ML14339A434
| ML14339A434 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 11/24/2014 |
| From: | FirstEnergy Nuclear Operating Co |
| To: | Office of Nuclear Reactor Regulation |
| Shared Package | |
| ML14339A419 | List:
|
| References | |
| L-14-360 | |
| Download: ML14339A434 (186) | |
Text
{{#Wiki_filter:BVPS-2 UFSAR Rev. 20 10-i CHAPTER 10 TABLE OF CONTENTS Section Title Page 10 STEAM AND POWER CONVERSION SYSTEM...............10.1-1
10.1
SUMMARY
DESCRIPTION.............................10.1-1
10.2 TURBINE GENERATOR...............................10.2-1
10.2.1 Design Bases....................................10.2-1 10.2.2 Description.....................................10.2-2 10.2.3 Turbine Rotors and Turbine Disk Integrity.......10.2-9 10.2.4 Safety Evaluation...............................10.2-13 10.2.5 References for Section 10.2.....................10.2-13
10.3 MAIN STEAM SUPPLY SYSTEM........................10.3-1
10.3.1 Design Bases....................................10.3-1 10.3.2 Description.....................................10.3-3 10.3.3 Safety Evaluation...............................10.3-5 10.3.4 Inspection and Testing Requirements.............10.3-6 10.3.5 Water Chemistry.................................10.3-7 10.3.6 Steam and Feedwater Materials...................10.3-8 10.3.7 Instrumentation Requirements....................10.3-8 10.3.8 References for Section 10.3.....................10.3-10
10.4 OTHER FEATURES OF THE STEAM AND POWER CONVERSION SYSTEM..........................................10.4-1
10.4.1 Main Condenser..................................10.4-1 10.4.2 Condenser Evacuation System.....................10.4-3 10.4.3 Turbine Gland Sealing System....................10.4-6 10.4.4 Turbine Bypass System...........................10.4-8 10.4.5 Circulating Water System........................10.4-12 10.4.6 Condensate Cleanup System.......................10.4-18 10.4.7 Condensate and Feedwater Systems................10.4-24 10.4.8 Steam Generator Blowdown System.................10.4-32 10.4.9 Auxiliary Feedwater System......................10.4-35a 10.4.10 Auxiliary Steam and Condensate System...........10.4-42a 10.4.11 Extraction Steam System.........................10.4-46 10.4.12 References for Section 10.4.....................10.4-49
APPENDIX 10A AUXILIARY FEEDWATER SYSTEM SIMPLIFIED RELIABILITY ANALYSIS
BVPS-2 UFSAR Rev. 20 10-ii LIST OF TABLES
Table Number Title 10.1-1 Steam and Power Conversion System Principal Design and Performance Characteristics
10.2-1 Turbine Trip Signals
10.2-2 ASTM Material Properties for Siemens Turbine Rotors and Discs
10.2-3 Deleted
10.2-4 Deleted
10.3-1 Main Steam Line Branch Connections
10.3-2 Materials of Code Class 2 and Class 3 Main Steam and Feedwater Piping Systems
10.4-1 Main Condenser Design Parameters and Performance Characteristics
10.4-2 Circulating Water System Cooling Tower Pump Characteristics
10.4-3 Natural Draft Cooling Tower Design Parameters
10.4-4 Chemical Analysis of Water
10.4-5 Condensate Polishing System Effluent Parameters for Normal Operation
10.4-6 Condensate Polishing System Component Design Data
10.4-7 Condensate Polishing System Influent Parameters for Normal, Start-up and Major Condenser Leakage
10.4-8 Condenser Cooling Water Analysis Average Parameters
10.4-9 Steam Generator Blowdown Analysis at Normal Operations
10.4-10 Powdered Resin Dewatering System Component Design Data
10.4-11 Powdered Resin Dewatering System Operating Parameters for Clamshell Filter
10.4-12 Steam Generator Blowdown System Component Design Parameters
BVPS-2 UFSAR Rev. 20 10-iii LIST OF TABLES (continued)
Table Number Title 10.4-13 Steam Generator Steam Side and Feedwater Chemistry Specifications
10.4-14 Auxiliary Boilers Performance Characteristics
10.4-15 Auxiliary Boilers Design Parameters
10.4-16 Auxiliary Boilers Principal Components and Design Parameters
BVPS-2 UFSAR Rev. 20 10-iv LIST OF FIGURES
Figure Number Title 10.1-1 Heat Balance Diagram
10.2-1 Turbine Steam System
10.2-2 DELETED
10.2-3 DELETED
10.2-4 DELETED
10.2-5 DELETED
10.2-6 DELETED
10.2-7 DELETED
10.2-8 DELETED
10.2-9 DELETED
10.2-10 DELETED
10.2-11 Tangential Aim Inspection Technique
10.2-12 Radial Aim Inspection Technique
10.2-13 DELETED
10.3-1 Main Steam System
10.4-1 Turbine Gland Seal Steam System
10.4-2 Piping: Turbine Bypass System
10.4-3 Circulating Water System
10.4-4 DELETED
10.4-5 DELETED
BVPS-2 UFSAR Rev. 20 10-v LIST OF FIGURES (Cont) Figure Number Title 10.4-6 DELETED
10.4-7 Condensate Demineralizer System
10.4-8 Condensate Demineralizer System
10.4-9 DELETED
10.4-10 DELETED
10.4-11 DELETED
10.4-12 Condensate System
10.4-13 DELETED
10.4-14 Feedwater System
10.4-15 DELETED
10.4-16 DELETED
10.4-17 DELETED
10.4-18 DELETED
10.4-19 DELETED
10.4-20 DELETED
10.4-21 DELETED
10.4-22 DELETED
10.4-23 Piping: Steam Generator Blowdown System
10.4-24 Auxiliary Feedwater System
10.4-25 DELETED
10.4-26 DELETED
10.4-26a DELETED
10.4-27 DELETED
10.4-28 DELETED
BVPS-2 UFSAR Rev. 20 10-vi LIST OF FIGURES (Cont)
Figure Number Title 10.4-29 DELETED
10.4-30 DELETED
10.4-31 DELETED
10.4-32 DELETED
10.4-33 Extraction Steam System
BVPS-2 UFSAR Rev. 16 10.1-1 CHAPTER 10 STEAM AND POWER CONVERSION SYSTEM 10.1
SUMMARY
DESCRIPTION This section describes the steam and power conversion system
which is designed to receive steam generated by the steam generators (Chapter 5) and to produce electrical power. The major components of the steam and power conversion system are:
turbine-generator-exciter complete with moisture separators/reheaters, main steam, main condenser, condensate pumps, condenser air removal system, turbine gland sealing system, turbine bypass steam system, condensate demineralizer system, heater drain pumps, steam generator feed pumps, feedwater heaters, and drain coolers. The heat rejected in the
main condenser is removed by the circulating water system. The steam produced in the steam generators is passed through the
high-pressure turbine, where the steam is expanded, and then exhausted to the moisture separators/reheaters. The moisture separators reduce the moisture content of the steam, and the reheaters superheat the steam before it enters the low-pressure turbines. From the low-pressure turbine, the steam is exhausted into the main condenser, where it is condensed and deaerated, and then returned to the closed loop cycle as condensate. A portion of the main steam is fed to the reheaters. This main steam is condensed in the reheater and cascaded to the highest pressure heater. A small part of the main steam supply is continuously used by the auxiliary steam system, which supplies miscellaneous loads including the air ejectors and gland steam system. The condensate pumps take suction from the condenser hotwell, discharge through the condensate polishing system, the air ejector intercondensers, gland steam condenser, drain coolers, and five stages of low-pressure feedwater heaters to the suction of the steam generator feed pumps. The feed pumps supply feedwater through one stage of high-pressure feedwater heaters to the steam generators. Steam and hot water for the feedwater heating cycle is supplied from the turbine extractions and moisture separator/reheater drains, respectively.
Under normal operation, the turbine uses all the steam produced in the steam generators except for auxiliary steam uses.
However, an automatic pressure/temperature controlling turbine bypass system (TBS) is provided to discharge excess steam, greater than 40 percent of full load steam flow, directly to the main condenser. The TBS is designed to control steam generator pressure by dumping excess steam during start-up, shutdown, and transient periods when steam generation exceeds turbine steam
requirements. The following design features are safety-related:
- 1. Main steam lines from the steam generator up to and including the main steam isolation trip valves.
BVPS-2 UFSAR Rev. 16 10.1-2 2. Feedwater piping from the steam generators up to and including the isolation valve outside the containment.
- 3. All components of the auxiliary feedwater system.
- 4. Steam generator blowdown lines from the steam generators up to and including the isolation valves outside the containment.
The turbine generator has a maximum calculated capability as depicted on Figure 10.1-1 when operating with six stages of feedwater heating.
The plant heat balance at the Nuclear Steam Supply System (NSSS) thermal power of 2910 MWt is shown on Figure 10.1-1. Also, important design and performance characteristics are provided in
Table 10.1-1. The following sections describe the equipment and systems required for the steam and power conversion system: 10.2 Turbine-Generator 10.3 Main Steam Supply System 10.4.1 Main Condenser 10.4.2 Condenser Evacuation System 10.4.3 Turbine Gland Sealing System 10.4.4 Turbine Bypass System 10.4.5 Circulating Water System 10.4.6 Condensate Cleanup System 10.4.7 Condensate and Feedwater Systems 10.4.8 Steam Generator Blowdown System 10.4.9 Auxiliary Feedwater System 10.4.10 Auxiliary Steam and Condensate Systems 10.4.11 Extraction Steam System
BVPS-2 UFSAR Tables for Section 10.1
BVPS-2 UFSAR Rev. 20 1 of 3 TABLE 10.1-1 STEAM AND POWER CONVERSION SYSTEM PRINCIPAL DESIGN AND PERFORMANCE CHARACTERISTICS Item Design and Performance Characteristics Turbine-generator unit (Section 10.2)
Turbine 1,009 Mwe rating at the NSSS thermal power of 2910 MWt, 1,800 rpm, tandem compound, four flow, 13.9m annulus area, last-stage buckets, with single-stage reheat, at 2.30 in Hg absolute exhaust pressure and 0 percent makeup Generator 1,070,000 kVA, 1,800 rpm, direct-
connected, three-phase, 60 Hz, 22,000 V, hydrogen inner-cooled, rated at 0.92 pf, and 75 psig hydrogen pressure
Exciter 3,900 kW, 525 V, direct connected and
brushless
Control Electro-hydraulic control (EHC)
Overspeed
Protection
Redundant speed control systems
- 1. Normal and transient EHC speed control system
- 2. Auto stop trip system
- 3. Overspeed protection controller
- 4. Mechanical overspeed trip weight
Main steam supply
system (Section 10.3)
between the steam Piping and valves up to and including
isolation trip valves outside
containment: ASME Section III, Code generator and the Class 2 and Seismic Category I
isolation trip valves
outside the
containment
Main steam supply
system from the
isolation trip valves
to outside the main
steam valve house Piping and valves: ANSI B31.1, Seismic
Category I BVPS-2 UFSAR Rev. 16 2 of 3 TABLE 10.1-1 (Cont) Item Design and Performance Characteristics Main steam supply system outside the main steam valve
house Piping and valves: ANSI B31.1, nonseismic Main Condenser (Section 10.4.1) Twin-shell, single pass, 720,000 ft surface area, equalizing ducts between steam sections and hot well section Condenser air removal system (Section 10.4.2) Two half-capacity vacuum priming ejectors for initial shell-side air removal, two full-capacity steam jet air ejectors for
maintaining vacuum. Steam and noncondensibles go to the gaseous waste disposal system for the air ejectors, and
directly to the atmosphere for the vacuum priming ejectors. Piping and valves: ANSI B31.1 Turbine gland sealing system (Section 10.4.3) Steam is supplied either from the main
steam supply system directly or via the
auxiliary steam system. Piping and valves: ANSI B31.1 Turbine bypass Flow capacity of greater than 40 percent system of full load steam flow. Piping and (Section 10.4.4) valves: ANSI B31.1 Circulating water system (Section 10.4.5) Four 25 percent capacity circulating
water pumps, one hyperbolic natural draft
cooling tower, and a fabricated-steel piping system Condensate demineralizer system (Section 10.4.6) 1. One train of five ion exchangers, designed for four normally operating.
The demineralizers remove ion and
particulate contaminates from the condensate and feedwater cycle.
- 2. Piping: ANSI B31.1 Pressure vessels: ASME Section VIII Condensate and feedwater systems (Section 10.4.7) 1. Three half-capacity motor-driven condensate pumps, two air ejector
intercondensers, one gland steam
condenser, five stages of low-pressure regenerative feedwater heaters, including one separate drain
cooler, all divided into two strings of half-capacity heaters, two half-capacity motor-driven feed pumps, and
one stage of BVPS-2 UFSAR Rev. 0 3 of 3 TABLE 10.1-1 (Cont) Item Design and Performance Characteristics two half-capacity high-pressure feedwater heaters
- 2. Piping and valves from the hotwell up to but not including the containment
isolation valves outside the
containment structure: ANSI B31.1. Piping and valves from the containment isolation valves to the
steam generators: ASME Section III, Code Class 2
f H q g c)!LJ o p o T oo9 ll tl q, \, Ein\q*a{C, z3^2 NT frp 6.;t b rrH g$', Hiu 5-:J diu t-o 5 ul I o c)!3 o.D iooo{@\o iflE+!-c)-to{F m'nz p-{c F (D z rn*$s t-p{c F g0 z rn I H;Hs r p-l C F cp z m I NJ.a C)nrn lnZ im cDp=l{c)n igl pll-o56 I'r1!--T--T H ri*ii :13 51 il'-.'E {l r !l col utl\I 5l.ol O'll N C, o.l E FF$!u, o I11 t Tl D o 3!m I m D m u@(.)(.).o o t*;il*6 tv ul Ol (.)o a il;$il lg(").o!l, I TlTv t op Fi :'- C);!@o t c?o t 2 r')2 ()m-{zo tt)D trl tn a m 3 o o o 2 o m z.n m D col (, I (-)gl Ol I Tt D Cf-tJl<(-r uto=z trtn.<m z a D tn I t-@$ Eidu f q;sd I.t A z___l I I I a m_ f')69 3cr3 s3 z ITTI mo=\26 fri { -{f,-T1-TS I'h++mzl*fiifrkn nl-C=rfC, D!n;lm-f -< mr-lZ F;;F IO m-{a-./-ts-.!'-'YD@H- P c)@ i-nn OU.00.o T1 N IJI!nC)(n mm -{mzm omD til3 c:{30-t fl u)(, o UI@5 e rr(,mc) m D= C)1aO-m-t z fJCf'n!()3-r'l D at)I D z x t-m D x D C)m Tl r O{\ONOrrnN)=ur(r\Kjs;J:SPN!4=?[Egr llllll;I I I ctl nr I o> , zz I Po-, I zaQ I Ln{ lmm:oD I 3l I I I I o,.0 A (^)!I+--r tDl I I L-_I itsvr pJlfi (,@oo ITI! I I-U-t rnc) I\2a rri { Cf:D T!TI[=I ni-t -7 c-) (/)c)cf{r zm>Q>z rnS(f z a Cf T l+g;(, (, (r{ t'- @;\I F-;NE)!b-$$$nee I T' 'T1 moo D=c 1Z,Tlrl- {NT gH xur r- cD{co lv G)I!'r1!a!O z. c)I m D m!;{!o ul (.)I-I=t rsd lt irr b, I 'tl l3 sQ aA)1T --3BD Zlt-crmh N ot, S^3*fi ;E 3rfi^ ] -#3 B=*eil ElruQ 2: t-t \ -{=?gd ---6; r-r*f'r- =A=iq d=lD-n z HbP '-'.sfrn 3-=D(n TN m!n 5 ul t\)o-o!I 5N)@c!5A blv'n!rv (,-o I$; H!o N g s I t--o-bd'in Tl I-U(, mcf-D '- )(- \r-tZ-l u'----l -r + I!lTl -t -'t- A TS a 36 rve@:-oul UII I$F qr tr NUr$N ul +a+rIDl l-l'--r- -l-T C9!6---^N(, lioN-oo-o. I'rl P6 C!ul'!I c)Ocf f, cfD rH s1Z T H I H H I LTJ a+a I\--?A?I I-!N)5 NOO(JluN5!firH e 4\I ttllltr,lll A I[;lu/l L ll{.o lo ol ,l o L---l ', i rflD h5 r)cf T a g[ fiE ilHfrs s= 4qt) -t -F iF ?EEI PT 3. Ipilt ir fii <F 6+tg Ets* u;aFIa 7.nc vr 9 i H= $rf = F'tr-{ - DQru fr B I;;(](]=N\/I!s rvs co i-Or=o,!F rn.<NJ F HF N!g N)a lv (, o I lo{-o b (9 N rt r m D z z r"l a atr I rv-o T m a a C:0 m lf, al 7 D 2 F.)a T m m o aa m r m f-)r Cf a a m!l 3 m r-).:E c]a U)m a 7 c)a (t)!c){m p C)m@p p-o N c9 s cs s s@s s N)A s (, s\)(,'o.o U]@s s m n D-l Cf n o I o r D 1!3 r*T{T{ BVPS-2 UFSAR Rev. 17 10.2-1 10.2 TURBINE GENERATOR 10.2.1 Design Bases
- 1. The turbine generator (TG) is a 1,800 rpm, tandem compound, four-flow, reheat steam turbine with 44 inch
last stage blades and a single-stage of reheat. The output of the TG at the NSSS thermal power of 2910 MWt is shown on Figure 10.1-1. During faulted and emergency conditions, the turbine is shut down.
- 2. The generator is 1,800 rpm, direct-connected, three-phase wye-connected, 60 Hz, 22,000 V, hydrogen inner-cooled, synchronous generator rated at 0.92 pf, 0.61 short circuit ratio, and a maximum hydrogen pressure of 75 psig, and an
output of 1,070,000 kVA at turbine VWO conditions.
- 3. The brushless excitation system consists of a 60 Hz, 1,800 rpm air-cooled ac exciter and a rectifier assembly mounted on a common shaft. The exciter is rated for a maximum output of 3,900 kW at 525 V.
- 4. The TG is designed in accordance with Regulatory Guide 1.68, as it relates to preoperational and start-up testing
of system components, equipment, and systems.
- 5. The TG unit control is through an electro-hydraulic control (EHC) system capable of controlling the speed, load, and steam flow under steady-state and transient conditions. The intended mode of operation is for base-loaded conditions.
- 6. The TG unit is designed in accordance with General Design Criterion 4, as it relates to the protection of structures, systems, and components important to safety from the effects of turbine missiles by providing a redundant turbine overspeed protection system.
- 7. The TG unit is a Westinghouse Electric Corporation (Westinghouse) design and is built in accordance with Westinghouse and industry standards and codes. The moisture separators/reheaters are built in accordance with ASME Section VIII.
- 8. The TG is capable of increasing or decreasing electrical load at a rate consistent with the requirements of the nuclear steam supply system manufacturer (Section 7.7) and the turbine manufacturer's loading rate recommendations. However, under emergency conditions, the TG can accept
greater load changes.
BVPS-2 UFSAR Rev. 16 10.2-2 10.2.2 Description The TG system consists of one double-flow high pressure casing, two double-flow low pressure casings, four moisture
separators/reheaters, four high pressure inlet throttle valves, four high pressure inlet governing valves, four low pressure reheat stop valves, four low pressure intercept valves, an EHC, provisions for extracting steam for six stages of feedwater heating, a lubricating oil system, gland steam sealing system, turbine turning gear system, generator seal oil system, and
hydrogen cooling system. The turbine steam valves and piping are shown on Figure 10.2-1. Each high pressure steamline to the high pressure turbine contains automatically- or manually-controlled throttle valves
for wide range speed control during start-up, and governor valves for controlling steam flow for synchronizing and load control. These valves are located in the steam chest just upstream of the high pressure turbine inlet. The reheat stop and intercept valves are located in the crossover piping between the moisture separators/reheaters and low pressure turbine inlet. These valves are of the on-off type and offer redundant, positive isolation of the steam flow path to the low pressure turbine. Steam exhausting from the high pressure turbine flows to the moisture separators/reheaters, which uses chevron separator vanes for moisture separation and integral live steam U-tube reheaters with Type 439 stainless steel tubes. The moisture separators/reheaters are designed in accordance with ASME Section VIII. Each of the four steamlines between the reheater outlet and low pressure turbine inlet is provided with a crossover stop valve and a crossover intercept valve in series. These valves, operated by the turbine electro-hydraulic control system, function to prevent turbine overspeed. A safety valve is installed on each moisture separator/reheater to protect the separators/reheaters and crossover system from overpressure.
The safety valves are designed to pass the flow resulting from closure of the crossover stop or intercept valves with the main turbine throttle valves wide open. These valves discharge to
the condenser. There are two parallel flow paths to each of the two low
pressure casings, resulting in a total of four steam flow paths. In the event of a large scale, external electrical load decrease of up to 85 to 100 percent, the turbine bypass system (TBS) relieves main steam directly to the condenser, thus it is capable of preventing a reactor or turbine trip and the lifting of the main steam safety valves. The bypass line provides a capacity of greater than 40 percent of full load steam. Turbine bypass control is covered more fully in Section 7.7.1.8 and TBS capability and operation is covered in Section 10.4.4.
BVPS-2 UFSAR Rev. 15 10.2-2a Six stages of extraction steam are provided on the turbine. Redundant extraction steam isolation valves are located in the extraction steamlines to prevent a turbine overspeed after a trip. They consist of a spring-assisted, air-actuated swing
check valve, (nonreturn valve) and a motor-operated gate valve in series. Upon a turbine trip, the nonreturn valve (NRV), which is equipped with a spring-assisted, side closing cylinder
for positive closing, is closed by venting the air in the cylinder and spring action. The extraction steam system is described more fully in Section 10.4.11.
The TG lubricating oil system consists of an oil reservoir, a shaft-driven main and six motor-driven oil pumps, vapor
extractor, oil coolers, centrifuge type lube oil purifier, associated piping, and various control devices. A particulate and water coalescing type lube oil purifier was added subsequent to obtaining the plant operating license. The reservoir is equipped with high and low level switches, temperature indicators, and a local level indicator.
BVPS-2 UFSAR Rev. 12 10.2-3 During normal unit operation, lubricating oil is supplied by an oil ejector mounted inside the oil reservoir. The ejector discharge pressure is sufficient to assure a positive supply of lubricating oil to all bearings. Additionally, the ejector maintains the main (shaft-driven) oil pump net positive suction head, which in turn operates the ejector.
An ac motor-driven bearing oil pump and an ac motor-driven high pressure generator seal oil backup pump are provided, each having a dual function. The bearing oil pump serves to provide lubricating oil to the bearings when the unit is on turning gear and acts as a backup should the main oil pump fail. The high pressure generator seal oil backup pump serves to provide high pressure oil to latch the mechanical overspeed trip mechanism during start-up and acts as a seal oil backup for the generator (Section 10.2.2.4). A pressure switch automatically starts the
high pressure generator seal oil pump and the bearing oil pump when bearing oil pressure is low.
A dc motor-driven emergency oil pump serves as an emergency backup for the ac motor-driven bearing oil pump when the ac power is lost. A pressure switch automatically starts the dc
motor-driven oil pump when the bearing oil pressure is low. All of the pumps are controlled from the main control room via
individual control switches. The pressure switches controlling the start of the bearing oil
pump, the high pressure generator seal oil backup pump, and dc emergency oil pump will automatically start the pumps on falling pressure. Once energized, the pumps must be shut down manually. A test valve is provided to test the cut-in points of the pumps. The test can be made during normal operation.
Three bearing oil lift pumps provide lift oil to the low pressure bearings to meet the requirements for placing the unit on turning gear. Bearing oil pressure must be at least 5 psig
to permit starting the turning gear motor. The Beaver Valley Power Station - Unit 2 (BVPS-2) turbine oil reservoir receives its oil supply from the Beaver Valley Power Station - Unit 1 (BVPS-1) lubricating oil storage tank. The BVPS-1 fill pump discharge is piped to supply oil to either the
BVPS-1 or BVPS-2 turbine oil reservoirs. This pump has a capacity of 100 gpm at 80 psig discharge pressure and takes its suction from the BVPS-1 lubricating oil storage tank.
The temperature of the oil supply to the bearings is automatically controlled by the cooling water flow regulator
valve and temperature control device located in the oil piping. A bypass stream of turbine lubricating oil flows continuously through an oil conditioner to remove any water and other impurities.
BVPS-2 UFSAR Rev. 14 10.2-4 One of the lubricating oil purifiers is an integral centrifuge unit consisting of a feed pump, a centrifuge type separator, and controls. A supply line from the turbine oil reservoir feeds the oil to the purifier where it is cleaned and then returned back to the turbine oil reservoir. The purifier has a purifying capacity of 3,000 gallons per hour (gph).
The inlet line to the purifier is provided with a loop seal arrangement, complete with a sight glass, to prevent siphoning
of oil from the reservoir. Water from the demineralized water distribution system is used to seal the purifier against oil spillage. A flow-type emergency breakover switch mounted on the water outlet of the purifier allows for normal water discharge and prevents
excessive flow of water or oil. The purifier is provided with a bowl drain recovery kit such that when the purifier is shut down, the contents of the self-draining bowl can be reclaimed. Recovered oil is reintroduced to the purifier feed line when the unit is started.
10.2.2.1 Turbine Control System
10.2.2.1.1 Normal Operation The TG system is equipped with an analog type EHC system to regulate turbine generator speed, load, and steam flow, and to protect the turbine from reaching a destructive overspeed condition. The EHC system consists of a solid-state electronic control cabinet, an operators panel, steam valve servo actuators, high pressure fluid control system, and a lube oil and associated electro-hydraulic emergency trip system.
Valve opening activation is provided by a high pressure hydraulic system (approximately 2000 psig). However, valve closure under emergency tripping is provided by powerful springs
aided by steam forces when the high pressure hydraulic fluid is dumped from the piston by the tripping action.
During start-up, from turning gear to rated speed, the EHC system is in a manual wide-range speed control mode. Speed
control is accomplished by increasing the speed demand reference signal manually to bring the shaft to rated speed at a controlled and selectable rate. The resolution of the
controller with respect to actual speed versus set speed is 1.0 rpm. When the turbine reaches rated speed and the main generator circuit breaker is closed, the EHC system changes from
a speed controller to a load controller. The EHC system provides the ability to increase or decrease electrical load at a controlled and selectable rate with a resolution of 0.1
percent load.
BVPS-2 UFSAR Rev. 16 10.2-5 The control of the reactor and TG is accomplished from the main control room, which contains all instrumentation and control equipment required. The control system allows BVPS-2 to accept step load increases of 10 percent and ramp load increases of 5 percent/min over a load range of 15 to 100 percent power. For reactor power levels below the P-9 permissive setpoint, the unit is designed to accept a turbine trip without initiating a reactor trip; however, the Plant Technical Specifications require an anticipatory reactor trip following turbine trips at reactor power levels above the P-9 permissive setpoint. The turbine bypass steam dump capacity permits a 50 percent external load rejection from full load without a turbine or reactor trip. The control of the reactor with turbine is covered more fully in Section 7.7. The turbine bypass system's capability is covered more fully in Section 10.4.4.
