ML071100214
| ML071100214 | |
| Person / Time | |
|---|---|
| Site: | Kewaunee  |
| Issue date: | 04/18/2007 |
| From: | Grecheck E Dominion, Dominion Energy Kewaunee |
| To: | Document Control Desk, NRC/NRR/ADRO |
| References | |
| 07-0217 | |
| Download: ML071100214 (137) | |
Text
Don~inionEnergy Kewaunee, Inc.
i l l 0 0 D o n i ~ n ~ oI'mulcvard, n Glen Allcn, V,4 23060 S Dominion' April 18, 2007 U. S. Nuclear Regulatory Commission Serial No. 07-0217 Attention: Document Control Desk KPSILICINW: R3 Washington, DC 20555 Docket No. 50-305 License No. DPR-43 DOMINION ENERGY KEWAUNEE. INC.
KEWAUNEE POWER STATION Pursuant to Kewaunee Power Station (KPS) Technical Specification 6.21, "Technical Specifications (TS) Bases Control Program," Dominion Energy Kewaunee, Inc. (DEK) hereby submits changes to the TS Bases.
DEK is also submitting a summary of the changes to the KPS Technical Requirements Manual (TRM). provides a summary of the KPS TS Bases changes that have been incorporated since March 2004. Attachment 2 provides a summary of the KPS TRM changes that have been incorporated since February 2005. Attachment 3 and 4 contain copies of the current KPS TS Bases and TRM, respectively.
The TS Bases changes were made in accordance with the provisions of 10 CFR 50.59 and reviewed and approved by the Plant Operating Review Committee.
If you have questions or require additional information, please feel free to contact Mr.
Gerald Riste at 920-388-8424.
Very truly yours, E. S. Grecheck Vice President - Nuclear Support Services Attachments:
- 1. Summary of Kewaunee Power Station Technical Specifications Bases Changes
- 2. Summary of Kewaunee Power Station Technical Requirements Manual Changes
- 3. Kewaunee Power Station Technical Specification Bases
- 4. Kewaunee Power Station Technical Requirements Manual
Serial No. 07-0217 TS and TRM Changes Page 2 of 2 Commitments made by this letter: NONE cc: Regional Administrator U. S. Nuclear Regulatory Commission Region Ill 2443 Warrenville Road Suite 210 Lisle, Illinois 60532-4352 Ms. M. H. Chernoff Project Manager U.S. Nuclear Regulatory Commission Mail Stop 0 7D1A Washington, D. C. 20555 Mr. S. C. Burton NRC Senior Resident Inspector Kewaunee Power Station
Serial No. 07-0217 ATTACHMENT 1 TECHNICAL SPECIFICATIONS BASES CHANGES AND TECHNICAL REQUIREMENTS MANUAL CHANGES
SUMMARY
OF KEWAUNEE POWER STATION TECHNICAL SPECIFICATIONS BASES CHANGES KEWAUNEE POWER STATION DOMINION ENERGY KEWAUNEE, INC.
Serial No. 07-0217 Attachment 1 Page 1 of 2
SUMMARY
OF KEWAUNEE POWER STATION TECHNICAL SPECIFICATIONS BASES CHANGES Technical Date of Specifications Summary Change Bases Page 3/30/2004 TS B4.8-1 Technical Specification (TS) item number was changed (TS 3.4. b.2.B to TS 3.4. b.4.B) without corresponding changes to bases page TS B4.8-1. TS B4.8-1 was changed to correct the error.
7/6/2004 TS B3.10-2 The COLR was revised to include the penalty factor in the TS 83.1 0-3 measured FQeq(Z) equation in section 2.6.2-and to clarify TS B3.10-4 in section 2.6.3 the values to use for the penalty factor TS B3.10-6 depending on which TS 3.10.b.6 (A, B, or C) applies. The TS 83.1 0-7 change clarifies the bases for TS 3.10.b.6 and TS TS 83.1 0-8 3.1 0.b.7.
TS B3.10-7 Submitted with License Amendment Request (LAR) 203, which added an allowed outage time for the individual rod position indication system of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> with more than one individual rod position indication group inoperable.
TS B 3.3-4 Submitted with LAR 197, which added requirements for the turbine building service water header isolation logic.
TS B3.3-2 Submitted with LAR 205, which revised TS 3.3.a.2.B to TS 83.3-3 allow a 24-hour completion time to restore an accumulator TS B3.3-4 that is inoperable for a reason other than boron concentration.
The bases were changed because the curve fitting process within the Power Plant Computer System was removed due to the correction for the rod calibration curve now being performed within each new analog rod position indication module.
3/24/2005 TS B3.10-6 Submitted with LAR 203, which added Rod Position TS 63.1 0-7 Indicator bank demand step counters to the TS and a note TS B3.10-8 to allow for a soak time subsequent to substantial rod TS B3.10-9 motion for the rods that exceed their position limits before invoking the TS requirements.
313 112005 TS B3.1-2 The bases were changed to clarify whether a loss of the TS 83.1-3 automatic open feature of the pressurizer power-operated relief valves (PRZR PORVs) affect PRZR PORV operability.
Serial No. 07-0217 Attachment 1 Page 2 of 2 Technical Date of Specifications Summary Change Bases Page 612012005 TS B3.4-1 Submitted with LAR 213, which modified the existing auxiliary feedwater pump suction protection requirements.
Submitted with LAR 200, which changed the name of the station and license holder.
Submitted with LAR 218, which revised the TS requirements related to steam generator tube integrity, consistent with Technical Specification Task Force 449, Revision 4.
TS Bases pages TS B3.1-13 and TS B3.1-14 were not submitted with LAR 218 but were changed due to page truncation.
Serial No. 07-0217 ATTACHMENT 2 TECHNICAL SPECIFICATIONS BASES CHANGES AND TECHNICAL REQUIREMENTS MANUAL CHANGES
SUMMARY
OF KEWAUNEE POWER STATION TECHNICAL REQUIREMENTS MANUAL CHANGES KEWAUNEE POWER STATION DOMINION ENERGY KEWAUNEE, INC.
Serial No. 07-0217 Attachment 2 Page 1 of 2
SUMMARY
OF KEWAUNEE POWER STATION TECHNICAL REQUIREMENTS MANUAL CHANGES Mav 15.2005 Addition of TRM 3.5.2, Revision 0, "Flooding Protection- Circulating Water Pump Trip."
TRM 3.5.2 provides Administrative Limiting Condition for Operations (ALCOs) and Administrative Surveillance Requirements (ASRs) for the circulating water pump trip circuitry. The objective of TRM 3.5.2 is to provide turbine building flood protection in the event of a failure in the circulating water system piping.
June 2.2005 Addition of TRM 3.5.3, Revision 0, "Emergency Plan Portable Radiation Survey Instruments." The objective of TRM 3.5.3 is to provide ASRs to perform ANSI recommended checks, calibrations, and functional tests on portable radiation survey instruments specifically called out in the KPS Emergency Plan.
Julv 15. 2005 Revision to COLR, Cycle 27, to correct an administrative error, making the COLR consistent with the Westinghouse Kewaunee Nuclear Power Plant Cycle 27 Reload Safety Evaluation.
Julv 21.2006 Revision to TRM 3.7.1, "Technical Support Center (TSC) 1 Station Blackout (SBO) Diesel Generator." This revision documents that a specific Probabilistic Risk Assessment evaluation to determine appropriate compensatory / mitigating measures is not necessary when the TSCISBO DG is made or found to be inoperable and when the reactor coolant temperature is c 540 O F .
Auaust 18.2006 Addition of TRM 3.1 1. l , "Core Surveillance Instrumentation (Incore Thimbles)." TRM 3.1 1.1 provides an ALCO, which clarifies operability requirements for the movable incore detector system (Incore Thimbles).
COLR Cycle 28, Revision 0 replaced COLR Cycle 27, Revision 1. The Technical Requirements Manual was revised to change the name from Kewaunee Nuclear Power Plant to Kewaunee Power Station.
Serial No. 07-0217 Attachment 2 Page 2 of 2 March 9.2007 Addition of TRM 3.7.2, "Common Cause Testing of Emergency Diesel Generators." TRM 3.7.2 provides ALCOs and ASRs, which clarify the daily testing requirement of Kewaunee Power Station Technical Specification 3.7.b.2 when one emergency diesel generator is made or found to be inoperable.
Serial No. 07-0217 ATTACHMENT 3 TECHNICAL SPECIFICATIONS BASES CHANGES AND TECHNICAL REQUIREMENTS MANUAL CHANGES KEWAUNEE POWER STATION TECHNICAL SPECIFICATIONS BASES KEWAUNEE POWER STATION DOMINION ENERGY KEWAUNEE, INC.
BASIS Safetv Limits-Reactor Core (TS 2.1)
The reactor core safety limits shall not be exceeded during steady state operation, normal operational transients, and anticipated operational occurrences. This is accomplished by having a departure from nucleate boiling (DNB) design basis, which corresponds to a 95% probability at a 95% confidence level that DNB will not occur and by requiring that fuel centerline temperature stays below the melting temperature.
The restrictions of the reactor core safety limits prevent overheating of the fuel and cladding as well as possible cladding perforation that would result in the release of fission products to the reactor coolant. Overheating of the fuel is prevented by maintaining the steady state peak linear heat rate (LHR) below the level at which fuel centerline melting occurs. Overheating of the fuel cladding is prevented by restricting fuel operation to within the nucleate boiling regime where the heat transfer coefficient is large and the cladding surface temperature is slightly above the coolant saturation temperature.
Fuel centerline melting occurs when the local LHR, or power peaking, in a region of the fuel is high enough to cause the fuel centerline temperature to reach the melting point of the fuel.
Expansion of the pellet upon centerline melting may cause the pellet to stress the cladding to the point of failure, allowing an uncontrolled release of activity to the reactor coolant.
To maintain the integrity of the fuel cladding and prevent fission product release, it is necessary to prevent overheating of the cladding under all OPERATING conditions. This is accomplished by operating the hot regions of the core within the nucleate boiling regime of heat transfer, wherein the heat transfer coefficient is very large and the clad surface temperature is only a few degrees Fahrenheit above the coolant saturation temperature. The upper boundary of the nucleate boiling regime is termed departure from nucleate boiling (DNB) and at this point there is a sharp reduction of the heat transfer coefficient, which would result in high clad temperatures and the possibility of clad failure. DNB is not, however, an observable parameter during reactor operation. Therefore, the observable parameters of RATED POWER, reactor coolant temperature and pressure have been related to DNB through a DNB correlation. The DNB correlation has been developed to predict the DNB heat flux and the location of the DNB for axially uniform and non-uniform heat flux distributions. The local DNB ratio (DNBR), defined as the ratio of the heat flux that would cause DNB at a particular core location to the local heat flux, is indicative of the margin to DNB. The minimum value of the DNBR, during steady-state operation, normal operational transients, and Condition I and II transients is limited to the DNBR limit. This minimum DNBR corresponds to a 95% probability at a 95% confidence level that DNB will not occur and is chosen as an appropriate margin to DNB for all OPERATING conditions.
The SAFETY LIMIT curves as provided in the Core Operating Report Limits Report show the loci of points of thermal power, reactor coolant system average temperature, and reactor coolant system pressure for which the minimum DNBR is not less than the safety analysis limit, that fuel centerline temperature remains below melting, that the average enthalpy at the exit of the core is less than or equal to the enthalpy of saturated liquid, or that the core exit quality is within limits defined by the DNBR correlation. At low pressures or high temperatures the average enthalpy at the exit of the core reaches saturation before the DNBR ratio reaches the DNBR limit and thus, this limit is conservative with respect to maintaining clad integrity. The area where clad integrity is ensured is below the safety limit curves.
The curves are based on the nuclear hot channel factor limits of as specified in the COLR.
Amendment 172 02/27/2004
These limiting hot channel factors are higher than those calculated at full power for the range from all control rods fully withdrawn to maximum allowable control rod insertion. The control rod insertion limits are given in TS 3.10.d. Slightly higher hot channel factors could occur at lower power levels because additional control rods are in the core. However, the control rod insertion limits as specified in the COLR ensure that the increase in peaking factor is more than offset by the decrease in power level.
The Reactor Control and PROTECTION SYSTEM is designed to prevent any anticipated combination of transient conditions that would result in a DNBR less than the DNBR limit.
Two departure from nucleate boiling ratio (DNBR) correlations are used in the generation and validation of the safety limit curves: the WRB-1 DNBR correlation and the high thermal performance (HTP) DNBR correlation. The WRB-1 correlation applies to the Westinghouse 422 V+ fuel. The HTP correlation applies to FRA-ANP fuel with HTP spacers. The DNBR correlations have been qualified and approved for application to Kewaunee. The DNB correlation limits are 1.14 for the HTP DNBR correlation, and 1.17 for the WRB-1 DNBR correlation.
Amendment 172 02/27/2004
P r w r e ITS 7Y The Reactor Coolant stern serves as a barrier preventing radionuclides contained in the reactor coolant from reaching the atmosphere. In the event of a fuel cladding failure, the Reactor Coolant System is the primary barrier against the release of fission products. By establishing a system pressure limit, the continued integrity of the Reactor Coolant System is ensured. The maximum transient pressure allowable in the reactor pressure vessel under the ASME Code, Section Ill, is 110% of design pressure. The maximum transient pressure allowable in the Reactor Coolant System piping, valves and fittings under USASl B.31.I .0 is 120% of design pressure. Thus, the SAFETY LIMIT of 2735 psig (110% of design pressure, 2485 psig) has been established. "'
The settings of the power-operated relief valves, the reactor high pressure trip and the safety valves have been established to prevent exceeding the SAFETY LIMIT of 2735 psig for all transients except the hypothetical RCCA Ejection accident, for which the faulted condition stress limit acceptance criterion of 3105 psig (3120 psia) is applied. The initial hydrostatic test was conducted at 3107 psig to ensure the integrity of the Reactor Coolant System.
"' USAR Section 4
"' USAR Section 4.3 Amendment No. 167 04/04/2003
BASIS - Limiting Safetv Svstem Settings - Protective Instrumentation ITS 2.3)
Nuclear Flux The source range high flux reactor trip prevents a startup accident from subcritical conditions from proceeding into the power range. Any setpoint within its range would prevent an excursion from proceeding to the point at which significant thermal power is generated.
The power range reactor trip low setpoint provides protection in the power range for a power excursion beginning from low power. This trip was used in the safety analysis.(')
The power range reactor trip high setpoint protects the reactor core against reactivity excursions which are too rapid to be protected by temperature and pressure protective circuitry. The prescribed setpoint, with allowance for errors, is consistent with the trip point assumed in the accident analysis.(')
Two sustained rate protective trip functions have been incorporated in the Reactor PROTECTION SYSTEM. The positive sustained rate trip provides protection against hypothetical rod ejection accident. The negative sustained rate trip provides protection for the core (low DNBR) in the event two or more rod control cluster assemblies (RCCAs) fall into the core. The circuits are independent and ensure immediate reactor trip independent of the initial OPERATING state of the reactor. These trip functions are the LIMITING SAFETY SYSTEM actions employed in the accident analysis.
Pressurizer The high and low pressure trips limit the pressure range in which reactor operation is permitted.
The high pressurizer pressure trip setting is lower than the set pressure for the safety valves (2485 psig) such that the reactor is tripped before the safety valves actuate. The low pressurizer pressure trip causes a reactor trip in the unlikely event of a loss-of-coolant accident.(3)The high pressurizer water level trip protects the pressurizer safety valves against water relief. The specified setpoint allows margin for instrument error (2) and transient level overshoot before the reactor trips.
Reactor Coolant Temperature The overtemperature AT reactor trip provides core protection against DNB for all combinations of pressure, power, coolant temperature, and axial power distribution, provided only that: 1) the transient is slow with respect to piping transit delays from the core to the temperature detectors (about 2 seconds), and 2) pressure is within the range between the high and low pressure reactor trips. With normal axial power distribution, the reactor trip limit, with allowance for errord2) is always below the core SAFETY LIMITS shown in the Core Operating Limits Report. If axial peaks I are greater than design, as indicated by differences between top and bottom power range nuclear detectors, the reactor trip limit is automatically reduced.
USAR Section 14.1.I (2) USAR Section 14.0 (3) USAR Section 14.3.1 Amendment No. I 6 5 0311 112003
The overpower AT reactor trip prevents power density anywhere in the core from exceeding a value at which fuel pellet centerline melting would occur, and includes corrections for change in 1 density and heat capacity of water with temperature, and dynamic compensation for piping delays from the core to the loop temperature detectors. The specified setpoints meet this requirement and include allowance for instrument errors.(2)
The overpower and overtemperature PROTECTION SYSTEM setpoints include the effects of fuel densification and clad flattening on core SAFETY LIMITS.(~)
Reactor Coolant Flow The low-flow reactor trip protects the core against DNB in the event of either a decreasing actual measured flow in the loops or a sudden loss of power to one or both reactor coolant pumps. The setpoint specified is consistent with the value used in the accident ana~ysis.'~)
The undervoltage and low frequency reactor trips provide additional protection against a decrease in flow. The undervoltage setting provides a direct reactor trip and a reactor coolant pump breaker trip. The undervoltage setting ensures a reactor trip signal will be generated before the low-flow trip setting is reached. The low frequency setting provides only a reactor coolant pump breaker trip.
Steam Generators The low-low steam generator water level reactor trip ensures that there will be sufficient water inventory in the steam generators at the time of trip to allow for starting the Auxiliary Feedwater System. (6)
Reactor Trip Interlocks Specified reactor trips are bypassed at low power where they are not required for protection and would otherwise interfere with normal operation. The prescribed setpoints above which these trips are made functional ensures their availability in the power range where needed.
Confirmation that bypasses are automatically removed at the prescribed setpoints will be determined by periodic testing. The reactor trips related to loss of one or both reactor coolant pumps are unblocked at approximately 10% of power.
Table TS 3.5-1 lists the various parameters and their setpoints which initiate safety injection signals. A safety injection signal (SIS) also initiates a reactor trip signal. The periodic testing will verify that safety injection signals perform their intended function. Refer to the basis of Section 3.5 of these specifications for details of SIS signals.
'4' WCAP-8092
( 5 ) USAR Section 14.1.8 (6) USAR Section 14.1. I 0 Amendment 172 02/27/2004
TS 3.0.a establishes the applicability statement within each individual TS as the requirement for when (i.e., in which OPERATIONAL MODES or other specified conditions) conformance to the LC0 is required for safe operation of the facility. The ACTION requirements establish those remedial measures that must be taken within specified time limits when the requirements of a LC0 are not met.
There are two basic types of ACTION requirements. The first specifies the remedial measures that permit continued operation of the facility which is not further restricted by the time limits of the ACTION requirements. In this case, conformance to the ACTION requirements provides an acceptable level of safety for unlimited continued operation as long as the ACTION requirements continue to be met. The second type of ACTION requirement specifies a time limit in which conformance to the conditions of the LC0 must be met. This time limit is the allowable outage time to restore an inoperable system or component to the OPERABLE status or for restoring parameters within specified limits. If these actions are not completed within the allowable outage time limits, a shutdown is required to place the facility in a MODE or condition in which the TS no longer applies.
The specified time limits of the ACTION requirements are applicable from the point in time it is identified that a LC0 is not met. The time limits of the ACTION requirements are also applicable when a system or component is removed from service for surveillance testing or investigation of operational problems. Individual TSs may include a specified time limit for the completion of a surveillance requirement when equipment is removed from service. In this case, the allowable outage time limits of the ACTION requirements are applicable when this limit expires if the surveillance has not been completed. When a shutdown is required to comply with ACTION requirements, the plant may have entered a MODE in which a new TS becomes applicable. In this case, the time limits of the ACTION requirements would apply from the point in time that the new TS becomes applicable if the requirements of the L C 0 are not met.
TS 3.0.b establishes that noncompliance with a TS exists when the requirements of the LC0 are not met and the associated ACTION requirements have not been implemented within the specified time interval. The purpose of this TS is to clarify that the implementation of the ACTION requirements within the specified time interval constitutes compliance with a TS. Completion of the remedial measures of the ACTION requirements is not required when compliance with a L C 0 is restored within the time interval specified in the associated ACTION requirements.
TS 3.0.c provides the standard shutdown sequence to be followed in the event a LIMITING CONDITION FOR OPERATION cannot be met and the condition is not specifically addressed by the associated action requirements. The purpose of this TS is to delineate the time limits for placing the unit in a safe shutdown mode allowed by the TSs.
Amendment No. 119 04118/95
BASIS Reactor Coolant Svstem (TS 3.1 .a)
Reactor Coolant Pumps (TS 3.1 .a.l)
When the boron concentration of the Reactor Coolant System is to be reduced, the process must be uniform to prevent sudden reactivity changes in the reactor. Mixing of the reactor coolant will be sufficient to maintain a uniform boron concentration if at least one reactor coolant pump or one residual heat removal pump is running while the change is taking place. The residual heat removal pump will circulate the equivalent of the primary system volume in approximately one-half hour.
Part one of the specification requires that both reactor coolant pumps be OPERATING when the I reactor is in power operation to provide core cooling. Planned power operation with one loop out-of-service is not allowed in the present design because the system does not meet the single failure (locked rotor) criteria requirement for this MODE of operation. The flow provided in each case in part one will keep Departure from Nucleate Boiling Ratio (DNBR) well above 1.30.
Therefore, cladding damage and release of fission products to the reactor coolant will not occur.
I One pump operation is not permitted except for tests. Upon loss of one pump below 10%full power, the core power shall be reduced to a level below the maximum power determined for zero power testing. Natural circulation can remove decay heat up to 10% power. Above 10% power, an automatic reactor trip will occur if flow from either pump is lost.)
The RCS will be protected against exceeding the design basis of the Low Temperature Overpressure Protection (LTOP) System by restricting the starting of a Reactor Coolant Pump (RXCP) to when the secondary water temperature of each SG is < 100°F above each RCS cold leg temperature. The restriction on starting a reactor coolant pump (RXCP) when one or more RCS cold leg temperatures is I 200°F is provided to prevent a RCS pressure transient, caused by an energy addition from the secondary system, which could exceed the design basis of the LTOP System.
Decav Heat Removal Capabilities (TS 3.1 .a.2)
When the average reactor coolant temperature is 5 350°F a combination of the available heat sinks is sufficient to remove the decay heat and provide the necessary redundancy to meet the single failure criterion.
When the average reactor coolant temperature is I200°F, the plant is in a COLD SHUTDOWN condition and there is a negligible amount of sensible heat energy stored in the Reactor Coolant System. Should one residual heat removal train become inoperable under these conditions, the remaining train is capable of removing all of the decay heat being generated.
USAR Section 7.2.2 Amendment No. 165 03111I2003
The requirementfor at least one train of residual heat removal when in the REFUELING MODE is to ensure sufficient cooling capacity is available to remove decay heat and maintain the water in the reactor vessel < 140°F. The requirement to have two trains of residual heat removal OPERABLE when there is < 23 feet of water above the reactor vessel flange ensures that a single failure will not result in complete loss-of-heat removal capabilities. With the reactor vessel head removed and at least 23 feet of water above the vessel flange, a large heat sink is available. In the event of a failure of the OPERABLE train, additional time is available to initiate alternate core cooling procedures.
Pressurizer Safetv Valves /TS 3.1.a.3)
Each of the pressurizer safety valves is designed to relieve 325,000 Ibs. per hour of saturated steam at its setpoint. Below 350°F and 350 psig, the Residual Heat Removal System can remove decay heat and thereby control system temperature and pressure. If no residual heat were removed by any of the means available, then the amount of steam which could be generated at safety valve relief pressure would be less than half the valves1capacity. One valve therefore provides adequate protection against overpressurization.
Pressure Isolation Valves (TS 3.1 .a.4)
The basis for the pressure isolation valves is discussed in the Reactor Safety Study (RSS),
WASH-1400, and identifies an intersystem loss-of-coolantaccident in a PWR which is a significant contributor to risk from core melt accidents (EVENT V). The design examined in the RSS contained two in-series check valves isolating the high pressure Primary Coolant System from the Low Pressure Injection System (LPIS) piping. The scenario which leads to the EVENT V accident is initiated by the failure of these check valves to function as a pressure isolation barrier. This causes an overpressurization and rupture of the LPIS low pressure piping which results in a LOCA that bypasses ~ontainment.'~)
PORVs and PORV Block Valves (TS 3.1 .a.5)
The pressurizer power-operated relief valves (PORVs) operate as part of the normal Pressurizer Pressure Control System. The PORVs are air-operated valves that are controlled to automatically open at a set pressure when the pressurizer pressure increases and to automatically close when the pressurizer pressure decreases. The PORVs are intended to relieve RCS pressure below the setting of the code safety valves, however, the automatic control function is not a requirement of the TS. The PORVs also have the capability to be manually operated from the control room.
Remotely operated block valves are located between the pressurizer and the PORVs. The block valves provide a positive shutoff capability should a PORV become inoperable in the case of excessive seat leakage or a stuck open PORV. In these cases, block valve closure terminates the RCS depressurization and coolant inventory loss.
The pressurizer PORVs and associated block valves must be OPERABLE to ~rovidean alternate means of mitigating a design basis steam generator tube rupture. Thus, an inoperable PORV (for reasons other than seat leakage) or block valve is not permitted in the HOT STANDBY and OPERATING MODES for periods of more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
(2)Orderfor Modification of License dated 4120181
An OPERABLE PORV is required to be capable of manually opening and closing, and not experiencing excessive seat leakage. Excessive seat leakage, although not associated with a specific acceptance criteria, exists when conditions dictate closure of the block valve to limit leakage. The automatic functioning of the PORV is not a requirement of the TS.
An OPERABLE block valve may be either open and energized with the capability to be closed, or closed and energized with the capability to be opened, since the required safety function is accomplished by manual operation. Although typically open to allow PORV operation, the block valves may be OPERABLE when closed to isolate the flow path of an inoperable PORV that is capable of being manually cycled but experiencingexcessive seat leakage. Similarly, isolationof an OPERABLE PORV does not render that PORV or block valve inoperable providedthe relief function remains available with manual action.
Pressurizer Heaters (TS 3.1 .a.6)
Pressurizer heaters are vital elements in the operation of the pressurizer which is necessary to maintain system pressure. Loss of energy to the heaters would result in the inability to maintain system pressure via heat addition to the pressurizer. Hot functional testd3)have indicatedthat one group of heaters is required to overcome ambient heat losses. Placing heaters necessary to overcome ambient heat losses on emergency power will ensure the ability to maintain pressurizer pressure. Surveillance tests are performed to ensure heater OPERABILITY.
Reactor Coolant Vent Svstem (TS 3.1 .a.7)
The function of the High Point Vent System is to vent noncondensible gases from the high points of the RCS to ensure that core cooling during natural circulation will not be inhibited. The OPERABILITY of at least one vent path from both the reactor vessel head and pressurizer steam space ensures the capability exists to perform this function.
The vent path from the reactor vessel head and the vent path from the pressurizer each contain two independently emergency powered, energize to open, valves in parallel and connect to a common header that discharges either to the containment atmosphere or to the pressurizer relief tank. The lines to the containment atmosphere and pressurizer relief tank each contain an independently emergency powered, energize to open, isolation valve. This redundancy provides protection from the failure of a single vent path valve rendering an entire vent path inoperable.
A flow restriction orifice in each vent path limits the flow from an inadvertent actuation of the vent system to less than the flow capacity of one charging pump.(4)
Hot functional test (PT-RC-31)
'" Letter from E. R. Mathews to S. A. Varga dated 5/21/82 (3)
TS 83.1-3
Heatup and Cooldown Limit Curves for Normal Operation (TS 3.1 .bl Fracture Toughness Properties (TS 3.1 .b.l)
The fracture toughness properties of the ferritic material in the reactor coolant pressure boundary are determined in accordance with the ASME Boiler and Pressure Vessel code,(') and the calculation methods of ~ootnote.'~) The postirradiation fracture toughness properties of the reactor vessel belt line material were obtained directly from the Kewaunee Reactor Vessel Material Surveillance Program.
