ML20129C453
| ML20129C453 | |
| Person / Time | |
|---|---|
| Site: | Hope Creek  |
| Issue date: | 07/03/1985 |
| From: | Butler W Office of Nuclear Reactor Regulation |
| To: | Mittl R Public Service Enterprise Group |
| References | |
| NUDOCS 8507160198 | |
| Download: ML20129C453 (491) | |
Text
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UUL 3 1985 Occket No. 50-354 Mr. R. L. liitti, General l'anager liuclear Assurance and Regulation Public Service Electric & Gas Company P.O. Box 570, T22A Newark, New Jersey 07101
Dear lir. Hitti:
SUBJECT:
HOPE CREEK TECH!!ICAL SPECIFICATI0ris Enclosed is a copy of the first draft of the Hope Creek Technical Specifi-cations. This first oraft is based on PSELG's sutnittals dated January 17, February 7, March 22, April 10, !!ay 13, and June 10, 1985, ano on the General Electric Stancard Technical Specifications (STS BUR /4). The Draft Technical Specifications enclosed will be the basis for a staff site visit the week of August 12, 1985 to discuss areas in which additional information may be re-quired to ensure that the final Hope Creek Technical Specifications are con-sistent with the FSAR arc! reflect the "as-built" plant design. This August 12, 1985 visit date has been discussed with Mr. Bruce Preston of your staff.
Please call us if you have any questions.
Sincerely, Or18 1oel signed byi Walter R. Butler, Chief Licensing Branch flo. 2 Division of Licensing
Enclosure:
As stated cc: See next page Distribution Decket. .fikC PDR Local PDR PRC Systen liSIC LE42Rcading EHylton Dewey ,0 ELD ACRS (16) UPartlow BGrimes EJordan SBrown TSRG L M LB#2/DL/BC LWagner:mk UButler 7/l/85 7/ [ /85 8507160198 850703 PDR ADOCK 05000354 A PDR
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'/'E g( g NUCLEAR REGULATORY COMMISSION g/ . WASHINGTON, D. C. 20555 0 i o JUL 3 1985 Docket flo. 50-354 21r. R. L. liitti, General Manager fluclear Assurance and Regulation Public Service Electric & Gas Company P.O. Box 570, T22A Newark, New Jersey 07101 Cear Mr. Mitti:
SUBJECT:
HOPE CREEK TECHNICAL SPECIFICATIONS Enclosed is a copy of the first draft of the Hope Creek Technical Specifi-cations. This first draft is based on PSE&G's submittals dated January 17, February 7, March 22, April 10, May 13, and June 10, 1985, and on the General Electric Standard Technical Specifications (STS BWR/4). The Draft Technical Specifications enclosed will be the basis for a staff site visit the week of August 12, 1985 to discuss areas in which additional information may be re-quired to ensure that the f_inal Hope Creek Technical Specifications are con-sistent with the FSAR and reflect the "as-built" plant design'. This August 12, 1905 visit date has been discussed with Mr. Bruce Preston of your staff.
Please call us if you have any questions.
Sincerely, Walter R. Butler, Chief Licensing Branch No. 2 Division of Licensing
Enclosure:
As stated cc: See next page v
Mr. R. L. Mitti Public Service Electric & Gas Co. Hope Creek Generating Station
'cc:
. Gregory Minor Susan C. Remis Richard Hubbard Division of Public Interest Advocacy Dale Bridenbaugh New Jersey. State Departroent of
~MHB Technical Associates the Public Advocate 1723 Hamilton Avenue, Suite K Richard J. Hughes Justice Ccmples San Jose, California 95125 CN-850 Trenton, New Jersey 08625 Troy B. Conner, Jr. Esquire Office of Legal Counsel Conner & Wetterhahn Department of Natural Resources 1747 Pennsylvania Avenue N.W. and Environmental Control Washington, D.C. 20006 89 Kings Highway P.O. Box 1401 Dover, Delaware 19903 Richard Fryling, Jr., Esquire Mr. K. W. Burrowes, Project Engineer Associate General Solicitor Bechtel Pcher Corporation Public Service Electric & Gas Ccmpany 50 Beale Street P. O. Box 570 TSE P. O. Box 3965 Newark, New Jersey 07101 San Francisco, California 94119 Mr. J. M. Ashley Resident Inspector Senior Licensing Engineer U.S.N.R.C. _ c/o Public Service Electric & Gas Co.
P. O. Box 241 Bethesda Office Center, Suit 550 Hancocks Bridge, hew Jersey 08038 4520 East-West Highway Bethesda, Maryland 20814 Richard F. Engel Deputy Attorney General Mr. A. E. Giardino Division of Law Manager - Quality Assurance E&C Environmental Protection Section Public Service Electric & Gas Co.
Richard J. Hughes Justice Complex P. O. Box A Ch-112P Hancocks Bridge, New Jersey C8038 Trenton, New Jersey 08625 Mr. Robert J. Touhey, Mr. Anthony J. Pietrofitta Acting Director General Manager DNREC - Division of Pcwer Prcduction Engineering Environmental Control Atlantic Electric !
89 Kings Highway 1199 Black Horse Pike P. O. Box 1401 Pleasantville, New Jersey Cb'c 32 Dover, Delaware 19903 Regional Administrator, Region I Mr. R. S. Salvesen U. S. Nuclear Regulatory Commissicn General Manager-Hcpe Creek Operation 631 Park Avenue Public Service Electric & Gas Co. King of Prussia, Pennsylvania 19406 P.O. Box A -
Hancocks Bridge, hew Jersey 0E038
Public Service- Electric & Gas Co. Hope' Creek Generating Station 4
- cc:
Mr. B. A. Preston Project' Licensing flanager
- Public Service Electric & Gas Co.
P. O. Box 570 T22A Newark, New Jersey 07101 Ms. Rebecca Green New Jersey Bureau of Radiation Protection
- i. 380 Scotch Road Trenten,.New Jersey 08628 i
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PUBLIC SERVICE ELECTRIC AND GAS COMPANY HOPE CREEK GENERATING STATION TECHNICAL SPECIFICATIONS 4
APPENDIX "A" TO LICENSE NO.
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6 JUN 2 8 385 INDEX s
M I
1 OEFINITIONS JUN 2 8 EES SECTION
- 1. 0 DEFINITIONS PAGE 1.1 ACTI0M..................................................... 1-1
- 1. 2 AVC.7 AGE PLANAR EXPOSURE................ ................... 1-1
- 1. 3 AVERAGE PLANAR LINEAR HEAT GENERATION RATE................. 1-1 1.4 CHANNEL CALIBRATION........................................ 1-1
- 1. 5 CHANNEL CHECK.............................................. 1-1 1.6 CHANNEL FUNCTIONAL TEST.................................... 1-1
- 1. 7 CORE ALTERATION............................................ 1-2 1.8' CORE MAXIMUM FRACTION OF LIMITING POWER SENSITY............ 1-2 1.9 CRITICAL POWER RATI0....................................... 1-2 1.10 DOSE EQUIVALENT I-131...................................... 1-2 1.11 E-AVERAGE DISINTEGRATION ENERGY............................ 1-2 1.12 EMERGENCY CORE COOLING SYSTEM (ECCS) RESPONSE TIME......... 1-2 1.13 END-OF-CYCLE RECIRCULATION PUMP TRIP SYSTEM RESPONSE TIME.. 1-3 1.14 FRACTION OF LIMITING POWER DENSITY......................... 1-3 1.15 FRACTION OF RATED THERMAL P0WER............................ 1-3 1.16 FREQUENCY N0TATION......................................... 1-3 1.17 IDENTIFIED LEAKAGE......................................... 1-3 1.18 ISOLATION SYSTEM RESPONSE TIME........................... . 1-3 1.19 LIMITING CONTROL ROD PATTERN............................... 1-3 1.20 LINEAR HEAT GENERATION RATE................................ 1-3 1.21 LOGIC SYSTEM FUNCTIONAL TEST............................... 1-4 (1._ MAXIMUM TOTAL PEAKING FACT 0R............................... 1-4) 1.22 MINIMUM CRITICAL POWER RATI0............................... 1-4
(
HOPE CREEK i
INDEX y 28 g DEFINITIONS SECTION pEFINITIONS (Continued)
PAGE 1.23 OPERABLE -
OPERABILITY..................................... 1-4 1.24 OPERATIONAL CONDITION - CONDITION..........................
1-4 1.25 PHYSICS TESTS.............................................. 1-4 1.26 PRESSURE BOUNDARY LEAKAGE.................................. 1-4 1.27 PRIMARY CONTAINMENT INTEGRITY..............................
1-5 1.28 RATED THERMAL P0WER........................................ 1-5 1.29 REACTOR PROTECTION SYSTEM RESPONSE TIME.................... 1-5 1.30 REPORTABLE OCCURRENCE...................................... 1-5 1.31 R00 DENSITY................................................ 1-5 1.32 SECONDARY CONTAINMENT INTEGRITY............................ 1-6 1.33 SHUTDOWN MARGIN............................................ 1-6 1.34 STAGGERED TEST BASIS....................................... 1-6 1.35 THERMAL POWER............ ................................. 1-6 c1. _ TOTAL PEAKING FACT 0R...................................... 1-7) 1.36 TURBINE BYPASS SYSTEM RESPONSE TIME........................ 1-7 1.37 UNIDENTIFIED LEAKAGE.............. . ...................... 1-7
! TABLE-1.1, SURVEILLANCE FREQUENCY N0TATION...................... 1-8 TABLE 1.2, OPERATIONAL CONDITIONS............................... 1-9 h
HOPE CREEK ii
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INDEX JU112 8 1985 SAFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGS SECTION PAGE 2.1 SAFETY LIMITS THERMAL POWER, Low Pressure or Low Flow................... 2-1 THERMAL POWER, High Pressure and High Flow................ 2-1 Reactor Coolant System Pressure........................... 2-1 Reactor Vessel Water Leve1................................ 2-2 2.2~ LIMITING SAFETY SYSTEM SETTINGS Reactor Protection System Instrumentation Setpoints....... 2-3 BASES 2.1 SAFETY LIMITS THERMAL POWER, Low Pressure or Low Flow. . . . . . . . . . . . . . . . . . . B 2-1 _
THERMAL POWER, High Pressure and High Flow................ B 2-2
, Reactor Coolant System Pressure........................... B 2-5 Reactor Vessel Water Leve1................................ B 2-5 2.2 LIMITING SAFETY SYSTEM SETTINGS Reactor Protection System Instrumentation Setpoints........ B 2-6 HOPE CREEK iii
INDEX JUN 2 81985 ,
LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE 3/4. 0,_, APP _QCA,BILITY. . . . . . . . ........ . .............. ........ 3/4 0-1 3/4.1 REACTIVITY' CONTROL SYSTEMS 3/4.1.1 SHUTDOWN MARGIN........................................ 3/4 1-1 3/4.1.2 REACTIVITY AN0MALIES................................... 3/4 1-2 3/4.1.3 CONTROL RODS Control Rod Operability................................ 3/4 1-3 Control Rod Maximum Scram Insertion Times.............. 3/4 1-6 Control Rod Average Scram Insertion Times..............
3/4.1-7 Four Control Rod Group Scram Insertion Times........... 3/4 1-8 Control Rod Scram Accumulators......................... 3/4 1-9 Control Rod Drive Coupling............................. 3/4 1-11 Control Rod Position Indication........................ 3/4 1-13 Control Rod Drive Housing Support...................... 3/4 1-15 3/4.1.4 CONTROL ROD PROGRAM CONTROLS Rod Worth Minimizer.................................... 3/4 1-16 Rod Sequence Control System............................ 3/4 1-17 Rod Block Monitor...................................... 3/4 1-18 l
3/4.1.5 STANDBY LIQUID CONTROL SYSTEM.......................... 3/4 1-19 3/4.2 POWER DISTRIBUTION LIMITS 3/4.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE............. 3/4 2-1 3/4 2.2 APRM SETP0lNTS......................................... 3/4 2-5 3/4.2.3 ' MINIMUM CRITICAL POWER RATI0........................... 3/4 2-6 .
3/4.2.4
. LINEAR HEAT GENERATION RATE............................ 3/4 2-9 HOPE CREEK iv
INDEX JUN 2 81985 LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE 3/1.3 INSTRUMENTATION 3/'.3.1 REACTOR PROTECTION SYS fbi INSTRUii't NTATION. . . . . . . . . . . . 3/4 3-1 3/4.3.2 ISOLATION ACTUATION INSTRUMENTATION.................. 3/4 3-9 3/4.3.3 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION...................................... 3/4 3-27 3/4.3.4 RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION ATWS Recirculation Pump Trip System Instrumentation.. 3/4 3-36 End-of-Cycle. Recirculation Pump Trip System Instrumentation...................................... 3/4 3-40 3/4.3.5 REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION...................................... 3/4 3-46 3/4.3.6 CONTROL RCD BLOCK INSTRUMENTATION.................... 3/4 3-51 3/4.3.7 MONITORING INSTRUMENTATION Radiation Monitoring Instrumentation................. 3/4 3-57 Seismic Monitoring Instrumentation................... 3/4 3-64 Meteorological Monitoring Instrumentation............ 3/4 3-67 Remote Shutdown Monitoring Instrumentation........... 3/4 3-70 Accident Monitoring Instrumentation.................. 3/4 3-73 Source Range Monitors................................ 3/4 3-77 Traversing In-Core Probe System...................... 3/4 3-78 Chlorine (and Ammonia) Detection System.............. 3/4 3-79 Chlorine Intrusion Monitors......................... 3/4 3-80 Fire Detection Instrumentation....................... 3/4 3-84 Loose-Part Detection System.......................... 3/4 3-86 3/4.3.8 TURBINE OVERSPEED PROTECTION SYSTEM........ ......... 3/4 3-87 3/4.3.9 PLANT SYSTEMS ACTUATION INSTRUMENTATION............... 3/4 3-89 HOPE CREEK v
INDEX JUN 2 81985 LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE 3/4.4 REACTOR COOLANT SYSTEM 3/4.4.1 RECIRCULATION SYSTEM Recirculation Loops.................................. 3/4 4-1 Jet Pumps..............................\.............. 3/4 4-2 Recirculation Pumps.................................. 3/4 4-3 Idle Recirculation loop Startup...................... 3/4 4-4 3/4.4.2 SAFETY / RELIEF VALVES s
Safety / Relief Valves................................. 3/4 4-5 Safety / Relief Valves Low-Low Set Function............ 3/4 4-7 3/4 4.3 REACTOR COOLANT SYSTEM LEAKAGE 'i
.- Leakage Detection Systems............................ 3/4 4-8 .
Operational Leakage.................................. 3/4 4-9 3/4.4.4 CHEMISTRY............................................ 3/4 4-12 3/4.4.5 SPECIFIC ACTIVITY.................................... 3/4 4-15 3/4.4.6
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PRESSURE / TEMPERATURE LIMITS l Reactor Coolant System............................... 3/4 4-18 Reactor Steam Dome................................... 3/4 4-22 3/4.4.7 MAIN STEAM LINE ISOLATION VALVES..................... 3/4 4-23 3/4.4.8 STRUCTURAL INTEGRITY................................. 3/4 4-24 3/4.4.9 RESIDUAL HEAT REMOVAL Hot Shutdown......................................... 3/4 4-25 Cold Shutdown........................................ 3/4 4-26 3/4.5 EMERGENCY CORE COOLING SYSTEMS 3/4.5.1 ECCS - 0PERATING..................................... 3/4 5-1 3/4.5.2 ECCS - SHUTD0WN...................................... 3/4 5-6 3/4.5.3 SUPPRESSION CHAMBER.................................. 3/4 5-8 HOPE CREEK vi
INDEX y 2 8 1985 LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE 3/4.6 CONTAINMENT SYSTEMS s/4.6.1 PRIMARY CONTAINMENT Primary Containment Integri ty. . . . . . . . . . . . . . . . . . . . . . . . 3/4 6-1 Prima ry Containment Leakage. . . . . . . . . . . . . . . . . . . . . . . . . . 3/4 6-2 Primary Containment Ai r Locks. . . . . . . . . . . . . . . . . . . . . . . . 3/4 6-5 MSIV Leakage Control System.......................... 3/4 6-7 Primary Containment Structural Integrity. . . . . . . . . . . . . 3/4 6-8 Drywell and Suppression Chamber Internal Pressure.... 3/4 6-9 Drywell Average Ai r Temperature. . . . . . . . . . . . . . . . . . . . . . 3/4 6-10 Drywell and Suppression Chamber Purge System......... 3/4 6-11 Primary Containment Penetration Pressurization System. 3/4 6-12 3/4.6.2 DEPRESSURIZATION SYSTEMS Suppression Chamber.................................. 3/4 6-13 Suppression Pool (and Drywell) Spray. . . . . . . . . . . . . . . . . 3/4 6-16 Suppression Pool Cooling............................. 3/4 6-17 Drywell-Suppression Chamber Differential Pressure.... 3/4 6-18 3/4.6.3 PRIMARY CONTAINMENT ISOLATION VALVES. . . . . . . . . . . . . . . . . 3/4 6-19 3/4.6.4 VACUUM RELIEF Suppression Chamber - Drywell Vacuum Breakers. . . . . . . . 3/4 6-23 Reactor Building - Suppression Chamber Vacuum Breakers........................................... 3/4 6-25 3/4.6.5 SECONDARY CONTAINMENT Secondary Containment Integri ty. . . . . . . . . . . . . . . . . . . . . . 3/4 6-26 Secondary Containment Automatic Isolation (Dampers)
(Valves)........................................... 3/4 6-27 Standby Gas Treatment System......................... 3/4 6-29 HOPE CREEK vii
. 1 l
l INDEX y 2 8 1985 LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE CONTAINMENT SYSTEMS (Continued) 3/4.6.6 PRIMARY CONTAINMENT ATMOSPHERE CONTROL Drywell and Suppression Chamber Hydrogen Recombiner Systems............................................ 3/4 6-32 Drywell and Suppression Chamber Atmosphere Dilution Systems............................................ 3/4 6-33 Drywell (and Suppression Chamber) Hydrogen Mixing System............................................. 3/4 6-34 Drywell and Suppression Chamber Oxygen Concentration. 3/4 6-35 3/4.7 PLANT SYSTEMS 3/4.7.1 SERVICE WATER SYSTEMS Residual Heat Removal Service Water System........... 3/4 7-1 Plant Service Water System........................... 3/4 7-3 Ultimate Heat Sink................................... 3/4 7-5 3/4.7.2 CONTROL ROOM EMERGENCY FILTRATION SYSTEM. . . . . . . . . . . . . 3/4 7-6 3/4.7.3 FLOOD PROTECTION..................................... 3/4 7-9 3/4.7.4 REACTOR CORE ISOLATION COOLING SYSTEM. . . . . . . . . . . . . . . . 3/4 7-10 3/4.7.5 SNUBBERS............................................. 3/4 7-12 3/4.7.6 SEALED SOURCE CONTAMINATION.......................... 3/4 7-19 3/4.7.7 FIRE SUPPRESSION SYSTEMS Fire Suppression Water System........................ 3/4 7-21 Spray and/or Sprinkl er Systems. . . . . . . . . . . . . . . . . . . . . . . 3/4 7-24 CO 2
Systems.......................................... 3/4 7-26 Halon Systems........................................ 3/4 7-28 Fire Hose Stations................................... 3/4 7-29 Yard Fire Hydrants and Hydrant Hose Houses........... 3/4 7-31 3/4.7.8 FIRE RATED ASSEMBLIES................................ 3/4 7-33 ,
3/4.7.9 AREA TEMPERATURE MONITORING..... .................... 3/4 7-35 3.4.7.10 MAIN TURBINE BYPASS SYSTEM......... ................. 3/4 7-37 HOPE CREEK viii
INDEX JUN 2 81o85 LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE 3/4.8 ELECTRICAL P0wdk SYSTEMS 3/4.8.1 A.C. SOURCES A.C. Sources-Operating............................... 3/4 8-1 A.C. Sources-Shutdown................................ 3/4 8-9 3/4.8.2 0.C. SOURCES 0.C. Sources-Operating............................... 3/4 8-10 0.C. Sources-Shutdown................................ 3/4 8-13 3/4.8.3 ONSITE POWER DISTRIBUTION SYSTEMS Distribution - Operating............................. 3/4 8-14 Distribution - Shutdown.............................. 3/4 8-15 3/4.8.4 ELECTRICAL EQUIPMENT PROTECTIVE DEVICES A.C. Circuits Inside Primary Containment............. 3/4 8-16 Primary Containment Penetration Conductor Overcurrent Protective Devices................................. 3/4 8-17 Motor Operated Valve Thermal Overload Protection. . . . . 3/4 8-20 Reactor Protection System Electric Power Monitoring.. 3/4 8-22 3/4.9 REFUELING OPERATIONS 3/4.9.1 REACTOR MODE SWITCH.................................. 3/4 9-1 3/4.9.2 INSTRUMENTATION...................................... 3/4 9-3 3/4.9.3 CONTROL ROD P0SITION................................. 3/4 9-5 3/4.9.4 DECAY TIME........................................... 3/4 9-6 3/4.9.5 COMMUNICATIONS....................................... 3/4 9-7 3/4.9.6 REFUELING PLATF0RM................................... 3/4 9-8 HOPE CREEK ix
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INDEX 2 8 1985 LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE REFUELING OPERATIONS (Continued) 3/4.9.7 CRANE TRAVEL - SPENT FUEL STORAGE P00L............... 3/4 9-9 3/4.9.8 WATER LEVEL - REACTOR VESSEL......................... 3/4 9-10 3/4.9.9 WATER LEVEL - SPENT FUEL STORAGE P00L................ 3/4 9-11 3/4.9.10 CONTROL ROD REMOVAL Single Control Rod Removal........................... 3/4 9-12 Multiple ContrIl Rod Removal......................... 3/4 9-14 3/4.9.11 RESIOUAL HEAT REMOVAL AND COOLANT CIRCULATION High Water Level..................................... 3/4 9-16 -i
.. ~ Low Water Leve1...................................... 3/4 9-17 .
3/4.10 SPECIAL TEST EXCEPTIONS 3/4.10.1 PRIMARY CONTAINMENT INTEGRITY........................ 3/4 10-1 3/4.10.2 ROD SEQUENCE CONTROL SYSTEM.......................... 3/4 10-2 3/4.10.3 SHUT 00WN MARGIN DEMONSTRATIONS....................... 3/4 10-3 3/4.10.4 RECIRCULATION L00PS:................................. 3/4 10-4 3/4.10.5 OXYGEN CONCENTRATION................................. 3/4 10-5 3/4.10.6 TRAINING STARTUPS.................................... 3/4 10-6 HOPE CREEK x
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INDEX BASES JUN 2 81985 SECTION PAGE 3/4.0 APPLICABILITY.................. ............ ......... B 3/4 0-1 3/4.1 REACTIVITY CONTROL SYSTEMS 3/4.1.1 SHUTDOWN MARGIN.................................. B 3/4 1-1 3/4.1.2 REACTIVITY AN0MALIES............................. B 3/4 1-1 3/4.1.3 CONTROL R0DS..................................... B 3/4 1-2 3/4.1.4 CONTROL ROD PROGRAM CONTR0LS..................... B 3/4 1-3 3/4.1.5 STANDBY LIQUID CONTROL SYSTEM.................... B 3/4 1-4 3/4.2 POWER DISTRIBUTION LIMITS 3/4.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE........................................... B 3/4 2-1 3/4.2.2 APRM SETP0INTS...................................
B 3/4 2-2 3/4.2.3 MINIMUM CRITICAL POWER RATI0..................... B 3/4 2-4 3/4.2.4 LINEAR HEAT GENERATION RATE...................... B 3/4 2-5 3/4.3 INSTRUMENTATION
'~
3/4.3.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION........ B 3/4 3-1 3/4.3.2 ISOLATION ACTUATION INSTRUMENTATION. . . . . . . . . . . . . . B 3/4 3-2 3/4.3.3 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION.................................. B 3/4 3-2 3/4.3.4 RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION.................................. B 3/4 3-3 3/4.3.5 REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION........................ B 3/4 3-4 3 3/4.3.6 CONTROL RCD BLOCK INSTRUMENTATION.................................. B 3/4 3-4 HOPE CREEK xi
b INDEX gN 2 8 Tc85 BASES SECTION -
PAGE TNSTRUMENTATION (Continued) 3/4.3.7 MONITORING INSTRUMENTATION ~
Radiation Monitoring Instrumentation............ Bc3/4 3-4 Seismic Monitoring Instrumentation.............. B'.3/4 3-4 Meteorological Monitoring Instrumentation....... B 3/4 3-4 Remote Shutdown Monitoring Instrumentation...... B 3/4 3-5 Accident Monitoring Instrumentation............'. B 3/4 3-5 Source Range Monitors.........................n B 3/4 3-5 Traversing In-Core Probe System................. B 3/4 3-5 -,
Chlorine (and Ammonia) Detection System......... B 3/4 3-5 g Chloride Intrusion Monitors..................... B 3/4 3-6 Fire Detection Instrumentation.................. B 3/4 3-6 Loose-Part Detection System..................:.. B 3/4 3-6 \
3/4.3.8 TURBINE OVERSPEED PROTECTION 5 3 TEM............. B 3/4 3 6 3/4.3.9 P LANT SYSTEMS ACTUATION INSTRUMENTATION. . . . . . . . . B 3/4 3-6 -
1 3/4.4 REACTOR COOLANT SYSTEM r,
3/4.4.1 RECIRCULATION SYSTEM............ ../..../....... R 3/4 4-1 3/4.4.2 SAFETY / RELIEF VALVES........................ .. B 3/4 4-1 3/4.4.3 REACTOR COOL)NT SYSTEM LEAKAGE ,
Leakage Detection' Systems....................... B 3/4 4-2 ',
Operational Leakage............................. B 3/4 4-2 3/4.4.4 CHEMISTRY....................................... B 3/4 4-2 3/4.4.5 SPECIFIC ACTIVITY............................... B 3/4 4-3 3/4.4.6 PRESSURE / TEMPERATURE LIMITS..................... B 3/4 4-4 ,
3/4.4.7 MAIN STEAM LINE ISOLATION VALVES................ B 3/4 4-5 3/4.4.8 STRUCTURANINTEGRITY............................ B 3/4 4-5 3/4.4.9 RESIOUAL HEAT REM 0 VAL......f.................... B 3/4 4-5 HOPE CREEK xii
INDEX BASES M'28 I5
. SECTION PAGE 3/4.5 EMERGENCY CORE COCLIfic SYSTOiS 3/4.5.1/2 ECCS - 0."ERATINC and SHUTD0WN.................... b 3/4 5-1 3/4.5.3 SUPPRESSION CHAMBER.............................. B 3/4 5-2 3/4.6 CONTAINMENT SYSTEMS 3/4.6.1 PRIMARY CONTAINMENT Primary Containment Integrity. . . . . . . . . . . . . . . . . . . . B 3/4 6-1 Primary Containment Leakage. . . . . . . . . . . . . . . . . . . . . . B 3/4 6-1 Primary Containment Air Locks.................... B 3/4 6-1 MSIV Leakage Control System...................... B 3/4 6-1 Primary Containment Structural Integrity......... B 3/4 6-2 Drywell and Suppression Chamber Internal Pressure....................................... B 3/4 6-2 Drywell Average Ai r Temperature. . . . . . . . . . . . . . . . . . B 3/4 6-2 Drywell and Suppression Chamber Purge System..... B 3/4 6-2 Primary Containment Penetration Pressurization System........................................... B 3/4 6-3 3/4.6.2 DEPRESSURIZATION SYSTEMS......................... B 3/4 6-3 J 3/4.6.3 PRIMARY CONTAINMENT ISOLATION VALVES............. B 3/4 6-5 3/4.6.4 VACUUM RELIEF.................................... B 3/4 6-5 3/4.6.5 SECONDARY CONTAINMENT............................ B 3/4 6-5 N
3/4.6.6 PRIMARY CONTAINMENT ATMOSPHERE CONTROL........... B 3/4 6-6 3/4.7 PLANT SYSTEMS 3/4.7.1 SERVICE WATER SYSTEMS............................ B 3/4 7-1 3/4.7.2 CONTROL ROOM EMERGENCY FILTRATION SYSTEM......... B 3/4 7-1 i;' 3/4.7.3 F LOOD PROTECTION. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B 3/4 7- 1 0 3/4.7.4 REACTOR CORE ISOLATION COOLING SYSTEM. . . . . . . . . . . . B 3/4 7-1 HOPE CREEK xiii
INDEX y 2 8 1C85 BASES SECTION PAGE PJ. ANT SYSTEMS (Continued) 3/4.7.5 SNUBBERS........................................ B 3/4 7-2 3/4.7.6 SEALED SOURCE CONTAMINATION..................... B 3/4 7-3 3/4.7.7 FIRE SUPPRESSION SYSTEMS........................ B 3/4 7-4 3/4.7.8 FIRE RATED ASSEMBLIES........................... B 3/4 7-4 3/4.7.9 AREA TEMPERATURE MONITORING..................... B 3/4 7-5 3/4.7.10 MAIN TURBINE BYPASS SYSTEM...................... B 3/4 7-5 3/4.8 ELECTRICAL POWER SYSTEMS 3/4.8.1, 3/4.8.2 and 3/4.8.3 A.C. SOURCES, D.C. SOURCES and ONSITE POWER DISTRIBUTION SYSTEMS............................ B 3/4 8-1 3/4.8.4 ELECTRICAL EQUIPMENT PROTECTIVE DEVICES......... B 3/4 8-3 3/4.9 REFUELING OPERATIONS 3/4.9.1 REACTOR MODE SWITCH............................. B 3/4 9-1 3/4.9.2 INSTRUMENTATION................................. B 3/4 9-1 3/4.9.3 CONTROL ROD P0SITION............................ B 3/4 9-1 3/4.9.4 DECAY TIME...................................... B 3/4 9-1 3/4.9.5 COMMUNICATIONS................ ............... B 3/4 9-1 3/4.9.6 REFUELING PLATFORM......., .. .............. B 3/4 9-2 3/4.9.7 CRANE TRAVEL-SPENT FUEL STORAGE r00L............ B 3/4 9-2 3/4.9.8 and 3/4.9.9 WATER LEVEL - REACTOR VESSEL and WATER LEVEL - SPENT FUEL STORAGE P00L....... B 3/4 9-2 3/4.9.10 CONTROL ROD REM 0 VAL............................. B 3/4 9-2 B 3/4 9-2 3/4.9.11 RESIDUAL HEAT REMOVAL AND COOLANT CIRCULATION...
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INDEX
@ 2 8 196$
BASES SECTION PAGE 3/4.10 SPECTAL TEST FXCEPTIONS 3/4.10.1 PRIMAPV CONTAINMENT INTEGRITY................... B 3/4 10-1 3/4.10.2 ROD SEQUENCE CONTROL SYSTEM..................... B 3/4 10-1 j l
3/4.10.3 SHUTDOWN MARGIN DEMONSTRATIONS.................. B 3/4 10-1 3/4.10.4 RECIRCU LATION L00PS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . B 3/4 10-1 3/4.10.5 OXYGEN CONCENTRATION............................ B 3/4 10-1 3/4.10.6 TRAINING STARTUPS............................... B 3/4 10-1 f
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INDEX JUN 2 81985 DESIGN FEATURES SECTION PAGE 5.1 SITE Exclusion Area..... ....................................... 5-1 Low Population Zone........................................ 5-1
- 5. 2 CONTAINMENT Configuration.............................................. 5-1 Design Temperature and Pressure............................
5-1 Secondary Containment...................................... 5-1 5.3 REACTOR CORE Fuel Assemblies............................................ 5-4 ~3
. ~ Control Rod' Assemblies..................................... 5-4 5.4 REACTOR COOLANT SYSTEM
- Design Pressure and Temperature............................ 5-4 i Vo1ume..................................................... 5-4
- 5. 5 METEOROLOGICAL TOWER LOCATION.............................. 5-5
- 5. 6 FUEL STORAGE Criticality................................................ 5-5 0rainage................................................... 5-5 Capacity................................................... 5-5 5.7 COMPONENT CYCLIC OR TRANSIENT LIMIT........................ 5-5 HOPE CREEK xvi
..r .
INDEX r
ADMINISTRATIVE CONTROLS *0N 2 8 YFS SECTION PAGE 6.1 RESPONFIBILITY. ....... ................................. 6-1
- 6. 2 ORGANIZATION....... ..................................... 6-1 6.2.1 0FFSITE.............................................. 6-1 6.2.2 UNIT STAFF........................................... 6-1~
6.2.3 INDEPENDENT SAFETY ENGINEERING GROUP................. 6-6 FUNCTION ............................................ 6-6 COMPOSITION.......................................... 6-6 RESP 0NSIBILITIES..................................... 6-6 REC 0RDS.............................................. 6-6 6.2.4 SHIFT TECHNICAL ADVIS0R.............................. 6-6 6.3 UNIT STAFF QUALIFICATIONS................................. 6-6 6.4 TRAINING.................................................. 6-7 6.5 REVIEW AND AUDIT.......................................... 6-7 6.5.1 (UNIT REVIEW GROUP (URG))............................ 6-7 FUNCTION ............................................ 6-7 COMPOSITION ......................................... 6-7 ALTERNATES........................................... 6-7 MEETING FREQUENCY ................................... 6-7 QU0 RUM............................................... 6-7 RESPONSIBILITIES .................................... 6-8 REC 0RDS.............................................. 6-9 HOPE CREEK xvii
l INDEX N 2 6 1965 ADMINISTRATIVE CONTROLS LIST OF FIGURES FIGURE FAGE 6.2.1-1 0FFSITE ORG8NIZATION................................. 6-3 6.2.2-1 UNIT ORGANIZATION............... ................... 6-4 LIST OF-TABLES TABLE PAGE 6.2.2-la MINIMUM SHIFT CREW COMPOSITION - SINGLE UNIT FACILITY............................................. 6-Sa 6.2.2-lb MINIMUM SHIFT CREW COMPOSITION - TWO UNITS WITH A COMMON CONTROL R00M........................... 6-5b 6.2.2-1c MINIMUM SHIFT CREW COMPOSITION - TWO UNITS
~ WITH TWO CONTRO L R00MS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-Sc HOPE CREEK xix
DRAFI JilN 2 8 1985 SECTION 1.0 DEFINITIONS w
- 1. 0 DEFINITIONS The following terms are defined so that uniform interpreta~ tion of these specifications may be achieved. The defined terms appear in capitalized type and shall be applicable throughout these Technical Specifications.
ACTION 1.1 ACTION 37.311 be thct part of a Specification which prescribes remedial measures requirrd under designated conditions.
AVERAGE PLANAR EXPOSURE
- 1. 2 The AVERAGE PLANAR EXPOSURE shall be applicable to a specific planar height and is equal to the sum of the exposure of all the fuel rods in the specified bundle at the specified height divided by the number of fuel rods in the fuel bundle.
AVERAGE PLANAR LINEAR HEAT GENERATION RATE 1.3 The AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR) shall be applicable to a specific planar height and is equal to the sum of the LINEAR HEAT GENERATION RATES for all the fuel rods in the specified bundle at the specified height divided by the number of fuel rods in the fuel bundle.
CHANNEL CALIBRATION
- 1. 4 A CHANNEL CALIBRATION shall be the adjustment, as necessary, of the channel output such that it responds with the necessary range and accuracy to known values of the parameter which the channel monitors. The CHANNEL CALIBRATION shall encompass the entire channel including the sensor and alarm and/or trip functions, and shall include the CHANNEL FUNCTIONAL TEST. The CHANNEL CALIBRATION may be performed by any series of sequential, overlapping or total channel steps such that the entire channel is calibrated.
CHANNEL CHECK
- 1. 5 A CHANNEL CHECK shall be the qualitative assessment of channel behavior during operation by observation. This determination shall include, where possible, comparison of the channel indication and/or status with other indications and/or status derived from independent instrument channels measuring the same parameter.
CHANNEL FUNCTIONAL TEST
- 1. 6 A CHANNEL FUNCTIONAL TEST shall be:
- a. Analog channels - the injection of a simulated signal into the channel as close to the sensor as practicable to verify OPERASILITY including alarm and/or trip functions and channel failure trips.
- b. Bistable channels - the injection of a simulated signal into the sensor to verify OPERABILITY including alarm and/or trip functions.
The CHANNEL FUNCTIONAL TEST may be performed by any series of sequential, overlapping or total channel steps such that the entire channel is tested.
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drift .
DEFINITIONS JUN 2 81sg CORE ALTERATION
- 1. 7 CORE ALTERATION shall be the addition, removal, relocation or movement of
. fuel, sources, incore instruments or reactivity controls within the reactor pressure vessel with the vessel head removed and fuel in the "aesal. Normal movement 'of the SRMs, IRMs, Tips, or special movable detectors is not considered a CORE ALTERNATION. Suspension of CORE ALTERATIONS shall not preclude completion of the movement of a component to a safe conservative position.
CORE MAXIMUM FRACTION OF LIMITING POWER DENSITY
- 1. 8 The CORE MAXIMUM FRACTION OF LIMITING POWER DENSITY (CMFLPD) shall be highest value of the FLPD which exists in the core.
CRITICAL POWER RATIO
- 1. 9 The CRITICAL POWER RATIO (CPR) shall be the ratio of that power in the assembly which is calculated by application of the (GEXL) correlation to cause some point in the assembly to experience boiling transition, divided by the actual assembly operating power.
DOSE EQUIVALENT I-131 1.10 DOSE EQUIVALENT I-131 shall be that concentration of I-131, microcuries per 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 for Power and Test Reactor Sites."
E-AVERAGE DISINTEGRATION ENERGY 1.11 E shall be the average, weighted in proportion to the concentration of each racionuclide in the reactor coolant at the time of sampling, of the sum of the average beta and gamma energies per disintegration, in MeV, for isotopes, with half lives greater than 15 minutes, making up at least 95% of the total non-iodine activity in the coolant.
EMERGENCY CORE COOLING SYSTEM (ECCS) RESPONSE TIME-1.12 The EMERGENCY CORE COOLING SYSTEM (ECCS) RESPONSE TIME shall be that time l interval from when the monitored parameter exceeds its ECCS actuation set-point at the channel sensor until the ECCS 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 i include diesel generator starting and sequence loading delays where i
applicable. The response time may be measured by any series of sequential, overlapping or total steps such that the entire response time is measured.
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DRH DEFINITIONS
,4jN 2 8 1985 END-OF-CYCLE RECIRCULATION PUMP TRIP SYSTEM RESPONSE TIME 1.13 The END-OF-CYCLE RECIRCULATION PUMP TRIP SYSTEM RESPONSE TIME shall be that time interval to complete suppression of the electric arc between the fully oren contacts of the rer bcH etic, rump circuit breaker fecm initial movement of the associated:
- a. Turbina stop valves, and
- b. Turbine control valves.
The response time may be measured by any series of sequential, overlapping or total steps such that the entire response time is measured.
FRACTION-OF LIMITING POWER DENSITY 1.14 The FRACTION OF LIMITING POWER DENSITY (FLPD) shall be the LHGR existing at a given location divided by the specified LHGR limit for that bundle type.
FRACTION OF RATED THERMAL POWER 1.15 The FRACTION OF RATED THERMAL POWER (FRTP) shall be the measured THERMAL POWER divided by the RATED THERMAL POWER.
FREQUENCY NOTATION 1.16 The FREQUENCY NOTATION specified for the performance of Surveillance Requirements shall correspond to the intervals defined in Table 1.1.
