ML21361A213
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The heat cycle provides for extraction at six pressure stages for feedwater heating as follows:
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10.2.2.4 Turbine Protection System In addition to overspeed trip signals discussed above, the emergency trip system closes the main stop and control valves, and the intermediate stop and intercept valves, thereby shutting down the turbine on the trip signals listed in <Section 10.2.2.4.1> and
<Section 10.2.2.4.2>.
Revision 12 10.2-7 January, 2003
The sequence of events and response times following a turbine trip are given in <Section 15.2.3>, <Figure 15.2-2>, <Figure 15.2-3>,
<Figure 15.2-4>, and <Figure 15.2-5>, and
,
,
, and
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10.2.2.4.1 Turbine Trip Signals Due to Mechanical Faults The turbine is shut down due to the following mechanical fault signals:
. Resulting radiation dose rates are approximately 6 R/hr for the main steam pipes, 2 R/hr for the high pressure turbine and 4 R/hr for the moisture separator.
As discussed in <Section 11.3>, most of the gaseous activity in the condenser is removed by the steam jet air ejector to the gaseous waste system. The activity that is not removed by the air ejector is reduced significantly by the approximately three minute holdup time in the condenser hotwell. Therefore, the activity entering the condensate and feedwater lines is significantly less than that originally entering the steam and power conversion system.
Biological shielding design is discussed in <Section 12.3.2.2>. The turbine is in an administratively controlled access area.
Revision 12 10.2-18 January, 2003
10.2.5 HYDROGEN AND CARBON DIOXIDE SYSTEMS 10.2.5.1 Power Generation Design Bases
during normal plant conditions without exceeding 5 inches Hg absolute or 200F at the turbine exhaust to any shell.
The main condenser is designed for the following approximate conditions:
Condenser duty 8.1 x 109 Btu/hr Circulating water inlet temperature 94F (design)
Circulating water temperature rise 32F Revision 12 10.4-1 January, 2003
Air in-leakage 55 scfm Disassociated H2 and O2 from the BWR H2 162 scfm O2 81 scfm Steam processed through the main condenser normally contains small amounts of radioactive material. Noncondensible gases are removed via the steam jet air ejectors (SJAE) to the offgas processing system.
Liquids are processed through the condensate filter/demineralizer systems. Excessive radioactive leakage is detected by the main steam line radiation monitors and the offgas pretreatment monitor.
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During normal operation the main condenser receives the following flows:
. The valve casing (valve chest) is welded to a branch line coming from the main steam pipes. This connection point to the main steam pipes is downstream of the outboard mainstream isolation valves and upstream of the main turbine admission valves. Mounted in the chest are several bypass valves, each connected to its own hydraulic actuator.
The steam bypass valves receive electronic positioning from the pressure regulator cabinet and are hydraulically powered by an external source of high pressure hydraulic fluid.
Revision 12 10.4-17 January, 2003
When the steam bypass valves are open, steam enters each end of the chest, flows downward between the seat and the stem, and then exits through the discharge casing. The amount of steam passing through each valve is controlled by the lift of the valve. The valve disk and seat are hardsurfaced at their contacting points to improve the ability to maintain adequate seating contact.
The force required to open and position each steam bypass valve is applied to the valve stem by the power actuator which is mounted directly below each valve.
The double acting hydraulic cylinder operator is equipped with an air bleed in both end caps and internal stop tube on the rod side to limit stroke. The piston is fitted with a small leakage plug to allow a small amount of fluid to leak from the high pressure side to the low pressure side of the piston. This small leakage assures a continuous flow of fluid and prevents fluid stagnation.
A hydraulic control manifold is provided with the necessary passages to connect the hydraulic supply and drain to the correct ports on the servovalves, fast acting solenoid valve and cylinder.
The servovalve is mounted on the manifold and controls the fluid flowing to each end of the hydraulic cylinder. The valve receives an analog electrical signal from the pressure regulator cabinet and is used for normal positioning of the steam bypass valve.
In the event that the steam bypass valves must be opened faster than that allowed by the flow capacity of the servovalve, a parallel fluid path to the cylinder is provided by opening of the fast acting solenoid valve. This valve is opened by an electrical current originating in the pressure regulator cabinet. Since considerable time may elapse between the actuations of the solenoid valve, provision is made in the valve test logic to exercise this valve. During valve testing, the steam Revision 12 10.4-18 January, 2003
bypass valve is slowly stroked open by sending an appropriate electrical signal to the servovalve. After the valve is stroked to approximately the 90 percent open position, the switch rod collar closes a switch in the switchbox. These contacts complete a circuit to the fast acting solenoid valve which allows hydraulic fluid to pass into the hydraulic cylinder at a high rate of flow. Using this scheme, the steam bypass valve slowly strokes open to the 90 percent position and then snaps fully open.
10.4.4.2.3 Classification The steam bypass system is classified as a primary power generation system (i.e., it is not a safety system and its operation is essential to the power production cycle).
10.4.4.3 Safety Evaluation The turbine bypass system is not essential for turbine operation.
Should the bypass system malfunction and inadvertently admit bypass steam to the condenser while the turbine is under load, the steam flow to the turbine would be reduced by action of the pressure controller.
If, under these conditions, the condenser heat rejection rate is inadequate and the exhaust pressure becomes excessive, the turbine will be tripped by vacuum trips. In addition, should the turbine exhaust pressure continue to increase, additional redundant vacuum trips are provided to trip the bypass, stop and control valves and MSIVs.
The effects of a malfunction of the turbine bypass system valves and the potential effects of such failures on safety systems and components are evaluated in <Chapter 15>. A pipe break in the turbine bypass system will not have an adverse affect on any safety-related systems and components.
Revision 12 10.4-19 January, 2003
The turbine bypass system can malfunction in either the open or closed mode. The effects of both of these failure modes on the operation of the reactor are discussed in <Appendix 15A>, Nuclear Safety Operational Analysis. The analyses are system level/qualitative type plant failure mode and effects analyses.
The effects of turbine bypass system malfunctions on the reactor operation are bounded by events presented in <Appendix 15A> as follows:
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It is very unlikely that draining of the cooling tower basin will occur under the conditions postulated in <Section 10.4.5.3.1>. Pumping of the water into the turbine building is also very unlikely to occur since the water level switches located within the turbine building basement would actuate shutdown of the pumps. Pump discharge valve closure would also be actuated by the level switches to break a postulated siphon flow.
A discussion of the design basis accident involving a postulated yard pipe break or flooding of the turbine building via flow through fractured base mat to the underdrain system is contained in
<Section 2.4.13.5>.
10.4.5.2 System Description The closed loop system will consist of one natural draft cooling tower, the main and auxiliary condensers, three circulating water pumps, piping and various valves, and piping specialties required to operate the system, as shown on <Figure 10.1-7>. Typical system operation utilizes all three of the circulating water pumps. When conditions permit, system and plant operation can be fulfilled utilizing less than three Revision 21 10.4-22 October, 2019
pumps. Water flows from the cooling tower basin through a set of fixed screens to the suction of the circulating water pumps. The pumps discharge water through a 12-foot diameter pipe to the main and auxiliary turbine condensers, condensing the steam therein. From the condensers, water flows out to the cooling tower where it cascades through a set of baffles, is cooled by the air flow and returns to the cooling tower basin. The cooling towers are approximately 411 feet in diameter at the base, and approximately 516 feet high. The distance from any point on the cooling tower to the nearest safety-related structure is in excess of 540 feet.
Winter startup and operation must be carefully controlled to ensure that no excessive ice formation occurs which can lead to reduced tower performance and possible equipment damage. For winter startups, the cooling tower is positioned in the bypass mode which limits the water to the cooling tower basin only. When the basin water temperature reaches a predetermined value, the cooling tower is positioned in the central deicing mode.
The cooling tower is designed with a central deicing system for normal winter operation. The deicing system controls ice formation in the following manner. The central deicing mode limits the cold water through the outer perimeter fill of the tower, i.e., no water is supplied to the center portion of the tower. This results in a greater heat load being applied to the outer perimeter fill, causing the cold water temperature to rise. This hot water melts any ice formed in the outer perimeter fill. As the water temperature continues to rise, the tower will be positioned in the normal operating mode, evenly distributing the hot water over all portions of the tower fill.
