ML13331A882
| ML13331A882 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 05/19/1986 |
| From: | SOUTHERN CALIFORNIA EDISON CO. |
| To: | |
| Shared Package | |
| ML13331A880 | List: |
| References | |
| NUDOCS 8605210202 | |
| Download: ML13331A882 (21) | |
Text
ATTACHMENT 1 PROPOSED CHANGE 136 (These pages are from Proposed Change 136, as revised by SCE to NRC letter dated December 17, 1985) 8605210202 860519 PDR ADOCK 05000206 p
-3 Table 3.14.1 REQUIRED SPRINKLER AND SPRAY SYSTEMS Hazard Location System Type Reactor Coolant Containment Sphere Deluge - Borated Pumps, RHR Pumps, Water Spray*
Cable Insulation Outside Secondary Shield Turbine lubricating System #1 Chemical Deluge water spray oil and cable Treatment Area insulation Turbine lubricating System #2 Lube Oil Deluge water spray oil and cable Reservior area insulation (north half)
Turbine lubricating System #3 Lube Oil Deluge water spray oil and cable Reservior area insulation (south half)
Turbine lubricating System #4 480 V Room Wall Wet Pipe oil
& Turbine Building North Wall Turbine lubricating System #5 North Turbine Wet Pipe oil and cable Building Area Protection insulation Hydrogen Seal Oil Hydrogen Seal Oil Deluge water spray Unit Diesel Generator Diesel Generator Pre-Action Sprinkler Building 1 Diesel Generator Diesel Generator Pre-Action Sprinkler Building 2 Transformer oil Station Service Deluge water spray Transformer 2 & 3 This includes a refueling water pump, 240,000 gallons of water in the refueling water storage tank and associated system valves.
-10 Table 3.14.3 FIRE DETECTION INSTRUMENTS Minimum Instruments Operable Infrared Ultraviolet Detector Smoke Flame Thermal Flame Zone Location Detectors Detectors Detectors Detectors 1
No. 1 DC Switchgear and 3
Battery Room 2
480-V Switchgear Room 8
3 4160-V Switchgear Room 18 4
2 5 Administration Building, 4**
1st Floor 7
Control Room Complex 20 8
Turbine Lube Oil Reservior 29 6
6***
9 Containment Sphere Inside 7*
1 Secondary Shield 10 Containment Sphere Outside 10 2
8 Secondary Shield 11 Reactor Auxiliary Building 10*
and Storage Rooms 16 Sphere Enclosure Building 12 15 4
17 Lube Oil Shed 1
18 Air Compressors 1
19 Ventilat-ion Equipment Room 2
20 Pipe Tunnel 4
21 No. 2 Battery 1
22 Service Transformers 2&3 2
DG No. 1 Diesel Generator Room 2
2 DG2 No. 2 Diesel Generator Room 2
2 Note: The Fire Detection Zones not identified either do not contain safety related equipment or do not involve potential fire hazards to safety related equipment.
Includes one high flow smoke detector.
Detectors above suspended ceiling.
- Line type heat detectors.
ATTACHMENT 2 PROPOSED TECHNICAL SPECIFICATION (The changes indicated in this proposed change reflect differences from Proposed Change 136, as revised by SCE to NRC letter dated December 17, 1985)
-3 Table 3.14.1 REQUIRED SPRINKLER AND SPRAY SYSTEMS Fire Area/
Zone Hazard Location System Type 1
Reactor coolant pumps, Containment sphere Deluge - borated RHR pumps, cable water spray*
insulation outside secondary shield 2A Charging Pumps Charging Pump Room Wet Pipe 4B/4D Cable Insulation Cable Trays, Deluge water spray Yard/Breezeway Area 40 Transformer oil Station Service Transformer 1 Deluge water spray Transformers 2 & 3 Deluge water spray 9A Turbine lubricating oil System #1 chemical treatment Deluge water spray and cable insulation area Turbine lubricating oil System #2 lube oil reservoir Deluge water spray and cable insulation area (north half)
Turbine lubricating oil System #3 lube oil reservoir Deluge water spray and cable insulation area (south half)
Turbine lubricating oil System #4 480 V room wall &
Wet pipe turbine building north wall Turbine lubricating oil System #5 north turbine Wet pipe and cable insulation building area protection Hydrogen seal oil Hydrogen seal oil unit Deluge water spray 17A Diesel Generator North Diesel Generator Pre-Action Sprinkler 18 Diesel Generator South Diesel Generator Pre-Action Sprinkler
- This includes a refueling water pump, 240,000 gallons of water in the refueling water storage tank and associated system valves.