Allowable pressure-temperature relationshipsfor various heatup and cooldown rates are calculated using methods derived from Appendix G in Section Ill of the ASME Boiler and Pressure Vessel Code, and are discussed in detail in ~ootnote.(~)
The method specifies that the allowable total stress intensity factor (K,) at any time during heatup or cooldown cannot be greater than that shown on the KIRcurve for the metal temperature at that time.
Furthermore, the approach applies an explicit safety factor of 2.0 on the stress intensity factor induced by the pressure gradient. Thus, the governing equation for the heatup-cooldown analysis is:
where KI, is the stress intensity factor caused by membrane (pressure) stress Kit is the stress intensity factor caused by the thermal gradients KIR is provided by the Code as a function of temperature relative to the RTNDT of the material.
(5)Section Ill and XI of the ASME Boiler and Pressure Vessel Code, Appendix G, "Protection Against Non-ductile Failure."
Standard Method for Measuring Thermal Neutron Flux by Radioactivation Techniques, astm designation E262-86.
WCAP-14278, Revision 1, 'Kewaunee Heatup and Cooldown Limit Curves for Normal Operation," T. Laubham and C. Kim, September 1998.
From equation (3.1b-1) the variables that affect the heatup and cooldown analysis can be readily identified. KI, is the stress intensity factor due to membrane (pressure) stress. Kit is the thermal (bending) stress intensity factor and accounts for the linearly varying stress in the vessel wall due to thermal gradients. During heatup Klt is negative on the inside and positive on the outer surface of the vessel wall. The signs are reversed for cooldown and, therefore, an ID or an OD one quarter thickness surface flaw is postulated in whichever location is more limiting. KIR is dependent on irradiation and temperature and, therefore, the fluence profile through the reactor vessel wall and the rates of heatup and cooldown are important. The heatup and cooldown limit curves have been developed by combining the most conservative pressure temperature limits derived by using material properties of the intermediateforging, closure head flange, and beltline circumferentialweld to form a single set of composite curves. Details of the procedure used to account for these variables are explained in the following text.
Following the generation of pressure-temperature curves for both the steady-state (zero rate of change of temperature) and finite heatup rate situations, the final limit curves are produced in the following fashion. First, a composite curve is constructed based on a point-by-pointcomparison of the steady-state and finite heatup rate data for each of the limiting materials. At any given temperature, the allowable pressure is taken to be the lesser of the values taken from the curves under consideration. The composite curve is then adjusted to allow for possible errors in the pressure and temperature sensing instruments including the pressure difference between the gage and beltline weld.
The use of the composite curve is mandatory in setting heatup limitations because it is possible for conditions to exist such that over the course of the heatup ramp the controlling analysis switches from the OD to the ID location. The pressure limit must, at all times, be based on the most conservative case.
The cooldown analysis proceeds in the same fashion as that for heatup with the exception that the controlling location is always at the ID. The thermal gradients induced during cooldown tend to produce tensile stresses at the ID location and compressive stresses at the OD position. Thus, the ID flaw is clearly the worst case.
As in the case of heatup, allowable pressure-temperature relations are generated for both steady-state and finite cooldown rate situations for each of the limiting materials. Composite limit curves are then constructed for each cooldown rate of interest. Again, adjustments are made to 1 account for pressure and temperature instrumentation error.
The use of the composite curve in the cooldown analysis is necessary because system control is based on a measurement of reactor coolant temperature, whereas the limiting pressure is calculated using the material temperature at the tip of the assumed reference flaw. During cooldown, the 114T vessel location is at a higher temperature than the fluid adjacent to the vessel ID. This condition, of course, is not true for the steady-state situation. It follows that the AT induced during cooldown results in a calculated higher KIR for finite cooldown rates than for steady-state under certain conditions.
Amendment No. 165 03111I2003
Limit curves for normal heatup and cooldown of the primary Reactor Coolant System have been calculated using the methods discussed above and limited application to ASME Boiler and Pressure Vessel Code Case N-588 to the circumferential beltline weld. The derivation of the limit curves is consistent with the NRC Regulatory Standard Review ~lan)and ~ootnote.(~)
Transition temperature shifts occurring in the pressure vessel materials due to radiation exposure have been obtained directly from the reactor pressure vessel surveillance program. As presented in WCAP 14279, Revision 1,(lo) weld metal Charpy test specimens from Capsule S indicate that the core region weld metal exhibits the largest shift in RTNDT (250°F).
The results of IrradiationCapsules V, R, P, and S analyses are presentedin WCAP 8908,"') WCAP 9878,'") WCAP-12020,"~)WCAP-142i'9,(14)and WCAP-14279, Revision 1(lo) respectively. Heatup and cooldown limit curves for normal operation of the reactor vessel are presented in Figures TS 3.1 -1 and TS 3.1 -2 and represent an operational time period of 33[11effective full-power years.
The isothermal cooldown limit curve (Figure TS 3.1 -2) is used for evaluation of low temperature overpressure protection (LTOP) events. This curve is applicable for 33[11 effective full-power years of fluence (through the end of OPERATING cycle 33l1]). If a low temperature overpressure event occurred, the RCS pressure transient would be evaluated to the limits of this figure to verify the integrity of the reactor vessel. If these limits are not exceeded, vessel integrity is assured and a TS violation has not occurred.
['I The curves are limited to 31.IEFPY due to changes in vessel fluence associated with operation at uprated power. 1
(')" Fracture Toughness Requirements," Branch Technical Position MTEB 5-2, Chapter 5.3.2 in Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants, LW R Edition, NUREG-0800, 1981.
(') 1989 ASME Boiler and Pressure Vessel (B&PV) Code,Section XI, Appendix G , "Fracture Toughness Criteria for Protection Against Failure."
(lo) C. Kim, et al., "Evaluation of Capsule S from the Kewaunee and Capsule A35 from the Maine Yankee Nuclear Power Reactor Vessel Radiation Surveillance Programs," WCAP-14279, Revision 1, September 1998.
(") S.E. Yanichko, S. L. Anderson, and K. V. Scott, "Analysis of Capsule V from the Wisconsin Public Service Corporation Kewaunee Nuclear Plant Reactor Vessel Radiation Surveillance Program," WCAP 8908, January 1977.
'I2) S.E. Yanichko, et al., "Analysis of Capsule R from the Wisconsin Public Service Corporation Kewaunee Nuclear Plant Reactor Vessel Radiation Surveillance Program," WCAP 9878, March 1981.
(13) S.E. Yanichko, et al., "Analysis of Capsule P from the Wisconsin Public Service Corporation Kewaunee Nuclear Power Plant Reactor Vessel Radiation Surveillance Program,"
WCAP-12020, November 1988.
(I4) E. Terek, et al., "Analysis of Capsule S from the Wisconsin Public Service Corporation Kewaunee Nuclear Power Plant Reactor Vessel Radiation Surveillance Program," WCAP-14279, March 1995.
Amendment No. 168 07/08/2003
Pressurizer Limits (TS 3.1 .b.3)
Although the pressurizer operates at temperature ranges above those for which there is reason for concern about brittle fracture, OPERATING limits are provided to ensure compatibilityof operation with the fatigue analysis performed in accordance with Code requirements. In-plant testing and calculations have shown that a pressurizer heatup rate of 100°F/hr cannot be achieved with the installed equipment.
Low Tem~eratureOveruressure Protection (TS 3.1 .b.4)
The Low Temperature Overpressure Protection System must be OPERABLE during startup and shutdown conditions below the enable temperature (i.e., low temperature) as defined in Branch Technical Position RSB 5-2 as modified by ASME Boiler and Pressure Vessel Code Case N-514.
Based on the Kewaunee Appendix G LTOP protection pressure-temperature limits calculated through 33[11effective full-power years, the LTOP System must be OPERABLE whenever one or more of the RCS cold leg temperatures are 5 200°F and the head is on the reactor vessel. The LTOP system is considered OPERABLE when all four valves on the RHR suction piping (valves RHR-1A, 1B, 2A, 28) are open and valve RHR-33-1, the LTOP valve, is able to relieve RCS overpressure events without violating Figure TS 3.1 -2.
The set pressure specified in TS 3.1 .b.4 includes consideration for the opening pressure tolerance of + 3% (k 15 psig) as defined in ASME Boiler and Pressure Vessel Code, Section Ill, Division 1, Subsection NC: Class 2 Components for Safety Relief Valves. The analysis of pressure transient conditions has demonstrated acceptable relieving capability at the upper tolerance limit of 515 psig.
If one train of RHR suction piping to RHR 33-1 is isolated, then the valves and valve breakers in the other train shall be verified open, and the isolated flowpath must be restored within five days. Ifthe isolated flowpath cannot be restored within five days, then the RCS must be depressurized and vented through at least a 6.4 square inch vent within an additional eight hours.
If both trains of RHR suction are isolated or valve RHR 33-1 is inoperable, then the system can still be considered OPERABLE if an alternate vent path is provided which has the same or greater effective flow cross section as the LTOP safety valve (1 6.4 square inches). If vent path is provided by physical openings in the RCS pressure boundary (e.g., removal of pressurizer safety valves or steam generator manways), then the vent path is considered secured in the open position.
['I The curves are limited to 31.1 EFPY due to changes in vessel fluence associated with operation at uprated power.
Amendment No. 168 07/08/2003
Maximum Coolant Activitv (TS 3.1.c)
The maximum dose that an individual may receive following an accident is specified in GDC 19 and 10 CFR 50.67. The limits on maximum coolant activity ensure that the calculated doses are held to the limits specified in GDC 19 and to a fraction of the 10 CFR 50.67 limits.
The Reactor Coolant Specific Activity is limited to 5 1.0 pCi/gram DOSE EQUIVALENT 1-131 to ensure the dose does not exceed the GDC-19 and 10 CFR 50.67 guidelines. The applicable accidents identified in the USAR"~)are analyzed assuming an RCS activity of 1.0 pCi/gram DOSE EQUIVALENT 1-131 incorporating an accident initiated iodine spike when required. To ensure the conditions allowed are taken into account, the applicable accidents are also analyzed considering a pre-existing iodine spike of 60 pCi/gram DOSE EQUIVALENT 1-131. The results obtained from these analyses indicate that the control room and off-site doses are within the acceptance criteria of GDC-19 and a fraction of 10 CFR 50.67 limits.
The Reactor Coolant Specific Activity is also limited to a gross activity of 1E9cc1E. Again the 91 pCi accidents under consideration are analyzed assuming a gross activity of =-. The results E cc obtained from these analyses indicate the control room and off-site dose are within the acceptance criteria of GDC-19 and a small fraction of 10 CFR 50.67 limits.
The action of reducing average reactor coolant temperature to < 500°F prevents the release of activity should a steam generator tube rupture occur since the saturation pressure of the reactor coolant is below the lift pressure of the main steam safety valves. The surveillance requirements provide adequate assurance that excessive specific activity levels in the reactor coolant will be detected in sufficient time to take corrective action.
'15' USAR Section 14.0 Amendment No. 167 04/04/2003
RCS Operational LEAKAGE (TS 3.1 Components that contain or transport the coolant to or from the reactor core make up the RCS.
Component joints are made by welding, bolting, rolling, or pressure loading, and valves isolate connecting systems from the RCS.
During plant life, the joint and valve interfaces can produce varying amounts of reactor coolant LEAKAGE, through either normal operational wear or mechanical deterioration. The purpose of the RCS Operational LEAKAGE technical specification (TS) is to limit system operation in the presence of LEAKAGE from these sources to amounts that do not compromise safety. This TS requirement specifies the types and amounts of LEAKAGE.
KPS USAR, GDC Criterion 16 - "Monitoring Reactor Coolant Pressure Boundary," (I7), states that means shall be provided for monitoring the reactor coolant pressure boundary to detect leakage.
USAR section 6.5 describes the capabilities of the leakage monitoring indication systems.
The safety significance of RCS LEAKAGE varies widely depending on its source, rate, and duration. Therefore, detecting and monitoring reactor coolant LEAKAGE into the containment area is necessary. Quickly separating the identified LEAKAGE from the unidentified LEAKAGE is necessary to provide quantitative information to the operators, allowing them to take corrective action should a leak occur that is detrimental to the safety of the facility and the public.
A limited amount of leakage inside containment is expected from auxiliary systems that cannot be made 100% leaktight. Leakage from these systems should be detected, located, and isolated from the containment atmosphere, if possible, to not interfere with RCS leakage detection.
This TS deals with protection of the reactor coolant pressure boundary (RCPB) from degradation and the core from inadequate cooling, in addition to preventing the accident analyses radiation release assumptions from being exceeded. The consequences of violating this TS include the possibility of a loss of coolant accident (LOCA).
APPLICABLE Safety Analysis Except for primary to secondary LEAKAGE, the safety analyses do not address operational LEAKAGE. However, other operational LEAKAGE is related to the safety analyses for LOCA; the amount of leakage can affect the probability of such an event. The safety analysis for an event resulting in steam discharge to the atmosphere assumes that primary to secondary LEAKAGE from the steam generators (SGs) is 150 gallons per day per steam generator ('8)('9)(20)(21). The TS to limit primary to secondary LEAKAGE through any one SG to less than or equal to 150 gallons per day is the conditions assumed in the safety analysis.
Primary to secondary LEAKAGE is a factor in the dose releases outside containment resulting from a steam line break (SLB) accident. Other accidents or transients involve secondary steam release to the atmosphere, such as a steam generator tube rupture (SGTR). locked RCP rotor, and control rod ejection. The primary to secondary LEAKAGE contaminates the secondary fluid.
(I6) USAR Sections 6.5, 11.2.3, 14.2.4
(") Kewaunee Power Station Updated Safety Analysis Report (USAR), Section 1.8, Criteria 16.
USAR Section 14.2.4, "Steam Generator Tube Rupture.
('9)USARSection 14.1.8, Locked Rotor
'20'USARSection 14.2.5, Main Steam Line Break
'2') Westinghouse Calculation CN-CRA-00-70, Rod Ejection Accident Amendment No. 188 TS 83.1-9 711812006
The radiological accident analysis (") for SGTR assumes the contaminated secondary fluid is released to the environment from the ruptured and the intact steam generators. The release from the ruptured SG occurs until 30 minutes after the reactor trip and the release from the intact SG occurs until 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after the reactor trip when RHR is placed in service. The 150 gpd per SG primary to secondary LEAKAGE safety analysis assumption is relatively inconsequential.
The SLB is less limiting for site radiation releases. The safety analysis for the SLB accident assumes 150 gpd primary to secondary LEAKAGE through the affected generator as an initial condition. The dose consequences resulting from the SLB accident are well within the limits defined in 10 CFR 50.67 or the staff approved licensing basis (i.e., a small fraction of these limits).
The RCS operational LEAKAGE satisfies Criterion 2 of 10 CFR 50.36(c)(Z)(ii).
APPLICABILITY When the RCS average temperature is > 200°F, the potential for RCPB LEAKAGE is greatest when the RCS is pressurized.
In COLD SHUTDOWN and REFUELING MODES, LEAKAGE limits are not required because the reactor coolant pressure is far lower, resulting in lower stresses and reduced potentials for LEAKAGE.
SPECIFICATIONS RCS operational LEAKAGE shall be limited to:
A. Pressure Boundary LEAKAGE No pressure boundary LEAKAGE is allowed, being indicative of material deterioration.
LEAKAGE of this type is unacceptable as the leak itself could cause further deterioration.
resulting in higher LEAKAGE. Violation of this TS could result in continued degradation of the RCPB. LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE.
- 6. Unidentified LEAKAGE One gallon per minute (gpm) of unidentified LEAKAGE is allowed as a reasonable minimum detectable amount that the containment air monitoring and containment sump level monitoring equipment can detect within a reasonable time period. Violation of this TS could result in continued degradation of the RCPB, if the LEAKAGE is from the pressure boundary.
Leakage from the Reactor Coolant System is collected in the containment or by the other closed systems. These closed systems are: the Steam and Feedwater System, the Waste Disposal System and the Component Cooling System. Assuming the existence of the maximum allowable activity in the reactor coolant, the rate of 1 gpm unidentified leakage would not exceed the limits of 10 CFR Part 20. This is shown as follows:
'*I Westinghouse Calculation CN-CRA-99-36, Steam Generator Tube Rupture Amendment No. 188 TS 83.1 -1 0 7/18/2006
If the reactor coolant activity is 911E ,uCi/cc ( E = average beta plus gamma energy per disintegration in Mev) and 1 gpm of leakage is assumed to be discharged through the air ejector, or through the Component Cooling System vent line, then the yearly whole body dose resulting from this activity at the SlTE BOUNDARY, using an annual average XIQ = 2.0 x 10-6 sec/n13, is 0.09 rem/yr, compared with the 10 CFR Part 20 limits of 0.1 remlyr.
With the limiting reactor coolant activity and assuming initiation of a 1 gpm leak from the Reactor Coolant System to the Component Cooling System, the radiation monitor in the component cooling pump inlet header would annunciate in the control room. Operators would then investigate the source of the leak and take actions necessary to isolate it. Should the leak result in a continuous discharge to the atmosphere via the component cooling surge tank and waste holdup tank, the resultant dose rate at the SlTE BOUNDARY would be 0.09 remlyr as given above.
Leakage directly into the containment indicates the possibility of a breach in the coolant envelope. The limitation of 1 gpm for an unidentified source of leakage is sufficiently above the minimum detectable leak rate to provide a reliable indication of leakage, and is well below the capacity of one charging pump (60 gpm).
C. ldentified LEAKAGE Up to 10 gpm of identified LEAKAGE is considered allowable because LEAKAGE is from known sources that do not interfere with detection of unidentified LEAKAGE and is well within the capability of the RCS Makeup System. Identified LEAKAGE includes LEAKAGE to the containment from specifically known and located sources, but does not include pressure boundary LEAKAGE or controlled reactor coolant pump (RCP) seal leakoff (a normal function not considered LEAKAGE). Violation of this TS could result in continued degradation of a component or system.
D. Primary to Secondary LEAKAGE through Any One SG The limit of 150 gallons per day limit per SG is based on the operational LEAKAGE performance criterion in NEI 97-06, Steam Generator Program Guidelines (23). The Steam Generator Program operational LEAKAGE performancecriteria in NEI 97-06 states, "The RCS operational primary to secondary leakage through any one SG shall be limited to 150 gallons per day." The limit is based on operating experience with SG tube degradation mechanisms that resulted in tube leakage. The operational leakage rate criterion in conjunction with the implementation of the Steam Generator Program is an effective measure for minimizing the frequency of steam generator tube ruptures.
Unidentified LEAKAGE, or identified LEAKAGE in excess of the TS limits must be reduced to within limits within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. This Completion Time allows time to verify leakage rates and either identify unidentified LEAKAGE or reduce LEAKAGE to within limits before the reactor must be
'23' NEI 97-06. "Steam Generator Program Guidelines.
Amendment No. 188 TS 63.1-11 711812006
shut down. This action is necessary to prevent further deterioration of the RCPB.
If any pressure boundary LEAKAGE exists, or primary to secondary LEAKAGE is not within limits, or if unidentified or identified LEAKAGE cannot be reduced to within limits within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, the reactor must be brought to lower pressure conditions to reduce the severity of the LEAKAGE and its potential consequences. It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE. The reactor must be brought to HOT SHUTDOWN within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and COLD SHUTDOWN within an additional 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. This action reduces the LEAKAGE and also reduces the factors that tend to degrade the pressure boundary.
The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. In COLD SHUTDOWN, the pressure stresses acting on the RCPB are much lower, and further deterioration is much less likely.
If leakage is to the containment, it may be identified by one or more of the following methods:
The containment air particulate monitor is sensitive to low leak rates. The rates of reactor coolant leakage to which the instrument is sensitive are dependent upon the presence of corrosion product activity.
The containment radiogas monitor is less sensitive and is used as a backup to the air particulate monitor. The sensitivity range of the instrument is approximately 2 gpm to
> 10 gpm.
Humidity detection provides a backup to A and 6.The sensitivity range of the instrumentation I is from approximately 2 gpm to 10 gpm.
A leakage detection system is provided which determines leakage losses from all water and steam systems within the containment. This system collects and measures moisture condensed from the containment atmosphere by fancoils of the Containment Air Cooling System and thus provides a dependable and accurate means of measuring integrated total leakage, including leaks from the cooling coils themselves which are part of the containment boundary. The fancoil units drain to the containment sump, and all leakage collected by the containment sump will be pumped to the waste holdup tank. Pump running time will be monitored in the control room to indicate the quantity of leakage accumulated.
If leakage is to another closed system it will be detected by the area and process radiation monitors and/or inventory control.
Amendment No. 188 711812006
Maximum Reactor Coolant Oxyqen, Chloride and Fluoride Concentration (TS 3.1.e)
By maintaining the oxygen, chloride and fluoride concentrations in the reactor coolant below the limits as specified in TS 3.1 .e.l and TS 3.1 .e.4, the integrity of the Reactor Coolant System is ensured under all OPERATING conditions. (24)
If these limits are exceeded, measures can be taken to correct the condition, e.g., replacement of ion exchange resin or adjustment of the hydrogen concentration in the volume control tank.(251 Because of the time-dependent nature of any adverse effects arising from oxygen, chloride, and fluoride concentration in excess of the limits, it is unnecessary to shut down immediately since the condition can be corrected. Thus, the time periods for corrective action to restore concentrations within the limits have been established. If the corrective action has not been effective at the end of the time period, reactor cooldown will be initiated and corrective action will continue.
The effects of contaminants in the reactor coolant are temperature dependent. The reactor may be restarted and operation resumed if the maximum concentration of any of the contaminants did not exceed the permitted transient values; otherwise a safety review by the Plant Operations Review Committee is required before startup.
Minimum Conditions for Criticality (TS 3.1.f)
During the early part of the fuel cycle, the moderator temperature coefficient may be calculated to be positive at I60% RATED POWER. The moderator coefficient will be most positive at the beginning of life of the fuel cycle, when the boron concentration in the coolant is greatest. Later in the fuel cycle, the boron concentrations in the coolant will be lower and the moderator coefficients either will be less positive or will be negative.(26' The requirement that the reactor is not to be made critical except as specified in TS 3.1 .f.l provides increased assurance that the proper relationship between reactor coolant pressure and temperature will be maintained during system heatup and pressurization whenever the reactor vessel is in the nil-ductility temperature range. Heatup to this temperature will be accomplished by operating the reactor coolant pumps and by the pressurizer heaters.
The shutdown margin specified in the COLR precludes the possibility of accidental criticality as a 1 result of an increase in moderator temperature or a decrease in coolant pressure.(lQ)
The requirement that the pressurizer is partly voided when the reactor is < 1% subcritical ensures that the Reactor Coolant System will not be solid when criticality is achieved.
'24' USAR Section 4.2
'"' USAR Section 9.2
'26) USAR Section 3.2.1 Amendment No. 165 0311112003
The requirement that the reactor is not to be made critical when the moderator coefficient is greater than the value specified in the COLR has been imposed to prevent any unexpected power excursion during normal operation as a result of either an increase in moderator temperature or a decrease in coolant pressure. The moderator temperature coefficient limits are required to maintain plant operation within the assumptions contained in the USAR analyses. Having an initial moderator temperature coefficient no greater than the value specified in the COLR provides reasonable assurance that the moderator temperature coefficient will be negative at 60% rated thermal power.
The moderator temperature coefficient requirement is waived during low power physics tests to permit measurement of reactor moderator coefficient and other physics design parameters of interest. During physics tests, special OPERATING precautions will be taken. In addition, the
~ ~ )the small integrated Aktk would limit the magnitude of a strong negative Doppler c ~ e f f i c i e n t 'and power excursion resulting from a reduction in moderator density.
Suitable physics measurements of moderator coefficients of reactivity will be made as part of the startup testing program to verify analytical predictions.
Analysis has shown that maintaining the moderator temperature coefficient at criticality less than or equal to the value specified in the COLR will ensure that a negative coefficient will exist at 60%
power. Current safety analysis supports OPERATING up to 60% power with a moderator temperature coefficient less than or equal to the value specified in the COLR. At power levels I greater than 60%, a negative moderator temperature coefficient must exist.
The calculated hot full power (HFP) moderator temperature coefficient will be more negative than the value specified in the COLR for at least 95% of a cycle's time at HFP to ensure the limitations I associated with and anticipated transient without scram (ATWS) event are not exceeded. NRC approved method^(^')(^') will be used to determine the lowest expected HFP moderatortemperature coefficient for the 5% of HFP cycle time with the highest boron concentration. The cycle time at HFP is the maximum number of days that the cycle could be at HFP based on the design calculation of cycle length. The cycle time at HFP can also be expressed in terms of burnup by converting the maximum number of days at full power to an equivalent burnup. If this HFP moderator temperature coefficient is more negative than the value specified in the COLR, then the ATWS design limit will be I met for 95% of the cycle's time at HFP. If this HFP moderator temperature coefficient design limit is still not met after excluding the 5% of the cycle burnup with the highest boron concentration, then the core loading must be revised.
The results of this design limit consideration will be reported in the Reload Safety Evaluation Report.
USAR Section 3.2.1 (27) "NRC Safety Evaluation Report for Qualification of Reactor Physics, Methods for Application to Kewaunee," dated October 22, 1979.
('*) "NRC Safety Evaluation Report for the Reload Safety Evaluation Methods for Application to Kewaunee," dated April 11, 1988.
Amendment No. 165 0311 112003
In the event that the limits as provided in the COLR are not met, administrative rod withdrawal limits shall be developed to prevent further increases in temperature with a moderator temperature coefficient that is outside analyzed conditions. In this case, the calculated HFP moderator temperature coefficient will be made less negative by the same amount the hot zero power moderator temperature coefficient exceeded the limit as provided in the COLR. This will be accomplished by developing and implementing administrative control rod withdrawal limits to achieve a moderator temperature coefficient within the limits for HFP moderator temperature coefficient.
Due to the control rod insertion limits of TS 3.1 O.d and potentially developed control rod withdrawal limits, it is possible to have a band for control rod location at a given power level. The withdrawal limits are not required if TS 3.1 .f.3 is satisfied or if the reactor is subcritical.
If after 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, withdrawal limits sufficient to restore the moderator temperature coefficient to within the limits as provided in the COLR are not developed, then the plant shall be taken to HOT STANDBY until the moderator temperature coefficient is within the limits as specified in the COLR.
The reactor is allowed to return to criticality whenever TS 3.1 .f is satisfied.
BASIS - Steam Generator Tube lnteqrity (TS 3.1 .q)
BACKGROUND Steam generator (SG) tubes are small diameter, thin walled tubes that carry primary coolant through the primary to secondary heat exchangers. The SG tubes have a number of important safety functions. Steam generator tubes are an integral part of the reactor coolant pressure boundary (RCPB) and, as such, are relied on to maintain the primary system's pressure and inventory. The SG tubes isolate the radioactive fission products in the primary coolant from the secondary system. In addition, as part of the RCPB, the SG tubes are unique in that they act as the heat transfer surface between the primary and secondary systems to remove heat from the primary system. This Specification addresses only the RCPB integrity function of the SG. The SG heat removal function is addressed by TS 3.4. "Steam and Power Conversion" when the RCS average temperature is greater than 350 F," and TS 3.1 .a.2, "Decay Heat Removal Capability," when the RCS temperature is less than or equal to 350 F.
SG tube integrity means that the tubes are capable of performing their intended RCPB safety function consistent with the licensing basis, including applicable regulatory requirements.
Steam generator tubing is subject to a variety of degradation mechanisms. Steam generator tubes may experience tube degradation related to corrosion phenomena, such as wastage, pitting, intergranular attack, and stress corrosion cracking, along with other mechanically induced phenomena such as denting and wear. These degradation mechanisms can impair tube integrity if they are not managed effectively. The SG performance criteria are used to manage SG tube degradation.
Specification 6.22, "Steam Generator (SG) Program," requires that a program be established and implemented to ensure that SG tube integrity is maintained. Pursuant to Specification 6.22, tube integrity is maintained when the SG performance criteria are met. There are three SG performance criteria: structural integrity, accident induced leakage, and operational LEAKAGE.
The SG performance criteria are described in Specification 6.22. Meeting the SG performance criteria provides reasonable assurance of maintaining tube integrity at normal and accident conditions.
