RS-14-128, LaSalle, Units 1 & 2, Updated Final Safety Analysis Report, Revision 20, Chapter 5.0, Reactor Coolant System and Connected Systems
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LSCS-UFSAR 5.4-1 REV. 13 5.4 COMPONENT AND SUBSYSTEM DESIGN 5.4.1 Reactor Recirculation Pumps See Subsection G.2.1 of Appendix G.
5.4.2 Steam Generators (PWR)
Subsection 5.4.2 is not applicable to this UFSAR.
5.4.3 Reactor Coolant Piping The reactor coolant piping description and design characteristics are presented in Subsection G.2.1 of Appendix G. The recirculation loops are shown in Figures G.2.1-1 through G.2.1-5 and Drawing Nos. M-93 (sheets 1, 2) and M-139 (sheets 1, 2).
5.4.4 Main Steamline Flow Restrictors 5.4.4.1 Safety Design Bases The main steamline flow restrictors were designed:
- a. to limit the loss of coolant from the reactor vessel following a steamline rupture outside the containment to the extent that the reactor vessel water level remains high enough to provide cooling within the time required to close the main steamline
isolation valves; and
- b. to withstand the maximum pressure difference expected across the restrictor, following complete severance of a main steamline.
5.4.4.2 Description
A main steamline flow restrictor (Figure 5.4-1) is provided for each of the four main steamlines. The restrictor is a complete assembly welded into the main steamline.
It is located within the primary cont ainment upstream of the MSIV and is downstream of the main steamline safety
/relief valves. In the event a main steamline break occurs outside the containment, the restrictor limits the coolant blowdown rate from the reactor vessel to the maximum (choke) flow of 7.12 x 10 6 lb/hr at 1015 psig upstream pressure. The restrictor assembly consists of a venturi-type nozzle insert welded, in accordance with applicable code requirements, into the main steamline. The flow restrictor is designed and fabricated in accordance with ANSI B31.7 Code and AS ME "Fluid Meters," 6th edition, 1971.
LSCS-UFSAR 5.4-2 REV. 14, APRIL 2002 The flow restrictor has no moving parts. Its mechanical structure can withstand the velocities and forces associated with a main steamline break. The maximum differential pressure is conservatively assumed to be 1375 psi, the reactor vessel ASME Code limit pressure.
The ratio of venturi throat diameter to st eamline inside diameter of approximately 0.514 results in a maximum pressure differe ntial (unrecovered pressure) of about 11 psi at rated flow. This design limits the steam flow in a severed line to approximately 200% rated flow, yet it results in negligible increase in steam moisture content during normal operation. The restrictor is also used to measure steam flow to initiate closure of the main steamline isolation valves when the steam flow exceeds preselected operational limits.
5.4.4.3 Safety Evaluation In the event a main steamline should break outside the containment, the critical flow phenomenon would restrict the steam fl ow rate in the venturi throat to 200% of the rated value. Prior to isolation valve closure, the total coolant losses from the vessel are not sufficient to cause core uncov ering, and the core is thus adequately cooled at all times.
Analysis of the steamline rupture accide nt (Chapter 15.0) shows that the core remains covered with water and that the am ount of radioactive materials released to the environs through the main steamlin e break does not exceed guideline values.
Tests on a scale model determined final design and performance characteristics of the flow restrictor. The characteristics in clude maximum flow rate of the restrictor corresponding to the accident conditions, irreversible losses under normal plant operating conditions, and discharge moisture level. The tests showed that flow restriction at critical throat velocities is stable and predictable.
If moisture forms in the nozzle throat du e to a momentary large static pressure reduction, the droplets of wet steam woul d have to be at saturation temperature corresponding to throat static pressure.
When proceeding to the downstream region where vapor temperatures are higher, the dr oplets of wet steam partially vaporize and reach equilibrium with vapor at a lower pressure. The moisture is then reduced and is actually negligible and has negligible corrosion effect on the highly corrosion-resistant material (A351) used fo r the inlet and throat sections. High velocity or impingement also has neglig ible erosion effect on this material.
The steam flow restrictor is exposed to st eam of 1/10% to 2/10% moisture flowing at velocities of 150 ft/sec (steam piping inside diameter) to 600 ft/sec (steam restrictor throat). ASTM A351 (Type 304) cast stainl ess steel was selected for the steam flow restrictor material because it has excellent resistance to erosion-corrosion in a high-velocity steam atmosphere. The exce llent performance of stainless steel in LSCS-UFSAR 5.4-3 REV. 13 high-velocity steam appears to be due to its resistance to corrosion. A protective surface film forms on the stainless steel which prevents any surface attack, and this film is not removed by the steam.
Hardness has no significant effect on erosion-corrosion. For example, hardened carbon steel or alloy steel erodes rapidly in applications where soft stainless steel is unaffected.
Surface finish has a minor effect on erosion-corrosion. If very rough surfaces are exposed, the protruding ridges or points erode more rapidly than a smooth surface. Experience shows that a machined or a ground surface is sufficiently smooth and that no detrimental erosion occurs.
5.4.4.4 Inspection and Testing Because the flow restrictor forms a permanent part of the main steamline piping and has no moving components, no testing program is planned. Only very slow erosion will occur with time, and such a slight enlargemement has no safety significance. Stainless steel resistance to corrosion has been substantiated by turbine inspections at the Dresden Unit 1 facility, which have shown no noticeable effects from erosion on the stainless st eel nozzle partitions. The Dresden inlet velocities are about 300 ft/sec; the exit ve locities are 600 to 900 ft/sec. However, calculations show that, even if the erosio n rates are as high as 0.004-inch per year, after 40 years of operation the increase in restrictor choked flow rate would be no more than 5%. A 5% increase in the radiol ogical dose calculated for the postulated main steamline break accident is not significant.
5.4.5 Main Steamline Isolation System 5.4.5.1 Safety Design Bases The main steamline isolation valves, individually or collectively:
- a. close the main steamlines within the time established by design-basis accident analysis to limit the release of reactor coolant; b. close the main steamlines slowly enough that simultaneous closure of all steamlines does not exceed the nuclear system design limits;
- c. close the main steamline when required despite single failure in either valve or in the associated controls, to provide a high level of reliability for the safety function;
LSCS-UFSAR 5.4-4 REV. 14, APRIL 2002 d. use separate energy sources as the motive force to close independently the redundant isolation valves in the individual steamlines;
- e. use local stored energy (compressed air and/or springs) to close at least one isolation valve in each steam pipeline without relying on the continuity of any variety of electrical power to furnish the motive force to achieve closure;
- f. are able to close the steamlines, either during or after seismic loadings, to assure isolation if the nuclear system is breached; and g. have capability for testing, du ring normal operating conditions, to demonstrate that the valves function properly.
5.4.5.2 Description Two isolation valves are welded in a horizontal run on each of the four main steam pipes; one valve is as close as possible to the inside of the drywell and the other is just outside the containment.
Figure 5.4-2 shows a main steamline isolat ion valve. Each is a 26-inch Y-pattern, globe valve. Rated steam flow rate through each valve is 3.786 x 10 6 lb/hr (Reference 3). The main disc or poppet is attached to the lower end of the stem.
Normal steam flow tends to close the valve, and higher inlet pressure tends to hold the valve closed. The bottom end of the valve stem closes a small pressure-balancing hole in the poppet. When the hole is open, it acts as a pilot valve to relieve differential pressure force s on the poppet. Valve stem travel is sufficient to give flow areas past the wide open poppet approximately equal to the seat port area. The poppet travels approximately 90% of the valve stem travel; approximately the last 10% of travel closes the pilot hole. The air cylinder can open the poppet with a maximum differential pressure of 200 psi across the isolation valve in a direction that tends to hold the valve closed.
A 45° angle permits the inlet and outlet passages to be streamlined; this minimizes pressure drop during normal steam flow and helps prevent debris blockage. The pressure drop at 105% of rated flow is 7.8 psi maximum. The valve stem penetrates the valve bonnet through a stuffing box that has two sets of repl aceable packing. A lantern ring and leakoff drain are located between the two sets of packing. To help prevent leakage through the stem packing, the poppet backseats when the valve is fully open.
Attached to the upper end of the stem is an air cylinder that opens and closes the valve and a hydraulic dashpot that controls its speed. The speed is adjusted by a LSCS-UFSAR 5.4-5 REV. 13 valve in the hydraulic return line bypassing the dashpot piston. Valve closing time is adjustable to between 3 and 10 seconds.
The air cylinder is supported on the valve bonnet by actuator support and spring guide shafts. Helical springs around the spring guide shafts close the valve if air pressure is not available. The motion of the spring seat member actuates switches in full open, 92% open, and full closed valve positions.
The valve is operated by pneumatic pre ssure and by the action of compressed springs. The control unit is attached to the air cylinder. This unit contains three types of control valves: pneumatic; a-c; an d a-c from another source that open and close the main valve and exercise it at sl ow speed. Remote manual switches in the control room enable the operator to operate the valves.
Operating air is supplied to the valves from the plant air system through a check valve. An air tank accumulator provides backup operating air.
Each valve is designed to accommodate saturated steam at 1250 psig and 575° F, with a moisture content of approximately 0.23%, an oxygen content of 30 ppm, and a hydrogen content of 4 ppm.
In the worst case, if the main steamline should rupture downstream of the valve, steam flow would quickly increase to 200%
of rated flow. Further increase is prevented by the venturi flow restrictor inside the containment.
During approximately the first 75% of closing, the valve has little effect on flow reduction, because the flow is choked by the venturi restrictor. After the valve is approximately 75% closed, flow is reduced as a function of the valve area versus travel characteristic.
The design objective for the valve is a minimum of 40 years service at the specified operating conditions. Operating cycles are estimated to be 100 cycles per year during the first year and 50 cycles per year thereafter.
In addition to minimum wall thickness re quired by applicable codes, a corrosion allowance of 0.120-inch minimum is ad ded to provide for 40-year service.
Design specification ambient conditions for normal plant operation are 135° F normal temperature, 150° F maximum temp erature, 100% humidity, in a radiation field of 15 rad/hr gamma and 25 rad/hr ne utron plus gamma, continuous for design life. The inside valves are not conti nuously exposed to maximum conditions, particularly during reactor shutdown, and valves outside the primary containment and shielding are in ambient conditions that are considerably less severe.
LSCS-UFSAR 5.4-6 REV. 14, APRIL 2002 The main steamline isolation valves ar e designed to close under accident environmental conditions of 340° F for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> at drywell design pressure. In addition, they are designed to remain closed under the following postaccident environmental conditions:
- a. 340° F for 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> at drywe ll design pressure of 45 psig maximum, b. 320° F for an additional 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> at 45 psig maximum, c. 250° F for an additional 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> at 25 psig maximum, and
- d. 200° F during the next 99 days at 20 psig maximum.
To resist sufficiently the response motion from the safe shutdown earthquake, the main steamline valve installations are designed as Seismic Category I equipment. The valve assembly is manufactured to withstand the safe s hutdown earthquake forces applied at the mass center of the extended mass of the valve operator. The stresses caused by horizontal and vert ical seismic forces are assumed to act simultaneously and are added directly.
The stresses in the actuator supports caused by seismic loads are combined with the stresses caused by other live and dead loads, including the operating loads.
The allowable stress for this combination of loads is based on the ordinary allowable stress set forth in applicable codes. The parts of the main steam isolation valves that constitute a process fluid pressure boundary are designed, fabricated, inspected, and tested as required by the ASME Section III, Class I Code, 1971 Edition with Winter 1971 Addendum.
5.4.5.3 Safety Evaluation In a direct cycle nuclear power plant the reactor steam goes to the turbine and to
other equipment outside the containment.
Radioactive materials in the steam are released to the environs through process openings in the steam system or escape from accidental openings. A large break in the steam system can drain the water from the reactor core faster than it is replaced by feedwater.
The analysis of a complete, sudden steamline break outside the containment is described in Chapter 15.0. The analysis shows that the fuel barrier is protected against loss of cooling if main steam isolation valve closure takes 10.5 seconds or less (including as much as 0.5 second for the instrumentation to initiate valve closure after the break). The calculated radiological effects of the radioactive material assumed to be released with the steam are shown to be well within the guideline values for such an accident.
The shortest closing time (approximately 3 seconds) of the main steam isolation valves is also shown in Chapter 15.0 to be satisfactory. The switches on the valves LSCS-UFSAR 5.4-7 REV. 13 initiate reactor scram when specific conditions (extent of valve closure, number of pipelines involved, and reactor power level) are exceeded (Subsection 7.2.1). The pressure rise in the system from stored and decay heat may cause the nuclear system relief valves to open briefly, but the rise in fuel cladding temperature will be insignificant. No fuel damage results.
The ability of this 45°, Y-design globe valve to close in a few seconds after a steamline break, under conditions of high-pressure differe ntials and fluid flows with fluid mixtures ranging from mostly steam to mostly water, has been demonstrated in a series of tests in dynamic test facilities. A full-size 20-inch valve was tested in a range of steam-water blowdown conditions simulating postulated accident conditions (Reference 1).
The following specified hydrostatic, leakage, and stroking tests, as a minimum, are performed by the valve manufacturer in shop tests:
- a. To verify its capability to close between 3 and 10 seconds, each valve is tested at rated pressure (1000 psig) and no flow. The valve is stroked several times, and the closing time is recorded. The valve is closed by spring only and by the combination of air cylinder and springs. Usually the closing time is slightly greater when closure is by springs only.
- b. Leakage is measured with the valve seated and backseated. The specified maximum seat leakage, using cold water at design pressure, is 2 cm /hr/in of nominal valve size. In addition, an air seat leakage test is conducted using 50 psi pressu re upstream.