IDENTIFIED LEAKAGE 1.17 IDENTIFIED LEAKAGE shall be:
- a. Leakage into collection systems, such as pump seal or valve packing leaks, that is captured and conducted to a sump or collecting tank, or
- b. Leakage into the containment atmosphere from sources that are both spe-cifically located and known either not to interfere with the operation of the leakage detection systems or not to be PRESSURE BOUNDARY LEAKAGE.
ISOLATION SYSTEM RESPONSE TIME 1.18 The ISOLATION SYSTEM RESPONSE TIME shall be that time interval from when the monitored parameter exceeds its isolation actuation setpoint at the channel sensor until the isolation valves travel to their required positions. Times shall include diesel generator starting and sequence loading delays where applicable. The response time may be measured by any series of sequential, overlapping or total steps such that the entire response time is measured.
LIMITING CONTROL R00 PATTERN 1.19 A LIMITING CONTROL ROD PATTERN shall be a pattern which results in the core being on a thermal hydraulic limit, i.e., operating on a limiting value for APLHGR, LHGR, or MCPR.
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JUN 2 E T:ss DEFINITIONS LINEAR HEAT GENERATION RAT 1.20 LINEAR length ofHEAT GENERATION RATE (LHGR) shall be the heat generation per unit fuel rod.
It is the integral of the heat flux over the heat transfer area associated with the unit length.
LOGIC SYSTEM FUNCTIONAL TEST -
1.21 A LOGIC SYSTEM FUNCTIONAL TcS shall be z. test of all logic components, i.e., all relays and contacts, all trip units, solid state logic elements, etc, of atologic device, verifycircuit, from sensor through and including the actuated OPERABILITY.
The LOGIC SYSTEM FUNCTIONAL TEST may be performed such that theby any entireseries logicofsystem sequential, overlapping or total system steps is tested.
MAXIMUM FRACTION OF LIMITING POWER DENSITY 1.22 The MAXIMUM FRACTION OF LIMITING POWER DENSITY (MFLPD) shall be highest value of the FLPD which exists in the core.
MEMBER (S) 0F THE PUBLIC 1.23 associated MEMBER (S) with0FtheTHE PUBLIC shall include all persons who are not occupationally plant.
the utility, it contractors orThis category does not include employees of 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 recre-ational, occupational or other purposes not associated with the plant.
MINIMUM CRITICAL POWER RATIO 1.24 The MINIMUM CRITICAL POWER RATIO (MCPR) shall be the smallest CPR whic exists in the core (for each class of fuel).
OFF-GAS TREATMENT SYSTEM 1.25 An 0FF-GAS TREATMENT SYSTEM is any system designed and installed to reduce radioactive gaseous effluents by collecting reactor coolant system offgases from the reactor coolant and providing for delay or holdup for the purpose of reducing the total radioactivity prior to release to the environment.
OFFSITE COSE CALCULATION MANUAL 1.26 The OFFISTE DOSE CALCULATION MANUAL (ODCM) shall contain the current method-ology and parameters used in the calculation of offsite doses due to radio-active gaseous and liquid effluents, in the calculation of gaseous and liquid effluent monitoring alarm / trip setpoints, and in the conduct of the radiological environmental monitoring program.
d s
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L DEFINITIONS M 0 OPERABLE - OPERABILITY 1.27 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 inste r tat 4 n, contrcls, electr cel 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).
OPERATIONAL CONDITION - CONDITION 1.28 An OPERATIONAL CONDITION, i.e., CONDITION, shall be any one inclusive combination of made switch position and average reactor coolant temperature as specified in Table 1.2.
PHYSICS TESTS 1.29 PHYSICS TESTS shall be those tests performed to measure the fundamental nuclear characteristics of the reactor core and related instrumentation and 1) described in Chapter 14 of the FSAR, 2) authorized under the provisions of 10 CFR 50.59, or 3) otherwise approved by the Commission.
PRESSURE BOUNDARY LEAKAGE 1.30 PRESSURE BOUNDARY LEAKAGE shall be leakage through a non-isolable fault in a reactor coolant system component body, pipe wall or vessel wall.
PRIMARY CONTAINMENT INTEGRITY 1.31 PRIMARY CONTAINMENT INTEGRITY shall exist when:
- a. All primary containment penetrations required to be closed during accident conditions are either:
- 1. Capable of being closed by an OPERABLE primary containment autcmatic isolation system, or
, 2. Closed by at least one manual valve, blind flange, or l deactivated automatic valve secured in its closed position, except as provided in Table 3.6.3-1 of Specification 3.6.3.
l l b. All primary containment equipment hatches are closed and sealed.
- c. Each primary containment air lock is in compliance with the i requirements of Specification 3.6.1.3.
-d. The primary containment leakage rates are within the limits of Specificati'an 3.6.1.2.
- e. The suppression chamber is in compliance with the requirements
} of Specification 3.6.2.1.
- f. The sealing mechanism associated with each primary containment penetration; e.g. , welds, bellows or 0-rings, is OPERABLE.
HOPE CREEK 1-5 i
DEFINITIONS
$N28 C PROCESS CONTROL PROGRAM 1.32 The PROCESS CONTROL PROGRAM (PCP) shall contain the provisions to assure that the SOLIDIFICATION or dewatering and packaging of radioactiva wastec resulL, in a wast.e package with properties that meet the minimum and stability requirements of 10 CFR Part 61 and other requirements for trans-portation to the disposal site and receiat at the disposal site. With SOLIDIFICATION, the PCP shall identify tne process parameters influencing SOLIDIFICATION such as pH, oil content,2H O content, solids content ratio j
of solidification agent to waste and/or necessary additives for each type of anticipated waste, and the acceptable boundary conditions for the process parameters shall be identified for each waste type, based on laboratory scale and full scale testing or experience. With dewatering, the PCP shall include an identification of conditions that must be satisfied, based on full scale testing, to assure that dewatering of bead resins, powdered resins, and filter sludges will result in volumes of free water, at the time of disposal, within the limits of 10 CFR Part 61 and of the low-level radioactive waste disposal site.
PURGE - PURGING 1.33 PURGE or PURGING shall be the controlled process of discharging air or gas
' from a confinement to maintain temperature, pressure, humidity, concentra-or other operating condition, in such manner that replacement air or 9 is required to purify the confinement.
- RATED THERMAL POWER
- 1.34 RATED THERMAL POWER shall be a total reactor core heat transfer rate to the reactor coolant of (3293) MWT.
REACTOR PROTECTION SYSTEM RESPONSE TIME 1.35 REACTOR PROTECTION SYSTEM RESPONSE TIME shall be the time interval frem when the monitored parameter exceeds its trip setpoint at the channel sensor until de energization of the scram pilot valve solenoids. The response time may be measured by any series of sequential, overlapping or total steps such that the entire response time is measured.
REPORTABLE EVENT 1.36 A REPORTABLE EVENT shall be any of those conditions specified in Section 50.73 tc 10 CFR Part 50.
R00 DENSITY 1.37 ROD DENSITY shall be the number of control rod notches inserted as a '
fraction of the total number of control rod notches. All rods fully inserted is equivalent to 100% R00 DENSITY.
HOPE CREEK 1-6
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hlb i DEFINITIONS yn 2 8 WB5 4 SECONDARY CONTAINMENT INTEGRITY 1.38 SECONDARY CONTAINMENT INTEGRITY shall exist when:
i a. Ali secanoary containment penetrations required to be closed during
, accident conditions are either:
- 1. Capable of being closed by an OPERABLE secondary containment automatic isolation system, or
- 2. Closed by at least one manual valve, blind flange, or deactivated automatic valve or damper, as applicable secured in its closed position, except as provided in Table 3.6.5.2-1 of Specification 3.6.5.2.
- b. All secondary containment hatches and blowout panels are closed and sealed.
, c. The standby gas treatment system is in coapliance with the requirements of Specification 3.6.5.3.
- d. For double door arrangements, at least one door in each access to the secondary containment is closed except for normal entry and exit.
- e. For single door arrangements, the door in each access to the secondary 4
containment is closed,
- f. The sealing mechanism associated with each secondary containment penetration, e.g., welds, bellows or 0-rings, is OPERABLE.
- g. The pressure within the secondary containment is less than or equal-to the value required by Specification 4.6.5.1.a.
SHUTDOWN MARGIN 1.39 SHUTDOWN MARGIN shall be the amount of reactivity by which the reactor is j
~ subcritical or would be subcritical assuming all control rods are fully inserted except for the single control rod of hignest reactivity worth I which is assumed to be fully withdrawn and the reacter is in the shutdown condition; cold, i.e. 68*F; and xenon free.
SITE BOUNDARY 1.40 The SITE BOUNDARY shall be that line beyond which the land is neither owned, nor leased, nor otherwise controlled, by the licensee.
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A b
DEFINITIONS M SOLIDIFICATION 1.41 SOLIDIFICATION shall be the immobilization of wet radioactive wastes such as evaporator bottoms snent resins, cledgas, and reveree osme is ccr.cen-trates as a result of a process of thoroughly mixing the water ~ type with a solidification agent (s) to form a free standing monolith with chemical and physical characteristics specified in the PROCESS CONTROL PROGRAM (PCP).
SOURCE CHECK 1.42 A SOURCE CHECK shall be the qualitative assessment of channel response when the channel sensor is exposed to a radioactive source.
STAGGERED TEST BASIS 1.43 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.
- b. The testing of one system, subsystem, train or other designated %
component at the beginning of each subinterval.
- THERMAL POWER
- 1.44 THERMAL POWER shall be the total reactor core heat transfer rate to the reactor coolant.
TOTAL PEAKING FACTOR 1.45 The TOTAL PEAKING FACTOR (TPF) shall be the ratio of local LHGR for any
( specific location on a fuel rod divided by the core average LHGR associ-I ated with the fuel bundles of the same type operating at the core average bundle power.
TURSINE BYPASS SYSTEM RESPONSE TIME 1.46 The TURBINE BYPASS SYSTEM RESPONSE TIME consists of two separate time intervals: a) time from initial movement of the main turbine stop valve or control valve until 80% of the turbine bypass capacity is established, and b) the time from initial movement of the main turbine stop valve or control valve until initial movement of the turbine bypass valve. Either response time may be measured by any series of sequential, overlapping, or total steps such that the entire response time is measured.
UNIDENTIFIED LEAKAGE 1.47 UNIDENTIFIED LEAKAGE shall be all leakage which is not IDENTIFIED LEAKAGE.
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DEFINITIONS JUN 2 81985 UNRESTRICTED AREA 1.48 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 protec' tien of individuals from exposure to raoiation and radioactive materials, or any area within the SITE BOUNDARY used for residential quarters or for indrntrial, commercial, institutional, and/or recreational purposes.
VENTILATION EXHAUST TREATMENT SYSTEM 1.49 A VENTILATION EXHAUST TREATMENT SYSTEM shall be any system designed and installed to reduce gaseous radiciodine or radioactive material in particu-late 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. Engineered Safety Feature (ESF) atmospheric cleanup systerr.s are not considered to be VENTILATION EXHAUST TREATMENT SYSTEM components.
VENTING 1.50 VENTING shall be the controlled process of discharging air or gas from a confinement to maintain temperature, pressure, hun idity, 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.
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=
J' C TABLE 1.1 SURVEILLANCE FRE0VENCY NOTATION g 3S $63 NOTATION FREQUENCY S At least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
O At ler.st once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
W At least once per 7 days.
M At least once per 31 days.
Q At least once per 92 days.
SA At least once per 184 days.
A At least once per 366 days.
R At least once per 18 months (550 days).
S/U Prior to each reactor startup.
N.A. Not applicable.
l 1
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0 l TABLE 1.2 OPERATIONAL CONDITIONS JUN 2 8 2 MODE SWITCH AVERAGE REACTOR CONDITION POSITION COOLANT TEMPERATURE
- 1. POWER OPERATION Run Any temperature
- 2. STARTUP Startup/ Hot Standby Any temperature
- 3. HOT SHUTOOWN Shutdown #'*** > 200 F
- 4. COLD SHUTDOWN Shutdown #'##'*** 1 200*F
- 5. REFUELING
- Shutdown or Refuel ***# 1 140*F
~
- The reactor mode switch may be placed in the Run or Startup/ Hot Standby position to test the switch interlock functions provided that the control rods are verified to remain fully inserted by a second licensed operator or other technically qualified member of the unit technical staff.
- The reactor mode switch may be placed in the Refuel position while a single control rod drive is being removed from the reactor pressure vessel per Specification 3.9.10.1.
- Fuel in the reactor vessel with the vessel head closure bolts less than fully tensioned or with the head removed.
- See Special Test Exceptions 3.10.1 and 3.10.3.
- The reactor mode switch may be placed in the Refuel position while a single control rod is being recoupled provided that the one-rod-out interlock is OPERABLE. ,
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j y 2 6 13'3 SECTION 2.0 SAFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGS
2.0 SAFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGS 2.1 SAFETY LIMITS THERMAL POWER, Low Pressure or Low Flow WUN 2 8 1985 2.1.1 THERMAL POWER shall not exceed 25% of RATED THERMAL POWER with the reactor vessel steam dome pressure less than 785 psig or core flow less than 10% of rated flow. APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. ACTION: With THERMAL POWER exceeding 25% of RATED THERMAL POWER and the reactor vessel steam dome pressure less than 785 psig or core flow less than 10% of rated flow, be in at least HOT SHUTDOWN within 2 hours and comply with the requirements of Specification 6.7.1. THERMAL POWER, High Pressure and High Flow 2.1.2 The MINIMUM CRITICAL POWER RATIO (MCPR) shall not be less than 1.06 with the reactor vessel steam dome pressure greater than 785 psig and core flow greater than 10% of rated flow. APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. ACTION: With MCPR less than 1.06 and the reactor vessel steam dome pressure greater than 785 psig and core flow greater than 10% of rated flow, be in at least HOT SHUTDOWN within 2 hours and comply with the requirements of Specification 6.7.1. REACTOR COOLANT SYSTEM PRESSURE l 2.1.3 The reactor coolant system pressure, as measured in the reactor vessel steam dome, shall not exceed 1325 psig.
- APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3 and 4.
ACTION: With the reactor coolant system pressure, as measured in the reactor vessel steam dome, above 1325 psig, be in at least HOT SHUTDOWN with , reactor coolant system pressure less than or equal to 1325 psig within 2 hours and comply with the requirements of Specification 6.7.1. HOPE CREEK 2-1 E
SAFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGS SAFETY LIMITS (Continued)
,ggypg g REACTOR VESSEL WATER LEVEL 2.1.4 The reactor vessel water level shall be above the top of the active irradiated foel.
APPLICABILITY: OPERATIONAL CONDITIONS 3, 4 and 5 ACTION: With the reactor vessel water level at or below the top of the active irradiated fuel, manually initiate the ECCS to restore the water level, after depressurizing the reactor vessel, if required. Comply with the requirements of Specification 6.7.1. e == l 1 l l i HOPE CREEK 2-2
SAFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGS 2.2 LIMITING SAFETY SYSTEM SETTINGS y 2 6 1985 REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS 2.2.1 The reactor protection system instrumentation setpoints shall be set consistent with the Trip Setpoint values shown in Table 2.2.1-1. APPLICABILITv- As shown in Table 3.3.1-1. ACTION: With a reactor protection system instrumentation setpoint less conservative than the value shown in the Allowable Values column of Table 2.2.1-1, declare the channel inoperable and apply the applicable ACTION statement requirement of Specification 3.3.1 until the channel is restored to OPERABLE status with its setpoint adjusted consistent with the Trip Setpoint value. HOPE CREEK 2-3
=c -TABLE 2.2.1-1 o " REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS 9a " ALLOWABLE
. m VALUES
- TRIP SETPOINT FUNCTIONAL UNIT 4
- 1. Intermediate Range Monitor, Neutron Flux-High 5 120/125 divisions 5 122/125 divisions-of full scale of full scale .
- 2. Average Power Range Monitor: ,
- a. Neutron Flux-Upscale, Setdown 5 15% of RATED THERMAL POWER 5 20% of RATED THERMAL POWER I b. Flow Biased Simulated Thermal Power-Upscale 5 0.66 W+51%, with 5 0.66 W+54%, with j 1) Flow Biased a maximum of a maximum of
- 2) High Flow Clamped 5 113.5% of RATED $ 115.5% of RATED THERMAL POWER THERMAL POWER ro I c. Fixed Neutron Flux-Upscale ~< 118% of RATED THERMAL POWER -< 120% of RATED THERMAL POWER NA NA
! d. Inoperative
- e. Downscale > 5% of RATED ~> 3% of RATED i THERMAL POWER THERMAL POWER l
I Reactor Vessel Steam Dome Pressure - High 5 1037 psig 5 1057 psig i 3. Reactor Vessel Water Level - Low, Level 3 ~> 12.5 inches above instrument > 11.0 inches above
- 4. instrument zero
' zero* i
- 5. Main Steam Line Isolation Valve - Closure 5 8% closed 5 12% closed j
; 6. Main Steam Line Radiation - High 5 3.0 x full power background 5 (3.6) x full power background i
l *See Bases Figure B 3/4 3-1. hd Cl "1CI ro CO % Y
= l
TABLE 2.2.1-1 x
- REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS (continued) y ALLOWABLE m
- VALUES TRIP SETPOINT FUNCTIONAL UNIT 5 (1.68) psig < (1.88) psig
- 7. (Primary Containment) (Drywell) Pressure - High
- 8. Scram Discharge Volume Water Level - High 5 (36)% of full scale $ (39)% of full scale
- a. Float Switch
$ (36)% of full scale 5 (39)% of full scale
- b. Level Transmitter 5 5% closed $ 7% closed
- 9. Turbine Stop Valve - Closure
- 10. Turbine Control Valve Fast Closure, 1 465 psig Trip Oil Pressure - Low 1 530 psig NA NA
- 11. Reactor Mode Switch Shutdown Position NA NA
- 12. Manual Scram 00 u,
"""***ff' '-
i' l{} { . _ - _ _ - _ _ - _ _ -
.)UN 2 8 1985 BASES FOR SECTION 2.0 s SAFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGS m
4 s
JUN 2 8 1985 1 NOTE The BASES contained in succeeding pages summarize the reasons for the Specifications in Section 2.0, but in accordance with 10 CFR 50.36 are not part of these Technical Specifications. O
$ 2.1 SAFETY LIMITS
.!DN 2 8 1m BASES
2.0 INTRODUCTION
The fuel cladding, reactor pressure vessel and primary system piping are the principal barriers to the release of radic.ictive materials to the environs. Safety Limits are established to protec the integrity of these barriers during normal plant operations and anticipated transients. The fuel cladding integrity Safety Limit is set such that no fuel damage is calculated to occur if the limit is not violated. Because fuel damage is not directly observable, a step-back approach is used to establish a Safety Limit such that the MCPR is not less than 1.06. MCPR greater than 1.06 represents a con-servative margin relative to the conditions required to maintain fuel cladding integrity. The fuel cladding is one of the physical barriers which separate the radioactive materials from the environs. The integrity of this cladding barrier is related to its relative freedom from perforations or cracking. Although some corrosion or use related cracking may occur during the life of the cladding, fission product migration from this source is incrementally cumulative and continuously measurable. Fuel cladding perforations, however, can result from thermal stresses which occur from reactor operation signifi-cantly above design conditions and the Limiting Safety System Settings. While fission product migration from cladding perforation is just as measurable as that from use related cracking, the thermally caused cladding perforations signal a threshold beyond which still greater thermal stresses may cause gross rather than incremental cladding deterioration. Therefore, the fuel cladding Safety Limit is defined with a margin to the conditions which would produce onset of transition boiling, MCPR of 1.0. These conditions represent a signi-ficant departure from the condition intended by design for planned operation. 2.1.1 THERMAL POWER, Low Pressure or Low Flow The use of the GEXL correlation is not valid for all critical power calculations at pressures below 785 psig or core flows less than 10% of rated flow. Therefore, the fuel cladding integrity Safety Limit is established by
- other means. This is done by establishing a limiting condition on core THERMAL POWER with the following basis. Since the pressure drop in the bypass region is essentially all elevation head, the core pressure drop at low power and flows will always be greater than 4.5 psi. Analyses show that with a bundle flow of 28 x 103 lbs/hr, bundle pressure drop is nearly independent of bundle
- power and has a value of 3.5 psi. Thus, the bundle flow with a 4.5 psi driving i head will be greater than 28 x 103 lbs/hr. Full scale ATLAS test data taken i at pressure; from 14.7 psia to 800 psia indicate that the fuel assembly criti- '
cal power at this flow is approximately 3.35 MWt. With the design peaking I factors, this corresponds to a THERMAL POWER of more than 50% of RATED THERMAL , POWER. Tr.M , a THERMAL POWER limit of 25% of RATED THERMAL POWER for reactor j pressure lislow 785 psig is conservative. i l HOPE CREEK B 2-1 l
i
,' r -
~
SAFETY LIMITS ,e - JUN 2 8 1985 .
/
BASES l l 2.1._2 THERMAL, POWER, High Pressure and High Flow ThefuelcladdingintegritySafetyLimitissNtsuchthatno(mechanistic) a fuel damage is calculated to or. cur if the limit istnot violated. Si.m the parameters which result in fuel damage are not directly observable during reac-tor operation, the thermal and hydraulic conditions resulting in a departure - I from nucleate boiling have been used to mark the beginr.ing of the region where fuel damage could occur. . Although it is recognized that a departure from 'o nucleate boiling would not necessarily result in damage to BWR fuel rods, the
- critical power at which boiling transition is calculated to occur has been
- adopted as a convenient limit. However, the unce*ttinties in monitoring the core operating state and in the procedures used to calculate the critical power f*
result in an uncertainty in the value of the critical power. Thecefore, the fuel cladding integrity Safety Limit is defined as the CPR in the;1imiting fuel ! assembly for which.more than 99.9% of the fuel rods in the core are expected f to avoid boiling transition considering the power distribution within the core , - t and all uncertaintiel. y N o ", , The Safety Limit aMCPR is determined using the General Electric Thermal * . Analysis Basis, GETAB , wnich is a statistical,model that combines all of the [ uncertainties in operating parameters and the procedures used to calculate y [ critical power. The probability of the, occurrence of boiling transition is t'
~/-
determined using the General Electric Critical Quality (X) Boiling Length (L), . (GEXL), correlation. , y-The GEXL correlat. ion is valid ove'. the range of conditions used in the tests of the data used to develop the correlation. j kl The required input to the statisk.ical model are the uncertainties listed in Bases Table 82.1.2-1 and the nominal values of the core parameters listed in Bases Table B2.1.2-2. / The bases for the uncertainties in the core parameters are given in D NE00-20340 and the basis for the uncerpainty in the GEXL correlation is given
~
a in NE00-10958-A . The power distribution is based on a typical 764 assembly core in which the rod pattern was arbitrarily chosen to produce a skewed power t distribution having the greatest number of assemblies at the highest power levels. The worst dist-foution during any fuel cycle would not be as severe as the distribution used in the analysis. <
- a. ." General Electric BWR T d nal Analy is;3ases (GETAB) Data, Correlation and '
Design Application," NE00,r10958-A. ,
- b. General Electric " Process' Computer IVrformance Evaluation Accuracy" NE00-20340 and Amendment I, NE00-20340-1 dated June 1974 and Decemeer 1974, respectively. ;
HOPE CREEK B 2-2 i e
-i s Bases Table 82.1.2-1 UNCERTAINTIES USED IN THE DETERMINATION 2 8 *$
0F THE FUEL CLADDING SAFETY LIMIT *
~
Pand: d - Deviation h Quantity (% of Point) e Feedwater Flow 1.76 . Feedwater Temperature 0.76 Reactor Pressure 0.5 Core Inlet Temperature 0.2 Core Total Flow 2.5 c-
- p. Channel Flow Area 3.0 Friction Eactor Multiplier 10.0 Channel Friction Factor Multiplier 5.0 TIP Readings 6.3 ,
1 R Factor 1.5 Critical Power 3.6
~
I' - ^ The uncertainty analysis used to establish the core wide Safety Limit MCPR is based on the assumption of quadrant power symmetry for the reactor core. HOPE CREEK B 2-3
Bases Table B2.1.2-2 NOMINAL VALUES OF PARAMETERS USED IN LR#i 2 8 $6-THE STATISTICAL ANALYSIS OF FUEL CLADDING INTEGRITY SAFETY LIMIT THERMAL. POWER 3323 MW Core Flow 108.5 Mlb/hr Dome Pressure 1010.4 psig Channel Flow Area 0.1089 ft2 R-Factor High enrichment - 1.043 Medium enrichment - 1.039 Low enrichment - 1.030 0 I
~
HOPE CREEK B 2-4
SAFETY LIMITS JUN 2 8 1985 BASES 2.1.3 REACTOR COOLANT SYSTEM PRESSURE ine safety Limit for the reactor coolant system pressure has been selected of the that such system it isisatnot a pressure below which it can be shown that the integrity endangered. The reacter pressure vessel is designed to Section III of the ASME Boiler and Pressure Vessel Code 1968 Edition, including e Addenda through Winter 1969, which permits a maximum pressure transient of 110%, 1375 psig, of design pressure 1250 psig. The Safety Limit of 1325 psig, as measured by the reactor vessel steam dome pressure indicator, is equivalent to 1375 psig at the lowest elevation of the reactor coolant system. The reactor coolant system is designed to the USAS Nuclear Power Piping Code, Section B31.7 1969 Edition, including Addenda through July 1, 1970 for the reactor recirculation piping, which permits a maximum pressure transient of 110%, 1375 psig, of design pressure, 1250 psig for suction piping and 1500 psig for discharge piping. The pressure Safety Limit is selected to be the lowest transient overpressure allowed by the applicable codes. 2.1.4 REACTOR VESSEL WATER LEVEL With fuel in the reactor vessel during periods when the reactor is shutdown, consideration must be given to water level requirements due to the effect of decay heat. If the water level should drop below the top of the active reduced. irradiated fuel during this period, the ability to remove decay heat is This reduction in cooling capability could lead to elevated cladding temperatures and clad perforation in the event that the water level became less than two-thirds of the core height. The Safety Limit has been established at the top of the active irradiated fuel to provide a point which can be monitored and also provide adequate margin for effective action. sp, HOPE CREEK B 2-5
2.2 LIMITING SAFETY SYSTEM SETTINGS
@ 2 6 17 BASES 2.2.1 0 FACTOR DROTECTION SYSTEM INSTRUMENTATION SETOOTNTS The Reactor Protection System instrumentation setpoints macified in Table 2.2.1-1 are the values at which the reactor trips are set for each para-meter. The Trip Setpoints have been selected to ensure that the reactor core and reactor coolant system are prevented from exceeding their Safety Limits during normal operation and design basis anticipated operational occurrences and to assist in mitigating the consequences of accidents. Operation with a trip set less conservative than its Trip Setpoint out within its specified Allowable Value is acceptable on the basis that the difference between each Trip Setpoint and the Allowable Value is equal to or less than the drift allowance assumed for each trip in the safety analyses.
- 1. Intermediate Range Monitor, Neutron Flux - High The IRM system consists of 8 chambers, 4 in each of the reactor trip systems. The IRM is a 5 decade 10 range instrument. The trip setpoint of 120 divisions of scale is active in each of the 10 ranges. Thus as the IRM is ranged up to accommodate the increase in power level, the trip setpoint is also ranged up. The IRM instruments provide for overlap with both the APRM and SRM systems.
The most significant source of reactivity changes during the power increase is due to control rod withdrawal. In order to ensure that the IRM provides the required protection, a range of rod withdrawal accidents have been analyzed. The results of these analyses are in Section 15.4 of the FSAR. The most severe case involves an initial condition in which THERMAL POWER is at approximately 1% of RATED THERMAL POWER. Additional conserva-tism was taken in this analysis by assuming the IRM channel closest to the control rod being withdrawn is bypassed. The results of this analysis shcw l that the reactor is shutdown and peak power is limited to (21)% of RATED THERMAL POWER with the peak fuel enthalpy well below the fuel failure thres-hold of 170 cal /gm. Based on this analysis, the IRM provides protection against local control rod errors and continuous withdrawal of control rods in sequence and provides backup protection for the APRM.
- 2. Average Power Range Monitor For operation at low pressure and low flow during STARTUP, the APRM scram setting of 15% of RATED THERMAL POWER provides acequate thermal margin between the setpoint and the Safety Limits. The margin accommodates the anticipated maneuvers associated with power plant startup. Effects of increasing pressure at zero or low void content are minor and cold water from sources available during startup is not much colder than that already in the system. Tempera-ture coefficients are small and control rod patterns are constrained by the RSCS and RW. Of all the possible sources of reactivity input, uniform con-i i
trol rod withdrawal is the most probable cause of significant power increase. l l , HOPE CREEK B 2-6 l
LIMITING SAFETY SYSTEM SETTINGS i s JW 2 8 Se5 BASES REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS (ContinueO Average Power Range Monitor (Continued) Because the flux distribution associated with unifonn rod withdrawals does not involve high local peaks and because several rods must be moved to change power by a significant amount, the rate of power rise is very slow. Generally the heat flux is in near equilibrium with the fission rate. In an assumed uniform rod withdrawal approach to the trip level, the rate of power rise is not more than 5% of RATED THERMAL POWER per minute and the APRM system would be more than adequate to assure shutdown before the power could exceed the Safety Limit. The 15% neutron flux trip remains active until the mode switch is placed in the Run position. The APRM trip system is calibrated using heat balance data taken during steady state conditions. Fission chambers provide the basic input to the system and therefore the monitors respond directly and quickly to changes due to transient operation for the case of the Fixed Neutron Flux-Upscale set-point; i.e, for a power increase, the THERMAL POWER of the fuel will be less than that indicated by the neutron flux due to the time constants of the heat transfer associated with the fuel. For the Flow Biased Simulated Thermal Power-Upscale setpoint, a time constant of 6 0.6 seconds is introduced into the flow biased APRM in order to simulate the fuel thermal transient characteristics, A more conservative maximum value is used for the flow biased setpoint as shown in Table 2.2.1-1. The APRM setpoints were selected to provide adequate margin for the Safety Limits and yet allow operating margin that reduces the possibility of unneces-sary shutdown. The flow referenced trip setpoint must be adjusted by the specified formula in Specification 3.2.2 in order to maintain these margins when MFLPD is greater than or equal to FRTP.
- 3. Reactor Vessel Steam Dome Pressure-High High pressure in the nuclear system could cause a rupture to the nuclear system process barrier resulting in the release of fission products. A pressure increase while operating will also tend to increase the power of the reactor by compressing voids thus adding reactivity. The trip will quickly reduce the neutron flux, counteracting the pressure increase. The trip setting is slightly higher than the operating pressure to permit normal operation without spurious trips. The setting provides for a wide margin to the maximum allowable design pressure and takes into account the location of the pressure measurement compared to the highest pressure that occurs in the system during a transient. This trip setpoint is effective at low power / flow conditions when the turbine control valve fast closure and turbine stop valve closure trip are bypassed. For a load rejection or turbine trip under these conditions, the transient analysis indicated an adequate margin to the thermal hydraulic limit.
HOPE CREEK B 2-7
LIMITING SAFETY SYSTEM SETTINGS L N 2 8 1985 BASES REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS (Continued)
- 4. Reactor Vessel Water Level-Low The reactor vessel water level trip setpoint has been used in transient analyses dealing with coolant inventory decrease. The scram setting was chosen far enough below the normal operating level to avoid spurious trips but high enough above the fuel to assure that there is adequate protection for the fuel and pressure limits.
- 5. Main Steam Line Isolation Valve-Closure The main steam line isolation valve closure trip was provided to limit the amount of fission product release for certain postulated events. The MSIV's are closed automatically from measured parameters such as high steam flow, high steam line radiation, low reactor water level, high steam tunnel temperature, and low steam line pressure. The MSIV's closure scram anticipates the pressure and flux transients which could follow MSIV closure and thereby protects reactor vessel pressure and fuel thermal / hydraulic Safety Limits.
- 6. Main Steam Line Radiation-High The main steam line radiation detectors are provided to detect a gross failure of the fuel cladding. When the high radiation is detected, a trip is initiated to reduce the continued failure of fuel cladding. At the same time the main steam line isolation valves are closed to limit the release of fission products. The trip setting is high enough above background radiation levels to prevent spurious trips yet low enough to promptly detect gross failures in the fuel cladding.
- 7. Primary Containment Pressure-High High pressure in the drywell could indicate a break in the primary pressure boundary systems or a loss of drywell cooling. The reactor is tripped in order to minimize the possibility of fuel damage and reduce the amount of energy being added to the coolant and the primary containment. The trip setting was selected as low as possible without causing spurious trips.
- 8. Scram Discharge Volume Water Level-High The scram discharge volume receives the water displaced by the motion of the control rod drive pistons during a reactor scram.~ Should this volume fill up to a point where there is insufficient volume to accept the displaced water at pressures below 65 psig, control rod insertion would be hindered. The reac- -
. tor is therefore tripoed when the water level has reached a point high enough to indicate that it is indeed filling up, but the volume is still great enough to accommodate the water from the movement of the rods at pressures below 65 psig when they are tripped. The trip setpoint for each scram discharge volume is equivalent to a contained volume of 35 gallons of water. HOPE CREEK B 2-8
LIMITING SAFETY SYSTEM SETTING DRAE g gg BASES REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS (Continued) .. Turbi% Stoa Valve-Closure The turbine stop valve closus. trip 2riticipates the pressure, neutron flux, and heat flux increases that would result from closure of the stop valves. With a trip setting of (5)% of valve closure from full open, the resultant increase in heat flux is such that adequate thermal margins are maintained during the worst case transient.
- 10. Turbine Control Valve Fast Closure, Trip Oil Pressure-Low The turbine control valve fast closure trip anticipates the pressure, neutron flux, and heat flux increase that could result from fast closure of the turbine control valves due to load rejection with or without coincident with failure of the turbine bypass valves. The Reactor Protection System initiates a trip when fast closure of the control valves is initiated by the fast acting solenoid valves and in less than 30 milliseconds after the. start of control valve fast closure. This is achieved by the action of the fast acting solenoid valves in rapidly reducing hydraulic trip oil pressure at the main turbine control valve actuator disc dump valves. This loss of pressure is sensed by pressure switches whose contacts form the one-out-of-two-twice logic input to the Reactor Protection System. This trip setting, a slower closure time, and a different valve characteristic from that of the turbine stop valve, combine to prcduce transients whicn are very similar to that for the stop valve. Relevant transient analyses are discussed in Section 15.2.2 of the Final Safety Analysis Report.
- 11. Reactor Mode Switch Shutdown Position The reactor mode switch Shutdown position is a redundant channel to the automatic protective instrumentation channels and provides additional manual reactor trip capability.
- 12. Manual Scram The Manual Scram is a redundant channel to the automatic protective instrumentation channels and provides manual reactor trip capability.
HOPE CREEK B 2-9
\s '
WN 2 8 1985 SECTIONS 3.0 and 4.0 LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS
3/4.0 APPLICABILITY
=
JUN 2 8 1985 LIMITING CONDITION FOR OPERATION 3.0.1 Compliance with the Limiting Conditions for Operation contained in the l' 3%c.e6cing Specifications is requirea d .-i. ; tii= OPERAT!OMAL CCNG;T GlE or ,ther conditions specified therein; except that upon failure to meet the Limiting i Cw.ditions for Operation, the associated ACTION requirements shall be met. 3.0.2 Noncompliance with a Specification shall exist when the requirements of . the Limiting Condition for Operation and associated ACTION requirements are not met within the specified time intervals. If the Limiting Condition for Operation is restored prior to expiration of the specified time intervals, completion of the Action requirements is not required. 3.0.3 When a Limiting Condition for Operation is not met, except as provided in the associated ACTION requirements, within one hour action shall be initi-ated to place the unit in %n OPERATIONAL CONDITION in which the Specification does not apply by placing it, as applicable, in:
- 1. At least STARTUP within the next 6 hours,
- 2. At least HOT SHUTDOWN within the following 6 hours, and
- 3. At least COLD SHUTDOWN within the subsequent 24 hours. "
Where corrective measures are completed that permit operation under the ACTION. requirements, the ACTION may be taken in accordance with the specified time limits as measured from the time of failure to meet the Limiting Condition for Operation. Exceptions to these requirements are stated in the individual Specifications. This Specification is not applicable in OPERATIONAL CONDITIONS 4 or 5. 3.0.4 Entry into an OPERATIONAL CONDITION or other specified condition shall not be made unless the conditions for the Limiting Condition for Operation are met without reliance on provisions contained in the ACTION requirements. This provision shdll not prevent passage through or to OPERATIONAL CONDITIONS as required to comply with ACTION requirements. Exceptions to these requirements are stated in the individual Specifications. HOPE CREEK 3/4 0-1
APPLICABILITY JUN 2 8 1985 l SURVEILLANCE RE0VIREMENTS I J
- 4. 0.1 Surveillance Requirements shall be met during the OPERATIONAL CONDITIONS or vuwe wonditions specified for individual Limii.lng Cunditions for Operation unless otherwise stated in an individual Surveillance Requirement. (
4.0.2 Each Surveillance Requirement shall be performed within the spacified time interval with:
- a. A maximum allowable extension not to exceed 25% of the surveillance interval, but
- b. The combined time interval for any 3 consecutive surveillance inter-vals shall not exceed 3.25 times the specified surveillance interval.
4.0.3 Failure to perform a Surveillance Requirement within the specified time interval shall constitute a failure to meet the OPERABILITY requirements for a Limiting Condition for Operation. Exceptions to these requirements are stated in the individual Specificatons. Surveillance requirements do not have to be performed on inoperable equipment. 4.0.4 Entry into an OPERATIONAL CONDITION or other specified applicable condi-tion shall not be made unless the Surveillance Requirement (s) associated with the Limiting Condition for Operation have been performed within the applicable surveillance interval or as otherwise specified. 4.0.5 Surveillanca Requirements for inservice inspection and testing of ASME Code Class 1, 2, & 3 components shall be applicable as follows:
- a. Inservice inspection of ASME Code Class 1, 2, and 3 components and inservice testing of ASME Code Class 1, 2, and 3 pumps and valves shall be performed in accordance with Section XI of the ASME Boiler and Pressure Vessel Code and applicable Addenda as required by 10 CFR 50, Section 50.55a(g), except where specific written relief has been granted by the Commission pursuant to 10 CFR 50, Section 50.55a(g)
(6) (i).
- b. Surveillance . intervals specified in Section XI of the ASME Boiler and Pressure Vessel Code and applicable Addenda for the inservice inspection and testing activities required by the ASME Boiler and Pressure Vessel Code and applicable Addenda shall be applicable as follows in these Technical Specifications:
ASME Boiler and Pressure Vessel Required frequencies Code and applicable Addenda for performing inservice terminology for inservice inspection and testing insoection and testina activities activities Weekly At least once per 7 days Monthly At least once per 31 days Quarterly or every 3 months At least once per 92 days > Semiannually or every 6 months At least once per 184 days Every 9 months At least once per 276 cays Yearly or annually At least once per 366 days HOPE CREEK 3/4 0-2
APPLICABILITY JUN 2 8 tcP SURVEILLANCE REQUIREMENTS (Continued)
- c. The provisions of Specification 4.0.2 are applicable to the above required frequencies for performing inservice inspection and testing activities,
- d. Performance of the doovt. 'nstervice inspection and testing activities shall be in addition to other specified Surveillance Requirements.
- e. Nothing in the ASME Boiler and Pressure Vessel Code shall be con-strued to supersede the requirements of any Technical Specification.
3 HOPE CREEK 3/4 0-3
-1
3/4.1 REACTIVITY CONTROL SYSTEMS 3/4.1.1 SHUTDOWN MARGIN JUN 2 8 1985 LIMITING CONDITION FOR OPERATION 3.1.1 The SHUTDOWN MARGIN shall be equal to or greater than:
- a. 0.38% delta k/k with the highest worth rod analytically determined, or
- b. 0.28% delta k/k with the highest worth rod determined by test.