The Westinghouse analog EHC system and electromechanical trip system include three separate speed sensors, mounted on the turbine stub shaft located in the turbine front pedestal as
follows: 1. Mechanical overspeed trip weight (spring-loaded), 2. Electro-magnetic pickup for main speed governing channel, and
- 3. Electro-magnetic pickup for overspeed protection control channel. (This pickup uses the same toothed wheel as item 2.)
10.2.2.1.2 Turbine Trip System
The electro-hydraulic emergency trip system consists of an emergency trip block, two test blocks mounted on the governor pedestal, a cabinet containing all the electrical and electronic hardware, a remote trip test panel, and main control board-mounted trip pushbuttons for manual tripping. The emergency trip system offers a redundant overspeed protection (Section 10.2.2.1.3) via electro-hydraulic and mechanically-actuated systems, an auto stop trip (AST) system which monitors various TG parameters, an overspeed protection controller (OPC) which monitors turbine speed and load, and a mechanical overspeed trip weight. The system also offers provisions for detection and diagnosis of failed devices, and provisions for inservice maintenance and inspection.
Under normal conditions, the AST solenoid valves and the interface diaphragm valve are closed, blocking the path to drain off the auto-emergency trip header fluid. The pressure in the trip header line keeps the dump valves associated with each steam valve closed. Upon collapse of this pressure, the dump valve will unseat, causing the throttle valves, governor valves, intercept valves, and reheat stop valves to close in approximately 150 milliseconds.
The AST solenoid valves are separated into two channels, with two valves per channel, which are kept energized from separate relay trains in the emergency trip system cabinet. If a trip
contingency BVPS-2 UFSAR Rev. 8 10.2-6 should occur, at least one valve from each channel must function to trip the turbine. However, each channel can be tested separately while on line without causing or preventing a valid trip. Since one valve from each channel must function to cause a trip, a single valve failure will neither cause a trip nor prevent a trip. The trip signals for which AST action will automatically trip the turbine are listed in Table 10.2-1. Lubricating oil is used as the control medium for the interface diaphragm valve in the mechanical-hydraulic trip system. The diaphragm valve is the link between the lube oil system and the high pressure EHC system. Lube oil supplied to the valve acts to overcome the spring force to keep the valve closed. Upon a
decay of the lube oil pressure the valve will unseat, causing the EHC fluid to drain, thus tripping the turbine.
10.2.2.1.3 Overspeed Protection Overspeed protection is accomplished by the actuation of either
the OPC, the mechanical overspeed trip weight, or by de-energizing the AST solenoid valves.
The OPC action will de-energize and open the solenoid-operated dump valves to collapse the OPC header pressure, thus closing the governor and interceptor valves. Check valves prevent collapse of the throttle and reheat stop valves header pressure. The OPC action will occur if the main generator breaker should open when the turbine is above 30 percent load or turbine overspeeds to 103 percent of rated speed. There are two OPC valves furnished for the system for redundant protection to prevent the failure of one valve from inhibiting a valid trip.
The mechanical overspeed trip weight uses a turbine shaft-mounted weight with its center line offset. During normal operation conditions, it is held in place against centrifugal force by a
BVPS-2 UFSAR Rev. 2 10.2-6a spring. When turbine speed reaches 111 percent of rated speed, increased centrifugal force overcomes the spring's compression and the weight moves outward with a snap action, releasing lube oil BVPS-2 UFSAR Rev. 2 10.2-7 pressure on the diaphragm of the interface diaphragm valve. This drains the AST header pressure and closes all the throttle, governor, reheat stop and intercept valves.
The electro-hydraulic overspeed trip utilizes a speed pickup mounted adjacent to the turbine stub shaft. When the speed sensor indicates 111.5 percent of rated speed, the relay logic in the trip cabinet will be such that all four AST solenoid valves will open and trip the turbine.
The throttle and governor valves and the stop and intercept valves are arranged in a redundant fashion such that failure of one valve will not cause or prevent a turbine trip.
The extraction steam lines to the first through fifth point heaters contain nonreturn valves which are used to protect the turbine from a reverse flow. Each nonreturn valve is a swing check valve with a side-closing, spring-loaded cylinder. During normal operation, air pressure compresses this spring so the disc can swing freely. Upon receipt of a low AST header pressure signal or if the AST fluid-operated air pilot valve is vented (turbine tripped), the cylinder air pressure is released
and the spring provides a rapid and positive closure of the check valve to prevent the fluid inventory in the down-stream heater from flashing and entering the turbine and providing
energy to accelerate the turbine. The sixth point heaters have no nonreturn valves because there is a low inventory of fluid in these heaters so that overspeeding the turbine due to flashing
in the heater is prevented. A single failure of any component will not lead to destructive overspeed. A multiple failure, including combinations of undetected electronic faults, mechanically stuck valves, and hydraulic fluid contamination, at the instant of load loss would be required to reach destructive overspeed. The probability of such joint occurrences is extremely low due to the high design reliability of components and frequent inservice testing.
The effects of turbine missiles on safety-related systems or components is not required to be analyzed because the probability of generating a turbine missile is acceptably low, as described in Section 3.5.1.3.
10.2.2.2 Turbine Gland Sealing System The TG is sealed using labyrinth type shaft seals. The seal
system is supplied with steam at 150 psig from the auxiliary steam system or 125 psig steam from the main steam system. Auxiliary steam is used during start-up and when main steam
becomes available, the auxiliary steam supply is isolated.
BVPS-2 UFSAR Rev. 15 10.2-8 The steam to the high pressure glands is maintained at 5 psig. Steam to the low pressure glands is maintained at 1 psig. Any excess steam is bypassed to the condenser through a spillover valve. The turbine gland sealing system is described more fully
in Section 10.4.3. 10.2.2.3 Inspection and Testing Requirements
The main turbine throttle and governor valves and the intercept and reheat stop valves are exercised in accordance with the requirements contained in the Licensing Requirements Manual to detect possible valve stem sticking. The valves are closed and then reopened during this procedure. Mecha nical overspeed trip tests are performed on an 18 month frequency in accordance with the Licensing Requirements Manual. 10.2.2.4 Generator The generator is sized to a ccept the output of the turbine. The generator is equipped with an excitation system, hydrogen control system (HCS), and a seal oil system. The generator terminals are connected to the main step up transformer and unit station service transformers through the isolated phase generator leads.
The air-cooled generator excitation system controls the voltage of the generator. The HCS includes pressure regulators, condition monitor for detection of thermally produced particulate, purity monitor for recording changes in gas density, temperature pressure transmitters, liquid detector, and water-cooled gas coolers. A circuit to supply and control the CO is used during filling and purging operations to avoid explosive gas mixtures. A hydrogen seal oil system prevents hydrogen leakage or air inleakage through the generator shaft seals. This system includes pumps, controls, and a storage tank, and degasifies the oil before it is returned to the shaft seals. 10.2.2.5 Generator Hydrogen
The HCS is used to cool both the rotor and stator. The rating of the generator is a function of the hydrogen pressure which is normally 75 psig. The system includes pressure regulators for
control of the hydrogen gas, and a circuit for supplying and controlling the carbon dioxide used in purging the generator during filling and degassing operations. To prevent hydrogen leakage through the generator shaft seals, a hydrogen seal oil system is provided. This system, which includes pumps, controls, and a storage tank, deaerates the oil before it is
sent to the shaft seals. Hydrogen is fed to the generator to maintain design pressure. A continuous hydrogen feed and bleed is controlled from the hydrogen control panel. Manual shutoff valves are provided in the turbine building. A flow meter in the hydrogen feed line to the generator and a flow meter in the vent line from the hydrogen control panel provide a means to measure leakage. The bulk storage facility also
BVPS-2 UFSAR Rev. 20 10.2-9 supplies hydrogen to the chemical and volume control tank (Section 9.3.4) and the boron recovery system (Section 9.3.4.6).
To avoid an explosive hydrogen-air mixture while charging the generator with hydrogen, carbon dioxide is used as the purging
agent. While the generator is being filled with carbon dioxide, the percentage of carbon dioxide in the air/gas mixture is
measured. Carbon dioxide is admitted to the generator until the
percentage of carbon dioxide in the discharged gas is in excess
of 70 percent. After purging the air from the generator, hydrogen is admitted purging the carbon dioxide. Purity of the hydrogen is monitored during operation to prevent an explosive
mixture.
10.2.3 Turbine Rotors and Turbine Disc Integrity
The probability of a turbine disc failure has been assessed as part of the design of Siemens 13.9m LP rotors. The risk from missiles created during a hypothetical turbine-generator failure on safety-related systems or components is discussed in Section 3.5.1.3. Integrity of the turbine discs and rotors is demonstrated by information provided in that section.
10.2.3.1 Materials Selection
Forgings produced for nuclear turbine discs and rotors are made to comply with Siemens specifications. The detailed materials specifications, fabrication history, and chemical analysis of the disc and rotor forgings are considered proprietary information of the turbine manufacturer, Siemens. More general ASTM specifications for discs and rotors (ASTM A-470 Class 7, and ASTM A-471 Class 4) do exist and may be used for guidance.
The forgings for the rotor shafts and disks are made from 3.5% nickel steel alloy. This material has been selected because of its low transition temperature. The forging technique has been advanced to minimize impurities. In addition to the ideal properties for low temperature LP turbine operation, the material also provides high yield strength at the temperature levels of the LP turbine inlet.
The disc material property requirements are listed in Table 10.2-2 along with the comparable ASTM requirements for
ASTM A-470. Any deviation from specification requirements for material
composition and properties is evaluated by Siemens.
BVPS-2 UFSAR Rev. 20 10.2-10 10.2.3.2 Fracture Toughness
The detailed materials specifications, fabrication history, and chemical analysis of the disc and rotor forgings are considered proprietary information of the turbine manufacturer, Siemens. The specific fracture toughness properties of the LP rotor discs are considered in the design of the turbine rotating components.
10.2.3.3 Pre-service Inspection
All rotors and discs are given pre-service inspections. In addition, Siemens utilizes ultrasonic inspection techniques for in-service inspection (ISI) of bores and keyways of shrunk-on discs in low pressure rotors. These techniques have undergone extensive development and qualification. As a part of the inspection during manufacturing, discs are rough machined as close as practical to the forging drawing dimensions prior to heat treatment for properties. After heat treatment, the forgings are machined to the dimensions of the
forgings drawing and stress relieved.
Low pressure and high pressure rotors are rough machined with maximum stock allowance prior to heat treatment and stress
relieved.
After heat treatment, the rough machined disc is ultrasonically
inspected on the flat surfaces of the hub and the rim (Figure 10.2-11). If ultrasonic indications are detected in the hub or the rim sections, additional ultrasonic testing may be
required.
Centerline tangential stresses of a no-bore rotor are approximately half the tangential bore stresses of a bored rotor
of the same size. This significantly increases integrity of no-bore rotor for a given size sonic indication compared to that of
bored rotor of similar design.
The rotors are ultrasonically tested after heat treatment and rough machining. The sonic indications are either removed or evaluated to determine that they will not grow to a size that will compromise the integrity of the component during its
service life.
The finished machined discs are fluorescent magnetic particle-inspected except for blade grooves. The disc is shrunk on to
the shaft. After the disc is cooled, equally spaced, round-bottomed holes or keyways are drilled and reamed and are inspected using dye penetrant techniques. No indications are
allowed in the bore or keyway regions.
BVPS-2 UFSAR Rev. 20 10.2-11 Siemens HP rotors designed with KWU-technology integral shroud blades are spin-tested to 125 percent of rated speed to allow
these Torsionally-preloaded blades to seat properly in the rotor
grooves prior to final shroud seal land machining. The Siemens 13.9 m LP Rotors are spin tested to 120 percent of rated speed. The maximum speed anticipated following a turbine trip from full
load is less than 110 percent of rated speed.
10.2.3.4 Turbine Disc Design
The highest anticipated speed resulting from a loss of load is
less than 110 percent of rated speed. The HP rotor is spin-tested at 125 percent of rated speed and LP rotors are spin-tested to 120 percent of rated speed. Turbine shaft bearings are designed to withstand any combination
of the normal operating loads, anticipated transients, and
accidents resulting from a turbine trip. The low pressure rotor bearings are provided with lifting capabilities. During start-
up and on turning gear high pressure, lubricating oil lifts the
low pressure rotor to minimize wear on the bearing surface.
The rotors are designed so that the response levels at the
natural frequency of the turbine shaft assemblies are controlled between 0 and 20 percent overspeed so as to cause no distress to
the unit during operation.
The new no-bore HP rotor can be given a volumetric UT exam without removal of the rotor from the unit. The rims of the low
pressure discs can also be inspected.
BVPS-2 UFSAR Rev. 20 10.2-12 10.2.3.5 In-Service Inspection
The inservice inspection of the steam turbine assembly will be conducted to provide assurance against brittle failure of a disc at design overspeed. The inservice inspection will be performed approximately every 10 years, coincident with a plant shutdown.
The inspection interval is based upon the probability of generating a turbine missile as a function of actual operating time. The operating time related probabilities associated with
the BVPS-2 low pressure turbine rotor are shown on Figure 3.5-2. The inservice inspection will consist of visual and surface examinations of couplings, coupling bolts, high pressure turbine
rotor and discs, and low pressure turbine blades. Low pressure turbine rotors and discs will also be volumetrically examined
using the inspection techniques described below.
Inspection Techniques
For the no-bore HP rotor, Siemens has developed a phased array volumetric UT technique that can detect off-center flaws in the forging. This capability allows improved characterization of internal flaw shape and size by measuring sound reflection of
the same indication from several different angles.
Tangential Aim Technique
In the tangential aim technique, an ultrasonic transducer is
mounted on a plexiglas block that sits on the disc hub (Figure 10.2-11). The plexiglas block is contoured so that it is in complete contact with the disc hub. The ultrasonic waves are
directed tangentially towards the bore/keyway so that any cracks above the bore/keyway area will be perpendicular to the sound beam and reflect the sound. A careful analysis of the time differences between the echos from the keyway and cracks should
allow discrimination of false indications.
Radial Aim Technique
Because stress corrosion cracks have been found to be branched, the radial aim technique has been successfully used to verify
the presence and quantify the depth of cracks. In this technique, the ultrasonic waves are directed perpendicular to
the keyway/bore (Figure 10.2-12). The depth of the crack is estimated from the time difference between an echo from the
crack and the echo from the keyway crown or bore.
When the turbine is disassembled, a visual and magnetic particle examination is made externally on accessible areas of the high pressure rotor, low pressure turbine blades, and low pressure
discs. The coupling and coupling bolts are visually examined.
BVPS-2 UFSAR Rev. 20 10.2-13 The ISI program for throttle, governor, reheat stop and interceptor valves is in accordance with vendor recommendation of 15, 27, and 39 months after initial start-up of a turbine. In this program, some valves are inspected 12 to 15 months after
start-up, others 24 to 27 months, and the remainder 36 to 39 months so that all valves are inspected at least once in the 39 months of operation following initial start-up. Throttle and
reheat stop valves are inspected twice in this period. After
this initial inspection program is completed, valves will be
inspected periodically in accordance with Westinghouse
recommendations.
Functional testing of the turbine steam inlet valves will be performed in accordance with the requirements contained in the
Licensing Requirements Manual. These tests can be performed while the unit is carrying load. The purpose of the test is to ensure proper operation of the throttle, governor, reheat stop, and interceptor valves. The operation of these valves will be observed during the test by an operator stationed at the valves. Movements of the valves should be smooth and free. Jerky or intermittent motion may indicate a buildup of deposits on
shafts.
10.2.3.6 High Temperature Properties
The operating temperatures of the high pressure rotors in turbines operating with light-water-reactors are below the creep rupture range. Creep rupture is, therefore, not considered to be a factor in assuring rotor integrity over the lifetime of the
turbines.
10.2.4 Safety Evaluation
Beaver Valley Power Station - Unit 2 is a pressurized water reactor. As such, during normal operation the concentration of
radioactive contaminants is minimal and no shielding is required
for the TG, thus permitting unlimited access. There is no equipment required to be QA Category I (safety related) as
listed in Table 3.2-1 in the turbine building, thus, rupturing
of the connection joints between the low pressure casing and the
condenser will not adversely affect any QA Category I equipment.
The turbine stop and control valves and reheat stop and
intercept valves are arranged such that failure of any one valve
will not cause an overspeed event.
10.2.5 References for Section 10.2
Westinghouse Electric Corporation 1971. Scientific Paper.
71-1E7-MSLRF-P1. MSTG-lP.
Siemens Technical Report EC-10079, BB-281-13.9m Low Pressure Turbine Design Analysis Report for Beaver Valley Unit 2, Revision 1, June 15, 2010. Siemens Technical Report CT-27472, Missile Report, Revision 2, August 5, 2011.
BVPS-2 UFSAR Tables for Section 10.2
BVPS-2 UFSAR Rev. 17 1 of 1 TABLE 10.2-1 TURBINE TRIP SIGNALS
- 1. Low turbine bearing oil pressure,
- 2. Low vacuum in either condenser, 3. Loss of various power supplies to turbine control and protection,
- 4. Excessive wear (axial movement) of the turbine thrust bearings in either direction,
- 5. Electrical protection trip (generator),
- 6. Turbine overspeed trip, 7. Turbine anti-motoring (generator is in motoring mode, turbine is anti-motoring), or
- 8. External trips:
- a. Reactor trip,
- b. Feedwater isolation,
- c. Manual trip, or
- d. AMSAC.
BVPS-2 UFSAR Rev. 20 1 of 1 TABLE 10.2-2 ASTM MATERIAL PROPERTIES FOR SIEMENS TURBINE ROTORS AND DISCS Turbine Component ASTM Spec/CI 0.2% YS (KSI) UTS (KSI) Min ELONG (%) Min RA (%) Max FATT ( F) Min CVN Room Temp (ft-lb) HP Rotor A470 CI 7 100 min 120-135 18 52 30 40 LP Rotor Shafts A471 CI 7 100 min 120-135 18 52 30 40 LP Rotor Disks A471 CI 4 110-130 120 min 17 45 0 45
FROM TURBINE STEAM LINE C FROM TURBINE (r---... STEAM LINE A STEAM CHEST FROM MAIN STEAM FROM MAIN STEAM EQUALIZATION HEADER '-'-----+__,--..TO FIRST POINT HEATER 2FWS-H21A REV. 1 2 EQUALIZATION ZTMA-1 RL _,....--L---+-. HEADER MOISTURE SEPERATOR REHEATER H21C 2TMA-2RL TO 2ND..._____ _ _. POINT HEATERS H.P. TURBINE TO POINT HEATERS -........_---+-' ______... MOISTURE SEP REHEATER H21A TO FIRST POINT HEATER 2FWS-H21A FROM MAIN STEAM EQUALIZATION HEADER ____. '-.!...-...----+---' T 0 F I R S T POINT HEATER 2FWS-H21B ) TO 2ND ..___ __ _..,.\ PO I NT L----------. HEATERS FROM TURBINE STEAM L I NE B ,-t-( ___., __ _ FROM TURBINE STEAM LINE D 6TH POINT HEATER 2CNM-CND21A CONDENSER TO 3RD PO I NT HEATER ...._.._...__,...._----' TO 4TH POINT HEATER TO 5TH POINT HEATERS MAIN STEAM EQUALIZATION HEADER FIRST POINT HEATER 2FWS-H21B MOISTURE SEPERATOR REHEATER H21D CONDENSER TO 3RD POINT HEATER TO 4TH POINT HEATER 2TMA-21L 2TMA-2IR 2TMA-2RR ALL VALVE AND EQUIPMENT IDENTIFICATION NUMBERS ON THIS FIGURE ARE PRECEDED BY THE SYSTEM DESIGNATOR H2TMSH UNLESS OTHERWISE INDICATED. F I GURE 1 0. 2 -1 TURBINE STEAM SYSTEM
REFERENCE:
STATION DRAWINGS OM 26-1 AND OM 23A-1 BEAVER VALLEY POWER STATION UNIT NO. 2 UPDATED FINAL SAFETY ANALYSIS REPORT LP TURBINE DISC BORE FIGURE 10.2-11 TANGENTIAL AIM INSPECTION TECHNIQUE BEAVER VALLEY POWER STATION-UNIT 2 FINAL SAFETY ANALYSIS REPORT
CRYSTAL / O:Z-PLEXIGLAS ECHOFROM It APEX OF ____. l6ECHO FROM KEYWAY---CRACKS LP TURBINE DISC C __ :::: ..... "" KEYWAY BORE FIGURE 10.2-12 RADIAL AIM INSPECTION TECHNIQUE BEAVER VALLEY POWER STATION-UNIT 2 FINAL SAFETY ANALYSIS REPORT BVPS-2 UFSAR Rev. 12 10.3-1 10.3 MAIN STEAM SUPPLY SYSTEM The main steam supply system (MSSS) carries steam from the steam generators in the containment to the main turbine in the turbine building and to the auxiliary feed pump turbine in the safeguards area. The system also supplies steam to the auxiliary steam system and turbine gland seal system. The MSSS
is shown on Figure 10.3-1.
10.3.1 Design Bases
The MSSS is designed in accordance with the following criteria:
- 1. General Design Criterion 1, as it relates to the requirement that structures, systems, and components important to safety be designed, fabricated, erected, and tested to quality standards commensurate with the importance of the safety functions to be performed.
- 2. General Design Criterion 2, as it relates to safety-related portions of the system being capable of withstanding the effects of natural phenomena such as
earthquakes, tornadoes, hurricanes, and floods.
- 3. General Design Criterion 4, as it relates to safety-related portions of the system being capable of withstanding the effects of external missiles and internally generated missiles, pipe whip, and jet
impingement forces associated with pipe breaks.
- 4. General Design Criterion 5, as it relates to the capability of shared systems and components important to safety to perform required safety functions.
- 5. General Design Criterion 34, as it relates to the system function of transferring residual and sensible
heat from the reactor coolant system (RCS).
- 6. General Design Criterion 35, as it relates to the requirement that abundant emergency core cooling be provided such that damage to reactor components is minimal following any loss of reactor coolant.
- 7. Regulatory Guide 1.29, as it relates to the seismic design classification of the system components.
- 8. Regulatory Guide 1.115, as it relates to the protection of structures, systems, and components important to safety against the effects of low
trajectory turbine missiles.
BVPS-2 UFSAR Rev. 0 10.3-2 9. Regulatory Guide 1.117, as it relates to the protection of structures, systems, and components important to safety from the effects of tornado missiles.
- 10. Branch Technical Position RSB 5-1 (USNRC 1981), as it relates to the design requirements for residual heat removal.
- 11. NUREG-0138 (USNRC 1976), as it relates to credit being taken for all valves downstream of the main steam isolation valves (MSIVs) to limit blowdown of a second steam generator in the event of a steamline break.
- 12. The main steam piping from the MSIV to the turbine is designed in accordance with ANSI B31.1. That portion which connects the steam generators and isolation valves is designed in accordance with ASME Boiler and Pressure Code, Section III.
- 13. The following piping and equipment of the MSSS are designed as Seismic Category I:
- a. Steam generators and supports,
- b. Main steam piping, valves, safety valves, and supports from the steam generators up to and
including the first anchor beyond the MSIVs, and
- c. Steam piping from the main steamlines through the residual heat release control valve and the atmospheric steam dump valves to atmosphere, and to the turbine drive for the turbine-driven steam generator auxiliary feedwater pump.
- 14. The main steam piping supports are analyzed for turbine trip forces as well as seismic criteria. In addition, the system is stress-analyzed for the forces and moments which result from thermal growth and deadweight. The main steam piping within the
containment annulus is analyzed for postulated pipe rupture. Sufficient separation, supports, and restraints are provided to prevent damage to the
containment liner, adjacent piping, and equipment.
- 15. The maximum flow through any one main steam safety valve, atmosphere steam dump valve, or residual heat release control valve shall not exceed 890,000 lb/hr at 1,100 psia to limit steam generator blowdown (SGB)
if a single valve fails open. The design basis for main steam safety valve sizing is discussed in Section 15.1.4. BVPS-2 UFSAR Rev. 16 10.3-3 The performance requirements of the MSSS are shown on the heat balance diagram, Figure 10.1-1, with the design and performance characteristics shown in Table 10.1-1. The MSSS is designed for 1,100 psia and 560 F, and the environmental design criteria is specified in Section 3.11 for the Class 1E components.
10.3.2 Description Steam from each of the three steam generators passes through 32-
inch outside diameter (OD) carbon steel pipes. A steam flow meter, interconnected with a three-element feedwater control system, is provided in the main steamline at the outlet of each steam generator. A MSIV in each of the three main steamlines is located in the main steam valve house, immediately outside the reactor containment. Following the MSIVs, the three main steamlines enter a single, 38-inch OD manifold. Connections for the turbine steam bypass, turbine steam sealing system, reheater supply, and auxiliary steam supply are provided at the manifold.
From this manifold, steam passes to the turbine stop trip valves and governor valves.
The MSIVs automatically prevent reverse flow of steam in case of accidental pressure reduction in any steam generator or its piping. If a steamline breaks between a MSIV and a steam
generator, the affected steam generator continues to blow down while the isolation valve prevents blowdown from the other steam generator. In addition, the MSIVs prevent blowdown through a ruptured pipe downstream of the isolation valves. This steamline break accident is discussed in Section 15.1.5.
The wye pattern globe type MSIVs are opened pneumatically and are held open by air pressure. If a pipe ruptures either upstream or downstream of an isolation valve, a main steamline isolation signal causes vent solenoids to release the air, closing the valve by spring force. Maximum closing time for the isolation valve upon receipt of the signal is 6 seconds. Valve closure prevents rapid cooling of the RCS by limiting SGB to a single steam generator. Isolation valve closure also ensures a supply of steam for the turbine-driven steam generator auxiliary
feedwater pump. Five ASME Code Section III safety valves are located in each main steamline outside the containment and upstream of the MSIVs. The combined relieving capacity of these safety valves will prevent maximum secondary system pressure from exceeding
110 percent of the steam generator secondary side design pressure of 1085 psig.
Excess steam generated by the sensible heat in the nuclear steam supply system immediately following loss of load is bypassed directly to the turbine condenser (Section 10.4.1) by means of two turbine steam bypass lines (Section 10.4.4), which provide a total bypass capacity of greater than 40 percent of full load steam flow.
