NRC-16-0034, 0 to Updated Final Safety Analysis Report, Chapter 10, Steam and Power Conversion System
Text
FERMI 2 UFSAR CHAPTER 10: STEAM AND POWER CONVERSION SYSTEM 10.1
SUMMARY
DESCRIPTION The steam and power conversion system for Fermi 2 includes a tandem-compound, single-stage reheat, six-flow exhaust, 1800-rpm turbine with nominal 43-in. (8th stage) last-stage buckets (blades). The turbine nominal rating at the generator terminals is 1235 MWe at 1.5 in. Hg abs, 100 percent reactor flow, and zero percent makeup. The design rating of the generator coupled to the turbine is 1,350,000 kVA at 22,000 V, 60-Hz frequency, and 0.90 power factor. Steam at 981.0 psia, 544°F, and 0.46 percent moisture is provided by the nuclear steam supply system (NSSS) at the turbine throttle to drive the main turbine generator.
Moisture separation with one stage of reheat is provided between the high-pressure and the low-pressure turbines for all steam entering the low-pressure turbines. Steam from the low-pressure turbines is condensed in a single-pressure condenser of divided water-box design.
Condensate is collected in the condenser hot-wells and pumped through the condensate/feedwater cycle to the NSSS. Heater drains are cascaded into the condenser, except for the heater drains from heaters 5 and 6. The condensate/feedwater from these is pumped forward into the reactor feed pump (RFP) suction.
The condensate and feedwater system supplies feedwater to the NSSS through a condensate cleanup system and then through six stages of extraction feedwater heating.
Circulating water from a circulating water reservoir is pumped through the main condenser and returned to the cooling towers. There, the heat rejected from the steam conversion system is dissipated into the atmosphere. Makeup water for the circulating water system is taken from Lake Erie.
The heat balance at design rating is shown in Figure 10.1-1. Key cycle characteristics are shown in Table 10.1-1.
Normally, the turbine and auxiliary equipment use all the steam being generated by the NSSS; however, an automatic pressure-controlled 23.5 percent-capacity turbine bypass system discharges excess steam directly into the condenser. The capacity of this system is 23.5 percent of the rated reactor flow.
The steam and power conversion system is designed to use the energy available from the NSSS. It has the capability of accepting at least rated reactor flow and reactor pressure for safe, continuous operation. The necessary biological shielding for the main turbines, RFP turbines, moisture separators and reheaters, and condenser is provided for personnel protection.
The individual components of the steam and power conversion system are based on a proven conventional design acceptable for use in large central-station power plants. All auxiliary equipment has been sized on the basis of the design flow rating and pressure rating with turbine valves providing adequate margin for pressure control in accordance with the heat balance shown in Figure 10.1-1. Design margins have been included to ensure adequate capacity under all operating circumstances.
10.1-1 REV 19 10/14
FERMI 2 UFSAR The steam turbine is provided with an electro-hydraulic control (EHC) system having three electrical speed inputs. Speed logic is redundantly processed in both electronic and hydraulic channels. Turbine steam supply valves are provided in serial pairs; a stop valve is actuated by either of two redundant overspeed trip systems followed by a controlling valve modulated by the speed governing system. The latter valve is tripped by either of the two overspeed trip systems. Failure of a single component in the speed control system does not lead to excessive overspeed.
Logic circuits are provided for turbine protection and operation. Additionally, testing circuits for the turbine steam valves are provided. Emergency trip devices include a manual trip, a mechanical overspeed trip, an electrical overspeed trip, and an electrical vacuum trip.
None of the components of the power conversion systems are required to operate to ensure a safe reactor shutdown. This is because reactor safety systems are provided that are designed to protect the reactor under all conditions, including complete isolation from the power conversion systems. Therefore, reliability of these power conversion systems, except where concerned with control of radioactivity, is primarily a function of system operating requirements.
Redundant equipment is provided, wherever feasible, to prevent excessive loss of plant output or excessive frequency of reactor scram.
The safety-related aspects of several postulated failures that might occur within the power conversion system have been considered. The following specific situations have been analyzed:
- a.
Breaks in the feedwater system that allow discharge of contaminated feedwater into the turbine building
- b.
Failure of the air-ejection line resulting in discharge of activity directly into the turbine building
- c.
Missiles generated by a postulated turbine failure
- d.
Introduction of contaminants into the reactor vessel via the condensate/feedwater system.
Feedwater system breaks and failure of the air-ejection line are both discussed in Chapter 15.
These analyses indicate that the amount of radiation released into the environment following any one of these studied incidents is within acceptable limits.
The effects of turbine missiles are analyzed in Subsections 10.2.3 and 3.5.1.2.2. The conclusion is that postulated turbine missiles are not a plausible event.
Regulatory Guide 1.56, Maintenance of Water Purity in Boiling Water Reactors, will be met to ensure that contaminants from the feedwater entering the reactor vessel are kept at acceptably low levels.
10.1-2 REV 19 10/14
FERMI 2 UFSAR TABLE 10.1-1
SUMMARY
OF IMPORTANT NOMINAL AND PERFORMANCE CHARACTERISTICS OF THE POWER CONVERSION SYSTEM Turbine Data Manufacturer General Electric Company Turbine Generator, LTD.a GE for HP and LP Steam Path replacement components Type / LSB length, in.
43 (8th stage)
Number of cylinders One higher pressure, three low pressure Gross electrical output at the generator terminals (MWe) 1235 Condenser pressure, in. Hg abs 1.5 Final feedwater temperature, °F 426.5 (nominal)
Steam conditions at throttle valves inlet Flow, lb/hr 13,722.820 Pressure, psia 981.0 Temperature, °F 544 Enthalpy, Btu/lbm 1190.6 Moisture content, percent 0.46 Turbine cycle arrangement Number of steam reheat stages One Number of feedwater heating stages Six Heater drain system Heaters 5 and 6 pumped forward Feedwater heaters in condenser neck Numbers 1 and 2 Type of condensate demineralizer Mixed-powdered-resin type Main steam bypass capacity, percent of rated reactor flow 23.5 a Formerly English Electric Co, Page 1 of 1 REV 19 10/14
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FIGURE 10.1-1 HEAT BALANCE AT 100 PECN REACTOR FLOWI DETROIT EDISON COMPANY DRAWING NO. C1 C OUT REV. 3, EDISON FILE T12-099
FERMI 2 UFSAR 10.2 TURBINE GENERATOR 10.2.1 Design Bases The turbine generator is designed to meet the following conditions:
- a.
Gross electrical output at the generator terminals at 100 percent reactor flow is 1235 Mwe.
- b.
Steam conditions at the turbine throttle valves inlet
- 1.
Flow, lb/hr 13,722,820
- 2.
Pressure, psia 981.0
- 3.
Temperature, °F 544
- 4.
Enthalpy, Btu/lbm 1190.6
- 5.
Moisture content, percent 0.46
- c.
Exhaust pressure, in. Hg abs 1.5
- d.
Final feedwater temperature, °F 426.5
- e.
Stages of feedwater heating Six
- f.
Stages of steam reheating One These figures represent the 100 percent reactor flow heat balance conditions shown in Figure 10.1-1.
The unit is to be operated initially in a base-loaded manner but has the provision to be operated in a load-following manner when this becomes beneficial from the standpoint of system reliability and economics.
The nuclear steam supply system (NSSS) and turbine have the ability to provide continuous load-following capability over a range of approximately 31.5 percent of rated power. This power change via recirculation flow can be accomplished at the rate of 1.5 percent/sec for both load increases and decreases. Step-change electrical load reductions that do not exceed 23.5 percent of rated power are handled by operation of the main steam bypass system without requiring an associated change in reactor power.
10.2.2 Description 10.2.2.1 Turbine Generator The General Electric Company Turbine Generator, Ltd. (formerly English Electric Co.)
turbine is a four-casing, tandem-compound, six-flow, 1800-rpm unit that has been modified.
During RF05, the LP Turbine Steam Path consisting of rotors, buckets (blades), diaphragms and steam flow guides was replaced with GE designed components. The HP Turbine Steam Path was replaced during RFO7 with GE designed components. The major components replaced were the rotor, diaphragms, associated seals, and coupling spacers. An inlet snout was added to provide the steam flow path into the first stage nozzles. An ac generator is 10.2-1 REV 19 10/14
FERMI 2 UFSAR connected to the turbine shaft. The excitation system is an Asea Brown Boveri (ABB) type APS-0631 static excitation system.
The turbine consists of one double-flow high-pressure element in tandem with three double-flow low-pressure elements.
Turbine-generator bearings are lubricated by a conventional pressurized oil system. Two 100 percent electric (ac) motor-driven pumps supply bearing oil to the turbine generator under normal operation. Normally one ac pump is running and one is a spare. One electric (dc) motor-driven backup pump is provided in the event both ac pumps fail as a result of a loss of ac power.
Steam from the NSSS enters the high-pressure turbine through four 24-in. stop valves and governing control valves. One stop valve and one control valve form a single assembly.
After expanding through the high-pressure turbine, the steam flows through the moisture separators and reheaters to the six intermediate stop valves and six intercept valves into steam lines leading to the three low-pressure turbines. Steam from each low-pressure turbine is then exhausted into the main condenser.
Moisture separation and reheating of the steam are provided between the high-pressure and low-pressure elements in two parallel shells, each of which contains combined moisture-separator-reheater assemblies. A separator-reheater assembly is located on each side of the turbine parallel to the turbine shaft.
The turbine generator is protected from excessive overspeed by two emergency overspeed trip protection systems, the mechanical overspeed trip system and the electrical overspeed trip system. The mechanical overspeed trip system consists of two redundant systems using two separate spring-loaded throwout plungers mounted on the turbine shaft. Should the turbine accelerate to its over-speed trip set point, each plunger strikes its respective position limit switch mounted adjacent to each of the plungers, energizing a system of protective relays that will trip the turbine.
The electrical overspeed system uses four separate and redundant channels of speed measurement. The four channels are fed through a network of comparative logic gates. This comparative logic system monitors the speed input signals and alerts the operator with an alarm if any one of the four inputs fails to match the others. The system ac power supply is redundant with automatic throwover to the backup ac supply. The power supplies, main, backup, and test, are monitored for loss of potential and alarmed for operator corrective action. Figure 10.2-1 is the block diagram of the electrical overspeed system.
The generator is sized to accept the gross rated output of the turbine at rated reactor pressure and reactor flow at the throttle. The generator is a direct-coupled, 60-Hz, three-phase, 22,000-V unit designed at 1,350,000 kVA at 0.90 power factor, and has a short-circuit ratio of 0.58, at a maximum hydrogen pressure of 75 psig. The generator shaft seals are oil-sealed to prevent hydrogen leakage. The static excitation system has been sized for a maximum field current of 5,200 A at a rated field voltage of 575 VDC.
Excitation power for the generator rotor is supplied from the excitation transformer through three thyristor bridges in a configuration to allow continuous operation with one bridge out of service at full power, with the excitation being controlled by the excitation control cubicle.
10.2-2 REV 19 10/14
FERMI 2 UFSAR 10.2.2.2 Cycle Description Steam is fed from the reactor, through four lines and associated isolation valves, into a 52-in.
common manifold. From the manifold, steam is supplied to the high-pressure turbine through four 24-in. lines. Each line contains a turbine stop valve and a turbine control valve.
The control valves adjust the quantity of steam admitted to the turbine and thus control the reactor steam pressure and the electrical power output.
If operation with one control valve out of service is necessary, steam is supplied to the high-pressure turbine through three 24-in. lines. An evaluation of the limiting transients and issues associated with one turbine stop or control valve out of service for Fermi 2 has been documented in Reference 2. The evaluation is qualitative and independent of fuel type through GE14. The conclusions are generic and can be applied to both current and future cycles of Fermi 2. The assessment with one turbine stop or control valve out-of-service covers the adequacy of the current power dependent MCPR and MAPLHGR limits and the impact on ECCS/LOCA and ATWS. The assumptions for the assess-ments and conclusions are that operation with one steam feed to the main turbine isolated by a TCV or TSV is acceptable if:
- a.
Core thermal power will be at or below 91.5 percent
- b.
Operating dome pressure is maintained at or above normal off-rated operating dome pressure but below the LCO maximum dome pressure
- c.
The turbine bypass system is operable
- d.
The moisture separator reheaters are operable
- e.
Operating with normal feedwater heating
- f.
Reactor Flow Limiter Setpoint is at 115 percent or higher.
During an electrical load reduction, steam may be bypassed directly to the condenser to maintain constant reactor pressure. The capacity of the bypass system is 23.5 percent of rated reactor flow.
After passing through the high-pressure turbine, steam is exhausted to the moisture separators and reheaters, where it is reheated by steam taken from the main steam lines ahead of the turbine stop valves. The reheated steam then passes into the low-pressure turbines.
There, the steam is equally divided among the three low-pressure turbines and is eventually exhausted into the condenser. The condensed heating steam is drained to the No. 6 feedwater heaters.
Steam is extracted from six points on the turbine for feedwater heating. There is one extraction point from the high-pressure turbine, one from the high-pressure turbine exhaust, and four from the low-pressure turbines, as shown in Figure 10.2-2.
Steam is supplied to the reactor feed pump (RFP) turbines from two sources: (1) the main steam manifold during startup and low-load operation and (2) the hot reheat line during normal operation.
10.2-3 REV 19 10/14
FERMI 2 UFSAR 10.2.2.3 Instrumentation Application The turbine generator uses an electro-hydraulic control (EHC) system that controls the speed, load, pressure, and flow for startup and planned operation, and trips the unit when required.
The EHC system operates the high-pressure stop valves, bypass valves, control valves, low-pressure stop and intercept valves, and other protective devices. Turbine-generator supervisory instrumentation is provided for operational analysis as well as for pre-and postmalfunction diagnosis.
The automatic control functions of the turbine generator are correlated with the reactor pressure control and recirculation control. For details, see Subsection 7.7.1.
The turbine EHC system uses solid-state electronics and high-pressure hydraulics to control the nuclear steam flow from the reactor.
Four major functions are performed by the turbine EHC system, as follows:
- a.
Speed control
- b.
Pressure control
- c.
Valve position control
- d.
Supervisory control.
Speed control is accomplished by comparing a turbine shaft speed signal to a speed reference to produce a speed error signal. In addition, a digital technique is used to produce a turbine acceleration signal from the turbine shaft speed pickup pulses. This acceleration signal is compared to a reference to produce an acceleration error signal that is summed with the speed error signal to produce a speed/acceleration error. The speed/ acceleration error is modified by an adjustable proportional constant to produce a valve position demand. The speed governing system has been designed using three redundant systems.
Pressure control is accomplished by comparing turbine inlet steam pressure to a pressure reference and thereby producing a pressure error signal. This pressure error is modified by an adjustable electronic regulator to obtain a valve position demand.
Unitized actuators at each turbine steam valve accept the electrical signals from the pressure control, speed control, or the supervisory control and position the valve in the required manner. Each valve is provided with an individual valve actuator, which eliminates the need for extensive high-pressure control oil piping. The unitized actuator is a self-contained, electro-hydraulic valve positioner that converts the electrical control signals to valve position. Each unitized actuator is designed to perform a specific valving function.
Supervisory control is provided to maintain the turbine in a safe controlled state or to initiate a rapid shutdown in case of an emergency.
Rapid shutdown is achieved by initiating the fast closure mode of valve control. Under this mode of control, the maximum closure rate is obtained. Fast-closure full-stroke travel time of the turbine stop valves is 0.20 to 0.22 sec. The fast-closure full-stroke travel time of the turbine control valves is 0.20 to 0.22 sec. Low-pressure stop and intercept valves close in approximately 1.0 sec when operating in the fast closure mode.
10.2-4 REV 19 10/14
FERMI 2 UFSAR 10.2.2.4 Emergency Control Operations Loss of electrical load with respect to subsequent interactions should be considered under three conditions (a., b., and c. below). For these three conditions, the turbine-generator emergency overspeed will not exceed 120 percent of rated speed (1800 rpm).
- a.
Generator breakers (two) trip The generator has a system of protective devices that protect the generator from damage. This protection is achieved by tripping open the generator breakers.
The generator breakers have position switches that will initiate a direct turbine trip when both breakers are tripped open.
- b.
System disturbances resulting in sustained loss of electrical load If the turbine generator has been running at maximum load and the load on the generator is suddenly lost (not the result of generator breaker trips), the following events will occur in controlled rapid succession:
- 1.
The turbine will accelerate at a rate proportional to loss in electrical load until the turbine control system starts to close the control valves
- 2.
The turbine control will initiate the fast closure mode of the turbine control valves (TCV), when the turbine acceleration exceeds a prescribed trip setpoint
- 3.
The operation of the HP stop valve and the associated RPS turbine stop valve closure limit switch initiates fast closure mode which will initiate a direct reactor scram
- 4.
The control valves will close at the maximum closure rate by means of the fast-acting solenoid valves
- 5.
The entrained steam between the valves and the turbine, in the turbine steam casing, and in the extraction lines will expand. Some of the accumulated water will flash into steam, supplying energy to the turbine at a relatively moderate rate
- 6.
The turbine speed will cease to increase when the entrained steam has stopped expanding. The turbine will trip on reverse power when its speed is less than synchronous
- 7.
Generator breaker and turbine trips will be initiated on reverse power to the generator if the loss of electrical load has not already isolated the generator from the system
- 8.
The turbine will coast down until turning gear speed is established. The turning gear will maintain slow rotation of the turbine to allow even cooling during the desoaking period.
10.2-5 REV 19 10/14
FERMI 2 UFSAR
- c.
Partial loss of electrical load On a small loss of load, the turbine will accelerate slowly. Assuming that the fast closure mode is not initiated, the bypass valves will divert the nuclear steam supply to the condenser until the steam supply can be decreased.
The emergency trip system closes all valves (turbine stop valves, control valves, intercept valves, and reheat stop valves), shutting down the turbine on the following signals:
NOTE:
Setpoints are approximate and are for illustration only.
- a.
Turbine speed approximately 7 to 10 percent above rated speed by
- 1.
Magnetic speed pickups - four provided (106 to 108 percent speed)
- 2.
Overspeed trip plungers - two provided (107 to 110 percent speed).
- b.
Vacuum less than a preselected value (7.5 in. Hg abs)
- c.
Excessive thrust-bearing wear (+/-0.050 in.)
- d.
Low flow of generator stator water coolant (600 gpm or less after a time delay of 60 seconds)
- e.
High stator-coolant outlet temperature (195°F)
- f.
Generator protection, including reverse-power sustained and both generator breakers tripped
- g.
Low lube-oil pressure - below 10 psig after a 20-sec time delay
- h.
Loss of two speed-sensing signals (failure of two of three computing channels)
- i.
Loss of both main and emergency power supplies to the EHC cubicle
- j.
High pressure in separator-reheaters - 256 psia
- k.
High reactor water level
- l.
Manual trip from control room panel
- m.
Exhaust hood high temperature - 280°F
- n.
High shaft or pedestal vibration after a 7.5 second (maximum) time delay with
- 1.
Hi Hi (12 mils shaft or 10 mils pedestal) on any bearing and
- 2.
Hi (<10 mils) on an adjacent bearing
- o.
Hydrogen-seal oil-pressure differential low - 10 psig after a 20-sec time delay
- p.
Hydrogen gas temperature high - 185°F
- q.
Both main lube-oil reservoir emergency valves open.
10.2.2.5 Turbine-Generator Supervisory Instruments The turbine supervisory instrumentation is located in the main control room and is sufficient to detect malfunctions.
The turbine-generator supervisory instrumentation includes monitors for the following:
10.2-6 REV 19 10/14
FERMI 2 UFSAR
- a.
Electrical load
- b.
Shaft speed
- c.
Control valve position
- d.
Vibration and eccentricity
- e.
Thrust-bearing wear
- f.
Exhaust hood temperature and spray pressure
- g.
Oil system pressures, levels, and temperatures
- h.
Bearing metal and oil drain temperatures
- i.
Shell temperatures
- j.
Valve positions
- k.
Shell and rotor differential expansion
- l.
Hydrogen temperature, pressure, and purity
- m.
Stator-coolant temperature and conductivity
- n.
Stator winding temperature
- o.
Excitation equipment area temperature
- p.
Steam seal pressure
- q.
Gland steam condenser vacuum
- r.
Steam chest pressure
- s.
Hydrogen-seal oil pressure.
10.2.2.6 Testing Provisions Provisions are made for testing each of the following devices while the turbine generator is operating:
- a.
Main stop and control valves
- b.
Intermediate stop and intercept valves
- c.
Overspeed governor
- d.
Turbine extraction nonreturn valves (excluding small valves)
- e.
Vacuum trip
- f.
Lubricating oil system backup pumps.
The following testing and inspection activities are performed in accordance with the manufacturer's recommendations and operational experience or constraints:
- a.
The mechanical and electrical overspeed trip systems are operated and checked
- b.
The main steam stop valves, main steam control valves, low pressure stop valves, and intercept valves are dismantled and inspected 10.2-7 REV 19 10/14
FERMI 2 UFSAR
- c.
The main steam stop valves, main steam control valves, low pressure stop valves, and intercept valves are exercised.
10.2.3 Turbine Missiles Fermi 2 was designed with barriers to resist potential turbine missiles. These barriers were designed to protect the safety related plant components from a design basis turbine missile which, prior to the replacement of the LP turbines during RF05, was a 120° segment of the largest main low-pressure turbine wheel. That missile weighed 8650 lbs. and had an initial velocity of 383 mph.
During the fifth refueling outage, the three built-up low pressure rotors, including blades and diaphragms, for Fermi 2 LP turbines were replaced. The maximum attainable speed of the new rotors will be approximately 218-222% of rated speed. At this point, the steam flow through the rotating steam path is well away from design conditions with some stages being driven by the steam while the remainder absorb energy. This scenario assumes that all the buckets remain intact on the rotor, the generator does not loosen retaining rings, wedges or field bars, and that the unit does not experience severe rubbing, all of which would keep the rotor at lower speeds.
Considering the minimum rotor material specification strength values, and assuming all buckets remain attached, the minimum overspeed capability of the rotors is about 219-225%.
Using typical strength values, the overspeed capability of the rotors is considerably higher than the shrunk-on designs and exceeds the maximum overspeed the rotors can attain.
However, the turbine overspeed control system is designed to limit maximum turbine overspeed of 120% of the turbine rated speed.
A complete failure of the control system and safety-related items is required to reach the event described. The probability of this occurring is well below 10 to the -8 power. In conclusion, the rotor stress levels are quite low; the probability of missiles being generated by the low pressure rotors is not present.
During the seventh refueling outage, the high pressure rotor, including blades and diaphragms for Fermi 2 HP turbine, was replaced. Although the HP rotor was replaced after the LP rotors, the LP rotor document regarding nuclear turbine missile analysis still governs.
This concluded that blades will not penetrate outer casings. The minimum speed at which the HP blades fail is bounded by the LP turbine analysis performed for RFO5.
The generator is not being replaced. The existing calculations indicate that missiles emanating from the generator rotor will be stopped before they can completely breach their respective outer casings. Concluding, with the low-pressure rotor replacement, there will no longer be a design basis turbine missile at Fermi 2, however the originally designed missile barriers remain intact.
The probability of a failure of a rotor or bucket (blade) is further minimized by the selection of materials, manufacturing process, preservice inspections and established inservice inspection programs.
The LP rotors are a GE proven monoblock design, whereby a rotor is machined from a single forging that accounts for bucket (blade) attachment points, as well as the coupling configuration; thus, eliminating the need for shrunk on discs and couplings. The new rotors 10.2-8 REV 19 10/14
FERMI 2 UFSAR are forged out of a GE proprietary NiCrMoV material that is similar to ASTM A470 Class 6 which meets the requirements specified in the purchase specification. The monoblock forging material chemistry is optimally balanced to have high hardenability, to achieve good fracture toughness at the required tensile strength, low tramp elements to minimize temper embrittlement and low sulfur to minimize harmful segregation. The rotors have the bucket (blade) wheel dovetails machined directly into the rotor forgings. The first six stages utilize tangential entry pinetree dovetails to attach the buckets, the last two stages utilize radial entry finger dovetails with pins.
The buckets (rotor blades) are either fabricated from bar stock or forged. The material is a GE proprietary material that consists of nominal 12% Cr. and is similar to ASTM A479, except with more stringent quality requirements. To protect against moisture erosion of the blade tips, GE uses flame hardening in lieu of stellite shields to provide an equivalent resistance to erosion, and to minimize the addition of cobalt into the primary system. The last four bucket stages (5, 6, 7 and 8) will be flame hardened. In addition to flame hardening, stages 5, 6 and 7 have moisture removal grooves that help direct water to drainage paths through the diaphragms. This design helps prevent water build-up, and that will reduce buckets loading during turbine operation.
The first six bucket stages have standard GE shot peened pinetree dovetails for attachment to the rotor wheels. The last two stages have finger dovetails with shot peened pins for attachment to the rotor wheels. Shot peening reduces concentrated stresses, therefore significantly improving the material resistance to stress corrosion cracking and improving the dovetail reliability.
The last stage bucket is what GE refers to as a 43C design. The bucket length is only 43 inches as compared to the original last stage blade which was approximately 45 inches. The 43C bucket is based on GE proven designs and latest technology utilizing, at its outer periphery, a two-piece over-under continuous cover connecting each bucket (blade) in its row together. This helps maintain the space at the bucket tips where the steam flows through and helps resist blade twisting, thus allowing for a more efficient bucket design.
The turbine supervisory instrumentation is used as a continuous inservice monitoring process of the turbine and associated equipment performance.
Edison performed the inspection of the low-pressure turbine disks during the second refueling outage in accordance with the Technical Specifications. This inspection consisted of volumetric examination of the disk bore area using ultrasonic techniques. Future inspection requirements will be per the turbine manufacturers recommendation.
10.2.4 Evaluation The primary source of activity in the steam and power conversion system is radiation from 16N, formed by activation in the reactor. Nitrogen-16 has a half-life of approximately 7 sec.
The activated nitrogen is carried with the steam to the turbine. Fission-product noble gases and other activation gases, such as 19O, 17N, and 13N, are also carried with the steam to the turbine. Some nongaseous fission and activation products are present in the turbine as a result of moisture carryover in the steam from the NSSS.
