ML20128B413
| ML20128B413 | |
| Person / Time | |
|---|---|
| Site: | Comanche Peak  |
| Issue date: | 01/22/1993 |
| From: | TEXAS UTILITIES ELECTRIC CO. (TU ELECTRIC) |
| To: | |
| Shared Package | |
| ML20128B410 | List: |
| References | |
| PROC-930122, NUDOCS 9302030044 | |
| Download: ML20128B413 (39) | |
Text
-_-_
1 i
PLANT CHANGES THAT MAY EFFECT THE TRM Changes made at CPSES have the potential to affect (or be affected by) 2 the TRM. These include items such as design modifications, procedure changes, other licensing document changes, etc. The TRM has been identified as a CPSES licensing i> asis document by the 10CFR50.59 Program. The 10CFR50.59 Program is based on the latest NUMARC 2 Guidelines for 50.59 evaluations. This program requires that the TRM be considered in a manner similar to the FSAR when screening changes to determine if an unreviewed safaty question might be involved, nISTRIBUTION OF TRM CHANGES / DELETIONS Changes to the TRM will be issued on a replacement page basis to controlled document holders promptly following approval of the che 9 REPORT OF TRM CHANGES / DELETIONS TO THE NRC Changes to the TRM will be reported to the NRC annually as part of the SAR update. Related safety evaluations will be reported as part of the 50.59 annual report.
Proposed TRM changes that are determined to constitute an unreviewed safety question (as defined by 10CFR50.59(a)(2)) will either not be made or will be submitted to the NRC for prior review and approval.
UNIT 2 APPLICABIllTY 8 The requirements fnr Unit 2 are effective upon issuance of the 8 operation license fer Unit 2. 9 1
COMANCHE PEAK - UNITS 1 AND 2 0-2 January 22, 1993 ,
9302030044 DR 930126 ADOCK 05000445 PDR ,
y DEFINIT 10NS CONTAINMEST INTEGRITY
1.7 CONTAINMENT
INTEGRITY shall axist when:: '
- t. All penetrations required to b: closed during_ accident conditions are either:
- 1) Capable of being closed by an OPERABLE containment autonatic isolation valve system, or.
- 2) Closed by manual valves, blind /langes, or deactivated automatic va?ws secured in their closed positions, except as prov'ided in Table.t.l.1:of.the Technical Genuirements Manual,
- b. All equipment hatches are closed and sealed,
- c. Each air lock is in compliance with the requirements _of Specification 3.6.1.3
- d. The containment leakage rttes are within the limits of-Specification 3.6.1.2, and
- e. The scaling mechanism associated with each penetration (e.g.,
welds, bellows, or 0-rings) is OPERABLE.
CP" TROLLED LEAKAGE 1.8 CONTROLLEO_ LEAKAGE shall be that seal water flow supplied to the reactor coolant pump seals.
CQRE ALTERATIONS 1.9 CORE AllERATIONS shall be the movement or manipulation of any component within the reactor pressure vessel with the vessel head -
removed and fuel in the vessel. Suspension of CORE ALTERATIONS shall not preclude completion of movement of a. component to a safe conservative position.
CQPE OPERATING _ LIMITS REPORT 8 1.10 The CORE OPERATING LIMITS REPORT (COLR) is the unit-specific- _
8 document that provides core operating limits for the current operating reload cycle. These cycle-specific core operating limits shall be determined for each reload cycle in accordance with Specification 6.9.1.6. Unit operation within these operating limits is addressed in individual specifications.
COMANCHE PEAK - UNITS 1 AND 2 0-5 January 22, 1993
DEFINITIONS DIGITAL CHANNEL OPERATIONAL TEST 1.11 A DIGITAL CHANNEL .0PERATIONAL TEST shall consist of exercising -
the digital computer hardware using data base manipulation and _.
injecting simulated process. data to verify OPER/.BILITY of alarm and/or trip functions. '
DOSE EOUIVALENT I-131 1.12 DOSE EQUIVALENT I-131 shall be that concentration of I-131 1 (microcurie / gram) which alone would produce the same. thyroid dose as the quantity and isotopic mixture of I-131 I-132,_I-133,_I-134,'and I-135 actually present. The thyroid dose conversion factors used.for-this calculation shall be those listed in Table III of TID-14844,
" Calculation of Distance Factors fer Power and Test Reactor Sites" or Table f,-7 of NRC Regulatory Guide 1.109. Revision 1. C;tober 1977. ,
E - AVERAGE DISINTEGRATION ENERGY 1.13 E shall be the average (weighted in proportion to the concentration of each radionuclide in the sample) of the sua of the 4 average beta and gamma energies per disintegration (MeV/d) for the:
radionuclides with a halflife greater than ten (10) minutes in the ' ;
sample.
ENGINEERED SAFETY FEATURES RESPONSE TLME 1,14 The ENGINEERED SAFETY FEATURES (ESF) RESPONSE' LIME shall be that time interval frop when the monitoreo' parameter exceeds-its ESF <
Actuation Setpoint at the channel sensor until the ESF equipment'is capable of performing its safety function (i.e., the valves travel to their required positions, pump discharge pressures reach their required values, etc.). Times shall include Ciesel generator-starting and sequence loading delays where applicable.
FRE00ENCY NOTATION 1.15 The FREQUENCY NOTATION specified for the performance.of-Surveillance Requirements shall ccrrespond to the intervals defined in Table 1.1.
JOENTIFIED LEAKAGL .
-1.16 IDENTIFIED LEAKAGE shall be:
- a. Leakage (except CONTROLLED LEAKAGE) into closed systems, such as pump seal or valve packing leaks that are captured and conducted to a sump-or cnllecting tank, or COMANCHE PEAK - UNITS 1 AND 2 0-6 January 22, 1993
DEFINITIONS a
IDENTIFIED LEAKAGE (Continued)
- b. Leakage into the containment atmosphere from' sources that are:
both specifically located and known-either not to interfere with the operation of Leakage Detection Systems or not to be PRESSURE BOUNDARY LEAKAGE, or
- c. Reactor Coolant System leakage through a steam generator to--
the Secondary Coolant System.-
MASTER RELAY TEST 1.17 A MASTER RELAY TEST shall be the energization of each master relay and verification of OPERABILITY of each relay. The MASTER RELAY.
TEST shall include a continuity check of each associated slave relay.
MEMBER (S)-0F THE PUBLIC.
1.18 MEMBER (S) 0F THE PUBLIC shall include all persons who are not' occupationally associated with the plant. This category does not include employees of the licensee, its contractors, or vendors. Also-excluded from this category are persons who enter the site to service equipment or to make deliveries. This category does include persons who use portions of the site for recreational, occupational, or-other purposes not associated with the plant.
QFFSITE DOSE CALCULATION MANUAL
- 1.19 The OFFSITE DOSE CALCULATION MANUAL (00CM) shall contain the methodology and parameters used in the calculation of~offsite doses resulting from radioactive gaseous and liquid effluents, in the.
calculation of gaseous and liquid effluent' monitoring Alarm / Trip Setpoints, and in the conduct of the Environmental Radiological Monitoring Program. The 00CM shall also contain-(1) the Radioactive f
Effluent Controls and Radiological Environmental-Monitoring Programs-required by Section 6.8.3 and (2) descriptions of the information that should be included in the Annual Radiological Environmental Operating and Semi-annual Radioactive Effluent Release Reports required.by.
Specifications 6.9.1.3 and 6.9.1.4.
OPERABLE - OPERABILITY 1.20 A system, subsystem, train, component or device shall be OPERABLE or have OPERABILITY when it is capable of performing its specified function (s), and when all necessary attendant instrumentation, controls, electrical power, cooling or seal water, lubrication or other auxiliary equipment that are required for the system, subsystem, train, component, or device to perform its function (s) are also capable of performing their related support function (s).
l l
COMANCHE PEAK - UNITS 1 AND 2 0-7 January 22, 1993-
c o DEFINITIONS OPERATIONAL MODE - MODE 11.21 AnOPERATIONALN00E.(i.e., MODE)shallcorrespondtoanyone:
inclusive combination of core reactivity condition, power level, and average reactor coolant temperature specified in Table 1.2.