Makeup for tower evaporation, wind loss and blowdown is obtained from the service water system. This system will provide the makeup requirements after cooling the various components that use service Revision 21 10.4-23 October, 2019
water. This water will come from Lake Erie via the intake tunnel into a service water pumphouse. Service water pumps transmit the water to the plant through various heat exchangers in the service water system. It then goes to a weir box from which flow is diverted to the cooling tower basins, with the remainder going directly to the lake by means of the discharge tunnel entrance structure <Figure 9.2-14>. Makeup flow to the cooling tower varies from 16,000 gpm to 25,979 gpm depending on atmospheric conditions.
A blowdown system is provided at the circulating water pump discharge to maintain the concentrated solids in the system at a design level of 2.5 concentrations of makeup water (service water). The blowdown is added to the service water discharge flow and is conveyed to the discharge tunnel entrance structure from which it will flow to the lake by means of the discharge tunnel. Blowdown from the cooling tower varies from 6,000 gpm to 10,332 gpm depending on atmospheric conditions.
Cleanliness of the main condenser tubes is maintained by the use of chemicals and biocide. A mechanical (Amertap) cleaning system was originally installed to maintain condenser tube cleanliness. Although the Amertap system remains installed, it is no longer used for this purpose. Anti-scaling chemicals are added into the circulating water system, on an as-needed basis, to prevent scale deposition on heat exchanger surfaces. A liquid biocide injection system is used, as required, to minimize algae growth in the circulating water and cooling water systems. The circulating water system, as well as the plant effluent water, consisting of cooling water discharge and circulating water blowdown, is monitored to determine biocide concentrations.
Discharged effluent water quality will be maintained in accordance with Perrys National Pollution Discharge Elimination System (NPDES) permit.
All parts of the circulating water system are classified nonsafety.
Revision 21 10.4-24 October, 2019
10.4.5.3 Safety Evaluation The circulating water system is designed with cross connected discharge piping from the circulating water pumps. The pumps are equipped with separate butterfly valves which permit each circulating water pump to be isolated. Each of the four condenser waterbox circuits is provided with inlet and outlet isolation valves. Therefore, in case of a pump failure or a condenser tube leak, the circulating water system is capable of Revision 21 10.4-24a October, 2019
operating with two pumps or three trains of condenser water boxes.
Operation for extended periods with less than three pumps is also considered a mode of normal operation, when conditions permit.
The cooling tower is located at a minimum of one tower height away from the containment and any other Seismic Category I structure. Since the cooling tower is smaller at the top, the tower would tend to collapse inwardly although collapse of the tower is highly improbable.
Therefore, the potential for debris damaging any plant structure is minimal. The cooling tower is made primarily of noncombustible material.
The circulating water system is designed to prevent any injection of radioactive material into the circulating water and its subsequent release to the atmosphere through evaporation in the cooling tower. The circulating water passing through the condenser will be at a higher pressure than the shell or condensing side; therefore, any leakage (such as from a condenser tube) will be from the circulating water into the shell side of the condenser.
The circulating water system serves no safety function. Systems analysis has shown that failure of the circulating water system will not compromise any safety-related systems or prevent safe shutdown.
10.4.5.3.1 Circulating Water Expansion Joint Failure (without a turbine building mat fracture)
In the postulated case that an expansion joint in the circulating water system in the turbine building ruptures causing flooding of the turbine building, heater bay and condensate demineralizer building, the Revision 21 10.4-25 October, 2019
following precautions have been taken to preclude this flooding from affecting safety-related buildings and components (refer to <
Table 2.4-9> and
without mat fracture):
and
demonstrate that the storage volume to Elevation 599-0 within the buildings exceeds with significant margin the potential flooding water volume.
. Startup concentrations are defined to occur for periods up to a week. Extended normal operation concentrations are defined as those occurring during full power operation without condenser tube leaks.
The total capacity of condensate demineralizer resin will be measured on each lot of new resin. Total capacity analysis will be performed in accordance with approved chemistry instructions. This testing may be fulfilled by the resin supplier by providing a Certificate of Analysis for each lot, or by an independent testing facility.
Water quality will be tested in accordance with approved chemistry instructions. Analysis will be performed on grab samples for pH and chloride ion using standard industrial practice when conductivity values in the reactor water are elevated. Water conductivity will be monitored and recorded continually on the sampling panel.
The maximum effluent composition from the cleanup system based upon the influent concentrations listed in
is as follows:
Conductivity at 25C 0.1 mho/cm pH at 25C 6.5 to 7.5 Metallic Impurities Not measured at condensate effluent. Measured in feedwaterChlorideChloride concentration shall be less than 2 ppb Revision 14 10.4-31 October, 2005
10.4.6.3 System Description System descriptions for the condensate filters and mixed bed demineralizers are as follows:
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10.4.6.4 Safety Evaluation The condensate cleanup system removes some radioactive material created by corrosion, fission products and carry over from the reactor. While radioactive effects from these sources do not affect the capacity of the resin, the concentration of such radioactive material requires shielding
<Section 12.1.2>. Vent gases and other waste water from the condensate cleanup system are sent to the radwaste system for treatment and/or disposal. The addition of new regenerated resin will be done manually.
<Chapter 11> describes the activity level and removal of radioactive material from the condensate system. The condensate cleanup system complies with <Regulatory Guide 1.56> as discussed in
.
All condensate cleanup system piping and vessels are located in the nonsafety-related turbine power complex. Therefore, the effects of postulated piping failures are not analyzed.
10.4.6.5 Tests and Inspections Preoperational tests are performed on the condensate cleanup system to ensure operability, reliability and integrity of the system. Each demineralizer vessel and the resin addition equipment can be isolated during normal plant operation to permit testing and maintenance.
Conductivity requirements of the condensate cleanup system are monitored continuously. Refer to <Section 9.3.2> for sampling system points.
Revision 12 10.4-34 January, 2003
10.4.6.6 Instrumentation Application Conductivity elements are provided for the system influent and for each demineralizer vessel effluent. System influent conductivity detects condenser leakage, whereas, demineralizer effluent conductivities provide indication of resin exhaustion.
Differential pressure is monitored across the demineralizer vessels and each vessel discharge resin trap to detect blockage of flow. The flow rate through each demineralizer is monitored to ensure the even distribution of condensate flow through all operating vessels. The water quality at 93% of bed depth is monitored for each operating demineralizer to warn of impending resin exhaustion. The three tank external resin transfer equipment includes conductivity rinse monitors to ensure the completeness of preservice rinsing. Differential pressure and flow measurement indications are available at the local control panel. Conductivity instrumentation is located at the Turbine Plant Sample Panel for bed and effluent samples for each demineralizer vessel.
Conductivity readings are processed by the plant process computer and alarms are generated by the analyzers and/or the process computer to provide remote annunciation in the control room. A multipoint annunciator is included in the local panel to alarm abnormal conditions within the cleanup system. Electrical contacts for the local annunciator provide remote annunciation in the main control room. Other instrumentation includes flow indicators, pressure gauges and timers for automatic supervision of the regeneration cycle. Procedures will prevent the initiation of any automatic operation or sequence of operations which would conflict with any operation or sequence already in progress, whether such an operation is under automatic or manual control.
Revision 12 10.4-35 January, 2003
10.4.7 CONDENSATE AND FEEDWATER SYSTEM 10.4.7.1 Condensate System 10.4.7.1.1 Design Bases The condensate system transports condensate from the main condenser hotwell to the hot surge tank, maintaining proper water levels in the surge tank for all operating conditions. Condensate quality is maintained by the condensate cleanup system <Section 10.4.6>. The condensate system provides the overall steam cycle water inventory required to accommodate reactor water level variations arising from load changes. The condensate system also serves as a cooling source for the offgas condenser, the steam jet air ejector condenser and the steam packing exhauster.
10.4.7.1.2 System Description The condensate system is illustrated in <Figure 10.1-4>. The condensate system consists of three 50 percent motor driven hotwell pumps, three 50 percent motor driven condensate booster pumps, three stages of closed low pressure feedwater heaters, a direct contact heater and hot surge tank, and associated piping, valves and instrumentation. Feedwater heaters 1A, 1B, 1C, 2A, 2B, and 2C are located in the main condenser necks.
Equipment interacting with, but not part of the condensate system includes the condensate cleanup system, the offgas condenser, the steam jet air ejector condensers, and the steam packing exhauster.
The hotwell pumps take suction from the hotwell storage area below the IP condenser. The condensate is pumped through the condensate cleanup system, the offgas condenser, the steam jet air ejector condenser, and Revision 12 10.4-36 January, 2003
the steam packing exhauster, providing sufficient NPSH for the condensate booster pumps during all operating conditions. The hotwell pumps are the vertical-can centrifugal type.
