ML20247H336
| ML20247H336 | |
| Person / Time | |
|---|---|
| Site: | 05200002, 05000470 |
| Issue date: | 03/30/1989 |
| From: | ABB COMBUSTION ENGINEERING NUCLEAR FUEL (FORMERLY |
| To: | |
| Shared Package | |
| ML20247G537 | List:
|
| References | |
| NUDOCS 8904040441 | |
| Download: ML20247H336 (142) | |
Text
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C E S S A R innne. m . -(Sheet 1 of 4) j EFFECTIVE PAGE LISTING CHAPTER 10 Table __of Contegy .
Lagg Amendment i E 11 C 111 E iv E v C vi C v11 E viii E-
. Text j Eaggt Amendment l i
10.1-1 A 10.1-2 E 10.2-1 E 10.2-2 E 10.2-3 E 10.2-4 E 10,2-5 E 10.2-6 E 10.2-7 E 10.2-8 E 10.2-9 E 10.2-10 E I 10.2-11 E i E I 10.2-12 10.2-13 E 10.2-14 E lo.2-15 E 10.2-16 E 10.2-17 E 10,2-18 E 10,2-19 E 10.3-1 A 10.3-2 E 10.3-3 A 10.3-4 A 10.3-5 A 10.3-6 A 10.3 'i A 10.3-8 E 10.3-9 E 10.3-10 A i
_ Amendment E 8904040441 890330 ,
December 30' 1988 PDR ADOCK 05000470S K PDR ' ,
CESSAREnMem:u (Sheet 2 of 4)
EFFECTIVE PAGE LISTING (Cont'd)
Ol CHAPTER 10 T. ext (Cont'd)
P_ age Amendment 10.3-11 A 10.3-12 E 10.3-13 E 10.3-14 E 10.3-15 E 10.3-16 E I l
10.3-17 E 10.3-18 E 10.3-19 E 10.3-20 E l 10.3-21 E j 10.3-22 E l 10.4-1 E 10.4-2 E 10.4-3 E 10.4-4 E 10.4-5 E 10.4-6 E 10.4-7 E 10.4-8 E 10.4-9 A 10.4-10 A 10.4-11 E 10.4-12 E 10.4-13 E 10.4-14 E 10.4-15 A 10.4-16 A 10.4-17 E 10.4-18 E 10.4-19 E 10.4-20 A 10.4-21 A 10.4-22 A 10.4-23 E 10.4-24 E 10.4-25 E 10.4-26 A 10.4-27 E 10.4-28 A 10.4-29 A 10.4-30 E 10.4-31 C Amendment E December 30, 1988 N_-
CESSAR Er"4inem (Sheet 3 of 4)
EFFECTIVE PAGE LISTING (Cont'd)
CHAPTER 10 Text (Cont'd) j Page Amendment 10.4-32 E 10.4-33 C i 10.4-34 C 10.4-35 E l i
10.4-36 C 10.4-37 E 10.4-38 E 10.4-39 E 10.4-40 C 10.4-41 E 10.4-42 E 10.4-43 C 10.4-44 E 10.4-45 C
/q t 10.4-46 C U 10.4-47 C E
10.4-48 l 10.4-49 C
' Tables Amondment I 10.1-1 (Sheet 1) E q 10.1-1 (Sheet 2) E 10.1-1 (Sheet 3) E 10.1-1 (Sheet 4) E 10.2.2-1 E 1^.2.3-1 E
.0.3.2-1 (Sheet 1) E ,
10.3.2-1 (Sheet 2) E 10.3.5-1 E 10.3.5-2 E 10.3.5-3 E 10.4.9-1 (Sheet 1) C 10.4.9-1 (Sheet 2) C 10.4.9-1 (Sheet 3) C 10.4.9-1 (Sheet 4) E 10.4.9-2 C 10.4.9-3 (Sheet 1) C 10.4.9-3 (Sheet 2) C 10.4.9-4 (Sheet 1) E 10.4.9-4 (Sheet 2) E 10.4.9-4 (Sheet 3) E Amendment E December 30, 1988
1 CESSAR !!Sinem (Sheet 4 of 4)
O EFFECTIVE PAGE LISTING (Cont'd)
CHAPTER 10 Tables (Cont'd) Amendy. eat 10.4.9-4 (Sheet 4) E 10.4.9-5 (Sheet 1) E 10.4.9-5 (Sheet 2) C 10.4.9-5 (Sheet 3) C ]
10.4.9-5 (Sheet 4) C Fiqures Amendment i
10.1-1 A )
10.1-2 10.3.2-1 A 10.4.7-1 A 10.4.7-2 A )
10.4.7-3 A j i
10.4.8-1 A 10.4.9-1 (Sheet 1) C ,
10.4.9-1 (Sheet 2) C 1
O Amendment E i December 30, 1988
CESSAR EnnncAm,, )1 s <
[
\_- 1 TABLE OF CONTENTS CHAPTER 10 Section Subiect Pace No. ,
d 10.0 STEAM AND POWER CONVERSION SYSTEM
- 10.1-1 10.1-1 l 10.1
SUMMARY
DESCRIPTION 10.2 TURBINE GENERATOR 10.2-1 10.2.1 DESIGN BASES 10.2-1 10.2.2 SYSTEM DESCRIPTION 10.2-2 10.2.3 SAFETY EVALUATION 10.2-15 t
i 10.2.4 INSPECTION AND TESTING REQUIREMENTS 10.2-17 10.2.5 INSTRUMENT APPLICATION 10.2-19 10.3 MAIN STEAM SUPPLY SYbTEM 10.3-1
('(() 10.3.1 DESIGN BASES 10.3-1 j 1
10.3.2 SYSTEM DESCRIPTION 10.3-2 1
10.3.2.1 System Performance 10.3-2 l
10.3.2.2 System Arrangement 10.3-3 10.3.2.3 Pipina, Valve, I&C and 10.3-7 Insulation c 10.3.2.3.1 Piping 10.3-7 10.3.2.3.2 Valves 10.3-7 10.3.2.3.2.1 Main Steam Isolation 10.3-7 Valve (MSIV) and MSIV Bypass Valve 10.3.2.3.2.2 Main Steam System 10.3-9 Safety Valves 10.3.2.3.2.3 Main Steam Atmospheric 10.3-10 u Dump Valves (ADVs) l s
- Chapter 10 will be updated in future submittals to include baseline data from Chapters 6 and 15 safety analyses and A
( the Systen 80+ probabilistic risk assessment.
Amendment E i December 30, 1988
i CESSAR Minncueu O
TABLE OF CONTENTS (Cont'd)
CHAPTER 10 1
Section Subiect Pace No.
10.3.2.3.3 Instrumentation and Control 10.3-11 10.3.2.3.3.1 Main Steam Isolation 10.3-12 Valve (MSIV) 10.3.2.3.3.2 Atmospheric Dump 10.3-12 Valves (ADVs) 10.3.2.3.4 Insulation 10.3-13 10.3.3 SAFETY EVALUATION 10.3-15 10.3.4 INSPECTION AND TESTING REQUIREMENTS 10.3-15 10.3.5 SECONDARY WATER CHEMISTRY 10.3-16 10.3.5.1 Chemistry Control Basis 10.3-16 10.3.5.2 Corrosion Control Effectiveness 10.3-18 C 10.3.6 STEAM AND FEEDWATER SYSTEM MATERIALS 10.3-21 10.3.6.1 Fracture Touchness 10.3-21 10.3.6.2 Materials Selection and 10.3-21 Fabrication 10.4 OTHER FEATURES OF STEAM AND POWER 10.4-1 CONVERSION SYSTEM 10.4.1 MAIN CONDENSER 10.4-1 10.4.1.1 Desian Bases 10.4-1 10.4.1.2 System Description 10.4-1 10.4.1.3 Sa_fety Evaluation 10.4-3 10.4.1.4 Tests and Inspections 10.4-4 10.4.1.5 . Instrumentation Application 10.4-4 O
Amendment C ii June 30, 1988
m
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TABLE OF CONTENTS (Cont'd)
CHAPTER 10 Section Subiect Pace No. 3 10.4.2 MAIN VACUUM SYSTEM 10.4-4 l
10.4.2.1 Desian Bases 10.4-4 System Description 10.4-4 j 10.4.2.2 10.4.2.3 Safety Evaluation 10.4-5 ,
10.4.2.4 Tests and Inspections 10.4-5 10.4.2.5 Instrument Application 10.4-5 C
10.4.3 TURBINE GLAND SEJ aING SYSTEM 10.4-5 10.4.3.1 Desian Bases 10.4-5 f"'s 10.4.3.2 Eystem Description 10.4-5
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I ( )
E
\~ / 10.4.3.3 Safety Evaluation 10.4-6 10.4.3.4 Tests and Inspections 10.4-6 10.4.3.5 Instrumentation Applications 10.4-7 ,
10.4.4 TURBINE BYPASS SYSTEM 10.4-7 10.4.4.1 Desian Bases 10.4-7 l
10.4.4.2 System Description and Operation 10.4-8 10.4.4.2.1 General Description 10.4-8 C 10.4.4.2.2 Piping and Instrumentation 10.4-8 10.4.4.2.3 Turbine Bypass Valves 10.4-8 10.4.4.2.4 System Operation 10.4-8 10.4.4.2.4.1 System Performance 10.4-9 10.4.4.3 Safety Evaluation 10.4-10 10.4.4.4 Inspection and Testina 10.4-10 Requirements l' Instrumentation Application 10.4-10 10.4.4.5
(
b Amendment E iii December 30, 1988
CESSAR ENGnce O
TABLE OF CONTENTS (Cont'd)
CHAPTER 10 l Subiect Pace No. l Section 10.4.5 CONDENSER CIRCULATING WATER SYSTEM 10.4-11 10.4.5.1 Desian Basis 10.4-11 10.4.5.2 System Description 10.4-11 10.4.5.3 Safety Evaluation 10.4-12 l
Tests and Inspections 10.4-12 E 4 10.4.5.4 10.4.5.5 Instrument Applications 10.4-13 10.4.6 CONDENSATE CLEANUP SYSTEM 10.4-13 !
l I
10.4.6.1 Desian Basis 10.4-13 10.4.6.2 System Description 10.4-13 ]
1 10.4.6.3 Safety Evaluation 10.4-14 10.4.6.4 Inspection and Testina 10.4-14 C
Requirements 10.4.6.5 Instrumentation Applications 10.4-14 10.4.7 CONDENSATE AND FEEDWATER SYSTEMS 10.4-15 10.4.7.1 Desian Basis 10.4-15 10.4.7.2 System Description 10.4-15 10.4.7.2.1 System Performance 10.4-17 10.4.7.2.2 System Arrangement 10.4-18 10.4.7.2.3 Piping, Valves, 10.4-20 Equipment and Instrumentation 10.4.7.3 Safety Evaluatiom 10.4-23 10.4.7.4 Tests and Inspections 10.4-23 10.4.7.5 Instrumentation Applications 10.4-23 Amendment E iv December 30, 1988
CESSAR in'rincuia
[h.
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. lU TABLE OF CONTENTS (Cont'd)-
CHAPTER 10 Section Subiect Pace No.
10.4.8 STEAM GENERATOR BLOWDOWN SYSTEM 10.4-25 10.4.8.1 Desian Basis 10.4-25 10.4.8.2 System Description 10.4-25 10.4.8.3 Safety Evaluation 10.4-28 10.4.8.4 Tests and Inspections 10.4-28 10.4.8.5 Instrumentation Applications 10.4-29 10.4.9 EMERGENCY FEEDWATER SYSTEM 10.4-31 C
10.4.9.1 Desian Basis 10.4-31
<~N 10.4.9.1.1 Functional Requirements 10.4-31 g
10.4.9.1.2 Design Criteria 10.4-31 j
10.4.9.2 System Description 10.4-35 10.4.9.2.1 General Description 10.4-36 10.4.9.2.2 Component Description 10.4-37 10.4.9.2.2.1 Emergency Feedwater 10.4-37 Pumps 10.4.9.2.2.2 Steam-Driven 10.4-37 Emergency Feedwater Pump Turbines 10.4.9.2.2.3 Emergency Feedwater 10.4-38 Storage Tanks 10.4.9.2.2.4 Emergency Feedwater 10.4-38 Cavitating Venturis 10.4.9.2.2.5 Active Valves 10.4-39 10.4.9.2.3 Electrical Power Supply 10.4-41 ,
10.4.9.2.4 Emergency Feedwater 10.4-42 System Operation and Control l 10.4.9.3 Safety Evaluation 10.4-43 i
( Inspection and Testina 10.4-45 10.4.9.4 Beauirements Amendment C v June 30, 1988
i CESSAR Enamu l
O
. TABLE OF CONTENTS (Cont'd)
CHAPTER 10 l
Section Subiect Pacre No. I 10.4.9.4.1 EFW System Performance 10.4-45 i Tests 10.4.9.4.2 Reliability Tests and 10.4-45 Inspections 10.4.9.5 Instrument Requirements 10.4-46 10.4.9.5.1 Pressure Instrumentation 10.4-46 l 10.4.9.5.2 Temperature Instrumentation 10.4-47 l 10.4.9.5.3 Flow Instrumentation 10.4-47 l
10.4.9.5.4 Level Instrumentation 10.4-48 10.4.9.5.5 Steam-Driven Pumps 10.4-48 Turbine Speed APPENDIX 10A EMERGENCY FEEDWATER SYSTEM RELIABILITY 10A-1 C
ANALYSIS O ;
l l
1 O
Amendment C vi June 30, 1988
CESSAR 8!$1ncoi:,,
/"'N I
( I s_ ' i LIST OF TABLES l
CHAPTER 10 J l
Table Subiect (
4 10.1-1 Steam and Power Conversion System Design '
A and Performance Characteristics .
I 10.2.2-1 Turbine Speed Control System Protection Devices E
10.2.3-1 Turbine Speed Control System Component Failure Analysis l
l l 10.3.2-1 Main Steam Supply System Design Data 1
10.3.5-1 Operating Chemistry Limits for Secondary A Steam Generator Water 10.3.5-2 Operating Chemistry Limits for Feedwater E
10.3.5-3 Operating Chemistry Limits for Condensate i n 10.4.9-1 Emergency Feedwater System Component Parameters l 10.4.9-2 Emergency Feedwater System-Active Valve List 10.4.9-3 Emergency Feedwater System Failure Analysis C 10.4.9-4 Emergency Feedwater System Instrumentation and Control 10.4.9-5 Emergency Feedwater System Emergency Power Requirements p-s !
l Aiuendment E vil December 30, 1988
CESSAR !!!nneari u O
LIST OF FIGURES CHAPTER 10 Floure Subiect 10.1-1 Flow Diagram of Steam and Power Conversion System A E
10.1-2 Main Steam System Piping and Instrumentation Diagram 10.3.2-1 Atmospheric Dump Valve Flow Requirements A
10.4.7-1 Steam Flow Versus Power 10.4.7-2 Steam Generator Outlet Pressure Versus Power l
10.4.7-3 Economizer /Downcomer Flow Split 10.4.8-1 Flow Diagram of Steam Generator Blowdown System 10.4.9-1 Emergency Feedwater System Piping and C
Instrumentation Diagram l
J O
Amendment E viii December 30, 1988
1 r
I CESSAR EnnnCATICN A
10.0 STEAM AND POWER CONVERSION SYSTEM 10.1
SUMMARY
DESCRIPTION The function of the Steam and Power Conversion System is to convert the heat energy generated by the nuclear reactor into A electrical energy. The heat energy produces steam in two steam generators capable of driving a turbine generator unit.
T:.le Steam and Power Conversion System utilizes a condensing cycle with regenerative feedwater heating. Turbine exhaust steam is i condensed in a conventional surface type condenser. The condensate from the steam is returned to the steam generators i through the condensate feedwater system.
A Turbine Bypass System capable of relieving 55% of full load main steam flow is provided to dissipate heat from the Reactor Coolant System during turbine and/or reactor trip. This system consists of eight turbine bypass valves to limit pressure rise in the steam generators following cessation of flow to the turbine.
Once the steam flow path to the turbine has been blocked by the closing of the turbine valves, decay heat is removed by directing steam to the condenser.
j In addition to the above, atmospheric steam dump valves are l connected to the main steam lines upstream of the main steam line
! isolation valves to provide the capability to hold the plant at hot standby or, in the event of loss of power to the condenser i circulating water pumps, cool the plant down to the point at l which the shutdown cooling system may be utilized. These valves l are not part of the Turbine Bypass System; no credit for their
! use is assumed in obtaining the 55% capacity of the Turbine Byu a s Syst;em.
Overpressure protection for the shell side of the steam generators and the main steam line piping up to the inlet of the turbine stop valve is provided by spring-loaded safety valves.
Modulation of the turbine bypass valves discussed earlier would normally prevent the safety valves from opening. The steam bypass system, coupled with the reactor power cutback system, would prevent opening of the safety valves following a turbine and/or reactor trip.
Each steam generator has two steam discharge lines. Each line is provided with a flow measuring device, five spring-loaded safety i relief valves, a main steam isolation valve, and a power operated atmospheric dump valve. Additionally, one of the two lines utilizes a bypass line and valve around the respective main steam O isolation valve. Each main steam line is provided with a turbine stop valve and a control valve just up. stream of the high pressure turbine.
Amendment A 10.1-1 September 11,-1987
i CESSARnuiLwa O
Two steam- and two water-driven emergency feedwater pumps are provided to assure that adequate feeduater will be supplied to the steam generators in the event of loss of the main and startup feedwater pumps. The Emergency Feedwater System is discussed in Section 10.4.9.
The safety-related portions of the Steam and Power Conversion System are as follows:
A. Emergency Feedwater System, including main feedwater isolation valves and piping to steam generators. j B. Main steam isolation valves, including piping from steam generators.
A C. Atmospheric dump valves.
D. Safety relief valves. )
l E. Steam supply to Emergency Feedwater System. !
l F. Feedwater main isolation valves including piping from steam l generators. l
(
Means are provided to monitor and prevent the discharge of j radioactive material to the environment to insure that technical i specifications are met under normal operating conditions or in the event of anticipated system malfunctions or fault conditions, l
A summary of the design and performance characteristics is provided in Table 10.1-1. Figures 10.1-1 and 10.1-2 provide an overall system flow diagram and main steam system piping and l:
instrumentation diagram.
O Amendment E 10.1-2 December 30, 1988
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TABLE 10.1-1 (Sheet 1 of 4)
STEAM AND POWER CONVERSION SYSTEM DESIGN AND PERFORMANCE CHARACTERISTICS pesian and Performance Characteristics value Main steam system design 1200/570 )
pressure / temperature, psia /*F l I
Main steam system operating 1000/544.6 l pressure / temperature, psia /*F (at I steam generator) l Main steam flow, 10 6 lb/hr 17.12 Main feedwater temperature, *F 450 (+0, - 10) 6 10 lb/hr 17.29 E g-"3 Main feedwater Downcomer flow, flog,1b/hr 10 1.71 6
? j Economizer flow, 10 lb/hr 15.58
%J Steam generator blowdown system, .2%/1%/10% of maximum flowrate, normal / abnormal /high steam rate System / Component Performance Characteristics Main Steam System (Section 10.3)
Main steam piping From each steam generator up to and including the main steam isolation valves: ASME III, Code Class 2 (design pressure 1200 psia, design temperature 570*F, Seismic Category I).
Balance of the main steam piping:
l ANSI B31.1.0.
O) i
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Amendment E December 30, 1988
1 CESSAR 557l CAT 12N O<l TABLE 10.1-1 (Cont'd)
(Sheet 2 of 4)
STEAM AND POWER CONVERSION SYSTEM DESIGN AND
- PERFORMANCE CHARACTERISTICS i
Bystem/ Component Performance Characteristics I Main steam isolation Maximum closing time 5 seconds valves (1 per steam line) after receipt of signal. ASME E l III, Code Class 2 valves '
(design pressure 1200 psia, design temperature 570*F, Seismic Category I).
Main steam safety valves Total steam safgty valve flow (5 per steam line) rate is 19 x 10 lb/hr; set pressure in accordance with I
Article NC-7000 of ASME Section III. ASME III, Code Class 2 valves (design pressure 1320 ,
psia, design temperature 570*F, i Seismic Category I) (See l Table 5.4.13-2).
Power-operated atmospheric Saturated steam flow not less dump valves (1 per steam than 950,000 gb/hr but not more j line) than 1.9 x 10 lb/hr. ASME III, ;
Code Class 2 valves (design i pressure 1200 psia, design !
temperature 570*F, Scismic j Category I).
Turbine Bypass System (Section 10.4.4) {,
Bypass valves downstream Flow capacity equal to 55% of of main steam isolation design steam flow: Piping ANSI valves B31.1.0 (design pressure 1200 !
psia, design temperature 570*F, l non-Seismic Category I).
(
. l Amendment E December 30, 1988
--_.-__-._____________w
CESSAR Eannemu
/3 TABLE 10.1-1 (Cont'd)
(Sheet 3 of 4)
STEAM AND POWER CONVERSION SYSTEM DESIGN AND PERFORMANCE CHARACTERISTICS Bystem/ Component Performance Characteristics Condensate and Main Feedwater l System (Section 10.4.7)
E Feedwater pumps 3-50% steam-driven; 1 in standby l
Feedwater booster pumps 3-50% motor-driven; 1 in standby Condensate pumps 3-50% motor-driven / 1 in standby Low pressure feedwater 4 stages of low pressure heaters feedwater heating. 1/3 total g'~N feedwater flow per sting i
(N- Deaerator 100% of total feed flow High pressure heaters 2 stages, 1/2 total feed flow per string Condensate and Main Piping in main steam support Feedwater System piping structure (MSSS) to downstream feedwater isolation valves - ASME III, Code Class 2; From downstream and including feedwater isolation valves to steam generators - ASME III, Code Class 2, Seismic Category I. All other piping ANSI B31.1.
Balance of system piping: ANSI B31.1.
Emergency Feedwater System Two Seismic Category I (Section 10.4.9) moto -driven emergency feedwater pumps and two steam-driven emergency feedwater pumps, each providing a minimum of 500 gpm to the steam generators. Two emergency (s)
N/
feedwater storage tanks storing 350,000 gallons feedwater.
Amendment E l
December 30, 1988
TABLE 10.1-1 (Cont'd)
(Sheet 4 of 4)
STEAM AND POWER CONVERSION SYSTEM DESIGN AND PERFORMANCE CHARACTERISTICS System / component Performance Characteristics l All piping from the emergency feedwater storage tank to the E j Seismic Category I emergency feedwater pumps and containment isolation valves is ASME III, Code Class 3; piping from and I
including the isolation valves to the steam generators is ASME III, Code Class 2, Seismic Category I. !
l Secondary Chemistry Control Full flow condensate l
System (Section 10.4.6) demineralization. Continuous hydrazine additions for oxygen scavenging and continuous ammonia !
additions for pH control.
Continuous monitoring of I significant chemical parameters.
Continuous steam generator blo'1down at a rate up to 1% of the maximum steam rate.
l O
Amendment E December 30, 1988
OVERSIZE DOCUMENT PAGE PULLED SEE APERTURE CARDS NUMBER OF OVERSIZE PAGES FILMED ON APERTURE CARDS APERTURE CARD /HARD COPY AVAILABLE FROM QECORDS AND REPORTS MANAGEMENT BRANCH
CESSARinMem l
10.2 TURDINE GENERATOR 10.2.1 DESIGN BASES E
The turbine generator converts the energy of the steam produced in the steam generators into mechanical shaft power and then into electrical energy. Each unit is operated as a load following unit. The unit is capable of taking a 10% step load change or a ramp change of 5% per minute without steam bypass, as dictated by the Reactor Coolant System.
Turbine generator functions under normal, upset, emergency, and faulted conditions are monitored and controlled automatically by the turbine control system described in Section 10.2.2. The control system includes redundant mechanical and electrical trip devices to prevent excessive overspeed of the turbine generator.
Additional external trips are provided to ensure operation within conditions that preclude damage to the turbine generator. A standby manual control system is also provided in the event that the automatic control system is not available. The application of design codes to the turbine generator is discussed in Section 10.2.3.6.
