I STATION HYDRAULIC GRADIENT-3 PUMPS OPERATING* 115,000 GPM EA EL 731.0 FIN GRADE El 727 .0 +/- OP TUBE 730.0 116°-11-1;1r 730.0 I HYDRAULIC GRADIENT-4 PUMPS OPERATING e 102,500 GPM EA I 720.0 720.0 El 709.0 710.0 710.0 I 700.0 700.0 rEL 691.0 690.0 690.0 680.0 680.0 670.0
!il Iii ~I 670.0 N
N I 660.0 660.0 COOLING TOWER BASIN El 650.0 EL 650.0 COOLING TOWER BASIN 12'-0'"' 12*-o* 12'-0"1> OPEN CHANNEL FLUME 12 '-o*x9 '-o* IYE REDUCER 9*-0*¢ 9*-o*xs*-0" IYE REDUCER 6' -O"X9 '-0" WYE INCREASER INCREAS
+8' WATTS BAR FINAL SAFETY ANALYSIS REPORT GENERAL UNIT 2 PROFILE FLOW DIAGRAM UNIT2 CONDENSER CIRCULATING WATER VERT 1 '-10' SCALE { HORIZ 1 *-so*
COMPANION DRAWING: 2-47W831-1 TVA DWG NO. 2-47W831-2 R3 FIGURE 10.4-3(U2)
(.!) ABANDONED IN PLACE z
- s, a
- ::
C, C, RIVER w z 1-z
- I:
C, u rSI~~AR I
--- I
--F- , M
~
L~...:~:!~J 21-11, ~ DISCHARGE WEIR UNIT 1 COOLING TOWER ffi---r-- 1 I I TABLE A1 I DIGITAL COMPUTER POINTS ABANDONED I IN PLACE I POINT ID DESCRIPTION I Y24300 CCW Pt.I' A BKR I Y24l1D CCW PIM' B BKR I I Y24l2D CCW PIM' C BKR I Y2425D CCW PW D BKR I I I I ____[gi[]
~~I j ---i:rililll NOTES:
- 1. SYSTEM SHOWN FOR UNIT 1 ANO Cot.tAON.
1-TE LOG
@ a- ...! -
I -FC 2:-31 T241 A ____[gi[]
- 2. ~~M~~~- A~~.~~~:xTHiR~i~~~~1 ~E~.~*~m~~~,n~~UCTS COMPANY DRAWING D-09151 ON CONTRACT 74Cl1-8JOH(NJM-Hl.
-7lliilll 3. TORQUE AND POWER ON LIGHTS VISIBLE OHL Y WHEN VAL VE COVER IS OPEN.
- 4. HANDSWITCH IS MADE FRO-t A SELECTOR AND PUSH-BUTTONS.
- 5. REFER TO TABLE A1 FOR DIGITAL COMPUTER POINTS (BREAKER POSITION).
REFERENCE DRAWINGS: 1-471831-1 i. 2 -------- COND CIRCULATING ITR FLOW DIAGRAM
~ +7W832-1 -------------- ~t~wsini21uwTR I: FIRE PROT SYS
=rI ---r---- -
1-471837 - - - CCW GLAND SEAL FLOW DIAGRAM 1-471611-27-1 --------- CCW LOGIC DIAGRAM 1-451760-27 SERIES ---- CCW ELECTRICAL SCHEMATIC I I SYMBOLS I fl. DEVICE LOCATED LOCALLY AT ECIUIPMENT I ... LOCAL TEST SWITCH I VALVE REMAINS AS IS AT TIME FAILURE I lSl CENTRAL CONTROL PANEL AT PlliAPING STATION I I I I I I I I I I WATTS BAR FINAL SAFETY ANALYSIS REPORT
$ I POWERHOUSE
~~I~~ ,,,b-, UNIT 1
,,,b-,
(:}- ~\SlL~a ~ ELECTRICAL Imm! -1J+---~-- ~i, CONTROL DIAGRAM CONDENSER CIRCULATING WATER SYS CIM'ANIONDRAWING,O-47161O-27-2 TVA DWG NO. 1-47W610-27-1 R13 FIGURE 10.4-4
t!) z 3' a:: Cl Cl w z 1-z
- E Cl u
( TYP 4 PLACES) lr::::~;::11J::c~°
.' LOGIC REF FS ~OG ~OG T2416A T2417A
~OG 02822A m
@-~------ 08F802403-F0-2898 ABANDONED IN PLACE ABANDONED IN PLACE NOTES:
- 2. FOR PU~P AND MOTOR THERMJCOUPLES SEE INGERSOLL - RAND DRAWINGS: B-650B98X1 a. C-750898X1, ANO ELECTRIC PRODUCTS COl.f'ANY DRAWING D-09151 ON CONTRACT 74C31-830H (NJM-H).
REFERENCE DRAWINGS: 2-47W831-1 Ir. 2-------------COND CIRC WTR FLOW DIAGRAM 2-47W8J2-1 AW SERVICE WTR ii:. FIRE PROT SYS
$ FLOW DIAGRAM 2-47W837-1-~=========~W GLAND SEAL FLOW DIAGRAM 2-47W611-27-1 W LOGIC DIAGRAM
-l------------ 2-45W760-27 SERIES---------ccw ELECTRICAL SCHEMATIC I TYP 4 PLACES I SYMBOLS:
FOXBORO OCS I,,. DEVICE LOCATED LOCALLY AT EQUIPMENT
~~
2-471610-98-llA, COORD F5 r (FBN-98-Rl 21A04,CH5) 2-471610-98-1 IA, COORD F5 ~OG .& LOCAL TEST SWITCH I LOGIC REF (FBM-98-R121A04,CH71 ~
' 08F802403-F0-2896 LOGIC REF 02821 A VALVE REW.INS AS IS AT TIME OF FAILURE I
L-504 rj @-~------ 08F802403-fD-2896 T: 0-,o,; 7 'Q CENTRAL CONTROL PANEL AT PUt.4PING STATION PI 27-408 PT 27-40 __ j_ lp;.°; ,I IT;.7.A1 1
- J 27-18D ~<~* I ~~
---l--
I I w~ 2~~198
~~~
5 M-1s 27-19A~7r,;<
~
TE 27-ISH ~wl
~IA R
~ HS 27-19D
'S.
4. b~ UFSAR AMENDMENT WATTS BAR
~~ ~~
( TYP 4 PLACES) FINAL SAFETY 2:~22H i\ ~~~ ~ ~ ill ANALYSIS REPORT L-~---1---@s*~s*-~-@s ~~ 0 ~~ ri:.lc-, UNIT 2
@ EI M-15 27-98 27-9A 27-9D
'S. LOCIC REF 08F8D24D3-FD-2896 G R I G R
~
POWERHOUSE 1 ELECTRICAL
@_-_@_,~_~_5_*"&___~__-__,"_1~_._*_t,,.______A ____________________________________.. CONTROL DIAGRAM L
(TYP 4 PLACES) -1l1-CONDENSER CIRCULATING WATER SYS TVA DWG NO. 2-47W610-27-1 R14 COl.f'ANION DRAWING, 0-*HW610-27-2 FIGURE 10.4-4(U2)
t!) z 3' a::: i::::, i::::, TUHJNE Bl.DC l-71110-27-1, E-:S w z 1-t.71110-27-1. D-3 1-z ~ i::::, tJ i 1--~ 08
,;;:r:J
~iH~
~2-M-15
- V"'
UNIT 1 CONDEN&H UNIT 2 CONDE:NSElt I L ~ l.!Hst
~...,,
I - ~*1 - ~ , , . 1-11-15
-r.h ~
1-L-130
~ .... 1-M-15 uJ "t3***
B- ~ UNIT 2 COOLIN!. TOIElt y T ~r f:~)'-L-UO
~
y* l- 21-,:s I I I I _ JLOC ~ ~ LDC L T1441A n++cM.