PHYSICS TESTS 1.22 PHYSICS TESTS shall be those tests perforned to measure the fundamental nuclear characteristics of the reactor core and related instrumentation: (1)describedinChapter:14.0oftheFSAR,(2) authorizedundertheprovisionsof10CFR50.59,or(3)otherwise approved by the Commission.
PRESSURE BOUNDARY LEAKAGE 1.23 PRESSURE BOUNDARY LEAKAGE shall be leakage (except steam generator tube leakage) through a nonisolable fault _in a Reactor Coolant System component body, pipe wall, or vessel wall.
PRIMARY PLANT VENTILATION SYSTEM 1.24 A PRIMARY PLANT VENTILATION SYSTEM shall be any system designed and installed to reduce gaseous radiciodine or radioactive material in particulate form in effluents by passing ventilation or vent exhaust
~
gases through charcoal adsorbers and/or HEPA filters for the purpose of removing iodines or particulates from the gaseous exhaust stream prior to the release to the environment. Such a system is not considered to have any effect on noble gas effluents.
PROCESS CONTROL PROGRAM 1.25 The PROCESS CONTROL PROGRAM (PCP)-shall contain the current formulas, sampling, analyses, tests, and determinations to be made to ensure that processing and packaging of solid radioactive wastes based on demonstrated processing of actual or simulated wet solid wastes will be accomplished in such a way as to assure compliance with 10CFR Parts 20, 61, and 71, State regulations, burial ground requirements, and other requirements governing the disposal'of solid radioactive waste.
PURGE - PURGING 1.26 PURGE or PURGING shall be any controlled process of discharging-air or gas from a confinement to maintain temperature, pressure, humidity, concentration or other operating condition, in such a manner-that replacement air or gas is required to purify the confinement.
COMANCHE PEAK - UNIT 5 1 AND 2 0-8 January 22, 1993
DEFINITIONS __
QdADRANTNOWERTILT'RATIQ 1.27 -QUADRANT POWER TILT RATIO shall be the ratio ofSthe maximum upper half excore detector calibrated' output-to the average of the upper half excore detector calibrated outputs, or the ratic'of the
-maximum lower half excore detector calibrated output to the average of the lower half excore detector calibrated outputs, whichever is greater. With one excore detector inoperable, the remaining.three detectors shall be used for computing the average.
RATED-THERMAL POWER 1.28 RATED THERMAL POWER shall be a total reactor core heat transfer rate to the reactor coolant of 3411 MWt.
REACTOR TRIP SYSTEM RESPONSE TIME 1.29 The REACTOR TRIP SYSTEM RESPONSE TIME shall be-the time interval from when the monitored parameter exceeds its Trip Setpoint at the channel sensor until loss of stationary gripper coil. voltage.
REPORTAJLE EVENT 1.30 A REPORTABLE EVENT shall be any of those conditions specified in-10CFR50.73.
SHUTDOWN MARGIN 1.31 SHUT 00WN MARGIN shall be the instantaneous amount' of' reactivity by which the reactor is subcritical or would be subtritical from its present condition assuming all rod cluster assemblies (shutdown and-control) are fully in:erted except for the single rod cluster assembly of highest reactivity worth which is assumed to be fully withdrawn.
SITE BOUNDARY 1,32 The SITE BOUNDARY shall be that line as shown-in Figure 5.1-3.
COMANCHE PEAK - UNITS 1 AND 2 0-9 January 22,-1993
-DIFINITIONS SLAVE RELAY TEST 1.33 A SLAVE RELAY TEST shall be the energization of each slave relay and verification of OPERABILITY of each relay. The SLAVE RELAY _ TEST sha11' include a continuity check, as a minimum, of associated testable actuation devices.
SOURCE CHECK 1.34 A SOURCE CHECK shall be the qualitative assessment of channel response when the channel sensor is exposed to a source of increased radioactivity.
STAGGERED TEST BASIS 1.35 A STAGGERED TEST BASIS shall consist of:
a, A test schedule for n systems, subsystems, trains, or other designated components obtained by dividing the specified test interval into n equal subintervals, and
- b. The testing of one system, subsystem, train, or other -
designated component at the beginning of each subinterval.
THERMAL POWER 1.36 THERMAL POWER shall be the total core heat transfer rate to the reactor coolant.
TRIP ACTUATING DEVICE OPERATIONAL TEST 1.37 A TRIP ACTUATING DEVICE OPERATIONAL TEST shall consist of-operating the Trip Actuating Device and verifying OPERABILITY.of alarm, interlock and/or trip functions. The TRIP ACTUATING DEVICE OPERATIONAL TEST shall include adjustment, as necessary, of the Trip Actuating Device such that it actuates at the required setpoint within the required accuracy.
COMANCHE PEAK - UNITS 1 AND 2 0-10 January 22, 1993
(
l ,
F: ]
DEFINITIONS UNIDENTIFIED LEAKAGE 1.38- UNIDENTIFIED LEAKAGE shall-be all leakage which is not IDENTIFIED LEAKAGE or CONTROLLED LEAKAGE.
UNRESTRICTED AREA- !
1.39 An UNRESTRICTED AREA shall be any area at or beyond the SITE BOUNDARY access to which is not controlled by the licensee, for purposes of protection of individuals from exposure to radiation and radioactive materials, or any area within the SITE BOUNDARY used for residential quarters or for industrial, commercial,-institutional, and/or recreational purposes.
VENTING 1.40 VENTING shall be the controlled process of discharging air or gas from a confinement to maintain temperature, pressure, humidity, concentration, or other operating condition, in such a manner that-replacement air or gas is not provided or required during VENTING.
Vent, used in system names, does not imply a VENTING process.
WASTE GAS HOLDUP SYSTEM 1.41 A WASTE GAS HOLDUP SYSTEM shall be any system designed and installed to reduce radioactive gaseous effluents t.y collecting Reactor Coolant System offgases from the Reactor Ccolant' System and providing for delay or holdup for the purpose of reducing the total radioactivity prior to release to the environment, l
COMANCHE PEAK - UNITS 1 AND 2 0-11 January 22, 1993-
~
_j APPLICABILITY LIMITING CONDITION FOR OPERATION 1 Continued 1 3.0.5 Limiting Conditions for Operation-including the associated '8 ACTION _ requirements shall apply to each unit individually unless otherwise indicated as follows;
- a. Whenever the Limiting Conditions for Operation refers to 8 systems or components which are shared by both units, the ACTION requirements will apply to both units simultaneously, unless specifically noted otherwise, and will be. denoted in the ACTION section of the specification;
- b. Whenever the Limiting Conditions for Operation applies to' 8 only one unit, this will be identified in the APPLICABILITY section of the specification; and
- c. Whenever certain portions of a specification contain 8 operating parameters, setpoints, etc., which are different for each unit, this will be identified in parer. theses, footnotes or body of the requirement.
COMANCHE PEAK - UNITS 1 AND 2 0-16 January 22, 1993
l l
APPLICABillTY SURVEILLANCE RE0UIREMENTS 4.0.1 Surveillance Requirements shall be met during the OPERATIONAL MODES or other conditions specified for individual Limiting Conditions for Operation unless otherwise stated in an inoividual Surveillance Requirement.
4.0.2 Each Surveillance Requirement shall be performed within the specified surveillance interval with a maximum allowable extension not to exceed 25% of the specified surveillance interval.
Exceptions to this requirement are stated in the individual specifications.
4.0.3 Failure to perform a Surveillance Requirement within the allowed surveillance interval, defined by Specification 4.0.2, shall constitute noncompliance with the OPERABILITY requirements for a Limiting Condition for Operation. The time limits of the ACTION requirements are applicable at the time it is identified that a Surveillance Requirement has not been performed. The ACTION requirements may be delayed for up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to permit the completion of the surveillance when the allowable outage time limits of the ACTION requirements are less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Surveillance Requirements do not have to be performed on inoperable equipment.