10.2.2 SYSTEM DESCRIPTION D a double-flow, Each unit's turbine generator consists of high-pressure turbine and double-flow low pressure turbines ;
driving a direct-coupled generator. l I
The flow of main steam is directed from the steam generators to the high-pressure turbine through stop valves and control valves.
Af ter expanding through the high-pressure turbine, exhaust steam passes through external moisture separators and two stage steam-to-steam shell and tube-type reheaters. Extraction steam from the high-pressure turbine is supplied to the first reheater stage tube bundle in each reheater. Main steam is supplied to the second reheater stage tube bundle in each reheater. Reheated steam is admitted to the low pressure turbines through intermediate stop valves and intercept valves and expands through' the low-pressure turbines to the main condensers.
Bleed steam for the feedv/ater heating is provided from the turbine casing or turbine piping.
O V
Amendment E 10.2-1 December 30, 1988
1 CESSAR nainma ;
Extraction Source O
Heater 6 H-P turbine !
5 H-P turbine l Deaerator H-P turbine exhaust 4 L-P turbines 3 L-P turbines 2 L-P turbines 1 L-P turbines ]
Provided in the higher pressure extraction lines are piston-assist, spring-closed swing check valves. The ,
piston-assist, spring-closed actuators are designed to overcome i friction and allow the valves to close rapidly on turbine trip. j Low-pressure bleed lines are not provided with check valves since j installation in the condenser neck would be impractical. {
However, the low-pressure heaters are provided with anti-flash baffle plates located inside the heaters.
1 I
Generator rating, temperature rise, and class of insulation are in accordance with IEEE standards. Excitation is provided by a shaft-driven alternator with its output rectified.
A conventional oil-scaled hydrogen cooling system provides rotor l cooling. The stator conductors are water cooled by a stator water cooling system. Differential relays protect the generator against electrical faults.
The hydrogen bulk storage facility is located outdoors. Hydrogen is supplied from high-pressure storage tanks and an electrolysis hydrogen / oxygen generator.
In order to prevent explosions or fires, the hydrogen piping and the main generator are checked for leaks and then purged with CO2 to remove all air and oxygen before the introduction of hydrogen.
The hydrogen purged from the generator is vented through the Turbine Building roof and dissipates in the outside air.
Provisions are included at various points in the distribution system to allow for Co, purging and safe venting of the hydrogen in the generator and pfping prior to maintenance.
Turbine generator bearings are lubricated by a conventional oiling system of proven components. The main oil pump, which supplies oil to the bearings of the turbine generator shaft, is a centrifugal pump mounted on the turbine shaft. It is supplied with suction oil by an oil-driven booster pump located in the oil tank. Oil discharging from the main oil pump is piped to the oil tank where it passes through the oil turbine which drives the booster pump. The oil then goes through the oil cooler and on to the bearings. The two oil coolers are each full capacity and use conventional LP service water for cooling.
Amendment E 10.2-2 December 30, 1988
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/ l V E Two motor-driven centrifugal oil pumps are provided to supply bearing oil to the turbine bearings while the turbine is on i turning gear, while the turbine is coming up to speed, or in an I emergency condition. These pumps are the turning-gear oil pump and the emergency bearing oil pump. They take suction oil directly from the oil tank and discharge it into the bearing header prier to the main oil coolers.
One AC motor-driven centrifugal oil pump is provided to perform the function of the bocster pump until the turbine shaft has reached approximately 90% of rated speed. This pump, called the motor auction pump, is needed since high-pressure operating oil is not available to drive the booster pump until the main oil pump has reached about 90% of rated speed. Thus, until this spec.d is reached, the function of the booster pump, which is to l provide the main oil pump with suction oil at a positive pressure, must be provided by this motor suction pump.
The Electro-Hydraulic Control (EHC) System incorporates the circuitry and equipment required to provide the following basic turbine control functions:
A. Automatic control of turbine speed and acceleration through t the entire speed range.
V B. Automatic control of load and loading rate from auxiliary to full load, with continuous load adjustment and discrete loading rates.
C. Standby manual control of speed and load when it becomes '
necessary to take the primary automatic control out of service.
D. Limiting of load in response to preset limits on operating parameters. ,
l E. Detection of dangerous or undesirable operating conditions, i annunciation of det ted conditions, and initiation of ;
proper control respone. to such conditions.
F. .onitoring M the status of the control system, including the l power supplies and redundant control circuits. l G. Testing of valves and controls.
l H. Prewarming of valve chest and turbine rotor.
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The hydraulic power unit, associated with the EHC, supplies high-O' pressure fluid directly to the control pacs on the steam valves E for controlling the valves, and to the trip devices in the trip and overspeed protection circuits. The unit accommodates both, steady-state and transient requirements.
The fluid is supplied to all components at the correct temperature and required cleanliness, and the unit is equipped with special chemically active filters to maintain the proporties of the fluid over very long service times. The unit offers two complete pumping systems, allowing the turbine to operate while maintenance work is taking place on either pump system. The unit incorporates various alarms and pressure switches which will auto-start the standby pumping system or trip the turbine, should a malfunction occur in the system which is operating. The unit is designed to maximize reliability.
The electrical power required by the EHC equipment is supplied from two sources for redundancy. The primary power source is a 115 V AC, 60 Hz permanent magnet generator (PMG), gear-driven from the turbine shaft. The PMG supplies all power required by the EHC equipment at turbine speeds above 90% of rated speed, except hydraulic pumps. Normal 115 V AC provides backup power and power during startup.
The EHC equipment requires four electrical power voltage levels in addition to 115 V AC. These are +22 V AC regulated, -22 V DC regulated, " Floating" 24 V DC regulated, and " Floating" 125 V DC regulated. The +22 V DC and -22 V DC levels share a common ground. Two regulated power supplies are provided at each voltage level, one supplied from the primary PMG source, the other from 115 V AC housepower. Redundancy is, thus, provided for each voltage level. The two power supplies for a given voltage level are identical and will operate equally well on housepower or PMG power. All of the regulated power supplies are monitored with solid state dccection devices that provide light indication of power supply output voltage above or below proper level at the EHC cabinet. Should a malfunction occur in the primary power supply, the backup supply automatically maintains the voltage at the proper level. The " floating" 24 V DC and 125 V DC power supplies are provided with ground detection for indication if either side of the 24 V DC or 125 V DC line becomes grounded. Unless the other line becomes grounded, the equipment continues to operate. A second ground at the same voltage level trips the unit.
The speed control unit of the EHC system provides a speed error signal for input to the load control unit. Three distinct speed error signals are derived by the circuit. A low value gate Amendment E 10.2-4 December 30, 1988
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U receives the three signals and permits propagation of the signal demanding the smaller valve opening. The desired speed reference E is manually selected using pushbuttons mounted on the operating panel. Speed references are provided for steady-state operation at the speeds required for thermal soaking holds, as well as at rated speed. A pushbutton is also provided that, when pushed and held, overspeeds the turbine for purposes of testing the overspeed protective equipment. The maximum overspeed that the unit will reach should the pushbutton be held down does not exceed the turbine overspeed capabilities. The machine coasts down to rated speed when the pushbutton is released. A circuit is incorporated in the speed control unit to slowly vary the turbine speed above and below hold speeds that are near bucket critical speeds to avoid the possibility of extended operation in i
a resonant condition. Discrete acceleration reference signals are selected manually to provide for controlled rotor acceleration during startup. Two independent rotor speed circuits are provided for redundancy, and fail-safe circuitry protects the turbine in the event of failure of the primary circuit.
The turbine overspeed protection is divided into two basic categories of mechanical overspeed protection in the turbine and electrical overspeed protection in the EHC controller.
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l v Mechanical overspeed protection, which is independent of the EHC controller is provided by the mechanical overspeed trip mechanism, which is located in the turbine front standard on the end of the control rotor stub shaft. The over-speed trip device consists of an unbalanced ring, which is actuated by centrifugal force against the force of a spring when the turbine overspeeds.
This movement puts the ring in an eccentric position so that it strikes the trip finger of the mechanical trip linkage which operates the mechanical trip valve to close all turbine valves.
The mechanical overspeed trip device is set to activate at 110%
of rated speed.
Electrical overspeed protection, which is set at 111.6% of rated speed, is provided as a backup to the mechanical overspeed trip device. The electrical trip solenoid valves are deenergized to trip the turbine upon receiving an open contact from the EHC which represents an overspeed condition.
In addition to the overspeed protection, control, and trip functions provided by the EHC, a diverse method of tripping is provided by an independent over frequency relay which is used to l
trip the turbine if the generator frequency reaches approximately 1 111% of its rated value.
l V Amendment E 10.2-5 December 30, 1988
CESSAREMaum To further decrease the possibility of an overspeed condition O
E occurring during unit shutdown, a sequential generator trip is provided. The turbine is manually tripped after the load l reference has been runback. The reverse power relay must then sense a reverse power condition prior to initiating a generator breaker trip (unit disconnect) . This sequence is to assure that !
all steam capable of adding to a potential overspeed condition has been expanded through the turbine. l The turbine speed control system protection devices are listed in l Table 10.2.2-1. j The basic purpose of the load control unit is to accept input l' signals from other units of the EHC system and to use these signals in conjunction with functions designated as load control unit functions to compute flow reference signals for the flow control unit. Switching signals indicating operating conditions are also supplied to other units of the EHC systems. ,
The load control unit functions may be grouped as follows:
A. Sensing functions are provided to detect and generate signals proportional to parameters that affect loading of the unit.
B. Limiting functions are provided to electrically constrain the flow reference signals in response to signals from the sensing circuits, from the speed control unit, or ' rom i devices detecting the state of plant components. i l
C. Computing functions are provided to generate flow reference signals for the valve sets, considering the desired load l signal, the limiting functions, and the speed error signal from the speed control unit.
D. Logic functions are provided to ensure that necessary permissives have been satisfied prior to changes in mode of operation, to communicate status infonaation between the I load control unit and other elements of the EHC system, and to provide switching signals to devices in the EHC system.
The load set circuit provides an analog signal used for synchronizing the main generator and for establishing the final value of desired load. It is generated by a position transducer in response to changes in position of the load set motor.
Increase load and decrease load pushbuttons are provided for manual positioning of the load set motor from the EHC control panel. A meter on the EHC control panel indicates the megawatts O
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of load being called for by the load' set circuit. The loading E
rate circuit imposes a rate of change limit on the load set signal in order to produce the load reference signal. Switching-circuits provide for selecting one of several discrete loading rates. Circuitry is incorporated to reposition the load set motor when certain abnormal operating conditions are detected.
Runbacks (setbacks) may be initiated by a signal from the power / load unbalance circuit by:
A. Speed control logic unless rated speed is selected. '
l l B. Indication that the. load reference signal exceeds a preset load limit.
C. Loss of generator stator coolant.
D. Signal from the Process Control System.
E. Loss of a feedwater pump turbine.
F. Partial loss of load.
A hand-operated potentiometer is located on the control panel to allow the operator to select the maximum load to be carried by the turbine. If the flow reference signal exceeds the limit established by the potentiometer, the output flow reference signai is limited to the limit value and a load set motor runback is initiated to drop the load setpoint to slightly above the level of the limit. To prevent excessive decrease of the main sten.m (throttle) pressure, a main steam (throttle) pressure ;
liniter circuit is provided to close the controlling valve set 4 when the main steam (throttle) pressure falls below a preset level. The regulation of this circuit is fixed at 10%. When the main steam (throttle) pressure falls below an adjustable setpoint, the flow reference signal to the controlling valve set is limited to the value permitted by the level of the main steam (throttle) pressure. The pressure set point is adjustable from zero to rated pressure by changing _the position of a motor-driven potentiometer using increase and decrease pushbuttons on the ;
control panel. Meters indicate the pressure setpoint selected, I as well as the actual main steam (throttle) pressure. Associated l with the load control unit .is a rate sensitive power- load l l
unbalance circuit whose purpose is to initiate control valve fast I closing action under load rejection conditions that might lead to rapid rotor acceleration and consequent overspeed. Valve action i will occur when the power exceeds the load by at least 40% and generator current is lost in a time span of 10 ms or less.
Pressure is used as a measure of power, and generator current is used as a measure of load to provide discrimination between loss
( of load incidents and occurrences of electrical system faults. ,
Amendment E 10.2-7 December 30, 1988
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Stage pressure feedback circuitry is incorporated in the EHC E system to provide more linear turbine response to the load signal i and to maintain near constant turbine output while testing control valves. During control valve testing, a feedback signal opens the control valves that are not being tested as the tested I valve closes to maintain near constant turbine output during the test.
The turbine and its control valves must be designed to pass the rated flow at throttle pressure existing at the main stop valves at rated output of the NSSS, i.e., at the lowest point of the pressure range. At higher throttle pressure, the CVs will, therefore, have excess capacity which would cause a non-linear regulation characteristic. In addition, overload could occur if the pressure does not fol}ow the design steady-state curve during load changes or even in steady state. The positioning system for CVs is designed to account for these effects by the use of a throttle pressure compensator which is in service at all times.
It consists of an electrical throttle pressure sensor the output of which is used to adjust the gain (opening rate) of the CVs in a manner inversely proportional to the instantaneous throttle pressures. Since the flow capacity of a CV is proportional to the pressure ahead of the valve, the described action will ,
correctly compensate for the varying throttle pressure.
The main stop valve position loop consists of electronic circuitry, a hydraulic actuator and a linear position transducer. .
Main stop valve testing is provided to determine the operational status of the valve system during normal operation and to increase the probability that the valves will fast close on a turbine trip. When a given valve is tested, it slowly closes until its position switch energizes the associated solenoid valve which tests the valve fast operation through a short stroke near ,
bottom. The individual main stop valve test also results in actuation of the dedicated limit switch which provides an input to the four-out-of-four reactor trip logic.
The control valve position loop consists of electronic circuitry, ;
an electrohydraulic servo-valve, a hydraulic actuator and a linear position transducer. By use of valve position feedback control, the control valve flow control unit positions the control valves according to the flow demand signal from the load control unit, or directly from the control panel. The purpose of the valve position feedback control is to keep the valve stem of the control valve at a desired position regardless of disturbances in the steam path as well as in the position control system itself. Valve position control is performed by using a feedback path that transmits the actual valve position back to a point where it is compared algebraically with the reference Amendment E 10.2-8 December 30, 1988 V
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input. The error signal, when different from zero, positions the E hydraulic actuator via the servo-valve in order to make it zero.
Control valve testing is designed to allow regular testing of each valve with the effects to on-line turbine operation minimized. Both normal and fast-acting valve operation are tested. The individual control valve test also results in actuation of the dedicated pressure switch which provides art input to the two-out-of-four reactor trip logic. Power load unbalance directly a,nd simultaneously energizes all control valve fast-acting solenoid, realves through full stroke. On loss of feedback signal, a fully open valve will remain open and a partially open valve will close. The control valves will also close on servo-valve failures and loss of emergency trip oil pressure.
The intercept valve position loop for valves #1, #2, and #3 consists of electronic circuitry, electro-hydraulic servo-valve, a hydraulic actuator and a linear position transducer. By use of valve position feedback control, the intercept valve flow control unit positions the intercept valves according to the flow demand signal received from the load control unit, standby control unit, or directly from the control panel. Intercept valves #4, #5, and
- 6 open after valves #1, #2, and #3 have opened;-these valves do j not have the electro-hydraulic servo-valve. The purpose of valve position feedback control is to keep the valve stem of the intercept valve at a desired position regardless of disturbances in the steam path, as well as in the position control system itself. Valve position control is performed by using a feedback path that transmits the actual valve position back to a summing point where it is compared algebraically with the reference input. The error signal, when different from zero, positions the .
hydraulic actuator via the servo-valve in order to make it zero.
Intercept valve testing is designed to allow regular testing of each valve and its intermediate stop valve with the effects to on-line turbine operation minimized. The intercept valve master-slave relationship is disrupted while both normal and fast-acting valve operations are tested. The intercept valves will fast close on a large closing position error and on turbine trips.
The EHC system incorporates a standby control system which provides the capability of manual turbine control in the event of failure of the automatic speed control and/or load control subsystems. The standby control system is independent of the speed and load control units, and may be used to maintain power output while the failed subsystems are being repaired. Although the valve loops and power supplies are common to both systems, they incorporate sufficient redundancy to prevent shutdown of the J
Amendment E 10.2-9 December 30, 1988
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CESSARnnL a unit if a malfunction in a valve loop or power supply should e
occur. Two lines of defense are provided against overspeed while E operating in the standby control mode. The first line of defense ;
is provided by the backup (electrical) ove-speed trip. When l control is transferred to the standby ystem, the backup overspeed trip set point is reduced from 111.5% to 105% of rated speed. The mechanical overspeed trip becomes the backup system, since its trip setting remains at 110%. If the unit trips while on standby control, the standby system must be reset separately from the main unit reset. The machine may be rolled off turning gear, accelerated to rated speed and synchronized using the standby control. An acceleration meter is provided to monitor rotor acceleration during startup using the standby control.
If the unit is running at maximum load (load set at 100%) and suddenly the load on the generator in lost, the following events will take place in rapid succession:
A. The power / load unbalance circuit will sense that there is a 40% mismatch in power to load, and the power / load unbalance relay will switch the desired load signal to zero and start running the load set back toward zero load.
D, The turbine will accelerate at its maximum rate.
C. The control valvem and intercept valves will close at the maximum rate by means of the fast acting solenoid valves.
D. The entrained steam between the valves and the turbine, in the turbine casings and in crossover and extraction lines, will expand in less than 2 seconds.
l E. The turbine speed will level off at a speed approximately l 0.5% to 1% below the overspeed trip setting when the entrained steam has ceased expanding and will start decreasing gradually at a rate depending on auxiliary load left on the generator.
F. When the speed has decreased to approximately 102%, the intercept valves will start to reopen under speed control.
The energy stored in the intermediate piping will be gradually bled off at a rate sufficient to maintain the rotor speed and supply the auxiliary load still connected to l the generator as well as the no-load losses in the unit.
G. When the reheat pressure drops to 40% of full load pressure, the power load unbalance relay will reconnect the normal load set signal to the system. By this time, the load set has been run down to essentially zero.
Amendment E 10.2-10 December 30, 1988
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H. After the reheat pressure has bled down, the unit is running !
a few rpm above rated speed ready to be synchronized. E In case of malfunction of any portion of the first line of defense against overspeed (speed control on control and intercept valves) when load is lost, the turbine will accelerate to the trip speed where the overspeed trip will activate. This will directly trip the main and intermediate stop valves (second line of defense), and the disc-dump valves of the Control and Intercept Valve actuators will also be tripped. Subsequently, the turbine will coast down to zero speed.
The Trip and Monitoring System will initiate appropriate action on abnormal operating conditions and indicate the existence of these conditions to the operator.
i In addition to the internally generated turbine trips, any of the following externally generated trip inputs will r1sult in removing the hydraulic fluid pressure from the emerc,ancy trip system (ETS). The removal of this prersure will result in rapid closure of all turbine valves, ExtLrnally generated trip inputs are: )
m A. Low Condenser Vacuum.
B. Thrust Bearing Failure.
C. Low Bearing Oil Pressure.
D. Internal Fault in Generator.
E. Generator Breaker Failure.
F. Reactor Trip.
G. Loss of Generator Stator Coolant Without EHC Runback.
H. Steam Generator Hi-Hi Level.
I. Safety Injection.
J. Both Main Feedwater Pumps Tripped.
K. High Exhaest Hood Temperature.
L. Manual Turbine Trip.
O M. Turbine Oil Fire Trip.
G Amendment E 10.2-11 December 30, 1988
CESSARE!Mc-Moisture Separator Reheater Hi Level.
O N. E O. Low Hydraulic Fluid Pressure.
1 P. Low Turbine Shaft Pump Discharge Pressure. l l
Q. Low Emergency Trip System Pressure.
1 Circuitry is also provided to test most components of the trip )
system during operation. When a signal is received from the l sensing divices indicating that a condition exists requiring a turbint trip of the ETS, the trip valves described below will act to release the hydraulic fluid pressure in the valve ,
actuators, thus rapidly closing all steam valves. The pressure i may be released by either the electrical trip valve (ETV) or the mechanical trip valve (MTV). The me'chanical trip valve (MTV) is operated by the mechanical trip pilot valve (MTPV). The trip mechanism is reset by the oil reset piston (ORP) operated by the ,
oil resat solenoid valve (ORSV). The mechanical lockout valve is a solenoid pilot operated, three way valve that permits testing of the MTV during normal operation by admitting HP Fluid to the electrical trip valve (ETV) and closing off the output line of j I
the MTV. The electrical trip valve (ETV) is a three way valve, fluid pilot operated by the electrical trip solenoid valve (ETSV) which is held in a reset position by energizing eithe" one or both of the 24 V DC solenoids from the 24 V DC trip s ' stem.
Both solenoids must be deenergized to trip the ETV, preventing falso trip if one solenoid coil should burn out. The electrical lockout valve (ELV) is a solenoid pilot operated, three way valve j that permits testing of the ETV and ETSV during normal operation !
by shutting off the ETV output and admitting the MTV output pressure directly to the ETS. The two air relay dump valves (ARDV-1 and ARDV-2) are high pressure fluid pilot operated, three way air valves that transforms the ETS pressure into a 0-100 psi air pressure for the emergency trip air system (ETAS) that operates positive closed extraction check valves.
The first hit detection system provides indication of the reasone for a trip by turning on appropriate indicating lights on a panel in the EHC cabinet. The first hit detection system thus aids analysis of trip incidents, and may enable quick correction of system malfunctions without relying on event records.
The turbine assembly is designed to withstand normal conditions and anticipated transients including those resulting in turbine trip without loss of structural integrity. The design of the turbine assembly meets the following criteria:
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Amendment E l
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A. Turbine shaft bearings are designed to retain their E structural integrity under normal operating loads and anticipated transients, including those leading to turbine '
trips.
B. The multitude of natural critical frequencies of the turbine shaft assemblies existing between zero speed and 20%
overspeed is controlled in the design and operation so as to cause no distress to the unit during operation.
C. The maximum tangential stress in wheels and rotors resulting l from centrifugal forces, interference fit and thermal gradients does not exceed 0.75 of the yield strength of the materials at 115% of rated speed.
Turbine wheels and rotors are made from vacuum melted or vacuum degassed Ni-Cr-Mo-V alloy steel by processes which minimize flaw occurrence and provide adequate fracture toughness. Tramp elements are controlled to the lowest practical concentrations consistent with good scrap selection and melting practices, and consistent with obtaining adequate initial and long life fracture toughness for the environment in which the parts operate. The p turbine wheel and rotor materials have the lowest fracture appearance transition temperatures (FATT) and highest Charpy l
V-notch energies obtainable, on a consistent basis from water quenched Ni-Cr-Mo-V material at the sizes and strength levels used. Since actual levels of FATT and Charpy V-notch energy vary l depending upon the size of the part and the location within the part, etc., these variations are taken into account in accepting specific forgings for use in turbines for nuclear application.
Charpy tests essentially in accordance with Specification ASTM A-370 are included.
Suitable material toughness is obtained through the use of !
materials that provide a balance of adequate muterial strength and toughness to ensure safety while simultaneously providing high reliability, availability, and efficiency during operation. ,
Bore stress calculations include components due to centrifugal !
loads, interference fit, and thermal gradients where applicable.
The ratio of material fracture toughness, K (as de s ed from material tests on each wheel or rotor) to thdCmaximum tangential stress for wheels and rotors at speeds from normal to 115% of .
rated speed (the highest anticipated speed resulting from a loss l of load is 110%) is at least 2. Adequate material fracture toughness needed to maintain this ratio is assured by destructive tests on material taken from the wheel or rotor using
)
conservative correlation methods.
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Amendment E 10.2-13 December 30, 1988 1
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Turbine operating procedures are employed to preclude brittle O
E fracture at startup by ensuring that the metal temperature of !
wheels and rotors is adequately above the FATT and, as defined above, is sufficient to maintain the fracture toughness to tangential stress ratio at or above 2.