APPLICA8ILITY: OPERATIONAL CONDITIONS 1, 2, 3, 4 and 5. ACTION: With the SHUTDOWN MARGIN less than specified:
- a. In OPERATIONAL CONDITION 1 or 2, reestablish the required SHUTDOWN MARGIN within 6 hours or be in at least HOT SHUTDOWN within the next 12 hours,
- b. In OPERATIONAL CONDITION 3 or 4, immediately verify all insertable control rods to be inserted and suspend all activities that could reduce the SHUTDOWN MARGIN. In OPERATIONAL CONDITION 4, establish SECONDARY CONTAINMENT INTEGRITY within 8 hours.
- c. In OPERATIONAL CONDITION 5, suspend CORE ALTERATIONS and other activities that could reduce the SHUTDOWN MARGIN and insert all insertable control rods within 1 hour. Establish SECONDARY CONTAIN-MENT INTEGRITY within 8 hours.
SURVEILLANCE REOUIREMENTS 4.1.1 The SHUTDOWN MARGIN shall be determined to be equal to or greater than specified at any time during the fuel cycle:
- a. By measurement, prior to or during the first startup after each refueling.
- b. By measurement, within 500 MWD /T prior to the core average exposure at which the predicted SHUTDOWN MARGIN, including uncertainties and calculation biases, is equal to the specified limit.
- c. Within 12 hours after detection of a withdrawn control rod that is immovable, as a result of excessive friction or mechanical inter-ference,.or is untrippable, except that the above required SHUTDOWN MARGIN'shall be verified acceptable with an increased allowance for the withdrawn worth of the immovable or untrippable control rod.
HOPE CREEK 3/4 1-1
REACTIVITY CONTROL SYSTEMS 3/4.1.2 REACTIVITY ANOMALIES
.R!N 2 8 E85 LIMITING CONDITION FOR OPERATION 3.1.2 The reactivity equivalence of the difference between the actual R00 DENSITY and the predicted ROD DENSITY shall not exceed 1% delta k/k.
APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. ACTION: With the reactivity equivalence difference exceeding 1% delta k/k:
- a. Within 12 hours perform an analysis to determine and explain the cause of the reactivity difference; operation may continue if the difference is explained and corrected.
- b. Otherwise, be in at least HOT SHUTOOWN within the next 12 hours.
SURVEILLANCE REQUIREMENTS 4.1.2 The reactivity equivalence of the difference between the actual ROD DENSITY and the predicted R0D DENSITY shall be verified to be less than or equal to 1% delta k/k:
- a. During the first startup following CORE ALTERATIONS, and
- b. At least once per 31 effective full power days during POWER OPERATION.
I O HOPE CREEK 3/4 1-2
REACTIVITY CONTROL SYSTEMS 3/4.1.3 CONTROL RODS CONTROL ROD OPERABILITY LIMITING CONDITION FOR OPERATION -. 3.1.3.1 All control rods shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. ACTION:
- a. With one control rod inoperable due to being immovable, as a result of excessive friction or mechanical interference, or known to be untrippable:
- 1. Within one hour:
a) Verify that the inoperable control rod, if withdrawn, is separated from all other inoperable control rods by at least two control cells in all directions. b) Disarm the associated directional control valves ** either:
- 1) Electrically, or
- 2) Hydraulically by closing the drive water and exhaust water isolation valves.
Otherwise, be in at least HOT SHUTDOWN within the next 12 hours.
- 2. Restore the inoperable control rod to OPERABLE status within 48 hours or be in at least HOT SHUTOOWN within the next 12 hours.
- b. With one or more control rods trippable but inoperable for causes other than addressed in ACTION a, above:
- 1. If the inoperable control rod (s) is withdrawn, within one hour:
a) Verify that the inoperable withdrawn control rod (s) is separated from all other inoperable withdrawn control rods by at least two control cells in all directions, and b) Demonstrate the insertion capability of the inoperable withdrawn control rod (s) by inserting the control rod (s) at least one notch by drive water pressure within the normal operating range *. Otherwise, insert the inoperable withdrawn control rod (s) and disarm the associated directional control valves ** either: a) Electrically, or b) Hydraulically by closing the drive water and exhaust water isolation valves.
*The inoperable control rod may then be withdrawn to a position no further
withdrawn than its position when found to be inoperable.
- May be rearmed intermittently, under administrative control, to permit testing associated with restoring the control rod to OPERABLE status.
HOPE CREEK 3/4 1-3
REACTIVITY CONTROL SYSTEMS Zs]N 2 8 W~ LIMITING CONDITION FOR OPERATION (Continued) ACTION (Continued) .
- 2. If the inoperable control rod (s) is inserted, within one hour disarm the associated directional control valves ** either:
a) Electrically, or b) Hydraulically by closing the drive water and exhaust water isolation valves. Otherwise, be in at least HOT SHUTDOWN within the next 12 hours.
- 3. The provisions of Specification 3.0.4 are not applicable.
s
- c. With more than 8 control rods inoperable, be in at least HOT SHUTDOWN within 12 hours.
- d. With one scram discharge volume vent valve and/or one scram discharge volume drain valve inoperable and open, restore the inoperable valve (s) ~~
to OPERABLE status within 24 hours or be in at least HOT SHUTDOWN within the next 12 hours. .
- e. With any scram discharge volume vent valve (s) and/or any scram discharge volume drain valve (s) otherwise inoperable, restore the inoperable valve (s) to OPERABLE status within 8 hours or be in at least HOT SHUTDOWN within the next 12 hours.
SURVEILLANCE REOUIREMENTS 4.1.3.1.1 The scram discharge volume drain and vent valves shall be demonstrated OPERABLE by:
- a. At least once per 24 hours verifying each valve to be open,* and
- b. At least once per 31 days cycling each valve through at least one complete cycle of full travel.
4.1.3.1.2 When above the low power setpoint of the RhN and RSCS, all withdrawn control rods not required to have their directional control valves disarmed
*These valves may be closed intermittently for testing under administrative controls. > **May be rearmed intermittently, under administrative control, to permit j testing associated with restoring the control rod to OPERABLE status.
HOPE CREEK 3/4 1-4 l
REACTIVITY CONTROL SYSTEMS ( SURVEILLANCE REOUIREMENTS (Continued) JUN 8 585 electrically or hydraulically shall be demonstrated OPERABLE by moving each control rod at least one notch:
- a. At least once per 7 days, and
- b. At least once per 24 hours when any control rod is immovable as a result of excessive friction or mechanical interference.
4.1.3.1.3 All control rods shall be demonstrated OPERABLE by performance of Surveillance Requirements 4.1.3.2, 4.1.3.4, 4.1.3.5, 4.1.3.6 and 4.1.3.7. 4.1.3.1.4 The scram discharge volume shall be determined OPERABLE by demonstrating:
.a. The scram discharge volume drain and vent valves OPERABLE, when control rods are scram tested from a normal control rod configuration of less than or equal to 50% R00 DENSITY at least once per 18 months, by verifying that the drain and vent valves:
- 1. Close within 30 seconds after receipt of a signal for control rods to scram, and
- 2. Open when the scram signal is reset.
- b. Proper float response by verification of proper float switch actua-tion within 72 hours after each scram from a pressurized conditions great'er than or equal to 900 psig.
- The provisions of Specification 4.0.4 are not applicable for entry into CPERATIONAL CONDITION 2 provided the surveillance is performed within 12 hours af ter achieving less than or equal to 50% R00 DENSITY.
HOPE CREEK 3/4 1-5
$ REACTIVITY CONTROL SYSTEMS CONTROL ROD MAXIMUM SCRAM INSERTION TIMES 4'N 2 8 }cy . LIMITING CONDITION FOR OPERATION 3.1.3.2 The maximum scram insertion time of each control rod from the fully withdrawn position to notch position 5, based on de-energizatinn of the scra.n pilot valve solenoids as time zero, shall not exceed 7.0 seconds.
APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. ACTION:
- a. With the maximum scram insertion time of one or more control rods exceeding 7 seconds:
- 1. Declare the control rod (s) with the slow insertion time inoperable, and
- 2. Perform the Surveillance Requirements of Specification 4.1.3.2.c at least once per 60 days when operation is continued with three or more control rods with maximum scram insertien times in excess of 7.0 seconds.
Otherwise, be in at least HOT SHUTDOWN within 12 hours.
- b. The provisions of Specification 3.0.4 are not applicable.
SURVEILLANCE REQUIREMENTS 4.1.3.2 The maximum scram insertion time of the control rods shall be demon-strated through measurement with reactor coolant pressure greater than or equal to 950 psig and, during single control rod scram time tests, the control rod drive pumps isolated from the accumulators:
- a. For all control rods prior to THERMAL POWER exceeding 40% of RATED
! THERMAL POWER following CORE ALTERATIONS
- or after a reactor shutdown that is greater than 120 days.
- b. For specifically affected individual control rods following l
maintenance on or modification to the control rod or control rod drive system which could affect the scram insertion time of those specific control rods, and
- c. For at least 10% of the control rods, on a rotating basis, at least once per 120 days of POWER OPERATION.
( HOPE CREEK 3/4 1-6 l l
REACTIVITY CONTROL SYSTEMS CONTROL R0D AVERAGE SCRAM INSERTION TIMES JUN 28 ngg LIMITING CONDITION FOR OPERATION 3.1.3.3 The average scram insertion time of all OPERABLE control rods from the fully withdrawn position, based on de-anergization of the scram pilot valve solenoids as time zero, shall not exceed any of the following: Position Inserted From Average Scram Inser-Fully Withdrawn tion Time (Seconds) 45 0.43 39 0.86 25 1.93 05 3.49 APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. ACTION: With the average scram insertion time exceeding any of the above limits, be in at least HOT SHUTDOWN within 12 hours. SURVEILLANCE REOUIREMENTS 4.1.3.3 All control rods shall be demonstrated OPERABLE by scram time testing from the fully withdrawn position as required by Surveillance Requirement 4.1.3.2. HOPE CREEK 3/4 1-7
REACTIVITY CONTROL SYSTEMS FOUR CONTROL ROD GROUP SCRAM INSERTION TIMES JUN 2 8 1985 LIMITING CONDITION FOR OPERATION 3.1.3.4 The average scram insertion time, from the fully withdrawn position, for the three fastest control rods in each group of four control rods arranged in a two-by-two array, based on deenergization of the scram pilot valve solenoids as time zero, shall not exceed any of the following: Position Inserted From Average Scram Inser-Fully Withdrawn tion Time (Seconds) 45 0.43 39 0.86 25 1.93 5 3.49 APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. ACTION:
- a. With the average scram insertion times of control rods exceeding the above limits:
- 1. Declare the control rods with the slower than average scram insertion times inoperable until an analysis is performed to determine that required scram reactivity remains for the slow four control rod group, and
- 2. Perform the Surveillance Requirements of Specification 4.1.3.2.c at least once per 60 days when operation is continued with an average scram insertion time (s) in excess of the average scram insertion time limit.
Otherwise, be in at least HOT SHUTDOWN within the next 12 hours,
- b. The provisions of Specification 3.0.4 are not applicable.
SURVEILLANCE RE0VIREMENTS 4.1.3.4 All control rods'shall be demonstrated OPERABLE by scram time testing from the fully withdrawn position as required by Surveillance Requirement 4.1. 3. 2. HOPE CREEK 3/4 1-8
REACTIVITY CONTROL SYSTEMS CONTROL R00 SCRAM ACCUMULATORS JUN 2 8 1ES LIMITING CONDITION FOR OPERATION 3.1.3.5 All control rod scram accumulators shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 5*. ACTION:
- a. In OPERATIONAL CONDITIONS 1 or 2:
- 1. With one control rod scram accumulator inoperable, within 8 hours:
a) Restore the inoperable accumulator to OPERABLE status, or b) Declare the control rod associated with the inoperable accumulator inoperable. Otherwise, be in at least HOT SHUTDOWN within the next 12 hours.
- 2. With more than one control rod scram accumulator inoperable, declare the associated control rods inoperable and:
a) If the control rod associated with any inoperable scram accumulator is withdrawn, immediately verify that at least one control rod drive pump is operating by inserting at least one withdrawn control rod at least one notch or place the reactor mode switch in the Shutdown position. b) Insert the inoperable control rods and disarm the associated control valves either:
- 1) Electrically, or
- 2) Hydraulically by closing the drive water and exhaust water isolation valves.
Otherwise, be in at least HOT SHUTDOWN within 12 hours.
- b. In OPERATIONAL CONDITION 5*:
- 1. With one withdrawn control rod with its associated scram accumu-lator inoperable, insert the affected control rod and disarm the associated directional control valves within one hour, either:
a) Electrically, or b) Hydraulically by closing the drive water and exhaust water isolation valves.
- 2. With more than one withdrawn control rod with the associated scram accumulator inoperable or no control rod drive pump operating, immediately place the reactor mode switch in the Shutdown position.
- c. The provisions of Specification 3.0.4 are not applicable.
"At least the accumulator associated with each withdrawn control rod. Not applicable to control rods removed per Specification 3.9.10.1 or 3.9.10.2.
~
HOPE CREEK 3/4 1-9 t
I- k REACTIVITY CONTROL SYSTEMS N gag ( 2 8 1985 SURVEILLANCE REQUIREMENTS 4.1.3.5 Each control rod scram accumulator shall be determined OPERABLE:
- a. At least once per 7 days by verifying that the indicated pressure is greater than or equal to 940 psig unless tha control rod is inserted and disarmed or scrammed.
- b. At least once per 18 months by: ,
- 1. Performance of a:
a) CHANNEL FUNCTIONAL TEST of the-leak detectors, and b) CHANNEL CALIBRATION of the pressure detectors, and veritying an alarm setpoint of (940) + (30), -(0) psig on decreasing pressure.
- 2. Measuring and recording the time for up to 10 minutes that each individual accumulator check valve maintains the associated accumulator pressure above the alarm set point with no control 'i rod drive pump operating.
. ~
l l l d HOPE CREEK 3/4 1-10
REACTIVITY CONTROL SYSTEMS CONTROL ROD ORIVE COUPLING g 2 8 icg5 LIMITING CONDITION FOR OPERATION 3.1.3.6 All control rods shall be couoled to their drive mechanismo APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 5*. ACTION:
- a. In OPERATIONAL CONDITION 1 and 2 with one control rod not coupled to its associated drive mechanism, within 2 hours:
- 1. If permitted by the RWM and RSCS, insert the control rod drive mechan-ism to accomplish recoupling and verify recoupling by withdrawing the control rod, and:
a) Observing any indicated response of the nuclear instrumentation, and b) Demonstrating that the control rod will not go to the overtravel position. Otherwise, be in at least HOT SHUTOOWN within the next 12 hours.
- 2. If recoupling is not accomplished on the first attempt or, if not permitted by the RhN or RSCS, then until permitted by the RWM and RSCS, declare the control rod inoperable, insert the control rod and disarm the associated directional control valves ** either:
a) Electrically, or b) Hydraulically by closing the drive water and exhaust water isolation valves. Otherwise, be in at least HOT SHUTDOWN within the next 12 hours.
- b. In OPERATIONAL CONDITION 5* with a withdrawn control rod not coupled to its associated drive mechanism, within 2 hours either:
- 1. Insert the control rod to accomplish recoupling and verify recoupling by withdrawing the control rod and demonstrating that the control rod will not go to the overtravel position, or
- 2. If recoupling is not accomplished, insert the control rod and disarm the associated directional control valves ** either:
a) Electrically, or b) Hydraulically by closing the drive water and exhaust water isolation valves.
- c. The provisions of Specification 3.0.4 are not applicable. ,
"At least each withdrawn control rod. Not applicable to control rods removed per Speci fication 3. 9.10.1 or 3. 9.10.2.
- May be rearmed intermittently, under administrative control, to permit testing associated with restoring the control rod to OPERABLE status.
HOPE CREEK 3/4 1-11
5 REACTIVITY CONTROL SYSTEMS , JJN 2 8 Ec5 SURVEILLANCE REQUIREMENTS 4.1.3.6 Each affected control rod shall be demonstrated to be coupled to its driva mechanisr. by obeerving any inMoltM *. p- :e of the nuclear instru..en-tation while withdrawing the control rod to the fully withdrawn position and then verifying that the control rod drive does not go to the overtravel position:
- a. Prior to reactor criticality after completing CORE ALTERATIONS that could have affected the control rod drive coupling integrity,
- b. Anytime the control rod is withdrawn to the " Full out" position in subsequent operation, and
- c. Following maintenance on or modification to the control rod or control rod drive system which could have affected the control rod drive coupling integrity.
l l l i l HOPE CREEK 3/4 1-12
l 1 REACTIVITY CONTROL SYSTEMS !] CONTROL ROD POSITION INDICATION , I
.g)N 2 B EB5 LIMITING CONDITION FOR OPERATION 3.1.3.7 The control rod position indication system shall be OPERABLE.
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 58 ACTION:
- a. In OPERATIONAL CONDITION 1 or 2:
- 1. With one or more control rod position indicators inoperable, except for the " Full-in" or " Full-out" indicators, within one hour:
a) Determine the position of the control rod by:
- 1) Moving the control rod, by single notch movement, to a position with an OPERABLE position indicator,
- 2) Returning the control rod, by single notch movement, to its original position, and
- 3) Verifying no control rod drift alarm at least once per 12 hours, or b) Move the control rod to a position with an OPERABLE position indicator, or c) When THERMAL POWER is: __
- 1) Within the low power setpoint of the RSCS, declare the control rod inoperable, or
- 2) Greater than the low power setpoint of the RSCS, declare the control rod inoperable, insert the control rod and disarm the associated directional control valves ** either:
(a) Electrically, or (b) Hydraulically by closing the drive water and exhaust water isolation valves. l Otherwise, be in at least HOT SHUTDOWN within the next 12 hours. A At least each withdrawn control rod. Not applicable to control rods removed per Specification 3.9.10.1 or 3.9.10.2. as May be rearmed intermittently, under administrative control, to permit testing associated with restoring the control rod to OPERABLE status. HOPE CREEK 3/4 1-13
REACTIVITY CONTROL SYSTEMS LIMITING CONDITION FOR OPERATION (Continued) ACTION (Continued)
- 2. With one or more control cod "F"11-in" and/or "Fi.ill-out" pn::f Hon indicators inoperable, either:
- 7) When THERMAL POWER is within the (prt. set power level) (low pcwer setpoint) of the RSCS:
- 1) Within one hour:
(a) Determine the position of the control rod (s) per ACTION a.1.a, above or (b) Move the control rod to a position with an OPERABLE position indicator, or (c) 0?clare the control rod inoperable.
- 2) Verify :the position and bypassing of control rods with opsrable " Full-in and/or Full-out" position indicatars by a second licensed operator or other technichily qualified member of the unit technical staff.
b) When THERMAL POWER is greater than the (preset power level) (low power setpoint) of the RSCS, determine the position of the control rod (s) by (an alternate method). Otherwise, be in at least HOT SHUTOOWN within 12 hours.
- b. In OPERATIONAL CONDITION S* with a withdrawn control rod position indicator inoperable, move the control rod to a position with an OPERABLE position' indicator or insert the control rod.
- c. The provisions of Specification 3.0.4 are not applicable.
SURVEILLANCE REQUIREMENTS 4.1.3.7 The control red position indication system shall be determined OPERABLE by verifying:
- a. At least once per 24 hours that the position of each control rod is indicated,
- b. That the indicated control rod position changes during the movement of the control rod drive when performing Surveillance Requirement 4.1.3.1.2, and
- c. That the control rod position indicator corresponds to the control rod position indicated by the " Full out" position indicator when performing Surveillance Requirement 4.1.3.6.b.
"At least each withdrawn control rod. Not applicable to control rods removed per Specification 3.9.10.1 or 3.9.10.2. HOPE CREEK 3/4 1-14
REACTIVITY CONTROL SYSTEMS CONTROL ROD ORIVE HOUSING SUPPORT JUN 2 E IMi LIMITING CONDITION FOR OPERATION 3.1.3.8 The control rod drive housing support shall be in place. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION: With the control rod drive housing support not in place, be in at least HOT SHUTDOWN within 12 hours and in COLD SHUTDOWN within the following 24 hours. SURVEILLANCE REQUIREMENTS 4.1.3.8 The control rod drive housing support shall be verified to be in place by a visual inspection prior to startup any time it has been disassembled or when maintenance has been performed in the control rod drive housing support area. HOPE CREEK 3/4 1-15
REACTIVITY CONTROL SYSTEMS 3/4.1.4 CONTROL ROD PROGRAM CONTROLS JUN 2 8 1985 ROD WORTH MINIMIZE 3 LIMI ING CONDITION FOR OPERATION 3.1.4.1 The rod worth minimizer (RWM) shall be OPERABLE. APPLICABILITY. OPERATIONAL CONDITIONS 1 and 2*, when THERMAL POWER is less than or equal to 20% of RATED THERMAL POWER, the minimum allowable low power setpoint. ACTION:
- a. With the RWM inoperable, verify control rod movement and compliance with the prescribed control rod pattern by a second licensed operator or otner technically qualified member of the unit technical staff
~
who is presenthet the reactor control console. Otherwise, control rod movement may be only by actuating the manual scram or placing the reactor mode switch in the Shutdown position,
- b. The provisions of Specification 3.0.4 are not applicable. 3 SURVEILLANCE REQUIREMENTS 4.1.4.1 The RWM shall be demonstrated OPERABLE:
- a. In OPERATIONAL CONDITION 2 within 8 hours prior to withdrawal of control rods for the purpose of making the reactor critical, and in OPERATIONAL CONDITION 1 within 8 hours prior to RWM automatic initia-tion when reducing THERMAL POWER, by verifying proper indication of the selection error of at least.one out-of-sequence control rod.
i b. In OPERATIONAL CONDITION 2 within 8 hours prior to withdrawal of control rods for the purpose of making the reactor critical, by verifying the rod block function by demonstrating inability to
- withdraw an out-of-sequence control rod.
1
- c. In OPERATIONAL CONDITION 1 within one hour after RWM automatic initiation when reducing THERMAL POWER, by verifying the rod block function by demonstrating inability to withdraw an out-of-sequence i control rod. _
l d. By demonstrating that the control rod patterns and sequence input to ! the RWM computer are correctly loaded following any loading of the program into the computer. Entry into OPERATIONAL CON 9ITION 2 and Eithdrawal of selected control rods is permitted for the purpose of determining the OPERABILITY of the RbM prior to withdrawal of control rods for the purpose of bringing the reactor to criticality. l I HOPE CREEK 3/4 1-16 L
s
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REACTIVITYCONTROLSYSTkMS
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ROD SEQUENCE CONTROL SYSTEM f LIMITING CONDITION FOR OPERATI$N r
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3.1.4.2 fne rod sequence A:ontrol system (RSCS) shall be OPERABLE.- APPLICABILITY: OPERATICNAL CONDITIONS 1 and 2*# when HERMAL POWER is less than or equaT to (20)% RATED THERMAL POWER, the minimum allowable low power setpoint. ACTION:
- a. b With the RSCS inoperuc -, control red movement shall not be permitted, except by a scram.
- b. With an inoperable control rod (s), OPERABLE control rod movement may continue by bypassing the inoperable control rod (s) in the P.SCS provided that: , , ,
- 1. The posikfon and byp\assing of inoperable control, rods.is veriffed by a second licensed operator or other technically qt/alifiad member of the unit technicai staff, and ,
. ; , g.
- 2. There are not more than 3 inoperable' control rods iii iny RSCS group. .
' ~
t'i SURVEILLANCE REQUIREMENTS'. c 4.1.4.2 The RSCS shall be demonstrat_ed OPERABLE by: 7
" 1 1
/ ,
- a. Performance of a ' system diagnostic function: 0 e
Within' 8 hours prior to each reactor startup, and 1. 1.
- 2. Prior to movement of a control rod after rod inhibit mode automatic initiation when reducing THERMAL POWER.
b. Attempting to select and move an inhibited coatrol.; rod:
- 1. After' withdrawal of the first insequence control rod 'for each reactor startup, and
- 2. Within one hour after rod inhibit' mode automatic initiation _:
when reducing THERMAL POWER. .
*See Special Test Exception 3.10.2 , # Entry into OPERATIONAL CONDITION 2 and withdrawal of selected control rods s s
is permitted for the purpose of determining the OPERASILITY of the RSCS 3 ' prior to withdrawal of control. rods for the purpose of bringing the reactor to criticality, s HOPE CREEK 3/4 1-17 '
REACTIVITY CONTROL SYSTEMS 3/4.1.5 STANDBY ' LIQUID CONTROL SYSTEM JIJN 2 8 g LIMITING CONDITION FOR OPERATION .' 3.1.5 The s+.aridby liquid centrol ty:; tor s:.cil,be OPERABLE. APPlTCABIL,I]: OPERATIONAL CONDITIONS 1, 2, cnd 5* ACTION: ,
- a. In OPERATIONAL CONDITION 1 or 2:
- 1. With one syctem subsystem inoperable, restore the subsystem to OPERABLE status within 7 days or be in at least HOT SHUTDOWN within the next 12 hours.
- 2. With the standby liquid control system otherwise inoperable, restore at least one subsystem to OPERABLE status within 8 hours or be in at least HOT SHUTDOWN within the next 12 hours.
- b. In OPERATIONAL CONDITION 5*:
- 1. With one system subsystem inoperable, restore subsystem to OPERABLE status within 30 days or insert all insertable control rods within the next hour.
- 2. With both standby liquid control system subsystems inoperable,
,'r,( insert all insertable control rods within'one hour.
i SURVEILLANCE REQUIREMENTS 4.1.5 The standby' liquid control system shall be demonstrated OPERABLE: y a. At least once per 24 hours by verifying that;
- 1. The temperature of the sodium pentaborate solution is within the limits of Figure 3.1.5-1.
- 2. The available volume of sodium pentaborate solution is, greater
~
than or equal to ( ) gallons.
- 3. The heat tracing circuit is OPERABLE by determining the temperature of the pump suction piping to be greater than or equal to 70*F.
s "With any control rod withdrawn. Not applicable to~ control rods removed per Speci fication 3. 9.10.1 or 3. 9.10. 2. HOPE CREEK 3/4 1-19 ~ v
REACTIVITY CONTROL SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)
- b. At least once per 31 days by:
- 1. Verifying tne continuity of the explosive charge.
- 2. Determining that the avai'able weight of sodium po-taborate is greater than or equal to 5,750 lbs and the concentration of boron in solution is within the limits of Figure 3.1.5-1 by
. chemical analysis."
- 3. Verifying that each valve, manual, power operated or automatic, in the flow path that is not locked, sealed, or otherwise secured in position, is in its correct position.
- c. Demonstrating that, when tested pursuant to Specification 4.0.5, the minimum flow requirement of 41.2 gpm, per pump, at a pressure of greater than or equal to 1235 psig is met.
- d. At least once per 18 months during shutdown by:
- 1. Initiating one of the standby liquii control system loops, including an explosive valve, and verifying that a flow path from the pumps to the. reactor pressure vessel is available by pumping demineralized water into the reactor vessel. The replacement charge for the explosive valve shall be from the same manufactured batch as the one fired or from another batch which has been certified by having one of that batch success-fully fired. Both injection loops shall be tested in 36 months.
- 2. Demonstrating that the pump relief valve setpoint is less than or equal to 1400 psig and verifying that the relief valve does not actuate during recirculation to the test tank.
- 3. ** Demonstrating that all heat traced piping between the storage tank and the reactor vessel is unblocked by (purr. ping from the storage tank to the test tank) and then draining and flushing the piping with demineralized water.
- 4. Demonstrating that the storage tank heaters are OPERABLE by verifying the expected temperature rise of the sodium penta-borate solution in the storage tank by at least __*F within
__ minutes after the heaters are energized.
*This test shall also be performed anytime water or boron is added to the solu tion or when the solution temperature drops below the limit of Figure 3.1.5-1. **This test shall also be performed whenever both heat tracing circuits have been found to be inoperable and may be performed by any series of sequential, overlapping or total flow path steps such that the entire flow path is included.
HOPE CREEK 3/4 1-20
E cThD b*'$ me, S T N E M NE t OR h II g TU i UQ e LE w OR S 1 y N - b EO 5 TI .
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OR 3 n BT o AN e i TE r t NC u a EN g r PO i t C F n M/ e UE c IR n DU o OT C SA R E P M E T . 1 5m 0An Ru TS
3/4.2 POWER DISTRIBUTION LIMITS 3/4.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE JUN 2 8 1985 LIMITING CONDITION FOR OPERATION 3.2.1 All AVERAGE PLANAR LINEAR HEAT GENERATION RATES (APLHGRs) for each type of fuel as a function of AVERAGE PLANAR EXPOSURE shall not exceed the limits shown in Figures 3.2.1-1, 3.2.1-2, and 3.2.1-3. APPLICABILITY: OPERATIONAL CONDITION 1, when THERMAL POWER is greater than or equal to 25% of RATED THERMAL POWER. ACTION: With an APLHGR exceeding the limits of Figure 3.2.1-1, 3.2.1-2, or 3.2.1-3, initiate corrective action within 15 minutes and restore APLHGR to within the required limits within 2 hours or reduce THERMAL POWER to less than (25)% of RATED THERMAL POWER within the next 4 hours. SURVEILLANCE REQUIREMENTS 4.2.1 All APLHGRs shall be verified to be equal to or less than the limits determined from Figures 3. 2.1-1, 3. 2.1-2, and 3. 2.1-3:
- a. At least once per 24 hours,
- b. Within 12 hours after completion of a THERMAL POWER increase of at least 15% of RATED THERMAL POWER, and
- c. Initially and at least once per 12 hours when the reactor is operating with a LIMITING CONTROL ROD PATTERN for APLHGR.
- d. The provisions of Specification 4.0.4 are not applicable.
J HOPE. CREEK 3/4 2-1
g. 5
,1 '
O n N r v R
.s. t 7
N AVERAGE PLANAR EXPOSURE (mwd /t) MAXIMUM AVERAGE PLANAR LINEAR HEAT GENERATION RATE (MAPLHGR) VERSUS AVERAGE PLANAR EXPOSURE INITIAL CORE FUEL TYPES ( ) C Figure 3'.2.1-1 x T f ro p m 3 <a
I 5 rA 9 El n l i l M.
?
w i i AVERAGE PLANAR EXPOSURE (mwd /t) MAXIMUM AVERAGE PLANAR LINEAR HEAT GENERATION RATE (MAPLHGR) VERSUS AVERAGE PLANAR EXPOSURES INITIAL CORE FUEL TYPES ( ) Q 2 C
~~
Figure 3.2.1-2 ro y t s
i 5 rl g El
- n:
w ~ . N k AVERAGE PLANAR EXPOSURE (mwd /t) MAXIMUM AVERAGE PLANAR LINEAR HEAT GENERATION RATE (MAPLHGR) VERSUS AVERAGE PLANAR EXPOSURE INITIAL CORE FUEL TYPES ( )- h 2 g i Figure 3.2.1-3 ,,,g
% C p
5 m b
POWER DISTRIBUTION LIMITS JUN 2 E iss3 3/4.2.2 -APRM SETPOINTS LIMITING CONDITION FOR OPERATION 3.2.2 The APW flow hissed simula .ed thermal power-apscale = cram trip secpvir.i. (S) and flow biased neutron flux upscale control rod block trip setpoint (SRB) shall be established sccording tn the following relatione, hips: TRIP SETPOINT ALLOWABLE VALUE S < (0.66W + 51%)T S < (0.66W + 54%)T S RB 5 (0.66W + 42%)T S RB 5 (0.66W + 45%)T where: S and S DB are in percent of RATED THERMAL POWER, W = Loop recirculation flow as a percentage of the loop recirculation flow which produces a rated core flow of (100) million lbs/hr, T = Lowest value of the ratio of FRACTION OF RATED THERMAL POWER (FRTP) divided by the CORE MAXIMUM FRACTION OF LIMITING POWER DENSITY (CMFLPD). T is applied only if less than or equal to 1.0. APPLICABILITY: OPERATIONAL CONDITION 1, when THERMAL POWER is greater than or equal to (25)% of RATED THERMAL POWER. ACTION: With the APRM flow biased simulated thermal power-upscale scram trip setpoint and/or the flow biased neutron flux-upscale control rod block trip setpoint less conservative than the value shown in the Allowable Value column for S or S as above determined, initiate corrective action within 15 minutes andadhs,tSand/ ors to be consistent with the Trip Setpoint values
- within6hoursorredNeTHERMALPOWERtolessthan(25)%ofRATEDTHERMAL POWER within the next 4 hours.
SURVEILLANCE REQUIREMENTS 4.2.2 The FRTP and the CMFLPD shall be determined, the value of T calculated, and the most recent actual APRM flow biased simulated thermal power-upscale scram and flow biased neutron flex-upscale control rod block trip setpoints verified to be within the above limits or adjusted, as required:
- a. At least once per 24 hours,
- b. Within 12 hours after completion of a THERMAL POWER increase of at least 15% of RATED THERMAL POWER, and
- c. Initially and at least once per 12 hours when the reactor is operating with CMFLPD greater than or equal to FRTP.
- d. The provisions of Specification 4.0.4 are not applicable.
"With (CMFLPD) (MTPF) greater than the (FRTP) (design TPF) during power ascension up to 90% of RATED THERMAL POWER, rather than adjusting the APRM setpoints, the APRM gain may be adjusted such that the APRM readings are greater than or equal to 100% times (CMFLPD) (MTPF), provided that the adjusted APRM reading does not exceed 100% of RATED THERMAL POWER and a notice of adjustment is posted on the reactor control panel.
HOPE CREEK 3/4 2-5
POWER DISTRIBUTION LIMITS 3/4.2.3 MINIMUM CRITICAL POWER RATIO JUN 2 6 1935 LIMITING CONDITION FOR OPERATION 3.2.3 The MINIMUM CRITICAL POWER RATIO (MCPR) shall be equal to or greater than both MCPRf and MCPR p limits at indicated core flow and THERMAL POWER as shown in Figures 3.2.3-1 and 3.2.3-2. APPLICABILITY: OPERATIONAL CONDITION 1, when THERMAL POWER is greater than or equal to 25% of RATED THERMAL POWER. ACTION: With MCPR less than the applicable MCPR limit shown in Figures 3.2.3-1 and 3.2.3-2, initiate corrective action within 15 minutes and restore MCPR to within the required limit within 2 hours or reduce THERMAL POWER to less than 25% of RATED THERMAL POWER within the next 4 hours. SURVEILLANCE REOUIREMENTS 4.2.3 MCPR shall be determined to be equal to or greater than the applicable MCPR limit determined from Figure 3.2.3-1:
- a. At least once per 24 hours,
- b. Within 12 hours after completion of a THERMAL POWER increase of at least 15% of RATED THERMAL POWER, and
- c. Initially and at least once per 12 hours when the reactor is operating with a LIMITING CONTROL R00 PATTERN for MCPR.
- d. The provisions of Specification 4.0.4 are not applicable.
HOPE CREEK 3/4 2-6
i gitN 2 B 'S85 CORE FLOW, % OF RATED CORE FLOW MCPR 7 Figure 3.2.3-1 HOPE CREEK 3/4 2-7
MUN 2 E C-F s ) l I l !_ THERMAL POWER, % OF RATED THERMAL POWER MCPR P ( Figure 3.2.3-2 l HOPE CREEK 3/4 2-8
30 POWER DISTRIBUTION LIMITS dih I 3/4.2.4 LINEAR HEAT GENERATION RATE sy 2 B IE LIMITING CONDITION FOR OPERATION 3.2.4 The LINEAR HEAT GENERATION RATE (LHGR) shall not exceed 13.4 kw/ft. APPLICABILITY: OPERATIONAL CONDITION 1, when THERMAL POWER is greater than or equal to 25% of RATED THERMAL POWER. ACTION: With the LHGR of any fuel rod exceeding the limit, initiate corrective action within 15 minutes and restore the LHGR to within the limit within 2 hours or reduce THERMAL POWER to less than 25% of RATED THERMAL POWER within the next 4 hours. SURVEILLANCE REQUIREMENTS 4.2.4 LHGR's shall be determined to be equal to or less than the limit:
- a. At least once per 24 hours,
- b. Within 12 hours after completion of a THERMAL POWER increase of at least 15% of RATED THERMAL POWER, and
- c. Initially and at least once per 12 hours when the reactor is operating on a LIMITING CONTROL ROD PATTERN for LHGR.
- d. The provisions of Specification 4.0.4 are not applicable.
HOPE CREEK 3/4 2-9
3/4.3 INSTRUMENTATION 3/4.3.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION
.y 7. b 1 LIMITING CONDITION FOR OPERATION 3.3.1 As a minimum, the reactor protection system instrumentation channels shown in Table 3.3.1-1 shall be OPERABLE with the REACTOR PPOTECTTnu cycTFM l'.t0PG;iSE TIhE os snuwn in raaie 's.3.1-2.
APPLICABILITY: As shown in Tabie 3.3.1-1. ACTION:
- a. With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip System requirement for one trip system, place the inoperable channel (s) and/or that trip system in the tripped condi-tion
- within one hour. The provisions of Specification 3.0.4 are not applicable.
- b. With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip System requirement for both trip systems, place at least one trip system ** in the tripped condition within one hour and take the ACTION required by Table 3.3.1-1.
SURVEILLANCE REQUIREMENTS 4.3.1.1 Each reactor protection system instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations for the OPERATIONAL CONDITIONS and at the frequencies shown in Table 4.3.1.1-1. 4.3.1.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic operation of all channels shall be performed at least once per 18 months.
~4.3.1.3 The REACTOR PROTECTION SYSTEM RESPONSE TIME of each reactor trip functional unit shown in Table 3.3.1-2 shall be demonstrated to be within its limit at least once per 18 months. Each test shall include at least one channel per trip system such that all channels are tested at least once every N times 18 months where N is the total number of redundant channels in a specific reactor trip system.
"An inoperaole cnannel need not be placed in the tripped condition where this would cause the Trip Function to occur. In these cases, the inoperable channel shall be restored to OPERABLE status within 2 hours or the ACTION required by Table 3.3.1-1 for that Trip Function shall be taken.
**If more channels are inoperable in one trip system than in the other, place the trip system with more inoperable channels in the tripped condition, 4
except when this wouia cause tne trip tunction to occur. t HOPE CREEK 3/4 3-1
x TABLE 3.3.1-1 m REACTOR PROTECTION SYSTEM INSTRUMENTATION O , in x APPLICABLE MINIMUM OPERATIONAL OPERABLE CHANNELS j FUNCTIONAL UNIT CONDITIONS PER TRIP SYSTEM (a) ACTION
- 1. Intermediate Range Monitors (b).