4.0.4 Entry into an OPERATIONAL MODE or other specified condition shall not be made unless the Surveillance Requirement (s) associated with the Limiting Condition for Operation has been performed within the stated surveillance interval or as otherwise specified. This urovision shall not prevent passage through or to OPERATIONAL MODES as required to comply with ACTION requirements. Exceptions to these requirements are stated in the individual specifications.
4,0.5 Surveillance Requirements for inservice inspection and testing of ASME Code Class .1, 2, and 3 components shall be applicable as follows:
CDMANCHE PEAK - UNITS 1 AND 2 0-17 January 22, 1993
J APPLICABILITY 8 BA$ff 8 8 -
Under the' terms of this specification, the more restrictive 8 requirements of the Technical Specification take precedence over the ASME Boiler and Pressure Vessel Code and applicable Addenda. The i requirements of Specification 4.0.4 to perform surveillance activities before entry into an OPERATIONAL H0DE or other specified condition takes precedence over the ASME Boiler and Pressure Vessel Code provision which allows pumps and valves to be tested up to one week ,
af ter return to normal operation. 1he Technical Specification .
definition of OPERABLE does not allow a grace period before a '
component, that is not capable of performing its s)ecified function. ,
is declared inoperable and takes precedence over tie ASME Boiler and -
Pressure Vessel Code provision which allows a' valve to be inc6pable of ' t performing its specified function for up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> before being. F declared inoperable.
l T'
- COMANCHE PEAK - UNITS'l AND 2 0-26 January 22 1993
1((HNICAL RE0DIREMENT L.L.LCOntinuedl Table 1.1.1 REACTOR T&lf_jilSJ1M INSTRUMENTATION RESPONSE TlHES DLHCTIONAL lLE ESEDNSE TIME
- 12. Reactor Coolant flow-Low
- a. Singic Loop (Above P-8) 5 1 second
- b. Two Loops (Above P-7 and below P-8) 5 1 second
- 13. Steam Generator Water Level--Low-Low 5 2 seconds
- 14. Undervoltage - Reactor Coolant Pumps 5 1.5 seconds
- 15. Underfrequency - Reactor Coolant Pumps s 0.6 second
- 16. Turbine Trip
- a. Low Fluid 011 Pressure N.A.
- b. Turbine Stop Valve Closure N.A.
- 17. Safety injection input from ESFAS N.A.
- 18. Reactor Trip System Interlocks N.A.
- 19. Reactor Trip Breakers N.A.
- 20. Automatic Trip and Interlock logic N.A.
BASES 1.1 REACTOR TRIP SYSTEM RESPONSE TIMES The bases for the Reactor Trip System are contained in the CPSES Technical Specifications. The measurement of response time at the specified frequencies provides assurance that the Reactor trip actuation associated with each channel is completed within the time limit assumed in the safety analyses. No credit was taken in the analyses for those channels with response times indicated as not applicable. Response time may be demonstrated by any series of sequential, overlapping, or total channel test measurements provided that such tests demonstrate the total channel response time as defined. Sensor response time verification may be demonstrated by either: (1) in place, onsite, or offsite test measurements, or (2) utilizing replacement sensors with certified response time.
COMANCHE PEAK - UNITS 1 AND 2 1-4 January 22, 1992
TECHNICAL REOUIREMENT 1.4 (continued)
TABLE 1.4.1 SLISMIC MONITORING INSTRUMENTATION
- 8 HINIMUM INSTRUMENTS l INSTRUMENTS AND SENSOR LOCATIONS _ QPf D A.1Lf,_.
- 1. Triaxial Time-History Accelerographs-
- a. Accelerometer-Fuel Building 1
- b. Accelerometer-Unit 1 Containment 1 8
- c. Accelerometer-ElectricalHanhole(Yard) 1 8
- d. Seismic Trigger-Fuel Building 1** 8 l
- e. Recorder Unit, SMA-3 (Unit 1 Control Room) 1 8
- f. Playback Unit, SMP-1 (Unit 1 Control Room) 1 8
- 2. Triaxial Peak Accelerographs
- a. PressurizerLiftingTrunion(Unit 1 Containment) 1 8
- b. Reactor Coolant Piping (Unit 1 Containment) 1 8
- c. CCWHeatExchanger(AuxiliaryBuilding) 1 8
- 3. Triaxial Seismic Switch fuel Building 1** 8
- 4. Triaxial Response-Spectrum Recorders
- a. Fuel Building 1
- b. Unit 1 Reactor Bldg. Internal Structure 1 8
- c. Unit 1 Safeguards Building 1 8
- 5. . Response Spectrum Annunciator Unit 1 Control Room 1** 8
- Unit 1 and Unit 2 control room alarms are connected to shared seismic-instruments which are located in Unit 1 and common structures. 8 -
- With control room indication. 8 i
COMANCHE PEAK _- UNITS 1 AND 2. 1 January 22, 1992
. TECHNICAL REOUIREMENT 1.4 (continued)
TABLE 1.4.2 SEISMIC MONITORING INSTRUMENTATION SURVEILLANCE RE0VIREMENTS
- 8 ANALOG ** 8 CHANNEL CHANNEL CHANNEL OPERATIONAL INSTRUMENTS AND SENSOR LOCATIONS CHECK CAllBRATION ___IEST-
- 1. Triaxial Time-History Accelerographs
- c. Accelerometer-Elec- M R SA tricalManhole(Yard) 8
- d. Seismic Trigger-Fuel M R SA Building'** 8
- e. Recorder Unit, SMA-3 M R SA (Unit 1 Control Room) 8
- f. Playback Unit, SMP-1 M R SA (Unit 1 Control Room) 8.
- 2. Triaxial Peak Accelerographs
~
- a. Pressurizer Lifting N.A. R N.A. 8 Trunion - Unit 1 Containment 8
- b. Reactor Coolant Piping - N.A. R N.A.
Unit 1 Containment 8
- c. CCW Heat Exchar.ger - N.A. R N.A.
Auxiliar3 Building 8
- 3. Triaxial Seismic Switch fuel Building *** M R SA 8 4
- Unit 1 and Unit 2 control room alarms are connected to shared seismic instruments which are located in Unit 1 and common structures. 8
- Setpoint verification is not applicable. S
- With control room indication. 8 CDMANCHE PEAK - UNITS 1 AND 2 1-19 January 22, 1992;
TECHNICAL REOUIREMENT is4_(continued)
TABLE 1.4.2 ,
SEISHIC MONITORING INSTRUMENTATION SURVEILLANCE RE0VIREMENTS* 8 ANALOG ** 8 CHANNEL CHANNEL CHANNEL OPERATIONAL INSTRUMENTS AND SENSOR LOCATIDill CHECK CAllBRATION ,
-TEST -
- 4. Triaxial Response-Spectrum Recorders
- a. Fuel Building N.A. R N.A.
- b. Unit 1 Reactor 81dg. N.A. R N.A. 8 Internal Structure
- c. Unit 1 Safeguurds Building H.A. R N.A. 8
- 5. Response Spectrum M R SA Annunciator *** 8 (Unit 1 Control Room) 8-E
- Unit 1 and Unit 2 control room alarms are connected to shared seismic instruments which are located in Unit 1 and common structures. 8
- Setpoint verification is not applicable. 8
- With control room indication.
8 COMANCHE PEAK - UNITS 1 AND 2 1-20 January 22, 1993
. l IffHNICAL REOUIREMENT P d TABLE 2.1.1 QNTAINMENT ISOL ATION VALVES MAXIMUM ISOLATION NOTES AND FSAR TABLE TIME LEAK TEST ,
VALVE NO. PEFERENCE NO.* LINE OR SERY,l(( (Second.11 REOUIREMENTS
- 1. Phase "A" Isolation Valves HV-2154 20 Feedwater Sample 5 N.A. 8 (FWtoStmGen#1)
HV-2155 22 Feedwater Sample 5 N.A. 8 (FWtoStmGen#2)
HV-2399 27 810wdown from Steam 5 N.A. 8 Generator #3 HV-2398 28 Blowdown from Steam 5 N.A. 8 Generator #2 HV-2397 29 Blowdown From Steam 5 N.A. 8 Generator #1 i HV-2400 30 Blowdown From Steam 5 -N.A. 8 !