Amendment No. 188 711812006
The processes used to meet the SG performance criteria are defined by the Steam Generator Program Guidelines.
APPLICABLE SAFETY ANALYSIS The steam generator tube rupture (SGTR) accident is the limiting design basis event for SG tubes and avoiding an SGTR is the basis for this Specification. The analysis of a SGTR event assumes a bounding primary to secondary LEAKAGE rate equal to the operational LEAKAGE rate limits in TS 3.1 .d, "RCS Operational LEAKAGE," plus the leakage rate associated with a double-ended rupture of a single tube.
The analysis for design basis accidents and transients other than a SGTR assume the SG tubes retain their structural integrity (i.e., they are assumed not to rupture.) In these analyses, the steam discharge to the atmosphere is based on the total primary to secondary LEAKAGE from all SGs of 300 gallons per day, or is assumed to increase to 300 gallons per day as a result of accident induced conditions. For accidents that do not involve fuel damage, the primary coolant activity level of DOSE EQUIVALENT 1-131 is assumed to be equal to the TS 3.1 .c, "Maximum Coolant Activity," limits. For accidents that assume fuel damage, the primary coolant activity is a function of the amount of activity released from the damaged fuel. The dose consequences of these events are within the limits of 10 CFR 50.67 or the NRC approved licensing basis (e.g., a small fraction of these limits).
Steam generator tube integrity satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).
SPECIFICATIONS The TS requires that SG tube integrity be maintained. The TS also requires that all SG tubes that satisfy the repair criteria be plugged in accordance with the Steam Generator Program.
During an SG inspection, any inspected tube that satisfies the Steam Generator Program repair criteria is removed from service by plugging. If a tube was determined to satisfy the repair criteria but was not plugged, the tube may still have tube integrity.
In the context of this Specification, a SG tube is defined as the entire length of the tube, including the tube wall, between the tube-to-tubesheet weld at the tube inlet and the tube-to-tubesheet weld at the tube outlet. The tube-to-tubesheet weld is not considered part of the tube.
A SG tube has tube integrity when it satisfies the SG performance criteria. The SG performance criteria are defined in Specification 6.22, "Steam Generator Program," and describe acceptable SG tube performance. The Steam Generator Program also provides the evaluation process for determining conformance with the SG performance criteria.
There are three SG performance criteria: structural integrity, accident induced leakage, and operational LEAKAGE. Failure to meet any one of these criteria is considered failure to meet the TS.
The structural integrity performance criterion provides a margin of safety against tube burst or collapse under normal and accident conditions, and ensures structural integrity of the SG tubes under all anticipated transients included in the design specification. Tube burst is defined as, "The gross structural failure of the tube wall. The condition typically corresponds to an unstable opening displacement (e.g., opening area increased in response to constant pressure)
Amendment No. 188 711812006
accompanied by ductile (plastic) tearing of the tube material at the ends of the degradation."
Tube collapse is defined as, "For the load displacement curve for a given structure, collapse occurs at the top of the load versus displacement curve where the slope of the curve becomes zero." The structural integrity performance criterion provides guidance on assessing loads that have a significant effect on burst or collapse. In that context, the term "significant" is defined as "An accident loading condition other than differential pressure is considered significant when the addition of such loads in the assessment of the structural integrity performance criterion could cause a lower structural limit or limiting burstlcollapse condition to be established." For tube integrity evaluations, except for circumferential degradation, axial thermal loads are classified as secondary loads. For circumferential degradation, the classification of axial thermal loads as primary or secondary loads will be evaluated on a case-by-case basis. The division between primary and secondary classifications will be based on detailed analysis and/or testing.
Structural integrity requires that the primary membrane stress intensity in a tube not exceed the yield strength for all ASME Code, Section Ill, Service Level A (normal operating conditions) and Service Level B (upset or abnormal conditions) transients included in the design specification.
This includes safety factors and applicable design basis loads based on ASME Code, Section Ill, Subsection NB and Draft Regulatory Guide 1.121.
The accident induced leakage performance criterion ensures that the primary to secondary LEAKAGE caused by a design basis accident, other than a SGTR, is within the accident analysis assumptions. The accident analysis assumes that accident induced leakage does not exceed 150 gallons per day per SG. The accident induced leakage rate includes any primary to secondary LEAKAGE existing prior to the accident in addition to primary to secondary LEAKAGE induced during the accident.
The operational LEAKAGE performance criterion provides an observable indication of SG tube conditions during plant operation. The limit on operational LEAKAGE is contained in TS 3.1.d, "RCS Operational LEAKAGE," and limits primary to secondary LEAKAGE through any one SG to 150 gallons per day. This limit is based on the assumption that a single crack leaking this amount would not propagate to a SGTR under the stress conditions of a LOCA or a main steam line break. If this amount of LEAKAGE is due to more than one crack, the cracks are very small, and the above assumption is conservative.
APPLICABILITY Steam generator tube integrity is challenged when the pressure differential across the tubes is large. Large differential pressures across SG tubes can only be experienced in the OPERATING, HOT STANDBY, HOT SHUTDOWN, or INTERMEDIATE SHUTDOWN MODES.
RCS conditions are far less challenging in the COLD SHUTDOWN or REFUELING MODES than during the OPERATING, HOT STANDBY, HOT SHUTDOWN, or INTERMEDIATE SHUTDOWN MODES. In the COLD SHUTDOWN or REFUELING MODES, primary to secondary differential pressure is low, resulting in lower stresses and reduced potential for LEAKAGE.
ACTIONS The ACTIONS are modified by a Note clarifying that the Conditions may be entered independently for each SG tube. This is acceptable because the Required Actions provide appropriate compensatory actions for each affected SG tube. Complying with the Required Actions may allow for continued operation, and subsequent affected SG tubes are governed by subsequent Condition entry and application of associated Required Actions.
Amendment No. 188 711812006
This TS applies if it is discovered that one or more SG tubes examined in an inservice inspection satisfy the tube repair criteria but were not plugged in accordance with the Steam Generator Program as required by TS 4.1 9. An evaluation of SG tube integrity of the affected tube@) must be made. Steam generator tube integrity is based on meeting the SG performance criteria described in the Steam Generator Program. The SG repair criteria define limits on SG tube degradation that allow for flaw growth between inspections while still providing assurance that the SG performance criteria will continue to be met. In order to determine if a SG tube that should have been plugged has tube integrity, an evaluation must be completed that demonstrates that the SG performance criteria will continue to be met until the next refueling outage or SG tube inspection. The tube integrity determination is based on the estimated condition of the tube at the time the situation is discovered and the estimated growth of the degradation prior to the next SG tube inspection. If it is determined that tube integrity is not being maintained, TS 3.1 .g.3 applies.
A Completion Time of 7 days is sufficient to complete the evaluation while minimizing the risk of plant operation with a SG tube that may not have tube integrity.
If the evaluation determines that the affected tube(s) have tube integrity, Required Action TS 3.1.g.2.B allows plant operation to continue until the next refueling outage or SG inspection provided the inspection interval continues to be supported by an operational assessment that reflects the affected tubes. However, the affected tube(s) must be plugged prior to entering INTERMEDIATE SHUTDOWN following the next refueling outage or SG inspection. This Completion Time is acceptable since operation until the next inspection is supported by the operational assessment.
If the Required Actions and associated Completion Times are not met or if SG tube integrity is not being maintained, the reactor must be brought to HOT SHUTDOWN within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and COLD SHUTDOWN within an additional 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
The allowed Completion Times are reasonable, based on operating experience, to reach the desired plant conditions from full power conditions in an orderly manner and without challenging plant systems.
Amendment No. 188 711812006
The Chemical and Volume Control System provides control of the Reactor Coolant System boron inventory. This is normally accomplished by using any one of the three charging pumps. Also, the Safety Injection pumps can take a suction from the Refueling Water Storage Tank and provide borated water to the Reactor Coolant System.
The quantity of boric acid stored in the Refueling Water Storage Tank is sufficient to achieve COLD SHUTDOWN at any time during core life.
Amendment No. 116 03/28/95
BASIS Engineered Safetv Features and Auxiliarv Svstems (TS 3.3)
The normal procedure for starting the reactor is, first, to heat the reactor coolant to near OPERATING temperature by running the reactor coolant pumps. The reactor is then made critical by withdrawing control rods and/or diluting boron in the coolant.(') With this mode of start-up, the energy stored in the reactor coolant during the approach to criticality is substantially equal to that during power operation and therefore, to be conservative, most engineered safety features components and auxiliary cooling systems shall be fully OPERABLE.
The OPERABLE status of the various systems and components is to be demonstrated by periodic tests, defined by TS 4.5. These periodic tests ensure, with a high reliability, that the various systems will function properly if required to do so. A large fraction of these tests will be performed while the reactor is OPERATING in the power range. If a component is found to be inoperable, it will be possible in most cases to effect repairs and restore the system to full OPERABILITY within a relatively short time. LIMITING CONDITIONS OF OPERATION permit temporary outages of redundant components and are specified for specific time intervals that are consistent with minor maintenance. These permissible conditions and time intervals are specified in such a manner as to apply identically during sustained power operation and during recovery from an inadvertent trip. The transient condition of restart in the latter case in no way alters the types of safety features equipment nor the extent of redundancy that must be available.
Inoperability of a single component does not negate the ability of the system to perform its function, but it reduces the redundancy provided in the plant design and thereby limits the ability to tolerate additional equipment failures. However, the equipment out-of-service times specified in the LIMITING CONDITIONS FOR OPERATION are a temporary relaxation of the single failure criterion, which, consistent with overall system reliability considerations, provides a limited time to restore equipment to the OPERABLE condition. If the inoperable component is not repaired within the specified allowable time period or a second component in the same or related system is found to be inoperable and cannot be repaired within the specified time, the reactor will initially be put in HOT STANDBY and subsequently in the HOT SHUTDOWN condition to reduce the stored energy in the Reactor Coolant System and to provide for the reduction of the decay heat from the fuel. These actions result in a reduction of the cooling requirements after a postulated loss-of-coolant accident. If the malfunction(s) are not corrected after the specified time in a HOT SHUTDOWN condition, the reactor will be placed in the COLD SHUTDOWN condition, utilizing normal shutdown and cooldown procedures. In the COLD SHUTDOWN condition there is no possibility of an accident that would release fission products or damage the fuel elements.
'I' USAR Section 3.2 Amendment No. 103 11/05/93
When the inoperable component is part of the Residual Heat Removal (RHR), Component Cooling Water (CCW) or Service Water (SW) Systems, the average Reactor Coolant System temperature (T), will be maintained below 350°F through an alternate heat removal method.
The various alternate heat removal methods include the redundant RHR train and the steam generators.
Assuming the reactor has been OPERATING at full-rated power for at least 100 days, the magnitude of the decay heat decreases as follows after initiating HOT SHUTDOWN.
Time After Shutdown Decay Heat, % of Rated Power 1 minute 4.5 30 minutes 2.0 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> 1.62 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> 0.96 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> 0.62 Thus the requirement for core cooling in case of a postulated loss-of-coolant accident while in the HOT SHUTDOWN condition is significantly reduced below the requirements for a postulated loss-of-coolant accident during power operation. Putting the reactor in the HOT SHUTDOWN condition significantly reduces the potential consequences of a loss-of-coolant accident, and also allows more free access to some of the engineered safety features in order to effect repairs. Failure to complete repairs after placing the reactor in the HOT SHUTDOWN condition may be indicative of need for major maintenance, and in such cases the reactor should therefore be placed in the COLD SHUTDOWN condition.
TS 3.3.a.2.B provides a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> completion time to restore an accumulator that is inoperable for a reason other than boron concentration. The 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> allowed to restore an inoperable accumulator to operable status is justified in WCAP-15049, Revision 1. (2)
TS 3.3.b.5 provides protection from the possibility of one SI pump reaching runout condition during SI accumulator fill concurrent with a large break LOCA. With both trains of SI and both EDGs operable, the SI system will meet accident analysis.
(') WCAP-I 5049-A, Rev. I , "Risk-Informed Evaluation of an Extension to Accumulator Completion Times," April 1999.
Amendment No. 178 10/05/2004
The containment cooling function is provided by two systems: containment fancoil units and containment spray systems. The containment fancoil units and containment spray system protect containment integrity by limiting the temperature and pressure that could be experienced following a Design Basis Accident. The Limiting Design Basis accidents relative to containment integrity are the loss-of-coolant accident and steam line break. During normal operation, the fancoil units are required to remove heat lost from equipment and piping within the ~ontainment.'~) In the event of the Design Basis Accident, either of the following I combinations will provide sufficient cooling to limit containment pressure to less than design values: four fancoil units or two fancoil units plus one containment spray pump. ) I In addition to heat removal, the containment spray system is also effective in scrubbing fission products from the containment atmosphere. Therefore, a minimum of one train of containment spray is required to remain OPERABLE in order to scavenge iodine fission products from the containment atmosphere and ensure their retention in the containment sump water. (5)(6) I Sodium Hydroxide (NaOH) is added to the spray solution for pH adjustment by means of the spray additive system. The resulting alkaline pH of the spray enhances the ability of the spray to scavenge iodine fission products from the containment atmosphere. The NaOH added in the spray also ensures an alkaline pH for the solution recirculated in the containment sump.
The alkaline pH of the containment sump water inhibits the volatility of iodine and minimizes the occurrence of chloride and caustic stress corrosion on mechanical systems and components exposed to the sump fluid. Test data has shown that no significant stress corrosion cracking will occur provided the pH is adjusted within 2 days following the Design Basis Accident. (7)(8) I A minimum of 300 gallons of not less than 30% by weight of NaOH solution is sufficient to adjust the pH of the spray solution adequately. The additive will still be considered available whether it is contained in the spray additive tank or the containment spray system piping and Refueling Water Storage Tank due to an inadvertent opening of the spray additive valves (CI-1001A and Cl-I 001B).
(3' USAR Section 6.3 (4) USAR Section 6.4
' 5 ) USAR Section 6.4.3 USAR Section 14.3.5 (7) USAR Section 6.4 (8) Westinghouse Chemistry Manual SIP 5-1, Rev. 2, dated 3/77, Section 4.
Amendment No. 178 10/05/2004
The spray additive system may be inoperable for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. The containment spray system would still be available and would remove some iodine from the containment atmosphere in the event of a Design Basis Accident. The 72-hour completion time takes into account the containment spray system capabilities and the low probability of the worst case Design Basis Accident occurring during this period.
One component cooling water pump together with one component cooling heat exchanger can accommodate the heat removal load either following a loss-of-coolant accident or during normal plant shutdown. If, during the post-accident phase, the component cooling water supply were lost, core and containment cooling could be maintained until repairs were effected. (g) I A total of four service water pumps are installed and a minimum of two are required to operate during the postulated loss-of-coolant accident.() The service water valves in the redundant I safeguards headers have to be OPERABLE in order for the components that they supply to be considered OPERABLE.
The various trains of equipment referred to in the specifications are separated by their power supplies (i.e.: SI Pump I A , RHR Pump 1A and Valve SI-4A, etc.). Shared piping and valves are considered to be common to both trains of the systems.
Service Water Header Isolation Logic (TS 3.3.e.l .A.3)
The turbine building service water (SW) header isolation logic automatically closes valves SW-4A and S W 4 B on a Safety Injection (SI) signal coincident with a service water low-pressure signal. Failure to isolate the turbine building from the service water header during a design basis accident may result in insufficient pressure in the containment fan coil units discharge piping or decreased heat removal capability in other safety-related components. The isolation logic is only required to function for the SW train aligned to the turbine building header during a design basis accident.
The isolation logic is OPERABLE when turbine building service water header isolation valves (SW-4A and SW4B) are capable of automatically closing from a safety injection signal coincident with a low header pressure signal from the service water header pressure switches.
If either input into the isolation logic is inoperable, the isolation function can be returned to OPERABLE status by tripping the affected circuit.
To prevent a change in the valve position by a single active failure when the valve or isolation logic is inoperable, the turbine building service water header isolation valve is deactivated.
Removing or interrupting the valves motive force deactivates the isolation valve. De-activation may be accomplished by isolating air to the valve, removing the supply fuse for the solenoid, or any other means for ensuring the valve cannot be affected by a single active failure.
( USAR Section 9.3 (I0) USAR Section 9.6 Amendment No. 178 10/05/2004
BASIS Steam and Power Conversion Svstem (TS 3.4)
Main Steam Safetv Valves (TS 3.4.a)
The ten main steam safety valves (MSSVs) (five per steam generator) have a total combined rated capability of 7,660,380 Ibs./hr. at 1I 8 1 ~ b s . / i npressure.
.~ This flow ensures that the main steam pressure does not exceed 110 percent of the steam generator shell-side design pressure (the maximum pressure allowed by ASME B&PV Code) for the worst-case loss-of-sink-event.
While the plant is in the HOT SHUTDOWN condition, at least two main steam safety valves per steam generator are required to be available to provide sufficient relief capacity to protect the system.
The OPERABILITY of the MSSVs is determined by periodic surveillance testing in accordance with the lnservice Testing Plan.
Auxiliary Feedwater Svstem (TS 3.4.b)
The Auxiliary Feedwater (AFW) System is designed to remove decay heat during plant startups, plant shutdowns, and under accident conditions. During plant startups and shutdowns the system is used in the transition between Residual Heat Removal (RHR) System decay heat removal and Main Feedwater System operation.
The AFW System is considered OPERABLE when the components and flow paths required to provide redundant AFW flow from the AFW pumps to the steam generators are OPERABLE.
This requires that the two motor-driven AFW pumps be OPERABLE, each capable of taking suction from the Service Water System, capable of discharge throttling with AFW-3A or AFW-3B, and supplying AFW to separate steam generators (SGs). The turbine-driven AFW pump is required to be OPERABLE with redundant steam supplies from each of two main steam lines upstream of the main steam isolation valves and shall be capable of taking suction from the Service Water System, capable of discharge throttling with AFW-2C, and supplying AFW to I both of the steam generators. With no AFW trains OPERABLE, immediate action shall be taken to restore a train.
Auxiliary feedwater trains are defined as follows:
" A train - " A motor-driven auxiliary feedwater pump and associated AFW valves and piping to "A" steam generator, not including AFW-1 OA or AFW-1OB "B" train - "B" motor-driven auxiliary feedwater pump and associated AFW valves and piping to "B" steam generator, not including AFW-1 OA or AFW-1OB Turbine-driven Turbine-driven AFW pump and associated AFW valves and piping to train - both "A" steam generator and "B" steam generator, including AFW-1OA and AFW-1OB Amendment No. 183 6/20/2005
Two analyses apply to the Loss of Normal Feedwater event:
- 1. Analysis of the Loss of Normal Feedwater (LONF) event at 1772 MWt.
- 2. Analysis of the Loss of Normal Feedwater event at 1673 MWt.
One AFW pump provides adequate capacity to mitigate the consequences of the LONF event at 1673 MWt. In the LONF event at 1772 MWt, any two of the three AFW pumps are necessary to provide adequate heat removal capacity.
In the unlikely event of a loss of off-site electrical power to the plant, continued capability of decay heat removal would be ensured by the availability of either the steam-driven AFW pump or one of the two motor-driven AFW pumps, and by steam discharge to the atmosphere through the main steam safety valves. Each motor-driven pump and turbine-driven AFW pump is normally aligned to both steam generators. Valves AFW-1OA and AFW-IOB are normally open.
Any single AFW pump can supply sufficient feedwater for removal of decay heat from the reactor.
As the plant is cooled down, heated up, or operated in a low power condition, AFW flow will have to be adjusted to maintain an adequate water inventory in the steam generators. This can be accomplished by any one of the following:
- 1. Throttling the discharge valves on the motor-driven AFW pumps
- 2. Closing one or both of the cross-connect flow valves
- 3. Stopping the pumps If the main feedwater pumps are not in operation at the time, valves AFW-2A and AFW-2B must be throttled or the control switches for the AFW pumps located in the control room will have to be placed in the "pull out" position to prevent their continued operation and overfill of the steam generators. The cross-connect flow valves may be closed to specifically direct AFW flow.
Manual action to re-initiate flow after it has been isolated is considered acceptable based on analyses performed by WPSC and the Westinghouse Electric Corporation. These analyses conservatively assumed the plant was at 100% initial power and demonstrated that operators have at least 10 minutes to manually initiate AFW during any design basis accident with no steam generator dryout or core damage. The placing of the AFW control switches in the "pull out" position, the closing of one or both cross-connect valves, and the closing or throttling of valves AFW-2A and AFW-2B are limited to situations when reactor power is ~ 1 5 % of RATED POWER to provide further margin in the analysis.
During accident conditions, the AFW System provides three functions:
- 1. Prevents thermal cycling of the steam generator tubesheet upon loss of the main feedwater pump
- 2. Removes residual heat via the steam generators from the Reactor Coolant System until (
the temperature drops below 300-350°F and the RHR System is capable of providing the necessary heat sink
- 3. Maintains a head of water in the steam generator following a loss-of-coolant accident Amendment No. 183 6/20/2005
Each AFW pump provides 100% of the required capacity to the steam generators as assumed in the accident analyses performed at 1772 MWt to fulfill the above functions. The exception is the LONF accident analysis performed at 1772 MWt. Based on the LONF accident analysis at 1772 MWt, two AFW pumps are required to provide adequate capacity.
The pumps are capable of automatic starting and can deliver full AFW flow within one minute after the signal for pump actuation. However, analyses from full power demonstrate that initiation of flow can be delayed for at least 10 minutes with no steam generator dryout or core damage. The head generated by the AFW pumps is sufficient to ensure that feedwater can be pumped into the steam generators when the safety valves are discharging and the supply source is at its lowest head.
Analyses by WPSC and the Westinghouse Electric Corporation show that AFW-2A and AFW-2B may be in the throttled or closed position, or the AFW pump control switches located in the control room may be in the "pull out" position without a compromise to safety. This does not constitute a condition of inoperability as listed in TS 3.4.b.l or TS 3.4.b.4. The analysis shows that diverse automatic reactor trips ensure a plant trip before any core damage or system overpressure occurs and that at least 10 minutes are available for the operators to manually initiate auxiliary feedwater flow (start AFW pumps or fully open AFW-2A and AFW-26) for any credible accident from an initial power of 100%.
The OPERABILITY of the AFW System following a main steam line break (MSLB) was reviewed in our response to IE Bulletin 80-04. As a result of this review, requirements for the turbine-driven AFW pump were added to the Technical Specifications. In a secondary line break, it is assumed that the pump discharging to the intact steam generator fails and that the flow from the redundant motor-driven AFW pump is discharging out the break. Therefore, to meet single failure criteria, the turbine-driven AFW pump was added to Technical Specifications.
The OPERABILITY of the AFW system following a LONF event was analyzed as part of the stretch uprate. As a result of the analysis at 1772 MWt, requirements for three OPERABLE AFW trains prior to increasing power above 1673 MWt were added to the Technical Specifications. In a LONF event, it is assumed that one of the AFW pumps fails. Therefore, to meet single failure criteria, all three pumps are required to be OPERABLE prior to increasing power level above 1673 MWt.
For all design basis accidents other than MSLB and the LONF at 1772 MWt, the two motor-driven AFW pumps supply sufficient redundancy to meet single failure criteria.
The cross-connect valves (AFW-1OA and AFW-IOB) are normally maintained in the open position This provides an added degree of redundancy above what is required for all accidents except for a MSLB. During a MSLB, one of the cross-connect valves will have to be repositioned regardless if the valves are normally opened or closed. Therefore, the position of the cross-connect valves does not affect the performance of the turbine-driven AFW train.
However, performance of the train is dependent on the ability of the valves to reposition.
Although analyses have demonstrated that operation with the cross-connect valves closed is acceptable, the TS restrict operation with the valves closed to ~ 1 5 % of RATED POWER. At
> 15% RATED POWER, closure of the cross-connect valves renders the TDAFW train inoperable.
Amendment No. 183 612012005
An AFW train is defined as the AFW system piping, valves and pumps directly associated with providing AFW from the AFW pumps to the steam generators. The action with three trains inoperable is to maintain the plant in an OPERATING condition in which the AFW System is not needed for heat removal. When one train is restored, then the LIMITING CONDITIONS FOR OPERATION specified in TS 3.4.b.2, TS 3.4.b.3, and TS 3.4.b.4 are applied. The two and four hour clocks in TS 3.4.b.3 and TS 3.4.b.4 are started simultaneously. The two hour clock of TS 3.4.b.3 is for the power level restriction. The four-hour clock of TS 3.4.b.4 is for starting the shutdown sequence. Should the plant shutdown be initiated with no AFW trains available, there would be no feedwater to the steam generators to cool the plant to 350°F when the RHR System could be placed into operation.
It is acceptable to exceed 350°F with an inoperable turbine-driven AFW train. However, OPERABILITY of the train must be demonstrated within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> after exceeding 350°F or a plant shutdown must be initiated. This provides 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> with steam pressure for post-maintenance testing of the turbine AFW pump.
AFW Pump Low Discharqe Pressure Trip This Function must be OPERABLE when the average RCS temperature is > 350°F to ensure that the AFW System is available to maintain the SGs as the heat sink for the reactor. This Function does not have to be OPERABLE when the average RCS temperature is 5350°F because RHR is required to be OPERABLE to remove decay heat.
A low discharge pressure signal in the AFW pump discharge line protects the AFW pumps from damage due to runout conditions during alignment and operation of the pumps to a depressurized steam generator. A low-pressure signal sensed by any one of the pump switches will cause the associated AFW pump to trip. Operator action is required to align the associated pump to the non-faulted steam generator, throttle the AFW pump discharge flow, if necessary, and restart the pump(s).
AFW Pump Low Suction Pressure T r i ~
This Function must be OPERABLE when the average RCS temperature is > 350°F to ensure that the AFW System is available for alignment to Service Water for the AFW System to maintain the SGs as the heat sink for the reactor. This Function does not have to be OPERABLE when the average RCS temperature is < 350°F because RHR is required to be OPERABLE to remove decay heat.
A low pressure signal in the AFW pump suction line protects the AFW pumps against a loss of the normal water supply from the condensate storage tanks (CSTs). Three pressure switches are located on the AFW pump suction line from the CST. A low-pressure signal sensed by any one of the switches will cause the associated AFW pump to trip. Operator action is required to bypass the trip circuit or align to the Service Water source and restart the associated AFW pump. Service Water alignment and restart of the AFW pumps ensures an adequate supply of water to maintain at least one of the SGs as the heat sink for reactor decay heat and sensible heat removal.
Amendment No. 183 612012005
Condensate Storaqe Tank (TS 3.4.c)
The specified minimum usable water supply in the condensate storage tanks (CST) is sufficient for four hours of decay heat removal. The four hours are based on the Kewaunee site specific station blackout (loss of all AC power) coping duration requirement. Total CST water supply is maintained above a level that includes minimum usable water supply in technical specifications based on the station blackout analysis, allowance for flow to the condenser before isolation, allowance for AFW pump cooling, unusable level, and instrument error in each tank's level instrument.
The shutdown sequence of TS 3.4.c.3 allows for a safe and orderly shutdown of the reactor plant if the specified limits cannot be met. (I)
Secondaw Activitv Limits (TS 3.4.d)
The maximum dose that an individual may receive following an accident is specified in GDC 19 and 10 CFR 50.67. The limits on secondary coolant activity ensure that the calculated doses are held to the limits specified in GDC 19 and to a fraction of the 10 CFR 50.67 limits.
The secondary side of the steam generator's activity is limited to 5 0.1 pCiIgram DOSE EQUIVALENT 1-131 to ensure the dose does not exceed the GDC-19 and 10 CFR 50.67 guidelines. The applicable accidents identified in the USAR(') are analyzed assuming various inputs including steam generator activity of 0.1 pCi1gram DOSE EQUIVALENT 1-131. The results obtained from these analyses indicate that the control room and off-site doses are within the acceptance criteria of GDC-19 and a fraction of 10 CFR 50.67 limits.
