ML17117A449
| ML17117A449 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 04/21/2017 |
| From: | FirstEnergy Nuclear Operating Co |
| To: | Office of Nuclear Reactor Regulation |
| Shared Package | |
| ML17117A433 | List:
|
| References | |
| L-17-029 | |
| Download: ML17117A449 (44) | |
Text
BVPS UFSAR UNIT 1 Rev. 22 10-1 SECTION 10 STEAM AND POWER CONVERSION SYSTEM TABLE OF CONTENTS Section Title Page 10.1 GENERAL DESCRIPTION 10.1-1 10.2 DESIGN BASES 10.2-1 10.3 SYSTEM DESIGN AND OPERATION 10.3-1 10.3.1 Main Steam System 10.3-1 10.3.1.1 Design Basis 10.3-1 10.3.1.2 Description 10.3-2 10.3.1.3 Performance Analysis 10.3-5 10.3.1.4 Tests and Inspections 10.3-5 10.3.2 Auxiliary Steam System 10.3-6 10.3.2.1 Design Bases 10.3-6 10.3.2.2 Description 10.3-6 10.3.2.3 Safety Analysis 10.3-7 10.3.2.4 Tests and Inspections 10.3-7 10.3.3 Turbine-Generator 10.3-7 10.3.3.1 Design Bases 10.3-7 10.3.3.2 Description 10.3-8 10.3.3.3 Performance Analysis 10.3-9 10.3.3.4 Tests and Inspections 10.3-9 10.3.3.5 In-Service Inspection 10.3-9 10.3.4 Circulating Water System 10.3-10 10.3.4.1 Design Bases 10.3-10 10.3.4.2 Description 10.3-11 10.3.4.3 Performance Analysis 10.3-12 10.3.4.4 Tests and Inspections 10.3-12 10.3.5 Condensate and Feedwater Systems 10.3-12 10.3.5.1 Design Bases 10.3-12 10.3.5.1.1 Condensate and Feedwater System 10.3-12 10.3.5.1.2 Auxiliary Feedwater Systems (AFWS) 10.3-13 10.3.5.2 Description 10.3-14 10.3.5.2.1 Condensate and Feedwater Systems 10.3-14 10.3.5.2.2 Auxiliary Feedwater System 10.3-16 10.3.5.2.3 Dedicated Auxiliary Feedwater System 10.3-17 10.3.5.3 Design Evaluation 10.3-18 10.3.5.4 Tests and Inspections 10.3-19 10.3.6 Condenser 10.3-19 10.3.6.1 Design Bases 10.3-19 10.3.6.2 Description 10.3-19 10.3.6.3 Design Evaluation 10.3-20 10.3.6.4 Tests and Inspections 10.3-20 BVPS UFSAR UNIT 1 Rev. 22 10-2 TABLE OF CONTENTS (CONT'D)
Section Title Page 10.3.7 Lubricating Oil System 10.3-20 10.3.7.1 Design Bases 10.3-20 10.3.7.2 Description 10.3-20 10.3.7.3 Design Evaluation 10.3-21 10.3.7.4 Tests and Inspections 10.3-21 10.3.8 Secondary Vent and Drain System 10.3-21 10.3.8.1 Design Bases 10.3-21 10.3.8.2 Description 10.3-22 10.3.8.3 Performance Analysis 10.3-23 10.3.8.4 Tests and Inspections 10.3-24 10.3.9 Turbine Plant Cooling Water System 10.3-24 10.3.9.1 Design Bases 10.3-24 10.3.9.2 Description 10.3-25 10.3.9.3 Performance Analysis 10.3-25 10.3.9.4 Tests and Inspections 10.3-25 BVPS UFSAR UNIT 1 Rev. 19 10-3 LIST OF TABLES Table Title 10.3-1 Cooling Tower Design Parameters
10.3-2 Cooling Tower Pump Design Parameters
10.3-3 Circulating Water System Design Parameters
10.3-4 Condenser Design Parameters
BVPS UFSAR UNIT 1 Rev. 21 10-4 LIST OF FIGURES Figure Title 10.2-1 Heat Balance
10.3-1 Main Steam System Sh. 1
10.3-2 Main Steam System Sh. 2
10.3-3 Circulating Water System 10.3-4 Condensate System 10.3-5 Feedwater System 10.3-6 Steam Generator Blowdown
BVPS UFSAR UNIT 1 Rev. 23 10.2-1 10.2 DESIGN BASES The steam and power conversion system is designed to provide the highest operating economy with maximum safety and availability. The principal design basis is represented by the heat balance calculated at the rated thermal power of the reactor which incorporates all the applicable design considerations for steam and power conversion. The heat balance applicable for operation at the licensed power conditions is shown in Figure 10.2-1.
The unit is normally operated base loaded, but responds automatically to unscheduled changes in load.
Because of the nuclear application of the steam and power conversion sy stem, provisions have been made in safety-related portions of the system for earthquake, tornado and missile protection. Those portions of the system that are safety related are located in the main steam valve cubicle area which is missile, tornado and flood protected. The valve cubicle also contains, in addition to the main steam isolation valves, the main feedwater isolation valves and the steam supply valves for the steam driven auxiliary feedpump.