Generator #4 8152 32 Letdown Line to 10 C 8 Letdown Heat Exchanger 8160 32 Letdown Line to 10 C 8 Letdown Heat Exchanger 8890A 35 RHR to Cold Leg 15 C 8
, Loops #1 & #2 Test Line 88908 36 RHR to Cold Leg 15 C 8 Loops #3 & #4 Test Line 8047 41 Reactor Makeup 10 C 8 Water to Pressure Relief Tank & RC Pump Stano Pipe 8843 42 Si to RC System 10 H.A. 8 Cold Leg Lcops #1,
- 2, #3, #4 Test Line i
COMANCHE PEAK - UNITS 1 AND 2 2-4 January 22, 1993
IECHNICAL REOUIREMENT Ps1 (continued)
TABLE 2.1.1 (continuedl CONTAINMENT ISOLATION VALVES HAXIMUM ISOLATION NOTES AND >
FSAR TABLE TIME LEAK TEST VALVE NO. REFERENCE NO.* LINE OR SERVICE (feconds) REOUIREMENTS
- 1. Filase "A" Isolation Valves (Continued)
HV-5559 97 Containment Air 5 C 8 PASS Inlet i
HV-5560 100 Containment Air 5 C 8 PASS Inlet HV-5561 100 Containment Air 5 C 8 PASS Inlet HV-5546 102 Radiation Monitor- 5 C 8-
- ing Sample Return HV-5547 102 Radiation Monitor- 5 C 8-ing Sai.ple Return 8880 104 N2 Supply.to 10 C 8 Accumulators 7126 105 H Supply to 10 C 8 :
R Drain Tank 7150 105 Hg 3upply to 10 C 8 RC Drain Tank HV-4710 111 -CCW Supply to -5 N. A.- 8 Excess Letdown
& RC Drain Tank Heat Exchanger HV-4711 112 CCW Return From 5 N.A. 8 ,
Excess Letdown &
RC Drain Tank Heat Exchanger ;
HV-3486 113 Service Air 5 C. 8' to Containment l
l COMANCHE PEAK - UNITS 1 AND 2 2-8 January 22, 1993 l
,11giHJCAL REOUIREMENT 2,1 (continued)
TABLE 2.1.1 (continued)
CONTAlHMENT ISOLATION VALVES MAXIMUM ISOLATION NOTES AND FSAR TABLE . TIME LEAK TEST VALVE NO. BEFERENCE NO,* LINE OR SERVICE (Seconds) REOUIREMENTS
- 2. Phase "B" Isolation (continued)
HV-4709 119 CCW Return From 15 C 8 RCP's Thermal Barrier HV-4696 119 CCW Return From 15 C 8 -
RCP's Thermal Barrier
- 3. Containment Ventilation Isolation Valves HV-5542 58 Hydrogen Purge N.A. C 8 Supply HV-5543 58 Hydrogen Purge N.A. C 8 Supply HV-5563 58 Hydrogen Purge H.A. C 8 Supply HV-5540 59 Hydrogen Purge H.A. C 8 Exhaust HV-5541 59 Hydrogen Purge H.A. C 8 Exhaust HV-5562 59 Hydrogen Purge N.A. C 8 Exhaust HV-5536 109 Containment Purge 5 C 8 Air Supply HV-5537 109 Containment Purge 5 C 8 Air Supply HV-5538 110 Containment Purge 5 C 8 Air Exhaust HV-5539 110 Containment Purge 5- C 8 Air Exhaust COMANCHE PEAK - UNITS 1 AND 2 2-10 January 22, 1993 Y- --
- . -- - .- . _ = - . . - - . . _ . _ - - - . . - - . . -
m IECHNICAL REOUIREMENT 2.1 (continued)
TABLE 2.1.1 (continued) f i
CONTAINMENT ISOLATION VALVES MAXIMUM ISOLATION NOTES AND FSAR TABLE TIME LEAK TEST i yXyf._& REFERENCE NO.* LINE OR SERVICE (Seconds) REOUIREMENTS !
285-0030# 134 Airlock N.A. Notes 8 Hydraulically 5,6.7 8 Operated Equalization 8 2BS-0025# 134 Airlock H.A. Notes 8
'I Hydraulically 5, 6. 7 8 Operated Equalization 8 285-0056# 134a Airlock Manual N.A. Notes 8 Equalization 5, 6 8 285-0044# 134a Airlock Manual N.A. Notes 8 Equalization 5, 6 8 285-0029# 134a Airlock Manual N.A. Notes- 8 Equalization 5, 6 8 l
285-0015# 134a Airlock Manual N.A. Notes 8 Equalization 5. 8
- 5. Power-Operated Isolation Valves HV-2452-1 4 Main Steam to Aux. N.A. N.A.- 9 FPT from Steam Line #1 PV-2325 5 Atmospheric Relief N.A. Note 3 8 Steam Generator 3 PV-2326 9 Atmospheric Relief N.A. Note 3 8 Steam Generator -3 PV-2327 13 Atmospheric Relief N.A. Note 3 8 Steam Generator 3 HV-2452-2 1/ Main Stearr. to Aux. N.A. N.A. 8 FPT From Steam Line PV-2328 -18 Atmospheric Relief N.A. Note 3 8 Steam Generator. 3 l
HV-2491A 20a Auxiliary Feedwater N.A. N.A. 8 to Steam Generator ,
- 1 COMANCHE PEAK - UNITS 1 AND 2 2-14 January 22, 1993
TECHNICAL REOUIREMENT 2.1 (continuedl TABLE 2.1.1 (continuedl CONTAINMENT ISOL ATION VALVES HAXIMUM ISOLATION NOTES AND-FSAR TABLE TlHE LEAK TEST VALVE NO. REFERENCE NO.* LINE OR SLRVICE .(.$econds) RE0VIREMENTS
- 6. Check Valves (Continued)
SI-8819B 45 51 to RC System N.A. N.A. 8 Cold Leg Loop #2 SI-8819C 45 Si to RC System N.A. N.A. 8 Cold Leg Loop 13 51-88190 45 SI to RC System H.A. N.A. 8 Cold Leg Loop #4 8381 46 Charging Line to N.A. C 8 Regenerative Heat Exchanger CS-8368A 47 Seal injection to N.A. N.A. 8- ,
RCPump(Loop #1)
CS-8368B 48 Seal Injection to - N.A. N.A. ~8 RCPump(Loop #2)
CS-8368C 49 Seal Injection to N.A. N.A. 8 RCPump(Loop #3)
CS-83680 50 Seal Injection-to N.A. N.A. 8 RCPumo(Loopit) ,
CS-8180 51 Seal Water Return N.A. -C 8 l
and Excess Letdown CT-145 54 Containment Spray N.A. Note 4 8 to Spray Header 2
! (Tr. B) l r
COMANCHL PEAK - UNITS 1 AND 2 2-19 January 22, 1993
_ . . . _ - _ . _ ~ . _ _ _ _ _ _ _ . _ _ . . . _ . . . . . . _ . _ _ - . . _ . _ . . _ . _ . . _ . - . _ . _ . _ . .__
.IECHNICAL REOUIREMENT 2.1 (continued)
TABLE 2.1.1 (continued) ;
t CONTAINMENT ISOLATION VALVES [
MAXIMUM ISOLATION NOTES AND FSAR TABLE TIME LEAK TEST VALVE NO. REFERENCE NO.* LINE OR SERVICE (Seconds) REOUlEEMEH11 :
6.CheckValves(Continued)
CT-342 55 . Containment Spray H.A. Note 4- 8 to Spray lleader 2 (Tr. A)
CI-030 62 Instrument Air N.A. C 8 to Containment :
8841A 63 RHR to Hot Leg H.A. N.A. 8 Loop #2 8841B 63 RHR to Hot Leg N.A. N.A. 8 Loop #3 51-8968 104 N2 Supply to N.A. C 8' Accumulators ,
l CA-016 113 Service Air to N.A. C 8 Containment CC-629 117 CC Return From N.A. C 8~ _
RCP's Motors CC-713 118 CC Supply to RCP's N.A. C 8 Motors
'- CC-831 119 CC Return From H.A. C 8 RCP's Thernal l~ Barrier l
l CH-024 120 Chilled Water N.A. C. 8 Supply to Contain-ment Coolers ,
COMANCHE PEAK - UNITS 1 AND 2 2-20 January 22, 1993
. - . - _ . . . - . --:._=...- -
TEfM ICAL req lllBEMENT 2.1 (continued)
TABLE 2.1.1 (continued)
CONTAINMENT ISOLATION VALVES MAXIMUM ,
ISOLATION NOTES AND FSAR TABLE TIME LEAK TEST i VALVE NO. REFERENCE NO.* LINE OR SERVICE (Seconds) REQUIREMENTS !
