ML23193A895
| ML23193A895 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 06/28/2023 |
| From: | Dominion Energy Nuclear Connecticut |
| To: | Office of Nuclear Reactor Regulation |
| Shared Package | |
| ML23193A862 | List:
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| References | |
| 23-169 | |
| Download: ML23193A895 (1) | |
Text
Millstone Power Station Unit 3 Safety Analysis Report Chapter 10: Steam and Power Conversion System
Table of Contents tion Title Page
SUMMARY
DESCRIPTION................................................................... 10.1-1 TURBINE-GENERATOR........................................................................ 10.2-1
.1 Design Bases............................................................................................. 10.2-1
.2 Description................................................................................................ 10.2-2
.2.1 Turbine-Generator Equipment .................................................................. 10.2-2
.2.2 Turbine Overspeed Protection .................................................................. 10.2-4
.3 Turbine Integrity ....................................................................................... 10.2-5
.3.1 Materials Selection ................................................................................... 10.2-6
.3.2 Fracture Toughness................................................................................... 10.2-6
.3.3 High Temperature Properties.................................................................... 10.2-6 2.3.4 Turbine Design ......................................................................................... 10.2-6
.3.5 Preservice Inspection ................................................................................ 10.2-6
.3.6 Inservice Inspection .................................................................................. 10.2-7
.4 Evaluation ................................................................................................. 10.2-8
.5 References for Section10.2 ....................................................................... 10.2-8 MAIN STEAM SYSTEM ....................................................................... 10.3-1
.1 Design Bases............................................................................................. 10.3-1
.2 System Description ................................................................................... 10.3-2
.3 Safety Evaluation ...................................................................................... 10.3-3
.4 Inspection and Testing Requirements....................................................... 10.3-7
.5 Secondary Side Water Chemistry ............................................................. 10.3-8
.6 Main Steam and Feedwater System Materials.......................................... 10.3-9
.6.1 Fracture Toughness................................................................................... 10.3-9
.6.2 Materials Selection and Fabrication ......................................................... 10.3-9
.7 Instrumentation Requirements ................................................................ 10.3-10 OTHER FEATURES OF MAIN STEAM AND POWER CONVERSION SYSTEM ........................................................................ 10.4-1
.1 Main Condenser ........................................................................................ 10.4-1
tion Title Page
.1.1 Design Bases............................................................................................. 10.4-1
.1.2 System Description ................................................................................... 10.4-1
.1.3 Safety Evaluation ...................................................................................... 10.4-2
.1.4 Tests and Inspections ................................................................................ 10.4-4
.1.5 Instrumentation Requirements .................................................................. 10.4-4
.2 Main Condenser Evacuation System ........................................................ 10.4-4
.2.1 Design Bases............................................................................................. 10.4-4
.2.2 System Description ................................................................................... 10.4-5
.2.3 Safety Evaluation ...................................................................................... 10.4-5
.2.4 Tests and Inspections ................................................................................ 10.4-6
.2.5 Instrumentation Requirements .................................................................. 10.4-6
.3 Turbine Gland Sealing System ................................................................. 10.4-7
.3.1 Design Bases............................................................................................. 10.4-7
.3.2 System Description ................................................................................... 10.4-7
.3.3 Safety Evaluation ...................................................................................... 10.4-8
.3.4 Tests and Inspections ................................................................................ 10.4-8
.3.5 Instrumentation Requirements .................................................................. 10.4-9
.4 Turbine Bypass System ............................................................................ 10.4-9
.4.1 Design Basis ........................................................................................... 10.4-10
.4.2 System Description ................................................................................. 10.4-10
.4.3 Safety Evaluation .................................................................................... 10.4-11
.4.4 Tests and Inspections .............................................................................. 10.4-11
.4.5 Instrumentation Requirements ................................................................ 10.4-11
.5 Circulating Water and Associated Systems ............................................ 10.4-13
.5.1 Design Bases........................................................................................... 10.4-14
.5.2 System Description ................................................................................. 10.4-15
.5.3 Safety Evaluation .................................................................................... 10.4-18
.5.4 Tests and Inspections .............................................................................. 10.4-21
.5.5 Instrumentation Requirements ................................................................ 10.4-21
.6 Condensate Polishing Demineralizer System ......................................... 10.4-26
.6.1 Design Bases........................................................................................... 10.4-26
tion Title Page
.6.2 System Description ................................................................................. 10.4-26
.6.3 Safety Evaluation .................................................................................... 10.4-27
.6.4 Tests and Inspection................................................................................ 10.4-28
.6.5 Instrumentation Requirements ................................................................ 10.4-28
.7 Condensate and Feedwater Systems ....................................................... 10.4-29
.7.1 Design Basis ........................................................................................... 10.4-29
.7.2 System Description ................................................................................. 10.4-30
.7.3 Safety Evaluation .................................................................................... 10.4-34
.7.4 Testing and Inspection Requirements..................................................... 10.4-36
.7.5 Instrumentation Requirements ................................................................ 10.4-36
.8 Steam Generator Blowdown System ...................................................... 10.4-41
.8.1 Design Basis ........................................................................................... 10.4-41
.8.2 System Description ................................................................................. 10.4-42
.8.3 Safety Evaluation .................................................................................... 10.4-43
.8.4 Testing and Inspection ............................................................................ 10.4-43
.8.5 Instrumentation Requirements ................................................................ 10.4-44
.9 Auxiliary Feedwater System................................................................... 10.4-44
.9.1 Design Basis ........................................................................................... 10.4-45
.9.2 System Description ................................................................................. 10.4-49
.9.3 Safety Evaluation .................................................................................... 10.4-52
.9.4 Inspection and Testing Requirements..................................................... 10.4-54
.9.5 Instrumentation Requirements ................................................................ 10.4-55
.10 Auxiliary Steam and Associated Systems .............................................. 10.4-57
.10.1 Design Basis ........................................................................................... 10.4-57
.10.2 System Description ................................................................................. 10.4-58
.10.3 Safety Evaluation .................................................................................... 10.4-60
.10.4 Inspection and Testing Requirements..................................................... 10.4-61
.10.5 Instrumentation Requirements ................................................................ 10.4-61
.11 References for Section 10.4 .................................................................... 10.4-62
List of Tables mber Title
-1 Steam and Power Conversion System Principle Design and Performance Characteristics
-1 Materials of Main Steam and Feedwater Valves and Piping
-2 Materials of Main Steam Safety Valves
-3 Materials of Main Steam Pressure Relieving Valves
-4 Materials of Main Steam/Feedwater Valves
-1 Circulating Water and Associated Systems Design and Performance Characteristics
-2 Design Data Condensate Polishing System
-3 Condensate and Feedwater System Equipment Design parameters
-4 Equipment Design Parameters
-5 Equipment Design Parameters
-6 Condenser: Physical Characteristics and Performance Requirements (1)
-7 Deleted by PKG FSC MP3-UCR-2010-012
List of Figures mber Title
-1 Fundamental Diagram
-2 Rated Heat Balance
-3 Deleted by PKG FSC 03-MP3-027
-1 P&ID Electro-Hydraulic Control
-2 (Sheets 1-3) P&ID Turbine Generator and Feed Pump Oil Systems
-3 P&ID Turbine Generator Support Systems
-1 (Sheets 1-6) P&ID Main Steam and Reheat
-2 (Sheets 1-3) P&ID Turbine Plant Miscellaneous Drains
-3 P&ID Chemical Feed
-3(1)(A) Deleted by PKG FSC 98-MP3-126
-1 (Sheets 1-3) P&ID Condensate System
-2 (Sheets 1-2) P&ID Condenser Air Removal System and Waterbox Priming
-3 P&ID Extraction Steam and Turbine Generator Gland Seal and Exhaust (Sheets 1-2) 4-4 P&ID Circulating Water System (Sheets 1-2) 4-5 P&ID Condensate Demineralizer - Mixed Bed (Sheets 1-5)
-6 P&ID Feedwater System (Sheets 1-4)
-7 P&ID Feedwater Heater and Main Steam Reheat Vents and Drains (Sheets 1-3) 4-8 Not Used
-9 P&ID Auxiliary Steam, Feedwater and Condensate (Sheets 1-3)
-9(1)(A) Auxiliary Steam, Feedwater and Condensate (TEMP/MOD 3-97-061)
-10 Minimum Auxiliary Feedwater Flow to Four Steam Generators, Loss of Normal Feedwater Event
-11 Minimum AFW Flow to Three Effective Steam Generators, Feedwater Line Break Event
-12 Minimum Auxiliary Feedwater Flow to Two Steam Generators, Better Estimate Loss of Normal Feedwater Event for Reliability Analysis
s chapter provides information concerning the Millstone 3 steam and power conversion em.
1
SUMMARY
DESCRIPTION steam and power conversion system (Figure 10.1-1) is designed to accept steam from a surized water-type nuclear steam supply system (NSSS) at a steam generator power of 5 MWt. The system consists of an 1,800 rpm tandem compound, 6-flow, 43 inch last stage ket turbine coupled to a single, hydrogen inner-cooled generator and rotating rectifier exciter.
s system converts the thermal energy of the steam to electric energy, producing 1305 MWe ign rated) at the NSSS warranted condition (Figure 10.1-2).
steam and power conversion system is based on a turbine cycle consisting of motor-driven densate pumps, turbine-driven feedwater pumps, six stages of feedwater heating, and a single e of steam reheat. Moisture separation and steam reheat are provided between the high and pressure turbines. Steam is condensed in three surface-type, single-pass condensers of ded water box design, and condensate is collected in the hotwell which has storage capacity ivalent to approximately 5 minutes of full load operation.
condensate and feedwater system returns feedwater to the steam generators through six es of extraction heating arranged in three parallel strings.
system provides load following capability in accordance with the NSSS vendors specified ability and within the turbine manufacturers recommended limitations. Turbine bypass and ospheric steam dump capacity accommodates more severe load rejections without reactor or ine trip, as specified by the NSSS vendor.
principal design and performance characteristics of the steam and power conversion system summarized in Table 10.1-1. Those design features of the steam and power conversion system are safety-related QA Category I are indicated by asterisks.
AND PERFORMANCE CHARACTERISTICS Item Design and Performance Characteristics rbine-Generator ction 10.2)
Turbine 1,235,219 kW (design rated),
1,800 rpm tandem compound, 6-flow, 43 inch last stage bucket, single stage reheat.
Generator 1,500 MVA, 1,800 rpm, direct coupled, 3 phase, 60 Hz, 24,000V, liquid cooled stator hydrogen cooled rotor rated at 0.9 pf, 0.48 short circuit ratio (SCR) at 75 psig hydrogen pressure.
Exciter 4,110 kW, 463V, 0.5 response ratio, Alterrex design (silicon-diode rectifier).
Control Electrohydraulic control (EHC).
Overspeed Protection Redundant speed control systems:
- 2. Mechanical overspeed system.
- 3. Electrical backup overspeed system.
Moisture-Separator/ ASME VIII Reheaters rbine Gland Seal System Operated with main steam, extraction steam or auxiliary steam.
ction 10.4.3) Noncondensables discharged to atmosphere.
in Steam Supply System ction 10.3)
Main Steam Piping
- From each steam generator up to the first rupture restraint immediately downstream of the main steam isolation trip valves: ASME III, Code Class 2.
- From main steam isolation trip valve rupture restraint to the east wall of the turbine building: ASME III, Code Class 3.
- Main steam to auxiliary feedwater pump turbines: from main steam lines in containment up to and including containment isolation vales: ASME III, Code Class 2. From containment isolation valves to inlet and exhaust of auxiliary feedwater pump turbine: ASME III, Code Class 3.
- Balance of the main steam piping: ANSI B31.1.0b-1971.
Item Design and Performance Characteristics Main Steam Isolation
- ASME III, Code Class 2; maximum closing time 10 sec.
Trip Valves Main Steam Safety
- ASME III, Code Class 2; flow capacity equal to 105 percent Valves of the maximum calculated steam generators mass flow at setpoint pressure plus accumulation. Flow from any one valve does not exceed 970,000 lb/hr at 1,200 psia.
Main Steam Pressure
- ASME III, Code Class 2; flow capacity equal to 15 percent of Relieving Control Valves the maximum calculated steam generators mass flow at no load pressure. Flow from any one valve does not exceed 970,000 lb/hr at 1,200 psia.
rbine Bypass System For the range of NSSS design parameters, a rapid ramp load ction 10.4.4) decrease equivalent to 50 percent of rated thermal power /
turbine load at a maximum turbine unloading rate of 200 percent per minute can be accommodated without a reactor or turbine trip, and without lifting the main steam safety valves.
Piping: ANSI B31.1-Ob-1971.
Turbine Bypass Valves Capable of completely opening from closed position to full open position within 3 seconds after receipt of a trip open signal (normal modulation from full close to full open in 20 seconds).
The capacity of any one turbine bypass valve will not exceed 970,000 lb/hr at 1,200 psia.
in Condensers Triple shell, approximately 503,000 sq ft surface area, 18F ction 10.4.1) design tube rise, equalized steam dome and hotwell sections.
ndenser Air Removal Two condenser air removal pumps for initial shell side air stem (Section 10.4.2) removal, two steam jet air ejector units for maintaining vacuum:
noncondensible gases from air ejectors discharged to radioactive gaseous waste systems (Section 11.3).
culating Water and Six motor driven wet pit vertical water pumps, normally sociated Systems controlled by six Variable Frequency Drives (VFDs), 912,000 ction 10.4.5) gpm total flow, discharge through concrete tunnel to seal pit.
Item Design and Performance Characteristics am Generator Blowdown The normal steam generator blowdown system flow is 22,800 lb/
stem (Section 10.4.8) hr, per steam generator. Blowdown liquid flashed into the steam generator blowdown flash tank. Flashed steam is discharged to fourth point extraction and liquid drained to the condenser. There is continuous sampling for chemical and radioactive content (Section 9.3.2.2).
- All piping and valves inside the containment structure up to and including the first rupture restraint outside the containment structure ASME Section III, Code Class 2.
All other piping: ANSI B31.1.Ob-1971.
ndensate and Feedwater Three one-half capacity motor-driven condensate pumps, six stems (Section 10.4.7) stages of regenerative feedwater heating, two one-half capacity turbine-driven steam generator feedwater pumps, one one-half capacity motor-driven steam generator feedwater pump.
- Piping from the rupture restraint upstream of the containment isolation valve outside the containment structure to steam generator inlets: ASME III, Code Class 2.
- Piping from main steam valve building wall up to containment isolation valve rupture restraint: ASME III, Code Class 3.
Piping from hotwell up to main steam valve building wall: ANSI B31.1.Ob-1971.
edwater Isolation Trip
- ASME III, Code Class 2, maximum closing time 5 seconds.
ves xiliary Feedwater System
- Two motor-driven steam generator auxiliary feedwater ction 10.4.9) pumps: ASME III, Code Class 3; one turbine-driven steam generator auxiliary feedwater pump, ASME III, Code Class 3; one 360,000 gallon capacity demineralized water storage tank (DWST), ASME III, Code Class 3; one DWST heater non-nuclear safety; one DWST heater circulating pump, non-nuclear safety.
- All piping up to but excluding the auxiliary feedwater containment isolation valve and pipe to the feedwater system pipe connection: ASME III, Code Class 3.
- Piping from and including the auxiliary feedwater containment isolation valve to the feedwater system pipe connection: ASME III, Code Class 2.
Item Design and Performance Characteristics ndensate Demineralizer Full flow condensate demineralizer, 9,857,455 lb/hr capacity; eight mixed bed demineralizers: ASME VIII, Div 1 piping ANSI xed Bed System B31.1.Ob-1971.
ction 10.4.6)
FIGURE 10.1-1 FUNDAMENTAL DIAGRAM FIGURE 10.1-2 RATED HEAT BALANCE figure indicated above represents an engineering controlled drawing that is Incorporated by erence in the MPS-3 FSAR. Refer to the List of Effective Figures for the related drawing ber and the controlled plant drawing for the latest revision.
FIGURE 10.1-3 DELETED BY PKG FSC 03-MP3-027 turbine-generator receives steam from the main steam supply system (Section 10.3) and sforms the thermal energy in the steam to electrical energy. The turbine-generator and ciated accessories are supplied by the General Electric Company. The turbine steam system is wn on the station fundamental diagram (Figure 10.1-1).
2.1 DESIGN BASES turbine-generator and the turbine steam system are designed in accordance with the following eria:
- 1. The turbine is designed for normal operation based on steam conditions reflecting steam generator outlet conditions (Figure 10.1-2).
- 2. The turbine-generator is designed for base load operation with remote dispatching provisions.
- 3. The turbine-generator allows safe continuous operation at the maximum capability of the turbine (valves wide open (VWO) condition).
- 4. The turbine-generator and associated steam and power conversion systems are capable of a 50 percent load rejection without producing a reactor trip by dumping steam into the condenser through the turbine bypass system (Section 10.4-4) plus NSSS transient capability.
- 5. The turbine-generator is capable of increasing or decreasing electrical load at a rate consistent with the requirements of the NSSS and the turbine manufacturer loading rate recommendations. However, under emergency conditions the turbine-generator can accept greater load changes.
- 6. The turbine-generator is built in accordance with the turbine manufacturers standards and the industry codes that most closely approximate the conditions of turbine-generator applications.
- 7. The moisture separator/reheaters are designed and fabricated in accordance with Section VIII, Division 1, of the 1971 ASME Boiler and Pressure Vessel Code.
- 8. Generator rating, temperature rise, and insulation class are in accordance with applicable ANSI Standards.
- 9. Preoperational and startup testing of the power conversion system meet the requirements of Regulatory Guide 1.68.
description of the turbine generator includes the turbine-generator equipment, moisture aration, use of extraction steam for feedwater heating, and control functions that could uence operation of the reactor coolant system. The turbine overspeed system is described in il. The control, lubrication, and support systems for the turbine-generator are shown on ures 10.2-1, 10.2-2, and 10.2-3.
.2.1 Turbine-Generator Equipment turbine is an 1,800 rpm, tandem compound, 6-flow, steam reheat machine with 43-inch last-e blades. The turbine consists of one double-flow high pressure cylinder and three double-low pressure cylinders. Steam from the main steam system, flowing through four main steam s, passes through the turbine stop and control valves in each line and into the high pressure ine. Steam leaving the high pressure turbine passes through the moisture separator and ater to the inlets of the low pressure turbines. Each of the lines between the reheater outlets low pressure turbine inlets is provided with a combined intercept and stop valve.
moisture separator/reheaters are located on the operating floor on both sides of the turbine.
h moisture separator/reheater has one stage of reheat. High pressure turbine exhaust steam ses through the chevron baffles which remove the moisture and then passes through the ater bundle which uses main steam as the reheating medium. The moisture separators are vided with relief valves which discharge to the condenser. The relief valves are mounted on hot reheat lines to the low pressure turbines.
exhaust from the three low pressure turbines passes to the condenser where it is condensed by circulating water system (Section 10.4.5).
bine extraction steam, used for six stages of feedwater heating and two half-capacity steam erator feedwater pump turbines, is taken from seven extraction points (Figure 10.1-1): one on high pressure turbine casing, one from the exhaust of the high pressure turbine, one from the reheat piping, and four from the low pressure turbine casing. Motor-operated block valves and er assisted nonreturn valves in the first, second, third, and fourth point heater extraction ng and antiflash back baffles in the fifth point heaters protect against the possibility of turbine er induction or overspeed due to energy stored in the extraction steam system.
extraction steam valves are not safety related. As such, they are not inspected or tested within plants inservice inspection program (ASME Section XI). However, these valves are rationally tested monthly to ensure proper operation.
extraction line non-return valves are straight-through type having a swinging disc rotating on aft in bushed bearings. To ensure positive closing in the event the turbine is tripped due to rspeed, a spring loaded air cylinder, which is installed on the outside of the valve body, is nected by means of a piston rod and shaft linkage. The disc arm and shaft are free to swing hout movement of the connecting linkage to the air cylinder.
surized, the valve disc is free to swing open or closed as with any ordinary check valve.
n release of air pressure, the closing spring acts through the linkage to hold the disc to its seat.
valve will remain in this position until air pressure is re-established, moving the piston ard.
air cylinder has a connection for a high pressure air supply below the piston and a leakoff nection above the piston, connected to a manually operated test valve, which permits testing to fy that the non-return valve piston rod is free to move.
erator generator is sized to accept the output of the turbine. The generator is equipped with an itation system, hydrogen control system, a seal oil system, and a cooling water system for the or. The generator terminals are connected through the isolated phase generator leads and erator circuit breaker (GCB) to the main stepup transformers and normal service transformers.
generator excitation system provides a DC source for the field and controls the voltage of the erator. The hydrogen control system includes pressure regulators, control for the hydrogen and a circuit to supply and control carbon dioxide used during filling and purging operations.
ydrogen seal oil system prevents hydrogen leakage through the generator shaft seals. This em includes pumps, controls, and a storage tank, and degasifies the oil before it is returned to shaft seals. The cooling water system for the stator provides cooling for the stator windings.
bine Control System turbine control system is capable of remote manual or automatic control of acceleration and ing of the unit at preset rates, and holding speed and load at a preset level. The system tains valve positioning, operating, and tripping devices with provisions for testing valve ration including local manual trip capability.
turbine control system is an electrohydraulic control (EHC) system and includes both digital analog circuitry, electronic servo hardware, and hydraulic valve actuators. During automatic ration, the EHC system speed and load control units send output signals to the servo system to ition the valve actuators, which, in turn, admit steam to the turbine and thus control turbine ed and/or load. A standby manual control system is provided independent of the speed and control units and may be used to maintain power output while subsystems are being repaired, hout bypassing turbine protection and trip systems.
rapid loss of load, the turbine control system will reduce main steam flow through the turbine er than steam generation can be reduced. If the load loss is less than 50 percent of rated load, turbine bypass system will operate to allow reduction of reactor power without trip. The tor and turbine controls are interconnected so that a reactor trip signal will trip the turbine to
- 1. Turbine overspeed
- 2. Low turbine bearing oil pressure
- 3. High steam generator water level
- 4. Safety injection signal
- 5. Generator trip
- 6. Excessive thrust bearing wear
- 7. Low hydraulic fluid supply pressure
- 8. Low condenser vacuum
- 9. Main shaft oil pump low discharge pressure (when turbine speed is greater than 1,350 rpm)
- 10. High moisture separator water level
- 11. Loss of both primary and backup speed feedback signals (when the EHC speed control is in automatic mode)
- 12. High exhaust hood temperature
- 13. Loss of stator coolant
- 14. Loss of EHC 125 VDC power supply below 1350 rpm
- 15. Low emergency trip system fluid pressure
- 16. Action of the mechanical trip handle or main board pushbutton
- 17. Reactor trip
.2.2 Turbine Overspeed Protection EHC provides a normal overspeed protection system and an emergency overspeed protection em to limit turbine overspeed. These two systems are essentially separate and independent.
normal overspeed protection system is part of the turbine load and speed control system and esigned to limit turbine overspeed without a turbine trip under all load conditions. The rgency overspeed protection system is part of the emergency trip system and is designed to
turbine control system (Figures 10.2-1 and 10.3-1) provides two independent valve groups protection against overspeed in each steam admission line to the turbine. Steam is admitted to high pressure turbine through four main stop valves, a manifold (equalizer line), four main trol valves, then four unmanifolded main steam inlets. Steam leaving the high pressure turbine ses through the moisture separator reheaters and the combined intermediate valves prior to ring the low pressure turbine. Each combined intermediate valve contains two independently rated valve discs in series, one called an intercept valve and the other called an intermediate valve.
ve closing actuation of the turbine stop, control, and intermediate valves is provided by springs aided by steam forces upon the reduction of relief of hydraulic fluid pressure. The valves are gned to close in approximately 0.2 seconds. The system is designed so that loss of hydraulic d pressure for any reason leads to valve closing (fail safe).
ngle failure of any component will not lead to destructive overspeed. A multiple failure, uding combinations of undetected electronic faults and/or mechanically stuck valves and/or raulic fluid contamination at the instant of load loss would be required to reach destructive rspeed. The probability of such joint occurrences is extremely low, due to the high design ability of components and frequent inservice testing.
extraction steam lines (Figure 10.4-3) to the first through fourth point feedwater heaters tain extraction steam line nonreturn valves which are used to protect the turbine from reverse of vapor in the event of a sudden turbine trip or load reduction. The valves are a swinging design with a spring assisted closure mechanism to ensure rapid closure in the event of a rsal of steam flow direction past the valve. This results in an extremely conservative design e the turbine manufacturer has determined that the failure of extraction steam nonreturn es during a loss of maximum load would only cause a moderate rise in speed. This is a result he modest steam pressure levels and entrained steam volumes in the extraction steam lines of ines for light water reactors in relation to the very large rotor inertia relative to the turbine er of an 1800 rpm unit. This is also the reason that extraction steam line nonreturn valves are required on the extraction lines to the fifth and sixth point heaters.
ther, an analysis has been performed (Section 3.5.1.3) which has determined an acceptable e of damage probability to safety related equipment as a result of ductile fracture of a rotating ine component upon turbine runaway after extensive, highly improbable turbine control em failure. Section 10.2.3.6 discusses the testing of steam valves.