10.2-9 REV 19 10/14
FERMI 2 UFSAR The activity entering the low-pressure turbine is reduced because of the presence of moisture separation and transit time between the high-pressure and low-pressure turbines, which permits the 16N to decay.
Most of the noncondensible gases in the condenser are removed by the steam-jet air ejectors to the offgas system, which is described in Section 11.3. The activity remaining in the condensate is reduced significantly by the nominal 4-minute holdup time in the condenser hotwell.
Shielding requirements are discussed in Section 12.1. The turbine generator is in an administratively controlled access area.
10.2-10 REV 19 10/14
FERMI 2 UFSAR 10.2 TURBINE GENERATOR REFERENCES
- 1. USAEC/ACRS subcommittee meeting minutes, March 2, 1971, Enrico Fermi Atomic Power Plant - Unit 2, AEC Docket No. 50-341
- 2. GNF DRF: GE-NE-J11-03920-07-01, Turbine Control Valve Out-of-Service for Enrico Fermi Unit-2, Revision 0, October 2001.
10.2-11 REV 19 10/14
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'B' 1....J
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SI M. o/s TRlP sel...lfGTEO LOW TURBINE SPEED TRIP 5Ei HIGH BACK-UP SUPPL'I !'AILURE N\\AIN SUPPL'I FAILUIitE MI>.'i, C"'I>... ~ELS "Eu.e<eo
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I DETECT LOSS OF' SUPPL"I REPEJI.."T INDICAiiONS AT CON,iZOL-PANIOL I"---
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r---------Jr~---l
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C.O)J"TROL RoaN'!.
Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 10.2-1 TURBINE GENERATOR ELECTRICAL OVERSPEED PROTECTION SYSTEM BLOCK DIAGRAM
36" 36" 36" 36" 36" 36" 36" 36" 36" HIGH PRESSURE TURBINE N2102C015 REACTOR FEED PUMP TURBINE SOUTH-1/2 SIZE N2102C014 REACTOR FEED PUMP TURBINE NORTH-1/2 SIZE SOUTH N30 CENTER N30 NORTH N30 FEEDWATER HEATER NO. 3 SOUTH N2003B010 FEEDWATER HEATER NO. 3 NORTH N2003B009 FEEDWATER HEATER NO. 4 NORTH N2003B011 FEEDWATER HEATER NO. 4 SOUTH N2003B012 FEEDWATER HEATER NO. 5 NORTH N2003B013 FEEDWATER HEATER NO. 6 NORTH N2101B001 FEEDWATER HEATER NO. 6 SOUTH N2101B002 MAIN CONDENSER MAIN CONDENSER GLAND STEAM REGULATOR LPSV LPSV LPSV LPSV LPSV LPSV IV IV IV IV IV IV N3021 F013F N3021 F012F N3021 F012E N3021 F013E N3021 F013D N3021 F012D N3021 F012C N3021 F013C N3021 F013B N3021 F012B N3021 F012A N3021 F013A TEW N400 TEW N401 TEW N418 TEW N417 TEW N419 TEW N403 TEW N421 TEW N404 TEW N423 TEW N422 TEW N424 TEW N407 TEW N426 TEW N408 TEW N428 TEW N427 TEW N429 36" 36" 36" 36" 36" 36" MO MO MO AO MO CRPB CRPB FTL N11 L422 B
FTL N11 L420 B
FXE N11 N432 B
FSE N11 N430 B
FTH N11 L423 B
FTH N11 L421 B
PT N11 L452 B
PXE N11 N434 B
TEW N11 N458 B
TY N11 K830 B
FTH N11 L421 A
FTH N11 L423 A
FXE N11 N432 A
FSE N11 N430 A
FTL N11 L422 A
FTL N11 L420 A
PT N11 L452 A
PXE N11 N434 A
TEW N11 N458 A
TY N11 K830 A
ZSV N11 N409 D
CRPB CRPB I & C REF.2 FOR INSTRUMENT SOURCE CONNECTIONS INSIDE CONDENSER SEE I-R DWG. N4-242 RET-520 X I (F.D. T2-51)
TP FROM LPSV AND IV 16" AS TEW N402 TEW N420 PT L402 PXE N530 B
PXE N530 A
PT L403 TEW N409 6M-2985 (E-3) 3" DRAIN TO COND.
3635 (SUPERHEAT)
MO MO C
R P
B DE E
VENT E
TURB. TRIP TPC(E)
HI HTR.LEV.
CRPB HI HTR.LEV.
30" 30" I&C REF.13 N.O.
N.O.
VENT E
TURB. TRIP TPC(E)
HI HTR.LEV.
CRPB HI HTR.LEV.
N.O.
CLOSED DRN MO TURB. TRIP CRPB N.O.
VENT E
LOAD REJECT TURB. TRIP TPC(E)
HI HTR.LEV.
CRPB CLOSED DRN LOAD REJECT N3016 F604 N3000 F402B ZSV N532 B
ZSV N532 D
EV F402 B
N3016 F603 N3000 F402A ZSV N532 C
EV F402 A
213 ZSV N532 A
36" N3016 F615 N3016 F616 N3016 F602 AO DE E
VENT E
CLOSED DRN N3000 F400B EV F400 B
ZSV N531 D
ZSV N531 B
212 LOAD REJECT TPC(E)
HI HTR.LEV.
LOAD REJECT I&C REF.13 MO HI HTR.LEV.
N3016 F607 N3016 F608 36" EV F400 A
ZSV N531 C
211 HI HTR.LEV.
TURB. TRIP TPC(E)
HI HTR.LEV.
MO AO VENT E
E DE TEW N410 B
N3000 F404B N3016 F606 4" VENT FROM FLASH TANK EV F404 B
HI HTR.LEV.
CRPB CLOSED 216 ZSV N533 B
ZSV N533 D
LOAD REJECT TURB. TRIP TPC(E)
AO VENT E
CLOSED LOAD REJECT TURB. TRIP TPC(E)
HI HTR.LEV.
MO AO VENT E
E DE 4" VENT FROM FLASH TANK CRPB CLOSED TEW N410 A
N3000 F404A N3016 F605 ZSV N533 A
ZSV N533 C
EV F404 A
215 HI HTR.LEV.
MO E
DE HI HTR.LEV.
CRPB N3016 F612 N3000 F406A TEW N412 A
EV F406 A
ZSV N534 C
ZSV N534 A
217 12" I&C REF.12 LOAD REJECT TURB. TRIP TPC(E)
AO VENT E
CLOSED HI HTR.LEV.
MO E
DE HI HTR.LEV.
CRPB 6M-2985 (F-4) 12" I&C REF.12 N3016 F614 N3000 F406B TEW N412 B
ZSV N534 D
ZSV N534 B
218 MO SOUTH RFPT GLAND STEAM SUPPLY NORTH RFPT GLAND STEAM SUPPLY N3016 F618 N3016 F617 6"
6" TP TP BW BW EEC GLAND STEAM SYSTEM GLAND STEAM RELIEF VALVE DISCHARGE LINE TO CONDENSER N3000 F030 TP AU HO MO AO DE DE CRPB CRPB EV N11 F409 A
MO TO GLAND STEAM EXHAUSTER SEE DECO FILE DWG. TI-600 TO GLAND STEAM EXHAUSTER SEE DECO FILE DWG. TI-600 ZSV N11 N409 C
ZSV N11 N409 A
1" DRAIN 1" DRAIN 1" DRAIN 1" DRAIN E
DRN DELAVAL DECO DELAVAL DECO DRN E
PXE N21 N461 B
N3016 F609 N1100 F409B PXE N21 N461 A
N3016 F610 N1100 F409A 6M-2017-1 (A-7)
TO VACUUM PUMP SUCTION OFF GAS SYSTEM 4496 10" N3016 F622 REACTOR ISOL. MIMIC HI HTR.LEV.
12" N3016 F621 N3016 F623 3" FROM HPT DRIPS & DRAINS 3201 EEC EEC PT L405 PXE N433 TEW N414 36" 36" 36" 36" 36" 36" 3399 REACTOR ISOL. MIMIC 12" 12" 3398 3600 3399 MO MO RFPT. EXH.
6" 4"
6" 3610 3647 30" 14" 6M-2985 (E-4) 4" DRAIN FROM
- 6 FDWTR. HTR.
6" 3601 24" MO MO N3016 F611 N3016 F613 SPARGER STEAM MO 10" TO SEPARATOR SEAL TANK 6M-2985 (D-3) 3196 3394 1"
4182 3201 1 1/2" DRN P9500 F633 1"
1 1/2" 3394 3605 6M-2985 (F-5) 4182 1.
2.
FOR LEGEND OF SYMBOLS AND ABBREVIATIONS, DIAGRAM DRIPS AND DRAINS FOR STEAM LINES 3.
4.
5.
6.
DELETED 8.
DESIGNATES ISOMETRIC DRAWING NO.
(PREFIX NO. 6M721-)
MAIN TURBINE GLAND SEAL SYSTEM.
9.
10.
NOTES:
SYSTEM N30 NOTES:
A.
UNLESS OTHERWISE SHOWN, ALL INSTRUMENT NUMBERS ON THIS DIAGRAM ARE FOR SYSTEM N30.
WHERE POSSIBLE, ALL INSTRUMENTS TO BE LOCATED IN ACCESSIBLE AREAS.
REFERENCES:
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
MAIN AND REHEAT STEAM DIAGRAM CONDENSATE DIAGRAM DRIPS AND DRAINS DIAGRAM INGERSOLL RAND DWG.#N4-242 RET-501X1,(T2-57)
INGERSOLL RAND DWG.#N4-242 RET-520X1,(T2-51)
HTR. 3 & 4 EXTRAC. STM. INTERLOCKS HTR. 5 EXTRAC. STM. INTERLOCKS HTR. 6 EXTRAC. STM. INTERLOCKS 3638 10" I&C REF.12 3197 3"
CRPB 3197 1 1/2" DRN 3196 24" 3601 6" DRAIN N30 44" 10" 10" 24" 24" 44" 20" 20" 3196 3196 3610 6M-2985 (F-4)
FEEDWATER HEATER N0.1N (N2003B003)
FEEDWATER HEATER N0.2N (N2003B006) 8" 8"
3614 8"
FEEDWATER HEATER N0.1C (N2003B004)
FEEDWATER HEATER N0.2C (N2003B007) 3614 3614 8"
8" 14" 10" FEEDWATER HEATER N0.1S (N2003B005)
FEEDWATER HEATER N0.2S (N2003B008) 36" 36" 36" 30" 16" 16" 3198 36" 3200 3199 TEW N416 8"
R.F.P.T.
SOUTH R.F.P.T.
NORTH 12" 12" 12" 12" 12" 44" 4"
3392 3197 24" 3"
3201 1 1/2" HOT DRIP TO CONDENSER 1 1/2" HOT DRIP TO CONDENSER 12" 3198 N3016 F601 16" 16" 30" 30" 3"
24" 10" 3392 3648 3643 EV F406 B
12" B.
TURBINE GLAND STEAM SEALIND SYS.
C.
ALL FEEDWATER HEATER EXTRACTION STEAM SUPPLY CHECK VALVE-SOLENOID PILOT VALVES ARE SHOWN IN THEIR ENERGIZED STATE.
HOWEVER TURBINE TRIP HI HTR. LEVEL,LOAD REJECTION OR TEST PUSH-BUTTON WILL DE-ENERGIZE THESE SOLENOIDS, RELEASING VALVE TO TRIP CLOSE.
OPERATOR AIR PRESSURE TO ALLOW THE CHECK 11.
FOR FUNCTIONAL OPERATING SKETCH K
A145 K
A144 A007 K
A008 K
N3018B001 REHEATER/SEPARATOR EAST N3018B002 REHEATER/SEPARATOR WEST K
K A119 A118 FE N11 N419 A
K A467 6M-2005(E-5)
I&C REF.12 MO MO OPEN TO ATMOSPHERE VENTILATOR SCREEN MO 6M-4504-1 (F-4)
K K140 K
A300 1"
N3016 F356 N3016 N3016 F355 F357 LOAD REJECT 6M-2005-1(G-7) 3/4" 1"
1 1/2" N3000 N3000 N3000 FEEDWATER HEATER NO. 5 SOUTH N2003B014 N3000 F400A ZSV N531 A
F318 F317 F358 REF.1 E-7 K
A467 A467 A123 K
A468 K
A121 FE N11 N419 B
TO PIE-N21R810B TO PIE-N21R810A K
K K
K A055 A056 A053 A321 K
A319 K
K K
A058 A057 A054 K
K K
A043 A046 A045 K
K K
K K
K A048 A047 A044 A033 A036 A035 K
K K
A034 A037 A038 K
A032 K
K K
A042 A041 A051 K
A052 DRAIN DRAIN 6M-2004-1 (H-5) 1" 6M-2004-1 (H-6) 1" 7.
DELETED 6M-2005 E-6 6M-2005-1 G-4 INSTRUMENT & CONTROL SYSTEMS DRN.
1 1/2" 3/4" 4/
3 3/4" 6M-2005-1 (H-8) 6M-2005 (H-4)
VENTS FROM REHEATER SEAL TANKS 3206 3207 6"
6" 6M-2985 (F-2) 32" 32" 32" 32" 44" 44" 20" 20" DRN.
DRN.
DRN.
DRN.
3614 I & C REV. 13 I & C REV. 13 CONDENSER OUTLINE REHEATER SEP.
6M-2985 (F-5) 6I-2336-05 (F-4) 6I-2336-5 (D-4)
DELETED 6M-2985 (E-3) 1 1/2" DRAIN 6WM-N30-3635-1 PXE N530 C
PT L401 K
A031 FOR CONNECTIONS ON DRAIN POT SEE FOR CONNECTIONS ON DRAIN POT SEE 1 1/2" 1 1/2" FOR PROCESS CONDITIONS, SEE GENERAL ELECTRICS 12.
N3016 F619 N3016 F620 N3000 F033B N6100 F602 PT N21 L005 B
PXE N61 B
N428 N017 PSE B
N21 N018 N21 B
PSE N3000 F033A L004 B
N016 N21 B
N21 N428 PXE A
N61 N017 N21 A
N21 L005 A
PT N21 N6100 F601 L004 N100 N21 A
PSE N21 A
PSE N015 A
N21 LATEST HEAT BALANCE DWGS.
N2200 F285 N2200 F297 N3018 G079A N3018 G079B N3018 G079C N3018 G079D 48" 48" 48" 48" N3018 G078D N3018 G078C N3018 G078B N3018 G078A 32" 32" 32" 32" 48" 48" 48" 48" BC B3 B2 B1 BC B3 B2 B1 A4 A3 A2 A1 A1 A4 A3 A2 I-2336-05 TO TRE-N11R803 13.
MO
- 14. S/D I-2332-07 S/D I-2332-16 S/D I-2332-17 I-2330-17 I-2330-16 I-2330-15 M-2985 M-2004 M-2002 SEE DWG M-5717-2 I-2314-03 RFPT GLAND SEAL SYSTEM I-2336-05 HEATER DRAINS DIAGRAM, SEE DWG. M-2005.
MAIN STEAM DIAGRAM, SEE DWG. M-2002.
AND MAIN TURBINE, SEE DWG. M-2985.
SEE DWG. NO. M-2000 AND M-2001.
SEE DWG. 6I721-2336-05 (F-4) 6M-2985 (H-2)
I-2314-03 (H-3)
I-2314-03 (H-3)
I-2336-05 (F-2)
I-2336-05 (F-2)
I-2336-05 (G-4)
I-2336-05 (F-2)
M-2985 (D-2)
M-2985 (E-2)
DELETED 14.
DELETED Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT DETROIT EDISON COMPANY DRAWING NO.
FIGURE 10.2-2 EXTRACTION STEAM SYSTEM 6M721-2003, REV. AN REV 19 10/14
FERMI 2 UFSAR 10.3-1 REV 16 10/09 10.3 MAIN STEAM SUPPLY SYSTEM 10.3.1 Design Bases 10.3.1.1 Safety Design Bases To satisfy the safety design bases, the main steam lines from the reactor up to the third isolation valves are designed according to the following piping classification, which is in accordance with the ASME Boiler and Pressure Vessel Code:
- a.
From the reactor to the drywell wall - ANSI B31.7, Class A, Category I
- b.
From the drywell wall to the outer main steam isolation valve - Section III, Class 1, Category I
- c.
From the outer isolation valve to the third isolation valve - ANSI B31.1.0, Category I, with volumetric examination.
10.3.1.2 Power Generation Design Bases The main steam supply system is designed to fulfill the following functions:
- a.
To deliver steam from the nuclear steam supply system (NSSS) up to the turbine generator
- b.
To provide steam for the reheater and the steam-jet air ejectors
- c.
To provide steam for the reactor feed pump (RFP) turbines during startup and low-load operations
- d.
To provide steam for the turbine seal system and flange warming during startup
- e.
To deliver excess steam produced in the NSSS to the condenser during startup and transients whenever the steam used by the turbine is less than that produced by the NSSS.
10.3.2 Description The main steam supply system is shown in Figure 10.3-1.
The main steam piping consists of four 24-in. lines from the outboard (second) main steam isolation valves (MSIVs) to the 52-in. manifold (including the motor-operated [third]
MSIVs), and then to the locations described in Subsection 10.3.1.2. The turbine stop valves and MSIVs may be tested independently during plant operation.
The main steam line pressure relief system, main steam line flow restrictors, and MSIVs are described in Subsections 5.2.2, 5.5.4, and 5.5.5, respectively.
The design pressure-temperature rating of the main steam piping is 1250 psig/575°F, the same as the design pressure-temperature of the NSSS. The Category I design requirements are placed (1) on the main steam piping from the reactor up to the third isolation valve and (2) on all branch lines up to and including the first valve, which is either normally closed or capable of automatic closure during all modes of normal NSSS operation. The main steam
FERMI 2 UFSAR 10.3-2 REV 16 10/09 line is also analyzed for the dynamic loadings caused by fast closure of the turbine stop valves. For further information on the design of the main steam piping and valves, see Subsection 6.2.6.6.
A 52-in. manifold is installed ahead of the turbine stop valves. This provides a common point for the four steam lines from the reactor, the four steam lines to the turbine, the two bypass steam lines, the steam line to the RFP turbines, and plant auxiliaries.
A drain line is connected to the low points of each main steam line, both inside the drywell and outside the containment. Both sets of drains are headered and connected by valving to permit steam line isolation and drainage to the main condenser hotwell. To permit draining the lines for maintenance, an additional drain is provided from the low points of the drains to the radwaste system.
The drains inside and outside the containment are capable of equalizing pressure across the MSIVs prior to restart following steam line isolation. Assuming all MSIVs are closed, and the steam lines outside the drywell have been depressurized, the isolation valves outside the drywell are opened first. Then the drain lines are used to warm up and pressurize the outside steam lines. Finally, the MSIVs inside the drywell are opened.
10.3.3 Evaluation The seismic and quality group requirements of all main steam lines and components are defined in Section 3.2. This design ensures conformance with the intent of Regulatory Guide 1.26.
An analysis of the MSIV leakage, which shows that the main steam system provides an effective boundary against MSIV leakage, is provided in Subsection 6.2.6. A discussion of the leakage control for the main steam system in relation to Regulatory Guide 1.96 is found in Subsection A.1.96.
10.3.4 Inspection and Testing Requirements Inspection and testing are carried out in accordance with the requirements of Regulatory Guide 1.68 and ANSI N18.7. The mainsteam line is hydrostatically tested to confirm leaktightness. All welding in the above steam line is 100 percent volumetrically inspected.
TW N30 L203 E
TE N30 N552 E
F L203 N30 TW F
N552 N30 TE TE N30 N552 D
TW N30 L203 D
C N552 N30 TE C
L203 N30 TW TE N30 N552 B
TW N30 L203 B
A N552 N30 TE A
L203 N30 TW TEW N30 N567 TEW N30 N567 PT N30 L194 PXE N30 N415 PXE C71 N052 PXE C32 N007 L194 N30 PT L194 N30 PT L194 N30 PT L194 N30 PT PXE C71 N052 PXE C71 N052 PXE C71 N052 PT N30 L064 L063 N30 PT L064 N30 PT N30 PT PIS B21 N676 PIS B21 N676 PXE B21 N076 N076 B21 PXE PXE B21 N076 PIS B21 N676 PXE B21 N076 RME D11 K603 RME D11 K603 RME D11 K603 RME D11 K603 RR D11 R603 RE D11 N006 RE D11 N006 N006 D11 RE N006 D11 RE MO MO N30 N30 N30 MO M-2004 M-2003 I-2339-02 I-2336-07 I-2336-03 & 27 I-2336-05 I-2346-08 I-2156-02 I-2336-27 M-2005 T1-654 T1-701 S23-101 M-2017-1 (G-6)
M-2017-1 (H-8)
M-2017-1 (G-8)
M-2017-1 (E-8)
M-2017-1 (F-8)
M-2017-1 (H-6)
M-2017-1 (H-6)
TO SJAE #4 TO SJAE #3 TO SJAE #2 TO SJAE #1 TO WEST PREHEATER TO EAST PREHEATER TO SJAE DISCH. MANIFOLD M-2089 (D-3)
M-2089 (C-3)
M-2089 (F-2)
M-2089 (B-3)
D-3 M-2985-1 (D-4) 3261 1"
6" 8"
3261 B-4 8"
10" N1100 F066 4"
B21 PIS N676 I.A.S.
L472 PTT N11 N11 L471 PTT L066D N30 PTL L066C N30 PTL N6100D007B N6100D007A N6100D007D N6100D007C
- 9. THE HOTWELL COIL STEAM SUPPLY SYSTEM IS NOT IN USE.
PER SOP 23.125, ISOLATION VALVE N1100F606 IS CLOSED AND PCV-N61F402 IS ISOLATED BECAUSE ITS AIR SUPPLY IS CLOSED. INSTRUMENTATION PT-N11L470, PXE-N11N465 AND PSE-N11N468 ARE IN SERVICE TO DETECT STEAM LINE PRESSURE INCREASES CAUSED BY LEAKAGE PAST PCV-N61F402.
UP TO VALVE P33F404 TAP IS QA LEVEL 1 FOR PRESSURE BOUNDARY INTEGRITY
- 10.
N621 N30 PXE N275A N30 N275B N30 N276A N30 N30 N276B I-2336-07A T12-074 T12-071 M-2002-1 M-5717-1 M-5717-11 MO
- 7. SYMBOLIZES COMPUTER SEQUENCE NUMBER SEE DWG REF. 4 005 COMPUTED FLOW K
A005 A006 K
6" DRAIN 6"
LOGIC I-2310-11 2"
6" 2"
MO 6"
M-2985 1 1/2" DRAIN 10" 6"
3266 NOTES:
- 1. FOR LEGEND OF SYMBOLS AND ABBREVIATIONS, SEE DWG. "M-2000" AND "M-2001".
FOR FUNCTIONAL OPERATING SKETCH SEE M-5717-1.
- 2. EXTRACTION STEAM DIAGRAM-DWG NO "M-2003."
- 4. DELETED
- 5. DIAGRAM DRIPS AND DRAINS FOR STEAM LINES AND TURBINE SEE M-2985.
- 6. DIAGRAM OF SAMPLES IN T/B SEE I-2400-03.
12" 20" 12" 12" 3393 3370 3393 3393 E.E.C.
36" 36" 36" 12" 20" 12" SOUTH LPSV5 IV5 UA 36" LPSV6 IV6 K
A020 A021 K
K A023 A022 K
IV4 LPSV4 IV3 LPSV3 CENTER K
A025 A024 K
IV2 LPSV2 IV1 LPSV1 NORTH LOW PRESSURE TURBINES 36" E.E.C.
E.E.C.
ALSO SEE REF 14, SHEET 27, ZONE E-3.
T1-932 36" E.E.C.
NORTH CONDENSER HOTWELL SOUTH CONDENSER HOTWELL 2 1/2 1 1/2 1 1/2 2 1/2 1 1/2 2 1/2 1 1/2 2 1/2 HOTWELL COIL STEAM TRAPS 24" 30" 24" 6"
3619 24" 1 1/2" 6WM-N62-3261-1 1"
4"
- 12. MAIN TURBINE TRIP LOGIC
- 13. LIVE STEAM TO REHEATERS SYS.
- 14. MISC. PRESSURES & TEMPERATURES
- 15. TURB. GLAND SEAL SYS.
- 16. TURB. FLANGE HEATING SYS.
- 17. INSTRUMENT DIAGRAM REACTOR PROTECTION SYSTEM C71
- 18. INST. FLOW DIA. ICFD 163
- 1. DELAVAL. GLAND SEAL & EJECTOR
- 2. G.E. NUCLEAR BOILER SYSTEM
- 3. FEEDWATER CONTROL SYSTEM
- 4. G.E. PROCESS RAD MON. SYSTEM
- 5. E.E. UNITIZED ACTUATOR SYSTEM
- 6. E.E. TURB. SUPERVISORY EQUIP.
- 7. E.E. ELECT/HYD GOVERNOR
- 8. E.E. STEAM TURB. BYPASS SYSTEM.
- 9. CONDENSATE SYSTEM DIA
- 10. MAIN TURBINE EXTRACTION STEAM DIA (REHEAT STEAM)
- 11. INSTRUMENT FLOW DIAGRAM ICFD 175 I-2314-03 M-2089 I-2126-01 I-2181-01 & 02 I-2346-01 I-2336-01 I-2336-02 TCS-144 T1-527 6"
6" 6"
3265 24" 8"
12" 12" T1-932 44" I.D.
DRAIN 44" I.D.
44" I.D.
44" I.D.
E.E.C.
20" 20" 18" 20" 20" G078A 24" 32" 32" 32" 32" 20" SV SV SV 10" 10" LEAK OFF LINES 1/2" 1/2" 3378 3/4" 1/2" SV SV SV LEAK OFF LINES A
20" X 12" 1/2" 1/2" 3/4" 3/4" 14"X10" RED.
3378 B
E.E.C.
REF.17 (D-1)
E.E.C.
E.E.C.
44" I.D.
44" I.D.
44" I.D.
44" I.D.
E.E.C.