--HS ffi--- I (SEE NOTE 2)
~ ..-*
TUHJNE Bl.DC
. '() ~ _.., ~ NOTES:
- 1. THE t.CITOR OPERATORS FOR VALVES 2-FCV-27-142, 14.3 1-f ANO 144 HAVE BEEN ABANDONED IN PLACE AND ALL ELECTRICAL POWER/CONTROL REMOVED.
1-M-15 I 2. THE KITOR OPERATORS FOR VALVES 1-FCV-27-142 ANO 4
- ATER I HAVE BEEN ABANDONED IN PLACE. THE KITOR OPERATOR FDR I 1-FCV-27-143 HAS BEEN REMOVED. ALL ELECTRICAL POWER/CONTROL I HAS BEEN RE..<<JVEO FOR THESE VALVES. (UNIT 1 ONLY)
IIiT
~t D+-----'"
nut~1.rRGY ,------+ I l"AftK IS£[ NOTE 11 !SEE NOTE 1) I I HOT WATER lf£~1C ,------+ x umb (SEE NOTE 21
!' -GR©!,
!SEE PIJTE l'o\lM IATER nllt~~, ,------+
f _ _ _ _,. .jt: c;} 0-ffS 1~!!!- 27-m 0-HS 27-17B fl.
~-, r-~'f!j' @r-<-m PARIC !SEE NOTE 21 II[)
"-------------------- ~ 1,.:::,,1
~---*1 ,_., "r---:l-- ;:.,
!SEE NOTE 2)
I
~ ~~
'9'-
I j
-@-r--*, @ f"ti1 e !
5-13 99 1-4-15 0-L-157 O-R-144
~
Fl ,.
~---161
,+.._/:, &---
~ r OOA- ~100 T
G;~ i @f" + ~-..L
'GJ -1?1-,
r--
~~:.~~~~'~
UFSAR AMENDMENT WATTS BAR 1-1-R-m G;l LOO DIFFUSER FINAL SAFETY DIFFUSER YIIXJU
--------RESERWIR----------
YIOOIM ANALYSIS REPORT POWERHOUSE UNITS 1 &. 2 ELECTRICAL CONTROL DIAGRAM CONDENSER CIRCULATING WTR SYS TVA DWG NO. 0-47W610-27-2 R1 FIGURE 10.4-5
-~
00 7~
~-,~- t::i~-,~- ~--
~
(.!) [oz LOW FLOW THROUGH ~z z WATTS BAR HYDRO (SEE NOTE 5) ~~ I NO NO NO NOTES,
- s, n..O
- :i ~ ~
< ~~ u~ u~ 1. NOT USED a::: """~ 8M~0~ 8S
~~
.!.~
~~
.!.~
~~
.!.~
- 2. THE NORMAL PROCEDURE FOR STOPPING THE CCW PUMP IS TO CLOSE THE DISCHARGE VALVE AND LET THE PUMP BE TURNED OFF BY THE VALVE C,
SOS CLOSED LIMIT SWITCH. THIS IS ACCOMPLISHED BY THE CLOSE POSITION OF THE CONTROL SWITCH. C, w J. IC SYMBOLS ARE USED ON LOGIC DIAGRAMS TO z THE PROCESS CONTROL.REFER TO THE ASSOCIATED HE ELECTRICAL COMPONENTS USED TD IMPLEMENT
- 4. O-HS-27-97A PROVIDES THROTTLING CONTROL IN THE *our* POSITION AND 1- FULL CLOSE OR FULL OPEN CONTROL IN THE *1N* POSITION.
z 5. FOR LOW FLOW RECUIREKNTS, SEE WB-OC-4-0-37.
- 6. THE l<<}TQR OPERATORS FOR VALVES 1-FCV-142 a:. -144 HAVE BEEN
< ABANDONED IN PLACE. THE MOTOR OPERATOR FOR 1-FCV-27-143 HAS BEEN
- I: REMOVED. ALL ELECTRICAL POWER/CONTROL HAS BEEN REK>VED FOR THESE C,
- 7. ~t~~i1t~~ 1 1 rs M~~~ VROM A SELECTOR AND PUSHBUTTONS.
*DERIVED FROM UNIQUE LIMIT AND TORQUE SIi REQ OF VALVE u
TYPICAL MOV CONTROL STOP TYPICAL MOY CONTROL
~Ut~t~~E:5 1--------i 1-FCV-27-87 FULLY OPEN
~Ut~~-iiE~5 1--------r--
1-Fcv-21-11 FULLY OPEN 1-FCV-27-5 FULLY OPEN CCW PUMP 1A ON OPEN //;_H~ CLOSE CLOSE 27-SA_,_==--, KEY PLAN A CLOSE TYPICAL lillV CONTROL 1-FCV-27-11
> 501 CLOSED C>'EN STOP CLOSE OPEN OPEN TYPICAL MOV CONTROL TYPICAL KN CONTROL TYPICAL MOV CONTRQ.
OPEN OPEN UNIT 1 CONOENSER
~r;:tJ 2-47W611-27-1 COORD F-4
~
REFERENCE DRAWINGS: WARM WATER CONDUIT 1-45W760-27-SERIE:>-----SCHEMATIC DIAGRAMS 1-471831-1---------------------FLOW DIAGRAM 1-47W610-27-1-------COINTROL DIAGRAM 0-47W61 0-27-2--- ------------- --CONTROL DIAGRAM OPEN SYMBOLS: WATTS BAR I::!,,. DEVICE LOCATED LOCALLY AT EQUIPMENT LOCAL TEST SWITCH FINAL SAFETY
~
CENTRAL CONTROL PANEL AT PUMPING STATION VALVE REMAINS AS IS AT TIME OF FAILURE ANALYSIS REPORT
~~~¥ ~~~~l~x.~*srcJ
,....____~2
~-rev 0 do I I I ~ STCP..---~
I POWERHOUSE UNIT 1 I ~,.i1r+(SEE 27 - 1~ 4 ELECTRICAL
~ E E NOTE 6)
(SEE LOW FLOW LOGIC DIAGRAM TO HOT WATER PUMP S T A T I O N r - z WASTE HEAT ENERCY PARK 1111,1,1;,.11.1.,-' CLOSE THROUGH WATTS BAR HYDRO CONDENSER CIRC WATER SYSTEM 2 1 (SEE NOTE 6) TO DIFFUSER TVA DWG NO. 1-47W611-27-1 R9 FIGURE 10.4-6
t!) z 3' a:: NOTES,
- 2. THE PROCEDURE FOR STOPPING THE CCW PUMP IS TO CLOSE THE DISC VALVE AND LET THE PUMP BE TURNED OFF BY THE VALVE Cl 501 LIMIT SWITCH. THIS IS ACCCM'LISHEO BY THE CLOSE POSI F THE CONTROL SWITCH.