No equipment contained within the turbine building is required for the safe shutdown of the reactor plant or to mitigate the consequences of an accident. However, the River Water System discharge pipe does enter the turbine building and empties into the circulating water system or, upon operation of valves, flows through a bypass line to the Unit 2 cooling tower blowdown line.
BVPS UFSAR UNIT 1 Rev. 24 10.3-2 stresses due to deadweight, pressure and thermal expansion effects were considered. The analysis assumed a system temperature and pressure of 560F and 1100 psig respectively, and concluded that the main steam piping and supports between the steam generators and the first isolation valve outside of containment have the capability to support flooded lines.
10.3.1.2 Description Steam from each of the three steam generators is conducted in 32 inch OD x 0.9297 inch minimum wall thickness, carbon steel pipe through swing disk-type trip and nonreturn valves, located in an enclosure immediately outside the reactor containment, to a 36 inch OD manifold which is located in the turbine building. A 2 inch bypass valve is provided around each of the swing disk type trip valves. Connections for the turbine steam bypass, turbine steam sealing system, reheater supply and auxiliary steam supply are provided at the manifold. A steam flowmeter interconnected with a three-element feedwater control system is provided in the main steam line between each steam generator and its main steam isolation valve. From the 36 inch OD manifold, the steam passes to the turbine throttle/stop valves and governor control valves.
The nonreturn valves automatically prevent reverse flow of steam in the case of accidental pressure reduction in any steam generator or its piping. If a steam line breaks between a nonreturn valve and a steam generator, the affected steam generator continues to blowdown while the nonreturn valve in the line prevents significant blowdown from the other steam generators. This steam line break accident is discussed in Section 14. The main steam trip valves provide backup for the nonreturn valves to prevent blowdown from intact steam generators through a ruptured pipe between a nonreturn valve and another steam generator.
The swing disk-type trip valve in series with each main steam isolation valve contains a free swinging disk normally held up out of the main steam flow path. If a pipe ruptures (Section 14) downstream of the trip valve, a signal derived as indicated in Section 7 causes all three trip valves to trip closed, thus stopping the flow of steam through the pipe rupture. Maximum closing time for the trip valves is 5 seconds following receipt of an isolation signal. Since these are swing check valves, actual closure times are much faster than 5 seconds. All analysis performed on a steam inventory basis is done using a 5 second closure. The analysis for steam hammer forces from valve closure uses the actual closure time. Valve closure checks the sudden and large release of energy in the form of main steam, thereby preventing rapid cooling of the reactor coolant system. Trip valve closure also ensures a supply of steam to the turbine drive for the turbine-driv en steam generator auxiliary feedpump.
The 2 inch bypass valves provided around each trip valve are motor operated globe valves.
These valves are normally closed during power operation. The valves are used during plant heat-up to assist in warming up the main steam piping and in opening the trip valves. Interlocks are provided to the bypass valves to allow only one bypass valve to be open at a time. The bypass valves also receive one train of a main steam isolation signal. No credit for automatic closure from a steam isolation signal is taken to close the bypass valves in the accident analysis.
Two manual blowdown valves are installed in the instrument air (Section 9.8) common air supply to the trip valves. The blowdown valves allow manual closure of the trip valves from the auxiliary feed pump room in the event of a 10 CFR 50 Appendix R design basis fire.
BVPS UFSAR UNIT 1 Rev. 23 10.3-3 Five ASME Code safety valves are located in each main steam line outside the reactor containment and upstream of the nonreturn and trip valves. These safety valves are sized to pass steam flow resulting from a complete loss of load without exceeding 110% of the steam generator secondary side design pressure of 1085 psig. This is considered the most extreme accident condition.
Excess steam generated by the sensible heat in the nuclear steam supply system (NSSS), immediately following loss of load, is bypassed directly to the turbine condenser (Section 10.3.6) by means of two turbine steam bypass lines, which provide a total bypass capacity of greater than 40 percent of full load steam flow. Each bypass line contains a bank of nine steam bypass control valves arranged in parallel. These va lves are controlled by reactor coolant average temperature with provisions to control a portion of the valves with steam pressure. A potential hazard in the form of an uncontrolled station cooldown caused by a large single valve sticking open is prevented by the use of this group of 18 valves installed in parallel. A single valve can pass a maximum steam flow of 890,000 lb per hour which is within the capability of the reactor transient criteria. The 18 valves combined can pass a nominal steam flow of 9,314,000 lb per hour based on a steam generator outlet full load steam pressure of 790 psia. A potential hazard equivalent to nine steam bypass valves remaining open and causing uncontrolled unit cooldown is the break of the steam line supplying one bank of bypass valves. Such a condition would initiate action to trip the unit. This would be followed by a complete load rejection with shutoff of
main steam flow.
All or several of the bypass valves are opened under the following conditions, provided a turbine condenser vacuum permissive interlock is satisfied:
- 1. On a large step load decrease, the turbine steam bypass system creates a load on the steam generators, thus providing a controlled disposal of generated steam. An error signal exceeding a set value of reactor coolant Tavg minus T ref fully opens all valves. Tref is a function of load and is set automatically. The turbine steam bypass valves close automatically as reactor coolant conditions approach their programmed setpoint for the new load.