Maximum permissible leakage is 0.1 scfh/in of nominal valve size. There must be no visible leakage from either set of stem packing at hydrostatic test pressu re. The valve stem is operated a minimum of three times from the closed position to the open position, and the packing leakage still must be zero by visual examination.
- c. Each valve is hydrostatically tested in accordance with the requirements of the 1971 Edition of the ASME Code. During valve fabrication, extensive nondestructive tests and examinations are conducted. Tests include radiographic, liquid penetrant, or magnetic partic le examinations of casting, forgings, welds, hardfacings, and bolts.
- d. The spring guides, the guiding of the spring seat member on the support shafts, and rigid attachment of the seat member assure correct alignment of the actuating components. Binding of the valve poppet in the internal guides is prevented by making the LSCS-UFSAR 5.4-8 REV. 14, APRIL 2002 poppet in the form of a cylinder longer than its diameter and by applying stem force near the bottom of the poppet.
After the valves are installed in the nuclear system, each valve is tested several times in accordance with the preoper ational and startup test procedures.
Two isolation valves provide redundancy in each steamline so that either can perform the isolation function, and either ca n be tested for leakage after the other is closed. The inside valve, the outside valv e, and their respective control systems are separated physically.
The isolation valves and their installation are designed as Seismic Category I equipment.
Electrical equipment that is associated with the isolation valves and operates in an accident environment is limited to the wiring, solenoid valves, and position switches on the isolation valves. The expected pressure and temperature transients following an accident are discussed in Chapter 15.0.
5.4.5.4 Inspection and Testing The main steam isolation valves can be fu nctionally tested for operability during plant operation and refueling outages. The test operations are listed below. During refueling outage the main steam isolation valves can be functionally tested, leak tested, and visually inspected.
The main steam isolation valves can be tested and exercised individually to the 85% open position, because the valves still pass rated steam flow when 85% open.
The main steamline isolation valves can be tested and exercised individually to the fully closed position if reactor power is reduced sufficiently to avoid scram from reactor overpressure or high flow through the steamline flow restrictors.
Leakage from the valve stem packing will become suspect during reactor operation from measurements of leakage into the drywell, or from observations or similar measurements in the steam tunnel. During shutdown while the nuclear system is pressurized, the leak rate through the inner packing can be measured by collecting LSCS-UFSAR 5.4-9 REV. 14, APRIL 2002 and timing the leakage. Leakage through the inner packing would be collected from the packing drain line.
The leak rate through the pipeline valve seats (pilot and poppet seats) is accurately measured during shutdown.
During prestartup tests following an ex tensive shutdown, the valves undergo the same hydro tests (approximately 1000 psi) that are imposed on the primary system.
Such a test and leakage measurement program ensures that the valves are operating correctly and that a leakage trend is detected.
5.4.6 Reactor Core Isolation Cooling (RCIC) System 5.4.6.1 Design Bases 5.4.6.1.1 Safety Design Bases The RCIC system is not a safety system, hence it has no safety design bases. The RCIC system meets the following functional design bases:
- a. The system operates automatically in time to maintain sufficient coolant in the reactor vessel so that the integrity of the radioactive material barrier is not compromised during conditions noted in Subsection 5.4.6.1.1 (c), (d), and (e).
- b. Piping and equipment, including support structures, are designed to withstand the effects of the SSE without a failure that could lead to a significant radioactive release.
- c. The system assures that adequate core cooling takes place to prevent the reactor fuel from overheating in the event the reactor isolation is accompanied by loss of flow from the reactor feedwater system.
- d. The system allows complete pl ant shutdown under conditions of loss of normal feedwater by maintaining sufficient water inventory until the reactor is depressurized to a level where the shutdown cooling system is placed in operation.
- e. The system assures that adequate core cooling takes place to prevent the reactor fuel from overheating in the event the reactor is isolated and maintained in the hot standby condition.
LSCS-UFSAR 5.4-10 REV. 14, APRIL 2002 5.4.6.1.2 Power Generation Design Bases The RCIC system meets the followin g power generation design bases:
- a. The system operates automatically in time to maintain sufficient coolant in the reactor vessel as noted in Subsection
5.4.6.1.1 (a).
- b. Design is provided for remote-manual operation of the system by an operator.
- c. To provide a high degree of assurance that the system operates when necessary:
- 1. The power supply for the system is from immediately available energy sources (d-c batteries) of high reliability.
- 2. Design is provided for periodic testing during plant operation.
5.4.6.2 System Design 5.4.6.2.1 Schematic Piping and Instrumentation Diagrams The RCIC system consists of a steam-dr iven turbine-pump unit and associated valves and piping capable of delivering makeup water to the reactor vessel. The RCIC P&ID is shown in Draw ing Nos. M-101 and M-147.
Quantitative information on steam and de livery water conditions is given in the system process diagram for all operating modes of the RCIC system (Figure 5.4-3).
5.4.6.2.2 Applicable Codes and Classifications The RCIC system components within the drywell up to and including the outer isolation valve are designed in accordance with ASME Code,Section III, Class 1, Nuclear Power Plant Components. The RCIC system is also designed as Seismic Category I equipment.
The reactor core isolation cooling system component classifications are given in Table 3.2-1.
LSCS-UFSAR 5.4-11 REV. 13 5.4.6.2.3 System Reliability Considerations To assure that the RCIC will operate when necessary and in time to prevent inadequate core cooling, the power supply for the system is taken from immediately available energy sources of high reliability. Added assurance is given in the capability for periodic testing during station operation. Evaluation of reliability of the instrumentation for the RCIC shows that no failure of a single initiating sensor either prevents or falsely starts the syst em. Operation of the RCIC system in the event of loss of offsite power is discussed in Section 15.9.
Reactor core isolation cooling system steam leaks outside the containment are detected by low steamline pressure, high flow rate in the flow element, and high reactor core isolation system turbine exhaust pressure. High differential temperature in the equipment area ventilation inlet and exhaust, high differential temperature in pipe routing area, high ambient temperature in the equipment and pipe areas, and high flow rate in the containment building sump indicate leakage.
Low steamline pressure, high flow rate in the flow element, high turbine exhaust pressure, and high ambient temperature or high differential temperature initiate an alarm in the main control room and automatic isolation of the system. In response to NUREG 0737,Section II.K.3.15, a time delay of 4 se conds was added to the RCIC Steamline Isolation Systems to av oid spurious isolations that may occur as a result of flow peaks occurring during a normal system start transient. Sections 6.2 and 7.4 discuss isolation of the containment.
The RCIC system may provide the ability to mitigate the consequences of small pipe breaks, but it is not provided primarily for such purpose. The emergency core cooling systems provide redundant protection for the entire spectrum of pipe breaks. For small breaks this protection would be provided by HPCS plus ADS.
Both the RCIC and the HPCS provide decay heat removal capability when the main condenser is unavailable (isolated from the nuclear system) for heat sink purposes. The RCIC is not a portion of the emergency core cooling system; the HPCS is a part of this system.
Long-term heat-removal capability may be provided by the RCIC or HPCS during the following operational events: scram, pressure relief, core cooling, reactor vessel isolation, and to restore a-c power. Th e RHR system may be used for long-term heat removal during any long-term isolatio
- n. These events are all situations in which the reactor vessel is isolated from the main condenser. None of these events are pipe break (loss-of-coolant) situations requiring immediate reactor water level restoration.
In order to assure HPCS or RCICS availability for the operational events noted previously, certain design considerations are utilized in design of both systems.
LSCS-UFSAR 5.4-12 REV. 13 a. Physical Independence - The two systems are located in separate areas in different corners of the reactor building. Piping runs are separated, and the water deli vered from each system enters the reactor vessel via different nozzles.
- b. Prime Mover Diversity and Independence - Prime mover independence is achieved by using a steam turbine to drive the RCIC system and an a-c motor to drive the HPCS system. The HPCS motor is supplied from either normal a-c power or a separate diesel generator.
- c. Control Independence - Control independence is secured by using a different battery system to provide control power to each unit. Separate detection initiation logics are also used for each system. d. Environmental Independence - Both systems are designed to meet ASME Section III Class 2 requirements. Environment in the equipment rooms is mainta ined by separate auxiliary systems. A design flow functional test of the RCIC is performed during plant operation by taking suction from the condensate stor age tank and discharging through the full flow test return line back to the condensate storage tank. A design flow functional test of the RCIC System can also be performed during plant operation by taking suction from the suppression pool and discharging through the full flow test return line back to the suppression pool. The discharge valve to the headspray line remains closed during the test, and reactor operation is undisturbed. Control system design provides automatic return from test to operating mode if system initiation is required during testing of individual components. Periodic inspections and maintenance of the turbine pump unit are conducted in accordance with manufacturers' recommendations. Valve po sition indication and instrumentation alarms are displayed in the control room.
5.4.6.2.4 Manual Actions Manual actions required to be taken by an operator in order for the RCIC system to operate properly are discussed in Subsection 5.4.6.3.
In addition to the automatic operationa l features, provisions are included for remote-manual startup, operation, and shutdown of the RCIC system provided
initiation or shutdown signals do not exist.
LSCS-UFSAR 5.4-13 REV. 13 5.4.6.3 Performance Evaluation The pump discharges either to the headspray nozzle, the full flow test return line to the condensate storage tank or to the suppression pool. A minimum flow bypass line to the suppression pool is provided to protect the pump during startup and shutdown. The makeup water is delivered into the reactor vessel through the headspray nozzle. Cooling water for the RCIC turbine lube oil cooler and gland seal condenser is supplied from the discharge of the pump (Drawi ng Nos. M-101 and M-147). Following any reactor shutdown, steam generation continues from the heat produced by the radioactive decay of fission products. Initially the rate of steam generation is augmented during the first few seconds by delayed neutrons and some of the residual energy stored in the fuel. Steam normally flows to the main condenser through the turbine bypass or, if the condenser is isolated, to the suppression pool. The fluid removed from the reactor vessel is normally made up by the feedwater pumps supplemented by leakage from the control rod drive system. If makeup water is required to supplement these primary sources of water, the RCIC turbine-pump unit starts automatically on receipt of a reactor vessel low-water level signal (Figure 5.4-11) or is started by th e operator from the control room. The RCIC delivers its design flow within 30 seconds after actuation at rated reactor pressure. To limit the amount of fluid leaving the reactor vessel, the reactor vessel low-water level signal also actuates the closure of the main steam isolation valves.
Pump suction normally is taken from the condensate storage tank. The volume of water stored for the RCIC is sufficient to allow operation for 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> after shutdown, assuming that none of the stea m generated in the reactor vessel can be returned to the reactor vessel as condensate. Other systems that use the same reservoir and could jeopardize the availability of this quantity of water can be isolated. A low-level alarm is energized wh en the level in the storage volume falls to the minimum required to meet th e design requirements of the RCIC.
The RCIC system is sized to provide adequate makeup for breaks outside the containment, thus precluding actuation of the automatic depressurization system thereby reducing total mass lost from the RPV for this situation.
The backup supply of cooling water for the RCIC is the suppression pool. When the condensate storage tank level is low, pump suction is automatically switched over to the suppression pool in accordance wi th NUREG 0737, Item II.K.3.22. The turbine-pump assembly is located below the level of the condensate storage tank and below the minimum water level in the suppression pool to assure adequate net positive suction head to the pump.
All components required for initiating the RCIC are completely independent of auxiliary a-c power, plant service air, an d external cooling water systems; they LSCS-UFSAR 5.4-14 REV. 13 require only power derived from the station battery to operate the valves and motors. The power source for the turbine-pump unit is the steam generated in the reactor vessel by the decay heat in the core. The steam is piped directly to the turbine, and the turbine exhaust is piped to the suppression pool.
Throughout the period of RCIC operation, the exhaust from the RCIC turbine is condensed in the suppression pool, which results in a slow temperature rise (approximately 3° F/hr) in the pool. One RHR heat exchanger can be used to cool the suppression pool after approxim ately 1-1/2 hours, if necessary.
If for any reason the RCIC is unable to supply sufficient flow for core cooling, the emergency core cooling systems provide the required barrier boundary protection (Chapter 6.0).
The RCIC turbine-pump unit is located in a shielded area to assure that personnel access areas are not restricted during RCIC operation. The turbine controls provide for automatic shutdown on the RCIC turbine on receipt of the following signals:
- a. turbine overspeed - prevents damage to the turbine and turbine casing, b. pump low suction pressure - prevents damage to the turbine pump unit that results from loss of cooling water, c. turbine high exhaust pressure - indicates turbine or turbine control malfunction, and
- d. system isolation signal - indicates need to shut down equipment.
Because the steam supply line to the RCIC turbine is a pressure barrier boundary, certain signals automatically isolate this line and cause shutdown of the RCIC turbine.
The RCIC turbine has a speed governor that is positioned by the demand signal from the flow controller. Maximum output from the controller corresponds to maximum turbine speed.
The analytical methods and assumptions used in evaluating the RCIC system are presented in Chapter 15.0 and Appendix D.
5.4.6.4 Preoperational Testing The preoperational and initial startup test program for the RCIC system is presented in Chapter 14.0.
LSCS-UFSAR 5.4-15 REV. 14, APRIL 2002 5.4.6.5 Safety Interfaces The balance of plant-GE steam supply system safety interfaces for the reactor core isolation cooling system are: (1) preferred water supply from the condensate storage tank; and (2) all associated wire, cable, piping, se nsors, and valves which lie outside the nuclear steam supp ly system scope of supply.
5.4.7 Residual Heat Removal System 5.4.7.1 Design Bases The RHR operates in three modes. For clarity, each mode is discussed separately. It is shown how each mode contributes toward satisfying all the design bases of the RHR system.