.3 TURBINE INTEGRITY s section provides information to demonstrate the integrity of turbine rotors.
bine rotors are made from vacuum melted or vacuum degassed Ni Cr Mo V alloy steel by cesses which minimize flaw occurrence and provide adequate fracture toughness. Tramp ments have been controlled to the lowest practical concentrations consistent with good scrap ction and melting practices, and consistent with obtaining adequate initial and long life ture toughness for the environment in which the parts operate.
2.3.2 Fracture Toughness able material toughness is obtained through the use of materials (Section 10.2.3.1) to produce lance of adequate material strength and toughness to ensure safety while providing ultaneously high reliability, availability, efficiency, etc., during operation.
bine operating procedures are employed to preclude brittle fracture at startup by ensuring that metal temperature of wheels and rotors (a) is adequately above the FATT and (b) as defined ve is sufficient to maintain the fracture toughness to tangential stress ratio at or above 2 inches encer and Timo 1974).
.3.3 High Temperature Properties peratures in the high pressure turbine are below the creep rupture range. Creep rupture is, efore, not considered to be a significant factor in assuring rotor integrity over the lifetime of turbine. Basic data is obtained from laboratory creep rupture tests.
.3.4 Turbine Design turbine assembly is designed to withstand normal conditions and anticipated transients, uding those resulting in turbine trip without loss of structural integrity. The design of the ine assembly meets the following criteria:
- 1. Turbine shaft bearings are designed to retain their structural integrity under normal operating loads and anticipated transients, including those leading to turbine trips.
- 2. The multitude of natural critical frequencies of the turbine shaft assemblies existing between zero speed and 20 percent overspeed is controlled in the design and operation so as to cause no distress to the unit during operation.
.3.5 Preservice Inspection preservice inspection program included:
- 1. As part of the manufacturing process, the rotors were subjected to ultrasonic examinations.
- 2. All finish-machined surfaces were subjected to a magnetic particle examination.
.3.6 Inservice Inspection inservice inspection program for the turbine assembly and valves will include the following:
- 1. Disassembly of the turbine at approximately 10 year in service intervals during plant shutdown. Inspection of all parts that are normally inaccessible when the turbine is assembled for operation such as couplings, coupling bolts, turbine shafts, low pressure turbine buckets, and high pressure rotors, will be conducted.
This inspection consists of visual, surface, and volumetric examinations, as indicated below:
- a. Ultrasonic inspection of the tangential entry dovetails and pins of the finger dovetails will be conducted. This inspection should be conducted at intervals of approximately 10 in service years.
- b. A thorough volumetric ultrasonic examination of the high pressure rotor will be conducted. In addition, all accessible rotor surfaces will be inspected visually and by magnetic particle testing. This inspection should be conducted at intervals of approximately 10 in service years.
- c. Visual and surface examination of all low pressure buckets.
- 2. Dismantle at least one main steam stop valve, one main steam control valve, one reheat stop valve, and one reheat intercept valve, at approximately 3 1/3 year intervals during refueling or maintenance shutdowns, and conduct a visual and surface examination of valve seats, discs, and stems. If unacceptable flaws or excessive corrosion are found in a valve, all valves of its type will be inspected.
Valve bushings will be inspected and cleaned, and bore diameters will be checked for proper clearance.
- 3. Main steam stop, control, and combined intercept (reheat stop, and intercept valve) valves will be exercised by closing each valve and observing, by the valve position indicator, that it moves smoothly to a fully closed position. This observation will be made by actually watching the valve motion. The testing frequency will be performed in accordance with the Turbine Overspeed Protection Maintenance and Testing Program. The positive closing feature on non return extraction valves is testable locally where partial movement of the valve disc and shaft can also be observed.
turbine-generator is protected against destructive overspeed by redundant speed control ems during normal and transient conditions.
ensure system reliability, the overspeed protection systems are designed to ensure operability er the most severe environmental conditions for which the turbine building is designed.
vision has been made for online testability of both the mechanical and electrical overspeed trip ems. Connections between the turbine and the reactor protection system are redundant, sically independent, and separated and designed to withstand a single failure.
turbine-generator and related steam handling equipment systems are radioactively taminated only when there is a steam generator tube rupture resulting in leakage of reactor lant from the primary to the secondary side of a steam generator. Shielding of the turbine-erator systems is not required because the activity level during operation is minimal and well hin safe limits. The equilibrium concentrations of various isotopes in the turbine steam system essentially the same as the equilibrium concentrations in the main steam system. Tables 11.1-d 11.1-3 list these concentrations.
safety related equipment is located in the turbine building. Safety related systems in proximity he turbine building are protected from the effects of high and moderate energy turbine erator system piping failures or failure of the connections from the low pressure turbine to the n condenser by barriers or remote location.
2.5 REFERENCES
FOR SECTION10.2
figure indicated above represents an engineering controlled drawing that is Incorporated by erence in the MPS-3 FSAR. Refer to the List of Effective Figures for the related drawing ber and the controlled plant drawing for the latest revision.
SYSTEMS figure indicated above represents an engineering controlled drawing that is Incorporated by erence in the MPS-3 FSAR. Refer to the List of Effective Figures for the related drawing ber and the controlled plant drawing for the latest revision.
figure indicated above represents an engineering controlled drawing that is Incorporated by erence in the MPS-3 FSAR. Refer to the List of Effective Figures for the related drawing ber and the controlled plant drawing for the latest revision.
main steam system transports steam from the steam generators to the power conversion ems. This system provides a means of controlled heat release from the nuclear steam supply em during periods of station electrical load rejection or when the condenser is not available.
system also provides steam for various auxiliary services including the steam generator iliary feedwater pump turbine, turbine gland sealing, and the auxiliary steam system ure 10.3-1). Drains are provided as shown on the turbine plant miscellaneous drains system ure 10.3-2).
3.1 DESIGN BASES ortion of the main steam system is Safety Class 2 (QA Category I) and is designed and icated in accordance with the ASME Code,Section III, Class 2 requirements as discussed in tion 3.2. This portion of the system extends from the steam generators up to and including:
- 1. The main steam isolation trip valves
- 2. The main steam pressure relieving valves
- 3. The main steam pressure relieving bypass valves
- 4. The main steam safety valves
- 5. The motor-operated stop-check valves in the steam lines to the auxiliary feedwater pump turbine.
portion of the main steam system from the main steam isolation trip valves to the turbine ding wall and from the motor operated stop check valves to the auxiliary feedwater pump ine is Safety Class 3 (QA Category I) and is designed and fabricated in accordance with the ME Code,Section III, Class 3 requirements as discussed in Section 3.2.
Safety Class 2 and 3 portions of the main steam system are designated Seismic Category I as ned by Regulatory Guide 1.29 (Section 3.2.1). Seismic Category I design requirements are lied to nonsafety class portions of the main steam system in order that proper operation of ty related equipment is not adversely affected. (This portion includes the steam piping from main steam isolation trip valves up to the turbine building wall, and from the motor-operated
-check valves to the auxiliary feedwater pump turbine.)
remainder of the main steam system is not safety related and is designed and fabricated in ordance with ANSI B31.1 requirements (NNS) as discussed in Section 3.2.
design pressure and temperature of the main steam system piping and components are the e as the steam generator secondary side design conditions, 1,185 psig and 600F, respectively.
capacity of main steam safety valves is determined based on the main steam pressure not eeding 110 percent of steam generator shell side design pressure following loss of load from percent power with a reactor trip. The maximum capacity of each safety valve shall not eed 970,000 lbm/hr to preclude an uncontrolled plant cooldown and corresponding excessive tivity excursion due to a failed open valve.
main steam system delivers steam to the turbine stop valves under NSSS warranted ditions.
capacity of the turbine bypass portion of the main steam system is described in FSAR tion 10.4.4.1.
main steam system is designed to ensure that a 30 psi differential between any two steam erators for more than 1 minute during transients and turbine valve testing and a 10 psi erential during normal operation will not be exceeded.
main steam system design ensures a supply of steam to the turbine-driven auxiliary feedwater p under all accident conditions.
main steam system design prevents the uncontrolled blowdown of more than one steam erator following a main steam line break accident.
n steam piping inside and outside the containment structure has been designed in accordance h the design criteria discussed in Sections 3.7B.3. and 3.9B.3. Analyses have been performed ocate supports and restraints in a manner that will prevent a whipping pipe from having an erse effect on safety related structures, systems, or components.
.2 SYSTEM DESCRIPTION m from each of the four steam generators is carried in separate carbon steel pipes through tainment penetrations and main steam isolation valves to the main steam manifold. Four pipes y the steam from the main steam manifold to the four main turbine stop and control valves and to the high pressure turbine. System parameters are provided in the heat balance included in ure 10.1-2.
m leaving the high pressure turbine passes through the moisture separator reheaters to the ts of the three low pressure turbines and the two steam generator feedwater pump turbines.
h of the steam lines between the reheater outlets and the low pressure turbine inlets is vided with a combined intermediate valve (each comprised of an intercept valve and rmediate stop valve) and a moisture separator relief valve discharging to the condenser ction 10.4.4).
eam line to the steam generator auxiliary feedwater pump turbine steam supply header is nected to three main steam lines inside the containment, upstream of the main steam isolation valves.
se lines provide steam for the steam generator auxiliary feedwater pump turbine.
three steam system supply lines each contain one normally closed air-operated valve. Each of e air-operated valves is provided with dual solenoid actuators. Downstream of the air-rated valves each of these steam lines contains a motor-operated nonreturn containment ation valve before joining the common header to the steam generator auxiliary feedwater p turbine.
am lines from the main steam manifold supply steam to the turbine bypass system ction 10.4.4), the single stage reheater of the moisture separator reheaters, the turbine gland ing system (Section 10.4.3), the auxiliary steam system (Section 10.4.10), and the two steam erator feedwater pump turbines (Section 10.4.7).
.3 SAFETY EVALUATION main steam system has been designed to perform its functions under all operating conditions.
ing normal operation, the main steam system transports steam from the NSSS to the steam and er conversion systems. Under accident conditions the safety related portion of the main steam em provides a heat sink for the reactor, protects the secondary system from overpressure and vides steam to the auxiliary feedwater pump turbine.
main steam isolation trip valves are provided to isolate the nonsafety related portions of the n steam system under accident conditions. The main steam isolation trip valves also prevent uncontrolled blowdown of more than one steam generator in the event of a main steam line k accident.
m line break accidents include a guillotine (double ended) break of the main steam piping tream or downstream from the valves. Under such conditions, the mass flow rate, moisture y over (steam quality), and fluid velocity increase considerably relative to the values at mal operation, their magnitudes being functions of the relief opening size plus system flow ands and power level prior to the break. A flow restrictor is provided in each steam generator et nozzle to restrict the rate of steam flow from the steam generators.
steam line breaks downstream of the main steam isolation trip valves, closure of these valves s the flow of steam from the steam generators to the ruptured pipe section. Maximum closing e for the main steam isolation trip valve is 10 seconds from the receipt of the signal to close.
ve closure checks the sudden release of energy in the form of main steam, thereby preventing d cooling of the reactor coolant system. Valve closure also ensures a supply of steam to the ine drive for the turbine driven steam generator auxiliary feedwater pump.
harge through the valve. This results in greatly increased mass flow rate and low moisture tent steam at high velocity (as established by sonic velocity at valve seat bore).
en the above limited quantity of steam has been expelled, the mass flow rate decreases (as rmined by sonic velocity at the steam generator flow restrictor).
he steam generator continues to blow down, swelling of the water level produces high sture carryover. The mass flow rate is a function of the steam generator flow restrictor meter and the steam generator pressure.
steam line breaks between the main steam isolation trip valve and the steam generator, the cted steam generator would blow down. The main steam isolation trip valves prevent wdown from the other steam generators. For a steam line break upstream of the main steam ation trip valve, the conditions encountered during the first phase of this accident are similar to described earlier.
steam line break accidents are discussed in Section 15.1.5.
he event of a main steam pipe rupture, the motor-operated stop check valves in the steam ply lines to the steam generator auxiliary feedwater pump turbine prevent reverse flow of
- m. This ensures that the steam supply line to the steam generator auxiliary feedwater pump ine inlet is continuously under steam generator pressure.
main steam system is capable of removing heat from the reactor coolant system following den load rejection or trip of the turbine generator unit by automatically bypassing main steam he condenser through the turbine bypass system (See Section 10.4.4 for steam dump ability), or by relieving to the atmosphere through the main steam safety valves, or the main m pressure relieving valves if the turbine bypass system is unavailable (due to loss of denser vacuum or both circulating water pumps in any condenser section not running).
oval of the reactor coolant system sensible heat and core decay heat maintains the main m pressure at or below the allowable limits. The main steam safety valves have a total flow acity at accumulated pressure which exceeds 105 percent of maximum full load steam flow, which is sufficient to prevent the main steam pressure from exceeding110 percent of the m generator shell side design pressure for the most severe loss of heat sink accident. The main m pressure relieving valves have a total flow capacity of 15 percent of the maximum rating steam flow at no load pressures. These pressure relieving valves are designed to have icient capacity to release decay heat and sensible heat to the atmosphere until such time as the dual heat removal system can assume the task of heat removal.
steam generator atmospheric relief valve isolation valve can be operated to isolate a steam erator in the event that a steam generator atmospheric relief valve fails to close.
r main steam pressure relieving bypass valves are provided to ensure a secure path around n steam pressure relieving valves in the event that the primary path is no longer available due
osphere remotely from the control room following an SSE coincident with LOP. Thus, a cold tdown can be achieved with dependence upon only safety grade components. Also, these es may be used for atmospheric steam dump during recover from a steam generator tube ure, thus providing a safety grade means to perform a RCS cooldown. The safety grade cold tdown process is described in Section 5.4.7.2.3.5.
pressure relieving valves operate during periods when the turbine generator or condenser is in service, the unit is being started up shut down, or during core physics testing, turbine trip on of condenser vacuum, during safety grade cold shutdown or loss of electric power to unit iliaries. These valves are normally under automatic control from the steam generator pressure may be manually positioned from the main control board. Local manual action of the main m pressure bypass valves may be required during a loss of power in order to permit ressurization of the reactor coolant system. The main steam pressure relieving valves or sure relieving bypass valves preclude operation of the safety valve during normal operating sients by keeping the main steam pressure below the safety valve setpoints. The main steam sure relieving control valves are not required for overpressure protection of the unit, as the m generators are protected by the main steam safety valves.
air-operated globe valves for the steam generator auxiliary feedwater pump turbine are matically operated. Information on the steam generator auxiliary feedwater pumps may be nd in Section 10.4.9 and Technical Specifications (16.3/4.7.1.2).
tection from floods, tornadoes, and missiles is discussed in Sections 3.4.1, 3.3, and 3.5, ectively. Protection from high and moderate energy pipe breaks is discussed in Section 3.6.1.
RMIS evaluation of the probability of failure of the TDAFW pump turbine vent above the ESF ding under a tornado missile has been completed and found to meet the requirements of SRP tion 3.5.2 and Section 2.2.3. See Section 9.5.8.3 for TORMIS limiting assumptions and eptions.
main steam system piping supports have been analyzed for forces due to the more severe dition of either turbine trip or seismic events from the steam generators to and including the n steam manifold. The main steam system piping supports from the main steam manifold to turbine have been analyzed for turbine trip forces only. The main steam system has also been ss analyzed for the forces and moments which result from thermal growth. The main steam em piping within the containment structure has been reviewed for possible pipe rupture and icient supports and guides have been provided to prevent damage to the containment liner and cent piping, equipment, controls, and electric cables.
main steam isolation valves, safety valves, and the pressure relieving control valves are sile protected and are housed in the Seismic Category I main steam valve building ction 3.8.4).
sure from the main steam line.
main steam isolation valve design has a flow profile minimally affected by seismic elerations. Other advantages include no significant leakage to the environment. The valve ators are designed as an integral unit with the system steam-operated piston actuator grated in the valve housing (within the valve pressure boundary).
h respect to main steam isolation valve actuation mechanisms, all solenoid valves are provided edundant pairs and are mounted on the piston cylinder assembly. They are physically arated within the confines of the valve configuration. The valve can operate independently m an outside energy supply (nitrogen) and utilizes system energy to actuate the valve erating pressure taken up or down-stream of the valve).
main steam isolation valve body is a forged and welded steel design, see Figure 10.3-4. The uator piston cylinder, valve disc, piston and bonnet are forged steel and are built into the e body as one cylinder unit, fastened by threaded expansion studs with nuts. By pressurizing enting of appropriate piston compartment, the isolation valve will open or close. An itional closing force is exerted by springs which keep the isolation valve closed at zero sure differential. In the closed position of the isolation valve, the hard-faced sealing surface of valve disc rests on the hard-faced sealing surface of the valve body. In the open position of the ation valve, the hard-faced back-seat of the valve disc rests on the hard-faced back seat of the on cylinder, thus sealing off the lower piston compartment from the pressure in the valve y.
solenoid valves controlling the operating medium (steam) for the piston compartments are uped in two multi-sectioned control blocks mounted on the piston cylinder. The control lines m the valve inlet side are led internally through the piston cylinder. The control lines from the e outlet side are led in duplicate and are on the outside of the valve body to the control blocks.
operating medium (steam) is automatically taken either from the inlet side or the outlet side he valve body depending on which side is pressurized. As shown on Figure 10.3-4, the valve ositioned by appropriate pilot valves (solenoid valves) which admit system steam to the proper e chambers.
main steam isolation trip valve is suitable for the following normal operating conditions (at lear steam supply system output of 3725 MWt):
Upper Operating Limit based Best Estimate Conditions on Tavg=589.5F (55.5F based Tavg = 587.1F (55.5F Cir Water Inlet Temp) Circ Water Inlet Temp)
Steam Flow (lbm/hr) 4,117,940 4,114,455 Steam Pressure (psia) 990.7 970.0 Steam Temperature (F) 543.4 540.9
valves are also suitable for the following design conditions:
Steam pressure (psia) 1,200 Steam temperature (F) 600 en steam line pressure is inadequate, the main steam isolation valve can be held open using ogen supplied at 185 psig. However, the main steam isolation valves are required to be closed h the RCS less than 320F in Mode 4.
he piston area is larger than the seating area, there is always a surplus of closing thrust ilable, which closes the valve safely. The high seating thrust produced as a result of this action ures tightness of the main seat.
.4 INSPECTION AND TESTING REQUIREMENTS main steam isolation trip valves are equipped with provisions for testing by partial valve king. The partial stroking is accomplished by opening a solenoid valve to admit steam sure into the lower piston chamber. After a time delay the solenoid valve for the upper piston mber opens. After 10 percent travel the position indicating device vents both piston chambers the valve fully opens to the back seat due to pressure acting on the valve plug.
main steam isolation valves are tested for full closure during each refueling interval.
main steam pressure relieving valves, motor operated stop check valves and the air-operated be valves in the lines to the steam generator auxiliary feedwater pump turbine are full stroke ed at refueling intervals.
e Classes 2 and 3 piping within the jurisdiction of ASME III were inspected and tested during struction according to articles NC-,ND 5000 and NC-,ND-6000, respectively, of that code.
ng falling within the jurisdiction of ANSI B31.1.0 is inspected and tested during construction ccordance with Paragraphs 136 and 137, respectively, of that code. Preservice and inservice ections of Class 2 and 3 components will be in accordance with FSAR Section 6.6.
main steam isolation valve design meets the requirements of Regulatory Guide 1.48 and also inservice inspection requirements of ASME Section XI.
main steam isolation valve manufacturer performed the hydrotest on the main steam isolation valves using kerosene as the test medium. The use of kerosene as a test fluid is in accordance h the manufacturers standard test procedures and it has been demonstrated through substantial umulated past experience that this has no deleterious effects on the material of the pressure ndary. Kerosene has better wetting characteristics than water and, therefore, is advantageous leak detection.