- 2. On a turbine trip with reactor trip, the pressure in the steam generators rises. To prevent overpressure without main steam safety valve operation, the turbine steam bypass valves open discharging to the condenser for several minutes, providing time for the reactor control system (Section 7.3) to reduce the thermal output of the reactor without exceeding acceptable core and coolant conditions (Section 3).
- 3. After a normal orderly shutdown of the turbine-generator leading to unit cooldown, the turbine steam bypass valves are used to release steam generated by the sensible heat for several hours. Unit cooldown, programmed to minimize thermal transients and based on sensible heat release, is effected by a gradual manual closing of the bypass valves until the cooldown process is transferred to the residual heat removal system (Section 9.3). During startup, hot standby service or physics testing, the bypass valves are manually operated from the main control board. All bypass valves are prevented from opening on loss of condenser vacuum, and excess steam pressure is relieved to the atmosphere through th e atmospheric dump valves or the main steam safety valves. Interlocks are provided to reduce the probability of spurious opening of the bypass valves.
BVPS UFSAR UNIT 1 Rev. 24 10.3-4 In the event that the condenser becomes unavailable during a turbine trip, excess steam generated as a result of reactor coolant system (RCS) sensible heat and core residual heat is discharged to the atmosphere through the main steam safety valves. Radioactivity released during this discharge is assumed to be negligible since little or no primary coolant leakage is anticipated. Should significant radioactivity exist, as a result of leakage in the steam generators, concentration would be continually controlled to acceptable levels by the steam generator blowdown system. Any release of radioactive steam that takes place will be monitored by high range detectors located at the discharge points. A remote manually-operated atmospheric dump valve is also provided on each main steam header upstream of the nonreturn valve outside the containment. These valves are individually positioned from the main control board. The three valves each have a total effective relieving capacity of 294,400 lb per hour at an inlet pressure of 1035 psig, when accounting for friction losses associated with upstream and downstream piping.
In addition, a residual heat release control valve is provided which, after approximately 0.5 hr, is capable of releasing the sensible and core residual heat to the atmosphere via the residual heat release header. This valve is manually positioned from the main control board by remote control. This one valve, which is mounted on the common residual heat release header, serves all three steam generators through connections on each main steam line upstream of the nonreturn valve and trip valve. In addition, the residual heat release control valve is used to release the steam generated during reactor physics testing and operator training. There is a check valve in each line connecting a main steam line to the common residual heat release header. These check valves ensure that steam may flow to the header, but prevent reverse flow of steam as may occur if a line breaks between a steam generator and main steam nonreturn valve. When servicing all three steam generators, the residual heat release control valve has an effective relieving capacity of 222,000 lb/hr at an inlet pressure of 1035 psig taking into account friction losses associated with upstream and downstream piping.
Upon actuation of the atmospheric dump valves or the residual heat release control valve, any radioactive contaminants in the steam generators are released to the environment. These radioactive contaminants are monitored by the sampling system connections on the blowdown lines (Section 9.6). A system for continuous monitoring of releases to the environment is described in Section 11.3.3.3.24. The operator can control secondary system radioactivity concentrations at acceptable levels by steam generator blowdown system operation, reduction in power level, and/or isolation of a ruptured steam generator.
Steam can be supplied from each main steam line upstream of the trip valve to the turbine drive for the turbine-driven steam generator auxiliary f eedwater pump (Section 10.3.5). The piping is arranged so that any steam generator can s upply the turbine drive for this pump.
Check valves are provided in the steam supply line from each steam generator to the turbine drive to ensure the availability of driving steam in the event of failure of a steam generator or a line break upstream of a main steam nonreturn valve. Two trip open valves in parallel are located in the inlet of the turbine drive. Steam pressure is available at the inlet of these valves at all times. Indications of all operating conditions are available in the main control room to enable the operator to adjust feedwater flow by throttling valves at the pump discharge.
Additional description of steam generator auxiliary feedwater pump operation is contained in Section 10.3.5.
BVPS UFSAR UNIT 1 Rev. 23 10.3-5 Steam leaving the high pressure turbine passes through four moisture separator-reheater units in parallel to the inlets of the main low pressure turbine cylinders. Each of the four steam lines between the reheater outlet and low pressure turbine inlet is provided with a reheat stop valve and a reheat intercept valve in series. These valves, operated by the turbine control system, function to prevent turbine overspeed. An ASME Code safety valve is installed on each moisture separator reheater to protect the separators and reheat system from overpressure.
The safety valves are designed to pass the flow resulting from closure of the reheat stop and intercept valves with the main steam inlet valves wide open. These valves discharge to the
condenser.
10.3.1.3 Performance Analysis If a main steam line break occurs (Section 14.2.5), a 2 out of 3 channel low pressure signal from any main steam line causes the swing trip valves in all three main steam lines to trip closed.
Maximum closing time for the trip valves is 5 seconds following receipt of an isolation signal. If the break occurs downstream of the trip valve, valve closure stops the flow of steam through the break, thus checking the sudden and large release of energy in the form of steam. This prevents rapid cooling of the Reactor Coolant System (RCS). Trip valve closure also ensures a supply of steam to the turbine drive of the turbine-driven steam generator auxiliary feedwater pump, as described in Section 10.3.5.