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O Amendment 8 10.2-14 December 30, 1988
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(V~'T TABLE 10.2.2-1 E
TURBINE SPEED CONTROL SYSTEM PROTECTION DEVICES Design 07< rating Speed Component Functi on in % of dated Speed Primary speed control Control 0% - 100%
Backup speed control Control 0% - 100%
Mechanical overspeed Trip 110%
Backup " electrical" trip Trip 111.5% (Normal Mode) over-speed trip 105% (Standby Mode) a l
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Amendment E December 30, 1988
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d E 10.2.3 SAFETY EVALUATION {
The turbine generator and all related steam handling equipment are of conventional proven design. This unit automatically follows the electrical load requirements from station auxiliary load to turbine full load.
The turbine generator' is located entirely in the Turbine Building. Thus, no safety-related system or portion of safety-related. system is close enough to the turbine generator to be affected by the failure of a high or moderate energy line I associated with the turbine generator or the low-pressure turbine / condenser connection.
The results of a failure analysis of the turbine speed control system are tabulated in Table 10.2.3-1. The system will be designed so that the single failure of a main stop, main control, intermediate stop, or intercept valve does not disable the turbine overspeed trip function.
Under normal operating conditions, there are no radioactive l
contaminants present. It is possible for this system to become contaminated only through steam generator tube. leaks. In this O event, radioactivity in the Main Steam System is detected and
( measured by monitoring condenser air ejector off-gas which is released through the unit vent, Section 10.4.2, and by monitoring the steam generator blowdown samples, Section 10.4.8.
No radiation shielding is required for the components of the turbine generator and related steam handling equipment.
Continuous access to the components of this system is possible during normal conditions.
The condensate polisher domineralizers are available to remove radioactive particulate from the condenser hotwell, Section 10.4.7, in the event of primary to secondary leakage. Shielding surrounds an area containing the condensate . polisher domineralizers, the backwash tank, the decant monitor tank, and associated pumps. The control panel is located outside of the !
labyrinth shield wall for accessibility, l The moisture separator reheaters and drain tanks are designed and constructed to ASME Section VIII. The generator rating, temperature rises and insulation class are in accordance with ASA Standards.
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U TABLE 10.2.3-1 TURBINE SPEED CONTROL SYSTEM E j COMPONENT FAILURE ANALYSIS 2
Component Malfunction Overspeed Prevented by Main control valve Fail to close Closure of stop valves Main stop valve Fail to close Closure of control valves Intercept valve Fail to close Closure of ,
l intermediate stop valve )
Intermediate stop valve Fail to close Closure of intercept valve Primary speed control Fails Backup speed control loop !
Mechanical overspeed Fails Backup " electrical" s_, trip over-speed trip 24 volt " electrical" Fails 125 volt " mechanical" trip solenoid valve trip solenoid valve (dual) solenoids)
A mechanical trip Fail An electrical trip Fast-acting solenoid Emergency Trip Fluid valves System 1
Amendment E December 30, 1988 l
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10.2.4 INSPECTION AND TESTING REQUIREMENTS The pre-service inspection program is as follows:
A. Wheel and rotor forgings are' rough machined with minimum stock allowance prior to heat treatment.
B. Each finish machined wheel and rotor is subjected to LOD %
volumetric (ultrasonic), surface, and visual examinations using the manufacturer's acceptance criteria. These criteria are more restrictive than those specified for Class 1 components in the ASME Boiler and Pressure Code, Sections III and V, and include the requirement that subsurface sonic l indications are either removed or evaluated to assure that thev will not grow to a size wTich compromises the integrity of the unit during the service life.
C. All finish machined surfaces are subjected to a magnetic particle test with no flaw indications permissible.
D. Each fu'l15 %cketed turbine rotor assembly is spin tested at or above 'b2 maximum speed anticipated following a turbine i e trip from 111 load.
V The in-service inspection program for the turbine assembly includes disassembly of the turbine in stages over a six year interval during plant shutdowns such that the entire turbine is inspected within six years. This includes complete inspection of all normally inaccessible parts, such as couplings, couplir:g '
bolts, turbine shafts, low-pressure turbine buckets, low-pressure wheels, and high-pressure rotors. This inspection consists of visual, surface, and volumetric examinations, as indicated below:
A. A thorough volumetric examination of all low pressure wheels, including areas immediately adjacent to keyways and ,
bores, is conducted. ,
B. Visual examination of all accessible surfaces of rotors and wheels.
C. Visual and surface examination of all low pressure buckets.
D. 100% surface examination of couplings and coupling bolts.
The in-service inspection of main steam and reheat valves includes the following: j A. Dismantle each main stop valvo, main steam control valve, reheat stop valve and reheat intercept valve at
'v) approximately complete 5-year inspeccion intervals including during visual refuelings.
and surface A
Amendment E 10.2-17 December 30, 1988
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examinations of the valve seats, discs and stems will be O
E conducted. All major valve components will be cleaned, inspected and measured for proper clearance. I B. Main stop, control, and combined intermediate valves are exercised at least once a week by closing each valve and j observing by the valve position indicator that it moves i smoothly to a fully closed position. At least once a month, i this observation is made by actually watching the valve .
motion. l The extraction check valves will be tested to assure that each valve is capable of being actuated by its power cylinder and to exercise the mechanism so as to keep it free to move.
The extraction check valves will be tested weekly with the turc>ine on line and loaded.
The turbine system maintenance program described above is based on the manufacturer's calculations of missile generation probabilities.
Under normal operating conditions, there are no radioactive contaminants present. It is possible for this system to become contaminated only through steam generator tube leaks. In this event, radioactivity in the steam is detected and measured by l monitoring condenser air ejector off-gas which is released ;
through the unit vent, and by monitoring the steam generator blowdown samples.
No radiation shielding is required for the components of the turbine generator and related steam handling equipment.
Continuous access to the components of this system is possible during normal condjtions.
The turbine generator is designed and manufactured in accordance with the manufacturer's design criteria and manufacturing practices, procedures, and processes as well as its Qc.ality Assurance Program. National codes are not included since existing national codes do not apply to nuclear turbine generators.
The moisture separator reheaters and drain tanks are designed and constructed to ASME Section VIII.
The orientation of the turbine and the fact that Category I st1uctures are designed to withstand turbine missiles provide additional assurance that safety-related structures and components will not be affected in the extremely unlikely event a turbine missile is generated. Further analysis of turbine missiles is provided in Section 3.5.
l Ameniment E 10.2-18 December 30, 1988
CESSAR n!'ancoic, j 10.2.5 INSTRUMENTATION APPLICATION E The turbine generator is.provided with a full range of standard turbine supervisory instruments which indicate and record the operation of the unit. This instrumentation, however, is not cafety related.
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Amendment E 10.2-19 December 30, 1988
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1 10.3 MAIN STEAM SUPPLY SYSTEM 10.3.1 DESIGN BASES A A. The Main Steam Supply System is designed to:
- 1. Deliver steam from the secondary side of the NSSS steam generators to the turbine generator.
- 2. Dissipate heat during the initial phase of plant cooldown.
- 3. Dissipate heat from the RCS following a turbine an'/ord reactor trip.
- 4. Dissipate heat when the main condenser is not available.
I
- 5. Provide steam for:
- a. Main feedwater pump turbines j l
- b. Emergency feedwater pump turbines b
h c. Condenser steam air ejectors
- d. Turbine gland seals
- e. Miscellaneous auxiliary equipment
- f. Feedwater heaters
- g. Steam reheaters
- 6. Isolate the NSSS steam generators from the remainder of the main steam system when necessary (including containment isolation, post-LOCA). )
- 7. Provide adequate overpressure protection for the NSSS steam generators and main steam system.
- 8. Conform to applicable design codes.
- 9. Permit visual inservice inspection.
- 10. Adequately cover the environmental operating conditions for the system and be thermally insulated to protect personnel, adjacent equipment, and conserve energy. <
O i
() B. The safety-related portion of the main steam system is that portion between the steam generators down to and including the main steam isolation valves.
Amendment A 10.3-1 September 11, 1987
CESSARn h .
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10.3.2 SYSTEM DESCRIPTION 0'
Steam is generated in two steam generators by heat transferred A from the Reactor Coolant System to the feedwater. Steam for the steam-driven emergency feedwater pumps is taken from either of the two steam generators via two of the four main steam lines at a point outside of containmt . and upstream of the main steam isolation valves (MSIVs).
High pressure steam from the high pressure turbine is used to l heat the feedwater in the high pressure feedwater heaters. Lower pressure steam from the low pressure turbines is used to heat the feedwater in tha low pressure feedwater heaters.
Five ASME Code spring loaded secondary safety valves are provided for each individual main steam line for protection against j J
overpressurization of the shell side of the steam generators and the main steam line piping up to the inlet of the turbine stop l l valve.
An atmospheric steam dump valve is provided on each main steam line downstream of the safety valves and upstream of the MSIVs.
Each main steam line is provided with an isolation valve for ,
positive isolation against forward steam flow and isolation ;
against reverse flow. The MSIV on one of the two lines from each steam generator is provided with a bypass around it for warm-up of the steam lines downstream of the isolation valves and i pressure equalization prior to admitting steam to the turbino. I Downstream of the MSIVs are eight power-operated bypass valves to bypass steam to the condenser. These valves comprise the Turbine Bypass System, which is discussed in Section 10.4.4. Each of the four main steam lines is provided with a turbine stop valve and a turbine control valve to shutdown and control the turbine.
l The following standardized functional descriptions and requirements present the system configuration necessary to meet the tJuclear Power Module (NPM) licensing, safety, and reliability i l requirements.
l
[
l A listing of the principle data for the Main Steam System is provided in Table 10,3.2-1.
10.3.2.1 Sy_ stem Performance A
A. The main steam piping, its isolation valves, all steam branches, their isolation valves, and all associated supports from the steam generators up to and including the required isolt.tjon valves are Seismic Category I, and are designed in accordance with the requirements of Section III Amendment E 10.3-2 December 30, 1988 l
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CESSAR 8Mnric 1,tu O
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N of the ASME Boiler and Pressure Vessel Co6e, Class 2. The A remaining steam piping is in accordance with ANSI-B31.1.
The steam piping and supports are designed. so that any single adverse event, such as a ruptured main steam line or a closed isolation valve, can occur without:
- 1. Initiating a loss-of-coolant incident.
- 2. Causing failure of any steam _ lines, Main Steam Isolation Valves (MSIV), Main Feed Isolation Valves (MFIV), Safety Valves, Atmospheric Dump Valves, or any feedwater line required for controlled cooldown of the unaffected steam generator.
- 3. Preventing the Reactor Protective System and Engineered Safety Features Actuation systems from initiating !
proper safety actions.
4 .. Transmitting excessive loads to the containment {
pressure boundary.
- 5. Compromising the function of the plant control room.
l 6. Precluding an orderly cooldown of the RCS.
J The design pressure, temperature and flow rating of the main B. l' steam piping and valves are greater than or equal to the design pressure, temperature and flow rating of the steam generator secondary side.
l 10.3.2.2 System Arrangement A. All valves in the main steam lines outside of containment up to and including the MSIVs are located as close to the containment wall as practical.
B. The main steam lines are headered tcgether prior to the Turbine Stop Valves but not upstream of the MSIVs, and a cross-connect line is arranged such that the pressure drops between each steam nozzle and the main steam cross-connect line are approximately equal. Specifically, the difference between steam line pressure drops shall be within:
- 1. 1 psi for 0-15% power operation.
- 2. 3 psi for 15%-100% power operation.
- 3. Less than 30 psi for transient conditions of no greater C\ than 1 minute duration.
Amendment A 10.3-3 September 11, 1987
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CESSAREniN m l l
l The cross-connection is sized to allow full closure, at 90% A O a i
power, of one of the high-pressure turbine stop valves without imposing a severe pressure / load transient on one of the steam generators.
1 C. There are no isolation valves in the main steam lines between the steam generators and the Secondary SafetV Valves. The steam line AP between the steam generator and the safety valves is minimized.
D. The MSIVs, the Secondary Safety Valves, the Atmospheric Dump ,
Valves, and the MSIV Bypass Valves are protected against the l cffects of missiles, steam and pipe whip such that these l events cannot prevent the valves from performing their required safety function.
E. The Secondary Safety Valves are installed in accordance with the applicable provisions of the ASM2 Boiler and Pressure Vessel Code Section III-Division 1, Nuclear Power Plant Components (Subsection WC-Class 2 Components).
F. The Secondary Safety Valve discharge piping is arranged and supported such that the limiting loads are not exceeded for normal and relieving conditions.
G. In the combined event of a steam line break and the loss of power or a steam generator tube rupture and loss of power, personnel access to the manual operator of the intact Atmospheric Dump Valves on the intact steam generator is possible.
11 . Each automatically actuated valve, located upstream of the MSIVs, will close on a main steam isolation actuation signal except as required for the steam-driven emergency feedwater pugps. The maximum allowable flow rate per line is 1.9 x 10 lb/hr.
I. The system piping is designed to allow cleaning for the ;
removal of foreign material and rust prior to operation and '
to prevent introduction of this material into the turbine.
Chemical cleaning or hand cleaning may be employed. During !
1 chemical cleaning, no fluid can enter the nt oam generators.
Suitable bypass piping is provided where applicable. {
J. Emergency feedwater pump turbine steam supplies are taken off the main steam lines upstream of the Main Steam Isolation Valves. ,
K. Main feedwater pump turbine steam supplies are located on ;
the downstream side of the Main Steam Isolation Valves. ;
Amendment A !
10.3-4 September 11, 1987 l l
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CESSARnnLm, 1 1
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t V paths L. Following a steam line la reak , either all steam A ;
downstream of the MSIVs are shown to be isolated by their j respective control systems following an MSIV Actuation '
l Signal, or the results of a blowdown through a non-isolated path are shown to be acceptable. An acceptable maximum steam flow from a non-isolated steam path is 10% of Maximum Steam Rate * . It is not required that the control systems I for downstream valves nor the dounstream valves themselves I be designed to ASME Code,Section III, Seismic Category I, I IEEE Standard 279 or IEEE Standard 280 Criteria.
I M. The Main Steam Safety Valves are arranged su6h that any l condensate in the line between the safety valves and main ]
l steam line drains back to the main steam line. l l
N. The main steam piping is arranged to minimize the number of !
low points.
O. The pressure drop at the maximum guaranteed steam flow ;
rate does not cause the inlet moisture level at the turbine stop valve to exceed 0.5%, or a thermal analysis of the steam system is performed and the calculated moisture level at the turbine stop valve is acceptable to the turbine vendor.
[
v The drainage system for main steam piping is designed to P.
remove water prior to and during initia. rolling of the turbine and during shutdown. Drain system flow velocity does not exceed 10 ft/sec.
- 1. A drain is located at each low point in the main steam piping system where water may collect during startup, shutdown, or normal operation of a unit. The position of the pipin~ in both hot and cold conditions is considered. ir long runs of piping with no special low point, a low 1 int drain is installed at the turbine end of the section. If the main steam line is split into more than one lead going into the turbine, then each of tnese leads and the main header are reviewed for low points. The low point drain consists of a drain pot with a minimum diameter of 12 inches.
- 2. Low point drains are provided upstream of each of the Main Steam Isolation Valves.
6
- 19 x 10 lb/hr 9 1000 psia saturated steam.
Amendment A 10.3-5 September 11, 1987
m 3
CESSARUnamu l l
- 3. The routing of drain piping is downward, and the slope A O
of all horizontal pipes in the direction of the flow is j downward at a minimum of 1/8 inch per foot of pipe.
- 4. Main Steam System drains are routed to the condenser.
S. Main Steam System drains are not connected to manifold serving drains from sources downstream of the turbine j throttle valve. 1 I
- 6. Two valves are installed in series in each drain line. I One of these valves is pneumatically operated and j arranged to fail open. This valve is located as close ]
as possible to the main steam header or lead to reduce 1 the amount of water trapped upstream of the closed l drain valve. The second valve is manual and locked )
open.
l l 7. Traps are not used for drains essential to system i operation unless they are used in conjunction with a j fully automatic redundant drain system.
- 8. All Main Steam System drain lines and valve ports have a minimum inside diameter of one inch to minimize the l risk of plugging by foreign material.
- 9. Safety-related Main Steam System drains, located in the region from the steam generator to the MSIV, are i provided with remote motor-operated valves.
Non-safety-related Main Steam System drains, MSIV to turbine generator, are automatically operated.
Q. The Main Steam Isolation valves for each steam generator are arranged such that a maximum of 2,000 cubic feet (total for two steam lines per steam generator) is contained in the piping between each steam generator and its associated MSIVs. This volume includes all lines off of the main steam line up to their isolation valves.
R. The main steam lines are arranged such that a maximum of 14,000 cubic feet is contained between the MSIVs and the Turbine Stop Valves. This volume includes all lines off of the main steam line up to their isolation valves.
S. A discharge connection is provided on the steam generator main steam line to allow venting of nitrogen gas during steam generator fill operations while still maintaining a pressure of about 5 psig in the steam generator.
O Amendment A 10.3-6 September 11, 1987
m CESSAREna mu l
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A 10.3.2.3 Piping, Valve, I & C, and Insulation )
10.3.2.3.1 Piping i
A. The main steam piping and its supports and restraints are designed to withstand loads arising from the various operating and design bases events specified in Section i 3.9.3. l l
B. The attachment of the main steam piping to the steam generators is designed such that the maximum permissible l I
nozzle loadings are not exceeded.
C. Every effort is made to avoid the use of construction materials or protective coatings containing low melting point elements, particularly lead, mercury and sulfur, where a these materials may be in contact with the secondary steam l system. This is required to reduce to a minimum the j potential for stress corrosion cracking of Inconel material in the steam generators.
O D. The flow area of the main steam piping is sufficient to keep j p steam velocity below 150 ft/sec. j E. Main steam piping layouts that result in 90-degree elbow and miters are minimized.
F. The main steam piping material is carbon steel. )
G. Provisions are made for conveniently supporting the deadweight loads imposed during hydrostatic test of the main steam piping.
10.3.2.3.2 Valves 10.3.2.3.2.1 Main Steam Isolation Valve (MSIV) and MSIV Uypass valve A. The MSIV is an air-operated y-globe valve.
B. The valves are designed so that no damage due to excessive closure force is incurred during closure under design conditions.
C. Backseating of valve stems is provided when the valve is in the full open position.
D. Unrecovered pressure loss from valve inlet to valve outlet O at rated flow with the valve full open does not exceed 2 psid.
Amendment A 10.3-7 September 11, 1987 1
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CESSAREMUncmu i O1 1 E. The Main Steam Isolation Valve (MSIV) in each main steam I line is remotely operated and is capable of maintaining A tight shutoff under the main steam line pressure, temperature and flow resulting from the transient conditions l
associated with a pipe break in either direction of the I valves. !
F. The MSIV leak flow does not exceed 0.001% of nominal flow at l l 1200 psia in the forward direction and does not exceed 0.1%, I of nominal flow at 1200 psia in the reverse direction. ;
I G. The full open to close stroke time of the MSIVs and the MSIV E l bypass valves are 5 seconds or less upon receipt of a Main {
Steam Isolation Signal (MSIS). {
4 A
l 11 . The MSIVs are supported such that the valve body and l actuator will not be distorted to such a degree that the l
valve cannot close or be displaced as a result of pipe break l l thrust loadings. ]
l I. The MSIVs and the MSIV bypass valves are designed, l fabricated and installed such that the requirements for l In-service Testing and Inspection of ASME Section XI, i Subsection IWV can be met. J J. The provisions of General Design Criteria 54 and 57 for containment isolation valves are met. !
l K. The MSIV is a fail close valve; upon receipt of a Main Steam j Isolation Signal the MSIV closes automatically, i L. The MSIV bypass valve is a fail close, power operated valve. f M. The MSIVs and their supports and the MSIV bypass valves and their supports are designed to withstand loads arising from l the various operating and design bases events as specified j in Section 3.9.3. l N. No single MSIV bypass valve 6 r MSIV bypass line has a !
capacity greater than 1.9 x 10 lb/hr of saturated steam at ;
1000 psia. i i
O. The MSIV and MSIV bypass valves are classified " active" and !
conform to design requirements meeting the intent of ;
NUREG-0800. j i
O' Amendment E 10.3-8 December 30, 1988
CESSAR n!Mncuiu 1
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C/ i Main Steam System Safety Valves A 10.3.2.3.2.2 A. Each main steam line is provided with ASME Code, ;
spring-loaded safety valves between the containment and the isolation valves.
B. The total relieving capacity of these valves is equally divided between the main steam lines and is based on the ASME Boiler and Pressure Vessel Code,Section III.
1 C. The Main Steam Safety Valves are a proven design and consistently open fully at a pressure within acceptable limits around the set pressure during operability tests. [
The acceptable limits are based on transient analysis and I control system designs.
D. The Main Steam Safety Valves are mounted on separate headers connected to the seismically designed portions of the main steam piping. One header is associated with each main steam l line.
E. The Main Steam Safety Valves and their supports are designed i to withstand loads arising from the various operating and design bases events as specified in Section 3.9.3.
( The piping and valve arrangement minimizes the loads on the F. :
attachment and an analysis confirms the design using ANSI /ASME B.31.1 Appendix 2, "Non-Mandatory Rules for the l Design of Safety Valve Installations." 1 l
G. The opening action of the Main Steam Safety Valve is of a design proven to minimize slight leakage of the valve near i the set pressure (" simmering").
H. Safety valve cet pressure is calculated in accordance with Article NC-7000 of ASME Section III. The following is included:
- 1. A maximum allowable pressure of 110% of steam generator design pressure (1200 psia) which equals 1320 psia.
- 2. A valve accumulation of 3%.
- 3. A valve set pressure tolerance of 1%.
- 4. Incorporation of the AP between the steam generator nozzles and the safety valves.
/ I. The total secogdary safety valve capacity is sufficientplus to C pass 19 x 10 accumulation.
lb/hr at the maximum set pressure E Amendment E 10.3-9 December 30, 1988
1 l
CESSAR EnL"lCATISN J. The maximum steam f36 w per secondary safety valve is no OA greater than 1.9 x 10 lb/hr at 1000 psia.
K. The Main Steam Safety Valves are designed, fabricated and installed such that the requirements for In-service Testing and Inspection of ASME Section XI, Subsection IWV can be j met. i L. The Main Steam Safety Valves are classified " active" and shall conform to design requirements meeting the intent of NUREG-0800.
10.3.2.3.2.3 Main Steam Atmospheric Dump Valves (ADVs)
A. Each main steam line is provided with one modulating atmospheric dump valve. This valve is designed to maintain the steam pressure below the lowest setting of the main steam safety valves during emergency shutdowns or plant hot standby conditions. Each valve is capable of holding the plant at hot standby, dissipating core decay and Reactor Coolant Pump heat, and allowing controlled cooldown from hot standby to Shutdown Cooling System initiation conditions. I Each valve is sized to allow a controlled plant cooldown in the event of a line break or tube rupture, which renders one ,
steam generator unavailable for heat removal, concurrent I with a loss of normal AC power and single active failure of I one of the remaining two ADVs. For the preceding .
conditions, site boundary radiation dose limits are not l exceeded. To accomplish the above, each ADV has sufficient capacity to meet the saturated steam flow conditions shown in Figure 10.3.2-1. An ADV with a saturated steam capacity of not less than 950,000 lb/hr at 1000 psia (critical flow assumed) satisfies the steam flow requirements over the range of inlet pressures shown in Figure 10.3.2-1. Also, ng single valve has a maximum capacity greater than 1.9 x 10 lb/hr at 1000 psia.
The valves are manually operated from the main control room or the remote shutdown panel. They fail closed on a loss of electrical power or control signal. Spurious opening of any one valve does not compromise reactor safety requirements.
B. During pre-core hot functional testing, the plant must be maintained at standby conditions. To accomplish this, each Atmospheric Dump Valve is capable of controlling flow at 63,000 lb/hr at 1100 psia.
l C. The valves are mounted on separate headers connected to the seismically designed portions of the main steam piping. One i header is associated with each main steam line. One valve l
Amendment A 10.3-10 September 11, 1987 L_______________ . _ _ _ _ _
CESSAREnnnc- t
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is mounted on each header along with ASME Section III code A safety valves. The' headers are horizontal with the valve mounted vertically upward. The valves vent directly to the atmosphere, with a separate vertical vent stack provided for ,
each valve. ]
l D. The piping and valve arrangement minimizes the loads on the attachment, and analysis is performed to confirm the design using ASME/ ANSI B.31.1 Appendix 2, "Non-Mandatory Rules for the Design of Safety valve Installations."