Analysis: 90 kerosene + 10 oil (rust preventative oil: Valvoline Tectly 875 - S-1)
Sulfur Content Max. = 0.1 Chlorine Content Max. = 0.001 Specific Gravity, 0.805 gr/cm3 at 15C Viscosity (Kinematic), 6.71 Stokes above fluid presents no safety hazard problems at the specified hydrotest pressure and perature.
3.5 SECONDARY SIDE WATER CHEMISTRY objective of the Millstone 3 chemistry program is to establish effective secondary water-mistry control to minimize metal corrosion and scale/sludge accumulation in the steam erators.
ondary chemistry is monitored and controlled by procedures and administrative controls in the ondary Water Chemistry Program. This program is based upon EPRI PWR Secondary Water mistry Guidelines and vendor recommendations.
secondary water chemistry program includes the following.
Identification of a sampling schedule for the critical parameters, and of control points for these parameters, for each plant operating mode.
Identification of the procedures used to measure the value of the critical parameters.
Identification of the sampling points.
Procedures for recording and management of data.
Procedures for defining corrective actions for out-of-specification conditions, including time limits.
Identification of a) the authority responsible for interpreting the data and initiating actions, and b) the sequence and timing of the administrative events required to initiate corrective action.
purpose of the secondary side water chemistry control is to minimize metal corrosion ughout the system and subsequently minimize scale/sludge formation in the steam generators.
uction of this sludge and scale, in conjunction with the stringent chemical control, will vent or alleviate steam generator component corrosion and/or tube failures.
ction of hydrazine downstream of the condensate polishers. The pH is controlled by additions n approved pH control agent via the condensate chemical feed system (Section 10.4.7).
steam generator blowdown system (Section 10.4.8) is used to lower impurity concentrations, to remove particulate solids from the steam generator during startup. Some blowdown also is d during operation to supplement the condensate polishing system and to remove solids from steam generator tube sheet. An approved polymeric dispersant may be injected downstream of first point feedwater heaters to improve the effectiveness of the steam generator blowdown em in removing particulate solids from the steam generators.
ing startup and operation, the deep bed condensate polishing system (Section 10.4.6) serves to ove unwanted chemical species and to reduce suspended solids on a continuous basis.
water ingress via the condenser is highly unlikely due to the use of corrosion resistant nium tubing. However, should any ingress occur, then the condensate polishing system also remove any deleterious ionic and/or solid species.
ondary chemistry control parameters are monitored and controlled per the EPRI PWR ondary Water Chemistry Guidelines.
.6 MAIN STEAM AND FEEDWATER SYSTEM MATERIALS material specifications used in the containment pressure boundary are listed in Tables 10.3-1 ugh 10.3-4.
.6.1 Fracture Toughness pressure retaining ferritic materials in the containment pressure boundary are fracture ghness tested in accordance with NE 2300 and NC 2300 of the ASME B&PV Code, Section 1971; Winter 1973 Addenda.
act property testing was optional in the Code edition in effect on Millstone 3; therefore, act testing was not imposed on main steam and feedwater systems.
.6.2 Materials Selection and Fabrication material specifications used for pressure-retaining component parts in the containment ation boundary are listed in Appendix I of the ASME B&PV Code,Section III, 1971; Winter 3 Addenda.
ere austenitic steel is used, the requirements of NRC Regulatory Guide 1.44 are followed. The lation used with this material is in compliance with Regulatory Guide 1.36. The welding cedures for this material are in compliance with Regulatory Guide 1.31 to the extent specified
cleaning and handling of all safety related austenitic components were in conformance with ulatory Guide 1.37 requirements as described in Section 6.1.
ferritic steel components are thoroughly cleaned, descaled, and coated in accordance with the gn specifications. These specifications meet or exceed the requirements of standards cribed in the Quality Assurance Program Description Topical Report.
heat temperatures for welding low-alloy steel are in accordance with Regulatory Guide 1.50.
ding is performed with welders qualified in accordance with Regulatory Guide 1.71, where licable.
degree of compliance to the regulatory guide indicated in this section is found in Section 1.8.
destructive examination procedures for tubular products are in accordance with the uirements of the ASME Code,Section III.
3.7 INSTRUMENTATION REQUIREMENTS main steam system has steam flow and pressure instruments in each main steam line for main
-feedwater flow mismatch annunciation, three-element feedwater control, and steam line low sure isolation signal. These protection and control systems are described in Sections 7.2, 7.3, 7.7.
ip valve is installed in each of the four main steam lines for rapid line isolation in the event of pture. The actuation signal for each isolation trip valve is redundant and is supplied from the m line isolation (SLI) signal described in Section 7.3. A bypass valve around each main steam ation trip valve also closes upon receipt of an SLI signal.
ee parallel air-operated valves with redundant solenoids automatically start the steam erator auxiliary feedwater pump turbine upon receipt of a low-low steam generator level al. Local and remote pressure indicators monitor operation of the steam generator auxiliary water pump turbine.
ssure signals are supplied to the steam dump and steam generator feedwater pump turbine trol from the main steam manifold. The steam dump control is also supplied a pressure signal m the first stage of the high pressure turbine. These control systems are described in tion 7.7. Pressure signals are provided for NSSS protection and control from the first stage of high pressure turbine.
ressure transmitter supplies a high pressure turbine first stage pressure (load) signal to the ine electro-hydraulic control (EHC) system.
PIPING nual Gate, Globe, and Check Valves Bodies SA-105 or SA-216, Grade WCB A-105 or A-216, Grade WCB Bonnets SA-105, SA-217, Grade WC6 Discs SA-182, F316; Stellite trim or SA-216, WCB Studs SA-193, Grade B7 or A-193, B7 Nuts SA-194, Grade 2H or A-194, 2H r-Operated Valves Feedwater Flushing Valves:
Body A-217, WC9 Bonnet A-217, WC9 Plug 17-4 pH ST-ST Seat 316 SS hard face Feedwater Pump Discharge Control Valves:
Body A-216, WCB Bonnet A-217, WC6 Plug 17-4 pH ST-ST Seat 316 SS hard face Feedwater Pump Discharge Bypass Control Valves:
Body A-216, WCB Bonnet A-216, WCB Plug CA6NM Seat 316 SS hard face Feedwater Bypass Level Control Valves:
Body SA-216, WCB Bonnet SA-216, WCB Plug SB-166 CoCrA Seat SB-166 CoCrA am Generator Auxiliary Feedwater Pump Turbine Steam Supply Isolation Valves:
Body SA-216, WCB Bonnet SA-216, WCB Plug SB-166 INCNL CoCrA Seat SB-166 INCNL CoCrA
nual Globe Valves (2 in and Smaller)
Bodies SA-105, or A-105 Bonnets SA-105, or A-105 Discs SA-217, WC6 with Stellite or A-276 Type 410, AMS 5387 Stellite 6 ing Piping (Nominal Size) 24 inch and smaller SA-106, Grade B-main steam A-106, Grade B-main steam SA-106, Grade C-feedwater A-106,Grade C-feedwater SA-182, F22, Grade C-feedwater 26 inch turbine bypass A-155, Grade KC70, Cl.1 30 inch, 31.5 inch main steam SA-155, Grade KC70, Cl.1 32 inch main steam transition SA-155, Grade KC70, Cl.1 piece 36 inch feedwater piping A-155, Grade KC70, Cl.1 42.25 inch main steam manifold A-155, Grade KC70, Cl.1 Fittings 2 inch and smaller SA-105 or A-105 2.5 inch to 24 inch SA-234, WPB or A-234, WPB SA-182, F22 26 inch and larger SA-234, WPC or WPCW or A-234, WPC or WPCW Flanges All SA-105 or A-105 TES:
- Material designation for valves designed to Section III, ASME Code
- Material designed for valves designed to ANSI B31.1 Code
TABLE 10.3-2 MATERIALS OF MAIN STEAM SAFETY VALVES ve body SA-105 t nozzle SA-182, F316 c insert ASTM 565 Gr. 616T or ASME SB-637 UNS N07750 Type 3 e SA-105 e rod SA-193, Grade B6 mpression screw SB-164, Cl. A ndle SA-479, TY 316 or SB-637 UNS N07750 Type 3 (Inconel X-750) ds (inlet flange) SA-193, Grade B7 s (inlet flange) SA-194, Grade 2H
ABLE 10.3-3 MATERIALS OF MAIN STEAM PRESSURE RELIEVING VALVES ve body SA-216, Grade WCB c insert SA-479, Type 316, SA-105 or SA-216, Grade WCB net SA-216, Grade WCB net studs or bolts SA-193, Grade B7 net nuts SA-194, Grade 2H or 7
TABLE 10.3-4 MATERIALS OF MAIN STEAM/FEEDWATER VALVES n Steam Isolation Trip Valve Valve body SA-105 Bonnet SA-105 Bonnet studs SA-193, Grade B16 Bonnet nuts SA-194, Grade 7 Piston A-276, Type 410
- Valve disc A-276, Type 410
- dwater Isolation Trip Valve Bodies SA-216, Grade WCB Bonnets SA-216, Grade WCB Discs SA-515, Grade 70, with Stellite Stem A-276, Grade 410T Studs SA-193, Grade B7 Nuts SA-194, Grade 2H dwater Flow Control Valves Bodies SA-352, Grade LCB Bonnets SA-105 Stem SA-276, TP316 Plug SA-182, TPF304, Stellite No. 6 Studs SA-193, Grade B7 Nuts SA-194, Grade 2H ode Case 1334-3 used in fabrication.
figure indicated above represents an engineering controlled drawing that is Incorporated by erence in the MPS-3 FSAR. Refer to the List of Effective Figures for the related drawing ber and the controlled plant drawing for the latest revision.
figure indicated above represents an engineering controlled drawing that is Incorporated by erence in the MPS-3 FSAR. Refer to the List of Effective Figures for the related drawing ber and the controlled plant drawing for the latest revision.
figure indicated above represents an engineering controlled drawing that is Incorporated by erence in the MPS-3 FSAR. Refer to the List of Effective Figures for the related drawing ber and the controlled plant drawing for the latest revision.
FIGURE 10.3-3(1)(A) DELETED BY PKG FSC 98-MP3-126
.1 MAIN CONDENSER main condenser (Figure 10.4-1) condenses and deaerates steam from the three low-pressure ine exhausts, the two main feedwater pump turbine exhausts, the turbine bypass control es, and from various equipment vents and drains.
.1.1 Design Bases design bases of the main condenser are:
- 1. The condenser is nonnuclear class.
- 2. The condenser is designed for a 17.5F tube rise at a duty of 7.85 billion Btu/hr and a cooling water flow of 906,668 gpm. At rated power conditions, the temperature rise is expected to be approximately 18.3F with a heat removal rate of 8.2 billion Btu/hr for an approximate cooling water flow of 900,000 gpm. For physical characteristics and performance requirements of the main condenser, see Table 10.4-6.
- 3. The condenser maintains normal turbine backpressure for all operating conditions.
Backpressure during operation of the turbine bypass system may rise above the normal continuous range but remains within limits specified by the turbine manufacturer.
- 4. The condenser is designed to accept a 40 percent turbine bypass steam dump from the main steam system. This steam dump permits a 50 percent load rejection without reactor trip, as discussed in Section 10.4.4.
4.1.2 System Description main condenser is a single-pass, single-pressure, triple-shell unit with two tube banks per
- l. Each shell is rigidly supported. Relative movement between the shells and turbine is ommodated by rubber expansion joints in the steam inlets.
alizing ducts between the shells equalize pressure and hotwell condensate level. The total well storage capacity of the main condenser approximates 5 minute flow at full load operation.
o feedwater heaters are located in each condenser neck.
le 11.1-7 lists the anticipated inventory of radioactive contaminants in the condenser. The gn concentration of radioactivity in the condenser during normal operation is based on orical design calculations, assuming operation with 1percent cladding defects, coincident with gallons per day steam generator primary-to-secondary leakage.
emoval is discussed in Section 10.4.2.
.1.3 Safety Evaluation main condenser is not safety related; therefore, no safety evaluation is required. The owing design evaluation demonstrates condenser capability to perform its intended function.
condenser is designed for operation at maximum calculated unit capability. Impingement les protect the tubes from direct steam/water impingement and spray nozzles in the condenser ks dissipate steam from the turbine bypass system (Section 10.4.4).
following measures are taken to prevent the loss of condenser vacuum:
- 1. A main condenser evacuation (air removal) system is provided to establish and maintain condenser vacuum. A detailed description of this system design is provided in Section 10.4.2.
- 2. A vacuum priming system is provided on the condenser waterboxes (circulating water system) to ensure that the condenser tubes are flowing full. This condition maximizes the condenser vacuum. A detailed description of this system design is provided in Section 10.4.5.3.
- 3. Controls are provided to manually start a second 100 percent capacity air ejector, if necessary. (Section 10.4.2.2).
- 4. Loss of condenser vacuum has been anticipated and its consequences evaluated in the safety evaluation, Section 10.4.2.3.
- 5. Instrumentation required to monitor the status of the circulating water system is discussed in detail in Section 10.4.5.5.
condenser is protected from overpressure by relief diaphragms furnished on the low-pressure ine exhaust hoods (steam side) and by vacuum breakers on the water boxes (water side).
se vacuum breakers open automatically to prevent excessive pressure transients caused by tiple circulating water pump trips.
rosion induced tube leakage is minimized by using titanium (ASTM-B 338 Gr. 2) condenser es. Titanium is highly resistant to corrosion in seawater and also resistant to ammonia attack the effects of high velocity steam impingement.
kage of seawater into the condenser due to tube-to-tube sheet joint leaks is prevented by the denser tube sheet design. The tube holes in the tube sheet have three circumferential grooves.
two outer grooves are shallow grooves provided to increase the strength of the tube-to-tube et joint when the tubes are roller expanded into the tube sheet. The center groove is machined
an condensate is injected into the interconnecting center grooves at a pressure 10 psi higher the normal operating pressure in the water boxes. Because the pressure in the interconnecting oves is higher than the pressure at either face of the tube sheet, any leaks that do develop pass n condensate rather than permit seawater to enter the condenser.
kage from the circulating water system into the condenser due to tube leakage is detected by ductivity sample points in troughs under each tube sheet. Continuous sampling is provided to turbine plant sampling system to detect any major tube leakage in the hotwells. Each trough ple point and the hotwell sample point nearest the condensate pump suction are monitored tinuously and alarmed. When leakage is detected, the affected tube bundle can be removed m service by tripping the associated circulating water pump and breaking vacuum in the water
. The water box may then be entered for tube plugging or other maintenance operations. One pass can be isolated without reducing unit load.
impressed-current cathodic protection system is provided in the condenser water boxes to ect against galvanic corrosion due to the use of dissimilar metals (aluminum bronze tube et, copper- nickel water box cladding, titanium condenser tubes).
nitoring of radioactive leakage into the condenser is not required because there are indirect ns for detection; primary-to-secondary leakage into the steam generators is detected by tinuous monitoring of the steam generator blowdown. Also, radioactive leakage out of the denser is monitored by a radiation monitor in the steam jet air ejector discharge line.
ble integrally grooved tube sheets are supplied with seal water from the condensate system in er to prevent inleakage of circulating water at the tube sheets.
or condenser tube leakage is detected by on-line sampling of the full condensate flow through condensate demineralizer mixed bed. Permissible cooling water inleakage and design basis ondary water quality are provided in Section 10.4.6.1. The condenser is designed such that a le tube bundle can be isolated and plugged during plant operation. Major tube leakage is cted by a conductivity alarm in the turbine plant sampling system. Major tube leakage, severe ugh to rapidly deplete the condensate demineralizers requires plant shutdown and main denser tube plugging or replacement.
potential for hydrogen buildup in the condenser is negligible. Hydrogen entering the denser is removed by the condenser air removal system.
oding due to a complete condenser failure (Section 10.4.5) will not damage any safety related ipment inside or outside the turbine building. The worst case of flooding results from an ansion joint failure at the condenser inlet.
nways are provided in the exhaust neck and hotwell of each condenser shell to give access for ning, inspection, and repair as may be required. Manways are also provided in each of the denser water boxes.
.1.5 Instrumentation Requirements instrumentation on the condenser is nonsafety related.
el controllers and level alarms on the condenser are discussed under condensate and feedwater ems (Section 10.4.7).
h condenser backpressure is alarmed on the main control board and monitored by the puter.
low condenser vacuum, pressure switches trip the turbine which results in closure of the ine stop and bypass valves. This isolates the steam source. There is no change in position of main steam isolation valves for this condition since these valves are only automatically ated on a steam line isolation signal (described in Sections 7.3 and 15.1.5) which mitigates m line breaks and/or ensures containment integrity.
denser pressure is indicated on the main control board.
perature is indicated locally and monitored by the computer.
.2 MAIN CONDENSER EVACUATION SYSTEM main condenser evacuation (air removal) system (Figure 10.4-2) removes noncondensable es from the condenser shells.
.2.1 Design Bases condenser evacuation system is designed in accordance with the following criteria:
- 1. The condenser evacuation system is designed to draw the initial vacuum in the condenser shells during startup, maintain vacuum during operation, and dispose of the noncondensable gases from the condenser.
- 2. The condenser evacuation system is non safety-related and is classified as nonnuclear safety (NNS).
- 3. The condenser air removal pumps are sized to operate in parallel and to initially reduce condenser pressure from atmospheric to 10 inches HgA in 40 minutes. The capacity of each air removal pump is 3,100 scfm at 10 inches HgA.
pressure of 1.5 inches HgA.
- 5. General Design Criteria 60 and 64 are in accordance with the provisions for control and monitoring the release of radioactivity to the environment.
- 6. Quality Group D requirements are defined in Table I of Regulatory Guide 1.26 (Section 3.2.2).
.2.2 System Description o 100 percent capacity steam jet air ejector units and two horizontal, motor-driven condenser emoval pumps are provided.
condenser air removal pumps are rotary water-ring type pumps, including silencers and seal er cooling systems, and are used to draw initial condenser vacuum.
steam jet air ejectors are triple element first-stage and single element second-stage units with er cooled inter and after condensers. Motive steam is supplied to the air ejectors from the iliary steam supply header (Section 10.4.10) and cooling water is supplied from the densate system (Section 10.4.7).
and noncondensable gases removed from the main condenser shells by the steam jet air tor units is discharged to Millstone stack via the radioactive gaseous waste system ction 11.3). Air removed by the condenser air removal pumps is discharged directly to the osphere through a vent stack in the condensate polishing enclosure roof.
indication of low absolute pressure in the condenser, the condenser air removal pumps are ually shut down and one steam jet air ejector unit is manually started. During normal ration, one unit operates with the other unit on standby. On indication of high absolute sure in the condenser, during normal operation, the second steam jet air ejector unit is ually started.
4.2.3 Safety Evaluation condenser air removal system is not safety related. The following design evaluation onstrates the system capability to perform its intended function.
maximum air leakage into the condenser (Section 10.4.1) is 60 scfm. This leakage is servative and reflects the anticipated air inleakage after an extended period of plant operation.
mally, one air ejector unit is sufficient to maintain the required vacuum; however, if necessary, h units may be operated in parallel.
air discharged from the steam jet air ejector units is considered potentially radioactive and is nitored continuously by the effluent radiation monitoring system (Section 11.5.3). The air
rflow drains are also considered potentially radioactive. The air ejector condenser drains are rned to the main condenser. The air removal pump drains are piped to the turbine building r drains which are continuously monitored by the process radiation monitoring system ction 11.5).
ntaining vacuum in the condenser is necessary for operation of both the turbine bypass system ction 10.4.4) and the turbine generator unit (Section 10.2). Failure of the condenser air oval system causes a gradual loss of vacuum in the condenser which could ultimately result in ine generator trip, followed by a reactor trip if the unit load is above 50 percent. Depending n the magnitude of main steam flow, high condenser pressure may result in the opening of the n steam safety valves and the main steam pressure relieving control valves in the main steam em (Section 10.3).
tinuous venting prevents the buildup of explosive mixtures in the air removal equipment.
.2.4 Tests and Inspections steam jet air ejectors are periodically inspected in accordance with the applicable station cedures.
.2.5 Instrumentation Requirements condenser air removal system operating parameters are monitored, indicated, and controlled lly or remotely, as follows:
trols on the Main Board in the Control Room trol switches with indicating lights for administrative control of:
- 1. Condenser air removal pumps
- 2. Condenser air removal pump suction valves
- 3. Condenser air removal pump seal water pump
- 4. Condenser vacuum breaker valves unciators that alarm when the following conditions exist:
- 1. Condenser air removal pump breaker auto trip
- 2. Condenser low vacuum indicator and recorder for condenser vacuum
- 1. Condenser vacuum
- 2. Condenser air removal pump breaker position
- 3. Condenser air removal pump motor overcurrent
- 4. Condenser air removal pump breaker auto trip or overcurrent al Flow Indicators al flow indicators are provided on the outlet of the air ejectors to check periodically for denser air leakage.
iation Monitoring Equipment tion 11.5 describes the radiation monitoring equipment.
.3 TURBINE GLAND SEALING SYSTEM main turbine, feed pump turbines, and the main steam stop and control valves, and the bined intermediate valves are provided with gland seal steam and leak-off (Figure 10.4-3).
turbine gland sealing system is not safety related.
.3.1 Design Bases turbine gland sealing system (Figure 10.4-3) prevents air leakage into, and collects steam age out of the turbines and valve stems. The steam seal system provides this function matically from startup to full load.
turbine gland sealing system is designed in accordance with the turbine generator ufacturers standards. Connecting piping, valves, and equipment are designed in accordance h Quality Group D Standards as defined in Regulatory Guide 1.26.