10.ReliefValves(Continued) ;
SI-0183 126 Pressure Relief N.A. N.A. 9-for Bonnet of 9 HOV 88118 fi
CT-0310 128 Pressure Relief N.A. N.A.- 9 i
for Bonnet of 9 ,
H0V HV-4783 -9 i
i-l l
l l
COMANCHE PEAK - UNIls 1 AND 2 2-26 January 22, 1993
m.__._ _ _ _ . _ . - . _ _ _ . . _ - . _ _ . _ _ __ __- _._ -
TECHNICALREQU_lREMEl{T3.1 SXUB@_EQ ;
TESTSdHSPECTIONS.
1p3.1 Each snubber shall be demonstrated OPERABLE by performance of l 4
thu following augmented inservice inspection program in lieu of the !
requirements of Technical Specification 4.0.5. ,
of the same design and manufacturer, irrespective of capacity.
- b. Visual Inspecti_ons Snubbers are categorized as inaccessible or accessible during reactor operation. Each of these groups (inaccessibic and 10 accessible) inay be inspected independently. The first inservice visual inspection of each type of snubber shall be performed after 4 months but within 10 months of commencing POWER OPERATION and '
shall include all snubbers. !# all snubbers-of each type on any system are found OPERADLE during the first inservice visual inspection, the second inservice visual inspection on that type t shall be performed at the first refueling outage. Otherwise subsequent visual inspections of a given system shall be performed in accordance with the following schedules No. of Inoperable Snubbers 10 .
of Each Type on any System Subsequent Visual 10 per inspection Period ** Inspection Period
- 10 O,1 12 months + 25% 10 2 6 months i 25% 10' 3,4 124 days + 25% .10 5,6,7 62 days T 25% 10 8 or more 31 days T 25'S 10 t Visual inspection intervals following the second refueling outage I 10 shall be determined based upon the-criteria provided in the table below:
10
~~The inspection interval for each type of snubber shall not be 10' lengthened more than one step at a time unless a generic problem has ,
been identified and corrected; in that event the inspection interval -
may be lenthened one step the first time and two steps thereafter if no inoperable snubbers of that tyoe are found on any system.
- If one or more snubbers of eacn type on any system are found .
10 inoperable duriag the first inservice visual inspection, the second '
inservice visual inspection on that type shall be perfonned no later ,
than the first refueling outage or the subsequent visual inspection period, whichever comes first. '
COMANCHE PEAK - UNITS 1 AND 2 3-3 Revision 10 :
January 22, 1993
..- . , -_ _ - . . . , , , - . , . . . . .. , . ~ . . . - - , ,.,,.. _-.,,,w ..,- % .r ,c. m, m. -,_..,_,r#.. ., .-,.,-.c,_,.__._ , , _ . -
TECHNICAL REQUIREMENT 3.1 SNUBBERS
. TESTS /INSPEGJLQ,NS(Continued)-
@B3id 0F UNAl({EIABLE SNUBBERS 5 Population Column A Column B . Column C 5
- c/ Category Extend Intervii Repeat Interval Reduce Interval 5 (Notes 1 & 2) (Notes _3_& 6). (Notes 4 & 6) (Notes 5 L.1), 5 t
1 0 0 l' 5 80 0 0 2 -5 100 0 1 4 5 5
150 0 3 8 5: i c 200 2 -5 13 '5 300 5 12 25 _5 5-400 8 18 36 5- !
S00 12 24 48 5 750 20 40 78 5-1000 or greater 79 56 109 5
. 5 Wate 1: The next visual inspection interval for a snubber 5 population or category size shall be determined based upon th9 previous inspection interval and the number of
. unacceptable snubbers found during that interval.
Snubbers may be categorized, based upon their !
4 accessibility during power operation, as accessible or inaccessible. These categories may be examined separately or jointly. However, the licensee ruust make ;
- and document that decision before any inspection and shall l use that decision as the basis upon which to determine the next inspection interval for that category.
Note 2: Interpolation between population or category sizes and the 5
- number of unacceptable snubber /. is permissible. Use next lower integer for the value of the limit for Columns A, B.-
or C if that integer includes a fractional value of unacceptable snubhrs as determined by interpolation.
Note 3: If the number of unacceptable snubbers is equal to or less '5 than the number in Column A, the next. inspection interval . R may be twice the' previous interval bJt not greater than 48' months.
Note 4: If the number of unacceptable snubterf is equal to or less 5 3
than the number in Column B, but greater than the number in Column A, the next inspection interval shall be the same as the previous interval.
COMANCHE PEAK - UNI 15 1 AND 2 3-4 January 22, 1993.
TECHNICAL RE00lREMENT 3.1 (continued 1 ,
i SNUBBERS ,
ILilS/ INSPECTIONS (Continued 1 l Note 5: If the number of unacceptable snubbers is equal to or 5 greater than the number in Column C, the next inspection ,
interval shall be two-thirds of the previous interval.
However, if the number of unacceptable snubbers is less than the number in Column C but greater than the number in Column 0, the next interval shall be reduced proportionally be interpolation, that is, the previous interval shall be reduced by a factor that is one-third of' the ratio of the difference between the number of unacceptable snubbers found during the previous interval and the number in Column B to the difference in the numbers in Columns B and C. .
1 Note 6: _The provisions of Specification 4.0.2 are applicable for- 5-all inspection intervals up to and including 48 months.
- c. Visual Inspection Acceptance Criteria Visual inspections shall verify that:- (1)therearenovisible indications of damage or impaired OPERABILITY, (2) attachments to :
thefoundationorsupportingstructurearesecure,and(3) fasteners for attachment of the snubber to the component and to
l inoperable as a result of visual inspections may be determined- ,
j OPERABLE for the purpose of establishing the.next visual inspection interval, provided that: (1) the cause of the rejection is clearly established and remedied for that particular snubber and for other snubbers irrespective of-type that may be ..!
genericallysusceptible;or(2)theaffectedsnubberis functionally tested in the as-found condition and determined OPERABLE per Test / Inspection TR3.lf. All snubbers connected to an -
inoperable common hydraulic fluid reservoir shall be counted'as inoperable snubbers. -
sections of systems that have experienced unexpected, potentially '
damaging transients as determined from a review of operational data. A visual inspection of those systems shall be performed within 6 m6nths fallowing such an event. In-_ addition to ,
satisfying the visual inspection acceptance criteria, free.1om-of-motion of mechanical snubbers shall be verified using at least one !
of the following: (1) manually induced snubber movement; or (2) evaluation of in-place snubber piston setting;.or (3) stroking the mechanical snubber through its full range of travel.
COMANCHE PEAK - UMP 3.1.AND 2 3-5
' January 22, 1993__
i IECHNICAL'REOUIREMENT 3.2 [
t STATION SERVICE WATER SYSTEM ,
I OPERABILITY CRITERIA ,
f 3.2 A Unit 2 Service Water Pump shall be available to support Unit- f 1 operation.