(I)USAR Section 8.2.4 USAR Section 14.0 Amendment No. 183 6/20/2005
BASIS lnstrumentation Svstem (TS 3.5) lnstrumentation has been provided to sense accident conditions and to initiate operation of the engineered safety features.) Section 2.3 of these specifications describes the LIMITING SAFETY SYSTEM SETTINGS for the protective instrumentation.
Safety lniection Safety lnjection can be activated automatically or manually to provide additional water to the Reactor Coolant System or to increase the concentration of boron in the coolant.
Safety lnjection is initiated automatically by ( I ) low pressurizer pressure, (2) low main steam line pressure in either loop and (3) high containment pressure. Protection against a loss-of-coolant accident is primarily through signals (1) and (3). Protection against a steam line break is primarily by means of signal (2).
Manual actuation is always possible. Safety lnjection signals can be blocked during those OPERATING MODES where they are not "required" for safety and where their presence might inhibit operating flexibility; they are generally restored automatically on return to the "required" OPERATING MODE.
Reactor Trip Breakers With the addition of the automatic actuation of the shunt trip attachment, diverse features exist to effect a reactor trip for each reactor trip breaker. Since either trip feature being OPERABLE would initiate a reactor trip on demand, the flexibility is provided to allow plant operation on a reactor trip breaker (with either trip feature inoperable) for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. This specification also requires the plant to proceed to the HOT SHUTDOWN condition in accordance with the Kewaunee STANDARD SHUTDOWN SEQUENCE if a reactor trip breaker is bypassed for greater than 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.
Containment Spray Containment sprays are also actuated by a high containment pressure signal (Hi-Hi) to reduce containment pressure in the event of a loss-of-coolant or steam line break accident inside the containment.
The containment sprays are actuated at a higher containment pressure (approximately 50% of design containment pressure) than is Safety lnjection (10% of design). Since spurious actuation of containment spray is to be avoided, it is initiated only on coincidence of high containment pressure (Hi-Hi) sensed by three sets of one-out-of-two containment pressure signals provided for its actuation.
( I ) USAR Section 7.5 Amendment No. 101 09/30/93
Containment Isolation A containment isolation signal is initiated by any signal causing automatic initiation of Safety lnjection or may be initiated manually. The containment isolation system provides the means of isolating the various pipes passing through the containment walls as required to prevent the release of radioactivity to the outside environment in the event of a loss-of-coolant accident.
Steam Line Isolation In the event of a steam line break, the steam line isolation valve of the affected line is automatically isolated to prevent continuous, uncontrolled steam release from more than one steam generator.
The steam lines are isolated on Hi-Hi containment pressure or high steam flow in coincidence with Lo-Lo T ,, and Safety lnjection or Hi-Hi steam flow in coincidence with Safety Injection. Adequate protection is afforded for breaks inside or outside the containment even under the assumption that the steam line check valves do not function properly.
Main Feedwater Isolation Main feedwater isolation actuation occurs as a result of a Hi-Hi steam generator water level to prevent steam generator overfill conditions. Steam generator overfill may result in damage to secondary components; for example, high moisture steam could erode the turbine blades at an accelerated rate.
Settinq Limits
- 1. The high containment pressure limit is set at about 10% of the maximum internal pressure.
lnitiation of Safety lnjection protects against loss-of-coo~ant(~)
or steam line break(3)accidents as discussed in the safety analysis.
- 2. The Hi-Hi containment pressure limit is set at about 50% of the maximum internal containment pressure for initiation of containment spray and at about 40% for initiation of steam line 1 isolation. lnitiation of containment spray and steam line isolation protects against large loss-of-coolant or steam line break accidents as discussed in the safety analysis.
- 3. The pressurizer low-pressure limit is set substantially below system operating pressure limits.
However, it is sufficiently high to protect against a loss-of-coolant accident as shown in the safety analysis.
(2) USAR Section 14.3 (3) USAR Section 14.2.5
- 4. The steam line low-pressure signal is leadllag compensated and its setpoint is set well above the pressure expected in the event of a large steam line break accident as shown in the safety analysis.
- 5. The high steam line flow limit is set at approximately 20% of nominal full-load flow at the no-load pressure and the Hi-Hi steam line flow limit is set at approximately 120% of nominal full-load flow at the full-load pressure in order to protect against large steam line break accidents. The coincident Lo-Lo ,T ,, setting limit for steam line isolation initiation is set below its HOT SHUTDOWN value. The safety analysis shows that these settings provide protection in the event of a large steam line break.
- 6. The setpoints and associated ranges for the undervoltage relays have been established to always maintain motor voltages at or above 80% of their nameplate rating, to prevent prolonged operation of motors below 90% of their nameplate rating, and to prevent prolonged operation of 480 V MCC starter contactors at inrush currents.(4) All safeguard motors were designed to accelerate their loads to operating speed with 80% nameplate voltage, but not necessarily within their design temperature rise. Prolonged operation below 90% of nameplate voltage may result in shortening of motor insulation life, but short-term operation below 90% of nameplate voltage will not result in unacceptable effects due to the service factor provided in the motors and the conservative insulation system used on the motors. Prolonged operation of MCC contactors at inrush currents may result in blown control fuses and inoperable equipment; therefore operation will be limited to a time less than it takes for a fuse to blow.
The primary safeguard buses undervoltage trip (85.0% of nominal bus voltage) is designed to protect against a loss of voltage to the safeguard bus and assures that safeguard protection action will proceed as assumed in the USAR. The associated time delay feature prevents inadvertent actuation of the undervoltage relays from voltage dips, while assuring that the diesel generators will reach full capacity before the Safety Injection pump loads are sequenced on.
The safeguard buses second level undervoltage trip (93.6% nominal bus voltage) is designed to protect against prolonged operation below 90% of nameplate voltage of safeguard pumps. The time delay of less than 7.4 seconds ensures that engineered safeguards equipment operates within the time delay assumptions of the accident analyses. The time delay will prevent blown control fuses in 480 V MCC's; the MCC control fuses are the limiting component for long-term low voltage operation. The time delay is long enough to prevent inadvertent actuation of the second level UV relays from voltage dips due to large motor starts (except reactor (4' USAR section 8.2.3
coolant pump starts with a safeguards bus below 3980 volts). Up to 7.4 seconds of operation of safeguard pumps between 80% and 90% of nameplate voltage is acceptable due to the service factor and conservative insulation designed into the motors.
Each relay in the undervoltage protection channels will fail safe and is alarmed to alert the operator to the failure.
A blackout signal which occurs during the sequence loading following a Safety lnjection signal will result in a re-initiation of the sequence loading logic at time step 0 as long as the Safety lnjection signal has not been reset. The Kewaunee Emergency Procedures warn the operators that a Blackout Signal occurring after reset of Safety lnjection will not actuate the sequence loading and instructs to re-initiate Safety lnjection if needed.
Instrument OPERATING Conditions During plant OPERATIONS, the complete protective instrumentation systems will normally be in service. Reactor safety is provided by the Reactor Protection Systems, which automatically initiates appropriate action to prevent exceeding established limits. Safety is not compromised, however, by continuing OPERATION with certain instrumentation channels out of service since provisions were made for this in the plant design. This specification outlines LIMITING CONDITIONS FOR OPERATION necessary to preserve the effectiveness of the Reactor Control and PROTECTION SYSTEM when any one or more of the channels is out of service.
Almost all reactor protection channels are supplied with sufficient redundancy to provide the capability for CHANNEL CALIBRATION and test at power. Exceptions are backup channels such as reactor coolant pump breakers. The removal of one trip channel on process control equipment is accomplished by placing that channel bistable in a tripped mode; e.g., a two-out-of-three circuit becomes a one-out-of-two circuit. The source and intermediate range nuclear instrumentation system channels are not intentionally placed in a tripped mode since these are one-out-of-two trips, and the trips are therefore bypassed during testing. Testing does not trip the system unless a trip condition exists in another channel.
The OPERABILITY of the instrumentation noted in Table TS 3.5-6 assures that sufficient information is available on these selected plant parameters to aid the operator in identification of an accident and assessment of plant conditions during and following an accident. In the event the instrumentation noted in Table TS 3.5-6 is not OPERABLE, the operator is given instruction on compensatory actions.
BASIS Containment Svstem lnteqritv (TS 3.6.a)
The COLD SHUTDOWN condition precludes any energy releases or buildup of containment pressure from flashing of reactor coolant in the event of a system break. The restriction to fuel that has been irradiated during power operation allows initial testing with an open containment when negligible activity exists. The shutdown margin for the COLD SHUTDOWN condition assures subcriticality with the vessel closed even if the most reactive RCC assembly were inadvertently withdrawn. Therefore, the two parts of TS 3.6.a allow CONTAINMENT SYSTEM INTEGRITY to be violated when a fission product inventory is present only under circumstances that preclude both criticality and release of stored energy.
When the reactor vessel head is removed with the CONTAINMENT SYSTEM INTEGRITY violated, the reactor must not only be in the COLD SHUTDOWN condition, but also in the REFUELING shutdown condition. A 5% shutdown margin is specified for REFUELING conditions to prevent the occurrence of criticality under any circumstances, even when fuel is being moved during REFUELING operations.
This specification also prevents positive insertion of reactivity whenever Containment System integrity is not maintained if such addition would violate the respective shutdown margins.
Effectively, the boron concentration must be maintained at a predicted concentration of 2,200 ppm(')
or more if the Containment System is to be disabled with the reactor pressure vessel open.
Containment Isolation Valves (TS 3.6.b)
Containment isolation valves form a part of the containment boundary. The containment isolation valves' safety function is related to minimizing the loss of reactor coolant inventory and establishing the containment boundary during a DBA.
To be considered OPERABLE, automatic containment isolation valves are required to close within prescribed time limits and to actuate on an automatic isolation signal. Check valves are considered OPERABLE when they have satisfactorily completed their required surveillance testing. Manual isolation components are considered OPERABLE when manual valves are closed, blind flanges are in place, and closed systems are intact.
Penetration flow path(s) may be unisolated intermittently under administrative controls. These administrative controls consist of stationing a dedicated operator at the valve controls, who is in (I) USAR Table 3.2-1 Amendment No. 155 06/08/2001
continuous communication with the control room. In this way, the penetration can be rapidly isolated when a need for containment isolation is indicated. Specification TS 3.6.b.2 pertains to inoperable valves described in TS 3.6.b.3, manual valves assumed to be closed, and normally closed valves that are not assumed, by the USAR, to automatically close. This allows opening of containment isolation valves without entering the L C 0 or to open containment isolation valves closed as required by TS, provided the administrative controls are in place to ensure valve closure, if needed.
For these LCO(s), separate Condition entry is allowed for each penetration flow path. This is acceptable, since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable containment isolation valve. Complying with the Required Actions may allow for continued operation, and subsequent inoperable containment isolation valves are governed by subsequent Condition entry and application of associated Required Actions.
In the event a containment isolation valve in one or more penetration flow paths is inoperable, the affected penetration flow path must be isolated within the specified time constraints. The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are I ) a closed and de-activated automatic containment isolation valve, 2) a closed manual valve, 3) a blind flange, and 4) a check valve with flow through the valve secured, For a penetration flow path isolated, the device used to isolate the penetration should be the closest available one to containment. The 24-hour completion time is reasonable, considering the time required to isolate the penetration, perform maintenance, and the relative importance of supporting containment OPERABILITY.
For affected containment penetration flow paths that cannot be restored to OPERABLE status within the required completion time and that have been isolated, the affected penetration flow paths must be verified to be isolated on a periodic basis. This is necessary to ensure containment penetrations, requiring isolation following an accident and no longer capable of being automatically isolated, will be in that isolated position should an event occur. This Required Action does not require any testing or device manipulation. Rather, it involves verification, through a system walkdown, that those isolation devices outside containment and capable of being mispositioned are in the correct position. For the isolation devices inside containment, the time period is specified as "prior to entering INTERMEDIATE SHUTDOWN from COLD SHUTDOWN if not performed within the previous 92 days." This is based on engineering judgment and is considered reasonable in view of the inaccessibility of the isolation devices and other administrative controls that will ensure that isolation device misalignment is an unlikely possibility.
Amendment No. 155 06/08/2001
With two containment isolation valves in one or more penetration flow paths inoperable, the affected penetration flow path must be isolated within Ihour. The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a closed and de-activated automatic valve, a closed manual valve, and a blind flange. The I-hour Completion Time is consistent with the ACTIONS of L C 0 3.0.c. In the event the affected penetration is isolated, the affected penetration must be verified to be isolated on a periodic basis which remains in effect. This periodic verification is necessary to assure leak tightness of containment and that penetrations requiring isolation following an accident are isolated. The Completion Time of "once per 31 days for verifying each affected penetration flow path is isolated" is appropriate considering the fact that the valves are operated under administrative control and the probability of their misalignment is low.
For those penetrations where one of the isolation devices is a closed system, either inside containment or outside containment, a longer outage time is allowed. This condition is only applicable to those penetration flow paths with a single containment isolation valve and a closed system. This longer outage time is due to a closed system subjected to leakage testing, missile protected, and seismic category I piping. Also, a closed system typically has flow through it during normal operation such that any loss of integrity could be observed through leakage detection system inside containment and system walkdowns outside containment. Thus, a 72-hour completion time is considered appropriate given that certain valves may be located inside containment and the reliability of the closed system.
Isolation devices located in high radiation areas shall be verified closed by use of administrative means. Verification by administrative means is considered acceptable, since access to these areas is typically restricted. Therefore, the probability of misalignment of these devices once they have been verified to be in the proper position is small.
De-activation of an automatic containment isolation valve is accomplished by removing or interrupting the valves motive force, thus, preventing a change in the valve position by a single active failure. De-activation may be accomplished by opening the supply breaker for a motor operated valve, isolating air to an air operated valve, removing the supply fuse for a solenoid operated valve, or any other means for ensuring the isolation barrier cannot be affected by a single active failure.
Amendment No. 155 06/08/2001
Ventilation Systems (TS 3.6.c)
Proper functioning of the Shield Building Ventilation System is essential to the performance of the Containment System. Therefore, except for reasonable periods of maintenance outage for one redundant train of equipment, the complete system should be in readiness whenever CONTAINMENT SYSTEM INTEGRITY is required. Proper functioning of the Auxiliary Building Special Ventilation System is similarly necessary to preclude possible unfiltered leakage through penetrations that enter the Special Ventilation Zone (Zone SV).
Both the Shield Building Ventilation System and the Auxiliary Building Special Ventilation System are designed to automatically start following a safety injection signal. Each of the two trains of both systems has 100% capacity. If one train of either system is found to be inoperable, there is not an immediate threat to the containment system performance and reactor operation may continue while repairs are being made. If both trains of either system are inoperable, the plant will be brought to a condition where the air purification system would not be required.
High efficiency particulate air (HEPA) filters are installed before the charcoal adsorbers to prevent clogging of the iodine adsorbers. The charcoal adsorbers are installed to reduce the potential radioiodine release to the atmosphere. Bypass leakage for the charcoal adsorbers and particulate removal efficiency for HEPA filters are determined by halogenated hydrocarbon and DOP respectively. The laboratory carbon sample test results indicate a radioactive methyl iodine removal efficiency under test conditions which are more severe than accident conditions.
Operation of the fans significantly different from the design flow will change the removal efficiency of the HEPA filters and charcoal adsorbers. The performance criteria for the safeguard ventilation fans are stated in Section 5.5 and 9.6 of the USAR. If the performances are as specified, the calculated doses would be less than the guidelines stated in 10 CFR Part 100 for the accidents analyzed.
In-place testing procedures will be established utilizing applicable sections of ANSI N510 - 1975 standard as a procedural guideline only.
Accident analysis assumes a charcoal adsorber efficiency of go%.(') To ensure the charcoal adsorbers maintain that efficiency throughout the operating cycle, a safety factor of 2 is used.
Therefore, if accident analysis assumes a charcoal adsorber efficiency of 90%, this equates to a methyl iodide penetration of 10%. If a safety factor of 2 is assumed, the methyl iodide penetration is reduced to 5%. Thus, the acceptance criteria of 95% efficient will be used for the charcoal adsorbers.
(*) USAR TABLE 14.3-8, "Major Assumptions for Design Basis LOCA Analysis" Amendment No. 155 06/08/2001
Although committing to ASTM D3803-89, it was recognized that ASTM D3803-89 Standard references Military Standards MIL-F-51068D, Filter, Particulate High Efficiency, Fire Resistant, and MIL-F-51079A, Filter, Medium Fire Resistant, High Efficiency, these specification have been superseded. The latest versions, MIL-F-51068F and MIL-F-51079D, have been canceled and superseded by ASME AG-1, Code on Nuclear Air and Gas Treatment. This is an acceptable situation. Consequently, other referenced standards can be substituted if the new standard or methodology is shown to provide equivalent or superior performance to those referenced in ASTM D3803-89.
Containment Pressure (TS 3.6.d)
The 2 psi limit on internal pressure provides adequate margin between the maximum internal pressure of 46 psig and the peak accident pressure resulting from the postulated Design Basis Accident as discussed in Sections 14.2 and 14.3 of the USAR.(~)
The reactor containment vessel is designed for 0.8 psi internal vacuum, the occurrence of which will be prevented by redundant vacuum breaker systems.
Containment Temperature (TS 3.6.e)
The requirement of a 40°F minimum containment ambient temperature is to assure that the minimum containment vessel metal temperature is well above NDTT + 30" criterion for the shell material.
(3) USAR Section 5 Amendment No. 155 06/08/2001
BASIS - Auxiliarv Electrical Systems (TS 3.7)
The intent of this TS is to provide assurance that at least one external source and one standby source of electrical power is always available to accomplish safe shutdown and containment isolation and to operate required engineered safety features equipment following an accident.
Plant safeguards auxiliary power is normally supplied by two separate external power sources which have multiple off-site network connections (I): the reserve auxiliary transformer from the 138-Kv portion of the plant substation, and a tertiary winding on the substation auto transformer.
Either source is sufficient to supply all necessary accident and post-accident load requirements from any one of four available transmission lines.
Each diesel generator is connected to one 4160-V safety features bus and has sufficient capacity to start sequentially and operate the engineered safety features equipment supplied by that bus. The set of safety features equipment items supplied by each bus is, alone, sufficient to maintain adequate cooling of the fuel and to maintain containment pressure within the design value in the event of a loss-of-coolant accident.
Each diesel generator starts automatically upon low voltage on its associated bus, and both diesel generators start in the event of a safety injection signal.(2)A minimum of 7 days fuel supply for one diesel generator is maintained by requiring 36,000 gallons of fuel oil, thus assuring adequate time to restore off-site power or to replenish fuel. The diesel fuel oil storage capacity requirements are consistent with those specified in ANSI N195-1976lANS-59.51, Sections 5.2, 5.4, and 6.1.
The plant safeguards 125-V d-c power is normally supplied by two batteries each of which will have a battery charger in service to maintain full charge and to assure adequate power for starting the diesel generators and supplying other emergency loads. A third charger is available to supply either battery.(3)
The arrangement of the auxiliary power sources and equipment and this TS ensure that no single fault condition will deactivate more than one redundant set of safety features equipment items and will therefore not result in failure of the plant protection systems to respond adequately to a loss-of-coolant accident.
(I) USAR Figure 8.2-1 and 8.2-2 (2) USAR Section 8.2.3 (3) USAR Section 8.2.2 and 8.2.3
BASIS - Refuelina Operations (TS 3.8)
The equipment and general procedures to be utilized during REFUELING OPERATIONS are discussed in the USAR. Detailed instructions, the above specified precautions, and the design of the fuel handling equipment incorporating built-in interlocks and safety features, provide assurance that no incident occurs during the REFUELING OPERATIONS that would result in a hazard to public health and safety.(') Whenever changes are not being made in core geometry, one flux monitor is sufficient. This permits maintenance of the instrumentation. Continuous monitoring of radiation levels (TS 3.8.a.2) and neutron flux provides immediate indication of an unsafe condition. The residual heat removal pump is used to maintain a uniform boron concentration.
A minimum shutdown margin of greater than or equal to 5% Ak/k must be maintained in the core. The boron concentration as specified in the COLR is sufficient to ensure an adequate margin of safety. The specification for REFUELING OPERATIONS shutdown margin is based on a dilution during refueling a~cident.'~) With an initial shutdown margin of 5% Aklk, under the postulated accident conditions, it will take longer than 30 minutes for the reactor to go critical.
This is ample time for the operator to recognize the audible high count rate signal, and isolate the reactor makeup water system. Periodic checks of refueling water boron concentration ensure that proper shutdown margin is maintained. Specification 3.8.a.6 allows the control room operator to inform the manipulator operator of any impending unsafe condition detected from the main control board indicators during fuel movement.
Interlocks are utilized during REFUELING OPERATIONS to ensure safe handling. Only one assembly at a time can be handled. The fuel handling hoist is dead weight tested prior to use to assure proper crane operation. It will not be possible to lift or carry heavy objects over the spent fuel pool when fuel is stored therein through interlocks and administrative procedures.
Placement of additional spent fuel racks will be controlled by detailed procedures to prevent traverse directly above spent fuel.
The one hundred forty-eight hour decay time following plant shutdown bounds the assumption used in the dose calculation for the fuel handling accident. A cycle-specific cooling analysis will be performed to verify that the spent fuel pool cooling system can maintain the pool temperature within allowable limits based on the one hundred forty-eight hour decay time. In the unlikely event that the analysis determines this time is not sufficient to maintain acceptable pool temperature, the analysis will determine the additional in core hold time required. The requirement for the spent fuel pool sweep system, including charcoal adsorbers, to be operating when spent fuel movement is being made provides added assurance that the off-site doses will be within acceptable limits in the event of a fuel handling accident. The spent fuel pool sweep system is designed to sweep the atmosphere above the refueling pool and release to the Auxiliary Building vent during fuel handling operations. Normally, the charcoal adsorbers are bypassed but for purification operation, the bypass dampers are closed routing the air flow through the charcoal adsorbers. If the dampers do not close tightly, bypass leakage could exist to negate the usefulness of the charcoal adsorber. If the spent fuel pool sweep system is found not to be operating, fuel handling within the Auxiliary Building will be terminated until the system can be restored to the operating condition.
(I) USAR Section 9.5.2
(') USAR Section 14.1 Amendment 172 02/27/2004
The bypass dampers are integral to the filter housing. The test of the bypass leakage around the charcoal adsorbers will include the leakage through these dampers.
High efficiency particulate absolute (HEPA) filters are installed before the charcoal adsorbers to prevent clogging of the iodine adsorbers. The charcoal adsorbers are installed to reduce the potential radioiodine releases to the atmosphere. Bypass leakage for the charcoal adsorbers and particulate removal efficiency for HEPA filters are determined by halogenated hydrocarbon and DOP, respectively. The laboratory carbon sample test results indicate a radioactive methyl iodide removal efficiency under test conditions which are more severe than accident conditions.
Operation of the fans significantly different from the design flow will change the removal efficiency of the HEPA filters and charcoal adsorbers. If the performances are as specified, the calculated doses would be less than the guidelines stated in 10 CFR Part 50.67 for the I accidents analyzed.
The spent fuel pool sweep system will be operated for the first month after reactor is shutdown for refueling during fuel handling and crane operations with loads over the pool. The potential consequences of a postulated fuel handling accident without the system are a very small fraction of the guidelines of 10 CFR Part 50.67 after one month decay of the spent fuel. Heavy 1 loads greater than one fuel assembly are not allowed over the spent fuel.
In-place testing procedures will be established utilizing applicable sections of ANSI N510 - 1975 standard as a procedural guideline only.
A fuel handling accident in containment does not cause containment pressurization. One containment door in each personnel air lock can be closed following containment personnel evacuation and the containment ventilation and purge system has the capability to initiate automatic containment ventilation isolation to terminate a release path to the atmosphere.
The presence of a licensed senior reactor operator at the site and designated in charge provides qualified supervision of the REFUELING OPERATIONS during changes in core geometry.
Accident analysis assumes a charcoal adsorber efficiency of To ensure the charcoal adsorbers maintain that efficiency throughout the operating cycle, a safety factor of 2 is used.
Therefore, if accident analysis assumes a charcoal adsorber efficiency of 90%, this equates to a methyl iodide penetration of 10%. If a safety factor of 2 is assumed, the methyl iodide penetration is reduced to 5%. Thus, the acceptance criteria of 95% efficient will be used for the charcoal adsorbers.
Although committing to ASTM D3803-89, it was recognized that ASTM D3803-89 Standard references Military Standards MIL-F-51068D, Filter, Particulate High Efficiency, Fire Resistant, and MIL-F-51079A, Filter, Medium Fire Resistant, High Efficiency. These specifications have been revised and the latest revisions are, MIL-F-51068F and MIL-F-51079D. These revisions have been canceled and superseded by ASME AG-1, Code on Nuclear Air and Gas Treatment.
ASME AG-1 is an acceptable substitution. Consequently, other referenced standards can be substituted if the new standard or methodology is shown to provide equivalent or superior performance to those referenced in ASTM D3803-89.
(3) USAR TABLE 14.3-8, "Major Assumptions for Design Basis LOCA Analysis" Amendment 172 02/27/2004
BASIS-Control Rod and Power Distribution Limits (TS 3.10)
Shutdown Reactivitv (TS 3.1 O.a)
Trip shutdown reactivity is provided consistent with plant safety analysis assumptions. To maintain the required trip reactivity, the rod insertion limits as specified in the COLR must be observed. In addition, for HOT SHUTDOWN conditions, the shutdown margin as specified in the COLR must be provided for protection against the steam line break accident.
Rod insertion limits are used to ensure adequate trip reactivity, to ensure meeting power distribution I limits, and to limit the consequences of a hypothetical rod ejection accident.
The exception to the rod insertion limits in TS 3.10.d.3 is to allow the measurement of the worth of all rods. This measurement is a part of the Reactor Physics Test Program performed at the startup of each cycle. Rod worth measurements augment the normal fuel cycle design calculations and place the knowledge of shutdown capability on a firm experimental as well as analytical basis.
Operation with abnormal rod configuration during low power and zero power testing is permitted because of the brief period of the test and because special precautions are taken during the test.
TS 1.O.r, "Shutdown Margin," states the definition of shutdown margin as used in the technical specifications. As a part of this definition is a statement which removes the assumption that the highest reactivity worth rod cluster control assembly (RCCA) is fully withdrawn. This includes the verification that all RCCA's are fully inserted by two independent means. Although not fully independent, this requirement refers to indications which are independent. These independent means include such indicators as the control board individual rod position indicators or the rod position as indicated on the plant process computer system (PPCS) or the condition monitors referenced in TS 3.10.e.
Power Distribution Control (TS 3.10.b)
Criteria Criteria have been chosen for Condition I and II events as a design basis for fuel performance related to fission gas release, pellet temperature, and cladding mechanical properties. First, the peak value of linear power density must not exceed the value assumed in the accident analyses. The peak linear power density is chosen to ensure peak clad temperature during a postulated large break loss-of-coolant accident is less than the 2200°F limit. Second, the minimum DNBR in the core must not be less than the DNBR limit in normal operation or during Condition I or II transient events.
Amendment No. I 6 5 0311 1I2003
FQN(z),Heiqht Dependent Nuclear Flux Hot Channel Factor FQN(z),Height Dependent Nuclear Flux Hot Channel Factor, is defined as the maximum local linear power density in the core at core elevation Z divided by the core average linear power density, assuming nominal fuel rod dimensions.
An upper bound envelope for F ~ ~ (as z )specified in the COLR has been determined from extensive analyses considering all OPERATING maneuvers consistent with the Technical Specifications on power distribution control as given in TS 3.10. The results of the loss-of-coolant accident analyses based on this upper bound envelope indicate the peak clad temperatures, with a high probability, remain less than the 2200 OF limit.
The FQN(z)limits as specified in the COLR are derived from the LOCA analyses. The LOCA analyses are performed for Westinghouse 422 V+ fuel, FRA-ANP heavy fuel and for FRA-ANP standard fuel.
When a F ~ ~ (measurement z) is taken, both experimental error and manufacturing tolerance must be allowed for. Five percent is the appropriate allowance for a full core map taken with the movable incore detector flux mapping system and 3% is the appropriate allowance for manufacturing tolerance.