The major equipment of the RHR system cons ists of three independent closed loops, two heat exchangers, three main system pumps, and a service water supply. The equipment is connected by associated valves and piping. Controls and instrumentation are provided for correct system operation.
Safety Design Bases The engineered safety function of the RHR system is the low pressure coolant injection (LPCI) mode, which is one of the LaSalle ECCSs to mitigate LOCA as discussed in Section 6.2. The safety de sign bases for the RHR containment cooling mode are discussed there also, where it is concluded that the design objective is to safely terminate the post-DBA containment temperature transient. Note that other design features of the RHR system are essentially backup capabilities to the primary ESF design feature of LPCI. These features are manually initiated post-DBA to employ RHR equipment should the primary ESF capabilities not be present. For example, with the successful operation of the LaSalle ECCSs (HPCS, ADS, LPCS, and LPCI), no need exists, and no safety credit is claimed for the long-term cooling mode, nor the reactor vessel head spray, nor the fuel pool auxiliary cooling capability of RHR equipment in an accident mode. These features are included with power generati on bases as discussed below.
Power Generation Design Bases The RHR system has been designed to meet the following power generation design bases: a. The system was evaluated for power uprate to 3489 MWt in Reference 4, and has enough heat removal capacity to cool the reactor to 125°F in less than 32 hours3.703704e-4 days <br />0.00889 hours <br />5.291005e-5 weeks <br />1.2176e-5 months <br /> after shutdown.
LSCS-UFSAR 5.4-15a REV. 14, APRIL 2002 Since the normal heat removal function is not safety related, the increase in the shutdown time from the original design basis of 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br />, to approximately 32 hours3.703704e-4 days <br />0.00889 hours <br />5.291005e-5 weeks <br />1.2176e-5 months <br />, will be limited to an impact on plant availability, which is not a safety concern. (See Subsection 7.4.3.2 for shutdown cooling mode.)
LSCS-UFSAR 5.4-16 REV. 14, APRIL 2002
- b. Fuel pool connections are provided so that the "B" RHR pump and heat exchanger can be used in a fuel pool cooling capacity. (See also Chapter 9.0 on auxiliary plant systems.)
5.4.7.2 System Design 5.4.7.2.1 Schematic Piping and Instrumentation Diagrams A process diagram of the RHR system is show n in Figure 5.4-5. A description of the controls and instrumentation is presente d in Subsection 7.3.1. Figure 5.4-5 indicates the RHR heat exchanger duties/capabilities for the principal modes of operation. The operation of the RHR equipment with ot her emergency core cooling systems to protect the core in case of a loss-of-coolant accident is described in Chapter 6.0. A description of the controls and instrumentation is presented in Chapter 7.0.
5.4.7.2.2 Equipment and Component Description 5.4.7.2.2.1 General The components of the RHR system locate d inside the drywell required for LPCI operation are designed to operate in the following environmental conditions:
- a. 340° F for 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> at 45 psig, b. 320° F for an additional 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> at 45 psig, c. 250° F for an additional 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> at 25 psig, and
- d. 200° F during the next 99 days at 20 psig.
The main system pumps are sized for the flow required during low-pressure coolant injection (LPCI) operation. (See Chapte r 6.0 for discussion of the LPCI.) The pumps are arranged and located so that ad equate suction head is assured for all operating conditions. The pump motor is air cooled by the ventilation and heating system. The heat exchangers are sized on the basis of required duty for the shutdown mode.
The heat exchanger shell and tube sides are provided with drain connections. The shell side is provided with a vent to remove noncondensable gases. Relief valves on the heat exchanger shell side, on the RHR pump discharge, and on the RCIC supply line protect the heat exchanger from overpressure.
LSCS-UFSAR 5.4-17 REV. 14, APRIL 2002 The most limiting duty is that asso ciated with the shutdown mode. The performance of this type of heat exchanger operating in this mode (water to water) is well established by currently operating BWR facilities.
Heat exchanger shell side and tube side codes and standards are provided in Section 3.2. Classification information fo r the RHR heat exchanger is presented in Table 3.2-1.
The shutdown cooling piping may be connected to the fuel pool system (Drawing Nos. M-96 and M-142 (sheet 2)) so that th e "B" RHR pump and heat exchanger can provide fuel pool cooling if necessary. (See Section 9.1.3 concerning fuel pool cooling and cleanup system.)
An alternate method of removing decay heat during cold shutdown and refueling modes of operation can be established by gravity draining through a RHR heat exchanger to the suppression pool and returning water to the reactor using a low pressure ECCS pump.
5.4.7.2.2.2 Shutdown Cooling an d Reactor Vessel Head Spray Mode The shutdown cooling and reactor vessel head spray mode is an integral part of the RHR system. It is operated during a normal shutdown and cooldown. The initial phase of nuclear system cooldown is accomplished by dumping steam from the reactor vessel to the main condenser.
When nuclear system temperature has decreased to where the steam supply pressu re is not sufficient to maintain the turbine shaft gland seals, vacuum in the main condenser cannot be maintained and the RHR system is placed in the shutdown cooling mode of operation. The shutdown cooling subsystem is able to comp lete cooldown to 125° F in less than 32 hours3.703704e-4 days <br />0.00889 hours <br />5.291005e-5 weeks <br />1.2176e-5 months <br /> after the control rods have been inserted and can maintain the nuclear system at or below 125° F for reactor refueling and servicing.
Reactor coolant is pumped from recirculation loop A by the RHR main system pump and discharged through the RHR heat exchanger, where cooling occurs by heat being transferred to the service water. Part of the flow can be diverted to a spray nozzle in the reactor head (from loop A on ly) (Figure 5.4-5).
This spray maintains saturated conditions in the reactor vessel head volume by condensing steam being generated by the hot reactor vessel walls and internals. The spray also decreases thermal stratification in the reactor vessel coolant. This ensures that the water level in the reactor vessel can rise. The higher water level provides conduction cooling to more of the mass of metal of the reactor vessel.
The RHR system is warmed up prior to plac ing it in the shutdown cooling mode of operation. Water used for warm up is ta ken from the Reactor Recirculation system and is discharged to the radioactive waste disposal system or main condenser. The warm-up procedure may be conducted during the steam dumping portion of nuclear LSCS-UFSAR 5.4-18 REV. 14, APRIL 2002 system cooldown, so as not to deter or delay the system from accomplishing cooldown within 32 hours3.703704e-4 days <br />0.00889 hours <br />5.291005e-5 weeks <br />1.2176e-5 months <br />.
The RHR System warmup may be waived du ring emergency or transient conditions when action to bring the unit to cold shutdown quickly is deemed appropriate. RHR SDC may then be placed on line with no warming if the temperature differential between the RHR SDC piping and the Reactor Moderator does not exceed 250 deg F. This condition has been analyzed for a total 120 thermal cycles with no adverse effect on the suction and discharge tees to the recirculation loops.
The heat exchanger design provides for rated performance of the heat exchanger under fouled conditions. Fouling beyond the extent specified in the heat exchanger design results in a decrease in the heat transfer rate.
These fouling factors are a function of th e nature of the fluids, the temperatures involved, and the fluid velocities. The heat exchanger design includes the fouling factors in calculating this overall thermal resistance and provides sufficient surface area to allow the required heat transfer rate at fouled conditions.
5.4.7.2.2.3 Steam Condensing Mode On-Site Review 92-37 was performed by LaSalle Station to delete the Steam Condensing Mode of Residual Heat Removal System Operation from use at LaSalle (AIR 373-160-92-00108). The procedures governing Steam Condensing Mode Operation have been deleted and a review of other procedures that operate the below listed valves, concluded that these valves are not required to operate in plant emergency procedures. The active safety re lated function of the actuators has been deleted and the valves will only be opened in Operating Conditions 4, 5, and Defueled to support infrequent non-safety related functions. To ensure that the position of these valves will not impa ct a design basis event and to prevent inadvertent operation from the control room, actions have been taken to administratively control them in the closed position with power removed during Operating Conditions 1, 2, and 3. Otherwise, the valve(s) must be declared inoperable for all associated safety related functions.
These controls permit the Steam Condensing valves to be deleted from the Generic Letter (GL) 89-10 Testing and Environmental Qualification Programs (Engineering Letter Chron # 122980 dated November 15, 1993).
Steam Condensing Valves
1(2)E12-F011A/B A(B) RHR Hx Drai n to Sup Chamber Stop Valve 1(2)E12-F026A/B A(B) RHR Hx Drai n Outlet to RCIC Stop Valve
LSCS-UFSAR 5.4-19 REV. 16, APRIL 2006 1(2)E12-F051A/B A(B) RHR Hx Stea m Inlet Pressure Control Valve 1(2)E12-F052A/B A(B) RHR Hx Steam Inlet Stop Valve 1(2)E12-F065A/B A(B) RHR Hx Drain Outlet Valve
1(2)E12-F073A/B A(B) RHR Hx Shell Si de Vent Downstream Stop Valve 1(2)E12-F074A/B A(B) RHR Hx Shell Side Vent Upstream Stop Valve 1(2)E12-F087A/B A(B) RHR Hx Stea m Inlet PCV Bypass Stop Valve 1(2)E51-F064 RCIC Steam Inlet to RHR Heat Exchanger Valve, have been replaced by spectacle flange 1(2)E51-D324. The blind flange side of the spectacle will be in place during operating conditions 1, 2, and 3.
1(2)E12-F055A/B RHR Heat Exchanger RCIC Steam Inlet Header Relief Valves. These valves are permanently gagged in place and are not performing relief function.
5.4.7.2.2.4 Low-Pressure Coolant Injection Mode The low-pressure coolant injection (LPCI) mode is an integral part of the RHR system. It operates to restore and, if necessary, maintain the coolant inventory in the reactor vessel after a loss-of-coolant accident. A detailed discussion of the requirements and response of the LPCI for a loss-of-coolant accident is included in Section 6.3. A detailed discussion of the requirements and response of LPCI controls and instrumentation during a loss-of-coolant accident is found in Subsection 7.3.1.
LPCI is a low-head, high-flow function that delivers flow to the reactor vessel when the differential pressure between the vessel and drywell is less than 225 psid (rated flow is injected at 20 psid). LPCI is designed to reflood the reactor vessel to at least
two-thirds core height and to maintain this level. After the core has been flooded to this height, the capacity of one RHR main system pump is sufficient to make up for shroud leakage and boil-off.
During LPCI operation, the main system pumps take suction from the suppression pool and discharge to the core region of the reactor vessel through separate vessel piping penetrations. Any spillage through a break in the lines within the primary containment returns to the suppression pool. A minimum flow bypass line to the suppression pool is provided so the pumps are not damaged by overheating if operated with the discharge valves closed.
LSCS-UFSAR 5.4-19a REV. 14, APRIL 2002 Service water flow to the RHR heat exchan gers is not required immediately after a loss-of-coolant accident, because heat rejection from the containment is not needed during reactor flooding. Power for the main system pumps comes from normal a-c power. If this source is not available, power is available from standby a-c power.
The acceptability of utilizing the LPCI path as a return path to the reactor pressure vessel during operation of the RHR System in the shutdown cooling mode has been LSCS-UFSAR 5.4-20 REV. 13 determined to be adequate (Reference 2) as a backup loop to satisfy the requirements of the Technical Specificatio ns. A normally aligned loop would be utilized to perform the active cooling function, with the backup loop to be used only in case of failure of the primary loop.
The LSCS equipment cooling water piping is crosstied to the discharge piping
through the emergency fuel pool makeup pumps to provide a source of water in case any postaccident flooding of the primary containment occurs. This connection is provided with a spool piece connection to prevent inadvertent injection of cooling lake water into the RHR system.
5.4.7.2.2.5 Containment Cooling Mode
The containment cooling mode is an integral part of the RHR system. It consists of two subparts, the suppression pool coolin g part and the containment spray part. Suppression pool cooling is discussed in detail in Subsection 6.2.2.
During reactor operation, the containmen t cooling mode limits the temperature of the water in the suppression pool so th at after the design-basis LOCA, pool temperature does not exceed 200 F.
Test data shows that at 210
°F - 220°F, complete condensation of blowdown steam from the design-basis LOCA can be expected. (Reference 10 in section 6.2.7, also refer to sectio n 6.2.1.8) For the containment spray (cooling) mode of operation, the shell side inlet temperature to the RHR heat exchanger is the maximum su ppression pool temperature expected at postaccident conditions.
The containment spray cooling subsystem provides an alternate method of containment cooling for postaccident cond itions. Water pumped through the RHR heat exchangers can be diverted to sp ray headers in the drywell and above the suppression pool. The spray removes energy from drywell atmosphere by condensing the water vapor. The spray collects in the bottom of the drywell until the water level rises to the level of the pressure suppression vent lines. The water then overflows to the suppres sion pool. Approximately 5% of the total pump flow can be directed to the suppression chamber spray ring to cool any noncondensable gases collected in the free volume above the suppression pool.
The containment spray cooling subsystem of the RHR system normally would not be operated unless the core flooding requirements of the LPCI subsystem have been satisfied.
5.4.7.2.3 Applicable Codes and Classification
- a. American National Standards Institute (ANSI)
- 1. B31.10 Code for Pressure Piping, Power Piping LSCS-UFSAR 5.4-21 REV. 15, APRIL 2004
- 2. B31.7 Code for Pressure Piping, Nuclear Power Piping
- b. American Society of Mechanical Engineers (ASME)
- 1. Standard Code for Pumps an d Valves for Nuclear Power, Class 2 2. Boiler and Pressure Vessel Code, Sections III and VIII, Class A, C
- c. Standard of Tubular Exchanger Manufacturers Association (TEMA) Class C.
5.4.7.2.4 System Reliability Considerations Two loops, each consisting of a heat exchanger, main system pump, and associated piping, are located in separate protected areas.