Cl 3. "DIGITAL AND ANALOG LOGIC SYMBOLS ARE USED ON LOGIC DIAGRAMS TO w z FUNCTIONALLY DESCRIBE THE PROCESS CONTROL.REFER TO THE ASSOCIATED WIRING SCHEMATIC FOR THE ELECTRICAL CCMPONENTS USED TO U.f'LEMENT THE CONTROL SCHEME **
- 4. FOR LOW FLOW REQUIRD,ENTS, SEE WB-DC-+0-37.
1-z 5. THE lilJTOR OPERATORS FOR VALVES 2-FCV-27-142, 143, AND 144 HAVE BEEN ABANDONED IN PLACE AND ALL ELECTRICAL POWER/CONTOL REMOVED. < OPEN CLOSE
- E
~1-11ge *DERIVED FRCIIII UNIQUE LIMIT Cl AND TORQUE SW REO OF VALVE
< OPEN u STOP START TYPICAL t.0/ CONTROL PULL TO STOP STOP OPEN f/2-H~
~-""sT""A""R,~... 27-9D~==~=..,
TYPICAL K>V CONTROL OPEN 1/4-H~ F-""'--..--~-i27-11.6. CLOSE
~iim-~i.~s 1-----<P--. .-
2-FCV-27-5 FULLY OPEN CCW PUMP 2A. ON STOP iu[ftiiEr ,.....______, L-- ~CLOSE OPEN f/2-H~ 27-SA
~= CLOSE
=~ CLOSE KEY PLAN A (COOLING TOWER)
OPEN OPEN STOP CLOSE OPEN STOP CLOSE CNDS DMNRLZR TYPICAL MDV CONTROL TYPICAL KlV CONTROL WASTE ____"7l_______ 2-FCV-27-11 WASTE DISPOSAL ~ F U L L Y CLOSED STGEN BLWDN LJ----1 2-471611-15-1,COORD 0-8 OPEN OPEN OPEN PUMP 2A ,-----, UNIT 2
, - - - - FRO-t ERCW FROM RCW
~~~NJ~=!~ssJ CONDENSER 27-65 TO DIFFUSER REHRENCE DRAWINGS:
WARM WATER CONDUIT 2-45W760-27-SERIES-------------SCHEMA TIC DIAGRAMS 2-47W831-1---------------------FLOW DIAGRAM 2-47W610-27-1-------------------CONTROL DIAGRAM 0-47W610-27-2 - - - - - CONTROL DIAGRAM UFSAR AMENDMENT SYMBOLS: WATTS BAR I:!,,. DEVICE LOCATED LOCALLY AT EQUIPMENT A LOCAL TEST SWITCH FINAL SAFETY
~
CENTRAL CONTROL PANEL AT PLMPING STATION VALVE REMAINS AS IS AT TIME Of FAILURE ANALYSIS REPORT [II] DENOTES U1/U2 INTERFACE POINTS. UNIT 2 POWERHOUSE ELECTRICAL LOGIC DIAGRAM CONDENSER CIRCULATING WATER SYS TVA DWG NO. 2-47W611-27-1 R6 FIGURE 10.4-6(U2)
l.'.) z - N FEEDWATER PUM M O 1 890 FT TOH ( EACH PUMP) 1-TURB-3' 001-LPC <( De: 0 0 w z <( t-z <( 2 0 <( u PT 2-220 EXHAUST HOOD SPRAY (TYP) NOTES:
- 1. ALL VALVES ARE THE SAME SIZE AS THE PIPING, UNLESS OTHERWISE NOTED.
- 2. ALL INSTRUMENT VALVES 1/2" GLOBE, UNLESS OTHERWISE NOTED.
- 3. ALL VALVE NUMBERS SHALL BE PREFIXED WITH THE UNIT NUMBER.
- 4. ALL PRESSURE GUAGE, TEST AND SAMPLING CONNECTIONS ARE 1/2".
- 5. 0 DENOTES SAMPLING CONNECTIONS.
- 6. ALL PIPING TVA CLASS H, EXCEPT AS NOTED.
SOME CIDS ON THIS DRAWING HAVE BEEN CHANGED AND MAY DIFFER FROl.1 CIDS SHOWN ON OTHER DOCUMENTS FOR THE SAIA[ cm,4PONENT. THE AL TERNA TE ID CAN BE ACCESSED IN MAXIMO AS NECESSARY TO DETERMINE IF PREVIOUS CIDS EXISTED FOR SPECIFIC cm,4PONENT. ALL UN IDS SHOWN PREFIXED BY 1- (FOR UNIT 1) UNLESS OTHERWISE NOTED. REFERENCE DRAWINGS: SEE SHEET 2 CAP. 9000 GPM o 680 FT TDH ( EACH P JECTION LEAKOFF 1~ J PLACES) CONl TO lEMP
~riin~ ~8 UFSAR AMENDMENT 2 WATTS BAR FINAL SAFETY ANALYSIS REPORT TO AUX FEEDWATER PUMPS CONT ON 1-471803-2 COORO A-4 POWERHOUSE 10" UN IT 1 FLOW DIAGRAM FROM AUX FEEOWATER lANK CONT. ON 0-47W803-4 UNIT 2 CONFIGURATIONS SHOWN OUT -OF-FUNCTION.
CONDENSATE SEE 2-47W804-1. COMPANION DWG: 1-47'11804-2, -3 TVA DWG NO. 1-47W804-1 R7 2 FIGURE 10.4-7
EXHAUST HOOD SPRAY {TYP) VENT TO ROOF 1/2 SAMPLING PORTS (CAPPED) r-.. I- a, I-w w N ' -
.- N ' .-
63 l f - - - - - - -_-_-_-_--=:c--"-C:sc_JAMPLING PORTS
,.... 2 _ 57 (CAPPED) d ---..._i-='--'O..J__.:::..J__
FCV
-25 2-351A NOTES:
- 1. ALL VALVES ARE THE SAME SIZE AS THE PIPING, UNLESS OTHERWISE NOTED.
- 2. ALL INSTRUMENT VALVES 1/2" GLOBE, UNLESS OTHERWISE NOTED.
- 3. ALL VALVE NUMBERS SHALL BE PREFIXED WITH THE UNIT NUMBER.
- 4. ALL PRESSURE GAUGE, TEST AND SAMPLING CONNECTIONS ARE 1/2".
- 5. 0 DENOTES SAMPLING CONNECTIONS.
- 6. ALL PIPING TVA CLASS H, EXCEPT AS NOTED.
- 7. ALL UNIDS SHOWN ARE PREFIXED BY 2- (FOR UNIT 2) UNLESS OTHERWISE NOTED.