APPLICABILITY: Modes 1, 2, 3 and 4,* 8 i COMPENSATO R MEASURES:
f
- a. If neither Unit 2 Service Water Pump is available, either restore ,
a Unit 2 Service Water Pump to available status within 7 days, or, place Unit 1 in 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 /> and in COLD SHUTOOWN within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. .
- b. If only one Unit 1 Service Water Pump is OPERABLE and neither Unit 2 Service Water Pump is available, immediately initiate action to restore either a Unit 2 Service Water Pump to available status or -j the inoperable Unit 1 Service Water Pump to an OPERABLE status.
- TEST /lHSPECTIONS The Unit 2 Service Water Pump (s) shall be considered available if it '
is capable of being manually started and cross-connected to the Unit'l Service Water System. This availability shall be demonstrated by:
TR3.2.1 At least once per day, verifying that Bus 2EAl'is energized if the 2A Service Water Pump is the available pump, or Bus 2EA2 is energized if the 28 Service Water Pump is the available pump; and t TR3.2.2 At least once per day, verifying that the cross connect valve (s) between the Unit 1 Service Water' System and the ;
available Unit 2 Service Water Pump are open or capable of being opened. .
TR3.2.3 At least once quarterly stroking cross-connect valves XSW-0006, XSW-0007, XSW-0008, XSW-0028, XSW-0029 through their full range of motion.
TR3.2.4 At least once per 31 days, the available pump will be operated 3 for at least 15 minutes.. ~
Upon issuance of the CPSES Unit 2 low power license, this 10' Technical Requirement will no longer be applicable. Upon license issuance, refer to the combined Unit Technic'al Specification 3/4.7.4 and its Bases for Station Service Wat_cr i System information. Technical Requirement 3.2 will be .
deleted in the first TRM revision following low power license '
issuance.
. COMANCHE PEAK - UNITS 1 AND 2 3-10 Revision 10 .
January 22, 1993 I w~,-.-,+. , -,- - =.-.- - - . - - . - - - . - . - . - - . - - - - -. - - . -
~ ~ . - .
TECHNICAL REOUIREMENT 3.3 FEE 0 WATER ISOLATION VALVE TEMPERATURE OPERABillTY LRITERIA 3.3 Each main feedwater isolation valve shall be greater than or 3 equal to 900F, when feedwater line pressure is greater than 3- l 675 pss;. li APPLICAQ1L111: MODES 1*, 2, 3 and during pressure testing of the 8 I steam generator or main feedwater line.**
[0MPENSATORY MEASURES:
With one or more main feedwater valves outsied of the above limits:- 3
- a. Restor main feedwater isolation valve pressure'and/or 3 :
temperature to within the limits within 30 minutes, and-l
- b. Perform an engineering evaluation to determine the effect 3 3 of the overpressure on the structural integrity of the main 3 feedwater isolation valve (s) and determine that the main feedwater isloation valve (s) remains acceptable for' continued operations within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Complete this determination each time this compensatory measure is entered.
I
- c. Other' vise, be in 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 /> and in 3 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 />.
IESTS/ INSPECTIONS
^
TR3.3 Each main feedwater isolation valve shall be determined- 3 to be greater than or equal to 900F at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> *. 3. '
Readings shall be taken using the following instruments: TI-2152-l' , 8 TI-2152-2, TI-2152-3 and TI-2152-4. If any of these instruments are 8 ,
inoperable, a surface pyrometer may be used to determine valve ;
temperature.
- Except in MODE 1 with the feedwater isolation valve open, 3 temperature readings are not required. 3
- Upon issuance of the CPSES Unit 2110w power license, this 10 Technical Requirement will no longer be applicable. Upon license ,
issuance, refer to the combined Unit Techitcal Specification .
3/4.7.13 and. its Bases for-Feedwater Isolation Valve Temperature a information. Technical Requirement 3.3'will be deleted in the first TRM revision following low power license issuance.
1
' COMANCHE PEAK - UNITS 1 AND 2 3-12 Revision 10 January 22, 1993
- - . - - - - . . . _ - . - . _ . . - . - - . - - . . . - . . - . ~ . . . - . - . _ - - - , . - - - , - . , . .
[LECTRICAL E00lPHENT PROTECTIVE DEVICES SURVEILLA.NCE RE00lREMENTS 4.8.4 The containment penetration conductor overcurrent' protective devices shall be demonstrated OPERABLE:
- a. At least once per 18 months:
- 1) By verifying that the medium voltage 6.9 kV and low voltage 480V switchgear circuit breakers are OPERABLE by selecting, on a rotating basis, at least 10% of the circuit breakers of each current rating and performing the following:
a) A CHANNEL CAllBRATION of the associated protective relays, b) An integrated system functional test which includes simulate 1 automatic actuation of the system and verify 4 ) that each relay and associated circuit breakei3 and control circuits function as designed, and c) for each circuit breaker found inoperable during these functional tests, one or an additional representative semple of at least 10% of all'the circuit breakers of the inoperable type-shall also be functionally tested until no more failures are found or all circuit breakers of that type have been' functionally tested;
- 2) By selecting and f unctionally testing a representative sample of at least 10% of each type 480V molded case circuit breakers and of lower voltage circuit breakers. .
Circuit breakers selected for functional testing shall be selected on a rotating basis. Testing of these circuit
, breakers shall consist of-injecting a current with a value equal to 300% of the pickup of.the long-time delay trip element and 150% of the pickup of the short-time delay trip element, and verifying that the circuit breaker operates within the time delay band width for that current specified by the manufacturer. The instantaneous element shall be tested by injecting a current equal to 120% of the pickup value of the element and verifying that the-circuit breaker trips instantaneously with no intentional time delay. Molded case circuit breaker testing shall also follow this procedure except that generally no more ,
than two trip elements, time delay and instantaneous, will be involveo. The instantaneous slement for molded case circuit breakers shall be tested by injecting a current for a frame size of 250 amps or less with tolerances of I
l CDHANCHE PEAK - UNITS 1 AND 2 4-3 January 22, 1993
ELECTRICAL E0VIPMENT PROTECTIVE DEVICES SURVEILLANCE REOL'IREMEN15 .
1 440%, -25% and a frame size of 400 amps or greater with .
tolerances of 125% and verifying that the circuit breaker trips instantaneously with no apparent time-delay. .
Circuit breakers found inoperable during furetional '-l testing shall be restored to OPERABLE status prior to ;
resuming operation, for each circuit breaker.found i inoperable during these functional tests, an additional !
representative: sample of a least 10% of all the circuit i breakers of the inoperable _ type shall also be-functionally !
tested until no more failures are found or all circuit i breakers of that type have been functionally tested; and >
0 b. At least once per 60 months by subjecting each circuit breaker to an inspection _and preventive maintenance ~1n accordance with ,
-procedures prepared in conjunction with its manufacturer's i recommendations- .
A
'l
'f i
t t
i CDMANCHE PEAK - UNITS 1 AND.2 4-4 '
January 22, 1993- .
. ,- - .s. _ ,-, ,. ,,, 4 ,-, -
.-,1 ... .,.. - - . _ - . .. . - . . , . - . . . _ . . . _ , . . _ . . . . . . . - _;..,,.m ~ . . . -_.,.- _ _,.,-m ,-. m ..,w-, . , . . - - .,
IELHNICAL REGulREMENT 4J (continued)-
TABLE 4.1.la (Continued) 2 UNIT 1 8 CONTAINMENT PENEIBATJON CONDUCTOR OVERCURRENT PROTECflVE DEVICES DEVICE NUMBER
$30 LOCATION
- 9. 118V AC Control Power a.PrimaryDevices-N/A(Fuse)
- b. Backup Breakers GENERAL ZLECTRIC PANELBOARD NL CKT. NO. BREAKER TYPE 1C2 22 TED .