- a. Neutron Flux - liigh 2 3 1 j 3, 2 (c) 2(d)
- b. Inoperative 2 3 1 3, 4 2 2
, 5 3(d) 3 y 2. Average Power Range MonitorI *): e a. Neutron Flux - Upscale, Setdown 2 2 1 i y 3, 4(c) 2 2 m 5 2(d) 3
- b. Flow Biased Simulated Thermal
, Power - Upscale 1 2 4
- c. Fixed Neutron Flux - Upscale 1 2 4
- d. Inoperative 1, 2 2 1 2
'f(c) 2(d)
- e. Downscale 1(9) 2 4
- 3. Reactor Vessel Steam Dome Pressure - liigh 1, 2 II) 2 1
- 4. Ihe'actorVesselWaterLevel-Low, level 3 1, 2 2 1
- 5. Main Steam Line Isolation Valve -
Closure 1(g) 4 4 e,_ g y to 00
o TABLE 3.3.1-1 (Continued) m REACTOR PROTECTION SYSTEM INSTRUMENTATION O m E APPLICABLE MINIMUM OPERATIONAL OPERABLE CHANNELS FUNCTIONAL UNIT CONDITIONS PER TRIP SYSTEM (a) ACTION
- 6. Main Steam Line Radiation -
High 1, 2 II) 2 5
- 7. (Primary Containment) (Drywell)
Pressure - High 1,2(h) 2 1
- 8. Scram Discharge Volume Water Level - High g a. Level Transmitter 1, 2(g) 2 1 a 5 2 3 w
0 b. Float Switch 1, 2(g) 2 1 5 2 3
- 9. Turbine Stop Valve - Closure I I3) 4(k) 6
- 10. Turbine Control Valve Fast Closure, Valve Trip System Oil Pressure - Low I II9))Id) 2(k) 6
- 11. Reactor Mode Switch Shutdown Position 1, 2 2 1 3, 4 2 7 5 2 3
- 12. Manual Scram 1, 2 2 1 3, 4 2 8 5 2 9 to M
m M .
TABLE 3.3.1-1 (Continued) - REACTOR PROTECTION SYSTEM INSTRUMENTATION ACTION JUN 2 8 1935 ACTION 1 - Be in at least HOT SHUTDOWN within 12 hours. ACTION 2 - Verify all insertable control rods to be inserted in the core and lock the reactor mode switch in the Shutdown position within or.e hour. ACTION 3 - Suspend all operations involving CORE ALTERATIONS
- and insert all insertable control rods within one hour.
ACTION 4 - Be in at least STARTUP within 6 hours. ACTICN 5 - Be in STARTUP with the main steam line isolation valves closed within6goursorinatleastHOTSHUTDOWNwithin12 hours. ACTION 6 - Initiate a reduction in THERMAL POWER within 15 minutes and reduce turbine first stage pressure until the function is automatically bypassed, within 2 hours.
~.
ACTION 7 - Verify all insertable control rods to be inserted within one , hour. ACTION 8 - Lock the reactor mode switch in the Shutdown position within one hour. ACTION 9 - Suspend all operations involving CORE ALTERATIONS *, and insert all insertable control rods and lock the reactor mode switch in the SHUTDOWN position within one hour.
*Except movement of IRM, SRM or special movable detectors, or replacement of LPRM strings provided SRM instrumentation is OPERABLE per Specification 3.9.2.
HOPE CREEK 3/4 3-4
TABLE.3.3.1-1 (Continued) REACTOR PROTECTION SYSTEM INSTRUMENTATION JUN 2 8 1985 TABLE NOTATIONS (a) A channel may be placed in an inoperable status for up to 2 hours for required surveillance without placing the trip syste": in the tricoed i.v..oi e . v . p vvidt:d at. least one OPERAbLt channel in' tne same trip system is monitoring that parameter. (b) This function shall be automatically bypassed when the reactor mode switch is in the Run position. (c) The " shorting links" shall be removed from the RPS circuitry prior to and during the time any control rod is withdrawn
- and shutdown margin demonstrations are being performed per Specification 3.10.3.
(d) The non-coincident NMS reactor trip function logic is such that all channels go to both trip systems. Therefore, when the " shorting links" are removed,
.the Minimum OPERABLE Channels Per Trip System is 4 APRMS and 6 IRMS.
(e) An APRM channel is inoperable if there are less than 2 LPRM inputs per level.or less than 14 LPRM inputs to an APRM channel. (f) This function is not required to be OPERABLE when the reactor pressure vessel head is removed per Specification 3.10.1. (g) This function shall be automatically bypassed when the reactor mode switch is not in the Run position. (h) This function is not required to be OPERABLE when PRIMARY CONTAINMENT INTEGRITY is not required. (i) With any control rod withdrawn. Not applicable to control rods removed per Specification 3.9.10.1 or 3.9.10.2. (j) This function shall be automatically bypassed when turbine first stage pressure is < (250) psig, equivalent to THERMAL POWER less than (30)% of RATED THERMAL POWER. (k) Also-actuates the EOC-RPT system.
"Not required for control rods removed per Specification 3.9.10.1 or 3.9.10.2.
HOPE CREEK 3/4 3-5 Y--_, , , - - . - - - - - -
GN x TABLE 3.3.1-2 ni REACTOR PROTECTION SYSTEM RESPONSE TIMES S R; Pc RESPONSE TIME FUNCTIONAL UNIT (Seconds)
- 1. Internediate Range Monitors:
- a. teutron Flux - High NA
- b. Inoperative NA
- 2. Averate Power Range Monitor *:
- a. F.eutron Flux - Upscale, Setdown NA
- b. Flow Biased Simulated Thermal Power - Upscale
- c. Fixed Neutron Flux - Upscale 5 0.09**
- d. Inoperative 1 0.09 NA
- e. Cownscale NA
- 3. Reactor Vessel Steam Dome Pressure - High w 4. Reactor Vessel Water Level - Low, Level 3 5 0.55 Ei S.
< 1.05 Main Steam Line Isolation Valve - Closure 7 0.06
- 6. Main Steam Line Radiation - High NA
- 7. Primary Containment Pressure - High NA
- 8. Scram Dischar0e Volume Water Level - High NA
- a. Float Switch NA
- b. Level Transmitter NA
- 9. Turbine Stop Valve - Closure
- 10. Turbine Control Valve Fast Closure, 5 0.06 Trip Oil Pressure - Low
- 11. $ 0.08#
Reactor Mode Switch Shutdown Position NA
- 12. Manual Scram NA
- Neutron detectors are exempt from response time testing. Response time shall be measured f rom the detector output or from the input of the first electronic component in the channel.
**Not inclu' ling simulated thermal power time constant, 6 1 0.6 seconds. # Measured from start of turbine control valve fast closure. c E
n CO M 01
TABLE 4.3.1.1-1 5 rl REACTOR PROTECTION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS n E CHANNEL OPERATIb.4AL E CilANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH FUNCTIONAL UNIT CilECK TEST CALIBRATION (a) SURVEILLANCF REQUIRED
- 1. Intemediate Range Monitors:
- a. lieutron Flux - High S/U.S,(b) S/U IC) ,W R 2 S W R 3,4,5
- b. Enoperative NA W NA 2, 3, 4, 5
- 2. Average Power Range MonitorIII:
- a. Pleutron Flux - S/U.S,(b) S/U(c) ,W SA 2 Upscale, Seldown S W SA 3, 5 w b. Flow Biased Simulated D Thermal Power - Upscale S,D II9)) S/U IC) ,W W Id)(*} SA,(R(h))
, 7
- c. Iixed Neutron Flux -
Upscale S S/U IC) ,W W Id) , SA 1
- d. Inoperative NA W NA 1,-2, 3, 5
- e. [ownscale S W SA 1
- 3. Reactcr Vessel Steam Dome Pressure - liigh (5) H R 1, 2
- 4. Reactor Vessel Water Level -
Low, Level 3 (5) H R 1, 2
- 5. Main Steam Line Isolation Valve - Closure NA M R 1
- 6. Main Steam Line Radiation -
liigh S M R 1, 2 0) e
- 7. -Primary Containment Y Pressure - liigh .
S M R 1, 2 co _N
TABLE 4.3.1.1-1 (Ccntinued) 1 m REACTOR PROTECTION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS O CHANNEL OPERe.T101 AL El CHANNEL FUNCTIONAL CHANNEL- CONDITIONS FOR WHICH FUNCTIONAL LINIT CHECK TEST CALIBRATION SURVEILLANCE REQUIRED
- 8. Scram !!ischarge Volume Water Level - High
- a. Float Switch NA Q R 1, 2, S IS)
- b. Level Transmitter S M R 1, 2, S II)
- 9. Turbine Stop Valve - Closure NA M R 1
- 10. Turbine Control Valve Fast Clost re Valve Trip System Dil Fressure - Low NA M R 1 w
A 11. Reactor Mode Switch Shutcown Position NA R NA 1,2,3,4,5
- 12. Manual Scram NA M NA 1,2,3,4,5 (a) Neutror detectors may be excluded from CHANNEL CALIBRATION.
(b) The IRP and SRM channels shall be determined to overlap for at least (\) decades during each startup af ter entering OPERATIONAL CONDITION 2 and the IRM and APRM channels shall be determined to overlap for at least (\) decades during each controlled shutdown, if not performed within the previous 7 days. (c) Within 24 hours prior to startup, if not-performed within the previous 7 days. (d) This calibration shall consist of the adjustment of the APRM channel to conform to the power values calculated by a heat balance during OPERATIONAL CONDITION 1 when THERMAL POWER > 25% of RATED i THERMAL POWER. Adjust the APRM channel if the absolute difference is greater than 2% of JAiE0 THERMAL POWER. Any APRM channel gain adjustment made in compliance with Specification 3.2.2 shall not be l included in determining the absolute difference. (e) This calibration shall consist of the adjustment of the APRM flow biased channel to confo m to a calibrated flow signal. (f) The LPRMs shall be calibrated at least once per 1000 effective full power hours (EFPH) using the TIP system. (g) Verify measured core flow to be greater than or equal to established core flow at the existing pump speed. (h) This calibration shall consist of verifying the 610.6 second simulated thermal power time constant. e (i) This function is not required to be OPERABLE when the reactor pressure vessel head is removed per Q C l Specification 3.10.1. (j) With any control rod withdrawn. w i Not applicable to control rods removed per Specification 3.9.10.1 co i or 3.9.10.2. I *
=
INSTRUMENTATION JUN 2 8 ige $ 3/4.3.2 ISOLATION ACTUATION INSTRUMENTATION LIMITING CONDITION FOR OPERATION
'32 Th e !. lation actuation instrumentation channels shown in Table 3.3.2-1 shall be OPERABLE with their trip setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.3.2-2 and with ISOLATION SYSTEM RESPONSE TIME as shown in Table 3.3.2-3.
APPLICABILITY: As shown in Table 3.3.2-1. ACTION: a. With an isolation actuation instrumentation channel trip setpoint less of conservative Table than the 3.3.2-2, declare the value shown in the Allowable Values column channel inoperable until the channel is restored to OPERABLE status with its trip setpoint adjusted consistent with the Trip Setpoint value. b. With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip System requirement for one trip system, place the~ inoperable channel (s) and/or that trip system in the tripped condition
- within one hour. The provisions of Specification 3.0.4 are not applicable.
c. With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip System requirement for both trip systems, place at least one trip system ** in the tripped condition within one hour and take the ACTION required by Table 3.3.2-1.
"An inoperable channel need not be placed in the tripped condition where this would cause the Trip Function to occur. In these cases, the inoperable channel.shall be restored to OPERABLE status within 2 hours or the ACTION required by Table 3.3.2-1 for that Trip Function shall be taken. **If more channels are inoperable in one trip system than in the other, place the trip system with more inoperable channels in the tripped condition, except when this would cause the Trip Function to occur, place the trip system with the most inoperable channels in the tripped condition; if both systems have the same tripped number of inoperable channels, place either trip system in the condition.
HOPE CREEK 3/4 3-9
INSTRUMENTATION SURVEILLANCE RE0VIREMENTS
- Ibbb 4.3.2.1 Each isolation actuation instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL rHECK, CHANNEL FUNCTIONAL TEST and C;6;diEL CALIBRAi10N operations for tne OPERAl10NAL CONDITIONS and at the frequencies shown in Table 4.3.2.1-1.
4.3.2.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic operation of all channels shall be performed at least once per 18 months. 4.3.2.3 The ISOLATION SYSTEM RESPONSE TIME of each isolation trip function shown in Table 3.3.2-3 shall be demonstrated to be within its limit at least once per 18 months. Each test shall include at least one channel per trip system such that all channels are tested at least once every N times 18 months, where N is the total number of redundant channels in a specific isolation trip system.
~.
+
- s t
HOPE CREEK 3/4 3-10
TABLE 3.3.2-1 o A ISOLATION ACTUATION INSTRUMENTATION a A VALVE ACTUA-W TION GROUPS MINIMUM APPLICABLE OPERATED BY OPERABLE CHANNE OPERATIONAL TRIP FUNCTION SIGNAL PERTRIPSYSTEM[g) CONDITION ACTION
- 1. PRIMARY CONTAINMENT ISOLATION
- a. Reactor Vessel Water Level
- 1) Low, Level 3 15(b) 2 1,2,3 20 2} Low Low, Level 2 1,2,8,9, 2 1,2,3 20 12, 13, 14, 15, 17, 18
- 3) Low Low, Level 1 10, 11, 16(b) 2 1,2,3 20
- h. Drywell Pressure - High 1, 8, 9, 10, 2 1,2,3 20 w 11, 12, 13, D 14, 15 w 17,18(bj6, 0 c. Reactor Building Exhaust 1, 8, 9, 12 Radiation - High High 13, 14, 15, 2 1,2,3 23 17, 18
- d. Manual Initiation 1, 8, 9, 10 1 1,2,3 24 11, 12, 13, 14, 15, 16, 17, 18
- 2. SECONDARY CONTAINMENT ISOLATION
- a. Reactor Vessel Water Level -
Los Low, Level 2 19 IC) 2 1, 2, 3 and
- 26
- b. Drjwell Pressure - High 19(c) p 1, 2, 3 26
- c. Refueling Floor Exhaust Rajiation - High High 19(C) 2 1, 2, 3 and
- 26
- d. Reactor Building Exhaust Rafiation - High High 19(c) 2 1, 2, 3 and
- 26
- e. Manual Initiation 19(C) 1 1, 2, 3 and
- 26
$ v m
Ol "d n
v~ q TABLE 3.3.2-1 (Continued) %m ISOLATION ACTUATION INSTRUMENTATION O g VALVE ACTUA-x TION GROUPS MINIMUM APPLICABLE OPERATED BY OPERATIONAL
'OPERABLECHANNEg)
TRIP FUNCTID_N SIGNAL PER TRIP SYSTEM CONDITION ACTION
- 3. MAIN SIEAM LINE ISOLATION
- a. Reactor Vessel Water Level - 1 2 1,2,3 21 Law Low, Level I
- b. Main Steam Line Radiation - 1, 2(d) 2(*) 1, 2, 3 21 High High
- c. Main Steam Line Pressure - 1 2 1 22 L3w
- d. Main Steam Line Flow - High 1 2/lineI *) 1, 2, 3 20 2 e. C)ndenser Vacuum - Low 1 2 1, 2**, 3** 21 Y f. Main Steam Line Tunnel 1 2/line(*) 1, 2, 3 21 ES Temperature - High
- g. Minual Initiation 1, 2, 17 2 1,2,3 25
- h. _
- 4. REACT 0!! WATER CLEANUP SYSTEM ISOLATION
- a. R1/CS a Flow - High 7 1 1,2,3 23
- b. RWCS A Flow - High, Timer 7 1 1,2,3 23
- c. R1/CS Area Temperature - High 7 3 1,2,3 23
- d. RWCS Area Ventilation A Temp. - 7 3 1,2,3 23 liigh
- e. SLCS Initiation 7 II NA 1, 2, 3, 23
- f. Reactor Vessel Water 7 2 1,2,3 23 Level - Low Low, Level 2
- g. Manual Initiation 7 (1) 1, 2, 3 25 E8 O
-J
. .2 2 N!
m s
x TABLE 3.3.2-1 (Continued) ISOLATION ACTUATION INSTRUMENTATION 9
,q VALVE ACTUA- ^
TION GROUPS MINIMUM APPLICABLE OPERATED BY OPERABLE CHANNE OPERATIONAL TRIP FUNCTION SIGNAL PERTRIPSYSTEM(g) CONDITION ACTION
- 5. REACT 0it CORE ISOLATION COOLING SYSTEM ISOLATION
- a. RCIC Steam Line A Pressure - High 6 (1) 1, 2, 3 23
- b. RCIC Steam Line A Pressure - 6 (1) 1, 2, 3 23 High Timer
- c. RCIC Steam Supply 6 2 1,2,3 23 Pressure - Low R
- d. RCIC Turbine Exhaust 6 2 1,2,3 23
't" Diaphragm Pressure - High U
- e. RCIC Equipment Room 6 (1) 1, 2, 3 23 Temperature - High
- f. RCIC Equipment Room 6 (1) 1, 2, 3 23 A Temperature - High
- g. RCIC Pipe Routing Area 6 (1) 1, 2, 3 23 Temperature - High
- h. RCIC Pipe Routing Area 6 (1) 1, 2, 3 23 A Temperature - High
- 1. RCIC Emergency Area Cooler 6 (1) 1, 2, 3 23 Tepperature - High
- j. Malual Initiation 6((h)) (1)/(valve) 1, 2, 3 25
)t C Y
- p-e a
el s
ac TABLE 3.3.2-1 (Continued) ni ISOLATION ACTUATION' INSTRUMENTATION n ll sc VALVE ACTUA-TION GROUPS MINIMUM APPLICABLE OPERATED BY OPERABLE CHANNE OPERATIONAL TRIP FUNCTI(g SIGNAL PERTRIPSYSTEM(g) CONDITION ACTION
- 6. HIGH PI: ESSURE COOLANT INJECTION SYSTEM ISOLATION
- a. HPCI Steam Line A Pressure - 5 (1) 1, 2, 3 23 High
- b. HI'CI Steam Line A Pressure - 5 (1) 1, 2, 3 23 High Timer
- c. HFCI Steam Supply Pressure-Low 5 2 1,2,3 23 y' d. HFCI Turbine Exhaust Diaphragm 5 2 1,2,3 23
,, Pressure - High $$ e. HFCI Pump Room 5 (1) 1, 2, 3 23 Temperature - liigh
- f. HFCI Pump Room Ventilation 5 (1) 1, 2, 3 23 Dtcts A Temperature - High
- g. HFCI Emergency Area Cooler 5 (1) 1, 2, 3 23 Temperature - High
- h. HPCI Pipe Routing Area 5 (1) 1, 2, 3 23 Temperature - High i, llPCI Pipe Routine Area A 5 (1) 1, 2, 3 23 Temperature - liigh i j. Manual Initiation 5 (1)/(group) 1, 2, 3 25 I: O
=
M 00 magm emum u.
z TABLE 3.3.2-1 (Centinued) O E n ISOLATION ACTUATION INSTRUMENTATION h x VALVE ACTUA-TION GROUPS MINIMUM APPLICARLE OPERATED BY OPERABLE CHANNE OPERATIONAL TRIP FUNCTION SIGNAL PERTRIPSYSTEM(g) CONDITION ACTION
- 7. RilR SYSTEM SHUTDOWN COOLING MODE ISOLATION
- a. Reactor Vessel Water Level - Low, Level 3 3 2 1,2,3 26
- b. Reactor Vessel (RHR Cut-in Permissive) Pressure - High 3 (1) 1, 2, 3 26
- c. RHR Equipment Area _ (1) 1, 2, 3 26 m A Temperature - High h
m d. RH1 Area Cooler (1) 1, 2, 3 _ 26 Teinperature - High
- e. Maiual Initiation 3 (1)/(group) 1, 2, 3 25
- 8. RilR SYSTEM STEAM CONDENSING MODE ISOLATION
- a. RHit Flow - High (d)
_ (1) 1, 2, 3 28
- b. Manual Initiation _ (1)/(valve) 1, 2, 3 25 s
8 m
41 -e' I TABLE 3.3.2-1 (Continued) EN 28 cggf ISOLATION ACTUATION INSTRUMENTATION , ACTION ACTION 20 - Be,in at least HOT SHUTDOWN within 12 hours and in COLD SHUT 00WN wit 5in the next 24 hours. ACTION 21 - Be in at least STARTUP with the associated isolation valves closed within 6 hours or-be in at least HOT SHUT 00WN within ACTION 22 - 12 hours and in COLD SHUTDOWN within the next 24 hours. ACTION 23 - Be in at least STARTUP within 6 hours. Close the Effected system isolation valves-within one hour and declare the affected system inoperable. ' ACTION 24 - Restore the manual initiation function to OPERABLE status within 48 hours or be in at least HOT SHUTDOWN within the next ACTION 25 - 12 hours m d in COLD SHUT 00WN within the following 24 hours. Restore th'e manual initiation. function to OPERABLE status within 8 hours or (close the affected system isolation valves within the next hour and declare the affected system inoperable.) ' (be in at ieast HOT SHUTDOWN within the next 12 hours and in ' COLD SHUTDOWN within the following 24 hours). ACTION 26 - Establish SECONDARY CONTAINMENT INTEGRITY with the standby gas treatment system operating within one hour. ACTION 27 - Lock the affected system isolation valves closed within one U hour and declare the affected system inoperable. NOTES When handling irradiated fuel in the secondary containment and during CORE ALTERATIONS and operations with a potential for draining the reactor vessel. May be bypassed with reactor steam pressure 5 1043 psig and all turbine stop valves closed. (a) A channel ma~y be placed in an inoperable status for up to 2 hourc for required surveillance without placing the trip system in the tripped con-dition provided at least one other OPERABLE channel in the same '. rip system is monitoring that parameter. (b) Also trips and isolates the mechanical vacuum pumps and steam jet air i ejector. , (c) Also starts the standby gas treatment system. 1 (d) Actuates valves E11-F008 and E11-F009 only. (e) A channel is OPERABLEsif 2 of 4 detectors in that channel are OPERABLE. (f) Closes only RWCU system isolation valve (s) HV-F001 and HV-F004. s (g) Requires RCIC system steam supply pressure-low coincident with drywell pressure-high. e' ' (h) Manual initiation isolates only and only with a coincident reactor /' vessel water level-low, level 3. s s V
- d. %
HOPE CREEK 3/4 3-16
s :,~
/
/' TABLE 3.3.2-2 ^
/
ISOLATION ACTUATION INSTRUMENTATION SETPOINTS n
- u ALLOWABLE
{ TRIPFUNCTIOj TRIP SETPOINT VALUE _
- 1. PRIMARY CONTAINMENT ISOLATION
- a. Re.ictor Vessel Water Level
- 1) Low, Level 3 > 12.5 inches *
- 2) Low Low, Level 2 > 11.0 inches 5 -38.0 inches
- i -45.0 inches
- 3) Low Low Low, Level 1 5 -129.0 inches *
- b. i -136.0 inches Drvwell Pressure - High {1.68psig i1.88psig i
- c. Reactor Building Exhaust d.
Raillation - High High Manual Initiation
<( )mR/hr** <( )mR/hr**
NA NA
- 2. SECONDAI:Y CONTAINMENT ISOLATION w a. Reactor Vessel Water Level -
; D Low Low, Level 2 > -38.0 inches * > -45.0 inches T b. Dr3we11 Pressure - High < 1.68 inches
) _< 1.88 inches i c. Refueling Floor Exhaust j Radiation - High High mR/hr.
$ I mR'nr.
) d. Reactor Building Exhat;<,t j Raciation - High High 5 mR/hr. mR/hr. 1 ) e. Refuel Floor Wall Exhaust Duct Raciation - liigh $( )mR/hr. 5( )mR/hr.
- f. Manual Initiation NA NA
- 3. MAIN STEAM LINE ISOLATION
- a. Reactor Vessel Water Level -
Low Low Low, level 1 > -129.0 inches * > -136.0 inches
- b. Main Steam Line < 3.0 X full power
! Radiation - High High < 3.6 X full power 6ackground 6ackground
- c. Main Steam Line Pressure - Low > 756.0 psig > 736.0 psig i
- d. Main Steam Line '
Flov - H,igh $ 108.7 psid i 111.7 piid to i 'c
=
=
m Q
TABLE 3.3.2-2 (Continued) 5 ISOLATION ACTUATION INSTRtiMENTATION SETPOINTS A n ALLOWABLb iX TRIP FUNCTION TRIP SETPOINT VALUE E MAIN STEAM LINE ISOLATION (Continued) '
- e. Condenser Vacuum - Low 1 8.5 inches Hg vacuum 17.6 inches Hg vacuum
- f. Main Steam Line Tunnel Temperature - High 5 (177)*F $ (184)*F
- g. Main Steam Line Tunnel A Temperature - High $ (99)*F $ (108)*F
- h. Manual ~ Initiation NA NA
- 4. REACTOR WATER CLEANUP SYSTEM ISOLATION
- a. RWCS A Flow - High 5 60.0 gpa $ 68.0 gin i b. RWCS A Flow - High Timer 1 45.0 seconds i 47.0 seconds T c. RWCS Area Temperature - High 5 (147)*F or (118.3)*F# $ (154)*F or (125.3)*F#
5 d. RWCS/ Area Ventilation A Temperature - High 5 (69)*F or (35.3)*F# $ (78)*F 3r (44.3)*F#
- e. SLCS Initiation NA NA
- f. Reactor Vessel Water Level -
Low Low, Level 2 1 -38.0 inches
- 1 -45.0 ixhes
- g. RWCS A Pressure - High 1( )psid 1( ) ps:d
- h. Manual Initiation NA NA
- 5. REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION
- a. RCIC Steam Line A Pressure - High 1 218.0" H 2O $ 228.0" H 2O
- b. RCIC Steam Line A Pressure - -> 3.0 seconds ~< 13.0 ser.onds High Timer c.
- c. RCIC Steam Supply Pressure - Low 1 64.0 psig 1 56.5 psig C
2 O
- d. RCIC Turbine Exhaust Diaphragm co Pressure - High 5 10.0 psig $ 20.0 psig g O!
TABLE 3.3.2-2 (C ntinued) g ISOLATION ACTUATION INSTRUMENTATION SETPOINTS o ALLOWA8LE TRIP FUNCTION TRIP SETPOINT [ VALUE y REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION Continued)
- e. RCIC Pump Room Temperature - High 1( )*F $ (167)*F 1( )*F 5 (174)*F
- f. RCIC Pump Room Ventilation Duct a Temperature - High 5 (89)*F $ (98)*F
- g. RCIC Pipe Routing Area Temperature - High ## ##
5 (167)*F $ (174)*F
- h. RCIC Pipe Routing Area A Temperature - High ## ##
5 (89)*F $ (98)*F
- i. RCIC Emergency Area Cooler Temperature - High 5 (147)*F $ (154)*F
- j. Manual Initiation NA NA
- 6. HIGH PRESSURE COOLANT INJECTION SYSTEM ISOLATION
{ y a. HPCI Steam Line Flow - liigh 5 337.0 inches H 2O 5 352.0 1.iches H 2O !$ b. IIPCI Steam Line Flow - High 1 3.0 seconds Timer 5 13.0 se onds
- c. HPCI Steam Supply Pressure - Low 1 100.0 psig > 90.u psig
- d. HPCI Turbine Exhaust Diaphragm Pressure - High 5 10.0 psig 5 20.0 psig
- e. HPCI Pump Room Temperature - liigh 5 (167)*F 5 (174)*F
- f. HPCI Pump Room Ventilation Ducts A Temperature - High 5 (89)*F $ (98)*F
- g. HPCI Emer0ency Area Cooler Temperature - High 5 (147)*F $ (154)*F
- h. IIPCI Pipe Routing Area Temperature - High ##
5 (167)*F $ (174)*F" g
- i. IIPCI Pipe Routing Area co a Temperature - liigh ## ##
5 (89)*F $ (98)*F o*
- j. Manual Initiation 'NA NA h
TABLE 3.3.2-2 (Continued) ISOLATION ACTUATION INSTRUMENTATION SETPOINTS o ALLOWABLF h x TRIP FUNCTION TRIP SETPOINT VALUE ,
- 7. RilR SYSTEM SilUTDOWN COOLING MODE ISOLATION
- a. Reactor Vessel Water Level -
Low, level 3 5 12.5 inches * > 11.0 1.1ches
- b. Reactor Vessel (RilR Cut-in Permissive) Pressure - High 5 82.0 psig 5 102.0 psig
- c. RilR Equipment Area a Temperature - liigh 5 (89)*F** $ (9t,.5)*F**
- d. RilR Area Cooler Temperature -
High 5 (167)"F** $ (170.5'*F** q e. RilR Flow - High ( ) ( )
- f. Manual Initiation NA NA E$
*See Bases Figure B 3/4 3-1.
4
** Initial setpoint. Final setpoint to be determined during startup test program. Any required change to this setpoint shall be submitted to the Commission within 90 days of test completion.
# Lower setpoints for TSH-G35-N600 E, F and TSH-G33-N602 E, F.
##15 minute time delay.
c d m
i TABLE 3.3.2-3 ISOLATION SYSTEM INSTRUMENTATION RESPONSE TIME TRIP FUNCTION RESPONSE TIME (Seconds)#
- 1. PRIMARY CONTAINMENT ISOLATION
- a. Reactor Vessel Water Level
- 1) Low, Level 3
- 2) Low Low, Level 2 $ (13)(a) 5 (1.0)*/5 (10){,)**
- b. Drywell Pressure - High -< (13)(a)
(c. Drywell and/or Suppression Chamber Radiation - High NA)
- d. Manual Initiation NA e.
- 2. SECONDARY CONTAINMENT ISOLATION
- a. Reactor Vessel Water Level-Low, Level 3 < a b.
c. Drywell Pressure - High 7(13)(a)) 13)( Refuel (gjoorHighExhaustDuctRadiation-High 3((13)(a)
- d. Railroad Access Shaft Exhaust Duct Radiation - High -(13)(a)
- e. Refuel (gjoorWallExhaustDuctRadiation-High $(13)(a)
- f. Unit 2 SGTS Actuation NA g .' Manual Initiation NA f.
~
- 3. MAIN STEAM LINE ISOLATION
- a. Reactor Vessel Water Level - Low Low, Level 2 $(13)(a)
- b. Main Steam Line Radiation - High(a)(b) <
c. d. Main Steam Line Pressure - Low 7(1. 0)*/<(13)({ (1.0)*/7 13) * ** *))*
- Main Steam Line Flow-High 7(0.5)*/5((13)(a),,
- e. Condenser Vacuum - Low TNA)
- f. Main Steam Line Tunnel Temperature - High (NA)
- g. Main Steam Line Tunnel A Temperature - High (NA)
- h. Manual Initiation NA 1.
~
- 4. REACTOR WATER CLEANUP SYSTEM ISOLATION
- a. RWCS a Flow - High b.
<(13)(a)(##)
RWCS Area Temperature - High (NA)
- c. SLCS Initiation (NA)
- d. SLCS Initiation NA
- e. Reactor Vessel Water Level - Low Low, Level 2
- f. <(13)(a)
RWCS A Pressure - High {NA)
- g. Manual Initiation NA h.
~
- 5. REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION
- a. RCIC Steam Line a Pressure - High <(13)(a)(###)
- b. RCIC Steam Supply Pressure - Low 7(13)(a)
- c. RCIC Turbine Exhaust Diaphragm Pressure - High [NA)
HOPE CREEK 3/4 3-21 9
^0 A 3 3 2~3 (Continued)
ISOLATION SYSTEM INSTRUMENTATION RESPONSE TIME TRIP FUNCTION RESPONSE TIME (Seconds)# REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION
- d. RCIC Equipment Room Temperature - Hioh
- e. (NA)
RCIC Equipment Room a Temperature - High (NA) f. RCIC Pipe Routing Area Temperature - High (NA)
- g. RCIC hpe Rot. ting Area A Temperature - High
- h. (NA)
RCIC Emergency Area Cooler Temperature - High (NA)
- 1. Manual Initiation NA d-6.
HIGH PRESSURE COOLANT INJECTION SYSTEM ISOLATION
- a. HPCI Steam Flow - High
- b. HPCI Steam Supply Pressure - Low <(13)(a)(####)
- c. 7(13)(*)
HPCI Turbine Exhaust Diaphragm Pressure - High {NA)
- d. HPCI Equipment Room Temperature - High
- e. (NA)
HPCI Equipment Jtoom a Temperature - High (NA) f. HPCI Emergency Area Cooler Temperature - High (NA)
- g. HPCI Pipe Routing Area Temperature - High
- h. (NA)
HPCI Pipe Routing Area A Temperature - High (NA)
- 1. Manual Initiation
- j. NA
- 7. ~
' RHR SYSTEM SHUTDOWN COOLING MODE ISOLATION 8: 281H8FV81181(#sRrbMAPeNYssyggl3 C 5(13/a) Pressure - High
- c. (NA)
RHR Equipment Area A Temperature - High (NA)
- d. RHR Area Cooler Temperature - High
- e. RHR Flow - High (NA)
- f. (NA)
Manual Initiation NA 9-(a) Isolation system instrumentation response time specifie includes diesel generator starting and sequence loading delays. (b) Radiation detectors are exempt from response time testing. Response time shall be measured from detector output or the input of the first electronic component in the channel.
- Isolation system instrumentation response time for MSIVs only. No diesel generator delays assumed for ( ) valves.
** Isolation system instrumentation response time for associated valves except MSIVs.
# Isolation system instrumentation response time specified for the Trip Function actuating each valve group shall be added to isolation time shown in Table 3.6.3-1 and 3.6.5.2-1 for valves in each valve group to obtain ISOLATION SYSTEM RESPONSE TIME for each valve. .
(##With time delay of (45) seconds.) (###With time delay of 13 + 0, -1) seconds.) (####With time delay of ( ) seconds.) HOPE CREEK 3/4 3-22
TABLE 4.3.2.1-1 5 m ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS O m CHANNEL OPERATIONAL R CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLAdCE REQUIRED
- 1. PRIMt.id CONTAINMENT ISOLATION
- a. Reactor Vessel Water Level -
- 1) Low, Level 3 S M R 1 , T., 3
- 2) Low Low, Level 2 S M R 1, 1:, 3
- b. Drywell Pressure - High NA M Q 1,2,3 (c. Drywell and/or Suppression Chamber Radiation - High S R 1, 2, 3)
- d. Manual Initiation NA M(M (,)) (R) NA 1, 2, 3 e.
} 2. SECONDARY CONTAINMENT ISOLATION c. w Reactor Vessel Water Level - 4 Low, Level 3 S M R 1, ;, 3 and *
- b. Drywell Pressure - High NA M Q 1, 2 , 3
- c. Refuel Floor liigh Exhadst Duct Radiation - High 5 M R 1, 2, 3 and *
- d. Railroad Access Shaft Exhaust Duct Radiation - High S M R 1, 2, 3 and *
- e. Refuel Floor Wall Exhaust Duct Radiation - High S M R 1, 2, 3 and *
- f. Unit 2 SGTS Actuation NA Q 1, 2, 3 and *
- g. Manual Initiation NA M (M (,)) (R) NA 1, 2, 3 and *
- h.
- 3. MAIN STEAM LINE ISOLATION
- a. Reactor Vessel Water Level -
Low Low, Level 2 S M R 1, 2. 3
- b. Main Steam Line Radiation - High S M R 1, 2, 3
- c. Main Steam Line Pressure - Low NA M Q L g C
- d. Main Steam Line
.e: "3 m
Flow - High S M R 3., 2, 3
- y Q &
m s
in , TABLE 4.3.2.1-1 (Co.itinued) % ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS n CHANNEL OPERATIONAL E CHANNEL FUNCTIONAL CHANNEL E CONDITI0NS FOR WHICH TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED MAIN STEAM LINE ISOLATION (Continued)
- e. Condenser Vacuum - Low NA M Q 1, 2**, 3**
- f. Main Steam Line Tunnel Temperature - High NA M Q 1,2,3 9 Main Steam Line Tunnel A Temperature - liigh NA M Q 1,2,3
- h. Manual Initiation NA (M(a)) (R) NA 1, 2, 3 1.
{ 4. REACTOR WATER CLEANUP SYSTEM ISOLATION y a. RWCS A Flow - liigh S M R 1, ', 3 % b. RWCS Area Temperature - High NA M Q 1,?,3
- c. RWCS Area Ventilation A Temperature - liigh NA M Q 1, 2, 3
- d. SLCS Initiation NA (M(b))(R) NA 1,2,3
- e. Reactor Vessel Water Level - Low Low, Level ? S M R 1,2,3
- f. RWCS A Pressure - liigh S M R 1,2,3
- g. Manual Initiation NA (M(a)) (R) NA 1,2,3
- h. _ _
y
- 5. REACTOR CORE ISOLATION COOLING SYSTEF ISOLATION
- a. RCIC Steam Line A g
w M Pressure - High NA M Q 1,/,3 co M
- b. RCIC Steam Supply Pressure -
Low NA M Q 1, ;', 3
=
- c. RCIC Turbine Exhaust Diaphragm Pressure - High NA M Q 1, 2, 3
( TABLE 4.3.2.1-1 (Continued) y ISOLATION ACTUATION INSTRUMENTATION-SURVEILLANCE REQUIREMENTS n CilANNEL OPERATIONAL iR CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH
$2 TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION (Continued)
- d. RCIC Equipment Room Temperature - High NA M Q 1, 2, 3
- e. RCIC Equipment Room A Temperature - High NA M Q 1, 2, 3
- f. RCIC Pipe Routing Area Temperature - High NA M Q 1, '. , 3
- g. RCIC Pipe Routing Area A Temperature - High NA M Q 1, ? , 3 t' h. RCIC Emergency Area Cooler Temperature - High NA M. Q 1, . , 3
- 1. Manual Initiation NA (MI ")) (R) NA 1,2,3 3- _
- 6. IIIGH PRESSURE COOLANT INJECTION SYSTEM ISOLATION
- a. HPCI Steam Line A Pressure - High NA M 'Q 1, 2, 3
- b. IIPCI Steam Supply Pressure - Low NA M Q 1,2,3
- c. HPCI Turbine Exhaust Diaphragm Pressure - High NA M Q 1, 1, 3
- d. HPCI Equipment Room Temperature .High NA M Q 1,2,3
- e. IIPCI Equipment Room c=
A Temperature - High NA M Q 1, l', 3 Ei! IIPCI Emergency Area f. Cooler Temperature - High NA M 1, I , 3 Q
- g. IlPCI Pipe Routing Area T.
Temperature - liigh NA M Q 1,2,3
2 o TABLE 4.3.2.1-1 (Continued) A ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS Q CHANNEL OPERA 1IONAL y CHANNFL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH
^ TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLAICE REQUIRED HIGli PRESSURE COOLANT INJECTION SYSTEM ISOLATION (Continued)
- h. IIPCI Pipe Routing Area a Temperature - liigh NA M Q 1, r , 3
- i. Manual Initiation NA (M(a)) (R) NA 1, 2, 3 j.