F ~ ~ (isz arbitrarily
) limited for P 5 0.5 (except for low power physics tests).
FQEQ(z)is the measured FQN(z)obtained at equilibrium conditions during the target flux determination. FQEQ(z) must satisfy the relationship that is in the COLR.
Because the value of FQN(z)represents an equilibrium condition, it does not include the variations of F ~ ~ ( which z) are present during non-equilibrium situations such as load following or power ascension. To account for these possible variations, the equilibrium value of FQN(z)is adjusted by an elevation dependent factor, W(z), that accounts for the calculated worst case transient conditions. Core power distribution is controlled under non-equilibrium conditions by operating the core within the core operating limits on axial flux distribution, quadrant power tilt, and control rod insertion.
If a power distribution measurement indicates that the F ~ ~ (transient Z) relationship's margin to the limit has decreased since the previous evaluation then TS 3.10.b.6.C provides two options of either increasing the F ~ ~ ~transient
( z ) relationship by the appropriate penalty factor or increasing the power distribution surveillance to once every 7 EFPD until two successive flux maps indicate that the F ~ ~ " ( Ztransient
) relationship's margin to the limit has not decreased. IF F ~ ~ ~with ( z the
)
penalty factor applied is greater than the limit, then TS 3.10.b.6 is not satisfied and TS 3.10.b.7 should be applied to maintain the normal surveillance interval. Based on TS 3.10.b.7.A, the axial flux distribution (AFD) limits are reduced by 1% for each 1% that the FQEQ(z) transient relationship exceeds its limit within the allowed time of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.
The contingency actions of TS 3.10.b.6 and TS 3.10.b.7 are to ensure that FQN(z)does not exceed its limit for any significant period of time without detection. Satisfying limits on F ~ ~ (ensures z) that the safety analyses remain bounding and valid.
EMN Nuclear Enthalpv Rise Hot Channel Factor FAHN, Nuclear Enthalpy Rise Hot Channel Factor, is defined as the ratio of the maximum integral of linear power along a fuel rod to the core average integral fuel rod power.
It should be noted that FAHNis based on an integral and is used as such in DNBR calculations.
Local heat fluxes are obtained by using hot channel and adjacent channel explicit power shapes which take into account variations in horizontal (x-y) power shapes throughout the core. Thus, the horizontal power shape at the point of maximum heat flux is not necessarily directly related to FAHN.
The FAHN limit is determined from safety analyses of the limiting DNBR transient events. The safety analyses are performed for FRA-ANP heavy fuel, FRA-ANP standard fuel, and Westinghouse 422 V+ fuel. In these analyses, the important operational parameters are selected to minimize DNBR.
The results of the safety analyses must demonstrate that minimum DNBR is greater than the DNBR limit for a fuel rod operating at the FAHNlimit.
The use of FAHN in TS 3.10.b.5.C is to monitor "upburn" which is defined as an increase in FAHN with exposure. Since this is not to be confused with observed changes in peak power resulting from such phenomena as xenon redistribution, control rod movement, power level changes, or changes in the number of instrumented thimbles recorded, an allowance of 2% is used to account for such changes.
Rod Bow Effects No penalty for rod bow effects needs to be included in TS 3.10.b.l for FRA-ANP fuel.)
Surveillance Measurements of the hot channel factors are required as part of startup physics tests, at least each full power month of operation, and whenever abnormal power distribution conditions require a reduction of core power to a level based on measured hot channel factors. The incore map taken following initial loading provides confirmation of the basic nuclear design bases including proper fuel loading patterns. The periodic monthly incore mapping provides additional assurance that the nuclear design bases remain inviolate and identifies operational anomalies which would otherwise affect these bases.
For normal operation, it is not necessary to measure these quantities. Instead it has been determined that, provided certain conditions are observed, the hot channel factor limits will be met.
These conditions are as follows:
- 1. Control rods in a single bank move together with no individual rod insertion differing by more than an indicated 12 steps from the bank demand position where reactor power is 2 85%, or an indicated 24 steps when reactor power is < 85%.
- 2. Control rod banks are sequenced with overlapping banks as specified in the COLR.
- 3. The control bank insertion limits as specified in the COLR are not violated, except as allowed by TS 3.10.d.2.
- 4. The axial power distribution, expressed in terms of axial flux difference, is maintained within the limits.
The limits on axial flux difference (AFD) assure that the axial power distribution is maintained such that the FQ(Z) upper bound envelope of FQLlMlT times the normalized axial peaking factor [K(Z)] is not exceeded during either normal operation or in the event of xenon redistribution following power changes. This ensures that the power distributions assumed in the large and small break LOCA analyses will bound those that occur during plant operation.
Provisions for monitoring the AFD on an automatic basis are derived from the plant process computer through the AFD monitor program. The computer determines the AFD for each of the operable excore channels and provides a computer alarm if the AFD for at least 2 of 4 or 2 of 3 operable excore channels are outside the AFD limits and reactor power is greater than 50 percent or RATED POWER.
For Condition II events the core is protected from overpower and a minimum DNBR less than the DNBR limit by an automatic Protection System. Compliance with the specification is assumed as a precondition for Condition II transients; however, operator error and equipment malfunctions are separately assumed to lead to the cause of the transients considered.
("N. E. Hoppe, "Mechanical Design Report Supplement for Kewaunee High Burnup (49 GWDIMTU)
Fuel Assemblies," XN-NF-84-28(P), Exxon Nuclear Company, July 1984.
Quadrant Power Tilt Limits (TS 3.10.c)
The radial power distribution within the core must satisfy the design values assumed for calculation of power capability. Radial power distributions are measured as part of the startup physics testing and are periodically measured at a monthly or greater frequency. These measurements are taken to assure that the radial power distribution with any quarter core radial power asymmetry conditions are consistent with the assumptions used in power capability analyses.
The quadrant tilt power deviation alarm is used to indicate a sudden or unexpected change from the radial power distribution mentioned above. The 2% tilt alarm setpoint represents a minimum practical value consistent with instrumentation errors and operating procedures. This symmetry level is sufficient to detect significant misalignment of control rods. Misalignment of control rods is considered to be the most likely cause of radial power asymmetry. The requirement for verifying rod position once each shift is imposed to preclude rod misalignment which would cause a tilt condition less than the 2% alarm level. This monitoring is required by TS 4.1.
The two hour time interval in TS 3.10.c is considered ample to identify a dropped or misaligned rod.
If the tilt condition cannot be eliminated within the two hour time allowance, additional time would be needed to investigate the cause of the tilt condition. The measurements would include a full core power distribution map using the movable detector system. For a tilt ratio > 1.02 but 11.09, an additional 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> time interval is authorized to accomplish these measurements. However, to assure that the peak core power is maintained below limiting values, a reduction of reactor power of 2% for each 1% of indicated tilt is required. Power distribution measurements have indicated that the core radial power peaking would not exceed a two-to-one relationship with the indicated tilt from the excore nuclear detector system for the worst rod misalignment. If a tilt ratio of > 1.02 but 5 1.09 cannot be eliminated after 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, then the reactor power level will be reduced to 5 50%.
If a misaligned rod has caused a tilt ratio > 1.09, then the core power shall be reduced by 2% of rated value for every 1% of indicated power tilt ratio > 1.O. If after eight hours the rod has not been realigned, then the rod shall be declared inoperable in accordance with TS 3.10.e, and action shall be taken in accordance with TS 3.10.g. If the tilt condition cannot be eliminated after 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, then the reactor shall be brought to a minimum load condition; i.e., electric power 2 30 MW. If the cause of the tilt condition has been identified and is in the process of being corrected, then the generator may remain connected to the grid.
If the tilt ratio is > 1.09, and it is not due to a misaligned rod, then the reactor shall be brought to a no load condition (i.e., reactor power 2 5%) for investigation by flux mapping. Although the reactor may be maintained critical for flux mapping, the generator must be disconnected from the grid since the cause of the tilt condition is not known, or it cannot be readily corrected.
Rod Insertion Limits (TS 3.1 0.d)
The allowed completion time of two hours for restoring the control banks to within the insertion limits provides an acceptable time for evaluation and repairing minor problems without allowing the plant to remain in an unacceptable condition for an extended period of time.
Operation beyond the rod insertion limits is allowed for a short-time period in order to take conservative action because the simultaneous occurrence of either a LOCA, loss-of-flow accident, ejected rod accident, or other accident during this short time period, together with an inadequate power distribution or reactivity capability, has an acceptably low probability.
The time limits of six hours to achieve HOT STANDBY and an additional six hours to achieve HOT SHUTDOWN allow for a safe and orderly shutdown sequence and are consistent with most of the remainder of the Technical Specifications.
Rod Misalisnment Limitations (TS 3.10.e)
During normal power operation it is desirable to maintain the rods in alignment with their respective banks to provide consistency with the assumption of the safety analyses, to maintain symmetric neutron flux and power distribution profiles, to provide assurance that peaking factors are within acceptable limits and to assure adequate shutdown margin.
Analyses have been performed which indicate that the above objectives will be met if the rods are aligned within the limits of TS 3.10.e. A relaxation in those limits for power levels < 85% is allowable because of the increased margin in peaking factors and available shutdown margin obtained while OPERATING at lower power levels. This increased flexibility is desirable to account for the nonlinearity inherent in the rod position indication system and for the effects of temperature and power as seen on the rod position indication system.
Rod position measurement is performed through the effects of the rod drive shaft metal on the output voltage of a series of vertically stacked coils located above the head of the reactor pressure vessel. The rod position can be determined by the analog individual rod position indicators (IRPI),
the plant process computer which receives a voltage input from the conditioning module, or through the conditioning module output voltage via a correlation of rod position vs. voltage.
The plant process computer converts the output voltage signal from each IRPl conditioning module to an equivalent position (in steps).
The rod position as determined by any of these methods can then be compared to the bank demand position which is indicated on the group step counters to determine the existence and magnitude of a rod misalignment. This comparison is performed automatically by the plant process computer. The rod deviation monitor on the annunciator panel is activated (or reactivated) if the two position signals for any rod as detected by the process computer deviate by more than a predetermined value. The value of this setpoint is set to warn the operator when the Technical Specification limits are exceeded.
The rod position indicator system is calibrated once per REFUELING cycle and forms the basis of the correlation of rod position vs. voltage. This calibration is typically performed at HOT SHUTDOWN conditions prior to initial operations for that cycle. Upon reaching full power conditions and verifying that the rods are aligned with their respective banks, the rod position indication may be adjusted to compensate for the effects of the power ascension. After this adjustment is performed, the calibration of the rod position indicator channel is checked at an intermediate and low level to confirm that the calibration is not adversely affected by the adjustment.
A note indicating individual control rod position indications may not be within limits for up to and including one hour following substantial control rod movement modifies this LCO. This allows up to one hour of thermal soak time to allow the control rod drive shaft to reach thermal equilibrium and thus present a consistent position indication. Substantial rod movement is considered to be 10 or more steps in one direction in less than or equal to one hour.
Amendment No. 181 3/24/2005
Inoperable Rod Position Indicator Channels (TS 3.10.f)
The axial position of shutdown rods and control rods are determined by two separate and independent systems: the Bank Demand Position lndication System (commonly called group step counters) and the Individual Rod Position lndication (IRPI) System.
The Bank Demand Position lndication System counts the pulses from the Rod Control System that move the rods. There is one step counter for each group of rods. Individual rods in a group all receive the same signal to move and should, therefore, all be at the same position indicated by the group step counter for that group. The Bank Demand Position lndication System is considered highly precise (+ 1 step or + %8 inch). If a rod does not move one step for each demand pulse, the step counter will still count the pulse and incorrectly reflect the position of the rod.
The IRPl System provides an indirect indication of actual control rod position, but at a lower precision than the step counters. The rod position indicator channel is sufficiently accurate to
+
detect a rod 12 steps away from its demand position. If the rod position indicator channel is not OPERABLE, special surveillance of core power tilt indications, using established procedures and relying on movable incore detectors, will be used to verify power distribution symmetry.
A note indicating individual control rod position indications may not be within limits for up to and including one hour following substantial control rod movement modifies this LCO. This allows up to one hour of thermal soak time to allow the control rod drive shaft to reach thermal equilibrium and thus present a consistent position indication. Substantial rod movement is considered to be 10 or more steps in one direction in less than or equal to one hour.
3.10.f.l When one IRPl channel per group fails, the position of the rod may be determined indirectly by use of the movable incore detectors. The required action may also be satisfied by ensuring at least once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> that Fa satisfies TS 3.lO.b.l .A (FQN(z)),TS 3.10.b.5 (FaEQ),F ~ satisfies H ~
TS 3.10.b.l .B, and SHUTDOWN MARGIN satisfies TS 3.10.a, provided the non-indicating rods have not been moved. Based on experience, normal power operation does not require excessive movement of banks. If a bank has been significantly moved (2 24 steps), the required action of TS 3.10.f.3 is required. Therefore, verification of RCCA position within the completion time of 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> is adequate for allowing continued full power operation, since the probability of simultaneously having a rod significantly out of position and an event sensitive to that rod position is small. A reduction of reactor thermal power to 550% RATED POWER puts the core into a condition where COLR limits are sufficiently relaxed such that rod position will not cause the core to violate COLR limits2. The allowed completion time of 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> is reasonable, based on operating experience, for reducing power to 550% RATED POWER from full power conditions without challenging plant systems and allowing for rod position determination by movable incore detectors.
3.10.f.2 When more than one IRPl per group fail, additional actions are necessary to ensure that acceptable power distribution limits are maintained, minimum SDM is maintained, and the potential effects of rod misalignment on associated accident analyses are limited. Placing the Rod Control System in manual assures unplanned rod motion will not occur. This together with the indirect position determination available via movable incore detectors will minimize the USAR Chapter 14 Amendment No. 181
potential for rod misalignment. The immediate completion time for placing the Rod Control System in manual reflects the urgency with which unplanned rod motion must be prevented while in this condition. Monitoring and recording reactor coolant Tavg helps assure that significant changes in power distribution and SDM are avoided. The once per hour completion time is acceptable because only minor fluctuations in RCS temperature are expected at steady state plant operating conditions. The position of the rods may be determined indirectly by use of the movable incore detectors. The required action may also be satisfied by ensuring at least once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> that FQ satisfies TS 3.10.b.l.A ( F ~ ~ ( z )TS
) , 3.10.b.5 (FQEQ),FhHNsatisfies TS 3.10.b.l.B, and SHUTDOWN MARGIN satisfies TS 3.10.a, provided the non-indicating rods have not been moved. Verification of control rod position once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> is adequate for allowing continued full power operation for a limited, 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period, since the probability of simultaneously having a rod significantly out of position and an event sensitive to that rod position is small. The 24-hour completion time provides sufficient time to troubleshoot and restore the IRPl system to operation while avoiding the plant challenges associated with the shutdown without full rod position indication.
3.10.f.3 Based on operating experience, normal power operation does not require excessive rod movement. If one or more rods has been significantly moved. When one or more rods with inoperable position indicators have been moved in excess of 24 steps in one direction, since the position was last determined, the required actions of one or more inoperable individual rod position indicators, as applicable, are still appropriate but must be initiated under TS 3.10.f.3 to begin verifying that these rods are still properly positioned, relative to their group positions. If, within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, the rod positions have not been determined, thermal power must be reduced to 5 50% RATED POWER within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> to avoid undesirable power distributions that could result from continued operation at > 50% RATED POWER, if one or more rods are misaligned by more than 24 steps. The allowed completion time of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> provides an acceptable period of time to verify the rod positions.
3.1O.f.4 With one demand position indicator per bank inoperable, the IRPl System can determine the rod positions. Since normal power operation does not require excessive movement of rods, verification by administrative means (logging IRPl position and verifying within rod alignment limitations) that the rod position indicators are OPERABLE and the most withdrawn rod and the least withdrawn rod are 5 12 steps apart when operating at > 85% RATED POWER or 5 24 steps apart when operating at 5 85% RATED POWER within the allowed Completion Time of once every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> is adequate. A reduction of reactor thermal power to 5 50% RATED POWER puts the core into a condition where COLR limits are sufficiently relaxed such that rod position will not cause the core to violate COLR limits. The allowed completion time of 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> provides an acceptable period of time to verify the rod positions or reduce power to I 50%
RATED POWER.
Inoperable Rod Limitations (TS 3.10.q)
One inoperable control rod is acceptable provided the potential consequences of accidents are not worse than the cases analyzed in the safety analysis report. A 30-day period is provided for the reanalysis of all accidents sensitive to the changed initial condition.
Rod Drop Time (TS 3.1O.h)
The required drop time to dashpot entry is consistent with safety analysis.
Amendment No. I 8 1 03/24/2005
Core Averaae Temperature (TS 3.10.k)
The core average temperature limit is consistent with full power operation within the nominal operational envelope. Either Tavg control board indicator readings or computer indications are averaged to obtain the value for comparison to the limit. The limit is based on the average of either 4 control board indicator readings or 4 computer indications. A higher Tavg will cause the reactor core to approach DNB limits.
Reactor Coolant Svstem Pressure (TS 3.10.1)
The RCS pressure limit is consistent with operation within the nominal operational envelope. Either pressurizer pressure control board indicator readings or computer indications are averaged to obtain the value for comparison to the limit. The limit is based on the average of either 4 control board indicator readings or 4 computer indications. A lower pressure will cause the reactor core to approach DNB limits.
Reactor Coolant Flow (TS 3.10.m)
The reactor coolant system (RCS) flow limit, as specified in the COLR, is consistent with the minimum RCS flow limit assumed in the safety analysis adjusted by the measurement uncertainty.
The safety analysis assumes initial conditions for plant parameters within the normal steady state envelope. The limits placed on the RCS pressure, temperature, and flow ensure that the minimum departure from nucleate boiling ratio (DNBR) will be met for each of the analyzed transients.
The RCS flow normally remains constant during an operational fuel cycle with all reactor coolant pumps running. At least two plant computer readouts from the loop RCS flow instrument channels are averaged per reactor coolant loop and the sum of the reactor coolant loop flows are compared to the limit. Operating within this limit will result in meeting the DNBR criterion in the event of a DNB-limited event.
DNBR Parameters (TS 3.1O.n)
The DNBR related safety analyses make assumptions on reactor temperature, pressure, and flow.
In the event one of these parameters does not meet the TS 3.10.k, TS 3.10.1 or TS 3.10.m limits, an analysis can be performed to determine a power level at which the MDNBR limit is satisfied.
Amendment No. 181 03/24/2005
BASIS Control Room Post-Accident Recirculation System (TS 3.12)
The Control Room Post-Accident Recirculation System is designed to filter the Control Room atmosphere during Control Room isolation conditions. The Control Room Post-Accident Recirculation System is designed to automatically start upon SIS or high radiation signal.
If the system is found to be inoperable, there is no immediate threat to the Control Room and reactor operation may continue for a limited period of time while repairs are being made. If the system cannot be repaired within 7 days, the reactor is placed in HOT STANDBY until the repairs are made.
Accident analysis assumes a charcoal adsorber efficiency of go%.(') To ensure the charcoal adsorbers maintain that efficiency throughout the operating cycle, a safety factor of 2 is used.
Therefore, if accident analysis assumes a charcoal adsorber efficiency of 90%, this equates to a methyl iodide penetration of 10%. If a safety factor of 2 is assumed, the methyl iodide penetration is reduced to 5%. Thus, the acceptance criteria of 95% efficient will be used for the charcoal adsorbers.
Although committing to ASTM D3803-89, it was recognized that ASTM D3803-89 Standard references Military Standards MIL-F-51O68D, Filter, Particulate High Efficiency, Fire Resistant, and MIL-F-51079A, Filter, Medium Fire Resistant, High Efficiency. These specifications have been revised and the latest revisions are, MIL-F-51O68F and MIL-F-51Oi'gD. These revisions have been canceled and superseded by ASME AG-1, Code on Nuclear Air and Gas Treatment. ASME AG-1 is an acceptable substitution. Consequently, other referenced standards can be substituted if the new standard or methodology is shown to provide equivalent or superior performance to those referenced in ASTM D3803-89.
(I)USAR TABLE 14.3-8, "Major Assumptions for Design Basis LOCA Analysis" Amendment No. 152 02/28/2001
Shock suppressors (snubbers) are designed to prevent unrestrained pipe motion under dynamic loads, as might occur during seismic activity or severe plant transients, while allowing normal thermal motion during startup or shutdown. The consequence of an inoperable snubber is an increase in the probability of structural damage to piping as a result of a seismic event or other events initiating dynamic loads. It is therefore required that all snubbers designed to protect the reactor coolant and other safety-related systems or components be operable during reactor operation. The intent of this TS is to prohibit startup or continued operation with defective safety-related shock suppressors.
Because the protection afforded by snubbers is required only during low probability events, TS 3.14.b allows a period of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> for repairs or feasible alternative action before reactor shutdown is required.
Amendment No. 122 12/21195
ITS 4Q) I TS 4.0.a establishes the requirements that surveillances must be met during the operational I MODES or other conditions for which the requirements of the LIMITING CONDITIONS FOR OPERATION (LCO) apply unless otherwise stated in an individual surveillance requirement. The purpose of this TS is to ensure that surveillances are performed to verify the OPERABILITY of I systems and components and that parameters are within specified limits. This ensures safe operation of the facility when the plant is in a MODE or other specified condition for which the associated LCOs are applicable. Surveillance requirements do not have to be performed when the facility is in an operational MODE for which the requirements of the associated LC0 do not apply unless otherwise specified. Surveillance requirements do not have to be performed on inoperable equipment because the action requirements define the remedial measures that apply.
However, the surveillance requirements have to be met to demonstrate that inoperable equipment has been restored to OPERABLE status.
TS 4.0.b establishes the limit for which the specified time interval for surveillance requirements may be extended. It permits an allowable extension of the normal surveillance interval to facilitate surveillance scheduling and consideration of plant operation conditions that may not be suitable for conducting the surveillance (e.g., transient conditions or other ongoing surveillance or maintenance activities). It also provides flexibility to accommodate the length of a fuel cycle for surveillances that are performed at each refueling outage and are specified with an 18-month surveillance interval. It is not intended that this provision be used repeatedly as a convenience to extend surveillance intervals beyond that specified for surveillances that are not performed during refueling outages. The limitation of TS 4.0.b is based on engineering judgement and the recognition that the most probable result of any particular surveillance being performed is the verification of conformance with the surveillance requirements. This provision is sufficient to ensure that the reliability ensured through surveillance activities is not significantly degraded beyond that obtained from the specified surveillance interval.
TS 4.0.c establishes the flexibility to defer declaring affected equipment inoperable or an affected variable outside the specified limits when a surveillance has not been completed within the allowed surveillance interval. A delay period of up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or up to the limit of the allowed surveillance interval, whichever is greater, applies from the point in time that it is discovered that the surveillance has not been performed in accordance with TS 4.0.b, and not at the time that the allowed surveillance interval was not met.
This delay period provides adequate time to complete surveillances that have been missed. This delay period permits the completion of a surveillance before complying with required actions or other remedial measures that might preclude completion of the surveillance.
Amendment No. 163 9/24/2002
The basis for this delay period includes consideration of unit conditions, adequate planning, availability of personnel, the time required to perform the surveillance, the safety significance of the delay in completing the required surveillance, and the recognition that the most probable result of any particular surveillance being performed is the verification of conformance with the requirements. When a surveillance with an allowed interval based not on time intervals, but upon specified unit conditions, OPERATING situations, or requirements of regulations (e.g., prior to entering OPERATING MODE after each fuel loading, or in accordance with 10 CFR 50, Appendix J, as modified by approved exemptions, etc.) is discovered to not have been performed when specified, TS 4.0.c allows for the full delay period of up to the allowed surveillance interval to perform the surveillance. However, since there is not a time interval specified, the missed surveillance should be performed at the first reasonable opportunity.
TS 4.0.c provides a time limit for, and allowances for the performance of, surveillances that become applicable as a consequence of MODE changes imposed by required actions.
Failure to comply with allowed surveillance intervals for SRs is expected to be an infrequent occurrence. Use of the delay period established by TS 4.0.c is flexibility which is not intended to be used as an operational convenience to extend surveillance intervals.
While up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or the limit of the allowed interval is provided to perform the missed surveillance, it is expected that the missed surveillance will be performed at the first reasonable opportunity. The determination of the first reasonable opportunity should include consideration of the impact on plant risk (from delaying the surveillance as well as any plant configuration changes required or shutting the plant down to perform the surveillance) and impact on any analysis assumptions, in addition to unit conditions, planning, availability of personnel, and the time required to perform the surveillance. This risk impact should be managed through the program in place to implement 10 CFR 50.65(a)(4) and its implementation guidance, NRC Regulatory Guide 1.182, "Assessing and Managing Risk Before Maintenance Activities at Nuclear Power Plants." This Regulatory Guide addresses consideration of temporary and aggregate risk impacts, determination of risk management action thresholds, and risk management action up to and including plant shutdown. The missed surveillance should be treated as an emergent condition as discussed in the Regulatory Guide. The risk evaluation may use quantitative, qualitative, or blended methods. The degree of depth and rigor of the evaluation should be commensurate with the importance of the component. Missed surveillances for important components should be analyzed quantitatively. If the results of the risk evaluation determine the risk increase is significant, this evaluation should be used to determine the safest course of action.
All missed surveillances will be placed in the licensee's Corrective Action Program.
If a surveillance is not completed within the allowed delay period, then the equipment is considered inoperable or the variable is considered outside the specified limits and the completion times of the required actions for the applicable LC0 conditions begin immediately upon expiration of the delay period. If a surveillance is failed within the delay period, then the equipment is inoperable, or the variable is outside the specified limits and the completion times of the required actions for applicable LC0 conditions begin immediately upon failure of the surveillance.
Amendment No. 163 9/24/2002
Completion of the surveillance within the delay period allowed by this Specification, or within the completion time of the actions, restores compliance with TS 4.0.a.
TS 4.0.d establishes the requirements that all applicable surveillance must be met before entry into an operational MODE or other condition of operation specified in the applicability statement.
The purpose of the TS is to ensure that system and component operability requirements or parameter limits are met before entry into a MODE or condition for which these systems and components ensure safe operation of the facility. This provision applies to changes in operational MODES or other specified conditions associated with plant shutdown as well as startup.
Under the provisions of the TS, the applicable surveillance requirements must be performed within the specified surveillance interval to ensure that the LCOs are met during initial plant startup or following a plant outage.
When a shutdown is required to comply with action requirements, the provisions of I TS 4.0.d do not apply because this would delay placing the facility in a lower MODE of operation.
Amendment No. 163 9/24/2002
R e v b ITS 4.1)
Check Failures such as blown instrument fuses, defective indicators, or faulted amplifiers which result in "upscale" or "downscale" indication can be easily recognized by simple observation of the functioning of an instrument or system. Furthermore, such failures are, in many cases, revealed by alarm or annunciator action, and a check supplements this type of built-in surveillance. Based on experience in operation of both conventional and nuclear plant systems, the minimum checking frequency of once per shift is regarded as adequate for reactor and steam system instrumentation when the plant is in operation.
Calibration shall be performed to ensure the accuracy of information presented.
The nuclear flux (linear level) channels shall be calibrated at least daily against a heat balance standard to verify drift and effects of changing rod patterns.
Other channels are subject only to "drift" errors induced within the instrumentation itself and, consequently, can tolerate longer intervals between calibration. Process system instrumentation errors induced by drift can be expected to remain within acceptable tolerances if recalibration is performed at each REFUELING shutdown.
Substantial calibration shifts within a channel (essentially a channel failure) will be revealed during routine checking and testing procedures.
Thus, minimum calibration frequencies of once-per-day for the nuclear flux (linear level) channels, and once each REFUELING shutdown for the process system channels is considered acceptable.
Experience with this type of instrumentation has shown that the testing frequency as specified in Table TS 4.1-1 will assure the required level of performance.
Two fuel assemblies per region will be selected as reference assemblies on which base line data will be taken prior to initial fuel loading. During each refueling, visual inspections will be made on a representative sample of assemblies and in addition on any suspect assembly. Any observed unexplained anomalies in the suspected assembly will determine the necessity to recheck the reference assemblies against the original base line data.