1 1PC1 10,13 TED-1PC4 6,10 TED 1EC1 7 TED 2 1EC2 7 TED 2 1EC5 8 TED 1EC6 3,B TED
-1
- 10. Emergency Evacuation System Warning Lights Power
- a. Primary Devices - N/A (Fuse)
- b. Backup Breakers SQUARE D-PANELBOARD NO. CKT. NO. BREAKER TYPE XEC3-3 9, 10 FY 10 1 --
- 11. DRPI Data Cabinet Power Supplies
- a. Primary Breakers 2 2.
SQUARE D 2.
PANELBOARD NO. CKT. NO. BREAKER TYPE 2 1C14 1,2- 'FA 10
- b. Backup Breakers SQUARE D-PANELBOARD NO. CKT. NO. BREAKER TYPE 1C14 Main Pni. Bkrs. FA 10 COMANCHE PEAK - UNITS 1 AND 2 4-17 Revision 10-January _22,1993
1((HNICAL REOUIREMENT 4.1 (continuedl 8 TABLE 4.1.lb (Continued) 8 UNIT 2 8.
CONTAINHENT PENETRATION CONDUCTOR 8 OVERCURRENT PROTECTIVE DEVICES 8 DEVICE NUMBER 8 AND. LOCATION 8
- 3. 480fromMotorControlCenters(Continued) 8 MCC 2EB1-2 G.E. 8 COMPT. NO. BKR. TYPE SiSTEM POWERED 8 4G THED Motor Operated Valve 2-TV-4691 8 4M -THED Motor Operated Valve 2-TV-4693 8 3F THED Containment Drain Tank Pump-03 8 9H THED- Reactor Cavity Sump Pump-01 8 9M THED Reactor Cavity Sump Pump-02 8 7H THED Containment Sump #1 Pump-01 8-7M THED Containment Sump fl Pump-02 8 6H THED RCP #21 Motor Space Heater-01 8 6M THED RCP #23 Motor Space Heater-03 8 i 8B THED Incore Detector Drive "A" 8 8D THE0 Incore Detector Drive "8" 8 78 THED Incore Detector Drive "F" 8 3B THED Stud Tensioner Hoist Outlet-01 8 70 THED Hydraulic Deck Lift-01 8 4B THED Reactor Coolant Pump Motor 8 Hoist Receptacle 42 8 8H THED RC Pipe Penetration Cooling 8 Unit-01 8 8M THED RC Pipe Penetratio'n Cooling 8 Unit ~02 8 5H THED RCP #21 011 Lift Pump-01 8 SM THED RCP #23 011 Lif t Pump-03' 8 10B THED Preaccess Filter Train Package 8 Receptacle-17 8 SB THED Containment Ltg. XFMR-14 8 (PNL 2LPC3) 8 10F THED S.G. Wet Layup Circ. Pump 01 8
.(CP2-CFAPRP-01) 8 12M THED S.G. Wet Layup Circ Pump 03 8 .
(CP2-CFAPRP-03) 8 12H THED Containment Ltg. XFMR-28 8 (PNL 2011 & 2012) .
8-128 THED Personnel Air Lock Hydraulic 10 Unit #2 10 i
l COMANCHE PEAK - UNITS 1 AND 2 4-22 Revision 10 January 22, 1993'
'~
TECHNIGAL REOUIREMENT 4s1 (continued) 8 TABLE 4.1.lb (Continued) 8 UNIT 2 8 CONTAINMENT PENETRATION CONDUCTQB 8=
OVERCURRENT PROTECTIVE DEVICES 8 1
DEVICE NUMBER 8 AND LOCATION 8 l i
[QMPT. NO. BKR. TYPE SYSTEM POWERED 8 GD THED Refueling Machine (Manipulator 8 Crane-01) 8 l 2M THED_ RC Drain Tank Pump No. 1- 8 2F THED Containment-Ltg. XFMR-16 8 (PNL 2C7 & 2C9) 8 1H THED Containment Ltg. XFMR-12 8- ,
(PNL ELPC1 & 2LFCS) 8 3M THED Preaccess Fan No. 11- 8 SD THED Fuel Transfer System Pr Mr 8 Side Cont. Pn1. for TtX- M STTS-01 8 3.2 Device Location - MCC 2EB2-2 Containmer. Numbers 8 listed below. 8 Primary and Backup - Both primary and backup breakers 8 Breakers have identical trip ratings and are 8 located in the same MCC compt. ~8 These breakers are General Electric 8 type THED and THFK with. thermal- 8 !
magnetic trip elements. 8 MCC 2EB2-2 G.E. -8 COMPT. NO. BKR. TYPE SYSTEM POWEREQ 8 4G THED Motor Operated Valve 2-TV-4692. 8 4M THED Ntor Operated Valve 2-TV-4694- 8' l 3F THED Containment Drain Tank Pump-04 -8 7H THED Containment Sump No. 2 Pump-03 -8 7M THED Containment Sump No. 2 Pump-04 8-6H THED RCP #22 Motor Space Heater-02 8' 6M THED RCP #24 Motor Space. Heater-04 8 SB THED Incore Detector Drive "C" 8-2B- THED Incore Detector Drive "0" 8 l 7B THED incore Detector Drive "E" 8 :
l 50 THED Containment Fuel Storage Crane-01 8 i 3B THED Stud Tensioner Hoist Outlet-02 8-10 4 t
I COMANCHE PEAK - UNITS 1 AND 2 4-23 Revision 10 January 22.--1993-
1 .
TECHNICAL REOUIREMENT 4.1 (continued) 8 'f TABLE 4.1.1b (Continuedl 8 UNIT 2 8 .
CONTAINHENT PENETRATION CONDUCTOR. 8 !
OVERCURRENT PROTECTIVE DEVICES 8 DEVICE NUMBER 8 i AND LOCATION 8
- 3. 480VACfromMotorControlCenters(Continued) 8- -
Q_MP1. N0u BKR. TYPE SYSTEM POWERED 8 .
10B TiiED RCC Change Fixture Hoist Drive-01= 8 10F THED Refueling Cavity Skimmer Pump-01 8 128 THED PowerReceptacles(Cont.E1. . 8 841') 8-1H- THED S.G. Wet Layup Cire. Pump 102- 8 (CP2-CFAPRP-02) 8 12M THED S.G. Wet Layup Circ. Pump 04 ~8 ,
- CP2-CFAPRP-04)
, 8 '
8H THED RC-Pipe. Penetration Fan-03 8 8M THED RC Pipe Penetration Fan-04 8 5H THED RCP 122 011 Lift Pump-02 8 SH THED RCP #24 011 Lift Pump-04 8-12H THED Preaccess filter Train Package 8 ;
Receptacles - 18 8-6D THED Containment Auxiliary Upper 8 Crane-01 8 2F THED ContainmentLtg.XFMR-13(PNL 8
.2LPC2) 8 70 THED Containment Elevator-Ol'. 8 2D THED Containment Access Rotating 8 ,
. Platform-01 .. 8 2M THED Reactor Coolant Drain Tank Pump-02 8 ,
9F THED Containment Ltg. XFMR-17 8 (PNL208&-2010) .8- :
9M THED Containment Ltg. XFMR-15 8 ;
(PNL2LPC4-&2LPC6) :8 3M THED Preaccess_ Fan-12 8 10 10 1C THFK Containment Welding Receptacles '8 3.3 _ Device-Location -MCC 2EB3-2 Containment numbers 8 listed below. 8 Primary and Backup -Unless noted otherwise, both 8 l primary and backup breakers have 8 a identical trip ratings and are B located in the same MCC compt. 8 These breakers are General Electric, 8 .. .
l l-type THED or-THFK with~ thermal-8 .