NOTES CONTINUED ON SHEET 2 REFERENCE DRAWINGS: SEE SHEET 2 UFSAR AMENDMENT 3 WATTS BAR FINAL SAFETY ANALYSIS REPORT CONDENSATE RATED CAP. 900D GPM BOOSTER PUMPS 680 FT TOH ( EACH PUMP) POWERHOUSE INJECTION LEAKOFF ( TYP 3 PLACES)
-6" UN IT 2 10*-
FLOW DIAGRAM UN IT 1 AND COMMON CONDENSATE CONDENSATE CONF !GURA TIONS SHOWN TVA DWG NO. 2-47W8O4-1 R36 TRANSFER PUMP RATED CAP. 1000 GPM o 55 FT TOH OUT-OF-FUNCTION. SEE 1-47W8O4-1 FIGURE 1O.4-7(U2)
DESIGN PRESSURE AND TEMPERATURE DATA Cl z £_ 1-3-535 LINE DESIGN DESIGN ~ 1" BYPASS 1-3-556 NUMBER PRESS. (PSIG) TEMP ( 'Fl 3' 1-J-639 1 1185 465 <( Ct'. PIPING VALVES 2 650 410 0 3 1185 600 FIRST NO. USED 1-3-640 4 350 140 0 1" DR 1" 5 440 140 w 500 6 50 180 z 7 680 370 <( 8 410 180 r- [ OPEN NUMBERS 9 250 370 z 10 50 140 564 11 50 298 <(
- e "~
12 2000 480 13 1230 455
~
0 LAST NUMBER USED 14 100 350 <( 15 1250 425 u 674 NOTES:
- 1. ALL VALVES ARE THE SAME SIZE AS THE PIPING UNLESS OTHERWISE NOTED.
- 2. ALL PRESSURE GAGE VALVES ARE 1" GLOBE UNLESS OTHERWISE NOTED.
PIPING VALVES 3. ALL VALVE NUMBERS SHALL BE PREFIXED WITH THE UNIT NUMBER. FIRST NO. USED 5. LC INDICATES VALVE IS LOCKED CLOSED AND LO INDICATES VALVE IS LOCKED OPEN. 500 6. FOR VAL VE MARKER TAG LIST SEE WATTS BAR MECH. VAL VE PROGRAM RTP-009 AND 010.
- 7. [I] ETC. INDICATES LINE NUMBER CORRESPONDING TO DESIGN PRESSURE AND TDJPERATURE CHART ON THIS SHEET.
OPEN NUMBERS 8. SAMPLING CONNECTIONS ARE 1". [ 510. 511
- 9. THE DES[GN PRESSURE &. TEMPERATURE OF ALL DRAIN & VENT LINES THRU THE LAST ISOLATION VALVE SHALL BE THE SAME AS THE PROCESS LINE.
" 10.CLASS B PIPING SHALL BE HYDROSTATIC TESTED TO 1-1/4 TIMES DESIGN PRESSURE (1481 PSIG). ALL NON-SAFETY RELATED PIPING SHALL BE
~ LAST NUMBER USED if STE R~~it
-~f~T~I~~sT~~5 §~~Tt~Eli~Rt r ** ~~0~5N~~t§R~6N~HE HY TEST. ASME CODE CASES INVOLVING HYDROSTATIC TESTING MAY 574 BE EN DES APPROVES THEIR APPLICATION. HYDROSTATIC TEST PRE TA IS HISTORICAL INFORMATION AND NO LONGER MAINTAINED AS DESIGN OUTPUT.
- 11. REPLACEMENT OF NO. 1 HTRS ARE FROM YCNP,CONTRACT N0.78KJ8-821635, YUBA CORP .* DWG 78-H-25D-1-1.
- 12. DESIGN CRITERIA/SYSTEM DESCRIPTION REFERENCE DOCUMENTS INSTRUMENT (USE THE LATEST REVISlON ON ALL WORK UNLESS OTHERWISE SPECIFIED.
ROOT VALVES SEE THE LATEST REVISION OF THE 47B21 SERIES DRAWINGS "PIPING SYSTEM CLASSIFICATION.'): FIRST NO. USED N3-3A-4002---------~~J~c~6~ ::frn: FEEDWATER CONTROL 246A 1J. FOR TVA CLASS B PIPING ALL PIPING DOWNSTREAM OF THE LAST ISOLATION VALVE ON LOCAL VENTS, DRAINS ANO TEST CONNECTIONS IS TVA CLASS G UNLESS OTHERWISE NOTED. OPEN NUMBERS 14. FOR TVA CLASS H PIPING: DRAIN, VENT, TEST AND SAMPLE CONNECTIONS [ ON SYSTEMS 3A, 6 AND 54 UTILIZE FITTINGS AS NEEDED FOR USER CONNECTIONS/HOSES WHICH ARE INSTALLED BUT MAY NOT APPEAR ON THE DRAWINGS.
"w
~ FEEDWATER PUMP
- 15. THE SYSTEM 54 FE'S ARE PROVIDED FOR MFP INJECTION WATER TROUBLESHOOTING ANO TESTING PURPOSES ONLY. THE FE'S MAY
~
LOW LOAD BYPASS BE REMOVED AND STORED WHEN NOT BEING USED FOR TROUBLESHOOTING LAST NUMBER USED TO CONDENSER CONT OR TESTING AS DESIRED. ON 1-47W805-2 (TYPJ E-2--;::i 16. INDICATES FCV-J-35,-48,-9D,-1D3 ARE TVA CLASS C VALVES MOUNTED 307A IN TVA CLASS H PIPING AND FCV-3-35A,-48A,-9DA.-10JA ARE TVA CLASS H VALVES MOUNTED IN TVA CLASS H PIPING AND ALL VALVES ARE 1-3-581 IN LIMITED QA PROGRAM 031.
- 17. SETPOINT FOR 1-RFV-J-938-A & -939-B ADJUSTABLE IN ACCORDANCE WITH N3-3B-4002, SECTION 4.14.
- 18. THE SECONDARY CHAMBER OF THE STEAM GENERATORS (SHELL SIDE) ARE BUILT TO TVA CLASS A. ALTHOUGH THE SHELL SIDE OF THE STEAM GENERATORS FUNCTIONS ONLY DICTATE A TVA CLASS B, THEY WERE INSTRUMENT PROCURED TO COMPLY WITH TVA CLASS A. PIPING CONNECTED TO THE ROOT VALVES TVA CLASS A STEM.4 GENERATORS IS TVA CLASS B EXCEPT AS NOTED.