The ADVs and their supports are designed to withstand loads arising from the various operating and design bases events i as specified in Section 3.9.3. l E. The ADVs are of a design providing for quick change trim, i.e., the- valve internals are designed for removal for maintenance without removing the valve from the line.
F. Block valves or isolation valves are provided in the steam line for each Atmospheric Dump Valve. The block valves are l locked open from the Main Control Room and are capable of j being remotely and manually positioned from the Main Control 1 Room or from the Remote Shutdown Panel to isolate the
(
( Atmospheric Dump Valves.
G. The ADVs are provided with accessible handwheels such that each valve may be hand operated in the event of a loss of the normal power supply.
H. The ADVs are designed, fabricated and installed such that the requirements for In-service Testing and Inspection of ASME Section XI, Subsection IWV can be met.
I. The ADVs are classified " active" and conform to design I requirements meeting the intent of NUREG-0800.
10.3.2.3.3 Instrumentation and Control The control system minimizes the number of instrumentation control functions and control loops required to perform the essential control functions. Further, the number of different types of instrumentation and control components used in the system is minimized and coordinated with the remainder of the plant to reduce the maintenance effort and the number of spare parts which must be stocked.
Each subsystem automatic control loop, such as the controls for the bypass valves is analyzed to establish that it meets its Q functional requirements and has adequate stability margin.
Amendment A 10.3-11 September 11, 1987
CESSAR nn!Picari:n A
10.3.2.3.3.1 Main Steam Isolation h lves (MSIVs) l A. Control of the main steam isolation rd.ves is accomplished l by a separate system independent of the protection system.
B. Operator interface to the isolation valve is provided ,
locally, in the Main Control Room (MCR) and at the Remote l Shutdown Panel (RSP). The following are provided:
- 1. The capability to manually open and close the valve.
- 2. The capability to test the valve operation (MCR only).
- 3. Valve position indication (open/close indicating lights).
C. The MSIVs are interlocked to close upon initiation of a main steam isolation signal (redundant).
I D. Each Main Steam Isolation Valve (MSIV) has two physically separate and electrically independent closure solenoids in order to provide redundant means of valve operation. A MSIS "
Actuation Signal is provided to each solenoid.
E. An electrical or mechanical malfunction of one solenoid does not prevent the MSIV from closing.
1 F. The MSIV bypass valve control circuits are designed, or )
precautions are taken, such that no single electrical {
failure results in the spurious opening of the valves. j G. No single failure of the control circuits prevents closure of the MSIV bypass valves. The control circuit is designed to the applicable parts of IEEE Standard 279-1971 and IEEE Standard 308-1980. E l H. The available air supply for valve pneumatic operators is 70 psi i minimum to 105 psig maximum. Pneumatic lines and A fit ings are designed for a minimum pressure of 150 psig.
10.3.2.3.3.2 Atmospheric Dump Valves (ADVs)
A. Operator interface to the atmospheric dump valve control system is provided in the Main Control Room (MCR) and at the Remote Shutdown Panel (RSP) . The following are provided:
- 1. The capability to manually close and position the valve.
- 2. Valve position indication (both analog position and open/close indication lights).
Amendment E 10.3-12 December 30, 1988
CESSARM h m.
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B. No single failure of the control circuits prevents operation A of at least one ADV on each steam generator. The control circuits are designed to the applicable parts of IEEE Standard 279-1971 and IEEE Standard 308-1980. l E.
C. A safety-grade air pressure supply shall be provided to operate the ADV actuators should the normal air supply fail A to be available. This safety-grade backup pressure supply may be a nitrogen supply or a Type A source of air, as defined in ANS 59. . .'N187 (1984), " Safety Criteria for Control Air Systems.."
10.3.2.3.4 Insulation A. Non-metallic insulation conforms to NRC Regulatory Guide 1.36. The chloride and fluoride content of the non-metallic '
insulation are acceptable as shown in Regulatory Guide 1.36.
Tests are made on representative samples of the non-metallic thermal insulation to certify that the maximum chloride and fluoride contents are not exceeded. All water used in the ;
fabrication of non-metallic thermal insulation is !
demineralized or distilled water. l i B. The insulation thickness is selected to minimize the heat
,b load on the containment ventilation and cooling system. A l of not more than 0.14 thermah Btu-hr - *Fyansfgrence
-ft of insulated component surface area is used as a design basis for insulation. 1 l
l l
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i Amendment E 10.3-13 December 30, 1988
CESSAR nuirication i
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O Amendment E >
10.3-14 December 30, 1988
- hh E r ICATICN j-TABLE 10.3.2-1 (Sheet 1 of 2) E l
MAJN STEAM SUPPLY SYSTEM DESIGN DATA Component Parameter l Main Steam Piping:
Steam flow, lb/hr 17.12 x 10 Number of main steam lines 4 Pipe size, O.D. inches 28 Design pressure, psia 1200 Design temperature, *F 570 Pipe material carbon steel Main Steam Isolation Valves:
1 Number por main steam line 1 Total number required 4 Atmospheric Dump Valves:
Number per main steam line 1 Total number required 4 6
Design relieving capacity per valve, 1,39 x 10 100% open, lb/hr (at 1,000 psia)
Controllable capacity per valve, 63,000 lb/hr (at 1,100 psia)
O Amendment E December 30, 1988
1 l
CESSAR EEnnCATl?iN O
TABLE 10.3.2-1 (Cont'd)
E (Sheet 2 of 2) !
1 MAIN STEAM BUPPLY SYSTEM DESIGN DATA Component Parameter Main Steam Safety Valves:
Number per main steam line 5 Set pressure, psia No. 1 1200 No. 2 1235 No. 3 1260 No. 4 1260 No. 5 1260 Orifice size, in 2 l
No. 1 16.0 .
No. 2 16.0 No. 3 16.0 No. 4 16.0 1 No. 5 16.0 Inlet / outlet size, in/in j No. 1 6 x 10 l No. 2 6 x 10 (
No. 3 6 x 10 1 No. 4 6 x 10 ;
No. 5 6 x 10 !
6 Relieving capacity, per valve, lb/hr 0.95 x 10 l l
Total relieving capacity (20 valves), lb/hr 19 x 10
(
Total number required 20 l
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Amendment E December 30, 1988 l
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x M l r - - -
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=! 2.0 - -
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I $ 1.0 - - l sm I I I f I I 0 200 400 600 800 1000 1200 1400 INl.ET PRESSURE (PSI A) i l
Amendment A September 11, 1987 Figure gg f ATMOSPHERIC DUMP VALVE FLOW REQUIREMENTS 10.3.2 1 l
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CESSAR nainc-n I
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A 10.3.3 SAFETY EVALUATION A. A failure of any main steam line or malfunction of a valve i in the system will not:
- 1. Reduce flow capability of the Emergency Feedwater System below the minimum required.
- 2. Prohibit function of an Engineered Safety Feature.
- 3. Initiate a Loss-Of-Coolant-Accident.
- 4. Cause uncontrolled flow from more than one steam generator.
- 5. Jeopardize containment integrity.
B. The Main Steam System delivers the generated steam from the outlet of the steam generators to the various system components throughout the Turbine Building without incurring excessive pressure losses. Steam is generated at essentially dry and saturated conditions. Functional requirements of the system are as follows:
5
- 1. Achieve minimum pressure drop between the steam generators and the turbine steam stop valves.
- 2. Assure similar conditions between each steam stop valve and between each steam generator.
- 3. Provide adequate piping flexibility to accommodate thermal expansion.
- 4. Assure adequate draining provisions for startup and for operation with saturated steam.
C. Safety-related portions of the Main Steam System are contained in Seismic Category I structures and are designed and located to protect against environmental hazards such as wind, tornadoes, hurricanes, floods, missiles, and the effects of high and moderate energy pino. rupture as detailed in Chapter 3.
10.3.4 INSPECTION AND TESTING REQUIREMENTS ,
A. ASME Section III Code, Cl tas 2 piping is inspected and tested in accordance with ASME Code Section III and XI.
s ANSI B31.1 piping is inspected and tested in accordance with Paragraphs 136 and 137. Non-safety Class piping is E v
}
Amendment E 10.3-15 December 30, 1988
l CESSAREinibmu inspected in accordance with a program similar to the l E l program outlined in report EPRI NP-3944, " Erosion / Corrosion in Nuclear Plant Steam Piping: Causes and Inspection Guidelines."
B. To permit testing for pH and the existence of foreign l substances,_ sample connections are provided in the steam A j line piping between the steam generator nozzles and equalization header.
C. During initial startup and during periods of unit shutdown, the tripping mechanisms for the main steam isolation valves are tested for proper operation in accordance with the technical specifications. The valves are periodically inservice tested for leakage and freedom of movement during plant operation in accordance with ASME Code Section XI, subsection IWV.
D. The secondary safety valves are tested during initial startup or during shutdown operation by checking the actual lift and closing pressures of the valves in comparison to the required design opening and closing pressures in accordance with ASME Code,Section XI, Subsection IWV.
E. ASME Code Section XI, Subsection IWV requirements for in-service testing and inspection of nuclear safety-related valves apply to the atmospheric dump and atmospheric dump isolation valves.
10.3.5 SECONDARY WATER CHEMISTRY 10.3.5.1 Chemistry Control Basis Steam generator secondary side water chemistry control is accomplished by:
A. Close control of the feedwater to limit the amount of impurities which can be introduced into the steam generator.
B. Continuous blowdown of the steam generator to reduce the concentrating effects of the steam generator.
C. Chemical addition to establish and maintain an environment which minimizes system corrosion.
D. Preoperational cleaning of the feedwater system.
E. Minimizing feedwater oxygen content prior to entry into the steam generator.
Amendment E 10.3-16 December 30, 1988
~
1 1
CESSARn!MN - 1 O Secondary. water chemistry is based on the zero solids treatment j
method. This method employs the use of volatile . additives to maintain system pH and to scavenge dissolved oxygen which may be present in the feedwater. ,
l A neutralizing amine is added to establish and maintain alkaline I
conditions in the feedtrain. Neutralizing amines which can be used for pH control are ammonia, morpholine, and cyclohexylamine.
Ammonia should be used in plants employing condensate polishing to avoid resin fouling. Although the amines are volatile and will not concentrate in the steam generator, they will reach an equilibrium level which will establish an alkaline condition in the steam generator.
Hydrazine is added to scavenge dissolved ' oxygen which may ne present in the feedwater. Hydrazine also tends to promote the )
formation of a protective oxide layer on metal surfaces by keeping these layers in a reduced chemical state.
4 Both the pH agent and hydrazine can be injected continuously at the discharge headers of the condensate pumps or condensate domineralizer, if installed. These chemicals are added as necessary for chemistry control, and can also be added to the O upper steam generator feed line when necessary.
Operating chemistry limits for secondary steam generator water, r
i foodwater and condensate are given in Tables 10.3.5-1, 10.3.5-2 E l and 10.3.5-3. l 3
The limits stated are divided into three groups: normal, abnormal ,
and immediate shutdown. The limits provide high quality chemistry control and yet permit operating flexibility. The normal chemistry conditions can be maintained by any plant operating with little or no condenser lc.akage . The abnormal steam generator limits are suggested to permit operations with minor system fault conditions until the affected component can be isolated and/or repaired. The immediate shutdown limits E represent chemistry conditions at which continued operation could result in severe steam generator corrosion damage.
The following procedures are recommended for protection against A secondary system and steam generator corrosion:
i l A. When the normal range is exceeded, immediate investigation l-of the problem should be initiated, sampling frequency increased to the abnormal level (at least twice per 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> shift) and blowdown increased to one percent of the main steaming rate. The problem should be corrected and the parameter (s) returned to the normal' range within one week.
Amendment E 10.3-17 December 30, 1988
CESSAREnac-and the parameter has a listed O
If this cannot be done, abnormal range, power should be reduced as if the abnormal range had been exceeded.
E B. When the abnormal range is exceeded, power should be reduced to the lowest value (typically 25% or less) consistent with automatic operation of the feed system. Continued plan't operation is then possible while corrective action is taken.
Power reduction should be initiated within four hours of exceeding the abnormal range. The problem should be corrected and the parameter (s) returned to the normal range within one hundred hours. If this cannot be done, the unit l should be shut down. When an immediate shutdown limit i,s E exceeded, the unit must be shut down within four hours to prevent rapid steam geiz:.rator corrosion.
C. Draining or flushing of the steam generators will be necessary to reduce the impurity concentration.
10.3.5.2 Corrosion Control Effectiveness Alkaline conditions in the feed train and the steam generator reduce general corrosion at elevated temperatures and tend to i decrease the release of soluble corrosion products from metal i surfaces. These conditions promote the formation of a protective j metal oxide film and thus reduce the corrosion products released into the steam generator.
Hydrazine also promotes the formation of a metal oxide film by the reduction of ferric oxide to magnetite. Ferric oxide may be loosened from the metal surfaces and be transported by the feedwater. Magnetite, however, provides an adherent protective layer on carbon steel surfaces.
The removal of oxygen from the secondary water is also essential in reducing corrosion. Oxygen dissolved in water causes general corrosion that can result in pitting of ferrous metals, particularly carbon steel. Oxygen is removed from the steam cycle condensate in the main condenser deaerating section and by A the full flow feedwater deaerator which is a portion of the low pressure feedwater heaters. Additional oxygen protection is obtained by chemical injection of hydrazine into the condensate stream. Maintaining a residual level of hydrazine in the feedwater ensures that any dissolved oxygen not removed by the main condenser is scavenged before it can enter the steam
- generator.
O Amendment E 10.3-18 December 30, 1988
CESSARnn%me.
~
The presence of free . hydroxide (OH ) can cause rapid corrosion (caustic stress corrosion) if it is allowed to concentrate in a Free hydroxide is avoided by mainuining proper pH local area.
control, and by minimizing impurity ingress in the steam generator.
Zero solids treatment is a control technique whereby both soluble and insoluble solids are excluded from the steam generator. This is accomplished by maintaining strict' surveillance over the ;
possible sources of feed train contamination (e.g., Main Condenser cooling water leakage, air inleakage and subsequent corrosion product generation in the Low Pressure Drain System.
Solids are also excluded, as discussed above, by injecting only volatile chemicals to establish conditions which reduce corrosion and, therefore, reduce the transport of corrosion products into the steam generator. Reduction of solids in the steam generator can also be accomplished through the use of full flow condensate demineralization.
In addition to minimizing the sources of contaminants entering the steam generator, continuous blowdown is employed to minimize their concentration. q The systems, condensate cleanup and blowdown, are discussed in E U Sections 10.4.6 and 10.4.8. With the low solid levels, which .I result from employing the above procedures, the accumulation of j corrosion deposits on steam generator heat transfer surfaces and A internals is limited. Corrosion product formation can alter the thermal-hydraulic performance in local regions to such an extent that deposits create a mechanism which allows impurities to concentrate to high levels, and thus could possibly cause corrosion. Therefore, by limiting the ingress of solids into the steam generator, the effect of this type of corrosion is reduced.
Because they are volatile, the chemical additives will not' concentrate in thn steam generator, and do not represent chemical impurities which can themselves cause corrosion.
Amendment E l 10.3-19 December 30, 1988
"5 'a" CESSAR CERTIFICATION O!
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Amendment E 10.3-20 December 30, 1988
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TABLE 10.3.5-1 OPERATING CHEMISTRY LIMITJ FOR SECONDARY STEAM GENERATOR WATER Normal I} Abnormal Variable Specifications Limits A
pH (mixed system)I ) 8.5 - 9.0 (copper free) 9.0 - 9.5( )
Cation Conductivity (3) s 0.8 pmhos/cm 0.8-2.0 pmhos/cm Silica 5 300 ppb E l
Chloride 1 20 ppb 20-100 ppb Sodium (4) $ 20 ppb 20-100 ppb Sulfate 5 20 ppb f
())
NOTES:
(1) Normal specifications are those which should be maintained by continuous steam generator blowdown during proper operation of secondary systems.
(2) A mixed system is any secondary system containing copper alloy components.
(3) If the immediate shutdown limit of 7.0 pmhos/cm is exceeded, the unit should be shut down within four hours.
(4) If the immediate shutdown limit of 500 ppb is exceeded, the unit should be shut down within four hours.
(5) In plants where condensate polishers are in operation, the pH of a copper-free system can be controlled to a value of 2 A 8.8, with action required at < 8.8.
O l
Amendment E December 30, 1988
CESSAR E!!DICATitN o
TABLE 10.3.5-2 E
OPERATING CHEMISTRY LIMITS FOR FEEDWATER Normal I}
Variable Specifications pH
- a. Mixed system 8.8 - 9.2
- b. Copper-free system 9.3 - 9.6(3).
Conductivity (Intensified cation)(4) $ 0.2 pmhos/cm Hydrazine 2 20 ppb Dissolved Oxygen s 5 ppb Sodium (4) $ 3 ppb
,- s Iron s 20 ppb Copper (2) s 2 ppb NOTES:
(1) Normal specifications are those which should be maintained during proper operation of secondary systems.
l (2) Analysis not required for copper-free systems.
(3) In plants where condensate polishers are in operation, the pH of a copper-free system can be controlled to a value of
> 9.0, with action required at < 9.0.
(4) Conductivity and sodium are diagnostic parameters. These values were set as a means of addressing steam purity concerns. It is realized that lower values will'be needed to meet blowdown limitations in Table 10.3.5-1. Feedwater sodium values of <<1 ppb are required to meet steam generator water quality. Likewise, cation conductivity values <<0.2 are generally required to meet steam generator water quality.
Amendment E December 30, 1988
I I
- h E ICATICN
('~N_;) "
I TABLE 10.3.5-3 OPERATING CHEMISTRY LIMITS FOR CONDENSATE Normal ( }
Variable Specifications Dissolved Oxygen (2) < 10 ppb l
NOTES: (1) Normal specifications are those which should be maintained di 'ing proper operation of secondary systems at >' power.
(2) The condensate abnormal limit is 10-30 ppb, but
( the requirement for immediate-shutdown does not
\ apply even if the problem is not corrected within 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br />.
1 i
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Amendment E December 30, 1988
C E S S A R 8lMinc m u
?
U 10.3.6 STEAM AND FEEDWATER SYSTEM MATERIALS Fracture Toughness l 10.3.6.1
^ )
Materials ~are in compliance with Sections II and III of the ASME 1 Boiler and Pressure Vessel Code with respect to fracture toughness and meet the requirements of ASME Section III, articles MB-2300, NC-2300, and ND-2300.
10.3.6.2 Materials Selection and Fabrication A. Materials used are included in Appendix I of Section III of ,
the ASME Code. I l
B. No austenitic stainless steel piping material is used in j these systems.
C. Cleaning and acceptance criteria are based on the requirements of ANSI N45.2.1-73 and the recommendations of NRC Regulatory Guide 1.37.
D. Low-alloy steels are not used in the systems for piping materials. i (j E. The degree of compliance with NRC Regulatory Guide 1.71,
" Welder Qualification for Areas of Limited Accessibility,"
3 is discussed in Section 1.8.
F. Non-destructive examination procedures for tubular products conform to the requirements of the ASME Code,Section III, l NC-2000 for Class 2 materials. j G. No copper alloys are used for components that are in contact with feedwater, steam, or condensate. g H. Oxygen induced corrosion is minimized by providing the following component materials:
- 1. Moisture separator reheater tubes that are ferritic stainless steel or equivalent.
- 2. Low pressure feedwater heater tubes that are type 304L stainless steel with 340L-clad carbon steel tube sheets or equivalent.
- 3. High pressure feedwater beater tubes that are type 316L stainless steel with 316L-clad carbon steel tube sheets or equivalent.
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Amendment E l
10.3-21 December 30, 1988 l
o
CESSAR EnflNmu E
- 4. Condenser tube material that is type 304L stainless >
steel or equivalent for fresh water applications with ;
chloride levels below 200 ppm. For higher chloride )
levels up to 500 ppm, type 316L stainless steel tubing or equivalent. For chloride levels between 500 and 800 j ppm, higher grade of stainless steel (such as 904L or i AL-6X, or equivalent). For brackish or salt water I applications containing high concentrations of dissolved solids (greater than 1000 ppm) or chlorides (greater than 800 ppm), or water contaminated by sewage i discharger, titanium tubing or equivalent.
- 5. Condenser tube sheets that are specified as follows:
i
- a. For 304L stainless steel tubes, 304L stainless-clad carbon steel tube sheets or o.quivalent.
- b. For 316L stainless steel tubes, 316L stainless-clad carbon steel tube sheets or equivalent.
- c. For titanium tubing, titanium-clad carbon steel tube sheets or equivalent.
1 i
- 6. Main steam piping, hot reheat piping, condensate l
- piping, feedwater piping, and heater drain piping upstream of the drain control valves that are carbon steel or equivalent. Extraction steam piping, heater drain piping downstream of the drain control valves, and other piping exposed to wet steam or flashing liquid flow that are chrome-moly, stainless steel, or equivalent. The degree of corrosion / erosion resistance of the piping material must be consistent with the temperature, moisture content, and velocity of the steam to which the piping is exposed.
O Amendment E 10.3-22 December 30, 1988
CESSAR 880lCATl:N n
V 10.4 OTHER FEATURES OF STEAM AND POWER CONVERSION SYSTEM 10.4.1 MAIN CONDENSER 10.4.1.1 Design Bases A
A. The main condenser is designed to condense the low pressure turbine exhaust steam so it can be efficiently pumped through the steam cycle. The main condenser also serves as a collection point for the following:
- 1. Feedwauer heater drains and vents.
- 2. Condensate and Feedwater System makeup.
- 3. Condenser steam air ejector inner-condenser drains.
- 4. Miscellaneous equipment drains and vents. !
B. The main condenser is also designed to condense up to 55%
of the full load main steam flow bypassed directly to the condenser by the Turbine Bypass System. The steam is bypassed to the main condenser in case of a sudden load b
V rejection by the turbine generator or a turbine trip, and at plant startup and shutdown as described in Section 10.4.4.
The main condenser hotwells serve as a storage reservoir for the Condensate and Feedwater Systems with sufficient volume to supply maximum condensate flow for 5 minutes. The main condenser is also designed to provide removal of noncondensable gases from the condensing steam by the Main Vacuum System, described in Section 10.4.2. Heat is removed from the main condenser by the Condenser Circulating Water System.
10.4.1.2 System Description E
The following functional requirements are to be met to ensure a reliable system:
A. The condenser is designed in accordance with Heat Exchanger The condenser is a- multi-pressure A Institute Standards.
design, with two or more parallel circulating water flow paths. Tubing is of commercially available lengths. The design does not preclude shop pre-fabrication.
v Amendment E 10.4-1 December 30, 1988
CESSAR!ah mu is as specified in Section O
B. The condenser tube material E 10.3.6.2.
C. Tube gauge with stainless steel is not thinner than 22 BWG.
Tube gauge with titanium is not thinner than 23 BWG. A l Condenser design precludes or minimizes steam impingement ;
forces on the condenser tubes for normal operation and turbine bypass valve quick opening events. Tube support plates are designed to minimize tube vibrations.
Q D. Provisions for chemical injection into the condenser for l biofouling control is included in accordance with site-specific requirements and applicable regulations.
E. Means are provided to protect the tubes from pitting during periods of condenser shutdown.
E F. Tube sheets are specified as stated in Section 10.3.6.2.
G. Double tube sheets or welded tube to tube sheet joints are provided.
' ^
H. Leak detection trays are included at all tube to tube sheet interfaces. Provisions for early leak detection are provided at tube sheet trays and in each hotwell section.
The hotwell is divided into sections to allow for leak detection and location.
I. The condenser is designed to deaerate the condensate during startup and normal operation. The design also deaerates any drains which enter the condenser.
J. The condenser and circulating water system are designed to permit isolation of a portion of the tubes (segmented condenser) to permit repair of leaks and cleaning of water boxes while operating at reduced power.