If a main steam line breaks between a trip valve and a steam generator, the affected steam generator continues to blowdown. The nonretur n valve in the broken line prevents blowdown from the other steam generators. This is the worst steam line break accident and is discussed in Section 14.2.5. 10.3.1.4 Tests and Inspections During unit refueling shutdown, the tripping mechanisms for the swing trip valves in the main steam lines are tested for proper operation in accordance with the BVPS Technical Specifications. The nonreturn valves are also tested to verify that they are in operable
condition.
Preoperational testing includes a hydrostatic line test and a clean flush plus complete checkout
of instrumentation components.
The turbine steam bypass system and the steam dump valves are operated in conjunction with the turbine overspeed test (Section 10.3.3.4).
To meet the inservice inspection requirements, the lines will be provided with removable insulation to permit ultrasonic testing of the welds upstream of the isolation valves. These welds are prepared to suit this inspection.
BVPS UFSAR UNIT 1 Rev. 21 10.3-9 10.3.3.3 Performance Analysis Primary protection of the main generator is provided by differential current and field failure relays. Protective relays automatically trip the turbine throttle stop valves and electrically isolate the generator.
Turbine trips are provided for protection of the turbine-generator and safety of personnel and surrounding equipment. The turbine trip is accomplished by shutting off all steam flow to and through the turbine by simultaneously closing all throttle stop valves, governor control valves, intercept valves and reheater stop valves. Turbine trips are provided for low bearing oil pressure, thrust bearing failure, low condenser vacuum, overspeed and all generator trips. The turbine can be tripped manually. Reactor trips and steam generator high high level can also trip
the turbine.
This system has been reviewed on the basis of a full load trip of the turbine generator along with loss of normal power. During such an event, there would be no serious effect on the reactor.
For interaction of the turbine controls and reactor controls, see description in Sections 7.2 and 7.3, supported by Figure 7.2-1.
For a discussion of turbine overspeed, see Section 14.1.12. 10.3.3.4 Tests and Inspections The main turbine throttle and governor valves and the combined intercept and intermediate stop valves are exercised in accordance with the requirements contained in the Licensing Requirements Manual to detect possible valve stem sticking. The valves are closed and then reopened during this procedure. The turbine is overspeed checked at a refueling frequency. (This test may be performed at the beginning of an outage rather than at startup, providing no work will be performed during the outage that could affect the overspeed trip setpoint.) This is done by running the turbine up to the overspeed trip points. A device is also included with the turbine for testing the overspeed trip mechanism without actually overspeeding the turbine. 10.3.3.5 In-Service Inspection The inservice inspection of the steam turbine assembly will be conducted to provide assurance against brittle failure of a disc at rated speed or design and intermediate overspeed. The inservice inspection will be performed when required to maintain the probability of turbine missile generation (P1) less than or equal to 10
-5, as described in Section 14.1.12.4. The inspection interval is based upon the probability of generating a turbine missile as a function of actual operating time.
When the turbine is disassembled, a visual and magnetic particle examination is made externally on accessible areas of the high pressure rotor, low pressure turbine blades, and low pressure discs. The coupling and coupling bolts are visually examined.
BVPS UFSAR UNIT 1 Rev. 21 10.3-11 10.3.4.2 Description Circulating water flows by gravity from the basin of the cooling tower, through screens, through two 108 inch diameter circulating water pipes to the inlet water boxes of the condenser. The water passes through the tubes of the condenser to the outlet water boxes. Two 108 inch lines carry condenser discharge cooling water to a pumping structure outside of the turbine building.
The discharge lines of the raw water system and the river water system flow into the circulating water system between the condenser outlet water boxes and the pumping structure. The four cooling tower pumps are mounted in the pumping structure. These cooling tower pumps pump the water to the top of the cooling tower fill where it is discharged into the cooling tower distribution system. Cooling tower blowdown passes from an overflow at the cooling tower basin and is discharged back into the Ohio River.
A minimum cooling tower blowdown rate of 9,000 gpm is anticipated during normal unit operation. However, this blowdown rate can be raised to 22,500 gpm if dilution of radioactive liquid waste discharge is found necessary to meet the guidelines of 10CFR50, Appendix I (see
Appendix 11A).
The circulating water system is a nonsafety related system and is independent of emergency core cooling requirements.
The worst possible postulated break in the circulating water system is the rupture of the main condenser inlet expansion joint with failure of its associated condenser inlet valve to close. This break would allow the largest quantity of water to flow from the cooling tower basin to the turbine building basement with no means available to stop the flow.
The normal capacity of the cooling water tower basin is approximately 5,945,000 gal. The flow rate through the ruptured expansion joint, assuming a double ended break configuration, is approximately 120,000 gpm. The capacity of the turbine building basement is 270,000 gal per ft. Therefore, the water level would rise on the order of 0.45 ft per minute.