BVPS-2 UFSAR Rev. 16 10.3-4 All bypass valves are prevented from opening on loss of condenser vacuum, and excess steam pressure is relieved to the atmosphere through the atmospheric steam dump valves or the main steam safety valves. Interlocks are provided to reduce the
probability of spurious opening of the bypass valves. In the event that the condenser becomes unavailable during a turbine trip, excess steam generated from the RCS sensible heat and core decay heat is discharged to the atmosphere through the main steam safety valves. Radioactivity released during this discharge will be negligible since little or no primary coolant leakage is anticipated. However, continuous radioactivity monitoring is provided (Section 11.5) in case of a primary coolant leak to the secondary side through a steam generator. The control of radioactive steam released during such an event is discussed in Chapter 15. A remote electro-hydraulic-operated
atmospheric steam dump valve is also provided on each main steam header upstream of the MSIV, outside the containment. These safety grade valves, powered from a Class 1E power supply, will individually modulate to maintain a steamline pressure as determined from the main control room. Individual maximum valve capacity does not exceed 890,000 lb/hr at 1,100 psia, thus limiting SGB if a single valve sticks open. In addition, a remotely-operated residual heat release control valve capable of releasing the sensible and reactor decay heat to the atmosphere via the residual heat release header is provided. This valve is manually positioned from the main
control room. This valve is safety-related and powered from a Class 1E power supply that is redundant to the Class 1E power being supplied to the atmospheric steam dump valves described above. This one valve, which is mounted on the common residual heat release header, serves all three steam generators through connections on each main steamline upstream of the MSIV. Check
valves ensure that steam may flow to the header, but prevent reverse flow of steam as may occur if a line breaks between a steam generator and a MSIV. In addition, the residual heat release control valve is used to release the steam generated during reactor physics testing and operator training. The maximum capacity of the residual heat release valve does not exceed 890,000 lb/hr at 1,100 psia, thus limiting SGB if the valve sticks open.
Both the atmospheric dump valves and the residual heat release valves discharge to atmosphere through a diffuser for noise suppression. These diffusers do not affect the safety function
of the steam dump system. Radioactive contaminants in the steam generator are monitored by
the sampling system connections on the blowdown lines (Section 10.4.8). The operator can minimize secondary system
radioactivity
BVPS-2 UFSAR Rev. 0 10.3-4a concentrations by SGB operation, reduction in power level, and/or isolation of a faulty steam generator. An off-line post-accident radiation monitor (one detector for
each main steam line) is provided to monitor main steam line radioactivity. Section 11.5 includes a description of the monitor design and operation.
Steam is supplied from each main steamline upstream of the isolation valve to the turbine drive for the turbine-driven steam generator auxiliary feedwater pump (Section 10.4.9). The piping is arranged so that any steam generator can supply the turbine drive for this pump. The required steam flow for the
turbine drive at rated conditions is 31,000 lb/hr.
BVPS-2 UFSAR Rev. 15 10.3-5 Two normally closed, solenoid-operated trip valves are located in series in each steam supply line to the auxiliary feedwater pump. The valves receive a signal to open, as described in Section 10.4.9.5, and are of the fail open type; they are powered from the emergency power supply. Steam pressure is available at the valve inlet at all times. Check valves are provided in each steam supply line to ensure the availability of driving steam in the event of failure of a steam generator or a line break upstream of a MSIV. Indications of operating conditions are available in the main control room. The turbine speed is automatically controlled by the turbine inlet governor valve. The operator adjusts feedwater flow by throttling valves at the pump discharge. Additional description of the steam generator auxiliary feedwater pump operation is contained in Section 10.4.9. Branch connections from the main steamline between the main steamline trip valves and the turbine stop valves consist of the following:
- 1. Auxiliary steam supply,
- 2. Gland steam supply,
- 3. Reheater steam supply, and 4. Steam bypass (dump) to the condenser.
Each line is provided with shutoff capability and is classified as QA Category II. Additional data on these branch connections are given in Table 10.3-1. 10.3.3 Safety Evaluation
The MSSS is evaluated for environmental and accident conditions, high energy line breaks, and break exclusions in Section 3.6. Also, seismic and safety classifications are discussed in Section 3.2.
The MSIVs are designed to close within 5 seconds and required to close at a maximum of 6 seconds after receipt of a main steamline isolation signal. If a main steamline rupture occurs, a steamline low pressure signal causes the isolation valve in each of the three main steamlines to trip closed. If a rupture occurs downstream of the trip valve, valve closure stops the flow of steam through the pipe rupture, thus checking the sudden and large release of energy in the form of steam, which in turn prevents rapid cooling of the RCS. The MSIV closure also ensures a supply of steam to the turbine-driven auxiliary feed
pump. BVPS-2 UFSAR Rev. 15 10.3-6 Single failure of a MSIV is discussed in Section 15.1.5. Further discussion of main steam system component failure can be found in Sections 15.1 and 15.2.
If a main steamline breaks between a MSIV and a steam generator, only that steam generator will blow down. Closure of the MSIV in the ruptured line prevents blowdown from the other steam generators.
The maximum capacity of any single main steam safety valve, steam bypass valve, residual heat release valve or atmospheric dump valve does not exceed 890,000 lb/hr at 1,100 psia inlet pressure. This feature limits the potential uncontrolled blowdown flow rate in the event a valve inadvertently fails or sticks in the open position.
Failure modes and effects analyses (FMEA) to determine if the instrumentation and control and electrical portions meet the single failure criterion, and to demonstrate and verify how the General Design Criteria and IEEE Standard 279-1971 requirements are satisfied, have been performed on the main steamline isolation system. The FMEA methodology is discussed in Section 7.3.2. The results of these analyses can be found in the separate FMEA document (Section 1.7).
10.3.4 Inspection and Testing Requirements
Piping and equipment of the MSSS designed as Seismic Category I require preoperational and periodic in-service testing. For discussion on preoperational tests, refer to Chapter 14. Section 3.9B.6.2 discusses in-service tests of valves. In-service tests of other Class 2 and Class 3 components are discussed in Section 6.6.
Test requirements of the MSIVs in the MSSS are as follows:
Prior to service, each MSIV shall be cycled from fully open to fully closed. This cycling will occur with cold and hot system conditions. During cold system condition tests (i.e., no elevated pressure or temperature), the MSIV trip closure time will be checked. Limit switch operation and indicating lights will also be checked for operability. During hot system condition (no load pressure and temperature), each MSIV will be closed by a trip signal from Train "A," then closed by a trip signal generated from Train "B". For each trip cycle the
closure time will be monitored.
BVPS-2 UFSAR Rev. 12 10.3-7 10.3.5 Water Chemistry The secondary side water chemistry is controlled to minimize metal corrosion, scale formation on heat transfer surfaces, and the accumulation of sludge in the steam generator. This is accomplished by continuous injection of chemicals to control pH and oxygen concentration, and the action of the condensate polishing demineralizer (Section 10.4.6) when utilized, which removes trace quantities of heavy metals, dissolved solids and suspended colloidal solids. In addition, the blowdown system flow rate is adjusted to minimize ionic impurities. Turbine
plant sampling is described in Section 9.3.2.2. Steam generator blowdown sampling is described in Section 9.3.2.1. During normal Beaver Valley Power Station - Unit 2 (BVPS-2) operation, the chemical feed system delivers addition chemicals separately to the condensate system by four diaphragm-type, positive displacement feed pumps. Each pump takes suction from separate 415-gallon chemical feed tanks. The injection rate (up to 13.3 gph per pump at 600 psig) is continuously controlled by manual adjustment of the pump stroke from 0 to
100 percent. Specifications for chemical control procedures are detailed in the BVPS-2 Chemistry Manual. These specifications are based upon EPRI/PWR secondary chemistry guidelines.
For wet lay-up of the secondary side, gross chemical adjustment is accomplished by three positive displacement wet lay-up pumps. The injection rate (up to 40 gph per pump at 1,200 psig) is controlled by adjustment of the pump stroke from 0 to 100 percent. A 415-gallon chemical feed tank provides concentrated chemicals for wet lay-up. Wet lay-up pumps discharge to the primary plant demineralized water storage tank (PPDWST) and the steam generator feedwater inlet.
Chemical spillage and tank overflow are drained to a chemical waste sump.
The radioactive iodine partition coefficients in the steam generator and air ejector are consistent with NUREG-0017 (USNRC 1976). In the steam generator, 5 percent of the iodine leaking from the primary to secondary side is volatile and is treated
as a noble gas while the
BVPS-2 UFSAR Rev. 0 10.3-8 other 95 percent has a partition factor of 0.01. In the air ejector, the partition factor is 0.15 for the volatile 5 percent of the iodine and 0 for the nonvolatile 95 percent of the iodine. 10.3.6 Steam and Feedwater Materials
The typical material specifications used in the Code Class 2 and Class 3 main steam and feedwater piping systems are listed in Table 10.3-2. The materials used for the Code Class 2 portions
of the steam generators are discussed in Section 5.4.2.1. 10.3.6.1 Fracture Toughness
Fracture toughness testing of Code Class 2 and Class 3 components was optional in the editions of the ASME Code Section
III in effect at the time of procurement for BVPS-2. Due to successful power plant operating experience with the materials of construction, fracture toughness testing was not generally specified for the main steam and feedwater system piping and components. Fracture toughness testing was specified, however, for the weld filler metal used in the field erection of piping.
Testing is to the requirements of ASME Code Section III, NB 2400, and the applicable ASME, Code Section II, Part C, filler material specification. In addition, where components were fabricated to later editions of ASME Code Section III that required fracture toughness testing, this testing was performed in accordance with the code then in effect.
10.3.6.2 Material Selection and Fabrication
The pressure retaining materials specified for use in the Code Class 2 and Class 3 main steam and feedwater systems conform to Appendix I of ASMS Code Section III, and to Parts A, B, and C of ASME Code Section II. Compliance to Regulatory Guides 1.31, 1.36, 1.44, 1.50, and 1.85 is discussed in Section 1.8. Welding in areas of limited welder accessibility is controlled, as applicable to the materials of construction, per Regulatory Guide 1.71, as discussed in Section 1.8. Cleaning of Code Class 2 and Class 3 main steam and feedwater systems is controlled in accordance with ANSI N45.2.1, per Regulatory Guide 1.37, as discussed in Section 1.8. Nondestructive examination of tubular products was specified in accordance with ASME Code Section III. The allowable design stresses for tubular products are consistent with the degree of nondestructive testing, as required by ASME Code Section III.
10.3.7 Instrumentation Requirements
Control switches with indicating lights are provided in the main control room for the MSIVs. These valves have an extra set of indicating lights located on the MSIV logic cabinet. These MSIVs require electric power for opening, which is done pneumatically. They will close upon signal actuation by mechanical spring force. These valves are opened manually
provided a main steamline isolation BVPS-2 UFSAR Rev. 0 10.3-9 signal Train A or Train B is not present. These trip valves will close provided a main steamline isolation signal from either train exists.
Testing capabilities are available at the MSIV logic cabinet for the MSIVs. Pushbuttons are provided on the logic cabinet for performing these test procedures, which consist of partial
closing and reopening of these trip valves. Control switches with indicating lights are provided in the main
control room for the main steamline bypass trip valves. These valves are opened manually. The valves will close when they receive a main steamline isolation signal, Train A or Train B.
Annunciation with associated computer inputs is provided in the main control room for the steamline stop valve not fully open
and bypass valve not fully closed. Status indicating lights are provided on the MSIV logic cabinets for emergency trips of channels A and B, solenoid valves open, solenoid valves closed, and both trips available.
Pushbuttons are provided in the main control room for manual initiation of the steamline isolation signal. This signal will be initiated automatically when a high rate of change of steamline pressure (detected in two out of three channels) of any steamline is present and steamline isolation/safety injection is blocked, Hi-2 reactor containment pressure detected
in two out of three channels or any steamline pressure low (detected in two out of three channels), either hot or cold leg isolation valve is open, and steamline isolation/safety
injection signal is not blocked. Pushbuttons are provided at the emergency shutdown panel (ESP), which will transfer control to the ESP for the steamline/safety injection block reset. A manual reset pushbutton is used to transfer control back to the main control room.
Annunciation with associated computer inputs is provided in the main control room for: loop A steamline high rate of pressure change for channels II, III, and IV; loop B steamline high rate of pressure change for channels II, III, and IV; loop C steamline high rate of pressure change for channels II, III, and
IV; one out of three steamline high rate of pressure change, containment pressure high/high-high for channels II, III, IV; loop A steamline pressure low for channels II, 111, and IV; loop
B steamline pressure low for
BVPS-2 UFSAR Rev. 10 10.3-10 channels II, III, IV; loop C steamline pressure low for Channels II, III, and IV; and steamline pressure low reactor trip and safety injection for loops A, B, and C.
Status indicating lights are provided in the main control room for these functions: steamline pressure high rate of change, one each for Channels II, III, and IV of steamlines A, B, and C; Hi-
2 containment pressure, one each for channels II, III and IV; steamline pressure low, one each for channels II, III, and IV of steamlines A, B, and C; and steamline isolation/safety injection
blocked, one each for Trains A and B. Control switches with indicating lights are provided at the
chemical feed panel for the hydrazine feed pumps, morpholine feed pumps, and wet layup pumps. The main steam safety valves (MSSVs) are provided with a Class 1E powered valve position indicator (VPI) system that monitors the positions of the safety valves. The valve position information is provided to two systems: the main steamline monitor (SLM) associated with the digital radiation monitoring system (DRMS) and the plant safety monitoring system (PSMS). The SLM measures steam effluent releases and the PSMS provides safety valve position display in the control room.
10.3.8 References for Section 10.3 U.S. Nuclear Regulatory Commission (USNRC) 1976. Calculations of
Releases of Radioactive Material in Gaseous and Liquid Effluents from PWR Reactors. NUREG-0017.
U.S. Nuclear Regulatory Commission 1976. Staff Discussions of Fifteen Technical Issues Listed in Attachment to November 3, 1976 Memorandum from Director NRC to NRC Staff. NUREG-0138.
U.S. Nuclear Regulatory Commission 1981. Design Requirements of the Residual Heat Removal System. Branch Technical Position RSB
5-1. BVPS-2 UFSAR Tables for Section 10.3
BVPS-2 UFSAR Rev. 16 1 of 1 Table 10.3-1 MAIN STEAM LINE BRANCH CONNECTIONS Total of Opening/ Branch Closure System Flows Type No. of Size Time Design Normal Code (# / hr) Valve Valves (in) (sec) Code Position Reheat steam MSS 787,169 Motor- 2 10 64 ANSI B31.1 Open operated gate Steam bypass to condenser MSS >522,000 Manual gate 2 24 Not applicable ANSI B31.1 Open Pressure control air-operated diaphragm 3 8 3 ANSI B16.10 B16.5 MSS Std. SP-25* Closed Temperature control air-operated diaphragm 15 8 3 ANSI B16.10 B16.5 MSS Std. SP-25* Closed Auxiliary steam ASS 76,000 Manual gate 1 8 Not applicable ANSI B31.1 Open Pressure control air-operated diaphragm 1 8 30 ANSI B31.1 Open Gland steam GSS 9,464 Manual gate 1 3 Not applicable ANSI B31.1 Open Motor- operated gate 1 4 20 ANSI B31.1 Open Steam drain SDS 12,194 Manual gate 15 1 1/2 to 2 Not applicable ANSI B31.1 Open NOTE: *Manufacturers Standardization Society Standard - Standard Practice.
BVPS-2 UFSAR Rev. 0 1 of 1 TABLE 10.3-2 MATERIALS OF CODE CLASS 2 AND CLASS 3 MAIN STEAM AND FEEDWATER PIPING SYSTEMS
Pipes Over 24" SA 155 C1 1 Gr. KC70, or SA 106 Gr.C Up to 24" SA 106 Gr.B Fittings Over 24" SA 234-WPC or WPCW or SA 106 Gr. C 2 1/2" to 24" SA 234-WPB Up to 2" SA 105 Flanges All sizes SA 105 Bolting Studs SA 193 Gr. B7 Nuts SA 194 Gr. 2H Valves Bodies and Bonnets SA 105, SA 181 Gr.2, SA 216 Gr. WCB or WCC, SA 350 Gr. LF2, SA 352 Gr. LCB, and SA 479 Type 316 Covers SA 216 Gr. WCB or SA 516 Gr. 70 Disks and Wedges SA 216 Gr. WCB Studs and Bolts SA 193 Gr. B7 Nuts SA 194 Gr. 2H
REV. 12 VENT TO VENT TO VENT TO VENT TO ATMOSPHERE ATMOSPHERE ATMOSPHERE ATMOSPHERE VENT TO ATMOSPHERE STEAM GENERATOR SG21B 1-z w ::2 z <! 1-z 0 u w 0 VI z FROM SG C STEAM LINE FROM SG A STEAM LINE 1058 1 04B 1028 2SVS-24 TO AUX TO RESIDUAL 2SVS-FEED PUMP HEAT 1018 TURBINE DUMP FROM STEAM LINE C FROM STEAM LINE A 15 1 05A 1 05D 20 1 96 VENT TO ATMOSPHERE NOTE: MAIN STEAM LINE uBu IS TYPICAL OF LINES uAu AND uCu. LEGEND AUX AUXILIARY SG STEAM GENERATOR MSR MOISTURE SEPERATOR AND REHEAT 101B 101B MAIN TRIP SG c STEAM LINE STEAM VALVE SG A STEAM LINE TO MSR SYSTEM TO CONDENSER DUMPS 1-------...---....,..,. TO T UR B I NE STOP TRIP VALVE 3 TO TURBINE STOP TRIP VALVE 2 TO TURBINE STOP TRIP VALVE 4 TO AUX SYSTEM TO CONDENSER DUMPS TO MSR SYSTEM TO TURBINE GLAND STEAM PIPING 2FWE-P22 ALL VALVE AND EQUIPMENT IDENTIFICATION NUMBERS ON THIS FIGURE ARE PRECEDED BY THE SYSTEM DESIGNATOR u2MSS" UNLESS OTHERWISE INDICATED. FIGURE 10.3-1 MAIN STEAM SYSTEM
REFERENCE:
STATION DRAWINGS OM 21-1 AND OM 21-2 BEAVER VALLEY POWER STATION UNIT NO. 2 UPDATED FINAL SAFETY ANALYSIS REPORT BVPS-2 UFSAR Rev. 16 10.4-1 10.4 OTHER FEATURES OF THE STEAM AND POWER CONVERSION SYSTEM 10.4.1 Main Condenser
The main condenser condenses and deaerates steam from the two low-pressure turbine exhausts, the turbine bypass system (TBS) (Section 10.4.4), and miscellaneous drains.
10.4.1.1 Design Bases
The main condenser is designed in accordance with the following criteria:
- 1. The condenser is non-nuclear safety (NNS) class. The intent of Regulatory Guide 1.26, as addressed in
Section 1.8, is met by BVPS-2.
- 2. To remove 6.286 x 10 Btu/hr from the turbine exhaust at 6,713,000 lb/hr steam flow and maintain a 2.99 in Hg abs back pressure with a circulating water inlet temperature of 81F. Refer to UFSAR Figure 10.1-1 for the operating conditions for the NSSS thermal power of 2910 MWt.
- 3. To condense and deaerate the turbine exhaust at all loads.
- 4. To withstand the dynamic and thermal effects of the turbine bypass. The condenser is designed to accept up to approximately 90 percent of the full load steam flow from the TBS.
- 5. To meet Heat Exchanger Institute, Standards for Steam Surface Condensers, Sixth Edition 1970.
- 6. To meet the requirements of General Design Criterion 60 as it relates to control of releases of radioactive
materials to the environment. 10.4.1.2 System Description
The condenser is a conventional, twin-shell, single-pass, divided water box design, having impingement baffles to protect the tubes where required, with lower casing steam and condensate crossover ducts to equalize pressure, and stainless steel expansion joints between the condenser necks and the turbine exhaust flanges. One sixth point feedwater heater is located in
each condenser neck. Partitioned hotwells, with sampling points in each section, are provided to detect inleakage of circulating water (Section 10.4.5). The total hotwell water storage capacity is equivalent to approximately 4 minutes of condensate system flow at full load operation (71,000 gallons).
Condenser cooling water is provided by the circulating water system (CWS). A description of the CWS design, including heat transfer and system flow requirements, is provided in Section
10.4.5. BVPS-2 UFSAR Rev. 0 10.4-2 Table 10.4-1 gives the design parameters and performance characteristics of the main condenser. 10.4.1.3 Safety Evaluation
The condenser is designed for operation at loads up to and including maximum calculated Beaver Valley Power Station -
Unit 2 (BVPS-2) output. Tubes in the condenser are fabricated of stainless steel and are protected against impingement of high energy fluids by local baffles and by appropriate distribution
piping. Motor-operated butterfly valves are provided at the condenser inlet and outlet water boxes for maintenance isolation (Section 10.4.5.3). The potential for hydrogen buildup in the
condenser is negligible. The condenser is designed to maintain a maximum condensate oxygen content of 0.005 ppm with an air inleakage rate of 40 scfm. Noncondensable gases entering the main condenser are removed by the condenser evacuation system (Section 10.4.2).
In the event of a steam generator tube leak, with subsequent contamination of the steam, radioactive noncondensable gases separate from the steam and concentrate in the main condenser.
The main condenser air ejectors remove noncondensable gases from the condenser. The principal radioisotopes extracted from the condenser during leakage conditions are Xe-133, Xe-135, Kr-85, and Kr-88 at the rate of 0.9 Ci/sec, 0.1 Ci/sec, 0.06 Ci/sec, and 0.09 Ci/sec, respectively. These release rates are based on expected primary coolant noble gas concentrations and a 100
lb/day primary to secondary system leak rate. Radiation monitoring is provided on the discharge side of the
air ejectors. Air removal equipment (Section 10.4.2) discharges are routed to the gaseous waste disposal (GWD) system.
Pressure relief diaphragms furnished on the turbine exhaust hood avoid buildup of excessive pressures in the condenser shell.
No safety-related equipment is affected by flooding in the event of a failure of the condenser (Section 10.4.5.3).
The probable circulating water condenser leak rate is expected to be approximately .34 gpm inleakage under normal operation. This is based on one tube in every 2,000 contributing .005 gpm
inleakage. In the event of excessive main condenser leakage, circulating
water will enter the condensate system and initiate high conductivity alarms from the sampling analysis performed by the hotwell sample system, a subsystem of the secondary plant sample
system (Section 9.3.2). The condensate cleanup system (CCS) (Section 10.4.6) is capable of treating 1 gpm inleakage for normal operation and 50 gpm during major condenser leakage.
BVPS-2 UFSAR Rev. 12 10.4-3 10.4.1.4 Inspection and Testing Requirements A total of 12 sample points on the condenser hotwells are used to check the condenser for circulating water inleakage by the
secondary plant sample system. A radiation monitor is installed in the common discharge line of
the two air ejectors to detect buildup of noncondensable radioactive gases indicative of steam generator tube leakage.
The condenser shell is hydrostatically tested after installation by completely filling it with water and inspecting for leakage.
Periodic inspection will determine the extent of corrosion, accumulation of debris, scale deposits, and organic growths in the water boxes and tubes. Chlorination of circulating water
will reduce organic growths. Preoperational tests are performed on the system as described in Section 14.2.12.
10.4.1.5 Instrumentation Requirements Level controllers and level alarms on the condenser are
discussed under the condensate and feedwater systems (FWS) (Section 10.4.7.5).
The condenser hotwell temperature is monitored by the BVPS-2 computer.
Local indication is provided for the condenser hotwell level, condenser pressure, and the low pressure turbine exhaust hood pressure.
10.4.2 Condenser Evacuation System
The condenser evacuation system is designed to draw the initial vacuum in the condenser shells during start-up, maintain vacuum during operation, and dispose of the noncondensable gases from
the condenser.
10.4.2.1 Design Bases
The condenser evacuation system is designed in accordance with the following criteria:
- 1. Heat Exchanger Institute, Standards for Steam Surface Condensers, Sixth Edition 1970.
- 2. The system is nonsafety-related and is classified as NNS class.
- 3. General Design Criteria 60 and 64, with respect to provisions for controlling and monitoring the release of radioactivity to the environment.
BVPS-2 UFSAR Rev. 14 10.4-4 4. Maintain a 1.0 in Hg abs pressure in the condenser, with air inleakage of 40 scfm during operation, and provide for air removal during start-up. 10.4.2.2 System Description Two, twin-element, two-stage steam jet air ejector units, each complete with tubed inter- and after-condensers, remove noncondensable gases from the condenser shells. Each element consists of two nozzles (stages) in series. One element of each
ejector operating for each condenser shell is sufficient for normal operation. The steam jet air ejectors function by using steam from the auxiliary steam system (Section 10.4.10). The auxiliary steam that condenses in the steam jet air ejector condensers flows through a loop seal to the main condenser (Section 10.4.1).
Each condenser steam jet air ejector is designed to remove 20 cfm of free air when one element is operated with 1,200 lb/hr of steam at 125 psig from the auxiliary steam header, and a minimum of 1,250 gpm of condensate is flowing through the inter- and after-condensers.
For initial condenser shell side air removal, a vacuum priming ejector is provided for each shell. The air removed from the
condenser shells by the priming ejectors is discharged to the atmosphere. The BVPS-2 ejector steam (Section 10.4.10) for initial condenser vacuum is supplied from the Beaver Valley
Power Station - Unit 1 (BVPS-1) auxiliary steam system or from the auxiliary boilers. When auxiliary steam is being provided by the BVPS-1 auxiliary steam system, radiation monitoring, provided in the BVPS-1 air ejector gaseous discharge piping, indicates potential high auxiliary steam radiation levels. When auxiliary steam is provided by the auxiliary boilers, no
radiation monitoring is required. Auxiliary steam is manually admitted to the priming ejectors
prior to BVPS-2 start-up. Operation of the priming ejectors is initiated manually. After establishing a condenser pressure at or below 15 in Hg abs during start-up, the priming ejector is
manually shut down and the steam jet air ejector is manually started for holding vacuum. With normal operating vacuum established, only one element on each stage of the steam jet air
ejector is required to operate if condenser air inleakage is not excessive. On indication of high absolute pressure in the condenser during normal operation, the second element of each
stage of steam air ejector may be manually started. Two blowers are located on the discharge of the air ejectors. Operation of the blowers or their bypass line is initiated manually when necessary.
The effluent from the air ejectors may contain gaseous radioactivity. These gases are discharged through the process vent atop the BVPS-1 cooling tower via the BVPS-2 GWD system (Section 11.3) and the BVPS-1 GWD system.
BVPS-2 UFSAR Rev. 14 10.4-5 During normal system operation the BVPS-2 gases are discharged through a flow path that is located downstream of the radiation monitor that is used to indicate whether the discharge is acceptable. An alarm from this radiation monitor indicates a primary-to-secondary system leak. This flow path has an open valve. A high activity alarm signals the operator to manually close this valve to divert the effluent through the charcoal delay beds to the BVPS-1 cooling tower vent. Radiation monitors are provided at three separate points in the discharge flow path to detect radioactive gas concentrations. One radiation monitor is located at the discharge of the air ejectors, a second is located in the GWD system downstream of
the charcoal delay beds, and the third is located in the effluent line at the cooling tower.
Alarm set points are determined on the basis of maintaining discharges within acceptable limits for environmental releases. Air ejector gaseous discharge is monitored for radiation, upstream of the charcoal delay beds. The air ejector charcoal delay bed exhaust monitor will indicate any adsorption malfunction in the charcoal delay beds for possible operator action. The third monitor located at a final release point on BVPS-1 is for indication of unacceptable environmental releases.
The charcoal delay beds provide sufficient holdup time for the decay of isotopes such as Xe-135, Kr-89, and I-131. For the long-lived noble gases, charcoal beds holdup xenon (the heaviest gas) approximately 8.0 days and krypton approximately 0.45 day. The charcoal bed effluent is continuously monitored by the radiation monitor in the GWD system discharge.