Amendment No. 121 08/31195
The seismic instrumentation will be checked for proper operation once per operating cycle or once every 18 months, whichever occurs first. In the event of a seismic disturbance, written administrative procedures will be put into effect covering operation of the plant. Inspection of crucial areas and components will be made immediately with the results of this inspection documented. In the absence of any unusual observations the plant will continue to be operated.
Visual inspections will be made of the accessible portions of the hot process pipeline guard pipes once during each operating cycle or once every 18 months, whichever occurs first.
Amendment No. 121 08131195
Kewaunee Power Station (KPS) design was not designed to Section XI of the ASME Code; therefore, 100% compliance may not be practically achievable. However, the design process did consider access for in-service inspection, and made modifications within design limitations to provide maximum access. To the extent practical, Dominion Energy Kewaunee, Inc. performs inspection of ASME Code Class 1, Class 2, Class 3, and Class MC components in accordance with Section XI of the ASME Code. If an inspection required by the Code is impractical, Dominion Energy Kewaunee, Inc. requests Commission approval for deviation from the requirement.
The basis for surveillance testing of the Reactor Coolant System pressure isolation valves identified in Table TS 3.1-2 is contained within "Order for Modification of License" dated April 20, 1981.
Technical Specification 4.2.b (Deleted)
Technical Specification 4.2.b.l (Deleted)
Technical Specification 4.2.b.2 (Deleted)
Technical Specification 4.2.b.3 (Deleted)
Technical Specification 4.2.b.4 [Deleted)
Technical Specification 4.2.b.5 (Deleted)
Technical Specification 4.2.b.6 (Deleted)
Technical Specification 4.2.b.7 (Deleted)
Amendment No. 188 711812006
Background - Containment Tests (TS 4.4)
The Containment System is designed to provide protection for the public from the consequences of a Design Basis ~ccident.(')The Design Basis Accident is an instantaneous double-ended rupture of the cold leg of the Reactor Coolant System. Pressure and temperature behavior subsequent to the accident was determined by calculations evaluating the combined influence of the energy sources, the heat sinks and engineered safety features. The assumptions and effects for containment vessel leakage rate are detailed in the USAR'~)and further amplified in one of its
~~pendices.'~)
The total containment system consists of two systems. The Primary Containment System consists of a steel structure and its associated engineered safety features systems. The Primary Containment System, also referred to as the Reactor Containment Vessel, is a low-leakage steel shell, including all of its penetrations, designed to confine the radioactive materials that could be released by accidental loss of integrity of the Reactor Coolant System pressure boundary. It is designed for a maximum internalltest pressure of 46 psig and a temperature of 268°F.
The Secondary Containment System consists of the Shield Building, its associated engineered safety features systems, and a Special Ventilation Zone in the Auxiliary Building. The Shield Building is a medium-leakage concrete structure surrounding the Reactor Containment Vessel and is designed to provide a means for collection and filtration of fission-product leakage from the Reactor Containment Vessel following the Design Basis Accident. A 54.annular space is provided between the Reactor Containment Vessel and the Shield Building. The Shield Building Ventilation System is the engineered safety feature utilized for the collection and filtration of fission-product leakage from the containment vessel.
The Special Ventilation Zone of the Auxiliary Building provides a medium-leakage boundary which confines leakage that could conceivably bypass the Shield Building annulus. The safety system associated with the Auxiliary Building Special Ventilation Zone is the Auxiliary Building Special Ventilation System (ABSVS). One of the functions of the ABSVS is to collect and filter any potential fission products that may bypass the Shield Building annulus.
(I) USAR Section 14.3 (2) USAR Section 14.3.5 (3) USAR Appendix H Amendment No. 155 06/08/2001
Maintaining CONTAINMENT SYSTEM INTEGRITY in an OPERABLE state requires, among other conditions, that all the requirements of TS 4.4.a and b, leakage rate testing (Containment Leakage Rate Testing Program), are satisfied. The testing process will include: (1) an overall containment leak rate evaluation (Type A); (2) a determination of the leakage through pressure containing or leakage limiting boundaries (Type B); and (3) an evaluation of the leak rate through containment isolation valves (Type c).(~)These tests are intended to check all possible paths for containment atmosphere to reach the outside atmosphere.
Shield Buildins Ventilation Svstem (TS 4.4.c)
Pressure drop across the combined HEPA filters and charcoal adsorbers of < 10 inches of water and an individual HEPA bank pressure drop of < 4 inches of water at the system design flow rate
(+I 0%) will indicate that the filters and adsorbers are not clogged by excessive amounts of foreign matter. A test frequency of once per operating cycle establishes system performance capability.
This pressure drop is approximately 3 inches of water when the filters are clean. I The frequency of tests and sample analysis are necessary to show that the HEPA filters and charcoal adsorbers can perform as evaluated. Replacement adsorbent should be qualified according to the guidelines of Regulatory Guide 1.52 (Rev. 1) dated July 1976, except that ASTM D3803-89 standard will be used to fulfill the guidelines of Table 2, item 5, "Radioiodine removal efficiency." The charcoal adsorber efficiency test procedures should allow for the removal of one adsorber tray, emptying of one bed from the tray, mixing the adsorbent thoroughly, and obtaining at least two samples. Each sample should be at least two inches in diameter and a length equal to the thickness of the bed. The use of multi-sample assemblies for test samples is an acceptable alternate to mixing one bed for a sample. If the iodine removal efficiency test results are unacceptable, all adsorbent in the system should be replaced. Any HEPA filters found defective should be replaced with filters qualified pursuant to Regulatory Position C.3.d of Regulatory Guide 1.52 (Rev. I ) dated July 1976.
If painting, fire, or chemical release occurs, the charcoal adsorber will be laboratory tested to determine whether it was contaminated from the fumes, chemicals, or foreign materials.
Replacement of the charcoal adsorber can then be evaluated.
Operation of the systems every month will demonstrate operability of the filters and adsorber system. Operation of the Shield Building Ventilation System will result in a discharge to the environment. This discharge is made after at least three samples of the building atmosphere have been analyzed to determine the concentration of activity in the atmosphere.
(4) 10 CFR Part 50, Appendix J, Option 6 TS 84.4-2
Auxiliaw Buildinq Special Ventilation System (TS 4.4.d)
Demonstration of the automatic initiation capability is necessary to assure system performance capability.(5)
Pressure drop across the combined HEPA filters and charcoal adsorbers of < 10 inches of water and an individual HEPA bank pressure drop of < 4 inches of water at the system design flow rate
(&lo%)will indicate that the filters and adsorbers are not clogged by excessive amounts of foreign matter. A test frequency of once per operating cycle establishes system performance capability.
This pressure drop is approximately 3 inches of water when the filters are clean. I The frequency of tests and sample analysis are necessary to show that the HEPA filters and charcoal adsorbers can perform as evaluated. Replacement adsorbent should be qualified according to the guidelines of Regulatory Guide 1.52 (Rev. 1) dated July 1976, except that ASTM D3803-89 standard will be used to fulfill the guidelines of Table 2, item 5, "Radioiodine removal efficiency." The charcoal adsorber efficiency test procedures should allow for the removal of one adsorber tray, emptying of one bed from the tray, mixing the adsorbent thoroughly, and obtaining at least two samples. Each sample should be at least two inches in diameter and a length equal to the thickness of the bed. The use of multi-sample assemblies for test samples is an acceptable alternate to mixing one bed for a sample. If the iodine removal efficiency test results are unacceptable, all adsorbent in the system should be replaced. Any HEPA filters found defective should be replaced with filters qualified pursuant to Regulatory Position C.3.d of Regulatory Guide 1.52 (Rev. I) dated July 1976.
If painting, fire, or chemical release occurs, the charcoal adsorber will be laboratory tested to determine whether it was contaminated from the fumes, chemicals, or foreign materials.
Replacement of the charcoal adsorber can then be evaluated.
Periodic checking of the inlet heaters and associated controls for each train will provide assurance that the system has the capability of reducing inlet air humidity so that charcoal adsorber efficiency is enhanced.
In-place testing procedures will be established utilizing applicable sections of ANSI N510-1975 standard as a procedural guideline.
Vacuum Breaker Valves (TS 4.4.e)
The vacuum breaker valves are 18 inch butterfly valves with air to open, spring to close operators.
The valve discs are center pivot and rotate when closing to an EPT base material seat. When closed, the disc is positioned fully on the seat regardless of flow or pressure direction. Testing these valves in a direction opposite to that which would occur post-LOCA verifies leakage rates of both the vacuum breaker valves and the check valves downstream.
(5) USAR Section 9.6
Isolation Device Positions (TS 4.4.f)
TS 4.4.f.l ensures each 36 inch containment purge valve is verified sealed closed at 31-day interva~s.'~) This Surveillance is designed to ensure that an inadvertent or spurious opening of a containment purge valve does not cause a gross breach of containment. Detailed analysis of the purge valves failed to conclusively demonstrate their ability to close during a LOCA in time to limit off-site doses. Therefore, these valves are required to be in the sealed closed position when critical. A containment purge valve that is sealed closed must be closed with its control switch sealed in the close position. In this application, the term "sealed" has no connotation of leak tightness. The frequency is a result of a NRC initiative, Generic Issue B-24, related to containment purge valve use during plant operations.
TS 4.4.f.2 ensures the 2-inch ventlpurge valves are closed as required or, if open, open for an allowable reason. If a 2-inch ventlpurge valve is open in violation of this TS, the valve is considered inoperable. If the inoperable valve is not otherwise known to have excessive leakage when closed, it is not considered to have leakage outside of limits. The TS is not required to be met when the 2-inch ventlpurge valves are open for the reasons stated. The valves may be opened for pressure control, ALARA, or air quality considerations for personnel entry, or for Surveillances that require the valves to be open. The 2-inch ventlpurge valves are capable of closing in the environment following a LOCA. Therefore, these valves are allowed to be open for limited periods of time. The 31 day frequency is consistent with other containment isolation valve requirements discussed.
TS 4.4.f.3.A requires verification that each containment isolation manual valve and blind flange located outside containment and not locked, sealed, or otherwise secured and required to be closed during accident conditions is closed. The TS helps to ensure that post-accident leakage of radioactive fluids or gases outside of the containment boundary are within design limits. This TS does not require any testing or valve manipulation. Rather, it involves verification, through a system walkdown, that those containment isolation valves outside containment and capable of being mispositioned are in the correct position. Since verification of valve position for containment isolation valves outside containment is relatively easy, the 31 day frequency is based on engineering judgment and was chosen to provide added assurance of the correct positions. The TS specifies that containment isolation valves that are open under administrative controls are not required to meet the TS during the time the valves are open. This TS does not apply to valves that are locked, sealed, or otherwise secured in the closed position, since these were verified to be in the correct position upon locking, sealing, or securing.
@) Letter from Steven A. Varga (NRC) to C.W. Giesler (WPSC) dated April 22, 1983 TS B4.4-4 10/25/2002
TS 4.4.f.3.B requires verification that each containment isolation manual valve and blind flange located inside containment and not locked, sealed, or otherwise secured and required to be closed during accident conditions, is closed. The TS helps to ensure that post-accident leakage of radioactive fluids or gases outside of the containment boundary is within design limits. For containment isolation valves inside containment, the frequency of "prior to entering INTERMEDIATE SHUTDOWN from COLD SHUTDOWN if not performed within the previous 92 days" is appropriate since these containment isolation valves are operated under administrative controls and the probability of their misalignment is low. The TS specifies that containment isolation valves that are open under administrative controls are not required to meet the TS during the time they are open. This TS does not apply to valves that are locked, sealed, or otherwise secured in the closed position, since these were verified to be in the correct position upon locking, sealing, or securing.
TS 4.4.f.3.C modifies TS 4.4.f.3 for valves and blind flanges located in high radiation areas and allows these devices to be verified closed by use of administrative means. Allowing verification by administrative means is considered acceptable, since access to these areas is typically restricted when above COLD SHUTDOWN for ALARA reasons. Therefore, the probability of misalignment of these containment isolation valves, once they have been verified to be in the proper position, is small.
BASIS Svstem Tests (TS 4.5.a)
The Safety Injection System and the Containment Vessel lnternal Spray System are principal plant safety systems that are normally in standby during reactor operation. Complete system tests cannot be performed when the reactor is OPERATING because a safety injection signal causes containment isolation, and a Containment Vessel lnternal Spray System test requires the system to be temporarily disabled. The method of assuring OPERABILITY of these systems is therefore to combine system tests to be performed during periodic shutdowns with more frequent component tests, which can be performed during reactor operation.
The system tests demonstrate proper automatic operation of the Safety Injection and Containment Vessel lnternal Spray Systems. A test signal is applied to initiate automatic action, resulting in verification that the components received the safety injection signal in the proper sequence. The test demonstrates the operation of the valves, pump circuit breakers, and automatic circuitry.(')
The lnternal Containment Spray (ICS) System is designed to provide containment cooling in the event of a loss-of-coolant accident or steam line break accident, thereby ensuring the containment pressure does not exceed its design value of 46 psig at 268°F (100% R.H.)."' With the Kewaunee Power Station ICS system design, 76 properly functioning spray nozzles per train will adequately provide the required ICS flow rate for post accident cooling.
Component Tests - Containment Fancoil Units (TS 4.5.a.3)
Testing of the containment fancoil unit emergency discharge and backdraft dampers is performed to assure the integrity of the duct work post-LOCA.
Component Tests - Pumps (TS 4.5.b.l)
During reactor operation, the instrumentation which is depended upon to initiate safety injection and containment spray is checked daily and the initiating logic circuits are tested monthly (in accordance with TS 4.1). In addition, the active components (pumps and valves) are to be tested quarterly to check the operation of the starting circuits and to verify that the pumps are in satisfactory running order. The quarterly test interval is based on the judgment that more frequent testing would not significantly increase the reliability (i.e., the probability that the component would operate when required), yet more frequent testing would result in increased wear over a long period of time.
(') USAR Section 6.2 (2) USAR Section 6.4 Amendment No. 185 7/5/2005
v Power -S (TS Each diesel generator can start and be ready to accept full load within 10 seconds, and will 1 sequentially start and supply the power requirements for one complete set of engineered safety features equipment in approximately one minute.(') This test will be conducted during each REFUELING outage to ensure that the diesel generator will start and assume required loads in accordance with the timing sequence listed in USAR Table 8.2-1 after the initial starting sequence.
The specified test frequencies provide reasonable assurance that any mechanical or electrical deficiency will be detected and corrected before it can result in failure of one emergency power supply to respond when called upon to function. Its possible failure to respond is, of course, anticipated by providing two diesel generators, each supplying through an independent bus, a complete and adequate set of engineered safety features equipment. Further, both diesel generators are provided as backup to multiple sources of external power, and this multiplicity of sources should be considered with regard to adequacy of test frequency.
The monthly tests specified for the diesel generators will demonstrate their continued capability to start and carry rated load. The fuel supplies and starting circuits and controls are continuously monitored, and abnormal conditions in these systems would be indicated by an alarm without need for test startup. Monthly tests are performed in accordance with the intent of IEEE 387-1977, paragraph 6.6.1.
The REFUELING interval diesel generator surveillance demonstrates that the Emergency Power System, and its control system, will function automatically to provide engineered safety equipment power in the event of loss of off-site power coincident with a safety injection signal. This test demonstrates proper tripping of motor feeder breakers, main supply and tie breakers on the affected bus, and sequential starting of essential equipment to demonstrate OPERABILITY of the diesel generators. This test is initiated by simultaneously unblocking safety injection and simulating a loss-of-voltage signal. This surveillance is performed to meet the intent of IEEE 387-1977 paragraph 6.6.2. (Note also that Reg. Guide 1.I08 addresses diesel generator surveillance.)
"' USAR Section 8.2
Inspections are performed at REFUELING outage intervals in order to maintain the diesel generators in accordance with the manufacturers' recommendations. The inspection procedure is periodically updated to reflect experience gained from past inspections and new information as it is available from the manufacturer.
The load rejection test demonstrates the capability of rejecting the maximum rated load without overspeeding or attaining voltages which would cause the diesel generator to trip, mechanical damage, or harmful overstresses.
Short-Term I nad Test: TS 4 . M Loading the diesel generators to their short-term rating will demonstrate their capability to provide a continuous source of emergency AC power during a load perturbation of up to 112% of the diesel generator's continuous rating.
Station batteries will deteriorate with time, but precipitous failure is extremely unlikely. The surveillance specified is that which has been demonstrated over the years to provide indication of a cell becoming unserviceable long before it fails.
If a battery cell has deteriorated, or if a connection is loose, the voltage under load will drop excessively, indicating need for replacement or maintenance.
Amendment No. 119 04118/95
BASIS The main steam isolation valves (MSIVs) serve to limit the cooldown rate of the Reactor Coolant System and the reactivity insertion that could result from a main steam line break incident. They also serve to limit the amount of mass and energy released into containment from the unfaulted steam generator during a main steam line break incident. Their ability to close upon signal should be verified at each REFUELING outage. The MSlV closure time assumption used in the main steam line break incident analysis can be found in Section 14.2.5 of the USAR.
Amendment No.114 TS B4.7-1 Revised NRC letter dated 04115/98
The Auxiliary Feedwater System (AFW) mitigates the consequences of any event that causes a loss of normal feedwater. The design basis of the AFW System is to remove decay and residual heat by delivering the minimum required flow to at least one steam generator until the Reactor Coolant System (RCS) is cooled to the point of placing the Residual Heat Removal System into operation.
In accordance with ASME Code Section XI, Subsection IWP, an in-service test of each auxiliary feedwater pump shall be run nominally every 3 months (quarterly) during normal plant operation.
It is recommended that this test frequency be maintained during shutdown periods if this can be reasonably accomplished, although this is not mandatory. If the normally scheduled test is not performed during a plant shutdown, then the motor-driven pumps shall be demonstrated OPERABLE within 1 week exceeding 350°F; and the turbine-driven pump shall be demonstrated OPERABLE within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> of exceeding 350~.
Quarterly testing of the AFW pumps is used to detect degradation of the component. This type of testing may be accomplished by measuring the pump's developed head at one point of the pump characteristic curve. This verifies that the measured performance is within an acceptable tolerance of the original pump baseline performance.
TS 3.4.b requires all three AFW pumps be OPERABLE prior to heating the RCS average temperature > 350'F. It is acceptable to heat the RCS to > 350°F with the turbine-driven pump inoperable for a limited time period of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. The wording of TS 3.4.b.4.B and TS 4.8.b allows 1 delaying the testing until the steam flow is consistent with the conditions under which the performance acceptance criteria were generated.
The discharge valves of the two motor-operated pumps are normally open, as are the suction valves from the condensate storage tanks and the two valves on a cross tie line that directs the turbine-driven pump discharge to either or both steam generators. The only valve required to function upon initiation of auxiliary feedwater flow is the steam admission valve on the turbine-driven pump. Proper opening of the steam admission valve will be demonstrated each time the turbine-driven pump is tested.
To eliminate possible errors in the calculations of the initial reactivity of the core and the reactivity depletion rate, the predicted relation between fuel burn-up and the boron concentration, necessary to maintain adequate control characteristics, must be adjusted (normalized) to accurately reflect actual core conditions. When full power is reached initially, and with the control rod groups in the desired positions, the boron concentration is measured and the predicted curve is adjusted to this point. As power operation proceeds, the measured boron concentration is compared with the predicted concentration and the slope of the curve relating burn-up and reactivity is compared with that predicted. This process of normalization should be completed after about 10% of the total core burn-up. Thereafter, actual boron concentration can be compared with prediction, and the reactivity status of the core can be continuously evaluated. Any reactivity anomaly greater than 1% would be unexpected, and its occurrence would be thoroughly investigated and evaluated.
The value of 1% is considered a safe limit since a shutdown margin of at least 1% with the most reactive rod in the fully withdrawn position is always maintained.
"' USAR Section 3.2 Amendment No. 122 1212 1I95
Pressure drop across the combined HEPA filters and charcoal adsorbers of < I 0 inches of water and 4 inches across any HEPA filter bank at the system design flow rate (+lo%) will indicate that the filters and adsorbers are not clogged by excessive amounts of foreign matter. A test frequency of once per operating cycle establishes system performance capability. This pressure drop is approximately 2 inches of water when filters are clean. 1 The frequency of tests and sample analysis are necessary to show that the HEPA filters and charcoal adsorbers can perform as evaluated. Replacement adsorbent should be qualified according to the guidelines of Regulatory Guide 1.52 (Rev. 1) dated July 1976, except that ASTM D3803-89 standard will be used to fulfill the guidelines of Table 2, item 5, "Radioiodine removal efficiency." The charcoal adsorber efficiency test procedures should allow for the removal of one adsorber tray, emptying of one bed from the tray, mixing the adsorbent thoroughly, and obtaining at least two samples. Each sample should be at least 2 inches in diameter and a length equal to the thickness of the bed. The use of multi-sample assemblies for test samples is an acceptable alternate to mixing one bed for a sample. If the iodine removal efficiency test results are unacceptable, all adsorbent in the system should be replaced. Any HEPA filters found defective should be replaced with filters qualified pursuant to Regulatory Position C.3.d of Regulatory Guide 1.52 (Rev. I ) dated July 1976.
If painting, fire, or chemical release occurs such that the charcoal adsorbers become contaminated from the fumes, chemicals, or foreign materials, the same tests and sample analysis should be performed as required for operational use.
Degradation of the HEPA filters due to painting, fire or chemical release in a communicating ventilation zone would be detected by an increased pressure drop across the filters. Should the filters become contaminated, engineering judgment would be used to determine if further leakage and/or efficiency testing was required.
Demonstration of the automatic initiation capability is necessary to assure system performance capability.
In-place testing procedures will be established utilizing applicable sections of ANSI N510 - 1975 standard as a procedural guideline only.
Ingestion or inhalation of source material may give rise to total body or organ irradiation. This specification assures that leakage from radioactive material sources does not exceed allowable limits. In the unlikely event that those quantities of radioactive by-product materials of interest to this specification which are exempt from leakage testing are ingested or inhaled, they represent less than one maximum permissible body burden for total body irradiation. The limits for all other sources (including alpha emitters) are based upon 10 CFR 70.39(c) limits for plutonium.
The Eberline Model 1000 Multi-Source Calibrator and the J. L. Shepherd Model 89-400 are totally enclosed instrument calibrating assemblies for which leak testing of the enclosed sources is not practical. Leak testing of these sources would require disassembly of the calibration assembly shield, controls, etc., resulting in personnel exposure without corresponding benefits.
Amendment No. 122 1212 1195
Control Room Post-Accident Recirculation System Pressure drop across the combined HEPA filters and charcoal adsorbers of less than 6 inches of water and 4 inches across any HEPA filter bank at the system design flow rate (k 10%) will indicate that the filters and adsorbers are not clogged by excessive amounts of foreign matter. A filter test frequency of once per operating cycle establishes system performance capability.
The frequency of tests and sample analysis are necessary to show that the HEPA filters and charcoal adsorbers can perform as evaluated. Replacement adsorbent should be qualified according to the guidelines of Regulatory Guide 1.52 (Rev. 1) dated July 1976, except that ASTM D3803-89 standard will be used to fulfill the guidelines of Table 2, item 5, "Radioiodine removal efficiency." The charcoal adsorber efficiency test procedures should allow for the removal of one adsorber tray, emptying of one bed from the tray, mixing the adsorbent thoroughly, and obtaining at least two samples. Each sample should be at least two inches in diameter and a length equal to the thickness of the bed. The use of multi-sample assemblies for test samples is an acceptable alternate to mixing one bed for a sample. If the iodine removal efficiency test results are unacceptable, all adsorbent in the system should be replaced.
Any HEPA filters found defective should be replaced with filters qualified pursuant to Regulatory Position C.3.d of Regulatory Guide 1.52 (Rev. I ) dated July 1976. If painting, fire, or chemical release occurs such that the charcoal adsorber could become contaminated from the fumes, chemicals, or foreign materials, the same tests and sample analysis should be performed as required for operational use.
Demonstration of the automatic initiation capability is necessary to assure system performance capability.
In-place testing procedures will be established utilizing applicable sections of ANSI N510-1975 standard as a procedural guideline only.
Amendment No. 152 O2/28/2OO1
Verifying RCS LEAKAGE to be within the TS ensures the integrity of the RCPB is maintained.
Pressure boundary LEAKAGE would at first appear as unidentified LEAKAGE and can only be positively identified by inspection. It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE. Unidentified LEAKAGE and identified LEAKAGE are determined by performance of an RCS water inventory balance.
The RCS water inventory balance must be met with the reactor at steady state operating conditions (stable temperature, power level, pressurizer and makeup tank levels, makeup and letdown). This surveillance is modified by two notes. Note 1 states that this SR is not required to be performed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after establishing steady state operation. The 12-hour allowance provides sufficient time to collect and process all necessary data after stable plant conditions are established.
Steady state operation is required to perform a proper inventory balance since calculations during maneuvering are not useful. For RCS operational LEAKAGE determination by water inventory balance, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows.
An early warning of pressure boundary LEAKAGE or unidentified LEAKAGE is provided by the automatic systems that monitor the containment atmosphere radioactivity and the containment sump level. It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE. These leakage detection systems are specified in TS 3.1 .d.4.
Note 2 states that this SR is not applicable to primary to secondary LEAKAGE because LEAKAGE of 150 gallons per day cannot be measured accurately by an RCS water inventory.
The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Frequency is a reasonable interval to trend LEAKAGE and recognizes the importance of early leakage detection in the prevention of accidents.
This SR verifies that primary to secondary LEAKAGE is less than or equal to 150 gallons per day through any one SG. Satisfying the primary to secondary LEAKAGE limit ensures that the operational LEAKAGE performance criterion in the Steam Generator Program is met. If this SR is not met, compliance with TS 3.1 .g, "Steam Generator (SG) Tube Integrity," should be evaluated. The 150 gallons per day limit is measured at room temperature as described in Reference 5. The operational LEAKAGE rate limit applies to LEAKAGE through any one SG. If it is not practical to assign the LEAKAGE to an individual SG, all the primary to secondary LEAKAGE should be conservatively assumed to be from one SG.
The surveillance is modified by a Note which states that the Surveillance is not required to be performed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after establishment of steady state operation. For RCS primary to secondary LEAKAGE determination, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows.
Amendment No. 188
The surveillance frequency of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> is a reasonable interval to trend primary to secondary LEAKAGE and recognizes the importance of early leakage detection in the prevention of accidents. The primary to secondary LEAKAGE is determined using continuous process radiation monitors or radiochemical grab samples in accordance with the EPRI guidelines(').
(I' EPRI, " Pressurized Water Reactor Primary to Secondary Leak Guidelines" I Amendment No. 188 711812006
BASIS - Steam Generator (SG) Tube Integrity (TS 4.19)
During shutdown periods the SGs are inspected as required by this SR and the Steam Generator Program. NEI 97-06, Steam Generator Program Guidelines, and its referenced EPRI Guidelines, establish the content of the Steam Generator Program.
Use of the Steam Generator Program ensures that the inspection is appropriate and consistent with accepted industry practices.
During SG inspections a condition monitoring assessment of the SG tubes is performed.
The condition monitoring assessment determines the "as found" condition of the SG tubes. The purpose of the condition monitoring assessment is to ensure that the SG performance criteria have been met for the previous operating period.
The Steam Generator Program determines the scope of the inspection and the methods used to determine whether the tubes contain flaws satisfying the tube repair criteria.
lnspection scope (i.e., which tubes or areas of tubing within the SG are to be inspected) is a function of existing and potential degradation locations. The Steam Generator Program also specifies the inspection methods to be used to find potential degradation.
lnspection methods are a function of degradation morphology, non-destructive examination (NDE) technique capabilities, and inspection locations.
The Steam Generator Program defines the Frequency of TS 4.19.a. The Frequency is determined by the operational assessment and other limits in the SG examination guidelines (I). The Steam Generator Program uses information on existing degradations and growth rates to determine an inspection Frequency that provides reasonable assurance that the tubing will meet the SG performance criteria at the next scheduled inspection. In addition, Specification 6.22 contains prescriptive requirements concerning inspection intervals to provide added assurance that the SG performance criteria will be met between scheduled inspections.