The condensate booster pumps are designed to pump condensate through three stages of closed low pressure feedwater heaters and into the direct contact heater.
System flow requirements at the valves wide open (VWO) condition are met by two 50 percent capacity hotwell pumps and two 50 percent capacity booster pumps operating in series.
The direct contact heater is of the horizontal spray type and is directly mounted on a horizontal hot surge tank. The direct contact heater and hot surge tank are designed in accordance with Section VIII, Division I of the ASME Code and meet the performance criteria of the Heat Exchange Institute (HEI) and ASTM D888-66.
The low pressure feedwater heaters are shell and U-tube heat exchangers designed in accordance with Section VIII, Division I of the ASME Boiler and Pressure Vessel Code. All heaters are two zoned, i.e., each has a condensing zone and an integral drain cooling zone. Heaters No. 1 and No. 2 consist of three parallel streams, any one of which may be isolated for maintenance. Maintenance on either stream of No. 3 heaters is accomplished by isolating that stream and passing the condensate through the hand operated bypass. All condensate system piping is carbon steel, ASTM A-106 Gr. B, and conforms to ANSI B31.1. Flanged connections are provided at the pumps and strainers for ease of maintenance. The majority of the other joints and connections are welded.
Revision 12 10.4-37 January, 2003
10.4.7.1.3 Safety Evaluation Fifty percent capacity standby pumps are provided for both the hotwell and condensate booster pumps. On loss of pressure in either the hotwell or condensate booster pump discharge header, the appropriate standby pump is manually started. No detrimental effect on the reactor coolant system is realized.
System makeup is provided directly from the condensate storage tank to the highest pressure main condenser shell.
Sentinel type tube side safety relief valves are provided for all closed feedwater heaters.
A feedwater heater tube rupture will precipitate high and very high water level alarms indicating operator action required. If the magnitude of the rupture is such that the heater is flooded, the shell side safety valves will discharge to the condenser. No radioactivity is released to the environment.
The level of radioactivity in the condensate system is low enough that leakage from valve stems, etc. will not create hazards. To further protect the environment, all floor drains from areas where leaks could occur are taken to the radwaste area for processing. Two 100% capacity control valves (1N21F0220 and 1N21F0230) are provided to maintain Hot Surge Tank level. Should the first valve (1N21F0230) fail to provide sufficient flow, redundant control valve 1N21F0220 can be operated manually from the control room console by a selector switch/potentiometer to maintain flow to the Direct Contact Heater and the downstream Hot Surge Tank.
A three-element control loop (condensate flow, feedwater flow and hot surge tank level) is provided to maintain hot surge tank level over the entire plant load range, including load changes and upsets. The loop Revision 12 10.4-38 January, 2003
executes this function by regulating the condensate flow into the hot surge tank to the value required for replacement of the feedwater leaving the surge tank. This enhances the response of the entire condensate-feedwater-steam cycle.
Any pressure, temperature or flow deviation due to a malfunction in the condensate system will not be immediately felt by the reactor coolant system due to the storage capacity in the hot surge tank, (two minute retention time), and the feedwater system. The storage capacity will allow either corrective actions to be taken or an orderly runback to a compatible load or shutdown.
Conductivity instrumentation is provided to monitor condenser leakage.
The condensate demineralizer system is designed to accept condenser leakage during normal operation.
During plant start-up, a 4 inch bypass line is used to fill the Hot Surge Tank. This line is isolated during normal plant operation. This bypass is manually operated and is isolated during normal plant operations.
10.4.7.1.4 Tests Periodic inspection will be made of all major equipment to ensure proper inservice operation.
The closed low pressure feedwater heaters are given both shell and tube side hydrostatic tests of 1.5 times the respective design pressures.
10.4.7.1.5 Instrumentation Condensate flow control instrumentation measures the feedwater and condensate flow rates, and hot surge tank level. These measurements are used to regulate the condensate flow to the No. 4 (Direct Contact Revision 16 10.4-39 October, 2009
Heater) through the 100% capacity condensate control valve 1N21F0230.
The condensate control valve, 1N21F0230, controls via signals from surge tank level, feedwater flow, and condensate flow. The redundant 100%
Revision 16 10.4-39a October, 2009
capacity control valve (1N21F0220) has an independent control loop with its own power supply and can be operated manually from the control room console by a selector switch/potentiometer.
Minimum flow requirements for the hotwell pumps, condensate booster pumps, the steam jet air ejector condenser, and the steam packing exhauster are met by a common recirculation line downstream of the condensate booster pumps. Flow through the recirculation line is regulated by a modulating control valve receiving a signal from a flow transmitter upstream of the offgas condenser.
Measurements of pump suction and discharge pressures are provided for all pumps in the system.
Temperature measurements are provided for each stage of feedwater heating. These measurements include the low pressure feedwater flow temperatures into and out of each feedwater heater and drain water temperatures from each heater.
Instrumentation and controls are provided for regulating heater drain flow rate to maintain proper condensate level in each feedwater heater shell. High level alarm, automatic operation of the alternate drain control valve at high level, and automatic isolation on high level of the cascaded drain valve and extraction valve are provided.
10.4.7.2 Feedwater System 10.4.7.2.1 General The feedwater system is designed to pump condensate from the direct contact heater hot surge tank through two stages of feedwater heating to maintain the reactor vessel water level. Reactor feedwater flow is Revision 12 10.4-40 January, 2003
automatically controlled to maintain vessel water level within predetermined levels during all modes of plant operation.
10.4.7.2.2 Design Basis The design requirements of the feedwater system are: for piping, valves, and pressure parts, the design pressures under normal and upset conditions are as tabulated on the right margin of the feedwater system diagrams <Figure 10.1-3> and <Figure 10.1-8>. The upset condition tabulated is considered to be the shutoff head of the feedwater heater or main feed pumps, and is expected to occur less than one percent of the time. Design conditions and requirements of the portion of the feedwater system from the outermost isolation valve to the reactor are covered in <Section 5.4.9>.
Pressure vessels will be designed to Section VIII, Division 1 of the ASME Boiler and Pressure Vessel Code. Piping will be designed to ANSI B31.1.
10.4.7.2.3 System Description The feedwater system is comprised of: four, one-third capacity motor driven booster pumps, one stage of intermediate pressure heating with external drain cooler, two nominal half capacity horizontal reactor feedwater pumps with variable speed turbine drives, one 20 percent capacity motor driven reactor feedwater pump, one stage of high pressure heating, valves, instrumentation and controls, and associated piping.
Three booster pumps take water from the hot surge tank and discharge it through one stage of heating to the reactor feed pump suction. Both feed pumps discharge water through one stage of high pressure heaters into a mixing header before passing through two parallel feedwater shutoff valves to the reactor.
Revision 12 10.4-41 January, 2003
Reactor feedwater flow is controlled automatically to maintain water in the reactor vessel within predetermined levels during all modes of plant operation. The system normally operates as a three element control using reactor vessel water level, steam flow and feedwater flow signals to control feedwater flow by adjusting the speed of the reactor feedwater pump turbines.
Three of the four booster pumps are required for normal operation with the fourth pump on standby. The standby booster pump will be started automatically in the event of a trip of an operating booster pump or low NPSH in the reactor feedwater pump suction header. Booster pumps are manually started from the control room.
Intermediate pressure Heaters 5A and 5B heat the feedwater using steam extracted from the high pressure turbine exhaust. They are shell and U-tube heat exchangers designed to ASME Section VIII, and have a condensing zone only. The drain coolers are horizontal, single pass heat exchangers and are also designed to ASME Section VIII.
Two nominal half capacity reactor feedwater pumps provide the feedwater required at all load points. Minimum flow recirculation for the turbine driven feedwater pumps is provided by lines to the hot surge tank.
Individual pump suction flow elements provide flow control for the recirculation valves.
In the case of one inoperative feedwater pump, the remaining pump and a motor driven pump will deliver 80 percent of nuclear boiler rated feedwater flow at no less than 1,060 psia at the reactor vessel feedwater sparger inlet.
Horizontal reactor feed pumps are connected directly to variable speed turbine drives. The dual admission turbines normally take steam from the main turbine crossover steam line after the moisture separators and reheaters. For startup and low load conditions the turbines are driven Revision 12 10.4-42 January, 2003
by main steam. A control system regulates feedwater flow to maintain reactor water level by controlling the admission of steam to the turbine drives.
Feedwater is heated in Heaters 6A and 6B by high pressure extraction steam. These heaters are shell and U-tube heat exchangers designed to ASME Section VIII, with a condensing zone and an integral drain cooling zone.