3" MANIFOLD (INSTRUMENT)
D A
C B
E A
C B
D K
A187 K
A719 A
A B
B HIGH PRESSURE TURBINE SEE DWG REFS. 6&7 DRAIN DRAIN 4"
SEE DWG REF. 5 24" T1-620 TSV1 TCV1 UA UA SEE I-2336-27 ICFD-163 UA UA TCV2 TSV2 T1-620 TSV3 TCV3 UA T1-932 3259 SEE I-2336-27 ICFD-163 3259 B
24" SEE DWG REF.7 F.H.C. PANEL INSERT D
D B
SEE B
A A
006 HI FROM TY K830A FROM TY K830B 002 LO C
SEE DWG REF.8 C
18" 24" 24" 52" MANIFOLD MAIN STEAM DUMP VALVES (2 PLCS)
UA 30" 30" M.S. BYPASS DUMP VALVE WEST T1-934 18" DRAIN 10" DRIP SEE DWG REF.2 3259 SEISMIC II/I "D"
"D+"
SEISMIC I MO SECONDARY CONTAINMENT BOUNDARY NOTE 24" 24" 24" 24" 3258 MO 10" DRIP 12" SCHEM.
I-2311-MO DRAIN TO P9500F407 3619 30" 3260 3259 SEE 24" 26" 3259 3259 3258 3258 3260 10" 12" 6"
SCHEMATIC I-2311-25 VENT 30" 6"
30" 6"
30" 2 1/2" 8"
TO FLANGE WARMING TO GLAND STEAM 3618 8"
M.S.
BYPASS DUMP VALVE EAST 18" X 2" S.O.L.(TYP.)
T1-934 3265 UA TSV4 TCV4 COMPUTED FLOW 6"
DRAIN SCHEMATIC I-2311-25 4"
4" REACTOR FEED PUMP TURBINE NORTH ISOLATION MIMIC I-2052-20 6"
4" 4"
SOUTH TURBINE FEED PUMP REACTOR DRAIN SEE I-2336-27 ICFD-163 T1-620 3259 DRAIN LOGIC I-2310-20 I&C LOOP N11-2 LOGIC I-2310-20 HOTWELL COIL STEAM SUPPLY Q=45,000 6"
3" F.C.
3" K
A001 A000 K
A004 K
A003 K
K A117 A120 K
A121 K
K A124 COMPUTED FLOW K
A325 RED ELL.
RED ELL.
RED ELL.
RED ELL.
B C
A D
D A
C B
F.O.
F.O.
6" 3261 6"
REF. DWGS:
- 19. HEATER DRAINS DIAGRAM
- 20. TURBINE AND REHEATER/SEPARATOR
- 21. HOT AND COLD REHEAT LINES
- 22. REACTOR FEED PUMP TURBINE
%+
3 2
SEE I-2311-26 I & C LOOP N11-1 SO E
6" HI LO 001 K
A015 2"
2" 2"
2" 2"
2" 6WM-N11-3299-1 6WM-N11-3298-1 6WM-N62-3301-1 6WM-N62-3300-1 6WM-N11-3296-1 6WM-N11-3297-1 3261 F003B F004B RV 3/4" 1/2" 32" 32" 32" UA UA UA UA UA UA UA UA UA UA UA 36" 36" UA DRAIN UA UA A324 K
A323 K
K A326 MO MO 27 1"
MO HO HO MO MO DE F387 N3000 F017 N3000 PI R242 B
PI R242 C
PI R242 A
DWG REF. #13 PT N30 L452 F019C N3000 F019B N3000 F019A N3000 PI R242 F
PI R242 D
PIE N30 R900 PTH L408 A
PTH L408 B
TEW N436 TWT L411 PTH L408 C
TEW N452 PT L406 PT L406 PSE N468 PCE K813 PE/P N61 K410 PXE N465 PT L460 TEW N467 PXE N464 F606 ZXV N61 N460 PCV N61 F402 TRE R803 PRA R800 TY K812 TEW N403 PXE N400 PT L404 PTT L431 B
TEW N413 B
CTT L413 F605 M-2985-1 (C-6)
CT L437 B
F060A PTT L431 A
FXE N428 A
FTH L433 A
FTL L432 A
FE N412 A
FTH L435 A
FTL L434 A
FSE N426 A
F601 PI R402 A
PT L417 A
FSE N426 B
FTH L435 B
FTL L434 B
FE N412 B
FTH L433 B
FTL L432 B
FXE N428 B
PI R402 B
PT L417 B
TEW N421 A
PTH L408 D
FTL L445 FTH L446 FTL L447 FTH L448 FE N433 FXE N420 TEW N421 B
TEW N413 C
FTH L444 FXE N441 FTL L443 FE N404 FTH L442 FTL L441 TEW N440 PCV F400 B
PCV F400 A
PT N61 L457 PTT N61 L456 EV F401 PT L414 PXE N453 PSE N491 PI R412 PCP K401 PIE R802 MS 6A27 PSE N455 F022C N3000 F023C N3000 F023B N3000 F022B N3000 F023A N3000 F022A N3000 F011 N3000 F021A N3000 F021C N3000 F021B N3000 F010A N3000 F010B N3000 F010C N3000 F008A N3000 F008B N3000 F008C N3000 F018B N3000 F018C N3000 F018A N3000 F012E N3021 F013E N3021 F012F N3021 F013F N3021 F012C N3021 F013C N3021 F013D N3021 F012D N3021 F012A N3021 F013A N3021 F013B N3021 F012B N3021 F607 N3018 F609 N3018 F003A N3021 F003C N3021 F004C N3021 F004D N3021 F003D N3021 F607 F609 F608 F610 TEW N413 A
TEW N413 D
F059B F059A F001A F001B F602 F060B F604 F603 F199 N6200 F062 F101A N6100 F102D N6100 F102C N6100 F101C N6100 F101B N6100 F103A N6100 F103B N6100 F103D N6100 F103C N6100 F102B N6100 F101D N6100 F102A N6100 N3000 F020A F020B N3000 F020C N3000 N30 N30 N30 RV N3000 F009 36" T
T T
T RV
- 3. UNLESS OTHERWISE SHOWN:
ALL INSTRUMENT PIS #s ARE PREFIXED N11 1
26" 26" 3259 REF. 10 (H-5)
REF. 10 (H-5)
N3021 F004A N3021 N3021 (TYP.)
F063 PT L470
- /HR MAX.
ICFD-163 SEE I-2336-27 FOR INSTRUMENTATION RV 6
SEE A002 K
REF. 2 24" A
24" 24" ALL VALVE & EQUIPMENT PIS #s ARE PREFIXED N1100 PTT N11 L473 M-2985 (B-3)
(SEE NOTE 9)
ABANDON IN PLACE 1"
1" DRAIN TO P9500F407 M-2985-1 (C-6) 6, 10 NOTES QA 1M QA 1 N3000 D012A D012B N3000 D012C N3000 N3000 D013A D013B N3000 D013C N3000 REF. 15 (D-4) 1" 1"
1" 1 1/2" 1"
1" 1 1/2" 1"
M-3370 24" 24" M-2985 (H-2)
DRAIN 6"
6" M-2985 (H-2)
M-2985 (H-2) DRAIN 6"
REHEATER/SEPARATOR EAST N3018B001 A4 A3 D
A2 A1 F
48" 48" 38" 48" 48" 10" 10" E1 E2 8"
18" 38" 45" 45" 45" 36" 36" 36" B3 B2 B1 M-2005-1 (H-7)
AH1 AH2 12" 12" AH1 12" E1 10" WEST N3018B002 REHEATER/SEPARATOR A3 A4 D
A1 A2 48" 48" 38" 48" 48" 12" AH2 E2 10" 45" 36" 45" B1 45" 36" B2 B3 M-2985 (F-2)
DRAIN M-2985 (F-2)
DRAIN 6"
6" 8"
12" 8"
38" E.E.C.
E.E.C.
E.E.C.
E.E.C.
M-2005-1 (G-4) 3203 4"
4" 4" 4" 4"
4" (TYP)
ANNUBAR 32" 32" 12" 12" G078B G078C G078D 38" 32" 32" G079A G079B G079C G079D 32" TO SOUTH REHEATER SEAL TANK TO NORTH REHEATER 3378 3378 M-6135 M-6135 N3018 N3018 N3018 N3018 N3018 N3018 N3018 N3018 FE F
4" 4"
SEAL TANK 3202 FE FE FE 36" TURBINE LIVE STEAM TO REHEATER SYSTEM
- 23. WEST MSR OUTLINE DWG
- 24. EAST MSR OUTLINE DWG 10" 16" TEI FOR INSTRUMENTATION SEE M-2002-1 TEI 10" 16" SEE M-2002-1 FOR INSTRUMENTATION TEI 10" 16" TEI 10" 16" TEI TEI TEI TEI
- 26. MAIN AND REHEAT STEAM SYS MSR INSTRUMENT & THERMOCOUPLE (FOS)
- 27. MAIN AND REHEAT STEAM SYS MSR
12" 2"
18" 10" 8"
10" 2"
2" 2"
18" 18" 10" 10" 2"
2" DRAIN TO COND 2" DRAIN TO COND 2" DRAIN TO COND 3644 2"
3644 2"
H21 P258 PXE N270B ICFD-175 SEE I-2336-07 FOR INSTRUMENTATION ICFD-175 SEE I-2336-07 FOR INSTRUMENTATION PT L219 ICFD-175 SEE I-2336-07 FOR INSTRUMENTATION H21 P258 N30 N270A L218 ICFD-175 SEE I-2336-07 FOR INSTRUMENTATION 18" 12" 6"
2" FC FC L063 11.
I-2314-03 (G-3)
I-2314-03 (G-3)
SEE DWG. "T1-600", I-2336-05 (C-6).
SEE DWG. "T1-579", I-2346-08 (D-6).
M-2985 (F-6) (NOTE 5)
M-2985 (G-6) (NOTE 5)
M-2985 (G-6) (NOTE 5)
M-2985 (G-6) (NOTE 5)
M-2985 (G-6) (NOTE 5)
HTR 5 N&S M-2003 (F-3) 20" HTR 5 N&S M-2003 (F-3) 20" HTR 5 N&S 20" HTR 5 N&S M-2003 (F-3) 20" (F-3)
M-2003 P
M-2985 (H-8) (NOTE 5)
M-2985 (G-8) (NOTE 5)
DELETED BQ N30 N30 BQ PXE PT N30 Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT DETROIT EDISON COMPANY DRAWING NO.
FIGURE 10.3-1 MAIN STEAM SYSTEM 6M721-2002, REV. BQ REV 19 10/14
FERMI 2 UFSAR 10.4 OTHER FEATURES OF THE STEAM AND POWER CONVERSION SYSTEM 10.4.1 Main Condenser 10.4.1.1 Design Bases 10.4.1.1.1 Performance Requirements The main condenser provides the heat sink for the turbine exhaust steam, turbine bypass steam, and other turbine cycle flows, and receives and collects flows for return to the nuclear steam supply system (NSSS).
The main condenser accommodates or provides for the following at rated (nominal) full load (see Figure 10.1-1):
- a.
Total turbine exhaust steam 8.10 x 106 lb/hr
- b.
Total condensate outflow 10.88 x 106 lb/hr
- c.
Total condenser heat duty 7.81 x 109 Btu/hr
- d.
Number of condenser shells One
- e.
Condenser pressure 1.5 in. Hg abs
- f.
Exhaust pressure limit 5.0 in. Hg abs
- g.
Circulating water
- 1.
Flow(Nominal) 836,700 gpm
- 2.
Number of passes One
- 3.
Temperature to limit condenser pressure to 4.5 in. Hg abs 100°F
- 4.
Condenser temperature rise 18°F 10.4.1.1.2 Turbine Bypass Steam The main condenser is designed to accept up to 23.5 percent rated reactor steam flow from the turbine bypass system, as described in Subsection 10.4.4 (also see Figure 10.3-1). This condition is accommodated without increasing the condenser backpressure to the turbine trip setpoint or exceeding the allowable turbine exhaust temperature.
10.4.1.1.3 Condensate Deaeration One purpose of the main condenser is to deaerate the condensate. More specifically, it is designed to reduce the dissolved oxygen level in the condenser hotwell effluent to 7 ppb or less under normal full-load operation. This level is undesirable from a carbon steel corrosion standpoint. However, experience has shown that the normal dissolved oxygen level will be 10 to 50 ppb. If the main condenser deaerates the condensate values consistently less than 10 ppb dissolved oxygen, actions must be promulgated to restore oxygen levels and/or evaluate 10.4-1 REV 19 10/14
FERMI 2 UFSAR the consequences consistent with Owners' Group guidelines and site programs. An Oxygen Injection System has been provided to inject oxygen gas into the condensate system to restore oxygen to normal levels. (See UFSAR Figure 10.4-8(1)).
10.4.1.1.4 Air Leakage The main condenser is designed to minimize air inleakage. Welded construction is used for the condenser shell and for condenser shell connections and penetrations. Equipment and piping connected to the condenser shell are also designed to minimize air inleakage to the main condenser. The design of the evacuation system is described in Subsection 10.4.2.
10.4.1.1.5 Condensate Detention The condenser hotwell is designed to store a sufficient volume of condensate to provide a nominal of 4 minutes' effective detention of the condensate to allow for radioactive decay.
10.4.1.1.6 Design Codes Condenser construction is in accordance with the requirements of Heat Exchange Institute (HEI) standards for steam surface condensers.
10.4.1.2
System Description
During plant operation, steam from the last stage of the low-pressure turbine is exhausted directly downward into the condenser shell through exhaust openings in the bottom of each of the three turbine casings and is condensed. The condenser consists of one shell serving three double-flow, low-pressure turbines. The condenser also serves as a heat sink for several other flows: the two reactor feed pump (RFP) turbine exhausts, cascading heater drains, steam line drains, pump vents and recirculation lines, heater vents, and condensate system makeup.
During transient conditions, the condenser is designed to receive bypass steam, feedwater heater drainage, and moisture-separator drainage. The condenser is also designed to receive relief valve discharges from the feedwater heater shells, steam seal regulator, and the various steam supply lines. The moisture-separator relief valves discharge to the turbine room.
These valves are backed up by rupture disks.
The condenser is cooled by the circulating water system, which removes the heat rejected to the condenser as described in Subsection 10.4.5.
The condensate is pumped from the condenser hotwell by the condenser pumps, described in Subsection 10.4.7, and is returned to the feedwater and steam cycle.
The main condenser is a single-pressure, single-shell, single-pass, deaerating-type condenser with divided water boxes. The condenser tubes are 1 in. in diameter, 50 ft in length, and are made of titanium.
The condenser shell is solidly supported on the turbine foundation mat. It has expansion joints provided between each turbine exhaust opening and the steam inlet connections of the condenser shells.
10.4-2 REV 19 10/14
FERMI 2 UFSAR The condenser hotwell has horizontal and vertical baffles. They improve deaeration and ensure a nominal detention of 4 minutes for all condensate from the time it enters the hotwell until it is removed by the condenser pumps.
Valves in the circulating water system permit one-half of the condenser to be removed from service. This might be required in case of a condenser tube leak.
The air leakage and noncondensible gases include hydrogen and oxygen gases contained in the turbine exhaust steam as a result of dissociation of water in the NSSS. These gases are collected in the condenser and passed through the air-cooling section of the condenser, where they are removed by the main condenser evacuation system, described in Subsection 10.4.2.
10.4.1.3 Safety Evaluation During operation, radioactive steam, gases, and condensate are present in the shell of the main condenser. The anticipated inventory of radioactive contaminants during operation is discussed in Sections 11.1 and 11.3. Shielding for the main condenser is provided as discussed in Section 12.1.
Condensate is retained in the main condenser for a nominal of 4 minutes to permit radioactive decay before the condensate enters the condensate system.
Hydrogen buildup during operation is not a problem because of the provisions for continuous evacuation of noncondensibles from the main condenser. During shutdown, significant hydrogen buildup in the main condenser does not occur because the main condenser is then isolated from the NSSS.
The main condenser is not required to cause or support the safe shutdown of the NSSS or to perform in the operation of NSSS safety features.
Exhaust hood overheating protection is provided by the low-pressure exhaust hood spray systems located just downstream from the last-stage blades of the turbine.
The loss of main condenser vacuum causes the turbine to be tripped. This transient and its effect on the reactor are discussed in Chapter 15.
Four rupture diaphragms on each turbine exhaust hood open at a few pounds per square inch, gage, to protect the condenser and turbine exhaust hoods (15 psig design) against overpressure. Failure of a rupture diaphragm results in radionuclides being admitted directly to the turbine building rather than passing to the offgas system. This specific failure is not analyzed but the results of a more significant event, i.e., failure of the air ejector line, are analyzed in Chapter 15.
Any leakage of circulating water into the condensate is detected by continuous monitoring of conductivity. Leakage of condensate out to the circulating water is detected by radioactivity monitoring in the circulating water reservoir decant line.
10.4.1.4 Tests and Inspections The condenser shell received a field hydrostatic test prior to initial operation. This test consisted of filling the condenser shell with water and, while at the resulting static head, 10.4-3 REV 19 10/14
FERMI 2 UFSAR inspecting all tube joints, accessible welds, and surfaces for visible leakage and/or excessive deflection.
Each condenser water box received a field hydrostatic test and a visual inspection of all joints and external surfaces.
10.4.1.5 Instrumentation Application The condenser shell is provided with local and remote indications of hotwell level and pressure, including alarms in the main control room.
Condensate temperature is measured in the suction lines to the condenser pumps.
Water-box pressure and temperature are measured.
Conductivity instruments detect leakage of circulating water into the condenser steam space.
Air leakage is monitored at the offgas system.
The condensate level in the condenser hotwell is maintained within proper limits by automatic controls. The controls provide for transfer of condensate to and from the condensate storage tank as needed to satisfy the requirements of the thermal cycle.
The condenser hotwell has heating coils in each of the four hotwell sections, however they are not used at Fermi 2.
Turbine exhaust temperature is monitored and controlled with water sprays to protect the turbine blading and exhaust hood from overheating.
A high condenser backpressure alarm is provided at a nominal 4.5 in. Hg abs.
Turbine trip is activated on loss of main condenser vacuum, when condenser backpressure reaches or exceeds a setpoint of a nominal 7.5 in. Hg abs.
10.4.2 Main Condenser Evacuation System 10.4.2.1 Design Bases The main condenser evacuation system during normal operation removes the noncondensible gases from the condenser, including air inleakage and dissociation products originating in the NSSS, and exhausts them to the offgas system (see Section 11.3).
10.4.2.2
System Description
The main condenser evacuation system consists of four 25 percent-capacity, two-stage steam-jet air ejector units, complete with intercondensers for normal plant operation and mechanical vacuum pumps for use during startup. Typically, only two of the four steam-jet air ejector units are required for normal operation.
The mechanical vacuum pumps are used to remove the air and offgases from the main condenser. The discharge from the vacuum pumps is routed to the reactor building vent stack via the 2-minute holdup pipe. The offgases from the vacuum pump are discharged directly to the environment. This is acceptable because the vacuum pump is in service when 10.4-4 REV 19 10/14
FERMI 2 UFSAR little or no radio-active gases are present. However, the gas is monitored for radioactivity and pumps will be shut down if Technical Specifications limits are exceeded.
When suitable steam is available, the steam-jet air ejectors are put into service to remove the gases from the main condenser after 6 in. Hg abs vacuum has been established in the main condenser by the mechanical vacuum pumps. Main steam, reduced in pressure to a nominal value of 200 psig by an automatic steam-pressure-reducing station, is supplied as the driving medium to the two-stage air ejectors. The first stages take suction from the main condenser and exhaust the gas vapor mixture to the intercondensers. The second stages exhaust the suction gas vapor mixture from the intercondensers to the offgas system. The steam-jet inter-condensers are drained back to the main condenser.
10.4.2.3 Safety Evaluation The treatment of radionuclide releases from the main condenser via the offgas system is discussed in Section 11.3. Prolonged shutdown of the offgas system can cause significant hydrogen buildup in the condenser and require shutdown of the unit within 5 to 10 minutes, if condenser backpressure warrants.
Failure of the air ejector line leading to the release of radionuclides directly to the turbine building is discussed in Chapter 15.
10.4.2.4 Tests and Inspections All tests and inspections of the equipment that is part of the main condenser evacuation system are performed in accordance with ANSI N18.7.6 and the applicable section of Regulatory Guide 1.68.
10.4.2.5 Instrumentation Application Process instrumentation applying to the evacuation system is described in Section 11.4. High radiation at the 2-minute holdup pipe will trip and isolate the vacuum pumps. High radiation from the offgas system causes an alarm signaling the operator to take corrective action.
10.4.3 Main Turbine Gland Sealing System 10.4.3.1 Design Bases The main turbine gland sealing system prevents air leakage into, or radioactive steam leakage out of, the main turbine.
The main turbine gland sealing system is designed to seal the main and RFP turbine shaft glands and valve stems (high-pressure stop, control, low-pressure stop, intercept, and bypass valves).
10.4.3.2
System Description
The turbine gland sealing system (Figure 10.4-1) consists of a startup steam supply from the 52-in. manifold or from the auxiliary boiler, steam seal pressure regulators, steam seal 10.4-5 REV 19 10/14
FERMI 2 UFSAR header, one full-capacity gland steam condenser, two full-capacity exhauster blowers, and the associated piping, valves, and instrumentation.
Sealing steam for turbine shaft packing glands and valve stem packing glands is supplied from the steam seal header, which is maintained at a positive pressure of approximately 2 psig. During startup and low load, the header is supplied with live steam from the 52-in.
manifold or from the auxiliary boiler. At normal load, the turbine becomes self-sealing as the seal header is then supplied with steam from the high-pressure turbine center gland.
The outer pockets of all glands are routed through the gland steam condenser, which is maintained at a slight vacuum of approximately 20 in. H2O by the exhauster blowers. This positively prevents escape of steam from the glands into the turbine room. Instead, air is drawn into the outer glands at these points, and the steam/air mixture is routed to the gland steam condenser. The gland steam condenser, which is cooled by the main condensate flow, condenses the gland steam and returns this to the main condenser, while allowing saturated air and noncondensible gases to be drawn out by the exhauster.
The gland steam exhauster discharges to the reactor building vent by way of the 2-minute holdup pipe. This flow is throttled by valve VR3-2578 to keep the discharge as low as possible but still maintain proper vacuum.
10.4.3.3 Safety Evaluation The turbine gland sealing system provides a continuous supply of steam to the turbine shaft glands and the valve stems.
The high-pressure turbine shaft packing can accommodate a range of turbine shell pressures from zero to full-load pressure. The low-pressure turbine shaft packing seals against vacuum at all times. The sealing steam enters the high-and low-pressure turbine shaft packings and the valve stem packings through the inner annulus pocket. Steam is positively prevented from leaking into the turbine room by maintaining a vacuum at each gland outer pocket at all times. This vacuum is provided by the gland steam exhauster. A standby exhauster is provided.
If exhauster vacuum falls below approximately 10 in. H2O, caused for example by loss of ac power, a vacuum switch initiates the closing of the live steam supply to the gland steam header.
An analysis of possible failure modes of the turbine gland sealing system is presented in Chapter 15.
10.4.3.4 Tests and Inspections Normal manufacturers' tests are performed on all equipment. The following tests are required for the gland steam condenser: leak test for tube-to-tube-sheet joints, hydrostatic test, and eddy current tube tests.
10.4.3.5 Instrumentation Application The liquid level in the gland steam condenser is maintained by a control valve connected to the main condenser. Local pressure-control valves are provided to maintain the gland steam 10.4-6 REV 19 10/14
FERMI 2 UFSAR header pressure constant at approximately 2 psig, by either supplying or dumping steam as required. If pressure rises above 5 psig, excess steam is discharged to the condenser by a relief valve.
Temperature and pressure gages are installed in a local panel. Test flow orifices are provided to monitor operation of the system.
10.4.4 Turbine Bypass System 10.4.4.1 Introduction The Fermi 2 bypass system is a composite of passive and active components that provides a steam path following a turbine-generator trip.
The Fermi bypass system has two key features: the live steam supply to the turbine reheaters, which has a nominal flow of 8 percent of nuclear boiler rating, and the electro-hydraulic control (EHC) redundant bypass valves, which are each designed to bypass a nominal 11.75 percent (23.5 percent total) rated reactor flow to the condenser.
Immediately following a turbine or generator trip from rated power, the bypass system will have a nominal capacity of 31.5 percent of nuclear boiler rating (reheater steam supply plus bypass valves). Following a typical trip, the live steam supply is eventually isolated and the pressure control system maintains the setpoint pressure by modulating the bypass valves.
10.4.4.2 Summary The Fermi bypass system is designed in such a manner that the loss of the bypass system would require multiple random failures in the system. However, as identified in Table 10.4-1, loss of the BOP dc feeding the system causes both bypass valves to close. Because this is very unlikely, the turbine trip without bypass transient was analyzed as the turbine trip with a single bypass valve failure prior to initial fuel load. This event was not the limiting transient with respect to minimum critical power ratio (MCPR) limits.
Edison maintained that the design of the Fermi 2 bypass system obviates the need to consider the turbine trip without bypass to be part of the design basis. Currently, Fermi performs the turbine trip event and the load reject event assuming that all bypass valves fail to open during the transient. The analysis was based on input parameters specified in Table 15.0-1 and used the TRACG computer code. The results are summarized in Subsection 15.2.3. The technical specification for MCPR is frequently based on these results.
The analysis of reheater steam flow, which is important in the turbine trip analysis, is described further in Subsection 10.4.4.3.
10.4.4.3 Passive Bypass (Live Steam to Reheaters) 10.4.4.3.1 Design Bases The primary purpose of piping the live steam to the reheater is to improve cycle efficiency by drying and superheating the high-pressure turbine exhaust before it enters the low-pressure turbines. In addition, piping live steam to the reheater minimizes the mechanical damage to 10.4-7 REV 19 10/14
FERMI 2 UFSAR turbine blades due to erosion by water droplets and the tearing of sealing surfaces due to leakage of wet steam. The reheat steam quality and flow at rated load are illustrated in the heat balance shown in Figure 10.1-1. As a secondary result of live-steam-reheat flow, a passive bypass system exists and continues to operate following a turbine stop and/or throttle valve closure. The length of time this passive system operates is a function of the time required to close the motor-operated isolation valve in the supply line. The rate of decay of flow following the turbine trip is controlled primarily by the thermodynamic response of the reheater's heat-exchange process until the isolation valve closes.