4.3.2 System Description turbine gland sealing system consists of three steam sources: main, auxiliary, and extraction m; a seal pressure controller, steam seal header, a steam packing exhaust condenser, two
-capacity exhaust blowers and the associated piping, valves, and instrumentation. The turbine d sealing system is normally operated with extraction steam from the fourth point extraction plemented by main steam during low load operation. The use of extraction and main steam is trolled by a split range pressure controller which maintains the gland steam header pressure by admitting extraction steam and, if necessary, main steam.
en main steam is unavailable, the gland steam seal system operates on 150 psig auxiliary m.
ing low load operation (startup and shutdown), steam is taken from the main steam lines ad of the turbine stop valves. This pressure is reduced by throttling the steam seal feed valve ch seals the turbine automatically with 25 percent rated throttle pressure and normal packing rances.
eal at low throttle pressures or with worn packings, the steam seal bypass feed valve may be d in parallel with the steam seal feed valve.
pressure in the turbine increases with load, the pressure packings and the steam seal feed valve action source contribute steam to the steam seal header.
m packing unloading valves are provided to vent excess gland seal steam to the condenser if essary to maintain 5 psig in the gland steam header. Relief valves on the steam seal header vent excessive steam seal pressure in the event of a control system failure.
ixture of air and steam drawn from the shaft packing is condensed in the steam packing auster condenser. During plant operation, the steam packing exhauster condenser is cooled by main condensate flow (Section 10.4.7). The recovered condensate is returned to the main denser hotwell via a loop seal and trap. The noncondensable gases are expelled to the osphere by one of the two motor-driven blowers mounted on top of the steam packing auster condenser.
.3.3 Safety Evaluation turbine gland sealing system is not safety related and there is no requirement for a safety luation which would demonstrate compliance with the criteria which would be applied to a ty system.
re is no radiation monitoring at the gland seal condenser vent as radioactive gaseous releases within the total unmonitored steam release specifications from the turbine building as defined UREG-0017, April 1976, Section 2.2.6.
.3.4 Tests and Inspections tests and inspections of equipment which are part of the turbine gland sealing system are as cribed in the manufacturers instructions. The gland sealing system is normally in operation no special tests are required to verify operability.
trol switches and indicator lights are provided on the main control board for manual operation he steam packing exhauster blowers.
following valves have control switches and position indicator lights on the main control rd:
Main steam gland seal steam supply valve Auxiliary steam gland seal supply valve Gland seal steam feed bypass valve Manual steam packing unloading valve istributed Control System (DCS) is utilized to control the steam seal pressure control valves.
irect sensing pressure control valve is utilized as the steam packing unloading valve.
following instrumentation is located on the main control board:
Annunciators that alarm when the following conditions exist:
Steam packing exhauster condenser level High Steam seal feed pressure High Steam seal feed pressure Low Steam packing exhaust vacuum Low Indicators that monitor the following parameters:
Steam packing exhaust vacuum Steam seal steam feed pressure al indicators are provided to monitor the steam packing exhauster condenser vacuum and the m seal feed pressure.
al flow elements are installed for performance testing of the system.
4.4 TURBINE BYPASS SYSTEM turbine bypass system is contained in the main steam system (Section 10.3), as shown on ure 10.3-1.
the range of NSSS design parameters, a rapid ramp load decrease equivalent to 50 percent of d thermal power / turbine load at a maximum turbine unloading rate of 200 percent per minute be accommodated without a reactor or turbine trip and without lifting the main steam safety es. This system design capability will accommodate up to two steam dump valves out of ice.
turbine bypass system is designed in accordance with ANSI B31.1. The system is not uired for safe shutdown and is not safety related. It is required only to provide flexibility of ration and a controlled cooldown.
capacity of any single turbine bypass valve does not exceed 970,000 lb/hr of steam at the n steam system design pressure, 1,185 psig, as specified by the nuclear steam system supplier.
failure of a turbine bypass valve to close will not cause an uncontrolled plant cooldown and esponding excessive reactivity excursion.
design pressure and temperature of the bypass piping from the main steam manifold up to and uding the turbine bypass valve is the same as the steam generator secondary side design ditions, 1,185 psig and 600F. The piping after the bypass valves has a design pressure of psig and a design temperature of 600F.
.4.2 System Description turbine bypass system includes a turbine bypass header, branching from the main steam ifold in the main steam system (Section 10.3), and individual bypass lines connecting the ass header to the condenser. One manual isolation valve and a turbine bypass valve are unted in series on each individual turbine bypass line.
full capacity of the turbine bypass system is equally distributed among the three condenser ls to ensure an even heat load and to minimize uneven turbine exhaust pressures and uneven ansion of the low pressure turbine casings.
details of the arrangement of the turbine bypass valves and associated controls are shown on ure 10.3-1. A total of nine bypass valves are provided, three in each condenser section. The ass valves are 8 inch, carbon steel globe valves with spring and diaphragm air operators. Each he valves is designed to pass a minimum of 70,600 lb/hr and a maximum of 970,000 lb/hr at sures ranging between 125 psig and 1185 psig, respectively. This ensures smooth control of steam dump flows over all steam operating pressure ranges. When the valves are modulated n, one valve from the bank of three valves in each condenser opens first, followed by ceeding valves opening in similar order for the remaining six valves. The methodology of the oints for actuating the bypass valves is described in Section 10.4.4.5.
er a normal orderly shutdown of the turbine generator leading to unit cooldown, the turbine ass valves will be used for several hours to release steam generated from reactor coolant em sensible heat. This is accomplished by first manually bypassing the lo-lo-Tavg interlock.
cess is transferred to the residual heat removal system.
.4.3 Safety Evaluation or several of the turbine bypass valves will be opened under the conditions described in this ion, providing the condenser is available.
ing startup, shutdown, operator license training, or physics testing, the turbine bypass valves be actuated remote manually from the main control board.
turbine bypass valves are prevented from opening on loss of condenser vacuum, or both ulating water pumps in any condenser section not running and in such a case, excess steam sure will be relieved to the atmosphere through the main steam safety and main steam sure relieving valves or the pressure relieving bypass valves. Redundant safety interlocks are vided to reduce the probability of inadvertent opening of the turbine bypass valves ction 7.7).
turbine bypass system high energy lines are located remote from any safety related ponents or systems. The turbine speed control system is not safety related. However, should turbine speed control system be damaged by the failure of a bypass system high energy line, redundancy built into the turbine control system (Section 10.2) makes the possibility of a ine overspeed situation unlikely. Further, an analysis has determined that the probability of age to safety related equipment resulting from a turbine overspeed is acceptably low.
failure mechanisms, which were accommodated in the design of the turbine bypass system, internal failures of the valves themselves, loss of instrument air to the valves, loss of electrical er to the valves, operator error, and spurious signals to the valves.
4.4.4 Tests and Inspections ing refueling shutdowns, the turbine bypass valves and turbine bypass system controls will be ected and tested for proper operation.
turbine bypass system piping will be inspected and tested in accordance with Paragraphs 136 137, respectively, of ANSI B31.1.
.4.5 Instrumentation Requirements a large external electrical load decrease (maximum of 50 percent), the turbine bypass system tes an artificial load on the steam generators to prevent the reactor from tripping. Reactor er can be decreased at a rate up to a maximum of 5 percent/minute until it matches the turbine erator load requirements. At that point, the bypass valves are fully closed. When a load ction occurs, if the difference between the required temperature setpoint of the reactor coolant em and the actual average temperature exceeds a predetermined amount, a signal will actuate
ated quickly to stroke full open or modulate, depending upon the magnitude of the perature error signal resulting from the loss of load. The Reactor Control System and Turbine ass control systems are discussed in detail in Sections 7.7.1 and 7.7.2. The turbine bypass es have the capability of going from full closed to full open within 3 seconds after receipt of ctuation open signal. Tref is a function of load and is set automatically. The turbine bypass es close automatically as reactor cooling conditions approach their programmed setpoint for new load.
a reactor trip, the turbine will trip and the turbine bypass system creates an artificial load on steam generators to prevent lifting of the main steam safety valves (Section 10.3). The control utomatically transferred from the load rejection controller to the turbine trip controller. An r signal exceeding a set value of auctioneered reactor coolant Tavg minus a preset turbine trip troller setpoint fully opens all turbine bypass valves. The valves discharge to the condenser for eral minutes, thereby removing the thermal output of the NSSS without exceeding acceptable and reactor coolant system limiting conditions. Following a reactor trip, the turbine bypass e signal may be transferred from the turbine trip controller to the steam line pressure troller. In this mode, main steam line pressure is compared with a predetermined setpoint to duce the controller output signal for valve modulation. Atmospheric steam discharge is not uired during these conditions, provided that no block signal, such as loss of condenser vacuum, resent.
following controls and instrumentation for the turbine bypass system are located on the main trol board:
- 1. Steam dump control mode selector switch positions RESET-T/AVG-STEAM PRESSURE.
- 2. Steam dump interlock selector switches (Trains A and B) with positions OFF/RESET-ON-BYPASS INTLK.
- 3. Position indication lights for the turbine bypass valves.
- 4. Steam header pressure controller AUTO/MANUAL station.
- 5. Steam generator atmospheric relief valve pressure indicating controllers with AUTO/MANUAL feature and valve position indicator lights.
- 6. Control switches and valve position indicator lights for the main steam pressure relieving isolation valves
- 7. Steam dump demand signal indicator.
- a. Steam pressure relieving valve in local control
- b. Main steam relief valve not closed.
- c. Main steam pressure relieving isolation valve in local control.
- 9. Status lights:
- a. Steam dump interlock bypassed.
- b. Turbine load rejection armed.
- c. Turbine bypass valves armed for opening.
- d. Condenser available for steam dump.
- e. Turbine bypass valves trip open signal present.
following instrumentation and controls for the turbine bypass system are located on the iliary shutdown panel:
- 1. REMOTE/LOCAL control selector switches for the main steam pressure relieving valves and valve position indicator lights.
- 2. Manual pressure control stations for the main steam pressure relieving valves.
- 3. REMOTE/LOCAL control selector switches for the main steam pressure relieving isolation valves.
- 4. Control switches with position indicating lights for the main steam pressure relieving isolation valves.
following parameters are monitored by the plant computer:
- 1. Turbine bypass steam temperature at discharge of each bypass valve.
- 2. Open and closed position of each main steam pressure relieving isolation valve
.5 CIRCULATING WATER AND ASSOCIATED SYSTEMS circulating water system (Figure 10.4-4) is a once-through cooling water design utilizing an hore Niantic Bay intake and a quarry surface discharge. The system provides debris-free salt er flow to the main condenser where waste heat from the thermal power cycle is collected for oval to the quarry. In addition, the circulating water discharge tunnel receives heated water
associated systems are the traveling screen wash and disposal system and the vacuum ing system. The traveling screen wash and disposal system (Figure 10.4-4) removes debris m the seawater used as cooling water in this unit. Fish removal equipment is incorporated into screen wash design. The vacuum priming system (Figure 10.4-2) initially primes and tinuously removes air from the circulating water lines, the condenser water boxes, and the ulating water discharge tunnel and outfall structure to create and maintain a siphon in the tube of each of the main condensers and to ensure that all tubes are filled.
le 10.4-1 contains design and performance characteristics for these systems.
4.5.1 Design Bases circulating water and associated systems are designed in accordance with the following eria.
ulating Water System circulating water system is not safety related and is designated nonnuclear safety class except the circulating water discharge tunnel and portions of the circulating and service water pump se (Section 3.8.4). A failure of this system, with the exception of the circulating water harge tunnel and portions of the circulating and service water pump house, does not affect any ty related equipment or the capability to shut down the primary plant safely. The circulating er discharge tunnel has QA Category I designation and has been designed Seismic Category I nsure availability as the discharge conduit for the service water system (Section 9.2.1). All ions of the circulating and service water pump house which support, or, by failure, could age the service water system (Section 9.2.1) are designated Seismic Category I.
circulating water system is designed as a once-through system to remove 7.5 x 109 Btu/hr of te heat from the power conversion cycle. The rejected heat is transferred to the circulating er as it flows through the condenser. The predicted temperature rise is expected to be 18.3F h a heat removal rate of 8.2 billion BTU/hr for an approximate cooling water flow of
,000 gpm at rated power conditions.
circulating water piping and expansion joints are designed for 50 psig internal pressure and vacuum. The discharge tunnel is designed for 7 psig and -8.7 psig internal pressure.
circulating water discharge tunnel is designed to receive heated water from the service water em and intermittent discharges from the liquid waste system and the steam generator wdown flash tank for discharge to the quarry.
circulating water system is designed to permit thermal backwashing of the inlet piping and ke pump bays for biofouling control.
traveling screen wash and disposal system is nonsafety related.
traveling screen wash and disposal system removes debris and fish from the seawater before nters the circulating water system and the service water system (Section 9.2.1). The system vides wash water at a pressure of 85 psig for high pressure spray nozzles for the removal of ris from the traveling water screens and for makeup flow to the fish a. The system also vides wash water at 10 to 35 psig for low pressure spray nozzles for the removal of fish from traveling water screens and for sluicing of removed fish. A screenwash flow rate of roximately 4,000 gpm is required for slow speeds screen operation and approximately 8,000 for fast speeds screen operation.
traveling screen wash and disposal system was designed to supply water to the Millstone 3 densate demineralizer component cooling water heat exchanger and back up the water supply he Millstone 2 condensate demineralizer component cooling water heat exchanger. Both of e functions have been removed from service. The system also provides an alternate means of plying water to the chemical feed chlorination system, if required.
uum Priming System vacuum priming system is nonsafety related.
vacuum priming system (Figure 10.4-2) consists of two subsystems: the station system and yard system. The station system removes a maximum air flow of 1,675 acfm at a vacuum of n Hg. The yard system removes a maximum air flow of 540 acfm at a vacuum of 10 in Hg.
ing normal circulating water system operation, the actual air flow and vacuums are less than design values.
.5.2 System Description ulating Water System circulating and service water pump house is divided into six bays which supply seawater to circulating water pumps: four service water pumps (Section 9.2.1) and two screenwash ps. Flow to each bay passes through a trash rack, which is cleaned by a trash rake and a eling water screen.
h of the six, one-sixth capacity, motor-driven, mixed flow, vertical, wetpit circulating water ps has a design flow of 152,000 gpm with a total dynamic head (TDH) of 27 feet. Pump ed is normally controlled by a Variable Frequency Drive (VFD). In the event that VFD mode a given pump is deemed undesirable, the VFD can be by passed, allowing operation at rated ed; however, no speed control is available in this condition. This operation requires that the cted circulating water pump be shut down during the transfer to the bypass mode of operation.
circulating water flows from the pumps to the condenser (Section 10.4.1) through six pendent inlet pipe lines. The circulating water discharges from the condenser though six
nd Sound.
otor-operated valve is installed at each circulating water pump discharge and in each denser circulating water outlet pipeline. Each pair of valves is used to isolate half of a denser shell. Operation with one or more circulating water pumps out of service is possible, ending on plant load and circulating water temperature. A motor-operated crossover valve is alled between adjacent condenser inlet waterboxes to permit use of both condenser tube dles in a shell with either one of the associated circulating water pumps. A motor-operated kwash valve is installed between adjacent condenser outlet waterboxes to permit thermal kwashing of the condenser.
t shock treatment (thermal backwash) controls marine growth in the circulating water phouse bays and condenser inlet piping. The heat shock treatment is accomplished by the hod described in Mode E below. This operation allows the circulating water that has passed e through half of a condenser shell to reverse and pass back again through the other half of the denser shell thereby increasing its temperature. The effect of passing hotter circulating water he reverse direction through the system is to kill marine growth. This process is repeated to t each pump bay and inlet pipe.
water velocity of approximately 9 fps in the inlet piping and 10 fps in the discharge piping contributes to the prevention of marine organisms adhering to, and growth within, the ulating water lines.
orination is performed on an intermittent basis in the circulating water system to prevent ouling of condenser tubes. Chlorination equipment is installed to prevent biofouling of the ice water system (Section 9.2.1).
re are five planned modes of operation of the circulating water system:
Mode A: To dissipate all rejected heat from the power conversion cycle.
All six circulating water pumps operate and pump water through six independent inlet lines, through six condenser half shells, and through six independent discharge lines to the discharge tunnel.
Modes B and E: To provide hot water for thermal backwashing of the condenser inlet piping and intake pump bays while dissipating all rejected heat from the power conversion cycle.
Mode E: Four circulating water pumps operate normally as discussed under Mode A.
Mode B: The pair of pumps involved in the thermal backwash have one pump operating and one pump stopped. Water is pumped through the inlet piping, through a condenser half shell. A portion of the flow is rerouted across the condenser outlet cross-connect pipe back
condenser then flows through the condenser inlet piping back to the pump house where it is discharged through the stopped pump. The remaining portion of flow passes to the discharge tunnel through the throttled condenser outlet valve.
Mode C: To dissipate all rejected heat from the power conversion cycle while one pump is out of service.
Four circulating water pumps operate normally as discussed under Mode A.
The partner pump of the pump out of service is operating and pumps water through the condenser inlet piping. At the condenser inlet water box flow is split by opening the condenser inlet cross-over valve. Water flows through both sides of the condenser shell and discharges through two independent lines to the discharge tunnel.
Mode D: To dissipate all rejected heat from the power conversion cycle during reduced unit load or during winter months.
Only three of six circulating water pumps operate and pump water through their respective condenser inlet piping. The flow, at each condenser, is split between inlet waterboxes as discussed under Mode C at cross-over valves. The flow is discharged through the six independent discharge lines to the discharge tunnel.
veling Screen Wash and Disposal System traveling water screens are located upstream of the circulating water pumps and consist of e-eighth inch mesh panels with fish trays attached to each panel. The screens have four-speed ors.
screens are automatically operated according to the differential water level across each en. The screens are also started by an automatic timer every four hours and run for 1.25 screen olutions. All six traveling screens and one screenwash pump start simultaneously. Two
-size screen wash pumps each have a design flow of 4,000 gpm with a total dynamic head of feet. One pump operates when the traveling screens are in slow speed and both pumps when screens are in fast speed. The operating modes of the pumps are manually changed on a ular basis to maintain uniform wear on pumps. The screen wash pumps take suction from the ke pump well and discharge to a manifold supplying each traveling water screen with high sure wash water and low pressure fish flush water. Individual trash and fish troughs collect sluice debris and fish received from the screens. The debris is removed from the trash trough motorized conveyor system to a trash container for removal. The fish are directed from the trough to a fish sluiceway which returns them directly to Long Island Sound.
traveling water screens also have the capability of reverse rotation, which is used in junction with the condenser backwashing sequence to remove any debris which has umulated in the inlet waterboxes and pump bays.
oved from service (Section 9.2.2.6).
vision is also made for the screen wash pumps to supply water to the chemical feed rination system, if required.
uum Priming System vacuum priming system primes the circulating water system prior to starting the circulating er pumps and continuously removes air from the discharge tunnel and condenser waterboxes ng circulating water system operation to maintain a siphon in the system. The system prises two independent subsystems, each including a vacuum tank and two full capacity uum pumps.
station vacuum priming system is located in the turbine building and removes air from the t and outlet condenser waterboxes. Air collects in vacuum priming domes at the top of each er box and is drawn by vacuum to a common vacuum tank. Vacuum is maintained on the tank he vacuum priming pumps which discharge the collected air directly to the atmosphere.
isture which accumulates in the vacuum priming tank is drained by gravity to the circulating er discharge tunnel.
yard vacuum priming system is located in the yard vacuum priming pumphouse and removes rom an air collection cap on the roof of the circulating water discharge tunnel seal pit. The ration of this system is similar to the station vacuum priming system.
h subsystem has two full size, liquid ring, centrifugal type vacuum priming pumps. One pump ach system is normally running with the second pump on standby. The operating modes of the ps are manually changed on a regular basis to maintain uniform wear on the pumps.