- 7. RilR SYSTEM SHUT 00WN COOLING MODE ISOLATION
- a. Reactor Vessel Water Level -
m Low, Level 3 S M R 1,2,3 D b. Reactor Vessel (RHR Cut-in y Permissive) Pressure - liigh NA M Q 1, 2, 3 -
~
m c. RHR Equipment Area A , Temperature - High NA M Q 1,2.3
- d. RilR Area Cooler Temperature -
liigh NA M Q 1,2,3
- e. RilR Flow - liigh S M R 1,2,3
- f. Manual Initiation NA (M(a)) (R) NA 1,2,3 9
( E E l
^ When with ahandling irradiated potential fuel inthe for draining the reactor secondary containment and during CORE ALTERATIONS and operations g vessel. e m, um
** When reactor steam pressure > (1043) psig and/or any turbine stop valve is open.
((a) Manual initiation switches shall be tested at least once per 18 months during shutdown. All other circuitry associated with manual initiation shall receive a CHANNEL FUNCTIONAL TEST at least once per 31 days as part of circuitry required to be tested for automatic system isolation.) ((b) Each train or logic channel shall be tested at least every other 31 days.) l
INSTRUMENTATION 3/4.3.3 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION JUN 2 8 533 LIMITING CONDITION FOR OPERATION 1.3.3 The emergancy core ennling :; '.em (CCCS) cciuotion in5trucienL6 tion channels shown in Table 3.3.3-1 shall be OPERABLE with their trip setpoints set consistent with the values who.1- in the Trip Setpoint column oi Table 3.3.3-2 and with EMERGENCY CORE COOLING SYSTEM RESPONSE TIAE as shown in Table 3.3.3-3. APPLICABILITY: As shown in Table 3.3.3-1. ACTION:
- a. With an ECCS actuation instrumentation channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.3.3-2, declare the channel inoperable until the channel is restored to OPERABLE status with its trip setpoint adjusted consistent with the Trip Setpoint value. ,
- b. With one or more ECCS actuation instrumentation channels inoperable, take the ACTION required by Table 3.3.3-1.
e SURVEILLANCE REOUIREMENTS 4.3.3.1 Each ECCS actuation instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations for the OPERATIONAL CONDITIONS and at the frequencies shown in Table 4.3.3.1-1. ! 4.3.3.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic operation of all channels shall be performed at least once per 18 months. 4.3.3.3 The ECCS RESPONSE TIME of each ECCS trip function shown in Table 3.3.3-3 shall be demonstrated to be within the limit at least once per 18 months. Each j test shall include at least one channel per trip system such that all channels I are tested at least once every N times 18 months where N is the total number ! of redundant channels in a specific ECCS trip system. HOPE CREEK 3/4 3-27
z TABLE 3.3.3-1 o E EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION 2 g MINIMUM OPERABLE x CHANNELS PER AFPLIC\BLE TRIP 0FERATIONAL TRIP FUNCTION FUNCTION (a) C_0NDITIONS ACTION
- 1. CORE SPRAY SYSTEM
- a. Reactor Vessel Water Level - Low Law Low, Level 1 2)I ) 1, 2, 3, 4 * , 5* 30
- b. Drywell Pressure - liigh " ((2)( ) 1, 2, 3 30
- c. Reactor Vessel Pressure - Low (Permissive) 2 1,2,3 31 4 *, 5* 32
- d. CSS Pump Discharge Flow - Low (Bypass) 1/ pump 1, 2, 3, 4*, 5* 33 l e. Manual Initiation (1)/(subsystem) 1, 2, 3, 4 * , 5* 34
! I-g> 2. LOW PRESSURE COOLANT INJECTION MODE OF RHR SYSTEM
- a. Reactor Vessel Water Level - Low Low Low, Level 1 (2) 1, 2, 1, 4*, 5* 30
- b. Drywell Pressure - High (2) 1, 2, 3 30 l
- c. Reactor Vessel Pressure - Low (Permissive) 2 1,2,3 31 1 4*, 55 32
- d. LPCI Pump Discharge Flow - Low (Bypass) 1/ pump 1,2,3,4*,5* 33
- e. Manual Initiation 1/ subsystem 1, 2, 3, 4*, 5* 34 f.
- 3. #
IIIGil PRESSURE COOLANT INJECTION SYSTEM
- a. Reactor Vessel Water Level - (Low Low Level 2) 4 1,2,3 35
- b. Drywell Pressure - liigh 1, 2, 3 35
- c. Condensate Storage Tank Level - Low 4(c) 2 1,2,3 36
- d. Suppression Pool Water Level - High 2 1, 2, 3 36
- e. Reactor Vessel Water Level - liigh, Level (8) 2(d) 1, 2, 1 31
- f. IIPCI l' ump Discharge Flow - Low (Bypass) 1 1,2,3 33
- g. Manual Initiation 1/ system 1, 2, 3 34 O
1 co h co m
x
'S TABLE 3.3.3-1 (Cont'd) m EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION
[2 x MINIMUM OPERABLE-CHANNELS PER APPLICABLE TRIP OPERATIONAL TRIP FUNCTION FUNCTION I ") CONDITIOlS_ ACTION
- 4. AUTOMATIC DEPRESSURIZATION SYSTEM #
- a. Reactor Vessel Water Level - Low Low Low, Level 1
- b. Drywell Pressure - High (2) 1, 2, 3 30
- c. ADS Timer (2) 1, 2, 3 30
- d. (1) 1, 2, 3 31 4
- Core Spray Pump Discharge Pressure - High (Permissive) (1)/ loop 1,2,3 31
- e. RHk LPCI Mode Pump Discharge Pressure - High i
(Permissive) (1)/(loop) 1, 2, 3
- f. 31
" Reactor Vessel Water Level - Low, Level 3 (Permissive) (1) 1, 2, 3 31
- g. Manual Initiation
- h. (1)/(valve) 1, 2, 3 34 MINIMUM APPLICABLE TOTAL NO. CHANNELS CHANNELS OPERATIONAL OF CHANNELS TO TRIP OPERABLE CONDITIONS ACTION
- 5. LOSS OF POWER 4 1. 4.16 kv Emergency Bus Under-voltage (Loss of Voltage) 1/ bus 1/ bus 1/ bus 1, 2, 3, 4**, 5**
- 2. 4.16 kv Emergency Bus Under- 37 voltage (Degraded Voltage) 3/ bus 2/ bus 2/ bus 1, 2, 3, 4**, 5** 38 (a) A channel may be placed in an inoperable status for up to 2 hours for required survei?lanse without placing the trip system in the tripped condition provided at least one OPERABLE channel i. the same trip system is monitoring that parameter.
' (b) Also actuates the associated emergency diesel generators.
(c) One trip system. Provides signal to HPCI pump suction valves only. (d) On 2 out of 2 logic, provides a signal to (close) (trip) HPCI pump (discharge valve) (turtine) only. When the system is required to be OPERABLE per Specification 3.5.2.
** Not required to be OPERABLE when reactor steam dome pressure is less than or equal to (100) psig. e Required when ESF equipment is required to be OPERABLE.
E O
=
., a ii
TABLE 3.3.3-1 (Continued) EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION JUN 2 8 1985 ACTION ACTION 30 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels oer Trip Function requirement:
- a. With one channel inoperable, place the inoperable channel in the tripped condition within one hour
- or declare the associated system inoperable.
- b. With more than one channel inoperable, declare the associated system inoperable.
ACTION 31 - With the number of OPERABLE channels less than required by the Minimum ' OPERABLE Channels per Trip Function requirement, declare the associated ECCS inoperable. ACTION 32 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, place the inoperable channel in the tripped condition within one hour ACTION 33 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, place the inoperable channel in the tripped condition within one hour; restore the inoperable channel to OPERABLE status within 7 days or declare the associated system inoperable. ACTION 34 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, restore the inoperable channel to OPERABLE status within 8 hours or declare the associated ECCS inoperable. ACTION 35 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement:
- a. For one trip system, place that trip system in the tripped condition within one hour
- or declare the HPCI system inoperable.
- b. For both trip systems, declare the HPCI system inoperable.
ACTION 36.- With the number of OPERABLE channels less than requircd by the Minimum OPERABLE Channels per Trip Function requirement, place at least one inoperable channel in the tripped condition within one hour
- or declare the HPCI system inoperable.
ACTION 37 - With the number of OPERABLE channels less than the Total Number of Channels, declare the associated emergency diesel generator
. inoperable and take the ACTION required by Specification 3.8.1.1 or 3.8.1.2, as appropriate.
ACTION 38 - With the number of OPERABLE channels one less than the Total Number of Channels, place the inoperable channel in the tripped
. condition within 1 hour;* operation may then continue until .
performance of the next required CHANNEL FUNCTIONAL TEST. ^The provisions of Specification 3.0.4 are not applicable. HOPE-CREEK 3/4 3-30
3; TABLE 3.3.3-2 c2 R$ EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION SETPOINTS n El ALLOWABLE 92 TRIP FUNCTION TRIP SETPOINT VALUE
- 1. CORE SPRAY SYSTEM
- a. Reactor Vessel Water Level - Low Low Low, Level 1 1-129 inches
- 1-136 inches
- b. Drywell Pressure - High 5 (1.69) psig 5 1.89 psig
- c. Reactor Vessel Pressure - Low 1 461 psig, decreasing 1 441 psig, decreasing
- d. CSS Pump Discharge Flow - Low >( ) gpm 1( ) gim
- e. Manual Initiation NA NA
- 2. LOW PRESSURE COOLANT INJECTION MODE OF RHR SYSTEM
- a. Reactor Vessel Water Level - Low Low Low, level 1 1(-129) inches
- 1(-136) inches en b. Drywell Pressure - High < (1.69) psgi < (1.89) psig 32 c. Reactor Vessel Pressure - Low [460psig, decreasing 5 (435) psig, decreasing y d.
e. LPCI Pump Discharge Flow -Low Manual Initiation
>( ) gpm 2( ) gpm g> NA. NA
- 3. HIGH PRESSURE COOLANT INJECTION SYSTEM
- a. Reactor Vessel Water Level - (Low Low, Level 2) 1-(38) inches
- l-(45) inches
- b. Drywell Pressure - High 5 (1.69) psig
- c. Condensate Storage Tank Level - Low 1 (X+3) inches (g) 5(1.89)osigg) 1 (X) incaes
- d. Suppression Pool Water Level - High 5 (Y-3) inches (gg) 5 (Y) incaes(gg)
- e. Reactor Vessel Water level - High, Level 8 5 54 inches 1 61.0 inches
- f. HPCI Pump Discharge Flow - Low 1( ) gpm 2( ) gp:
- g. Manual Initiation NA NA e
=
ba , 00 (Y
TABLE 3.3.3-2 (Continu::d) EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION SETPOINTS n All.0WALLE i g TRIP FUNCTION TRIP SETPOINT VALUE_ < ^ 4. AUTOMATIC DEPRESSURIZATION SYSTEM l a. Reactor Water Level - Low Low Low, Level 1 1-129 inches *- 1-136 inches
- b. Drywell Pressure - liigh 5 1.69 psig 5 1.89 psig
- c. ADS Timer < 105 seconds < 117 seconds
- d. Core Spray Pump Discharge Pressure - High [145psig,(increasing) [125psig,(increasing),
Subsystem A - 1 (155) psig, (increasing), Subsystem B . e. RilR LPCI Mode Pump Discharge Pressure-liigh 1 125 psig, increasing 2 (115) psig, (increasing) Subsystem A 2 (135) psig, (increasing),. Subsystem 8
- f. Reactor Vessel Water Level-Low, Level 3 2 12.5 inches 2 (11.0) inches .
- g. Manual Initiation NA NA g h. ADS Drywell Pressure Bypass Timer ( -)_ ( )
y 5. LOSS OF POWER i M
- a. 4.16 kv Emergency Bus Undervoltage a. 4.16 kv Basis - \
(Loss of Voltage (**)) 2975 1 30 volts 2975 1 63 volts a b. 120 v Basis - 85 1 0.85 volts 85 i 1.d volts
- c. 5 (10) sec. time delay 5 0.07 sec. time delay
- b. 4.16 kv Emergency Bus Undervoltage a. 4.16 kv Basis -
(Degraded Voltage) (3815)1(9) volts (3815)1(21) volts
- b. 120 v Basis -
(106.5)1(0.25) volts (109.0)1(0.60) volts
- c. (10)1(0.5) sec. time (10)1(1.0) sec. time delay delay
- See Bases Figure B 3/4 3-1. ~
g N' (** This is an inverse time delay voltage relay. The voltages shown are the maximum that wi 1 not result in a trip. Some voltage conditions will result in decreased trip times.) " co M (# X is value that ensures adequate NPSH and precludes air entry due to vortexing.) - (## Y is (5) inches above normal water level.) $ m .
F TABLE 3.3.3-3 EMERGENCY CORE COOLING SYSTEM RESPONSE TIMES JUN 2 8 1985 ECCS RESPONSE TIME (Seconds)
- 1. CORE SPRAY SYSTEM i 27
- 2. LOW PRESSURE COOLANT INJECTION MODE OF RHR SYSTEM $ 37
- 3. AUTOMATIC DEPRESSURIZATION SYSTEM NA
- 4. HIGH PRESSURE COOLANT INJECTION SYSTEM 5 25
- 5. LOSS OF POWER NA s
~. . ~
HOPE CREEK 3/4 3-33
5 TABLE 4.3.3.1-1 m EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS Qni CHANNEL E CHANNEL FUNCTIONAL OPERATIONAL CHANNEL CONDITIO.lS FOR WHICH TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLAICE REQUIRED
- 1. CORE SPRAY SYSTEM
- a. Reactor Vessel Water Level -
Low Low Low, Level 1 S M R 1, 2, 3, 4*, 5*
- b. Drywell Pressure - High S M R 1,2,3
- c. Reactor Vessel Pressure - Low S
- d. CSS Pump Discharge Flow - Low M R 1, 2, 3, 4*, 5*
S' R 1,2,3,4*,5*
- e. Manual Initiation NA H(M (,)) (R) NA 1,2,3,4*,5*
- 2. LOW PRESSURE COOLANT INJECTION MODE OF RHR SYSTEM
%
- a. Reactor Vessel Water Level -
ty Low Low Low, Level 1 S M R 1, 2, 3, 4*, 5* g b. Drywell Pressure - lii 0h S M R 1,2,3
- c. Reactor Vessel Pressure - Low S M d.
R 1,2,3,4*,5* LPCI Pump Discharge Flow - Low S R 1, 2, 3, 4*, 5*
- e. Manual Initiation NA M(M (,)) (R) NA 1, 2, 3, 4*, 5*
- 3. #
IIIGil PRESSURE COOLANT INJECTION SYSTEM
- a. Reactor Vessel Water Level -
(Low Low, Level 2) S M R 1,2,3
- b. Drywell Pressure - liigh S M R 1,2,3
- c. Condensate Storage Tank Level -
Low 5 M R 1,2,3
- d. Suppression Pool Water Level -
liigh S M R 1,2,3
- e. Reactor Vessel Water Level -
liigh, Level (8) S M f. R 1,2,3 IIPCI Pump Discharge Flow - Low S M R 1,2,3
- g. Manual Initiation NA (Mg ,)) (R) NA 1, 2, 3 h
3$ 2 ~A
z o TABLE 4.3.3.1-1 (Continued) E EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS 9 m x CHANNEL OPERATIONAL CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED
- 4. AUTOMATIC DEPRESSURIZATION SYSTEM
- a. Reactor Vessel Water Level -
Low Low Low, Level 1 S M R 1,2,3
- b. Drywell Pressure - High S M R 1, 2, 3
- c. ADS Timer NA M Q 1,2,3
- d. Core Spray Pump Discharge Pressure - High S M R 1,2,3
- e. RilR LPCI Mode Pump Discharge
- Pressure - High S M R 1,2,3 y f. Reactor Vessel Water Level - Low,
- Level 3 S R 1,2,3 y g. Manual Initiation NA M (M (,)) (R) NA 1,2,3 g h. ADS Drywell Pressure Timer NA M Q 1,2,3
- 5. LOSS OF POWER
- a. 4.16 kv Emergency Bus Under-voltage (Loss of Voltage) NA NA R 1, 2, 3, 4**, 5**
- b. 4.16 kv Emergency Bus Under-voltage (Degraded Voltage) S M R 1, 2, 3, 4**, 5**
((a) Manual initiation switches shall be tested at least once per 18 months during shutoown. All other circuitry associated with manual initiation shall receive a CHANNEL FUNCTIONAL, TEST at least once per 31 day as part of circuitry required to be tested for automatic system actuation.) When the system is required to be OPERABLE per Specification 3.5.2. Required OPERABLE when ESF equipment is required to be OPERABLE.
# Not required to be OPERABLE when reactor steam dome pressure is less than or equal to (100) psig.
L O
- h yu. wh
3/4.3.4 RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION ATWS RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION (Optional) LIMITING CONDITION FOR OPERATION 3.3.4.1 The anticipated transient without scram recirculation pump trip (ATWS-RPT) system instrumentation channels show. in Table 3 2.4.1-1 shel! L UPERaBLE Setpoint column witn of their trip 3.3.4.1-2. Table setpoints set consistent with values shown in the Trip APPLICABILITY: OPERATIONAL CONDITION 1. ACTION:
- a. With an ATWS recirculation pump trip system instrumentation channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.3.4.1-2, declare the channel inoperable until the channel is restored to OPERABLE status with the channel trip
'setpoint adjusted consistent with the Trip Setpoint value.
- b. With the number of OPERABLE channels one less than required by the Minimum OPERABLE Channels per Trip System requirement for one or both trip systems, place the inoperable channel (s) in the tripped condition within one hour.
- c. With the number of OPERABLE channels two or more less than required by the Minimum OPERABLE Channels per Trip System requirement for one trip system and:
- 1. If the inoperable channels consist of one reactor vessel water level channel and one reactor vessel pressure channel, place both inoperable channels in the tripped condition within one hour.
- 2. If the inoperable channels include two reactor vessel water level channels or two reactor vessel pressure channels, declare the trip system inoperable.
- d. With one trip system inoperable, restore the inoperable trip system to OPERABLE status within 72 hours or be in at least STARTUP within the next 6 hours.
- e. With both trip systems inoperable, restore at least one trip system to OPERABLE status within one hour or be in at least STARTUP within the next 6 hours.
SURVEILLANCE REOUIREMENTS 4.3.4.1.1. Each ATWS recirculation pump trip system instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations at the frequencies shown in Table 4.3.4.1-1. 4.3.4.1.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic operation of all channels shall be performed at least once per 18 months. HOPE CREEK 3/4 3-36
E E5 TABLE 3.3.4.1-1 ATWS RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION MINIMUM OPERABLE CHANNELS PER TRIP FUNCTION I ") TRIP SYSTEM
- 1. Reactor Vessel Water Level - 2 Low Low, Level 2
- 2. Reactor Vessel Pressure - High 2 R.
4 Y ti f i (a) One channel may be placed in an inoperable status for up to 2 hours for required surveillance provided the other channel is OPERABLE. e Y b gg m h- al
x TABLE 3.3.4.1-2 O g ATWS RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION SETPOINTS TRIP ALLOWABLE TRIP FUNCTION SETPOINT VALUE
- 1. Reactor Vessel, Water Level - -> -38 inches * > -45 in;hes Low Low, Level 2
- 2. Reactor Vessel Pressure - liigh 1 1071 psig 5 1086 psig M
u Y M
*See Bases Figure 83/4 3-1.
e O is n S
7 TABLE 4.3.4.1-1 ATWS RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREFENTS 9 m '!d CHANNEL CHANNEL FUNCTIONAL CHANNEL TRIP FUNCTION CHECK TEST CALIBRATION
- 1. Reactor Vessel Water Level - S M R Low Low, Level 2
- 2. Reactor Vessel Pressure - High S M R v
N u to
- bC 2
to co N J. 8?
INSTRUMENTATION !%}.kf hitf%4 i END-OF-CYCLE RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION mREV2L : LIMITING CONDITION FOR OPERATION 3.3.4.2 The end-of cycle recirculation pump trip (EOC-RPT) system instrumentation channels shown in Table 3.3.4.2-1 shall be OPERABLE with their trip setpoints set consistent with the values sh'own in the Trip Setpoint column of Table 3.3.4.2-2 and with the END-0F-CYCLE RECIRCULATION PUMP TRIP SYSTEM RESPONSE TIME as shown in Table 3.3.4.2-3. APPLICABILITY: OPERATIONAL CONDITION 1, when THERMAL POWER is greater than or equal to 30% of RATED THERMAL POWER. ACTION:
- a. With an.end-~of-cycle recirculation pump trip system instrumentation channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.3.4.2-2, declare the channel inoperable until the channel is restored to OPERABLE status with the channel setpoint adjusted consistent with the Trip Setpoint value.
b. With the number of OPERABLE channels one less than required by the Minimum OPERABLE Channels per Trip System requirement for one or both trip systems, place the inoperable channel (s) in the tripped condition within one hour.
- c. With the number of. 0PERABLE channels two or more less than required by the Minimum OPERABLE Channels per Trip System requirement for one trip system and: -
- 1. If the inoperable channels consist of one turbine control valve channel and orce turbine stop valve channel, place both inoperable channels in the tripped condition within one hour.
- 2. If the inoperable channels include two turbine control valve channels or two turbine stop valve channels, declare the trip system inoperable.
- d. With one trip system inoperable, restore the inoperable trip system to OPERABLE status within 72 hours or reduce THERMAL POWER to less than 30% of RATED THERMAL POWER within the next 6 hours.
- e. With both trip systems inoperable, restore at least one trip system to OPERABLE status within one hour or reduce THERMAL POWER to less than 30% of RATED THERMAL POWER within the next 6 hours.
HOPE CREEK 3/4 3-40
INSTRUMENTATION JL'N 2 8 1985 SURVEILLANCE REQUIREMENTS 4.3.4.2.1 Each end-of-cycle recirculation pu;np trip system instrumentation channel sh:11 ha demor.cteated 0?ERAELE by the p..ror,aance of tne CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations at the frequencies shown in r Table 4.3.4.2.1-1. 4.3.4.2.2. LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic operation of all channels shall be performed at least once per 18 months. 4.3.4.2.3 The END-OF-CYCLE RECIRCULATION PUMP TRIP SYSTEM RESPONSE TIM each trip function shown in Table 3.3.4.2-3 shall be demonstrated to be within its limit at least once per 18 months. Each test shall include at least the logic of one type of channel input, turbine control valve fast closure or turbine stop valve closure, such that both types of channel inputs are tested at least once per 36 months. (The time allotted for breaker arc suppression, ( ) ms, shall be verified by test at least once per 60 months.) i l l i HOPE CREEK 3/4 3-41
5 5 TABLE 3.3.4.2-1
!2 g END-OF-CYCLE RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION x
MINIMUM TRIP FUNCTION OPERABLECHANNE[g) PER TRIP SYSTEM
- 1. Turbine Stop Valve - Closure 2(b)
- 2. Turbine Control Valve-Fast Closure 2(b)
'l R.
.p 1
{ m (a)A trip system may be placed in an inoperable status for up to 2 hours for required surveillince provided that the other trip system is OPERABLE. (b)This function shall be automatically bypassed when turbine first stage pressure is less than or equal
, to ( ) psig, equivalent to THERMAL POWER less than 30% of RATED THERMAL POWER.
1 l 4
% 9 m
"Q m
u
, TABLE 3.3.4.2-2 END-OF-CYCLE RECIRCULATIdN PUMP TRIP SETPOINTS E m x ALLOWABLE TRIP FUNCTION TRIP SETPOINT VALUE
- 1. Turbine Stop Valve-Closure 5 5% closed 5 7% closed
- 2. Turbine Control Valve-Fast Closure 2 530 psig 2 465 psig V
N. Y O
=c I
.1
~
2 TABLE 3.3.4.2-3 m END-0F-CYCLE RECIRCULATION PUMP TRIP SYSTEM RESPONSE TIME i g 2 n TRIP FUNCTION RESPONSE TIME (Milleseconds)
- 1. Turbine Stop Valve-Closure 5 175
- 2. Turbine Control Valve-Fast Closure 5 175 i +
<. G3 4 < g f
f s e
/ $ ,}
s m 5=- )
- m e,
B: .. n
TABLE 4.3.4.2.1-1 5 A END-0F-CYCLE RECIRCULATION PUMP TRIP SYSTEM SURVEILLANCE REQUIREMENTS n i A CHANNEL W . FUNCTIONAL CHANNEL TRIP FUNCTION TEST CAllilRATION
- 1. Turbine Stop Valve-Closure M I*) R
- 2. Turbine Control Valve-Fas' Closure M I*) R w (^ Including trip system logic testing.) ' , .~
2 o , a l . G m 00
INSTRUMENTATION 3/4.3.5 REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION '55V 2 8 5 :,c LIMITING CONDITION FOR OPERATION i 3.3.5 The reactor core isolation cooling (RCIC) system actuation instrumentation channels shown in Table 3.3.5-1 shall be OPERABLE with their trip setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.3.5-2. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3 with reactor steam dome pressure greater than (100) psig. ACTION:
- a. With a RCIC system actuation instrumentation channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.3.5-2, declare the channel inoperable until the channel is restored to OPERABLE status with its trip setpoint adjusted consistent with the Trip Setpoint value.
- b. With one or more RCIC system actuation instrumentation channels inoperable, take the ACTION required by Table 3.3.5-1.
SURVEILLANCE REQUIREMENTS 4.3.5.1 Each RCIC system actuation instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations at the frequencies shown ~ in Table 4.3.5.1-1. 4.3.5.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic operation of all channels shall be performed at least once per 18 months. e HOPE CREEK 3/4 3-46 1
.. 1
5 A TABLE 3.3.5-1 REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION MINIMUM OPERABLECHANNEL{,) FUNCTIONAL UNITS PER TRIP SYSTEM ACTICN
- a. Reactor Vessel Water Level - Low Low, Level 2 2 50
- b. Reactor Vessel Water Level - High, Level 8 2(b) 51
- c. Condensate Storage Tank Water Level - Low (2)(c) 52
- d. Suppression Pool Water Level - High (2)(c) 52
- e. Manual Initiation 1/ system (d) 53 w
1 (a) A channel may be placed in an inoperable status for up to 2 hours for required survel': lance without placing the trip system in the tripped condition provided at least one other OPERABLE channel in the same trip system is mon.itoring that parameter. (b) One trip system with two-out-of-two logic. (c) One trip system with one-out-of-two logic. (d) One trip system with one channel. E'
=
x xs co %-=
~
9 TABLE 3.3.5-1 (Continued) REACTOR CORE ISOLATION COOLING SYSTEM dDi 2 8 1985 ACTUATION INSTRUMENTATION ACTION 50 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels pc- Trip Sysu m req & cm2nt:
- a. For one trip system, place the inoperable etnnel(s) and/or that trip system in the tripped condition within one hour or declare the RCIC system inoperable.
- b. For both trip systems, declare the RCIC system inoperable.
ACTION 51 - With the number of OPERABLE channels less than required by the minimum OPERABLE channels per Trip System requirement, declare the RCIC system inoperable. ACTION 52 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip System requirement, place at least one inoperable channel in the tripped condition within one hour or declare the RCIC system inoperable. ACTION 53 - With the number of OPERABLE channels one less than required by the Minimum OPERABLE Channels per Trip System requirement, restore the inoperable channel to OPERABLE status within 8 hours or declare the RCIC system inoperable. HOPE CREEK 3/4 3-48
5 A TABLE 3.3.5-2
- o x REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION SETPOINiS_
ALLOWABLE FUNCTIONAL UNITS TRIP SETPOINT VALUE
- a. Reactor Vessel Water Level - (Low Low, Level 2) 1 -38 inches
- 1 -45 inches
- b. Reactor Vessel Water Level - High, Level (8) $ 54 inches
- 5 61.0 irches
- c. Condensate Storage Tank Level - Low 1( ) inct#s ) inctes 1(
- d. Suppression Pool Water Level - High 5( ) inches 5( ) inches
- e. Manual Initiation NA NA R
c Y ^See Bases Figure B 3/4 3-1. 1 e c:3 s 8?
5 A TABLE 4.3.5.1-1 REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION SURVEILLANCE REQUIRLMENTS CHANNEL CHANtEL FUNCTIONAL CHANNEL FUNCTIONAL UNITS CHECK TEST CALIBRATION
- a. Reactor Vessel Water Level -
(Low Low, Level 2) S M R
- b. Reactor Vessel Water S M R Level - High, Level (8)
- c. Condensate Storage Tank Level - Low (S) M R
$ d. Suppression Pool Water Level -
y High (S) M (R)
- e. Manual Initiation NA (M(a)) (R) NA
((a) Manual initiation switches shall be tested at least once per 18 months during shutdown. All other circuitry associated with manual initiation shall receive a CHANNEL FUNCTIONAL TEST at least once per 31 days as part of circuitry required to be tested for automatic system actuation.)
- e O lit E,
g INSTRUMENTATION 3/4.3.6 CONTROL ROD BLOCK INSTRUMENTATION uh?i 2 8 1985 LIMITING CONDITION FOR OPERATION
' ? . 6. The control rod block inst.cuiaent4 Liv , cnannels snown in lable 3.3.6-1 shall be OPERABLE with their trip setpoints set consistent with the values shown in the Trip Setpoint columi, cf Table 3.3.6-2.
APPLICABILITY: As shown in Table 3.3.6-1. - ACTION:
- a. With a control rod block instrumentation channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.3.6-2, declare the channel inoperable until the channel is restored to OPERABLE status with its trip setpoint adjusted consistent with the Trip Setpoint value.
- b. With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, take the ACTION required by Table 3.3.6-1.
SURVEILLANCE REQUIREMENTS 4.3.6 Each of the above required control rod block trip systems and instrumentation channels shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations for the OPERATIONAL CONDITIONS and at the frequencies shown in Table 4.3.6-1. HOPE CREEK 3/4 3-51
TABLE 3.3.6-1 g CONTROL ROD BLOCK INSTRUMENTATION MINIMUM APPLICABLE O OPERABLE CilANNELS OPERATIONAL l2 TRIP FUNCTION PER TRIP FUNCTION CONDITIONS ACTION
- 1. R00 BLOCK MONITOR (a)
- a. Upscale 2 1* 60
- b. Inoperative. 2 1* 60
- c. Downscale 2 1* 60
- 2. APRM
- a. Flow Biased Neutron Flux -
Upscale 4 1 61
- b. Inoperative 4 1, 2, 5 61
- c. Downscale 4 1 61 .
- d. Neutron Flux - Upscale, Startup 4 2, 5 61
- 3. SOURCE RANGE MONITORS e a. Detector not full in(b) 3 2 61 1 2 5 61 Y b. Upscale (c) 3 2 61
- u. 2 5 61
- c. Inoperative (c) 3 2
- d. Downscale(d) 3 2 6 4.
INTERMEDIATE
- a. Detector not fullRANGE in "MONITORS *)) 6 2, 5 61
- b. Upscale 6 2, 5 61
- c. Inoperati 6 2, 5 61
- d. Downscale{g) 6 2, 5 61
- 5. SCRAM DISCHARGE VOLUME
- a. Water Level-liigh 2 1, 2, 5** 62
- b. Scram Trip Bypass 2 (1, 2,) 5** 62 '
- 6. REACTOR COOLANT SYSTEM RECIRCULATION FLOW
- a. Upscale 2 1 62
- b. Inoperative 2 1 62
- c. (Comparator) (Downscale) 2 1 62 EE C""3 se -g
- 7. REACTOR MODE SWITCil a.
b. Shutdown Mode Refueling Mode 2 34 62 [ h 2 5 62 @ m
TABLE 3.3.6-1 (Continued) CONTROL ROD BLOCK INSTRUMENTATION
,g gg ACTION ACTION 60 Declcr:: ths REM i.op cab!c and take se ACT L iequireo by Specification 3.1.4.3.
ACTION 61 - With the number of 3PERABLE Channels:
- a. One less than required by the Minimum OPERABLE Channels per Trip Function requirement, restore the inoperable channelto OPERABLE status within 7 days or place the inoperable channel in the tripped condition within the next hour.
- b. Two or more less than required by the Minimum OPERABLE Channels per Trip Function requirement, place at least '
one inoperable channel in the tripped condition within one hour. ACTION 62 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, place the inoperable channel in the tripped condition within one hour. NOTES With THERMAL POWER > (30)% of RATED THERMAL POWER. With more than one control rod withdrawn. Not applicable to control rods removed per Specification 3.9.10.1 or 3.9.10.2.
- a. The RBM shall be automatically bypassed when a peripheral control rod is selected (or the reference APRM channel indicates less than (30)% of RATED THERMAL POWER).
- b. This function shall be automatically bypassed if detector count rate is
> 100 cps or the IRM channels are on range (3) or higher.
- c. This function shall be automatically bypassed when the associated IRM channels are on range 8 or higher.
- d. This function shall be automatically bypassed when the IRM channels are on range 3 or higher.
- e. .This function shall be automatically bypassed when the IRM channels are on range 1.
HOPE CREEK 3/4 3-53
TABLE 3.3.6-2 CONTROL ROD BLOCK INSTRUMENTATION SETPOINTS E
- g. TRIP FUNCTION TRIP SETPOINT ALLOWABLE VALUE O 1. R0D BLOCK MONITOR -
p a. Upscale 5 0.66 W + 40% 5 0.66 W - 43% 3 b. Inoperative NA NA l c. Downscale 1 (5)% of RATED THERMAL POWER 1 (3)% of RATED THERMAL POWER
- 2. APRM i a. Flow Biased Neutron Flux -
Upscale < 0.66 W + 42%* < 0.66 W + 45%*
- b. Inoperative HA NA
- c. Downscale > 5% of RATED THERMAL POWER > 3% of RATED THERMAL POWER
- d. Neutron Flux - Upscale, Startup 312%ofRATEDTHERMALPOWER 314%ofRATEDTHERMALPOWER
- 3. SOURCE RANGE MONITORS
- a. Detector not full in NA NA
- b. Upscale 5 0 5 1.0 x 10 cps 5 1.6 x 10 cps
- c. Inoperative NA NA F d. Downscale 1 3 cps ** 1 1.8 cps
~ [ 4. INTERMEDIATE RANGE MONITORS 4 a. Detector not full in NA NA
- b. Upscale $ 108/125 divisions of < 110/125 divisions of full scale Tull scale
- c. Inoperative NA NA
- d. Downscale > 5/125 divisions of > 3/125 divisions of Tull scale full scali.
- 5. SCRAM DISCHARGE VOLUME
- a. Water Level-Hi0h '-< 72 inches above < 80 inchos above instrument zero Instrument zero
- b. Scram Trip Bypass NA NA
- 6. REACTOR COOLANT SYSTEM RECIRCULATION FLOW
- a. Upscale $ 108% of rated flow
- b. Inoperative $ 111% of rated flow NA NA
- c. Comparator 1 10% flow deviation 5 11% flow deviation
, 7. REACTOR MODE SWITCH
- a. Shutdown Mode NA NA
- b. Refueling Mode NA NA
*The Average Power Range Monitor rod block function is varied as a function of recirculation loop flow Ni c
C3 7 (W). The trip setting of this function must be maintained in accordance with Specification 3 2.2.
**May be reduced to 0.7 cps provided the signal-to-noise ratio is > 2.
M h, b c y _a
TABLE 4.3.6-1 CONTROL ROD BLOCK INSTRUMENTATI N SURVEILLANCE REQUIREMENTS n CHANNEL OPERATIONAL Ml CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH W TRIP FUNCTION CHECK TEST CALIBRATION (,) SURVEILLAUCE REQUIRED
- 1. ROD BLOCK MONITOR
- a. Upscale NA b)(c) (c) q 7,
- b. Inoperative NA S/U((b)(c)(c)
- c. Downscale S/U(b)(c),(c) NA 1*
NA S/U , q 7,
- 2. APRM.
- a. Flow Biased Neutron Flux - p Upscale (NA) S/U(b) (q) 7
- b. Inoperative NA S/U(b),gM NA 1, 2. 5
- c. Downscale (NA) H (Q) 1
- d. Neutron Flux - Upscale, Startup (NA) S/Uf,,,M S/U (Q) 2, 5 R 3. SOURCE RANGE MONITORS b a. Detector not full in NA S/U ,W NA 2, 5 a
- b. Upscale NA S/U W Q 2, 5
- c. Inoperative NA S/U(b),W NA 2, 5
- d. Downscale NA S/Ug),W ,
Q 2, 5
- 4. INTERMEDIATE RANGE MONITORS
- a. Detector not full in NA S/U ,W NA 2, 5
- b. Upscale NA W Q 2, 5
- c. Inoperative NA S/U(b),W S/U NA 2, 5
- d. Downscale NA S/Ug),W , Q 2, 5
- 5. SCRAM DISCHARGE VOLUME
- a. Water Level-High NA (M) (Q) R 1, 2, 5**
- b. Scram Trip Bypass NA M NA (1, 1,) 5**
- 6. REACTOR COOLANT SYSTEM RECIRCULATION FLOW
- a. Upscale NA S/U ,M Q 1
- b. Inoperative NA S/U M NA 1
- c. (Compat Mor) (Downscale) NA S/U(b),M , Q 1
- 7. REACTOR MODE SWITCil .
$::: C
- a. Shutdown Mode NA R NA 3, 4
- b. Refueling Mode NA R NA 5 co P 3
w
4 TABLE 4.3.6-1 (Continued) w[Ukl9' , CONTROL R0D BLOCX INSTRUMENTATION SURVEILLANCE REOUIREMENTS dW 2 8 igg 5 NOTES:
- a. Neutron detectors may be excluded from CHANNEL CALIBRATION.
- b. Within 24 hours prior to startup, if not performed within the previous 7 days.
- c. Includes reactor manual control' multiplexing system input.
With THERMAL POWER > (30)% of RATED THERMAL POWER. With more than one control rod withdrawn. Not applicable to control rods removed per Specification 3.9.10.1 or 3.9.10.2. 1
- HOPE CREEK 3/4 3-56
Ill INSTRUMENTATION i JUN 2 8 1985 3/4.3.7 MONITORING INSTRUMENTATION RADIATION MONITORING INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.7.1 The radiation monitoring instrumentation channels shown in Table 3.3.7.1-1 shall be OPERABLE with their alarm / trip setpoints within the specified limits. APPLICABILITY: As shown in Table 3.3.7.1-1. ACTION:
- a. With a radiation monitoring instrumentation channel alarm / trip setpoint exceeding the value shown in Table 3.3.7.1-1, adjust the setpoint to within the limit within 4 hours or declare the channel inoperable.
- b. With one or more radiation monitoring channels inoperable, take the ACTION required by Table 3.3.7.1-1.
- c. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.
SURVEILLANCE REQUIREMENTS 4.3.7.1 Each of the above required radiation monitoring instrumentation channels shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations for the conditions and at the frequencies shown in Table 4.3.7.1-1. 4 2 HOPE CREEK 3/4 3-57
- . _ _ . . _ _ . - - - _ - -.--- =
x TABLE 3.3:7.1-1 m RADIATION MONITORING INSTRUMENTATION Q l;; x MINIMUM CHANNELS APPLICABLE ALARM / TRIP INSTRUMENTATION OPERABLE CONDITIONS SETPOINT ACTION
- 1. Of f-Gas Pre-treatment Radiation Monitors 2 1, 2 <( ) mR/hrI *) 70 1 3 and
- 5( ) mR/hr 71 .
- 2. Of f-Gas Post-treatment 1 **
Radiation Monitor Table (3.3.7.11-1) 74 V
- 3. Main Control Room 2/(intake) 1,2,3,5 and ***
Ventilation Radiation $ (5) mR/hr 75 Monitor y 4. Standby Gas Treat- 1 1, 2, 3 and **** 5 (5) mR/hr(*) 74
- ment System Exhaust y Radiation Monitor v.
- 5. Area Monitors
- a. Criticality Monitors
- 1) New Fuel 1 # f 1 10 mR/hr *) '76 Storage Vault
- 2) Spent Fuel 1 ## f Storage Pool 1 2.5 mR/hr ') 76
- b. Control Room Direct 1 At all times 2.5 mR/hr(*) 76 i Radiation Monitor
- 6. Reactor Auxiliaries Cooling 1 At all times 9 x 10 5 pc/cc(*) 76 Radiation Monitor
- 7. Safety Auxiliaries Cooling I/ loop At all times 6 x 10 5 pc/ccI ') 76 Radiation Monitor b' ' O
" Mc3 m
_= '_]
.t 4
i TABLE 3.3.7.1-1 (Continued)
- y{ RADIATION MONITORING INSTRUMENTATION
!2 El TABLE NOTATION x
*When the main condenser air evacuation system is in operation.