10.4.4.3.2 System Description Each moisture separator reheater (MSR) is a cylindrical vessel located on either side of the main turbine generator on the turbine floor. The pressure vessel (shell) is approximately 12 ft in diameter and 111 ft long. Each MSR is equipped with a heating bundle at each end of the MSR vessel. The heating bundle consists of 1195 U-tubes configured in two sets of vertically arranged U-tubes, one located on top of the other to provide a "four pass" heating geometry. Each U-tube is 3/4 in. in outer diameter (nominal) with finned surface to promote more efficient heat transfer. Heating/live steam from the reactor enters the bottom bundle of the U-tubes, completes the first two passes, exits to the top bundle and completes the third and fourth passes. The drains from second pass are routed to the Reheater Seal Tank.
Whereas the drains from the fourth pass are routed to the shell of the MSR. Cold reheat steam from the high-pressure turbine exhaust enters the bottom of the separator reheater through four inlet connections. The steam is directed upward through the moisture separators, and passes the reheater tube bundles. The reheated steam then leaves the reheater and passes through the low-pressure turbine-stop and intercept valves and into the low-pressure turbines.
Live steam is supplied as shown in Figure 10.3-1. The steam source is the 52-in.-diameter pressure-equalizing manifold which supplies steam to the four turbine inlet connections through the high-pressure turbine-stop valves. The EHC-controlled bypass valves are also connected to this manifold. The live steam passes through two parallel motor-operated isolation valves (N3018F607) and bypass valve (N3018F609) and then through the parallel combination of two pressure-control valves (N30F006 and N30F007) and a full-flow valve (N3018F608). During normal operation at rated load, the isolation valve and the full-flow valve are fully open. On a turbine or generator trip, valve N3018F607 is closed automatically at a nominal 12-inch-per-minute rate. The bypass valve (N3018F609) is used for warmup purposes only. The two automatic pressure control valves are used during initial startup to maintain a controlled heatup rate. These valves are held completely open during normal operation to prevent the lines from forming/collecting condensate. The live steam then flows through the tube bundles inside each reheater where the heat is transferred to reheat the cold steam from the high-pressure turbine.
In addition to reheating the high pressure turbine exhaust steam, the MSRs provide the passive bypass capability to the reactor steam supply system following a main turbine/generator trip. UFSAR section 10.4.4.3.4 discusses the evaluation of the MSR passive bypass flow adequacy during a postulated turbine trip.
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FERMI 2 UFSAR 10.4.4.3.3 Single-Failure Analysis Because the amount of live steam flow following a turbine or generator trip, for the time period of interest, does not depend on the action or inaction of an active component, none of the single failures identified can terminate this flow.
10.4.4.3.4 Transient Analysis During Fermi 2 initial licensing process, the assumed passive bypass flow capability through the Moisture Separator Reheaters (MSRs), following a turbine trip was documented in Detroit Edison Letter to the NRC dated April 27, 1982 (Reference 1). The NRC acceptance of Fermi 2 analysis was based on reviewing the results generated using the NRC approved version of the RETRAN computer code. The NRC Safety Evaluation Report, NUREG-0798, (Reference 2), Supplement 1, September 1981 Section 15. 1, p. 15-1 and NUREG-0798, Supplement 3, January, 1983, Section 15.1, p 15-1(Reference 2) documented the NRC review and acceptance of Fermi 2 methodology. The model included the following physical entities:
- a.
Main steam and reheat steam lines, isolation valves, and MSR drains
- b.
High pressure turbine-stop and throttle valves
- c.
High-pressure turbine
- d.
Extraction flows to heaters 5 and 6
- e.
Shell side of reheater
- f.
Reheater heat transfer
- g.
Low pressure turbine intercept valves
- h.
Low-pressure turbines
- i.
Reheater seal tanks
- j.
Heaters 5 and 6.
Significant physical entities that affect the passive bypass flow during a turbine trip transient are as follows:
- a.
The configuration of the reheat steam supply piping
- b.
The physical characteristics of the MSRs
- c.
The configuration of the reheater drain piping upstream of the reheater seal tanks The analysis showed that the passive bypass flow through the MSRs was in excess of the assumed 8% of the nuclear boiler rating (NBR) flow during the first two seconds following a turbine trip.
The original MSRs were replaced during the 2006 Refueling Outage (RF11). The above transient analysis to demonstrate the passive bypass capability was repeated for the replacement MSRs using the NRC approved version of the RETRAN computer code, as documented in "RETRAN02 Analysis for a Moisture Separator Reheater Flow Distribution",
Dated October 18, 2005 (Reference 3). The new transient analysis models the steam cycle 10.4-9 REV 19 10/14
FERMI 2 UFSAR including the physical entities a through j listed above in order to establish initial steady state conditions. For conservatism, the above RETRAN02 Analysis (Reference 3) did not include the third and fourth passes of either of the two new MSRs. This RETRAN02 analysis (Reference 3) showed that the passive bypass flow through the replacement MSRs remains in excess of the assumed 8% of the nuclear boiler rating (NBR) flow during the first two seconds following a turbine trip.
Additional sensitivity analyses were performed to determine the parameters that may affect the assumed passive bypass flow through the MSRs following a hypothetical turbine trip event, as documented in "RETRAN02 Analysis for a Moisture Separator Reheater Flow Distribution", Dated October 18, 2005 (Reference 3). These sensitivity analyses show that the required passive bypass flow capability through the MSRs can be maintained when:
(1)180 tubes are plugged in each of the MSR's first and second passes even after excluding the third and fourth passes in each MSR; and (2) when the volumes of the nearest and the next to the nearest nodes upstream and down stream of the MSRs are varied by plus or minus 10 percent. Therefore, future tube plugging and changes in nodal volumes that are within the bounds of the above sensitivity analysis (Reference 3) can be performed without further analysis.
A bounding (conservative) flow characteristic, documented in "RETRAN02 Analysis for a Moisture Separator Reheater Flow Distribution", (Reference 3) is used as an input to Subsection 15.1.2, Feedwater Controller Failure transient analysis, Subsection 15.2.2 Generator Load Rejection transient analysis and Subsection 15.2.3 Turbine Generator Trip transient analysis, as shown in Figure 15.0-2.
The RETRAN02 Analysis was repeated for operation at 3486 MWt. The revised RETRAN02 Analysis (Reference 8) showed that the passive bypass flow through the MSRs remains in excess of the assumed 8% of the NBR flow during the first two seconds of a trip.
10.4.4.4 Active Bypass (EHC-Controlled Bypass System) 10.4.4.4.1 Design Bases The EHC-controlled (electro-hydraulic control) bypass system is designed to control reactor pressure whenever the turbine throttle valves are not able to maintain control. This includes startup and shutdown operations. The bypass system possesses an emergency open mode of operation in which the bypass valves are opened at a full-stroke rate equal to the full-stroke, trip-closure rate of the high-pressure turbine-stop and throttle valves.
The bypass system control logic is designed with triple redundant channels to be compatible with the English Electric (EE) philosophy used on the turbine-governor portion of the system. Each of the two bypass valves operates independently and each has its own self-contained hydraulic (unitized actuator) system. Each valve is sized to pass a nominal 11.75 percent rated reactor flow in the full-open position for a controlled total bypass of 23.5 percent rated reactor flow. The system is designed so that any postulated failure will not cause both valves to fail to open in the fast-opening mode of operation coincident with the closure of the turbine-stop or throttle valves. The controlled bypass failure analysis is discussed in Subsection 10.4.4.4.3 and the failure mode and effects analysis is presented on a systems basis in Table 10.4-1.
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FERMI 2 UFSAR 10.4.4.4.2 System Description The pressure control system used on Fermi 2 is a solid-state electronic system, designed by English Electric Company Elliot Automation. The system is a three-channel design operating with a two-out-of-three logic. A simplified sketch of the pressure control system is shown in Figure 10.4-3. The positioning of each bypass valve is achieved by using an individual, unitized actuator for each valve. Each module of each channel has its own power supply, which is connected to two independent ac sources. Each module power supply can use either source to supply its requirements. Consequently, a fault in one module cannot affect the other module power supplies.
The total power requirement for the governor/pressure control system (approximately 2.5 kVA) is supplied entirely by twenty-nine +/-15-V dc and three +/-5-V dc power supplies. Each of these supplies provides operating potential for one module/control function such as a bypass valve control module. These precision-regulated power supplies are not interconnected with the other module supplies and are fed from redundant and independent 110-V ac power feeds.
The sources for these two independent power feeds are the reactor pressure system buses A and B, which would supply ac power to the system following a loss of offsite power for a period of at least 2 sec. Isolation within a power supply is accomplished using diodes, and each redundant portion of an individual supply is sized to carry the entire module power requirement. A loss of either ac power feed to an individual power supply is alarmed in the control room.
A 480-V ac supply is provided for each valve actuator oil pump. These feeds are common from one power supply. The oil pumps operate in an on-off fashion to replenish the hydraulic accumulators in the actuators as demand dictates.
The 130-V dc power supply that energizes the valve actuator solenoid valves is supplied from the plant battery system. All the turbine valves are powered by battery 2PB-1 and the bypass valve solenoids are powered by battery 2PB-2.
Referring to Figure 10.4-3, in each pressure module the pressure signal from the associated pressure transmitter is compared with the pressure-regulator setpoint. The resulting difference is the pressure error signal. The pressure error signal is operated on by the control algorithm of the pressure regulator and steam line resonance filter to produce a pressure demand signal.
The pressure demand from each pressure regulator is auctioneered against the other demands in three independent, high-value gates. This results in the selection of the pressure demand that will produce the largest bypass valve flow demand. The output of each of the three gates is modified by the flow limiter, which is adjustable and consists of a three-gang potentiometer. The resulting signal is the pressure-steam signal, which is transmitted to the three computing channel modules. At this point, each signal is compared on a per-channel basis in a low-value gate with the other signals controlling the turbine-stop, throttle, and intercept valves.
The low-value gates send the lowest signal back to the pressure control modules. A turbine and/or generator trip sets the low-value gates to a minimum, which results in the generation 10.4-11 REV 19 10/14
FERMI 2 UFSAR of a large, opening-demand signal at the input to each of the bypass valve control modules.
This error signal is sent from each pressure module and the pressure control module to the input-averaging amplifier of each bypass valve control module. The input amplifier in the bypass valve module averages the three signals and detects and removes any signal that deviates from the average.
The average-demand signal is compared to the actual bypass valve position as measured by redundant valve position transducers (LVDTs) to generate a control signal to drive the bypass servovalve through a power amplifier. The spool valve of the servovalve is mechanically biased to open the bypass valve if the control current through the servovalve is zero. A position-error detection circuit is provided to activate the fast-opening mode of operation when the bypass valve position error (in the open direction) exceeds approximately 8 percent. A contact from the comparator output relay energizes the fast-opening solenoid valve (c) shown in Figure 10.4-4. The solenoid valve allows high-pressure oil from the accumulators to operate the fast-opening valve. The fast-opening valve admits high-pressure oil directly into the bypass valve servocylinder to achieve an opening time of 0.2 sec for full stroke.
An independent one-out-of-two-times-two condenser pressure logic also interfaces with the close solenoid of each actuator to trip the valves closed on low condenser vacuum. When the fast-opening solenoid and the close solenoid are operated at the same time, the close solenoid will override the fast-opening solenoid, and the bypass valve will close. The station battery powers the control solenoids on the bypass valve unitized actuators. Alarms are provided on loss-of-actuator pressure, pressure-module failure, pressure-control-module failure, computing-channel failure, excessive valve-position error, power-supply failure, low fluid level, LVDT failure, or a single condenser switch failure.
10.4.4.4.3 Controlled Bypass Failure Analysis Due to the redundancy of the control logic and the hydraulic actuator hardware, no identified hardware failure can result in the fast closure of the turbine stop and/or throttle valves and prevent the fast opening of both the bypass valves. In addition, external failures such as loss of condenser vacuum have been considered. A protection logic using separate and redundant condenser-pressure trip strings for both turbine-trip and bypass-trip functions has been provided. The trip setpoint for closure of the turbine control valve and stop valve occurs at a much lower condenser pressure than the bypass valve condenser pressure trip. This allows ample time for the fast opening of the bypass valves to mitigate the effects of the fast stop and/or control valve closure during a condenser vacuum loss.
The control power for the stop and control valve unitized actuators is separate from the bypass valve control power, thereby preventing a single battery failure from closing all the valves through the loss of power to the trip solenoids.
In the unlikely event that all offsite power is lost, the turbine stop and throttle valves will close in the fast closure mode. The bypass system will function in the fast opening mode as intended in this situation. Each unitized actuator has two accumulators that store enough hydraulic energy to stroke each valve approximately three times. Battery control power is provided for the critical control solenoid valves and a supply of ac power to the pressure 10.4-12 REV 19 10/14
FERMI 2 UFSAR control module is provided for the duration of the transient. Refer to Table 10.4-1 for a summary of EHC-controlled bypass failure mode and effects analyses.
10.4.4.4.4 Transient Analysis To exhibit an additional degree of conservatism for the turbine-trip transient analysis, it is assumed that one of the redundant bypass valves fails to open in the fast mode and therefore credit has been taken for only one-half of the controlled bypass capability. The one bypass valve is analyzed with an opening delay of 0.1 sec and a full-stroke time of 0.2 sec. The capacity of one valve at full-open is a nominal 12-1/2 percent rated steam flow.
10.4.5 Circulating Water System 10.4.5.1 Design Bases The circulating water for cycle heat rejection from the main condenser is provided by a closed cycle circulating water system using two parallel natural draft cooling towers. The cooling towers remove the design heat load from the circulating water for all weather conditions.
10.4.5.2
System Description
The circulating water system supplies the main condenser with the necessary cooling water at temperatures ranging from nominal 55°F to 94°F. In the winter, the water temperature may be as low as 35°F; however, if that is the case, the cooling towers are bypassed. The system consists of the main condenser, cooling towers, circulating water reservoir, and circulating water pumps, as shown in Figure 10.4-5. Data on specific components are given in Table 10.4-2.
The circulating water reservoir is sized to support limited operation of Fermi 2 following loss of makeup water, which might occur with simultaneous conditions of sustained strong westerly winds and low Lake Erie water level, or damage to or blockage of the intake structure. The reservoir base area is nominally 5.5 acres. Approximately 23 x 106 gal are available at sufficient head for the circulating water pumps and are sufficient for the evaporative losses expected during a limited period of operation and plant shutdown.
Following this, if makeup water is still not available, approximately 7.9 x 106 gallons would still remain in the reservoir to supply general service water (GSW) following shutdown of the circulating water pumps.
Five 20 percent (180,000 gpm each), motor-driven, vertical, wet-pit circulating water pumps are located in the circulating water pump house. These pumps take suction from the circulating water reservoir and discharge the circulating water via two 12-ft-diameter pipes to the main condenser where the water temperature is raised 18°F (nominal). The heated water is discharged from the two outlet water boxes into two circulating water pipes, which are 12 ft in diameter and are interconnected so that a cooling tower may be removed from service during operation.
The natural draft cooling towers are designed for a wet-bulb temperature of 74°F. The design range and the design approach are both 18°F. The design range and design approach 10.4-13 REV 19 10/14
FERMI 2 UFSAR may vary slightly due to the installation of wind vanes and replacement fill which improve performance under wind conditions. ("Range" is the amount the water is cooled.
"Approach" is the difference between cooled water temperature and air wet-bulb temperature.) Each tower is approximately 450 ft in diameter at the base; the maximum elevation is 400 ft above the grade elevation.
After passing through the cooling tower fill, the circulating water flows into the circulating water reservoir and then to the circulating water pump house located at the south end of the reservoir.
A decanting blowdown system is provided on the circulating water system. This is required to maintain water quality because the evaporative process in the cooling tower tends to increase the dissolved solids content in the circulating water. Blowdown (approximately 10,000 to 30,000 gpm) is taken from the circulating water reservoir by one, two, or three decanting pumps, monitored, and discharged to Lake Erie through the 36-in.-diameter decanting line.
A makeup water system replaces the circulating water losses caused by evaporation and blowdown. Makeup water is fed into the circulating water system from the GSW system discharge or from the circulating water makeup pumps (normal and standby).
Approximately 22,000 to 28,000 gpm of makeup water are required, depending upon the season of the year.
A biocide can be added to the circulating water to prevent growth of algae and slime on the inner surfaces of the condenser tubes. Regular monitoring of residual halogens at the decanting line is done to comply with environmental regulations. The biocide injection system and dehalogenation system are shown in Figure 10.4-6. A chemical scale inhibitor that has been evaluated to be compatible with materials in the Circulating Water System is added to minimize formation of scale on internal system surfaces. Sulfuric acid is added as needed to adjust the system pH.
The circulating water system is designed with cross-connected discharge piping from the circulating water pumps. The pumps are equipped with separate butterfly valves that permit any circulating water pump or pumps to be isolated while the remaining pumps continue to operate.
Appropriate valving allows the plant to operate on one train of condenser water boxes (one longitudinal half of the condenser can be taken out of service). The system piping is designed in accordance with ANSI B31.1.0.
Cooling water pumps are tripped on high pressure to prevent over-pressurization of the 12-ft lines. Relief valves are provided at the cooling towers to prevent overpressurization by the GSW system.
10.4.5.3 Safety Evaluation The closest cooling towers are located at least one tower height away from the NSSS containment and auxiliary and turbine buildings complex. It is extremely unlikely that the towers will collapse because they were designed for a wind velocity of 90 mph. If a cooling tower were to collapse, however, it would fall inward, because its base is wider than its top.
Therefore, the potential for the debris to damage any plant structure is minimal.
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FERMI 2 UFSAR Circulating water is not required for safe shutdown of the plant.
The potential for water hammer in the circulating water piping and the associated rupture of expansion joints has been minimized by using motor-operated valves in place of fast-acting hydraulic or pneumatic positioners. A postulated rupture of the expansion joint in the system may flood the basement of the turbine building; however, even this would not result in any risk to the health and safety of the public because there is no engineered safety feature equipment located in the turbine building.
The reactor/auxiliary building houses safety-related components and is designed against site flooding to Elevation 588 ft, as described in Subsection 2.4.2.2.2. It would therefore withstand turbine building flooding to first floor and grade Elevation 583 ft, at which point the water would run out of the building.
Even though flooding of the turbine building does not pose a safety threat, the following additional information has been provided to describe some aspects of such an event.
First, if the failure were to occur in a circulating water line because of a pressure surge, that same surge would probably trip off the circulating water pumps by means of the pressure switches that protect the system. Flooding would thus not occur.
Second, if the joint should completely fail in either the 9-or 12-ft-diameter circulating water lines, and the pumps did not trip, water would be forced out the resulting 3.5-in. gap at an estimated rate of about 200,000 gpm and would take about 45 minutes to fill the turbine building to grade level. However, the operator would be made aware of the problem due to variations in process parameters and would trip the circulating water pumps long before flooding to grade level would occur.
10.4.5.4 Tests and Inspections All active components of the system (except the main condenser) are accessible for inspection during station operation. Cooling tower tests, if deemed necessary, are in accordance with the ASME power test code for atmospheric water cooling equipment, PTC-
- 23.
The circulating water pump house (CWPH) will be sampled every spring and fall for the presence of Mollusks. The Fermi 2 Mollusk Monitoring Implementation and Treatment Plan requires that the inlet and outlet water boxes to the main condenser be inspected during the next scheduled outage following the detection of Mollusks in the CWPH. Also, the inlet and outlet water boxes of the main condenser will be inspected if performance decreases significantly.
10.4.5.5 Instrumentation Application The condenser shell water boxes are equipped with isolation valves that enable either half of the condenser to be isolated. All isolation valves are operated by remote switches in the main control room. Temperature and pressure are measured at the condenser. Circulating water flow and reservoir level are monitored. Also, analysis of the circulating water for pH, biocide residual, and radioactivity is performed.
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FERMI 2 UFSAR 10.4.6 Condensate Polishing Demineralizer System Condensate polishing is performed by a full flow polishing demineralizer of the mixed-powdered-resin type.
10.4.6.1 Design Bases 10.4.6.1.1 Fraction of Condensate Flow Treated The condensate polishing demineralizer system processes all of the condensate from the condenser hotwell (approximately 10.5 x 106 lb/hr at full load). The heater drains are pumped forward from the No. 5 heaters to the feedwater stream and are not demineralized (approximately 4.3 x 106 lb/hr at full load). These drains, however, are continuously recycled and deaerated to less than 70 ppb dissolved oxygen prior to forward pumping. They are also continuously monitored for oxygen and conductivity to provide additional assurance of no adverse impact to final feedwater quality. Turbidity is monitored on an as-needed basis by local grab during periods when corrosion product concentrations are expected to be higher than normal.
10.4.6.1.2 Effluent Impurity Levels To Be Maintained Operating procedures ensure that the effluent from the condensate polishing demineralizer system results in reactor impurity levels that meet the requirements of Regulatory Guide 1.56 (see Subsection A.1.56). Further limits on condensate composition and electrical conductivity are established in GE Specification 22A2707, BWR Plant Requirements, Part 7, Water Quality.
The condensate polishing demineralizer maintains the required purity of feedwater flowing to the reactor. During normal operation, the system removes dissolved and suspended solids from the feedwater and maintains a high effluent quality based on the following design values:
- a.
Specific conductivity (µmho/cm) at 25°C 0.1
- b.
pH at 25°C 6.5 to 7.5
- c.
Metallic impurities, as the metal (ppb) 10 (of which copper shall not exceed 2 ppb)
- d.
Silica, as SiO2 (ppb) 5
- e.
Chloride (ppb) 2 The limit of metallic impurities in the feedwater measured at the outboard isolation valve is 15 ppb, including a maximum of 2 ppb of copper. During initial plant testing and startup, the normal limit of metallic impurities may be exceeded for the first 500 hr of effective full-power operation. During such a period, the average concentration of metallic impurities shall not exceed 50 ppb at greater than 50 percent power, nor shall it exceed 100 ppb at less than or equal to 50 percent power.
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FERMI 2 UFSAR During restarts or periods of operational disturbance, the normal limit of 15 ppb may be exceeded for up to 14 days in any 12-month period. However, the average concentration during this period shall not exceed 50 ppb.
10.4.6.1.3 Design Codes The condensate cleanup system pressure vessels are constructed in accordance with the ASME Boiler and Pressure Vessel (B&PV) Code Section VIII, Division I. All piping is in accordance with the ANSI B31.1.0 Code for Pressure Piping.
10.4.6.2
System Description
The condensate polishing-demineralizer system is shown in Figure 10.4-7. It consists of eight parallel-operating demineralizers. Normally, all eight demineralizers are in operation except when one is in backwash/precoat or down for maintenance. The number of demineralizers in service may be varied to accommodate the varying differential flow and pressure requirements of the system. The system includes the associated piping, effluent strainers, backwash, precoat system (with backwash tank and pumps), as well as the necessary valves, instrumentation, and controls required to provide proper operation and protection against malfunction.
The body feed system (with body feed tank pumps) has been abandoned in place and no longer in service.
Instrumentation includes an automatic flow-balancing control that can be used to maintain equal flow (approximately 3000 gpm) through each onstream unit. The valves, pumps and flow can also be controlled manually from local panels.
In the event that a high pressure differential occurs across the condensate cleanup system, an automatic bypass valve opens to prevent damage to the demineralizer. It is highly unlikely that the bypass valve will open during normal operation. However, if this were to occur, appropriate steps would be taken to minimize the introduction of untreated water to the reactor.
10.4.6.3 Safety Evaluation The condensate demineralizers provide high purity water to the reactor pressure vessel (RPV). Any loss of performance of the demineralizers would be immediately detected by process instrumentation. Buildup of impurities in the RPV is restrained by Technical Specifications limits such that the reactor is shut down well before unacceptable limits are reached. Additionally, more conservative limits and corrective actions are maintained and administered by the plant chemistry section. Subsequent safe shutdown of the reactor does not require the condensate demineralizers.
Resins are not regenerated at Fermi 2. However, they are replaced before the differential pressure of an individual demineralizer or the conductivity of a demineralizer effluent reaches detrimental levels. The alarm setpoint for the influent conductivity meter is 0.2
µS/cm. At this point, the plant chemistry section is notified to acquire samples of influent to check the possibility of a condenser leak. If analysis indicates that a leak exists, corrective action is taken before the 0.5 µS/cm high-high alarm is reached. The alarm setpoints for the 10.4-17 REV 19 10/14
FERMI 2 UFSAR effluent conductivity meter are 0.1 and 0.09 µS/cm for the individual and the combined demineralizer outlet, respectively. Corrective action is initiated at 0.1 µS/cm but before 0.2
µS/cm for all individual demineralizer effluents.
The conductivity meter in the condensate cleanup system will be calibrated by comparing it with an in-line laboratory cell once a week. The flow rate through each demineralizer is measured at the outlet from the pressure drop across an orifice plate.
The initial total capacity of condensate polishing and reactor water cleanup demineralizer resins will be measured at least once per year before demineralizer vessel loading. Capacity determinations will be performed by one of the following:
- a.
Plant Chemistry Section, Fermi 2
- b.
Engineering Services Organization, Edison
- c.
Resin vendor/supplier.
The chemistry performed to determine the total resin ionic capacity is outlined by ASTM D-2187. If the type or the supplier of cation and anion resins is changed, a measurement of initial total capacity will be performed before vessel loading. Excess capacity exists in the condensate treatment system to provide for the orderly shutdown of the reactor in the event of a postulated condenser leak of 50 gpm.
The condensate quality guidelines of condensate influent, effluent, final feedwater, and reactor water are summarized in Table 10.4-3.
10.4.6.4 Tests and Inspections The condensate polishing demineralizer system is tested and inspected in accordance with ANSI N18.7.6 and applicable sections of Regulatory Guide 1.68. All pressure vessels and piping are hydrostatically tested at a pressure 1.5 times the design pressure. Additionally, before the equipment was put into service, a performance test was run to ascertain that the equipment is performing according to the specifications.