10.4.7.2.4 Safety Evaluation Upon failure of one of the two normally operating reactor feedwater pumps or their turbine drives, a motor driven feed pump will be started automatically in less than ten seconds. The remaining turbine driven pump and the motor driven pump will provide 80 percent of rated flow to prevent reactor scram or actuation of RCIC.
A feedwater heater tube rupture will precipitate high and very high water level alarm, indicating operator action required. The closure of the extraction line valves is automatically initiated. If the magnitude of the rupture is such that the heater is flooded, the shell side safety valves will discharge to the condenser. No radioactivity will be released to the environment.
The level of radioactivity in the feedwater system is low enough that leakage from valve stems, etc. will not create hazards. To further protect the environment, all floor drains for areas where leaks could occur are taken to the radwaste area for processing.
In the event of the loss of feedwater, the reactor is tripped and the RCIC system is actuated. The most severe case is a guillotine break of the feedwaterheader outboard of the reactor containment vessel. The analysis of the consequences of this postulated incident is discussed in
<Chapter 15>.
Revision 12 10.4-43 January, 2003
The reactor can be isolated from the feedwater system by the following three independent valves in each of the two feedwaterheaders:
.
10.4.8 STEAM GENERATOR BLOWDOWN SYSTEM This section is not applicable to PNPP.
Revision 12 10.4-45 January, 2003
10.4.9 AUXILIARY FEEDWATER SYSTEM This section is not applicable to PNPP.
10.4.10 REFERENCES FOR SECTION 10.4
| ML21361A213 | |
| Person / Time | |
|---|---|
| Site: | Perry  |
| Issue date: | 12/20/2021 |
| From: | Energy Harbor Nuclear Corp |
| To: | Office of Nuclear Reactor Regulation |
| Shared Package | |
| ML21361A235 | List:
|
| References | |
| L-21-287 | |
| Download: ML21361A213 (94) | |
Text
TABLE OF CONTENTS Section Title Page 10.0 STEAM AND POWER CONVERSION SYSTEM 10.1-1 10.1
SUMMARY
DESCRIPTION 10.1-1 10.2 TURBINE GENERATOR 10.2-1 10.2.1 DESIGN BASES 10.2-1 10.
2.2 DESCRIPTION
10.2-2 10.2.2.1 Turbine Generator 10.2-2 10.2.2.2 Electrohydraulic Control System 10.2-3 10.2.2.3 Turbine Overspeed Protection System 10.2-5 10.2.2.4 Turbine Protection System 10.2-7 10.2.3 TURBINE DISK INTEGRITY 10.2-11 10.2.3.1 Materials Selection 10.2-11 10.2.3.2 Fracture Toughness 10.2-11 10.2.3.3 High Temperature Properties 10.2-12 10.2.3.4 Turbine Disk Design 10.2-12 10.2.3.5 Preservice Inspection 10.2-13 10.2.3.6 Inservice Inspection 10.2-14 10.2.4 EVALUATION 10.2-17 10.2.5 HYDROGEN AND CARBON DIOXIDE SYSTEMS 10.2-19 10.2.5.1 Power Generation Design Bases 10.2-19 10.2.5.2 System Description 10.2-20 10.2.5.3 System Evaluation 10.2-20 10.2.5.4 Tests and Inspection 10.2-23 10.
2.6 REFERENCES
FOR SECTION 10.2 10.2-23 10.3 MAIN STEAM SUPPLY SYSTEM 10.3-1 10.3.1 DESIGN BASES 10.3-1 10.
3.2 DESCRIPTION
10.3-2 10.3.3 EVALUATION 10.3-2 10.3.4 INSPECTION AND TESTING REQUIREMENTS 10.3-3 10.3.5 WATER CHEMISTRY (PWR) 10.3-4 Revision 12 10-i January, 2003
TABLE OF CONTENTS Section Title Page 10.3.6 STEAM AND FEEDWATER SYSTEM MATERIALS 10.3-4 10.3.6.1 Fracture Toughness 10.3-4 10.3.6.2 Material Selection and Fabrication 10.3-5 10.4 OTHER FEATURES OF STEAM AND POWER CONVERSION SYSTEM 10.4-1 10.4.1 MAIN CONDENSER 10.4-1 10.4.1.1 General 10.4-1 10.4.1.2 Design Bases 10.4-1 10.4.1.3 System Description 10.4-3 10.4.1.4 Safety Evaluation 10.4-5 10.4.1.5 Tests and Inspections 10.4-7 10.4.1.6 Instrumentation 10.4-8 10.4.2 MAIN CONDENSER EVACUATION SYSTEM 10.4-9 10.4.2.1 General 10.4-9 10.4.2.2 Design Bases 10.4-9 10.4.2.3 System Description 10.4-10 10.4.2.4 Safety Evaluation 10.4-11 10.4.2.5 Tests and Inspections 10.4-12 10.4.2.6 Instrumentation 10.4-12 10.4.3 TURBINE GLAND SEALING SYSTEM 10.4-12 10.4.3.1 Steam Seal Evaporator 10.4-13 10.4.4 TURBINE BYPASS SYSTEM 10.4-16 10.4.4.1 Design Basis 10.4-16 10.4.4.2 System Description 10.4-16 10.4.4.3 Safety Evaluation 10.4-19 10.4.4.4 Tests and Inspections 10.4-20 10.4.4.5 Instrumentation Application 10.4-21 10.4.5 CIRCULATING WATER SYSTEM 10.4-21 10.4.5.1 Design Basis 10.4-21 10.4.5.2 System Description 10.4-22 10.4.5.3 Safety Evaluation 10.4-24 10.4.5.4 Tests and Inspections 10.4-29 10.4.5.5 Instrumentation Application 10.4-29 Revision 12 10-ii January, 2003
TABLE OF CONTENTS (Continued)
Section Title Page 10.4.6 CONDENSATE CLEANUP SYSTEM 10.4-30 10.4.6.1 General 10.4-30 10.4.6.2 Design Bases 10.4-30 10.4.6.3 System Description 10.4-32 10.4.6.4 Safety Evaluation 10.4-34 10.4.6.5 Tests and Inspections 10.4-34 10.4.6.6 Instrumentation Application 10.4-35 10.4.7 CONDENSATE AND FEEDWATER SYSTEM 10.4-36 10.4.7.1 Condensate System 10.4-36 10.4.7.2 Feedwater System 10.4-40 10.4.7.3 Failure Modes and Effects Analysis 10.4-45 10.4.8 STEAM GENERATOR BLOWDOWN SYSTEM 10.4-45 10.4.9 AUXILIARY FEEDWATER SYSTEM 10.4-46 10.4.10 REFERENCES FOR SECTION 10.4 10.4-46 Revision 12 10-iii January, 2003
LIST OF TABLES Table Title Page 10.2-1 Turbine Overspeed Protection System Failure Analysis 10.2-24 10.4-1 Condensate Cleanup System Influent Concentrations 10.4-47 10.4-2 Failure Modes and Effects Analysis Feedwater and Condensate Systems 10.4-48 10.4-3 Main Condenser Design Data 10.4-49 10.4-4 Turbine Bypass Valve Design Data 10.4-53 Revision 12 10-iv January, 2003
10.0 STEAM AND POWER CONVERSION SYSTEM 10.1
SUMMARY
DESCRIPTION The steam and power conversion system for the Perry Nuclear Power Plant is rated at approximately 1,327.6 MW of gross electrical output. An 1,800 rpm, six flow, tandem compound reheat turbine with 43-inch last stage blades will drive a 1,446,700 kVA (with the capability of operating at 1,513,556 kVA at 0.90 power factor), 1,800 rpm, direct connected, 22,000 volt, 3 phase, 60 Hertz, conductor cooled, synchronous generator. Equipment for regenerative feedwater heating, pumping to required pressure, condensate purification, and various auxiliary systems complete the power conversion system.
Main steam from the nuclear boiler system flows to the main turbine generator through four main steam lines. Steam is diverted from the main steam for reheating purposes, seal steam generation, offgas preheaters, reactor feed pump turbines during startup, and steam jet air ejectors. Main steam enters the high pressure turbine, flows through the blade paths and exhausts to the moisture separator reheaters, where moisture is removed and the steam is slightly superheated. Steam then enters the three low pressure turbines, flows through the blade paths and exhausts to the three shells of the condenser.
Steam is extracted at several points in the main turbine cycle for regenerative feedwater heating, for driving the reactor feed pump turbines and for the seal steam evaporator during normal operation.