During an SG inspection, any inspected tube that satisfies the Steam Generator Program repair criteria is removed from service by plugging. The tube repair criteria delineated in Specification 6.22 are intended to ensure that tubes accepted for continued service satisfy the SG performance criteria with allowance for error in the flaw size measurement and for future flaw growth. In addition, the tube repair criteria, in conjunction with other elements of the Steam Generator Program, ensure that the SG performance criteria will continue to be met until the next inspection of the subject tube(s). NEI 97-06, "Steam Generator Program Guidelines." provides guidance for (I)EPRI, "Pressurized Water Reactor Steam Generator Examination Guidelines." I Amendment No. 188 711812006
performing operational assessments to verify that the tubes remaining in service will continue to meet the SG performance criteria.
The Frequency of prior to entering INTERMEDIATE SHUTDOWN following a SG inspection ensures that the Surveillance has been completed and all tubes meeting the repair criteria are plugged prior to subjecting the SG tubes to significant primary to secondary pressure differential.
Amendment No. 188 711812006
Serial No. 07-0217 ATTACHMENT 4 TECHNICAL SPECIFICATIONS BASES CHANGES AND TECHNICAL REQUIREMENTS MANUAL CHANGES KEWAUNEE POWER STATION TECHNICAL REQUIREMENTS MANUAL KEWAUNEE POWER STATION DOMINION ENERGY KEWAUNEE, INC.
KEWAUNEE POWER STATION TECHNICAL REQUIREMENTS MANUAL
KEWAUNEE POWER STATION TRM Table of Contents TECHNICAL REQUIREMENTS MANUAL Revision 14 March 9, 2007 KEWAUNEE POWER STATION TECHNICAL REQUIREMENTS MANUAL Table of Contents SECTION TITLE Revision TRM 1.0 General Information................................................................................. 4 TRM 2.0 Reports TRM 2.1 Core Operating Limits Report (COLR) Cycle 28 ................... 0 TRM 3.0 Administrative Limiting Conditions for Operation (ALCOs) and Administrative Surveillance Requirements (ASRs)
TRM 3.5.1 Containment Hydrogen Monitoring System .......................... 1 TRM 3.5.2 Flooding Protection - Circulating Water Pump Trip .............. 1 TRM 3.5.3 Emergency Plan Portable Radiation Survey Instruments ..... 1 TRM 3.7.1 Technical Support Center (TSC) 1 Station Blackout (SBO) Diesel Generator (DG). ......................... ..2 TRM 3.7.2 Common Cause Testing of Emergency Diesel Generators .. 0 I TRM 3.1 1.I Core Surveillance Instrumentation (Incore Thimbles) ........... 1 TRM 4.0 Programs
KEWAUNEE POWER STATION TRM 1.0 TECHNICAL REQUIREMENTS MANUAL Revision 4 September 25,2006 1.0 GENERAL INFORMATION
- 1. PURPOSE:
The Technical Requirements Manual (TRM) is a Kewaunee Power Station (KPS) controlled document, which supplements the Kewaunee Technical Specifications. The TRM contains requirements similar to the Technical Specifications, which are not required to be located in the Technical Specifications, because they do not meet the requirements of 10 CFR 50.36.
Although these requirements are excluded from Technical Specifications, they are still requirements placed upon plant operation due to regulatory issues.
The TRM is considered a part of the Updated Safety Analysis Report (USAR).
- 2. ORGANIZATION:
Section 2.0 -- REPORTS This section currently contains the Core Operating Limits Report (COLR).
This is a KPS controlled document that provides cycle-specific parameter I limits for the current reload cycle. These cycle-specific parameter limits shall be determined for each reload cycle in accordance with Technical Specification Section 6.9(a)(4), "Core Operating Limits Report (COLR)". Plant operation within these limits is addressed in the individual specifications.
Other reports may be added to this section, as they become available and as deemed appropriate.
Section 3.0 --ADMINISTRATIVE LIMITING CONDITIONS FOR OPERATION (ALCOs) AND ADMINISTRATIVE SURVEILLANCE REQUIREMENTS (ASRs)
This section contains administrative (i.e., non-Technical Specification)
Limiting Conditions for Operation and Surveillance Requirements (designated as ALCOs and ASRs, respectively), in order to distinguish them from Technical Specification requirements.
Specific ALCOs 1 ASRs will be grouped under the appropriate subsection and sequentially numbered within the subsections.
The ASR is to be performed within the specified surveillance interval, with a maximum allowable extension not to exceed 25% of the specified surveillance interval.
KEWAUNEE POWER STATION TRM 1.0 TECHNICAL REQUIREMENTS MANUAL Revision 4 September 25,2006 If an ALCO is not met, or if an ASR frequency (including the allowed 25%
extension) is not met, an Action Request (AR) item is to be submitted to document the circumstances.
As ALCOs and ASRs become available, they will be inserted into this section.
Section 4.0 -- PROGRAMS The Program Description includes a designation of organizational program ownership, a description of the methodology or basis for establishing acceptance criteria, any associated reporting requirements, content review frequency, and method for determining program effectiveness. Also included will be a description of Program implementation and change control. Where appropriate, applicable TS L C 0 and TRM ALCO required actions or other compensatory measures will be noted.
As Programs are developed, they will be inserted into this section. There are none at this time.
- 3. REVISIONS:
Revisions to the TRM will be made in accordance with procedure GNP-03.25.01, "Technical Specification Bases and Technical Requirements Manual Control Procedure". As part of the USAR, the revisions must comply with the requirements of 10 CFR 50.59.
- 4. DEFINITIONS:
The definitions given in the KPS Technical SpecificationsSection I.O, are to be applied to the appropriate ALCOs and ASRs specified in the TRM.
- 5.
REFERENCES:
- a. KPS Technical Specifications
- b. GNP-03.25.01, "Technical Specification Bases and Technical Requirements Manual Control Procedure"
- c. NAD-03.25, "Technical Requirements Manual Control Directive"
- d. NAD-04.04, "Changes, Tests, and Experiments (10CFR50.59)"
KEWAUNEE POWER STATION TRM 3.5.1 TECHNICAL REQUIREMENTS MANUAL Revision 1 September 25,2006 3.5.1 CONTAINMENT HYDROGEN MONITORING SYSTEM APPLICABILITY During OPERATING or HOT STANDBY Modes.
OBJECTIVE To monitor the beyond design-basis accident containment air and provide a continuous indication of hydrogen concentration.
TECHNICAL REQUIREMENTS Administrative Limiting Conditions for Operation (ALCOs)
- a. Two trains of the Containment Hydrogen Monitoring System shall be OPERABLE except as allowed below:
I.One train may be inoperable for 30 days.
- 2. Two trains may be inoperable for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />
- b. If operability is not restored in the timeframes above, then immediately initiate a Corrective Action to assure prompt attention and adequate management oversight.
- c. A change in operational MODES or conditions is acceptable with one or both trains of the Containment Hydrogen Monitoring System inoperable.
Administrative Surveillance Requirement (ASRs)
CHANNEL CHECK CALIBRATE TEST REMARKS DESCRIPTION Each Containment Hydrogen Daily refueling Monthly Monitors cycle
KEWAUNEE POWER STATION TRM 3.5.1 TECHNICAL REQUIREMENTS MANUAL Revision 1 September 25,2006 BASES The TS requirements for a Containment Hydrogen Monitoring System have been removed from TS as listed in the Federal Register on September 25, 2003. Guidance for the Consolidated Line Item Improvement Process (CLIIP) has been incorporated in the Technical Specification Task Force (TSTF) Change Traveler 447, Rev.1. Part of the requirements for removing Containment Hydrogen Monitoring System from TS was to place any remaining requirements in a Licensee controlled document (Technical Requirements Manual) with the requirements that a hydrogen monitoring system be available for beyond design-basis accident monitoring of containment hydrogen levels.
Even though the requirements for Hydrogen Monitors were taken out of TS, the system still needs to be available for beyond design-basis accident monitoring of containment hydrogen levels. In the event ALCO a.1 or a.2 are not met, an Action Request will be initiated immediately to address why the hydrogen monitors was not restored to OPERABLE status within the allotted time. Actions shall be implemented in a timely manner to place the unit in a safe condition as determined by plant management. The intent of this Action Request is to utilize the Corrective Action Program to assure prompt attention and adequate management oversight to minimize the additional time the hydrogen monitors are inoperable.
KEWAUNEE POWER STATION TRM 3.5.2 TECHNICAL REQUIREMENTS MANUAL Revision 1 September 25,2006 3.5.2 FLOODING PROTECTION CIRCULATING WATER PUMP TRIP APPLICABILITY Whenever the Circulating Water System is in operation.
OBJECTIVE To provide turbine building flood protection in the event of a failure in the Circulating Water System piping.
TECHNICAL REQUIREMENTS Administrative Limiting Conditions for Operation (ALCOs)
- a. Two trains of circulating water pump trip circuitry shall be OPERABLE.
- b. If one channel per train is inoperable, then place the channel in a trip condition within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> or declare the affected train inoperable.
- c. If two or more channels per train are inoperable, then declare the affected train inoperable.
- 1. One train may be inoperable for 90 days.
- 2. Two trains may be inoperable for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
- d. If the OPERABILITY requirements of (c) cannot be met then within 1 hour:
Achieve HOT STANDBY within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
Achieve HOT SHUTDOWN within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
Remove circulating water pumps from operation within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
Administrative Surveillance Requirements (ASRs)
CHANNEL DESCRIPTION CHECK CALIBRATE TEST REMARKS Each Not Not Circulating Water Pump Trip Refueling Applicable Applicable
- Cycle
KEWAUNEE POWER STATION TRM 3.5.2 TECHNICAL REQUIREMENTS MANUAL Revision 1 September 25, 2006 BASES General Overview The Circulating Water (CW) pump trip function is to provide a trip to both CW pump breakers whenever evidence of significant flooding in the Turbine Building (TB) basement could potentially impact operation of the emergency diesel generators, associated safety-related buses and motor control centers, and the auxiliary feedwater pumps and associated circuitry located in safeguards alley.
The detection, actuation, and logic circuitry used to actuate the CW Pump breaker trips, is designed and installed as non-safety-related, but with many attributes of a safety-related design such as redundancy, diversity, and separation. The outputs from the logic circuits and supplemental outputs from the actuation circuits will be used to electrically trip the CW pump breakers and indicate alarms to the operators. A supplemental alarm, including detector and associated circuitry, is installed to provide an early warning to the operators of potential flooding in the TB basement.
The design uses two independent trains of detection, actuation, and logic circuitry that will detect flooding on the TB basement in the vicinity of the north wall to provide 2 out of 3 logic matrix outputs to trip both CW pump circuit breakers. Additionally, any single detector actuation or logic matrix actuation will be alarmed in the Control Room to alert the operators of the abnormal condition.
The six TB basement high water level (flooding) detectors are listed for Underwriters Laboratories (UL) hazardous locations, are weatherproof and explosion proof, and have a leak proof lower body and an independent waterproof conduit seal. They can withstand up to 350 psig, can handle a minimum liquid specific gravity of 0.7; and have temperature limits of -4°F to +220°F. Thus their application to detect a water level due to flooding is assured. The float switch weighs approximately one pound. It is also sensitive to level changes of less than one-half inch.
Each of the three actuation relays (per train) will actuate an individual SER point to indicate to the operators that an individual actuation switch has tripped and associated actuation relay has energized. Thus, indication of a single switch actuation will be available to determine if the actuation occurred in the northwest (NW), north (N), or northeast (NE) section along the TB basement north wall. All six actuation relay SERs will alarm the same new annunciator window.
KEWAUNEE POWER STATION TRM 3.5.2 TECHNICAL REQUIREMENTS MANUAL Revision 1 September 25, 2006 Administrative Limiting Conditions for Operation (ALCO's)
The CW trip consists of two trains of trip function, each with three channels. Each train requires a minimum of two channels to be OPERABLE as long as the inoperable channel is placed in the tripped position within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. This allows the remaining 2 channels to function as a 1 out of 2 trip function to trip the pumps. If two or more channels are inoperable, the train is considered inoperable.
Based on Probabilistic Risk Assessment (PRA) application (a) and consistent with Regulatory Guide 1.I 77, one train can be inoperable for up to 90 days and both trains can be inoperable for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. The core damage frequency for flooding from the CW System into the turbine building with one train inoperable is 1.92 x 1 0 - ~ / ~ eand a r 4.76 x 10-~/year for both trains inoperable. The core damage frequency results with one train inoperable equates to 990 days of inoperability potential and 92 hours0.00106 days <br />0.0256 hours <br />1.521164e-4 weeks <br />3.5006e-5 months <br /> of inoperability potential for both trains inoperable.
If the train ALCO cannot be met, the plant will begin to shutdown within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and achieve HOT STANDBY within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and HOT SHUTDOWN within another 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
The CW pumps will then be removed from operation within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> of achieving HOT SHUTDOWN.
Administrative Surveillance Requirements (ASR's)
The CW pump trip will require testing each refueling cycle to assure it will function as expected. This frequency is consistent with other systems of similar or higher safety significance.
(a) PRA Application # 05-16 dated May 13, 2005.
3.5.2-3
KEWAUNEE POWER STATION TRM 3.5.3 TECHNICAL REQUIREMENTS MANUAL Revision 1 September 25, 2006 3.5.3 EMERGENCY PLAN PORTABLE RADIATION SURVEY INSTRUMENTS APPLICABILITY At all times.
OBJECTIVE To perform ANSI recommended checks, calibrations, and functional tests on portable radiation survey instruments specifically called out in the Kewaunee Power Station Emergency Plan. 1 TECHNICAL REQUIREMENTS Administrative Limiting Condition for Operation (ALCO)
- a. There are no ALCOs associated with this TRM item.
Administrative Surveillance Requirement (ASR)
- a. Perform the required CHANNEL CHECK, CHANNEL CALIBRATION, and CHANNEL FUNCTIONAL TEST activities in accordance with the following table:
CHANNEL FUNCTIONAL CHECK CALIBRATION DESCRIPTION TEST Emergency Plan Quarterly and Portable Radiation Annually Quarterly Prior to Use Survey Instruments
KEWAUNEE POWER STATION TRM 3.5.3 TECHNICAL REQUIREMENTS MANUAL Revision 1 September 25, 2006 BASES
- 1. The Kewaunee Power Station (KPS) Facility Operating License Amendment No. 182 was issued on April 6, 2005. This amendment relocates the surveillance requirements previously given in Technical Specification (TS)
Table TS 4.1-1 Item 25 "Portable Radiation Survey Instruments" to licensee-controlled documents. Per the NRC Safety Evaluation associated with this license amendment, the TS requirements for Emergency Plan (EP) portable radiation survey instruments will be relocated to the TRM.
The purpose of the ASRs provided in TRM 3.5.3 is to define the appropriate checks, calibrations, and functional tests for portable EP radiation survey instruments. An industry standard, ANSl N323-1978, American National Standards Institute "Radiation Protection Instrumentation Test and Calibration," provides guidance relative to the KPS requirements for portable radiation survey instruments.
The TRM 3.5.3 ASR description "Emergency Plan Portable Radiation Survey Instruments" refers to those portable survey instruments mentioned and covered in the EP. Most of these EP portable instruments are physically located outside of the KPS Owner-Controlled Area (OCA) (e.g. the Site Boundary Facility - SBF, Aurora Medical Center, etc.). Several EP portable instruments are located inside the OCA (e.g. the Radiological Analysis Facility
- RAF).
For non-EP portable radiation survey instruments, the source checks, functional tests, & calibrations are controlled by plant procedures, and are not covered in this TRM line item.
- 2. lnstrument Calibration:
ANSl N323 states instrument calibration is required at least annually. Current Radiation Protection (RP) instrument calibration procedures require annual or more frequent calibration of portable survey instruments. The TRM 3.5.3 ASR line item states that the EP portable radiation survey instrument calibration frequency is on an annual basis, and is thus compliant with the ANSl Standard.
- 3. lnstrument Source Check 1 Functional Test:
ANSl N323 states that an instrument shall be tested with the check source prior to each intermittent use. RP instrument use procedures and Emergency Plan Implementing Procedures (EPIPs) require source checks prior to use.
Additionally, RP training (lesson plans and qualifications) includes the performance of a source check on portable radiation survey instruments prior to use. Therefore, KPS meets the ANSl standard requirements through plant I procedures and practices.
KEWAUNEE POWER STATION TRM 3.5.3 TECHNICAL REQUIREMENTS MANUAL Revision 1 September 25, 2006 The EP portable radiation survey instruments which are physically located outside the OCA do not have the proper sources to perform a source check on all ranges 1 scales. Therefore, those survey instruments listed in the EP which are located outside the OCA need to be brought into the plant on a quarterly basis for functional testing (source check on all ranges Iscales).
Since the EPlPs require a source check prior-to-use, the prior-to-use source check will be completed on one range 1scale with a source that is available at the offsite emergency facilities.
The EP portable radiation survey instruments which are physically located inside the OCA will be subject to a functional test (source check on all ranges
/ scales) on a quarterly frequency and single point source check prior-to-use.
KEWAUNEE POWER STATION TRM 3.7.1 TECHNICAL REQUIREMENTS MANUAL Revision 2 September 25, 2006 3.7.1 TECHNICAL SUPPORT CENTER (TSC) I STATION BLACKOUT (SBO)
DIESEL GENERATOR (DG)
APPLICABILITY During ALL Modes.
OBJECTIVE To ensure the provision of a reliable emergency power source for the TSC and for a postulated SBO condition.
TECHNICAL REQUIREMENTS Administrative Limiting Condition for Operation (ALCO)
- b. If the TSC I SBO DG is made or found not to be OPERABLE, the following actions shall be initiated immediately:
- 1. If the plant is 2540 OF, a Probabilistic Risk Assessment (PRA) evaluation will be performed to determine the TSC I SBO DG allowed configuration time, and to verify a core damage probability of less than (the NUMARC 93-01 limit for Maintenance Rule (a)(4) risk).
- 2. Emergency Preparedness (EP) will be notified, and a 10CFR50.54(q) evaluation will be performed by EP to determine and document the effect on the EP Program.
- 3. Appropriate compensatory I mitigating measures are to be initiated, as determined by the 10CFR50.54(q) evaluation. These measures are to remain in-place while the TSC I SBO DG is not OPERABLE.
- c. A change in plant operational MODES or conditions is acceptable with the TSC I SBO DG not OPERABLE.
Administrative Surveillance Requirement (ASR)
- a. The TSC I SBO DG shall be tested for OPERABILITY once every 31 days.
KEWAUNEE POWER STATION TRM 3.7.1 TECHNICAL REQUIREMENTS MANUAL Revision 2 September 25,2006 BASES
- 1. The purpose of the TSC 1 SBO DG is to provide emergency AC power to Bus 1-46 through breaker 14604, and for station blackout to act as the alternate AC (ACC) power supply as specified in NUMARC 87-00 Rev.1.
The TSC I SBO DG starts automatically on loss of voltage to Bus 1-46 and automatically connects to the Bus after attaining voltage and frequency provided that Source Breaker 14601 has tripped.
The TSC I SBO DG design requirement is to provide emergency power for the TSC Building, security lighting system, and other non-ESF plant systems which are required to operate upon loss of the Main Generator and off-site electrical sources. The TSC 1 SBO DG does not typically supply power to QA Type 1 equipment. During an SBO event, the TSC I SBO DG can be manually tied between Bus 1-46 and Bus 1-52 to become the ACC.
Upon determination that the TSC 1SBO DG is made or found to be inoperable, a 10CFR50.54q evaluation (performed by EP) and a PRA evaluation are to be performed. PRA relies on GNP-08.04.01, "Shutdown Safety Assessment", when the plant is ~ 5 4 OF. 0 A specific PRA Evaluation is not necessary when the plant i s 5 4 0 OF. From an EP perspective, with the TSC I SBO DG out-of-service, the intent of performing the 10CFR50.54(q) evaluation is to develop compensatory 1 mitigation measures to:
Have adequate measures in-place that are intended to minimize the probability of creation of a loss-of-power event. Refer to examples in paragraphs 2.a through d.
= Have adequate measures in-place to deal with an event requiring activation and manning of the TSC, preceded by or followed by a loss of offsite power, rendering the TSC inoperable.
The PRA evaluation will dictate the appropriate limits for allowed configuration time, to allow for adequate time to perform routine maintenance & testing, and to complete the necessary corrective maintenance if the TSC I SBO DG was forced out-of-service. The intent is to prioritize the return-to-service of the TSC I SBO DG, and minimize the out-of-service time period, during which the TSC 1SBO DG would not be available to provide backup power for EP and SBO mitigation purposes.
Allowed Configuration Time is defined (ref. GNP-08.21.01) as the time required to remain at a given configuration before the Incremental Core Damage Probability (the increased probability of core damage that results from being in a given configuration for a given time) reaches the NUMARC 93-01 limit. The allowed configuration time for the TSC 1 SBO DG is based on the relative risk of the TSC 1 SBO DG being out-of-service to mitigate a SBO event.
KEWAUNEE POWER STATION TRM 3.7.1 TECHNICAL REQUIREMENTS MANUAL Revision 2 September 25, 2006 A PRA evaluation was conducted (reference PRA Application # 03-17) on October 28, 2003. WinNUPRA was run with no test and maintenance; one case with the TSC 1SBO DG in service and one case with the TSC 1SBO DG assumed out-of-service. The assumption was added for nothing else being out-of-service. The evaluation results were that the TSC 1SBO DG could have been inoperable for 12.7 days, before reaching a core damage probability of 1 0 . ~(the NUMARC 93-01 limit for Maintenance Rule (a)(4) risk).
- 2. Examples of acceptable compensatory I mitigation measures may include the following:
- a. Prior to taking the TSC 1SBO DG out-of-service, a review of the surveillance tests associated with Emergency Diesel Generators (EDGs)
A and B should be performed. If a surveillance test for either of these EDGs is to come due during TSC 1 SBO DG outage, the test should be performed prior to removing the TSC 1 SBO DG from service.
- b. While the TSC I SBO DG is out-of-service (except for unplanned necessary emergent circumstances), work and testing related to EDGs A or B should not be conducted. This would include the appropriate associated support systems and auxiliaries such as:
EDG engine, generator, and turbocharger EDG auxiliaries -- cooling water, fuel oil, lube oil, starting air, room coolers EDG electrical support components -- 125vdc (Cabinets BRA-104
& BRB-104) and 480v motors (MCC 52A & 62A)
EDG protective relaying
- c. Except for unplanned necessary emergent circumstances, work and testing relative to the following high voltage electrical distribution equipment should not be undertaken:
Main Power Transformer, Main Auxiliary Transformer, and the Reserve Auxiliary Transformer Switchyard equipment (i.e. circuit breakers, capacitor banks, transformer, disconnects, buswork, etc.)
Transmission and substation equipment 1 components in the relay house (i.e. protective relaying, fault detection, etc.)
- d. Except for unplanned necessary emergent circumstances, work and testing relative to Bus 46 should not be undertaken.
The once-per-31-day surveillance test requirement for the TSC 1SBO DG is deemed adequate to demonstrate operability of the TSC I SBO DG and its auxiliaries.
KEWAUNEE POWER STATION TRM 3.7.2 TECHNICAL REQUIREMENTS MANUAL Revision 0 March 9, 2007 3.7.2 COMMON CAUSE TESTING OF EMERGENCY DIESEL GENERATORS APPLICABILITY Whenever the plant is in the HOT STANDBY or OPERATING Modes and one emergency diesel generator is made or determined to be inoperable.
OBJECTIVE To define the requirements necessary to ensure OPERABILITY of the other emergency diesel generator as required by TS 3.7.b.2.
TECHNICAL REQUIREMENTS Administrative Limiting Conditions for Operation (ALCOs)
Note 1: All DG starts may be preceded by an engine prelube period and followed by a warmup period prior to loading.
Note 2: A modified DG start involving idling and gradual acceleration to synchronous speed may be used for this TRM as recommended by the manufacturer.
- a. When one emergency diesel generator is made or found inoperable:
- 1. Within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter, verify correct breaker alignment and indicated power availability for each required offsite circuit, and
- 2. Within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, verify the requirement of TS 3.7.c is met, and
- 3. Daily, in accordance with TS 3.7.b.2, manually start the OPERABLE diesel generator from a standby condition verifying that the emergency diesel generator achieves steady state voltage r 4000 V and 14400 V, and frequency r 60.0 Hz and 163.0 Hz.
Administrative Surveillance Requirement (ASRs)
CHANNEL CHECK CALIBRATE TEST REMARKS DESCRIPTION Not Not Not Not Applicable Not Applicable A licable Applicable Applicable
KEWAUNEE POWER STATION TRM 3.7.2 TECHNICAL REQUIREMENTS MANUAL Revision 0 March 9. 2007 BASES
Background
Technical Specification (TS) 3.7.b.2 states, in part, that one diesel generator (DG) may be inoperable for a period not exceeding 7 days provided the other DG is tested daily to ensure OPERABILITY. However, the TS does not prescribe the specific daily testing required. The purpose of this TRM section is to prescribe the specific DG tests for satisfying the DG testing requirement in TS 3.7.b.2.
TS 4.0 requires that surveillance requirements be met during the MODES specified for individual LCOs. The purpose of TS 4.0 is to ensure that surveillances are performed to verify the OPERABILITY of systems and components. TS 4.6 provides the surveillance requirements to verify that DGs are OPERABLE. Although all the requirements of TS 4.6 must be met (within their required periodicity), TS 3.7.b.2 does not require that any of these specific tests be repeated on a daily basis when the allowance of TS 3.7.b.2 is invoked. The TS is silent on the specific test to be performed.
The primary purpose for the requirement for daily testing is to determine that the OPERABLE DG has not become inoperable due to common cause failure. The guidance in NUREG-1431, Standard Technical Specifications provides for an evaluation of a determination for common cause failure. In the absence of a common cause evaluation, the guidance in NUREG-1431 calls for verification that each DG starts from standby conditions and achieves steady state voltage and frequency. This verification is sufficient to demonstrate DG OPERABILITY (provided all requirements of TS 4.6 remain met (within their required periodicity).
A verification that each DG starts from standby conditions and achieves steady state voltage and frequency satisfies the daily testing requirement of TS 3.7.b.2 to ensure OPERABILITY.
Although TS 3.7.b.2 is not insufficient to assure plant safety, the guidance contained in Administrative Letter 98-10, "Dispositioning of Technical Specifications That Are Insufficient to Assure Plant Safety" for submitting a license amendment is being followed. Therefore, this TRM Section is an interim requirement pending NRC approval of License Amendment Request 232 to clarify DG testing requirements.
Specification Verifying correct breaker alignment and indicated power availability ensures proper circuit continuity for the offsite AC electrical power supply to the onsite distribution network and availability of offsite AC electrical power. The breaker alignment verifies that each breaker is in its correct position to ensure that distribution buses and loads are connected to their preferred power source, and that appropriate independence of offsite circuits is maintained. If an offsite circuit is not available, it is inoperable. Upon offsite
KEWAUNEE POWER STATION TRM 3.7.2 TECHNICAL REQUIREMENTS MANUAL Revision 0 March 9, 2007 circuit inoperability, the associated Technical Specification must be reviewed and entered as applicable.
Verifying the requirements of TS 3.7.c is met is intended to provide assurance that a loss of offsite power, during the period that a DG is inoperable, does not result in a complete loss of safety function of critical systems. These safety functions are designed with redundant safety related trains. Although the requirement of TS 3.7.c is applicable at all times, TRM 3.7.2.a.2 and the associated completion time provides assurance that TS 3.7.c is reviewed.
Manually starting the OPERABLE diesel generator from a standby condition and verifying that each diesel generator achieves steady state voltage and frequency suffices to provide assurance of continued OPERABILITY of that DG while minimizing the period the OPERABLE emergency diesel generator is inoperable due to the test.
In the event the inoperable emergency diesel generator is restored to OPERABLE status before manually starting the redundant OPERABLE emergency diesel generator and the inoperable condition was caused by a diesel generator component, the plant corrective action program will continue to evaluate the common cause possibility. This continued evaluation would follow the requirements of the corrective action program.