To control moisture in the charcoal delay beds, the gas stream is chilled and dehumidified to 77F dry bulb and 55F dew point prior to entering the charcoal beds. Upon excessive primary-to-secondary leakage, which would cause excessive or unacceptable radioactive concentrations in the steam generators or main
condenser, operator action may be initiated to terminate the radioactivity release by isolating the faulty steam generator and operating the plant at reduced power.
10.4.2.3 Safety Evaluation
The condenser evacuation system has no safety function and its failure will not affect the safety functions of other equipment. Maintaining vacuum in the condenser is necessary for operation
of both the turbine bypass system (TBS) (Section 10.4.4) and the turbine generator (Section 10.2). Failure of the condenser evacuation system will cause a gradual loss of vacuum in the condenser by buildup of noncondensable gases. When the pressure in the condenser reaches approximately 6.0 in Hg abs, or the differential pressure between the twin condenser shells reaches
2.5 in Hg abs, the turbine generator trips.
BVPS-2 UFSAR Rev. 0 10.4-6 In the event of a reactor trip and the failure of the TBS to operate because of loss of condenser vacuum, the main steam flow can be discharged by the main steam safety valves and the main steam atmospheric dump valves to the atmosphere. The
radiological consequences of these events are discussed in Chapter 15.
The expected activity discharged from the air ejectors is based upon expected primary coolant activity levels combined with a primary-to-secondary side leakage of 100 lb/day (Section 11.3
and Table 11.3-3). The charcoal delay system will be operated as necessary to minimize the radioactivity released. 10.4.2.4 Inspection and Testing Requirements
Preoperational tests are performed as described in Section 14.2.12. Normally one of the two first stage ejector elements on the inter-condenser and one of the two second stage elements on the
after-condenser are in operation with the others on standby. The operation of these units is observed routinely, eliminating
the necessity for testing.
The priming ejectors normally operate only during start-up and need not be tested during BVPS-2 operation.
10.4.2.5 Instrumentation Requirements
Radiation level indicators and recorders are provided in the main control room for the discharges from the air ejectors and for the charcoal delay beds.
A pressure control valve is provided that modulates to reduce the auxiliary steam supply pressure to the proper operating
pressure of the air ejector. Alarms for alert radiation level, high radiation level, and radiation monitor failure are provided in the main control room. A control switch with indicating lights is provided in the control room for the condenser vacuum breaker valve.
Condenser pressures are recorded in the main control room and by the BVPS-2 computer system. An alarm is provided in the control
room for low condenser vacuum. Air leakage detection is an intrinsic function of this instrumentation.
10.4.3 Turbine Gland Sealing The turbine gland sealing system (TGSS), Figure 10.4-1, seals the turbine shaft (rotor) between both the turbine casings and exhaust hoods from the atmosphere, thus preventing leakage of
air into the
BVPS-2 UFSAR Rev. 0 10.4-6a condenser and steam from the turbine into the building. The system is not required to operate under accident conditions.
BVPS-2 UFSAR Rev. 18 10.4-7 10.4.3.1 Design Bases
The TGSS is designed in accordance with the following criteria:
- 1. The system is designed to seal the turbine continuously during start-up and full load operation.
The system collects and condenses gland leakoff steam.
The system also collects noncondensables.
- 2. The system is designed to prevent over-pressurization of the gland steam header if the pressure reducing
valve fails.
- 3. The system is nonsafety-related and is designated NNS class.
- 4. The system provides a backup source of steam for the auxiliary steam system.
10.4.3.2 System Description
The turbine shafts are sealed by glands of the labyrinth type. Steam from the BVPS-1 auxiliary steam system, or auxiliary
boiler via the BVPS-2 auxiliary steam system, is supplied at 150 psig to the gland steam header during start-up. When main steam
becomes available, the auxiliary steam seal path is isolated and the gland steam header is supplied by the main steam system at 125 psig. In addition, at low loads, steam leakoff from the high pressure turbine control valve is supplied to the gland
steam header, and steam leakoff from the high pressure turbine throttle valve is furnished to the high pressure turbine gland
supply line.
The steam to the high pressure gland is maintained at 5 psig. Any excess steam is bypassed to the condenser through a
spillover valve. The steam to the low pressure turbine glands is maintained at 1 psig. As the high pressure turbine exhaust increases with turbine load, the quantity of steam required to
seal the high pressure turbine glands decreases. Also, as the throttle valves are opened, the steam leakoff flow decreases and
terminates at full load. Excess steam is bypassed to the
condenser.
The leakoff steam from glands and any noncondensables will flow to the gland steam condenser (GSC), where the steam is condensed. The condensed water is then returned to the condenser hotwell. The noncondensable gases are exhausted from the GSC to the environment by one of the two exhaust blowers. The gland seal steam exhaust system is described in Section 9.4.15, which also describes how radioactivity is monitored in
the gland seal steam exhaust system.
10.4.3.3 Safety Evaluation
The TGSS has no safety function and its failure will not affect
the safety functions of other equipment.
The capability of the gland seal steam exhaust system to handle radioactive leakage for both normal condition and in the event
of a malfunction is discussed in Section 9.4.15. BVPS-2 UFSAR Rev. 16 10.4-8 10.4.3.4 Inspection and Testing Requirements Operation of the gland seal steam exhaust blowers is alternated, thus eliminating the need for periodic testing. Other components of the system are tested and inspected as recommended by the turbine manufacturer. Preoperational tests are performed as described in Section 14.2.12. 10.4.3.5 Instrumentation Requirements
Control switches with indicating lights are provided in the main control room for the gland steam supply control block valve and the gland steam supply control bypass valve.
Pressure indication is provided in the main control room for the gland steam supply header pressure and the high pressure turbine gland supply pressure. These pressures are also monitored by the BVPS-2 computer.
The gland steam supply pressure control valve, the high pressure turbine gland steam pressure control valve, and the low pressure turbine governor end gland steam pressure control valve will
modulate to admit steam, when a demand signal is received from their associated controllers.
The high pressure turbine gland steam header spillover valve modulates to remove excessive header pressure, when a demand signal is received from its associated controller.
The GSC differential pressure control valve maintains a constant differential pressure across the condenser by means of a control
signal received from its associated controller. Control switches with indicating lights are provided in the main control room for the manual operation of the gland steam exhausters.
A common turbine gland steam trouble alarm is provided in the main control room for any one of the following conditions: Gland steam header pressure high or low, No. 1 low pressure turbine governor end gland steam pressure high or low, No. 1 low pressure turbine exciter end gland steam pressure high or low, and the gland steam exhauster motor thermal overload. The individual inputs to the main annunciator are also monitored by the BVPS-2 computer.
10.4.4 Turbine Bypass System The TBS permits a 50 percent external load rejection from full load without reactor or turbine trip. The TBS is shown on Figure 10.4-2.
10.4.4.1 Design Bases The TBS is designed in accordance with the following criteria:
BVPS-2 UFSAR Rev. 16 10.4-9 1. General Design Criterion 4, as it relates to the failure of the TBS due to a pipe break or malfunction should not adversely affect essential systems or components.
- 2. General Design Criterion 34, as it relates to the ability to use the TBS for shutting down the plant during normal operation.
- 3. The function of the TBS is to permit a 50 percent external load rejection from full load without causing a reactor or turbine trip.
- 4. A single turbine bypass control valve sticking open shall not cause an uncontrolled plant cooldown.
- 5. The TBS piping is designed in accordance with ANSI B31.1, dated 1967, including all addenda through June
30, 1972.
- 6. The TBS is nonsafety-related and is designated as NNS class.
- 7. Failure or malfunction of the TBS, including a high energy line break, cannot adversely affect essential systems or components.
10.4.4.2 System Description
On a large external electrical load decrease (up to 85 to 100 percent), the TBS relieves main steam directly to the condenser, thus preventing a reactor or turbine trip and lifting of the main steam safety valves (Section 10.3). The maximum load step change without rod motion is 5 percent.
The load rejection capability; i.e., the capability of the plant to accept a large loss of external load without tripping the
turbine, is limited by a turbine trip upon high condenser pressure. Condenser pressure is dependent upon circulating
water inlet temperature (CWIT). The higher the CWIT, the higher the final pressure inside the condenser after TBS operation.
The maximum CWIT is 90 F. At 90F the plant has a 50 percent load rejection capability. Excess steam generated by the sensible heat in the nuclear steam
supply system (NSSS), immediately following loss of load, is bypassed directly to the main condenser (Section 10.4.1) by means of two turbine steam bypass lines, which provide a total
bypass capacity of greater than 40 percent of full load steam flow. Each bypass line contains a bank of nine steam bypass control valves arranged in parallel. These valves are
controlled by reactor coolant average temperature with provisions to control some of the valves with steam pressure.
BVPS-2 UFSAR Rev. 16 10.4-10 The details of the arrangement of the turbine bypass valves and associated controls are shown on Figure 10.4-2. The bypass valves are 8 inch, carbon steel globe valves with spring and
diaphragm air operators. The 18 valves are controlled in 4
blocks, with the valves in each block modulating in parallel. The blocks of valves will open sequentially.
All or several of the bypass valves are opened under the following conditions, provided a turbine condenser vacuum, cooling tower pump, and low-low T permissive interlocks are satisfied:
- 1. On a large step load decrease without reactor trip, the TBS creates a load on the steam generators, thus
providing a controlled condensation of generated steam. This enables the NSSS to accept a 50 percent net load rejection from full load without reactor trip. An error signal exceeding a set value of reactor coolant T minus T fully opens all valves in 3 seconds. T is a function of load and is set automatically. The turbine steam bypass valves close automatically as reactor coolant conditions approach
their programmed set point for the new load.
- 2. On a turbine trip with reactor trip, the pressure in each steam generator rises. To prevent overpressure without main steam safety valve operation, the turbine steam bypass valves open, discharging to the condenser for several minutes, providing time for the reactor control system (Section 7.3) to reduce the thermal output of the reactor without exceeding acceptable
core and coolant transient conditions.
- 3. After a normal orderly shutdown of the turbine generator leading to unit cooldown, the turbine steam bypass valves are used for several hours to release steam generated by the sensible heat. Unit cooldown, programmed to minimize thermal transients and based on sensible heat release, is effected by a gradual manual closing of the bypass valves until the cooldown process is transferred to the residual heat removal (RHR) system (Section 5.4.7). During start-up, hot standby service, or physics testing, the bypass valves
are manually operated from the main control board.
10.4.4.3 Safety Evaluation
The TBS has no safety function and its failure will not affect the safety functions of other equipment because it is located in
the turbine building away from all safety-related components. A potential hazard in the form of an uncontrolled station cooldown caused by a single large valve sticking open is prevented by the use of this group of 18 smaller valves installed in parallel, since any
BVPS-2 UFSAR Rev. 0 10.4-10a single valve can pass no more than 890,000 lb/hr at main steam system design pressure of 1,100 psia, which is the maximum allowable steam relief valve capacity in Section 4-1 of the Steam Systems Design Manual (Westinghouse Electric Corporation 1978). The effects of a valve sticking open or being opened due to operator error are therefore within Westinghouse design limitations. The steam dump control circuitry prevents
inadvertent opening of more than one turbine bypass valve. The analyses performed to determine the design criterion for safety and relief valves is given in Section 15.1.4. The valves will
fail closed on loss of power. Loss of the control air supply to any of the TBS valves prevents
the valves from opening or, if the valves are already open, trips them closed. In the event of loss of all control air, the steam generators are protected during all transients by the main
steam safety valves. During start-up, shutdown, operator training, or physics testing, the turbine bypass control valves can be actuated remotely from the main control room.
The turbine bypass control valves are prevented from opening on loss of condenser vacuum, loss of cooling tower pumps, or low-low T on two out of three steam generators, and in that case, excess steam
BVPS-2 UFSAR Rev. 0 10.4-11 pressure is relieved to the atmosphere through the atmospheric dump valves and through the main steam safety valves (Section 10.3). 10.4.4.4 Inspection and Testing Requirements During the Initial Startup Test Program, the turbine bypass control valves and TBS controls are inspected and tested in accordance with Section 14.2.12.
The TBS piping is inspected and tested in accordance with Paragraphs 136 and 137 of ANSI B31.1.
10.4.4.5 Instrumentation Requirements A steam dump control mode selector switch and redundant
interlock selector switches are provided in the main control room. Loss of condenser vacuum and circulating water pump interlocks are provided for the turbine bypass control valves.
The following control switches are provided in the main control room for operation of the TBS: steam bypass control mode selector switch (reset-T-steam pressure), steam bypass interlock selector switches (off/reset-on-defeat T), and selector switches (loop 21 T defeated, loop 22 T defeated, loop 23 T defeated). Manual/Auto stations for the atmospheric steam dump valves are
provided in the main control room and at the emergency shutdown panel (ESP). A pushbutton at the ESP will transfer control from the main control room to the ESP. A manual reset at the relay
will transfer control from the ESP back to the main control room. If their respective steam line pressures are not high, the atmospheric steam dump valves can be modulated automatically
or manually from either the main control room or from the ESP. Manual stations for two of the atmospheric steam dump valves are
provided at the alternate shutdown panel (ASP). A pushbutton on the ASP will transfer control from the main control room or the ESP to the ASP. A manual reset at the relay on the ASP will transfer control back to either the main control room or to the ESP. The atmospheric steam dump valves can be modulated manually from the ASP provided the transfer pushbutton on the
ASP has been depressed. Annunciation is provided in the main control room when control is at the ESP or at the ASP. These conditions are also monitored by the BVPS-2 computer. Red (open) and green (closed) indicating lights are provided at the main control board, at the
ESP, and at the ASP to indicate where the control is at. A manual loading station for the atmospheric residual heat release valve is provided in the main control room and at the ESP. A pushbutton at the ESP will transfer control from the main control room to the ESP, and a manual reset at the relay on the
ESP will BVPS-2 UFSAR Rev. 12 10.4-12 transfer control from the ESP back to the main control room. The atmospheric residual heat release valve can be modulated manually from either the main control room or from the ESP.
Annunciation is provided in the main control room when control is at the ESP. This condition is monitored by the BVPS-2 computer, and red (open) and green (closed) indicating lights are provided at the main control board and at the ESP to indicate where the control is at. Annunciation is provided in the main control room for steamline pressure high, which is a common annunciator with individual computer points for all main steamlines, and steam dump system
loss of control power, which is also monitored by the BVPS-2 computer. The following inputs are monitored by the BVPS-2 computer: small load rejection, large load rejection, main
steam header pressure, condenser available, steam dump
actuation, one for each steam dump valve bank trip open signal, reactor coolant loop 21 T , reactor coolant loop 22 T , reactor coolant loop 23 T, and reactor coolant loops median T. Status lights are provided in the main control room to monitor the following conditions: small load rejection, large load rejection, steam dump actuation, condenser unavailable, Train A two out of three reactor coolant loops low-low T ,T interlock defeated, Train B two out of three reactor coolant
loops low-low T , one for each steam dump valve open and closed, and one for each steam dump valve bank trip open
signal. Indicators are provided in the main control room to monitor the following conditions: loop 21 main steam line pressure post-accident monitoring (PAM) 2, loop 22 main steam line pressure PAM 2, loop 23 main steamline pressure PAM 2, loop
21 main steamline pressure, loop 22 main steamline pressure, loop 23 main steamline pressure, steam dump - median T , reactor coolant loop 21 T , reactor coolant loop 22 T , reactor coolant loop 23 T. A temperature recorder is provided in the main control room for median T for loops 21, 22, and 23. Automatic signals for opening the bypass control valves are
discussed in detail in Section 7.7. 10.4.5 Circulating Water System
The CWS provides cooling water for the main condenser (Section 10.4.1) of the turbine generator unit (Figure 10.4-3). It is a closed-loop system consisting of cooling tower pumps, a pumphouse, circulating water and blowdown piping, main condenser vacuum priming system, mechanical tube cleaning system, and a
natural draft cooling tower. Makeup water is supplied to the closed-loop CWS by discharging the plant service water into the circulating water condenser discharge lines.
BVPS-2 UFSAR Rev. 12 10.4-13 10.4.5.1 Design Basis The CWS is nonsafety-related and is classified NNS class. The CWS is a moderate energy piping system and is not protected against the dynamic effects of a postulated pipe rupture;
however, protection is inherent in the design, since the
majority of the circulating water piping is buried. The CWS complies with General Design Criterion 4, as it relates to design provisions provided to accommodate the effects of discharging water that may result from a failure of a component or piping in the CWS. 10.4.5.2 System Description
The CWS consists of cooling tower pumps, a pumphouse, circulating water piping, main condenser vacuum priming system, mechanical tube cleaning system, natural draft cooling tower, and associated hydraulic and electrical equipment. The system flow diagram is shown on Figure 10.4-3. The CWS contains four cooling tower pumps that are located in a pumphouse between the turbine building and the cooling tower. The pumphouse arrangement satisfies the net positive suction
head requirements of the pumps. Four 25 percent capacity pumps are provided to deliver the circulating water flow to the cooling tower. Each pump is rated as shown in Table 10.4-2. The natural draft cooling tower is a hyperbolic shell counter-flow tower equipped with an impingement-type drift eliminator
system, an icing c ontrol system, a system to zone 40 percent of the tower fill, and two bypass gates, each capable of bypassing approximately half of the circulating water flow directly to the cooling tower basin. The icing control system consists of a perforated pipe ring at the circumference of the cooling tower fill on the interior of the shell, which is serviced by a system of ten 18-inch motor-operated butterfly valves and associated piping that connect the ring to the ends of the hot water distribution flumes. The ring allows for a veil of hot water to shield the air inlet, warming the incoming cold air. It also serves to reduce the total air flow, which results in minimizing the possibilities for ice accumulation on the fill. The zoning system consists of a system of dividers and end walls in the distribution flumes that allow water to be bypassed under the distribution pipes serving the central 40 percent of the fill.
Flow to the flumes is controlled by power-operated gates installed in the tower risers. The zoning system allows cooling water to be concentrated onto a smaller fill area, thus reducing
cooling tower icing potential. Cooling tower design parameters are presented in Table 10.4-3. Circulating water flows by gravity from the basin of the cooling tower through fixed panel screens and then to the inlet water
boxes of the condenser. The condenser is described in Section 10.4.1. The water passes through the tubes of the condenser to the outlet water box. BVPS-2 UFSAR Rev. 13 10.4-14 The condenser operates as a siphon, with prime maintained by a vacuum priming system. The circulating water then flows to the pumphouse outside the turbine building. The discharge lines of the SWS tie into the CWS between the condenser outlet water
boxes and the pumphouse. The four cooling tower pumps, mounted in the pumphouse, pump the water to the top of the cooling tower fill where it is discharged into the cooling tower distribution system. The cooling tower blowdown is discharged from the circulating water discharge flume through a 36-inch butterfly valve located near the bottom of the discharge flume. Discharge
flow rate is controlled by an overflow weir which divides the blowdown discharge chamber adjacent to the flume. This weir controls water level in the cooling tower basin and blowdown discharge rate. Blowdown is conveyed by the blowdown discharge system to the Ohio River. The blowdown line can also be used to drain the cooling tower basin through a normally closed 24-inch
butterfly valve. Blowdown from the circulating water of BVPS-2 is combined with the blowdown discharge from BVPS-1 at the outfall structure and is discharged into the Ohio River.
The estimated chemical composition of the circulating water is presented in Table 10.4-4. Chemical constituents will be concentrated in the CWS by as much as 2.4 times the concentrations in the makeup water. Biofouling control will be achieved by chemical addition. Corrosion will be monitored to ensure that the design requirements of system components are maintained. Treated water from the BVPS-1 water treatment system is conveyed to the BVPS-2 CWS by a 4-inch line and injected into the BVPS-2 CWS just upstream of the condenser. The system is designed to maintain a measurable residual chlorine concentration at the condenser outlet while not exceeding administrative limits for discharge to the river. A grab sample connection is provided to monitor chlorine concentrations. This treated water will control biofouling of the condenser tubes and minimize it in the balance of the CWS. A vacuum priming system is provided to prevent air binding in the condenser waterboxes and sections of the circulating water piping. The system consists of two full-size vacuum pumps, a
vacuum priming tank, air separating tanks, and associated piping and controls. One vacuum pump is normally running with the other pump on standby. Air dissolved in the circulating water, which is released at high points in the system, that operates below atmospheric pressure, is continuously drawn off by the vacuum priming system to maintain a siphon to the cooling tower
pump suction. A mechanical tube cleaning system is provided to maintain the
condenser performance. The system (Amertap) continuously circulates sponge rubber balls through the condenser tubes. The balls are slightly oversized and provide a wiping action
BVPS-2 UFSAR Rev. 0 10.4-15 which prevents the buildup of deposits on the tube walls. System components consist of ball distributors, strainer sections to recover balls, recirculating systems for reinjecting balls into the circulating water inlet lines, collectors for removing balls from the cleaning system, and various valves and control equipment.
10.4.5.3 Safety Evaluation The CWS is a nonsafety-related system and is independent of the emergency cooling requirements. During normal cooldown, service water will be discharged to the CWS and allowed to discharge to the river through the cooling tower blowdown system. The CWS is not needed to cool this water. The emergency service water discharge system, which is independent of the CWS, will be used for emergency discharge of service water (Section 9.2.5).
The hyperbolic shape of the cooling tower is inherently strong and stable. The only credible collapse would be a postulated
failure of the shell support columns. Such a collapse mechanism could be described as overturning about the heel of the tower, that is, rotation of a point diametrically opposite the shell
support columns. Since the diameter of the tower at its base is nearly equal to the total height, this postulated collapse would not affect areas greater than about one-half a tower base diameter away from the supporting columns. All Category I structures for both
BVPS-1 and BVPS-2 are outside the affected area. The CWS is physically isolated and remote from both the ultimate heat sink (Section 9.2.5) and the safety-related portions of the SWS (Section 9.2.1) so that a failure in the CWS will not render any parts of safety-related portions of the SWS inoperable.
The interface between SWS and CWS are the two points where the service water discharges into the circulating water lines just downstream of the condenser. The SWS is also provided with its own separate emergency discharge system, which discharges directly into the Ohio River, so that the blockage of these two
points will not prevent service water discharge. Cooling tower pumps could continue to run during an accident
unless offsite power is lost or the operator manually trips the pumps. The CWS is not used for cooling safety-related equipment.
Expansion joints are located at the suction and discharge of each pump. A rupture of an expansion joint in the pumphouse will discharge water inside of the pumphouse at the operating floor level that would initially fill the valve pits on the suction side of the pumps. Flood indicators are installed in
these valve pits to provide flood alarm to the main control room. The BVPS-2 pumphouse is located more than 300 feet from the nearest safety-related structure. BVPS-2 UFSAR Rev. 16 10.4-16 Because of this separation, the site grading, and the storm drainage systems, no safety-related equipment would be affected. Expansion joints are also located in the turbine building between the water boxes and the motor-operated butterfly valves on both the inlet and the outlet sides of the condenser and downstream of the strainers in the condenser discharge line. If
a rupture should occur in an expansion joint in the turbine building, the escaping water would accumulate in the retention pit around the condenser and in the valve pits on the discharge side of the condenser. Flood indicators are installed below floor level (el 730 feet-6 inches) on both the inlet and outlet sides of the condenser and in the retention pit. These flood indicators will provide flood alarm to the main control room. Upon alarm, the operator will identify and isolate the failed joint to minimize the effects of flooding on the turbine building equipment. Operator action is not required to protect safety-related equipment.
There are no structures, systems, or components credited in accident analyses or required to be safety related (as listed in UFSAR Table 3.2-1) in the turbine building, although some equipment may have been procured to that standard or evaluated as such. Passageways from the turbine building enter the auxiliary building and the service building at el 735 feet-6 inches, which is 5 feet above the turbine building floor. Piping penetrations into safety-related areas below this level are encased in concrete and are therefore water-tight. The maximum flow through a ruptured expansion joint would be about 170,000 gpm. The turbine building side panels will release and discharge the water into the yard area before the water level could reach el 735 feet-6 inches. Circulating water discharged into the yard area of the turbine building will flow away from safety-related areas, along the railroad bed leading away from
the southeast corner of the turbine building towards Peggs Run. In summary, there are no safety-related structures, systems, or components that will be submerged following failure of a rubber expansion joint in the turbine building (Section 3.4.1).
10.4.5.4 Inspection and Testing Requirements The circulating water pumps and motor-operated valves (MOVs) will be functionally tested during start-up (Section 14.2.12). The CWS is in continued use and does not require periodic testing. Standby equipment will be cycled into service
occasionally to ensure their availability. 10.4.5.5 Instrumentation Requirements
Control switches with indicating lights for the cooling tower pumps are provided in the main control room. The cooling tower pumps are manually operated and are interlocked with their respective suction
BVPS-2 UFSAR Rev. 19 10.4-17 and discharge valves for proper pump operation. An amber light is provided in the main control room to indicate to the operator
the proper time intervals for the manual stopping of more than
one cooling tower pump. Ammeters are provided in the main
control room for each cooling tower pump. The BVPS-2 computer
monitors the starts and stops of each pump.
The discharge valves of the cooling tower pump open automatically when a manual demand start signal for the associated pump is initiated, and closes when the cooling tower pump is stopped. Valve position indicating lights are provided in the main control room. Control switches with indicating lights are provided in the main control room for manual
operation of the cooling tower pumps suction valves.
Indicating lights are provided in the main control room for each condenser outlet valve. Indicating lights for the inlet and
outlet valves are also provided locally. The operation of the
valves is local manual. Self supplied cooling water, from the discharge of the cooling tower pumps, is the method of providing cooling for the pump and motor bearings.
Selector switches, control switches, and indicating lights are provided in the main control room and control switches locally for the cooling tower deicing valves, cooling tower bypass sluice gate valves, and the zoning slide gate valves. (Functions
of these valves are described in Section 10.4.5.) A transfer switch is provided in the main control room for transferring
control of the cooling tower valves from the main control room
to local control. These valves are manually operated.
A common annunciator is provided in the main control room with the following inputs: cooling tower pumps trip, cooling tower pump stopped and respective discharge valve not closed, seal
injection pump trip, cooling tower pumps discharge pressure high
and cooling tower pump house floor level (water) high. The preceding conditions are monitored by the BVPS-2 computer. Annunciation is also provided for the condenser inlet and outlet valves retention pits levels high and condenser differential pressure, and these conditions are monitored by the BVPS-2 computer. Computer monitoring is also provided for the following: cooling tower blowdown flow, condenser differential pressure, condenser water boxes inlet temperature, cooling tower pump starts and stops and condenser water boxes outlet
temperatures.
BVPS-2 UFSAR Rev. 0 10.4-18 Indicators are provided in the main control room for cooling tower pumps discharge temperatures and condenser water boxes inlet temperatures. A recorder and totalizing indicator are provided in the main control room for cooling tower blowdown
flow. A common selector switch with indicating lights is provided for the vacuum priming pumps. The selector switch has the capability of selecting a lead/follow arrangement for either pump. One pump runs continuously while the other is in standby, and the standby pump will start automatically when the lead pump stops or there is low vacuum in the vacuum priming tank. Cooling water admission valves for the vacuum priming equipment seal water heat exchangers operate automatically, depending on the starting and stopping of their respective vacuum priming pump. Selector switches are provided locally for the vacuum
priming recirculation pumps. These pumps can be run manually or automatically. On automatic, these pumps will start and stop whenever their respective vacuum priming pump is running.