.5.3 Safety Evaluation circulating water system is not safety related except for the circulating water discharge tunnel portions of the intake structure. Section 3.8.4 discusses the circulating water discharge tunnel intake structure. Failure of the circulating water system or any of its components, with the eption of the discharge tunnel and portions of the intake structure, will not damage or flood safety related system or component.
following design evaluation demonstrates the system capability to perform its intended ction.
ulating Water System six circulating water pumps are normally in service and in Variable Frequency Drive (VFD) de. If a circulating water pump is out of service, operation of the unit can be continued, but the output may be reduced, depending on circulating water inlet temperature at that time. All
sed by rupture of the non-Category I pipe and components of the circulating water system.
rnal plant protection is provided by watertight areas specifically designed for such flooding ditions, by elevation, or by system and component design to ensure that such failures are not sible, as discussed under Circulating Water Expansion Joint Rupture, in this section.
kage of seawater from the circulating water system into interfacing systems is minimized by use of highly corrosion resistant materials as barriers between the circulating water system its interfacing systems. The most prominent of these barriers is the condenser (Section 10.4.1) h tubes fabricated from titanium, which is highly reliable for seawater application. The tube erial minimizes erosion due to high steam entrance velocity and protects the insides of the s from damage which could be caused by local high velocity circulating water. To further vent leakage of seawater into the condenser hotwell, aluminum-bronze tube sheets of double gral design are provided. Seal water from the condensate system (Section 10.4.7) is injected each inlet and outlet tube sheet at a pressure which is greater than the operating pressure of circulating water system.
uld any seawater leakage occur from the circulating water system into interfacing systems, leakage is detected in the condenser hotwell by the turbine plant sampling system ction 9.3.2.2). Section 10.4.1 discusses the detection of seawater leakage into the condenser.
circulating water system is protected from excessive pressure transients caused by multiple ulating water pump trips deriving from loss of all electrical power. Vacuum breaker valves, ted on each condenser inlet and outlet water box, are automatically opened by any two ulating water pumps tripping within one minute of each other. Hydraulic transient analyses e performed on the circulating water system to determine the most critical operating ditions which would yield the most severe transient pressures (both positive and negative) hin the system. It was determined that a loss of power which leads to a simultaneous loss of all circulating water pumps would produce the most severe pressures. The design transient sures for the circulating water system, based on loss of power and opening of the vacuum ker valves, fall within the maximum design pressure/vacuum envelope of the circulating er system.
ulating Water Expansion Joint Rupture re are no essential systems or components required for safe shutdown or to mitigate the effects n accident, located within the turbine building which could be affected by flooding due to a ulating water pipe or expansion joint rupture. In addition, there are no passageways, pipe ses, or cableways that could be rendered inoperable by flood waters generated by a complete ure of a main condenser circulating water expansion joint. However, a pipe tunnel is provided e basement floor, at elevation 14 feet 6 inches, in the turbine building, connecting the turbine ding to the safety related auxiliary building. This tunnel is totally sealed with a fire barrier at auxiliary building and will prevent any water from entering the auxiliary building.
econds; however, for design purposes, it is assumed that operator action is delayed for minutes. Within 15 minutes the total amount of water spillage into the turbine building could pproximately 2,250,000 gallons. This water results in a water level at approximately elevation eet-6 inches. This level of water does not affect any essential systems or components.
wever, the sump alarm system that is provided to detect flooding in the Turbine Building is not ty-related. Therefore, a circulating water expansion joint rupture in the Turbine Building ld result in internal flooding until the water level reaches elevation 28 feet (assuming no rator action). To compensate for this, the siding panel with pressure release feature is provided levation 24 feet 6 inches of the Turbine Building. This siding panel will blow out if the dwater reaches elevation 28 feet inside the Turbine Building. This panel is located on the west of the Turbine Building, away from several Category I structures which are located east of Turbine Building. Therefore, continued operation of the circulating water pumps will not lt in damage to safety-related systems or components.
rculating water expansion joint rupture in the turbine building could result in internal flooding l the water level reaches elevation 28 feet. The sump alarm system that is provided to detect ding in the turbine building is not safety-related. To compensate for this, the siding panel with sure release feature is provided at elevation 24 feet 6 inches between column lines A39 and of the turbine building. This siding panel will blow out if the floodwater reaches elevation eet inside the turbine building. This panel is located on the west side of the turbine building, y from several Category I structures which are located east of the turbine building. Therefore, tinued operation of the circulating water pumps will not result in damage to safety related ems or components.
veling Screen Wash and Disposal System hough the seawater must pass through the traveling water screens prior to entering the service er system, the service water pumps will function properly when the traveling screen drive ors are not operating. The traveling water screens are capable of manual operation and can be manually cleaned. Because the capacity of the service water pumps is a small percentage he traveling water screen capacity (less than 9 percent), gradual blockage of the traveling er screens with debris still allows sufficient flow for operation of the service water pumps. If screens become blocked to the extent that the differential water level across a screen exceeds; nches for screens upstream of service water pumps or 42 inches for screens upstream of enwash pumps, the circulating water pump is automatically tripped. However, even with a nch differential and low tide, there is adequate net positive suction head for the service water ps.
re is no dependence on the traveling screen wash and disposal system for safe plant shutdown ollowing a design basis accident.
vacuum priming system is a nonsafety related system. Failure of the vacuum priming system ny of its components will not damage any safety related system or component.
s-of-vacuum capability at the condenser water boxes reduces circulating water flow to the denser with some tubes flowing partially full or empty, which reduces the unit output. The
-of-vacuum capability at the circulating water system discharge structure reduces circulating er flow with the discharge tunnel flowing partially full, which reduces unit output.
.5.4 Tests and Inspections ulating Water System components of the circulating water system are normally in service. Therefore, no testing of of these components is required.
veling Screen Wash and Disposal System components of the traveling screen wash and disposal system operate intermittently on a daily
- s. Therefore, no testing of any of these components is required. Automatic operation of the eling water screens, screen wash pumps, and debris conveyor is checked during initial ration and at frequent intervals thereafter.
uum Priming System vacuum priming pump and associated equipment are normally in service in both the station yard systems at any time. Because the vacuum priming pumps and associated equipment rnate for operation, no testing is required.
.5.5 Instrumentation Requirements ulating Water System circulating water pumps and all motor operated valves are manually operated from the trol room. The circulating water pump motors are provided with speed controllers at the main trol board to manually set and monitor percent speed. Phase current is monitored on the Plant cess Computer through inputs from the Variable Frequency Drive (VFD). When the VFDs are in use, ammeters located on the main control board and at the switch gear will be used to nitor phase current. Six temperature resistance-detectors (RTDs) are provided for the motor dings on the circulating water pumps: two are utilized, the hottest point for an alarm on the n control board and the second hottest for a computer point; the other four are spares. The or sleeve bearing and thrust bearing temperatures are monitored by the computer. Circulating er pump discharge pressure is monitored by a local indicator and the computer.
denser circulating water inlet and outlet temperatures are monitored by the computer and l temperature indicators.
h level (1 foot) in the condenser discharge pit sump is alarmed in the control room.
veling Screens Wash and Disposal System screenwash pump is automatically started by a 6 inch differential water level to provide wash er through the spray nozzles associated with Slow 1 speed screen operation of five feet per ute. A 7 inch differential water level results in screen speed of rotation increase to Slow 2 at eet per minute. A 9 inch differential water level automatically starts the second screenwash p to provide additional wash water for screen speed Fast 1 at 16 feet per minute. A 10 inch erential water level results in screen speed increase to Fast 2 at 32 feet per minute. High erential (18 inches) level across any traveling water screen is alarmed in the Control Room.
h-High differential alarm (42 inch for A and F Bays with screenwash pumps, and 36 inch B, C, D, E Bays with service water pumps) automatically trips the associated ulating water pump. Traveling screen differential level is indicated on the main control board.
h trash rack differential level (6 inches) is alarmed in the Control Room.
uum Priming System ach vacuum priming subsystem, one pump is normally operating and one pump is in standby.
standby pump automatically starts on high air pressure in the vacuum priming tanks and stops ow air pressure. Low vacuum in the vacuum priming tank is alarmed in the control room.
circulating water systems operating parameters are monitored, indicated, and controlled, otely or locally, as follows:
The following controls and instruments are located on the main control board in the control room:
Control switches and indicating lights for:
- 1. Circulating water pumps
- 2. Circulating water pump discharge valves
- 3. Circulating water pump bearing lubricating water supply valves
- 4. Condenser crossover valves
- 5. Condenser backwash valves
- 6. Condenser outlet valves
- 7. Screenwash pump
- 9. Vacuum priming pump Annunciators that alarm when the following conditions exist:
- 1. Circulating water breaker auto trip/overcurrent
- 2. Circulating water pump stator winding temperature High
- 3. Condenser pressure differential High
- 4. Circulating water pump lube water strainer differential pressure High
- 5. Circulating water pump lube water pressure Low
- 6. Circulating water discharge pit level High
- 7. Trash rack differential level High
- 8. Screenwash pump auto trip/overcurrent
- 9. Screenwash discharge header pressure Low
- 10. Traveling screen differential water level Low
- 11. Screenwash strainer differential pressure High
- 12. Vacuum priming tank vacuum Low
- 13. Vacuum priming seal water flow Low
- 14. Vacuum priming pump auto trip
- 15. Variable Frequency Drive (VFD) alarm
- 16. VFD fault Indicators that monitor the following parameters:
- 1. Circulating water pump amperage
- 2. (Deleted)
- 3. Condenser outlet valve position
- 5. Traveling screen speed
- 6. Screenwash pump discharge valve position
- 7. Screenwash pump running for the condensate demineralizer system
- 8. Traveling screen differential water level
- 9. Seal water circulating pump
- 10. Seal water replenishing valve
- 11. (Deleted)
- 12. (Deleted)
- 13. VFD percent speed: setpoint and actual The following parameters are monitored by the plant computer:
- 1. Circulating water pump motor overcurrent
- 2. Circulating water breaker auto trip
- 3. Circulating water pump motor sleeve bearing temperature
- 4. Circulating water pump motor stator winding temperature
- 5. Circulating water pump motor thrust bearing temperature
- 6. Circulating water pump discharge pressure
- 7. Circulating water pump bearing water pressure Low
- 8. Circulating water pump breaker position
- 9. Circulating water pump motor vibration
- 10. Circulating water pump bearing lubricating water supply valve position
- 11. Circulating water box temperature
- 12. Condenser discharge tunnel temperature
- 14. Screenwash pump motor overcurrent
- 15. Screenwash pump auto trip
- 16. Vacuum priming pump auto trip
- 17. Condenser pressure differential
- 18. Condenser water box vacuum break valve not fully closed
- 19. Circulating water pump auto trip
- 20. VFD alarm
- 21. VFD fault The following controls and instruments are located on the liquid waste control panel:
Control switches with indicating lights for the following:
- 1. Screenwash pump B
- 2. Traveling screen and condensate demineralizer system supply valve
- 3. Condensate demineralizer component cooling water heat exchanger outlet isolation valve
- 4. (Deleted)
Local control switches with indicating lights are provided for the following:
- 1. Traveling water screen
- 2. Screenwash pump discharge valve
- 3. Variable Frequency Drive Local indicators are provided for the following:
- 1. Screenwash pump (indicator lights)
- 2. Traveling screen differential level
- 3. Traveling screen differential water level
- 5. Vacuum priming seal water flow The following indicators are provided on the switchgear:
- 1. Breaker indicator lights
- 2. Circulating water pump amperage in bypass mode
- 3. Vacuum priming pump indicator lights
.6 CONDENSATE POLISHING DEMINERALIZER SYSTEM condensate polishing demineralizer system (Figure 10.4-5) removes suspended and olved solids from the condensate stream. The condensate polishing demineralizer system is safety related.
.6.1 Design Bases condensate polishing system removes, from the condensate stream, impurities resulting from denser tube leakage, primary to secondary leakage, corrosion of the feedwater-condensate em, and produces a high-quality effluent capable of meeting feedwater and steamside mistry specifications. The condensate polishing system is capable of treating the entire flow of densate, and is capable of maintaining condensate impurities resulting from condenser tube age below EPRI Action Level values for condenser leakage rates up to 1000 ml/min proximately 0.26 gpm). The system conforms with NRC Regulatory Guide 1.56, Positions C.1 ugh C.5 for indirect cycle plants. (1) ormal operation, the condensate polishing demineralizers produce effluent that meets the uirements specified by secondary plant water chemistry procedures.
ficient demineralizer redundancy allows demineralizer regeneration while the system retains ull polishing capacity. The system is also designed to meet NRC Branch Technical Positions B 3-1 and MEB 3-1 as related to breaks in high and moderate energy piping systems outside tainment. Table 10.4-2 lists condensate polishing system design data.
.6.2 System Description condensate polishing system consists of eight 196 cubic foot mixed bed demineralizers ted in the condensate stream between the condensate pump discharge and the steam-jet air Regulatory Guide 1.56 was withdrawn by the NRC (see 75 FR 7526, 2/19/10). The hdrawal of Regulatory Guide 1.56 does not alter any prior or existing licensing commitments onditions based on its use.
ually. A normally closed bypass valve can be opened manually to route the condensate flow und the demineralizers. Demineralizers may be bypassed if demineralizer differential pressure eases to a point where demineralizer damage or excessive condensate flow restriction may ur, during plant startup, or during other plant conditions where feedwater quality can still be ntained within chemistry specifications. The resins used in the demineralizers are initially in H+ and OH- forms mixed in a chemically equivalent ratio.
condensate polishing system ion exchange resins require periodic cleaning and regeneration never either a demineralizer effluent quality does not meet acceptable values or the pressure p across a resin bed is too high. The resin cleaning and/or chemical regeneration is done rnally to the demineralizers.
polisher regeneration equipment consists of a cation regeneration vessel, an anion neration vessel, and a resin mix and storage vessel. A lime system for regenerating the resin if polishing system is operated in the ammonia cycle, and an ultrasonic resin cleaner are also ilable, but not currently used.
in beds to be regenerated are first transferred from the demineralizer to the cation regeneration sel where the anion and cation resins are separated. The anion resin is then transferred to the n regeneration vessel. The resins are chemically regenerated using sulfuric acid for cation n and a caustic solution for anion resin. The regenerated resins are transferred to the resin mix storage vessel for mixing and sluicing back to the demineralizer vessel. Spent resin can be osed of by sluicing from the resin mix and storage vessel through the resin transfer line to porary storage containers. Alternatively, spent resin may also be sluiced to the radioactive te disposal system of Unit 2 See Figure 10.4-5 (3 of 5).
design pressure of the condensate side of the condensate demineralizer system is 700 psig.
4.6.3 Safety Evaluation s system is not safety related. Failure of any portion or component of this system will not age any safety related component or system. The following design evaluation is provided to onstrate the system capability to perform its intended function.
ssive Condenser Tube Failure system provides some degree of protection even during massive leaks, such as a complete failure, thus affording reaction time to take corrective action or initiate a unit shutdown.
rder to prevent resin breakthrough into the steam generators, the condensate polishing ineralizer (CND) system design has the following features:
stainless steel laterals capable of retaining whole and partial resin beads.
- 2. Resin strainers (traps), 3CND-STR1A through H, are used on the outlet of each demineralizer prior to manifolding at the common effluent header. The strainer baskets are designed to retain all particles larger than 50 mesh if demineralizer underdrain failure occurs. Procurement specifications ensure less than 0.5 percent of new resin is smaller than 50 mesh.
Each strainer is provided with a pressure differential indicating switch, 3CND-PDIS 35A through H, which actuates an alarm and an indicating light when the strainer has become fouled by resin and should be cleaned by backflushing.
- 3. The broken, disintegrated, and worn beads and resin fines (finer than 50 mesh) formed by attrition are removed from the resin along with accumulated crud during air/water scrub and backwash steps in the cation regeneration tank (3CND-TK1). Resin fines can also be removed by the ultrasonic resin cleaner (3CND-URC1) if used.
.6.4 Tests and Inspection polisher vessels were hydrostatically tested in the assembly shop. The control system was tested in the shop to ensure proper valve and pump operation sequences. Following allation, the system was hydrostatically tested as a complete unit.
condensate polishing system is normally in continuous operation whenever the steam erators are being fed by main feed or condensate. If no condenser in-leakage occurs, each ineralizer is regenerated as required by resin exhaustion or increasing pressure drop.
refore, operability of the demineralizers and the regeneration system is demonstrated on a ular basis.
tem equipment is tested for leakage and proper automatic operation prior to initial startup of unit.
.6.5 Instrumentation Requirements conductivity of the influent condensate to the condensate demineralizers, the effluent from h demineralizer, and the condensate returning to the condensate header is measured and rded continuously.
urity levels of the effluent from each demineralizer can be measured and recorded. An alarm al is provided on the condensate polishing panel to indicate high levels.
ifferential pressure transmitter is provided to monitor the differential pressure across the densate demineralizer system. An alarm signal is provided to the condensate polishing panel
em.
w transmitters, recorders, and flow indicating totalizers are provided to monitor the throughput ach condensate demineralizer.
tinuous measurement of the waste stream for any radioactivity during disposal is provided by lement installed on a sample line which discharges back to the sump. Presence of a onuclide concentration exceeding the guidelines established in 10 CFR 20 automatically inates disposal to the circulating water outfall line. The applicable guidelines are those in endix B of 10 CFR 20. The validity of measurement by further tests and any possible need for rsion to the radwaste system are assessed by station operating personnel.
.7 CONDENSATE AND FEEDWATER SYSTEMS condensate and feedwater systems (Figures 10.4-1 and 10.4-6) supply feedwater at the uired temperature, pressure, and flow rate to the secondary sides of the steam generators.
.7.1 Design Basis condensate and feedwater systems are designed to provide approximately 16.6 x 106 pounds hour of feedwater at 441F to the steam generators during steady state operation (i.e., at NSSS ranted power). The portion of the feedwater system from the steam generators up to the first raint beyond the isolation valve outside containment is Safety Class 2 and is designed to lity Group B standards as defined in Regulatory Guide 1.26. The portion of the feedwater em upstream of the first restraint beyond the isolation valve to the turbine building wall is ety Class 3 and is designed to Quality Group C standards. The remainder of the feedwater em and the entire condensate system are non safety related and are designed to Quality Group andards. The safety related portions of the condensate and feedwater system are designed in ordance with the seismic design criteria discussed in Section 3.7B.3. The remainder of the water system and the entire condensate system are nonseismic.
tions of the feedwater system are also designed to the following criteria:
- 1. General Design Criterion 2 for structures housing the system and the system itself being capable of withstanding the effects of natural phenomena such as earthquakes, tornadoes, hurricanes, and floods.
- 2. General Design Criterion 4 for structures housing the system and the system itself being capable of withstanding the effects of external missiles and internally generated missiles, pipe whip, and jet impingement forces associated with pipe breaks.
- 3. General Design Criterion 44, to assure:
- b. Redundancy of components so that under accident conditions the safety function can be performed assuming a single active component failure.
(This may be coincident with the loss of offsite power for certain events.)
- c. The capability to isolate components, subsystems, or piping if required so that the system safety function is maintained.
- 4. General Design Criterion 45 for design provisions to permit periodic inservice inspection of system components and equipment.
- 5. General Design Criterion 46 for design provisions to permit appropriate functional testing of the system and components to assure structural integrity and leak-tightness, operability and performance of active components, and capability of the integrated system to function as intended during normal, shutdown, and accident conditions.
- 6. General Design Criterion 54 for design of lines penetrating containment to provide leak detection, isolation, and containment capabilities having redundancy, reliability, and performance requirements which reflect the importance to safety of isolating the piping system. The system is also designed with a capability to test periodically the operability of the isolation valves and associated apparatus and to determine if valve leakage is within acceptable limits.
- 7. Regulatory Guide 1.26 for the quality group classification of safety related system components.
- 8. Regulatory Guide 1.29 for the seismic design classification of safety related system components.
- 9. Regulatory Guide 1.102 for the protection of structures, systems, and components important to safety from the effects of flooding.
- 10. Regulatory Guide 1.117 for the protection of structures, systems, and components important to safety from the effects of tornado missiles.
- 11. Branch Technical Positions ASB 3-1 and MEB 3-1 for breaks in high and moderate energy piping systems outside containment (Section 3.6).
.7.2 System Description condensate system condenses and collects steam exhaust from the low pressure turbines and feedwater pump turbines. Condensate is drawn from the condenser hot well (Section 10.4.1)
n tripping of either condensate pump, the standby condensate pump is started automatically in er to continue plant operation at full load. From this header, the entire volume of flow is cted through the condensate demineralizers (Section 10.4.6). A bypass is provided to allow ration without use of the demineralizers.
manent piping is installed at the condensate pump discharge to drain the condenser hotwell to circulating water discharge tunnel to facilitate cleaning the hotwell.
m the main condensate header, a small line containing a pressure reducing valve supplies seal er to various pumps, valves, and loop seals throughout the plant.
m the main header, a portion of flow is directed through the steam jet air ejector units ction 10.4.2) and the steam packing exhauster condenser (Section 10.4.3). Condensate flow es as cooling water for these units. After passing through these units, the cooling water is rned to the main condensate header. A control valve is positioned in the main condensate der between the inlet to the steam jet air ejectors and the exit from the steam packing exhauster denser. This valve is modulated to maintain flow through the steam jet air ejectors at constant pproximately 25 percent.
additional branch from the condensate header provides condensate for the following services:
- 1. Turbine hood exhaust sprays, which are required to cool the turbine exhaust hoods during startup or low power operation.
- 2. Condenser de-superheating sprays, which are in operation whenever steam is being dumped to the condenser.
- 3. Condensate system recirculation, which provides adequate cooling for the steam jet air ejectors and steam packing exhauster condenser during low power levels as well as minimum flow recirculation for the condensate pumps.
- 4. Condensate drawoff to the condensate surge tank for excess water in the condensate system.
main condensate header is then split into three parallel strings of low pressure feedwater ters. The feedwater heaters (Figure 10.4-7) heat the condensate by condensing extraction m from the turbine generator (Figure 10.4-3). The condensed steam is drained to either the t lower pressure heater or to the condenser.
h low pressure (GED) feedwater heater string has five regenerative feedwater heaters (second ugh sixth on Figure 10.4-7). The second point feedwater heater receives the cascaded drains m the high pressure first point heater. The low pressure drains of the second point heater are aded to the third point heater and from the third point heater to the fourth point heater. The
denser. The fifth point heater drains via a control valve and the sixth point heater drains via a p seal in the drain line. Cascading drains enable an optimum amount of heat to be extracted m the heater drains. With the exception of the loop sealed sixth point heater, each of the heaters an individual emergency drain directly to the condenser in the event of a high level in the ciated heater. The condensate from each heater string is collected in a suction header for the water pumps. A bypass line is provided from the feedwater pump suction header to the water pump discharge header allowing the steam generators to be filled and serviced by the densate pumps during initial startup. A low pressure heater bypass is provided to allow roximately 92 percent NSSS-warranted power flow and to prevent exceeding the design duty he operating heaters should one heater string be isolated.
ee half-sized steam generator feedwater pumps take suction from the condensate system. Two he pumps are steam turbine-driven and are normally operating; the third is an electric or-driven pump on standby service. The feedwater pumps discharge into a common header.
dwater is then passed through three parallel aligned, high pressure feedwater heaters (first nt heaters). The discharges of the first point heaters are collected in a common header from ch four individual supply lines to the steam generators originate.
densed extraction steam in the first point feedwater heater shells is drained to the second point ters. An emergency drain line is provided for each heater directly to the condenser in the event igh level in the associated heater.
igh pressure heater bypass is provided to allow approximately 92 percent NSSS-warranted er flow should one heater be isolated.
h of the main feedwater steam generator supply lines contains a motor-operated stop valve, a modulating control valve, and a main feedwater isolation trip valve. A bypass line is vided around each set of main feedwater control valves and contains the main feedwater ass level control valve. During startup, low load operations (less than approximately 25 ent NSSS power), and shutdown, feedwater is admitted to the steam generators through the ass lines. At approximately 25 percent NSSS power, flow control to the steam generators is ually transferred from the feedwater bypass valves to the main feedwater flow modulating es (Section 7.7.1.7).
ultrasonic flow meter (UFM - trade name LEFM) is installed in each of the feedwater lines of steam generator feedwater system. The ultrasonic flow meter system measures feedwater
, feedwater temperature, and UFM-localized pressure for input into the secondary rimetric calculation (see Figure 10.4-6) h steam generator feedwater pump is provided with a minimum recirculation flow control e for protection against undue temperature rise and vibration in the pump casing at reduced p flows.