The third loop, made up of a pump and associated piping, is located in an area associated with the other Division II RHR pump, to minimize the possibility of a single physical event causing the loss of the entire system. The loops of the RHR are not connected so any failure of one loop cannot cause failure of another.
Impaired post-LOCA RHR syst em performance due to broken or loose parts in the suppression pool is avoided by providing suction strainers above the suppression pool bottom. The mesh is sized to pa ss no particles greater than 3/32 inch. Particles passing through the strainers will not cause pump damage or blockage of system flow openings.
In order to avoid water hammer damage, water is supplied by a fill pump to ensure that the RHR discharge piping is continuously filled. The design of the onsite and offsite electrical power systems provides compatible independence and redundancy to ensure an available source of power to the RHR syst em (Section 8.3).
A potential for water hammer exists due to drain down of the RHR System if a LOOP/LOCA occurs during suppression pool cooling (SPC) operation. The A/B RHR System is anticipated to be in the SPC mode for only a small fraction of time during normal plant operation. The total SPC operating time is anticipated to be less than 2% of the total plant operating time in a fuel reload cycle.
Consistent with the philosophy in Reference 5, an operational period is considered "short" if the fraction of time that the system operates within the pressure-temperature conditions specified for high-energy fluid systems is about 2% of the LSCS-UFSAR 5.4-21a REV. 15, APRIL 2004 time, then the system operates as a mo derate-energy fluid system. The "short operational period" defined in Reference 5 is not directly applicable to SPC mode since the RHR system will not be operating at conditions which would qualify as a high-energy fluid system subject to the 2% criteria. However, the 2% criteria of the "short operational period" philosophy is an acceptable definition for an intermittent mode of operation assumed to be only a low fraction of operating time. Since RHR is only operated in SPC mode for "short operational periods", a LOOP/LOCA water hammer is not postulated to occur as an initial condition of the accident analysis and a specific water hammer analysis to address the drain down concern is not required per 10 CFR 50, Appendix A, General Design Criterion 4.
LSCS-UFSAR 5.4-22 REV. 13 5.4.7.3 Performance Evaluation Because the LPCI mode acts with other em ergency core cooling systems to satisfy the safety objective, it is evaluated in conjunction with the other emergency core cooling systems in Chapter 6.0. The sa fety evaluation of the controls and instrumentation of the LPCI subsystem is in Subsection 7.3.1.
5.4.7.3.1 Reactor Shutdown wi th Crack in RHR Cooling Loop The RHR system is a low pressure system; it is interlocked so that an RHR cooling loop can be connected to the reactor vess el only when the reactor pressure is 135 psig or less. All of the piping outside of the primary coolant pressure boundary is classified as "moderate energy" piping, therefore, only cracks rather than pipe breaks need to be considered. If a crack is postulated in one of the two loops in the RHR shutdown cooling system, the pipe whic h would cause the greatest leak rate is a 24-inch Schedule 40 suction pipe. A crack in this pipe, corresponding to the maximum postulated size, would produce a leakage flow rate of 1443 gallons per minute with no allowance for flow reduction due to two-phase flow. This large leakage rate is possible only at the beginni ng of reactor shutdown when the internal pressure is the highest. A crack of this magnitude would be detected by the area radiation monitors and sump alarms. Isolation of the reactor from the leaking RHR loop would occur by operator action or automatically from the NSSS system on level 3 reactor low level.
The main steam isolation valves are not slammed shut at the start of a normal reactor shutdown sequence, therefore, vessel pressure does not increase; establishment of shutdown cooling is possible by activation of an RHR cooling loop. If that loop subsequently cracked, recovery of shutdown cooling is possible via activation of a redundant RHR loop. RHR cooling establishment in the normal situation requires less than 10 minutes after warming up the discharge line, recovery time for an alternate RHR loop is less than 30 minutes. If the postulated crack should occur in the common line supp lying suction to RHR loops A and B, its leak rate would be lower because it is a 20-inch Schedule 40 line. An alternate cooling configuration would be establishe d using ADS discharge lines to circulate vessel water to the suppression pool from which individual separate suctions, are available for RHR loops A, B, and C (or the ECCS pumps) to circulate coolant back to the vessel. These individual suctions would be isolated from the RHR shutdown cooling suctions, assumed to be cracked, by remotely operated MO valves. Recovery time to use RHR loop C is less than 30 minutes; recovery time to configure the alternate RHR cooling system is less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. The time in which operator action is required is discu ssed in Subsection 5.4.7.3.2.
If condenser vacuum has been lost and the MSIV's have already closed prior to the postulated crack occurrence the recovery routine would require more time. Up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> is needed to reestablish condenser vacuum, reopen the MSIV's, control the LSCS-UFSAR 5.4-23 REV. 14, APRIL 2002 vessel inventory, and reestablish the steam dump to the main condenser via the bypass valves. Vessel inventory can be controlled by blowdown through the reactor water cleanup system assuming feedwater is functional if the level is too high. If too low, the feedwater/condensate pumps or HPCS/LPCS/LPCI can provide needed water. Vessel pressure is controlled as requ ired by manual initiation of relief valves following MSIV closure.
The time in which reactor operator action is required is discussed in the following.
5.4.7.3.2 Required Op erator Response Time The RHR moderate energy pipe crack duri ng operation in the shutdown cooling mode is not a limiting event with respect to Suppression Pool temperature limits or required operator response time. This event was not re-analyzed for Power Uprate conditions; i.e., a starting Suppression Pool temperature of 105°F or an initial reactor power level of 3489 MWt. The original analysis, using a Suppression Pool starting temperature of 100°F and an init ial reactor power level of 3323 MWt, is presented in this subsection as historical information.
As shown in Figure 5.4-4, the minimum ti me to begin normal shutdown cooling is four hours after scram. If the water level in the vessel is normal and the main steam isolation valves are closed when shutdown is started, the RHR shutdown suction valves will isolate the reactor 3.1 minutes after the crack flow begins. Assuming instantaneous repressurization of the reactor vessel provides a very conservative basis, in that case, level 2 water-level will be reached in 2.4 minutes and HPCS will reach a minimum of 550 gpm in 13.1 minutes. The vessel water level will reach level 8 and shut off HPCS in 35 minutes. HPCS will cycle between level 2 and 8 until operator action is ta ken to reestablish other means of core cooling. Under the same set of conservative assumptions, it would take 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> of blowdown from the vessel to the pool to raise the pool temperature from 100° F to 180° F. During this time, no pool coolin g is assumed. Therefore, there is ample time for an operator to take appropriate action in response to a crack in RHR cooling loop piping. For long-term cooling cases with lesser energy removal requirements, even greater periods of time are available for operator response in reestablishing an RHR cooling loop for shutdown cooling.
5.4.7.4 Preoperational Testing, Inservice Inspection and Testing Preoperational tests were conducted during the final stages of plant construction prior to initial startup. These tests assured correct functioning of all controls, instrumentation, pumps, piping, and valves. System reference characteristics such as pressure differentials and flow rates were documented during the preoperational testing and were used as base points fo r measurements obtained in subsequent operational tests.
LSCS-UFSAR 5.4-23a REV. 14, APRIL 2002 For the suppression pool cooling mode, the preoperational tests verified that the RHR heat exchanger shell side design flow rate can be obtained while circulating water from the suppression pool, through the RHR pump and the RHR heat exchanger, and back to the suppression pool. During the test, head versus flow curves were developed for reference in evaluating the future performance of the suppression pool cooling mode and the RHR pumps.
LSCS-UFSAR 5.4-24 REV. 13 The preoperational and initial startup test program for the RHR system is discussed in Chapter 14.0 of the FSAR.
A design flow functional test of the RHR main system pumps is performed separately for each pump during normal pl ant operation by taking suction from the suppression pool and discharging thro ugh a full flow test line back to the suppression pool. All other discharge valves remain closed during this test; reactor operation is undisturbed.
All motor-operated valves required to oper ate for safety reasons are capable of being exercised periodically during normal powe r operation. The layout and arrangement of critical equipment, such as drywell wall penetrations, piping, and valves, are designed to permit access for appropriate equipment used in testing and inspection system integrity.
Sequencing of the LPCI mode is tested after the reactor is shut down. Valves required for the remaining subsystems may be tested at this time.
Drains are provided outside the drywell wall in the piping between the isolation valves for reactor process system leakage te sting. Relief valves on the low-pressure lines are removable for testing. A line is provided on the pump discharge line to take water samples.
Periodic inspection and maintenance of the main system pumps, pump motors, and heat exchangers are conducted in accordance with the manufacturer's guidelines and ASME Section XI requirements.
5.4.8 Reactor Water Cleanup System The reactor water cleanup system is an auxiliary system, a small part of which is part of the reactor coolant pressure boundary up to and including the outermost containment isolation valve. The other portions of the system are not part of the reactor coolant pressure boundary and are isolatable from the reactor.
5.4.8.1 Design Bases 5.4.8.1.1 Safety Design Bases The RCPB portion of the RWCU system:
- a. prevents excessive loss of reactor coolant, and
- b. prevents the release of radioa ctive material from the reactor.
LSCS-UFSAR 5.4-25 REV. 14, APRIL 2002 5.4.8.1.2 Power Generation Design Bases The reactor water cleanup system:
- a. removes solid and dissolved impurities from recirculated reactor coolant; b. discharges excess reactor water during startup, shutdown, and hot standby conditions;
- c. minimizes temperature gradients in the recirculation piping and vessel during periods of low flow rates;
- d. conserves reactor heat; and
- e. enables the major portion of the RWCU system to be serviced during reactor operation.
5.4.8.2 System Description
The reactor water cleanup system (Drawing Nos. M-97 and M-143) purifies the reactor water. The system removes water from the suction line of each reactor recirculation pump and from the reactor bottom head. The processed water is returned to the nuclear system or to storage.
A regenerative heat exchanger is provided to limit the loss of heat from the nuclear system. The cleanup system can be operated at any time during planned
operations, or it may be shut down when not required to clean up reactor coolant.
All the major equipment of the reactor water cleanup system is located near the reactor. This equipment includes pumps, regenerative and nonregenerative heat exchangers, and two filter-demineralizers with supporting equipment. The entire system is connected by associated valves and piping; controls and instrumentation provide proper system operation. Design data for the major pieces of equipment are presented in Table 5.4-1.
The reactor water clean-up pump motors are cooled by reactor building closed cooling water via a small heat exchanger supplied by the pump manufacturer. The pumps are also supplied with a small amo unt of purge flow from the control rod drive system, charging water header, at the base of the motor cavity. This was put in by the pump vendor to help prevent sediment from settling in the base of the pumps. However this purge flow is no t required for operation of the pump. (Drawing M-90, Sheet 3, M-97, Sheet 1, M-100, Sheet 1, M-136 Sheet 3, M-143 Sheet 1, and M-146 Sheet 1).
LSCS-UFSAR 5.4-26 REV. 14, APRIL 2002 Reactor water is cooled in the regenerati ve and nonregenerative heat exchangers, then filtered, demineralized, and returned to the reactor through the shell side of the regenerative heat exchanger. A proc ess diagram of the reactor water cleanup system is shown on Figure 5.4-6.
Because the temperature of the filter-demineralizer units is limited by the resin operating temperature, the reactor coolant mu st be cooled before being processed in the filter-demineralizer units. The regenera tive heat exchanger transfers heat from the influent water to the effluent water. The effluent returns to the reactor. The nonregenerative heat exchanger cools the influent water further by transferring heat to the closed cooling water system. The nonregenerative heat exchanger is designed to maintain the lower temperature even when the effectiveness of the regenerative heat exchanger is reduced by diversion of excess reactor water from the filter-demineralizer effluent to either the main condenser or the radioactive waste system.
The filter-demineralizer units (Figure 5.4-7) are pressure precoat type filters using filter aid and finely ground, mixed ion-exchange resins as a filter and ion-exchange medium. Spent resins are not regenerable and are sluiced from a filter-demineralizer unit to a resin receiver tank from which they are transferred in the radioactive waste system for processing and disposal. The suction line of the RCPB portion of the RWCU system contains two motor-operated isolation valves which automatically close in response to signals from the RCPB leak detection system. (Sections 5.2 and 7.6 describe the system, and it is summarized on Table 5.2-8). This action prevents the loss of reactor coolant and release of radioactive material from the reactor.
The outboard isolation valve also closes automatically to prevent removal of liquid poison in the event of standby liquid control system actuation and to prevent damage of the filter-demineralizer resins if the outlet temperature of the nonregenerative heat exchanger is high.
These isolation valves may be remote manually operated to isolate the system equipment for maintenance or servicing.
A remote manual-operated gate valve on the return line to the reactor provides long-term leakage control. Instantaneous reverse flow isolation is provided by at least one check valve in the RWCU or feedwater piping (Drawing Nos. M-97 and M-143). Two panels, a Material Monitoring System (MMS) and a Data Acquisition System (DAS), monitor the durability and effectiv eness of noble metal compounds deposited on reactor vessel and piping surfaces.
The MMS panel samples reactor coolant fr om the common discharge header of the RWCU pumps and returns reactor coolant to the common suction header of the RWCU pumps. The MMS panel contains metal coupons which are exposed to the LSCS-UFSAR 5.4-26a REV. 14, APRIL 2002 noble metal compounds during the NobleChem TM injection process. Periodically during the operating cycle, a coupon is removed from the MMS and analyzed for residual noble metals. The amount of residual metal is used in determining the most effective re-application schedule.