The condenser condenses the exhaust flows from the turbine as well as other miscellaneous flows from the cycle. Condensate is taken from the hotwell of the intermediate pressure condenser and is pumped by the hotwell pumps through the condensate filter/demineralizer systems, the offgas condenser, the steam packing exhauster, and the steam jet air ejector condensers to the suction of the condensate booster pumps.
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These pumps send the condensate through three closed feedwater heaters to the direct contact feedwater heater and hot surge tank. Feedwater is taken from the hot surge tank by the feedwater booster pumps and is pumped through one stage of intermediate pressure feedwater heating to the suction of the reactor feed pumps. These pumps force feedwater through one stage of high pressure feedwater heating to the nuclear boiler system inlet.
Water for condensing the steam in the condenser is circulated in a closed loop system that releases the heat to atmosphere through a natural draft cooling tower <Section 10.4.5>.
A turbine bypass system capable of bypassing 28.8 percent (nominal) of the full load main steam flow directly to the condenser is provided for startup and load changing operation.
The following system diagrams are included:
- a. Main and reheat steam <Figure 10.1-1 (1)>
<Figure 10.1-1 (2)>
<Figure 10.1-1 (3)>
- b. Extraction steam <Figure 10.1-2>
- c. Feedwater <Figure 10.1-3 (1)>
<Figure 10.1-3 (2)>
- d. Condensate (main) <Figure 10.1-4 (1)>
<Figure 10.1-4 (2)>
- e. Condensate filters <Figure 10.1-5 (1)>
<Figure 10.1-5 (2)>
<Figure 10.1-5 (3)>
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- f. Condensate demineralizers <Figure 10.1-6 (1)>
<Figure 10.1-6 (2)>
<Figure 10.1-6 (3)>
<Figure 10.1-6 (4)>
- g. Circulating water <Figure 10.1-7>
- h. High pressure heater drains and vents <Figure 10.1-8 (1)>
<Figure 10.1-8 (2)>
<Figure 10.1-8 (3)>
<Figure 10.1-8 (4)>
- i. Low pressure heater drains and vents <Figure 10.1-9>
- j. Steam seal system <Figure 10.1-10>
- k. Condenser air removal <Figure 10.1-11>
The following heat balances are included:
- a. Rated power <Figure 10.1-12>
- b. Designed power (valves wide open) <Figure 10.1-13>
Design and performance characteristics are listed on the figures for each respective system.
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The only portions of the steam and power conversion system (balance of plant) that are safety-related are:
- a. For the main steam system - outer containment isolation valve (B21-F028A,B,C,D) to the outermost system isolation valve (N11-F020A,B,C,D).
- b. For the feedwater system - from the first system isolation valve (B21-F065A,B) to the reactor.
These portions of the main steam and feedwater systems are Safety Class 1 and 2, and Seismic Category I. Refer to <Section 10.3>,
<Section 10.4.7>, and <Section 5.4.9> for further discussion.
System instrumentation is discussed, in general, in <Section 10.2>,
<Section 10.3>, and <Section 10.4>. Safety-related instrumentation associated with this system is discussed in <Section 7.2>,
<Section 7.3>, and <Section 7.7>.
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10.2 TURBINE GENERATOR 10.2.1 DESIGN BASES The General Electric Model TC6F-43 LSB turbine generators are tandem compound, six flow reheat units. The 1,800 rpm turbine generator produces a gross generator output of approximately 1,327.6 MWe with all feedwater heaters in service and with a nominal plant exhaust pressure of 1 inch Hg (absolute) and zero makeup. Steam conditions at the turbine inlet are 937 psia and 1,190.8 Btu/lb. Normal and upset conditions are shown on <Figure 10.1-1 (1)>.
The unit is expected to operate in the base load mode for the majority of its design life. Normal load swings are limited to the rate of change of the NSSS. Within these limitations, the turbine generator is capable of accepting a load reduction from 100 percent to approximately 71 percent (using the 28.8 percent nominal bypass) and automatically returning to rated power.
Functional limitations imposed by design characteristics of the reactor coolant system are as follows:
- a. Turbine Stop Valve During any event resulting in turbine stop valve fast closure, turbine inlet steam flow must not be reduced faster than permitted by <Figure 10.2-1>.
- b. Turbine Control Valve The turbine control valves are capable of full stroke openings of 10 seconds (nominal) and closures in 7 seconds nominal for adequate pressure control performance. During any event resulting in Revision 19 10.2-1 October, 2015
turbine control valve fast closure, turbine inlet steam flow cannot be reduced faster than permitted by <Figure 10.2-2>.
The turbine generator and associated equipment are designed and manufactured in accordance with the appropriate sections of the ASME Boiler and Pressure Vessel Code (
, Note 12) and the General Electric Company standards and specifications. 10.2.2 DESCRIPTION
10.2.2.1 Turbine Generator The turbine consists of four casings, a double-flow high pressure section, followed by three double-flow, low pressure casings. The 6 last stages have 43-inch buckets.
The 1,800 rpm generator is 3 phase, 60 hertz, rated 1,446,700 kVA with the capability of operating at 1,513,556 kVA at 0.90 power factor at 22,000 volts, and 75 psig hydrogen pressure.
A shaft driven alternator exciter rated at 3,410 kW provides the necessary dc supply for exciting the field.
An electrohydraulic control system, using electronic computing devices and high pressure fire-resistant fluid, actuates and controls the steam valves. This system is completely separated from the bearing oil supply. During normal operation the turbine control valves act to maintain constant upstream pressure, while the reactor recirculation is controlled according to load demand.
The turbine generator pressure regulator instrumentation and controls are described in <Section 7.7.1> and <Section 7.7.2>. The inservice inspection program for the main steam reheat valves is discussed in
<Section 10.2.3.6>.
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A set of seven bypass valves with a nominal capacity of 28.8 percent of full load throttle flow is installed immediately upstream of the inlet stop valves. The bypass valves permit rapid load reduction, up to 28.8 (nominal) percent capacity, without requiring that the reactor be tripped. During the PNPP startup program a measurement of the turbine bypass capacity demonstrated that the capacity of each of the seven (7) bypass valves is essentially equal. No direct means are available for measuring total bypass valve flow during startup testing.
Furthermore, analysis was performed to conclude that turbine bypass capacity as low as 25 percent NBR does not affect the bounding CPR results presented in- a. One on the high pressure turbine cylinder (Heater No. 6).
- b. One on the moisture separator (Heater No. 5).
- c. Four on each of the three low pressure turbine cylinders (Heater Nos. 4, 3, 2, and 1).
- a. Speed control unit
- b. Load control unit
- c. Flow control unit The speed control unit receives speed signals from the shaft speed pickups, which are compared to a speed reference signal, to produce a speed/error signal. The speed control unit also differentiates the speed signals to produce acceleration signals. These signals are compared to the acceleration reference to produce acceleration error signals that are integrated and combined with the speed/error signal, to produce an output to the load control unit.
- a. A mechanical overspeed trip test at the EHC Panel to test for operation of the overspeed trip device and mechanical trip valve.
- b. A mechanical trip piston test at the EHC panel to test for electrical activation of the trip mechanism.
- c. An electrical trip test at the EHC panel to test for operation of the electrical trip valve.
- d. A backup overspeed trip test at the EHC panel to test the 2 out of 3 logic circuits.
- a. Loss of vacuum trip.
- b. Excessive thrust bearing wear.
- c. Prolonged loss of generator stator coolant at loads in excess of a preset value.
- d. External trip signals, including remote-manual trip on the control panel.
- e. Loss of hydraulic fluid supply pressure (loss of emergency trip system fluid pressure automatically closes the turbine valves and then energizes the master trip relay to prevent a false restart).
- f. Low bearing oil pressure.
- g. Loss of both speed signals when turbine is not in standby control.
- h. (Deleted)
- i. (Deleted)
- j. Loss of 125-volt dc electrohydraulic control power supply when turbine is operating at less than 75 percent rated speed.
- k. Loss of 24-volt dc electrohydraulic control power supply.
- l. High level in moisture separators.
- m. High reactor water level.
- n. Low shaft pump discharge pressure when turbine is operating at greater than 75 percent of rated speed.
- o. Operation of the manual mechanical trip at the front standard.
- p. Low bearing oil pressure to the trip piston.
- q. RCIC initiation signal. (This signal may be delayed by a maximum of 5 minutes when steam line flows are 100 feet/second, as sensed by Main Turbine First Stage Pressure).
- a. 345 kV breaker failure.
- b. Main transformer differential.
- c. Deleted
- d. Main transformer 345 kV neutral overcurrent.