-10 Table 3.14.3 FIRE DETECTION INSTRUMENTS Minimum Instruments Operable Infrared Ultraviolet Fire Smoke Flame Thermal Flame Area/Zone Location Detectors Detectors Detectors Detectors 1
Containment Sphere Inside Secondary Shield 7
1 Outside Secondary Shield 10 2
8 2A Reactor Auxiliary Bldg.
Lower Level 8
3 Volume Control Tank Room 1
4A&B East and West Penetration 12 17 4
Areas 4C Doghouse 2
48/40 Cable Trays Yard/Breezeway Area 2*
40 Service Transformer 1 2
Service Transformers 2&3 2
46 Dedicated Shutdown Enclosure DSD Diesel Generator 6
DSD Switchgear/Battery Room 3
7 480V Switchgear Room 8
8 4160V Switchgear Room 16 9A Turbine Building Ground Floor Instrument Air Compressors 1
Lube Oil Reservoir 29 6
6*
10 Lube Oil Shed 1
11A Health Physics and 4
Locker Room 11B HVAC Equipment Room 3
12 Offices 1st Floor 7
-10a Table 3.14.3 (Contd)
FIRE DETECTION INSTRUMENTS Minimum Instruments Operable Infrared Ultraviolet Fire Smoke Flame Thermal Flame Area/Zone Location Detectors Detectors Detectors Detectors 13A DC Switchgear Room No. 1 2
13B Battery Room No. 1 1
16 Control Room 20 17A North Diesel Room 3
3 17B Battery Room No. 2 1
18 South Diesel Room 4
4 25 West Cable Shaft 1
26 East Cable Shaft 1
34 Pipe Tunnel 4
Note:
The fire area/zones not identified either do not contain safety realted equipment or do not involve potential fire hazards to safety related equipment.
- Includes line type heat detectors.
DA:6505F
DESCRIPTION OF PROPOSED CHANGE NO. 159 AND SAFETY EVALUATION This is a request to revise Appendix A Technical Specifications by incorporating four new sections as follows:
3.20 Dedicated and Alternate Shutdown Systems 3.21 Emergency Lighting Units 4.20 Dedicated and Alternate Shutdown Systems Surveillance 4.21 Emergency Lighting Units Surveillance and their associated Bases Description
References:
- 1) Letter, M. 0. Medford (SCE) to J. A. Zwolinski (NRC), dated October 4, 1985, Fire Protection Program Review
- 2) Letter, M. 0. Medford (SCE) to G. E. Lear (NRC), dated December 31, 1985 During the San Onofre Unit 1 outage which commenced on November 21, 1985, a new safety feature, the Dedicated Shutdown (OSD) system, is being installed.
In addition, in order to mitigate certain fires, alternate methods of plant shutdown have been developed. The purpose of the new system and alternate shutdown methods is to provide backup reactor shutdown capability in case the systems normally used to achieve and maintain cold shutdown become inoperable due to certain postulated fires.
This change also provides a requirement for surveillance of eight hour emergency lighting. The design bases for the DSD system and alternate shutdown methods are established by the appropriate sections of Appendix R to 10 CFR 50 as required by 10 CFR 50.48 and the NRC's Generic Letter 81-12, Fire Protection Rule, dated February 20, 1981.
The DSD system and alternate shutdown methods at San Onofre Unit 1 are scheduled to be available for operation upon plant restart for the next cycle (Cycle 9).
By Reference 1, Southern California Edison submitted a detailed design description of the DSD system for NRC's approval and also committed to the development and submittal of Technical Specifications for the associated equipment. Proposed Change No. 159 fulfills this commitment.
Proposed Change No. 159 provides:
A.
A comprehensive list of the minimum OSD/Alternate Shutdown equipment and emergency lights required to be operable.
B.
Surveillances and surveillance intervals for verifying the operability of the OSO/Alternate Shutdown equipment and emergency lights.
C.
A limit of 7 days in which to restore inoperable DSD/Alternate Shutdown equipment to operable status and compensatory measures required to be taken if the 7 day limit is exceeded.
D.