,000 gallons) is provided for supplying makeup requirements for the condensate and water systems. Automatic electric heating is provided for both tanks to maintain a 40F imum water temperature. A line from the condensate surge tank to the condenser hot well plies makeup to the condensate system upon demand. Excess water in the condensate system turned to the condensate surge tank via the condensate pump discharge header.
condenser hot well level is automatically controlled by normal, low, and high water level trollers during steady state and transient conditions. The normal level and low level controllers dulate valves in the condensate makeup and emergency makeup lines, respectively. The high l controller modulates a control valve in the condensate draw off line during abnormal high well level conditions. High and low level alarms are actuated on the main control board.
mical feed equipment is provided to ensure proper chemistry control of feedwater and densate systems during all modes of operation. Hydrazine and a pH control agent are provided he condensate system inside the turbine building during normal plant operation to maintain uired oxygen and pH levels. During startup and hot standby, these chemicals are provided ctly to the feedwater system inside containment. Each chemical feed line inside containment tains an air-operated isolation valve which is closed during normal plant operation. The mary objective of chemical injection is to minimize corrosion of the steam generator internals.
itionally, a polymeric dispersant may be injected into the feedwater system, downstream of first point feedwater heaters to improve the effectiveness of the steam generator blowdown em in removing particulate solids from the steam generators. The secondary objectives are:
- 1. To prevent or minimize turbine deposits due to carryover from the steam generator.
- 2. To reduce corrosion in the steam/feedwater cycle and deposits in the steam generator.
- 3. To minimize or prevent scale deposits on the steam generator heat transfer surfaces and in the turbine.
- 5. To minimize the potential for the formation of free caustic or acid in the steam generators.
se objectives are attained by comprehensive sampling and laboratory analyses, chemical ction at selected points, normally continuous blowdown from each steam generator, use of densate polishers, and chemical protection of the steam generator and feedwater train internals ng outages.
ing normal operation and shutdown, the condensate and feedwater systems supply feedwater he steam generators. During accident conditions, the feedwater system is isolated from the m generators.
ing normal plant operation, a failure in the feedwater control system could lead to one of two sible events. The first event is an abnormal increase of water inventory within the steam erator, and the second event is an abnormal decrease of water inventory within the steam erator. The abnormal increase is terminated by steam generator high level function, which ts to cause feedwater isolation should two out of the four high level bistables indicate an ormally large steam generator water inventory (each steam generator has four high level ables). The abnormal decrease is terminated by the steam generator low-low water level ction. Should two of four low-low water level signals be initiated in any one steam generator, tor trip will occur and the motor-driven auxiliary feedwater pumps will automatically start.
uld two of four low-low water signals be initiated by any two of the steam generators, the ine-driven auxiliary feedwater pump will automatically start.
dwater isolation valves are provided to isolate the safety related portions of the feedwater em from the remainder of the feedwater and condensate systems. These valves close matically (within 5 seconds) on receipt of a feedwater isolation signal generated by a safety ction signal, high-high water level in any steam generator, or by a reactor trip coincident with w Tavg. The main feedwater flow control and bypass level control valves receive the feedwater ation trip signal and receive power from opposite trains, therefore, providing a backup to the ation valves.
preclude over pressurization of the feedwater system piping due to deadheading of feedwater ps during feedwater isolation after a reactor trip coincident with low RCS Tavg, the feedwater ps trip automatically approximately 15 seconds after initiation of reactor trip signal. A bypass tch with normal and bypass positions is provided on the main control panel to facilitate a post manual restart of any of the FW pumps, as well as to bypass the FW pumps trip function ng operation below approximately 25 power, when over pressurization is not feasible.
ck valves are provided in the safety related portion of each feedwater line leading to the steam erators to preclude the uncontrolled blowdown of more than one steam generator in the event feedwater line break (Section 15.2.8).
effects and radiological consequences of condensate and feedwater system malfunctions lting in loss of normal feedwater flow, increase in feedwater flow, or decrease in feedwater perature are discussed in Sections 15.2.7, 15.1.2, and 15.1.1, respectively. The effects of a water system line break inside or outside the containment are discussed in Section 15.2.8.
safety related portion of the feedwater system is protected from tornadoes and tornado erated missiles by virtue of being housed in Seismic Category I structures (Section 3.3).
tection from floods is discussed in Section 3.4. Protection against the dynamic effects of high moderate energy pipe breaks (including pipe whip) is discussed in Section 3.6. Analyses have
condensate system and that portion of the feedwater system inside the turbine building are
-safety related. During normal operation, one condensate pump and the motor-driven water pump are on standby service. If one of the operating turbine-driven feedwater pumps s, the motor-driven feedwater pump automatically starts on low discharge header pressure.
standby condensate pump automatically starts if either of the two running condensate pumps
. The feedwater and condensate systems are capable of operation at 100 percent NSSS power h one condensate and one steam generator feedwater pump out of service. Any failure in the safety class portion of the condensate and feedwater system has no effect on the safety of the tor. A source of feedwater supply to the steam generator is required for decay heat removal m the reactor following a unit shutdown. In the event that the condensate and feedwater ems are not available, the auxiliary feedwater system (Section 10.4.9) provides the required rgency supply of feedwater.
e rupture in any feedwater heater necessitates isolation of the heater string in which the functioning feedwater heater is located. Two motor-operated isolation valves are provided for h string of low pressure feedwater heaters and for each high pressure heater. If a tube break urs in either of the feedwater heaters located in the condenser neck, the isolation valves close matically. If a break occurs in any of the remaining feedwater heaters, the affected low sure heater string or high pressure heater is isolated remote-manually. Bypasses are provided both the low pressure and high pressure heater strings. These bypasses are designed to allow approximately 92 percent NSSS-rated power flow in the event of isolation of a single heater ng. The shell sides of the feedwater heaters are protected from overpressure by relief valves.
ures in the condensate demineralizer system require isolation of the system from the densate system. Manual isolation valves are provided, one each in the lines going to and rning from the demineralizer. A motor-operated valve is provided in the bypass line around condensate demineralizers.
ease of radioactivity to the environment in the event of pipe rupture in the condensate or water system is bounded by the release that would occur from a pipe rupture in the main m system (Section 15.1.5).
feedwater system piping is arranged to prevent water hammer from occurring at the steam erators. The feedwater system has been analyzed to ensure the system withstands the effects of er hammer caused by a turbine-driven feedwater pump trip or a sudden closure of the water isolation valves. No hydraulic instabilities are postulated in the condensate system.
asures will be taken as appropriate to protect personnel from any toxic effects of chemicals d for water treatment. The tanks in which these chemicals are mixed and stored are vented to atmosphere outside the turbine building. A safety shower and eyewash are provided near the s for use by operating personnel in case of spillage accidents. Because the chemicals are not ificantly flammable, fire protection equipment is not needed.
mal operation and opened during startup operations. Each valve closes automatically upon ipt of a feedwater isolation trip signal.
.7.4 Testing and Inspection Requirements piping in the condensate and feedwater systems was hydrostatically tested during struction, and all active system components such as pumps, valves, and controls were ctionally tested during startup and tested periodically thereafter.
pling connections are provided in the condensate pump discharge header, sixth point water heaters inlet, and downstream of each first point heater. Periodic samples are taken m the condenser hotwell, and the condensate surge and storage tanks. Condenser hotwell ples are tested for sodium, conductivity, and chloride. Condensate surge and storage tank ples are tested for oxygen, pH, conductivity and chloride. In addition, condensate surge tank ples are tested for total gamma activity and condensate storage tank samples are tested for ium.
visions have been made to permit inservice inspection of Safety Class 2 and 3 portions of the water system as required by ASME XI (Section 6.6). Code Class 2 high energy fluid system ponents in designated break exclusion areas (BEA) are accessible for augmented inservice ection.
ting of the feedwater containment isolation valves is discussed in Section 7.1.2.5.
.7.5 Instrumentation Requirements densate System trol switches and indicator lights are on the main control board for operation of the three densate pumps. Normally, two pumps are running; the standby pump starts automatically n either one of the running pumps is tripped. Each pump motor is provided with an ammeter he main control board and an ammeter and indicator lights at the switchgear.
following annunciators are on the main control board:
- 1. Condensate pump flow Low.
- 2. Low pressure heater bypass valve not fully open.
- 3. Condensate pump auto trip/motor overcurrent (common).
- 4. Control power not available.
- 5. Motor stator winding temperature High (each pump motor).
- 7. Condenser sealwater pressure Low.
following parameters are monitored by the plant computer:
- 1. Condensate pump auto trip.
- 2. Condensate pump motor overcurrent.
- 3. Condensate pump motor upper sleeve bearing temperature.
- 4. Condensate pump motor lower sleeve bearing temperature.
- 5. Condensate pump motor thrust bearing temperature.
- 6. Condensate pump motor stator winding temperature.
- 7. Turbine exhaust hood temperature.
- 8. Condenser hot well water temperature.
- 9. Condensate discharge header temperature.
- 10. Condensate discharge header pressure.
- 11. Condensate header flow.
- 12. Sixth point heater inlet temperature.
- 13. Fifth point heater inlet temperature.
- 14. Fifth point heater outlet temperature.
- 15. Fourth point heater inlet temperature.
- 16. Fourth point heater outlet temperature.
- 17. Third point heater inlet temperature.
- 18. Third point heater outlet temperature.
- 19. Second point heater inlet temperature.
- 20. Second point heater outlet temperature.
- 1. Condensate discharge header temperature.
- 2. Condensate discharge header pressure.
- 3. Condenser pump motor amperage.
- 4. Condensate header flow.
- 5. Turbine exhaust hood spray bypass valve position.
- 6. Hot well level.
condenser hot well level is automatically controlled by normal, low, and high level trollers. The normal level and low level controllers modulate control valves in the condensate mal makeup and emergency makeup lines, respectively. The high level controller modulates a trol valve in the condensate drawoff line during abnormally high hot well level conditions.
h and low level alarms are actuated on the main control board.
trol switches and position indicator lights are on the main control board for the condensate p discharge valves. Throttling control is utilized for the condensate pump discharge valves.
condensate demineralizer mixed bed bypass valve has control switches and position indicator ts on the main control board and on the condensate demineralizer panel. A REMOTE/LOCAL trol selector switch is located on the main control board. Throttling control is used and a valve ition indicator is located on the condensate demineralizer panel. Differential pressure across condensate demineralizer is indicated on the main control board.
ow indicating controller located on the auxiliary condensate panel is used to modulate the densate minimum flow recirculation control valve. Valve position indicator lights are located he main control board. Condensate pump low flow is alarmed in the control room.
trol switches and position indicator lights are provided on the main control board for the low sure feedwater heater isolation valves. The heater string isolation valves are closed matically by high-high level in the associated strings fifth or sixth point heaters.
low pressure heater bypass valve has a control switch and valve position indicator lights on main control board. The valve is opened automatically by high-high level in any fifth or sixth nt low pressure feedwater heater. An annunciator is alarmed in the control room if the bypass e fails to open after an open signal has been initiated.
plant computer monitors each low pressure feedwater heater inlet and outlet temperature.
ontrol switch and indicator lights are located on the main control board for the motor-driven water pump. The pump starts automatically on low feedwater pump discharge header sure. A feedwater pump motor ammeter is provided on the main control board and at the tchgear. Indicator lights are also located at the switchgear.
unciators are alarmed on the main control board when any of the following conditions exists:
- 1. Feedwater pump discharge pressure Low.
- 2. Motor-driven steam generator feedwater pump overcurrent/auto trip.
- 3. Feedwater isolation signal.
- 4. Feedwater isolation signal bypassed.
- 5. Feedwater pump discharge pressure High.
- 6. Feedwater pump suction pressure Low.
- 7. Feedwater pumps trip on reactor trip bypassed.
following parameters are monitored by the plant computer:
- 1. Feedwater pump motor overcurrent.
- 2. Feedwater pump motor auto trip.
- 3. Feedwater pump motor breaker position.
- 4. Feedwater isolation trip signal.
- 5. Feedwater pump suction flow.
- 6. Feedwater pump suction temperature.
- 7. Feedwater pump discharge temperature.
- 8. Feedwater isolation signal bypassed.
- 9. Feedwater pumps trip on reactor trip bypassed.
peed controller automatically controls speed of the turbine-driven feed pumps.
omatic/manual control selectors are located on the main control board. Inputs to the speed
tor-operated valves are utilized as feedwater pump discharge isolation valves. Control tches and valve position indicator lights are provided on the main control board.
ation valves for the first point feedwater heaters, isolation valves for the main feedwater trol valves, and the first point feedwater heater bypass valve are motor-operated valves.
trol switches and valve position indicator lights are provided on the main control board for ual operation.
main feedwater isolation trip valves isolate the feedwater line as close to the containment cture wall as possible upon receipt of a feedwater isolation signal. Control switches with valve ition indicators are provided on the main control board for manual operation.
operated containment isolation valves are provided on each chemical feed line. The valves e automatically on receipt of a feedwater isolation signal. Control switches and valve position cator lights are located on the main control board for manual operation.
ineered safety features status lights for each chemical feed line containment isolation valve for each main feedwater stop valve are provided on the main control board.
er level in the steam generators is controlled by feedwater control valves. A separate e-element feedwater control system is provided for each steam generator. Feedwater flow is trolled automatically above approximately 25 percent load by a three-element controller using m generator water level, steam flow, and feedwater flow to control the feedwater flow control e for each steam generator. The feedwater flow control valve is pneumatically operated and is he fail closed design. The feedwater control valves close automatically on receipt of a water isolation signal. Valve position indicator lights and engineered safety features status ts for feedwater flow control valves are provided on the main control board.
h feedwater flow control valve has an inlet isolation valve and a bypass line containing a m generator level control valve. A level controller modulates the feedwater bypass control e to automatically control steam generator level when plant load is less than approximately 25 ent. This bypass level control valve closes on receipt of a feedwater isolation signal.
omatic/manual controls are provided on the main control board. Valve position indicator lights engineered safety features status lights for each level control valve are provided on the main trol board.
feedwater isolation trip signal is initiated when any of the following conditions exist:
- 1. Any steam generator High-High level.
- 2. Safety injection signal (SIS).
feedwater isolation trip valve signal is initiated when any of the following conditions exist:
- 2. Safety injection signal (SIS)
- 3. Reactor tripped coincident with a low Tavg signal present feedwater isolation trip signal causes the main feedpumps, feedpump turbines, and main ine to trip, while the feedwater isolation trip valve signal causes the feedwater isolation and trol valves and the chemical feed steam generator valves to trip. The feedwater pumps will trip approximately 15 seconds after a reactor trip to preclude system over pressurization due ump deadheading.
inimum recirculation flow control valve is provided for each steam generator feedwater
- p. A flow controller on the auxiliary condensate panel with flow indication and matic/manual features is utilized to maintain recirculation flow at a predetermined setpoint. A trol switch and valve position indicator lights are provided on the main control board for each
- e. Low feedwater pump suction flow is alarmed in the control room.
cators are provided on the main control board to monitor the following parameters:
- 2. Steam generator level program
- 3. Steam generator level
- 4. Main steam header pressure
- 5. Feedwater pumps discharge header pressure orders are provided on the main control board for the following:
- 1. Steam generator level
- 2. Feedwater flow
.8 STEAM GENERATOR BLOWDOWN SYSTEM steam generator blowdown system is shown on Figure 10.3-1.
.8.1 Design Basis steam generator blowdown system is used in conjunction with the condensate demineralizer, mical addition, and sample systems to control the chemical composition of the steam erator shell side water within specified limits (Section 5.4.2). During extended outage periods, steam generators are placed in wet layup. Wet layup connections are provided on each steam
m generator inventory. Temporary hose, which is stored outside containment during plant ration, is used to connect the wet layup skids and the wet layup connections.
steam generator blowdown system is monitored continuously for radiation in the secondary of the steam generator. It has the capability of diverting the blowdown liquid (after isolation substantial cooldown of a steam generator) to the radioactive liquid waste system in the event high radiation signal resulting from a steam generator tube leak. Main condenser inleakage is ussed in Section 10.4.1.
steam generator blowdown system isolation valves automatically close whenever a uenced safeguard signal (CDA, SIS, LOP), an auxiliary feedwater pump auto start signal (any m generator 2-out-of-4 low-low level), a reactor plant sampling system radiation high signal, n AMSAC actuation signal is present. An auto close signal can be reset at the main control rd and the valves reopened manually.
normal steam generator blowdown system flow is typically 22,800 lbm/hr per steam erator.
design pressure and temperature of the steam generator blowdown system from the steam erators up to and including the manually operated system isolation valves at the inlet of the wdown tank (V950) and the inlet of the steam generator drain pump (V975) are 1,185 psig and F (same as the design pressure and temperature of the shell side of the steam generators).
wnstream of V950, the system has a design pressure of 75 psig and a design temperature of F.
wnstream of V975 the system has a design pressure of 75 psig and a design temperature of F. The steam generator wet layup skids and hose have a design pressure of 100 psig and a gn temperature of 250F.
portion of the steam generator blowdown system up to and including the containment ation valves is Seismic Category I and designated Safety Class 2. All other piping and ipment in the steam generator blowdown system is nonnuclear safety class (NNS) and is gned to ANSI B31.1. The steam generator wet layup skids are nonnuclear safety class (NNS).
wever, they are designed and supported in such a manner that any failure will not preclude ration of safety-related equipment.
4.8.2 System Description four steam generator blowdown lines, one from each steam generator, are routed through the tainment to a common area where they penetrate the containment wall in the main steam valve ding. A containment isolation valve is located in each blowdown line and the blowdown es are located downstream of these isolation valves. The blowdown lines are joined in a mon header downstream of the blowdown valves; the header runs to the steam generator wdown tank. Blowdown tank pressure is maintained at 60 to 75 psig, slightly above the normal
he main board. Liquid in the tank flows to the condenser hotwell during closed cycle ration and to the circulating water discharge tunnel during open cycle blowdown. The wdown tank is protected against overpressurization by a relief valve.
n cycle blowdown is employed during startup and hot standby to aid in removing ionics and ds from the steam generators. During open cycle blowdown, steam from the steam generator wdown flash tank is vented to atmosphere and condensate is discharged to the circulating er discharge tunnel.
in lines are connected from the four steam generator blowdown lines downstream of the tainment isolation valves. These lines are joined in a common header that enters the steam erator drain pump. The steam generator drain pump discharge lines are connected to the densate demineralizer mixed bed waste neutralization sumps and the radioactive liquid waste em high level waste drain tanks. A hose connection is provided to direct the Steam Generator in Pump discharge to the Circulating Water Discharge Tunnel, after sampling. Drain nections on the steam generator drain the shell side water into the radioactive liquid waste em via the containment sump.
ing extended outage periods the steam generators will be placed in wet lay-up using porary hose connections off the steam generator blowdown system. The hoses will be nected to four permanently installed wet lay-up skids located inside the steam generator icles at elevation 28 feet 6 inches Each skid contains a pump, chemical addition tank, cartridge r, cation exchanger demineralizer associated piping and valves, sampling connections, sure and temperature gauges, and a combination starter. These components are sized to vide sufficient recirculation flow and chemical addition capability to maintain steam generator er chemistry within recommended limits.
.8.3 Safety Evaluation m Generator Blowdown flash tank can be drained to the circulating water discharge tunnel or main condenser, while it is being vented to the atmosphere, main condenser, or the fourth nt feedwater heater shells. Actual flow path being used will be determined by operations in ordance with chemistry and regulatory requirements. A primary to secondary leak in the steam erator which could contaminate the steam generator blowdown system and the secondary side he plant is detected by the Steam Generator Blowdown Sample Monitor which is part of the ctor Plant Sampling System (Section 9.3.2). The affected steam generator could be isolated subsequently drained after a substantial temperature reduction by the steam generator drain p to the radioactive liquid waste system.
4.8.4 Testing and Inspection steam generator blowdown containment isolation valves and the upstream piping to the steam erators are Safety Class 2. Access is provided so that the Safety Class 2 piping and valves can nservice inspected in accordance with ASME XI.
.8.5 Instrumentation Requirements steam generator blowdown isolation valves are provided with control switches and valve ition indicator lights on the main control board. The steam generator blowdown system ation valves automatically close whenever a sequenced safeguard signal (CDA, SIS, LOP), an iliary feedwater pump auto start signal (any steam generator 2/4 low-low level), a reactor plant pling system radiation high signal, or an AMSAC actuation signal is present. An auto close al can be reset at the main control board and the valves reopened manually. Engineered safety ures status lights are provided on the main control board for each valve and the plant computer nitors OPEN and CLOSED positions for each steam generator blowdown isolation valve.
eam generator blowdown outlet flow control valve is located downstream from each steam erator blowdown isolation valve. A manual control station for each valve is provided on the n control board. The valves are closed automatically by a condenser low vacuum signal or a m generator blowdown tank high pressure signal.
steam generator drain pump is provided with a control switch and indicator lights on the main trol board for manual operation.
trollers with indication and auto/manual features are located on the main control board to ntain level and pressure for the steam generator blowdown tank at predetermined set points.
steam generator blowdown tank steam to condenser isolation valve is provided with a control tch and valve position indicator lights on the main control board for manual operation.
trol switches and valve position indicator lights are provided on the main control board for the th point extraction steam inlet valves. The valves close automatically when the associated th point heater level is high.
unciators are alarmed on the main control board when the following conditions exist:
Steam generator blowdown tank level high Steam generator blowdown tank pressure high Steam generator blowdown isolation valve reset m generator blowdown tank pressure and steam generator blowdown flow are monitored by plant computer.