10.4.6.5 Instrumentation Application The performance of the condensate polishing demineralizer system is monitored by conductivity instrumentation at the inlet and outlet and downstream of each demineralizer.
Small condenser leaks as low as 6 gpm will be detected. Other instrumentation on the feedwater and reactor water checks for dissolved oxygen, pH, and conductivity. Differential pressure measurements are made to detect solids buildup on the filtering elements. Both local alarms and main control room alarms alert the plant operators whenever undesirable limits are reached. The alarm setpoint at the inlet of the demineralizers in the condensate system is 0.2 µS/cm, and the setpoints for the individual and overall demineralizer outlet are 0.1 and 0.09 µS/cm, respectively.
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FERMI 2 UFSAR 10.4.7 Condensate and Feedwater System 10.4.7.1 Design Bases The condensate and feedwater system provides a dependable supply of feedwater to the NSSS, provides feedwater heating, and maintains high feedwater quality. The system provides the required flow at the required pressure to the NSSS and allows sufficient margin to provide continued flow under anticipated transient conditions.
10.4.7.1.1 Performance Requirements The system provides feedwater at a nominal pressure of 1173 psia from the two RFPs. It has sufficient capacity with appropriate margin to provide feedwater flow for the unit design-basis rating. The feedwater heaters provide feedwater at the required temperature to the NSSS with six stages of closed feedwater heating. The final feedwater temperature is 425°F at 100 percent reactor flow.
10.4.7.1.2 Feedwater Quality Feedwater quality limits are established to prevent adverse effects to fuel, material integrity, and equipment performance. Corrosion product generation/transport and chemical intrusions are controlled and minimized so that a suitable environment is provided for high reliability of plant components.
During startup, condensate is recirculated to the main condenser hotwell until water quality specifications are met. The recirculation line is located downstream of the high-pressure feedwater heaters, and thus full-cycle recirculation is accomplished prior to introduction to the reactor. Guidelines for feedwater quality are listed in Tables 10.4-3 and 10.4-4.
Operating practices limit the conductivity of purified condensate during power operation to the reactor vessel to 0.07 µmho/cm. The control program for dissolved and suspended solids, including sampling frequency and chemical analysis, is described below.
Suspended and dissolved-solids samples are part of an integrated on-line sample collection, which consists of collecting both filterable and dissolved species in one filter housing that contains a membrane filter and ion exchange filter. The on-line filters are checked routinely for flow rate. Integrated on-line samples for feedwater are collected continuously during operation. There are three sample collection intervals weekly.
Filters collected are analyzed for certain metals necessary to conform to fuel warranty specifications. Metal species of interest are typically iron (Fe), copper (Cu), nickel (Ni),
Suspended-solids samples are acquired by grab sampling for qualitative analysis by filter color comparison during periods when corrosion product concentrations are expected to be higher than normal.
Control program limits are imposed within the limitations of fuel warranty specifications.
Total metals are limited during power operation to <15 ppb with no more than 2 ppb copper.
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FERMI 2 UFSAR The basis for these limits is to minimize deposit buildup on fuel heat transfer surfaces and the transport of corrosion products from the core surfaces. Consequently, high heat transfer is maintained, and out-of-core radiation levels are at a minimum.
Zinc is added to the feedwater to control radiation buildup in out-of-core primary coolant piping. The zinc will compete with the cobalt for deposition sites. This will have the end effect of reducing out-of-core radiation dose rates. The additional zinc will add to the dissolved metals and total metals in the feedwater. The amount of zinc to be added to the feedwater is much less than 1 ppb. The injection rate will be based on obtaining a target concentration of zinc in the reactor of between 3 and 10 ppb. The zinc will provide the beneficial outcome of controlling radiation build-up on out-of-core surfaces; however, overall metals concentration will still be maintained within the fuel warranty limits to ensure no impact on fuel performance.
Forward-pumped heater drains are untreated and account for approximately 30 percent of total feedwater flow. These drains are monitored for dissolved oxygen and conductivity prior to and during introduction to the feedwater. Turbidity is monitored on an as-needed basis by local grab during periods when corrosion product concentrations are expected to be higher than normal.
10.4.7.1.3 Design Codes All components of the condensate and feedwater system, except the main condenser and the feedwater piping from the second valve outside the containment to the reactor, are designed and constructed in accordance with the applicable requirements of the following codes:
- a.
ANSI Code for Pressure Piping, B31.1.0 - Power Piping
- b.
ASME B&PV Code Section VIII, Division I - Unfired Pressure Vessels.
10.4.7.2
System Description
The condensate and feedwater system consists of the piping, valves, pumps, heat exchangers, controls, instrumentation, and the associated equipment and subsystems that supply the NSSS with heated feedwater in a closed steam cycle using regenerative feedwater heating.
The system described in this section extends from the main condenser to the second valve outside the primary containment. The remainder of the system, extending to the reactor, is described in Subsection 5.5.9.
The main portion of the feedwater flow (approximately 70 percent) is condensate pumped from the main condenser. The remaining portion, which comes from the moisture-separator drains, steam reheater drains, and drains from the fifth-and sixth-stage feedwater heaters, is pumped forward from the fifth stage of feedwater heating into the feedwater stream. Turbine extraction steam provides six stages of closed feedwater heating, with the drains from the first four stages of feedwater heating being cascaded through successively lower pressure feedwater heaters to the main condenser.
The condenser pumps take the deaerated condensate from the main condenser hotwell and deliver it through the steam-jet air ejector condensers, the gland steam condenser, and offgas condenser to the condensate polishing demineralizers (see Figure 10.4-8). Demineralizer 10.4-20 REV 19 10/14
FERMI 2 UFSAR effluent then passes to the heater feed pumps, which discharge through the first-, second-,
third-, fourth-, and fifth-stage low-pressure feedwater heaters to the RFPs.
Additional drain flow comes to the RFPs from the fifth-stage drains, and then is pumped forward and injected into the feedwater stream at the RFP suction header. These drains originate as shown in Figure 10.4-9. The shell drains from the sixth-stage high-pressure feedwater heaters are directed to the shells of the fifth-stage low-pressure feedwater heaters.
The shell drainage from the fifth-stage feedwater heaters is collected in the heater drain flash tanks, and then is pumped into the feedwater system by the heater drain pumps.
The RFPs discharge the total feedwater flow through the sixth-stage high-pressure feedwater heaters to the NSSS, as shown in Figure 10.4-10.
10.4.7.2.1 Condenser Pumps Three condenser pumps operate in parallel (see Figure 10.4-8). Each is a motor-driven, vertical, multistage, centrifugal pump installed at an elevation that allows operation at low condensate level in the main condenser hotwell. The condenser pumps are sized to provide the necessary suction head at the heater feed pumps, even with one condenser pump out of service.
Isolation valves allow each condenser pump to be removed from service individually while maintaining full system capability with the remaining two condenser pumps; however, maintenance must be performed on the pumps during shutdown, with the condenser drained.
Condenser pump capacities are given in Table 10.4-5.
10.4.7.2.2 Heater Feed Pumps Three heater feed pumps operate in parallel (see Figures 10.4-8 and 10.4-9), taking suction from the polishing demineralizer outlet piping and discharging through the low-pressure feedwater heaters. Each is a motor-driven, horizontal, single-stage, centrifugal pump. The heater feed pumps are sized to provide the necessary suction head to the RFPs even with one heater feed pump out of service.
Isolation valves allow each heater feed pump to be removed from service individually while maintaining full system capability with the remaining heater feed pumps. Capacities are given in Table 10.4-6.
Controlled condensate recirculation to the main condenser hotwell is provided downstream of the condensate polishing demineralizer. This ensures that the minimum safe flow through the condenser pumps, steam-jet air ejectors, gland steam condenser, and offgas condenser, is maintained during operation. This recirculation path also provides cleanup during startup since flow is through the demineralizer. Separate minimum flow bypass lines are provided for the heater feed pumps. A Heater Feed Pump (HFP) running signal is taken from the auxiliary contact off of the switchgear breaker feeding each HFP. The use of auxiliary contacts prevents HWC System operation from impacting HFP operation.
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FERMI 2 UFSAR 10.4.7.2.3 Feedwater Heaters The first-and second-stage low-pressure feedwater heaters are identically arranged in three parallel streams. The third, fourth, fifth, and sixth stages of feedwater heating are arranged in two parallel streams. The first-and second-stage feedwater heaters are located in the necks of the three steam inlets of the main condenser.
Integral drain-cooling sections are included in the second-, third-, fourth-, and sixth-stage feedwater heaters. External drain coolers are provided for the first-stage heaters and are located on the first floor of the Turbine Building.
Each feedwater heater and drain cooler is of the horizontal, closed type, installed at an elevation that allows proper shell drainage at all loads. Each feedwater heater uses U-tube construction. All feedwater heater and drain cooler tubes are made of stainless steel.
Isolation valves and bypasses allow the feedwater heaters and the drain coolers to be removed from service in groups. System operability is maintained with the remaining feedwater heaters, drain coolers, and bypasses.
The startup and operating vents from the steam side of the feedwater heaters are piped directly to the main condenser. Discharges from shell relief valves on the steam side of the feedwater heaters are piped directly to the main condenser.
10.4.7.2.4 Heater Drain Flash Tank A heater drain flash tank receives deaerated drainage from the shells of the fifth-stage feedwater heaters. The drain tank provides reservoir capacity for the heater drain pumps suction. The heater drain flash tank is installed at an elevation beneath the fifth-stage feedwater heaters that allows the heaters to drain freely by gravity flow. Remote indicator light is provided to annunciate low tank level switch actuation. When necessary, the fifth-stage heater drains may be diverted to the main condenser instead of the drain tank.
10.4.7.2.5 Heater Drain Pumps Two one-half capacity heater drain pumps operate in parallel, each taking suction from the heater drain flash tank and discharging to the feedwater stream before the RFPs. A third one-half capacity pump is provided as a spare. Each is a motor-driven, vertical, multistage, centrifugal-type pump located below the heater drain flash tank and designed for the available suction conditions. Nominal sizes, capacities, and other information are given in Table 10.4-7.
The piping arrangement allows a heater drain pump to be removed from service individually while maintaining system operability.
Controlled drain recirculation is provided from the discharge side of each heater drain pump to the heater drain flash tank. This ensures that the minimum required flow through each heater drain pump is maintained during operation at low throughput.
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FERMI 2 UFSAR 10.4.7.2.6 Reactor Feed Pumps Two one-half capacity RFPs operating in parallel (see Figure 10.4-10), act in series with the condenser pumps and heater feed pumps and heater drain pumps. The RFPs take suction from the fifth-stage low-pressure feedwater heaters and discharge through the sixth-stage high-pressure feedwater heaters to provide the pressure head required at the NSSS. Each pump is a turbine-driven, horizontal, single-stage, centrifugal unit. Isolation valves allow either RFP to be removed from service individually while maintaining system operability with the remaining RFP. Data for these pumps are given in Table 10.4-8.
Controlled feedwater recirculation is provided from the discharge side of each RFP to the main condenser hotwell. This ensures that the minimum required flow through each RFP is maintained during operation at low throughput.
10.4.7.2.7 Reactor Feed Pump Turbine Drives Each of the two one-half capacity RFPs is driven by an individual steam turbine. The turbine drives are the dual-admission type, each equipped with two sets of main stop and control valves. One set of valves regulates the low-pressure steam flow extracted from the main turbine hot reheat piping. The other set regulates the high-pressure steam flow from the main steam supply. During normal operation, the turbine drives run on the low-pressure reheat steam. Main steam is used during plant-startup, low-load, or transient conditions when reheat steam either is not available or is of insufficient pressure. The turbine drives exhaust to the main condenser.
Isolation valves allow either turbine drive to be removed from service individually while maintaining system operability with the remaining turbine-driven RFP.
Total turbine output is 14,200 bhp at 4355 rpm with a low-pressure steam pressure of 225 psia and back-pressures of 1.5 in. Hg abs. Further data are given in Table 10.4-9.
10.4.7.3 Safety Evaluation During operation, radioactive steam and condensate are present in the feedwater heating portion of the system, which includes the extraction steam piping, feedwater heater shells, heater drain piping, and heater vent piping. Shielding and restricted access are provided as necessary (Section 12.1). The condensate and feedwater system is designed to minimize leakage with welded construction being predominantly used. Relief discharges and operating vents from heater shells are treated through closed systems and piped to the condenser.
System components are designed for pump shutoff pressures.
The condensate and feedwater system is not required to cause or support the safe shutdown of the NSSS or to perform in the operation of NSSS safety features.
If it is necessary to remove a component such as a feedwater heater, pump, or control valve from service, continued operation of the system is possible by use of the multistream arrangement and the provisions for isolating and bypassing equipment and sections of the system. The isolation capability of the system limits the magnitude of radioactive releases from failed components.
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FERMI 2 UFSAR An analysis is presented in Chapter 15 for a feedwater system piping break, which results in the massive leakage of contaminated feedwater directly to the turbine building.
10.4.7.4 Tests and Inspections During manufacture, shop performance tests on all pumps were carried out. Each feedwater heater, drain cooler, heater drain tank, and pump received a shop hydrostatic test performed in accordance with applicable codes. All tube joints of feedwater heaters and drain coolers were individually shop leak tested. Prior to initial operation, the complete condensate and feedwater system received a field hydrostatic test and inspection in accordance with ANSI N18.7.6 and applicable sections of Regulatory Guide 1.68. Periodic tests and inspections of the system will be performed in conjunction with scheduled maintenance outages.
10.4.7.5 Instrumentation Application Feedwater flow-control instrumentation measures the feedwater flow rate from the condensate and feedwater system. This measurement is used by the feedwater control system that regulates the feedwater flow to the NSSS to meet system demands. The feedwater control system is described in Sections 7.1 and 7.7.
Instrumentation and controls are provided for regulating pump recirculation flow rate for the condenser pumps, heater feed pumps, and RFPs.
Measurements of pump suction and discharge pressures are provided for all pumps in the system.
Sampling means are provided for monitoring the quality of the final feedwater, as described in Table 9.3-1.
In the feedwater heating portion of the system, temperature measurements are provided for each stage of heating. Steam pressure measurements are provided at each feedwater heater.
Instrumentation and controls are provided for regulating the heater drain flow rate in order to maintain the proper condensate level in each feedwater heater shell or heater drain tank.
High-level alarm and automatic emergency drain action on high level are also provided.
A feedwater flowrate signal is taken from the Feedwater Flow Loop and isolated to prevent HWC equipment from affecting the loop. The circuit is similar to the Integrated Plant Computer System (IPCS) input circuit, which is already used in this loop.
10.4.8 Standby Feedwater System 10.4.8.1 Design Basis The standby feedwater (SBFW) system provides condensate from the condensate storage tank to the feedwater system downstream of the No. 6 feedwater heater. It is a manually initiated system to provide additional assurance of the capability to maintain reactor core cooling and to prevent the uncovering of the core. No credit for the SBFW system has been assumed in the accident analyses in Chapters 6 or 15. The system may be initiated by the control room operator in response to an operational transient, e.g., loss of normal feedwater.
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FERMI 2 UFSAR This minimizes demands on other high-pressure core cooling systems. The system is not safety related and is nonseismic.
10.4.8.2
System Description
The SBFW system consists of piping, valves, pumps, motors, controls, instrumentation, and associated equipment that supply the feed-water system with condensate from the condensate storage tank. There are two SBFW pumps with a nominal capacity of 1300 gpm and 1247 psig. Each pump is driven by a 700-hp motor; the motors are independently fed from the SS64 and SS65 transformers. The pumps discharge to two parallel motor-operated (dc) modulating flow control valves. The larger valve (6 in.) is used when reactor pressure is near 1120 psi; the other (4-in.) valve is used when reactor pressure is low. There is a motor-operated (dc) isolation valve before tying into the feedwater system. This valve will automatically open when either pump is started and will close at RPV Level 8. The system diagram is shown in Figure 10.4-11.
10.4.8.3 Safety Evaluation The SBFW system is not required to support the safe shutdown of the reactor except for its use in the alternate shutdown system to meet 10 CFR 50, Appendix R, Section III.L. See Subsection 7.5.2.5. (Inadvertent initiation of the system is bounded by the inadvertent high-pressure-coolant-injection (HPCI) transient, discussed in Subsection 15.5.1, since HPCI flow is approximately five times SBFW flow.)
10.4.8.4 Tests and Inspections Normal manufacturer's tests were performed on the SBFW pumps and motors. Prior to initial operation, the system received a field hydrostatic test and inspection in accordance with ANSI N18.7.6.
10Property "ANSI code" (as page type) with input value "ANSI N18.7.6.</br></br>10" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process..4.8.5 Instrumentation Application Controls are located in the main control room. Measurement of pump discharge flow is provided in the main control room. Pump, motor bearing, and winding temperatures are displayed and alarmed in the main control room.
10.4.9 Zinc Injection System 10.4.9.1 Design Basis The zinc injection system is designed to allow Fermi 2 to continuously inject a dilute solution of zinc oxide into the reactor feedwater system. Zinc has been shown to reduce radiation fields coming from various primary coolant pipes (primarily in the drywell) by competing for the sites that 60Co would occupy. The system utilizes the differential pressure developed across the reactor feed pumps to provide motive force for the system and is completely manual. It is designed with a low flow bypass line in order to prevent thermal shock.
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FERMI 2 UFSAR The zinc injection system is nonsafety related, QA level Non-Q, seismic category none. The system and associated piping and valves meet ANSI B31.1 requirements. The piping and components connected to the reactor feed pump discharges are designed for 1750 psig and 450ºF. The piping and components connected to the reactor feed pump suctions are designed for 950 psig and 430ºF. The system is designed to inject sufficient zinc to obtain and maintain a target of 10 ppb zinc in the reactor. The amount of zinc injection in the feed water is to control the reactor water concentration at about 3 to 10 ppb. The dissolution column is designed to hold enough sintered zinc oxide pellets to last a fuel cycle.
10.4.9.2
System Description
The zinc injection system consists of piping, valves controls, instrumentation, and associated equipment that dissolves a dilute solution of zinc oxide into the reactor feedwater system.
The system is provided water from the discharge of one of the reactor feed pumps through connections on the pumps minimum flow lines. It enters the skid and passes through a flow straightening vane to ensure a fully developed flow. The flow is measured by a local flow element and then passes through the dissolution column. Dissolution column vessel temperature is measured locally by a thermometer attached to the dissolution vessel.
Temperature is measured so that the vessel is not opened for maintenance until it has cooled sufficiently. Flow passes through an outlet strainer which prevents large particles of sintered zinc oxide from entering the feedwater stream. The differential pressure across the column and strainer is measured by a local P indicator. The solution then exits the skid through a manual flow control valve and is returned to the suction of the reactor feedwater pumps. The system flow is manually controlled between zero and 100 gallons per minute. It is based on reactor water zinc concentrations. Zinc dissolution rate is controlled by flow through the vessel, by feedwater temperature, and by the amount of zinc pellets in the column.
To prevent thermal shock of mechanical components and the zinc oxide pellets, a low flow, heat up, bypass loop is provided around the main flow control valve. This bypass loop has a filter that will prevent small zinc oxide pellet fragments or other particles from lodging in the bypass flow control valve. The skid is provided with vents, drains, and test connections for maintenance purposes. Skid isolation valves are also provided. No pumps are installed in the system. All valves are manual and all instruments are local indication only. Therefore, the new system is passive and has no active components. The skid is bolted to the floor on the southeast corner of the TB-1 steam tunnel near column N-3. The system diagram is on drawing M-2012.
10.4.9.3 Safety Evaluation The zinc injection system is not required for safe shutdown or operation of the reactor. The zinc injection system is not required for plant operation. The addition of this new system does not change the operation or function of the condensate or feedwater systems.
10.4.9.4 Tests and Inspections The manufacturer performed testing to verify that the equipment operated prior to shipment.
They also perform a hydrostatic test of the skid equipment. Prior to initial operation, the system received a pressure test, instrumentation calibration check, and system flow testing.
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FERMI 2 UFSAR 10.4.9.5 Instrumentation Application All indications are local. There is local flow indication on the zinc skid for better control of zinc injection rate. Differential pressure indication for the dissolution vessel and outlet strainer is provided to indicate when strainer cleaning or dissolution vessel basket maintenance is required. The dissolution column vessel has local temperature indication provided such that the vessel is not opened for maintenance before the water has cooled to less than 212°F. All system control is local. There are no indications or controls in the control room.
10.4.10 Hydrogen Water Chemistry (HWC) System 10.4.10.1 Design Basis The purpose of the Hydrogen Water Chemistry (HWC) system is to inject hydrogen into the feedwater system at rates sufficient to allow the noble metal applied to stainless steel reactor vessel internals surfaces to control intergranular stress corrosion cracking (IGSCC) of the vessel internals. IGSCC control is accomplished by the addition of H2 gas to the final feedwater in an effort to reduce the dissolved O2 concentration due to the radiolytic decomposition of water in the reactor core. By reducing the O2 concentration in the reactor water, the corrosion potential of the water is reduced.
With a few exceptions, the HWC system has been designed in accordance with the BWR Owners Group Guidelines for Permanent BWR Hydrogen Water Chemistry Installation -
1987 Revision (Reference 4). The HWC system is designed to meet the following design bases:
- 1.
To supply hydrogen for feedwater injection at rates up to approx. 7-15 scfm, which corresponds to feedwater concentration of approx.. 0.14 - 0.31 ppm.
- 2.
To supply oxygen to the Off-Gas system at a rate equal to 50% of the hydrogen injection rate to ensure a stoichiometric mixture for recombination of hydrogen and oxygen.
- 3.
To supply oxygen into the Condensate system to keep the oxygen levels in the condensate and feedwater systems high enough to minimize general corrosion.
- 4.
To automatically isolate hydrogen and oxygen injection in the event of system or component failures.
The HWC System injects sufficient hydrogen into the feedwater system to allow the noble metal applied to stainless steel reactor internal surfaces via the On Line NobleChem (OLNC)
System to catalytically recombine oxygen and hydrogen peroxide in the reactor coolant.
OLNC is a technology developed by General Electric (GE) for applying noble metal to stainless steel reactor internals. This technology has successfully reduced the electrochemical corrosion potential (ECP) of internals below -230mVSHE (Standard Hydrogen Electrode). It has been shown that at this ECP and below, IGSCC is successfully mitigated in a BWR.
10.4-27 REV 19 10/14
FERMI 2 UFSAR In addition to the EPRI Guidelines (Reference 4), the HWC system was designed to meet the following codes and standards:
OSHA 29 CFR 1910.103 Hydrogen OSHA 29 CFR 1910.104 Oxygen OSHA 29 CFR 1990.119 Process Safety Management of Highly Hazardous Chemicals NFPA 50, 1990 Bulk Oxygen Systems at Consumer Sites NFPA 50A, 1994 Gaseous Hydrogen Systems at Consumer Sites NFPA 50B, 1994 Liquefied Hydrogen Systems at consumer Sites CGA G-4 Oxygen CGA-4.1, 1985 Cleaning Equipment for Oxygen Service CGA G-4.3 Commodity Specification for Oxygen CGA G-4.4, 1993 Industrial Practices for Gaseous Oxygen Transmission and Distribution Piping CGA G-5 Hydrogen CGA G-5.3 Commodity Specification for Hydrogen CGA G-5.4, 1992 Hydrogen Piping Systems at Consumer Locations The piping at the Gas Supply Facility is designed to ASME B31.3, Chemical Plant and Petroleum Refinery Piping. The underground yard piping and the piping inside the Turbine Building is designed to the requirements of ANSI/ASME B31.1, Power Piping.
All liquid and gas storage vessels are designed, fabricated and stamped as ASME Boiler and Pressure Vessel Code,Section VIII, Division I, Unfired Pressure Vessels.
System wiring, grounding and cathodic protection is designed in accordance with NFPA 70, the National Electric Code. In addition, lightning protection for the GSF has been designed per NFPA 780-92, Lightning Protection Code.
10.4.10.2 System Description The HWC system continuously injects hydrogen gas into the heater feed pump suction to reduce the dissolved oxygen concentration in the Reactor. Oxygen gas is continuously injected into the Off-Gas system at the common 18 manifold to recombine with hydrogen to maintain the stoichiometric balance for recombination. Oxygen gas is also added to the Condensate system at the condensate pump suction to make up for the reduced oxygen concentration in the condenser. The operating modes of the HWC system are startup, operation, and shutdown. For overall system piping configuration, see drawing 6M721-2013.
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FERMI 2 UFSAR Liquid hydrogen is stored in a cryogenic tank at the gas supply facility. The hydrogen is stored under its own vapor pressure until withdrawn by the compressor system. Two 100%
capacity parallel compressor trains are provided for system reliability. One compressor operates while the other acts as a backup. The operating compressor withdraws a combination of cold gas from the tank head space and liquid from the tank bottom and compresses it to a pressure several hundred psig above the required pressure. This allows the supply system to preferentially withdraw gaseous hydrogen from the tank head space, reducing system losses. After compression, the hydrogen is sent through ambient air vaporizers which evaporate it to within 20°F of ambient temperature. Each compressor train has two, 100% capacity vaporizers with automatic switching to allow de-icing. Gaseous hydrogen flows to a pressure control manifold which reduces the supply pressure to the operating pressure.
Hydrogen gas then flows via underground piping to the Turbine Building and through piping in the Turbine Building to the injection skid. The injection skid contains a flow element and three injection legs, each equipped with a flow control valve and isolation valve. Each injection leg from the skid is piped to the suction of one of the heater feed pumps. The isolation valve in each injection leg closes on a system shutdown signal, or individually, if the respective pump is tripped. There is a check valve at each heater feed pump suction connection to prevent backflow of water into the hydrogen piping. Each pump suction connection also contains a manual isolation valve and purge connection.
Liquid oxygen is stored in a cryogenic tank at the gas supply facility. The oxygen is stored under its own vapor pressure. Upon demand, oxygen is withdrawn from the tank and passed through an ambient air vaporizer. An economizer circuit preferentially withdraws oxygen vapor from the tank head space, reducing system losses. There are two 100% capacity vaporizers piped in parallel with automatic switching to allow de-icing. Gaseous oxygen flows to a pressure control manifold which reduces the supply pressure to the operating pressure.