A limit of 60 days within which to submit a special report to the NRC if the inoperable equipment remains in an inoperable status.
E.
Bases for Items A, 8, C and D above.
-2 Existing Technical Specifications None Proposed Technical Specifications As contained in Attachment 1.
Safety Evaluation Proposed Change No. 159 is determined not to constitute a significant hazards consideration based on the following review questions and responses.
- 1. Question Will operation of the facility in accordance with this proposed change involve a significant increase in the probability or consequences of an accident previously evaluated?
Response: No This change does not increase the probability or consequences of an accident previously evaluated. SCE's previous evaluation of the effects of a fire was contained in a letter from SCE to the NRC dated March 16, 1977, Re:
Fire Protection Program Review, BTP APC SB 9.5--l.
The technical specifications associated with this proposed Change are being added due to the addition of safe shutdown features beyond those previously available at the site. The Dedicated Shutdown System (DSO) will add the capability of safely shutting down the plant in the event of certain unlikely fires including consideration of loss-of-offsite power.
Alternate shutdown methods will provide the same capability for other fires. These fires are identified in SCE's letter to the NRC dated October 4, 1985. The added Technical Specifications will assure either that the DSD/Alternate Shutdown equipment is available or that compensatory measures are taken in the interim. The consequences of significant fires affecting plant shutdown are therefore reduced.
In accordance with 10 CFR 50, Appendix R, Item III.G.3, the DSD/Alternate Shutdown systems and their associated circuits are electrically independent of cables, systems and components of the existing safe shutdown systems.
The DSO/ Alternate Shutdown systems are independent of the existing plant configuration and normal plant operation in all the modes.
Therefore, the DSD and Alternate systems do not contribute significant new risks to those which already exist.
- 2. Question Will operation of the facility in accordance with this proposed change create the possibility of a new or different kind of accident.
Response: No The DSO is being installed to provide safe shutdown capability in the event of certain fires. There are no new or different kinds of accidents created by this facility modification.
The alternate shutdown methods use non-normal equipment to mitigate certain fires.
The proposed Technical Specifications are intended to assure the systems are maintained in a ready condition and will also cause no new or different accidents.
Inadvertent operation of the DSD or related equipment would cause additional "auxiliary" feedwater to be provided to the steam generators. Inadvertent operation is protected against by providing electrical isolation of DSD equipment from normal power sources.
This inadvertent operation is similar to but would have far lesser consequences than an increase in feedwater flow transient which has been previously analyzed. The alternate shutdown methods utilize equipment/instrumentation already existing. Further, it does not use this equipment in a new way, other than as an "alternate" to similar equipment normally used for shutdown.
- 3. Question Will operation of the facility in accordance with this proposed change involve a significant reduction in a margin of safety?
Response: No The DSD/Alternate Shutdown Technical Specifications wi l1 assure the availability of these systems for safe shutdown in the event of certain fires. It will not change the margin of safety currently available except to improve the plant's ability to respond to certain postulated fires.
The plant's margin of safety will therefore be improved.
This change is similar to example (1i) of the "Examples of Amendments that are Not Likely to Involve Significant Hazards Considerations" as published in 48 FR 14864 dated April 6, 1983. Example (1i) states: a change that constitutes an additional limitation, restriction or control not presently included in the technical specifications.
The proposed specifications are similar to the example because they provide limitations and surveillance of instrumentation not previously in effect.
Safety and Significant Hazards Determination Based on the safety analysis, it is concluded that:
- 1.
The proposed change does not constitute a significant hazards consideration as defined by 10 CFR 50.92;
- 2.
There is reasonable assurance that the health and safety of the public will not been endangered by the proposed change; and
- 3.
This action will not result in a condition which significantly alters the impact of the station on the environment as described in the NRC Environmental Statement.
GEH:5908F
ATTACHMENT PROPOSED TECHNICAL SPECIFICATIONS 3.20 Dedicated and Alternate Shutdown Systems 3.21 Eight Hour Emergency Lighting Units 4.20 Dedicated and Alternate Shutdown Systems Surveillance 4.21 Eight Hour Emergency Lighting Units Surveillance
3.20 DEDICATED AND ALTERNATE SHUTDOWN SYSTEMS APPLICABILITY:
Modes 1, 2, 3 and 4 OBJECTIVE:
To ensure the operability of the Dedicated Shutdown System (DSD) and equipment necessary for Alternate Shutdown methods in the event of fire.