K. The condenser is capable of being filled with water for hydrotest. Provisions are made to allow draining and cleaning of the hotwell. ,
l L. A stainless steel expansion joint and 'a water seal trough f between the condenser and the turbine are provided.
M. An automatic condenser cleaning system is provided.
N. Heater shells and piping installed in the condenser neck are located outside of the turbine exhaust steam high velocity I regions and within the limits specified by the turbine l
Amendment E l 10.4-2 December 30, 1988
CESSAR E!Nincum
( .
l supplier. Internal piping is as short and straight as A possible and all steam extraction piping slopes downward toward the heater shells.
O. Sections of heater shells and piping that are located inside the condenser and normally operated with a full load inside l te.nperature of about 194*F or more shall be lagged. The l lagging is made of stainless steel at least 1/16-inch thick and is designed consistent with proven practice.
P. The condenser neck fluid design is based on air tests, modelling the steam flow path from the low-pressure turbine exhaust hoods to the condenser tube bundles. The test model accounts for the condenser neck heaters and associated piping and for the neck major structural elements, lines and baffles. The tests cover all major operating modes including operation with steam bypass dump and operation with one tube bundle out of service.
Q. The change in liquid inventory in the steam generators, as plant load changes, is considered in designing the Condensate System and sizing the condenser hotwell. On a l
(qj V
steady state basis, the steam generator mass decreases by approximately 103,540 pounds between o percent percent load.
and 100 E 10.4.1.3 Safety Evaluation 1
The main condenser is normally used to remove residual heat from i the Reactor Coolant System during the initial cooling period l after plant shutdown when the main steam is bypassed to the I condenser by the Turbine Bypass System. The condenser is also used to condense the main steam bypassed to the condenser in the event of sudden load rejection by the turbine generator or a turbine trip.
In the event of load rejection, the condenser will condense 55%
of full load main steam flow bypassed to it by the Turbine Bypass System without tripping the reactor. If the main condenser is not available during normal plant shutdown, sudden load rejection, or turbine trip, the spring-loaded safety valves can discharge full main steam flow to the atmosphere to protect the Main Steam System from overpressure. Safe reactor shutdown may then be achieved by use of the atmospheric dump valves.
Non-availability of the main condenser considered here includes failure of the circulating water pumps to supply cooling water, or loss of condenser vacuum for any reason.
U Amendment E 10.4-3 December 30, 1988
CESSAR 8aMICATI@N During normal operation and shutdown, the main condenser will A O
have no radioactive contamin.Ints inventory. Radioactive contaminants can only be obtained through primary to secondary system leakage due to steam generator tube leak. A discussion of the radiological aspects of primary to secondary leakage, including operating concentrations of radioactive contaminants, is included in Chapter 11. There is no hydrogen buildup ir. the main condenser.
The main condenser is non-safety-related.
10.4.1.4 Tests and Inspections The main condenser is tested in accordance with the Heat Exchanger Institute Standards for Steam Surface Condensers. 4 Proper operation of the system after startup will assure system !
integrity and further testing of components in continuous use will not be necessary. Periodic visual inspections and preventive maintenance are conducted following normal industrial practice. E 10.4.1.5 Instrumentation Application A
All of the instrumentation for this system is operating instrumentation and none is required for safe shutdown of reactor.
the l E 10.4.2 MAIN VACUUM SYSTEM A 10.4.2.1 D_esian Bases The Main 7acuum Syster is designed to: ,
A. Remove air and other noncondensable gases from the condenser. :
i B. Maintain adequate condenser vacuum for proper turbine operation during startup and normal operation. ,
l 10.4.2.2 System Description !
The Main Vacuum System consists primarily of vacuum pumps and steam jet air ejectors (SJAEs) the main condenser. which are used to pull a vacuum on l E There is no direct connection between the Main Vacuum System and A the Reactor Coolant System; therefore, normal function of one l will not di actly affect the other. The SJAE air discharge is continuously monitored for radiation. E 1
Amendment E 10.4-4 December 30, 1988 l
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CESSAR En'iirlCAT13N n
10.4.2.3 Safety Evaluation A
The system is not assigned a safety class as it serves no plant safety function. It is not required for safe shutdown of the ,
I plant.
10.4.2.4 Tests and. Inspections The system is fully tested and inspected before initial plant operation and is subject to periodic inspections after startup.
System performance will indicate proper function of the system and any system malfunction will be corrected by means. appropriate lE 10.4.2.5 ];_n_strument n Application The Main Vacuum System includes sufficient instrumentation to !
assure proper operation. All of the instrumentation for this l system is operating instrumentation and none is required for safe shutdown of the reactor.
E 10.4.3 TURBINE GLAND SEALING SYSTEM 10.4.3.1 Design Bases
,V The Turbine Gland Sealing System (TGSS) serves both the main turbine and the feedwater pump turbines. It is designed to seal the annular openings where the turbine shaft emerges from the turbine shell casings to prevent steam outleakage and air in-leakage along the turbine shaft. The TGSS prevents air leakage and steam leakage through the turbine shaft glands and through various steam valve stems. The TGSS also returns the air-steam mixture to the turbine gland steam packing exhauster/ condenser (GSC), condenses the steam, returns the drains to the main condenser, and exhausts the noncondensible gases to the atmosphere.
10.4.3.2 System Description i~
The TGSS consists of a steam seal supply and exhaust header, gland steam seal feed valve, gland steam packing exhauster/ condenser (GSC), condenser drain hold tank, and the associated piping and valves. For the system to function satisfactorily from startup to full load, a fixed positive j pressure in the steam seal supply header and a fixed vacuum in !
the outer ends in all of the turbine glands must be maintained at all loads. The TGSS also receives steam seal leakoff from !
turbine control valves. l O !
O '
Amendment E 10.4-5 December 30, 1988
CESSARnaama -.
O on cold startup of the steam generators or during emergencies E when the normal steam supply is not available, sealing steam is provided by the auxiliary boiler. The steam discharge ends of all glands are routed to the GSC that is maintained at a slight vacuum by the redundant motor-driven blowers. The GSC is a shell and tube heat exchanger. Water supplied from the turbine cooling water system is used to condense the steam from the mixture of air and steam drawn from the shaft packings. Drains from the GSC are returned to the main condenser, and the noncondensibles are discharged to the atmosphere via the effluent filtration system.
When the steam generator has been brought up to full pressure, the auxiliary steam source is closed and main steam provides sealing. As the turbine is brought up to load, steam leakage from the high-pressure packings enters the steam-seal header.
When this leakage from the high-pressure packings enters the steam-seal header. When this leakage is sufficient to maintain steam-seal header pressure, the main steam source valve is closed, and sealing steam to all turbine seals is supplied from the high-pressure (HP) packings. At higher loads, when more steam is leaking from the HP packings than is required by vacuum packingn, the excess steam is discharged to the main condenser.
In case of a malfunction of the GSC, a motor-operated bypass l valve is opened and manually controlled to maintain steam-seal header pressure. Vacuum in the GSC can be maintained with one or ]
both blowers in operation. Loss of both blowers may cause i sufficient steam to blow through the seals into the turbine area i and thus necessitate shutdown of the turbine. Relief valves on the steam-seal header prevent excessive steam seal pressure. The ,
valves are vented to atmosphere. l l
10.4.3.3 Safety Evaluation The TGSS has no safety function. Turbine Gland Sealing System valves are arranged for fail safe operation to protect the turbine.
10.4.3.4 Tests and Inspections Tests and inspection on the TGSS equipment are performed in accordance with applicable codes and standards. The Turbine Gland Sealing System is functionally tested during unit startup.
Normal operating system performance monitoring detects any deterioration in the performance of system components, which is corrected by appropriate means as necessary.
O Amendment E 10.4-6 December 30, 1988
1 1
CESSAR an@icarian
(
(
10.4.3.5 Instrumentation Applications E Local and control room displays consist of indicating and alarm devices of steam seal header pressure, temperature and flow. All of the instrumentation for this system is operating instrumentation, and none is required for safety shutdown of the reactor.
10.4.4 TURBINE BYPASS SYSTEM
)
10.4.4.1 Design Bases
{
The turbine bypass system has no safety functions. The turbine bypass system, operating in conjunction with the reactor power cutback system (Section 7.7.1.1.6), is designed to accomplish the j following functions:
A. Accommodate load rejections of any magnitude without )'
tripping the reactor or lifting primary or secondary safety valves.
B. Control NSSS thermal conditions to prevent the opening of
, p safety valves following a unit trip.
C. Maintain the NSSS at hot zero power conditions.
D. Control NSSS thermal conditions when it is desirable to have I reactor power greater than turbine power, e.g., during turbine synchronization.
E. Provide pressure limiting control during the loss of one out l of two feedwater pumps. i L
F. Provide a CEA Automatic Motion Inhibit (AMI) signal when !
turbine power and reactor power fall below selected l thresholds. Provide AMI signal below 15 percent reactor power to block automatic control of the reactor below this power level. 4 I
G. Provide a means for manual control of Reactor Coolant System i (RCS) temperature during NSSS heatup or cooldown. l H. Provide for operation of the turbine bypass valves in a manner that minimizes valve wear and maintains controllability. j l
I. Provide for operation of the turbine bypass valves in a i sequence which, by proper applicant arrangement of valving l
\
Amendment E 10.4-7 December 30, 1988 l i
l j
CESSAREnfince flow imbalance between O
to the condenser, limits the condenser shells to the flow capacity of one valve when all turbine bypass valves and condenser shells are available.
J. Include redundancy in the design so that neither a single component failure nor a single operator error result in excess steam release.
K. Provide a condenser interlock which will block turbine bypass flow when unit condenser pressure exceeds a preset limit. E 10.4.4.2 System Description and Operation 10.4.4.2.1 General Description The turbine bypass system consists of the Steam Bypass Control System, the turbine bypass valves and associated piping and instrumentation. The Steam Bypass Control System is described in Section 7.7.1.1.5.
10.4.4.2.2 Piping and Instrumentation A typical turbine bypass system consisting of eight turbine 1 bypass valves located in lines branching from each main steam l line, downstream of the main steam isolation valves and l connecting to the main condenser is shown in Figure 10.1-1. j 10.4.4.2.3 Turbine Bypass Valves l The turbine bypass valves are air operated valves with a combined capacity of 55% of the total full power steam flow at normal full !
power steam generator pressure (1000 psia).. The valves are normally controlled by the steam bypass control system but are l^ l capable of remote or local manual operation. When operating ,
automatically the valves modulate full open or full close in a j minimum of 15 seconds and a maximum of 20 seconds. In response to a quick opening signal from the Steam Bypass Control System, they are designed to open in less than 1 second. In response to lA a closing signal from the steam bypass control system, they are designed to close in 5 seconds. The system is capable of controlling at flows as low as 63,000 lb/hr in order to permit operation at hot standby during pre-core hot functional testing. l 10.4.4.2.4 System Operation l The turbine bypass system takes steam from the main steam lines upstream of the turbine stop valves and discharges it directly to the main condenser, bypassing the turbine generator. During l Amendment E 10.4-8 December 30, 1988
l l
CESSAR Muama '
- n. i U
normal operation, the bypass valves are under the control of-the steam bypass control system, as discussed in Section 7.7.1.1.5.
During cooldown or hot shutdown, the turbine bypass valves may be actuated individually from the main control room to regulate steam generator pressure and reactor coolant temperature change.
10.4.4.2.4.1 System Performance A. The total Turbine Bypass Valve capacity is 55% of total full A power steam flow at normal full power steam generat6r pressure (1000 psia). This relieving capacity in l conjunction with the Steam Bypass Control and Reactor Power Cutback Systems allows a turbine full load rejection without causing a reactor trip or lifting the primary and/or secondary safety valves.
B. No single Turbine gpass Valve has a maximum capacity greater than 1.9 x 10 lb/hr at 1000 psia.
C. Turbine Bypass . Valves are fail close valves to prevent uncontrolled bypass of steam to the condenser.
D. The Turbine Bypass Valve operating speeds are as follows:
(' l. The valves stroke from the full closed position to the full open position and from full open position to full closed position in 15 to 20 seconds when a modulation signal is applied to the valve control system.
- 2. The valves stroke from the full closed position to the full open position in less than 1 second when a quick opening signal is applied to the valve control system.
- 3. The valves stroke from the full open position to the full closed position within 5 seconds when the permissive gating signal is removed from the valve control system.
E. The Turbine Bypass Valves and their supports are designed to withstand loads arising from the various normal operating and design bases events as specified in Section 3.9.3.
F. The as-built pressure drop between the steam generator outlet nozzles and each Turbine Bypass Valve is provided to C-E to evaluate the actual relieving capacity.
G. During pre-core hot functional testing, the plant must be maintained at hot standby conditions. To accomplish this, (n)
(/
at least one Turbine Bypass valve is capable of controlling flow at 63,000 lb/hr at 1100 psia.
l Amendment A 10.4-9 September 11, 1987
l CESSAR naincum l
H. The Turbine Bypass Valve control circuits are designed, or 9
precautions are taken, such that no single electrical A failure results in the opening of more than one valve.
I. The Turbine Bypass Valves should be equipped with I hand-wheels to permit manual operation at the valve j location. j J. The Turbine Bypass Valves are arranged such that operation of any valves results in approximately equal blowdown from each steam generator.
10.4.4.3 Safety Evaluation The valves in the turbine bypass system are designed to fail closed to prevent uncontrolled bypass of steam to the condenser.
Should the bypass valves fail to open on command, the secondary safety valves provide main steam line overpressure protection.
The power-operated atmospheric dump valves provide a means for controlled cooldown of the reactor. The secondary safety valves and power-operated atmospheric dump valves are described in g Section 10.3.2.
Should the condenser not be available as a heat sink, an interlock will prevent opening, or if opened, will close the turbine bypass system valves. The secondary safety valves and power-operated atmospheric dump valves are used to control the load transient, if the bypass valves are disabled. Because the ASME Code safety valves provide the ultimate overpressure protection for the steam generators, the turbine bypass system is defined as a control system and is designed without consideration for the special requirements applicable to protection systems.
Failure of this system will have no detrimental effects on the Reactor Coolant System.
Operation of the turbine bypass system has no adverse effects on the environment since steam is bypassed to the condenser, the heat sink in use during normal operation.
This system is not required for the safe shutdown of the reactor and has no safety function.
10.4.4.4 Inspection and Testina Requirements This system is non-safety-related.
10.4.4.5 Instrumentation Application The control system for the Turbine Bypass System is described in Section 7.7.1.1.5 (Steam Bypass Control System).
Amendment A 10.4-10 September 11, 1987
CESSAR Ennnema I
\v) ,
i 10.4.5 CONDENSER CIRCULATING WATER SYSTEM 1
E 10.4.5.1 Desian Basis The Condenser Circulating Water System provides cooling water for the turbine condensers and rejects heat to the atmosphere via the cooling towers. Tower sizing is such that full unit load can be maintained with one tower out of service except during the three hottest summer months of the year. The towers are capable of cooling the circulating water to 100*F with 82*F wet bulb (0%
exceedance). Pump head, piping size, and cooling tower height are optimized based on capital and pumping cost. Pumps are sized l such that full load can be maintained with one pump down except during the three hottest summer months of the year.
10.4.5.2 System Description The condenser circulating water pumps circulate cooling tower basin water through the turbine condensers. Water chemistry is ;
maintained by blowdown and chemical addition. Basin level is i maintained with makeup water.
l Cooling towers provide the heat sink for all non-safety-grade
[3
\
components during all modes of plant operation. The towers may be natural or mechanical draft for a particular site. (A single natural draft tower may be used where prescribed maintenance can be accomplished during the specified refueling time period.)
Valving is provided such that each tower can be isolated during normal power operation. The towers contain no wooden components exposed to circulating water. Tower design allows complete drainage, silt removal, and good access to the fans (if applicable) for inspection and maintenance. Tower icing during subfreezing conditions is prevented by a fill bypass system which diverts a portion of the total hot water flow to the basin, louvers to restrict air flow, an ice prevention ring which distributes a portion of the total hot water flow across tower inlet air, and a fill zoning subsystem which diverts water to limited locations in the tower.
The four condenser circulating water pumps are motor-driven, high flow, low head pumps. Valving is provided such that each pump can be isolated during normal operation. Suction screens prevent debris ingestion. Pump material selection is based on compatibility with circulating water chemistry and tested for acceptability. Pump location is such that the available NPSH exceeds the required NPSH by at least 10 feet, and flooding of one pump will not affect any of the other pumps. Seal water for the pumps is maintained within the temperature and purity limits
[] established by the manufacturer. High quality cooling water for U
Amendment E 10.4-11 December 30, 1988
1 1
I CESSAR Enfincmw O
the pump bearings is provided in sufficient quantity to maintain bearing temperatures within manufacturers limits under full pump output during the hottest days of the year. Separate flow paths, E cach with their own pressure control, are provided for each pump support system requiring cooling water (e.g., thrust bearing cooling, seal water cooling, wear ring flushing).
Valving is provided such that either condenser waterbox can be isolated and the unit operated at partial load. Means are provided for entry into the waterboxes and circulating water piping for repair and cleaning. Entry provisions allow cleaning within one eight-hour shift. Drains are available such that the circulating water system can be drained within eight hours.
1 Blowdown is provided to control the concentration factor of cooling tower solids. A throttling valve allows regulation of the blowdown flow.
Acid is injected in the cooling tower inlet header. Biocide and scale inhibitor are injected i; ^.o the basins. Water treatment for the circulating water systr':n is based on site makeup water chemistry, blowdown requirements, environmental regulations, and system materials. Consideration is given to the need for biogrowth control, pH control, and scale buildup. Water treatment follows the options in EPRI report CS-2276, " Design and j operating Guidelines Manual for Cooling Water Treatment."
Makeup flow to each cooling tower basin is regulated by a throttling valve. Each tower is provided with two 100% capacity makeup pumps. Filters at the makeup intake structure prevent debris from entering the pumps. The suction filters can be cleaned without loss of makeup flow. Pump discharge strainers additionally remove debris which might enter the circulating water system. Warm water from the condenser outlet is used to prevent icing of the intake structure during winter months. The intake structure is separated from the discharge structure as to l minimize the potential for recirculation. j 10.4.5.3 Safety Evaluation
+
The Condenser Circulating Water System does not perform any safety functions. Thus reliance on this system was not assumed in the safety analysis.
I 10.4.5.4 Tests and Inspections Prior to startup, all piping is hydrostatically tested and flushed to applicable codes and standards. A full power performance test is performed immediately following installation.
Amendment E 10.4-12 December 30, 1988 l
q 1
CESSAR MEncmu o
E Condenser inlet / outlet temperature, cooling tower inlet /outl-et temperature, cooling water flow, circulating pump suction / discharge pressure, ambient weather conditions (dry bulb, wet bulb, wind speed), and the position of all valves are l
l recorded. The cooling tower is tested in accordance with Cooling ;
Tower Institute Standard ATC-105. !
After startup, the circulating water pumps, valves, and motor operators are inspected and maintained on a routine basis.
10.4.5.5 Instrument Applications Pressure is measured at each circulating water pump suction and discharge. Differential pressure is also monitored across each pump. Temperature is measured at the condenser inlet and outlet.
The circulating water is also monitored for pH and conductivity. .
Permanent flow meters measure individual circulating pump flow and total flow to the main condenser. Access ports allow' temporary flow meters to be installed in the main circulating 1 water piping. Cooling tower basin level is monitored and used to control makeup flow. Blowdown flow is manually adjusted as required to maintain desired water chemistry.
A
/ 10.4.6 CONDENSATE CLEANUP SYSTEM 10.4.6.1 Desian Basis A
The Condensate Cleanup System (CCS) is an integral part of the Condensate System. The CCS is designed to remove dissolved and l suspended impurities which can cause corrosion damage to secondary system equipment. The CCS also removes radioisotopes l
l which might enter the system in the event of a primary to i secondary steam generator tube leak. The condensate polishing domineralizers will also be used to remove impurities which could enter the system due to a condenser circulating water tube leak.
10.4.6.2 System Description The condensate cleanup system utilizes a side stream, full condensate flow, polisher located downstream of the condensate pumps. Deep bed, mixed resin, ion exchangers are utilized to obtain the advantage of their larger capacity in the event of the E inleakage of impurities, to reduce the probability of resin discharge to the feed system due to failure of resin retention elements, and to simplify system operation.
The following functional requirements are to be met to ensure a reliable system.
D Amendment E 10.4-13 December 30, 1988
CESSAR n!#icaries polishing system is sized to meet the chemistry O
A. The 3 requirements for continuous operation specified in Section 10.3.5 while operating with a condenser leak of 0.001 gpm and to maintain water quality during an orderly unit shutdown (not longer than 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />) with a leak of 0.1 gpm irregardless of the type of cooling water.
B. The number and sizing of the ion exchangers are such that the functional requirements can be met while permitting the replacement of resin in one ion exchanger at a time. .
C Plant features are provided to facilitate replacement of ion exchange resin. No ion exchange resin regeneration system is provided. 1 D. Resin traps are installed down stream of each ion exchanger E
to remove resin fines.
E. Design flow rates through the domineralizers are 40 gpm/ft or less. In addition, a minimum flow rate is specified by the manufacturer to prevent channeling. Minimum bed height is 3 ft.
F. The domineralizer outlet lines are fitted with individual A flow regulating valves.
G. The system design permits full flow recirculation through each ion exchanger for cleanup and verification of resin bed performance after resin replacement and prior to alignment within the system.
H. Ion exchanger isolation valve and recirculation valves are designed to permit slow, controlled opening to minimize hydraulic surges on the resin bed.
10.4.6.3 Safety Evaluation This system is non-safety-related.
10.4.6.4 Inspection and Testing Requirements This system is non-safety-related.
10.4.6.5 Instrumentation Applications This system is non-safety-related.
O Amendment E 10.4-14 December 30, 1988
i CESSAR EnHricaria, m '
10.4.7 CONDENSATE AND FEEDWATER SYSTEMS A
10.4.7.1 DesiQn Basis l l
The Condensate and Feedwater Systems are designed to return condensate from the condenser hotwells to the steam generators.
In addition, the systems include a number of stages of regenerative feed and condensate heating and provisions for maintaining feedwater quality. .
The entire Condensate System is non-safety-related. The portions I of the Feedwater System that are required to mitigate the I consequences of an accident and allow safe shutdown of the reactor are safety-related. The safety-related portions of the system are designed in accordance with the following design bases:
A. The system is designed such that failure of a feedwater supply line coincident with a single active failure will not prevent safe shutdown of the reactor.
B. The system components are designed to withstand the offects of and perform their safety functions during a safe shutdown earthquake.
C. Components and piping are designed, protected from, or located to protect against the ef fects of high and moderate energy pipe rupture, whip, and jet impingement which are not climinated by leak-before-break analysis.
1 D. The system is designed such that adverse environmental I conditions such as tornados, floods, and earthquakes will not impair its safety function.
E. The system is designed such that the loss of offsite power will not prevent safe shutdown of the reactor.
F. The main feedwater lines are restrained or isolated to prevent damage to the reactor coolant pressure boundary and containment in the event of a feedwater pipe rupture that is not climinated by leak-before-break analysis.
10.4.7.2 System Description Three 50% capacity motor-driven condensate pumps (two operating and one standby) deliver condensate from the condenser hotwell to side stream full flow condensate polisher cells (See Section 10.4.6) followed by the condenser air ejectors, the gland seal O condenser, and four tages of three parallel feedwater heaters to V the deaerator.
Amendment A 10.4-15 September 11, 1987
1 CESSAR 8lE"lCAT13N O J Three 50% capacity motor-driven feedwater booster pumps (two j operat.ing and one standby) deliver condensate from the deaerator A storage tank to the suction of the main feedwater pumps.
Three 50% capacity steam-driven main feedwater pumps (two l 1
operating and one standby) deliver feedwater through two stages of two parallel high pressure feedwater heaters to a single feedwater distribution header. (A motor-driven feedwater pump is utilized for startup.) At this point, feedwater flow is divided ]
into two to each steam generator. i Each steam generator has one downcomer feedwater nozzle and two economizer nozzles. At 100% power, the downcomer feedwater line is sized for a flow of at least 10% of full power flow at the normal full power steam generator pressure. Each economizer g feedwater line is sized for a total flow of 50% of full power I flow at normal full power steam generator pressure. During plant startup, the downcomer feodwater line is sized to accommodate all feedwater flow below the temperature of 200*F.