When the level equalization point is reached between the final water level in the turbine building and the tower basin, and the flow has ceased, the water level in the turbine building will have risen 9.3 ft while the level in the basin will have fallen 2.2 ft; both surfaces will be approximately at El. 702.8 ft.
There are no possible paths for water to flow from the turbine building at or below El. 707.5 ft. All possible paths of floodwaters leaving the turbine building and flowing to other areas during a PMF, which produces a water level far greater than the level which could be obtained by a circulating water system failure, are discussed in Sections 2.3.3, 2.7.3.2.3 and 9.7.
Operation of the condenser inlet valves would, of course, limit the quantity to something less than 120,000 gal (60 second valve closure time).
Design parameters of the circulating water system components are listed in Table 10.3-3.
The cooling tower is located at a distance such that its failure would not cause disruption of safety-related systems.
BVPS UFSAR UNIT 1 Rev. 23 10.3-13 3. The Piping Class II (Q2) piping from the steam generators to and including the check valves just outside the containment, is required for the auxiliary feedwater system (AFWS) to maintain the steam generator levels when the main feedwater pumps are not available.
The condensate system is located totally within the turbine building. Aside from causing a plant shutdown, a condensate line rupture or failure of a structure housing portions of the condensate system cannot compromise the availab ility of any safety-related equipment. 10.3.5.1.2 Auxiliary Feedwater Systems (AFWS)
The design of the steam generator auxiliary feedwater subsystem portion of the feedwater system is based on the following conditions:
- 1. Integrated residual heat release from a full power equilibrium core
- 2. Feedwater inventory of the steam generators operating at normal minimum feedwater level 3. The minimum allowable steam generator feedwater level permitted to prevent thermal shock or other damage
- 4. A reasonable time interval to start th e steam generator auxiliary feedwater pumps
- 5. The temperature of the feedwater supplied from the primary plant demineralized water storage tank. This temperature is assumed to be 35F when considering thermal shock and 100F when considering feedwater enthalpy for tank sizing.
The entire auxiliary feedwater subsystem is designed as Seismic Category I, with the exception of the primary demineralized water chemical feed tank.
No portion of the auxiliary feedwater system (AFWS) is within the containment. The system, with the exception of the primary plant demineralized water storage tank and pump suction piping, is located in the auxiliary feedwater pump cubicle and main steam and valve cubicle. The auxiliary feedwater system outside containment is housed in a missile protected area.
Cavitating venturi flow orifices are provided in the auxiliary feedwater supply lines to each of the three steam generators. These venturi orifices are designed to limit the flow to 310 gpm (choked flow) to any steam generator. In the event of a steamline break that will result in a decrease in the steam generator shell pressure, the venturis will prevent excessive flow to the depressurized steam generator to prevent Containment over-pressurization.
The system is designed such that for any accident requiring the use of the AFWS, a single active (electrical) failure in the AFWS will not preclude the system's ability to perform its function. The positions of these valves are indicated in the control room. The instrumentation, control and electrical equipment of this system conforms to the requirements of Institute for Electrical and Electronic Engineers (IEEE) 279-1971 Criteria for Protection Systems for Nuclear Power Generating Stations and IEEE 308-1971 Criteria for Class 1E Power Systems for Nuclear Power Generating Stations.
BVPS UFSAR UNIT 1 Rev. 23 10.3-14 10.3.5.2 Description 10.3.5.2.1 Condensate and Feedwater Systems Condensate is withdrawn from the condenser hotwells by two half-size capacity motor-driven condensate pumps. The pumps discharge into a common header which carries the condensate through two steam jet air ejector condensers arranged in parallel and through one gland steam condenser. A flow control valve and a bypass around the gland steam condenser ensure that no more than maximum design flow passes through the gland steam condenser. Downstream of the gland steam condenser, the common header divides into two lines which carry the condensate through the tube side of two trains of heat exchangers arranged in parallel, each consisting of one heater drain cooler and five low pressure feedwater headers (No. 2 through 6),
each half-capacity. The effluent from each train combines into a common suction header for the two half-size design capacity steam generator feedwater pumps. Manual valves permit isolation of one train of heaters for maintenance without a station shutdown.
The condenser hotwell is designed to operate at normal level such that approximately 4 minutes of condensate flow (71,000 gal) is available to supply the condensate pumps. A 200,000 gal turbine plant demineralized water storage tank floats on the system. Each of the two vertical barrel-type condensate pumps is rated at 9,700 gpm at 1,078 ft TDH. Minimum flow of approximately 3,000 gpm total for each of the two condensate pumps is maintained by an orifice measuring device. The orifice measuring device operates the recirculation valve downstream of the gland steam condenser as shown in Figure 10.3-4.
Two half-size steam generator feedwater pumps, each rated at 15,200 gpm and 1,700 ft TDH, are furnished to supply feedwater to the three steam generators. Each feedwater pump is equipped with two 4,000 hp electric motor drivers in tandem. Minimum flow for each pump is maintained by administrative control and an automatic recirculation control and alarm system, consisting of: flow measuring nozzles, flow totalizer, controller, and recirculation valves. The recirculation valves normally maintain a minimum flow of 8,000 gpm per pump. Feedwater leaves the first-point heaters at 440 F. The steam generator feedwater pumps discharge through two half-size design capacity high pressure feedwater heaters (No. 1), arranged in parallel, to a common discharge header for distribution to the steam generators through individual feedwater flow control valves, positioned by the three-element feedwater control system for each steam generator. A manual bypass around each first-point heater allows isolation of these heaters for maintenance without a station shutdown. During low power operation or hot shutdown, when feedwater flow is below 20 percent of design flow, a bypass valve around each feedwater control valve provides steam generator level and feedwater flow control. The automatic control of the steam generator water level at low power using the feedwater bypass valve is also discussed in Section 7.7.1.7.