5.4.8.3 Safety Evaluation The RCPB isolation valves and piping are designed to the requirements defined in Section 3.2 and the requirements of Subsec tion 7.1.2.2. To prevent resins from entering the reactor recirculation sy stem in the event of failure of a filter-demineralizer resin support, a strainer is installed on the outlet of each filter-demineralizer unit. Each strainer has a control room alarm that is energized LSCS-UFSAR 5.4-27 REV. 13 by high differential pressure. A bypass line is provided around the filter-demineralizer units for bypassing when necessary.
In the event of low flow or loss of flow in the system, flow is maintained through each filter-demineralizer by its own holding pump. Sample points are provided in the influent header and effluent line of ea ch filter-demineralizer unit for continuous indication and recording of system conductivity. High conductivity is annunciated in the control room. The influent sample point is also used as the normal source of reactor coolant samples. Sample analysis also indicates the effectiveness of the filter-demineralizer units.
Operation of the reactor water cleanup syst em is controlled from the main control room. Resin-changing operations, which include backwashing and precoating, are controlled from a local control panel in the reactor building. Figure 5.4-8 shows the control and instrumentation logic.
5.4.9 Main Steamlines and Feedwater Piping 5.4.9.1 Safety Design Bases
The main steam and feedwater lines have been designed:
- a. to accommodate operational stresses, such as internal pressures and safe shutdown earthquake loads, without a failure that could lead to the release of radioactivity in excess of the guideline values in published regulations; and
- b. with suitable accesses to permit inservice testing and inspections.
5.4.9.2 Power Generation Design Bases The main steam and feedwater lines have been designed with the following power generation design bases:
- a. The main steamlines have been designed to conduct steam from the reactor vessel over the full range of reactor power operation.
- b. The feedwater lines have been designed to conduct water to the reactor vessel over the full range of reactor power operation.
LSCS-UFSAR 5.4-28 REV. 13 5.4.9.3 Description Steam piping is shown on Drawing No
- s. M-55 and M-116 and is described in Section 10.3. The feedwater piping is described in Subsection 10.4.7 and shown on
Drawing Nos. M-57 and M-118.
The feedwater piping consists of two 24-in ch nominal lines from the high pressure feedwater heaters to the reactor.
Each line includes three containment isolation valves consisting of one check valve inside the drywell and one check valve an d one motor-operated gate valve outside the containment. The design pressure and temperature rating of the feedwater piping between the reactor and manual valve is the same as that of the reactor feedwater nozzles (1300 psig and 575° F). The Seismic Category I design requirements are placed on the feedwater piping from the reactor through the outboard isolation valve and connected piping of 2-1/2 inches or larger nominal pipe size, up to and including the first is olation valve in the connected piping.
The materials used in the piping are in accordance with the applicable design code and supplementary requirements described in Section 3.2.
The general requirements of the f eedwater system are described in Subsections 7.7.4 and 10.4.7.
5.4.9.4 Safety Evaluation Differential pressure on reactor internals under the assumed accident condition of a ruptured steamline is limited by the use of flow restrictors and by the use of four main steamlines. All main steam and feedwater piping is designed in accordance with the requirements defined in Section 3.2. Design of the piping in accordance with these requirements ensures meeting the safety design bases.
5.4.9.5 Inspection and Testing Inspection and testing are carried out in accordance with Subsection 3.2.2. Inservice inspection is considered in the design of the main steam and feedwater piping. This consideration assures adeq uate working space and access for the inspection of selected components.
5.4.10 Pressurizer Subsection 5.4.10 is not applicable to this BWR power plant.
LSCS-UFSAR 5.4-29 REV. 13 5.4.11 Pressurizer Relief Tanks Subsection 5.4.11 is not applicable to this BWR power plant.
5.4.12 Valves
5.4.12.1 Safety Design Bases Line valves such as gate, globe, and check valves are located in the fluid systems to perform a mechanical function. Valves are components of the system pressure boundary. Having moving parts, they are designed to operate efficiently to maintain the integrity of this boundary.
The valves operate under the internal pressure/temperature loading as well as the external loading experienced during
the various system transient operating cond itions. The criteria are as required in Subsection 3.9.3 for ASME Class 1, 2, and 3 valves. Compliance with ASME Codes is discussed in Subsection 5.2.1.
5.4.12.2 Description Line valves are the standard manufactured types, designed and constructed in accordance with the requirements of Section III of the ASME Code for Class 1 and Class 2 valves. All materials, exclusive of seals and packing, are designed for the 40-year plant life when appropriate maintenance is periodically performed.
Power operators have been sized to operate under the maximum differential pressures determined in the design specification, and are designed as Class 1E components, in compliance with the requirements of IEEE-308.
5.4.12.3 Safety Evaluation Line valves have been production tested in the shop by the manufacturer for performability. Pressure-retaining parts are subject to the testing and examination requirements of Section III of the ASME Code. To minimize leakage past seating surfaces, maximum allowable leakage rates are stated in the design specifications for both the back seat and the main seat for gate and globe valves.
Valve construction materials are compatible with the maximum anticipated radiation dosage and the environmental cond itions for the service life of the valves.
5.4.12.4 Inspection and Testing
Valves serving as containment isolation valves and which must remain closed or open during normal plant operation may be partially exercised during this period to assure their operability at the time of an emergency or faulted conditions. Other LSCS-UFSAR 5.4-30 REV. 13 valves, serving as system block or throttling valves, may be fully exercised without jeopardizing system integrity for the same reason.
Leakage from certain valve stems is monitored by use of double-packed stuffing boxes with an intermediate lantern leakoff connection for detection and measurement of leakage rates.
Motors used with valve actuators have been furnished in accordance with NEMA Standard MG-1, Parts 10.35, 10.36, and 10.
61, as applicable. Each motor actuator has been assembled, factory tested, and adju sted on the valve for proper operation, position and torque switch setting, position transmitter function (where applicable), and speed requirements. Valves have been tested to demonstrate adequate stem thrust (or torque) capability to operate the valve within the specified time at the specified differential pressure. Tests also verified that no mechanical damage occurred to valve components during full st roking of the valve. Suppliers were required to furnish assurance of accept ability of the equipment for the intended service based on any combination of:
- a. test stand data, b. prior field performance, c. prototype testing, and
- d. engineering analysis.
Representative models of motor operators have been subjected to special seismic qualification tests in order to ensure compliance with the LSCS plant requirements.
5.4.13 Safety/Relief Valves 5.4.13.1 Safety Design Bases Overpressure protection has been provided at isolatable portions of systems in accordance with the rules set forth in the Nuclear Pump and Valve Code. An overpressure protection report was written to document compliance with the requirements of Article NB-7000 of Section III of the ASME Code.
5.4.13.2 Description Pressure relief valves have been designed and constructed in accordance with the same code class as that of the line valves in the system.
LSCS-UFSAR 5.4-31 REV. 13 Table 3.9-2 lists the applicable code classes for valves and system design pressures and temperatures. The design criteria, design loading, and design procedure are as described in Subsection 3.9.2.
5.4.13.3 Safety Evaluation The use of pressure-relieving devices assures that overpressure does not exceed 110% of the design pressure of the system. The number of relieving devices on a system or portion of a system was determined on an individual component basis.
5.4.13.4 Inspection and Testing
No provisions are made for in-line testing of pressure relief valves. Certified set pressures and relieving capacities are stam ped on the body of the valves by the manufacturer, and further examinations would necessitate removal of the component.
5.4.14 Component Supports
Support elements are provided for those components included in the RCPB and the connected systems.
5.4.14.1 Safety Design Bases Design loading combinations, design procedures, and acceptability criteria are described in Subsection 3.9.3. Flexibility calculations and seismic analysis for Classes 1, 2, and 3 piping components conf orm with the appropriate requirements of ASME Section III.
Spacing and size of pipe support elements were based on the piping analysis performed in accordance with ASME Section III and further described in Section 3.7. Standard manufacturer hang er types were used and fabricated of materials per ANSI 3.1.7 for hangers released for fabrication prior to December 1973, and per ASME Section III, Su bsection NF for hangers released for fabrications after that date.
5.4.14.2 Description The use and location of rigid-type supports, variable or constant spring-type supports, and anchors or guides were determined by flexibility, stress, and seismic analysis. Component support elements are manufacturers' standard items.
LSCS-UFSAR 5.4-32 REV. 18, APRIL 2010 5.4.14.3 Safety Evaluation Design loadings used for flexibility and seismic analysis toward the determination of adequate component support systems included all transient loading conditions expected by each component. Provisions were made to provide spring-type supports for the initial deadweight loading due to hydrostatic testing of steam systems to prevent damage to this type of support.
5.4.14.4 Inspection and Testing After completion of the installation of a support system, all hanger elements were visually examined to assure that they were in correct adjustment to their cold setting position. When hot startup operations began, thermal growth was observed to confirm that spring-type hangers functi oned properly between their hot and cold setting positions. Final adjustment capability was provided on all hanger or support types.
5.4.15 Hydrogen Water Chemistry System
The purpose of the Hydrogen Water Chem istry (HWC) program at LaSalle County Station is to reduce rates of intergranular stress corrosion cracking (IGSCC) in recirculation piping and reactor vessel intern als. This is accomplished by injecting hydrogen into each unit's condensate booster pump suction header to suppress the formation of radiolytic oxygen in the reac tor coolant. Suppres sion of dissolved oxygen, coupled with high purity reactor wa ter, reduces the susceptibility of reactor piping and internal materials to IGSCC. The HWC system is designed to provide up to a 0.45 ppm feedwater hydrogen level (25 scfm design maximum injection rate). Oxygen, as a constituent of air, is injected into the off-ga s system as part of this process in order for it to combine with excess hydrogen prior to entering the off-gas recombiners. The HWC system is non-safety related.
Intergranular stress corrosion cracking is discussed in Section 5.2.3.2.1.
In addition, through General Electric's noble metal chemical application (NMCA)
NobleChem process, noble metal compounds (platinum and rhodium) are periodically injected into the reactor vessel. The NobleChem process deposits a minute, discontinuous layer of noble me tal significantly reducing the oxidant potential, which allows for significantly lower HWC hydrogen addition rates, which could in turn result in significantly lowe r operational dose rates from main steam line radiation. Another potential benefit of noble metals is that additional components, which may not achieve the re commended ECP value with HWC alone, may do so with noble metals.
LSCS-UFSAR 5.4-33 REV. 18, APRIL 2010 5.4.15.1 Hydrogen Injection System 5.4.15.1.1 Design Basis The hydrogen injection system is designed to be capable of attaining and maintaining the following water chemistry limits in the reactor coolant to mitigate the potential for IGSCC.
A. Electrochemical Corrosion Potential below -230 mv (SHE);
B. Reactor water conductivity of less than 0.3 mS/cm.
5.4.15.1.2 Description Hydrogen is supplied from a cryogenic hydrogen storage system installed approximately 2012 feet northwest of the ne arest safety-related structure. An excess flow check valve at the hydrogen supply site restricts flow from a broken downstream line. The HWC system is desi gned to operate down to approximately 2% power.
The Hydrogen Flow Control Module 1(2)P73-P100 provides flow control, flow measurement, pressure indication and isolation of hydrogen flow for the hydrogen gas supply system. The Hydrogen Inje ction Module 1(2)P73-P150 provides a location for hydrogen injection and permissive based on sufficient condensate flow through the injection device. The Hydrogen Isolation Panel 1(2)P73-P400 provides shutoff of hydrogen near the hydrogen lines entrance into the Turbine Building facility.
A single flow control valve train is used for hydrogen injection into the condensate/feedwater stream through a side stream water path across the condensate booster pump. This path resu lts in a net loss of approximately 100 gpm of water from the condensate booster system downstream of this injection loop. The single hydrogen injection point contains a check valve to prevent water from entering the hydrogen line. Automatic is olation is provided to prevent hydrogen injection when no condensate flow is dete cted. Connections are provided to allow hydrogen piping to be completely purged of air before hydrogen is introduced into the line. The purge inlet is near the injection point and the purge outlet is near the 1(2)P73-P400 panel. Suitable valves are provided to cross connect the purge outlet to the hydrogen vent line, which is rout ed to the Turbine Building exterior to a flame arrestor.
5.4.15.2 Oxygen/Air Injection System LSCS-UFSAR 5.4-34 REV. 18, APRIL 2010 5.4.15.2.1 Design Basis The oxygen/air injection system is designed to inject sufficient oxygen (in air) into the off-gas system to ensure that the ex cess hydrogen in the off-gas stream is recombined. This prevents the hydrog en concentration from reaching the combustibility limit of hydrogen in air.
5.4.15.2.2 Description A cryogenic oxygen storage system instal led approximately 680 feet northwest of the nearest safety-related air intakes previously supplied oxygen to the Oxygen Flow Control Module 1(2) P73-P200. This oxygen supply has been isolated and abandoned in place or removed, and servic e air with oxygen as a constituent is supplied instead.
The Oxygen Flow Control Module 1(2)P 73-P200 provides flow control, flow measurement, pressure indication and isolation of air flow. A single flow control valve train is used for air injection into the off-gas system between the last stage steam jet air injector and off-gas preheater for each recombiner train. Each injection point contains a check valve to prevent off-gas from entering the air line. The normal oxygen injection rate is 50% of the hydrogen injection rate but may be adjusted between 40% to 60% of the hydrogen injection rate. There is a delay in the air injection to compensate for the transport time from the hydrogen injection point to the air injection point. Automatic isolation is provided for all HWC system trips. An outside vent is provided for the oxygen flow control module to facilitate testing and calibration activities.
5.4.15.3 Tests and Inspections The functional operability of the HWC system, including verification of the appropriate time delay for hydrogen and air ramp rates, was initially tested at time of system installation.
The station preventative maintenance program includes inspections of the HWC system. Retesting requirements for the system are based upon General Electric recommendations, and consider extended HWC system shutdown periods and other factors not consistent with normal system operation.