The condenser water boxes and condenser discharge lines air separating tanks water levels are automatically maintained by
their respective level controllers and level control valves. The mechanical tube cleaning system is an Amertap Corporation
tube cleaning system. The system controls are located local to the condensers. The system can be operated in the manual or automatic mode from the local control panel. Annunciation is provided at this panel for monitoring of the system parameters. Indicating lights are provided on the local panel for system pumps, valves, and collection screens operation.
Refer to Section 9.2.1.1 for additional references to chlorination system control and monitoring functions.
10.4.6 Condensate Cleanup System
The CCS consists of the condensate polishing system (CPS) and the powdered resin dewatering system (PRDS). The CPS removes dissolved and suspended impurities from the condensate stream
resulting from corrosion, condenser tube leakage, and primary-to-secondary system leakage. The CPS produces a high quality effluent capable of meeting feedwater and steam generator
chemistry specifications during normal operations. The PRDS dewaters expended resins backwashes from the CPS. This system also reclaims water used during backwashing of the filter/demineralizers (F/D).
BVPS-2 UFSAR Rev. 0 10.4-18a 10.4.6.1 Design Bases The CPS and PRDS are designed in accordance with the following criteria:
- 1. The CPS and PRDS are nonsafety-related and are classified NNS class.
BVPS-2 UFSAR Rev. 16 10.4-19 2. The CPS and PRDS are designed in accordance with the applicable portions of ASME Section VIII and ANSI B31.1, dated 1967, including all addenda through June
30, 1972.
- 3. The CPS is sized to accommodate 100 percent condensate flow.
- 4. The CPS maintains the condensate water chemistry in accordance with the requirements set forth in Table
10.4-5. These requirements are based on a condenser leak of 1 gpm at conditions of normal CPS operation. During a major condensate leak (50 gpm condenser leak), the CPS is capable of removing 90 percent of
chloride and sodium.
- 5. Sufficient demineralizer capacity is provided to allow demineralizer reconditioning while the CPS retains its
normal polishing capacity.
- 6. The pressure drop through the CPS from the condensate inlet header to the outlet header will not exceed 50 psi when operating at maximum flow under the most limiting resin conditions. As substantial amounts of
suspended materials such as iron, copper, and colloidal silica are removed by the F/D, the pressure
differential across the F/D increases. When the F/D
is loaded with these impurities such that the capability for further removal no longer exists, then
the resin is at its most limiting condition.
- 7. The PRDS has the capacity to remove powdered resin fines, suspended crud, heavy metal oxides, and dissolved solids with a removal efficiency greater
than 95 percent for a particle size of 1 micron and
larger.
- 8. The PRDS has the capability of processing 5,500 gallons of waste liquid (slightly greater than one main condensate F/D backwash) containing 400 pounds of
suspended solids within 1.5 hours. 10.4.6.2 System Description
10.4.6.2.1 Condensate Polishing System
The CPS is shown on Figure 10.4-7. Principal component design and performance characteristics are listed in Table 10 .4-6. The CPS removes ionic and particulate contaminants from the condensate, protecting the FWS, steam generator, and turbine against intrusion of foreign materials, which could result from
condenser or steam generator leaks. The CPS consists of five F/Ds with associated pumps, precoat facilities, sampling panel and controls located in the condensate stream between the
condensate pumps discharge and the steam jet air ejector condensers. The CPS is designed for full condensate flow. Four F/D vessels with one standby vessel are utilized for maximum condensate flow of 18,600 gpm at a temperature of 70 F to 125 F. Influent parameters and impurity concentrations for normal operation, start-up, and major condenser leakage are given in Table 10.4-7. Effluent water purity requirements are listed in
Table 10.4-5. BVPS-2 UFSAR Rev. 12 10.4-20 The resins used for precoating of the F/D are strong acid cation and strong base anion types, mixed in a ratio of two parts cation and one part anion. However, this ratio can be varied depending on the nature of the soluble materials being removed.
The anion material is in the hydroxide form, and cation material is in the ammonia form. The resin effectively removes substantial amounts of suspended material such as iron, copper, colloidal silica, and dissolved solids from the condensate water, as indicated in Table 10.4-5. Fresh precoat, which may consist of a filter aid only, resin only, or filter aid with resin, is chosen depending on system requirements. A fixed amount of filter aids, if required, is recirculated through the F/D in a slurry to form a cake on the filter tubes. Then, powdered ion exchange resins, if required, are educted through the precoat slurry pumps until a fixed
amount has been deposited on the filter tubes. Upon completion of the precoat cycle, the holding pump will recirculate water through the vessel to maintain the precoat on the filter tubes
until the vessel is placed in service. Once the vessel is placed in service, the CPS has controls for balancing the flow through each vessel while maintaining system differential pressure. System differential pressure is maintained by throttling the flow through each vessel. The
dirtiest filter will be indicated by the control valve which is throttling the least.
The F/D service cycle continues until the effluent water quality (conductivity) or differential pressure across the F/D increases above a predetermined value. Effluent water quality is determined using the CPS sample system. When either condition occurs, the F/D is backwashed. During the backwashing cycle, the resin and impurities collected on the precoat medium of the filter element screen are removed by a pressurized air bump followed by an air/water scour. The backwash slurry is flushed to the backwash receiving tank for further processing in the
PRDS. The CPS is not intended for full time operation. Its operation will be based on maintaining condensate and feedwater chemistry requirements. Chemical parameters are monitored using the sampling system (Section 9.3.2.2). Control of the condensate
and feedwater chemistry is by the CPS and the chemical feed system (Section 10.3.5).
Several sources exist for contamination to enter the condensate stream. The major source is in-leakage of condenser cooling water. This is assumed to be 1 gpm for normal operation and 50 gpm during major condenser leakage. Fifty gpm corresponds to the leakage expected from a complete failure of one condenser tube. A second source is primary to secondary in-leaking. The assumed maximum leak rate from the primary-to-secondary system in the steam generators is 550 lb/hr. This rate is based on the projected continuous in-leakage rate of 50 lb/hr total for the
steam generators and complemented with
BVPS-2 UFSAR Rev. 12 10.4-21 the maximum design total in-leakage rate of 500 lb/hr for one week. A third source of contamination is the steam generator blowdown (SGB), which is directed to the SGB flash tank. From here the vapor is directed to the second point heater and the
liquid drains to the fourth point heater. This allows for recovery of available heat prior to entering the condensate stream. The second point heater drains are pumped forward into
the FWS. The fourth point heater drains cascade to the condenser.
Condenser cooling water analysis is listed in Table 10.4-8. Steam generator blowdown analysis is listed in Table 10.4-9 for limiting conditions at normal operation.
The CPS maintains effluent purity levels in the condensate water as stated in Table 10.4-5. During periods of major condenser leakage, 90 percent of chloride and sodium contaminants are removed. Also, during major condenser leakage, the effluent quality will be maintained for one hour at full design flow rate when either the total dissolved solids concentration in the influent is 1,200 ppb or less, or when the total suspended solids concentration is 130 ppb or less.
During plant start-up operation, a prefiltration medium using a cellulose material as a filter aid, such as Solka Floc, may be
used for removing concentrations of crud, oil, organic and colloidal materials, and heavy metal oxides. This filter aid shall be added into the precoat recirculating tank for mixing.
The CPS will remove 90 percent of suspended solids and 90 percent of dissolved solids from the condensate during plant start-up.
Influent parameters for the CPS for normal operation, major condenser leakage, and initial and subsequent start-ups are
listed in Table 10.4-7. 10.4.6.2.2 Powdered Resin Dewatering System
The PRDS is shown on Figure 10.4-8. The principal components of the system are listed in Table 10.4-10. After the condensate F/D has been backwashed and the resulting slurry has been flushed to the backwash receiving tank, the PRDS is utilized to dewater the solids that have been collected in the backwash hold
tank and reclaim the backwash water. The PRDS consists of two clamshell filters capable of processing a total of 5,500 gallons of liquid waste containing 400 lbs of resin and suspended matter from the condensate polishing F/D during the recovery process. Each screen of the clamshell
filter is precoated with resin prior to running the backwash slurry through the filter.
BVPS-2 UFSAR Rev. 0 10.4-22 Resin for precoating is premixed in the slurry feed tank recirculated through the clamshell filters to form a cake on the screens l/8-inch thick.
During the filtering cycle, backwash slurry is pumped continuously into the clamshell filters for spent resin removal. The reclaimed water flows to the backwash feed tank. The spent resin is removed from the backwash slurry and forms a cake in the clamshell filter. The PRDS has the capability to recirculate the reclaimed water in the backwash feed tank through the clamshell filters to allow flexibility in control of the quality of the water leaving the PRDS.
After the filtering cycle is complete, the remaining water is forced out from the cake by high pressure air. This air-water mixture is sent to the backwash receiving tank. Dry cake
containing 50 percent water is dumped into a sludge chute for further processing. The sludge is either collected in containers and treated as industrial waste or placed in the sludge tank if the sludge is contaminated, and processed through the solid radwaste management system (Section 11.4).
Operating parameters of the clamshell filters are presented in Table 10.4-11. 10.4.6.3 Safety Evaluation The CPS and PRDS do not have safety function and their respective failures will not affect the safety functions of other equipment. The CPS and PRDS are capable of removing, on a continuous basis, condensate impurities resulting from anticipated condenser tube leakage expected during operation of the plant.
The F/D system (CPS) has redundancy in the form of an additional F/D vessel which is used as a standby unit. This standby unit is placed in service in the event that one of the other four vessels becomes inoperable due to high differential pressure or effluent requirements. Thus, the system is able to maintain its continuous operating characteristics.
The maximum tube leak that can be treated continuously will vary with the quality of the condenser circulating water. However, the system provides some degree of protection even during massive condenser leaks, such as complete tube failure, thus affording time to initiate corrective action or a plant
shutdown. Radiation shielding is provided around the condensate polishing area for personnel protection (Section 12.3). All tanks and clamshell filters in the systems which are potentially radioactive are located in shielded areas of the condensate polishing building and are provided with adequate ventilation and filtration to reduce the potential of airborne contamination (Section 11.3). All potentially contaminated overflows and
drains are routed to floor drains and then BVPS-2 UFSAR Rev. 0 10.4-23 sent to the radioactive liquid waste system for treatment (Section 11.2). 10.4.6.4 Inspection and Testing Requirements
The CPS includes four F/Ds normally in continuous operation and one standby F/D to be available as required. Each F/D will be
regenerated approximately every 21 days. The PRDS is not a continuously operated system. It is designed to handle the slurry from the backwash receiving tank when a condensate polishing F/D unit is backwashed. The PRDS will normally be in standby ready to receive a precoat. Visual inspection can be made of all portions of the systems during operation and standby position. Preoperational tests are performed as described in Section 14.2.12.
10.4.6.5 Instrumentation Requirements The CPS is designed for automatic operation following mode initiation. This means the operator is required to initiate each phase of operation but having once done so, the system operates automatically through that mode (backwash, precoat, filter, and hold). Control power status and operation mode for each demineralizer are indicated by lights on the control panel. In addition to automatic operation, each valve and motor has a
selector switch on the control panel for manual operation. The local control panel has audible and visible annunciators which indicate abnormal conditions in the polishing system. These conditions will also activate an alarm and computer signal in the main control room. Valve interlocks are also
provided at the control panel to ensure proper system operation. The system includes four units in normal operation and one in standby to be available as required. The flow through those on-line is equally balanced, and a minimum system differential pressure is maintained. Flow transmitters, recorders, and flow indicating totalizers are provided on the effluent side of each condensate demineralizer and are utilized in maintaining this minimum system differential pressure. For each F/D, high
demineralizer differential pressure and high strainer differential pressure are indicated by alarms at the control panel. The CPS utilizes a differential pressure flow control valve to ensure that the differential pressure across the CPS does not
exceed 50 lbs. The valve is controlled by a differential pressure transmitter.
A holding pump is utilized by each F/D for maintaining flow in the F/D in the event of loss of condensate flow. The pump is necessary to keep the resin on the filter tubes. When the F/D
is precoated prior to being placed in service or the condensate flow is lost, a flow switch causes the holding pump to start automatically and opens the hold valve to establish recycling
flow through the unit. BVPS-2 UFSAR Rev. 12 10.4-24 Low recirculation flow through each F/D is indicated by an alarm at the control panel, as is high F/D total flow. The influent condensate to the condensate demineralizer and the effluent from the demineralizer are continuously sampled. The conductivity at each location is measured and recorded continuously, and an alarm signal is provided to indicate high
conductivity. In addition, alarms are provided for high system effluent conductivity, high system influent conductivity (both before and after cation treatment), and high sodium concentration.
Tanks which are emptied by pumping are also provided with low level indicators and alarms. A high level in the backwash receiving tank is alarmed at the control panel. The potentially radioactive tanks and their level indicators are listed in Table 11.2-6. The PRDS is designed to operate automatically following mode initiation. There are switches which allow the operator to stop operation at the conclusion of certain phases of the backwash
and precoat cycles or to continue on automatically. Each valve and meter has a s elector switch on the control panel for manual operation. Normally, all of these are in the auto position. The control panel has audible and visible annunciators which alarm on various system conditions. Interlocks are provided at
the control panel to ensure proper system operation. Differential pressure across the clamshell filter is controlled at a preset level. This is accomplished by varying flow through the clamshell filter. Flow through the filter will automatically be stopped on a high pressure or low flow condition. High effluent conductivity or turbidity or low level in the backwash receiving tank will also stop flow through the clamshell, and for each of these conditions an alarm will sound
at the control panel annunciator. 10.4.7 Condensate and Feedwater Systems
The condensate and feedwater systems return condensed steam from the condenser (Section 10.4.1) and the drains from the regenerative feedwater heating cycle to the steam generators, while maintaining the water inventories constant throughout the systems. The systems automatically control the water levels in the steam generators and condenser hotwells during steady state and transient conditions.
A simplified schematic of the condensate system is shown on Figure 10.4-12. A simplified schematic of the feedwater system is shown on Figure 10.4-14.
BVPS-2 UFSAR Rev. 0 10.4-25 10.4.7.1 Design Bases The FWS and the condensate system are designed in accordance with the following criteria:
- 1. Regulatory Guides 1.26 and 1.29, as they relate to the quality group and seismic design classification of safety-related components:
- a. The portion of the FWS extending from and including the feedwater isolation valves nearest the containment to the steam generator inlets and feedwater control valves are safety-related, QA Category I, Seismic Category I, and are designed in accordance with ASME Section III, Code Class 2, and are designated Safety Class 2.
- b. The entire condensate system and the remainder of the FWS upstream of the feedwater isolation valves are neither safety-related nor Seismic Category I; are designed in accordance with ANSI-B31.1 dated 1967, including all addenda through June 30, 1972; and are designated NNS class. Portions of the feedwater piping which are in QA Category I buildings are seismically designed.
- c. The high pressure and low pressure feedwater heaters are designed in accordance with ASME Section VIII.
- 2. The condensate system and the nonsafety-related portions of the FWS are automatically isolated from the steam generators within 5 seconds following a feedwater isolation signal (Section 7.3).
The feedwater isolation valves nearest the containment are located as close as practicable to the containment structure. The feedwater control valves serve as the secondary feedwater isolation valves. Feedwater bypass control valves are normally closed.
- 3. Branch Technical Positions ASB 3-1 and MEB 3-1 (USNRC 1981), as they relate to breaks in high and moderate energy piping systems outside containment and as described in Section 3.6.
- 4. General Design Criterion 2, Regulatory Guides 1.29, 1.102, and 1.117, as they relate to structures housing the safety-related portion of the FWS being capable of withstanding the effects of natural phenomena such as earthquakes, tornadoes, hurricanes, and floods.
- 5. General Design Criterion 4, as it relates to structures housing the safety-related portion of the FWS being capable of withstanding the effects of
external missiles and
BVPS-2 UFSAR Rev. 12 10.4-26 internally-generated missiles, pipe whip, and jet impingement forces associated with pipe breaks, and Branch Technical Position ASB 10-2 (USNRC 1981), as it relates to the dynamic effects associated with
possible hydraulic instabilities. Piping supports and restraints are designed to withstand the effects of water hammer, which are postulated in all parts of the FWS, from the discharge of the feedpumps to the inlet of the steam generators.
- 6. General Design Criterion 5, as it relates to the capability of shared systems and components important to safety to perform required safety functions. There are no shared safety-related portions of the condensate system and the FWS.
- 7. General Design Criterion 44, as it relates to redundancy of components so that, under accident conditions, the safety-related portions of the FWS can be isolated assuming a single active component failure, and as it relates to the capability of the system to transfer heat loads from the steam
generators under both normal and accident conditions.
- 8. General Design Criterion 45, as it relates to design provisions to permit periodic in-service inspection (ISI) of system components and equipment.
- 9. General Design Criterion 46, as it relates to design provisions to permit appropriate functional testing of the system and components to assure structural integrity, leaktightness, operability and performance of active components, and the capability of the integrated systems to function as intended.
10.4.7.2 System Description
Principal operating characteristics of the condensate system and the FWS are shown on Figure 10.1-1 and in Table 10.1-1. Principle components are s hown on Figures 10.4-12 and 10.4-14. The condensate is normally drawn from the condenser hotwell by
two of the three half-capacity, motor-driven, vertical condensate pumps. The pumps discharge into a common header which passes the condensate through a full flow condensate polishing system (Section 10.4.6), the steam jet air ejector condensers, and the turbine gland steam condenser. Downstream of the gland steam condenser, condensate passes through two parallel flow paths of low pressure feedwater heating (fifth point heater drain coolers and feedwater heaters, Numbers 2 through 6). The
two flow paths are combined to ensure mixing and pressure equalization upstream of the feedwater pumps. The feedwater/condensate passing through the feedwater heaters is
heated by extraction steam taken from the turbine (Section 10.4.11). The spare condensate pump will auto-start on loss of one of the normally running condensate pumps and/or low
condensate header discharge pressure.
BVPS-2 UFSAR Rev. 17 10.4-27 The condenser hotwell is designed to operate at normal level, such that a volume equivalent to approximately 4 minutes of condensate flow (71,000 gallons) is available to the condensate
pumps. The water level is automatically maintained by a 200,000 gallon secondary plant demineralized water storage tank (SPDWST) (Section 9.2.6), which provides storage of makeup condensate and accommodates surges within the turbine plant cycle. Makeup flow to the hotwell is gravity-fed from the SPDWST. Hotwell drawoff is accomplished by diverting water from the condensate header to the SPDWST. Each of the three vertical, barrel-type, condensate pumps is rated at 9,700 gpm at 1,078 feet total discharge head (TDH). Two half-size, motor-driven steam generator feedwater pumps, each rated at 15,200 gpm and 1,694 feet TDH, are furnished to supply feedwater to the three steam generators. A motor-driven start-up feedwater pump is provided to minimize operation of main feedwater pumps at low flow during start-up and low load operation. The start-up feedwater pump can be operated in parallel with one steam generator feedwater pump if the other feedwater pump is out of service.
The steam generator feedwater pumps discharge through two half-size, high pressure feedwater heaters (first point heaters), arranged in parallel, to a common discharge header for distribution to the steam generators. Feedwater flows to each steam generator through individual feedwater flow control valves. Each valve is positioned by a three-element feedwater control system. A manual bypass around each first-point heater allows isolation of these heaters for maintenance without a unit shutdown. To provide better controllability during start-up and shutdown, a small bypass valve around each feedwater control valve provides automatic control of feedwater flow. The bypass valve is used when the feedwater flow is less than 15 percent of design flow.
Malfunction of any low pressure feedwater heater necessitates isolation of that entire string of low pressure heaters in which the malfunctioning feedwater heater is located. Isolation
valves are provided for each flow path of low pressure feedwater heaters and each high pressure feedwater heater. In case of malfunction of any of the feedwater heaters, the isolation
valves are closed. The turbine generator load must be reduced when a string of heaters is out of service.
A bypass exists around the sixth point heaters which can be aligned using control switches in the main control room. Since there are no valves in the extraction steamline between the turbine and the sixth point heater, the bypass prevents turbine water induction.
BVPS-2 UFSAR Rev. 14 10.4-28 Upon a 50 percent-or-greater load rejection, a low pressure feedwater heater bypass valve automatically opens. Condensate flows directly to the feedwater pump suction header, bypassing
the sixth through second point heaters. This enables the condensate pumps to supply adequate flow to the feedwater pumps when the flow from the heater drain pumps is lost during
transient conditions resulting from load rejections. Drains from the reheater section of the four moisture separator/reheater units, provided with the turbine generator, flow to four reheater drain receivers. Two reheater drain receivers drain to each of the two first point heaters. Drains from the separator section of the moisture separator/reheater units flow to four separator drain receivers. Drains from the four separator drain receivers, two first point heaters, and two second point heaters, flow to two second point heater drain receivers. From the second point heater drain receivers, the drains are pumped to the suction of the feedwater pumps utilizing the heater drain pumps and/or the separator drain pumps. One heater drain pump and/or one separator drain pump take suction from one second point heater drain receiver as needed to support plant load conditions. Chemical feed equipment is provided to ensure proper chemistry
control. This equipment is discussed in Section 10.3.5. 10.4.7.3 Safety Evaluation
The main FWS performs the following three safety-related functions:
- 1. Automatically isolate main feedwater flow to the steam generators following a feedwater isolation signal (Section 7.3). Redundant valves are provided for this function. The feedwater isolation valves are located in the main steam valve area with Seismic Category I supports and are designed to function with the environmental effects of a nonmechanistic pipe rupture. Valve closure time is described in Table 6.2-60. The feedwater control valves and bypass control valves, located in the service building, are located in NNS class lines. The feedwater control valve's closure time plus the ESF signal will be 7 seconds. These lines and their supports are designed for seismic loads. Failure of these lines
will not prevent feedwater isolation.
- 2. The Safety Class 2 piping of the main FWS provides a barrier against release of containment atmosphere during a loss-of-coolant accident (LOCA). This barrier, which is part of the containment, serves the
same function as the containment liner.
BVPS-2 UFSAR Rev. 1 10.4-29 3. The Safety Class 2 piping from the steam generators to and including the check valves just outside the containment, is required for the auxiliary feedwater system (AFWS) to maintain the steam generator levels
when the main feedwater pumps are not available. The ability of the feedwater system to perform its safety function is assured by conformance to the design criteria listed in Section 10.4.7.1.
A loss of normal feedwater flow results in a reduced capability for steam generator heat removal. Such a loss could result from a pipe break, pump failure, valve malfunction, or a loss of normal ac power. In the event of such an occurrence, the AFWS ensures a sufficient supply of cooling water for safe shutdown (Section 10.4.9).
The effects of the condensate system and the FWS equipment malfunctions on the reactor coolant system (RCS) are described
in Sections 15.2.7 and 15.2.8. The following features have been provided to reduce the
possibility of water hammer in the FWS:
- 1. The steam generator feed ring is provided with J-tubes to prevent drainage of water during low steam
generator water level (Section 5.4.2).
- 2. The feedwater piping connections of the steam generators are made with an elbow arrangement which does not present a horizontal pipe run immediately upstream of the feedwater nozzles. This configuration should prevent formation of steam pockets under low steam generator water level conditions.
Release of radioactivity to the environment in the event of pipe rupture in the condensate or FWS will not exceed releases that
would occur from a pipe rupture in the main steam system (Section 15.1.5).
Breaks in system piping will not result in adverse effects on the functional performance of essential systems or components (Section 3.6). Components in the main steam valve area are
designed for the effects of a nonmechanistic pipe rupture. 10.4.7.4 Inspection and Testing Requirements
Piping in the condensate system and the FWS will be hydrostatically tested during construction. All active system components such as pumps, valves, and controls will be functionally tested during start-up (Section 4.2.12). Design provisions for periodic testing are addressed in Sections
7.1.2.4 and 7.3.2.2.5.
BVPS-2 UFSAR Rev. 0 10.4-30 In-service inspection, as required by ASME Section XI for the Safety Class 2 portions of these systems, are discussed in Section 6.6.
Samples are taken from the condenser hotwell, the discharge of the condensate pumps, and the discharge of the steam generator feedpumps. The sampling systems determine oxygen content, pH
value, and conductivity (ion content). In addition, samples taken from the PRDS (Section 10.4.6) can be used to determine radioactive contamination of the secondary side. The sampling
systems are discussed in detail in Section 9.3.2. Preoperational tests are performed as described in Section
14.2.12. 10.4.7.5 Instrumentation Requirements
Control switches with indicating lights are provided in the main control room for the condensate pumps. During normal plant
operation, two condensate pumps are running. The third pump is automatically started if one of the operating pumps trips or if the condensate discharge header pressure is low.
Condensate discharge header pressure indication is provided on the main board in the main control room. Annunciation is provided in the main control room for condensate pump auto-start/stop and condensate pump suction strainer differential pressure high. These are also monitored by the BVPS-2 computer
system. Minimum condensate flow is controlled by flow control valve in a recirculation line to the main condenser. Indicating lights for valve position are provided on the main board in the main control room.
The hotwell level of the condensers is automatically controlled. Hotwell level indication and annunciation for hotwell high and
low levels are provided in the main control room. The SPDWST is filled from the demineralizer make-up system when there is low level indication, which actuates the fill line level control valve.
Annunciation is provided in the main control room for low and high levels in the SPDWST. The SPDWST level is indicated in the main control room. These are also monitored by the BVPS-2
computer system. Control switches with indicating lights are provided in the main
control room for the main and start-up feedwater pumps. The feedwater pumps are manually operated. A minimum recirculation flow control valve and a feed pump discharge valve are provided
for each feedwater pump. The recirculation valve will open or close, as required, depending on the operation of the feedwater pumps. BVPS-2 UFSAR Rev. 0 10.4-31 The steam generator feedwater control system establishes and maintains the feedwater level in each steam generator within limits by positioning the feedwater control valve in the feedwater line to each steam generator. The feedwater control valve responds to a three-element feedwater regulator. Input signals are feedwater flow, main steam flow, and steam generator water level. During power operation below approximately 15
percent load, each main feedwater control valve is bypassed by a smaller flow control valve. The bypass flow control valve responds to a single element feedwater regulator. The bypass
valve is controlled by steam generator water level. The feedwater control valves and bypass valves are provided with indicating lights in the main control room. The feedwater control valves close on receipt of a safety injection (SI) signal or any steam generator two out of three high-high level or a reactor trip associated with a low T in two out of three reactor loops. The feedwater bypass control valves close on a feedwater isolation signal made up of an SI signal or any steam generator two out of three high-high level. The feedwater bypass valves must be reset by a pushbutton switch located in the main control room after the isolation signal is removed.
Control switches with indicating lights are provided in the main control room for the feedwater isolation valves. A set of indicating lights is also provided on the feedwater isolation valve test panel. These feedwater isolation valves isolate each steam generator upon receiving a feedwater isolation signal, which is made up of an SI signal or any steam generator two out of three high-high level. These valves must also be reset by a pushbutton switch in the main control room after the isolation
signal is removed. Annunciation is provided in the main control room for steam generator feedwater pump auto-stop, start up feedwater pump auto-stop, steam generator feedwater pump discharge equalizing header pressure low, steam generator feedwater pump recirculation valve open, steam generator feedwater pumps 21A, B/auxiliary lube oil pump trouble, startup feedwater pump 24/auxiliary lube oil pump trouble, feedwater isolation trip
valves nitrogen pressure low, and steam generator feedwater pump suction pressure low. These conditions are also monitored by the BVPS-2 computer system.