The feedwater control valves and bypass valves are provided with indicating lights in the main control room. The feedwater control valves close on receipt of a safety injection (SI) signal or any steam generator two out of three high-high level or a reactor trip associated with a low Tavg in two out of three reactor loops. The feedwater bypass control valves close on a feedwater isolation signal made up of an SI signal or any steam generator two out of three high-high level. The feedwater bypass valves must be reset by a pushbutton switch located in the main control room after the isolation signal is removed.
BVPS UFSAR UNIT 1 Rev. 23 10.3-17 During operation, each pump continuously recirculates a specified flow back to the demineralized water storage tank through a common header. Cooling water for auxiliary feedwater pump bearing oil coolers is supplied from this continuous recirculation flow. This provides a guaranteed source of coolant under all conditions. The pumps are sized to supply their rated capacities plus this recirculation. Each pump is equipped with a recirculating line for long-term pump operation. The turbine driven pump is equipped with a 3 inch line to provide 250 gpm recirculating flow minimum and each motor driven pump with a 2 inch line to provide a minimum recirculating flow of 135 gpm. Each of the recirculating lines is equipped with an
automatically operated valve.
The recirculation header is also provided with a chemical feed tank for introducing chemicals to protect the carbon steel pumps, piping and primary plant demineralized water storage tank from the deleterious effects of dissolved oxygen in demineralized water.
The auxiliary feedwater is discharged to the steam generators through a connection in each main feedwater line outside the reactor containment but downstream of the containment isolation trip and check valve. This prevents loss of the auxiliary feedwater should a feedwater line break upstream of this check valve.
The system provides sufficient redundancy to ensure the required flow to a minimum of two steam generators while subjected to a single failure as defined in Section 1.3.1. To maintain a minimum heat sink, water must be supplied to a minimum of one steam generator.
When the motor driven auxiliary feedwater pump aligned to the redundant header is declared inoperable, the two remaining auxiliary feedwater pumps will be realigned to separate headers as per Technical Specifications. This action will maintain the necessary configuration to assure adequate auxiliary feedwater flow for normal, transient and accident conditions. 10.3.5.2.3 Dedicated Auxiliary Feedwater System This motor driven dedicated auxiliary feedwater pump, FW-P-4, is designed to meet Appendix R. It is powered from the emergency response facility substation, switchgear diesel, and is located on the 693'-6" elevation of the turbine building.
Control and power cables for this pump and substation power supply is routed in the turbine building alone independent of control room and other fire areas.
This pump is designed to provide water to the three steam generators after the loss of main feedwater and the existing auxiliary feedwater pumps, due to the loss of offsite power and a fire in the auxiliary feedwater pump area or associated control or power circuitry.
Suction to FW-P-4 is normally aligned to WT-TK-11 (turbine plant demineralized water). Additional makeup water is provided from alignment to WT-TK-26.
The capacity of these storage tanks will ensure that the dedicated auxiliary feedwater pump will be able to initiate a plant cooldown and meet the makeup capacity requirements necessary to remove the plant decay heat generated during the first 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> of a shutdown. Makeup water may be provided by trucking in water from an outside source or by using the river water system.
BVPS UFSAR UNIT 1 Rev. 25 10.3-18 The pump is designed to deliver 400 gpm at the time of initiation to 700 gpm at the reduced steam generator pressures in the approach to the 200 F cold shutdown state. This dedicated pump has the capability to utilize the steam generators as once through water to water heat exchangers, with the design intent of reaching cold shutdown conditions in 127 hours0.00147 days <br />0.0353 hours <br />2.099868e-4 weeks <br />4.83235e-5 months <br />.
10.3.5.3 Design Evaluation Steam supply lines to the trip valves of the turbine-driven steam generator auxiliary feedwater pump are continuously under main steam pressure. Steam traps are provided in the lines to ensure that any condensate formed as a result of warming is removed. The turbine is a single inlet, single stage unit and any drops of water forming do not damage or impair its operation.
When main steam pressure is no longer adequate to operate the turbine-driven pump, the need for residual heat removal is reduced to a level where the residual heat removal system (Section 9.3) can be used. In addition, each motor-driven pump is connected to an emergency bus and can be operated if necessary. An alternate source for auxiliary feedwater is one of the river water system headers, which is connected to the suction of the steam generator auxiliary feedwater pumps and can be supplied with water by either the river water pumps or the engine-driven fire pump.