5.4.15.4 Instrumentation Applications
The HWC Control Panel 1(2)P73-P500 prov ides processing of signal inputs, determination of alarm and shut down conditions and output of data and shutdown signals. The panel supplies alarm status and display, process parameter displays and operator interface capabilities. Output terminals are supplied that provide LSCS-UFSAR 5.4-35 REV. 18, APRIL 2010 signals to the control room for remote (plant control room) shutdown and alarm status. Process data is stored locally in the 1(2)P73-P500 panel computer and can be output on a portable disk drive. The hydrogen and air flow rates can be controlled manually or automatically. In the Automatic Power Determined Setpoint mode the controller varies hydrogen and de layed airflows as a function of reactor power, which is based on feedwater flow rate, to maintain a constant hydrogen concentration in the feedwater. A constant hydrogen injection flow is maintained when reactor power is 20% or lower. The controller also initiates a variety of alarms and HWC isolations, which are su mmarized in Table 5.4-2. Control room interfaces for the HWC system are provid ed on off-gas panels 1(2)N62-P600 and 1(2)N62-P601.
5.4.15.5 Performance Analysis Station personnel will maintain water quality consistent with Corporate and Site Specific Procedures in order to maximize the effectiveness of the HWC system in mitigating the occurrence of IGSCC.
Combination dissolved hydrogen/oxygen mo nitors are installed on the reactor feedwater, reactor recirculation loop "B" and reactor water clean-up inlet sample lines. Inputs from this new equipment in conjunction with other existing station chemistry inputs are used during HWC sy stem operation as secondary parameters to determine the effectiveness of the HWC system for protection of reactor core internals. In-situ tests for the Electroche mical Corrosion Potential levels in the reactor vessel were performed to validate the effectiveness of these parameters.
Combustible gas monitoring is discussed in Section 7.7.10.
5.4.16 References
- 1. "Design and Performance of Ge neral Electric Boiling Water Reactor Main Steam Line Isolation Valves," APED-5750, General Electric Co., Atomic Power Equipment Department, March 1969.
- 2. Letter from R. E. Spencer (Gener al Electric) to W. R. Huntington (CECo) on RHR System Operation dated October 31, 1986.
- 3. Power Uprate Project Task 300, "Nuclear Boiler," GE-NE-A1300384-28-01, Revision 0, October 1999.
- 4. Power Uprate Project Task 310. "R esidual Heat Removal System," GE-NE-A1300384-12-01, Revision 0, October 1999.
- 5. NUREG-0800, Section 3.6.2, BTP MEB 3-1, Revision 1 - July 1981.
LSCS-UFSAR TABLE 5.4-1 TABLE 5.4-1 REV. 13 REACTOR WATER CLEANUP SYSTEM EQUIPMENT DESIGN DATA
- MAIN CLEANUP RECIRCULATION PUMPS Number Required - 1 Design temperature ( °F) - 575 Capacity (each) - 100% Design pressure (psig) - 1450 Discharge head at rated flow (feet) - 500 Minimum available NPSH (feet) - 13 HEAT EXCHANGERS REGENERATIVE NONREGENERATIVE Shell design pressure (psig) 1425 150 Shell design temperature (°F) 575 370 Tube design pressure (psig) 1425 1425 Tube design temperature (°F) 575 575 FILTER-DEMINERALIZERS Type - pressure precoat Number required - 3 (2 active, 1 standby)
Capacity (each) - 50%
Flow rate per uni t (lb/hr) - 66,500 Design temperature (°F) - 150 Design pressure (psig) - 1400
__________________
- System Flow Rate (lb/hr) - 133,000 LSCS-UFSAR TABLE 5.4-2 TABLE 5.4-2 REV. 18, APRIL 2010 HYDROGEN WATER CHEMISTRY SYSTEM ALARMS AND ISOLATIONS
Parameter
Alarm Isolation Hydrogen Flow Setpoint error, High High Hydrogen Pressure Low, High High Air Pressure High, Low Low Air Flow Setpoint error Hydrogen Area High, High-High, Monitor Malfunction High-High Hydrogen Supply System Trouble, System Trip System Trip Offgas Monitor Trouble, Isolation, Monitors in Test High hydrogen, Isolation,Monitors in Test Hydrogen Injection Module Water Flow Differential Pressure Low Low HWC System Purge Purge Circuit Activated Programmable Logic Controller Operator Interface Unit Trip, Programmable Logic
Controller Fault Programmable Logic Controller Fault Local Local Demand Shutdown Pushbutton Depressed Manual Control Room Control Room Shutdown Switch in Shutdown, Trouble, Trip Manual Reactor Scram N/A Reactor Scram
LSCS-UFSAR REV. 19, APRIL 2012
FIGURE 5.1-1 Intentionally Deleted.
See Figure 1.2-1 for Unit 1 and Unit 2 operating conditions.
- LSCS-UFSARVOLUMEOFFLUID(ft')*A.LowerPlenum3790BCore2065+30ttl**CUnnerPlenumandSeparators2300DDome(Abovenormalwaterlevel)7340E.DowncomerRee:ion5320F.RecirculationLoopsandJetPumps1030*DRIVINGFLOW____.....MAINSTEAMFl.OWTOTURBINEMAINFEEDFl.OWFROMTURBINE****ThevaluesinthistablearetypicalcoolantvolumesforaBWR-5.Fuel/Channeltypedependentvalue.LASALLECOUNTYSTATIONUPDATEDFINALSAFETYANALYSISREPORTFIGURE5.1-2COOLANTVOLUMESREV.13 D V , C r A r-B (fltX)
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1:,..: LA SALLE COUNTY STATION UPDATED FINAL SAFETY ANALYSIS REPORT Fl GURE 5. 1-3 REACTOR COOLANT SYSTEM ELEVATION DRAWING REV. 0 -APRIL 1984 ASSUMED LIFT CHARACTERISTIC ASME CODE APPROVED SAFETY VALVE CAPACITY (40I I 60-100l-V<<a..<<V w<<..J a..w<<z w>..J<<>W l.L.<<(J)l.L.oo...J l.L.<<w(J)20.96.97.98.99 1.00 101 102 103 1 04 INLET PRESSURE SET PRESSURE LA SALLE COUNTY STATION UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 5.2-1 TYPICAL DUAL SAFETY/RELIEF POP VALVE CAPACITY CHARACTERISTICS REV.0-APRIL 1984 o 100\.r ReHef Valve Opening Characteristics t.........::z:..JW p,.WO>..J..J<<..J50ec::....0 0..J en WN:;:::1::-W>oenj....!-<:::::J W enu S=S en....we..JI:!:: I e:t::o<<!-<*0-<Q.,..J>til)000.-<.3 tl Time (sec)100 I Safety Valve t.....Opening....::z: Characteristics
..JW r...wo50WO:<N to-Time (sec)tl*T1=e at which pressure exceeds the valve set pressure LA SALLE COUNTY STATION UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 5.2-1a POWER ACTUATED AND SAFETY ACTION I VALVE LIFT CHARACTERISTICS J REV.0-APRIL 1984 1.0 0.8->...-Ililj...ZUI-tr t...0.8 z-::lZ tr::l Ula: o..UI I'"ZI 2t: t>0.4......Jill OU: j!:2 z":818 SCRAM ROD DRIVE TIME Iuc:I REV.13\SCRA'" CUIWE UTILIZED IN OVERPReSSURE ANAL YSIS LASALLE COUNTY STATION UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 5.2*2 TYPICAL SCRAM ROD DRIVE AND SCRAtvl REACTIVITY Tlrvm CHARACTERISTICS (INITIAL CORE)
LSCS*UFSAR 1450,.....---
-, BWFl/5 251 PLANT MSIV CLOSURE-14.01 Itf'lte VOID COEFFICIENT 1400 1350 1300 1250 PRESSURE SCRAM FLUX SCRAM IOOYNf*POSITION SCRAM D 1200...-------...-------....-------..........
.......40 60 80 100 120 SAFETY VALVE CAPACITY t'4"18 RATED STEAMFLOWI 8 10 12 14 NUM8ER OF Ol"EFlATING SAFETY VALVES 16 18 LASALLE COUNTY STATION UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 5.2-3 (TYPICAL)PEAK VESSEL PRESSURE VS.SAFETYfREUEF VALVE CAPACITY REV.13 LSCS-UFSAR
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- lE<'" u'".....>..J<:>.,..........<'1!: III LASALLE COUNTY STATION UPDATED FINAL SAFETY ANALYSIS REPORT r Less than 18 SRVs may be assumed in cycle-specific reload analyses.The information shown is historIcal, a new analysis based on 13 installed SRV's has been performed and accepted by the NRC, see References 13 and 14, FIGURE 5.2-4 (INITIAL CORE)TIME RESPONSE OF VESSEL PRESSURE FOR MSIV CLOSURE TRANSIENTS REV.15, APRIL 2004 LSCS-CFSAR 0:>"'*1 I z...11/a: o"'0<...ZU.....0...Wilt"'0<...zu...OW III.."'0<...ZU!ilo.....!::-....l.""'_.J-__-IL--I..-I..-I..
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- LEVER'\\\Yl.,.L_IN_D_E_R-t\DISC r SETPAESSURE
/SPFlINGtSi BACK PRESSURE BALANCING DEVICE STEAM DISCHARGE LA SALLE COUNTY STATION UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 5 0 2-4c GRAPHIC OF SAFETY/RELIEF VALVE WITH AUXILIARY ACTUATING DEVICE REV.0-APRIL 1984 LSCSUFSAR U LJ.J U1 o o (\J o o o-0 o 8 o 8 LASALLE COUNTY STATION UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 5.24d MSIV CLOSURE FLUX SCRAM EVENT 102P/105F, NOMINAL+3%, 8 SRVs OOS REV.14, APRIL 2002 I LSCSUFSAR 00 U LiJ N(J).'-" o ($)SlN3NOdWOJ
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0 N 8 I 8 mLASALLE COUNTY STATION UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 5.24e MSIV CLOSURE FLUX SCRAM EVENT 102P/105F, NOMINAL+3%,8 SRVs OOS REV.14, APRIL 2002 I LSCSUFSAR co U LL..I (J)o V>o o o Lf)
.0 o B 8 mLASALLE COUNTY STATION UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 5.2Af MSIV CLOSURE FLUX SCRAM EVENT 102P/105F, NOMINAL+3'!!,,8 SRVs OOS REV.14, APRIL 2002 I LSCS-UFSAR co U LlJ c.n o o to o o (\j o o........0 o 8 8 mLASALLE COUNTY STATION UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 5.2-4g MSIV CLOSURE FLUX SCR/\M EVENT 1 02P/1 05F, NOMINAL+3%, 8 SRVs OOS REV.14, APRIL 2002 I
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SAFETY RELIEF VALVES MAIN STEAM ISOLATION VALVES DRYWElL REACTOR VESSEL MAIN STEAM LINE SUPPRESSION POOL LA SALLE COUNTY STATION UPDATED FINAL SAFETY ANALYSIS REPOR1 FIGURE 5.2-6 SAFETY/RELIEF VALVE SCHEMATIC ELEVATION REV.0-APRIL 1984 MAIN STEAM ISOLATION VALVES c MAIN STEAMLINES REACTOR veSSEL B<8>These valves permanently removed as part of SRV Reduction Modification.