According to Generic Letter 84-15 (Reference I , Appendix A, page 2), 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is reasonable to confirm that the OPERABLE emergency diesel generator is not affected by the same problem as the inoperable emergency diesel generator. This is demonstrated by testing the redundant emergency diesel generator once every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> until the inoperable emergency diesel generator is returned to an operable status.
In order to reduce stress and wear on diesel engines, the KPS emergency diesel generator manufacturer recommended a modified start in which the starting speed of DGs is limited, warmup is limited to this lower speed, and the DGs are gradually accelerated to synchronous (References 2 and 3).
References
- 1. Generic Letter 84-15, "Proposed Staff Actions To Improve And Maintain Diesel Generator Reliability"
- 3. DCR 2571, "Evaluate and Correct Diesel Generator Governor Switch Settings, Add Slow Start," Design Description
- 4. Letter from R.C. Knop (NRC RIII) to K.H. Evers (WPSC), dated November 5, 1990, Inspection Report 50-305190017 (DRP) (K-90-230)
KEWAUNEE POWER STATION TRM 3.7.2 TECHNICAL REQUIREMENTS MANUAL Revision 0 March 9, 2007
- 5. Letter from R.C. Knop (NRC RIII) to C.A. Schrock (WPSC), dated December 13, 1991, lnspection Report 50-305191021 (DRP) (K-91-258)
- 6. Letter from R.C. Knop (NRC Rill) to C.A. Schrock (WPSC), dated January 31, 1992, lnspection Report 50-305/91024 (DRP) (K-92-016)
- 7. Letter from D.C. Hintz (WPSC) to D.G. Eisenhut (NRC), "Diesel Generator Reliability (Generic Letter 84-15)," dated October 22, I984 (NRC-84-172)
- 8. Calculation C-10915, "Safeguard Diesel Generator Loading Adjustments for Operation at Frequencies Other Than 60 Hertz," Revision 4, and Addendums A and B
KEWAUNEE POWER STATION TRM 3.1 1. I TECHNICAL REQUIREMENTS MANUAL Revision 1 September 25, 2006 3.1 1.I CORE SURVEILLANCE INSTRUMENTATION (INCORE THIMBLES)
APPLICABILITY Applies to the operability of the movable detector instrumentation system.
OBJECTIVE To clarify operability requirements for the movable detector system.
TECHNICAL REQUIREMENTS Administrative Limiting Condition for Operation (ALCO)
Note:
The percentage of thimbles available is meant in terms of the total number of thimbles originally available in the movable detector system. Thus 100% thimble availability and 50% availability correspond to 36 and 18 available thimbles, respectively.
a) At least 75% thimble availability is required at the startup of each cycle.
b) Thimble deletion below 50% availability is not allowed.
c) An extra penalty must be applied (above that specified in TRM 2.1lCOLR Sections 2.6 and 2.7) to the measured FAH and FQ if thimble availability falls below 75% during the operating cycle. At 50% thimble availability, the FAH penalty is 1% and the FQ penalty is 1%, giving total measurement uncertainties on FAH and FQ of 5% and 6% respectively.
Between 75% and 50% availability, the total measurement uncertainties are applied linearly using Equations 3.1 1.Iand 3.1 1.2 shown below FAH measurement uncertainty (%) = 7 - ( T I9 ) (Eq. 3.1 1. I )
FQ measurement uncertainty (%) = 8 - ( T 1 9 ) (Eq. 3.11.2) where T = number of thimbles used for flux traces d) When operating between 75% and 50% thimble availability, each of the core quadrants, as defined by both the major and minor axes (the minor axes are at 45" to the major axes), must contain at least 3 available thimbles (all thimbles, even those on the quadrant axes, are to be counted as whole values).
KEWAUNEE POWER STATION TRM 3.1 1.I TECHNICAL REQUIREMENTS MANUAL Revision 1 September 25, 2006 Administrative Surveillance Requirement (ASR)
None.
KEWAUNEE POWER STATION TRM 3.1 1. I TECHNICAL REQUIREMENTS MANUAL Revision 1 September 25, 2006 The purpose of the measurement uncertainty factor is to provide a means to account for statistical variation in the flux measurement process. A standard percentage value was used in the equations used in the COLR. The technical specification is not prescriptive as to the required actions when using less than 75% of the thimbles. Based on the uncertainty analysis performed by Westinghouse (reference NF-WP-05-19, "Kewaunee Thimble Deletion Analysis," dated October 31, 2005), the additional uncertainty factor provides conservatism to the calculated values when operating with less than 75% and greater than 50% of the thimbles available.
TRM 3.1 I. I (b) is necessary to avoid issues regarding the ability of the core monitoring system to detect a fuel misload event. In addition, this requirement helps to prevent long-term deterioration of the flux mapping system.
The uncertainties in TRM 3.1 I.I (c) were determined from Kewaunee Power Station Cycle 26 and 27 data. Given that the different fuel types in Cycles 26 and 27 are distributed in distinct patterns (for example, in Cycle 27, fuel type 1 is loaded in peripheral core locations), the use of the maximum sensitivity over all these fuel types ensures the peaking factor penalties are conservative. Further, these penalties discussed in this section can be applied to future cycles (of similar general fuel management strategy to Cycles 26 and 27) without regard for how the fuel types are distributed in the core. These penalties will bound future cycles where fewer fuel types are present. The basis for the uncertainty analysis is in WCAP-7308-L-P-A.
The study performed by Westinghouse shows that the probability of having less than 3 thimbles per quadrant, as a result of random thimble deletion, is about 11%. This suggests that if less than three thimbles remain in each quadrant when only 50% of thimbles are available, it is likely that these deletions were made systematically rather than randomly. Systematic thimble deletion which results in large uninstrumented regions of the core may result in larger penalties than described herein.
TRM 2.1 Kewaunee Power Station CORE OPERATING LIMITS REPORT (COLR)
CYCLE 28 REVISION 0 Approved
I I
Table of Contents I
I Section Title Paae 1.0 CORE OPERATING LIMITS REPORT .................................................................... 1 2.0 OPERATING LIMITS ...................................................................................................... 2 2.1 Reactor Core Safety Limits ......................................................................... 2 2.2 Shutdown Margin (SDM) ................................................................................... 2 2.3 Moderator Temperature Coefficient ................................................................ 2 2.4 Shutdown Bank Insertion Limit ........................................................................... 2 Control Bank Insertion Limits ......................................................................... 2 Nuclear Heat Flux Hot Channel Limits ( ~ ~ ~ ( ..................................................
2)) 3 Nuclear Enthalpy Rise Hot Channel Factor (F. HN) ............................................. 4 Axial Flux Difference (AFD) ................................................................................ 4 Overtemperature AT Setpoint .......................................................................... 5 Overpower AT Setpoint ...................................................................................... 5 RCS Pressure. Temperature. and Flow Departure From ................................... 6 Nucleate Boiling (DNB) Limits Refueling Boron Concentration .................................................................... 6
I I
List of Fiqures J
Finure Title Page
- 1. Reactor Core Safety Limits Curve (1772 MWt) ............................................................... 7
- 2. Required Shutdown Reactivity vs . Boron Concentration.............................................. 8
- 3. Hot Channel Factor Normalized Operating Envelope (K(z)) ........................................... 9
- 4. Control Bank Insertion Limits ........................................................................................ 10
- 5. W(Z) Values (Top and Bottom 9% excluded) ............................................................... I 1
- 6. Penalty Factor, Fp (%). for FaEQ(Z)................................................................................. 13
- 7. Axial Flux Difference ...................................................................................................... 14
L List of Tables I I
Table
- 1. NRC Approved Methodologies for COLR Parameters 15 iii
KEWAUNEE POWER STATION TRM 2.1 TECHNICAL REQUIREMENTS MANUAL Revision 0 CORE OPERATING LIMITS REPORT CYCLE 28 1.0 CORE OPERATING LIMITS REPORT This Core Operating Limits Report (COLR) for Kewaunee Power Station (KPS) has been prepared in accordance with the requirements of Technical Specification (TS) 6.9.a.4.
A cross-reference between the COLR sections and the KPS Technical Specifications affected by this report is given below:
COLR KPS Description Section TS 2.1 2.1 Reactor Core Safety Limits 2.2 3.10.a Shutdown Margin 2.3 3.1 .f.3 Moderator Temperature Coefficient 2.4 3.10.d.l Shutdown Bank lnsertion Limit 2.5 3.10.d.2 Control Bank Insertion Limits 2.6 3.10.b.l .A Heat Flux Hot Channel Factor (FQ(Z))
3.1O.b.5 3.10.b.6 3.10.b.6.C.i 3.10.b.7 3.10.b.l .B Nuclear Enthalpy Rise Hot Channel Factor ( F , ~ ~ )
3.10.b.8 Axial Flux Difference (AFD) 2.3.a.3.A Overtemperature AT Setpoint 2.3.a.3.B Overpower AT Setpoint 3.10.k RCS Pressure, Temperature, and Flow Departure from Nucleate Boiling 3.1 0.1 (DNB) Limits 3.10.m.l 2.12 3.8.a.5 Refueling Boron Concentration Figure 1 Reactor Core Safety Limits (1772 MWt)
Figure 2 Required Shutdown Margin Figure 3 K(Z) Normalized Operating Envelope Figure 4 Control Bank lnsertion Limits Figure 5 W(Z) Values (Top and Bottom 9% excluded)
Figure 6 Penalty Factor, F, for F ~ ~ ~ ( z )
Figure 7 Axial Flux Difference Cycle 28 Page 1 of 20 Rev. 0
KEWAUNEE POWER STATION TRM 2.1 TECHNICAL REQUIREMENTS MANUAL Revision 0 CORE OPERATING LIMITS REPORT CYCLE 28 2.0 O~eratinclLimits The cycle-specific parameter limits for the specifications listed in Section 1.0 are presented in the following subsections. These limits have been developed using the NRC approved methodologies specified in Technical Specification 6.9.a.4.
Reactor Core Safetv Limits The combination of rated power level, coolant pressure, and coolant temperature shall not exceed the limits shown in COLR Figure I (1772 MWt). The safety limit is exceeded if the point defined by the combination of Reactor Coolant System average temperature and power level is at any time above the appropriate pressure line.
Shutdown Marain 2.2.1 When the reactor is subcritical prior to reactor startup, the SHUTDOWN margin shall be at least that shown in COLR Figure 2.
Moderator Temoerature Coefficient 2.3.1 When the reactor is critical and s 60% RATED POWER, the moderator temperature coefficient shall be 15.0 pcmlQF,except during LOW POWER PHYSICS TESTING. When the reactor is > 60% RATED POWER, the moderator temperature coefficient shall be zero or negative.
2.3.2 The reactor will have a moderator temperature coefficient no less negative than -8 pcmI0Ffor 95% of the cycle time at full power.
Shutdown Bank Insertion Limit 2.4.1 The shutdown rods shall be fully withdrawn (2 225 steps and < 230 steps) when the reactor is critical or approaching criticality.
Control Bank Insertion Limits 2.5.1 The control banks shall be limited in physical insertion; insertion limits are shown in COLR Figure 4.
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KEWAUNEE POWER STATION TRM 2.1 TECHNICAL REQUIREMENTS MANUAL Revision 0 CORE OPERATING LIMITS REPORT CYCLE 28 2.6 Nuclear Heat Flux Hot Channel Factor (FQ~(z))
2.6.1 F ~ ~ (Limits z ) for Fuel FQN(z)x 1.03 x 1.05 5 (2.50)IP x K(Z) for P > 0.5 [422 V+]
FQN(z)x 1.03 x I.05 5 (5.00) x K(Z) for P 5 0.5 1422 V+]
where:
P is the fraction of full power at which the core is OPERATING K(2) is the function given in Figure 3 Z is the core height location for the FQof interest 2.6.2 The measured F ~ ~ ~hot ( zchannel
) factors under equilibriumconditions shall satisfy the following relationship for the central axial 80% of the core for fuel:
where:
P is the fraction of full power at which the core is OPERATING K(Z) is the function given in Figure 3 Z is the core height location for the FQof interest Fp is the FQEQ(z) penalty factor described in 2.6.3.
W(Z) Is the function given in Figure 5 F Q ~ ~ (isz a) measured Fa distribution obtained during the target flux determination 2.6.3 The penalty factor of 1.O shall be used for TS 3.lO.b.6.A and TS 3.10.b.6.B.
The penalty factor provided in Figure 6 shall be used for TS 3.10.b.6.C.i.
The penalty factor for all bumups outside the range of Figure 6 shall be 2%.
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KEWAUNEE POWER STATION TRM 2.1 TECHNICAL REQUIREMENTS MANUAL Revision 0 CORE OPERATING LIMITS REPORT CYCLE 28 2.7 Nuclear Enthal~vRise Hot Channel Factor ( ~ a 2.7.1 F~~~Limits for Fuel where:
P is the fraction of full power at which the core is OPERATING 2.8 Axial Flux Difference (AFD) 2.8.1 The Axial Flux Difference (AFD) acceptable operation limits are provided in Figure 7.
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KEWAUNEE POWER STATION TRM 2.1 TECHNICAL REQUIREMENTS MANUAL Revision 0 CORE OPERATING LIMITS REPORT CYCLE 28 2.9 OvertemperatureAT Setpoint Overtemperature AT setpoint parameter values:
lndicated AT at RATED POWER, %
Average temperature, OF 573.0 "F Pressurizer Pressure, psig 2235 psig 1.195 0.015PF 0.000721psig 30 seconds 4 seconds An even function of the indicated difference between top and bottom detectors of the power range nuclear ion chambers. Selected gains are based on measured instrument response during plant startup tests, where q, and qbare the percent power in the top and bottom halves of the core respectively, and q, + q, is total core power in percent of RATED POWER, such that (a) For q, - qbwithin -15, + I 0 %, f(AI) = 0 (b) For each percent that the magnitude of qt - qbexceeds +10 % the AT trip setpoint shall be automatically reduced by an equivalent of 1.51 % of RATED POWER.
(c) For each percent that the magnitude of qt - qbexceed -15 % the AT trip setpoint shall be automatically reduced by an equivalent of 3.78% of RATED POWER.
2.1 0 Over~owerAT Setpoint Overpower AT setpoint parameter values:
AT0 = Indicated AT at RATED POWER, %
T = Average temperature, "F T' i 573.0 O F K4 <
- 1.095 Kg 2 0.0275I0Ffor increasing T; 0 for decreasing T Kg 2 0.001031°F for T > T' ; 0 for T < Tr r3 = 10 seconds f(AI) = 0 for all Al Cycle 28 Page 5 of 20 Rev. 0
KEWAUNEE POWER STATION TRM 2.1 TECHNICAL REQUmEMENTS MANUAL Revision 0 CORE OPERATING LIMITS REPORT CYCLE 28 2.11 RCS Pressure, Temperature, and Flow Departurefrom Nucleate Boiling (DNB) Limits 2.1 1.1 During steady state power operation, Tavg shall be < 576.7"F for control board indication or < 576.5"F for computer indication.
2.1 1.2 During steady state power operation, Pressurizer Pressure shall be
> 2217 psig for control board indication or > 2219 psig for computer indication 2.11.3 During steady state power operation, reactor coolant total flow rate shall be 2 186,000 gpm.
2.12 Refuelinq Boron Concentration 2.12.1 When there is fuel in the reactor, a minimum boron concentration of 2500 ppm and a shutdown margin of 2 5% A klk shall be maintained in the Reactor Coolant System during reactor vessel head removal or while loading and unloading fuel from the reactor.
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KEWAUNEE POWER STATION TRM 2.1 TECHNICAL REQUIREMENTS MANUAL Revision 0 CORE OPERATING LIMITS REPORT CYCLE 28 Figure 1 Reactor Core Safety Limits Curve (1772 Mwt)
(Cores Containing 422V+ fuel) 20 40 60 80 100 Core Power (percent of 1772 MWt)
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KEWAUNEE POWER STATION TRM 2.1 TECHNICAL REQUIREMENTS MANUAL Revision 0 CORE OPERATING LIMITS REPORT CYCLE 28 Figure 2 Required Shutdown Reactivity vs. Boron Concentration Full Power Equilibrium Boron Concentration (PP~)
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KEWAUNEE POWER STATION TRM 2.1 TECHNICAL REQUIREMENTS MANUAL Revision 0 CORE OPERATING LIMITS REPORT CYCLE 28 Figure 3 Hot Channel Factor Normalized Operating Envelope (K(z))
0 1 2 3 4 5 6 7 8 9 1 0 1 1 1 2 Core height (ft)
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KEWAUNEE POWER STATION TRM 2.1 TECHNICAL REQUIREMENTS MANUAL Revision 0 CORE OPERATING LIMITS REPORT CYCLE 28 Figure 4 Control Bank Insertion Limits 30 40 50 60 70 Percent of Rated Thermal Power Fully withdrawn shall be the condition where control rods are at a position between the interval 1 225 and 5 230 steps withdrawn.
Note: The Rod Bank Insertion Limits are based on a control bank tip-to-tip distance of 126 steps.
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KEWAUNEE POWER STATION TRM 2.1 TECHNICAL REQUIREMENTS MANUAL Revision 0 CORE OPERATING LIMITS REPORT CYCLE 28 Figure 5 W(Z) Values (Top and Bottom 9% excluded)
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KEWAUNEE POWER STATION TRM 2.1 TECHNICAL REQUIREMENTS MANUAL Revision 0 CORE OPERATING LIMITS REPORT CYCLE 28 Figure 5 Cont'd (Top and Bottom 9% excluded)
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KEWAUNEE POWER STATION TRM 2.1 TECHNICAL REQUIREMENTS MANUAL Revision 0 CORE OPERATING LIMITS REPORT CYCLE 28 Figure 6 Penalty Factor, F, (%), for F ~ ~ ~ ( z )
Cycle Burnup Penalty m/MTU) Factor Fp (%I Note: Linear interpolation is adequate for intermediate cycle burnups.
All cycle burnups outside the range of the table shall use a penalty factor, Fp,of 2.0%.
Refer to TS 3.10.b.6.C.
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KEWAUNEE POWER STATION TRM 2.1 TECHNICAL REQUIREMENTS MANUAL Revision 0 CORE OPERATING LIMITS REPORT CYCLE 28 Figure 7 Axial Flux Difference
-20 -10 0 10 20 Axial Flux Difference (% delta-I)
Note: This figure represents the Relaxed Axial Offset Control (RAOC) band used in safety analyses, it may be administratively tightened depending on in-core flux map results. Refer to Figure RD 11.4.1 of the Reactor Data Manual.
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KEWAUNEE POWER STATION TRM 2.1 TECHNICAL REQUIREMENTS MANUAL Revision 0 CORE OPERATING LIMITS REPORT CYCLE 28 Table 1 NRC Approved Methodologies for COLR Parameters COLR Section Parameter NRC A ~ p r o v e dMethodo\ogy 2.1 Reactor Core Safety Limits WCAP-9272-P-A, "Westinghouse Reload Safety Evaluation Methodology," July 1985.
Safety Evaluation by the Office of Nuclear Reactor Regulation on 'Qualifications of Reactor Physics Methods for Application to Kewaunee" Report, dated August 21,1979, report date September 29, 1978.
Kewaunee Nuclear Power Plant-Review for Kewaunee Reload Safety Evaluation Methods Topical Report WPSRSEM-NP, Revision 3 (TAC NO MB0306) dated September 10,2001.
Shutdown Margin WCAP-9272-P-A, "Westinghouse Reload Safety Evaluation Methodology," July 1985 Safety Evaluation by the Office of Nuclear Reactor Regulation on "Qualifications of Reactor Physics Methods for Application to Kewaunee" Report, dated August 21,1979, report date September 29, 1978.
2.3 Moderator Temperature Coefficient WCAP-9272-P-A, "Westinghouse Reload Safety Evaluation Methodology," July 1985.
Safety Evaluation by the Office of Nuclear Reactor Regulation on "Qualifications of Reactor Physics Methods for Application to Kewaunee" Report, dated August 21,1979, report date September 29, 1978.
Shutdown Bank Insertion Limit WCAP-9272-P-A, "Westinghouse Reload Safety Evaluation Methodology," July 1985.
Safety Evaluation by the Office of Nuclear Reactor Regulation on "Qualifications of Reactor Physics Methods for Application to Kewaunee" Report, dated August 21, 1979, report date September 29, 1978.
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KEWAUNEE POWER STATION TRM 2.1 TECHNICAL REQUIREMENTS MANUAL Revision 0 CORE OPERATING LIMITS REPORT CYCLE 28 Table I (cont)
NRC Approved Methodoloqies for COLR Parameters COLR Section Parameter NRC A ~ ~ r o v eMethodoloay d
Kewaunee Nuclear Power Plant-Review for Kewaunee Reload Safety Evaluation Methods Topical Report WPSRSEM-NP, Revision 3 (TAC NO MB0306) dated September 10,2001.
2.5 Control Bank Insertion Limits WCAP-9272-P-A, "Westinghouse Reload Safety Evaluation Methodology," July 1985.
Safety Evaluation by the Office of Nuclear Reactor Regulation on "Qualifications of Reactor Physics Methods for Application to Kewaunee" Report, dated August 21,1979, report date September 29, 1978.
Kewaunee Nuclear Power Plant-Review for Kewaunee Reload Safety Evaluation Methods Topical Report WPSRSEM-NP, Revision 3 (TAC NO MB0306) dated September 10,2001.
2.6 Heat Flux Hot Channel Factor WCAP-10216-P-A, Revision I A , "Relaxation of Constant Axial Offset Control-FQ Surveillance Technical Specification,"
February 1994.
Safety Evaluation by the Ofice of Nuclear Reactor Regulation on "Qualificationsof Reactor Physics Methods for Application to Kewaunee" Report, dated August 21,1979, report date September 29, 1978.
WCAP-12945-P-A (Proprietary),
"Westinghouse Code Qualification Document for Best-Estimate Loss-of-Coolant Accident Analysis," Volume I,Rev.2, and Volumes II-V, Rev.1, and WCAP-14747 (Non-Proprietarj), March 1998.
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KEWAUNEE POWER STATION TRM 2.1 TECHNlCAL REQUIREMENTS MANUAL Revision 0 CORE OPERATING LIMITS REPORT CYCLE 28 Table I (cont)
NRC Approved Methodoloqies f o r COLR Parameters COLR Section Parameter NRC Approved Methodoloay ANF-88-133 (P)(A) and Supplement 1, "Qualification of Advanced Nuclear Fuels' PWR Design Methodology for Rod Bumups of 62 GWdlMTU," Advanced Nuclear Fuels Corporation, dated December 1991.
WCAP-14449-P-A, "Application Of Best Estimate Large Break LOCA Methodology To Westinghouse PWRs With Upper Plenum Injection," Revisionl, and WCAP-14450-NP-A, Rev.1 (Non-Proprietary), October 1999.
WCAP-12610-P-A, "Vantage+ Fuel Assembly Reference Core Report," April 1995.
Model WCAP-10054-P-AMICAP-1008 1-NP-A, "Westinghouse Small Break ECCS Evaluation Using the NOTRUMP Code,"
August 1985.
NOTRUMP WCAP-10054-P-ANVCAP-10081-NP-A, Addendum 2, Revision 1, "Addendum to the Westinghouse Small Break ECCS Evaluation Model Using the Code: Safety Injection into the Broken Loop and COSl Condensation Model," July 1997.
Nuclear Enthalpy Rise WCAP-9272-P-A, "Westinghouse Reload Hot Channel Factor ( F ~ , ~ ) Safety Evaluation Methodology," July 1985.
Safety Evaluation by the Office of Nuclear Reactor Regulation on "Qualifications of Reactor Physics Methods for Application to Kewaunee" Report, dated August 21, 1979, report date September 29, 1978.
Kewaunee Nuclear Power Plant-Review forKewaunee Reload Safety Evaluation Methods Topical Report WPSRSEM-NP, Cycle 28 Page 17 of 20 Rev. 0
KEWAUNEE POWER STATION TRM 2.1 TECHNICAL REQUIREMENTS MANUAL Revision 0 CORE OPERATING LIMITS REPORT CYCLE 28 Revision 3 (TAC NO MB0306) dated September 10,2001.
Table I (cont)
NRC Approved Methodoloqies for COLR Parameters COLR Section Parameter NRC Approved Methodoloay XN-82-06 (P)(A) Revision 1 and Supplements 2, 4, and 5, "Qualifications of Exxon Nuclear Fuel for Extended Burnup, Exxon Nuclear Company, dated October 1986.
ANF-88-133 (P)(A) and Supplement 1, "Qualification of Advanced Nuclear Fuels' PWR Design Methodology for Rod Burnups for 62 GWdIMTU," Advanced Nuclear Fuels Corporation, dated December 1991.
EMF-92-116 (P)(A) Revision 0,"Generic Mechanical Design Criteria for PWR Fuel Designs," Siemens Power Corporation, dated February 1999.
Axial Flux Difference WCAP-10216-P-A, Revision 1A, "Relaxation of Constant Axial Offset (AFD) Control-Fo Surveillance Technical Specification,"
February 1994.
Safety Evaluation by the Office of Nuclear Reactor Regulation on "Qualifications of Reactor Physics Methods for Application to Kewaunee" Report, dated August 21,1979, report date September 29, 1978.
Kewaunee Nuclear Power Plant-Review for Kewaunee Reload Safety Evaluation Methods Topical Report WPSRSEM-NP, Revision 3 (TAC NO MB0306) dated September 10, 2001.
2.9 Reactor Protection System (RPS) WCAP-8745-P-A, "Design Bases For The Instrumentation-Overtemperature AT Thermal Overpower AT and Thermal Overtemperature AT Trip Functions,"
September 1986.
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KEWAUNEE POWER STATION TRM 2.1 TECHNICAL REQUTREMENTS MANUAL Revision 0 CORE OPERATING LIMITS REPORT CYCLE 28 Table I (cont)
NRC Approved Methodoloaies for COLR Parameters COLR Section Parameter NRC Amroved Methodoloqy Kewaunee Nuclear Power Plant-Review for Kewaunee Reload Safety Evaluation Methods Topical Report WPSRSEM-NP, Revision 3 (TAC NO MB0306) dated September 10,2001.
CENP-397-P-A, "Improved Flow Measurement Accuracy Using Cross Flow Ultrasonic Flow Measurement Technology,"
Rev. 1, May 2000.
2.10 Reactor Protection System (RPS) WCAP-8745-P-A, "Design Bases For The Instrumentation-OverpowerAT Thermal Overpower AT and Thermal Overtemperature AT Trip Functions,"
September 1986.
Kewaunee Nuclear Power Plant-Review for Kewaunee Reload Safety Evaluation Methods Topical Report WPSRSEM-NP, Revision 3 (TAC NO MB0306) dated September 10,2001.
CENP-397-P-A, "Improved Flow Measurement Accuracy Using Cross Flow Ultrasonic Flow Measurement Technology,"
Rev. 1, May 2000.
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KEWAUNEE POWER STATION TRM 2.1 TECHNICAL REQUIREMENTS MANUAL Revision 0 CORE OPERATING LIMITS REPORT CYCLE 28 Table I (cont)
NRC Approved Methodolonies for COLR Parameters COLR Section Parameter NRC Approved Methodoloay 2.1 1 RCS Pressure, Temperature, and WCAP-11397-P-A, "Revised Thermal Design Flow Departure From Nucleate Procedure, "April 1989, for those events (DNB) Limits analyzed using RTDP Kewaunee Nuclear Power Plant-Review for Kewaunee Reload Safety Evaluation Methods Topical Report WPSRSEM-NP, Revision 3 (TAC NO MB0306) dated September 10,2001.
WCAP-9272-P-A, "Westinghouse Reload Safety Evaluation Methodology," July 1985 for those events not utilizing RTDP.
Boron Concentration WCAP-9272-P-A, "Westinghouse Reload Safety Evaluation Methodology," July 1985.
Safety Evaluation by the Office of Nuclear Reactor Regulation on "Qualifications of Reactor Physics Methods for Application to Kewaunee" Report, dated August 21,1979, report date September 29, 1978.
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