The manner in which the feedwater flow is delivered to the steam generator varies with reactor power:
A. When reactor power is from 0% to 15% of full power, all feedwater is delivered to the steam generator through the downcomer line.
B. When reactor power is above 15% and below 50%, all feedwater is delivered to the steam generator through the economizer.
C. When the reactor power is above 50% of full power, the feedwater flow is split, so that 10% of the full power main steam rate goes to the downcomer as feedwater while the remainder of the feedwater is injected into the economizer.
Two check valves in series are located in the downcomer feedwater lines and economizer feedwater lines to provide abrupt, complete termination of reverse feedwater flow. Redundant isolation valves are provided in both the economizer feedwater lines and the downcomer feedwater lines. These valves are active and provide complete termination of forward feedwater flow within 5 seconds after receipt of an MSIS. The safety analysis of these valves is described in Chapter 15.
All piping and valves from the steam generator nozzles to the second main feedwater isolation valve in both the economizer and downcomer feedwater lines are Seismic Category I and are designed to ASME Code Section III, Class 2 requirements.
O Amendment A 10.4-16 September 11, 1987
t I
CESSARn!nc-n V
One feedwater control valve on each steam generator is provided I
l to control feedwater flow to the economizer nozzles and one A l control valve on each steam generator is provided to control feedwater flow to the downcomer nozzle. These valves are automatically or manually controlled by the Feedwater Control System described in Section 7.7.1.1.4 to control the proper feedwater flow to each steam generator and maintain proper steam f generator level from startup through and including full power ;
operation.
E (
l 10.4.7.2.1 System Performance A {
A. Steam flow per steam generator as a function of power is '
shown on Figure 10.4.7-1. Feedwater flow requirements at any given power level are equal to the total steam flow plus 1 approximately 172,000 lb/hr, which allows a continuous I blowdown rate of 1% of the total steam flow at normal full power steam generator pressure (1000 psia).
P. Steam generator pressure as a function of power is given in Figure 10.4.7-2,
}
1 J C. Foodwater temperature at 100% power is 450*F (+0*F,-10*F).
D. Feedwater temperature is equal to or greater than 200*F ,
prior to initiation of feedwater flow to the economizer {
nozzles during plant startup. The 200*F feedwater temperature is achieved prior to reaching 15% power. All feedwater at a temperature lower than 200*F is directed to the downcomer feedwater nozzle. This does not include post turbine trip conditions.
E. The feedwater flow split between the economizer nozzles and l the downcomer nozzle throughout ascent in power is shown on Figure 10.4.7-3.
F. The Main Feedwater System provides the proper flow to the steam generators under the operating and design conditions contained in Section 7.7.1.1.4, Feedwater Level Control System.
G. The chemistry requirements of Section 10.3.5 ,pply during all phases of plant operation including startup, hot standby ,
and cooldown. g o
Amendment E 10.4-17 December 30, 1988
l CESSAREMUnce O
l H. The change in liquid inventory in the steam generators, as plant load changes, amounts to a decrease of approximately E l 103,500 pounds between C percent and 100 percent load. In designing the Condensate System and sizing the condenser l
hotwell, this difference is considered.
I. Plant operation can continue at reduced power with loss of one operating feedwater pump.
J. Plant operation can continue at 100% power with loss of one l
operating condensate or feedwater booster pump.
K. The feodwater and condensate system is designed to avoid erosion damage. The design and layout of piping systems considers the effect on the piping material from fluid velocity, bend location and the location of flash points.
The following velocity guidelines are recommended:
i
- 1. Pipe velocity 5 20 ft/sec.
- 2. Feedwater heater inlet flow velocity 5 12 ft/sec.
- 3. Condensate pump suction line velocity $ 5 ft/sec.
10.4.7.2.2 System Arrangement A. Redundant Feedwater System Isolation Valves meeting single failure criteria are provided in any feedwater piping interconnecting the steam generators to preclude blowdown of both steam generators following a postulated pipe rupture.
B. Redundant Feedwater System Isolation Valving is provided in both the economizer feedwater lines and the downcomer feedwater lines such that abrupt complete termination of an existing reverse flow condition is accomplished with consideration of a single failure. (Check valves are considered to be an acceptable means of achieving the above.)
C. The Main Feedwater Isolation Valves are located outside of the containment building as close to the containment wall as possible as required by General Design Criterion 57, " Closed Systems Isolation valves."
D. The Main Feedwater Isolation Valves for each steam generator are arranged such that a maximum of 500 cu. ft. of fluid is contained in the piping between ach steam generator and its l associated isolation valves. This volume also includes the !
O Amendment E 10.4-18 December 30, 1988
CESSAR En#ICATION (O3 volumes totmen the Redundant Main Feedwater Isolation ,
Valves and the volumes up to the respective isolation valves A l of 11 lines off of the main feedwater lines downstream of the Main Feedwater Isolation Valves for which a mechanism exists for getting the fluid into the main feedwater line (e.g., gravity, flow or flushing). g E
A 90-degree elbow facing downward is attached to each E.
feedwater nozzle. Such a precaution aids in the prevention l of water hammer.
F. To allow feed and condensate system startup recirculation A and layup, a pre-steam generator cleanup line is provided (
between the outlet (s) of the last feedwater heater (s) and the main condenser. The cleanup loop is designed for 25-50%
of the condensate and feedwater flow at the design operating pressure and temperature. The recirculation piping to the condenser is sized for 20-25 ft/sec velocity, if the pressure drop is not excessive. This recirculation loop is typically utilized with two other recirculation loops, one of these is located downstream of the gland steam condenser ,
for hotwell recirculation and the other is located l downstream of the deaerator storage tank. Both of these I
recirculation loops meet the above criteria.
G. The Emergency Feedwater System connection is located in the downcomer feedwater line between the Main Feedwater Isolation Yalves and the steam generator downcomer nozzle.
Emergency feedwater flow is directed to the downcomer nozzle only. A Safety Class 2 check valve located in the main feedwater piping upstream of this interface prevents back i flow of emergency feedwater to other portions of the Main Feedwater System.
H. The system is composed of three parallel main feedwater pumps. The feedwater. pumps are cross connected during all operations.
I. One deaerator and storage tank will be provided after the low pressure feedwater heaters. The liquid inventory of the deae ator tank, at normal operating level, is equal to at leas' three and one-half minutes of design feedwater flow.
The deareator and connected piping is designed to prevent watchammer. The deaerator storage tank is positiened to provide adequate NPSH to the feedwater booster pumps during normal and transient operation. Transient analyses are performed to assure satisfactory operation with the deaerator without causing system or plant trips.
l Amendment E 10.4-19 December 30, 1988 l . _ _ _ - _ _ - _ - _ _ _ - -
CESSAR HSibmu 10.4.7.2.3 Piping, Valves, Equipment and Instrumentation
^
O A. piping
- 1. The valves, piping and associated supports and restraints of the Main Feedwater System from and including the Main Feedwater Isolation Valves (MFIV) to the steam generator feed nozzles are Seismic Category I and designed to ASME Code Section III, Class 2 requirements.
- 2. ASME Section III, Code Class 2 Main Feedwater System piping is capable of being inspected and tested in accordance with ASME Code Section III and XI.
- 3. All ASME Section III Code Class 2 valves are capable of I
being periodically inservice tested for exercising and leakage in accordance with ASM" Code Section XI, Subsection IWV.
- 4. The design of the main feedwater piping and its supports and restraints accommodates the loads arising from the various normal operating and design bases events as specified in Section 3.9.3.
- 5. Feedwater piping is routed, protected and restrained such that in the case of a postulated rupture that is not eliminated by leak-before-break analysis of a feedwater linc or any other system pipeline, single failure criteria will not be exceeded with regard to safe shutdown of the plant.
- 6. Each economizer feedwater line is a 20-inch line based on a total flow of 50% of full power flow at normal full power steam generator pressure (1000 psia).
- 7. The downcomer feedwater line is an 8-inch line. This is based on the following:
- a. At 100% power, the downcomer feedwater line shall I be sized for a flow of at least 10% of full power flow at normal full power steam generator pressure ,
(1000 psia).
- b. During plant startup, the downcomer feedwater line 3 accommodates all feedwater flow below the I temperature of 200*F.
l O
Amendment A 1.0.4-20 September 11, 1987 u_______________-._______ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ .. J
CESSAR E%%m 1 1
m
/ T
'O A B. Main Feedwater Isolation Valves and Check Valves
- 1. Complete termination of forward feedwater flow is achieved within 5 seconds after receipt of an MSIS.
I
- 2. The Main Feedwater Isolation Valves (MFIVs) and associated supports and restraints are designed to ASME Section III, Class 2 and will be Seismic Category I. l
- 3. The MFIVs are capable of being in-service tested in accordance with ASME Code Section XI, Subsection IWV.
- 4. The Economizer and Downcomer Feedwater Line Isolation l Valves in each main feedwater line are remotely i
operated and capable of maintaining tight shutoff under the main feedwater line pressure, temperature and flow l l
resulting from the transient conditions associated with a postulated pipe break in either direction of the valves.
- 5. The MFIVs and their supports and restraints are designed to withstand loads arising from the various p normal operating and design bases events.
- 6. The MFIVs are classified " active" and meet the intent of NUREG-0800,
- 7. Each MFIV actuator is physically and electrically indepenLnt of the other such that failure of one will l not cause the failure of the other.
- 8. The main feedwater lines will meet the provisions of General Design Criteria 54 and 57.
P. Feedwater Control Valves
- 1. The feedwater co-trol valves have a design pressure /temperatur f 2600 psig at 475'F.
- 2. The Feedwater Cont) Valves and their supports are designed to withste i loads arising from the various normal operating and design bases events.
- 3. The maximum AP for both the Economizer and Downcomer Feedwater Control Valves is 40 psi at normal full power flow and the minimum temperature at which this flow could occur.
'w)
\
Amendment A 10.4-21 September 11, 1981
CESSARENGcm A
O l D. Pumps l l
l
- 1. Each feedwater pump includes a 5% design margin, i.e., {
head above the system required pump guarantee point.
Excess margin above this is to be minimized.
l
- 2. Pump head capacity characteristics continuously slope ;
upwards, with a minimum 10% head rise from design point to shutoff. Two or more pumps operated in parallel have identical characteristic curves and are designed j to operate on the steep portion of the curve.
- 3. Two feedwater pumps are driven by adjustable speed steam turbines; these pumps are normally operating.
The third purap is an identical standby pump, driven by a steam turbine and started manually on loss of one of the operating feedwater pumps, permitting the plant to regain 100% power. Each of the feedwater pumps delivers 50% of the plant related feedwater flow during normal full power operation at normal operating pressure. Each pump design includes an additional 5%
margin to accommodate wear of the pumps. Upon isolation or loss of one operating feedwater pump, the remaining operating pump is capable of providing a maximum runout flow of 70% (+5%) of the system rated flow against a steam generator pressure of 1120 psig within 6 seconds after receiving a full flow demand signal from the Feedwater Control System. This provides sufficient flow at the reduced load to prevent a low level trip.
- 4. A constant speed motor-driven feedwater pump is utilized for startup and shutdown. Upon loss of main feedwater and reactor trip, this pump starts automatically and maintains steam generater level.
E. Instrumentation and Control
- 1. The required accuracy of the feedwater temperature measurement devices is iS*F for any calorimetric measurement.
- 2. Feedwater control valves are capable of manual control at all times.
F. Insulation
- 1. Non-metallic insulation conforms to NRC Regulatory Guide 1.36. The chloric;e and fluoride content of the i
non-metallic insulation are acceptable as shown in Amendment A 10.4-22 September 11, 1987
cESSAREEsbo )
i 1
(O N.)
i
\
j Regulatory Guide 1.36. Tests will be made on A representative samples of the non-metallic thermal insulation to certify that the maximum chloride and fluoride content are not exceeded. All water used in the fabrication of non-metallic thermal insulation is demineralized or distilled water.
- 2. The insulation thickness is selected to minimize the heat load on the containment ventilation and cooling system.1 A _tperm_apoftransference of not more than 0.14 Btu-hr -F *
-ft insulated component surface area 4
is used as a design basis for insulation.
10.4.7.3 Safety Evaluation I
The safety-related portion of the Feedwater System is designed in accordance with the design bases presented in Section 10.4.7.1 (as long as the applicant conforms with the descriptions and requirements presented in Section 10.4.7.2). Any failure in the non-safety class portions of the Condensate and Feedwater Systems does not prevent safe shutdown of the reactor.
(N Effccts of equipment malfunction on the Reactor Coolant System
(%
8 are presented in Chapter 15.
,)
10.4.7.4 Tests and Inspections ,
I ASME Section III Code Class 2 piping is inspected and tested in j accordance with ASME Code Section III and XI. ASME Sections III Code Class 2 valves are periodically inservice tested for exercising and leakage in accordance with ASME Code Section XI, l Subsection IWV. j 10.4.7.5 Instrumentation Applications lE A
Feedwater flow control instrumentation measures the feedwater flow rate from the condensate and feedwater system. This flow measurement, transmitted to the feedwater control system,
' regulates the feedwater flow to the steam generators to meet system demands. Refer to Section 7.7.1.1.4 for a description of
.the feedwater control system.
/\
V Amendment E 10.4-23 December 30, 1988
CESSAR !!aincuion O' l l
THIS PAGE INTENTIONALLY BLANK l
l l
9 O
Amendment E 10.4-24 Decemoer 30, 1988 M
m l.
O 1
10.0 , , , , , , , , , ,
- 9. 0 - -
1
- 8.0 - - !
l 7.0 - -
e
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x 5.0 - -
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.e 4.0 - -
$ 3.0 - -
3 S'
2.0 - - r l
o U
31.0 - -
W m
t I I I I I I I I i 0 10 20 30 40 50 60 70 80 90 100
% POWER Amendment A F
September 11, 1987 O Figure ggg f STEAM FLOW vs POWER 10.4.7 1 1
i i i i i i i i i i i l 1100 -
1090 1080
'Ri 1070 - -
'm b 1060 - .
u '
5 tn 1050 i
c.
.10'40 - -
S 1030 1020 1010 1000 l 1 f I I I I I f f i 0 10 20 30 40 50 60 70 80 90 100 110
% POWER Amendment A September 11, 1987 O w Figure STEAM GENERATOR OUTLET PRESSURE vs POWER ~ 10.4.7 2
0 100 I I i i ECONOMIZER gg80 -
N0ZZLES g $ 60 - - .
w w Md 40 - -
tu5 20 - -
0 I I ' I 20 40 60 80 100 PERCENT POWER 100 , , , ,
3: 80 - DOWNCOMER _
pd 89 N0ZZLE
+- - -
s "e 60 Md 40 - _
tu 5 20 - -
0 ' I I I i 20 40 60 80 100 PERCENT POWER Amendment A September 11, 1987 1
"A Q Jgg f ECONOMlZER/DOWNCOMER FLOW SPLIT 10 7-3
l l
)! hhkk ER IC ATIO N
/\
b 10.4.8 STEAM GENERATOR BLOWDOWN SYSTEM j 1
'4 1 Desi_gn Basis 10.4.8.1 The design bases for the Steam Generator Blowdown System are:
A. Maintain proper steam generator shell side water chemistry 1 as outlined in Section 10.3.5 by removing non-volatile materials due to condenser tube leaks, primary to secondary tube leaks, and corrosion that would otherwise become more concentrated in the shell side of the steam generators.
B. Process steam generator blowdown for reuse as condensate.
C. Enable blowdown concurrent with steam generator tube leak (s) or radioactivity present on the secondary side without {
release of radioactivity to the environment.
D. Process a continuous steam generator blowdown rate of either 0.2% or 1% of the full power main steam flow. q E. Continuously sample the radioactivity of the steam generator )
g-'s blowdown. I N- F. Isolate the blowdown lines leaving the containment upon a Containment Isolation Signal, Main Steam Isolation Signal, or Emergency Feodwater Actuation Signal.
10.4.8.2 System Description A continuous high flow blowdown cont 11.s the concentration of impurities in the steam generator secondary side water. A general schematic of the blowdown system is shown in Figure E ,
i 10.4.8-1.
Each steam generator is equipped with its own blowdown line with A the capability of blowing down the hot leg and/or the economizer i regions of the steam generator shell side. The blowdown will be directed into a flash tank where the flashed steam is returned to the cycle via the low prensure feedwater heaters. The liquid portion flows to a heat exchanger where it is cooled, and then directed through a blowdown filter where the major portion of the suspended solids are removed. After filtration, the blowdown fluid is processed by blowdown demineralizers and returned to the condenser.
A I I Q
Amendment E 10.4-25 December 30, 1988 1
CESSAR EnnflCATION The final design ano layout of the Steam Gene? n- Blowdown A O\!
System is described in the site-specific SAR. 1;m following requirements are to be met to ensure a reliable system:
A. The Steam Generator Blowdown System is d7 signed to accommodate a continuous blowdown of appro) imately 1%
(172,000 lb/hr) maximum steam rate (MSR).
B. Each steam generator is provided with 2 tubesheet I
connections, including a 6-inch nozzle for hot leg blowdown, and a 6-inch nozzle for economizer blowdown. The Steam Generator Blowdown System, connected to each steam generator blowdown connection is capable of accommodating a continuous blowdown of approximately 0.5% MSR (86,000 lb/hr).
1 C. Makeup systems are capable of providing secondary makeup ,
water at a rate greater than 172,000 lb/hr. j D. Steam Generator Blowdown System piping and valves are arranged to allow blowdown from either or both blowdown I nozzles. j E. The Steam Generator Blowdown Processing System is capable of l accepting both a total continuous blowdown rate of 0.2% of j cach steam generator's MSR (17,200 lb/hr/ generator) while l the plant is at power and steam generator chemistry is within normal limits, and a continuous blowdown of up to 1%
of each steam generator's MSR (86,000 lb/hr/ generator) while the plant is at power and steam generator chemistry is not within normal limits. l F. The thermodynamic conditions at the blowdown nozzles are 6s follows:
Nozzle Flow Rate Power Level Fluid Condition Hot Leg 1% MSR Full Load (LATER) psia, (LATER) quality Economizer 1% MSR Full Load (LATER) psia, 30-40'F subcool Hot Leg 0.2% MSR No load (LATER) psia, saturated liquid G. Provisions are made to process the continuous steam generator blowdown water to 90% reduced radioactivity levels.
H. Blowdown water returned to the steam generator meets the water chemistry requirements outlined in Section 10.3.5.
I O
Amendment A 10.4-26 September 11, 1987
CESSARnn%mo l O
V I. The blowdown system piping material is compatible with A caturated steam service.
J. All components, piping, and their associated supports from the steam generator blowdown nozzles up to and including the l' E outer most containment isolation valves are ANS Safety Class 2 (see Section 3.2.2) and are designed to Seismic Category I requirements, as c% scribed in Section 3.7. All components, piping and their dissociated supports downstream of the outer most containment isolation valves are non-nuclear-safety and meet the intent of the quality standard of Positior. C.l.1 of Regulatory Guide 1.143, General Design Criterion 1, and the 3 seismic requirements of General Design Criterion 2. J l
K. Blowdown piping exiting containment consists of Redundant '
Blowdown Line Isolation Valves in accordance with General A Design Criteria 54 and 57 and is isolated by a MSIS, a CIAS, and an Emergency Feedwater Actuation Signal (EFAS).
L. The Steam Generator Blowdown System piping is used as the means to drain the secondary side of the steam generators. ;
The drain connections are located such that complete steam l l p generator drainage can be accomplished.
I
( M. One nitrogen supply connection is provided on either steam generator blowdown line to provide a purge path following j steam generator mainten6nce. l l
N. The steam generators are designed with the capability to achieve the following high capacity blowdown rates and associated thermodynamic conditions at the blowdown nozzles:
Nozzle Flow Rate Power Level Fluid Condition Hot Leg 5.5% M5R Full Load (LATER) psia 17.1% quality
! Hot Leg 8.6% MSR No Load (LATER) psia 5.6% quality Economizer 8.6% MSR No Load (LATER) psia 5.6% quality
- Note: Conditions presented assume a blowdown ng system with an equivalent flow resistance of pipf {/D
= 50. The balance of plant design shall provide a system resistance as follows:
50<f /D <60.
ity assumed n equiyalent system Maximum flow caE resistance of f /D = 50.
b The blowdown system is designed for a very high capacity
( flow (10% MSR) for a short period of time (2 minutes).
Amendment E 10.4-27 December 30, 1988
CESSARnninc- !
O A
O. A system is provided to maintain the steam generators in wet layup with the capability to adequately mix, sample, and add chemicals to them.
P. In addition to the above described High Capr. city Steam Generator Blowdown System, it is recommended that blanked connectors be incorporated in the blowdown and/or main ;
feedwater piping to allow for chemical cleaning of the steam i generators should it become necesscry in the future. 4 Q. Thermal insulation used on the blowdowr. system inside containment meets the following requirements:
Non-metallic insulation conforms to NRC Regulatory Guide j 1.36. The chloride and fluoride content of the non-metallic l insulation are acceptable as shown in Regulatory Guide 1.36.
i Tests will be made on representative samples of the non-metallic thermal insulation to certify that the maximum l chloride and fluoride contents are not exceeded. All water I used in the fabrication of non-metallic thermal insulation is demineralized or distilled water.
The insulation thickness is selected to minimize the heat load on the containment ventilation and cooling system. It is suggested ytha_t1 a germal transference of not more than 0.14 Btu-hr -F *
-ft of insulated component surface area be used as a design basis for insulation. l 10.4.8.3 Safety Evaluation l
The Steam Generator Blowdown System is designed to operate 1 manually and on a continuous basis as required to maintain acceptable steam generator secondary side water chemistry. The presence of ASME Section III - Class 2 piping and the system i containment isolation function require the system to be i designated " Nuclear Safety Related". The operation of the system ('
is not required, however, for plant safe shutdown. All blowdown lines which penetrate the containment are isolated automatically upon Containment Isolation Signal, Main Steam Isolation Signal or Emergency Feedwater Actuation Signal. The portion of the system inside the containment and the portion utilized as containment isolation are designed in accordance with applicable safety class requirements.
10.4.8.4 Tests and Inspections ASME Section III Code Class 2 piping is inspected and tested in accordance with ASME Code Sections III and XI. ASME Sections III O
l l
Amendment A 10.4-28 September 11, 1987 l
l 1 - _ _ _ _ _ - _ _ _ _ - - - _ _ _ _ _ _ _ - _ - _
CESSAR E! air,cy,o,,
Code Class 2 valves are periodically in-service tested for A
exercising and leakage in accordance with ASME Code Section XI'.
Subsection IWV.
10.4.8.5 Instrumentation Applications This system is-non-safety-related.
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CESSAR inWICATION 4
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V k 10.4.9 EMERGENCY FEEDWATER SYSTEM C 10.4.9.1 Design Basis .
l 10.4.9.1.1 Functional Requirements The Emergency Feedwater .(EFW) System provides an independent safety-related means of supplying secondary-side, quality j feedwater to the steam generator (s) for removal of heat and prevention of reactor core uncovery during emergency phases of plant operation. The EFW System is a dedicated safety system which has no operating functions for normal plant operation.
1 The EFW System is designed to be automatically or manually ,
4 initiated, supplying feedwater to the steam generators for any ovent that results in the loss of normal feedwater and requires ;
I heat removal through the steam generators, including the loss of normal onsite and normal offsite AC power.
Following the event, the EFW System maintains adequate feedwater i inventory in the steam generator (s) for residual heat removal and I i it is capable of maintaining hot standby and facilitating a plant i cooldown (at the maximum administratively controlled rate of 75 O *F/hr) from hot stnndby to Shutdown Cooling System initiation.
The Shutdown Cooling System becomes available for plant cooldown when the RCS temperature and pressure are reduced to the entry conditions given in Section 5.4.7.