LASALLE COUNTY STATION UPDATED FINAL SAFETY A..I\JALYSIS REPORT FIGURE 5.2-7 SAFETYiRELIEF VALVE SCHEMATIC PLAN REV.15, APRIL 2004 I-, LSCS-UFSAR IHISTORICAL]I.NOH*NUCLIAR HtATUP/COOU>OWN UlUT 1400 C*COR.!CUnCA.L LIKn'CRJ')PDiITlATION llJtITS WITH RT NOT-SS-, c 1000-.*....*0--600=i**.....400 200 312 PSIC"...!OL'TUP LIMIT lO-Y , , , ,.,.,., ,."';"..;WlTH llT mrr-40*'*0 o 100 200 300 LASALLE COUNTY STATION UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 5.2-8 Unit 1 Pressure-Temperature Operating Limits Valid to 16 EFPY REV.14.APRIL 2002 I LSCSUFSAR[HISTORICAL]
II.*nu;.s:;UJU:.1"&.:i 1: u.ru.l B*NON*NtlC1..tA.R HV.'IUP/COOt.IlO\l'N UHIT 1-.C 1400 C*COllE cunc:.u.UKl'I 1200..BEJ.n.INE UKITS WUH A a.c.1.99, l!V..2 SHIFT OF 11S*'Flott AN IHITIAi.ll'I NDT OF*30*'.*I 1000"It:.**:II a.:.800:z S.....*...*.......600*..i**....I**I**'., I, I ,I'..312 PSIG 200 o a IOLTUl'LIKIT 80*',I I'*I*I.I FEEJ)VA,T!ll NCZZU UlIITS::\illH R1imr-40*" 100 200 D'V Mat:.a1'f.-pu&tlIre (Op)LASALLE COUNTY STATION UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 5.2-8a Unit 1 Pressure-Temperature Operating Limits Valid to 32 EFPY 300 REV.14, APRIL 2002 I LSCS-UFSAR
[HISTORICAL]
'"-P1lE.SStJU nsT LI!UTB-NON-NUCLEAR HtATUPI COOl-OOlolN LlKIT 1400C-COllE c:unc.u.LIKIT.!£1.n.INE LlKITS\1ITH A It.C.1.99, lEV.2 SHIFT OF 16*'raOK AN INITIAL ItT NDT OF 52*',.1000 A*c , FEEDIolATEIl NO%%LE UIII'l'S.VIm I.TlfDT-/04., o o ,.10D 200 RPV Metal Temperature COF)300 LASALLE COUNTY STATTON UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 5.2-9 Unit 2 Pressure-Temperature Operating Limits Valid to 16 EFPY REV.14, APRIL 2002 I LSCSUFSAR[HISTORICAL]!.NON*NUC'UAJI.HIAT'O'l/COOl.DO\11'f LIKITIC 1400 C*COIlE CRlnCAL LIMIT 8nTUIfE LIMITS\11TH A I.C.1.99, REV.SHIFT OF 23-'FlClK All INITIAL 1200 IT NDT or'2-'," 1000""**Ii: Dopo 800:z S........*Do.....600 e I tt.00 FEEJ)\lATEIl lfOZ%LI UKITS VITH RT tmr-40-'.t" o o 100 ZOO In Ketal T..,-aClrra (on 300 LASALLE COUNTY STATIONUPDATEDFINAL SAFETY ANALYSIS REPORT FIGURE 5.2-9a Unit 2 Pressure-Temperature Operating Limits Valid to 32 EFPY REV.14, APRIL 2002 I 1000.---------------'------------------, 800 600 400 200 100';;...0 80-';....60.....0 ,., 40 20 15 10*6 2*AXIALLY ORIENTED CRACK*SATURATED WATER SYSTEM AT 1000...*ASTERISKS DENOTE CRACK OPENING OF 0.1 in.lL..1..LL._..J-L..-__-'-__...J.....__.......__...J.......__....__--'o 4*1216202428 32 36 CRACK LENGTH lin.}LA SALLE COU NTY STATION UPDATED FINAL SAFETY ANALYSIS REPORTFI GU RE 5.2-11 CALCULATED LEAK RATE AS A FUNCTION OF CRACK LENGTH AND APPLIED HOOP STRESS REV.0-APRIL 1984 13,...-------------------------------,.--, IS 9 10 1.8 1.6 1.4 1.2 1.0 0.8 0.6 0." OATA CORRELATION Qc*CRITICAL CRACK lENGTH lin.)o*MEAN PIPE DIAMETER (1h*PIPE HOOP STRESS MATERIAL-Al068 0.2 OL..__...L..L-__-l.....__....1.....__-ol-I-__-ol o 11 10 12 12 8 0 Qc/O*15,OOO/ch III 7)(15 J:.M.!;(:)--6)(r." 0 5 0 20 0 0 4 0 25 0 GE DATA (-600FI 30 3 00 0 BMIOATA 0 00..0 0 0 2 (UNFLAWEOI 50 60 70 QclO LA SALLE COUNTY STATION UPDATED FINAL SAFETY ANALYSIS REPORTFI GU RE 5.2-12 AXIAL THROUGH-WALL CRACK REV.0-APRIL 1984 LSCS-UFSAR i i I II_I PTus (PSI:****
SaI.IV\lIN.Flow 150.0....---Co", Inlet Flow 300.0 f-A....'VINe Flow I..Bypass V&lWI Flow'.." 100.0 ,,200.0 II)-'CD iii--'iii_.a::....-a::.-.-"'..:-.......50.01-10Q.0 f 0.0 0.0 0.0 4.Q a.o 0.0 4.Q 8.0 TIfTl8 (sec)Time (sec)I.Q 1.0....'..\.....1.'.\,..,'\\.\1 I.I-Z'OL.-__......\:lI-__"""-__.....0.0 4.Q lime (sec)a.o 4.Q Tme (sec)....."-I SIiIlIm!=low 2IlD.o...---T..,..StMrn!=low---
ur-10Q.01-...:......__--J 0.0" 10Q.0....-..-....CD".,**!',,',.'\---'.',.'.-._:..........
.,--"'..:.a.--
_::l:'..l'..'..........
-_-_-_-:=00-1
" LASALLE COUNTY STATION UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 5.2-13 GE MSIV CLOSURE, HIGH FLUX SCRAMREV.13 LSCS-UFSAR CORE POWER-lllQ"QJ----..,-----r-----r-----,-----:"!:'---":!t2.0UUTII£SECON>S LASALLE COUNTY STATION UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 5.2-14 SPC MSN CLOSURE, HIGH FLUX SCRAM SYSTEM RESPONSE (TYPICAL)REV.13 LSCS-UFSAR 14OOJ).,------------
.......---------------....., 1300.0<iii D...LlJ(I)(I)LlJ a:: D..t11X1DLlJ-'Go.ffi ttmD0-'1GoD ID.D LASALLE COUNTY STATION UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 5.2-15 SPC MSIV CLOSURE, HIGH FLUX SCRAM PRESSURE RESPONSE (TYPICAL)REV.13 STEAM DRYER AND SHAOUD HEAD ALIGNMENT AND GUIDE BAAS CORE DIFFERENTIAL PRESSURE TAl'at LIQUID COIlfTRQL INLET NOZZLE CONTROL ROD GUIDE TUSE RECIRULATING WATER OUTLET NOZZLE t STEAM SEPARATOR AND 1_ST ANDP,PE ASSEMBLY INLET NOZZLE:-fflr----
FEEOWATER SPARGER SPRAY SUPPLY HEADER I"l VESSEL WALL TOP FUEL GUIDE I LPCI NOZZLE/COUPLING SHROUD HEAD ALIGNMENT 7'f==f!:=:::::::.
__PINS CORE SPRAY SPARGER r:"'r-+-++-----+=UEL ASSEMBLY FUEL SUPPORT PIECEFLOW INLET INTO FUEL BUNDLE CORESHAOUD CORE PLATE ASSEMBLY CORE PLATE SUPf"ORT VELOCITY LIMITER SHROUD HEAD LI FTI NG LUGS INCORE FLUX MONITOR HOUSING/:::PAAE lTEMPOAARY INSTRUMENTATION)
/HEAD SPRAY VENT NOZZLE"I-il>/-,-""'" DRYER ASSEMBLY LIFTING LUGS 7t DRYER SEAL SKIRT
....".".,'<:'..." SHROUD HEAD CORE SPRAY SUPPLY SHROUD HEAD__
HOLD DOWN BOLTS SHROUD HEAD FLOOR SUPPORT LUGS JET PUMP NOZZLE ASSEMBLY RISER STABILIZER INCOAE FLUX MONITOR JET PUMP BODY RECIRCULATING WATER INLET NOZZLE JET PUMP INLET RISER JET PUMP DIFFUSER DIFFUSER SEAL RING AND SHROUD SUPPORT PLATE VESSEL SUPPORT SKIRT , I LA SALLE COUNTY STATION UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 5.3-1 REACTOR VESSEL CUTAWAY REV.0-APRIL 1984 LSCS*UFSAR HIGH WAnFl LEVEL ALARM 5&Il.l)HOI'IMAL WA TEfl I.EVEL...'O LOWWATl!A LEVEL ALARM SHJ)lfol'EI.OWALL TOIl'AC\'lVf'UEL.366.5*STEAM LINE NOZ%L£...'O HIGIoIWATER l.EVEL 5&3.D l.OW WATER LEvEL SCAAM!OoIQ.O'UOWAnR NOZZLE 493.25 l.OW WATER l.EVEL ,.,."_17.S Ices IHITIATION LEVEL itS.S 10TTOIiIl ACTIVEI'UEL 216.5*."ECIRCULATION OUTI.!T NOZZLl 172.5..366.5 and 216.5 are instrumentation setpoints for T AF and BAF.respectively.
The physical top of active fuel is366.31" above vessel zero.The physical bottom of active fuel is 216.31" above vessel zero."EClfilCULATIQN INLET HOZZl.E'".0 TlON o.&:lOC)om
- LASALLE COUNTY STATION UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 5.3*2 REACTOR VESSEL NOMINAL WATER LEVEL TRIP AND ALARM ELEVATIONS REV.13
- REACTOR VESSEL TEST CONNECTION 10211-151""'IN STEAM...INE I ISOLATION VALVESSTEAM FLOW RESTRICTOR_.r PRIMARY CONTAINMENT r"..II**LA SALLE COUNTY STATION UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 5.4-1 MAIN STEAMLINE FLOW RESTRICTOR LOCATION REV.0-APRIL 1984
- HELICAL SPRINGS..
LANTERN RING----I-J.....J CLEARANCE PILOT SPRING AIR CYLINDER.....
HYDRAULIC DASH POT SPRING GUIDE SPEED CONTROL VALVE rn--__ACTUATOR SUPPORT AND SPRING GUIDE SHAFT I'j------SPRING SEAT MEMBER 1...._.1--1-----
STEM STEM PACKING LEAK OFF CONNECTION BONNET BOLTS BONNET BODY POPPET (PLUG, MAIN DISK)MAIN VALVE SEAT PILOT SEAT LA SALLE COUNTY STATION UPDATED FINAL'SAFETY ANALYSIS REPORT FI GU RE 5.4-2 MAIN STEAMLINE ISOLATION VALVE REV.0-APRIL 1984 D c B A UQ5M--...'T1--1"-1.,., 1 FIGURE 5.4-3 LASALLE COUNTY STATION UPDATED FINAL SAFETY ANALYSIS REPORT REACTOR CORE ISOLATION COOLING SYSTEM PROCESS DIAGRAM 2-.too 11*UAaI ftll_'.C....t IlM...1'OlII'L f....,.
=.:::-:."ft........U..........
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fuw MI II'ItI-.uft...........,,, 1f*..,.....,"'" ,."'" , ,...CI:",M ttl........." ,'-"..It.co" ,td_II..ft."..., 1..-.._1IIl(.1t..alta*...,.ff...,....,"'.
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....e***It..I I" I'11 , , II-_I..B o A c 5 4 3 2 1 Rev.14, APRIL 2002 j.I 1 ,I f-L....;11.-'......>""'":..<\L REV.7-APRIL 1991 LA SALLE COUNTY STATION UPDATED FINAL SAFETY ANALYSIS REPORT J I II I FIGURE 5.4-4 REACTOR CORE ISOLATION COOLING SYSTEM FLOW CONTROL DIAGRAM (SHEET 1 OF 5)*
2 3 j 11 12 A OPEN OC o B E RCIC JNIT1ATJON SIGNAL H K..PUMP DISCHARGE VALVE MO fOl3 (TY?FOR PUMP DISCH VAL V[MO 1"0(2)NOTE 5 COUNTY STATION ANALYSIS REPORT GURE 5.4-4 ISOLATION COOLING SYSTEM CONTROL DIAGRAM (SHEET 2of'5)2 3" REV.0-APRIL 1984
.." VALVES MO FOU.140 Fon L VALVES AQ f004, FODS.f025.F026&F054<o/CO o 1984 4 COOLING SYSTEM DIAGRAM 5)NTY STATION ANALYSIS REPORT 12 T ABLE II TURBINE INDICATING LIGHTS c 10 12 c T ABLE II TURBINE INDICATING LIGHTS 10
...,--_a*II!8.JI*.,..J!IWIW Q!I!II" 1""1ClIL,*....*AQlIIl....11"-'...a._jmUL""1""W MY rr:......a....-POll"'" At-_I"I".,._&..!IlIIlmI.1.," or"11010...\.-II'Ill ICQM , CM.*1UC1II1CM.)
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'0 LOCII'.....".""l!U1'O"..."STMIT*_..LA SALLE COUNTY STATION UPDATED FINAL SAFElY ANALYSIS REPORT*FIGURE 5.4-4 REACTOR CORE ISOLATION COOUNG SYSTEM fLOW CONTROL DIAGRAM (SHEET 5 OF 5)BY.10 MaIL 1994
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....,.,_"'__"'........k.,.,.P...."'.....,---it---a__I I.4PL NO.E12-1020 MllIlE:i;A-l.ACCIDENT WIlH RECIRCULATION UNE aREAl<IN EIlHER SIDE I\ND THREE PUMP OPERATION.
ONE STRAINER SII" PLUCCED.A-2.ACCIDENT WIlH RECIRCULATION UNE BREAI<IN EITHER SIDE AND a.wllH HEAT REJECTION WIlH DNE PUMP DPERATION AND STRAINER 5IlI PLUGGED.(P_SUPPRESSION POOl TEllPERATURE.)
D.NORIoW..SH!ITDDWN AFTER F1.DWDDWN TO llAIN CONDENSER.
£.CONTINUATION OF_SHUTDOWN FROM PWIT lIDOE*r:r (AT*PSIC)AND FUNCTIONAL PUllP TEST AFTER SHUTDOWN.F.RHR S>'STEll TEST DURINC PLANT OPERATION.
C.MINIMUM FI.DW IJ!'PASS lIDO£.S.SYSTEM ON STANDBY DUlY.LOOP C olD¥>I"'If" 17 (SUA/orr No}MODEF , POSI11DNQ 1 Z 6.,6."., 8 19 10 lSI 24 I GPltI-jlO I SO-I'IfIiSS AI,..No7XXXXXxx;.-,:X ,X 147 ff!Mp'7-:Yo 1-I'%"-MAr MaS"",.&107.i::::-I PI'O" FEET I::-: 1___--....-.......1-."LOOI'A TUT"LOOl'TEn a J.Elil::!iIl Rl<PRESS----REJCrIlR VESSEl PRESSURE TOH---------TOT"!.DYlWIIC HEAD SOH SHUfOfT HEAD l!!H HOO l.OSS"" PRESSURE l.OSS!IIIPI'I.I:llEI"!.
OOCUlll:lfrS UNDER THE FOUOWlNG 1_lTIa ARE TO lIE USEil IN CDNJUCTlON WIlH THI$_NIl.IlEf"ERERCE,.REllIDU"l.
MfAT\l£llDV"!.
""ID E12-1'1.2.REllIDU"l.
MfAT\l£llDV"!.