Cavitating venturis provided in the three auxiliary feedwater supply lines reduce the minimum auxiliary feedwater flow available to the steam generators and limit the maximum auxiliary feedwater flow to a faulted steam generator or broken feedwater line. Minimum auxiliary feedwater pump performance with the cavitating venturis meets the flow requirements assumed in the Feedwater Line Break, Loss of Normal Feedwater and Small Break LOCA analyses.
The three steam generator auxiliary feedwater pumps with the redundant means of motive power and associated piping (with the exception of the TDAFWP steam exhaust stacks above elevation 790 feet) are installed in a tornado-protected area adjacent to the containment so that their use can be relied upon during any loss of normal station power.
BVPS UFSAR UNIT 1 Rev. 23 10.3-19 10.3.5.4 Test and Inspections The steam generator auxiliary feedwater pumps, their drives and the pump discharge valves are tested on a periodic basis. Steam is admitted to the turbine drive or the motor drivers are energized and flow is established by recirculation to the primary plant demineralized water storage tank. During station startups after extended shutdown the motor operated shutoff valves leading to the main feedwater lines are opened, and flow indication is observed at both the main control board and auxiliary shutdown panel for each loop. All weld surfaces are properly prepared to permit volumetric inspection and removable insulation is provided for feedwater and auxiliary feedwater lines from the steam generator to the first isolation valve outside containment.
10.3.6 Condenser A twin shell, single pass, divided water box condenser is provided for condensing steam from the two low pressure turbine exhausts, from the turbine steam bypass valves and for miscellaneous drains.
10.3.6.1 Design Bases The design parameters for the condenser are as given in Table 10.3-4. 10.3.6.2 Description The condenser is of conventional design, that has the following features: stainless steel expansion joint in each neck, steam and condensate crossover ducts to equalize pressure, impingement baffles to protect the tubes and partitioned hotwells for detection of circulating water inleakage. The total storage capacity of both condenser hotwells, based on normal level, is equivalent to approximately 4 minutes of fu ll load operation. One No. 6 feedwater heater shell is located in each condenser neck.
Two twin element, two-stage steam jet air ejector units, each complete with tubed inner and after condensers, remove noncondensable gases from the condenser shells. One element of each ejector is operated for each condenser shell. The ejectors utilize auxiliary steam for operation. The air ejector effluent is monitored for radiation as discussed in Section 10.3.8.
For initial condenser shell side air removal, a vacuum priming ejector is provided for each shell.
Steam from the auxiliary steam system operates these ejectors (Section 10.3.2).
BVPS UFSAR UNIT 1 Rev. 22 10.3-20 10.3.6.3 Design Evaluation The condenser is designed for operation at maximum expected station capability. Tubes in the condenser are protected by impingement baffles and spray pipes. Motor-operated butterfly valves are provided at the condenser inlet and outlet water boxes for maintenance isolation.
Any radioactive contaminants will be handled by the air ejectors as described in Section
10.3.8.2.
Normally, air leakage to the condenser will be handled by the steam air ejectors. Should air leakage become excessive so that backpressure cannot be maintained, the unit will trip. Unless a break occurs, the leakage should be nominal and controllable to permit repairs during a planned shutdown. 10.3.6.4 Tests and Inspections A total of 12 sample points on the condenser hotwells are used to check the condenser for circulating water inleakage. A radiation monitor is installed in the common discharge line of the two air ejectors.
10.3.7 Lubricating Oil System The lubricating oil system provides for storage, transfer and conditioning of lubricating oil for the turbine-generator.
10.3.7.1 Design Bases The lubricating oil system performs the following functions:
- 1. Stores lubricating oil
- 2. Supplies oil to and receives oil from the turbine-generator oil reservoir at 100 gpm
- 3. Purifies oil, at a rate of up to approximately 100 gpm, from the turbine-generator oil reservoir on a continuous offstream basis.
10.3.7.2 Description A 14,500 gal capacity oil storage tank and two transfer pumps are located at basement grade in the turbine building. Two connections are located outside the turbine building to allow for receiving fresh oil from or discharging used oil into tank trucks. The piping associated with one transfer pump is arranged to deliver oil to the turbine oil reservoir or into tank trucks from the oil storage tank. The second transfer pump can deliver turbine oil into tank trucks from the turbine oil reservoir or return it to the oil storage tank. All piping is welded steel.
Oil is continuously extracted from an overflow fitting on the turbine oil reservoir and pumped through a lubricating oil purifier which removes entrained water and impurities from the oil. After passing through this lubricating oil purifier, the oil is returned to the turbine oil reservoir.
BVPS UFSAR UNIT 1 Rev. 22 10.3-24 In the event of a high-energy line break (HELB) outside containment, two safety-related trip valves in series have been added to each blowdown line. These valves (TV-BD-101-A1, A2, B1, B2, C1, and C2) will isolate steam generator blowdown within 15 seconds after ambient temperature in the Auxiliary and Safeguards Buildings exceeds 111F (isolation time includes sensor response time, signal processing time, and valve stroke time). Reducing orifices (RO-BD-109A, B, and C) limits the energy release in those areas without ambient monitors so the environmental qualification envelope in those areas with vital equipment is maintained.