Ammeters are provided in the main control room to each main and start-up feedwater pump motor.
Main feedwater pump discharge header pressure indicators are provided in the main control room. Indication is provided in the main control room for feedwater to steam generator flow, steam generator steam pressure, turbine first stage pressure, and steam generator water level. These conditions are also monitored by the BVPS-2 computer system. Indication is BVPS-2 UFSAR Rev. 0 10.4-32 provided on the alternate shutdown panel (ASP) for steam generator steam pressure and steam generator water level (two steam generators only). A three-pen pressure recorder is provided in the main control room for the steam generator steam
pressure. A three-pen level recorder is provided in the main control room for the steam generators water level. Three flow recorders are provided in the main control room for the steam
generators. Drains from the feedwater heaters are controlled automatically to prevent the induction of water into the turbine while delivering an optimum amount of heat to the condensate flowing through the tube side of the heaters.
10.4.8 Steam Generator Blowdown System
The SGB system processes blowdown water from the steam generator to maintain steam generator water chemistry within specified limits. 10.4.8.1 Design Bases
The SGB system is designed in accordance with the following criteria:
- 1. General Design Criterion 1, as it relates to system components being designed, fabricated, erected, and
tested for quality standards.
- 2. General Design Criterion 2, as it relates to system components designed to Seismic Category I requirements.
- 3. General Design Criterion 14, as it relates to secondary water chemistry control to ensure that the primary coolant boundary material integrity will be maintained.
- 4. System components are designed to the maximum temperatures and pressures expected to occur under normal and transient system operating conditions.
- 5. The system is designed to maintain optimum secondary side water chemistry during normal operation and under anticipated operational occurrences, such as a primary to secondary leakage and main condenser leakage.
- 6. The system piping connecting to the steam generators inside containment up to and including the first isolation valve outside the containment is designated Safety Class 2, Seismic Category I, and meets QA Category I standards.
- 7. The system is designed in accordance with the guidelines of Regulatory Guides 1.26, 1.29, and 1.143.
BVPS-2 UFSAR Rev. 14 10.4-33 10.4.8.2 System Description and Operation When used for secondary chemistry control, the SGB system shown on Figure 10.4-23 , receives blowdown continuously from the steam generators at a maximum design rate of 97 gpm per steam generator. Normal flow rat es vary d epending on secondary water quality, condenser tube leakage, and primary-to-secondary leakage. The SGB flow is directed to the SGB flash tank where approximately 20 percent of the liquid flashes off to the second point feedwater heaters and is returned to the main condenser. The remaining liquid flows through two SGB heat exchangers where the SGB is cooled to less than 120F. The blowdown is then directed to a duplex filter, and then a mixed bed ion exchange resin demineralizer and returned to the condenser. Demineralizer effluent water chemistry is continuously monitored by a local sample panel. Sample Panel effluent is directed to the turbine building floor drain system. If a high water level exists in the SGB flash tank, liquid can be drained to the fourth point through level control valves. On high-high water level in the SGB flash tank, blowdown is isolated from the steam generators. In the event of high blowdown temperature, flow is isolated to the demineralizers. The main feedwater system is
described in Section 10.4.7. Provision is made for draining a limited quantity of blowdown to the blowdown hold tanks via the blowdown drain tank cooler. Additionally, flashed blowdown vapor from the blowdown tank can be directed to the main condenser through a pressure control
valve. The SGB system also provides for mixing of the steam generator water when the steam generator is in wet layup. Nitrogen is supplied to the bottom blowdown connections on the steam generators with the equivalent of six bottles (230 scf/bottle)
being released into the steam generator for mixing. The source of nitrogen is the nitrogen supply system described in Section 9.5.9. The SGB system component design parameters are described in Table 10.4-12. 10.4.8.3 Safety Evaluation
The SGB system interfaces with other systems in such a way as to prevent overpressurization of systems designed to lower pressure and temperature conditions by use of normally closed valves. Interfaces with systems having a lower or higher safety class designation are accomplished by safety grade valves that isolate the safety portions from the nonsafety portions of the systems.
The SGB system connects to the extraction steam system through the second point feedwater heaters. Backflow into the high pressure turbine is prevented by non-return valves (NRVs) in the extraction steamlines. Overspeed of the turbine due to the failure of a NRV is not considered credible, because the
extraction steamlines are
BVPS-2 UFSAR Rev. 13 10.4-34 supplied from the high pressure turbine, thus eliminating any flow path to the low pressure turbine in the turbine trip condition.
The SGB system lines penetrating the primary containment are isolated automatically, as described in the instrumentation section, to protect safety-related equipment located in the cable vault from the effects of a high energy line break. All of these isolation valves are powered from the safety-related buses. In these cases, where redundancy is provided, power is
from opposite buses. The SGB system maintains steam generator chemistry to reduce the possibility of corrosion of steam generator materials. The system can accommodate a long term primary to secondary leak rate of 1 gpm. The steam generator chemistry limits are provided in Table 10.4-13 and their bases are described in Section 5.4.2. The liquid waste management system (Section 11.2) can be utilized to assist processing of the blowdown water. Steam
generator sampling is described in Section 9.3.2.1. Oxygen concentration and pH are controlled by a separate
chemical addition system, as described in Section 10.3.5. The SGB system flash tank, drain tank cooler, filters, demineralizers, heat exchangers, and main feedwater heaters are located in the turbine building, a nonseismically designed building. Blowdown flow is not considered to be concentrated at
this stage of the process and should not have an appreciable radioactive content. Provision has been made for sampling the turbine building drains prior to discharge.
Grab samples can be obtained and analyzed for radioactivity from sumps in the turbine building drains systems as required by the
Offsite Dose Calculation Manual and in the event of a high activity alarm from the main steam discharge high range effluent monitor (Section 11.5.3). In the event of an alert alarm from the steam generator blowdown sample process monitor (Section 11.5.4), grab samples will be obtained every four hours while
the secondary activity exceeds 1.0E-5 Ci/ml, and turbine building sumps are being discharged to the storm drainage
system. A high activity alarm from the steam generator blowdown sample process monitor (Section 11.5.3) will isolate blowdown flow. If the turbine building drains activity concentrations at the drainage point are determined to exceed a gross
concentration of 10 Ci/ml, the turbine building drains will be isolated from the storm drainage system, via manually operated isolation valves, and transferred to the liquid waste
system for processing. A failure modes and effects analysis (FMEA) to determine if the instrumentation and controls (I&C) and electrical portions meet the single failure criterion, and to demonstrate and verify how the General Design Criteria and IEEE Standard 279-1971 requirements are satisfied, has been performed on the SGB system. The FMEA methodology is discussed in Section 7.3.2. The results of these analyses can be found in the separate FMEA
document (Section 1.7).
BVPS-2 UFSAR Rev. 2 10.4-34a 10.4.8.4 Inspection and Testing Requirements The preoperational inspection and testing requirements for the SGB system are described in Section 14.2.12.
10.4.8.5 Instrumentation Requirements
Control switches with indicating lights are provided in the main control room for the SGB (outside containment) isolation valves. These valves are opened manually when the SGB system tank level
is not high-high, the turbine auxiliary feedwater pump steam inlet valves are closed, the steam generator blowdown process sample radioactivity is acceptable, and the motor-driven auxiliary feedwater pumps are stopped. These valves will close automatically when there is a high-high level in the SGB tank, the turbine auxiliary feedwater pump steam inlet valves are
opened, the steam generator blowdown process sample radioactivity is high, or the motor-driven auxiliary feedwater pumps are running.
Control switches with indicating lights are provided in the main control room for the SGB (inside containment) isolation valves. These valves are opened manually when the turbine auxiliary feedwater pump steam inlet valves are closed, the motor-driven auxiliary feedwater pumps are stopped, and the cable vault area temperature is not high. These valves will close automatically provided the turbine auxiliary feedwater pump steam inlet valves are opened, the motor-driven auxiliary feedwater pumps are
running, or the cable vault area temperature is high. Control switches with indicating lights are provided in the main control room for the SGB (inside containment) isolation valves. These valves will close when the cable vault area temperature is high. A hand/auto control station and a selector switch with indicating lights are provided in the main control room for the blowdown tank drain valve to the condenser. This valve will be modulated to maintain level in the blowdown tank at set point. This valve receives a signal to shut if the blowdown temperature exceeds 120F. This valve can be closed manually from the control room.
Selector switches with indicating lights are provided in the main control room for the SGB tank inlet valves. These valves are operated manually.
Control switches with indicating lights are provided in the main control room for the steam generator sample isolation valves. These valves are operated manually. These valves will close automatically when the auxiliary feedwater pumps are auto-started, or a steam generator has a high radiation sample.
BVPS-2 UFSAR Rev. 2 10.4-35 Selector switches with indicating lights are provided on the sample system panel for the steam generator sample valves. These valves are operated manually and will be closed when their respective steam generator sample temperature is high or the
auxiliary feedwater pumps are auto-started. A control switch with indicating lights is provided in the main control room for the SGB tank outlet valve to the second point heaters. This valve may be operated manually or automatically when the second point heater backpressure is normal, the
blowdown tank level is not extreme high, and the second point heaters level is not high-high. This valve will close automatically when the second point heater back pressure is not
normal, the blowdown tank level is extreme high, or the second point heaters level is high-high.
A selector switch with indicating lights is provided in the Main Control Room for each of the SGB flash tank outlet valves to the fourth point heaters. These valves can open on a normal high
level in the SGB flash tank provided the fourth point heater levels are not high.
A SGB flash tank level control valve to the SGB hold tanks is provided to transfer SGB to liquid waste if required. A selector switch with indicating lights is provided in the Main
Control Room. An SBG tank pressure control valve to the main condenser is
provided to maintain the blowdown tank pressure at set point. A level indicator is provided on the main board for the blowdown
tank level. Temperature differential indicators are provided locally for the
SGB system temperatures. Annunciation and associated computer inputs are provided in the
main control room for SGB system trouble, which consists of SGB tank level high, SGB tank level low, and cable vault area temperature high.
Inputs needed, but not associated with the annunciation system, are provided in the computer for SGB tank level and SGB tank
pressure.
BVPS-2 UFSAR Rev. 8 10.4-35a 10.4.9 Auxiliary Feedwater System Following a loss normal feedwater, AFWS is designed to provide high pressure feedwater to the secondary side of the steam generators and maintain sufficient water level in the steam generators for reactor coolant heat removal, thus preventing an unacceptable temperature rise in the RCS. The AFWS is utilized during a main steamline break and feedwater line break, and provides a cooling source in the event of a small break LOCA. The AFWS can operate during start-up, hot standby, or cold shutdown conditions; however, this is not the intended function of this system.
10.4.9.1 Design Bases The AFWS from and including the primary plant demineralizer
water storage tank (PPDWST) to the auxiliary feedwater control valve is Safety Class 3 and is designed to Quality Group C standards, as defined in Regulatory Guide 1.26 and described in Section 3.2. Piping downstream of the auxiliary feedwater control valve is designed to Quality Group B standards. This portion of the AFWS is also seismically designed, as discussed in Section 3.7B.3. The PPDWST chemical addition system is designed to Quality Group D standards.
BVPS-2 UFSAR Rev. 0 10.4-36 The AFWS is equipped with two half-capacity motor-driven pumps and one full capacity turbine-driven pump. Each half-capacity pump has sufficient capacity to remove decay heat. The turbine-driven pump is rated at 750 gpm at 2,760 feet TDH. The motor-
driven pumps are each rated at 375 gpm at 2,760 feet TDH. The turbine-driven pump is powered independently of the motor-driven auxiliary feedwater pumps.
In the event of a line break in a feedwater supply line to a steam generator, each auxiliary feedwater supply line is equipped with a cavitating venturi capable of limiting flow to 310 gpm. Thus, sufficient auxiliary feedwater is available to the intact steam generators for reactor heat removal.
All redundant components and equipment are physically separated in individual cubicles, located at el 718 feet-6 inches of the
safeguards building. The safeguards building is designed to preclude seismic, tornado, and missile damage.
The AFWS is designed in accordance with the following criteria:
- 1. General Design Criterion 2, as it relates to the structures and systems being capable of withstanding the effects of natural phenomena such as earthquakes, tornadoes, and floods.
- 2. General Design Criterion 4, as it relates to structures and systems being capable of withstanding the effects of external missiles, internally-generated missiles, pipe whip, and jet impingement forces associated with pipe breaks.
- 3. General Design Criterion 5, as it relates to the capability of shared systems and components important to safety to perform required safety functions.
- 4. General Design Criterion 19 and Branch Technical Position RSB 5-1 (USNRC 1981), as they relate to the capability of I&C for prompt hot shutdown of the reactor and potential capability of subsequent cold
shutdown.
- 5. General Design Criteria 34 and 44 to ensure:
- a. The capability to transfer heat loads from the reactor system to a heat sink under accident
conditions,
- b. Redundancy of components so that under accident conditions the safety function can be performed, assuming a single active component failure, and
- c. The capability to isolate components, subsystems, or piping, if required, so that the system safety
function will be maintained.
BVPS-2 UFSAR Rev. 15 10.4-37 6. General Design Criterion 45, as it relates to the design provisions made to permit periodic ISI of systems, components and equipment.
- 7. General Design Criterion 46, as it relates to design provisions made to permit operational, functional
testing of the system and components to ensure:
- a. Structural integrity and system leaktightness,
- b. Operability and adequate performance of active system components, and
- c. Capability of the integrated system to function as intended during accident conditions.
- 8. Regulatory Guide 1.26, for the quality group classification of system components.
- 9. Regulatory Guide 1.29, for seismic design classification of system components.
- 10. Regulatory Guide 1.62, for design provisions made for manual initiation of each protective action.
- 11. Regulatory Guide 1.102, for the protection of structures, systems, and components important to
safety from the effects of flooding.
- 12. Regulatory Guide 1.117, for the protection of structures, systems, and components important to safety from the effects of tornado missiles.
- 13. Branch Technical Position ASB 10-1 (USNRC 1981), for auxiliary feedwater pump drive and power supply diversity.
- 14. The AFWS is designed to supply adequate minimum total flow, distributed to at least two steam generators, for the following transients as described in Chapter 15:
- a. Loss of normal feedwater,
- b. Loss of offsite power followed by reactor trip (results in a loss of normal feedwater),
- c. Secondary side pipe rupture, or
- d. Cooldown following steam generator tube rupture.
- 15. The PPDWST is designed to provide sufficient water for the unit to be maintained in a hot standby condition for at least 9 hours following a loss of normal feedwater and to allow
BVPS-2 UFSAR Rev. 12 10.4-39 water from the 600,000 DWST. Water chemistry in the PPDWST is controlled thereafter by periodic sampling of the water and the addition of chemical treatment, as required. Chemical addition for the PPDWST is performed by utilizing a small circulating pump and injecting chemicals into the suction piping as required. Local samples are located on the suction piping of the circulating pump. The AFWS is also provided with separate chemical feed connections for chemical treatment that are located on individual AFWS supply lines.
A secondary Category I water supply for the AFWS is provided, with piping cross-connections to the SWS. These piping cross-connections are located in the safeguards building and located
on the suction of each pump. The turbine drive for the turbine-driven pump is supplied with
steam from each of the steam generators, by pipe connections in each main steamline upstream of the main steam isolation trip valves (Section 10.3). The motor-driven auxiliary feedwater
pumps receive power from redundant 4,160 V ac emergency buses. The auxiliary feedwater pumps can be started either automatically or manually from the main control board. In addition, the pumps can be started manually from the emergency shutdown panel (ESP). Each motor-driven auxiliary feedwater pump delivers water to a separate auxiliary feedwater header, while the turbine-driven pump can be manually aligned to either one of the two headers. Each auxiliary feedwater pump is provided with a recirculation control valve, which is located on the discharge piping that recirculates back to the PPDWST. These valves are designed for a 30-percent minimum flow
recirculation. Piping from the auxiliary feedwater headers is arranged so that
water can be supplied to each steam generator from either header. Parallel and redundant flow control valves are located in each supply line from the auxiliary feedwater headers. These valves, which are normally open, can be modulated by remote manual control from the main control room and are powered from emergency power buses. Downstream of the control valves, check valves are provided to prevent the loss of auxiliary feedwater in the event of an auxiliary feedwater header rupture.
Cavitating venturi flow elements are provided in the common auxiliary feedwater supply lines to each steam generator. These venturi orifices are designed to limit the flow to 310 gpm (choked flow). In the event of a main steamline or main feedwater line rupture that would result in a decrease of steam generator shell pressure, the venturis will prevent excessive
flow to the depressurized steam generator. The remote manual flow control valves, check valves, and venturi
orifices are all located in the safeguards building.
BVPS-2 UFSAR Rev. 15 10.4-40 Individual containment penetrations are provided for the auxiliary feedwater supply lines. Each auxiliary feedwater line is provided with a check valve inside the containment. The auxiliary feedwater supply lines feed the steam generators through individual connections on the main feedwater supply lines (Figure 10.4-24).
10.4.9.3 Safety Evaluation The AFWS has sufficient design capacity with two half-capacity
motor-driven pumps, one full-capacity turbine-driven pump, redundant water supply headers, redundant flow supply paths, redundant remote manual control valves, cavitating venturi flow orifices, and redundant emergency power supplies to withstand a single failure coincident with environmental occurrences and loss of offsite or standby power and still perform its intended safety function. Each half-capacity pump has sufficient capacity to remove decay heat.
The design of the AFWS meets the intent of NUREG-0660 (USNRC 1980), TMI Action Items II.K.1.5 and II.K.1.10.
Each auxiliary feedwater supply line is provided with a cavitating venturi flow orifice. If the pressure downstream of the flow orifice is reduced significantly, the cavitating venturi orifice will restrict the flow to 310 gpm. During a main steam or main feedwater line rupture coincident with a single failure of one of the auxiliary feedwater pumps, the minimum required flow to the intact steam generators will be maintained until the affected loop can be isolated. The AFWS can perform its required safety function for a secondary side
pipe rupture while withstanding a single failure. A FMEA to determine if the I&C and electrical portions meet the single failure criterion, and to demonstrate and verify how the GDC and IEEE Standard 279-1971 requirements are satisfied, has been performed on the AFWS. Similarly, a FMEA was performed on
the mechanical portion of this system. The FMEA methodology is discussed in Section 7.3.2. The results of the I&C and electrical analysis can be found in the separate FMEA document (Section 1.7), while the mechanical analysis is incorporated in Appendix 10A.
A simplified reliability analysis of the AFWS has also been performed in accordance with the requirements of NUREG-0737 (USNRC 1980), TMI Action Item II.E.1.1, and is included in Appendix 10A. Also included in this appendix are the FMEA of the mechanical portion of AFWS and their computer-plotted fault-tree diagrams.
The auxiliary feedwater piping inside the containment, which is part of the main feedwater pressure boundary, is considered high
energy and is analyzed accordingly, as discussed in Sections 3.6B.1 and 3.6B.2. The remainder of the AFWS does not operate during normal BVPS-2 operation and therefore is not considered
for high energy line break analysis. This piping is considered moderate energy.
BVPS-2 UFSAR Rev. 17 10.4-41 The pressurization of auxiliary feedwater piping between the inside containment check valves and outside containment check valves to main feedwater pressure does not constitute a high-energy classification of the containment isolation piping. The loading due to a Design Basis Pipe Rupture (DBPR) on the Auxiliary Feedwater System is not considered concurrently with
earthquake loading.
The analysis to demonstrate the capability of the AFWS to
preclude hydraulic instabilities (water hammer) for all modes of operation is discussed in Section 3.7B.3.8. Additionally, as
part of the water hammer analysis, pump and system testing is
performed as discussed in Section 14.2.12. 10.4.9.4 Inspection and Testing Requirements Preoperational tests are performed as described in Section 14.2.12. The ASME OM Code testing requirements are described in Chapter 16. In-service testing of pumps and valves is discussed in Section 3.9B.6, and ISI of Class 2 and 3 components is discussed in Section 6.6. Periodic sampling of water in the
PPDWST is performed for hydrazine and/or ammonia requirements. 10.4.9.5 Instrumentation Requirements
The AFWS complies with the intent of NUREG-0737 (USNRC 1980), TMI Action Item II.E.1.2. The AFWS is further discussed in Section
7.3. Control
switches with indicating lights for the auxiliary feedwater pumps are provided on the main control board, the ASP, and on the ESP. Pushbuttons for transfer of control from the
main control room to the ESP are provided at the ESP, with a manual reset at relay used to transfer control back to the main control room from the ESP. A pushbutton on the ASP will transfer control of one auxiliary feedwater pump to the ASP from the ESP or the main control room. A manual reset at relay will transfer
control from the ASP back to the ESP or the main control room. The motor-driven auxiliary feedwater pumps can be operated manually or automatically from either the main control room or the ESP. If no loss of power condition exists, the pumps are
started automatically on a low-low steam generator level in two
out of three steam generators, SI signal, automatic tripping of the main feedwater pumps, or AMSAC actuation. If a loss of power
condition exists, the pumps are automatically started by the diesel loading sequence and any of the preceding conditions.
Only one of the two motor-driven auxiliary feedwater pumps can be
operated in the manual mode of operation from the ASP. The turbine-driven auxiliary feedwater pump can be operated manually from the main control room or the ESP, but automatically
only from the main control room. Automatically, a low-low level in any steam generator, an undervoltage on the reactor coolant pumps bus, SI signal, or AMSAC activation will start the pump by opening the solenoid-operated valves in the steam supply line, admitting steam to the turbine. The motor-driven auxiliary feedwater pumps can be stopped manually only if there is no SI signal present. The turbine-driven auxiliary feedwater pump can be stopped manually from the main control room or ESP by closing the steam supply solenoid-BVPS-2 UFSAR Rev. 17 10.4-42 operated valves, regardless of the presence of an automatic opening demand signal. The auxiliary feedwater control valves are normally open and are provided with hand indicating controllers and open/close indicating lights in the main control room and the ESP. Two auxiliary feedwater control valves are provided with hand indicating controllers and open/close indicating lights at the ASP. These valves are all modulated manually by their respective controllers.
Control of the auxiliary feedwater control valves may be initiated from either the main control room or from the ESP. A
pushbutton on the ESP will transfer control from the main control room to the ESP. A manual reset at relay is used to transfer control back to the main control room from the ESP.
Control of two auxiliary feedwater control valves may be initiated from the ASP. A pushbutton on the ASP will transfer control to the ASP from the main control room or from the ESP. A manual reset at relay is used to transfer control back to the main control room or back to the ESP.
Annunciation is provided in the main control room for control at the ASP, control at the ESP, a steam generator auxiliary feedwater pump auto-start and to alert main control room operators that the TDAFWP steam supply solenoid-operated valve selector switches in the control room are in the (non-automatic) closed position. The preceding conditions are monitored by the BVPS-2 computer.
Computer inputs are provided for the auxiliary feedwater
turbine-driven pump steam admission valves open/close position, auxiliary feedwater flow, main feedwater line pressure, auxiliary feedwater pumps lube oil discharge pressure, and
motor-driven auxiliary feedwater pumps start/stop. Indicators are provided in the main control room for auxiliary feedwater pump steam supply pressure, steam generator water level, and auxiliary feedwater flow.
Ammeters are provided in the main control room for the motor-driven auxiliary feedwater pumps.
Indicators are provided on the ESP for steam generator level and auxiliary feedwater flow.
Indication is provided on the ASP for auxiliary feed flow. The PPDWST supply valve is modulated at set-point to maintain
water level in the PPDWST. A level recorder and level indicators are provided in the main
control room for the PPDWST. Annunciation is provided in the main control room for the PPDWST
level. This condition is also monitored by the BVPS-2 computer system. An input not associated with the annunciation system is provided for the PPDWST level for monitoring by the BVPS-2
computer.
BVPS-2 UFSAR Rev. 18 10.4-42a A control switch with indicating lights is provided locally for the PPDWST chemical feed line pump. This pump may be started manually, provided the PPDWST level is normal and the chemical
feed line isolation valves are open. The chemical feed line pump may be stopped manually, or automatically when the PPDWST
level is below normal or the chemical feed line isolation valves
are closed.
Control switches with indicating lights are provided in the main control room for the PPDWST chemical feed line isolation valves. These valves are operated manually, provided the PPDWST level is
normal. The valves may be closed manually or automatically when
the PPDWST level is below normal.
10.4.10 Auxiliary Steam and Condensate System
The auxiliary steam and condensate system supplies heating and process steam throughout BVPS-2 to various equipment, and
recovers the condensed steam from the equipment served.
The auxiliary steam and condensate system is NNS class.
10.4.10.1 Design Bases
The auxiliary steam and condensate system is designed in
accordance with the following criteria:
- 1. Piping for this system is designed in accordance with ANSI B31.1, dated 1967, including all addenda through
June 30, 1972, and is designated NNS class.
- 2. The system is capable of providing steam during normal operation, plant start-up, and plant shutdown.
- 3. The system has the capability to detect radioactive contaminants carried over from the equipment served.
10.4.10.2 System Description
The auxiliary steam supply header for BVPS-2 normally receives
its steam requirements from one of four sources. During normal operation, the steam is supplied from the main steam manifold
through a pressure reducing valve. When main steam pressure is
too low, the main steam isolation valves are closed. During plant shutdown, steam is supplied from either the BVPS-1 main steam pressure reducing valve or from the auxiliary boilers. Auxiliary boilers are provided for both BVPS-1 and BVPS-2. Design data for BVPS-2 auxiliary boilers are provided in Tables 10.4-14, 10.4-15, 10.4-16. Connections are provided such that
any boiler or auxiliary steam system can supply steam to either BVPS-1 or BVPS-2. The condensate will be returned to the unit that is providing the steam in order to maintain fluid inventories. In addition, the turbine gland steam system provides a backup source of steam for the auxiliary steam supply header during normal plant operation.
BVPS-2 UFSAR Rev. 12 10.4-43 Auxiliary steam is used by and condensed in the following equipment:
- 1. Secondary plant demineralized water storage tank heater (Section 9.2.6), 2. Degasifier steam heaters (Section 11.3),
- 3. Evaporator reboilers (Section 11.2),
- 4. Boric acid batch tank (Section 9.3.4), 5. Carbon dioxide vaporizer (Section 9.5.1),
- 6. Cask washdown area (Section 9.2.3),
- 7. Building heating heat exchangers
- 8. Condenser vacuum priming ejectors during start-up (Section 10.4.2),
- 9. Condenser steam jet air ejectors during normal operation (Section 10.4.2),
- 10. Turbine gland seal steam system during start-up and shutdown (Section 10.4.3), and
- 11. Containment vacuum ejectors during start-up (Section 6.2). The condensate from the degasifier steam heaters is cooled by the primary component cooling water system (Section 9.2.2.1) so that it will not flash in the receiver. The condensate from the degasifier steam heaters and the boric acid batch tank is collected in the degasifier steam heater condensate receiver. From there it is pumped by one of the two degasifier condensate pumps to the auxiliary steam system condensate receiver tank.