The EFW System is designed to be initiated with operator action following a major loss of coolant accident to keep the steam generator tubes covered for the long term to enhance the closed system containment boundary. Note: Covering the steam generator tubes post-LOCA minimizes potential containment bypass leakage, should pre-existing primary-to-secondary leakage be present.
10.4.9.1.2 Design Criteria A. The EFW System and its supporting au) 'iaries are provided with emergency power and adequate redt..iancy, diversity and separation to perform its design basis ; ction in the event of a loss of offsite and normal onsite power, coincident with:
- 1. A single active mechanical component failure, or
- 2. A single active electrical component failure, or
- 3. The effects of a high or moderate energy pipe rupture, ln) j U
Amendment C 10.4-31 June 30, 1988
1 l
CESSAR 8annCAT13N O
B. All components and piping (upstream of the automatic steam I generator isolation valves and essential to the emergency C l runction) are ANS Safety Class 3. Components and piping involved in containment integrity (downstream of the automatic steam generator isolation valves) are ANS Safety i Class 2. The line classifications are consistent with the l requirements specified in ANS 51.10. All components and piping essential to the emergency function are designed to Seismic Category I requirements as described in Section 3.7.
The seismic category and safety and quality classification l l
of the EFW System components are listed in Table 3.2-1.
C. The EFW System is equipped with diverse pump drive mechanisms. This is accomplished by providing one full-capacity motor-driven pump and one full-capacity steam-driven pump in each EFW mechanical train. All controls, instrumentation, and valves, which are essential to the emergency operation of the steam-driven pumps subtrains, are powered by battery-backed Class 1E power.
The batteries are capable of powering the EFW steam-driven pump subtrains for a station blackout up to four hours with E appropriate load shedding. In addition to the batteries, an alternate AC source of standby power is provided for an extended station blackout period.
D. The EFW System components are located in Seismic Category I C
structures which also protect the components from external environmental hazards such as tornados, hurricanes, floods, and external missiles. Each redundant and diverse subtrain of the EFW System is physically separated from the others within these structures.
E. All essential components are designed to account for, located to protect against, or protected from internal j flooding, internal missiles, interactions from earthquakes, or the effects of high or moderate energy line breaks as described in Chapter 3.
P. The EFW System is designed so that it can be either manually initiated or automatically initiated by the Emergency .
Feedwater Actuation System (EFAS), described in Section l 7.3.1, or the Alternate Protection System (APS) described in l Section 7.7. The EFW System is designed to deliver flow to l the steam generator (s) within 60 seconds upon receipt of an ,
EFAS signal. l G. Each EFW pump is capable of providing 100% of the required 1 minimum flow of 500 gpm, to meet the design basis heat removal requirements. Each pump is capable of delivering this flow under the following coincident parameters:
i Amendment E l 10.4-32 December 30, 1988
CESSAR MairlCATION l
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- 1. The maximum steam generator downcomer nozzle pressure is 1217 psia which accounts for the steam generator C design pressure, safety valve uncertainty and feed nozzle losses from the downcomer nozzle to the steam generator steam space.
- 2. Feed line losses are those existing when full EFW flow is diverted to one steam generator.
I
- 3. Pump suction is at the minimum suction pressure.
- 4. A margin of 7% is added to the required head. This includes a 2% margin for wear and a 5% margin for ;
uncertainties.
1 H. The maximum EFW flow to each steam generator is restricted by a cavitating venturi to protect the EFW pumps from damage due to excessive runout flow, and to allow the operator 30 minutes to regulate or terminate EFW flow to prevent RCS overcooling, steam generator overfill or containment overpressurization.
I. The EFW System is designed to maintain an emergency feedwater temperature of at least 40*F and no greater than D 120*F. I l
J. The EFW System has a safety-related condensate storage !
volume of 350,000 gallons to achieve safe cold shutdown, l based on:
- 1. A main feedline break without isolation of EFW flow to the affected steam generator for 30 minutes.
- 2. Refill of the intact steam generator.
- 3. Eight hours of operation at hot standby conditions.
- 4. Subsequent cooldown of RCS within six hours to conditions which permit operation of the Shutdown Cooling System.
- 5. Continuous operation of one reactor coolant pump.
This safety-related condensate storage volume is sufficient to permit cooldown with the reactor in natural circulation.
Note: EFW System storage utilizes two dedicated safety grade supply tanks termed the Emergency Feedwater Storage (s
. Tanks (EFWSTs). Each tank contains 50% of the total
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Amendment C 10.4-33 June 30, 1988 L_-__-______-______-_____--__-_-____-_-__.--__. _ - _ _ _ _ - - _ _ _ - - _ - _ _ _ _ _ _ _ _ - _ _ _ _ . _ - - _ _ - _ _ _ _ - _ _ _ _ _ _ _ _ - - - _ - _ _ _ _ ___n
O CESSAR 8lniflCATICN 1 I
l C
O1I required EFW water supply. A low EFWST water level alarm q allows the operator 30 minutes to manually align the tank j from the other train. l K. A non-safety grade source of condensate can be aligned should the safety related source of condensate be exceeded before Shutdown Cooling System entry conditions are reached.
L. The EFW System is controllable in a post-accident environment from either the control room or the remote i shutdown station.
M. The EFW System piping in the vicinity of the steam ]
generators is arranged to minimize the potential for '
destructive water hammer during startup. The EFW piping continuously rises as it penetrates the containment to connect with the downcomer feedwater pipe which enters the I steam generator. After the two lines connect, the downcomer feedwater pipe continues to rise to prevent draining into l the steam generator with the feedwater flow shut off. It l then connects to a 90 degree elbow facing downward, which is
, attached to the steam generator downcomer nozzle.
1 N. The EFW Systq,m is des {gned to have an unavailability in the range of 10 to 10 per demand based on analysis using-methods and data presented in NUREG-0611 and NUREG-0635.
Analysis to support this criterion is presented in Appendix 10A.
O. The emergency feedwater supplied to the steam generators is of the same or better quality than the secondary system makeup water, except that the requirement on oxygen is i excluded.
P. Each steam-driven pump shall be supplied with steam from a single steam generator, i.e., the one to which it supplies feedwater.
Q. Means are provided to permit periodic surveillance testing of the EFW pumps and valves, and functional testing of the integrated operation of the system.
R. Emergency feedwater is delivered to the downcomer nozzles of the steam generators.
S. The EFW System provides double isolation from the Main Feedwater System during normal plant conditions when 6.he EFW l System is not required.
l Amendment C 10.4-34 June 30, 1988 L_______-.__-.__________
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T. A four-channel control scheme is provided to preclude C inadvertent actuation in the event of a single failure. A !
four-channel design is provided for the initiation logic, actuation logic, and power.
U. The Equipment and Floor Drainage System (Section 9.3.3) E provides for collection and detection of EFW system leakage which may originate in each EFW pump. room, in each Emergency Feedwater Storage Tank room or enclosure, and areas (
containing EFW system piping where a moderate- or high-energy pipe rupture is postulated, as defined in Section 3.8. The control room is alerted on detection of excessive leakage.
10.4.9.2 System Description C
10.4.9.2.1 General Description The EFW System is shown in Figure 10.4.9-1, Sheets 1 and 2.
The EFW System is configured into two separate mechanical trains.
Each train is aligned to feed its respective steam generator.
Each train consists of one Emergency Feedwater Storage Tank (A) (EFWST), one 100% capacity motor-driven pump subtrain, one 100%
A- capacity steam-driven pump subtrain, valves, one cavitating venturi, and specified instrumentation. Each pump subtrain takes suction from its respective EFWST and has its respective discharge header. Each subtrain discharge header contains a pump discharge check valve, flow regulating valve, steam generator isolation valve and steam generator isolation check valve. The motor-driven subtrain and steam-driven subtrain are joined
{
together inside containment to feed their respective steam ,
generator through a common EFW header which connects to the. steam generator downcomer feedwater line. Each common EFW header contains a cavitating venturi to restrict the maximum EFW flow rate to each steam generator. The cavitating venturi restricts the magnitude of the two pump flow as well as the magnitude of individual pump runout flow to the steam generator.
A cross-connection is provided between each EFWST so that either tank can supply either train of EFW. The two EFWSTs are safety grade tanks of seismic design in which each tank contains 50%
of the total volume specified in Section 10.4.9.1.2.J. A normally locked closed, local manually operated isolation valve is provided for each EFWST to provide separation. A line connected to a non-safety source of condensate is also provided with local manual isolation so that it can be manually aligned for gravity feed to either of the EFWSTs, should the EFWSTs reach p) low level before Shutdown Cooling System entry conditions are (V
Amendment E 10.4-35 December 30, 1988
I CESSARHMinc-I I
c reached. A check valve and a normally locked closed, local i manually operated isolation valve are provided for separation of q the non-safety source of condensate from the safety-related q sources. !I Pump discharge crossover piping is provided to enhance system versatility during long-term emergency modes, such that a single pump can feed both steam generators. Two normally locked closed, local manually operated isolation valves are provided for i subtrain separation.
A flow recirculation line is provided downstream of each pump discharge, which allows: j l
A. A continuous flow back to the EFWST for pump minimum flow protection; and B. Full or partial flow testing of the pumps.
A multi-stage flow restrictive orifice restricts the flow to the minimum required for pump protection. Each pump has adequate flow capacity to continuously recirculate this flow plus provide the required design basis flow to the steam generators. The recirculation lines are adequately sized so that full pump flow 4 can be recirculated through the bypass provided around the flow restrictive orifice for full flow pump testing during power (
operations. The bypass line contains a manual flow regulating i valve in order to vary the pump flow for performance testing.
Each steam-driven pump is provided with an atmospheric-discharge, I non-condensing turbine. Driving steam is supplied from the Main l Steam System upstream of the main steam isolation valves. Each turbine is supplied with steam from the steam generator to which the pump feeds. Each supply line contains a normally closed fail-open air operated steam isolation valve. A bypass is provided around each of these isolation valves with a flow restricting orifice and a normally closed fail-open air operating bypass isolation valve. The bypass provides a small controlled rate of steam flow to the turbine. This allows the hydraulic control portion of the governor to pressurize at turbine idle speed before the steam isolation valve is opened for full rated speed operation.
The turbines exhaust to atmosphere through a missile protected Seismic Category I vent line routed through the roof. Low point
! drains are provided for collection and return to the condensate system of any liquid that may condense in the supply and exhaust lines. A low point drain, located upstream of the steam supply isolation valve, provides a continuous blowdown through a flow restricting orifice in order to keep the supply line warm and Amendment C 10.4-36 June 30, 1988 l
CESSARMEncua
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L' prevent water slugs from entering the turbine on an automatic C emergency start. A power-operated valve is provided in this line so that it can be remotely isolated from the control room should high activity be present. A bypass is provided around each drain orifice should additional drain capacity be required.
Cooling water to the Emergency Feedwater Pump Turbine Bearing Oil Coolers is supplied fror, the first stage of the steam-driven pumps and returned to the pump suctions.
10.4.9.2.2 Component Description A summary of design parameters and codes for the major EFW System components is given in Table 10.4.9-1.
10.4.9.2.2,1 Emergency Feedwator Pumps The EFW pumps are horizontal multi-stage centrifugal pumps. Each pump is capable of delivering the system design flow of 500 gpm to the steam generator (s) over the entire range of steam generator pressures (0 to 1217 psia) while recirculating the required flow for pump protection back to the EFWSTs.
[
\ /
] The first stage of the steam-driven pumps is capable of producing the above flow requirements while providing the required cooling flow to the turbine bearing oil coolers.
Flanges are provided on each pump suction and discharge, and each pump is provided with casing vents and drains to facilitate maintenance.
The motors for the motor-driven pumps are cooled by the Component E Cooling Water System (Section 9.2.2).
10.4.9.2.2.2 Steam-Driven Emergency Feedwater Pump Turbines a ch steam-driven EFW pump is provided with a safety grade s ,ospheric discharge non-condensing turbine. E Each turbine is supplied with a hydraulic governor control valve, and a trip and throttle (stop) valve with motor reset capability. C The turbine is brought up to speed by governor control upon being supplied with steam by opening of the steam isolation valve EF-108 or EF-109. The governor then controls the turbine speed at the pump rated speed by modulating the governor control valve.
The governor controlled turbine speed can be adjusted from the !
main control room, the remote shutdown panel, or manually at the p, governor.
L ,Y Amendment E 10.4-37 December 30, 1988 I
CESSAR n!Mcamu O
The turbine is stopped by remotely tripping the trip and throttle C (stop) valve from the main control room or remote shutdown panel.
The trip and throttle (stop) valve is automatically tripped for turbine overspeed protection by an electrical trip at 115% of rated speed and by a mechanical trip at 125% of rated speed. The electronic overspeed trip is "non-fatal" (i.e., the valve can be reset from the control room or remote shutdown station). The mechanical overspeed trip is " fatal" (i.e., in that reset can only be accomplished at the turbine trip and throttle (stop) valve).
10.4.9.2.2.3 Emergency Feedwater Storage Tanks An assured source of emergency feedwater is provided by the two emergency feedwater storage tanks (one tank in train 1 and one ta rik in train 2). Each tank contains 50% of the required water volume given in Section 10.4.9.1.2.J.
Each tank is safety grade, seismically designed, contained in a Seismic Category I structure, and protected against environmental Adequate provisions are provided such that a failure or E hazards.
leak of the tank will not adversely affect other essential components.
The condensate stored in each tank is of the same quality for secondary makeup except there is no restriction on oxygen.
The tanks are vented to atmosphere and are protected from overpressure by adequately sized vents and overfill lines.
The tanks are provided with makeup, drain, and condensate cleanup supply and return connections.
The minimum and maximum temperatures of the condensate supplied or stored in each tank are 40*F and 120*F, respectively.
10.4.9.2.2.4 Emergency Feedwater Cavitating Venturis A cavitating venturi is located in the common EFW supply line to each steam generator. Each cavitating venturi limits the maximum EFW flow that can be fed to a steam generator. The cavitating venturis prevent pump cavitation due to pump runout, and minimize other potentially adverse effects of having excessive emergency feedwater flow, such as overfill of the steam generators, excessive reactor coolant system cooldown rates, excessive mass / energy input into containment following a main steam line break, and excessive draw down of the EFWST.
O Amendment E 10.4-38 December 30, 1988
CESSAR Eininc-G v I Each cavitating venturi is sized to cavitate at 650 gpm, thus g limiting the maximum emergency feedwater flow to each steam ,
generator. Cavitation occurs when one pump feeding one steam j generator runs out to 650 gpm and the EFWST is at minimum water level (isolation valve and control valve full open).
Each cavitating venturi will limit the maximum emergency J i
feedwater flow to each steam generator to 800 gpm. This occurs When both the motor- and steam-driven pumps are feeding a steam generator, the EFWST is at maximum water level, the control valves are fully open and the steam generator is at atmospheric ,
This maximum flow has been set to ensure that the pressure.
steam line break post-trip (DNBR) response remains above the minimum value, that the containment is not overpressurized following a main steam line break, and that the steam generator ,
is not overfilled without operator action to modulate or l terminate EFW flow for 30 minutes after EFW system actuation. 1
\
10.4.9.2.2.5 Active Valves f The following valves are required to maintain their functional capability during a safe plant shutdown. An active valve list is given in Table 10.4.9-2.
Y A. Steam Generator Isolation Valves Valves EF-100, EF-101, EF-102 and EF- 103 are normally closed during normal plant operations. These valves, in series with check valves EF-200, EF-201, EF-202 and EF-203 respectively, provide double isolation between the emergency feedwater system and the main feedwater system (steam generator). These valves are automatically opened by the !
Emergency Feedwater Actuation System (EFAS) on low steam generator level, or the Alternate Protection System (APS),
and are automatically closed by the EFAS at a steam generator level higher On the normal operating water level. These valves c' .lso be individually opened or closed remotely from the r control room and at the remote shutdown panel. The valves are provided with electric motor operators and with local manual handwheels.
B. Emergency Feedwater Control Valves Valves EF-104, EF-105, EF-106, and EF-107 are provided with remote manual positioning capability in the main control E room and at the remote shutdown panel to throttle each EFW pump flow to obtain a stable steam generator level. These valves are provided with fail open air operators and are c
, provided with local manual handwheels. These valves are available for remote manual flow control as long as Amendment E 10.4-39 December 30, 1988
l CESSARnaikua 1 non-safety grade instrument air is available. These valves C 01 1 are provided with safety grade air operators anc a safety grade solenoid to assure that the operatt '
can be doenergized and fail to the full open position. Travel stops are provided for system adjustment.
l C. Steam Generator Isolation Check Valves '
Valves EF-200, EF-201, EF-202 and EF-203 are provided for separation of the motor-driven and steam-driven subtrains and for double isolation from the steam generator during normal plant conditions. These valves are tilted disk check ;l valves designed to seat with a low-pressure differential.
D. Emergency Feedwater Pump Check Valves f Valves EF-204, EF-205, EF-206, and EF-207 are provided to prevent back flow through each EFW pump. These valves are I
tilted disk check valves designed to seat with a low-pressure differential.
l E. Steam Supply Bypass Valves {
Valves EF-112 and EF-113 open automatically en the EFAS or APS signal to supply a small controlled rate of steam flow to the turbines. This allows the hydraulic control portion of the governor to pressurize at a controlled turbine idle speed, before the steam supply isolation valve EF-108 or EF-109 opens. These valves are provided with a safety grade fail open air operator, a safety grade solenoid and local manual handwheel. These valves can be remotely opened and l I
closed from the main control room and at the remote shutdown panel.
F. Steam Supply Isolation Valves Valves EF-108 and EF-109 isolate the steam supply to the EFW steam-driven pump turbines. Opening of these valves supplies steam to the turbines and starts governor control of the steam flow to the turbines. These valves are double disk gate valves provided with a safety grade fail-open air actuator and a local manual handwheel. These valves open automatically on EFAS or APS after a delay allows full opening of the steam supply bypass valve and the turbine is at idle speed. These valves can be remotely opened and closed from the main control room and at the remote shutdown l panel.
O Amendment C 10.4-40 June 30, 1988
CESSAREnne-O C
G. Turbine Trip-and-Throttle (Stop) Valves These valves are part of the turbine package. The valves are latched open at all times. A motor operator is supplied to power the valve to the open-latched position. An overspeed signal generated by the turbine protection system trips the valve and immediately stops steam flow to the turbine. Remote manual open/ trip control is provided in the main control room and at the remote shutdown panel. If the valve is closed by a mechanical overspeed trip, the trip must be reset locally at the trip and throttle (stop) valve. !
H. Turbine Governor Valves (control valves)
These valves are part of the turbine package and they control steam flow to provide the required turbine speed.
These valves are controlled by the turbine governor.
I. Steam Supply Continuous Drain Isolation Valves Motor operated valves EF-110 and EF-111 are provided for remote isolation of the steam supply continuous drain line for prevention of release of high activity to the atmosphere due to a steam generator tube rupture. These valves can be (Vn) individually opened or closed from the main control room.
10.4.9.2.3 Electrical Power Supply Each subtrain of the EFW System receives power from its associated Class lE Emergency Power System. In the event of loss .
of normal onsite and offsite power, power is supplied by the !
l emergency diesel generators. All instrumentation, controls and valves that are essential to the operation of the steam-driven pump subtrains are supplied from battery-backed vital class 1E power supplies. Battery-backed power is available to the steam-driven pump turbine governor speed control and steam E generator water level indication in order to provide steam i i
generator level indication for at least 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> considering appropriate load shedding following a station blackout. In addition to the batteries, an alternate AC source of standby power is provided for an extended station blackout period. Each motor-driven pump subtrain is supplied by a Class 1E Emergency power train that is totally independent and separated from the other motor-driven pump subtrain. Each steam-driven pump C subtrain is supplied by a Class lE Emergency Power train that is totally independent and separated from the other steam-driven j pump subtrain and totally independent and separated from the associated motor-driven pump subtrain that feeds the same steam generator. The emergency bus designation for the EFW System Amendment E 10.4-41 December 30, 1988
CESSAR nni"lCATION motor-driven pumps and motor operated valves, and the emergency lC O
bus and channel designation for the EFW System instrumentation I and control is given in Table 10.4.9-5. A more detailed description of the onsite power systems is provided in Section E 8.3.
10.4.9.2.4 Emergency Feedwater System Operation and Control C
The EFW System can either be manually actuated or automatically actuated by the Emergency Feedwater Actuation System (EFAS) described in Section 7.3.1 or the Alternate Protection System (APS) described in Section 7.7. At the low steam generator water level setpoint, the EFAS associated with that steam generator or the APS will actuate the EFW System as follows:
A. Starts the associated motor-driven pump.
B. Deenergizes the solenoid to open associated turbine steam supply bypass valve EF-112 or EF-113.
C. Starts associated turbine driven pump by deenergizing the solenoid to open the associated turbine steam supply valve EF-108 or EF-109.
Note: A delay is provided in opening these valves so that the steam supply bypass valve (EF-112 or EF-113) is fully open and turbine is at idle speed.
D. Opens the associated steam generator isolation valves EF-100 and EF-102, or EF-101 and EF-103.
E. Decnergizes the solenoid to assure that the associated EFW flow control valves EF-104 and EF-106, or EF-105 and EF-107 i are in their full open position. ]
F. Assures that turbine governor speed control is at full rated speed.
After the EFW System has been actuated, the plant operator will control the flow to the steam generator (s) in order to control the steam generator normal water level. The operator has at least 30 minutes after EFW actuation before operator action is essential. The operator can control steam generator water level through any one or a combination of the following:
A. If non-safety grade instrument air is available, the operator can energize the solenoid and position the associated EFW pump flow control valves EF-104, EF-105, EF-106, and/or EF-107.
B. Open/ shut the associated EFW steam generator isolation valves EF-100, EF-101, EF-102, and/or EF-103.
Amendment E 10.4-42 December 30, 1988
l CESSARMEncuiu J l
/9 V C l C. Adjust turbine governor control speed.
D. Use the handwheel to throttle the EFW pump flow control valves EF-104, EF-105, EF-106 and/or EF-107.
E. Use on/off operation of the motor-driven EFW pumps. I The EFAS provides the following automatic protection functions, should the operator fall to control flow:
A. The EFAS will automatically shut the steam generator isolation valves EF-100, EF-101, EF-102, and/or EF-103 at a steam generator level setpoint higher than normal water level to prevent steam generator overfill. i B. If the steam generator water level falls to the low steam generator water level setpoint for EFW actuation, the EFW system is reactuated as described above.
An EFAS override is provided for each steam generator so that EFW flow can be terminated through operator action to close the steam generator isolation valves and/or shutoff the associated EFW pumps, should the steam generator be faulted (i.e., main feedwater or main steam line break).
10.4.9.3 Safety Evaluation l
For the design basis considerations given in Section 10.4.9.1,_
sufficient feedwater can be provided at the required temperature and pressure even if b secondary pipe break is the initiating event, if any one EFW pump subtrain fails to deliver flow, and if no operator action is taken for up to 30 minutes following the event. Because the EFW System is the only safety-related source of makeup water to the steam generators for heat removal when the Main Feedwater System and Startup Feedwater System are inoperable ,
or unavailable, it has been designed with special considerations.
That is, the use of redundancy, diversity, and separation has been incorporated into the design of the EFW System to ensure its q hbility to function. j Redundancy is provided by using two full-capacity motor-driven pumps and two full-capacity steam-driven pumps (one each for each steam generator) . Diversity is provided by using two types of pump drivers (steam turbines and electrical motors) and AC and DC emergency electrical power sources. Separation is provided with separated power and instrumentation and control subsystems having appropriate measures which preclude interaction between subsystems. Also, independent piping subsystems are incorporated O into the design, protected at interconnection points with appropriate isolation and/or check valves to ensure a high degree Amendment C 10.4-43 June 30, 1988
CESSAR E!!Lmu of piping separation, redundancy, and diversity. An EFW System O
C active component failure analysis is presented in Table 10.4.9-3.
Analysis of transients and accidents requiring the EFW System to function (discussed in Chapter 15), demonstrates that the EFW System satisfies the design basis described in Section 10.4.9.1.