**When the off gas treatment system is in operation.
***When irradiated fuel is being handled in the secondary containment.
****When irradiated fuel is being handled in the secondary containment and during CORE ALTERATIONS and operations with a potential for draining the reactor vessel. ~
#With fuel in the new fuel storage vault.
i
##With fuel in the spent fuel storage pool.
j (a) Time delay before off gas system holdup discharge valve closure i seconds. 4 (b)Also isolates the primary and secondary containment purge and vent penetrations, valve group (s)( ). (c)Also starts the standby gas treatment system. (d)Also isolates the secondary containment purge and vent penetrations, valve group (s) ( ). (e) Alarm only. R> Y w LD i i i f N h i
?o 00 t
VO b
B TABLE 3.3.7.1-1 (Continued) wa ~ as ! RADIATION MONITORING INSTRUMENTATION M 28 tog ACTION f.CTION 70 -
- a. With one of the required monitors inoperable, place the inonerable channel in the downscale tripped condition within one hour.
- b. With both of the required monitors inoperable, be in at least HOT SHUTDOWN within 12 hours.
ACTION 71 - With the required monitor inoperable, verify that the offgas treatment system is not bypassed and that the offgas post-treatment monitor is OPERABLE; otherwise, be in at least COLD SH'JTDOWN 24 hours. Restore the inoperable monitor to OPERABLE status prior to entering OPERATING CONDITION 3. ACTION 72 -
- a. With one of the required monitors inoperable, place the inoperable channel in the downscale tripped condition within one hour.
- b. With two of the required monitors inoperable, shutdown the (primary and secondary) containment ventilation systems and isolate the primary and secondary purge and vent penetrations within 12 hours.
ACTION 73 -
- a. With one of the required monitors inoperable, place the inoperable channel in the (downscale) tripped condition within one hour.
- b. With two of the required monitors inoperable, initiate and maintain operation of at least one standby gas treatment subsystem within 12 hours.
! ACTION 74 - With the required monitor inoperable, verify that the accident monitor on this release line shown on Table (3.3.7.5-1) is OPERABLE and restore the inoperable monitor to OPERABLE status l within 7 days. Otherwise, declare this system inoperable. ACTION 75 -
- a. With one of the required monitors inoperable, place the inoperable
- channel in the (downscale) tripped condition within one hour;.
l restore the inoperable channel to OPERABLE status within 7 days, j or, within the next 6 hours, initiate and maintain operation of ! the control room emergency filtration system in the (isolation) l mode of operation. i b. With both of the required monitors inoperable, initiate and maintain operation of the control room emergency filtration system in the (isolation) mode of operation within one hour. i l HOPE CREEK 3/4 3-50 l
TABLE'3.3.7.1-1 (Continued) JUN 2 8 1985 RADIATION MONITORING INSTRUMENTATION ACTION (Continued) ACTION 76 - With the required monitor inoperable, perform area surveys of the monitorad area with port.-kla meritoring instru=entation at least once per 24 hours. HOPE CREEK 3/4 3-61
Eg TABLE 4.3.7.1-1 RADIATION MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS
- o
"? OPERATIONAL CHANNEL CONDITIONS FOR CilANNEL FUNCTIONAL CHANNEL WhICH SURVEILLANCE INSTRUMENTATION CHECK TEST CALIBRATION REQUIRED
- 1. Off-Gas Pre-treatment Radiation Monitor S M R 1, 2, 3 and *-
- 2. Off-Gas Post -
Treatment Radiation Monitor S M R **
- 3. Main Control Room Ventilation Radiation Monitor S M R 1, 2, 3, 5 and ***
x
- 4. Standby Gas Treatment System Y Exhaust Radiation Monitor S M R 1, 2, 3, and ****
O S. Area Monitors
- d. Criticality Monitors
- 1) New Fuel Storage S M R #
Vault
- 2) Spent Fuel Storage S M R ##
Pool
- b. Control Room Direct S M R At all times Radiation Monitor
- 6. Reactor Auxiliaries Cooling S M R At all times Radiation Monitor
- 7. Safety Auxiliaries Cooling S M R At all times Radiation Monitor
~
co f
x TABLE 4.3.7.1-1 (Continued) RADIATION HONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS 9
- TABLE NOTATION
#With fuel in the new fuel storage vault.
##With fuel in the spent fuel storage pool.
*When the main condenser air evacuation system is in operation.
**When the off gas treatment system is in operation.
***When irradiated fuel is being handled in the secondary containment.
****When irradiated fuel is being hadnled in the secondary containment and during CORE ALTERATIONS and operations with a potential for draining the reactor vessel.
R. C kPg3 co
INSTRUMENTATION JUN 2 8 1995 SEISMIC MONITORING' INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.7.2 The seismic mon'itoring instrun ntation shown in Table 3.3.7.2 1(*) shall be OPERABLE. APPLICABILITY: At all times. ACTION:
- a. With one or more of the above required seismic monitoring instruments inoperable for more than 30 days, in lieu of any other report required by Specification 6.9.1, prepare and submit a Special Report to the Commissisn pursuant to Specification 6.9.2 within the next 10 days outlining the cause of the malfunction and the plans for restoring the instrument (s) to OPERABLE status.
- b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.
- SURVEILLANCE REQUIREMENTS 4.3.7.2.1 Each of the above required seismic monitoring instruments shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNC-TIONAL TEST and CHANNEL CALIBRATION operations at the frequencies shown in Table 4.3.7.2-1.
4.3.7.2.2 Each of the above required seismic monitoring instruments actuated during a seismic event greater than or equal to (0.01)g shall be restored to OPERABLE status within 24 hours and a CHANNEL CALIBRATION performed within i 5 days following the seismic event. Data shall be retrieved from actuated instruments and analyzed to determine the magnitude of the vibratory ground l motion. In lieu of any other report required by Specification 6.9.1, a Special l Report shall be prepared and submitted to the Commission pursuant to Specifica-l tion 6.9.2 within 10 days describing the magnitude, frequency spectrum and resultant effect upon unit features important to safety. 3 . HOPE CREEK 3/4 3-64 L
TABLE 3.3.7.2 3 SEISMIC MONITORING INSTRUMENTATION M MINIMUM MEASUREMENT INSTRUMENTS INSTRUMENT 9 AND_ SENSOR LOCATIONS DANGF OPERAB!E
- 1. Triaxial Time-History Accelerographs
- a. 500' From Reactor Building i 1G 1 Free Field, 60' Below Grade
- b. Primary Containment Foundation, t 1G 1 Room 4101
- c. Refueling Floor in Reactor 1G 1 Building
- d. Core Spray Piping in Drywell i 1G 1
- e. Auxiliary Building Foundation i 1G 1
- 2. Triaxial Peak Accelerographs
- a. Reactor Support lateral Truss SG 1
- b. Core Spray Piping in Drywell
- SG 1
- c. Service Water Pump Piping i SG 1
- 3. Triaxial Seismic Switches
- a. Primary Containment Foundation, NA 1(a)
Room 4101 (Trigger)
- b. Primary Containment Foundation, NA 1(,)
Room 4101 (Switch)
- 4. Triaxial Response-Spectrum Recorders
- a. Primary Containment Foundation 1.0 -32.0 Hz 1 (north-south)
- b. Primary Containment Foundation 1.0 -32.0 Hz 1 (east-west)
- c. Primary Containment Foundation 1.0 -32.0 Hz 1 (vertical)
(a)With reactor control room indication and annunciation. i HOPE CREEK 3/4 3-65
$- . TABLE 4.3.7.2-1 ill LX SEISMIC MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS JUN 2 8 1985 CHANNEL CHANNEL FUNCTIONAL CHANNEL INSTRUMENTS AND SENSOR LOCATIONS CHECK TEST CALIBRATION
- 1. Teiaxial Time-History Accelerographs
- a. 500' From Reactor Building M SA d Free Field, 60' Below Grade
- b. Primary Containment M SA R Foundation, Room 4101
- c. Refueling Floor in Reactor M SA R Building
- d. Core Spray Piping in Drywell M SA R
- e. Auxiliary Building Foundation M SA R
- 2. Triaxial Peak Accelerographs
- a. Reactor Support lateral NA NA R Truss
- b. Core Spray Piping in Drywell NA NA R
- c. Service Water Pump Piping NA NA R
- 3. Triaxial Seismic Switches
- a. Primary Containment M SA R Foundation, Room 4101 (Trigger)
- b. Primary Containment M SA R Foundation Room 4101 (Switch)
- 4. Triaxial Response-Spectrum Recorders t
! a. Primary Containment NA SA R Foundation (north-south)
- b. Primary Containment M SA R Foundation (east-west)
- c. Primary Containment M SA R Foundation (vertical) l l
HOPE CREEK 3/4 3-66 I
INSTRUMENTATION , ((a w {i sa l METEOROLOGICAL MONITORING INSTRUMENTATION l LIMITING CONDITION FOR OPERATION 3.3.7.3 The meteorological monitoring instrumentation channels shown in Table 3.3.7.3-1 shall ce OPERABLE. APPLICABILITY: At all times. ACTION:
- a. With one or more meteorological monitoring instrumentation channels inoperable for more than 7 days, in lieu of any other report required by Specification 6.9.1, prepare and submit a Special Report to the Commission pursuant to Specification 6.9.2 within the next 10 days outlining the cause of the malfunction and the plans for restoring the instrumentation to OPERABLE status.
- b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.
SURVEILLANCE REQUIREMENTS 4.3.7.3 Each of the above required meteorological monitoring instrumentation channels shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK and CHANNEL CALIBRATION operations at the frequencies shown in Table 4.3.7.3-1. HOPE CREEK 3/4 3-67
TABLE 3.3.7.3-1 DRAFf JL'N 2 8 1935 METEOROLOGICAL MONITORING INSTRUMENTATION MINIMUM INSTRUMENTS INSTRUMENT OPERABLE
- a. Wind Speed
- 1. Elev. 33 ft. 1
- 2. Elev. 150 ft. 1
- 3. Elev. 300 ft. 1
- b. Wind Direction
- 1. Elev. 30 ft. 1
- 2. Elev. 150 ft. 1
- 3. Elev. 300 ft. 1
- c. Air Temperature Difference
. 1. Elev. 33/150 ft. 1
- 2. Elev. 33/300 ft. 1 HOPE CREEK 3/4 3-68 4
DRAFT
, TABLE 4.3.7.3-1 METEOROLOGICAL MONITORING INSTRUMENTATION SURVEILLANCE REQUIREME 7985 CHANNEL CHANNEL INSTRUMENT CHECK CALIBRATION
- a. *'ind Speed 1 Elev. 33 ft. D SA
- 2. Elev. 150 ft. D SA
- 3. Elev. 300 ft. D SA
- b. Wind Direction
- 1. Elev. 33 ft. D SA
- 2. Elev. 150 ft. D SA
- 3. Elev. 300 ft. D SA
- c. Air Temperature Difference
- 1. Elev. 33/150 ft. D SA
- 2. Elev. 33/300 ft. D SA HOPE CREEK 3/4 3-69
INSTRUMENTATION , I'sh
!)s b al^8 (i
?
REMOTE SHUTOOWN MONITORING INSTRUMENTATION JUN 2 8 585 LIMITING CONDITION FOR OPERATION 3.3.7.4 The remote shutdown -onitoring instrumentation chain.ols shewn in Table 3.3.7.4-1 shall be OPERABLE with readouts displayed external to the control room. APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. ACTION:
- a. With the number of OPERABLE remote shutdown monitoring instrumentation channels less than required by Table 3.3.7.4-1, restore the inoperable channel (s) to QPERABLE status within 7 days or be in at least HOT SHUTDOWN within the next 12 hours.
- b. The provisions of Specification 3.0.4 are not applicable.
SURVEILLANCE REQUIREMENTS 4.3.7.4 Each of the above required remote shutdown monitoring instrumentation channels shall be demonstrated OPERABLE by performance of the CHANNEL CHECK and CHANNEL CALIBRATION operations at the frequencies shown in Table 4.3.7.4-1. l t 1 i e HOPE CREEK 3/4 3-70 l
2 o TABLE 3.3.7.4-1 m REMOTE SHUTDOWN MONITORING INSTRUMENTATION 2 m E READOUT MINIMHM LOCATION INSTRUMENTS INSTRUMENT PANEL OPERABLE
- 1. Reactor Vessel Pressure 10C399 1
- 2. Reactor Vessel Water Level 10C399- 1
- 3. Safety / Relief Valve Position, (3) valves 10C399 1/(valve)
- 4. Suppression Chamber Water Level 10C399 1
- 5. Suppression Chamber Water Temperature 10C399 1
- 6. Suppression Chamber Air Temperature 1 w
h 7. Drywell Pressure 1
- 8. Drywell Temperature 1
- 9. RHR System Flow 10C399 1
- 10. Safety Auxiliary Cooling System Flow 10C399 1
- 11. Safety Auxiliary Cooling System Temperature 10C399 1
- 12. RCIC System Flow 10C399 1
- 13. RCIC Turbine Speed 10C399 1 E: O 5:
W b
=Q
.a 9
vu TABLE 4.3.7.4-1 E A REMOTE SHUTDOWN MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS 2 m W CHANNEL CHANNEL INSTRUMENT CHECK CALIBRATION
- 1. Reactor Vessel Pressure M R
- 2. Reactor Vessel Water Level M R ~
- 3. Safety / Relief Valve Position M NA
- 4. Suppression Chamber Water Level M R
- 5. Suppression Chamber Water Temperature M R o 6. Suppression Chamber Air Temperature' M R 1
w 7. Drywell Pressure M R d
- 8. Drywell Temperature M R
- 9. RilR System Flow M R
- 10. Safety Auxiliary Cooling System Flow M R
- 11. Safety Auxiliary Cooling System Temperature M R
- 12. RCIC System Flow M R
- 13. RCIC Turbine Speed M R p.
- 14. ' - '
# f f ,
p
INSTRUMENTATION , JUN 2 8 1985 ACCIDENT MONITORING INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.7.5 The accident monitoring instrumentation channels shown in Table 3.3.7.5 2 shall be OPERABLE. APPLICABILITY: As shown in Table 3.3.7.5-1. ACTION: Witt, one or more accident monitoring instrumentation channels inoperable, take the ACTION required by Table 3.3.7.5-1. SURVEILLANCE REQUIREMENTS 4.3.7.5 Each of the above required accident monitoring instrumentation channels shall be demonstrated OPERABLE by performance of the CHANNEL CHECK and CHANNEL CALIBRATION operaticns at the frequencies shown in Table 4.3.7.5-1. 1 s t 1 HOPE CREEK 3/4 3-73
TABLE 3.3.7.5-1 5 ACCIDENT MONITORING INSTRUMENTATION m . g MINIMUM AlPLICABLE p REQUIRED NUMBER CHANNELS OPERATIONAL X INSTRUMENT OF CilANNELS OPERABLE CONDITIONS ACTION
- 1. Reactor vessel Pressure 2 1 1,2,3 80
- 2. Reactor Vessel Water Level 2 1 1,2,3 80 l 3. Suppression Chamber Water Level 2 1 1,2,3 80,
- 4. Suppression Chamber Water Temperature 2/ sector 1/ sector 1,2,3 80 .
- 5. Suppression Chamber Air Temperature 2 1 1,2,3 80 l, 6. Drywell Pressure 2 1 1,2,3 80
{ 7. Drywell Air Temperature 2 1 1,2,3 80 l y 8. Drywell Oxygen Concentration 2 1 1,2,3 80 l 5 9. Drywell llydrogen Concentration Analyzer and Monitor 2 1 1,2,3 80
- 10. Safety / Relief Valve Position Indicators 2/ valve 1/ valve 1,2,3 80 l 11. In-Core Thermocouples (4)/(1 per core (2)/(1 each 1,2,3 80 quadrant) of two care quadrants) 12/ Primary Containment Gross Radiation Monitors 2 1 1,2,3 81 13., Reactor Building Ventilation Exhaust Monitor # 1 1 1,2,3 81
- 14. Offgas and Radwaste Area Exhaust Monitor # 1 1 1,2,3 81
- 15. Fuel llandling Area Ventilation Exhaust Monitor # 1 1 1,2,3 81
- 16. Turbine Building Ventilation Exhaust Monitor # 1 1 1,2,3 81
- 17. Filtration, Recirculation and ventilationr 1 1 1,2,3 81 Syste.n Exhaust Monitor #
#lligh range noisle gas monitors.
- e a
m 3
Table 3.3.7.5-1 (Continued) h w8D
\('
ACCIDENT MONITORING INSTRUMENTATION 2 8 1985 ACTION STATENENTS ACTION 80 -
- a. With the number of OPERABLE accident monitoring instrumentation channels less than the Required Number of Channels shown in Table 3.3.7.5-1, restore the inoperable channel (s) to OPERABLE status within days or be in at least HOT SHUTDOWN within the next 12 houn.
- b. With the number of OPERABLE accident monitoring instrumentation channels less than the Minimum Channels OPERABLE requirements of Table 3.3.7.5-1, restore the inoperable channel (s) to OPERABLE status within 48 hours or be in at least HOT SHUTDOWN within the next 12 hours.
ACTION 81 - With the number of OPERABLE accident monitoring instrumentation channels less than required by the Minimum Channels OPERABLE requirement, either restore the inoperable channel (s) to OPERABLE status within 72 hours, or:
- a. Initiate the preplanned alternate method of monitoring the appropriate parameter (s), and
- b. In lieu of any other report required by Specification 6.9.1, prepare and submit a Special Report to the Commission pursuent to Specification 6.9.2 within 14 days following the event outlining the action taken, the cause of the inoperability and the plans and schedule for restoring the system to OPERABLE status.
HOPE CREEK 3/4 3-75
TABLE 4.3.7.5-1 I g ACCIDENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS F2 APPLICABLE g CilANNEL CHANNEL OPERATIONAL INSTRut1ENT CllECK CALIBRATION CONDITIONS
- 1. Reactor Vessel Pressure M R 1,2,3
- 2. Reactor Vessel Water tevel M R 1,2,3
- 3. Suppression Chamber Water Level M R 1,2,3
- 4. Suppression Chamber Water Temperature H R 1,2,3 ,
- 5. Suppression Chamber Air Temperature M R 1,2,3 .
- 6. Primary Containment Pressure M R 1,2,3
- 7. Drywell Air Temperature M R 1,2,3
- 8. Drywell Oxygen Concentration M R 1,2,3-Ed 9. Drywell flydrogen Concentration Analyzer and Monitor M 0* 1,2,3 .
- 10. Safety / Relief Valve Position Indicators M R 1,2,3 .
g 11. In-Core Thermocouples M R 1,2,3
- 12. Primary Containment Gross Radiation lionitors M R** 1,2,3
- 13. Reactor Building Ventilation Exhaust Monitor # M R \
1,2,3
- 14. Offgas and Radwaste Area Exhaust Monitor # M R 1,2,3
- 15. Fuel llandling Area Ventilation Exhaust Monitor # M R 1,2,3 16.' Turbine Buidling Ventilation Exhaust Monitor # M R 1,2,3
- 17. Filtration, Recirculation and Ventilation M R 1,2,3 System Exhaust Monitor #
*Using sample gas containing: '
- a. One volume percent hydrogen, balance nitrogen.
- b. Four volume percent hydrogen, balance nitrogen.
**CllANNEL CALIBRATION shall consist of an electronic calibration of the channel, not including the detector, for range decades above 10 R/hr and a one point calibration check of the detector ~below 10 R/hr with an , g installed or portable gamma source.
#11igh range noble gas monitors. Q 2
to 0.>
INSTRUMENTATION . DEFT SOURCE RANGE MONITORS JUN 2 8 1985 LIMITING CONDITION FOR OPERATION 3.3.7.6 At least the following source range monitor channels shall be OPERABLE:
- a. In OPERAfl0nAL COND1110N 2", three,
- b. In OPERATIONAL CONDITION 3 and 4, two.
APPLICABILITY: OPERATIONAL CONDITIONS 2*, 3 and 4. ACTION:
- a. In OPERATIONAL CONDITION 2* with one of the above required source range monitor channels inoperable, restore at least 3 source range monitor channels to OPERABLE status within 4 hours or be in at least HOT SHUTDOWN within the next 12 hours.
- b. In OPERATIONAL CONDITION 3 or 4 with one or more of the above required source range monitor channels inoperable, verify all insertable control rods to be inserted in the core and lock the reactor mode switch in the Shutdown position within one hour.
SURVEILLANCE REQUIREMENTS 4.3.7.6 Each of the above required source range monitor channels shall be demonstrated OPERABLE by:
- a. Performance of a:
- 1. CHANNEL CHECK at least once per:
a) 12 hours in CONDITION 2*, and b) 24 hours in CONDITION 3 or 4.
- 2. CHANNEL CALIBRATION ** at least once per 18 months.
- b. Performance of a CHANNEL FUNCTIONAL TEST:
- 1. Within 24 hours prior to moving the reactor mode switch from the Shutdown position, if not performed within the previous 7 days, and
- 2. At least once per 31 days.
I c. Verifying, prior to withdrawal of control rods, that the SRM count , rate is at least 3 cps *** with the detector fully inserted.
"With IRM's on range 2 or below.
** Neutron detectors may be excluded from CHANNEL CALIBRATION.
***May be reduced to 0.7 cps provided the signal-to-noise ratio is > 2.
HOPE CREEK 3/4 3-77
INSTRUMENTATION
- 7" wit if TRAVERSING IN-CORE PROBE SYSTEM LIMITING CONDITION FOR OPERATION 5.3.7.7. ine craversing in-core probe system shall be OPERABLE with:
a. Five and movaole detectors, drives and readout equipment to map the core, b. Indexing equipment to allow all five detectors to be calibrated in a common location. APPLICABILITY: When the traversing in-core probe is used for:
- a. Recalibration of the LPRM detectors, and b.* Monitoring the APLHGR, LHGR, MCPR, or NFLPD.
ACTION: With the traversing in-core probe system inoperable, suspend use of the system for the above applicable monitoring or calibration functions. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable. SURVEILLANCE REQUIREMENTS 4.3.7.7 The traversing in-core probe system shall be demonstrated OPERABLE by normalizing each of the above required detector outputs within 72 hours prior to use for the above applicable monitoring or calibration functions. "Only the detector (s) in the required measurement location (s) are required to be OPERABLE. HOPE CREEK 3/4 3-78
INSTRUMENTATION , b Uj d[U j l N CHLORINE (AND AMMONIA) OETECTION SYSTEM (Optional) 8 E65 LIMITING CONDITION FOR OPERATION 3.3.7.8 Two independent chlorine (and ammonia) detection system subsyster..; shall be OPERABLE with their (alarm) (trip) setpoints adjusted to actuate at a:
- a. Chlorine concentration of less than or equal to (5) ppm, and
- b. Ammonia concentration of less than or equal to ( ) ppm.
l APPLICABILITY: All OPERATIONAL CONDITIONS.
, ACTION:
- a. With one chlorine (and/or one ammonia) detection subsystem inoperable, restore the inoperable detection system to OPERABLE status within 7 days or, within the next 6 hours, initiate and maintain operation of at least one control room emergency filtration system subsystem in the (isolation) mode of operation.
- b. With both chlorine (and/or ammonia) detection subsystems inoperable, within one hour initiate and maintain operation of at least one control room emergency filtration system subsystem in the (isolation) mode of operation.
- c. The provisions of Specification 3.0.4 are not applicable.
SURVEILLANCE REQUIREMENTS 4.3.7.8 Each of the above required chlorine (and ammonia) detection system subsystems shall be demonstrated OPERABLE by performance of a:
- a. CHANNEL CHECK at least once per 12 hours,
- b. CHANNEL FUNCTIONAL TEST at least once per 31 days, and
- c. CHANNEL CALIBRATION at least once per 18 months.
5 HOPE CREEK 3/4 3-79
TABLE 3.3.7.9-1
)
CHLORIDE INTRUSION MONITORS gg,,12 8 ggg MINIMUM FUNCTIONAL UNIT OPERABLE CHANNELS
- 1. C%1ncide d:tc-tors in the con- (4) denser hotwell outlet headers
- 2. Chloride detectors in the 1 condensate pump discharge
- 3. Chloride detector in the inlet 1 to the demineralizer bank l
J i HOPE CREEK 3/4 3-80
INSTRUMENTATION a'i J - FIRE DETECTION INSTRUMENTATION ' UN 2 8 1985 LIMITING CONDITION FOR OPERATION + 3.3.7.9 As a minimum, the fire detection instrumer+= tion for ??eh f's oetection zone snown in Table 3.3.7.9-1 shall be OPERABLE. hPPLICABILITY: Whenever equipment protected by the fire detection instrument
'is required to be OPERABLE.
ACTION:
- a. With the number of OPERABLE fire detection instruments in one or more zones:
- 1. Less than, but more than one-half of, the Total Number of Instruments shown in Table 3.3.7.9-1 for Function A, restore the inoperable Function A instrument (s) to OPERABLE status within 14 days or within 1 hour establish a fire watch patrol to inspect the zone (s) with the inoperable instrument (s) at least once per hour, unless the instrument (s) is located inside the containment, then inspect that containment zone at least once per 8 hours or (monitor the containment air temperature at least once per hour at the locations listed in Specification 4.6.1.7).
- 2. One less than the Total Number of Instruments shown in Table 3.3.7.9-1 for Function B, or one-half or less of the Total Number of Instruments shown in Table 3.3.7.9-1 for Function A, or with any two cr more adjacent instruments inoperable, within 1 hour establish a fire watch patrol to inspect the zone (s) with the inoperable instrument (s) at least once per hour, unless the instrument (s) is located inside the containment, then inspect that containment zone at least once per 8 hours.
- b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.
1 SURVEILLANCE REQUIREMENTS 4.3.7.9.1 Each of the above required fire detection instruments which are accessible during unit operation shall be demonstrated OPERABLE at least once per 6 months by performance of a CHANNEL FUNCTIONAL TEST. Fire detectors which are not accessible during unit operation shall be demonstrated OPERABLE by the performance of a CHANNEL FUNCTIONAL TEST during each COLD SHUTDOWN exceeding 24 hours unless performed in the previous 6 months. 4.3.7.9.2 The NFPA Standard 72D supervised circuits supervision associated with the detector alarms of each of the above required fire detection , instruments shall be demonstrated OPERABLE at least once per 6 months. 4.3.7.9.3 The non-supervised circuits associated with detector alarms between the instruments and the control room shall be demonstrated OPERABLE at least once per 31 days. HOPE CREEK 3/4 3-81
TABLE 3.3.7.10-1 E lE FIRE DETECTION I STRUMENTATION-k DETECTION INFRA- PHOTC- IONIZA-N ZONE ELEV. ROOM OR AREA (FIRE ZONE / ROOM NO.) llEAT RED ELECTIIC TION (x/y) (x/y) (x/y',- (x/y)
- a. Reactor Building 4
4101 54' RHR Pump Room (4114) N/A N/A N/A 6/0 4102 54' RilR Pump /Ht. Exch. Room (4113) N/A N/A >I/A 4/0 - 4103 54' RHR Pump Room (4107) N/A N/A N/A 6/0 4 4104 54' RHR Pump /Ht. Exch. Room (4109) N/A N/A N/A 4/0 4105 54' Core Spray Pump Room (4116) N/W N/A N/A 5/0 4106 54' Core Spray Pump Room (4118) N/A N/A N/A 5/0 4107 54' Core Spray Pump Room (4105) N/A N/A N/A 6/0 4108 54' Core Spray Pump Room (4104) N/A N/A N/A 5/0 4109 54' !!PCI Pump & Turbine Room (4111) N/A N/A N/A 6/0 m 4110 54' RCIC Pump & Turbine Room (4110) N/A N/A N/A 3/0 1 4111 54' Electric Equipment. Room (4112) N/A N/A N/A 6/0 m 4112 54' Electric Equipment Room (4108) N/A N/A N/A 6/0 4 4102 77' RilR Heat Exchanger Room (4214) N/A N/A N/A 3/0 4104 77' RilR lleat Exchanger Room (4208) N/A N/A N/A 3/0 4201 77' RACS Pump / Heat Exch. Area (4211, 4209) N/A N/A N//. 18/0 4201 77' Safeguard Instrument Room (4210) N/A N/A N/n 1/0 4201 77' Safeguard Instrument Room (4219) N/A N/A N/A 1/0 4202 77' MCC Area (4215) N/A N/A N/A 4/0 4203 77' MCC Area (4205) N/A N/A N/A 4/0 4204 77' MCC Area & Corridor (4218, 4216) N/A N/A N/A 10/0 4205 77' MCC Area (4201) 0/(later) N/A N/A 7/0 4206 77' CRD Pumps Room 2 Corridor (4202 & 4203) N/A N/A N/A 9/0 1 4301 102' SACS Ileat Exch./Punip Room (4309) N/A N/A N/A 19/0 4302 102' MCC Area & Corridor (4310, 4301) 0/(later) N/A N/A 12/0 4303 102' SACS lleat Exch./ Pump Room (4307) N/A N/A N/A 18/0 4306 102' CRD flydr. Control Area (4328) N/A N/A N/A 5/0 4306 102' Perq. & Equip. Access Area & Corridor N/A N/A N/A 5/0 (4331, 4315) 4306 102' CRD Removal & Repair Area (4326) N/A N/A N/A 2/0 4307 102' CRD Hydr. Control Area (4320) 4307 102' CRD Haster Control Area (4317) N/A N/A N/A 11/0g co g b
o TABLE 3.3.7.10-1 (Continued) rl FIRE DETECTION INSTRUMENTATION n DETECTION INFRA- PHOTO- 10NIZA-E ZONE ELEV. ROOM OR AREA (FIRE ZONE / ROOM NO.) HEAT RED ELECTRIC TION (x/y) (x/y) (x/y'.- (x/y)
- a. Reactor Building (Cont'd) 4307 102' Perq. & Equip. Access Area (4322) 4401 132' FRVS Recirc. Unit Area (4322) N/A N/A N/A 7/0
~
4402 132' Compr. & Elec. Equip Area & Corridor (4404) N/A N/A N/A 13/0 4403 132' FRVS Recirc. Unit Area (4411) N/A N/A N/A 9/0 4404 132' Elec. Equipment Area (4401) N/A N/A N/A 11/0 4501 145' Elec. Equipment Area (4501) N/A N/A N/A 9/0 4502 145' Passageway (4504) N/A N/A N/A 11/0 4601 162' FRVS Circ. Unit Room (4614) N/A N/A N/A 6/0 4601 162' FRVS Circ. Unit Room (4615) N/A N/A N/A 6/0 w 4602 162' Equip Area 2 Cnrridor (4605, 4608) N/A N/A N/A 12/0 D 4602 162' Post-LOCA Recomb. Area (4604, 4602) N/A N/A N/A 4/0 w 4602 162' MCC Area (4601, 4618) N/A N/A N/A 4/0 d> 4602 162' Standby Liquid Control Area (4606) N/A N/A N/A 2/0 4701 178'-6" FRVS Recirc. Unit Room (4616) N/A N/A N/A 8/0 4701 178'-6" FRVS Recirc. Unit Room (4617) N/A N/A N/A 11/0 4308 102' Drywell Access Room (4330) N/A N/A N/A 3/0 4309 102' Heutron Monitoring Sys. Area (4318) N/A N/A N/A 3/0 4603 162' Fuel Pool Cooling & Heat Exch. Rooms N/A N/A N/A 3/0 (4625, 4626, 4628) 4604 162' Standby Liquid Control Area (4606) N/A N/A N/A 5/0 4113 54/77 Torus Area Safe Shutdown Cable Trays 1/0 N/A N/A N/A
- b. Auxiliary Building Control & D/G Areas 5103 54' 250V DC Battery Rooms (5104) N/A N/A 1/9 1/0 5103 54' 250V DC Battery Rooms (5128) N/A N/A 1/0 1/0 5104 54' RPS MG Set Area (5105) N/A N/A 1/1 1/0 5105 54' DSL Full 5 tor. Tanks Room (5107) 0/7 2/0 2/3 N/A 5106 54' DSL Full Stor. Tanks Room (5108) 0/7 2/0 2/0 N/A 5107 54' DSL Full Stor. Tanks Room (5109) 0/7 2/0 2/0 N/A 5108 54' DSL Full Stor. Tanks Room (5110) 0/7 2/0 2/0 N/A g M
O! z
v TABLE 3.3.7.10-1 (Continued) 5 g FIRE DETECTION INSTRUMENTATION kp DETECTION INFRA- .PHOTa- 10NIZA-ZONE- ELEV. ROOM OR AREA (FIRE 20NE/R00M NO.) HEAT RED ELECT' IC TION (x/y) (x/y) 'x/y; (x/y)
- b. Auxiliary Building Control & D/G Areas (Cont'd) 5109 54' Controlled Stor. Area (5106) N/A 5201 77' N/A 5/0 6/0 Cable Spreading Room (5202) N/A N/A 14/0 5202 77' H&V Equip. Room (5208) 13/0 N/A N/A 2/0 3/0 5203 77' H&V Equip. Room (5209) N/A N/A 2/0 3/0 5204 77' H&V Equip. Room (5210) N/A 5205 77' N/A 2/0 3/0 H&V Equip. Room (5211) N/A N/A 2/0 5206 77' 3/0 Corridor (5207) 0/(later) N/A 2/0 2/0 5206 77' Corridor (5237) 5301 102' Control Equip. Room (5302) 0/(later) N/A 3/0 2/0 N/A N/A 12/0 12/0 m 5314 102' DSL Generator Room (5304)
';;; 5315 0/7 2/0 1/0 N/A 102' DSL Generator Room (5305) 0/7 5316 2/0 1/0 N/A m 102' DSL Generator Room (5306) 0/7 2/0 1/0 N/A 4 5317 102' DSL Generator Room (5307) 0/7 2/0 1/0 N/A 5318 102' Elec Access Area (5301) N/A N/A 2/1 2/0 5318 102' Electrical Access Area (5339) 0/(later) N/A 3/3 4/0 5401 117'6" Control Equip. Room Mezz. (5403) 0/10 N/A 2/0 2/0 5402 124' Class IE Inverter Room (5447) N/A N/A N/A 1/0 5402 124' 5407 Class 1E Inverter Room (5448) N/A N/A 1/0 2/0 124' Corridor (5401) 5403 130' 0/(later) N/A 3/0 3/0 D/G Control Room (5410) N/A N/A N/A 1/0 54C 130' Class 1E Swgr. Room (5411) N/A 5404 130' N/A 1/0 2/0 D/G Control Room (5412) N/A N/A N/A 1/0 5404 130' Class 1E Swgr. Room (5413) N/A N/A 1/0 2/0 5405 130' D/G Control Room (5414) N/A N/A N/A 1/0 5405 130' Class 1E Swgr. Room (5415) N/A N/A 1/0 2/0 5406 130' D/G Control Room (5416) N/A N/A N/A 1/0 5406 130' Class IE Swgr. Room (5417) N/A N/A 1/0 2/0 5502 137' Control Room 2 Room (5510, 5511) N/A N/A N/A 13/0 5504 137' Control Room Console N/A 5505 N/A N/A 8/0 137' Control Room Vert. Board (Right) N/A 5506 N/A N/A 4/0 137' Control Room Vert. Board (Middle) t N/A N/A N/A 3/0 g to - 02
c TABLE 3.3.7.10-1 (Continued)
%rn FIRE DETECTION INSTRUMENTATION c3 EN DETECTION E INFRA- PHOTC- IONIZA-ZONE ELEV. ROOM OR AREA (FIRE ZONE / ROOM NO.) HEAT RED ELECT!IC TION (x/y) (x/y) (x/y I (x/y)
- b. Auxiliary Building Control & D/G Areas (Cont'd) 5507 137' Contre? Room Vert. Board (Left) N/A N/A N/A 4/0 5515 137' Elec. iccess Area (5501) N/A N/A 2/0 5516 146' Batte y Charger Room (5538) 1/3 N/A N/A 1/0 1/0 5516 146' Battery Room (5538) N/A N/A N/A 1/0 5517 156' Battery Charger Room (5540) N/A 5517 146' N/A 1/0 1/0 Battery Room (5541) N/A N/A N/A 5518 146' 1/0 Battery Charger Room (5542) N/A N/A 1/0 5518 146' Battery Room (5543) 1/0 N/A N/A N/A 1/0 5519 146' Battery Charger Room (5544) w N/A N/A 1/0 1/0 5519 146' Battery Room (5545) N/A 1 N/A N/A 1/0 5521 77', Elec. , Channel D (5203, 5323, 5331, 0/(later) N/A 3/0 o 102', 5405, 5419, 5531) 3/0 E
- 124',
120', 137', 150' 5522 77', Elec. , Channel B (5204, 5324, 5332, 102', 5406, 5420, 5532) 0/(later) N/A 3/0 3/0 124', 120', 137', l 150' l 5523 77', Elec. , Channel C (5205, 5325, 5333, 0/(later) 102', N/A 3/0 3/0 l - 5407, 5421, 5533) ! 124', i l 120', 137', 150' 5524 77', Elec. . , Channel A (5206, 5326, 5334, l 102', 5408, 5422, 5534) 0/(later) N/A 3/0 3/0 l 124', (. i 120', @ Ch 137', ,o m ,,,., 150' g T
@ m
TABLE 3.3.7.10-1 (Continuid) E A FIRE DETECTION INSTRUMENTATION O DETECTION INFRA-p ZONE ELEV. ROON OR AREA (FIRE ZONE /ROON NO.) HEAT RED PHOTC-- ElICTR.'C 10NIZA-TION
- b. Auxiliary Ruilding Control & D/G Areas (Cont'd)
(x/y) (x/y) ~( @- (x/y) 5601 155'3" Control Area HVAC Equip. Room (5602) N/A 5602 N/A 7/0 5/0 163'6" DSL Area HVAC Equip Room (5606, 5624) N/A N/A 4/0 4/0 - 5603 163'6" Corridors (5612, 5618) N/A N/A 5/0 8/0 5604 163'6" Control Equip. Room & Elec. Space N/A N/A 4/0 4/0 (5605, 5617) 5611 163'6" Inverter Room (5615) N/A 5612 163'6" Inverter Room (5616) N/A 1/0 N/A N/A N/A 1/0 N/A 5613 163'6" Inverter Room & Battery Room (5613, 5614) N/A 5614 163'6" Inverter Room & Battery Room (5607, 5604) N/A 2/0 N/A N/A N/A 2/0 N/A m 5615 163'6" HVAC Equip. Room (5620) N/A N/A 3/0 6/0 1 5701 178' HVAC Equip. Room & DSL Area N/A N/A 10/0 11/0 m HVAC Equip. Room (5703, 5704) g 5409 130' D/G Air Intake (5223, 5450) N/A N/A 17,0 N/A
- c. Intake Structure 7115 102' Intake Struct. Unit 1 A & C Serv. Wtr. 0/2 N/A 1/0 2/0 Pumps (208) 7116 102' Intake Struct. Unit 1 B & D Serv. Wtr. 0/2 Pumps (204)
N/A 1/0 2/0 7115 114' Intake Struct. Travelling Scram Pumps N/A N/A Later Later
- d. Charcoal Filter Units Reactor Building i
132' FRVS Recirc. Charcoal Filter Compartment 1/0 N/A N/A N/A 1 - 132' FRVS Recirc. Charcoal Filter Compartment 1/0 N/A N/A N/A ' 145' FRVS Vent Unit Charcoal Filter Compartment 1/0 N/A N/A N/A 145' FRVS Vent Unit Charcoal Filter Compartment 1/0 N/A N/A N/A 162' FRVS Recirc. Charcoal Filter Compartment 1/0 N/A N/A 162' FRVS Recirc. Charcoal Filter Compartment 178'6" FRVS Recirc. Charcoal Filter Compartment 1/0 1/0 N/A N/A N/A N/A @O a:
- - N/A N/A N/A M 178'6" FRVS Recirc. Charcoal Filter Compartment 1/0 N/A N/A N/A
!8 m
I (
d i TABLE 3.3.7.10-1 (Centinutd) i 5 g FIRE DETECTION INSTRUMENTATION
- k DETECTION INFRA- PHOTh- 10NIZA-gj ZONE ELEV. ROOM OR AREA (FIRE ZONE / ROOM NO.) HEAT RED TION ELECTQC i
(x/y) (x/y) (x/y) (x/y) { e. Auxiliary Building Control Area i - 153' Control Room Emerg. Char. Filter Units 1/0 N/A N/A N/A j - 153' Control Room Emerg. Char. Filter Units 1/0 N/A N/A N/A
- f. Auxiliary Buildiend Radwaste & Service Areas i
3203 77' Electrical Access Area (3204) 0/(later) N/A 4/0 4/0 3307 102' Electrical Access Area (3314) N/A N/A 1/0 2/0 34I0 124' Electrical Access Area (3425) 0/(later) N/A 2/0 2/0 3312 102' Hot Water Heater, Corridor & Janitor's N/A N/A 13/0 8/0 m Room (3342, 3302, 3304)
} 3313 102' Men's Toilet Rm (3303) N/A N/A 3/0 2/0 m 3503 137' Remote Shutdown Panel Room (3576) N/A N/A N/A 1/0 b
1 *(x/y): x is number of Function A (early warning fire detection and notification only) instr aents. y is number of Function B (actuation of fire suppression systems and early warning notification) instruments. (** List all detectors in areas required to ensure the OPERABILITY of safety related equipment.) The fire detection instruments located within the Containment are not required to be OPER/.Bli during the performance of Type A Containment Leakage Rate Tests. i 1 e c2 1$ a 21
INSTRUMENTATION LOOSE-PART DETECTION SYSTEM N28 1985 LIMITING CONDITION FOR OPERATION 3.3.7.10 The loose part detection system shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1 ano 2. ACTION:
- a. With one or more loose part detection system channels inoperable for more than 30 days, in lieu of any other report required by Specifi-cation 6.9.1, prepare and submit a Special Report to the Commission pursuant to Specification 6.9.2 within the next 10 days outlining the cause of the malfunction and the plans for restoring the channel (s) to OPERABLE status 3
- b. The provisions of Specification 3.0.3 and 3.0.4 are not applicable.