magnetic trip elements.- ~8 COMANCHE PEAK - UNITS 1 AND 2 4-24 Revision'10 January 22,;1993- '
- . . - , - - .. - - -- , - - - . -,- . - - .- .D
IECHNICAL REOUIREMENT 4.1 (continued) 8 TABLE 4.1.1b(Continued) 8 UNIT 2 - 8 ,
QNTAINMENT PENETRATION CONDUCTOR 8 OVERCURRENT PROTECTIVE DEVICES 8 ;
- 5. 120VSpaceHeaterCircuitsfrom480VSwitchgears(Continued) 8
- a. PrimaryDevices-N/A(Fuse) 8 :
- b. Backup Breakers 8-BKR. LOCATION WESTINGHOUSE 8
& NUMBER BKR. TYPE 8 l Swgr. 2EB1, EB1010 8 Cubicle 3A, 10 CP2-VAFNAV-01 8' Space Heater Bkr. .8 ,
Swgr. 2EB2, EB1010 -8 Cubicle 3A, .10 ,
CP2-VAFNAV-02 8 Space Heater Bkr. 8 Swgr. 2EB3, EB1010 8-Cubicle 9A. 10 CP2-VAFNAV-03 8 Space Heater Bkr. 8-Swgr. 2EB4, EB1010 8 Cubicle 9A. 10 CP2-VAFNAV-04 8 Space Heater Bkr. -8 Swgr. 2EB3, EB1010 8 ,
Cubicle 8A, 10 CP2-VAFNCB-01 8 -
Space Heater Bkr. 8 Swgr. 2EB4, EB1010 8-Cubicle 8A, .10 CP2-VAFNCB-02 8 Space Heater Bkr. 8 COMANCHE PEAK - UNITS 1 AND 2 4-28 Revision 10:
January 22, 1993
TECHNICAL REOUIREMENT 4.1 (continued) 8 IMLE 4.1.lb (Continued) 8 UNIT 2 8 CONTAINMENT PENETRATION CONDUCTOR -8 OVERCURRENT PROTECTIVE DEVICES 8 DEVICE NUMBER 8 AND LOCATION 8 9, 118V AC Control Power S a.PrimaryDevices-N/A(Fuse) 8
- b. Backup Breakers 8 GENERAL-ELECTRIC 8 PANELBOARD NO. CKT. NO. _8REAKER TYPE ;8 2C2 22 TED 10 2PC1 10,13 TED 8 2PC4 6,10 TED 8 2EC1 7 TED 8 2EC2 4,7 TED 8 2ECS 8 TED 8 2EC6 3,8 TED 8 8-8
- 10. Emergency Evacuation System Warning Lights Power 8 a.PrimaryDevices-N/A(Fuse) -8
- b. Backup Breakers 8 SQUARE D 8 PANELBOARD N0. CKT. NO. BREAKER TYPE 8 XEC4-3 9, 10 FY 10 8
- 11. DRPI Data Cabinet Power Supplies 8
- a. Primary Breakers '8 8
SQUARE D 8 PANELBDARD NO. CKT. NO. BREAKER TYPE 8 l 2C14 1,2 FA 10
- b. Backup Breakers 8 SQUARE D 8 PANELBOARD NO. CKT. NL BREAKER' TYPE 8 2014 Main Pnl. Bkrs. FA 10 COMANCHE PEAK - UNITS 1 AND 2 4-30 Revision 101 January 22, 1993
TECHNICAL REQUIREMENTS HANUAL EFFECTIVE PAGE LISTlHG BELOW IS A LEGEND FOR THE EFFECTIVE PAGE LISTING:-
Original Submitted July 21 -1989 Revision 1 September 15, 1989 Revision 2 . January 15, 1990 Revision 3 July 20, 1990. .
Revision 4 April 24, 1991 Revision 5 -September 0, 1991 Revision 6 November 22, 1991 ;
Revision 7 March 18, 1992 i Revision 8 June 30, 1992 '
Revision 9 December 18, 1992 Revision 10 January 22,-1993 ,
t r.
EPL 1 January 22, 1993 i I- _ . . _ _ . , . _
_ _ _ _ _ _ . _. .- _ _ _ - . _ _ _ ~ _ _ _ _ _ . _ . _ . . -
TECHNICAL REQUIREMENTS MANUAL EFFECTIVE PAGE LISTING TRM-Tab Original-TRM-Title Page June 30, 1992 i Table of Contents-Tab Original i December 18, 1992 Administrative Controis-Tab Original Administrative Controis-Title Page June 30, 1992 0-1 June 30, 1992 0-2 ' January 22, 1993 0-3 December 18, 1992 0-4 June 30, 1992 0-5 January 22, 1993-0-6 January 22, 1993 0-7 January 22, 1993 0-8 January 22, 1993 0-9 January 22, 1993 ;
0-10 January 22, 1993 -
0-11 January 22, 1993 0-12 June 30, 1992 0-13 June 30, 1992 0-14 June 30, 1992
- 0-15 June 30, 1992 0-16 January 22, 1993 0-17 January 22, 1993 ,
0-18 June 30, 1992 0-19 Revision 8 0-20 Revision 8 0-21 Revision 8 0-22 Revision 8 0-23 Revision 8 0-24 Revision 8 0-25 Revision 8 0-26 January 22, 1993 Technical Requirements-Tab Original Section 1-Tab Original 1-1 June 30, 1992 1-2 Revision 8 1-3 June 30, 1992 1-4 _ January 22, 1993
.1-5 June 30, 1992 1-6 Revision 8 1-7 June 30, 1992 1-8 June 30, 1992 1-9 Revision 9 1-10 Revision 9 1-11 Revision 9 1-12 Revision 9
.EPL 2 January 22, 1993
'o 1 -
TECHNICAL REQUIREMENTS HANUAL EFFECTIVE PAGE LISTING 1-13 Revision 9 1-14 June 30, 1992 1-15 Revision 8 1-16 June 30, 1992 1-17 Revision 8 1-18 January 22, 1993 1-19 January 22, 1993 1-20 January 22, 1993 1-21 June 30, 1992 1-22 Revision 8 Sec. 2-Tab Original ,
2-1 June 30, 1992
~
2-2 Revision 8 -
2-3 June 30, 1992 2-4 January 22, 1993 2-5 Revision 8 2-6 Revision 8
2-7 Revision 8 2-8 January 22, 1993 ;
2-9 Revision 8 2-10 January 22. 1993 2-11 Revision 8 .
2-12 Revision 9 2-13 Revision 8
- 2-14 January 22, 1993 2-15 Revision 8-2-16 Revision 8 2-17 Revision 8 2-18 Revision 8 3 2-19 January 22, 1993 2-20 January 22, 1993 2-21 Revision 8 2-22 Revision 8 2-23 Revision 8 2-24 Revision 8 2-25 Revision 9
?-26 January 22, 1993 2-27 December 18, 1992 2-28 December 18, 1992-Sec. 3-Tab Original 3-1 June 30, 1992:
3-2 Revision 8 3-3 Revision 10 .
3-4 January 22, 1993:
3-5 January 22, 1993 3-6 June 30, 1992 EPL 3 January 22, 1993
4
-TECHNICAL REQUIREMENTS. MANUAL-EFFECTIVE PAGE LISTING 3-7 June 30, 19921 3-8 June 30, 1992 3-9 June 30,.1992-Revision 10 3-10 3-11 June 30, 1992 3-12 Revision 10 3-13 Revision 8 Sec. 4-Tab Origi~al-n 4-1 June 30, 1992 4-2 Revision 8 4-4-3 January 22, 1993 4-4 January _22, 1993 '
4-5 Revision 9 4-6 Revision 9 -
4-7 Revision 8 _
4-8 Revision 8 4-9 Revision 8 4-10 Revision 8 4-11 Revision 8' 4-12 Revision 8 4-13 Revision-8 4 Revision 8 4-15 Revision 8 4-16 Revision 8 4-17 Revision 10.
4-18 Revision 9 '
4-19 Revision 9 4-20 Fevision 8 4-21 Revision 8 4-22 Revision 10 4-23 Revision 10 4-24 Revision 10 4-25 -Revision 8 4-26 Revision 8 4-27 Revision.8 4-28 Revision 10 4-29 Revision 8 4-30 Revision 10 4-31 June 130,.1992 EPL-Tab ' Original EPL-1 Revision 10' EPL-2 Revision 10 '
EPL-3 Revision 10 1EPL-4 '
Revision'10 EPL 4 January -22, 1993 G
w -