FIRST NO. USED REFERENCE DRAWINGS: TVA 200A 47W800-1 ------------FLOW DIAGRAM GENERAL PLANT SYSTEMS 30B617 SERIES--------INSTRUMENTATION SYMBOLS AND I .D. 478601-3 SERIES------INSTRUMENT TABULATION. 478611-3-2-----------LOGIC DIAGRAM OPEN NUMBERS 47W610-3-I &. 2-------CONTROL DIAGRAM [ 47W401 SERIES--------FEEDWATER SYSTEM PIPING 47W610-43------------SAMPL ING SYSTEM 47W80J-100 SERIES----STRESS ANALYSIS PROBLEM BOUNDARY
~
~ LAST NUMBER USED (TYP) 217A L J' STUFFING BOX LEAKOFF FROM SMFP INJECTION WATER LEAK-OFF TO ATMOSPHERIC CONDENSATE DRAIN TANK CONT ON 1-47W805-2, G-9 CON BOOSTER PUMP STUFFING BOX LEAKOFF UFSAR AMENDMENT 2 WATTS BAR FINAL SAFETY ANALYSIS REPORT EL 685.5 POWERHOUSE UN IT 1 1-54-526 FLOW DIAGRAM FEEOWATER
~~~----------;,,~I~*~"'-\~ ,g~~T ON 1-47WB05-2, 12" ATMOSPHERIC TVA owe NO. 1-47W803-1 R63 NO. 7 HEATER DRAIN TANK PUMPS CONDENSATE BOOSTER PUMPS DR. TANK VENT NO. 3 HEATER DRAIN TANK PUMPS FIGURE 10.4-8 RATED CAP. 3600 GPM O 1220 FT TDH RATED CAP. 2000 GPM o 730 FT TDH RATED CAP. 9000 GPM o 680 FT TDH
32" FEEDWATER
-32" DESIGN PRESSURE AND TEMPERATURE DAT.A Cl INSIDE REACTOR OUTSIDE REACTOR 8" THERMAL z CLASS B CONTAINMENT CONTAINMENT TEE 2-3-535 LINE DESIGN DESIGN 2-3-573 BYPASS NUMBER PRESS. (PSIG) TEMP ( 'F) 3'
<( 1" VENT 1 1185 465 Q:'. 2 65D 41D 0 2-3-572 3 1185 6DD 1" VENT 4 35D 14D 0 w 5 44D 14D z 6 5D 18D 7 68D 37D <( 8 41D 18D f-9 250 370 z 1D 50 140 11 5D 298 12 2000 480 13 1185 535 14 100 350 15 1200 465 NOTES:
- 1. ALL VALVES ARE THE SAME SIZE AS THE PIPING UNLESS 1" BYPASS It. DRAIN 2. ALL PRESSURE GAGE VALVES ARE 1" GLOBE UNLESS OTHERWISE NOTED.
- 3. ALL VALVE NUMBERS SHALL BE PREFIXED WITH THE UNIT NUMBER.
- 4. ALL PIPING IS TVA CLASS HAND B PER DRAWING 47821-1 UNLESS OTHERWISE NOTED.
- 5. LC INDICATES VALVE IS LOCKED CLOSED AND LO INDICATES VALVE IS LOCKED OPEN.
- 6. NOT USED.
- 7. [I] ETC. INDICATES LINE NUMBER CORRESPONDING TO DESIGN PRESSURE AND TEMPERATURE CHART ON TH IS SHEET.
- 8. SAMPLING CONNECTIONS ARE 1 ".
- 9. THE DESIGN PRESSURE It. TEMPERATURE OF ALL DRAIN It. VENT LINES THRU THE LAST ISOLATION VALVE SHALL BE THE SAME AS THE PROCESS LI NE.
10.NOT USED 11.REPLACEMENT OF NO. 1 HTRS ARE FROM YCNP,CONTRACT N0.78K38-821635, YUBA CORP., DWG 78-H-250-1-1. Cf} ~
- 12. r-==--'iOR r-==--'iINDICATES STRAP-ON TEMPERATURE ELEMENT OR INDICATOR.
13.FOR TVA CLASS 8 PIPING, ALL PIPING DOWNSTREAM OF THE LAST ISOLATION VALVE ON LOCAL VENTS DRAINS AND TEST CONNECTIONS IS TVA CLASS G UNLESS OTHERWISE NOTED.
- 14. THE SYSTEM 54 FEs ARE PROVIDED FOR MFP INJECTION WATER TROUBLESHOOTING AND TESTING PURPOSES ONLY. THE FEs MAY BE REMOVED AND STORED WHEN NOT BEING USED FOR TROUBLESHOOTING OR TESTING AS DESIRED.
- 15. TEMPORARY STRAINER TO BE REMOVED AFTER STARTUP. ref ORA 53692-01 6 16.THE SECONDARY CHAMBER OF STEAM GENERATORS (SHELL SIDE) ARE BUILT TO TVA CLASS A. ALTHOUGH THE SHELL SIDE OF STEAM GENERATORS FUNCTION'S ONLY DICTATE TVA CLASS 8. THEY WERE PROCURED TO COMPLY WITH TVA CLASS A PIPING CONNECTED TO THE TVA CLASS A STEAM GENERATORS IS TVA CLASS B EXCEPT AS NOTED.
2-3-581 REFERENCE DRAWINGS; FEEDWATER PUMP TVA 1" LOW LOAD BYPASS 47W800-1 ------------FLOW DIAGRAM GENERAL PLANT SYSTEMS TO CONDENSER 308617 SERIES--------I NSTRUMENT ATION SYMBOLS AND I. D. CONT ON 2-47W805-2 ( TYP). 47W611-3-2-----------LOGIC DIAGRAM D-2 47W610-3-1 It. 2-------CONTROL DIAGRAM 47W401 SERIES--------FEEDWATER SYSTEM PIPING 47W61 0-43------------SAMPL ING SYSTEM WBN2-3A-4002---------MAIN FEEDWATER, FEEDWATER CONTROL &. INJECTION WATER. INJECTION WATER LEAK-OFF TO ATMOSPHERIC CONDENSATE DRAIN TANK CONT ON 2-47W805-2, G-9 COND. BOOSTER PUMP STUFF I NG BOX LEAKOFF UFSAR AMENDMENT 3 WATTS BAR WBN TD-003-0415D1 WBN-2-TD-003-0415D2 FINAL SAFETY WBN-2-TD-003-041503 WBN-2-TD-003-041504 ANALYSIS REPORT WBN TD-003-041505 WBN TD-003-041506 WBN T0-003-041507 WBN T0-003-041 508 EL 685.5 POWERHOUSE WBN TD-003-0415U1 WBN-2-TD-003-0415U2 UN IT 2 WBN-2-TD-003-0415U3 1-1/2" (TYP) WBN-2-T0-003-0415U4 WBN-2-T0-003-0415U5
--.~--
2-54-527 2-54-534 TO ATMOSPHERIC T - - , ,-~~ FLOW DIAGRAM WBN-2-T0-003-0415U6 WBN TD-003-0415U7 CONDENSATE DRAIN TANK I@) FEEDWATER WBN-2-T0-003-0415U8 c~.lL=:____________ _!_L--==---_y-:~~~T ON 2-47W805-2, 12' ATMOSPHERIC TVA DWG NO. 2-47W8O3-1 R35 LEFM LEGEND NO. 7 HEATER DRAIN TANK PUMPS CONDENSATE BOOSTER PUMPS DR. TANK VENT........_ NO. 3 HEATER DRAIN TANK PUMPS FIGURE 1O.4-8(U2) RATED CAP. 2000 GPM @ 730 FT TOH RATED CAP. 9000 GPM @ 680 FT TOH RATED CAP. 3600 GPM@ 1220 FT TOH
NOTES: CONDENSATE BOOSTER PUMP Cl 1 . §~~~t~§E~b ~~~g~66~TtsT~:I~~:bN¥gRwir~rnpT~TIR1~~Dt~~A~~~~§~oN z 1-47W610-2-2 COOR D - 9 1 > - - - - - , - , . - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - ~ TABLE A1 OF HEATUP AND STEAM DUMPS TO ATMOSPHERE. DIGITAL COMPUTER POINTS LIC-2-9 INDICATES HOTWELL B LEVEL IN THE MAIN CONTROL ROOM 3' AND OPERATES LCV-2-9 TO GIVE AUTOMATIC MAKEUP FROM THE CONDENSATE <( SAMPLING SYSTEM POINT ID DESCRIPTION
~ ~
STORAGE TANK. Q:'. LP TURBINE A LP TURBINE 8 LP TURBINE C Y2225D HOTWELL PMP A BKR 1-47W610-43-2 COOR A-5 2. WHEN THE HOTWELL LEVEL BECOMES HIGH LIC-2-3 OPERATES LCV-2-3 0 Y2226D HOTWELL PMP B BKR
@t, TO BYPASS FLOW TO THE CONDENSATE STORAGE TANK.