- e. Unit 345 kV bus differential.
- f. Unit auxiliary transformer neutral overcurrent X.
- g. Unit auxiliary transformer neutral overcurrent Y.
- h. Unit auxiliary transformer sudden pressure.
- i. Unit auxiliary transformer differential.
- j. Generator volts/Hertz.
- k. Generator stator energized with machine at low speed (generator dead machine protection).
- l. Underfrequency with generator connected to system.
- m. Negative sequence overcurrent with generator connected to system.
- n. Generator loss of excitation with voltage balance supervision, generator connected to system.
- o. Generator out of step with generator connected to system, current and voltage balance supervision.
- p. Sustained generator overexcitation.
- q. Generator neutral overvoltage.
- r. Generator differential No. 1.
- s. Generator differential No. 2.
- t. Unit overall differential.
- u. Zero sequence overvoltage with voltage balance supervision.
- v. Reverse power with voltage balance supervision.
- w. Unit auxiliary transformer secondary overcurrent.
- a. Turbine shaft bearings are designed to retain structural integrity under normal operating loads and anticipated transients, including those leading to turbine trips.
- b. The multitude of natural critical frequencies of the turbine shaft assemblies existing between zero speed and 20 percent overspeed are controlled in the design and operation so distress to the unit during operation does not occur.
- c. The maximum tangential stress in wheels and rotors resulting from centrifugal forces, interference fit and thermal gradients will not exceed 0.75 of the yield strength of the materials at 115 percent of rated speed.
- a. Wheel and rotor forgings are rough machined with minimum stock allowance prior to heat treatment.
- b. Each finish machined wheel and rotor is subjected to 100 percent volumetric (ultrasonic), surface and visual examinations using General Electric acceptance criteria. These criteria are more restrictive than those specified for Class 1 components in the ASME Boiler and Pressure Code, Sections III and V, and include the requirement that subsurface sonic indications are either removed or evaluated to assure that they will not grow to a size which will compromise the integrity of the unit during the service life of the unit.
- c. All finish-machined surfaces are subjected to a magnetic particle test with no flaw indications permissible.
- d. Each fully bucketed turbine rotor assembly is spin tested at or above the maximum speed anticipated following a turbine trip from full load.
- a. A thorough volumetric examination of low pressure rotors and high pressure rotors, including areas immediately adjacent to keyways and bores.
- b. Visual examination of accessible surfaces of rotors.
- c. Visual and surface examination of low pressure buckets.
- a. Perform dismantled inspections, at no more than twelve year intervals for individual valves, within the following valve groups: (1) Main Turbine Stop Valves, (2) Main Turbine Control Valves, (3) Main Turbine Reheat Intermediate Stop Valves, (4) Main Turbine Reheat Intercept Valves and (5) Extraction Steam Valves.
- b. Turbine stop, turbine control, reheat stop and intercept valves, and the turbine overspeed trip mechanism will be exercised by closing each valve or performing the overspeed trip test and observing, by the valve position indicator, that the valves move Revision 22 10.2-16 October, 2021
- c. During normal unit operation, the critical power assisted extraction non-return valves will be tested weekly by partially closing the valves using the solenoid test valves.
- a. noble gases 1 (100% carry over)
- b. halogens 0.02
- c. other fission products 0.001 The activity entering the low pressure turbine is reduced further by moisture separation between the high pressure and low pressure turbines.
- a. The hydrogen and carbon dioxide systems are designed to provide the necessary flow and pressure at the main turbine generator:
- 1. During startup when air is purged from the generator by carbon dioxide.
- 4. During shutdown when carbon dioxide is purged from the generator by air.
- 5. During normal operation where hydrogen can be supplied to the generator as necessary to make up for generator hydrogen leakage.
- b. The unit has a hydrogen bulk storage system. Hydrogen supply to the generator is also being provided from the connection to the Hydrogen Water Chemistry supply piping for the plant.
- c. (Deleted)
- d. Should the carbon dioxide portion of the subject system fail, the plant could continue in normal operation. Should the hydrogen portion of the subject system fail, the plant could continue in normal operation in accordance with the turbine generator manufacturer's requirements.
- 1. Headers are located to prevent physical damage to pipe.
- 3. Headers are routed through ventilated areas.
- a. During normal operation, hydrogen is used to cool the generator.
- b. Hydrogen removal from the generator before it is opened for maintenance While the generator is at standstill or on turning gear operation and the shaft sealing system is in operation, carbon dioxide is admitted into the generator, maintaining a pressure between specified limits in the generator casing, until the carbon dioxide concentration in the discharge is in excess of 95 percent measured by a gas tester. When hydrogen is being purged from the casing, Revision 12 10.2-21 January, 2003
- c. Air leakage test of the hydrogen cooled generator While the generator is at a standstill or on turning gear and the shaft sealing system is in operation, an air leakage test will be performed prior to the initial startup of the hydrogen cooled generator and after the generator has been opened for maintenance.
- d. Air removal from the generator before hydrogen fill following maintenance While the generator is at a standstill or on turning gear operation and the shaft sealing system is in operation, carbon dioxide will be admitted to the bottom of the generator through carbon dioxide distribution piping, and air in the generator will be discharged to atmosphere through the hydrogen feed pipe.
- e. Filling generator with hydrogen When the air has been displaced by carbon dioxide as determined by the gas analyzer, hydrogen is admitted to the top of the generator through the sparger and carbon dioxide is vented to atmosphere through the lower sparger, where it was originally admitted. When Revision 12 10.2-22 January, 2003
2.6 REFERENCES
FOR SECTION 10.2
- 1. Letter, A. Kaplan (CEI) to U.S. Nuclear Regulatory Commission (NRC), USAR Appendix 1B Commitment No.4 - Turbine System Maintenance Program, PY-CEI/NRR-0977L, March 20, 1989.
- 2. Letter, U.S. Nuclear Regulatory Commission (NRC) to A. Kaplan (CEI), Turbine System Maintenance Program, Perry Nuclear Power Plant Unit No. 1 (TAC No. 72835), PY-NRR/CEI-0478L, August 23, 1989.
- 3. Safety Analysis Report for Perry 5% Thermal Power Uprate, NEDC-32907P, September 1999.
- 4. Letter, U.S. Nuclear Regulatory Commission (NRC) to S. Dembkowski (Siemens-Westinghouse Power Corporation), Safety Evaluation for Acceptance of Referencing the Siemens-Westinghouse Topical Report, Missile Analysis Methodology for General Electric (GE) Nuclear Steam Turbine Rotors by the Siemens-Westinghouse Power Corporation (SWPC) (TAC No. MB 5679), April 2, 2003.
- 5. Letter, M. Burnett (GE Energy) to FENOC, Turbine Missile Analysis Statement, FirstEnergy - Perry Nuclear Unit 1, Turbine #170X655, Rebuild #1LX0537, April 19, 2010.
Revision 18 10.2-23 October, 2013
TABLE 10.2-1 TURBINE OVERSPEED PROTECTION SYSTEM FAILURE ANALYSIS Component Malfunction Comment Steam Valve One valve fails to close All steam valves are in pairs in series.
(MSV, CV, IV, ISV) on overspeed trip Thus, failure of one valve to close does not defeat overspeed protection.
Turbine Extraction One valve fails to close The overspeed potential of the feedwater Non-return Valve heating system is small. The total energy addition due to any single extraction valve failure can contribute no more than 3 percent to the running speed of the turbine generator.
Mechanical Trip Fails to drop ETS pressure The backup electrical overspeed trip Valve upon actuation of de-energizes the master trip solenoid valve mechanical overspeed trip which, in turn, results in a drop in ETS pressure.
Revision 12 10.2-24 January, 2003
TABLE 10.2-1 (Continued)
Component Malfunction Comment Master Trip Fails to drop ETS pressure The mechanical overspeed trip actuates the Solenoid Valve upon actuation of overspeed mechanical trip valve which, in turn, results trip in a drop in ETS pressure.
Hydraulic Trip Piping fails causing All steam valves close as in overspeed trip.
System Piping depressurization DC Electric Power Power supply is lost Loss of two speed signals causes master trip Supply solenoid valve to be de-energized which, in turn, results in a drop in ETS pressure.
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10.3 MAIN STEAM SUPPLY SYSTEM 10.3.1 DESIGN BASES The main steam system is designed to convey the steam produced in the nuclear boiler system from the outermost containment isolation valves to the turbine stop valves, offgas preheaters, the moisture separator/reheaters, and the condenser steam jet air ejectors. Also provided are valves for bypassing the main turbine to the condenser, a steam supply to the reactor feedpump turbines for the startup and low load operation and a steam supply to the gland steam evaporator. The system is shown on <Figure 10.1-1>.