.9 AUXILIARY FEEDWATER SYSTEM auxiliary feedwater system is shown on Figure 10.4-6.
auxiliary feedwater system provides a supply of high-pressure feedwater to the secondary of the steam generators for reactor coolant system (RCS) heat removal following a loss of mal feedwater. It also provides a cooling source in the event of a small break loss-of-coolant dent (LOCA). Furthermore, the system is used in the event of a main steam line break, water line break, loss of power, or low-low steam generator water level conditions. Under of offsite power conditions, the auxiliary feedwater system maintains the plant at a standby dition. Under loss of all AC power (station blackout), the turbine-driven auxiliary feedwater p remains capable of auto or manual start due to the DC powered steam supply valves ction 7.3.1.1.5).
auxiliary feedwater system operates during startup and hot standby to maintain water level in steam generators.
auxiliary feedwater system also operates in conjunction with the main steam system to cool RCS to hot shutdown conditions during normal cooldown and safety grade cold shutdown rations. See Section 5.4.7 for a description of normal and safety grade cold shutdown.
auxiliary feedwater system maintains the water level in the steam generators at the ropriate level to minimize temperature increases in the RCS which also minimizes the release rimary coolant through the pressurizer relief valves.
auxiliary feedwater system from the main feedwater system up to and including the isolation es just outside containment is Safety Class 2 (Section 3.2).
demineralizer water storage tank (DWST) fill line from the water treating system, overflow
, and the heater circulating pump and piping are designed to nonnuclear safety (NNS),
ction 3.2). The safety class portions of the auxiliary feedwater system are seismically designed iscussed in Section 3.7B.3.
o half-capacity, motor-driven pumps and one full capacity turbine-driven pump are provided to ure an adequate supply of auxiliary feedwater following an accident coincident with a single ve failure.
turbine-driven pump is rated at 1,150 gpm at 2,975 foot total head (TDH) while the or-driven pumps are each rated at 575 gpm at 2,975 foot TDH. The turbine-driven pump or pair of motor-driven pumps each have sufficient capacity for sensible and decay heat removal.
turbine-driven pump and controls are powered completely independent of the motor-driven iliary feedwater pumps and controls.
redundant components are physically separated from each other by an arrangement of crete barriers designed to preclude coincident damage to equipment in the event of a tulated pipe rupture, equipment failure, or missile generation.
- 1. General Design Criterion 2, for structures housing the system and the system itself being capable of withstanding the effects of natural phenomena such as earthquakes, tornadoes, hurricanes, and floods.
- 2. General Design Criterion 4, with respect to structures housing the system and the system itself being capable of withstanding the effects of external missiles and internally generated missiles, pipe whip, and jet impingement forces associated with pipe breaks.
- 3. General Design Criterion 5, for shared systems and components important to safety being capable to perform required safety functions.
- 4. General Design Criterion 19, for the design capability of system instrumentation and controls for prompt hot shutdown of the reactor and potential capability for subsequent cold shutdown.
- 5. General Design Criterion 34, to ensure:
- a. The capability of the auxiliary feedwater system to sufficiently transfer fission product decay heat and other residual heat from the reactor core at a rate such that specified acceptable fuel design limits and the design conditions of the reactor coolant pressure boundary are not exceeded.
- b. Suitable redundancy in components, features, interconnections, leak detection, and isolation capabilities is provided to assure, under assumption of a single failure, the continued safety function regardless of the loss of either onsite, offsite, or the generating capability of both power systems.
- 6. General Design Criterion 44, to ensure:
- a. The capability to transfer heat loads from the reactor system to a heat sink under both normal operating and accident conditions.
- b. Redundancy of components so that under accident conditions the safety function can be performed assuming a single active component failure (This may be coincident with the loss of offsite power for certain events).
- c. The capability to isolate components, subsystems, or piping, if required, so that the system safety function is maintained.
- 7. General Design Criterion 45, for design provisions to permit periodic inservice inspection of system components and equipment.
leaktightness, operability and performance of active components, and capability of the integrated system to function as intended during normal, shutdown, and accident conditions.
- 9. Regulatory Guide 1.26, for the quality group classification of system components (Section 3.2).
- 10. Regulatory Guide 1.29, for seismic design classification of system components (Section 3.2).
- 11. Regulatory Guide 1.62, for design provisions made for manual initiation of each protective action.
- 12. Regulatory Guide 1.102, for the protection of structures, systems, and components important to safety from the effects of Flooding.
- 13. Regulatory Guide 1.117, for the protection of structures, systems, and components important to safety from the effects of tornado missiles.
- 14. Branch Technical Positions APCSB 3-1 and MEB 3-1, for breaks in high and moderate energy piping systems outside containment.
- 15. Branch Technical Position ASB 10-1, for auxiliary feedwater pump drive and power supply diversity.
- 16. Branch Technical Position RSB 5-1 for safety grade cold shutdown.
- 17. Selected auxiliary feedwater system minimum flow rates:
- a. Design:
The auxiliary feedwater system is designed to supply a minimum auxiliary feedwater flow in accordance with Figure 10.4-10 to four steam generators even with the occurrence of a single failure following any Condition II event; e.g., loss of normal feedwater, loss of offsite power, refer to Chapter 15 for details.
The auxiliary feedwater system is designed to supply a minimum auxiliary feedwater flow in accordance with Figure 10.4-11 to three effective steam generators even with the occurrence of a single failure following any Condition III or IV event; e.g., secondary-side rupture, small break loss-of-coolant accident, or cooldown following steam generator tube rupture, refer to Section 15.0 for details.
A better estimate loss of normal feedwater analysis is performed to support the probabilistic risk assessment reliability analysis of the auxiliary feedwater system. For the purpose of this reliability analysis, the system will supply a minimum auxiliary feedwater flow in accordance with Figure 10.4-12 to two intact steam generators even with the failure of two out of three auxiliary feedwater pumps. This capacity is provided to protect against multiple failures as well as to provide diversity between power sources.
- 18. The DWST is designed to provide sufficient water for the above transients and:
- a. hot standby condition for 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> with steam discharge to atmosphere concurrent with a total loss of offsite power;
- b. with an additional 6-hour cooldown period sufficient to reduce reactor coolant hot leg temperature to 350F to allow residual heat removal system operation; and
- c. in the event of a feedwater line break, an allowance for 30 minutes of spillage before operator action to isolate the depressurized steam generator.
The DWST is also designed to provide sufficient water for safety grade cold shutdown in accordance with BTP RSB 5-1.
- 19. NRC NUREG-0611 recommendation GL-3 which requires at least one auxiliary feedwater system pump and its associated flow path and essential instrumentation to automatically initiate auxiliary feedwater flow and be capable of being independent of any alternating current power source for at least two hours.
- 20. Appendix R to 10 CFR 50 fire protection program requirements for mechanical components and instrumentation required for cold shutdown.
- 21. NRC Generic Letter 80-020 dated March 10, 1980, concerning the Actions Required from Operating License Applicants of Nuclear Steam Supply Systems Designed by Westinghouse and Combustion Engineering Resulting from the NRC Bulletins and Orders Task Force Review Regarding the Three Mile Island Unit 2 Accident.
- 22. Appendix A to 10 CFR 50 General Design Criterion 57, for design provisions to ensure that each line that penetrates primary reactor containment and is neither part of the reactor coolant pressure boundary nor connected to the containment atmosphere shall have at least one containment isolation valve which shall be either automatic, or locked closed, or capable of remote manual operation.
system is located in both the ESF and the containment buildings, which are both Seismic egory I structures. The DWST is located in the yard with piping that is run underground to the building.
auxiliary feedwater system consists of two motor-driven auxiliary feedwater pumps, one ine-driven auxiliary feedwater pump and the associated piping and valves necessary to nect the DWST to the pump suctions, and the pump discharges to the feedwater system. The ST is provided with a heater cycle consisting of a recirculating pump and electric heater ch automatically maintains the water temperature at or above 40F. The auxiliary feedwater em is shown on Figure 10.4-6.
o half size motor-driven auxiliary feedwater pumps and one full size turbine-driven auxiliary water pump are provided. Sufficient auxiliary feedwater for plant cooldown can be supplied ither the turbine-driven pump or the pair of motor-driven pumps. For the better estimate loss ormal feedwater analysis performed to support the reliability analysis, a single motor-driven iliary feedwater pump is also capable of supplying an auxiliary feedwater flow in accordance h Figure 10.4-12 to two intact steam generators. This capacity is provided to protect against tiple failures as well as to provide diversity between power sources.
steam generator auxiliary feedwater pumps are used as an emergency source of feedwater ply to the steam generators. The pumps are required to ensure safe shutdown in the event of of power or functions as an Engineered Safeguards System to remove core decay heat. The ps are on standby service during normal plant operation.
motor-driven steam generator auxiliary feedwater pumps start automatically whenever any of following conditions occur:
- 1. Loss of power or (LOP)
- 2. Safety injection signal (SIS).
- 3. Containment depressurization actuation signal (CDA).
- 4. Two-of-four low-low water level signals in any one steam generator.
motor-driven (Train A) steam generator auxiliary feedwater pump is isolated from AUTO t and sequencer signals when in LOCAL control to facilitate safe shutdown from a remote tdown location following a fire as described in Section 6.2.11 of the Fire Protection Evaluation ort.
motor-driven auxiliary feedwater pumps take suction from the condensate storage tank to ntain steam generator water levels during startup and hot standby.
-start signal, or loss of emergency 125 VDC power.
steam generator auxiliary feedwater pumps start automatically or can be started manually m the main control board. In addition, the turbine driven pump can be started manually from auxiliary shutdown panel by opening the turbine pump steam supply valves (Section 7.4.3.1).
motor driven pumps can be manually started from their switchgear.
auxiliary feedwater pump turbine drive receives steam from the main steam system ction 10.3.2) piping through the steam generator auxiliary feedwater pump turbine steam ply header. The source of steam is not interrupted by a loss of AC power (station blackout).
en the turbine driven pump is started, it is initially supplied with 990 psia steam. As the reactor ls and the steam pressure decreases below approximately 615 psia, the turbine drive speed reases. However, sufficient pump capacity is available until the steam pressure to the turbine t decreases to 120 psia. Auxiliary feedwater flow for further cooling, if required, can be vided by one motor-driven auxiliary feedwater pump. When reactor coolant temperature reases to 350F, at which condition the residual heat removal system is typically placed into ice (Section 5.4.7), the auxiliary feedwater system is manually secured.
tive steam is provided to the turbine driven auxiliary feedwater (TDAFW) pump from A, B, D steam generators (3RCS*SG1A/B/D). A three inch supply line comes off the main steam from each of these steam generators and tie into a common steam supply header to the AFW pump. Each of the three steam supply lines is provided with a normally closed, Fail n, air operated valve which isolates the auxiliary feedwater turbine from the main steam em during normal operation (3MSS*AOV31A/B/D). Each branch line is also provided with a n strainer/oriface (venturi) (3DTM-STR2A/B/D and 3DTM-RO70A/B/D), to remove any m which has condensed in the piping, upstream of the closed AOV. To further eliminate rces of condensation in the TDAFW Pump steam supply header, a condensate collection dpipe is provided in the common steam supply header, downstream of the isolation valves.
s standpipe is provided to collect steam which has leaked through the closed isolation valves condensed in the down stream piping.
h motor-driven steam generator auxiliary feedwater pump receives power from a separate undant emergency electrical bus.
h AFW pump is provided with a continuously open recirculation line back to the DWST. Each rculation line is furnished with a restriction orifice (3FWA*RO24A/B/C) which is sized to ass a safe minimum quantity of water. The turbine-driven AFW pump recirculation line has a pm nominal hydraulic design value. Each motor-driven AFW pump recirculation line has a pm nominal hydraulic design value. The continuously open recirculation flow path design ure eliminates the need for an active instrumentation and control system to open the rculation path on a low pump flow condition. Thus, providing a reliable recirculation system ensures minimum pump flow requirements are satisfied. Cooling water, required for pump turbine bearing oil cooling, is supplied from the first stage casing of each pump. This vides a guaranteed source of cooling water under all conditions.
acity to satisfy the design basis of the auxiliary feedwater system. The total tank capacity udes unusable volume necessary to prevent vortexing at the auxiliary feedwater pump suction zles. Makeup is provided to the DWST from the water treating system (Section 9.2.3).
additional source of water is provided to each auxiliary feedwater pump suction by the densate storage tank (Section 9.2.6). This source is not safety related. The normally closed operated valves connecting the condensate storage tank and each motor-driven auxiliary water pump suction are closed automatically on receipt of an SIS, CDA, auxiliary feedwater p AUTO start (any steam generator 2-out-of-4 low-low level), AMSAC, or LOP signal. The ine-driven pump is provided with an administratively-controlled locked closed valve.
omestic water system connection is provided for DWST replenishment. A removable spool e must be installed to use this design feature. This spool piece is provided, in lieu of manent piping, to preclude inadvertent domestic water introduction into the steam generators.
.5 inch diameter fire hose connection fitting for use at the domestic water spool piece location lso available for installation to support DWST replenishment from the fire water system.
ervice water system to auxiliary feedwater pump suction cross-tie design feature is provided.
wever, this cross-tie design feature is only used as an option of last resort due to seawaters terious impact on steam generator tube integrity. Before the auxiliary feedwater pumps can suction from the service water system, spool pieces must be installed. These spool pieces are vided, in lieu of permanent piping, to preclude inadvertent seawater introduction into the m generators.
dwater from the steam generator auxiliary feedwater pumps is pumped to each steam erator through normally open control valves which may be throttled during auxiliary water pump operation during startup, shutdown, and standby. Flow is monitored in each line necting to the feedwater system. Each control valve is manually adjusted from the control m as dictated by the steam generator water level and auxiliary feedwater flow rate. The control es can also be manually adjusted from the auxiliary shutdown panel. In the event of a loss of er, these valves remain open.
iliary feedwater flow to the steam generators is limited by flow venturis located in each iliary feedwater line. These venturis are sized to cavitate in order to maintain the minimum uired flows to the intact steam generators and to prevent runout flow to a depressurized steam erator.
auxiliary feedwater is discharged to the steam generators through a connection in each main water line inside the containment structure and downstream of the main feedwater check es. This will prevent loss of auxiliary feedwater, should a main feedwater line rupture tream of the main feedwater check valve. The design parameters for the auxiliary feedwater ps are listed in Table 10.4-4.
nse-in-depth design features that are available for coping with an extended loss of AC power AP) event. The location and interconnections of these BDB AFW FLEX suction and harge connections are shown on Figure 10.4-6, Sheet 2.
4.9.3 Safety Evaluation h motor-driven steam generator auxiliary feedwater pump receives power from one of the rgency AC buses. One pump is available at all times in the event of the loss of one emergency
. The turbine-driven pump is sufficiently sized to be used for residual heat removal as long as quate steam is available. The turbine-driven pump receives control power from DC sources
. An ample supply of steam for the turbine-driven steam generator auxiliary feedwater pump vailable, provided at least one steam generator and its associated main steam loop from the m generator to the main steam isolation trip valve are intact. The reactor coolant temperature pressure will be reduced to a level where the residual heat removal system may be used ore the main steam pressure is no longer adequate to operate the turbine-driven pump. The two or-driven pumps operating together are sized to provide sufficient auxiliary feedwater to cool plant until the residual heat removal system can be initiated.
h MDAFW pump flowpath is independent from the other and feeds two steam generators.
o intact steam generators are required for decay heat removal. The TDAFW pump is redundant he two MDAFW pumps in that it feeds all four steam generators. Controls are provided on the iliary shutdown panel or the Emergency Switchgear to ensure that the reactor may be brought hot standby condition, should the control room become uninhabitable.
amount of water provided in the DWST is sufficient to hold the unit at hot standby for up to 7 rs and to provide a cooldown period of 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, concurrent with a total loss of offsite power, at ch time the residual heat removal system will be initiated. This amount of water is also icient for safety grade cold shutdown operations.
amount of flow to any steam generator is limited by cavitating venturis located in the iliary feedwater line to each steam generator. These elements are passive and are sized to itate at a flow which will allow sufficient cooling water to each steam generator. Because itation occurs, the flow will remain at the venturis rated flow regardless of the downstream sure. Therefore, these elements will limit flow to a depressurized steam generator thus venting the pumps from operating near runout.
venting runout flow provides a more suitable condition for the pumps to remain operable for nded periods.
e DWST level cannot be maintained above the required usable volume, the reactor will be ed in a shutdown condition. The leak will be located, isolated, and repaired. All pumps, es, and piping will be operable, and the DWST will contain the minimum required usable ume prior to taking the reactor critical.
RMIS evaluation of the probability of failure of the DWST vent above the DWST enclosure er a tornado missile has been completed and found to meet the requirements of SRP tion 3.5.2 and Section 2.2.3. See Section 9.5.8.3 for TORMIS limiting assumptions and eptions.
condensate storage tank provides a non-safety grade backup source of water for the auxiliary water pumps. DWST design features include non-safety grade water treating system and estic water system piping connections that may be used for DWST replenishment, if required.
.5 inch diameter fire hose connection fitting is also available for installation to support DWST enishment via the fire water system. A safety grade service water system to auxiliary water pump suction cross-tie design feature is available. However, this is only used as an on of last resort due to seawaters deleterious impact on steam generator tube integrity.
receipt of a sequenced safeguard signal auxiliary feedwater pump AUTO start signal (any m generator 2-out-of-4 low-low level), or AMSAC, the two motor-driven steam generator iliary feedwater pumps start and supply cooling water to the steam generators through parallel paths to remove the core sensible and decay heat. Each of the motor driven pump flowpaths dependent from the other and feeds two steam generators. Two intact steam generators are uired for heat decay removal. The turbine driven AFW pump is redundant to the two motor en AFW pumps in that it feeds all four steam generators.
motor-driven auxiliary feedwater pumps may be in normal use to support steam generator ntory maintenance during startup, shutdown, and hot standby. Normal auxiliary feedwater use urs only at below 10 rated thermal power. When the auxiliary feedwater system is in normal plant operators may partially or fully close control valves 3FWA*HV31A/B/C/D to control m generator water levels. These control valves do not receive an auto-open signal given an iliary feedwater auto-initiation signal. In this case, manual operator action is credited to open e control valves and to support auxiliary feedwater system operability. This manual action can ccomplished in the control room. For a reactor trip at low thermal power levels, the lower S decay heat and high steam generators thermal capacitance (heat removal capability) vides an adequate time for operators to manually open these control valves, if required. During mal auxiliary feedwater system use, the turbine driven auxiliary pump feedwater control es (3FWA*HV32A/B/C/D and 3FWA*HV36A/B/C/D) are maintained fully open. The or-driven auxiliary feedwater pumps may be aligned to take suction from the nonsafety grade densate storage tank during these evolutions. Pump suction automatically switches to the ST, including isolation from the condensate storage tank, in the event to an SIS, LOP, CDA, of four low-low water level in any one steam generator, or AMSAC signal.
uming a single failure, either the two motor-driven, or the turbine-driven auxiliary feedwater p are of sufficient capacity to remove the sensible and decay heat from the reactor core. The em supplies enough water to the steam generators to facilitate a safe shutdown condition and ntain it until the residual heat removal system is actuated. Above 10 power, system also vers sufficient auxiliary feedwater to the steam generators, starting at 60 and 90 seconds after
liability evaluation was performed for the auxiliary feedwater system to determine the ntial for system failure. The method of evaluation was similar to that described in REG-0611, Appendix III. This analysis included the calculation of the systems unavailability g fault tree logic and an investigation of the potential for system failures under various loss of water transient conditions. A detailed failure mode and effect analysis of the system electrical trols was also completed in accordance with Regulatory Guide 1.70, Paragraph 7.3.2.
analysis of the auxiliary feedwater system showed the reliability to be in accordance with eria defined in SRP Section 10.4.9. Implementation of 10 CFR 50.65 ensures continuous nitoring of auxiliary feedwater system reliability and compliance with the SRP criteria.
investigation did not reveal any significant potential sources for common cause failures. It uld be noted that the fault tree analysis considered various multiple failures, including rational errors, which might result in a common cause single failure. Physical separation was considered as a source of common cause failures. The most likely components were the ps. Each pump is located in a separate projectile-protected cubicle. The air-conditioning units MCCs for the turbine-pump steam supply valves are located in separated cubicles on the floor ve the pumps. The portions of the system required for safety meet Seismic Category I design uirements. Redundant electrical trains are provided for pump and valve controls.
4.9.4 Inspection and Testing Requirements piping in the auxiliary feedwater system was hydrostatically tested during construction, and ctive system components, such as pumps, valves, and controls, are functionally tested odically.
steam generator auxiliary feedwater pumps, their drives, and the pump discharge valves are ed at intervals indicated by Technical Specifications. Each of the three pumps will be tested vidually. An independent check of the system valve lineup will be performed after each test r to restoring the system to operational status. An incorrect valve lineup will be displayed on ESF status panel. Steam is admitted to the turbine drive, and the motor drives are energized ng these tests. Flow is established by recirculating auxiliary feedwater to the DWST.
owing the completion of the test, the auxiliary feedwater pumps are shut off, and the or-operated shutoff valves leading to the main feedwater lines are opened. Pump discharge sure is indicated on the main control board for each auxiliary feedwater pump.
system components are tested and inspected in accordance with the applicable codes.
odic sampling of the water in the DWST is provided in the tank heating cycle. The samples tested for oxygen content and pH.
rvice inspection of Safety Class 2 and 3 portions of the auxiliary feedwater system are ormed as required by the ASME Code,Section XI (Section 6.6).
DWST is provided with redundant level indication on the main control board and on the iliary shutdown panel. High, low, and low-low (DWST) level alarms are provided on the main trol board.