~ ~
Y2227D HOTWELL PMP C BKR 0 3. THE TOTAL CONDENSATE FLOW IS MEASURED BY FE-2-35 AND FT-2-35. w THIS IS RECORDED ON FR-2-35 IN THE MAIN CONTROL ROOM. z <( LOG
~-----,-----6ut.1-2 LOG L-593A 1 - - - - ~ 1-45W600-47-16 PT I
> FIC-2-35 IS SET TO MODULATE VALVE FCV-2-35A TO MAINTAIN A FLOW OF 5500 GPM.
- 4. A STEAM PACKING EXHAUSTER IS PROVIDED TO REMOVE THE AIR AND f- T2340A T2344A STEAM MIXTURE FROM THE SHAFT PACKING.
I I~ z F~V 2-75 18!
© 5. FOR OPERATION OF HEATER BANK ISOLATION VALVES (FCV-2-45, ETC)
SEE 1-47W610-6-1, NOTE 11.
- 6. FOR OPERATION OF MFPT CONDENSER ISOLATION VALVES SEE 1-47W610-3-1.
- 7. ALL OF THIS SYSTEM SHALL BE POWERED FROM A NON-DIVISIONAL 0 POWER SOURCE.
<( u
@x ~s
- 8. REFER TO TABLE Al FOR DIGITAL COMPUTER POINTS (BREAKER POSITION).
9. I R-125 R-123 SAMPLING SYSTEM SAMPLING SYSTEM 1,,,i,AI Lex;
-336 r
2-10 1-47W610-43-2 COOR A-6 1-47W610-43-2 COOR A-6 I __ J_ ____ l_ I _MI i tm
~3A-46C VACUUM REFERENCE PLUGGED/CAPPED AT
@ R-123:
I I I 1ST LINE: REFERS TO SYSTEM 098 CONTROL DIAGRAt.l CONTINUATION. 2ND,3RD, ETC LINES: DENOTESFBt.l'SFOR SIGNAL. LOOP IDENTIFIER (TYP) DENOTES I I ,------- (FBM-98-L982A05, CH 1) MAIN TURBINE GOVERNOR PEDESTAL LOCATION OF FBM.
--i----+-----t L-590A r - - - - - - - - - - - ~ 1-45W600-47-15 2-,c:~
PT : ANN 3A-46C QE[] 3A-46C LOG ~
'\1/
- ~ t(
I 1lLS00[4'D1 (FBM-98-L982A06, CH 1) LOGIC REF 08F734235-FD-1005
~------~
DCSIOPOINTNAME R191-AUXJNSTRRt.lR-191 L982 - t.CR PNL-98-L982 (TYPICAL) CH 2 - DENOTES FBM CHANNEL DENOTES FUNCTIONAL DIAGRAM DEPICTING
~
P2265A L-~ LOOP LOGIC. !1-00063673-) PRECEDES 2-2P002 ~gR~rEr~TD;V~gJPUT FRO.I DCS (08F7342JS-FO-XXXX). I
>-<M-3 I I r-~ [IQQJ_ ____ FOXBORO DCS I 2-2P001 I ,._______, ~ ,,,.._'-"41"w"'s,"-oc"_,,,.,-_~.A~c~o~oR~D~E"--rl4
( FBM-98-L 984802, CH 1 ) I 3A-46C : SIGNAL FROM TM-2-2 ( FBM-98-L 984802, CH 2) I r----- ( FBM-98-L 984802, CH 3) LOG @R-123 HEATER 86 ~ N L--<1-47W610-2-1 COORD D-4) 1 P2263A y 7 I ( FBM-98-L 984802, CH 4) FBM-98-L 984802 CH 5
@;r-'~3--ffi I
I 1-47W610-98-8A COOR E-5 __ J_ ___ ___.__r _ ( FBM-98-L 984802, CH 9) ( FBM-98-L 984802, CH 10) C ( FBM-98-L 984802, CH 11 ) L~~ M = = T2250A COORD F-1 I 9 (FBM-98-L984802, CH 12) ( FBM-98-L 984802, CH 13) FBM-98-L984802 CH 14 I 1-47W610-98-8A COOR F-8 IL _____ _ ( FBM-98-L 984803, CH 5) ( FBM-98-L 984803, CH 6) TW ( FBM-98-L 984803, CH 7 l 1-47W610-6-11 2-11 (j-47W610-2-3 cooR G-2 ~~~c~~=-9 iF~~~~~~L~~4~i5,c~oHR03f-s FBM-98-L 984A06 CH 3 1-47W610-98-8 COORD -5 CONDENSATE RESERVOIR r@;-3 I LR _r-------- ( FBM-98-R 195C02, CH 1 l 1-47W610-98-8A COOR F-8
~ : 2-12 .==--------- FBM-98-L 984803 CH 8 1-47W610-98-8 (FBM-98-R195C03, CH 1)
COOR D-7 I y" ~ ~ I I I r---------- 1-47W610-98-8 FBM-98-R195C01 1-47W610-98-8 COOR -3 CH 2 COOR D-5 I~----~ L-~ 1-45W600-47-15 > I 1 __Gut.1-2 I I r--------- (FBM-98-R195C02, CH 2) t--T~ __ J r------- 1-47W610-98-8 FBM-98-R195C03 CH 2 1-47W610-98-8A COOR E-2 COOR D-7 CON HOOD SPRAY HEATER 87
- r,-\ r----
(FBM-98-L984801, CH 1) (FBM-98-L984801, CH 2) 1-47W610-47-3 COOR E-9 CON HOOD SPRAY 1-HW610-47-3 COOR E-11
- 8 1 I
(FBM-98-L984801, CH 3) (FBM-98-L984801, CH 4) I FBM-98-L984801 CH 5 1-47W610-98-8A COOR E-3 I 2 (FBM-98-L984801, CH 9) C (FBM-98-L984801, CH 10) DEMI N CON PUMPS (FBM-98-L984801, CH 11) 3 (FBM-98-L984801, CH 12) 1-47W610-2-4 COOR C-2 r-------------------------------- (FBM-98-L984801, CH 13) 1 I ,------------------------- I FBM-98-L984801 1-47W610-98-8A COOR F-6 CH 14 CONDENSER ZONE A CONDENSER ZONE 8 CONDENSER ZONE C I I 'I r------------------ IL ____ _ ( FBM-98-L 984803, CH 1 ) 1 ( FBM-98-L 984803, CH 2) I I I MDFP LOW FLOW BYPASS I I I I I (1-47W610-2-3 COOR H-4 µ:.L~'{:~-~ l~~~w~~o:~~~~~ 3 cg8R~ C-5
~ J I I
I : 3A-45D L (FBM-98-L984A05, CH 2) ( FBM-98-L 984A06, CH 2) MFTP LOW FLOW BYPASS I
~~.:~~~0~~3- 1-47W610-98-8A COOR E-9 I
~ J I ~ ( FBM-98-L 984804, CH 1 )
N SAMPLING SYSTEM I L 0
~ '
I I I I MFPT CONDENSER VACUUM I N I
-123 1-47W610-2-3 COOR A-1 u