Oxygen gas then flows via underground piping to the Turbine Building and through piping in the Turbine Building to the injection skid. The injection skid contains a flow element and two parallel flow control valves. The skid outlet is piped to the common 18 manifold in the Off-Gas system. There is a check valve in the oxygen piping, upstream of the Off-Gas connection, to prevent backflow from the Off-Gas into the oxygen piping. (For system configuration details, see drawing 6M721-2013.)
Oxygen gas is also injected into the Condensate pumps suction common header to make up for the reduced oxygen concentration in the condenser. Injection can be accomplished through the supply piping routed from the gas supply facility, or through an alternate bottled gas station.
Liquid nitrogen is stored at the gas supply facility for use in purging, instrumentation, and valve actuation as required in the design of the gas supply facility. Prior to use, the liquid nitrogen is converted to gas by an ambient vaporizer.
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FERMI 2 UFSAR 10.4.10.3 Safety Evaluation The HWC system is non-safety related, QA level non-Q, seismic category none. The electrical components are not Class 1E or environmentally qualified. The HWC system is not required to mitigate the consequences of any accident or malfunction, nor to achieve safe shutdown of the reactor or safe plant operation.
The HWC system has been designed and sited in accordance with the requirements of Reference 1. Where full compliance could not be achieved, technical justification was provided. The liquid hydrogen storage tank is located at a distance greater than 800 feet from the nearest safety related structure (RHR Complex). This separation distance assures that a worst case hypothetical detonation of the liquid hydrogen storage tank will not endanger safety-related structures and equipment. An explosion of the liquid hydrogen tank may cause damage to the roof and siding of the Reactor Building above the elevation of the Refuel Floor, and the roof and siding of the Turbine Building above the elevation of the Operating Deck. However, due to the large separation distance, the force on these structures would be less than those generated by design-basis tornadoes or earthquakes. Therefore, the effects of a hydrogen tank explosion on the upper floors of the Turbine and Reactor Buildings is bounded by the analysis for the design basis tornado.
All hydrogen and oxygen storage vessels have sufficient separation from safety-related intakes in the event of vessel failure without fire or explosion. The liquid hydrogen storage tank and piping over 0.4-inch diameter are seismically designed to prevent failure during a safe shutdown earthquake. The liquid hydrogen and oxygen tanks and the gaseous hydrogen tube banks are designed to remain in place during a design basis tornado, earthquake, or flood so that any releases would originate from that source location. The storage vessels are also designed to be adequately protected from lightning and transportation accidents.
Excess flow protection devices at the gas supply facility and Turbine Building entrance will provide rapid isolation in the event of a line break. Area hydrogen detectors are installed in the Turbine Building near HWC equipment to detect hydrogen leakage and initiate system isolation. Once hydrogen injection is isolated by the system trip signals identified in the section below (Instrumentation and Controls), oxygen injection isolation will lag the hydrogen injection isolation by a pre-set time to ensure the maximum recombination of hydrogen in the Off-Gas system.
10.4.10.4 Instrumentation and Controls The hydrogen injection rate is initiated with a low flow that is sufficient for establishing IGSCC mitigation during heatup. This rate is maintained until reactor power reaches approximately 25% at which point the injection rate increases proportionally with reactor power level. The oxygen flow is approximately half the hydrogen flow rate. The flow control valve in each injection leg is controlled from a single flow control signal. The flow element on the skid provides feedback to the flow control loop. Once activated, injection will be isolated under any of the following actions/conditions:
- a. Manual Shutdown
- b. Reactor Protection System Trip 10.4-30 REV 19 10/14
FERMI 2 UFSAR
- c. Hi-Hi Hydrogen (From Area H2 Monitor)
- d. High Hydrogen Flow
- e. Off-Gas/Recombiner Trip
- f. High Percent Oxygen in Off-Gas
- g. Low Percent Oxygen in Off-Gas
- h. High Hydrogen Supply Pressure
- i. Low Oxygen Supply Pressure
- j. Supply Facility Trip Local instruments are provided at the gas supply facility and at the HWC control panels in the Turbine Building. System shutdown and trouble annunciators are provided in the Control Room. In addition, hydrogen injection enable/trip control is provided in the Control Room.
All signals from safety related circuits are isolated to prevent the HWC system from adversely affecting the operation of safety related systems.
10.4.11 On-Line Noble Chemistry Injection System 10.4.11.1 Design Basis The On-Line Noble Chemistry (OLNC) Injection System is designed to allow Fermi 2 to inject a dilute solution of platinum or other noble metals into the reactor feedwater system.
The injection results in a fine layer of noble metal being deposited onto the wetted surfaces of the reactor and associated piping.
As documented in Reference 6, surfaces with noble metal compound in a low hydrogen coolant environment have been shown to reduce the potential of intergrannular stress corrosion cracking (IGSCC) and mitigate existing IGSCC in the reactor vessel by reducing the electrochemical corrosion potential (ECP). Based on laboratory data, when the ECP is below 230 mVSHE, (SHE = Standard Hydrogen Electrode) IGSCC crack initiation is mitigated and crack growth rates are lowered. Noble metal coating on the wet surfaces of the reactor coolant system piping has been shown to slow or mitigate IGSCC in the reactor vessel and attached reactor coolant system piping. The noble metal penetrates existing cracks to help slow or mitigate crack growth.
The OLNC application is performed after a sufficient time of power operation after a refueling outage to ensure oxide layer is developed on newly inserted fuel assemblies and within the vendor recommended range of power and core flow necessary to ensure adequate noble metal deposition. The online injection results in a more even distribution of metals throughout the system and deeper penetration in to the existing cracks and crevices.
References 5 and 6 evaluated the effects of injection noble metal into the reactor coolant system. The evaluation reviewed effects on the reactor fuel, reactor fuel performance, reactor coolant piping, the Reactor Recirculation System, and the Reactor Water Clean-up System.
10.4-31 REV 19 10/14
FERMI 2 UFSAR The OLNC injection system is non-safety related, QA level Non-Q, seismic category II/I.
The system and associated piping and valves meet ANSI B31.1 requirements. The piping and components connected to the reactor fed water system are designed for 1275 psig and 450°F. The system is designed to inject sufficient noble metal solution to reduce the ECP of reactor coolant surfaces below -230 mVSHE, as measured at the mitigation monitoring system in the Reactor Water Clean-up System, when the injected noble metals, the zinc injection system, and the Hydrogen Water Chemistry system work concurrently.
10.4.11.2 System Description The OLNC injection system consists of piping, valves, controls, instrumentation, and associated equipment that injects a dilute solution of noble metal into the reactor feedwater system. The system pumps solution from a temporarily staged OLNC injection skid on the north-east corner of the Reactor Building First Floor by the steam tunnel entrance. The injection skid is connected to the injection lines viaflexible hose connections. The flow and the injection pressure are indicated at the injection skid.
The injection skid is provided with vents, drains, and test connections for maintenance purposes. Skid isolation valves are also provided. All valves are manual and all instruments are local indication only. Therefore, the new system is passive and has no active components. When not in use, the injection skid will be stored on Reactor Building Third Floor. The system tie-ins to the feedwater system are indicated in Figure 10.4-10.
The Mitigation Monitoring System (MMS) is a one-pass-through system that provides a series of tubing samples to monitor and analyze the amount of noble metal remaining on the tubing interior surfaces, which is representative of the amount of noble metal remaining on the internal surfaces of the reactor vessel during and following an OLNC application. The MMS consists of a Durability Monitor Panel, a Data acquisition System Panel, and an Automatic Flow Control Module Panel. The MMS includes sensors that are installed to measure the ECP of the reactor water.
The MMS skid is provided with vents, drains, and test connections for maintenance purposes.
Skid isolation valves are also provided. All valves are manual and all instruments are local indication only. Therefore, the new system is passive and has no active components. The system tie-ins to the Reactor Water Cleanup System are shown in Figures 5.5-19 and 5.5-20.
10.4.11.3 Safety Evaluation The OLNC injection system is not required for safe shutdown or operation of the reactor.
The OLNC injection system is not required for plant operation. The addition of this new system does not change the operation or function of the Reactor Water Clean-up, condensate or feedwater systems.
10.4.11.4 Tests and Inspections The manufacturer performed testing to verify that the equipment operated prior to shipment, including a hydrostatic test of the skid equipment. Prior to initial operation, the system received a pressure test, instrumentation calibration check, and system flow testing.
10.4-32 REV 19 10/14
FERMI 2 UFSAR 10.4.11.5 Instrumentation Application All indications are local. There is local flow indication on the OLNC injection skid for control of noble metal injection rate. Local indicators are provided on the durability monitor panel for flow and water temperature. All system control is local. There are no indications or controls in the control room.
10.4-33 REV 19 10/14
FERMI 2 UFSAR 10.4 OTHER FEATURES OF THE STEAM AND POWER CONVERSION SYSTEM REFERENCES
- 1. Detroit Edison Letter to the NRC, EF2-57,134, Dated April 27, 1982.
- 2. The NRC Safety Evaluation Report, NUREG-0798, Supplement 1, dated September 1981, and Supplement 3 Dated January 1983.
- 3. DECo File No. T14-006, "RETRAN02 Analysis for a Moisture Separator Reheater Flow Distribution", Dated October 18, 2005.
- 4. EPRI NP-5283-SR-A, Guidelines for Permanent BWR Hydrogen Water Chemistry Installations, 1987 Revision.
- 5. BWRVIP-143, BWR Vessel and Internals Project, On-Line Noble Metal Chemical Application Generic Technical Safety Evaluation.
- 6. DECo File No. R1-8056, GEH OLNC 0000 0099 7942 02 RO, On-Line NobleChemTM (OLNC) Application Technical Safety Evaluation For Fermi Unit 2.
- 8. DTE CP 003, DECo File No. T14-006, Revised RETRAN02 Model for Moisture Separator Reheater for Uprate Conditions, Dated August 30, 2013.
10.4-34 REV 19 10/14
FERMI 2 UFSAR Page 1 of 3 REV 16 10/09 TABLE 10.4-1 EHC-CONTROLLED BYPASS FAILURE MODE AND EFFECTS ANALYSES SUBSYSTEM: AUXILIARY SYSTEMS No. Component Failure Mode Cause Effect Method of Detection Disable Bypass Fast Opening Initiate Fast Closure of Turbine Stop or Throttle Valves Comments
- 1.
120-V ac supply to EHC cabinet Loss of potential Fuse failure, short, bus trip No effect Alarms on failure No No Load pickup by backup supply feeder
- 2.
130-V dc battery supply Loss of potential Fuse failure, short Deenergizes both closure solenoids in bypass valve actuators Alarms, pump duty Yes No Solenoid power supply for turbine valves is obtained from the other plant 130-V dc battery
- 3.
Actuator cooling water Loss of flow Line fails, trip of TBCCW system Temperature increase in actuator Alarms on high temperature No No Temperature rise is slow, addition of heat due to pump that is not operating continuously
- 4.
Condenser Loss of vacuum Condenser failure, loss of circulating water, loss of steam-jet air ejectors Trips bypass and turbine valves closed via actuator solenoids Alarms on decreasing vacuum; alarms on equipment loss Yes Yes Separate vacuum switch logic with redundant devices is provided for each trip (bypass valve and turbine valve vacuum trips); the setpoint for each trip is different, allowing the turbine to be tripped before the bypass valves are finally tripped as the condenser vacuum is lost
- 5.
Equipment cabinet environment Loss of cooling Loss of fan power, filters
- plugged, ambient temperature high Possibly failure system, progressive failure most probable Alarms on high temperature Yes Yes System has been operated continuously in a test ambient of 40°C as part of acceptance test
- 6.
Actuator oil pumps Manual trip of all actuator oil pumps Operator error Trip of turbine and bypass valves after 2-minute time delay Alarms Yes Yes This trip is normally used to lock valve closed during maintenance on turbine SUBSYSTEM: UNITIZED ACTUATOR
- 1.
Valve control module Output zero Electronic failure Deenergizes solenoid valve Alarms on failure of module Yes on one bypass valve No None
- 2.
Valve control module Position error detector Electronic failure Fails to energize solenoid valve Alarms, test of valve Yes on one valve No None
- 3.
Bypass valve position transducer (LVDT)
Output zero Mechanical or electrical failure Deenergizes solenoid valve Alarms on failure Yes on one valve No Redundant LVDTs provide check circuit for alarm
FERMI 2 UFSAR Page 2 of 3 REV 16 10/09 TABLE 10.4-1 EHC-CONTROLLED BYPASS FAILURE MODE AND EFFECTS ANALYSES SUBSYSTEM: AUXILIARY SYSTEMS No. Component Failure Mode Cause Effect Method of Detection Disable Bypass Fast Opening Initiate Fast Closure of Turbine Stop or Throttle Valves Comments
- 4.
Control cabling from EHC (valve control module) cabinet to actuator Shorted or open Mechanical damage Renders valve inoperable Failure obvious Yes No Cabling to bypass valves not common due to physical location of actuator on each valve
- 5.
Pressure module No. 1, 2, and control module Output zero Electronic failure No effect on operation of valves Alarms on failure No No Two-out-of-three taken twice analog control logic, failed channel is disconnected from control
- 6.
Computing channel No. 1, 2, or 3 low value gates Output saturated Electronic failure No effect on operation of valves Alarms on failure No No Two-out-of-three taken twice analog control logic, outputs of each channel are compared with the remaining two to detect this type of failure
- 7.
Power supply (any module)
Output zero Electronic failure No effect on operation of module Alarms on failure No No Redundant supplies are provided for each module SUBSYSTEM: UNITIZED ACTUATOR
- 1.
Servo-cylinder Leakage Seal failure Fast opening of bypass valve not obtained Level alarm on loss of fluid Yes on one valve No effect Oil line failure not considered, control hardware mounted actuator manifold ports directly
- 2.
Servo-cylinder Blockage Foreign substance in oil Fast opening of bypass valve not obtained Test of valve Yes on one valve No effect Each actuator has integral oil supply
- 3.
Dump valve Leakage Foreign substance in valve Fast opening of bypass valve not obtained Test of valve Yes on one valve No effect None
- 4.
Servo-valve Drain port open
- Defect, failure of valve control module Possibly prevent fast opening of valve Test of valve Yes on one valve No effect Servovalve is spring biased to admit oil to the servocylinder if the control signal is lost
- 5.
Accumulator Loss of nitrogen Diaphragm leak, valve leak Reduces stored energy available Gage readings on each accumulator No No effect Capacity of one actuator is ample for one valve operation
- 6.
Fast-open valve Jammed
- Defect, leakage, foreign material in oil Fast opening oil supply not available at the servo-cylinder Test of hardware Yes No effect None
FERMI 2 UFSAR Page 3 of 3 REV 16 10/09 TABLE 10.4-1 EHC-CONTROLLED BYPASS FAILURE MODE AND EFFECTS ANALYSES SUBSYSTEM: AUXILIARY SYSTEMS No. Component Failure Mode Cause Effect Method of Detection Disable Bypass Fast Opening Initiate Fast Closure of Turbine Stop or Throttle Valves Comments
- 7.
Oil dump solenoid valve Opens to drain Loss of dc control voltage, coil
- open, condenser vacuum trip Dump valve operates draining oil from servo-cylinder Alarms on power supply, cycling of oil pump increases Yes No effect Control power for both bypass valve solenoids is independent of control power for turbine valves; condenser vacuum trip logic for bypass valves (1/2) x 2 logic; control power for bypass valve solenoidsis independent of control power for turbine valves
- 8.
Oil dump solenoid valve Fails to operate Loss of dc control voltage, coil open, valve stuck Fast open valve does not receive operating oil pressure Alarm on power supply loss, test of circuit Yes No effect None
FERMI 2 UFSAR Page 1 of 1 REV 16 10/09 TABLE 10.4-2 CIRCULATING WATER SYSTEM COMPONENTS Circulating water pumps Number Five Type Vertical, wet pit Capacity (each), gpm 180,000 Head, ft 92 Cooling tower Number Two Type Natural draft Design wet-bulb temperature, °F 74 Design range, °F 18*
Design approach, °F 18*
Relative humidity, percent 58 Dimensions, ft 450 x 400 approximately Design capacity, each 450,000 gpm
- NOTE: The design range and design approach may vary slightly due to the installation of wind vanes and replacement fill which improve performance under wind conditions.
FERMI 2 UFSAR Page 1 of 1 REV 16 10/09 TABLE 10.4-3 CONDENSATE QUALITY GUIDELINES, NORMAL OPERATION Influent to Effluent from Cond. Demin.
Feedwater to Cond. Demin.
Reactor
- 1. Specific conductivity at 25
°C, maximum Reactor Water 0.5 µmho/cmc 0.1 µmho/cmc 0.1 µmho/cm 1.0 µmho/cmb
- 2. pH at 25 °C 6.5 to 7.5 6.5 to 7.5 5.6 to 8.6b
- 3. Chloride (as CL-),
maximum 200 ppbb
- 4. Dissolved O2 30-50 ppb 200 ppb max.
20 ppb min.
- 5. Total metallic impurities 15 ppb (max.)a a
No more than 2 ppb copper.
b These are limits from Regulatory Guide 1.56, Table 1 c These are limits from Regulatory Guide 1.56, Table 2
FERMI 2 UFSAR Page 1 of 1 REV 16 10/09 TABLE 10.4-4 CONDENSATE QUALITY GUIDELINES, STARTUP Influent to Effluent from Cond. Demin.
Feedwater Cond. Demin. to Reactor Specific conductivity at 25 °C, maximum Reactor Water 0.5 µmho/cme 0.1µmho/cme 2 µmho/cma,d 10 µmho/cmb,d pH at 25 °C 5.6 to 8.6d 5.3 to 8.6b,d Chloride (as Cl-),
maximum 200 ppbd 100 ppb a,d 500 ppbb,d Dissolved O2 200 ppb max.
20 ppb min.
Total metallic impurity, maximum 100 ppb (max.)c a
Steaming rates less than 1 percent of rated steam flow.
b Reactor depressurized (<100 °C).
c No more than 2 ppb copper.
d These are limits from Regulatory Guide 1.56, Table 1.
e These are limits from Regulatory Guide 1.56, Table 2.
FERMI 2 UFSAR Page 1 of 1 REV 16 10/09 TABLE 10.4-5 CONDENSER PUMPS Number Three Type Vertical Three Pumps, Two Pumps, 100 Percent 100 Percent Reactor Flow Reactor Flow Capacity per pump, gpm 7130 10,695 Suction temperature, °F 91.7 91.7 Suction pressure, psia 5.37 5.37 Discharge pressure, psia 243 183
FERMI 2 UFSAR Page 1 of 1 REV 16 10/09 TABLE 10.4-6 HEATER FEED PUMPS Number Three Type Horizontal, single-stage, double volute Manufacturer Byron Jackson Horsepower 3000 Shaft speed, rpm 3574 Driver Westinghouse, horizontal, three-phase, 60-Hz electric motor Applicable code ASME B&PV Code Section III, Division I ASTM A193 and A194 (Nuts and Bolts)
ASME Pump Test Code ANSI B1.4 and B18.2 (Nuts and Bolts)
Location First floor, turbine building Three Pumps, Two Pumps, 100 Percent 100 Percent Reactor Flow Reactor Flow Capacity per pump, gpm 7083 10,624 Suction temperature, °F 94.2 94.2 Suction pressure, psia 151 151 Discharge pressure, psia 693 548
FERMI 2 UFSAR Page 1 of 1 REV 16 10/09 TABLE 10.4-7 Number HEATER DRAIN PUMPS Three Type Vertical, nine stage, centrifugal Manufacturer Ingersoll-Rand Horsepower 1750 Shaft speed, rpm 1780 Driver Westinghouse, 4000-V, 60-Hz, three-phase Applicable Code ASME B&PV Code Section VIII, Division I ASTM A193 and A194 (Nuts and Bolts)
ANSI B1.1 and B18.2.1 (Nuts and Bolts)
ASME Pump Test Code Location First floor, turbine building Two Pumps, 100 Percent Capacity per pump, gpm Reactor Flow 5000 Suction temperature, °F 391.6 Suction pressure, psia 225 Discharge pressure, psia 705
FERMI 2 UFSAR Page 1 of 1 REV 16 10/09 TABLE 10.4-8 Number REACTOR FEED PUMPS Two Type Horizontal, single-stage, centrifugal Two Pumps, 100 Percent Capacity per pump, gpm Reactor Flow 17,100 Suction temperature, °F 388 Suction pressure, psia 513 Discharge pressure, psia 1173
FERMI 2 UFSAR Page 1 of 1 REV 16 10/09 TABLE 10.4-9 REACTOR FEED PUMP TURBINES Number Two Type Horizontal, dual-admission, multistage Two Turbines, 100 Percent Reactor Flow Speed, rpm 4355 Total Output, bhp 14,200 Low-pressure steam pressure, psia 225 125 °F of superheat (h = 1274 Btu/lbm)
Low-pressure steam temperature, °F 517 High-pressure steam pressure, psia 947 Saturated (h = 1190.4 Btu/lbm)
High-pressure steam temperature, °F 538 Total Low-pressure steam consumption, lb/hr 140,000
A1865626 TSI5474 TSI5475 F10523/3072 PT L454 FISHER 67FR REG (RACK #H21P426 P049 N073A RV N3013A001 N30L214 PE/P N624 3-15 PSIG 10" 2508 3638 T.P AU 10" MAIN CONDENSER CONNECTION #80 N3013 F399 N3013 F397 M
M FAN N3013C023 N3013C024 FAN EXHAUSTER UNITS (1) LEAD (1) STAND-BY F396 N3013 F398 N3013 8"%%c 16"%%c 4"%%c R852 ZIV UI 061 14"%%c 6"%%c N3013F430 IAS 4"%%c NO70 ZXV N3013F605 12"%%c N3013F433 NO71 ZXV ZIV UI 062 R853 12"%%c 12"%%c 14"%%c N3013F603 8"%%c N3013F502 R.V.
N/A PE/P IAS IAS 16"%%c 12"%%c IAS THIS DRAWING SUPERSEDES E.E.L. TS-25184 (EDISON T1-543)
I-2334-16 I-2334-20 I-2332-09 I-2332-10 I-2332-11 I-2332-12 I-2332-13 I-2332-14 I-2342-05 M-2165 M-2004 I-2346-08 M-2985 M-2017-1 I-2314-03 M-2003 I-2314-03 I-2331-05 I-2453-02, 03 M-5717-6 I-2070-02 I-2330-14 I-2070-02 SEE LOGIC I-2070-05 SEE LOGIC I-2330-01 M-2985-1 N/A N623 PCE K999 N/A F5, REF. 10 F5, REF. 11
- 10. I-2336-02 INSTRUMENT FLOW DIAGRAM ICFD 162/1 ELECTRONIC
& HYDRAULIC GOVERNOR & DUMP STEAM SYSTEM.
- 11. M-2002 MAIN AND REHEAT STEAM SYSTEM (P&ID)
N/A N575 PXE SEE NOTE 14 6-30 PSIG SEE NOTE 14
- 14. AIR REGULATOR IS INTEGRAL PART OF E/P CONVERTER - SEE CECO FOR SETTINGS.
TP AV 13 1/4" D004 N3013 D006 N3013 D005 N3013 D007 N3013 N3000F120 DRAIN 6"
20 PSI TO VALVE 6"x4" 4"x2" TWO PLACES DRAIN TO D017 FLOOR DRAIN M-2271 (F-2)
N30L212B N30L330 N30L212C N30L212D N30L216 N30L217 N30L215 (I-2334-20)
N30L212A N30L213 N30L212E N30L252 N3013F501 N3000F343 N3000F347 N3000F439 PNL. H21P257 6"
V V
B-5 B-5 A-6,REF.4 V
H-7 V
H-5 V
V B-6, REF 6 D-6, REF 6 V
V SEE DWG M-2985-1 F-6 N3013B021 (F-6)
V D-6 V
E-4, REF 6 & B-4, REF 5 D-5, REF 6 & B-4, REF 5 C-3, REF 6 & B-5 REF 5 C-3, REF 6 & B-5 REF 5 Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT DETROIT EDISON COMPANY DRAWING NO.
6I721-2336-05, REV. V FIGURE 10.4-1 TURBINE GLAND SEALING SYSTEM REV 19 10/14
FERMI 2 UFSAR FIGURE 10.4-2 HAS BEEN INTENTIONALLY DELETED REV 16 10/09 I
PRESSURE STEAM SIGNAL CC1lVG PRESSURE STEAM SIGNAL CC2LVG r - -
PRESSURE MODULE No.1 -
-I--
-_-----------..'-----P-R-E-SS-U-R-E-S-T-EA-M-S-IG-N-A-L-C_C_3_LV_G_:-.
PRESSURE I SET POINT 3% BIAS 1 -
TRANSMITTERI.~
PRESSURE I
.-------, STEAM a
NO. 1 I
REGULATOR &
HIGH COMBINED SIGNAL I
I
)13 +
+
RESONANCE VALUE ~ flOW
- - +
I---........ I--~
FILTER No.1 GATE LIMIT I
j I
L _ _O~BIAS ______ I-- ______ 1-- __.... F- __ I---.-.J I~-~I-FROM OUTPUT OF LVG CC No.1 I-- PRESSURE MODULE No.2 -
PRESSURE I POINT BIAS TRANSMITTER I 3% BIAS No.2 REGULATOR &
I--..