WST heater and heater pump are utilized to maintain water temperature above freezing.
trol switches and indicator lights are provided locally and on the turbine plant sample sink el. The circulating pump starts automatically when DWST water temperature is 35F or the ulating pump suction temperature is 50F. The tank heater operates to maintain the tank tents above 40F. DWST low temperature (less than 35F) is alarmed on the main control rd.
ation valves in the DWST circulating pump suction line are provided with control switches valve position indicator lights on the main control board. The valves are closed automatically safety injection signal or loss of power signal. Engineered safety features status lights on the n control board indicate when the valves are closed. The open and closed positions are nitored by the plant computer.
trol switches and indicator lights are provided on the main control board and at the switchgear each auxiliary feedwater motor driven pump. Remote local control selector switches are vided at the switchgear; an alarm is activated on the main control board when LOCAL control elected. Pump motor ammeters are provided on the main control board and at the switchgear.
ineered safety feature status lights indicate on the main control board when an auxiliary feed p motor is started. The auxiliary feed pump motors are started automatically by two out of low-low levels in any steam generator, by an AMSAC actuation signal or by an engineered ty features actuation signal. This signal is initiated whenever an SIS, CDA, or LOP signal is ent. The ESF actuation signal (Section 7.3) is sequenced on when an LOP signal exists. The n A motor-driven auxiliary feedwater pump is isolated from the AUTO start signal when it is OCAL control.
trol switches and valve position indicator lights are provided on the main control board and he auxiliary shutdown panel (ASP) for the turbine-driven auxiliary feedwater pump steam ply valves. LOCAL/REMOTE control transfer switches are located on the transfer switch el (TSP); an alarm is activated on the main control board when LOCAL control is selected.
n and close valve positions are monitored by the plant computer. The steam supply valves are ned automatically by two out of four low-low levels in two of four steam generators or by an SAC actuation signal. Upon loss of 125V DC, these valves fail open.
auxiliary feedwater pump turbine steam supply nonreturn valves have control switches and e position indicator lights on the main control board for manual operation.
auxiliary feedwater isolation valves are provided with control switches and valve position cator lights on the main control board and on the ASP. REMOTE/LOCAL control transfer tches are located on the TSP; an alarm is activated on the main control board when local trol is selected.
following instrumentation and controls are located on the main control board:
Indicators Each auxiliary feed pumps suction pressure Each auxiliary feed pumps discharge pressure Auxiliary feedwater flow to each steam generator DWST fill line flow DWST level (2)
Auxiliary feed pump turbine speed Turbine-driven auxiliary feedwater pump steam pressure Ammeter for the motor-driven auxiliary feedwater pump Auxiliary feedwater control valve demand signal Annunciators Auxiliary feed pump 1A suction pressure low Auxiliary feed pump 1B suction pressure low Auxiliary feed pump 2 (TDAFWP) suction pressure low Auxiliary feed pump 1A lube oil pressure Low Auxiliary feed pump 1B lube oil pressure Low Auxiliary feed pump 1A motor winding temperature High Auxiliary feed pump 1B motor winding temperature High Control for auxiliary feedwater isolation valve in local control DWST level High DWST level Low DWST level Low-Low DWST temperature Low Auxiliary feedwater system bypassed (TRAIN A)
Auxiliary feedwater pump motor AUTO TRIP/OVERCURRENT Auxiliary feedwater system bypassed (TRAIN B)
Auxiliary feed pump turbine speed in remote control Motor-driven auxiliary feedwater pump local control Control Switches Motor-driven auxiliary feedwater START/STOP Auxiliary feedwater control valves OPEN/CLOSE Auxiliary feedwater pump steam supply valve OPEN/CLOSE Controller Speed control for auxiliary feed pump turbine
Auxiliary feedwater flow to each steam generator (indicators for steam generators 1A and 1D are provided with umbilical type connections to isolate the normal source device and connect an alternate source device to facilitate safe shutdown from a remote shutdown location following a fire as described in Section 6.2.11 of the Fire Protection Evaluation Report).
DWST level (2) following parameters are monitored by the plant computer:
Auxiliary feedwater pump suction pressure Auxiliary feedwater pump motor breaker position Auxiliary feedwater pump motor winding temperature Auxiliary feedwater pump motor bearing temperature Auxiliary feedwater control valve open and closed positions Auxiliary feedwater pump discharge pressure Auxiliary feedwater pump motor overcurrent Auxiliary feedwater pump motor auto trip Auxiliary feedwater pump discharge temperature High Auxiliary feedwater pump ventilation system bypassed Auxiliary feed pump motor control circuit open Auxiliary feed pump motor control switch in Pull-To-Lock position Auxiliary feedwater system bypassed (TRAIN A)
Turbine-driven auxiliary feedwater pump steam pressure Turbine-driven auxiliary feedwater pump trip valve Turbine steam supply valve open and closed positions Auxiliary turbine-driven feed pump bypassed (TRAIN B)
Auxiliary feedwater flow to each steam generator
.10 AUXILIARY STEAM AND ASSOCIATED SYSTEMS Unit 3 auxiliary steam system is designed to supply steam to and carry condensate from ous heating and processing equipment associated with both Unit 2 and Unit 3 during normal t operations. The Unit 3 auxiliary steam and associated systems are shown on Figure 10.4-9.
.10.1 Design Basis Unit 3 auxiliary steam and associated systems (auxiliary condensate, auxiliary boiler water and condensate, auxiliary boiler blowdown and auxiliary boiler steam) are non-safety ted systems and are designed in accordance with the ANSI Code for Pressure Piping, ANSI
em is presented in the MP-2 FSAR.
Unit 3 auxiliary boiler steam and auxiliary steam systems are designed to supply steam to the ting and processing equipment listed below:
Auxiliary boiler deaerator (6 psig)
Regenerant evaporator reboiler (50 psig) (Removed from Service)
Boron evaporator reboiler (100 psig)
Degasifier feed preheater (150 psig)
Waste evaporator reboiler (100 psig) (removed from service)
Steam to water heat exchangers (plant heating) (150 psig)
Boric acid batch tank (15 psig)
Caustic dilution water heater (150 psig)
Containment vacuum ejector (150 psig)
Steam jet air ejector units (150 psig)
Turbine gland seal steam system (150 psig)
Main feed pump turbine test (150 psig)
Auxiliary feed pump turbine test (150 psig)
Primary grade water system (150 psig)
Unit 2 auxiliary steam system (50 psig) auxiliary condensate system associated with the Unit 3 auxiliary steam system is designed to rn the condensed steam used by some of this equipment to the condensate system if the iliary boilers are not operating, or to the auxiliary boiler deaerator if the auxiliary boilers are rating.
auxiliary boiler feedwater and condensate system provides condensate from the auxiliary densate system and condensate storage tank to the auxiliary boilers for the generation of iliary steam when main steam is not available during plant startup, shutdown, or extended ages.
ing normal plant operations when main steam is available and the auxiliary boilers are not in the auxiliary feedwater and condensate system collects the auxiliary condensate and pumps it he condensate storage tank.
.10.2 System Description auxiliary steam system is supplied by the main steam system (Section 10.3) through a sure reducing valve, when the unit is in operation, and by the auxiliary boilers at all other es.
rates at 150 psig and the Unit 2 auxiliary steam system operates at 50 psig a pressure reducing e station, including isolation and relief valves are installed.
pressure reducing valve station consists of two pressure reducing valves installed in parallel supplied with upstream and downstream isolation valves. The isolation valves are located at crosstie between Unit 3 auxiliary steam system supply to Unit 2. The pressure reducing valve ion is located in the Condensate Polishing facility in line 3-ASS-008-15-4 downstream of ation valve 2-ASS-3. This pressure reducing valve station regulates Unit 3 auxiliary steam em mass flow to Unit 2. The pressure reducing valve station is comprised of a 2 inch pressure ucing valve, four inch pressure reducing valve, isolation valves, pressure sensing line, and a l operated controller. This configuration allows the two inch valve to regulate auxiliary steam em mass flow from between 0 and 8,999 lb/hr as long as the downstream pressure sensing line cates an operating pressure of 50 psig or higher. When the downstream operating pressure s below 50 psig, the four inch pressure valve will modulate to allow up to the additional uired 35,682 lb/hr auxiliary mass flow required for Unit 2 use.
afety relief valve located downstream of the pressure reducing valve station provides nstream pressure protection for Unit 2 system piping and connected equipment.
condensate from the degasifier feed preheater, the boron evaporator reboiler, and the waste porator reboiler (removed from service) flow through their own conductivity analyzer and a e-way valve. In case of a leak in any of these heat exchangers, its associated conductivity lyzer will detect a high conductivity in the condensate, secure steam to the unit, and then rt the condensate coming from the unit via the three-way valve to a contaminated sump, eby preventing possible contamination of the auxiliary condensate/auxiliary steam systems.
er normal conditions, the condensate from these units flows to the auxiliary condensate flash of the auxiliary condensate system where a portion of it flashes to produce additional low sure (15 psig) steam for use as needed in the boric acid batch tank. That portion of the fluid ring the auxiliary condensate flash tank which does not flash, plus condensate from the boric batch tank jacket, is collected in the auxiliary condensate tank. As a further precaution, if the densate is indicated as being radioactive by the radiation monitor located in the condensate harge line of the auxiliary condensate flash tank, the condensate is diverted via a three-way e to the auxiliary building sump. From there, it is pumped to the radioactive liquid waste em for further processing. During normal operation, the condensate collected in the auxiliary densate tank is pumped by one of two, 100 percent capacity auxiliary condensate pumps to the densate surge tank in the condensate system. When the auxiliary boiler is operating, this iliary condensate is pumped to the auxiliary boiler deaerator.
ddition to condensate return line from the Unit 2 auxiliary feedwater surge tank is routed to Unit 3 auxiliary boiler deaerator, when the Unit 3 auxiliary boilers are supplying auxiliary m, or to the Unit 3 condensate surge tank, when Unit 3 main steam is supplying auxiliary m.
densate system.
wdown from the auxiliary boilers flows to the auxiliary boiler blowdown tank. The auxiliary er room floor drains are pumped forward to the auxiliary boiler blowdown tank. That portion he blowdown which flashes into steam passes through the auxiliary boiler blowdown vent denser. Noncondensable gases are vented to the atmosphere from the vent condenser, and the densate is drained back to the auxiliary boiler blowdown tank. The vent and drain from the iliary boiler blowdown tank is pumped to the condensate demineralizer system, downstream he etched disc filter. The fluid is then discharged to the circulating water system.
en main steam is not available and the auxiliary boilers are being used, system water level is trolled in the auxiliary boiler deaerator. On a high deaerator water level, water is bled from the iliary boiler feedwater pumps discharge to the condensate surge tank. On a low deaerator er level, water is pumped from the condensate surge tank via the auxiliary boiler condensate eup pumps to the deaerator.
.10.3 Safety Evaluation nt process steam is a significant Unit 3 requirement during normal and shutdown operation.
t 3 auxiliary steam is supplied to Unit 2 from the Unit 3 auxiliary boilers or the Unit 3 main m system. The Unit 3 auxiliary boilers are each rated for 60,000 lb/hr of auxiliary steam. The e of Connecticut Department of Environmental Protection air permit limits the auxiliary boiler consumption rate, which in turn limits the operating capacity of each auxiliary boiler to roximately 53,333 lb/hr steam flow. The Unit 3 auxiliary steam system or Unit 3 main steam em is capable of supplying all of the Unit 2 and Unit 3 steam use requirements as well as the m needs for the sites fire water storage tanks freeze protection during winter conditions (with t heating) and during summer conditions (without plant heating). Temporary electric heating been installed while the Auxiliary Steam supply is unavailable to the Fire Water tanks.
escription of the modes of operation which are available to allow Unit 3 to satisfy auxiliary m demands include the following.
- 1. Unit 3 auxiliary boilers operating only.
- 2. Parallel operation allowing for the Unit 3 main steam and Unit 3 auxiliary boilers to operate.
- 3. Unit 3 main steam operating only.
rder to prevent a hostile environment from an auxiliary steam pipe break (high temperature pressure) in the auxiliary building from damaging equipment, two quick-acting, air-operated ation valves are located in the auxiliary steam lines in the turbine building as close as possible he penetration into the auxiliary building. These valves are actuated by a temperature nitoring system located throughout the auxiliary building.
er installation of the auxiliary steam and its associated systems, all equipment and devices are jected to performance tests to demonstrate proper operation of the component. Visual ection is conducted at regular intervals and following system maintenance to confirm normal ration of the system.
.10.5 Instrumentation Requirements iliary steam supplied from the main steam system is maintained at 150 psig by a pressure trol valve modulated by a pressure indicating controller. The controller has an TO/MANUAL control selection on the main control board. High and low auxiliary steam sures are alarmed on the main control board.
steam jet air ejector isolation valves have control switches and valve position indicator lights he main control board. The steam jet air ejector isolation valves close automatically on receipt loss of power (LOP) signal. The plant computer monitors the close position of each isolation e.
auxiliary condensate flash tank is continuously monitored by a process radiation monitor ction 11.5). Control valves supplying auxiliary steam to the degasifier feed preheater, the on evaporator reboiler, and the waste evaporator reboiler are tripped closed on receipt of a high ductivity signal. Aux steam is no longer supplied to the waste evaporator reboiler since the oiler is removed from service.
ree-way air operated valve is located in the condensate line from the condensate flash tank to auxiliary condensate tank. Condensate is diverted to the auxiliary building sump upon receipt high radiation signal from the process radiation monitor installed upstream of the divert e.
n receipt of a high conductivity signal, the three-way air operated valves divert condensate m the waste evaporator reboiler to reactor plant aerated drains; condensate from the boron porator reboiler and from the degasifier feed preheater is diverted to the auxiliary building
- p. Condensate no longer exits the waste evaporator reboiler since the reboiler is removed m service.
cal level indicating controller and level valve automatically maintain water level in the iliary condensate flash tank at a predetermined level.
trol switches and indicator lights on the auxiliary condensate panel are provided for the iliary condensate pumps. A LEAD/FOLLOW switch selects the lead and follow auxiliary densate pumps. The pumps are started and stopped at appropriate levels by level switches on auxiliary condensate tank. High and low auxiliary condensate tank levels are alarmed in the trol room.
ductivity at any sample point is alarmed in the control room and at the local panel for the ciated equipment.
.11 REFERENCES FOR SECTION 10.4
PERFORMANCE CHARACTERISTICS System Design and Performance Characteristics culating Water System Six wet pit vertical circulating water pumps each deliver a flow of 152,000 gpm at a TDH of 27 feet. All six pumps are normally in operation.
veling Screen Wash and Two wet pit vertical screenwash pumps each deliver a flow sposal System of 4,000 gpm at a TDH of 235 feet. One pump is normally in operation when the traveling water screens are operating.
cuum Priming System Two horizontal, liquid ring, centrifugal station vacuum priming pumps each remove an air volume of 1,675 cfm at a vacuum of 26 inches Hg. Two horizontal, liquid ring, centrifugal yard vacuum priming pumps each remove an air volume of 540 cfm at a vacuum of 10 inches Hg. One station pump and one yard pump are normally in operation when the circulating water system is operating.
TABLE 10.4-2 DESIGN DATA CONDENSATE POLISHING SYSTEM mber of Vessels 8 (7 normally operating) ign Flow, total (gpm) 19,775 ign Flow (gpm/unit) 2,825 ign Pressure (psig) 700 ign Temperature (F) 175 mineralizer Type Mixed Bed ion Resin Volume (cubic feet/unit) Approximately 80 on Resin Volume (cubic feet /unit) Approximately 120
PARAMETERS NDENSATE PUMPS sign Parameter:
Capacity at design rating (gpm) 10,890 Minimum flow requirements (gpm):
Intermittent 2,700 Continuous 6,000 Pump efficiency at design rating (%) 85.5 Required NPSH at design rating (ft) 20.5 TDH at design rating (ft) 1,215 Bhp at design rating (hp) 3,907 Shutoff head (ft) 1,590 terial:
Discharge column ASTM A-515 Gr. 65, 70, and A-36 Suction barrel ASTM A-515 Gr. 65, 70, and A-36 First stage impeller ASTM A-351 Gr. CF-8M EAM GENERATOR FEEDWATER PUMPS Capacity at design rating (gpm) 19,865 Minimum continuous flow requirements (gpm): 5,000 Pump efficiency at design rating (%) 85 Required NPSH at design rating (feet)
If original OEM impeller installed 255 If Ingersoll-Dresser Pump replacement 275 impeller installed TDH at design rating (feet) 2,050 Bhp at design rating (hp) 10,672 Shutoff head (feet) 2,850 terial:
Outer casing and head flange ASTM A-105-70 ASTM A-296, Gr. CA-6NM
Impeller If original OEM impeller installed ASTM A-296, Gr. CA-6NM If Ingersoll-Dresser Pump replacement ASTM A-487, Gr. CA-6NM impeller installed
otor-Driven Auxiliary Feedwater Pump Safety class 3 Seismic class Category 1 Design flow, including recirculation (gpm) 575 Rated total head (ft) 2,975 NPSH required at rated flow (ft) 20 Shutoff head at rated flow (ft) 3,475 Minimum required recirculation (gpm)
- 45 Efficiency at design point (percent) 76.0 Required Bhp at rated flow 568 Design speed (rpm) 3,560 Pump design Horizontal, split-casing centrifugal pump, 10 stage Casing material ASME SA-216, WCB Impeller material ASTM A743 GR. CA6NM Suction and discharge nozzle material ASME SA-216, WCB Weight (pump, base, driver) 9,920 lb rbine-Driven Auxiliary Feedwater Pump Safety class 3 Seismic class Category I Design flow including recirculation (gpm) 1,150 Rated total head (ft) 2,975 NPSH required at rated flow (ft) 22 Minimum required recirculation (gpm)
- 90 Efficiency at design point (percent) 78.0 Required Bhp at rated flow 1,108 Design speed (rpm) 4,400
Pump design Horizontal, centrifugal pump, 7 stage Casing material ASME SA-216, WCB Impeller material ASTM A743 GR. CA6NM Suction and discharge nozzle material ASME SA-216, WCB Weight (pump, base, driver) 10,160 lb xiliary Feedpump Motors Synchronized speed (rpm) 3,560 Horsepower 600 Motor electrical requirements (V / Hz / phase) 4,000 / 60 / 3 Service factor 1.0 xiliary Feedpump Turbine Rated speed (rpm) 4,400 Potential maximum hp rating 1,400 Rated horsepower (at 1,195 psia, saturated 1,108 turbine inlet conditions)
Throttle flow (at 1,195 psia, sat) 64,300 lb/hr Nominal hydraulic design value for the minimum flow recirculation line which discharges back to DWST.
otor-Driven Auxiliary Feedwater Pump Safety class 3 Seismic class Category 1 Design flow, including recirculation (gpm) 575 Rated total head (ft) 2,975 NPSH required at rated flow (ft) 20 Shutoff head at rated flow (ft) 3,475 Minimum required recirculation (gpm)
- 45 Efficiency at design point (percent) 76.0 Required Bhp at rated flow 568 Design speed (rpm) 3,560 Pump design Horizontal, split-casing centrifugal pump, 10 stage Casing material ASME SA-216, WCB Impeller material ASTM A743 GR. CA6NM Suction and discharge nozzle material ASME SA-216, WCB Weight (pump, base, driver) 9,920 lb rbine-Driven Auxiliary Feedwater Pump Safety class 3 Seismic class Category I Design flow including recirculation (gpm) 1,150 Rated total head (ft) 2,975 NPSH required at rated flow (ft) 22 Minimum required recirculation (gpm)
- 90 Efficiency at design point (percent) 78.0 Required Bhp at rated flow 1,108 Design speed (rpm) 4,400
Pump design Horizontal, centrifugal pump, 7 stage Casing material ASME SA-216, WCB Impeller material ASTM A743 GR. CA6NM Suction and discharge nozzle material ASME SA-216, WCB Weight (pump, base, driver) 10,160 lb xiliary Feedpump Motors Synchronized speed (rpm) 3,560 Horsepower 600 Motor electrical requirements (V / Hz / phase) 4,000 / 60 / 3 Service factor 1.0 xiliary Feedpump Turbine Rated speed (rpm) 4,400 Potential maximum hp rating 1,400 Rated horsepower (at 1,195 psia, saturated 1,108 turbine inlet conditions)
Throttle flow (at 1,195 psia, sat) 64,300 lb/hr Nominal hydraulic design value for the minimum flow recirculation line which discharges back to DWST.
PERFORMANCE REQUIREMENTS (1) mber of condenser tubes 42,978 ndenser tube material Titanium (ASTM B-338 Gr. 2) at transfer area - ft2 503,304 erall condenser dimension - feet 40 feet-0 inches (tube length) mber of passes 1 twell capacity - gal 83,350 nimum heat transfer - Btu/lb-stm 979 rmal steam flow - lb/hr 8,376,175 rmal cooling water temperature, F Range: 33-80 ximum cooling water temperature,F Range: 33-80 rmal exhaust steam temperature, F
- a. With no turbine bypass flow 97.8
- b. With maximum turbine bypass flow 129.2 Performance characteristics based on 55.5F CWS.
TABLE 10.4-7 DELETED BY PKG FSC MP3-UCR-2010-012 figure indicated above represents an engineering controlled drawing that is Incorporated by erence in the MPS-3 FSAR. Refer to the List of Effective Figures for the related drawing ber and the controlled plant drawing for the latest revision.
WATERBOX PRIMING figure indicated above represents an engineering controlled drawing that is Incorporated by erence in the MPS-3 FSAR. Refer to the List of Effective Figures for the related drawing ber and the controlled plant drawing for the latest revision.
SEAL AND EXHAUST (SHEETS 1-2) figure indicated above represents an engineering controlled drawing that is Incorporated by erence in the MPS-3 FSAR. Refer to the List of Effective Figures for the related drawing ber and the controlled plant drawing for the latest revision.
figure indicated above represents an engineering controlled drawing that is Incorporated by erence in the MPS-3 FSAR. Refer to the List of Effective Figures for the related drawing ber and the controlled plant drawing for the latest revision.
figure indicated above represents an engineering controlled drawing that is Incorporated by erence in the MPS-3 FSAR. Refer to the List of Effective Figures for the related drawing ber and the controlled plant drawing for the latest revision.
figure indicated above represents an engineering controlled drawing that is Incorporated by erence in the MPS-3 FSAR. Refer to the List of Effective Figures for the related drawing ber and the controlled plant drawing for the latest revision.
AND DRAINS (SHEETS 1-3) figure indicated above represents an engineering controlled drawing that is Incorporated by erence in the MPS-3 FSAR. Refer to the List of Effective Figures for the related drawing ber and the controlled plant drawing for the latest revision.
(SHEETS 1-3) figure indicated above represents an engineering controlled drawing that is Incorporated by erence in the MPS-3 FSAR. Refer to the List of Effective Figures for the related drawing ber and the controlled plant drawing for the latest revision.
FIGURE 10.4-9(1)(A) AUXILIARY STEAM, FEEDWATER AND CONDENSATE (TEMP/MOD 3-97-061)
Revision 3606/29/23 MPS-3 FSAR 10.4-82
FEEDWATER EVENT EVENT LOSS OF NORMAL FEEDWATER EVENT FOR RELIABILITY ANALYSIS