.~
SURVEILLANCE REQUIREMENTS j~ 4.3.7.10 Each channel of the loose part detection system shall be demonstrated OPERABLE by performance of a:
- a. CHANNEL CHECK at least once per 24 hours,
- b. CHANNEL FUNCTIONAL TEST at least once per 31 days, and
[
- c. CHANNEL CALIBRATION at least once per 18 months.
l l l HOPE CREEK 3/4 3-88
INSTRUMENTATION RADI0 ACTIVE LIQUID EFFLUENT MONITORING INSTRUMENTATION LIMITING CONDITION FOR OPERATION l 3.3.7.11 The ==dinac.tive liquid effluent conitoring ieve..tation channah ' shown in Table 3.3.7.11-1 shall be OPERABLE with their Alarm / Trip Setpoints set to ensure that the limits of Specification 3.11.1.1 are not c.:caeded. The Alarm / Trip Setpoints of these channels shall be determined and adjusted in accordance with the methodology and parameters in the OFFSITE DOSE CALCULATION MANUAL (ODCM). APPLICABILITY: At all times. ACTION:
- a. With a radioactive liquid effluent monitoring instrumentation channel Alarm / Trip Setpoint less conservative than required by the above specification, immediately suspend the release of radioactive liquid J
effluents monitored by the affected channel, or declare the channel inoperable.
- b. With less than the minimum number of radioactive liquid effluent monitoring instrumentation channels OPERABLE, take the ACTION shown in Table 3.3.7.12-1. Restore the inoperable instrumentation to OPERABLE status within the time specified in the ACTION, or explain
, in the next Semiannual Radioactive Effluent Release Report pursuant l to Specification 6.9.1.7 why this inoperability was not corrected J in a timely manner.
- c. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.
, SURVEILLANCE REQUIREMENTS 4 4.3.7.11 Each radioactive liquid effluent monitoring instrumentation channal
- shall be demonstrated OPERABLE by performance of the CHANNEL CHECK, SOURCE CHECK, CHANNEL CALIBRATION, and CHANNEL FUNCTIONAL TEST at the frequencies shown in Table 4.3.7.11-1.
HOPE CREEK 3/4 3-89
, TABLE 3.3.7.11-1 o A RADIDACTIVE LIQUID EFFLUENT MONITORING INSTRUMENTATION n M E MINIMUM CHANNELS INSTRUMENT OPERABLE ACTION
- 1. RADI0 ACTIVITY MONITORS PROVIDING ALARM AND AUTOMATIC TERMINATION OF RELEASE -
- a. Liquid Radwaste Effluent Line 1 110
- 2. RADI0 ACTIVITY MONITORS PROVIDING ALARM BUT NOT PROVIDING AUTOMATIC TERMINATION OF RELEASE
- a. Service Water System Effluent Line 1 111
- b. Component Cooling Water System Effluent Line 1 111
- c. Cooling Tower Blowdown' Effluent Line 1 111
- 3. FLOW RATE MEASUREMENT DEVICES
- a. Liquid Radwaste Discharge Line to Cooling 1 112 Tower Blowdown Line
- b. Cooling Tower Blowdown Weir 1 112
- 4. RADI0 ACTIVITY RECORDERS *
- a. Liquid Radwaste Effluent Line 1 113
" Required only if alarm / trip set point is based on recorder / controller c
2 lM"3 h
4 TABLE 3.3.7.11-1 (Continued) DRAFT TABLE NOTATION 20 1985 ACTION 110 - With the number of channels OPERABLE less than required by the Minimum Channels OPERA 8LE requirement, effluent releases may continue provided that prior to initiating a release: a. At least two independent samples are analyzed in accordance with Specification 4.11.1.1.3, and b. At least two technically qualified members of the Facility Staff independently verify the release rate calculations and discharge line valving; Otherwise, suspend release of radioactive effluents via this pathway. ACTION 111 - With the number of channels OPERA 8LE less than required by the Minimum Channels OPERABLE requirement, effluent releases via this pathway may continue provided that, at least once per 12 hours, grab samples are collected and analyzed for radio-activity at a limit of detection of at least 10 7 microcuries/ml. ACTION 112 - With the number of channels OPERA 8LE less than required by the Minimum Channels OPERABLE requirement, effluent releases via this pathway may continue provided the flow rate is estimated at least once per 4 hours during actual releases. Pump per-formance curves generated in place may be used to estimate flow. ACTION 113 - With the number of channels OPERABLE less than required by the Minimum Channels OPERABLE requirement, effluent releases via this pathway may continue provided the radioactivity level is determined at least once per 4 hours during actual releases. HOPE CREEK 3/4 3-91
y TABLE 4.3.7.11-1 ni RADI0 ACTIVE LIQUID EFFLUENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIRLMEN',S 9 IN CHANNEL CHANNEL SOURCE CHANNEL INSTRUMENT FUNCTIONAL CHECK CHECK CALIBRATION TEST
- 1. RADI0 ACTIVITY MONITORS PROVIDING ALARM AND AUTOMATIC TERMINATION OF RELEASE
- a. Liquid Radwaste Effluent Line D P R(3) Q(1)
- 2. RADIOACTIVITY MONITORS PROVIDING ALARM BUT NOT PROVIDING AUTOMATIC TERMINATION OF RELEASE
- a. Service Water System Effluent Line D M R(3) Q(2) 32 b. Component Cooling Water System Effluent A Line D M R(3) Q(2)
- c. Cooling Tower Blowdown Effluent D M R(3)- Q(2)
- 3. FLOW RATE MEASUREMENT DEVICES
- a. Liquid Radwaste Discharge Line D(4) N.A. R to Cooling Tower Blowdown Line Q
- b. Cooling Tower Blowdown Weir D(4) N.A. R Q
- 4. RADI0 ACTIVITY RECORDERS
- a. Liquid Radwaste Effluent Line D N.A. R Q E=
ze t"l3 to Co m
, TABLE 4.3.7.11-1 (Continued) i TABLE NOTATIONS JUN28 1985 (1) The CHANNEL FUNCTIONAL TEST shall also demonstrate that automatic isola of this pathway following conditions and control exists: room alarm annunciation occur if any of the a. . Instrument indicates measured levels above the Alarm / Trip.Setpoint, or
- b. Circuit failure, or
- c. Instrument indicates a downscale failure, or
- d. Instrument controls not set in operate mode.
(2) The CHANNEL FUNCTIONAL TEST shall also demonstrate that control room alarm annunciation occurs if any of the following conditions exists: a. Instrument indicates measured levels above the Alarm Setpoint, or
- b. Circuit failure, or
- c. Instrument indicates a downscale failure, or
- d. Instrument controls not set in operate mode.
(3) The initial CHANNEL CALIBRATION shall be performed using one or more of the reference standards certified by the National Bureau of Standards (NBS) or using standards that have been obtained from suppliers that participate in measurement assurance activities with NBS. These standards shall permit calibrating the system over its intended range of energy and measurement range. For subsequent CHANNEL CALIBRATION, sources that have been related to the initial calibration shall be used. (4) CHANNEL CHECK shall consist of verifying indication of flow during periods of release. CHANNEL CHECK shall be made at least once per 24 hours on days on which continuous, periodic, or batch releases are made. O HOPE CREEK 3/4 3-93
l INSTRUMENTATION RADIOACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION JUN 2 8 1985 LIMITING CONDITION FOR OPERATION 3.3.7.12 The radioactive pasaous effluent monitoring ivtvumchtica channele
=huwn in Table 3.3.7.12-1 shall be OPERABLE with their Alarm / Trip Setpoints set to ensure that the limits of Specifications 3.11.2.1 and 3.10.2.6 are nat exceeded. The Alarm / Trip Setpoints of these channels meeting Specification 3.11.2.1 shali be determined and adjusted in accordance with the methodology and parameters in the ODCM.
APPLICABILITY: As shown in Table 3.3.7.12-1. l ACTION:
- a. With a radioactive gaseous effluent monitoring instrumentation channel Alarm /Irip Setpoint less conservative than required by the above specification, immediately suspend the release of radioactive gaseous effluents monitored by the affected channel, or declare the channel inoperable.
- b. With less than the minimum number of radioactive gaseous effluent "
monitoring instrumentation channels OPERABLE, take the ACTION shown in Table 3.3.7.12-1. Restore the inoperable instrumentation to . OPERABLE status within the time specified in the ACTION, or explain in the next Semiannual Radioactive Effluent Release Report pursuant to Specification 6.9.1.7 why this inoperability was not corrected in a timely manner.
- c. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.
i SURVEILLANCE REOUIREMENTS ! 4.3.7.12 Each radioactive gaseous effluent monitoring instrumentation channel shall be demonstrated OPERABLE by performance of.the CHANNEL CHECK, SOURCE l CHECK, CHANNEL CALIBRATION and CHANNEL FUNCTIONAL TEST at the frequencies ! shown in Table 4.3.7.12-1. I l i l HOPE CREEK 3/4 3-94 i
TABLE 3.3.7.12-1 5 RADI0 ACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION 9 m 92 MINIMUM CHANNELS INSTRUMENT OPERABLE APPLICABILITY ACTION
- 1. MAIN CONDENSER OFFGAS TREATMENT SYSTEM EFFLUENT MONITORING SYSTEM
- a. Noble Gas Activity Monitor -
Providing Alarm and Automatic Termination of Release (1)
- 123
- b. Iodine Sampler (1)
- 127
- c. Particulate Sampler (1)
- 127 b d. Effluent System Flow Rate Measuring g, Device (1)
- 122 UI
- e. Sampler Flow Rate Measuring Device (1)
- 122 2A. MAIN CONDENSER OFFGAS TREATMENT SYSTEM EXPLOSIVE GAS MONITORING SYSTEM (for systems designed to withstand the effects of a hydrogen explosion)
- a. Hydrogen Monitor (1) **
125
- b. Hydrogen or Oxygen Monitor (1) **
125
- 28. MAIN CONDENSER OFFGAS TREATMENT SYSTEM EXPLOSIVE GAS MONITORING SYSTEM (for systems not designed to withstand the ef fects of a hydrogen explosion) t- (75ll EE
- a. to Hydrogen Monitors (2) ** 00 l 126
- b. Hydrogen or Oxygen Monitors 53 (2) **
126 ER
m TABLE 3.3.7.12-1 (Continued)
%m RADI0 ACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION Q
m E MINIMUM CHANNELS INSTRUMENT OPERABLE APPLICABILITY ACTION
- 3. REACTOR BUILDING VENTILATION / PURGE SYSTEM
- a. Noble Gas Activity Monitor (1)
- 124
- b. Iodine Sampler (1)
- 127
- c. Particulate Sampler (1)
- 127 1
- d. Flow Rate Monitor (1)
- 122
- e. Sampler Flow Rate Monitor (1)
- 122 Y'
so
- 4. MAIN STACK SYSTEM
- a. Noble Gas Activity Monitor (1)
- 123
- b. o.ine Sampler (1)
- 127
- c. Particulate Sampler (1)
- 127
- d. Flow Rate Monitor (1)
- 122
- e. Sampler Flow Rate Monitor (1)
- 122
- 5. TURBINE BUILDING VENTIl.ATION SYSTEM
- a. Noble Gas Activity Monitor (1)
- 123 c.-
- b. Iodine Sampler (1)
- 127
[
- c. Particulate Sampler *
(1)
- 127 M
- u. &
o TABLE 3.3.7.12-1 (Continued) A RADI0 ACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION O E MINIMUM CHANNELS INSTRUMENT OPERABLE APPLICABILITY ACTION
- 5. TURBINE BUILDING VENTILATION SYSTEM (Continued)
- d. Flow Rate Monitor (1)
- 122
- e. Sampler Flow Rate Monitor (1)
- 122
- 6. AUXILIARY BUILDING VENTILATION SYSTEM
- a. Noble Gas Activity Monitor (1)
- 123 w b. Iodine Sampler (1)
- 127
- c. Particulate Sampler (1)
- 127
- d. Flow Rate Monitor (1)
- 122
- e. Sampler Flow Rate Monitor (1)
- 122
- 7. FUEL STORAGE AREA VENTILATION SYSTEM
- a. Noble Gas Activity Monitor (1)
- 123
- b. Iodine Sampler (1)
- 127
- c. Particulate Sampler (1)
- 127
- d. Flow Rate Monitor (1)
- 122
- e. Sampler Flow Rate Monitor (1)
- O 122 ,;O M
l
TABLE 3.3.7.12-1 (C:ntinutd) o D? RADI0 ACTIVE GASEOUS EFFLUENT MONITORING IMSTRUMENTATION n Ni 90 MINIMUM CHANNELS INSTRUMENT OPERABLE APPLICABILITY ACTION
- 8. RADWASTE AREA VENTILATION SYSTEM
- a. Noble Gas Activity Monitor (1)
- 123
- b. Iodine Sampler (1)
- 127
- c. Particulate Sampler (1)
- 127
- d. Flow Rate Monitor (1)
- 122 u, e. Sampler Flow Rate Monitor (1)
- 122
! lf
)'
- 9. TURBINE GLAND SEAL CONDENSER VENT AND MECHANICAL VACUUM PUMP EXHAUST SYSTEM
- a. Noble Gas Activity Monitor (1)
- 123
- b. Iodine Sampler (1)
- 127
- c. Particulate Sampler (1)
- 127 l
- d. Flow Rate Monitor (1)
- 122
- e. Sampler Flow Rate Monitor (1)
- 122
- 10. CONDENSER AIR EJECTOR RADI0 ACTIVITY MONITOR (Prior to Input to Holdup System)
- a. Noble Gas Activity Monitor (1) *** 121 to M oo ; sam
TABLE 3.3.7.12-1 (Continued)
- TABLE NOTATION
- At all times. JUN 2 8 1985 During main condenser offgas treatment system operation.
*** During operation of the main condenser air ejector.
ACTION 121 - With the number of channels OPERABLE less than required by the Minimum Channels OPERABLE requirement, the contents of the tank (s) may be released to the environment for up to 72 hours provided:
- a. The offgas system is not bypassed, and
- b. The offgas delay system noble gas activity effluent (downstream) monitor is OPERABLE; Otherwise, be in at least HOT STANDBY within 12 hours.
ACTION 122 - With the number of channels OPERABLE less than required by the Minimum Channels OPERABLE requirement, effluent releases via this pathway may continue provided the flow rate is estimated at least once per 4 hours. ACTION 123 - With the number of channels OPERABLE less than required by the Minimum Channels OPERABLE requirement, effluent releases via this pathway may continue provided grab samples are taken at least once per 12 hours and these samples are analyzed for gross activity within 24 hours. ACTION 124 - With the number of channels OPERABLE less than required by the Minimum Channels OPERABLE requirement, immediately suspend release of radioactive effluents via this pathway. ACTION 125 - With the number of channels OPERABLE less than required by the Minimum Channels OPERABLE requirement, operation of main condenser offgas treatment system may continue provided grab samples are collected at least once per 4 hours and analyzed within the following 4 hours. ACTION 126 - With the number of channels OPERABLE one less than required by the Minimum Channels OPERABLE requirement, operation of this system may continue for up to 14 days. ACTION 127 - With the number of channels OPERABLE less than required by the Minimum Channels OPERABLE requirement, effluent releases via this pathway may continue provided samples are continuously collected with auxiliary sampling equipment as required in Table 4.11-2. , HOPE CREEK 3/4 3-99
TABLE 4.3.7.12-1 RADI0 ACTIVE GASEOUS EiFLUENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS 9
$m CHANNEL MODES IN WHICH CHANNEL SOURCE CilANNEL FUNCTIONAL SURVEILLANCE INSTRUMENT CHECK CilECK CALIBRATION TEST _ REQUIRED
- 1. MAIN CONDENSER OFFGAS TREATMENT SYSTEM EFFLUENT MONITORING SYSTEM i
- a. Noble Gas Activity Monitor -
Providing Alarm and Automatic v Termination of Release D D R(3) Q(1) *
- b. Iodine Sampler W N.A. N.A. N.A. *
- c. Particulate Sampler W N.A. N.A. N.A.
- w d. Effluent System Flow Rate D N.A. R C
- y Measuring Device o
- e. Sampler Flow Rate Measuring D N.A. R Q Device 2A. MAIN CONDENSER OFFGAS TREATMENT SYSTEM EXPLOSIVE GAS MONITORING SYSTEM (for systems designed to withstand the effects of a hydrogen explosion)
- a. Hydrogen Monitor D N.A. Q(4) M **
- b. flydrogen or Oxygen Monitor D N.A. Q(4) or Q(5) M **
- 28. MAIN CONDENSER OFFGAS TREATMENT SYSTEM EXPLOSIVE GAS MONITORING SYSTEM (for systems not designed to withstand the C.g o
.g effects of a hydrogen explosion) L
- a. liydrogen Monitors D N.A. Q(4) M /. **
g
- b. Il/drogen or Oxygen Monitors D N.A. Q(4) or Q(5) M **
, .}.
TABLE 4.3.7.12-1 (Centinuid) 5 A RADIOACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS C . h CHANNEL MODES IN WHICH CHANNEL SOURCE CHANNEL FUNCTIONAL SURVEILLANCE INSTRUMENT CHECK CHECK CALIBRATION TEST REQUIRED
- 3. REACTOR BUILDING VENTILATION / PURGE SYSTEM
- a. Noble Gas Activity Monitor D M R(3) Q(1) *
- b. Iodine Sampler W N.A. N.A. N.A. *
- c. Particulate Sampler W N.A. N.A. N.A.
- w d. Flow Rate Monitor D N.A. R Q 1
m e. Sampler Flow Rate Monitor D N.A. R Q O S
- 4. MAIN STACK SYSTEM
- a. Noble Gas Activity Monitor D M R(3) Q(2) *
- b. Iodine Sampler W N.A. N.A. N.A. *
- c. Particulate Sampler W N.A. N.A. N.A. *
- d. Flow Rate Monitor D N.A. R Q
- e. Sampler Flow Rate Monitor D N.A. R Q 4
k e E b.,
TABLE 4.3.7.12-1 (Centinued) 5 A RADI0 ACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMEt:TS 9 h CHANNEL MG3ES IN WHICH CHANNEL SOURCE CilANNEL FUNCTIONAL SURVEILLANCE INSTRUMENT CHECK CHECK CALIBRATION TEST __ REQUIRED
- 5. TURBINE BUILDING VENTILATION SYSTEM
- a. Noble Gas Activity Monitor D M R(3) Q(2) *
- b. Iodine Sampler W N.A. N.A. N.A. *
- c. Particulate Sampler W N.A. N.A. N.A.
- w d. Flow Rate Monitor D N.A. R Q
'E w e. Sampler Flow Rate Monitor D N.A. R
- Q O
2
- 6. AUXILIARY BUILDING VENTILATION SYSTEM
- a. Noble Gas Actvity Monitor D M R(3) Q(2) *
- b. Iodine Sampler W N.A. N.A. N.A. *
- c. Particulate Sampler W N.A. N. A. N.A. *
- d. Flow Rate Monitor D N.A. R Q *
- e. Sampler Flow Rate Monitor D N.A. R
- Q b5 O
- 5 p
k
5 TABLE 4.3.7.12-1 (Continued) A n RADI0 ACTIVE GASE0US EFFLUENT MONITORING INSTRUMENTATION SURVEILLANCE REQUI9E
- iR W CHANNEL MCDES IN WHICH CHANNEL SOURCE CHANNEL FUNCTIONAL INSTRUMENT !URVEILLANCE CHECK CHECK CALIBRATION TEST REQUIRED
- 7. FUEL STORAGE AREA VENTILATION SYSTEM
- a. Noble Gas Activity Monitor D M R(3)
- Q(2)
- b. Iodine Sampler W N.A. N.A. N.A. *
- c. Particulate Sampler W N.A. N.A. N.A.
- a d. Flow Rate Monitor D N.A. R
- Q A
y e. Sampler Flow Rate Monitor D N.A. R
- Q 5
- 8. RADWASTE AREA VENTILATION SYSTEM
- a. Noble Gas Activity Monitor D M R(3) Q(2) *
- b. Iodine Sampler W N.A. N.A. N.A *
- c. Particulate Sampler W N.A. N.A. N.A *
- d. Flow Rate Monitor D N.A. R
- Q
- e. Sampler Flow Rate Monitor D N.A. R
- Q bO
.a 21
TABLE 4.3.7.12-1 (Centinued) 5 A RADI0 ACTIVE GASE0US [FFLUENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS n
- M?
r p CHANNEL MC' DES IN WHICH CHANNEL SOURCE CHANNEL FUNCTIONAL :,URVEILLANCE INSTRUMENT CHECK CHECK CALIBRATION TEST _ REQUIRE 0
- 9. TURBINE GLAND SEAL CONDENSER VENT AND MECHANICAL VACUUM PUMP EXilAUST SYSTEM
- a. Noble Gas Activity Monitor D M R(3) Q(2) *
- b. Iodine Sampler W N.A. N.A. N.A *
- c. Particulate Sampler W N.A. N.A. N.A. *
$ d. Flow Rate Monitor D N.A. R Q
- e. Sampler Flow Hate Monitor D N.A. R
- Q 2
- 10. CONDENSER AIR EJECTOR RADI0 ACTIVITY MONITOR (Prior to Input to Holdup System)
- a. Noble Gas Activity Monitor D M R(3) ***
Q(2) I O $
.a m
TABLE 4.3.7.12-1 (Continued) l TABLE NOTATION JUN 2 8 1985 At all times. During main condenser offgas treatment system operation. During operation of the main condenser air ejector. (1) The CHANNEL FUNCTIONAL TEST shall also demonstrate that automatic isolation of this pathway and control room alarm annunciation occurs if any of the following conditions exists:
- 1. Instrument indicates measured levels above the alarm / trip setpoint.
- 2. Circuit failure.
- 3. Instrument indicates a downscale failure.
- 4. Instrument controls not set in operate mode.
(2) The CHANNEL FUNCTIONAL TEST shall also demonstrate that control room alarm annunciation occurs if any of the following conditions exists:
- 1. Instrument indicates measured levels above the alarm setpoint.
- 2. Circuit failure.
- 3. Instrument indicates a downscale failure.
- 4. Instrument controls not set in operate mode.
(3) The initial CHANNEL CALIBRATION shall be performed using one or more of the reference standards certified by the National Bureau of Standards or using standards that have been obtained from suppliers that participate in measurement assurance activities with NBS. These standards shall permit calibrating the system cver its intended range of energy and measurement range. For subsequent CHANNEL CALIBRATION, sources that have been related to the initial calibration shall be used. (4) The CHANNEL CALIBRATION shall include the use of standard gas samples containing a nominal:
- 1. One volume percent hydrogen, balance nitrogen, and
- 2. Four volume percent hydrogen, balance nitrogen.
(5) The CHANNEL CALIBRATION shall include the use of standard gas samples containing a nominal:
- 1. One volume percent oxygen, balance nitrogen, and
- 2. Four volume percent oxygen, balance nitrogen.
HOPE CREEK 3/4 3-105
INSTRUMENTATION { b 7 s ul i 3/4.3.8 TURBINE OVERSPEED PROTECTION SYSTEM JUN 2 81985 LIMITING CONDITION FOR OPERATION 3.3.8 at least one turbine overspeed protection system shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. ACTION:
- a. With one turbine control valve, one turbine throttle stop valve or one turbine reheat stop valve per high pressure turbine steam lead inoperable and/or with one turbine interceptor valve per low pressure turbine steam lead inoperable, restore the inoperable valve (s) to OPERABLE status within 72 hours or close at least one valve in the affected steam lead (s) or isolate the turbine from the steam supply within the next,6 hours.
- b. With the above required turbine overspeed protection system otherwise inoperable, within 6 hours isolate the turbine from the steam supply.
SURVEILLANCE REQUIREMENTS 4.3.8.1 The provisions of Specification 4.0.4 are not applicable. 4.3.8.2 The.above required turbine overspeed protection system shall be demonstrated OPERABLE:
- a. At least once per 7 days by:
- 1. Cycling each of the following valves through at least one complete cycle from the running position:
a) For the overspeed protection control system;
- 1) Four high pressure turbine control valves, and
- 2) Four low pressure turbine interceptor valves b) For the electrical overs' peed trip system and the mechanical overspeed trip system;
- 1) Four high pressure turbine throttle stop valves,
- 2) Four high pressure turbine reheat stop valves,
- 3) Four high pressure turbine control valves, and
- 4) Four low r essure turbine interceptor valves.
HOPE CREEK 3/4 3-106
4 i INSTRUMENTATION JUN 2 8 1985 SURVEILLANCE REQUIREMENTS (Continued)
- b. At least once per 31 days by direct observation of the movement of each of the above valves through at least one complete cyc'e from the runaing position.
- c. At least once per 18 months Dy performance of a CHANNEL CALIBRAT::0N of the turbine overspeed protection instrumentation.
- d. At least once per 40 months by disassembling at least one of each of the above valves and performing a visual and surface inspection of all valve seats, disks and stems and verifying no unacceptable flaws or excessive corrosion. If unacceptable flaws or excessive corrosion are found, all other valves of that type shall be inspected.
HOPE CREEK 3/4 3-107
m =
' ~y
( s 3/4.4 REACTOR COOLANT SYSTEM L) PL 3/4.4.1 RECIRCULATION SYSTEM
,ggypg RECIRCULATION LOOPS LIMITING CONDITION FOR OPERATION 3.4.1.1 Two reactor coolant system recirculation loops shall be in operation with:
- a. Total core flow greater than or equal to 45% of rated core flow, or
- b. THERMAL POWER less than or equal to the limit specified in Figure 3.4.1.1-1.
APPLICABILITY: OPERATIONAL CONDITIONS 1* and 2*. ACTION:
- a. With one reactor coolant system recirculation loop not in operation, immediately initiate action to reduce THERMAL POWER to less than or equal to the limit specified in Figure 3.4.1.1-1 within 2 hours and initiate measures to place the unit in at least HOT SHUTDOWN within 12 hours.
- b. With no reactor coolant system recirculation loops in operation, immediately initiate action to reduce THERMAL POWER to less than or equal to the limit specified in Figure 3.4.1.1-1 within 2 hours and initiate measures to place the unit in at least STARTUP within 6 hours and in HOT SHUTDOWN within the next 6 hours.
- c. With two reactor coolant system recirculation loops in operation ar.d total core flow less than 45% of rated core flow and THERMAL POWER greater than the limit specifie.1 in Figure 3.4.1.1-1:
- 1. Determine the APRM and LPRM** noise levels (Surveillance 4.4.1.1.3):
a) At least once per 8 hours, and b) Within 30 minutes after the completion of a THERMAL POWER increase of at least 5% of RATED THERMAL POWER.
- 2. With the APRM or LPRM** neutron flux noise levels greater than three times their established baseline noise levels, immediately initiate corrective action to restore the noise levels to within the requir'ed limits within 2 hours by increasing core flow to greater than 45% of rated core flow or by reducing THERMAL POWER to less than or equal to the limit specified in Figure 3.4.1.1-1.
*See Special Test Exception 3.10.4. ** Detector levels A and C of one LPRM string per core octant plus detectors A and C of one LPRM string in the center of the core should be monitored.
HOPE CREEK 3/4 4-1
U. REACTOR COOLANT SYSTEM SURVEILLANCE REQUIREMENTS 3 1985 4.4.1.1.1 Each pump discharge valve shall be demonstrated OPERABLE by cycling each valve through at least one complete cycle of full travel during each startup* prior to THERMAL POWER exceeding 25% of RATED THERMAL POWER. 4.4.1.1.2 Each pump MG set scoop tube mechanical and electrical stop shall be demonstrated OPERABLE with overspeed setpoints less than or equal te 105% and 102.5%, respectively, of rated core flow, at least once per 18 months. 4.4.1.1.3 Establish a baseline APRM and LPRM** neutron flux noise value within the regions for which monitoring is required (Specification 3.4.1.1, ACTION c) within 2 hours of entering the region for which monitoring is required unless baselining has previously been performed in the region since the last refueling outage.
*If not performed within the previous 31 days. ,
- Detector levels A and C of one LPRM string per core octant plus detectors A and C of one LPRM string in the center of the core should be monitored.
HOPE CREEK 3/4 4-2
.a N
El n b l2 -
;5 5
a
- LJ
':: e
?
d N E' N \ 8 CORE FLOW (% RATED) TilERMAL POWER VERSUS CORE FLOW FIGURE 3.4.1.1-1 N. p
REACTOR COOLANT SYSTEM JET PUMPS JUN 2 8 1995 LIMITING CONDITION FOR OPERATION 3.4.1.2 All jet pumps shall be ODERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. ACTION: With one or more jet pumps inoperable, be in at least HOT SHUTDOWN within 12 hours. SURVEILLANCE REQUIREMENTS 4.4.1.2 Each of the above required jet pumps shall be demonstrated OPERABLE prior to THERMAL POWER exceeding 25% of RATED THERMAL POWER and at least once per 24 hours by determining recirculation loop flow, total core flow and diffuser-to-lower plenum differential pressure for each jet pump and verifying that no two of the following conditions occur when the recirculation pumps are operating at the same speed.
- a. The indicated recircu'lation loop flow differs by more than 10% from the established pump speed-loop flow characteristics.
- b. The indicated total core f1cw differs by more than 10% from the established total core flow value derived from recirculation loop flow measurements.
- c. The indicated diffuser-to-lower plenum differential pressure of any individual jet pump differs from the established patterns by more than 10%.
HOPE CREEK 3/4 4-4
m p W REACTOR COOLANT SYSTEM s L RECIRCULATION PUMPS EN 2 8 Jc85 LIMITING CONDITION FOR OPERATION 3.4.1.3 Recirculation pump speed snall be maintained within:
- a. 5% of each other with core flow greater than or equal to 70% of rated core flow.
- b. 10% of each other with core flow less than 70% of rated core flow.
APPLICABILITY: OPERATIONAL CONDITIONS 1* and 2*. ACTION: With the recirculation pump speeds different by more than the specified limits, either:
- a. Restore the recirculation pump speeds to within the specified limit within 2 hours, or
- b. Declare the recirculation loop of the pump with the slower speed not in operation and take the ACTION required by Specification 3.4.1.1.
SURVEILLANCE REQUIREMENTS 4.4.1.3 Recirculation pump speed shall be verified to be within the limits at least once per 24 hours.
^See Special Test Exception 3.10.4.
HOPE CREEK 3/4 4-5
r 4 ((9' REACTOR COOLANT SYSTEM s d nI l IDLE RECIRCULATION LOOP STARTUP JUN 2 8 Jgg*e LIMITING CONDITION FOR OPERATION 3.4.1.4 An idle recirculation loop shall not be started unless the temperature differential between the reactor pressure vessel steam space coolart and the bottom head drain line coolant is less than or equal to C 145 F ano:
- a. When both loops have been idle, unless the temperature differential between the reactor coolant within the idle loop to be started up and the coolant in the reactor pressure vessel is less than or equal to (50)*F, or
- b. When only one loop has been idle, unless the temperature differential between the reactor coolant within the idle and operating recircula-tion loops is less than or equal to 50*F and the operating loop flow rate is less than or equal to 50% of rated loop flow.
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3 and 4. -s ACTION: With temperature differences and/or flow rates exceeding the above limits, suspend startup of any idle recirculation loop. SURVEILLANCE REOUIREMENTS 4.4.1.4 The temperature differentials and flow rate shall be determined io be within the limits within 15 minutes prior to startup of an. idle recirculation loop. ~, HOPE CREEK 3/4 4-5
REACTOR COOLANT SYSTEM , 3/4.4.2 SAFETY / RELIEF VALVES SAFETY / RELIEF VALVES M 2 8 1989 LIMITING CONDITION FOR OPERATION 3.4.2.1 The safety valve function of at least 13 of the following reactor coolant system safety / relief valves shall be OPERABLE with the specified code safety valve function lift settings:* ' 4 safety-relief valves @ 1108 psig 11% 5 safety-relief valves @ 1120 psig 11% 5 safety-relief valves @ 1130 psig 11% APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:
- a. With the safety valve function of one or more of the above required safety / relief valves inoperable, be in at least HOT SHUTDOWN within 12 hours and in COLD SHUTDOWN within the next 24 hours.
- b. With one or more safety / relief valves stuck open, provided that suppression pool average water temperature is less than 110*F, close the stuck open safety relief valve (s); if unable to close the stuck open valve (r) within 2 minutes or if suppression pool average water temperature is 110*F or greater, place the reactor mode switch in the Shutdown position.
- c. With one or more safety / relief valve acoustic monitors inoperable, r' store the inoperable monitors to OPERABLE status within 7 days or be in a't least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.
i l
^The lift setting pressure shall correspond to a bient conditions of the valves at nominal operating temperatures and prassures.
e C HOPE CREEK 3/4 4-7 L
REACTOR COOLANT SYSTEM JUN 2 8 535 SURVEILLANCE REQUIREMENTS 4.4.2.1 The acoustic monitor for each safety / relief valve shall be demonstrated OPERABLE with the setpoint verified to be (percentage) of full open noise level ** by performance of a:
- a. CHANNEL (FUNCTIONAL TEST) (CHECK) at least once per 31 days, and a
- b. CHANNEL CALIBRATION at least once per 18 months".
4.4.2.2 At least 1/2 of the safety relief valves shall be removed, set pressure tested and reinstalled or replaced with spares that have been previously set pressure tested and stored in accordance with manufacturer's recommendations at least once per 18 months, and they shall be rotated such that all 14 safety relief valves are removed, set pressure tested and reinstalled or replaced with spares that have been previously set pressure tested and stored in accordance with manufacturer's recommendations tested at least once per 40 months.
*The provisions of Specification 4.0.4 are not applicable provided the Surveillance is performed within 12 hours after reactor steam pressure is adequate to perform the test.) ** Initial setting shall be in accordance with the manufacturer's recommendations.
Adjustment to the valve full open noise level shall be accomplished during the startup test program. t 3 1 HOPE CREEK 3/4 4-8
REACTOR COOLANT SYSTEM h ( JUN 2 8 EES SAFETY / RELIEF VALVES LOW-LOW SET FUNCTION LIMITING CONDITION FOR OPERATION 3.4.2.2 The relief valve function and the low-low set functier of the i:1!:. h.3 reactor cuoient system sarety/ relief valves shall be OPERABLE with the following settings: Low-Low Set Function Relief Function Setpoint* (psic) 1% Setooint* (psig) 1% Valve No. Open Close Open Close (1033) (926) (1073) (936) (1113) (946) (1113) (946) (1113) (946) APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION: a. With the relief valve function and/or the low-low set function of one of the above required reactor ccolant system safety / relief valves inoperable, restore the inoperable relief valve function and low-low set function to OPERABLE status within 14 days or be in at least HOT SHUTOOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours, b. With the relief valve function and/or the low-low set function of more than one of the above required reactor coolant system safety / relief valves inoperable, be in at least HOT SHUTDOWN within 12-hours and in COLD SHUTDOWN within the next 24 hours. SURVEILLANCE REQUIREMENTS 4.4.2.2.1 The relief valve function and the low-low set function pressure actuation instrumentation shall be demonstrated OPERABLE by performance of a:
- a. CHANNEL FUNCTIONAL TEST, including calibration of the trip unit, at least once per 31 days.
- b. CHANNEL CALIBRATION, LOGIC SYSTEM FUNCTIONAL TEST and simulated automatic operation of the entire system at least once per 18 months.
k "The lift setting pressure shall correspond to ambient conditions of the valves at nominal operating temperatures and pressures. HOPE CREEK 3/4 4-9
REACTOR COOLANT SYSTEM k Lau'll 3/4.4.3 REACTOR COOLANT SYSTEM LEAKAGE ' LEAKAGE DETECTION SYSTEMS LIMITING CONDITION FOR OPERATION 3.4.3.1 The following reactor coolant system leakage detection systems shall be OPERABLE:
- a. The drywell atmosphere noble gas monitoring system,
- b. The drywell floor and equipment drain sump monitoring system, and
- c. The drywell air cooler condensate flow monitoring system.
i APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION: With only two of the above required leakage detection systems OPERABLE, operation may continue for up to 30 days provided grab samples of the contain-ment atmosphere are obtained and analyzed at least once per 24 hours when the required gaseous radioactive monitoring system is inoperable; otherwise, be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours. SURVEILLANCE REOUIREMENTS 4.4.3.1 The reactor coolant system leakage detection systems shall be demonstrated OPERABLE by:
- a. Drywell atmosphere noble gas monitoring systems performance of a CHANNEL CHECK at least once per 12 hours, a CHANNEL FUNCTIONAL TEST at least once per 31 days and a CHANNEL CALIBRATION at least once per 1
18 months.
- b. Drywell floor and equipment drain sump monitoring system performance of a CHANNEL FUNCTIONAL TEST at least once per 31 days and a CHANNEL CALIBRATION TEST at least once per 18 months.
- c. Drywell air coolers condensate flow monitoring system performance of a CHANNEL FUNCTIONAL TEST at least once per 31 days and a CHANNEL CALIBRATION at least once per 18 months.
HOPE CREEK 3/4 4-10
REACTOR COOLANT SYSTEM OPERATIONAL LEAKAGE JUN 2 8 ogg L LIMITING CONDITION FOR OPERATION 3.4.3.2 Reactor coolant system leakage shall be limited to:
- a. No PRESSURE BOUNDARY LEAKAGE.
- b. 5 gpm UNICENTIFIED LEAKAGE.
- c. 25 gpm total leakage averaged over any 24-hour period.
- d. 1 gpm leakage at a reactor coolant system pressure of (950) (10) psig from any reactor coolant system pressure isolation valve specified in Table 3.4.3.2-1.
e. 2 gpm increase in UNIDENTIFIED LEAKAGE within any 4-hour period. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:
- a. With any PRESSURE BOUNDARY LEAKAGE, be in at least HOT SHUTDOWN within 12 hours and in COLD SHUTDOWN within the next 24 hours.