To prevent a failure that could lead to the release of radioactivity, the main steam system is designed to accommodate the most severe conditions of coincident pressure, temperature and loading.
Furthermore, system components are located in a shielded, restricted area to safeguard personnel from radiation.
If a postulated break occurs, radiation levels will not exceed the guideline values discussed in <Chapter 15>.
The main steam system from the outer containment isolation valve (B21-F028A,B,C,D) up to and including the third shutoff valve (N11-F020A,B,C,D) is classified as Safety Class 2, Seismic Category I, and all pressure parts conform to the ASME Boiler and Pressure Vessel Code,Section III, Class 2. The remainder of the system downstream of the third isolation valves is nonsafety class and conforms to ANSI B31.1.0.
Revision 12 10.3-1 January, 2003
Performance requirements, including design pressures and temperatures for pressure parts, are tabulated on the right margin of the system diagram. The upset condition tabulated is considered to be the condition existing during safety valve operation and is expected to exist less than one percent of the time.
10.
3.2 DESCRIPTION
The principal components of the main steam system are the main steam piping and connected systems. The main steam piping consists of four 28-inch O.D. Schedule 100 lines from the outer containment isolation valves to the main turbine stop valves, and connecting lines to supply steam to the second stage reheater, the condenser steam jet ejectors, offgas preheaters, the main turbine bypass valves, the reactor feedpump turbines, and the seal steam evaporator. All piping in the system is carbon steel.
10.3.3 EVALUATION The steam flow limiting devices and the flow measurement instrumentation are included in the nuclear boiler system and are discussed in
<Section 5.4.4>.
The piping in the main steam system is designed to withstand the maximum upset conditions listed in the tabulation of design requirements.
Safety-related equipment and piping located in the auxiliary building portion of the steam tunnel are protected from the effects of postulated phenomena occurring outside this area. Pipe restraints are provided to protect piping and valves from the effects of pipe rupture from any cause. A moment resisting pipe restraint system is provided for both the main steam and feedwater system. The system consists of two restraint locations for each system to provide a couple type moment resistance. Both restraint locations are in the safety-related portion of the steam tunnel in the auxiliary building. One of the two Revision 12 10.3-2 January, 2003
restraints is located adjacent to the point at which the classification of the steam tunnel changes. Therefore, effects of pipe rupture downstream of the motor-operated stop valves will not be transmitted to the isolation valves <Figure 10.3-1>. Impingement shields are provided where necessary to protect equipment from any postulated water, steam or missile impingement. These accident conditions and their effects on the main steam line are considered in <Section 3.6>. They are classified as faulted conditions and their results are compared with the applicable criteria of the ASME Boiler and Pressure Vessel Code Section III, Class 2.
Under operational basis and safe shutdown earthquake conditions, detailed seismic and stress analyses will be performed on the Safety Class 2 portion of the system; results of these analyses will be compared with the applicable criteria of the ASME Boiler and Pressure Vessel Code Section III, Class 2.
The turbine bypass valves are designed to control excess flow from the nuclear boiler system to the main turbine and are described in
<Section 10.4.4>.
The system as described complies with the letter from Mr. Joseph M. Hendrie, Deputy Director for Technical Review, Directorate of Licensing, USAEC, to Mr. John A. Hinds, Manager, Safety and Licensing, General Electric Company, dated April 19, 1974. This letter, and Attachment A to the Hendrie to Hinds letter, outlines a system classification which is an acceptable alternate to the requirements of
<Regulatory Guide 1.26>.
10.3.4 INSPECTION AND TESTING REQUIREMENTS The system boundary subject to inservice inspection extends from the nuclear boiler system (B21-F028A,B,C,D) to include the outer containment Revision 12 10.3-3 January, 2003
isolation valve in the main steam system (N11-F020A,B,C,D). The design, inservice inspection and testing of the main steam components included in this boundary are described in <Section 5.4.9>.
The main steam components which are not part of the system boundary will not be subjected to inservice inspection.
Preoperational and inservice testing and inspection requirements of the main steam isolation valves are included in <Section 5.4.5.4>.
Valves installed in the main steam system will be hydrostatically tested in accordance with ANSI B16.5 or MSS SP-66. The system when installed will be tested in accordance with Paragraph NC-6100 of Section III of the ASME Boiler and Pressure Vessel Code.
10.3.5 WATER CHEMISTRY (PWR)
This section is not applicable to PNPP, since BWR water is not chemically treated.
10.3.6 STEAM AND FEEDWATER SYSTEM MATERIALS 10.3.6.1 Fracture Toughness Charpy V notch tests are specified for ferretic materials used in safety-related feedwater and main steam system components where nominal pipe size exceeds 6 inches and material section thickness exceed 5/8 inch. Test methods and acceptance criteria for fracture toughness are in compliance with ASME Code Section III.
Revision 12 10.3-4 January, 2003
10.3.6.2 Material Selection and Fabrication ASME Class 2 and ASME Class 3 materials used in the main stream and feedwater systems are included in Appendix I to Section III of the ASME Code.
No austenitic stainless steel components are used in safety-related portions of the main steam and feedwater systems.
Cleaning and handling of ASME Class 2 and ASME Class 3 components is performed in accordance with the recommendations of <Regulatory Guide 1.37> and the requirements of ANSI N45.2.1.
Preheat temperatures used for welding of safety-related portions of the main steam and feedwater systems are in accordance with the recommendations of <Regulatory Guide 1.50>, and Section III Article D-1000 of the ASME Code.
Welder qualifications for welds made in areas of limited access are in accordance with the recommendations of <Regulatory Guide 1.71>.
Nondestructive examination of ASME Class 2 and 3 tubular products is performed in accordance with the ASME Code Section III (Winter 1975),
Paragraphs NC2550 through NC2569 and Paragraphs ND2550 through ND2569.
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10.4 OTHER FEATURES OF STEAM AND POWER CONVERSION SYSTEM 10.4.1 MAIN CONDENSER 10.4.1.1 General The main condenser acts as a heat sink for the three low pressure turbine exhausts, limiting the back pressure and thus increasing the amount of available work from the turbines. The main condenser serves as a collection point for turbine bypass steam, moisture separator-reheater relief valve flow and other flows. The main condenser also deaerates and provides storage capacity for the condensate which is reused after a period of radioactive decay.
10.4.1.2 Design Bases The design bases for the main condenser are as follows:
- a. The main condenser is designed to accept the influents specified in
- b. The main condenser is designed to accept 35 percent of the pre-power uprate design main steam flow through the turbine bypass.
- c. The main condenser is designed to accept approximately 11.2 x 106 pounds per hour of steam from the moisture separator-reheater (MSR) shell side relief valves for a maximum period of one minute. Of all of the relief valves discharging to the main condenser only the reheat steam relief valves, which discharge after inadvertent closure of the reheat stop valves, affect the heat load on the condenser to any extent during a transient condition. For this case the heat load is higher than during normal operation.
- d. The main condenser hotwell is capable of maintaining a minimum water level corresponding to a retention time of three minutes (approximately 77,000 gallons) at all times for radiation decay.
- e. Circulating water passes through the three main condenser shells in series. Four separate circulating water circuits and conductivity elements for leakage detection are provided, allowing unit operation without a severe load reduction or trip if one circuit requires removal from service to plug a leaking tube.
- f. Internal cleanliness of the Type 304 main condenser tubes is maintained through the use of chemicals and biocide.
- g. To prevent tube failure during operation of the turbine bypass, direct steam impingement on the tubes is prohibited by use of spargers to distribute the flow inside the condenser. All other high energy drains are also provided with spargers or baffles inside the condenser.
- a. Main turbine exhaust steam.
- b. Auxiliary condenser condensate.
- c. Drains from low pressure heater No. 1.
- d. Steam packing exhauster drains.
- e. Steam jet air ejector (SJAE) condenser drains.
- f. Offgas condenser drains.
- g. Feedwater heater vents.
- h. Turbine governor valve leakoffs.
- i. Seal steam header flow.
- j. Feedpump seal leakoff.
- k. Main, reheat, extraction, and miscellaneous drains.
- a. Hotwell pump, SJAE condenser, steam packing exhauster, and condensate booster pump recirculation.
- b. Hotwell pump startup vents.
- c. Feedwater cleanup flow.
- d. Emergency drains from feedwater heaters Nos. 6, 5, 3, and 2.
- e. Moisture separator and reheater drains.