SPECIFICATION:
The DSD and Alternate Shutdown equipment, shown on Table 3.20.1, shall be OPERABLE.
ACTION:
A. With less than the minimum DSD or Alternate Shutdown equipment in Table 3.20.1 OPERABLE,
- 1. Restore the inoperable equipment to OPERABLE status within 7 days from the time of discovery of loss, or
- 2. For each fire zone designated for 050 or Alternate Shutdown, provide the compensatory measure described in item a below and restore the inoperable equipment to OPERABLE status within 60 days from the time of initial loss.
- a. For accessible** areas outside containment in which DSD or Alternate systems are credited, provide an hourly fire watch patrol.
For areas inside containment, inspect containment at least once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> or monitor the containment air temperature at least once per hour at the locations listed in Specification 3.14.VI.B.2*.
- 3. For continued plant operation beyond the 60 day limit, in addition to the compensatory measure described above, a Special Report shall be provided in accordance with Technical Specification 6.9.2.
The As presented in Proposed Change No. 136.
Accessible areas are those areas that do not pose radiation and/or life threatening safety hazards.
Special Report shall outline the course of action taken, the cause(s) of the inoperability and the plans and schedule for restoring the equipment to OPERABLE status.
B. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.
BASIS:
The objective of the dedicated shutdown system (DSO) is to provide, in conjunction with existing plant systems, the capability to achieve safe shutdown for any postulated fire in accordance with the safe shutdown requirements of 10CFR5O Appendix R. Similarly, "Alternate" methods of shutdown have been developed that require the use of systems/equipment that are not normally used for plant shutdown. Having these means of shutdown in Modes 1, 2, 3 and 4 provides assurance that cold shutdown (Mode 5) can be achieved and maintained at any time.
The systems normally used for safe shutdown at San Onofre Unit 1 include reactor coolant, auxiliary feedwater, main steam, chemical and volume control, residual heat removal, component cooling water, and salt water cooling. Based on fire hazards analyses, fires postulated to occur in any one of several of the plant's fire zones have the potential for making one or more of these systems unavailable as the result of fire damage to system components, associated electrical power circuits, instrument air supplies, system instrumentation, and controls.
By recognizing the potential consequences of such fire scenarios, the design of the DSD represents one integrated combination of systems capable of being used in the event of any fire having the potential of making the existing normal safe shutdown systems unavailable. The DSD incorporates:
o Remote shutdown capability o
Independent onsite power source for primary makeup and auxiliary feedwater o
Separate auxiliary feedwater supply o
Independently powered instrumentation and controls Similarly, Alternate shutdown methods rely on existing plant equipment used in off-normal modes to assure safe shutdown
-2.-
capability in the event of certain fires. Table 3.20.1 lists the minimum equipment required to be OPERABLE in order to provide these capabilities.
Use of the equipment in Table 3.20.1, as it is used to mitigate certain fires, is described in the references.
In the event that one or more components listed in Table 3.20.1 is rendered inoperable for more than 7 days, the Technical Specifications permit continued plant operation for up to 60 days, provided specific compensatory measures are taken. These compensatory measures are designed to further reduce the low probability of a postulated fire causing damage to that equipment which could lead to the need for DSO or Alternate shutdown.
For continued plant operation beyond 60 days, with less than the minimum required capabilities, the Technical Specifications require that a Special Report be submitted to the NRC. These provisions take into account the fact that the DSD and Alternate Systems are backup standby safety features required only under certain very unlikely fire conditions. Therefore, a temporary loss of OSD or Alternate capability under otherwise normal conditions (no actual fire hazard present) does not per se make the plant unsafe.
References
- 1. Letter, M. 0. Medford (SCE), to J. A. Zwolinski (NRC), dated October 4, 1985, Fire Protection Program Review.
- 2. Letter, M. 0. Medford (SCE), to G. E. Lear (NRC), dated December 31, 1985.
TABLE 3.20.1 DSD AND ALTERNATE SHUTDOWN MINIMUM OPERABLE EQUIPMENT A.