10.3.8.4 Tests and Inspections The secondary vent and drain systems are in continual use and require no special periodic testing and inspection. However, the trip valves installed in these systems, which are part of the containment isolation system, provide HELB isolation, or which trip on high-high radiation level, are tested periodically. 10.3.9 Turbine Plant Component Cooling Water System The turbine plant cooling water system supplies cooling water to steam and power conversion system equipment. The system is a closed loop system using treated condensate as cooling water. 10.3.9.1 Design Bases Heat removed by the closed loop turbine plant component cooling water system is transferred to the circulating water system (Section 10.3.4) through component cooling water heat exchangers. A temperature controlled bypass around these heat exchangers maintains the cooling water supply temperature. The cooling water is circulated through the shell side of the component cooling water heat exchangers and through the various equipment coolers by motor-driven turbine plant component cooling water pumps.
The principal equipment served by the turbine plant component cooling water system is as follows:
- 1. Generator hydrogen coolers
- 2. Hydrogen seal oil coolers
- 3. Turbine oil coolers
- 4. Exciter cooler
- 5. EH cooler
- 6. Isolated phase bus duct air coolers BVPS UFSAR UNIT 1 Rev. 22 10.3-25 7. Station air compressors, each
- 8. Sample coolers
- 9. Condensate, feed and heater drain pumps
- 10. Vacuum priming pumps seal coolers, each 10.3.9.2 Description The cooling water flow through the major equipment coolers, such as the hydrogen and oil coolers, is controlled automatically to maintain the cooler fluid at a constant temperature.
A head tank is provided to maintain a positive pressure at all points in the system. Makeup to the system is provided from the condensate pump discharge header. An alarm is actuated upon low level in the head tank.
River water is pumped from the Ohio River through the tube side of the turbine plant component cooling water heat exchangers and returned to the main condenser circulating water outlet line.
10.3.9.3 Performance Analysis The station air compressors are the only equipment requiring cooling water when the turbine plant cooling water system is shut down. These compressors are required for maintenance reasons only at this time. The compressors are not safety related, as all air-operated valves are fail safe. Under this condition, air compressor cooling circuit & aftercooler cooling water is supplied from the filtered water storage tank via filtered water system pumps. 10.3.9.4 Tests and Inspections Pumps and heat exchangers are rotated between duty and standby or periodically test run.
BVPS UFSAR UNIT 1 Rev. 23 10.3-26 REFERENCES FOR SECTION 10.3
- 1. Deleted by Revision 23.
- 2. Letter from J. D. Sieber (Duquesne Light Company) to A. W. DeAgazio (Nuclear Regulatory Commission),
Subject:
Main Feedwater Piping Elbow Cracking and Misalignment - TAC 79769 (June 1991).
BVPS UFSAR UNIT 1 TABLES FOR SECTION 10
BVPS UFSAR UNIT 1 Rev. 19 1 of 1 Table 10.3-1 COOLING TOWER DESIGN PARAMETERS
- 1. Type Natural Draft
- 2. Flow, gpm 507,400 3. Range, F 25.5 4. Approach, F 16
- 5. Dry bulb temperature, F 87
- 6. Wet bulb temperature, F 74
- 7. Exit air volume, cfm 35 x 10 6 8. Exit air temperature, F 106 9. Evaporation loss, gpm 10,500
- 10. Drift loss, percent 0.05 11. Pumping head, ft 68.8 12. Top diameter, ft 219
- 13. Height, ft 501
- 14. Bottom diameter, ft 446
BVPS UFSAR UNIT 1 Rev. 19 1 of 1 Table 10.3-2 COOLING TOWER PUMP DESIGN PARAMETERS
- 1. Number of pumps 4 2. Capacity, gpm each 126,850 3. Type of pump vertical, dry pit
- 4. TDH, ft 96.4 BVPS UFSAR UNIT 1 Rev. 19 1 of 1 Table 10.3-3 CIRCULATING WATER SYSTEM DESIGN PARAMETERS Component Design Pressure (psig) Operating Pressure (psig) 1. Steel pipe under turbine bldg. 108 inch diameter or 78 inch diameter 30 9 (max) 2. Concrete pipe between turbine bldg. and pump house 108 inch diameter na (1) na (1) 3. Main Condenser inlet/outlet valves 78 inches 50 3.7/-2.1 4. Main condenser inlet/outlet expansion joints 78 inch diameter 40 3.7/-2.1 5. Cooling tower pump suction valves 150 9 6. Cooling tower pump discharge valves 150 43.2 7. Cooling tower pump suction expansion joints 45 9 8. Cooling tower pump discharge expansion joints 75 43.2 9. Steel pipe at cooling tower pump house 90-180 9-43.2 (1) Gravity flow BVPS UFSAR UNIT 1 Rev. 19 1 of 1 Table 10.3-4 CONDENSER DESIGN PARAMETERS
- 1. Steam condensed, lb/hr 6,700,000
- 2. Circulating water flow rate, gpm 480,000
- 3. Surface area, sq ft 720,000
- 4. Number of tubes 67,924
- 5. Tube material, Type SEA-CURE (A268-82)
UNS 44660
- 6. Tube OD, inches 0.75
- 7. Effective length per tube, ft 54 8. Back pressure, inches Hg abs 2.0 9. Hotwell temperature, F 101