DESICIl SPEl:.EI2-4111' m:\.5.LOW PRESSURE CORE SPRAY Pro-----£21-te2.1.DELE!tD.2.
EMPiY DATA BlANKS CAN BE FTLl£D IN BASED DN ACTUAl.ARRANGEMENT THE DATA IS NOT SIGNIFTCANT.
3.SHDWN AS TYPICAl.FOR ONE lOOP.IF lOOP ON SIDE I AND SIDE II ARE.NOT ARRANGED.V"!.UES FOR BOTH SIDES SHALl BE SUB1olmED.
4.6 H'VALUES FOR EQUIPIIENT WIlHIN GE-BWRSD SCOPE ARE AS NOTED.5.El.£VAllONS ARE NOT INCLUDED IN AI'.V"!.UES GIVEN.ElEVATIONS SHALl BE INClUDED WHEN DETERIlINING mw.V"!.UES FOR THE EllPiY DATA IJl.ANKS.e.8iiD1 lWllMUII (X)AND MINllIUM (\')VALUES FOR THE 7.DICATE FI.DW DOES NOT PASS THRU THESE POINTS.e.IN llDDES B..D AT CENTERlINE OF PUMP SUCTION DR EXCEED 15.1 FT.**BE SIZED TO FI.DW 3M GPII.HEAD MUST BE SUfflCIENT TO FlDDD THECONTAINMENT.
I'.THIS PDRl10N OF PIPING TO BE SIZEil BASED DN flOW SHOWN DN FUEl CDOUNG AND FTlTERING S>'STEll.11.I INDICATES V"!.VE POSITIONS DURING VARIOUS llOOES OPERATION.
12.:::*VAU/ES FOR lIAX.I\ND MIN.SUPPRESSION POOL TEMP.SHOWN.mw.TEllPERATURES DEPEND ON IN11lAl POOl WATER TEMPERATURE
..POOl WATER VOLUME.15.WATER FlOWS ARE IN GPII.SItAlI FUlWS ARE IN ,_lBS/HR.,e.MfAT MfAT\l£llDV"!.
I\ND SPRAY IIASED UPON 7_GPM FI.DW.11.FOR U INFO_YlON SEE REF.5.18.THE WATER SHUIDDWN CDOUNG SUIlSYSTEII PIPING.INCWDING THE MfAT AND PUllPS SHAU.NOT EXCEED 225,_lBS.AT 71'F DILUT10N OF STANDBY UQUID CONTROl.MINllIUM REQUIREIIENlS.S\'STDI AND TEMPERATURE AND THE ESTI....TED URE SIZES ONlY.ACTUAl.DESIGN PRESSURE..TEMPERATURE AS DETERMINED BY OTHERS SHALl Mm THE PROCESS REQUIREMENT.
21.Hx HEAT\l£llDV"!.
SHOWN FOR FUll.FI.DW AND lWllMUM TEMPERATURE DIFF<RERCE UNDER_OPERATING CONDmDNS THE TUBE SiDE DUl\.ET TEMPERATURE SHDUI.D NOT EXCEED 12!rF.22.SOH-7H FT.lWl.23.ONly ONE LOOP IS REQUIRED AT THIS STAGE OF SHUTDOWN._A LOOP IS SHDWN AS lYPlCAI.OF EITHER A DR B EXCEPT FOR THE HEAO SPRAY.24.THE Hk IRL.ET PRESSURE SHALl BE GREATER THAN III PSIA TO MINIMIZE THE POSSIBIUlY OF FI.DW INDUCED VIBRATION.
- .I:s iisHRJiitg QfWPEAIl POOl TEMPERATURE.
THE CURRENT__YSES PEAIl POOl TURE WAS NOT EllCEEDED.
U/OI'" 0)MODeS Rot PRESS.liD P$ltJ MODE G LaOIt I PRESS 1'$1.TEJlPoF MAr PRess D/IOP FEET OVIY PER HX 41 UI"!INIJ!R (2HX'S OPERATING) 1'tJS17111110 II U 16 5&1" 5 n"*'1'M MODi:'oS (CONr POtII770NO
.54 S4'44 35"AI...(""'3l..41 4.2 FLOWGIW.."...10 ,q" ItfA It/A It/A-It/A_/IISIA i"X Xxxx')("')(" x V").:xx;x.., TEMP", AlIa AW8 AM.Mill AlllII%ZAMIt f-ura....'f!:::
1" oJ.," Ii ,1: 111, 10.,;/IZI 6041 1&1..,"8 I.....A"....""" If-'A 14.7XXXXxx xXXX)(**,5 X 15.5 X lOIS X 101'.x X rEMP",,"13$1'%547%""
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- .,.ST_1II1/JIIIII
'lllllfl 1Irf1 1SIIII111f111.-E lllE/N'lIINlJITDIrt.-'"..'IHJHH""If (TEST lIillrl 5l/IIWSSIIIII1IIiIJ
_6 frt'(I'IJN'_1IIlJ1I_IIIICJ 0)LA SALLE COUNTY STATION UPDATED FINAL SAFETY ANALYSIS REPORT III..REV.9*APRIL 1993 FIGURE 5.4-5 RESIDUAL HEAT REMOVAL SYSTEM PROCESS DIAGRAM (SHEET 2 of*3)****a II*
/8 B SIDE I 9 B fj§Jc Fozse IV2!F027BJr024B 80\PPIMAR., CONTAINMENTF048A
,BOOlA:4?A._REACTOR S£COND4RY CQNr,4INM£/IIr SIDE 11 TO SERVICE:'WAT£R DISCH.RIIR SERVICE WAT£R 5Y5.E A A E TO SERVICE:'
WAT£R DISCH. RHR SERVICE WATeR 5Y5. SIDE 11
,BOOlA :4 PA ._REACTOR S£COND4RY CQNr,4INM£/IIr PPIMAR., CONTAINMENT fj§}c Fozse 9 8 SIDE I IV2! 18 13 F048A II 7 B c o 5.4-6 COUNTY STATION FINAL SAFETY ANALYSIS REPORT REFERENCE DOCUMENTS.
r.REACTOR WA1ER CLEAN-UP SYSTEMS PROCESS OATA-----G,,-IO,O 2.REACTOR wArtR CLElN-UP SYS P&IO-----------------G,,-IOIO 1.REACTOR WATtR CLEAN-UP SYSTEMS DESIGN SPEC.-----G,l-IfOIO If.REACTOR SYSTEM OUTLINE
,.REACTOR VESSEL OUTLINE DWG.--------------------BI,-OOO, 6.FILTER/DEMI" SYS PO------Gli-IOlO 7.FILTER/DEMI" sua SYS DEYICE LIST ITEM 20d-----Gl,-ZOOI I.OTESI I.POSITION 28 I 29 COllonlONS WITH TEMPE IlA TURES.2.'VALVES ARE I N THEIR NO'U1AL OPERATING POSITIONS, ,.THE PIPE FRICTION DROP FOR THt SIZING OF THE RECIRCULATION PUMPS SUCTION PIPinG FROM POSITIONS I-If SHALL BE.CONTROLLED h HOOE"B""'ID THE HPSH SHALL NOT BE BELOW THE MInIMUM AS SHOWN IN THE REFERENCE DOCUMENTS.
MODE"A" SMALL COUTROL THE SIZING OF THE DISCHARGE PIPInG AUD THE MAXIMUM ALLOHABLE PIPE FRICTIon DROP AS SHOWN SHOULD NOT BE If.FOR DATA PERTAINING TO IlUMDiORS\lITHIa HEXAGONS.REFER TO PROCESS DATA REF.I..MODE"A" BASIS FOR HEATCHANGERS AND NO FLOW IS REQUIRED AT POSITION 21, 22-27, 33A&338.6.HODEDESIGN BASIS FORUP PUMP (MAX.CAPACITY AUD MIN.NPSH)AND SIZING OF HAIN PUHPS SUCTION PIPING.NO FLOW REQO.HI MODE"B""'-'SIlION 11B-13A.21.22-27*33A&33B...,""...........
,&,..SPEC J-2500 OWOI 9220263 I I ,"--"--
- I L..".4_4....7_(nP._or.I.)
__*,-----: """"DW¥UoC.Illc;fIOMII' FORSAW COUNTY STAnON UNITS I tl 2 COMMONWEALTH fEDISON CO.SARGENT 81 LUNDY ENGINEEF1S
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REV18APRIL2010II1I!IIIII.III,IIfEIIIII....NO.A,-40S02!.3!fm.I:REACTORWATERCLEAN-uPSYSTE".....4-!LSCS-UFSAR16!78cIiI0MODENORMALOPERATION.......1010.",1.1111NOTaI.I.AND*CW"'OCI'IIDe.....LOCATION{}I*I..**.,**Ie*t*I'1411III?I'I*ao**a..ISIeI?IIII*I'n**nIe*IeF1.OW."..145111IIIIII352352.'1.110aeo-11.4114***.taI/allIII151IIIIIII48...,....514'10.,..,..***7M.,..'I"DIt.-.,.**1.111'1I"IiaIII114.14n..s110110I.11041?II...,.s.,41"IIIIIII**1=0**114100,SO101**0no0-.It...-4-101--165101059lO-P.....TDHDR.AU.OWAILI'tN'1umOM...tlaNOTE.....ocuaOIAMAII...'ltD._7.................MODE*HOTSHUTDOWNOPDtATION(WITHLOSSOFIIlPVRUlRCPUMPS,11.....100I.....1.tsIIItOTD*MD601'........DIAMAIGcLOCA".()II*4**?**10AIIII'I.tl"I?Ie..10It12IJ14..*ItaIIPLO.....85136.5...na...358358II/III!/IIIIInSMSM".IIIIIIIIINOTES:Tl......140MI544544544544545IIIIII/I545545545545545IIII,IIIIAJrIIlOcalDtAef\AM.UDHISHALLBEUSII)WI'"-..FORMAPARTOFnusPftOCESSDATA..FTHEft£MAX'",-..-4-MEANYCOHFLICTSBETWEENTHEPROCESSDIAGltAilI'fin....ANDTHISPAOCESSDATA.THEPROCESSDATASHAU.IDIIOPTDHALLOW....PIP!",.,nOMDROPSliE!NOTEIOf',1tOCUIOIAM."IIDDELTap.......L.J""CATOCOfC)fTrONSFOIl0FLOWIIAlEI!IIIC}1"Ht"'N.MUMREQUIREO"'-IfOFTHECL£ANtJPRE-IDE-SI6NPRESSUREANDGIVENBELOWISFOR'NFORMATIONONL'rANDISTHEBASISFORPIPINGDESIGN..ESTIMATEDLINESIZESAREFORINFOR-elRCPUMPSISIIFEETOFWATERAT544TIMATIONONLY..ACTUALLINESIZESASDETERMf:EDBYTHEPIPINGDESIGNERSHALLPJEETTHEPROCESSDATAHYDRAULICREQUIREMENTS.BASEDONCONDITIONSHOWNtNMODEB.ILOCATION()IA.....8*.lC-fD_-IEIA__a-tA51.....7-71.TA-e9-10IIA-f388SA-55Aiu-n."8-15A1'11.......27-55.15-21&'."-20(SEENOTEFlOJlEEP.....-APM4.Z:1OFDUOfSFORIT.,...lPftOCEDUft£.DES...PRESS."'1)12501250125012S0:2501250&1501500ISOO130013001300'3001'100.SOOfSOOBOO***E)DUftINtHOT.T....V.WITHONECL£.....P....IfflDESI"1"EIP..IDE"Pl5155755755757557557'5575575575'50150150150ISO150575***OPtItATrON.IIl..OWDOwr.RATEISAPPROXIM4TE1.Y121IPMAT..,.F..EST.MATEDLINESIZE(IN.)Z1..5I44*44444*J44444F)ftELOCAnOlCOF'CHECKVALVETOFLOWEL-EMENT..(F.W..P,P.ttaDESfGNEDBYOTH£RtTOAIi-.PfltOJUIMTELYIS50PStS)..ALLAUXILIMYPIPSDESI&HEDTO'SOPSI'ANDISOon.F..I*LOCATIONI.IS1'M£POINTWH£RETHEBOTTOMDRAINLINECO!eEtTIOMEXITS*IFRO"c..R.D..HOUSINSAREA.I**LOCATIONI.ISTHEPOINTlIfHERETHEBOTTOMOIIAINLINECOI\IIECTIONO.TSLA.SALLECOUNTYSTAT!ONFROMTHEREACTORVES$ELKDr'sTALUPDATEDFINALSAFETYYSISt...TOTHESMilECotCUTIONSASTHE:FEEDWATEJIPIP'.tal'OTHEltSJREPORTnV'/r'<>922D263ilFIGURE5_4-6LJvGSPECJ-2500REACTORWATERCLEANUPSYSTEMPROCESSDIAGRAM(SHEET2OF2)32HI
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-_.__.........J-......-Io.....-:--,-*FOR REACTOR WATER CLEANUP SYSTEM OPERATING PARAMETERS, SEE CURRENT STATION PROCEDURES.
2, SOURCE DOCUMENT: J-2500, 761E549.*NOTES: em_-----.------....---.....------------LASALLE COUNTY STATION UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 5.4-7 FILTER/DEMINERALIZATION SUBSYSTEM PROCESS DIAGRAM FIGURE 5.4-7 REV.11-APRIL 1996 LSCS-UFSAR o (G33-1020) 239X269AAG1.
G2 FeF:**r.LASALLE CO UPOATIm UNTY STATION SAFETY AN ALYSIS REPORT*LSCS-UFSAR 239X269AAG1.
G2 (G33-1020) o ** r. LASALLE CO UPOATlm UNTY STATION SAFETY AN , ALYSIS REACTOR WATER
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