- - - - - - - - - - - - - - - - ____________________ J I
M-3
~
C LOG
>' 0 MFPT CONDENSER VACUUM
@ ~@?,24 F2264A 0
z 8
~
9
~ - - - - < 1-47W610-2-3 COOR A-1
(/y FM ' I I 2-35A -/ 1 - 2-35
~ /@/ I R-124
( PX
~ SAMPLING SYSTEM 2-35
-3 [Tiii8_ UFSAR AMENDMENT 3 EI LOG ~- 2-19A L-309~ ~
2-2 Q2812A L ___ J_ ____ __@_ 47W420-1 THRU 12 ----- CONDENSATE PIPING WATTS BAR ffi IL _ _ _ ....... I ____ ET -- 47W601-2-1 THRU 33 --- INSTRUMENT TABULATION 2-26
~
1-47W610-2-1 THRU 4 -- CONTROL DIAGRAM-CONDENSATE SYSTEM FINAL SAFETY
~0~ ~0~
47W611-2-1,2,3 ----- LOGIC DIAGRAM-CONDENSATE SYSTEM HS M-3 ffi 1-47W804-1,2 --------- FLOW DIAGRAM-CONDENSATE ANALYSIS REPORT y t, 2-26A
---+-----
PRESSURE REGULA TOR WI TH FILTER. PRESSURE SET TO BE DETERMINED BY MANUFACTURER'S REQUIREMENT FOR THE DEVICE BEING SUPPLIED. POWERHOUSE UN IT 1 COMPANION DRAWINGS: 1-47W610-2-2 THRU 4 ELECTRICAL CONTROL DIAGRAM CONDENSATE SYSTEM TVA DWG NO. 1-47W610-2-1 R22 FIGURE 10.4-9
NOTES, 1, SUFFICIENT FEEDWATER IS MAINTAINED WITHIN THE CONDENSATE/FEED SYSTEMS TO ACCOMMODATE THE NEED FOR MAKEUP DURING THE EXPANSION OF HEATUP AND STEAM DUMPS TO ATMOSPHERE. LIC-2-9 INDICATES HOTWELL B LEVEL IN THE MAIN CONTROL CONDENSATE BOOSTER PUMP ROOM ANO OPERATES LCV-2-9 TO GIVE AUTOMATIC MAKEUP FROM THE CONDENSATE STORAGE TANK. 2-47W610-2-2, COOR D-10 2. WHEN THE HOTWELL LEVEL BECOMES HIGH LIC-2-3 OPERATES LCV-2-3 TO BYPASS FLOW TO THE CONDENSATE STORAGE TANK.
- 3. THE TOTAL CONDENSATE FLOW IS MEASURED BY FE-2-35 AND FT-2-35. THIS IS RECORDED ON FR-2-35 IN THE MAIN CONTROL ROOM FIC-2-35 IS SET TO MODULATE VALVE FCV-2-35A TO MAINTAIN A FLOW OF 5500 GPM.
- 4. A STEAM PACKING EXHAUSTER IS PROVIDED TO REMOVE THE AIR AND STEAM MIXTURE FROM THE SHAFT PACKING.
- 5. FOR OPERATION OF HEATER BANK ISOLATION VALVES (FCV-2-45, ETC.) SEE 2-47W610-6-1. NOTE 11.
- 6. FOR OPERATION OF MFPT CONDENSER ISOLATION VALVES, SEE 2-47W610-3-1.
- 7. ALL OF THIS SYSTEM SHALL BY POWERED FROM A NON-DIVISIONAL POWER SOURCE.
- 8. LOG POINTS WHICH DO NOT HAVE A SUFFIX "D" HAVE ANALOG INPUTS FROM 2-TIS-15-42 r< 2-47W610-15-1. COOR B-2 > ~
SYMBOLS, PRESSURE REGULATOR WITH FILTER. PRESSURE SET TO BE DETERMINED IL______________ _
~ BY MANUFACTURE'S REQUIREMENT FOR THE DEVICE BEING SUPPLIED.
0 <t: u SAMPLING SYSTEM SAMPLING SYSTEM LOG FOXBORO DCS 2-47W610-43-2, COOR C-6 2-47W610-43-2, COORD 8-5 P2265A 2-47W610-98-BA,COORD B-7 (FBM-9B-R125A05,CH 1) - 7 2-47W610-98-8A,COORD D-5 (FBM-98-R125801,CH 2) LOGIC REF 08F 802403-FD-2808 LOG P2264A I I
- FOXBORO cs L 2-47W610-98-8A,COORD D-5
~--l
~ I
*(FBM-98-R725B01.CH 1 J 2-47W610-98-BA,COORD E-9 (FBM-98-R725A08,CH 1) 2-47W610-98-BA,COORD G-5 i-*
FOXBORO cs 2-f7W610-98-8A,COORD (FBM-98-R125B02,CH D-3 1} I I (FBM-98-R125B07,CH 2) 2-47W610-98-8B,COORD C-8 I LOGIC REF (FBM-98-M018H05,CH 1} I OBF802403-FD-2810 FOXBORO DCS
-47W610-98-11.COORD C-9 r (FBM-98-M018H05,CH 2)
I I (FBM-98-M018H05,CH 3) BM-98-R124A01,CH 7 I I 2-47W610-98-8B,COORD C-3 LOGIC REF I I (FBM-98-M018H03,CH 1}
,-------_J I
08F 802403-FD-2896 I ,---- -* I (FBM-98-M018H03,CH (FBM-98-M018H03,CH 2) 3} I I
-47W610-2-1. COOR E-1 >-JI (FBM-98-M018H03,CH (FBM-98-M018H03,CH 4}
5} I I I r------12-45W600-47-16 I
> 2-47W610-98-8B,COORD (FBM-98-M018H03,CH C-3 9)
(FBM-98-M018H03,CH 10} I I (FBM-98-M018H03,CH 11) L_J I (FBM-98-M018H03,CH 12)
~ ~ - - - ~ - , L-593A I (FBM-98-M018H03,CH 13)
FOXBORO cs I (FBM-98-M018H03,CH 14} 2-47W610-98-88,COORD G-3 2- LM-2-9 I (FBM-98-L900A03,CH 3) 2-47W610-98-88,COORD G-3
/
)
2-47W61 0-98-88, COOR C-10 (FBM-98-M018H07,CH 3) (FBM-98-M018H07,CH 3) - - t<-2---47-.-,-10---2--3-.-C-0-0R--G---,-> ( FBM-98-L900A03, CH 2) ffi CON HOOD SPRAY 2-f7W610-98-8A,COORD 0-2 I t~~~~~,~~~:~~8A~~DH G;t 2-47W610-47-3, COOR E-11 (FBM-98-R125B02,CH 2} I LOGIC REF 2-f7W610-98-8B.COORD C-8 I I 08F802403-FD-2802 L ____ 7 L (FBM-98-M018H05,CH (FBM-98-M018H05,CH 5} 6) CONDENSER ZONE "B" (FBM-98-M018H05,CH 7} 2-47W610-2-3, 2-f7W610-98-8B,COORD C-6 I (FBM-98-M018H04,CH 1) _J I ABANDON