The condensate from the evaporator reboilers is cooled by the turbine plant component cooling water system (Section 9.2.7) so
that it will not flash in the receiver. The condensate from the evaporator reboiler is collected in the evaporator reboiler condensate receiver. There it is pumped by one of the two evaporator reboiler condensate pumps to the auxiliary steam condensate receiver tank.
The auxiliary steam system condensate receiver tank collects the condensate from the flash tank of the building heating effluent, the secondary plant valve stem leakoff, and the SPDWST, in addition to the condensate pumped by the degasifier condensate pumps and the evaporator reboiler condensate pumps. This condensate is discharged to the main condenser. When auxiliary steam is BVPS-2 UFSAR Rev. 0 10.4-44 supplied from BVPS-1, the condensate collected is returned to the condensate system of BVPS-1, and when auxiliary steam is supplied from BVPS-2, the condensate collected is returned to the condensate system of BVPS-2.
Condensate from the turbine gland seal system and the steam jet air ejectors is discharged directly to the condenser.
The containment vacuum ejectors and the condenser vacuum priming ejectors are used only during start-up. The steam used in these
components is released to the atmosphere. 10.4.10.3 Safety Evaluation
The Category I air operated fail close valves required to automatically isolate an auxiliary steamline break in the auxiliary building are the only equipment in the auxiliary steam and condensate system that perform a safety-related function. Individually, either the BVPS-2 auxiliary boilers or the auxiliary steam supply from BVPS-1 can accommodate a normal plant shutdown and an orderly plant start-up, with normal building heating being provided. The auxiliary steam header is protected from a malfunction of the main steam pressure reducing valve by safety valves. Control valves in the auxiliary steam lines to the various heaters regulate the temperature in the
equipment being serviced. Radiation detection is accomplished in the auxiliary steam and condensate system by means of radiation monitors located in the condensate discharge path from degasifier and evaporator reboiler condensate pumps. In addition, radiation in auxiliary steam and in turbine exhaust resulting from excessive primary-to-secondary steam generator tube leakage will initially be detected by an in-line radiation monitor located in the gaseous
discharge flow path from the air ejectors (Section 10.4.2). To prevent safety-related equipment in the auxiliary building
from exceeding individual environmental qualification conditions following an auxiliary steamline break in the auxiliary building, the auxiliary steam system is automatically isolated
by in-line Category I air-operated fail close valves when the auxiliary building temperature exceeds 118.5 F. 10.4.10.4 Inspection and Testing Requirements During the life of the plant, all portions of the system are either in continuous or intermittent operation and periodic tests are not required. Components are accessible for visual inspection during operation and following installation of spare parts or piping modifications, as necessary to confirm normal operation of the BVPS-2 UFSAR Rev. 0 10.4-45 system. Preoperational tests are performed as described in Section 14.2.12. 10.4.10.5 Instrumentation Requirements
Selector switches with indicating lights are provided on a local panel for the auxiliary steam condensate receiver pumps. A selector switch for mode control of the auxiliary steam condensate receiver pumps and the BVPS-1 and BVPS-2 auxiliary steam condensate level control valves is provided on the same local panel. Indicating lights are also provided locally for
both BVPS-1 and BVPS-2 auxiliary steam condensate receiver level control valves.
The auxiliary steam system condensate receiver tank is normally drained to the condenser by a level control valve controlled by a local level controller and mode selection for BVPS-2. Under
conditions when the auxiliary steam is supplied from BVPS-1, mode selection for BVPS-1 closes the preceding level control valve and allows another level control valve to modulate, by
means of the previous level controller, to return the water to BVPS-1. One of the condensate receiver pumps in the manual BVPS-1 mode will run continuously to maintain a receiver level.
The other condensate receiver pump set in the auto BVPS-1 mode will be on standby.
Selector switches with indicating lights are provided on local panels for the degasifier condensate pumps and the evaporator reboiler condensate pumps. These pumps can be operated manually or automatically. In the auto mode, these pumps run to maintain the level in their respective receivers, with the second pump in each system on standby.
Auxiliary steam header pressure is controlled by a local pressure indicating controller and a pressure control valve.
Drain coolers are provided to prevent flashing for the degasifier steam heater and evaporator receiver condensate
receivers. The level in the drain coolers is controlled by level controllers and level control valves.
Annunciation is provided in the main control room for auxiliary steam header pressure low, evaporator reboiler or degasifier steam heater condensate receivers levels low-low or high-high, auxiliary steam condensate receiver level high-high or low-low, and auxiliary steam condensate receiver pumps motor thermal overload. Those conditions are also monitored by the BVPS-2
computer. An indicator for auxiliary steam header pressure and a flow totalizing indicator for auxiliary steam header flow are provided in the main control room. Computer inputs are provided for auxiliary steam header flow and auxiliary steam header
pressure.
BVPS-2 UFSAR Rev. 17 10.4-46 Two air-operated isolation valves in series are provided to isolate auxiliary steam from the auxiliary building. Control switches with indicating lights are provided in the main control room for these isolation valves. These isolation valves can be
controlled manually or automatically. In auto, these valves will close on an auxiliary building high temperature signal.
Selector switches with indicating lights are provided at local panels for the manually operated auxiliary boiler main steam stop valves.
10.4.11 Extraction Steam System
The extraction steam system directs steam from the high pressure and low pressure turbines to the feedwater heaters. The extraction steam is utilized for feedwater heating to increase cycle efficiency. The extraction steam system is shown on Figure 10.4-33 , and the system flow to each feedwater heater is shown on the heat balance diagram (Figure 10.1-1). 10.4.11.1 Design Bases
The extraction steam system is designed in accordance with the following criteria:
- 1. Delivers extraction steam to the feedwater heaters over the full range of turbine operating loads.
- 2. Designed to prevent turbine overspeed from flashing heater drains after a turbine trip.
- 3. Designed to remove moisture from the turbine to provide protection for low pressure turbine blading.
- 4. Extraction steam piping is arranged and pitched to be self-draining away from the turbine to the feedwater
heaters. 5. The extraction steam system is nonsafety-related and is classified as NNS class.
- 6. The extraction steam piping is designed in accordance with the code for power piping, ANSI B31.1, dated 1967, including all addenda through June 30, 1972.
10.4.11.2 System Description
The basic components of the extraction steam system are the MOVs used for isolation, the in-line NRV, and associated piping.
These components direct extraction steam from various high and low pressure turbine stages to the feedwater heaters.
BVPS-2 UFSAR Rev. 17 10.4-47 During normal operation, extraction steam is supplied from the high pressure turbine to heat the feedwater flowing through the first and second point feedwater heaters. Extraction steam supplied from the low pressure turbines heats the feedwater flowing through the third, fourth, fifth, and sixth point feedwater heaters. The extraction steam is condensed in the feedwater heaters and recycled to the condensate system and the
FWS (Section 10.4.7). Each extraction line serving feedwater heaters external to the
condenser neck is equipped with an MOV and an air-assisted swing check NRV. The NRV is provided to prevent overspeeding of the turbine by vapor flashed off from the heater on a turbine trip. The MOVs are manually closed using control switches in the main control room thereby preventing moisture carry-over from the feedwater heater to the turbine.
The sixth point feedwater heaters located in the condenser neck are not equipped with extraction line isolation MOVs or power-
assisted NRVs. By cycle design, no cascaded drains or other external high enthalpy fluids are admitted to low pressure heaters in the condenser neck. Also, drain levels are maintained at a point external from the heater by loop seals. Consequently, there is a low inventory of fluid in the heater during operation so that overspeeding of the turbine as a result
of flashing in the heater is prevented. Condensate inlet and outlet from the tube side of the heater can be manually isolated using control switches in the main control room, thus preventing water induction from either malfunctioning drains (steam condensation will stop when tube side flow stops) or from a tube rupture. 10.4.11.3 Safety Evaluation
The extraction steam system has no safety function and its failure will not affect the safety functions of other equipment. Removal of extraction steam from the turbines is required for
moisture removal and the corresponding protection against erosion of the low pressure turbine blading.
If the turbine trips, the extraction line NRVs will automatically close and their associated extraction line drain valves will open. This prevents condensate flashing in the
feedwater heaters from flowing back to the turbine and causing a turbine overspeed condition.
Details concerning conditions causing turbine trip are discussed in Section 10.2.
The sixth point feedwater heaters that are located within the condenser neck, which are not provided with extraction line MOVs and NRVs, do not pose a safety problem for the turbines as
heater water inventories are minimized and have relatively low enthalpy values.
BVPS-2 UFSAR Rev. 17 10.4-48 10.4.11.4 Inspection and Testing Requirements Periodic observations and monitoring of the system parameters are performed during operation. Components are accessible for visual inspections during operation, and following installation of spare parts or piping
modifications, to confirm normal operation of the system. 10.4.11.5 Instrumentation Requirements
Control switches with indicating lights are provided in the main control room for the extraction steam isolation valves for the first, second, third, fourth, and fifth point feedwater heaters. These valves can be closed and adjusted to maintain feedwater heater levels, utilizing control switches in the main control room. The extraction steam isolation valves are normally open during BVPS-2 operation. Downstream of each extraction steam isolation valve, an NRV is provided. Upon a turbine trip signal, a solenoid valve will be de-energized, causing the NRV to vent air, which causes the spring to drive the clapper in the close direction. When the turbine is latched, a fluid-operated air pilot valve admits air to all NRVs, allowing the clapper to also swing freely. A test lever is provided locally at each NRV, which admits air to both sides of the piston so that the spring will be able to drive the piston to assist in the closing. Control switches with indicating lights are provided in the main control room for the extraction line drain valves, which are grouped together for their respective heaters. On the first and
second point heaters, there is a drain valve upstream of the extraction steam isolation valve, a drain valve between the extraction steam isolation valve and the extraction steam NRV, and a drain valve downstream of the extraction steam NRV. All of the drain valves will be opened provided that the control switch is in open, an extreme high level in its respective heater, or a turbine trip exists. The drain valve upstream of the extraction steam isolation valve will also open when the extraction steam isolation valve is closed. The drain valve between the extraction steam isolation valve and the extraction steam NRV, and the drain valve downstream of extraction steam NRV will be closed provided that the control switch is in close, the level in the respective heater is below the extreme high level, and there is no turbine trip signal present. The drain valve upstream of the extraction steam isolation valve will
close with the NRVs provided that the control switch is in close, the level in the respective heater is below the extreme high level, no turbine trip signal is present, and the
extraction steam isolation valve is opened.
BVPS-2 UFSAR Rev. 0 10.4-49 Control switches with indicating lights are provided in the main control room for the extraction line drain valves, which are grouped together for their respective heaters, on the third, fourth, and fifth point heaters. There is a drain valve upstream of the extraction steam isolation valve, and a drain valve between the extraction steam isolation valve and extraction steam NRV. The drain valve upstream of the
extraction steam isolation valve will also open when the extraction steam isolation valve is closed. The drain valve between the extraction steam isolation valve and the extraction steam NRV will close when the control switch is in close, the level in the respective heater is below the extreme high level, and there is no turbine trip signal. The drain valve upstream of the extraction steam isolation valve will also close provided the previous conditions exist and the extraction steam isolation valve is open.
Annunciation is provided in the main control room for first point high pressure feedwater heater level extremely high, second point low pressure feedwater heater level extremely high, third point low pressure feedwater heater level extremely high, fourth point low pressure feedwater heater level extremely high, fifth point low pressure feedwater heater level extremely high, and the sixth point low pressure feedwater heater level extremely high, all of which are monitored by the BVPS-2
computer. The extraction steam pressure and temperature going to each feedwater heater are also monitored by the BVPS-2 computer. A multipoint temperature recorder is provided in the main control room for recording of the extraction steam line drains temperature.
10.4.12 References for Section 10.4 Heat Exchanger Institute 1970. Standards for Steam Surface
Condensers. Sixth Edition. U.S. Nuclear Regulatory Commission (USNRC) 1980. NRC Action
Plan Developed as a Result of the TMI-2 Accident. NUREG-0660. U.S. Nuclear Regulatory Commission 1980. Clarification of TMI
Action Plan Requirements. NUREG-0737. U.S. Nuclear Regulatory Commission 1981. Protection Against Postulated Piping Failures in Fluid Systems Outside Containment. Branch Technical Position (BTP) ASB 3-1.
U.S. Nuclear Regulatory Commission 1981. Design Guidelines for Auxiliary Feedwater System Pumps Drive and Power Supply Density for PWRs. BTP ASB 10-1.
U.S. Nuclear Regulatory Commission 1981. Design Guidelines for Water Hammers in Steam Generators with Top Feedring Designs.
BTP ASB 10-2. BVPS-2 UFSAR Rev. 0 10.4-50 U.S. Nuclear Regulatory Commission 1981. Postulated Rupture Locations in Fluid System Piping Inside and Outside Containment. BTP MEB 3-1.
U.S. Nuclear Regulatory Commission 1981. Design Requirements of the Residual Heat Removal System. BTP RSB 5-1.
Westinghouse Electric Corporation 1978. Steam Systems Design Manual, Section 4-1. SIP/10-l (SG 689).
BVPS-2 UFSAR Tables for Section 10.4
BVPS-2 UFSAR Rev. 16 1 of 1 TABLE 10.4-1 MAIN CONDENSER DESIGN PARAMETERS AND PERFORMANCE CHARACTERISTICS
Characteristic Parameter Performance Characteristics Steam condensed, normal operation (lb/hr) 6,713,000 Steam condensed, turbine bypass (lb/hr) 5,500,000 Circulating water flow rate (gpm) 480,400 Heat transfer (Btu/hr) 6.286 x 10 Back pressure (in Hg abs) 2.99 Hotwell temperature ( F) 114.9 Circulating water temperature () 81 Refer to UFSAR Figure 10.1-1 for operating conditions for the NSSS thermal power of 2910 MWt.
Design Parameters Number of shells 2 Passes per shell 1 Surface area (ft) 720,000 Number of tubes 67,920 Tube material 304 Stainless steel Tube OD (in) 3/4 Effective length per tube (ft-in) 54-2 Hotwell capacity (minimum) 4 min full flow
/71,000 gal BVPS-2 UFSAR Rev. 0 1 of 1 TABLE 10.4-2 CIRCULATING WATER SYSTEM COOLING TOWER PUMP CHARACTERISTICS
Component Parameter Cooling Tower Pumps Quantity 4 Capacity (gpm) each 126,850 Design suction temperature ( F) 120 Total dynamic head (4 pump operation) (ft) 73
BVPS-2 UFSAR Rev. 0 1 of 1 TABLE 10.4-3 NATURAL DRAFT COOLING TOWER DESIGN PARAMETERS Component Design Parameters Natural Draft Cooling Tower Quantity 1 Flow (gpm) 507,400 Range ( F) 25.5 Approach ( F)* 16 Dry bulb temperature ( F)* 87 Wet bulb temperature ( F)* 74 Exit air volume (cfm)* 35,000,000 Exit air temperature ( F)* 106 Evaporation loss (gpm)* 10,500 Drift loss (%) 0.013 Top diameter (ft) 260 Throat diameter (ft) 243.5 Height (ft) 502 Bottom diameter (ft) 422 NOTE:
- Design conditions.
BVPS-2 UFSAR Rev. 13 1 of 2 TABLE 10.4-4 CHEMICAL ANALYSIS OF WATER Ohio River Closed-Loop Circulating Water Quality Water Quality Parameter Avg Min Max Avg MinMax Alkalinity, methyl orange 23.16.033.041.6 9.0 79.2 (as CaCO) Acidity, total (as
CaCO) 5.42.012.09.7 3.0 28.8 Hardness (as CaCO) 100.466.0174.0180.7 99.0417.6 Calcium 27.517.050.049.5 25.5120.0 Magnesium 7.54.512.013.5 6.8 28.8 Suspended solids 20.61.044.037.1 1.5105.6 Dissolved solids 202.897.0347.0365.0 145.5832.8 COD 6.95.011.012.4 7.5 26.4 BOD 1.01.07.01.8 1.5 16.8 Total organic carbon 4.71.010.08.5 1.5 24.0
Iron, total 1.50.13.82.7 0.15 9.1 Iron, soluble 0.050.050.050.09 0.080.12 Copper 0.030.020.480.05 0.03 1.15 Manganese 0.540.280.880.97 0.42 2.11 Chromium, total 0.030.030.030.05 0.05 0.07 Chromium, hexavalent
( g/l) 2233.6 3.0 7.2 Nickel 0.010.010.020.02 0.02 0.05 Zinc 0.090.030.230.16 0.05 0.55 Aluminum 0.420.10.90.76 0.15 2.16 Sodium 18.610.031.033.5 15.0 74.4 Potassium 3.42.05.36.1 3.0 12.7 Sulfate 86.651.5162.0155.9 77.3388.8 Phenol ( g/l) 611710.8 1.5 40.8 Surfactant ( g/l) 17104031 15 96 Nitrogen, Kjeldahl 0.910.341.501.64 0.51 3.60 Ammonia (as NH) 0.640.351.041.15 0.53 2.50 Nitrate (as NO) 5.83.58.010.4 5.3 19.2 Nitrite (as NO) 0.130.072.180.23 0.11 5.23 Phosphate, total (as PO) 0.300.090.510.54 0.14 1.22 Phosphate, ortho (as PO) 0.060.051.160.11 0.08 2.78 Silica, total (as SiO) 8.04.917.114.4 7.4 41.0 Mercury, aqueous ( g/l) 1.30.28.32.3 0.3 19.9 Mercury, sediment (g/l) 164.873.0299.0- - - Chlorine, free residual 0000 0 0 pH, units -6.67.6- 6.0 9.0 BVPS-2 UFSAR Rev. 16 2 of 2 TABLE 10.4-4 (Cont) NOTES: 1. All concentrations are expressed in mg/l unless indicated otherwise. 2. NUS Corporation 1974 Aquatic Ecology Study, Baseline Water Quality Data, Annual Report. 3. Average blowdown concentrations based on cooling tower concentration factor of 1.8 and average river water concentration. 4. Minimum blowdown concentrations based on cooling tower concentration factor of 1.5. 5. Maximum blowdown concentrations based on cooling tower concentration factor of 2.4 maximum river water concentration. 6. Average and maximum values during system chlorination. Chlorine will be present in the discharge from each unit
for no more than 2 hours per day.
BVPS-2 UFSAR Rev. 12 1 of 1 TABLE 10.4-5 CONDENSATE POLISHING SYSTEM EFFLUENT PARAMETERS FOR NORMAL OPERATION
Refer to UFSAR Section 10.3.5, Water Chemistry
BVPS-2 UFSAR Rev. 0 1 of 2 TABLE 10.4-6 CONDENSATE POLISHING SYSTEM COMPONENT DESIGN DATA Component Parameter Filter/demineralizer Quantity 5 Flow (gpm) 4,250 Filter area per vessel (ft) 1,500 Filter vessel diameter (ft-in) 6-4 Filter volume (gal) 2,730 Design pressure (psig) 665 Design temperature ( F) 180 Material A-515, Grade 70 carbon steel Filter tube No. per filter 1,218 Diameter (inch) 1 Overall length (ft-in) 4-9 3/4 Material Type 304 stainless steel Area (ft/tube) 1.23 Precoat recirculation tank
Quantity 1 Capacity (gal) 2,250 Design pressure Atmospheric Tank lining 10-14 mils Plasite No. 7155 Material A-283 GRC Agitator motor (hp) 2 No. of paddles 1 Agitator (rpm) 29 Resin feed tank
Quantity 1 Capacity (gal) 500 Design pressure Atmospheric Tank lining 10-14 mils Plasite No. 7155 Material A-283 GRC Agitator motor (hp) 3/4 No. of paddles 1 Agitator (rpm) 58 BVPS-2 UFSAR Rev. 1 2 of 2 TABLE 10.4-6 (Cont) Component Parameter Backwash receiving tank
Quantity 1 Capacity (gal) 15,000 Design pressure (psig) 15 Design temperature ( F) 180 Tank lining 10-14 mils Plasite No. 7155 Material Carbon steel Holding pump
Quantity 5
Capacity (gpm) (each) 750 Temperature of fluid ( F) 180 Specific gravity 0.97 TDH (ft) 30 Motor (hp) (each) 10 Precoat pump
Quantity 2
Capacity (gpm) (each) 2,250 Temperature of fluid ( F) 120 TDH (ft) 110 Motor (hp) (each) 50 Backwash water pump Quantity 2
Capacity (gpm) (each) 500 Temperature of fluid ( F) 180 Specific gravity 1 TDH (ft) 95 Motor (hp) (each) 20 Air receiving tank
Quantity 1
Capacity (gal) 400 Design pressure (psi) 125 Material A-285 GRC BVPS-2 UFSAR Rev. 0 1 of 2 TABLE 10.4-7 CONDENSATE POLISHING SYSTEM INFLUENT PARAMETERS FOR NORMAL, START-UP AND MAJOR CONDENSER LEAKAGE Major Normal Condenser Influent Parameter Operation Start-up Leakage Temperature ( F) 70 to 125 70 to 180 70 to 125 pH 8.8-9.6 8.8-9.6 8.8-9.6 Cation conductivity (micromho/cm 0.2-0.3 0.5 8.0 to at 25C) 12.0 Total dissolved 50 2,000 to 1,200 solids (ppb) 4,000 Suspended 20 2,000 to 130 solids (ppb) 4,000 Calcium (Ca)
(ppb) 5 5 170 Magnesium (Mg) (ppb) 3 3 40 Silica (SiO) 18 500 to 50 (ppb) 2,000 Chloride (Cl) (ppb) 6 7 115 Sulfate (SO) (ppb) 16 20 700 Bicarbonate (HCO) (ppb) 3 5 65 Sodium (Na) (ppb) 5 6 150 Iron (Fe) 10-15 2,000 to 10 to 15 (ppb) 4,000 Copper (Cu) 0-2 200 to 0-2 (ppb) 400
BVPS-2 UFSAR Rev. 0 2 of 2 TABLE 10.4-7 (Cont)
Major Normal Condenser Influent Parameter Operation Start-up Leakage Dissolved oxygen (O) (ppb) 5-7 5-10 5-10 BVPS-2 UFSAR Rev. 0 1 of 1 TABLE 10.4-8 CONDENSER COOLING WATER ANALYSIS AVERAGE PARAMETERS
Chemical Components Normal Operation pH at 77 F 6.0 to 9.0 Total dissolved solids (ppm) 365 Suspended solids (ppm) 37.1 Calcium (Ca) (ppm) 49.5 Magnesium (Mg) (ppm) 13.5 Silica (SiO) (ppm) 14.4 Chloride (Cl) (ppm) 27 Sulfate (SO) (ppm) 155.9 Bicarbonate (HCO) (ppm) 42 Sodium (Na) (ppm) 33.5 BVPS-2 UFSAR Rev. 12 1 of 1 TABLE 10.4-9 STEAM GENERATOR BLOWDOWN ANALYSIS AT NORMAL OPERATIONS
Chemical Component Normal Operation
Refer to UFSAR Section 10.3.5, Water Chemistry
BVPS-2 UFSAR Rev. 0 1 of 2 TABLE 10.4-10 POWDERED RESIN DEWATERING SYSTEM COMPONENT DESIGN DATA Component Parameter Clamshell Filter Quantity 2 Filter area per vessel (ft) 10.38 Design pressure (psig) 75 Design temperature ( F) 120 Material SA-240, Stainless steel Type 304 Precoat Tank Quantity 1 Capacity (gal) 250 Design pressure (psig) Atmospheric Tank lining (mils) 8-10 Plasite No. 7155 Material Carbon steel Agitator motor (hp) 3/4 No. of paddles 1 Agitator (rpm) 70 Paddles and wetted shaft
material Stainless steel Type 304 Slurry Feed Tank
Quantity 1 Capacity (gal) 70 Design pressure (psig) Atmospheric Tank lining (mils) 8-10 Plasite No. 7155 Material Carbon steel Agitator motor (hp) 1/2 No. of paddles 1 Agitator (rpm) 112 Paddles and wetted shaft material Stainless steel Type 304
Backwash Feed Tank
Quantity 1 Capacity (gal) 15,000 Design pressure (psig) Atmospheric Material SA-240, Stainless steel Type 304 BVPS-2 UFSAR Rev. 0 2 of 2 TABLE 10.4-10 (Cont)
Component Parameter
Sludge Tank
Quantity 1 Capacity (gal) 3,620 Design pressure (psig) 150 Design temperature ( F) 200 Material SA-240, Stainless steel Type 304 Agitator motor (hp) 15 No. of paddles 2 Agitator (rpm) 37 Paddles and wetted shaft material Stainless steel Type 304 Filter Feed Pump
Quantity 2 Capacity (gpm) (each) 100 TDH (ft) 200 Motor (hp) 15 Precoat pump
Quantity 2 Capacity (gpm) (each) 50 TDH (ft) 20 Motor (hp) 1 Sludge Tanks Bottoms Pump
Quantity 1 Capacity (gal) 10 TDH (ft) 50 Motor (hp) 5 Overflow Pump (Recirculation Pump)
Quantity 1 Capacity (gpm) 100 TDH (ft) 150 Motor (hp) 1/2 BVPS-2 UFSAR Rev. 0 1 of 1 TABLE 10.4-11 POWDERED RESIN DEWATERING SYSTEM OPERATING PARAMETERS FOR CLAMSHELL FILTER
Component Parameter Clamshell filter
Operating pressure (psig) 75 Differential pressure: Clean (psig) 1 Precoated (psig) 2 End of filter cycle (psig) 50 Flow rate - operating (gpm) 100 Design temperature ( F) 200 Maximum volume of cake (ft) 6 Maximum weight of cake (lb) 132 Density of spent mixed powdered resin (50% water) (lb/ft) 23 Density of fresh powdered resin use for precoat (lb/ft) 12 BVPS-2 UFSAR Rev. 2 1 of 1 TABLE 10.4-12 STEAM GENERATOR BLOWDOWN SYSTEM COMPONENT DESIGN PARAMETERS Steam Generator Blowdown Tank Capacity (gal) 2,500 Design pressure (psig) 275 Design temperature ( F) 410 Design code ASME VIII
Steam Generator Blowdown Drain Tank Cooler
Total duty (Btu/hr) 5.035 x 10 Inlet temperature (blowdown) ( F) 397 Inlet temperature (component cooling water) (F) 95 Outlet temperature (blowdown) ( F) 180 Outlet temperature (component cooling water) ( F) 120 Design code ASME VIII
Steam Generator Blowdown Demineralizer Heat Exchanger
2BDG-E22 Total Duty (Btu/hr) 35.779 x 10 Inlet temperature (blowdown) ( F) 410 Inlet temperature (condensate) ( F) 155 Outlet temperature (blowdown) ( F) 150 Outlet temperature (condensate) ( F) 155 Design Code ASME VIII
2BDG-E23 Total Duty (Btu/hr) 3.690 x 10 Inlet temperature (blowdown) ( F) 150 Inlet temperature (component cooling water) ( F) 115 Outlet temperature (blowdown) ( F) 120 Outlet temperature (component cooling water) ( F) 115 Design Code ASME VIII
BVPS-2 UFSAR Rev. 12 1 of 1 TABLE 10.4-13 STEAM GENERATOR STEAM SIDE AND FEEDWATER CHEMISTRY SPECIFICATIONS C o l d H y d r o/ Cold Hot Functional/ W e t H o t S h u t d o w n/ Layup Hot Standby Start-up From Hot Standby Normal Power Operation Chemistry Blowdown Blowdown Feedwater Blowdown Feedwater Blowdown Parameter Control Control Expected Expected Control Control Expected Expected Control Control Expected pH @ 25 C Free hydroxide as ppm CaCO 3 Cation conductivity mhos/cm @ 25 C Total conductivity mhos/cm @ 25 C Refer to UFSAR Section 10.3.5, Water Chemistry
Sodium, ppm
C h l o r i d e , p p m
NH 3 , p p m Hydrazine, ppm
Dissolved oxygen, ppb
SiO 2 , p p m
Fe, ppb
Cu, ppb
Suspended solids, ppm Blowdown rate, gpm/SG
BVPS-2 UFSAR Rev. 0 1 of 1 TABLE 10.4-14 AUXILIARY BOILERS PERFORMANCE CHARACTERISTICS Condition Parameters Steam output 150,000 lb/hr Boiler operating pressure/temperature 150 psig/366 F Auto boiler blowdown 7,500 lb/hr Boiler feedwater temperature 228 F Burner turndown ratio 15,000 lb/hr to 10,000 lb/hr Overall unit efficiency at 100% load 80.3%
Exilt gas temperature at 80 F inlet air 601 F BVPS-2 UFSAR Rev. 0 1 of 1 TABLE 10.4-15 AUXILIARY BOILERS DESIGN PARAMETERS
Component Parameter
Make Babcock-Wilcox
Type D type, FM Design pressure waterside (psig) 250 Design pressure gas side (wg) (in.) 18
Drum material, ASME designation SA515GR70/SA106 Upper drum I.D. (in.)/thickness (in.) 48/1.03 Lower drum I.D. (in.)/thickness (in.) 24/0.0875
Membrane type construction Side walls, rear wall, floor and
ceiling Refractory wall construction Front wall
NOTES 1. Materials listed in this table may have been replaced with materials of equivalent design characteristics. The term equivalent is described in UFSAR Section 1.12, "Equivalent Materials".