HIGH I---~'~"+
+
I--~~I RESONANCE J...a..~~~ VALUE ~
I -
FILTER No.2 GATE COMBINED flOW LIMIT
+
L_~ __ _
-~ -
-I- -
I
_J FROM OUTPUT OF LVG CC No.2 r-------
PRESSURE CONTROL MODULE -
-~R-;;U-; -
3% BIASI I
I I
I I
I I
I I
AVERAGED CC1, CC2 & CC3 SPEED STEAM TRANSIENT SET POINT ADJUSTER HIGH VALUE ~
'---.-1 GATE TO REACTOR 10%....... -
1--_____.1--_......... RECIRCULATION COMBINED flOW LIMIT SIGNAL t
BIAS PUMP MASTER CONTROL STATION AVERAGE PRESSURE STEAM AVERAGE AMP STEAM SIGNAL FROM OUTPUT OF LVG CC No.3 E BYPASS VALVE TYPE 3 VALVE CONTROL MODULE W BYPASS VALVE
~ TYPE 3 VALVE
....... 1 CONTROL 6-----.-1 MODULE Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 10.4-3 SIMPLIFIED GOVERNOR/PRESSURE CONTROL BLOCK DIAGRAM
OIL SYSTEM PRESSURE PUMP
-- FEED LINE PRESSURE LINE
== RETURN LINE
-- SENSING LINE SYSTEM IN OPERATING CONDITION
/
PUMP
~
PRESSURE SWITCH UNLOAOING VALVE SECONDARY SPOOL
\\
'----)J-£.:....1. I------- MA I N SPO 0 L l~.I"!1,I*;
-I C'-'-
r---------'
t t
[
SERVO VALVE u~l':
~~,
......... ~-~
t t
SYSTEM PRESSURE GAUGE 1-IIIIIIII.II1II I
ORIFICE:J;.' l]~CHECK VALVE
~
FIL C:::~'1 -~"'UTTlE RELIEF PDPPET/
~ ~ :I i
~
O!L P~_E~~~RE RELIEF VALVE IU ACCUMULATOR-SYSTEM DEPRESSURIZE SOLENOID VALVE (DE-ENERGIZED) i r----ACCUMULATOR DUMP VALVE WITHIN MANIFOLD OIL DUMP SOLENOID VALVES (DE-ENERGIZED)
J 1
t I:>c:. \\
1-' __
~i1~.,r---"
] 0
)j SERVO IvLINOER i
FAST OP~N VALVE WITHIN MANIFOLO BLOCK Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 10.4-4 SERVO OIL SYSTEM BYPASS VALVE ACTUATOR
5(9
C:U~C. VATER SlJPPl, y GS\\i SUPPLY N-572'a(C-j)
- a.
N-2IJfl7<C-3) 2" PVC r034 SO --------,,--- __ Til CaNTRIlL i
PAr£L W~1f"~OI
'~"".J l~
'.. 0 CIRe. uATCR SCRE:CN CLC~ING PUMP N7liJ:a N711X1Ctlfl9 F173 e'
IlUTS;[DE "ALL r049 ra411 rtl'l rOll'A FQ37B F037C TO CU~C VATER H-572Oc:1I-::})
ItZ'"
- a.
~
N-a:i07<<:-~1 F'!l3 r21'SA e'
rZ'l~
1/2*
\\1-'1_006 I'LLSATlB-I DANP£NE:1i
'"21'5 f!Uilrl Jri2" 1012312
.2191 L ______ '=~::~_;;;I;_~~I;_~;;~~---- --~~---T---- ___ -.J Al.LPIPlrGPVC:
~
L!J
- NOTES,
~~
________________ ~.'~.~v~c~_L~CO~j*p~
I;!£L[£r /~AIN H\\':ADI:R TO CIAC. 'WATEIi! ~D VIA F1.0I:R DRAIN-T'vP (2)
} CLEAR PVC F0298 '-rl<l.... ~.:...:.:.::....:::::-'Ol.:.::'.~::.t~==+--.!..:::.:~::::.Jl 1/2' pVC ~
'-_----------------"2-' ::'"V:C;C,--1 __ l0 tONIoOI RELIEf /IQ4IN HEADEIif 2' PvC rco?C I) ALL [EH... lOGC..... T ION VAL V(S "'1ilE PREF I;tC D By \\11:332 IJNlESS D1H(R'ttIS( NOTED.
e) ALL [EHAl()j(NA1IDN lN$l~lI4ENrs; Alii( ~f[x(f1 By vi!!3 lH.EU Q'H(~ls£: IIIQTED pVC
'077 CU'i!c:. WATER
~lENDlD VAL\\tES T'I'P (2)
CIRCULA TING \\.lATER DEHALOGENATIDN SYSTD \\,12302 Til C[]NTRIlL PAt£L W27P.4QI nUl:lS roOJS CIRCULJIoTlI'CI WATER PUMP DI SCHARGE T'vP (5) e."C.s. LH£D Ea'C.S. LINED TO HA]N CONII:I1SER N-S7!Q(D-A)
OR H-2QQ7(D-4)
NOTES I. ALL SIDCID£ [NJ£CT(QN V£s.stLS SH[]\\JN IN srANDSy LINI:LF'.
- 2. CR1F(CE PLATE Y[TH 1I/J6' DIA. HOLE.
- l. SCLENOID VAI.:vES \\l[LL NIlT [SOL4TE [I'll Ii!EvERS£ DIR£CTlIlN.
.. IN.ESS OTHERWISE SH(]YN:
ALL [NSTRUM(111 PIS NUMBERS ARC PR(tlX( D 10'27 ALL VA1..vE AND EQJ]PMEI1T PIS NUHBERS ARE PREFIxED Y2700 l~P~ ~~~~~~
________________ J
'07'
\\.....Z 1/".
CU:AR flEx PVC: TUBlt<<:i 1
~
Fermi 2 2* PvC
~--~------------------~~--------------------~I----------------~
00Ii3 UPDATED FINAL SAFETY ANALYSIS REPORT NOTE 2 CIRCULATlNG \\,lATER FIGURE 10.4-6 BIOCIDE lNJECTION SYSTEM -
\\.12700 CIRCULATING WATER SYSTEM BIOCIDE INJECTIONI DEHALOGENATION SYSTEMS DETROIT EDISON COMPANY DRAWING NO, 6M721-6743, REV, V REV 16 10/09
5(9
5(9
POLISHING DEMINERAL PLT. IDENT.
N2002D006 10" 12" 10" 12" 10" 12" 10" 12" 10" 12" 10" 12" 10" 12" POLISHING DEMINERAL PLT. IDENT.
N2002D012 POLISHING DEMINERAL PLT. IDENT.
N2002D011 POLISHING DEMINERAL PLT. IDENT.
N2002D010 POLISHING DEMINERAL PLT. IDENT.
N2002D009 POLISHING DEMINERAL PLT. IDENT.
N2002D008 POLISHING DEMINERAL PLT. IDENT.
N2002D007 3128 1"
1" 1"
1" 18" 24" 30" TO HOTWELL SUPPLY PUMP DISCHARGE SEE M-2006 (D-3) 18" 24" 3123 REACTOR COLD FILL LINE 3102 4092 FROM T.W.M.S.
DWG. M-4100 (G-3)
CT L025 30" 3122 16" 3121 3126 8"
3122 I&C REF.3 PDX N011 PTH L021 PDIC K004 PDIC K840 3129 24" 20" ZXV N482 ZYE K407 ZIV R604 ZSV N500 026 012 PDCV F400 20" 1 "
16" 20" 1 "
1/2 1/2 F.O.
OPEN 3129 LOCATE IN PANEL H21P250 LOCATE ON CTL PANEL 3127 4102 RETURN TO T.W.M.S.
DWG. M-4100 (G-3) 8" I&C LOOP N20-3 FOR INSTRUMENTATION SEE M-2011 & 2011-1 REF. 10 & 7 TEW N406 CT L465 K
FXE N433 FSE N407 FTH L416 FTL L415 FTH L418 FTL L417 K
018 LO FY K802 I&C LOOP N20-4 OFF-GAS CONDENSER PLT. IDENT.
N6200B004 MO MO PDS N20 N553 B
(D)
(V) 12" 12" F610 1"
3/4 "
F609 MO MO (D)
(V) 12" 12" 1"
3/4 "
(V)
(D)
OFF-GAS CONDENSER PLT. IDENT.
N6200B003 PDS N20 N553 A
F612 F611 3237 3238 3238 FOR INSTRUMENTATION SEE M-2017-1 (V)
(D)
INTER CONDSR PLT. IDENT.
N6101D004 3112 HYDROGEN PEROXIDE INJECTION PUMP PIS #P9000C001 MO 1/8 "
1/4" 2"
4245 4"
(D)
LCV F401 COND NORMAL RELIEF 2"
F.C.
F.C.
3" (D)
ZXV N428 ZIV R806 L.P. TURBINE NORTH HEATER NO.2 NORTH PLT IDENT NO. N2003B006 K
K (V)
(V)
K LIE N61 R809 WWR LP/E N61 K404 K
K (V)
(V)
K CONDENSER PUMP TRIP (V)
K (V)
(V)
K 12" VACUUM BRKR TEW N30 N556 A
MO MO (D) 18" 3120 TEW N452 A
CT L469 A
TEW N453 A
REF 10 & 7 TEW N61 N465 A
MTT L472 A
TEW N30 N556 C
3108 18" MO HEATER NO.2 CENTER PLT IDENT NO. N2003B007 CRPB (D) 3119 TEW N452 B
MTT L472 B
(V) 18" L.P. TURBINE CENTER (V)
(D)
(6) DUMP STEAM INLETS 3707 6"
LXP N61 N427 LXP N61 N409 A
TEW N61 N465 B
(D)
HEATER NO.1 CENTER PLT IDENT NO. N2003B004 HEATER NO.1 NORTH PLT IDENT NO. N2003B003 CT L469 B
TEW N453 B
REF 10 & 7 L.P. TURBINE SOUTH TEW N30 N556 E
LCV F402 COND EMER RELIEF (D) 3/4" ZIV R805 ZXV N427 (D) 3/4 "
8" 8"
3/4" F620 3126 8" TO CONDENSATE STORAGE I&C LOOP N20-1 FTT L503 FTT L503 3111 ANNUBAR 3/4" 6"
10" 3111 3/4 "
6" 3112 3111 ANNUBAR 3/4" 6"
3/4 "
6" FE N412 FT L410 6"
10" 10" 3111 ANNUBAR 3/4" 6"
3/4 "
6" 3112 3111 ANNUBAR 3/4" 6"
3/4 "
6" 12" 14" 20" 3112 (V) 3238 12" 12" (D) 3102 12" FE N413 FT L411 INTER CONDSR PLT. IDENT.
N6101D002 INTER CONDSR PLT. IDENT.
N6101D003 INTER CONDSR PLT. IDENT.
N6101D001 FE N414 FT L412 4 - STEAM JET AIR EJEC.
1/4 SEE DWG M-2017-1 GLAND STM COND PLT IDENT. N3013B021 (D) 14" 30" 3102 PT L439 PXE N442 K
MO TEW N473 1 "
1/4 K
(V) 3102 F608 PTT N20 L498 14" 3101 20" LSE N61 N405 A
LSE N61 N406 A
3100 24" 30" NORTH SOUTH 3100 30" LSE N61 N405 B
LSE N61 N406 B
24" MO N6101F602 12" VAC.
BRKR.
CT L469 C
TEW N453 C
MO 10" 18" REF. 10 & 7 (D) 16" F286 18" 3118 TEW N452 C
MTT L472 C
(D)
(D)
(V) 3108 30" 18" 10" 8"
6" 4"
LXP N61 N410 B
LXP N61 N409 B
REF. 10 & 7 3121 CT L474 B
20" 36" 30" F602 3100 FSE N002 031 30" REF. 10 & 7 2"
2" 3101 MO F605 PT L402 B
PXE N403 B
CT L463 B
PXP N458 B
PP/E K408 B
PIE PT L401 B
MO 30" 3100 30" REF 10 & 7 3101 MO 1 1/2" PIE K
K PT L401 A
PXP N458 A
PP/E K408 A
PXE N403 A
PT L402 A
CT L463 A
HI 3"
030 FSE N001 F601 6"
CONDENSER PUMP NORTH 1/3 SIZE PLT. IDENT. NO.
N2001C020 FE N411 FT L409 14" 6"
1" 1"
1" PTL L022 CT L466 REF. 10 & 7 30" V
6" LP/E N61 K403 A
K LSE N61 N804 A
LSE N61 N803 A
002 HI LO 3707 1/2" 14" 3/4" 18" GLAND SEAL WATER 3101 30" 12"}
2400 GPM PT L490 ANNUBAR FE N410 FT L408 3101 3111 4"
20" 1"
HI 1/2" 3707 2940 MO 1"
2 18" K
K 30" 3100 30" REF. 10 & 7 3101 MO 1"
HI 1/2" 3707 MO 1"
2 18" K
032 PT L401 C
PXP N458 C
PP/E K408 C
CT L463 C
PT L402 C
PXE N403 C
FSE N003 F603 14" F606 18" 3101 2" CAPPED CONN 30" 3100 36" 3"
14" (V)
I & C LOOP N20-2 1 1/4" F613 20" ZIV R825 (D)
(D)
(D)
ZXV N468 ZXV N425 FCV F403 (D)
FE/P K400 TEW N472 F607 3102 PTT N20 L497 F614 ZIV R814 14" COND COOLING LINE PT L407 PXE N408 K
3480 GPM 3102 14" REF. 10 & 7 20" CT L464 O2 pH (D)
CONDENSATE BYPASS LINE 3101 14" (V)
(V) 3102 F636 (D)
(D)
COND.
EMER.
MAKE-UP LCV F406 ZXV N430 Z1V R808 ZSV N432 MO (D)
(D)
Z1V FC FC ZXV N429 R807 ZSV N431 3"
LCV F407 4"
- 1. ALL FLOWS AND VELOCITIES SHOWN WITH THE EXCEPTION OF PUMP BY PASSES ARE AT 105% WARRANTED REACTOR LOAD.
2.
DELETED 3.
DESIGNATES ISOMETRIC PIPING DRAWING NO. PREFIX TO ALL ISOMETRIC DRAWING NO.S IS 6M721-
- 4. ALL PIPING AND EQUIPMENT IS QA LEVEL II, SIESMIC II.
- 5. VENT & DRAIN VALVE NO.S TYPICAL FOR EACH DRAIN COOLER UNIT.
- 6. FOR SYSTEM FUNCTIONAL OPERATING SKETCH SEE DWG. M-5714-1 NOTES
- 1. SEAL WATER CLG SYSTEM 2.
COND. STORAGE DIAG.
POL. DEM. SYS DIAG.
3.
4.
FEEDWATER DIAG.
5.
IR DWG MAIN STM. & REHEAT STM. DIAG.
6.
- 7. DIAG. OF TURB. BLDG. SAMPLES 8.
- 9. CW SYS. DIAG.
10.
PLANT SAMPLING 11.
GEN. SER. SYS DIAG.
M-2002 DLB654-34 M-2006 M-2011 & 2011-1 M-2023 I-2400-03 M-2007 I-2400-01 M-2010
REFERENCES:
SYSTEM N20 LP/E N61 K402 B
LP/E N61 K403 B
LSE LSE N61 N804 B
K K
N61 R805 FT L413 PDIS N488 PDXE N404 PDCE K801 R801 PDI HI LO 003 HI LO 001 TEW N409 2" GLAND SEAL 2" GLAND SEAL 2"
EEL ICFD 168 (V)
EEL ICFD 168 (V)
EEL ICFD 168 24" 3100 36" 3120 3119 1"
1/2" R800A 3"
3/4" 18" 18" 4"
3208 (D)
(D)
(V)
(V) 8" 4"
3209 3208 1 1/2" 3121 (V)
(V)
(D) 16" 3121 (D)
F.C.
(D) 10" MIN FLOW RECIRC FCV F404 MO (D)
ZXV N426 Z1V R804 18" 6"
6" 1 1/2" R800B 3/4" PIE R800C LIE MO 10" Z1V R822 ZXV N465 F618 16" 20" 1 1/2" 2940 1"
1" 1"
1" 1"
1" 1"
3102 30" FE 6"
20" MO MO F.O.
MO HEATER NO.1 SOUTH PLT IDENT NO. N2003B005 M-2004-1 (A-3)
N4 242 RET 501X1(T2-57) 3200 GPM M-2004-1 (D8) 18" M-2004-1 (F8) 18" M-2004-1 (F8) 3118 M-2004-1 (E4)
M-2004-1 (C8)
%+
%+
SEE REF 7 & 10 FOR SAMPLING & CONTROL PEROXIDE FEED.
COND.
NORMAL MAKE-UP SEE DWG M-2006 (D-8) 4" HEATER NO.2 SOUTH PLT IDENT NO. N2003B008 M-2004-1 (G8)
I-2336-06 (B-7)
N61-N466 CONDENSER PUMP SOUTH 1/3 SIZE PLT. IDENT. NO.
N2001C018 CONDENSER PUMP CENTER 1/3 SIZE PLT. IDENT. NO.
N2001C019 F604 I-2336-06 (B-8)
I-2336-06 (B-6)
THIS DRAWING SHOULD BE USED WITH M-2004-1 WHICH WAS INITIATED AS A RESULT OF REDRAW AT REV AB.
M-2006 (D-4) 21,200 GPM/ =12.40fpm N2002 D013 CONN.
6" CHEM.
CLEAN 3/4" 16" RO LIE N61 R807 A
LT N61 L055 LT N61 L022 LT N61 L023 LT N61 L026 LT N61 L027 LT N61 L057 N61 N803 B
1" 3/4" RV 3/4" RV 1"
3/4" RV 1"
M-2005-1 (B2)
M-2005-1 (B4) 1" 1"
M-2005-1 (C4)
FLOOR DRAIN 1"
3540 3540 1"
EQUIP DRAIN EXP. JOINT P.I.S.#
N2001D020 I-2400-03 (B-3) 1 1/2" CLTN. TANK P3301A001 EXP. JOINT P.I.S.#
N2001D019 N2001D018 P.I.S.#
EXP. JOINT 4" TO L.P. EXHAUST SYSTEM SEE DWG. I-2336-06 (E-5)
BY E. E.
TI-908 1"
M-2005-1 (B6) 1" 1"
M-2005-1 (C2)
B L521 CT B
N401 TEW K
K809B TY R803B TIE HI 003 D-7 K803 24" K
L473 CT REF. 10 & 7 B
L520 B
CT N400 B
TEW 24" 002 HI K
CT REF. 10 & 7 A
L473 A
L520 CT A
N400 TEW K809A TY R803A TIE 24" 24" TEW A
N401 CT A
L521 A
REF. 10 & 7 CT L474 K
CONDENSER HOTWELL W/B NE STRAINER TYPICAL SEE T2-57 NW SE SW 3132 1"
1" N2002D015 PLT. IDENT.
DEMINERAL POLISHING 12" 10" 16" 14" 3329 4"
F110 F117 F173B F175B ZONE E-4, THIS DWG TO FCP-K050 IAS K051 FY ANNUBAR L052 FT N070 FE N071 FXP L051 FTL IAS L050 FTH ZONE D-1, THIS DWG FROM FY-K051 R815 FRE K050 IAS FCP (TYP.)
L056 N61 LT LT N61 L058 SEALED SENSORS (TYP.)
LIS N61 N406 D
N405 D
LIS N61 6WT-N61-7636-1 ABANDONED IN PLACE 6WT-N61-7636-1 6WT-N61-7636-1 IN PLACE ABANDONED 6WT-N61-7637-1 N406 C
LIS N61 SENSOR SEALED LIS N61 N405 C
6WT-N61-7637-1 6WT-N61-7637-1 P9000 1/4" TANK TANK OXYGEN GAS PCV P90 F403 OXYGEN LIQUID PCV F013 F405 P90 6WM-N20-5852-1 F404 P90 PCV 1/4" P9000 1/4" F015 6WM-N20-5852-1 CHEMISTRY HYDROGEN WATER R402 P90 F014 P9000 M-2013 (A-6) 3/8" ATMOS.
RV FIC 1/4" F439 FROM SAMPLE DRAIN THIS DWG. (G-3)
F265 THIS DWG. (E-6) 2" 1/4" 6WM-N20-5852-1 3/8" F284C F174C F175C F285C F629 (V)
F283C F173C F282C F171C F628 F285B F284B F174B (V)
(V)
F283B F282B F171B N6101F601 F627 F175A F284A F174A F173A F282A F171A F283A F285A (V)
(V)
F617 UNLESS OTHEDWISE SHOWN:
7.
ALL INSTRUMENT PIS NUMBERS ARE PREFIXED N20 ALL VALVE & EQUIPMENT PIS NUMBERS ARE PREFIXED N2000 M-2006 (C-6)
EMERG HOTWELL SUPPLY LINE M-2006 (C-6)
HOTWELL SUPPLY LINE (SPARE)
(SPARE)
N6100F612 N6100F615 N61 L411 PT N61 L412 PT TYP (12)
PLACES K800 LCP N61 N6100F178 K406 N61 LCP DUAL LOOP-#
F211 F210 F199 F200 F201 F202 F203 F209 F207 F208 F205 F204 F206 N6101 F601 FO34H FO33H N444 MOTOR CONT. LOGIC DIAGRAM I-2070-08 HTR 1S LXPS HTR 2S LXPS HTR 1C LXPS HTR 2C LXPS HTR 1N LXPS HTR 2N LXPS M-2005-1 (C-6)
M-2004-1 (B8) 12" 16" 3106 10" SEE DWG. M-2023 (E-3)
F051 F052 F047 F048 F016A F015A F015B F016B F015C F016C F015D F016D F015E F016E F015F F016F F015G F016G F015H F016H F033G F034G F033F F034F F033E F034E F033D F034D F033C F034C F033B F034B F033A F034A F054 F278 F002 P9000 F215 F214 F213 F212 F218 F219 F220 F221 F222 F223 F217 F216 F130 F131 F132 F134 F135 F136 F133 F313C F311 F371 F369 F313B F313A F372 F370 F092C F300C F093C F097C F092B F092A F300B F093B F097B F097A F300A F093A F098A F098B F266 F098C F267 F273 F119 F120 F114 F116 F252 F253 F122 F121 F123 F124 F107 F102D F111 F113 F115 F101D F102C F101C F102B F101B F102A F101A F103B F103A F103C F103D F106D F105D F106C F105C F106B F105B F106A F105A F225 F227B F227A F228A F230A F228B F230B F229A F229B F231A F232A F233A F234A F232B F233B F234B F231B F277 RV RV 3112 Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT DETROIT EDISON COMPANY DRAWING NO.
FIGURE 10.4-8, SHEET 1 CONDENSATE SYSTEMS 6M721-2004, REV. BB REV 19 10/14
10" LOOP N21-1B LOOP N21-1A N2102C001 TO RFP NORTH H11P919 POINT #84 STARTREC PANEL A
A L403 N21 FTL A
N401 N21 FXE A
L404 N21 FTH G-3 I-2126-01 (C-6)
N2102D010 STRAINER H-3 02 M-2023 (G-8)
A N400 N21 FE A
L401 N21 FTL A
L402 N21 FTH A
N436 N21 FSE A
L429 N21 PTL A
N440 N21 PDIS A
L430 N21 PTH A
N439 N21 PXE A
L405 N21 PT A
L406 N21 PT A
N402 N21 PXE A
N406 N21 PSE A
N405 N21 PSE A
N404 N21 PSE A
N403 N21 PSE PRESSURE TRIP R.F.P.T. NORTH LOW PRESSURE TRIP R.F.P.T. SOUTH LOW HI 24" H-2 N2102D011 STRAINER K
H11P919 POINT #85 STARTREC PANEL R817 FIE B
N21 N2102C002 TO RFP SOUTH M-2023 (E-8)
G-2 B
L403 N21 FTL B
N401 N21 FXE B
L404 N21 FTH B
N400 N21 FE B
L401 N21 FTL B
L402 N21 FTH I-2126-01 (C-5)
B N436 N21 FSE B
L429 N21 PTL B
N440 N21 PDIS B
L430 N21 PTH 03 B
N439 N21 PXE B
L405 N21 PT B
L406 N21 PT B
N402 N21 PXE B
N406 N21 PSE B
N405 N21 PSE B
N404 N21 PSE B
N403 N21 PSE K
HI 24" K
R817 FIE N21 K
D-3 DWG M-2023 FEEDWATER SYSTEM TO D-4 (D)
(V) 1 "
1/4 1/4 (V) 1 "
1" 3/4" 4"
3132 (D) 2" 1"
1" 1"
M-2003 (E-5)
EXT. DRN FROM NORTH RFPT M-2003 (F-5)
EXT. DRN FROM SOUTH RFPT 6WM-N30-5390-1 M-2023 (F-8) 3108 (V)
(V)
E-4 2"
(D)
(V) 1/2 1 "
(D) 1/2 1 "
F.O.
1 "
1 "
1/4 R.F.P.T.
(V)
TYP 8 PLCS INST. TAP (V)
(D) 4" (V)
(D)
(D)
(V)
(V)
(V)
(D)
(D)
R811 M-2005 (B-4)
DISCHARGE LINES HEATER DRAIN PUMPS M-2005-1 (D-6)
M-2004 (F-8)
M-2004 (H-4)
M-2004 (F-7)
M-2004 (G-4)
M-2004 (H-4) 1" 1"
3106 B
N426 N21 TEW I&C REF 8 INCORPORATED CHANGES PER ABN-3503-1,REV 0 THIS DWG SHOULD BE USED WITH M-2004 THIS DWG WAS INITIATED BY IGDS AT REV "0" AS A RESULT OF REDRAWING M-2004 AT REV "AB" N426 N61 PSE N61L410 I-2336-06 (B-8)
(F-2)
DWG. M-4100 FROM T.W.M.S 4092 6"
8" DETAIL ZONE B,C-1 PUMP DRAINS SEE FOR HEATER FEED TYP HTR FEED PUMP CASING DRAINS N2003C014 N2003C013 N2003C012 1 1/2" 18" DRAINS EQUIPMENT 3/4" 18" 1/2" 14" 1/2" 3/4" 18" 10" M-2004 (H-4)
I-2310-04 SEE DWG M-2004 FOR ADDITIONAL NOTES AND REFERENCES 3856 A
N426 N21 TEW 3108 A
N427 N21 TEW N420 PXE (V) 4" 18" (V) 3108 A
L424 FTL A
K405 FCP 6"
A F405 FCV (V)
= 10.12 FPS 7070 GPM B
L422 FTL PIE
= 10.12 FPS 7070 GPM PIE
= 10.12 FPS 7070 GPM
= 10.12 FPS 7070 GPM 1/2 M-2004 (D-1)
(V) 4" 3113 24" L478 PT N474 PSE REF. 8 INJECT. PUMP LOGIC SEAL PUMP MOTOR N422 PDSE 3127 30" L440 PT N443 PXE K
30" 1"
4" 4"
SEAL WATER 16" (D)
K N477 ZSV G
N477 ZSV D
N477 ZSV A
N477 ZSV CLOSED OPEN 3104 A
L425 FTH A
N417 FXP A
F408 EV (V) 14" 3127 MO 24" MO RO 30" (D) 4" SEAL WATER 30" A
N480 PSE A
N481 PSE A
N479 PSE A
N478 PSE A
L484 PT R809A A
L420 PT A
N419 PXE A
N418 PXE A
L421 PT IDENT NO. N2003C012 EAST SIZE PLT HEATER FEED PUMP A
L423 FTH A
L422 FTL A
N416 FE 12" C
F408 E/V B
F408 E/V B
L424 FTL B
L425 FTH B
N417 FXP B
K405 FCP CLOSED OPEN/
L N477 ZSV H
N477 ZSV E
N477 ZSV B
N477 ZSV 8"
B F405 FCV PLACES TYP (3) 6" 6"
3127 18" IDENT NO. N2003C013 CENTER SIZE PLT HEATER FEED PUMP B
N481 PSE B
N480 PSE B
N479 PSE B
N478 PSE B
L484 PT B
L420 PT B
N419 PXE R809B B
N418 PXE B
L421 PT B
L423 FTH B
N416 FE CLOSED OPEN/
(V)
DE 2
3 1
E SO 10" 3106 L.O.