An adequate safety-related water supply is available to allow the plant to remain at hot standby for 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> followed by an orderly j cooldown to shutdown cooling system entry conditions. This is possible even if the initiating event is a main feedwater line break with a spill of EFW for 30 minutes at the maximum EFW flow.
Level instrumentation and a low level alarm are provided on the Emergency Feedwater Storage Tanks to allow the operator 30 minutes at full flow to align the EFWST from the other train or a non-safety source of condensate in order to preclude the tank from being emptied before Shutdown Cooling System entry conditions are reached.
1 Following a primary side loss-of-coolant-accident, the EFW System may be used to assure that the steam generator tubes are covered to enhance the closed system containment boundary. The two motor-driven pumps will be used for this purpose as steam for the steam-driven pumps may or may not be available. In the event of failure of one of the motor-driven pumps, the water supply to one of the steam generators would be temporarily unavailable. By opening the cross-connection valves between the pump discharge '
lines, the one operating motor-driven pump may be used to 1ill and maintain level in both steam generators. .
1 In the unlikely event of a station blackout, the steam-driven !
subtrains are capable of providing emergency feedwater to the I steam generators coincident with a single failure. The steam-driven pump discharge valves are assured to open by .
providing battery-backed power. Battery-backed power is also available to the turbine governor speed control and steam generator water level indication in order to provide steam generator level control for at least 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> with appropriate load shedding. In addition to the batteries, an alternate AC E source of standby power is provided for an extended station j blackout period.
The EFW System piping is arranged to minimize the potential for C l' water hammer occurrences induced by the piping system. Specific design considerations are covered in Section 10.4.9.1.
All components and piping are designed to protect against the offccts of high and moderate energy pipe ruptures as discussed in j Section 3.6. j O l Amendment E 10.4-44 December 30, 1988
I CESSAR EnWicarien bq All EFW System components are located in Seismic Category I structures which also protect the components from external environmental hazards. All piping and ' components essential to EFW operation are designed to Seismic Category I standards as described in Section 3.7, and are designed to accommodate, located to protect against, or protected from internal flooding and internal missiles as discussed in Sections 3.4 and 3.5.
10.4.9.4 Inspection and Testina Requirements During fabrication of the EFW components, tests and inspections are performed and documented in accordance with code requirements to assure high quality construction. As necessary, performance tests of components are performed in the vendor's facility. The EFW System is designed and installed to permit in-service inspections and tests in accordance with ASME Code Section XI.
10.4.9.4.1 EFW System Performance Tests Prior to initial plant startup, a comprehensive performance test, as detailed in Section 14.2, will be performed to verify that the C design performance of the system and individual components is {
attained.
10.4.9.4.2 Reliability Tests and Inspections A. System Level Tests l
After the plant is brought into operation, periodic tests and inspections of the EFW components and subsystems are performed to ensure proper operation.
The scheduled tests and inspections are necessary to verify system operability, since during normal plant operation, EFW components are aligned for emergency operation and serve no other function. The tests defined permit a complete checkout at the component level during normal plant operation. Satisfactory operability of the complete system can be verified during normal scheduled refueling shutdown.
The complete schedule of tests and inspections of the EFW ;
i System is detailed in Chapter 16.
B. Component Testing In addition to the system level tests, tests to verify proper operation of the EFW components are also conducted. .
I These tests supplement the system level tests by verifying I acceptable performance of each active component in the EFW i Amendment C 10.4-45 June 30, 1988 j
CESSARnainc-Pumps and valves are tested in accordance with ASME O
System. C Section XI. A full flow test line is provided so that the pumps can be performance tested after maintenance at various flow rates up to and including their design point.
10.4.9.5 Jnstrument Requirements Sufficient instrumentation and controls are provided to adequately monitor and control the EFW System. Appropriate methods are employed to assure independent operation of the instrumentation and control channels and to prevent any interaction between subsystems. All non-safety-related instrumentation and controls are designed such that any failure will not cause degradation of any safety-related equipment function. All valve and pump controls, and status and parameter indications are listed in Table 10.4.9-4. Instrumentation and control emergency power bus and channel designation is given in Table 10.4.9-5. All of the EFW System parameter measurement and indication instrumentation is described below.
10.4.9.5.1 Pressure Instrumentation A. Emergency Feedwater Pumps Discharge Pressure The main control room and remote shutdown panel are provided with motor-driven EFW pumps 1 and 2 and steam-driven EFW O,
pumps 1 and 2 discharge pressure indication.
B. Emergency Feedwater Pumps Suction Pressure The main control room and remote shutdown panel are provided with motor-driven EFW pumps 1 and 2 and steam-driven EFW pumps 1 and 2 suction pressure indication and low pressure alarm.
C. Emergency Feedwater Pump Turbines Inlet Pressure The main control room and remote shutdown panel are provided with EFW pump turbines 1 and 2 inlet pressure indication.
D. Pressure Test Points Pressure test points are provided at the following locations:
- 1. EFW Pump Turbines 1 and 2 Steam Inlets.
- 2. EFW Pump Turbines 1 and 2 Steam Exhausts.
O Amendment C 10.4-46 June 30, 1988
CESSAR Ennncoia n C
- 3. EFW Steam-Driven Pump Turbine Bearing Oil Coolers 1 and 2 Inlet.
- 4. EFW Steam-Driven Pump Turbine Bearing Oil Coolers 1 and 2 Outlet.
- 5. Each EFW Pump Suction.
- 6. Each EFW Pump Discharge.
10.4.9.5.2 Temperature Instrumentation A. Steam Generator Isolation Valves Upstream Temperature The main control room is provided with temperature indication upstream of steam generator isolation valves and a high temperature alarm for detection of back leakage and steam voiding.
B. Emergency Feedwater Storage Tanks Temperature The main control room is provided with EFWST 1 and 2 temperature indication and high and low temperature alarms.
C. Temperature Test Points Temperature test poi.its are located at the inlet and outlet of each steam-driven EFW pump turbine bearing oil cooler.
D. Emergency Feedwater Pump Turbine Bearing Temperatures The main control room is provided with EFW pump bearing i
temperature indication.
10.4.9.5.3 Flow Instrumentation A. Emergency Feedwater Pumps Discharge Flow Flow indication for the motor-driven EFW pumps 1 and 2 and steam-driven EFW pump 1 and 2 discharge are provided locally, in the main control room, and at the remote shutdown panel. This instrumentation is designed and procured to meet the criteria given in Regulatory Guide 1.97.
B. Emergency Feedwater Pumps Recirculation Flow Flow indication for the motor-driven EFW pump 1 and 2 and
/ steam-driven EFU pumps 1 and 2 recirculation are provided locally, in the main control room, and at the remote shutdown panel.
Amendment C 10.4-47 June 30, 1988
1 l 1 CESSAR nninc- .
i 10.4.9.5.4 Level Instrumentation !
A. Emergency Feedwater Storage Tank Level Level indication and low level alarm for EFWST 1 and 2 are provided in the main control room and at the remote shutdown panel. This is provided by redundant level instrumentation on each tank.
The low level alarm is set at a point to allow 30 minutes for manual alignment of the other EFWST or the non-safety supply of condensate before the level decreases to a point where pump suction is lost.
This instrutantation is designed and procured to meet the criteria given in Regulatory Guide 1.97.
B. Steam Generator Level Steam generator level indication is provided at the steam-driven EFW pump control valves EF-104 and EF-105 and motor-driven EFW pump control valves EF-106 and EF-107.
This allows steam generator level control by manual handwheel control of the valves. The level instrumentation has battery-backed power for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> with appropriate load shedding, so that indication is available for a station E I blackout event. In addition to the batteries, an alternate j' AC source of standby power is provided for an extended station blackout period. Steam generator level indication ,
is also provided close to the remote manual controls for EFW operation in the main control room and at the remote c .
shutdown panel. This provides indication for proper EFW l flow regulation. l C. Steam Supply and Exhaust Drain Level Alarms An alarm sounds in the main control room, should the level in drain pots for the low point drains in the steam turbine supply and exhaust lines be excessive. This alerts the operator that the orifice bypass valves should be opened.
10.4.9.5.5 Steam-Driven Pumps Turbine Speed Instrumentation is provided in the main control room and at the remote shutdown panel for manual adjustment of the turbine governor control speed. This instrumentation allows the operator to adjust the turbine governor control speed after automatic ramp control from turbine ideal speed to turbine rated speed. If the operator should lower the speed to a point which will not produce adequate EFW flow, the Emergency Feedwater Actuation System Amendment E 10.4-48 December 30, 1988
""'o" I CESSAR CERTIFICATION O returns the turbine governor control speed to the rated speed C ;
setting at a low steam generator setpoint. Turbine speed indication is provided in the main control room and at the remote shutdown panel.
i O !
I i
i
(
Amendment C 10.4-49 June 30, 1988
-~
lw! !hbh k I $b$N ICAT13N
-1
( }
\s / l TABLE 10.4.9-1 c f (Sheet 1 of 4)
I EMERGENCY FEEDWATER SYSTEM COMPONENT PARAMETERS Emergency Feedwater Pumps Quantity 2-Motor Driven 2-Steam Driven Type Multistage, Horizontal, !
Centrifugal Design Code ASME III, Class 3 l Design Pressure, psia 2925 l Design Temperature, 'F 140 Design Flow .< ate, gpm* 670
(
\ Design Head 0 120*F, ft** 3620 NPSH Available (Design Point) 34 0 120*F, ft )
Maximum Shutoff Head 0 Rated Speed, ft 4520
- 500 gpm to steam generator, 170 gpm recirculation flow for minimum flow pump protection.
- Contains 7% margin, 2% for wear and 5% for uncertainties.
O Amendment C June 30, 1988
CESSAR innncum O1s TABLE 10.4.9-1 (Cont'd)
(Sheet 2 of 4) l EM_ERGENCY FEEDWATER SYSTEM COMPONENT PARAMETERS Emercency Feedwater Cavitatinc Venturi 1
Quantity 2 l Design Code ASME III, Class 2 i
Design Pressure, psia 2015 Design Temperature, *F 140 Choked Flow at Inlet 9 1185 psia, gpm 650 Operating Temperature Range, 'F 40 - 120 Minimum Pressure Recovery 83 0 Choked Flow, %*
1
- The maximum permanent line pressure loss created by the venturi shall not exceed 118 psid at a flow (non-cavitating) of '
500 gpm.
i i
i O
Amendment C June 30, 1988
l CESSAR En#ICATION l l
l
'\ !
TABLE 10.4.9-1 (Cont'd) C (Sheet 3 of 4)
EMERGENCY FEEDWATER SYSTEM COMPONENT PARAMETERS Emergency Feedwater Stora_ge Tanks Quantity 2 Design Code ASME III, Class 3 Minimum. Usable Volume per Tank, 175,000 j
gallons 1
Design Pressure, Internal / External, 1.0/0.5 j psig ]
i Design Temperature, *F 140 l
1 1
f I
i l
l
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)
l i
1 1
i Amendment C !
June 30, 1988 l
CESSAR En'rificmu ;
l TABLE 10.4.9-1 (Cont'd)
(Sheet 4 of 4)
EMERGENCY FEEDWATER SYSTEM C COMPONENT PARAMETERS
)
l The above component parameters are based on an Emergency Feedwate.r System with the following arrangement requirements: lE ]
- 1. The ninia"- elevation /.ifference between the minimum Emergency Feeav;3ter Stoir.ge Tank water level and the Emergency Feedwater im;; .satums is not less than 20 ft. 1 1
1 C
- 2. The maximum elevation difference between the maximum l Emergency Feedwater Storage Tank water level and the center i line of the Emergency Feedwater pump suctions does not exceed 90 ft.
- 3. The Emergency Feedwater pump suctior, piping and component pressure losses does not exceed 14 ft at a flow rate of 670 i gpm. ]
- 4. The maximum elevation difference between the center line of the Emergency Feedwater pump discharges and the center line of the Steam Generator Downcomer nozzle does not exceed 100 ft.
- 5. The Emergency Feedwater pump discharge piping and component pressure losses does not exceed 62 ft from the pump discharge to the inlet of the cavitating venturi and the piping and component pressure loss f rom the pump discharge to the steam generator downcomer nozzle (including the cavitating venturi) does not exceed 481 ft at a flow rate of 500 gpm to either one of the steam generators and a 170 gpm recirculation flow with one pump operating.
O Amendment E December 30, 1988
CESSAR EnWncuiu
!o) s-Table 10.4.9-2 EMERGENCY FEE 0 WATER SYSTEM - ACTIVE VALVE LIST Valve No. Type Size. Inches Actuator i
EF-100 Gate 6 Electric Motor ]
EF-101 Gate 6 Electric Motor EF-102 Gate 6 Electric Motor EF-103 Gate 6 Electric Motor !
EF-200 Check 6 None EF-201 Check 6 None EF-202 Check 6 None EF-203 Check 6 None EF-104 Globe 6 Pneumatic EF-105 Globe 6 Pneumatic i EF-106 Globe 6 Pneumatic EF-107 Globe 6 Pneumatic EF-204 Check 6 None EF-205 Check 6 None EF-206 Check 6 None i EF-207 Check 6 None
, EF-108 Gate 6 Pneumatic
\ EF-109 Gate 6 Pneumatic Electric Motor
- EF-110 Gate 1 l EF-lll Gate 1 Electric Motor EF-ll2 Gate 1 Pneumatic I
EF-ll3 Gate 1 Pneumatic EF-212 Butterfly 8 Manual t EF-213 Butterfly 8 Manual EF-288 Gate 6 Manual EF-289 Gate 6 Manual EF-290 Gate 6 Manual EF-291 Gate 6 Manual 1
O V
Amendment C June 30, 1988
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CESSAR Eniincm2 O TABLE 10.4.9-4 (Sheet 1 of 4)
EMERGENCY FEEDWATER SYSTEM INSTRUMENTATION AND CONTROL l
l '
Main Control Remote Shutdown l Controls Room Control Room Motor-Driven Pump 1 Start /Stop X X E
Motor-Driven Pump 2 Start /Stop X X Steam-Driven Pump 1 Start /Stop X X Steam-Driven Pump 2 Start /Stop X X Individual Emergency Feedwater X X ,
Steam Generator Isolation Valves !
EF-100, EF-101, EF-102, EF-103 Open/Close f' Individual Valve Position Controls for X X EFW Flow Control Valves EF-104, -
EF-105, EF-106, EF-107 Steam Supply Bypass Valves EF-ll2, EF-ll3 X X
[s Open/Close j V) Steam Supply Isolation Valves EF-108, EF-109 Open/Close X X l
Turbine Trip and Throttle (Stop) Valves 1 & 2 X X 1 Trip / Reset Control Turbine 1 & 2 Speed Control X X Steam Supply Continuous Drain Isolation X {
Valves EF-110, EF-lll Open/Close j EFAS Override X X l
)
l O
Amendment E December 30, 1988
CESSAR !nnriom
)
TABLE 10.4.9-4 (Cont'd)
O\1 1
(Sheet 2 of 4)
CMERGENCY FEE 0 WATER SYSTEM INSTRUMENTATION AND CONTROL Main Control Remote Shutdown Controls Room Control Room Motor-Driven Pump 1 Discharge Pressure X X g X
Motor-Driven Pump 2 Discharge Pressure X X
Steam-Driven Pump 1 Discharge Pressure X X
Steam-Driven Pump 2 Discharge Pressure X Motor-Driven Pump 1 Suction Pressure X X and Low Pressure Alarm Motor-Driven Pump 2 Suction Pressure X X and Low Pressure Alarm Steam-Driven Pump 1 Suction Pressure X X and Low Pressure Alarm Steam-Driven Pump 2 Suction Pressure X X and Low Pressure Alarm Steam-Driven EFW Pump Turbi'e 1 Inlet Pressure X X Steam-Driven EFW Pump Turbine 2 Inlet Pressure X X Steam Generator Isolation Valves X EF-100, EF-101, EF-102, EF-103 Upstream Temperature and High Temperature Alarm Emergency Feedwater Pump Turbines 1 & 2 Bearing X Temperature EFWST 1 Temperature and High and Low Temperature X Alarm EFWST 2 Temperature and High and Low Temperature X '
Alarm l
i l
l l
1 l
l O'
Amendment E December 30, 1988
CESSAR Enamon _
a TABLE 10.4.9-4 (Cont'd)
(Sheet 3 of 4)
EMERGENCY FEEDWATER SYSTEM INSTRUMENTATION AND CONTROL q Main Control Remote Shutdown Controls Room Control Room Motor-Driven Pump 1 Flow X X E l l
Motor-Driven Pump 2 Flow X X Steam-Driven Pump 1 Flow X X Steam-Driven Pump 2 Flow X X Motor-Driven Pump 1 Recirculating Flow X X Motor-Driven Pump 2 Recirculating Flow X X Steam-Driven Pump 1 Recirculating Flow X X Steam Driven Pump 2 Recirculating Flow X X EFWST-1 Level and Low Alarm X X EFWST-2 Level and Low Alarm X X Steam Generator 1 Level X X Steam Generator 2 Level X X Individual Steam Supply and X 1 Exhaust Drain Pot High Level Alarms Steam-Driven EFW Pump 1 Turbine Speed X X Steam Driven EFW Pump 2 Turbine Speed X X Motor-Driven Pump 1 Running Status X X l
Motor-Driven Pump 2 Running Status X X Steam-Driven Pump 1 Running Status X X Steam-Driven Pump 2 Running Status X X I
l i
O Amendment E December 30, 1988
CESSAR !!nLmu O
TABLE.J 0.4.9-4 (Cont'd)
(Sheet 4 of 4)
EMERGENCY FEEDWATER SYSTEM INSTRUMENTATION AND CONTROL
! Main ,
Control Remote Shutdown Controls Room Control Room l Individual Emergency feedwater X X E Steam Generator Isolation Valves 4 EF-100, EF-101, EF-102, EF-103 Open/Close Position Individual EfW flow Control X X Valves EF-104, EF-105, EF-106, l EF-107 Open/Close Position j Steam Supply Bypass Valves X X EF-ll2, EF-ll3 Open/Close Position Steam Supply Isolation Valves X X l EF-108, EF-109 Open/Close Position Turbine Trip and Throttle (Stop) Valves X X 1 & 2 Open/Close Position and Close !
Position Alarm Steam Supply Continuous Drain X lsolation Valves EF-110, EF-lll !
Open/Close Position ;
l O
Amendment E December 30, 1988
CESSAR Eniincmou O
TABLE 10.4,9-5 (Sheet 1 of 4) c FMFRGENCY FEEDWATER SYSTEM EMERGENCY POWER REQUIREMENTS l Emeroency Feedwater System Pump Motors Motor Emeraency Bus Motor-Driven Emergency A Feedwater Pump 1 Motor Motor-Driven Emergency B Feedwater Pump 2 Motor Emeroency Feedweter System Motor Operated Valves Valve Emeraency Bus EF-100 B (Battery-Backed, Channel D) E EF-101 A (Battery-Backed, Channel C)
EF-102 A EF-103 8 Trip & Throttle (Stop) Valve-1 B (Battery-Backed, Channel B)
Trip & Throttle (Stop) Valve-2 A (Battery-Backed, Channel A)
EF-llo B EF-lli A C l
l I
O Amendment E December 30, 1988
q CESSAR 8lnificuion O'
TABLE _10.4.9-5 (Cont'd)
(Sheet 2 of 4) C EMERGENCY FEE 0 WATER SYSTEM EMERGENCY POWER REQUIREMENTS Instrumentation and Controls Controls Emergenc,y_Bm Channel Motor-Driven Pump 1 Start /Stop A A tiotor-Driven Pump 2 Start /Stop B B Steam-Driven Pump 1 Start /Stop B B Steam-Driven Pump 2 Start /Stop A A Steam Generator Isolation Valve EF-100 Open/Close B D Steam Generator Isolation Valve EF-101 Open/Close A C Steam Generator Isolation Valve EF-102 Open/Close A C Steam Generator Isolation Valve EF-103 Open/Close B D flow Control Valve EF-104 Position Controls B B flow Control Valve EF-105 Position Controls A A flow Centrol Valve EF-106 Position Controls A A flow Cor. trol Valve EF-107 Position Controls B B Steam Supply Bypass Valve EF-ll2 Open/Close B B Steam Supply Bypass Valve EF-ll3 Open/Close A A Steam Supply Isolation Valve EF-108 Open/Close B B Steam Supply isolation Valve EF-109 Open/Close A A Turbine Trip and Throttle (stop) Valve-1 Open/Close B B Turbine Trip and Throttle (stop) Valve-2 Open/C' lose A A Turbine-1 Speed Control B B Turbine-2 Speed Control A A <
Valve EF-110 Open/Close B B Valve EF-lll Open/Close A A l
l l
9 Amendment C June 30, 1988 9
CESSAR EMuncma O TABLE 10.4.9-5 (Cont'd)
(Sheet 3 of 4) e EMERGENCY FEEDWATER SYSTEM EMERGENCY POWER REQUIREMENTS Instrumentation and Controls Emtr_q_ ency Bus Channel indication and Alarms A A Motor-Driven Pump 1 Discharge Pressure B B Motor-Driven Pump 2 Discharge Pressure B B Steam-Driven Pump 1 Discharge Pressure A A Steam-Driven Pump 2 Discharge Pressure Motor-Driven Pump 1 Suction Pressure and Low A A Pressure Alarm Motor-Driven Pump 2 Suction Pressure and Low B B Pressure Alarm Steam-Driven Pump 1 Suction Pressure and Low B B Pressure Alcrm Steam-Driven Pump 2 Suction Pressure and Low A A
/ Pressure Alarm Q] Steam-Driven Pump 1 Turbine Inlet Pressure Steam-Driven Pump 2 Turbine Inlet Pressure B
A B
A A
Motor-Driven Pump 1 Flow A Motor-Driven Pump 2 Flow B B Steam-Driven Pump 1 Flow B B Steam-Driven Pump 2 Flow A A Motor-Driven Pump 1 Recirculation flow A A Motor-Driven Pump 2 Recirculation Flow B B ,
Steam-Driven Pump.1 Recirculation Flow B B Steam-Driven Pump 2 Recirculation Flow A A A A EFWST-1 Level (Train A) and low Alarm B B EFWST-1 Level (Train B) and Low Alarm A C EFWST 2 Level (Train A) and Low Alarm B D l EFWST-2 Level (Train B) and Low Alarm Steam-Driven Pump 1 Turbine Speed B B Steam-Driven Pump 2 Turbine Speed A A Motor-Driven Pump 1 Running Status A A Motor-Driven Pump 2 Running Status B B i Steam-Driven Pump 1 Running Status B B Steam-Driven Pump 2 Running Status A A Steam Generator Isolation Valve EF-100 Open/Close Position B D Steam Generator Isolation Valve EF-101 Open/Close Position A C Steam Generator Isolation Valve EF-102 Open/Close Position A C Steam Generator Isolation Valve EF-103 Open/Close Position B D I
Amendment C June 30, 1988
CESSAREnemia i TABLE 10.4.9-5(Cont'd)
O1 (Sheet 4 of 4) c EMERGENCY FEEDWATER SYSTEM EMERGENCY POWER REQUIREMENTS
{
Instrumentation and Controls Indication & Alarms Emeroency Bus Channel flow Control Valve EF-104 Open/Close Position B B Flow Control Valve EF-105 Open/Close Position A A Flow Control Valve EF-106 Open/Close Position A A Flow Control Valve EF-107 Open/Close Position B B Steam Supply Bypass Valve EF-ll2 B B Open/Close Position Steam Supply Bypass Valve EF-ll3 A A Open/Close Position Steam Supply Isolation Valve EF-103 B B Open/Close Position Steam Supply Isolation Valve EF-109 A A Open/Close Position Turbine Trip and Throttle (stop) Valve-1 B B Open/Close Position and Close Alarm Turbine Trip and Throttle (stop) Valve-2 A A Open/Close Position and Close Alarm Valve EF-110 Open/Close Position B B Valve EF-lli Open/Close Position A A i
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/ EMERGENCY FEEDWATER SYSTEM i
jM / PIPING AND INSTRUMENTATION DIAGRAM tv.4.9 1 f
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4 EMERGENCY FEEDWATER SYSTEM jMM
/ PIPING AND INSTRUMENTATION DIAGRAM 0.4 -
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