Remote-shutdown panel C38 instrumentation Indications:
Pressurizer pressure (PI-434A)
Pressurizer level (LI-430A)
Steam generator wide range level* (LI-450C, LI-451C, LI-452C)
Reactor coolant temperature* (hot leg and cold leg) (TI.-402B and TI-5402A, TI-412B and TI-5412A, TI-422B and TI-5422A)
Controls:
Charging flow controller (FC-5112)
Steam dump controller (FC.-1076A)
PORV (CV546) and PORV block valve (CV530) control (HS-5546)
B. Dedicated diesel generator (X-2000)
Dedicated fuel day tank with at least 130 gallons of diesel fuel and associated transfer pump (0-959)
Portable fuel transfer pump and connecting hoses Underground Fuel Tank (0-958) with 1875 gallons of diesel fuel C.
Pressurizer heater units, Group D, Units 21, 23 and 25 (2 of 3 units required available)**
- 0. Auxiliary feedwater pump G-10W (when additional [non-DSD related]
equipment is incorporated during future outage, "**" will apply)
E. North charging pump 6-BA and associated air cooler**
OPERABILITY of two of three channels for each listed parameter is acceptable provided that the operable channels for steam generator level and reactor coolant temperature correspond.
- Equipment "upstream" of DSO transfer switches that do not affect DSD OPERABILITY is not included in these items.
F. Auxiliary Saltwater Cooling Pump (G-13C) (required for alternate shutdown only)
G. Atmospheric steam dump valves CV-76, CV-77, CV-78 and CV-79 including SV-175 (at least 2 of 4 required to be available)**
H.
PORV CV 546, PORV Block Valve CV 530 and PORV Backup Nitrogen I. Dedicated hoses for steam generator blowdown and auxiliary feedwater makeup J. Flow path from Auxiliary Feedwater Storage tank to third Auxiliary Feedwater Pump (G-1OW)
K. Alternative suction path from the Refueling Water Storage Tank to the North Charging Pump including FCV 5051 L. DSD AC distribution equipment including,
- 1.
4.16 kV Bus A4
- 2.
Load Center (MCC B30**) and Transformer (X55)
- 3.
UPS (including Batteries [D25], Battery Charger [D26] and Inverter [YV30])
- 4.
Transfer Switches for 4.16 kV (A4S1) and 480V (B31, B32) buses M.
Communications equipment (four 2-way radios)
N.
Post Accident Sampling System (PASS) Boron Meter (required for alternate shutdown only) including:
- 1.
- 2.
Valves CV-956, RSS-345, CV-2023 and PAS-312, PAS-363, RSS-344, HV-5730, HV-5731 and HV-2023
- 3.
- 4.
Power supply via MCC-3A and transfer switch B43
- 5.
Cooling water pump PAS-G--78
- 6.
Cooling water heat exchanger PAS-E-24
- Equipment "upstream" of DSD transfer switches that do not affect DSO OPERABILITY is not included in these items.
3.21 EIGHT HOUR EMERGENCY LIGHTING UNITS APPLICABILITY:
MODES 1, 2, 3 and 4 OBJECTIVE:
To assure that adequate lighting for operator actions during DSO or alternate shutdown is available during a fire.
SPECIFICATION:
All self-contained, battery-powered emergency lighting units installed at San Onofre Unit 1, as described in the Updated Fire Hazards Analysis, shall be OPERABLE.
ACTION:
A.
With one or more of the required 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> emergency lighting units inoperable, within 7 days either repair the inoperable lighting unit or replace it with an OPERABLE lighting unit.
B.
If lights cannot be made OPERABLE within 7 days, make provisions for equivalent lighting (e.g., flashlights or portable lights).
C.
For continued plant operation beyond 60 days, in addition to the compensatory measures described above, a Special Report shall be provided in accordance with Technical Specification 6.9.2.
The Special Report shall outline the course of action taken, the cause(s) of the inoperability and the plans and schedule for restoring the emergency lights to OPERABLE status.
D.
The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.
BASIS:
The 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> emergency lighting units are provided in certain areas needed for operation of safe shutdown equipment and in access and egress routes thereto. This equipment provides illumination for operators to manipulate required equipment concurrent with plant emergency shutdown operations upon loss of normal illumination.
In the event that any of the lights remain inoperable for longer than 7 days, requirements are specified for backup illumination that, in the event of loss of normal lighting, would still allow the operators to perform their function.
4.20 DEDICATED AND ALTERNATE SHUTDOWN SYSTEMS SURVEILLANCE APPLICABILITY:
Applies to the surveillance of the equipment listed in Table 3.20.1.
OBJECTIVE:
To demonstrate the OPERABILITY of the DSO equipment.