1/3 P1E K
I&C REF 8 (D)
FO 18" 3127 (D) 10" 14" (V) 18" 3104 (V)
3 1
E SO 10" 3106 3104 L.O.
1/3 K
K I&C REF 8 (D)
FO 18" 3127 (D) 10" 14" (V) 18" 3104 M
N477 ZSV J
N477 ZSV F
N477 ZSV C
N477 ZSV (V)
C L425 FTH C
K405 FCP C
N417 FXP C
3 1
E SO C
F405 FCV C
N416 FE C
L422 FTL C
L423 FTH 10" 3106 3104 L.O.
IDENT NO. N2003C014 WEST SIZE PLT HEATER FEED PUMP 1/3 R809C K
K C
L420 PT C
N419 PXE C
N418 PXE C
L421 PT C
L484 PT C
N481 PSE C
N480 PSE C
N478 PSE C
FO 18" 1 1/2" 3127 (D) 10" 14" (V) 18" 30" 3104 (D)
I&C R OF 7&10 K
L467 CT L441 PT N461 PXE L470 CT N421 TEW 18" 20" L426 PT N466 R823 ZXV ZIV 30" 1 1/2" 3104 1 1/2" 3132 F.C.
4" 20" L414 PT 2202 3107 DRAIN TO EQUIP 2"
L443 PTT K
N471 TEW L437 N21 CT 16" 16" 24" 3191 3132 R820 N21 K420 N21 LIE LP/E N447 N21 LSL N446 N21 LSH 060 LO HI 4"
K805 FY R812 FIE N476 FXE 16" L483 FTH L481 FTH N475 FE L482 FTL L480 FTL R821 N467 ZIV ZXV MO 3108 30" 3108 4"
LO 39 K
K825 TRE TY N457 TEW R810 PIE N464 PXE L444 PT DRNS.
4" 36" =12.58fps 24" 24" 36" 1/2 1/2 2 "
2 "
4" 10" PLT IDENT NO.N2003B010 HEATER NO.3 SOUTH PLT IDENT NO.N2003B012 HEATER NO.4 SOUTH PLT IDENT NO.N2003B014 HEATER NO.5 SOUTH B
N462 PXE B
L442 PT B
L476 MTT B
N455 TEW B
N454 TEW B
L475 MTT F302B F633 B
N456 TEW B
L471 (V) 3107 20" 3107 30" F194B 1 1/2" 20" (V)
(D) 1 1/2" 3105 MO (V)
(D)
(V)
(V)
K (D) 3105 K
MO (V)
(V)
K K
(D) 3105 3107 30"
=13.80 FPS 12,000 GPM (D) 1 1/2" A
L471 (V)
(D) 1 1/2" 3105 MO PLT IDENT NO.N2003B009 HEATER NO.3 NORTH (V)
(D)
A L475 A
N454 TEW PLT IDENT NO.N2003B011 HEATER NO.4 NORTH (V)
(V)
K (D) 3105 K
A N456 TEW MO F302A (V)
(V)
A L476 K
A N462 PXE A
L442 PT K
(D) 3105 A
N455 TEW PLT IDENT NO.N2003B013 HEATER NO.5 NORTH L463 N21 TWT R.F.P.T.
A N400 N21 FE N2102D010 P.I. NO.
STRAINER N2102C001 PLT IDENT NO.
R.F.P. NORTH 2"
A F001 N21 TCV A
F002 N21 TCV A
K405 N21 TE/P 1/2 1 "
1" 1"
3/4 "
24" (V) 2" (V)
(D)
MO 1 1/2" (D)
REF 2 (V)
DWG M-2023 FEEDWATER SYSTEM TO 1/2 1 "
F.O.
F.O.
3132 L455 N21 TWT A
K404 N21 TE/P 14" 10" 1"
1" 3/4" 24" B
N400 N21 FE (V) 2" B
N427 N21 TEW L464 N21 TWT (V) 3108 (D) 2" N2102D011 P.I. NO.
STRAINER MO 10" 1/2 1/2 2 "
2 "
HI 2"
1 1/2" (D)
REF 2 (V)
N2102C002 PLT IDENT NO.
R.F.P. SOUTH 1/2 A
L432 N21 PTH A
L424 N21 FTH A
L423 N21 FTL A
N425 N21 FXE A
N424 N21 FE A
L431 N21 PTL A
N441 N21 PDSE HI 058 K
2" K
A L441 N21 PT A
N452 N21 PXE B
L441 N21 PT B
N452 N21 PXE R818 N21 P1E 3"
3" 4"
3113 3"
3113 1"
N2102C023 PLT IDENT NO.
WEST (100%)
INJECT PUMP R.F.P. SEAL WATER 4"
N2102C022 PLT IDENT NO.
EAST (100%)
INJECT PUMP R.F.P. SEAL WATER 4"
3" 1"
3" 3"
3856 4"
3" 3856 B
L431 N21 PTL B
N441 N21 PDSE B
L432 N21 PTH B
N424 N21 FE B
L424 N21 FTH B
N425 N21 FXE B
L423 N21 FTL 059 2"
B K404 N21 TE/P (V)
F.O.
B F001 N21 TCV B
F002 N21 TCV 3132 4"
10" L456 N21 TWT B
K405 N21 TE/P HI 019 R819 N21 TRA I&C LOOP N20-6 VENT N485 N21 LXP L435 N21 LT 2198 N445 N21 LXP L433 N21 LT 4"
3" N2102C024 PLT IDENT NO.
RETURN PUMP R.F.P. SEAL WA 4"
1" K406 N21 LCP N2102A003 PLT IDENT NO.
RETURN TANK SEAL WATER I-2310-09 LOGIC MOTOR PUMP F401 N21 LCV F405 N21 E/V R824 N21 ZIV N413 N21 ZXV C
N451 TEW C
L468 3120 3119 B
N451 TEW B
L468 PLT IDENT NO. N2003B016 DRAINS COOLER NO. 1 CTR K
3104 18" (V)
(D)
MO (V)
(V)
(V) 3104 PLT IDENT NO. N2003B017 DRAINS COOLER NO. 1 WEST PLT IDENT NO. N2003B015 DRAINS COOLER NO. 1 EAST 18" K
(V)
(D)
MO (V)
(V)
(V) 18" K
A N451 TEW A
L468 MTT 1 1/2" (V)
(D)
MO 3104 (V)
(V) 3118 (V)
MO DE VENT E
N486 N21 ZSV SO MO REF. 4, 10 SAMPLE SINK 16 MTT SINK 16 SAMPLE MTT SAMPLE SINK 16 MTT SAMPLE SINK 17 SINK 17 SAMPLE SAMPLE SINK 17 MTT SAMPLE SINK 19 SAMPLE SINK 19 MTT SINK 19 SAMPLE MTT M-2535 (E-5)
M-2535 (E-4) 1 "
1/2 1 1/2" 1 1/2" 1 1/2" 1 1/2" 1 1/2" 1/2 1 "
1/2 1 "
N2200DO49A DRNS.
1 1/4" 1 1/2" 1 1/2" N446 PXE K
IAS IAS IAS IAS F829 F827 F828 2"
2" F830A F831A 3/4" HWC H INJ.
2 M-2013(F-1)
F830B F831B 3/4" (D) 3/4" F830C F831C PT L537 A
PI N22 R451 A
PI N22 R450 A
N2200 F470A 3/4" 6WM-N22-5001-1 SEAL FLUSH FILTERS N2200D060A/D061A FILE #C7-205 3/4" 3/4" 1"
SEAL FLUSH FILTERS FILE #C7-205 N2200D060B/D061B PT L537 6WM-N22-5001-1 R450 R451 N22 B
1/2 N2200DO49B F470B N2200 R450 N22 R451 C
PI C
6WM-N22-5001-1 SEAL FLUSH FILTERS L537 3/4" N2200D060C/D061C FILE #C7-205 PT N22 PI 3/4" 1"
C 1/2 N2200DO49C F470C N2200 6WM-N22-3094-1 6WM-N20-5850-1 P9500F030B N2102 D017A D016A N2102 D016B N2102 D017B N2102 3127 HWC H INJ.
M-2013(E-1) 3127 2
HWC H INJ.
M-2013(D-1) 2 3127 M-2012 (G-8)
F626 F166C F167C F168C F243C F242C F167B F168B F243B F166B F625 F242B F170C F166A F624 F167A F168A F243A F242A F170B F170A F195 F632 F194A F279 F192A F189A F280 F188A F281 F186A F185A F630 F184A F183A F241A F631 F185B F183B F184B F241B F303 F186B F188B F304 F189B F192B F305 F198 F196 FILL/DRN.
FILL/DRN.
P9500 F010A P9500F030A P9500 F010B LOOP SEAL LOOP SEAL N2100 F099B NOTE:
1.
UNLESS OTHERWISE SHOWN:
ALL INSTRUMENT PIS NUMBERS ARE PREFIX N20.
ALL VALVES AND EQUIPMENT PIS NUMBERS ARE PREFIX N2000.
C32K669 DCS-FW C32K669 DCS-FW DCS-FW C32K669 DCS-FW C32K669
& ERIS POINT #3
& ERIS POINT #4 F144A F146A F147A F148A F149A F623 F138 F143A F139A F140A F268 F139B F140B F143B F144B F146B F147B F148B F149B F275 F152B F153B F240B F154B F155B F240A F153A F152A F139C F140C F143C F144C F146C F148C F149C F147C F276 N2100F165A N2100F166A F099A F005A N2100 N2100 N2100 F003A N2100F011A N2100F007A N2100F009A N2100F006A N2100 N2100F010A N2100F012A 1 1/2" 1 1/2" 1 1/2" F008A N2100 F004A 1 1/2" N2100F013A N2100F017A N2100F018A N2100 F015A N2100 F016A N2100F101 N2100F100 N2100F022 N2100F023 N2100F024A N2100F025A N2100F115 F288 F269 N2100 F107 N2100 F028A N2100F029A N2100 N2100F028B F029B N2100F025B N2100F024B N2100F166B N2100F165B N2100 F003B N2100 F005B N2100F007B N2100F009B N2100F011B 1 1/2" F004B N2100 N2100 F006B N2100F008B N2100F012B F013B N2100 N2100F010B N2100 F038B F033B N2100 N2100 F034B F163B F162B F164B F635 F162A F164A F634 F163A N2100 F031A N2100F033A N2100 F034A N2100F038A F621 F180 F158A F159A (V)
(V)
F158C (V)
F158B (D)
F159B (D)
F160A F160B F160C F152C F153C F240C N2100F619 N2100 F620 N2100 F337 N2100 F077 N2100 F175 N2100F336 N2100F078 N2100F075 N2100F335 N2100 F074 N2100 F076 N2100F800 F622 N22 N22 N22 F139A,B&C F270A,B&C F271A,B&C F272A,B&C TS TS TS TS K
N2100F031B 2.
3.
DELETED DELETED N2100 F018B N2100 F017B N2100 F015B N2100 F016B AH AH AH AH AH AH AH AH AH AH HTR. DRAIN PUMPS DWGS M-2005 (D-4/5) & M-2005-1 (F-6/7)
AH AH M-2004 (F-5/6)
AH AH AH AH (G-7/8)
(E-7/8)
Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT DETROIT EDISON COMPANY DRAWING NO.
FIGURE 10.4-8, SHEET 2 CONDENSATE SYSTEMS 6M721-2004-1, REV. AH REV 19 10/14
5(9
5(9
n N006 C32 TEW N006 C32 TEW B
L439 PT B
N443 PXE B
R807 PIE A
N443 PXE A
R807 PIE A
N421 TEW B
N420 TEW B
N438 PXE B
L428 PT B
L438 CT B
L479 FTL B
N490 FXE B
L480 FTH A
N420 TEW A
L479 FTL A
N490 FXE A
L480 FTH A
N438 PXE A
L428 PT A
L438 CT A
N421 TEW A
F400 FCV B
N444 ZXV B
R815 ZIV A
N444 ZXV A
R815 ZIV B
L410 FTH B
L409 FTL M-2004-1 (G-2)
L442 PT N450 PXE K403 LE/P N417 ZXV A&B N442 ZSV A
L410 FTH A
L409 FTL M-2004-1 (F-3)
B L407 PT B
N407 PXE B
R803 PIE M-2004-1 (D-2)
M-2004-1 (H-3)
A L407 PT A
N407 PXE A
R803 PIE M-2004-1 (D-4)
N415 FE L415 FTL L416 FTH N416 FXE R805 FIE R620 C32 LH/A B
F400 FCV L486 CTT L485 CTT F403 LCV A
K858 FH/A B
K858 FH/A S
S C
C C
C FY C32 K615 F/E C32 R604 A
F/E C32 R604 B
FRE C32 R607 TWT L454B L454D TWT TO STARTREC PNL. H11P919 POINT 92 & 93 URE B21 R809 TEW B21 N041 B
TY B21 N602 B
TEW B21 N041 D
TY B21 N602 D
3/4" TEST CONN.
ZSV B21 N477 B
E/V B21 F483 B
ZSV B21 N476 B
RCIC RWCU ZSV B21 N432 B&D ZSV B21 N434 B&D E/V B21 F482 B
CLASS A ZSV N21 N533 A&B FDVC N21 F539B B21 URE R809 CLASS A HPCI F539A N21 FDVC A&B N532 N21 ZSV 3/4" A
F482 B21 E/V A&C N432 B21 ZSV ZSV B21 N434 A&C E/V B21 F483 A
A N477 B21 ZSV ZSV B21 N476 A
C N602 B21 TY C
N041 B21 TEW A
N602 B21 TY A
N041 B21 TEW TWT L454C L454A TWT 2336 3/4" 20" BY GENERAL ELECTRIC BY DETROIT EDISON 20" 3/4" 20" DRYWELL CONTAINMENT REF. 5,7 6"
FROM SBFW PUMPS 5085 QAII QAIII 14" CONDENSATE/FEEDWATER CLEANUP RETURN-6000 GPM.
REACTOR COLD FILL 3123 1"
10" 3115 3103 24" 3109 FEEDWATER HTR. NO. 6 SOUTH-PLANT IDENT. NO.
N2101B002 3109 3109 900 LB 300 LB NOTE 5 LC 1"
DRN.
1 1/4" REF.5&7 14" 3110 3109 3103 I/C LOOP N21-2 DRAIN 3109 FEEDWATER HTR. NO. 6 NORTH-PLANT IDENT. NO.
3109 ELBOW TAPS (TYPICAL)
REF. 5&7 NOTE 5 3109 LC 900LB 300LB VENT 14" DRAIN 3114 14" FO CRPB 24" 12" 12" FO R.F.P.T.-S TRIP TRIP R.F.P.T.-N 8"
8" B
8" I/C LOOP N21-2 A
3110 I/C LOOP N21-3 3116 TEW B21 N041 C
B21 C
N602 TY E
E DE CRPB F065 F067 F066 F070A F614 F618 F070B F615 F047B F044B F045B F608 F612 F081 F334 F079 F616 F080 F403 F613 F052 F044A F045A F607 F047A F617 F095A F055A F609 F159A F058A F601 F604 F059A F332 F055B F159B F610 F602 F059B F605 F603 F060 F064 F164 F103A F102A B2100F011A B2100 B2100F011B F103B F102B B2100 F098A F331 F098B F063 F606 F010A F168B F168A F046A F539A F539B 2336 c.s.
s.s.
REFERENCES:
NORTH CENTER SOUTH HOTWELL NORTH HOTWELL SOUTH REACTOR PRESSURE VESSEL 12" 12" 12" AO AO 20" 12" 12" 12" TEST CONN 20" 14" X-9B X-9A 4"
6" RCIC 20" 14" 36" 1"
1 1/4" 24" 10" N2101B001 1 1/4" 1 1/4" 1 1/4" 10" 24" RO 24" 24" N2102D008 FE N408 B
FXE N409 8"
3/4" FE/P K400 B
FE/P K400 A
R.F.P.-SOUTH RECIRC LINE 8" R.F.P.-NORTH RECIRC LINE N2102D013C N2102D013B N2102D013A 1 1/4" NOTES:
- 1. ALL FLOWS AND VELOCITIES SHOWN WITH THE EXCEPTION OF PUMP BY-PASSES ARE AT 105% WARRANTED REACTOR FLOW.
- 2. DELETED.
- 3. FOR LEGEND OF SYMBOLS AND ABBREVIATIONS, SEE DWG. M-2000 AND M-2001.
- 5. VALVES V12-2524 AND V12-2514 ARE TO BE DE-ENERGIZED DURING PLANT OPERATION. THEY ARE OPERATED ONLY DURING LONG CLEAN UP CYCLE.
INSTRUMENT & CONTROL SYSTEM SYSTEM N21 NOTES:
A. DELETED.
B. DELETED.
C. LAST INSTRUMENT NUMBERS ASSIGNED F002/F406-K-406/K815-L442-N450-R401/R819 (N500-525).
D. LOOP N21-4AB, N21-5AB, AND N21-6 ARE SHOWN ON M-2004-01
REFERENCES:
- 2. CONDENSATE SYSTEM M-2004 & 2004-01
- 3. FEEDWATER HEATER DRAINS SYSTEM M-2005 & 2005-01
- 4. TBCCW SYSTEM DIAGRAM M-2008
- 5. DIAG. OF TURB. BLDG. SAMPLES I-2400-03
- 6. FEEDWATER CONTROL SYSTEM I-2126-01 INSTRUMENT DIAGRAM 732E153(R1-155)
- 7. PLANT SAMPLING I-2400-01 36" VENT 3114 3103 36" 17,600GPM-16.4FPS 17,600GPM-16.4FPS 3131 24" FE C32 N001 B
B L002 C32 FTH FTL C32 L001 B
FXE C32 N002 B
L003 C32 FTL N001 C32 FE L004 C32 FTH N002 C32 FXE FY C32 K619 A
FY C32 K619 B
K K
24" A
A A
A A
B K
K GROUP D NON-Q GROUP A QA I K
AO AO K
K 3103 3114 10" K
3/4" K
1 1/4" 3109 3109 3109 N2102D007 30 GPM R.F.P. DISCHARGE M.O. VALVE-SOUTH 24" ZSV N171 A,B,C&D M.O. START-UP VALVE-SOUTH 12" 14" 14" K
F.O.
START-UP CONTROL VALVE 80%
01 7860 GPM START-UP LINE K
N409 FXE A
N408 FE 8"
REACTOR FEED PUMP-NORTH PLANT IDENT. NO. N2102C001 R.F.P. BYPASS LINE REACTOR FEED PUMP-SOUTH PLANT IDENT. NO. N2102C002 K
3110 14" (D)
(D) 1 1/4" K
12" VALVE-NORTH M.O. START-UP A,B,C&D N170 ZSV 24" M.O. VALVE-NORTH R.F.P. DISCHARGE 30 GPM N2102D006 3109 1 1/2" DRN.
DRAIN K
FROM FEEDWATER CONTROL SEE I/C REF. 1 K
MO 3/4" 1"
F163A MO 3110 1 1/2" L.P. TURB.
L.P. TURB.
L.P. TURB.
F163B 3/4" F049A F049B 2"
2" F833B F833A F832 6WM-N21-5851-1 M-2012 (F-8)
VENT VENT F058B F106
- 7. UNLESS OTHERWISE SHOWN:
ALL INSTRUMENTS PIS NUMBERS ARE PREFIX N21 ALL VALVES AND EQUIPMENT PIS NUMBERS ARE PREFIX N2100.
B2100 B2100 NON-Q GROUP D QA I GROUP A F032B B2100 F010B F076A F032A F076B B2100 K
K K
K K
K K
C32K669 DCS-FW DCS-FW C32K669 C32K669 DCS-FW DCS-FW C32K669 DCS-FW C32K669 DCS-FW C32K669 C32K669 DCS-FW C32K669 DCS-FW C32K669 DCS-FW K
STARTREC PNL H11P919 POINT 86 F611 F032B F076B F076A F032A RO RO B21DC0489 B21DC0488 B21DC0487 N21DC0456 DRAIN F095B 20" F836A F835A 1/4 "
3/4 "
F839A FUNC. TEST/
CAL. TAP F837A F838A FROM OLNC INJECT. SKID PIS# P79P001 S.S.
C.S.
FUNC. TEST/
CAL. TAP F839B FROM OLNC INJECT. SKID PIS# P79P001 B21DC0490 F836B F837B F838B 1/4 "
F835B 3/4 "
M-2039 NOBLE CHEMISTRY INJECTION SKID DIAGRAM M-5821 ISI BOUNDARY DRAWING REACTOR FEEDWATER SYSTEM M-5715-1 REACTOR FEEDWATER SYSTEM FUNCTIONAL OPERATING SKETCH STRAIGHTENING VANE STRAIGHTENING VANE F582A F581A B2100 GROUP D NON-Q GROUP A QA I V
B2100 F584A B2100 D
GROUP D NON-Q B2100 F583A GROUP A QA I F580A B2100 F579A B2100 GROUP D NON-Q GROUP A QA I D
NON-Q GROUP D QA I GROUP A D
F580B B2100 F579B B2100 B2100 F581B B2100 F582B GROUP A QA I GROUP D NON-Q V
GROUP A QA I GROUP D NON-Q B2100 F583B B2100 F584B D
- 6. DELETED PLANE B PXE N21 N802 A
N21N801A TRANSDUCERS PLANE A PLANE B 1 UP 2 UP 3 UP 4 UP 1 DN 2 DN 3 DN 4 DN 5 UP 6 UP 7 UP 8 UP 5 DN 6 DN 7 DN 8 DN RTD RTD PLANE B 1 UP 2 UP 3 UP 4 UP 1 DN 2 DN 3 DN 4 DN 6 UP 7 UP 8 UP 5 DN 6 DN 7 DN 8 DN RTD RTD PLANE A PLANE A N21 A
H21 P637 FXE N21 B
H21 P637 PLANE B N21N801B TRANSDUCERS PLANE A PLANE B RTD RTD PLANE B 1 UP 2 UP 3 UP 4 UP 1 DN 2 DN 3 DN 4 DN 5 UP 6 UP 7 UP 8 UP 5 DN 6 DN 7 DN 8 DN PLANE A PLANE A FXE N21 C
H21 P637 FXE N21 D
H21 P637 H21 P637 K1002 K1002 K1002 K1002 TEN21N807A FXEN21N803A FXEN21N803B FXEN21N803C FXEN21N803D FXEN21N803E FXEN21N803F FXEN21N803G FXEN21N803H TEN21N807B FXEN21N804A FXEN21N804B FXEN21N804C FXEN21N804D FXEN21N804E FXEN21N804F FXEN21N804G FXEN21N804H N21 K1001 2"
2" 2"
2" H21 P426 N21 L487 A
PXE N21 N802 B
H21 P426 N21 L487 B
PT PT DETAIL A 3D15 3D17 C
SEE DETAIL A N802 N21 PXE A
H21 P426 L487 N21 A
PT N21 N801A CTT L483 B
N802 N21 PXE H21 P426 SEE DETAIL A B
L487 N21 PT N801B N21 CTT L484 3131 8.
9.
- 4. DESIGNATES PIPING ISOMETRIC NUMBER.
1 UP 2 UP 3 UP 4 UP 1 DN 2 DN 3 DN 4 DN 5 UP 6 UP 7 UP 8 UP 5 DN 6 DN 7 DN 8 DN RTD RTD FXEN21N805A FXEN21N805B TEN21N808A FXEN21N805C FXEN21N805D FXEN21N805E FXEN21N805F FXEN21N805G FXEN21N805H TEN21N808B FXEN21N806A FXEN21N806B FXEN21N806C FXEN21N806D FXEN21N806E FXEN21N806F FXEN21N806G FXEN21N806H 5 UP C
FXE DELETED DELETED BF BF (SEE DWG. M-2004 ZONE C-3
& M-2011 ZONE H-2)
BF BF M-2044 (E-5)
BF M-2046 (H-6)
M-2035 (D-7)
BF BF M-5083 (H-3)
BF Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT DETROIT EDISON COMPANY DRAWING NO.
6M721-2023, REV. BF FIGURE 10.4-10 FEEDWATER SYSTEM REV 19 10/14
TE N.C.
N491
- 10. UNLESS OTHERWISE NOTED:
ALL INSTRUMENT PIS #s ARE PREFIXED N21 ALL VALVE & EQUIPMENT PIS #s ARE PREFIXED N2103 N2103C001 N2103C002 N2103F002 N2103F003 L.O.
F331 AUTOMATIC BYPASS/CHECK RO D002 RO D001 T
M-2081 M-2034 111 M-2006 M-2006 M-2023 SEE M-2001.
M-5087 M-5715-3.
DELETED M-2023 M-2006 M-2090 M-2035 I-2315-10 I-2310-24 THRU 34 I-2311-35 THRU 43 (M-2090)
T N2103 F315A T
Fermi 2 UPDATED FINAL SAFETY ANALYSIS REPORT DETROIT EDISON COMPANY DRAWING NO.
6M721-5083, REV. T FIGURE 10.4-11 STANDARD FEEDWATER SYSTEM P&ID REV 19 10/14