BVPS-2 UFSAR Rev. 0 1 of 2 TABLE 10.4-16 AUXILIARY BOILERS PRINCIPAL COMPONENTS AND DESIGN PARAMETERS Component Design Parameters Deaerator Quantity 1 Capacity (lb/hr) 150,000 Operating pressure (psig) 5 Operating temperature ( F) 228 Boiler feed pumps
Quantity 2 Gpm (each) 330 Head (ft) 550 Horsepower 100
Underground fuel oil tanks
Quantity 5 Dimensions (ft, each) 12 (diameter) x 63 (length) Capacity (gal, each) 48,000 Underground fuel oil transfer pumps
Quantity 2 Gpm (each) 30 Head (ft) 125 Horsepower 3
Fuel oil day tank
Quantity 1 Design capacity (gal) 596
Fuel oil pumps (boilers)
Quantity 2 Gpm (each) 24 Head (ft) 460 Horsepower 7.5 BVPS-2 UFSAR Rev. 0 2 of 2 TABLE 10.4-16 (Cont)
Component Design Parameters
Chemical feed system
Number of chemical skids 2 Feed tanks per skid 1 Capacity (gal) 100 Feed pumps per skid 2 GPH (each) 5 Horsepower
0.5 Auxiliary
boiler blowdown tank
Quantity 1 Design capacity (gal) 483 Auxiliary boiler blowdown vent condenser
Quantity 1 Design pressure shell (psig) 150 Design pressure tube (psig) 150 Fluid condensed steam Flow (lb/hr) 1414.5 GLAND EXHAUST ALL VALVE AND EQUIPMENT IDENTIFICATION NUMBERS ON THIS FIGURE ARE PRECEDED BY THE SYSTEM DESIGNATOR "2GSS" UNLESS OTHERWISE INDICATED. TO CLAND STEAM CCI\IOENSER EXHAUSTERS FIGURE 10.4-1 REV. 18 TURBINE GLAND SEAL STEAM SYSTEM
REFERENCE:
STATION DRAWINGS OM 26-2 AND OM 26-3 BEAVER VALLEY POWER STATION -UNIT 2 UPDATED FINAL SAFETY ANALYSIS REPORT P&ID-FSAR CROSS-REFERENCE KEY FSAR FSAR FSAR P&ID FIGURE P&ID FIGURE P&ID FIGURE NO. NO. NO. NO. NO. NO. 06-1A 5.1-2 15-8 9.2-16 25-3A 11.2-3 06-18 5.1-3 25-38 11.2-4 06-1C 5.1-4 16-1 6.5-2 25-4 11.2-5 06-2A 5.4-8 16-2 6.5-3 25-5 11.2-6 06-28 5.4-9 06-4A 5.1-5 17-1 11.2-1 26-1A 10.2-2 06-48 5.1-6 26-18 10.2-3 D6-4C 5.1-7 18-1 11.4-1 26-2 10.2-7 18-2 11.4-2 26-3 10.4-1 07-1 9.3-21 26-4 10.2-1 07-2 9.3-22 19-1 11.3-1 26-6 10.2-6 07-3A 9.3-23 19-2 11.3-2 26-7 10.2-8 07-38 9.3-24 19-3 11.3-3 26-17 9.4-16 07-4 9.3-25 20-1 9.1-4 27-1 10.4-25 08-1A 9.3-26 27-2 10.4-26 08-18 9.3-27 21-1A 10.3-1 27-3 10.4-32 08-2 9.2-30 21-18 10.4-2 27-4 10.4-26A 21-1C 10.3-3 278-1 10.4-37 09-1 9.3-13 21-1D 10.3-4 278-2 10.4-38 09-2 9.3-14 21-1E 10.3-2 278-3 10.4-39 09-3A 9.3-15 21-2 9.5-14 278-4 10.4-40 09-38 9.3-16 22-1A 10.4-13 28-1A 9.2-28 10-1 5.4-4 22-18 10.4-12 28-18 9.2-29 22-2A 10.4-7 29-1 9.2-17 11-1 6.3-1 22-28 10.4-8 29-2 9.2-18 11-2 6.3-2 22-3A 10.4-10 29-3 9.2-19 11-3 9.5-13 22-38 10.4-11 29-4 9.2-20 11-4 6.3-3 22-4 10.4-9 30-1 9.2-1 12-1 9.5-15 22-5 9.3-5 30-2 9.2-2 30-3 9.2-3 13-1 6.2-122 23A-1A 10.4-33 30-4 9.2-4 13-2 6.2-121 23A-1B 10.4-34 30-5 9.2-5 23A-1C 10.4-35 31-1 10.4-3 14A-1A 9.3-6 23A-2 10.4-36 31-2 '10.4-4 14A-18 9.3-7 31-3 10.4-5 14A-2 9.3-8 23B-3A 10.4-17 31-4 10.4-6 238-38 10.4-18 32-1 9.2-22 148-1 9.3-9 23B-4A 10.4-19 32-3 10.3-5 148-2 9.3-10 238-48 10.4-20 32-4 9.2-c27 14C-1 9.3-11 SHT1 238-5A 10.4-21 33-1A 9.5-1 14C-2 9.3-11 SHT2 238-58 10.4-22 33-18 9.5-2 15-1 9.2-10 33-2 9.5-3 15-2 9.2-11 24-1A 10.4-15 33-3 9.5-4 15-3 9.2-12 24-18 10.4-14 33...:4A 9.5-5 15-4 9.2-13 24-1C 10.4-16 33-48 9.5-6 15-5 9.2-21 24-2 10.4-24 33-5 9.5-6A 15-6 9.2-14 34-1 9.3-1 15-7 9.2-15 25-1 10.4-23 34-2 9.3-2 25-2 11.2-2 34-3 9.3-3 34-4 9.3-4 P&ID NO. 35-2 .35-3 36-9 36-10 36-11 36-12A. .36-128 36-13 41A-1 41A-2 41A-3A 41A-38 41A-4 41C-1 41C-2 41C-'-3 410-1 410-2 410-3 410-5 410-6 44A-1 44A-2 44A-4 448-1 44B-3A 448-38 44C-1 44C-2 44D-1A 440-18 440-2 44F-1 44F-2 44F-3 44F-4 44G-1 44G-2 44G-3 44G-4 46-1 59A-1 598 1 -FSAR FIGURE NO. 10.2-9 10.2-10 9.5-7 9.5-12 9.5-10 9.5-8 9.5-9 9.5-11 10.4-27 10.4-28 10.4-29 10.4-30 J0.4-31 9.2-24 9.2-25 9.2-26 9.3-17 9.2-23 9.3-18 9.3-20 9.3-19 9.4-2 9.4-1 9.4-3 9.4-12 9.4-15 9.4-14 9.4-9 9.4-10 9.4-4 9.4-5 9.4-6 9.4-11 9.4-7 9.4-13 9.4-8 9.4-17 9.4-18 9.4-19 9.4-:20 6.2-131 H1 9.5 2A SH2 9.5-2A S -NO. 10080-0M-21-18 I *
- D lf TO CQNDENSER 118 2CN.4-CN>21A -Rr;.22......miC-7l ADc-O 1 EI.OCK A El.obc B S'ffi\tr.l 1 SS SS 11.o&t B BLOCK A 1 .. 'I'C 2" Ill" I cs REV. 10 (97) 2" riG. 10.4-2 a :t' ACC:-0 2" TO CONlENSER Fn22-7CIE-3J TO CONlENSER 2CI&H:>D2Il FIG.2Z-7CIE-3)
- 2. .ld..L VENTS,DRAINS.MD .ef'ESSI..R:
CONNECrt::JNS ME O'J"'tofRNNSE t<llU>. 3. *llENOTES IUlLEAR SoiFEN RELATED. 4. REFERENCE DWG. 10080-RI.t 4'8 10080-Riol -PIPING: TURBINE BYPASS SYSTEM BEAVER VALLEY POWER STATION -UNIT 2 UPDATED FINAL SAFETY ANALYSIS REPORT
- 0 COOLING TOWER MAIN CONDENSERS FROM UNIT 1 RIVER WATER OUT FALL STRUCTURE REV. 1 2 FLOW SERVICE WATER SERVICE WATER P21B P21D COOLING TOWER PUMPS ALL VALVE AND EQUIPMENT IDENTIFICATION NUMBERS ON THIS FIGURE ARE PRECEDED BY THE SYSTEM DESIGNATOR
- zcws" UNLESS OTHERWISE INDICATED. F I GURE 1 0. 4-3 CIRCULATING WATER SYSTEM
REFERENCE:
STATION DRAWINGS OM 31-1 AND OM 31-2 BEAVER VALLEY POWER STATION UNIT NO. 2 UPDATED FINAL SAFETY ANALYSIS REPORT CONDENSATE POLl SH I NG SERVICE AIR ACCUMULATOR TK25 MAIN HEADER CONDENSATE POLISHING SERVICE AIR HEADER CONDENSATE RETURN HEADER 1 04E DEMINERALIZERS REV. 1 2 DEMN 21E MAIN ______________________ ._ ____ __j HEADER I PRECOAT '> PRECOAT SUPPLY HEADER PUMPS SAMPLE PANEL PNL21 P22A(8} l DISHCHARGE PRECOAT RETURN HEADER/BACKWASH WATER SUPPLY 155 FROM BACKWASH WATER PUMPS P23A & B I DEMI NERAL I ZER ORA IN HEADER TO RECIRCULATING TANK TK21 NOTE: VALVES 103A. 114A, 148, 152A. 153A AND THE ASSOCIATED PIPING AND CONNECTIONS FOR DEMN-21A ARE TYPICAL FOR ALL OF THE OEMINERALIZERS. ... ALL VALVE AND EQUIPMENT IDENTIFICATION NUMBERS ON THIS FIGURE ARE PRECEDED BY THE SYSTEM DESIGNATOR u2CND" UNLESS OTHERWISE INDICATED. FIGURE 1 Q. 4-7 CONDENSATE DEMINERALIZER SYSTEM
REFERENCE:
STATION DRAWINGS OM 228-1 AND OM 22B-2 BEAVER VALLEY POWER STATION UNIT NO. 2 UPDATED FINAL SAFETY ANALYSIS REPORT BACKWASH RECEIVING TANK SOLID WASTE OR TRUCK CONNECTION TK22 DRAIN HEADER 1 45 300 FLT22A CLAM SHELL FILTER DUMP CHUTE P26 SLURRY FEED TANK P24B P23B P23A CLAM SHELL FILTERS FLT22B TK24 ... BACKWASH FEED TANK FLT22B CLAM SHELL FILTER DUMP CHUTE n WASTE UCONTAINER TK26 PRECOAT RECIRC TANK REV. 1 2 ALL VALVE AND EQUIPMENT IDENTIFICATION NUMBERS ON THIS FIGURE ARE PRECEDED BY THE SYSTEM DESIGNATOR "2CND" UNLESS OTHERWISE INDICATED. F I GURE 1 0. 4 -8 CONDENSATE DEMINERALIZER SYSTEM
REFERENCE:
STATION DRAWINGS OM 22B-3A AND OM 22B-4 BEAVER VALLEY POWER STATION UNIT NO. 2 UPDATED FINAL SAFETY ANALYSIS REPORT TURBINE PLANT DEMIN WATER STORAGE TANK TK211 MAIN CONDENSERS HOTWELL EQUALIZER LINES 2CNC-611 2CNC-610 CHEMICAL FEED 2CNS-1150 HOTWELL HIGH LEVEL RETURN TO CONDENSATE STORAGE TK211 P21B P21C CONDENSATE PUMPS CONDENSATE PUMP MINIMUM FLOW LINE REV. 1 2 5TH POINT HEATERS 4TH POINT HEATERS 3RD POINT HEATERS 2ND POINT HEATERS TO STEAM GENERATOR FEED PUMPS ALL VALVE AND EQUIPMENT IDENTIFICATION NUMBERS ON THIS FIGURE ARE PRECEDED BY THE SYSTEM DESIGNATOR u2CNMu UNLESS OTHERWISE INDICATED. F I GURE 1 0. 4 -1 2 CONDENSATE SYSTEM
REFERENCE:
STATION DRAWINGS OM 22A-1 AND OM 22A-2 BEAVER VALLEY POWER STATION UNIT NO. 2 UPDATED FINAL SAFETY ANALYSIS REPORT P21B MAIN FEEDWATER PUMP 15 18 154C 498 27 1548 CONTAJNMENT 157C 30 1578 29 ALL VALVE AND EQUIPMENT IDENTIFICATION NUMBERS ON THIS FIGURE ARE PRECEDED BY THE SYSTEM DESIGNATOR H2FWSH UNLESS OTHERWISE INDICATED. F I GURE 1 0. 4 -1 4 FEEDWATER SYSTEM
REFERENCE:
STATION DRAWINGS OM AND BEAVER VALLEY POWER STATION UNIT NO. 2 UPDATED FINAL SAFETY ANALYSIS REPORT SG-21C 1-1-z z w w :::E :L z = ...... <I <I I-1-z z 0 0 u u w LJ.J 0 s (j) (/) ,_ ::J 0 1enc1 101C2 100Cl SG-218 12 10181 10182 10081 SG-21A STEAM GENERATORS 101Al T 101A2 100Al REV I 12 304 TO 2ND POINT 110 HEATERS 305 TO CONDENSER 303 302 TK-21 STEAM 301 GENERATOR BLOW DOWN TANK TO STEAM GENERATOR SLOWDOWN HOLD TANKS BLOW DOWN DEMINERALIZERS 1018 313 312 E-21 BLOW DOWN TANK DRAIN COOLER E-23 BLOW DOWN HEAT EXCHANGER E-22 BLOW DOWN HEAT EXCHANGER 582 311 101A2 TO 4TH POINT HEATERS 101Al 584 CONDENSER 601 583 ALL VALVE AND EQUIPMENT IDENTIFICATION NUMBERS ON THIS DIAGRAM ARE PRECEDED BY THE SYSTEM DESIGNATOR
- 2BDG" UNLESS OTHERWISE INDICATED.
102 FIGURE 10.4-23 STEAM GENERATOR BLOWDOWN REFERENCE DRAWINGS OM 25-1 AND 25-lA BEAVER VALLEY POWER STATION UN[T N0.2 UPDATED FINAL SAFETY ANALYSIS REPORT FROM OEMIN WATER SUPPLY SYSTEM t 96 97 98 PRIMARY PLANT OEM IN WATER STORAGE TANK HYORAZINE AUXILIARY S/G FEED PUMP MORPHOLINE P238 FROM SERVICE WATER SYSTEM DISCHARGE CHECK AND RECIRCULATING VALVES CAVITATING VENTUR l FLOW ELEMENTS lliEt!O 1-z w :::::= z ..:( 1-z 0 u w 0 (/) z SIG STEAM GENERATOR DEMIN DEMINERALIZED RECIRC RECIRCULATION REV. 12 TO S/G 'A' FEEOWATER PIPING SYSTEM TO S/G '6' FEEDWATER PIPING SYSTEM TO S/G 'C' FEEDWATER PIPING SYSTEM All VALVE AND EQUIPMENT IDENTIFICATION NUMBERS ON THIS FIGURE ARE PRECEDED BY THE SYSTEM DESIGNATOR
- 2FWEu UNLESS OTHERWISE INDICATED.
FIGURE 10.<4-2<4 AUXILIARY FEEOWATER SYSTEM
REFERENCE:
STATION DRAWING OM 24-3 BEAVER VALLEY POWER STATION UNIT NO. 2 UPDATED FINAL SAFETY ANALYSIS REPORT TO/FROM FEEDWATER 3RD POINT HEATER 2SVH-29 2CNM-CND21A CONDENSER 4TH POINT HEATER 2CNM-CND21A CONDENSER 4TH POINT HEATER 105D REV. 12 2CNM-CND21B CONDENSER NOTE: 3RD POINT HEATER 103B VALVE ARRANGEMENT FOR 2FWS-H23A. H24A, AND H25A ARE TYPICAL FOR 2FWS-H23B. H24B. AND H25B RESPECTIVELY. 2CNM-CND218 TO/FROM CONDENSATE <TYPICAL FOR ALL 2ND. 3RO. 4TH, 5TH AND 6TH POINT HEATERSl CONDENSER ALL VALVE AND EQUIPMENT IDENTIFICATION NUMBERS ON THIS FIGURE ARE PRECEDED BY THE SYSTEM DESIGNATOR "2ESSn UNLESS OTHERWISE INDICATED. FIGURE 1 Q. 4-33 EXTRACTION STEAM SYSTEM
REFERENCE:
STATION DRAWINGS OM 23A-1 OM 23A-2 AND OM 26-1 BEAVER VALLEY POWER STATION UNIT NO. 2 UPDATED FINAL SAFETY ANALYSIS REPORT BVPS-UFSAR Rev. 15 10A-i
APPENDIX 10A
AUXILIARY FEEDWATER SYSTEM
SIMPLIFIED RELIABILITY ANALYSIS
NOTE: UFSAR Appendix 10A is for Historical Information only, and should not be used for plant-specific PRA Risk Determination.
BVPS-2 UFSAR Rev. 0 10A-iii CHAPTER 10A AUXILIARY FEEDWATER SYSTEM SIMPLIFIED RELIABILITY ANALYSIS TABLE OF CONTENTS Section Title Page 10A AUXILIARY FEEDWATER SYSTEM SIMPLIFIED RELIABILITY ANALYSIS 10A-1 10A.1 Unavailability Evaluation 10A-1 10A.2 Summary of Findings 10A-1 10A.3 Methods and Assumptions Used 10A-1 10A.4 Single Failure Analysis 10A-2 10A.5 References for Appendix 10A 10A-3 BVPS-2 UFSAR Rev. 0 10A-v APPENDIX 10A LIST OF FIGURES Figure Title 10A-1 Availability and Unavailability (with Offsite Power), Auxiliary Feedwater System 10A-2 Availability and Unavailability (without Offsite Power), Auxiliary Feedwater System
FMEA-5-13M Failure Modes and Effects Analysis, Auxiliary Feedwater System (Mech)
FTSK-5-13M Fault Tree Diagram, Auxiliary Feedwater System (Mech) BVPS-2 UFSAR Rev. 0 10A-1 10A AUXILIARY FEEDWATER SYSTEM SIMPLIFIED RELIABILITY ANALYSIS 10A.1 Unavailability Evaluation
A simplified reliability analysis was performed on the auxiliary feedwater system (AFWS) to determine the potential for system failure and to meet the intent of NUREG-0737 (USNRC 1980), Action Item II.E.1.1. This analysis was performed for the loss of main feedwater transient conditions, both with and without
offsite power available. 10A.2 Summary of Findings
The analysis of the AFWS showed the system to be very reliable. An overall system unavailability was determined from common cause failures, independent human errors, hardware failures, and test and maintenance errors. Figures 10A-1 and 10A-2 show the simplified unavailability models for the Beaver Valley Power Station - Unit 2 (BVPS-2) AFWS. For the loss of main feedwater transient with offsite power available, the calculated overall system unavailability was 8.70 X 10. For the transient where offsite power is not available, the calculated overall system unavailability was 9.00 x 10. The slight increase in the unavailability of the system for the latter transient condition is a result of including the unavailability of the emergency diesel generator power sources in the hardware failures unavailability contribution.
10A.3 Methods and Assumptions Used
Two of the unavailability values used in the calculations for BVPS-2 were taken from the Zion Units 1 and 2 probabilistic Safety Study (ZPSS) (U.S. Nuclear Regulatory Commission 1981)
that was performed on their AFWS. These were values for independent human errors and test and maintenance errors. Although the designs of the Zion units and BVPS-2 AFWSS are not
identical, the unavailability values for these two failure contributors were assumed to be similar. The unavailability value for common cause failures is also an assumed value.
Fault tree logic technique (Sections 1.7 and 7.3.2) were used to determine the unavailability due to hardware failures. These fault trees are presented as FTSK-5-13M-A through FTSK-5-13M-AG. The fault trees were developed based on the following considerations and assumptions:
- 1. Electrical portions of the components in the fault trees are shown as single components. Since only one
fault tree was used for both transients, for the transient that addresses the loss of offsite power the unavailability of the redundant emergency diesel
generator power sources was included as directly causing the failure of the motor-driven auxiliary feedwater pump powered from that source. The
BVPS-2 UFSAR Rev. 0 10A-2 event blocks and logic gates for this portion of the loss are not shown on the fault trees, however.
- 2. The fault tree analysis is based on a system operating time of 24 hours being required to remove heat from the reactor coolant system.
- 3. The fault tree configuration reflects the availability of backup water sources. Therefore, a rupture of the primary plant demineralized water storage tank (PPDWST) or a piping failure between the PPDWST and any auxiliary feedwater pump has not been configured into the fault tree as causing the top event directly.
This consideration requires the level in the PPDWST be monitored during system operation to allow sufficient time to align the backup water sources before the PPDWST supply, described in Section 10.4.9, is depleted. The backup water sources from the 600,000 gallon demineralized water storage tank and the service water system are described in Section 10.4.9. This fault tree configuration is believed to be representative of the actual mode of operation following a loss of feedwater transient condition.
- 4. The fault tree configuration is also based on system design features, such as the missile-protected PPDWST structure, the redundant power sources to the motor-driven auxiliary feedwater pumps, the location of these pumps in separate cubicles, and the seismic design of the safeguards building that these pumps are housed in.
- 5. In support of this evaluation, a separate study which showed the development of simplified event sequence
diagrams that reflects the system operation was used. 10A.4 Single Failure Analysis
Based on the fault trees, a single failure analysis was performed using the SWEC CS-007 (Stone & Webster Engineering Corporation 1981) computer program. This program also generated the failure modes and effects analysis (FMEA) that describes the failure mode of each component and its effect on the system, including potential single failures. The FMEA is presented as
FMEA-15-13M. One source of a potential single failure was identified in the FMEA. This single failure would result from a rupture of the piping between the check valves downstream of each flow control valve and the cavitating venturi in the associated header. A
rupture in the piping here could cause flow to all steam generators to be decreased. The control room operators would be alerted to this event by alarms and indications from the redundant flow transmitters in each header, and they could isolate the pipe rupture by closing the appropriate flow BVPS-2 UFSAR Rev. 0 10A-3 control valve. Flow would then be restored through the unaffected headers to meet the design requirements of the system. 10A.5 References for Appendix 10A Stone & Webster Engineering Corporation 1981. Fault Tree
Analysis Computer Program. SWEC CS-007. U.S. Nuclear Regulatory Commission 1980. Clarification of TMI
Action Plan Requirements. NUREG-0737. U.S. Nuclear Regulatory Commission 1981. Zion Units 1 and 2
Probabilistic Safety Study, Volume 3, Section 1.5.2.3.9. Docket Nos. 50-295 and 50-304.
FAILURE OF AUXILIARY FEEDWATER SYSTEM (24 HOURS) COMMON CAUSE FAILURES INDEPENDENT HUMAN ERRORS HARDWARE FAILURES TEST AND MAINTENANCE ERRORS FAILURES COMMON CAUSE FAILURES INDEPENDENT HUMAN ERRORS HARDWARE FAILURES TEST AND MAINTENANCE ERRORS OVERALL SYSTEM tt ZPSS TABLE 1.5.2 3.9 -7G tt tt Z PS S T A 8 L E I 5. 2 . 3 . 9 -7 D AVAILABILITY (A) 9999990 .9999997 .9999958 .9999968 .99999!3 UNAVAILABILITY (Q) 1. oo x w-6 3.54xiQ-7 tt 4.21 x w-6 3.24x10-6** 8.70 X lQ-6 FIGURE tOA-1 AUXILIARY FEEOWATER SYSTEM AVAILABILITY AND UNAVAILABILITY (WITH OFFSITE POWER) BEAVER VALLEY POWER STATION-UNIT 2 FINAL SAFETY ANALYSIS REPORT FAILURE OF AUXILIARY FEEDWATER SYSTEM (24 HOURS) COMMON CAUSE FAILURES INDEPENDENT HUMAN ERRORS HARDWARE FAILURES {INCLUDING LOSS OF DIESEL POWER) TEST AND MAl NTENANCE ERRORS FAILURES COMMON CAUSE FAILURES INDEPENDENT HUMAN ERRORS AVAILABILITY (A) .9999990 .9999997 HARDWARE FAILURES {INCL. LOSS OF DIESELS) .9999955 TEST AND MAINTENANCE ERRORS .9999968 OVERALL SYSTEM tt ZPSS TABLE 1.5. 2 .3 9 -7G tttt ZPSS TABLE 1.5.2.3 9-7D .9999910 UNAVAILABILITY (Ql I. 00 X 10-8 3.54110-7 It 4 52 .. w-e 3.24 .. w-e *
- 9.00 X IQ-6 FIGURE IOA-2 AUXILIARY FEEOWATER SYSTEM AVAILABILITY AND UNAVAILABILITY
{WITHOUT OFFSITE POWER) BEAVER VALLEY POWER STATION-UNIT 2 FINAL SAFETY ANALYSIS REPORT