SPECIFICATION:
A.
- 1. The indicating instrumentation associated with the remote shutdown panel, as identified on Table 3.20.1, shall be demonstrated OPERABLE by performing a CHANNEL CHECK at least once per 31 days and a CHANNEL CALIBRATION at least once per 18 months.
- 2. The controls instrumentation associated with the remote shutdown panel, as identified on Table 3.20.1, shall be demonstrated OPERABLE at least once per 18 months by exercising the actuated components from the remote shutdown panel.
B.
The dedicated diesel generator shall be demonstrated OPERABLE:
- 1. At least once per 92 days by verifying:
a) The diesel starts.
b) The dedicated fuel transfer pump starts and transfers fuel from the dedicated fuel storage tank to the day tank.
c) The dedicated diesel generator is running and loaded at > 250 kW for > 60 minutes.
d) The availability of 130 gallons of fuel in the day tank and 1875 gallons in the dedicated diesel fuel storage tank.
e) That samples of diesel fuel taken from and the fuel storage tank are within the acceptance limits specified by the diesel supplier when checked for viscosity, water and sediment.
- 2. At least once per 18 months, during plant shutdown, by subjecting the diesel to an inspection in accordance with procedures prepared in conjunction with the manufacturer's recommendations.
C.
The dedicated auxiliary feedwater pump, the north charging pump and the auxiliary saltwater cooling pump shall be demonstrated OPERABLE by testing these pumps in accordance with Section XI of the ASME Boiler and Pressure Vessel Code and applicable Addenda as required by 10 CFR 50.55a(g), except where specific written relief has been granted by the NRC pursuant to 10 CFR 50.55a(g)(6)(i).
D.
The dedicated power supply shall be demonstrated OPERABLE at least once per 18 months by energizing the dedicated diesel powered equipment via associated transfer switches and verifying that the equipment functions.
E.
Valve FCV-5051, which provides the alternative suction path to the North charging pump, shall be tested at least once per 18 months during plant shutdown by activating the valve to a fully open position by a test signal and observing the corresponding indications on the remote shutdown panel.
F.
The dedicated 125 volt battery bank and chargers shall be demonstrated OPERABLE:
- a. At least once per 31 days by verifying that:
- 1) The electrolyte level of each battery is above the plates and
- 2) The overall battery voltage is greater than or equal to 120 volts for the 125 volt battery.
- b. At least once per 18 months by verifying that:
- 1) The batteries, cell plates and battery racks show no visual indication of physical damage or abnormal deterioration, and
- 2) The battery-to-battery and terminal connections are clean, tight and free of corrosion.
G.
The dedicated diesel generator batteries shall be verified OPERABLE at least once per 31 days by checking the green battery ready indicators.
H.
The steam generator letdown hoses, auxiliary feedwater makeup hoses and portable fuel transfer hoses shall be demonstrated OPERABLE by performing the following:
- 1. At least once per 31 days by visual inspection of the hoses to assure all equipment is at the designated storage locations.
- 2. At least once per 3 years, by hydrostatic test of all hoses.
I.
The portable communications 2-way radios shall be demonstrated OPERABLE at least once per 31 days by performing a communications check on each radio.
J.
The boron measuring capability of the Post-Accident Sampling System shall be demonstrated OPERABLE by measuring boron concentration at least once per 184 days.
BASIS The comprehensive surveillance program described in this Technical Specification is to provide periodic verification that the minimum DSD equipment listed in Table 3.20.1 functions as required, and if not, it can be repaired or replaced in a timely manner. This program was developed based on requirements for similar equipment in other sections of these Technical Specifications, the existing In-Service Testing program for safety-related pumps and valves at the plant, the equipment suppliers recommendations and engineering judgement. The dedicated diesel generator loading requirement is derived from operating the dedicated auxiliary feedwater pump.
e9 4.21 EIGHT HOUR EMERGENCY LIGHTING UNITS SURVEILLANCE APPLICABILITY:
Applies to surveillance of emergency 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> lighting units.
OBJECTIVE:
To demonstrate the operability of the 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> emergency lighting units SPECIFICATION:
Each of the required 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> emergency lighting units shall be demonstrated OPERABLE by performing surveillance in accordance with procedures prepared in conjunction with the manufacturer's recommendations.
BASIS:
See Section 3.21 IAA:5908F/8295