- f. Condensate makeup.
- g. Turbine bypass flow.
- h. Feedwater heater vents.
- a. Reheat steam relief.
- b. Heater vents and relief.
- c. Offgas condenser.
- d. Offgas water separation effluent line.
- e. Offgas air preheater.
- f. SJAE intercondenser.
- g. Steam seal evaporator.
- a. Each condenser shell is provided with local and remote hotwell level and pressure indication.
- b. The condensate levels in the condenser hotwell are maintained within proper limits by automatic control. Transfer condensate is passed to and from the condensate storage tank as needed to satisfy the requirements of the system.
- c. Turbine exhaust hood temperature is monitored and controlled with water sprays to provide protection from overheating.
- d. A high condenser back pressure alarm is set to warn the operator prior to turbine trip. Turbine trip is initiated on loss of condenser vacuum or when condenser back pressure exceeds approximately eight inches Hg absolute. Main steam isolation valve closure is initiated at 21.5 inches Hg absolute (8.5 inches Hg vacuum).
- e. Waterbox temperature and level measurements are provided.
- f. Conductivity elements detect leakage of circulating water into the condenser.
- a. Air inleakage for main condenser 55 scfm
- b. Disassociated H2 162 scfm Revision 12 10.4-9 January, 2003
- c. Disassociated O2 81 scfm Each steam jet air ejector set is designed to use main steam reduced in pressure by an automatic pressure reducing device. Discharge is to the offgas system for treatment at 8.0 psig and a maximum hydrogen concentration of 4 percent by volume.
- a. Mechanical vacuum pumps are used to evacuate the condenser prior to turbine startup.
- b. Noncondensible gases cascade from the highest to lowest main condenser shell and are then removed. Each steam jet air ejector set is a two stage unit with a common condenser after the first stage. Four first stage elements are used for the main condenser and one 100 percent first stage element for each auxiliary condenser. The second stage element is common to all condensers and removes the noncondensibles to the offgas system.
- a. An automatic pressure reducing device is used to reduce main steam pressure to steam jet air ejector operating pressure.
- b. One steam jet air ejector set is used as a spare. In the event of the failure of one of the steam jet air ejector sets, the remaining set is started.
- c. Vacuum pumps operate only for startup to pull a vacuum in the main and auxiliary condenser to establish a vacuum of three inches of Hg.
- d. The condenser evacuation system has no direct effect on the reactor coolant system during normal operation.
- e. Under normal operating conditions, radioactive leakage is negligible as all leakage up to the steam jet air ejectors is under vacuum and will leak back to the condenser. An analysis of pipe rupture of the discharge pipe to the offgas system from the steam jet air ejector is presented in <Chapter 15>.
- f. The system is Quality Group D, as defined by <Regulatory Guide 1.26>, and of non-seismic design.
- g. The main condenser air removal system is not designed to withstand the effects of an explosion. If an explosion occurs within the system, continuous leakage paths afterward are prevented by isolating the affected portions of the system from the main condenser and the offgas system. Provisions for the effects of an explosion within the offgas system are discussed in
- a. The turbine bypass system is designed to control reactor pressure during reactor heatup to rated pressure while the turbine is being brought up to speed and synchronized during power operation when the reactor steam generation exceeds the transient turbine steam requirements; and cool down of the reactor.
- b. The turbine bypass system capacity is designed for 28.8 percent (nominal) of the 100 percent rated reactor steam flow. The bypass system will accommodate approximately a 28.8 percent load rejection. The bypass system works in conjunction with the turbine controls (pressure control) <Section 7.7.1>.
- c. The turbine bypass valves are capable of remote-manual operation in their normal sequence, during plant startup and shutdown, and for exercising to verify that the valves are operable.
- a. A bypass system line failure is bounded by the pipe break outside containment accident. Refer to Event 38 in <Appendix 15A.6.5.3>.
- b. A failure of the bypass system to open is bounded by the turbine trip and load rejection without bypass events. Refer to Events 30 and 31 in <Appendix 15A.6.4.3>.
- c. An inadvertent opening of the bypass system, at worst, might cause a high steam line flow or low steam line pressure with a resultant MSIV closure trip. Refer to Event 14 in <Appendix 15A.6.3.3>.
- a. Inadvertent flooding of the turbine room basement would be first detected by a level switch located on the turbine room basement wall, which would actuate an alarm in the control room. The unit operator would then investigate the cause of the alarm. If the water level should continue to rise to a second verification level switch located three feet above the turbine room basement floor, a second alarm would be sounded in the control room. The operator would immediately shut down all circulating water pumps, close the pump discharge valves and close the condenser waterbox isolation valves. This procedure is incorporated into the Perry alarm response instructions. In the design basis accident analysis, no credit was taken for operator action.
- b. A set of three auto-shutdown level switches positioned at a higher level (five feet above the turbine room basement floor) would automatically initiate, on a two of three level switch signal, circulating water pump trip, pump discharge valve closure and condenser waterbox isolation valve closure. The flow path between the cooling tower and the condenser waterbox expansion joints is thereby isolated by the two sets of valves: pump discharge and condenser waterbox isolation valves. In the analysis, no credit was taken for the level switches.
- c. To reduce the possibility of a water hammer in the circulating water system, slow closing (60 seconds) motor-operated butterfly valves are used for condenser isolation.
- d. All rubber expansion joints, valves and piping in the circulating water system are initial service leak tested.
- e. Even if interlocks and safeguards failed and the entire water volume in the circulating water system including the cooling tower basin emptied into the turbine building, the water level in the turbine room basement, heater bay and condensate demineralizer building would remain below Elevation 599-0.
- f. In addition to the precautions taken above, no doors are installed between the condensate demineralizer building and the auxiliary building, below Elevation 599-0. Water is not permitted to enter Seismic Category I buildings, except for the pipe chase within the auxiliary building. This pipe chase as well as all other openings leading to Seismic Category I Buildings are sealed, thereby protecting safety-related equipment from the effects of flooding.
- g. Makeup water to the cooling tower is supplied by four service water pumps, two of which are operating at one time <Section 9.2.7.2>.
- h. To prevent the service water from providing makeup water to the cooling tower basin, two level switches positioned at approximate Elevation 583-0 will automatically close the Seismic Category I circulating water makeup isolation valves.
- a. Condensate Filters Each condensate filter vessel contains vertical filter elements.
- b. Mixed Bed Demineralizers The mixed bed demineralizer system is operated with resin that is procured in the regenerated form. This fully regenerated resin enters the system via the cation resin regeneration tank and is transferred to the mix and hold tank prior to moving the resin to the empty demineralizer vessel. The demineralizer is then on standby, ready for service.
- a. The first valve from the reactor is a damped check valve located inside containment.
- b. The second valve is a damped check valve located outside containment.
- c. The third valve is a motor-operated gate valve operated from the control room. The closing time of this gate valve is 100 seconds.
- 1. Licensing Topical Report, NEDO-10899, Chloride Control in BWR Coolants, June 1973.
- 1. Turbine exhaust steam 8,959,898 993.8 -
- 2. Auxiliary condenser condensate (flows to highest pressure main condenser shell only) 196,130 69.1 1.23 (2.5 in. Hg ABS.)
- 3. L.P. 1 heater drain 2,375,452 81.3 -
- 4. Steam packing exhauster drains 7,200 180.2 -
- 5. Seal steam header bypass flow 14,800 1175.5 -
- 6. High pressure turbine gland leakoffs 6,664 1090.5 200.2
- 7. Turbine governor valve leakoffs 3,274 1190.8 980.7 Revision 12 10.4-50 January, 2003
- 1. Turbine bypass steam before throttling and attemperation 5,635,438 1190.8 965 -
- 2. Moisture-separator drains 891,045 349.7 - 372.1 360,455 1197.4 - 372.1
- 3. Reheater Drains 376,020 461.3 555.5 -
- 4. No. 3 low pressure heater drains 401,067 196.9 - 228.5
- 5. No. 2 low pressure heater drains 448,820 134.7 - 166.7
- 6. Moisture Separator-Reheater Relief Valve Flow The main condenser is also designed to receive steam from the moisture separator-reheater shell relief valves for a maximum period of one minute at the following conditions:
- a. Flow, lb/hr 11,243,633
- b. Enthalpy, Btu/lb 1278.3
- c. Pressure, psia 182.1 Guaranteed free O2:
- a. Plant loads from 10% to 50% 0.010 cc/liter
- b. Plant loads from 50% to 100% 0.005 cc/liter Revision 12 10.4-51 January, 2003