,* (FBM-98-M018H04,CH (FBM-98-M018H04,CH (FBM-98-M018H04,CH 2) 3}
4) (FBM-98-M018H04,CH 5) 2-47W610-98-8B,COORD C-6 CJ
- J_ (FBM-98-M018H04,CH (FBM-98-M018H04,CH (FBM-98-M018H04,CH 9) 10) 11) 11 MFPT CONDENSER VACUUM (FBM-98-M018H04,CH 12) 2-47W610-2-3, COORD A-1 I_J (FBM-98-M018H04,CH 13)
I (FBM-98-M018H04,CH 14) MFPT CONDENSER VACUUM 2-47W610-2-3, COORD A-1 I I I 2-47W61 0-98-88, COOR C-10 (FBM-98-M018H07,CH 4) - - l<-2___4 7-.-,-,0---2--3-,_C_OO_R_-H---.-> (FBM-98-M018H08,CH 4) 2- LM-2-3 I I 2-47W610-98-8B,COORD E-9 L-30~ I I L_. (FBM-98-M018I07,CH 1) 2-47W610-98-8A,COORD B-2 2-Ls-=-2-=f~ 3A-45D (FBM-98-R125A01,CH 2) 2-47W610-98-8A,COORD G-2 (FBM-98-R125B05,CH 1) - ----, I ,--- I
, - _ _ _ _ _ _ _ _ __. _ _ _J : LOGIC REF 08F 802403-FD-2802 I 08F802403-FD-2803 I
- 11 L _________________ JI 1,-------------J I I I I 11 l1r _____________ JI I I I FOXBORO cs LOG F2264A Lll_..!I_ 2-47W610-98-10,COORD C-2
{FBM-98-R026D01 ,CH 3)
<:-:~;:,~~~:~110:~~:o !~s
~- 2-47W610-98-10A,COORD 8-7 M-3 L
{FBM-98-L901A08,CH 2) 2-47W610-98-10,COORD C-9 {FBM-98-R026D05 ,CH 1) (FBM-98-R026D06 ,CH 1) M-& FR 2-35 2-47W610-98-10,COORD C-9 (FBM-98-R026D05 ,CH 2) EDl UFSAR AMENDMENT 3 {FBM-98-R026D06 .CH 2) :QI 6~~J82:g_FD-2811 'SH 1 +/-I WATTS BAR L-----------------~ FINAL SAFETY ANALYSIS REPORT POWERHOUSE UN IT 2 ELECTRICAL COMPANION DRAWINGS: CONTROL DIAGRAM REFERENCE DRAWi NGS, 2-47W610-2-2 THRU 2-47W610-2-4 CONDENSATE SYSTEM 2-47W420-1 THRU-12-----CONDENSATE PIP ING 2-47W61D-2-1 THRU-4----CONTROL DIAGRAM CONDENSATE SYS TVA DWG NO. 2-47W61O-2-1 R21 2-47W611 1 , -2. ----LOGIC DIAGRAM-CONDENSATE SYS 2-47W804-1,-2----------FLOW DIAGRAM-CONDENSATE SYS FIGURE 1O.4-9(U2)
CONDENSER VACUUM HOR 1-47W61D-2-1,COORD F-2 D <( u LOG T2243A
~
SAMPLING SYSTEM SAMPLING SYSTEM lill,llil SAMPLING SYSTEM I 1-47W610-43-2,C00R0 A-7 1-47W610-43-2,C00RD A-7 I 1-47W610-43-2, COOR A-7 _ _ _ _ _ _ _ _J
~~w NO. 3 NO. 3 NO. 3 HTR DR TK PMP DISCH HTR DR TK PMP DISCH HTR DR TK PMP DISCH ~~-3 1-47W610-6-8,COORD A-l J>-----------, 1-47W610-6-8,COORD 8-l J>-----------, 1-47W610-6-8,C00RD C-1 1>-----------,
id: 2 J-us*s L LOG LOG LOG 2 T2266A T2267A T2268A 1 2 1 I LOG LOG LOG MAKE : T2269A T2270A T2271A I VENT _J 2-181D CONDENSER VACUUM PUMPS RE 90-256 REFERENCE DRAWING 1-47W610-90-5
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LOW PRESS. HEATER TIE w w w 1-47W610-2-1.C00RD A-1 1-L-282
~ @M-3 ~ @M-3 ~ @M-3 2-L-279 PT .....,__.,._
I I -@-3 PI YA YA YA 2-77 : 2-77
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LOG T2275A I LOG @ X 7
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P2272A 1 TABLE AZ DIGITAL COMPUTER POINTS
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-3 CONDENSER VACUUM EXHAUST RADIATION MONITORING I I NOTE:
TEST 1. REFER TO TABLE A2 FOR DIGITAL COMPUTER POINTS (BREAKER POSITION). I I I I I I [""ANii7 [""ANii7 UFSAR AMENDMENT 3 ii:::GIJ I ii:::I::TIJ I WATTS BAR PI L-98 Pl L-98 FINAL SAFETY 2-95 2-82 ANALYSIS REPORT POWERHOUSE r----- UN IT 1 IL ____ _ ELECTRICAL CONTROL DIAGRAM CONDENSATE SYSTEM AUX OIL SUPPLY AUX OIL SUPPLY AUX OIL SUPPLY TVA DWG NO. 1-47W610-2-2 R22 PUMP "A" CONDENSATE BOOSTER PUMPS PUMP "8' PUMP "C" FIGURE 10.4-10
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c:, LI --r-~** ~M-J w z 1-FCV 2-128 4 z ,_, MFP A .t. B 2-4-7W610-2-3,CCXJRD E-8 c:, u HEATER AZ
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I M-3 *-J HS 2-111al I y** v,* t, i____f'i;s\ I I t--@ 1 2~~78B1 L_ f\t.!_*i* N0.3 HTR DR TANK PMP DISCH N0.3 HTR DR TANK PMP DISCH N0.3 HTR DR HNK PW DISCH L ffi--tI 2-47W610-6-6.COORD C-11 2-471610-6-6,COORD 0-11 2-47W610-6-6,COORD E-1I 2 1 1 2 1 1 2-181D (REC! Pl.MP) CONDENSER VACUUM PUMPS REFERENCE owe 2-47W610-90-5, COORD G-8,H-8 LOW PRESS HEATER TIE
~-7 2-47W610-2-1 ,COORD A-2 I
~-=,o~x=eo~RO~oc=s-~ J 2-47W610-98-8A,COCR> B-2 (FBM-98-R125A01.CH J) 2-471610-98-SA,OXR> B-7 (FEIM-98-R125A05,CH 2) 7 LOGIC REF OBF 802403-FO- 2805 I
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