- b. With any reactor coolant system leakage greater than the limits in b and/or c, above, reduce the leakage rate to within the limits within 4 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.
c. With any reactor coolant system pressure isolattun valve leakage greater than the above limit, isolate the high pressure portion of the affected system from the low pressure portion within 4 hours by use of at least two other closed (manual or deactivated automatic) (or check *) valves, i or be in at least HOT SHUTOOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.
- d. With one or more of the high/ low pressure interface valve leakage pressure monitors shown in Table 3.4.3.2-1 inoperable, restore the inoperable monitor (s) to OPERABLE status within 7 days or verify the pressure to be less than the alarm setpoint at least once per 12 hours; restore the inoperable monitor (s) to OPERABLE status within 30 days or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.
- e. With any reactor coolant system UNIDENTIFIED LEAKAGE increase greater than 2 gpm within any 4-hour period, identify the source of leakage increase as not service sensitive Type 304 or 316 austanitic stainless steel within 4 hours or be in at least HOT SHUTOOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.
(*Which have been verified not to exceed the allowable leakage limit at the last refueling outage or the after last time the valve was disturbed, whichever is more recent.) HOPE CREEK 3/4 4-11
' REACTOR COOLANT SYSTEM fU..9 SURVEILLANCE REQUIREMENTS
.firN 3 8 7985 4.4.3.2.1 The reactor coolant system leakage shall be demonstrated to be within each of the above limits by:
- a. Monitoring the primary containment atmosoheric (particulate) (and)
(genw) radioactivity at least once per (4) (12) hours, b. Monitoring the primary containment sump fic: rata st least onca per (4) (12) hours, (and)
- c. Monitoring the primary containment air coolers condensate flow rate or the (gaseous) (particulate) radioactivity at least once per (4) (12) hours, and
- d. Monitoring the reactor vessel head flange leak detection system at least once per 24 hours.
4.4.3.2.2 Each reactor coolant system pressure isolation valve specified in Table 3.4.3.2-1 shall be demonstrated OPERABLE by leak testing pursuant to Specification 4.0.5 and verifying the leakage of each valve to be within the specified limit:
- a. At least once per 18 months, and
- b. Prior to returning the valve to service following maintenance, repair or replacement work on the valve which could affect its leakage rate.
The provisions of Specification 4.0.4 are not applicable for entry into OPERATIONAL CONDITION 3. 4.4.3.2.3 The high/ low pressure interface valve leakage pressure monitors shall be demonstrated OPERABLE with alarm setpoints per Table 3.4.3.2-2 by performance of a:
- a. CHANNEL FUNCTIONAL TEST at least once per 31 days, and
- b. CHANNEL CALIBRATION at least once per 18 months, i
l l A HOPE CREEK 3/4 4-12
REACTOR COOLANT SYSTEM
,-l TABLE 3.4.3.2-1 ISEI REACTOR COOLANT SYSTEM PRESSURE ISOLATION VALVES VALVE NUMBER SYSTEM s
TABLE 3.4.3.2-2
- TOR COOLANT SYSTEM INTERFACE VALVES
_3 . ~ LEAKAGE PRESSURE MONITORS ALARM SETPOINT VALVE NUMBER SYSTEM (psia)
=%
0 HOPE CREEK 3/4 4-13
REACTOR COOLANT SYSTEM 3/4.4.4 CHEMISTRY JIlN28 g LIMITING CONDITION FOR OPERATION 3.4.4 The chemistry of the reactor coolant system shall be maintained within 4 the limits spacifiad in T?bla 3.4.4-1. APPLICABILITY: At all times. ACTION:
- a. In OPERATIONAL CONDITION 1:
+
- 1. With the conductivity, chloride concentration or pH exceeding the
,' limit specified in Table 3.4.4-1 for less than 72 hours during one continuous time interval and, for conductivity and chloride concen-tration, for less than 336 hours per year, but with the conductivity less than 10 pmho/cm at 25*C and with the chloride concentration less than 0.5 ppm, this need not be reported to the Commission and the provisions of Specification 3.0.4 are not applicable.
- 2. With the conductivity, chloride concentration or pH exceeding the limit specified in Table 3.4.4-1 for more than 72 hours during one continuous time interval or with the conductivity and chloride concentration exceeding the limit specified in Table 3.4.4-1 for more than 336 hours per year, be in at least STARTUP within the next
- 6 hours.
- 3. With the conductivity exceeding 10 pmho/cm at 25'C or chloride concentration exceeding 0.5 ppm, be in at least HOT SHUTDOWN within 12 hours and in COLD SHUTDOWN within the next 24 hours.
- b. In OPERATIONAL CONDITION 2 and 3 with the conductivity, chloride concentration or pH exceeding the limit specified in Table 3.4.4-1 for more than 48 hours during one continuous time interval, be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.
- c. At all other times:
- 1. With the:
! a) Conductivity or pH exceeding the limit specified in Table 3.4.4-1, restore the conductivity and pH to within the limit within 72 hours, or b) ; Chloride concentration exceeding the limit specified in Table
'.3.4.4-1, restore the chloride concentration to within the limit within 24 hours, or perform an engineering evaluation to determine the effects of the out-of-limit condition on the structural integrity of the reactor coolant system. Determine that the structural integrity of the >
reactor coolant system remains acceptable for continued operation prior to proceeding.to OPERATIONAL CONDITION 3.
- 2. The provisions of Specification 3.0.3 are not applicable.
HOPE CREEK 3/4 4-14
i REACTOR COOLANT SYSTEM SURVEILLANCE REQUIREMENTS AN28 7985 4.4.4 The reactor coolant shall be determined to be within the specified chemistry limit by:
- a. Measurement prior to pressurizing the reactor during each star +"p, if not performed within the previous 72 hours,
- b. Analyzing a sample of the reactor coolant for:
- 1. Chlorides at least once per: .
a) 72 hours, and b) 8 hours whenever conductivity is greater than the limit in Table 3.4.4-1.
- 2. Conductivity at least once per 72 hours.
- 3. pH at least once per:
a) 72 hours, and b) 8 hours whenever conductivity is greater than the limit in Table 3.4.4-1.
- c. Continuously recording the conductivity of the reactor coolant, or, when the continuous recording conductivity monitor is inoperable for up to 31 days, obtaining an in-line conductivity measurement at least once per: -
- 1. 4 hours in OPERATIONAL CONDITIONS 1, 2 and 3, and
- 2. 24 hours at all other times.
- d. Performance of a CHANNEL CHECK of the continuous conductivity monitor with an in-line flow cell at least once per:
- 1. 7 days, and-
- 2. 24 hours whenever conductivity is greater than the limit in in Table 3.4.4-1.
s HOPE CREEK 3/4 4-15
TABLE 3.4.4-1 5 m
- REACTOR COOLANT SYSTEM S CHEMISTRY LIMITS "I
OPERATIONAL CONDITION CHLORIDES CONDUCTIVITY (pahos/cm 025*C) _PH . 1 5 0.2 ppe
$ 1. 0 5.6 5 pH $ 8.6 2 and 3 5 0.1 ppm 5 2.0 5.6 5 pH $ 8.6 At all other times 5 0.5 ppm 5 10.0 5.3 5 pH $ 8.6 I
l 1 G2 f' B; 4 I i
- v
.. =a
=> ,
$h
REACTOR COOLANT SYSTEM 3/4.4.5 SPECIFIC ACTIVITY M28 g LIMITING CONDITION FOR OPERATION 3.4.5 The specific activity of the primary coolant shall be limited to: a. Less tnan or equal to 0.2 microcuries per gram DOSE EQUIVALENT I-131, and
- b. Less than or equal to 1004 microcuries per gram.
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3 and 4. ACTION: a. In OPERATIONAL CONDITIONS 1, 2 or 3 with the specific activity of the primary coolant;
- 1. Greater than 0.2 microcuries per gram DOSE EQUIVALENT I-131 but less than or equal to 4.0 microcuries per gram, operation may continue for up to 48 hours provided that the cumulative operating time under these circumstances does not exceed 800 hours in any consecutive 12-month period. With the total cumulative operating time at a primary coolant specific activity greater than 0.2 micro-curies per gram DOSE EQUIVALENT I-131 exceeding 500 hours in any consecutive six-month period, prepare and submit a Special Report to the Commission pursuant to Specification 6.9.2 within 30 days indicating the number of hours of operation above this limit.
The provisions of Specification 3.0.4 are not applicable.
- 2. Greater than 0.2 microcuries per gram DOSE EQUIVALENT I-131 for more than 48 hours during one continuous time interval er for more than 800 hours curaulative operating time in a consecutive 12-month period, or greater than 4.0 microcuries per gram, be in at least HOT SHUTDOWN with the main-steam line isolation' valves closed within 12 hours.
- 3. Greater than 1004 microcuries per gram, be in at least HOT SHUTDOWN 12 hours. with the main steamline isolation valves closed within
! b. ' In OPERATIONAL CONDITIONS 1, 2, 3 or 4, with the specific activity of the primary coolant greater than 0.2 microcuries per gram DOSE EQUIVALENT I-131 or greater than 100/E microcuries per gram, perform the sampling and analysis requirements of Item 4a of Table 4.4.5-1 until the specific activity of the primary coolant is restored to within its limit. A Special Report shall be prepared and submitted to the Commission pursuant to Specification 6.9.1. This report shall contain the results of the specific activity analyses and the time , duration when the specific activity of the coolant exceeded 0.2 micro-curies per gram DOSE EQUIVALENT I-131 together with the following additional information. HOPE CREEK 3/4 4-17 1
REACTOR COOLANT SYSTEM DMFi JD 2 8 g LIMITING CONDITION FOR OPERATION (Continued) ACTION (Continued)
- c. In OPERATIONAL CONDITION 1 or 2, with:
- 1. THERMAL POWER changed by more than 15% cf RATED THERMM ONER lr. one huur^, or
- 2.
The off gas level, at the SJf,C, incrra::cd by more than (10,000) microcuries por second in one hour curing steady state operation at release rates less than 75,000 microcuries per second, or
- 3. The off gas level, at the SJAE, increased by more than 15% in one hour during steady state operation at release rates greater than 75,000 microcuries per second, perform the sampling and analysis requirements of Itam 4b of Table 4.4.5-1 until the specific activity of the primary coolant is restored to within its limit. Prepare and submit to the Commission a Special Report pursuant to Specification 6.9.2 at least once per 92 days containing the results of the specific activity analysis together with the below additional information for each occurrence.
Additional Information
- 1. Reactor power history starting 48 hours prior to:
a) The first sample in which the limit was exceeded, and/or b) The THERMAL POWER or off gas level change.
- 2. Fuel burnup by core region.
- 3. Clean-up flow history starting 48 hours prior to:
a) The first sample in which the limit was exceeded, and/or b) The THERMAL POWER or off gas level change.
- 4. Off gas level starting 48 hours prior to:
a) The first sample in which the limit was exceeded, and/or b) The THERMAL POWER or off gas level change. SURVEILLANCE REQUIREMENTS 4.4.5 The specific activity of the reactor coolant shall be demonstrated to be within the limits by performance of the sampling and analysis program of ' Table 4.4.5-1. Not applicable during the startup test program. HOPE CREEK 3/4 4-18
TABLE 4.4.5-1 a g PRIMARY COOLANT SPECIFIC ACTIVI'TY SAMPLE AND ANALYSIS PROGRAM 9 R
- TYPE OF MEASUREMENT OPERATIONAL CONDITIONS SAMPLE AND ANALYSIS AND ANALYSIS IN WHICH SAMPLE FREQUENCY AND ANALYSIS REQUIRED
- 1. Gross Beta and Gamma Activity At least once per 72 hours Determination 1, 2, 3
- 2. Isotopic Analysis for DOSE At least once per 31 days 1 EQUIVALENT I-131 Concentration v
- 3. Radiochemical for E Determination At least once per 6 months
- 1
- 4. Isotopic Analysis for Iodine a) At least once per 4 hours, 1#, 2#, 3#, 4#
w whenever the specific j h activity exceeds a limit, as required by ACTION b.
- i i e
i "' b) At least one sample, Letween 1, 2 2 and 6 hours following the change in THERMAL POWER or off gas level, as required by ACTION c.
- 5. Isotopic Analysis of an Off- At least once per 31 days gas Sample Including Quantitative 1 Measurements for at least Xe-133, Xe-135 and Kr-88 i
- last Sample to be taken subcritical for 48after hoursa minimum of 2 EFPD and 20 days of POWER OPERATION have elapsed since reactor wa or longer.
#Until the specific activity of the primary coolant system is restored to within its limits.
E O l 2 @
- i. J-N m
~
P N REACTOR COOLANT SYSTEM i \+
" *I I
3/4.4.6 PRESSURE / TEMPERATURE LIMITS
#8 IS65 REACTOR COOLANT SYSTEM LI:iITI# T :CITIch FOR OPcRATIOii i
3.4.6.1 The reactor coolant system temperature and pressure shall be limited in accordance with the limit lines shown on Figure 3.4.6.1-1 (1) curves A and
- A' for hydrostatic or leak testing; (2) curves B and 8' for heatup by non-nuclear means, cooldown following a nuclear shutdown and low power PHYSICS TESTS; and (3) curves C and C' for operations with a critical core other than low power PHYSICS TESTS, with:
+
- a. A maximum heatup of (100)*F in any one hour period,
- b. A maximum cooldown of (100)*F in any one hour period,
- c. A maximum temperature change of less than or equal to 20*F in any j
one hour period during inservice hydrostatic and leak testing opera-tions above the heatup and cooldown limit curves, and '
- d. The reactor vessel flange and head flange temperature greater than or equal to (70)*F when reactor vessel head bolting studs are under tension.
! APPLICABILITY: At all times. ACTION: With any of the above limits exceeded, restore the temperature and/or pressure to within the limits within 30 minutes; perform an engineering evaluation to ! determine the effects of the out-of-limit condition on the structural integrity of the reactor coolant system; determine that the reactor coolant system remains acceptable for continued operations or be in at least HOT SHUTDOWN within 12 hours and in COLD SHUTDOWN within the following 24 hours. SURVEILLANCE REQUIREMENTS 4.4.6.1.1 During system heatup, cooldown and inservice leak and hydrostatic testing operations, the reactor coolant system temperature and pressure shall be determined to be within the above required heatup and cooldown limits and to the right of the limit lines of Figure 3.4.6.1-1 curves A and A', B and 8', or C and C' as applicable, at least once per 30 minutes. < HOPE CREEK 3/4 4-20
REACTOR COOLANT SYSTEM EUN 2 8 1995 SURVEILLANCE REQUIREMENTS (Continued) (b. The reactor coolant system temperature at the following location shall be determined at least once pea 5 minute unti' 2 s;;cossive-temperatures at each location are within 5*F:
- 1. Reactor vessel bottom drain,
- 2. Recirculation loops A and B, and
- 3. Reactor vessel bottom head.)
4.4.6.1.2 The reactor coolant system tenperature and pressure shall be determined to be to the right of the criticality limit line of Figure 3.4.6.1-1 curves C and C' within 15 minutes prior to the withdrawal of control rods to bring the reactor to criticality and at least once per 30 minutes during system heatup. 4.4.6.1.3 The reactor vessel material surveillance specimens shall be removed and examined, to determine changes in reactor pressure vessel material properties, as required by 10 CFR 50, Appendix H in accordance with the schedule in Table 4.4.6.1.3-1. The results of these examinations shall be used to update the curves of Figure 3.4.6.1-1. 4.4.6.1.4 The reactor vessel flange and head flange temperature shall be verified to be greater than or equal to (70)*F:
- a. In OPERATIONAL CONDITION 4 when reactor coolant system temperature is:
- 1. 5 99*F, at leart once per 12 hours.
- 2. 5 89*F, at least once per 30 minutes.
- b. Within 30 minutes prior to and at least once per 30 minutes during tensioning of the reactor vessel head bolting studs.
HOPE CREEK 3/4 4-21
.o ij JWI28 q L Curve A' applicable for service i
periods up to ( ) EFPY (and l contain margins of (10)'F l- and (60) psig for possible instrument errors). (RPV Metal) Temperature (*F) - MINIMUM (REACTOR PRESSURE VESSEL METAL) TEMPERATURE VS. REACTOR VESSEL PRESSURE Figure 3.4.6.1-1 ,- . l . I l HOPE CREEK 3/4 4-22 l L
REACTOR COOLANT SYSTEM I REACTOR STEAM DOME JUN 2 3 g LIMITING CONDITION FOR OPERATION 3.4.6.2 The pressure in the reactor steam dome shall be less than 1020 psig APPLICABILITY: OPERATIONAL CONDITION 1* and 2*. ACTION: With the reactor steam dome pressure exceeding 1020 psig, reduce the pressure to less than 1020 psig within 15 minutes or be in at least HOT SHUTDOWN within 12 hours. SURVEILLANCE REOUIREMENTS 4.4.6.2 The reactor steam dome pressure shall be verified to be less than 1020 psig at least once per 12 hours. A Not applicable during anticipated transients. o HOPE CREEK 3/4 4-23
REACTOR COOLANT SYSTEM 3/4.4.7 MAIN STEAM LINE ISOLATION VALVES 28 TS63 LIMITING CONDITION FOR OPERATION a
~.*.i Two main steam line isolation valves (MSIVs) per main steam line shall be OPERABLE with closing times greater than or equal to 3 and less than or equai io 5 seconds.
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:
- a. With one or more MSIVs inoperable:
- 1. Maintain at least one MSIV OPERABLE in each affected main steam line that is open and within 8 hours, either:
a) Restore the inoperable valve (s) to OPERABLE status, or b) Isolate the affected main steam line by use of a deactivated
- MSIV in the closed position.
- 2. Otherwise, be in at least HOT-SHUTDOWN within the next 12 hours
, and in COLD SHUTDOWN within the following 24 hours,
- b. The provisions of Specification 3.0.4 are not applicable.
SURVEILLANCE REQUIREMENTS 4.4.7 Each of the above required MSIVs shall be demonstrated OPERABLE by verifying full closure between 3 and 5 seconds when tested pursuant to Specification 4.0.5. 3 l I 4 i HOPE CREEK 3/4 4-24
A REACTOR COOLANT SYSTEM 3/4.4.8 STRUCTURAL INTEGRITY JUN28 g LIMITING CONDITION FOR OPERATION S.4.o ihe structural integrity of ASME Code Class 1, 2 and 3 components shall
,be maintained in accordance with Specification 4.4.8.
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3, 4 and 5. ACTION:
- a. With the structural integrity of any ASME Code Class 1 component (s) not conforming to the above requirements, restore the structural integrity of the affected component (s) to within its limit or isolate i
the affected component (s) prior to increasing the Reacto- Coolant System temperature more than 50 F above the minimum temperature required by NDf considerations.
- b. With the structural integrity of any ASME Code Class 2 component (s) not conforming to the above requirements, restore the structural integrity of the affected component (s) to within its limit or isolate ~5 the affected component (s) prior to increasing the Reactor Coolant
. . System temperature above 200 F.
- c. With the structural integrity of any ASME Code Class 3 component (s) not conforming to the above requirements, restore the structural integrity of the affected component (s) to within its limit or isolate the affected component (s) from service.
- d. The provisions of Specification 3.0.4 are not applicable.
SURVEILLANCE REQUIREMENTS 4.4.8 No requirements other than Specification 4.0.5. HOPE CREEK 3/4 4-25
i i REACTOR COOLANT SYSTEM i j 3/4.4.9 RESIDUAL HEAT REMOVAL
*/UN28 g HOT SHUTDOWN LIMITING CONDITION FOR OPERATION .a. 4. J.1 iwo# shutdown cooling mode loops of tne residual heat removal (RHR) system shall be OPERABLE and, unless at least one recirculation pump is in operation, at leart one shutdown cooling mode loop shall be in operation *'N with each loop consisting of at least:
- a. One OPERABLE RHR pump, and
- b. One OPERABLE RHR heat exchanger.
APPLICABILITY: OPERATIONAL CONDITION 3, with reactor vessel pressure less than the RHR cut-in permissive setpoint. ACTION:
- a. With less than the above required RHR shutdown cooling mode loops OPERABLE, immediately initiate corrective action to return the required loops to OPERABLE status as soon as possible. Within one hour and at least once per 24 hours thereafter, demonstrate the operability of at least one alternate method capable of decay heat removal for each inoperable RHR shutdown cooling mode loop. Be in at least COLD SHUTDOWN within 24 hours.**
- b. With no RHR shutdown cooling mode loop in operation, immediately initiate corrective action to return at least one loop to operation as soon as possible. Within one hour establish reactor coolant circulation by an alternate method and monitor reactor coolant temperature and pressure at least once per hour.
SURVEILLANCE REQUIREMENTS 4.4.9.1 At least one shutdown cooling mode loop of the residual heat removal system or alternate method shall be determined to be in operation and circulating reactor coolant at least once per 12 hours. 0ne RHR shutdown cooling mode loop may be inoperable for up to 2 hours for surveillance testing provided the other loop is OPERABLE and in operation.
*The shutdown cooling pump may be removed from operation for up to 2 hours per 8 hour period provided the other loop is OPERABLE. ##The RHR shutdown cooling mode loop may be removed from operation during hydrostatic testing. . **Whenever two or more RHR subsystems are inoperable, if unable to attain COLD SHUTDOWN as required by this ACTION, maintain reactor coolant temperature as low as practical by use of alternate heat removal methods.
HOPE CREEK 3/4 4-26
REACTOR COOLANT SYSTEM Di {Dg COLD SHUTDOWN gg gg 1985 LIMITING CONDITION FOR OPERATION 3.4.9.2 Two# shutdown cooling mode loops of the residual
;j.tu .h4.. haat r?moval (9HP) be GPERABLE ano, unless at least one recirculation pump is in operation, at least one shutdown coolirg mode loop shall ',e in operation *'##
with each loop consisting of at least:
- a. One OPERABLE RHR pump, and
- b. One OPERABLE RHR heat exchanger.
APPLICABILITY: OPERATIONAL CONDITION 4. ACTION: a. With less than the above required RHR shutdown cooling mode loops OPERABLE, within one hour and at least once per 24 hours thereafter, demonstrate the operability of at least one alternate method capable of decay heat removal for each inoperable RHR shutdown cooling mode loop.
- b. With no RHR shutdown cooling mode loop in operation, within~one hour establish reactor coolant circulation by an alternate method and monitor reactor coolant temperature and pressure at least once per hour.
SURVEILLANCE REQUIREMENTS 4.4.9.2 At least one shutdown cooling mode loop of the residual heat removal system or alternate method shall be determined to be in operation and circulating reactor coolant at least once per 12 hours.
#0ne RHR shutdown cooling mode loop may be inoperable for up to 2 hours for surveillance testing provided the other loop is OPERABLE and in operation. *The shutdown cooling pump may be removed from operation for up to 2 hours per 8 hour period provided the other loop is OPERABLE. ##The shutdown cooling mode loop may be removed from operation during hydrostatic testing.
HOPE CREEK 3/4 4-27
r I 3/4.5 EMERGENCY CORE COOLING SYSTEMS Yr Unn I 3/4.5.1 ECCS - OPERATING
@N28 y LIMITING CONDITION FOR OPERATION 15.1 Tha emer 3My r.o' e coolir.g system; chill bc OPC.%CLE wit.h.
- a. The core spray systen: censisting of two subsystems with each subsystem comprised of:
- 1. Two OPERABLE core spray pumps, and
- 2. An OPERABLE flow path capable of taking suction from the suppression chamber and transferring the water through the spray sparger to the reactor vessel.
- b. The low pressure coolant injection (LPCI) system of the residual heat removal system consisting of four subsystems with each subsystem comprised of:
- 1. One OPERABLE LPCI pump, and
- 2. An OPERABLE flow path capable of taking suction from the suppression chamber and transferring the water to the reactor vessel.
- c. The high pressure cooling injection (HPCI) system consisting of:
- 1. One OPERABLE HPCI pump, and
- 2. An OPERABLE flow path capable of taking suction from the suppression chamber and transferring the water to the reactor vessel.
- d. The automatic depressurization system (ADS) with at least five OPERABLE ADS valves.
APPLICABILITY: OPERATIONAL CONDITION 1, 2*, ** #, and 3*, **, ##. The HPCI system is not required to be OPERABLE when reactor steam dome ns pressure is less than or equal to 200 psig. The ADS is not required to be OPERABLE when reactor steam dome pressure is less than or equal to 100 psig. See Special Test Exception 3.10.6. l 0ne LPCI subsystem of the RHR system may be inoperable in that they are aligned in the shutdown cooling made when the reactor vessel pressure is less than the RHR shutdown cooling permissive setpoint. . l HOPE CREEK 3/4 5-1
EMERGENCY CORE COOLING SYSTEMS LIMITING CONDITION FOR OPERATION (Continued) 0% ACTION:
- a. M r the core spray system:
- 1. With one core spray subsystem inopercble, provided that at least two LPCI subsystem are OPERABLE, restore the inoperable core spray subsystem to OPERABLE status within 7 days or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.
- 2. With both core spray subsystems inoperable, be in at least HOT SHUTDOWN within 12 hours and in COLD SHUTDOWN within the next 24 hours.
- b. For the LPCI system:
- 1. With one LPCI subsystems inoperable, provided that at least one core spray subsystem is OPERABLE, restore the inoperable LPCI subsystem to OPERABLE status within 30 days or be in at least HOT SHUTOOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.
- 2. With two LPCI subsystems inoperable, provided that at least one core spray subsystem is operable, restore at least one LPCI subsystem to OPERABLE status within 7 days or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.
- 3. With three LPCI subsystem inoperable, provided that both core spray subsystems are OPERABLE, restore at least two LPCI subsystems to OPERABLE status within 72 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.
- 4. With all four LPCI subsystems inoperable, be in at least HOT SHUTDOWN within 12 hours and in COLD SHUTDOWN within the next 24 hours.*
- 5. With (a) (no) LPCI system cross-tie valve closed (or with power not removed from the closed cross-tie valve operator), be in at least HOT SHUTDOWN within 12 hours and in COLD SHUTDOWN within the next 24 hours.
1
- c. For the HPCI system, provided the CSS, the LPCI system, the A05 and the RCIC system are OPERABLE:
*Whenever two or more RHR subsystems are inoperable, if unable to attain COLD SHUTDOWN as required by this ACTICN, maintain reactor coolant temperature as low as practical by use of alternate heat removal methods.
HOPE CREEK 3/4 5-2
EMERGENCY CORE COOLING SYSTEMS DPMT dW 28 g LIMITING CONDITION FOR OPERATION (Continued) ACTION: (Continued)
- 1. With the HPCI system inoperable, restore the HPCI system to OPERABLE status within 14 davs or be in it lecrt unT SHUTDOWN within the next 12 hours and reduce reactor steam dome pressure to 1 200 psig within the following 24 hours.
- d. For the ADS:
- 1. With one of the above required ADS valves inoperable, provided the HPCI system, the core spray system and the LPCI system are OPERABLE, restore the inoperable ADS valve to OPERABLE status within 14 days or be in at least HOT SHUTOOWN within the next 12 hours and reduce reactor steam dome pressure to < 100 psig within the next 24 hours. -
- 2. With two or more of the above required ADS valves inoperable, be in at least HOT SHUTDOWN within 12 hours and reduce reactor steam dome pressure to i 100 psig within the next 24 hours,
- e. With a CSS header AP instrumentation channel inoperable, restore the inoperable channel to OPERABLE status within 72 hours or determine the CSS header AP locally at least once per 12 hours; otherwise, declare the associated CSS subsystem inoperable.
- f. With an LPCI or CSS system discharge line " keep filled" alarm 'nstru-mentation inoperable, perform Surveillance Requirement 4.5.1.a.1.a.
- g. In the event an ECCS system is actuated and injects water into the Reactor Coolant System, a Special Report shall be prepared and sub-mitted to the Commission pursuant to Specification 6.9.2 within 90 days describing the circumstances of the actuation and the total accumulated actuation cycles to date. The current value of the useage factor for each affected safety injection nozzle shall be provided in this Special Report whenever its value exceeds 0.70.
HOPE CREEK 3/4 5-3
i EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE REQUIREMENTS NN28 q 4.5.1 The emergency core cooling systems shall be demonstrated OPERABLE by:
- a. At least once per 31 days:
- 1. For the core spray system, the LPCI system, and the llPCI system:
a) Verifying by venting at the high point vents that the system piping from the pump discharge valve to the system isolation valve is filled with water. b) Verifying that each valve, manual, power operated or automatic, in the flow path that is not locked, sealed, or otherwise secured in position, is in its correct
- position.
- 2. For the LPCI system, verifying that (the) (at least one) LPCI system subsystem cross-tie valve is (open) (closed with power removed from the valve operator).
- 3. For the HPCI system, verifying that the HPCI pump flow controller is in the correct position.
- b. Verifying that, when tested pursuant to Specification 4.0.5:
- 1. The two core spray system pumps in each subsystem together develop a flow of at least 6350 gpm against a test line pressure of greater than or equal to ( ) psig, corresponding to a reactor vessel pressure of 1 (115) psig.
- 2. Each LPCI pumps in each subsystem develop a flow of at least 10,000 gpm against a test line pressure of 1 ( ) psig, corre-sponding to a reactor vessel to primary containment differential pressure of 1 (20) psid.
- 3. The HPCI pump develops a flow of at least 5600 gpm against a test line pressure of > (1100) psig when steam is being supplied to the turbine at (10@, +20, -80) psig.**
- c. At least once per 18 months:
- 1. For the core spray system the LPCI system, and the HPCI system, performing a system functional test which includes simulated auto-matic actuation of the system throughout its emergency operating sequence and verifying that each automatic valve in the flow path actuates to its correct position. Actual injection of coolant into the reactor vessel may be excluded from this test.
*Except that an automatic valve capable of automatic return to its ECCS ,
position when an ECCS signal is present may be in poisition for another mode of operation.
**The provisions of Specification 4.0.4 are not applicable provided the surveillance is performed within 12 hours after reactor steam pressure is adequate to perform the test.
HOPE CREEK 3/4 5-4
4 EMERGENCY CORE COOLING SYSTEMS M 28 g SURVEILLANCE REQUIREMENTS (Continued)
- 2. For the HPCI system, verifying that:
a) The system develops a flow of at least 5600 gpm against a
' test line pressure of ( ) psig, corresponding to a reactor vessel pressare of > 165 psig, when steam is being supplied to the turbine at 250 + 15 -0 psig.**
b) The suction is automatically transferred from the condensate storage tank to the suppression chamber on a condensate storage tank water level - low signal and on a suppression chamber - water level high signal.
- 3. Performing a CHANNEL CALIBRATION of the CSS, LPCI, and HPCI system discharge line " keep filled" alarm instrumentation.
- 4. Performing a CHANNEL CALIBRATION of the CSS header AP instru-mentation and verifying the setpoint to be i the allowable value of 4.4 psid.
- 5. Performing a CHANNEL CALIBRATION of the LPCI header AP instru- .!
mentation and verifying the setpoint to be i the allowable value of 3.0 psid.
- d. For the ADS:
- 1. At least once per 31 days, performing a CHANNEL FUNCTIONAL TEST of the Primary Containment Instrument gas system low-low pressure alarm system.
- 2. At least once per 18 months:
a) Performing a system functional test which ir.cludes simulated automatic actuation of the system throughout its emergency operating sequence, but excluding actual valve actuation. b) Manually opening each ADS valve when the reactor steam dome pressure is greater than or equal to 100 psig(**) and observing that either:
- 1) The control valve or bypass valve position responds accordingly, or
/
**The provisions of Sp.ecification 4.0.4 are not applicable provided the surveillance is performed within 12 hours after reactor steam pressure is adequate to perform the test.
HOPE CREEX 3/4 5-5 x
EMERGENCY CORE COOLING SYSTEMS 3/4 5.2 ECCS - SHUTOOWN 1S85 LIMITING CONDITION FOR OPERATION
- 2) Them is a corr;;;e.';c., h ..ge in the measured steam flow.
c) Performing a CHANNEL CALIBRATION of the Primary Containment Instrument gas system low-low pressure alarm system and verifying an alarm setpoint of 85 + -2 psig on decreasing pressure. 3.5.2 At least two of the following shall be OPERABLE:
- a. Core spray system subsystems with a subsystem comprised of:
- 1. Two OPERABLE core spray pumps, and
- 2. An OPERABLE flow path capable of taking suction from at least one of the following water sources and transferring the water through the spray sparger to the reactor vessel:
a) From the suppression chamber, or b) When the suppression chamber water level is less than the limit or is drained, from the condensate storage tank containing at least 135,000 available gallons of water, equivalent to a level of ( ) feet.
- b. Low pressure coolant injection (LPCI) system subsystems with a subsystem comprised of:
- 1. One OPERABLE LPCI pump, and
- 2. An OPERABLE flow path capable of taking suction from the suppression chamber and transferring the water to the reactor vessel.
APPLICABILITY: OPERATIONAL CONDITION 4 and 5*. ACTION:
- a. With one of the above required subsystems inoperable, restore at least two subsystems to OPERABLE status within 4 hours or suspend all operations with a potential for draining the reactor vessel.
! *The ECCS is not required to be OPERABLE provided that the reactor vessel head is removed, the cavity is flooded, the spent fuel pool gates are removed, and l water level is maintained within the limits of Specification 3.9.8 and 3.9.9. 1 l ( HOPE CREEK 3/4 5-6
l
)
l ' EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE REQUIREMENTS DS ACTION (Continued)
- b. With both of the above required subsystems inoperable, suspend CORE ALTERATIONS OM all operations with a potential for dra'ning the reactor vessel. Rettore at least one subsystem to OPERABLE status within 4 hours or establish SECONDARY CONTAINMENT INTEGRITY within the next 8 hours.
4.5.2.1 At least the above required ECCS shall be demonstrated OPERABLE per Surveillance Requirement 4.5.1. 4.5.2.2 The core spray system shall be determine OPERABLE at least once per 12 hours by verifying the condensate storage tank required volume when the condensate storage tank is required to be OPERABLE per Specification 3.5.2.a.2.b. I l n I i HOPE CREEK 3/4 5-7 ;
J EMERGENCY CORE COOLING SYSTEMS -Nlld iC 3/4.5.3 SUPPRESSION CHAMBER JUN 2 g g LIMITING CONDITION FOR OPERATION 3.5.3 The suppression chamber shall be OPERABLE:
- a. In OPERATIONAL CONDITION 1, 2 and 3 with a contained water volume of at least 118,000 ft8 , equivalent to a level of (22'0").
- b. In OPERATIONAL CONDITION 4 and 5* with a contained volume of at least 118,000 ft , equivalent to a level of (
3
), except that the suppression chamber level may be less than the limit or may be drained provided that:
- 1. No operations are performed that have a potential for draining the reactor vessel,
- 2. The reactor mode switch is locked in the Shutdown or Refuel position,
- 3. The condensate storage tank contains at least 135,000 available gallons of water, equivalent to a level of ( ) feet,and
- 4. The core spray system is OPERABLE per Specification 3.5.2 with an OPERABLE flow path capable of taking suction frem the condensate storage tank and transferring the water through the spray sparger to the reactor vessel.
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3, 4 and 5*. ACTION:
- a. In OPERATIONAL CONDITION 1, 2 or 3 with the suppression chamber water level less than the above limit, restore the water level to within the limit within 1 hour or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours,
- b. In OPERATIONAL CONDITION 4 or 5* with the suppression chamber water level less than the above limit or drained and the above required
, conditions not satisfied, suspend CORE ALTERATIONS and all operations 4
that have a potential for draining the reactor vessel and lock the reactor mode switch in the Shutdown position. Es:ablish SECONDARY CONTAINMENT INTEGRITY within 8 hours.
*The suppression chamber is not requirod to be OPERABLE provided that the reactor vessel head is removed, the cavity is flooded (or being flooded from the suppression pool), the spent fuel pool gates are removed (when the cavity is flooded), and the water level is maintained within the Ifmits of !
Specification 3.9.8 and 3.9.9. HOPE CREEK 3/4 5-8
DR*MT , EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE REQUIREMENTS 4.5.3.1 The suppression chamber shall be determined OPERABLE by verifying the water lavel to ha creater thar, nr equal on se app i t - .bh:
- a. (22'0") at least once per 24 hours,
- b. ( ) at least once per 12 hours.
4.5.3.2 With the suppression chamber level less than the above limit or drained in OPERATIONAL CONDITION 4 or 5*, at least once per 12 hours:
- a. Verify the required conditions of Specification 3.5.3.b to be satisfied, or
- b. Verify footnotg conditions
- to be satisfied.
m G 9 8 . 4 e. HOPE CREEK 3,4 g,9
1 -- 3/4.6 CONTAINMENT SYSTEMS $*l o L 3/4.6.1 PRIMARY CONTAINMENT PRIMARY CONTAINMENT INTEGRITY 8 IS85 LIMITING CONDITION FOR OPERATION . . . . __ . _ _ _
- 3. 6.1. .'. PRIMARY CONTAINMENT INTEGRITY shall oe maintained.
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2* and 3. ACTION: Without PRIMARY CONTAINMENT INTEGRITY, restore PRIMARY CONTAINMENT INTEGRITY within 1 hour or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUT 00WN within the following 24 hours. SURVEILLANCE REQUIREMENTS
- 4. 6.1.1 PRIMARY CONTAINMENT INTEGRITY shall be demonstrated:
- a. After each closing of each penetration subject to Type 8 testing, except the primary containment air locks, if opened following Type A or 8 test, by leak rate testing the seals witn gas at Pa, 48.1 psig, and verifying that when the measured leakage rate for these seals is added to the leakage rates determined pursuant to Surveillance Requirement 4.6.1.2.d for all other Type B and C penetrations, the combined leakage rate is less than or equal to 0.60 La.
- b. At least once per 31 days by verifying that all primary containment penetrations ** not capable of being closed by OPERABt.E containment automatic isolation valves and required to be closed dut"ng accident conditions are closed by valves, blind flanges, or deactivated automatic valves secured in position, except as provided in Table 3.6.3-1 of Specification 3.6.3.
- c. By verifying each primary containment air lock is in compliance with the requirements of Specification 3.5.1.3.
- d. By verifying the suppression chamber is in compliance with the requirements of Specification 3.6.2.1. '
l
*See Special Test Exception 3.10.1 l **Except valves, blind flanges, and deactivated automatic valves which are located l inside the containment, and are locked, sealed or otherwise secured in the closed position. These penetrations shall be verified closed during each COLD SHUTDOWN except such verification need not be performed when the primary containment has not been de-inerted since the last verification or more often than once per 92 days. l HOPE CREEK 3/4 6-1 l
Di C CONTAINMENT SYSTEMS da dil i PRIMARY CONTAINMENT LEAKAGE LIMITING CONDITION FOR OPERATION 8 ISS5 3.6.1.2 Primary containment leakage rates shall be Ifmited to: a.
, 0.5 An overall integrated leakage rate of less than or percent by weight of the containment air per 24 hours at P,, equal to L,481 psig.
- b. A combined leakage rate of less than or equal to 0.60 L for all penetrations and all valves listed in Table 3.6.3-1, ex8ept for main steam line isolation valves
- and valves which are hydrostatically tested per Table 3.6.3-1, subject to Type B and C tests when pressurized to P,, 48,1 psig.
- c. "Less than or equal to 11.5 scf per hour for any one main steam line through the isolation valves when tested at (Pt ,) (20.2) psig.
- d. A combined leakage rate of less than or equal to (1 gpm times the total number of) (3 gpm for all) (ECCS and RCIC) containment isolation valves in hydrostatically tested lines which penetrate the primary containment, when tested at (1.10) Pa, (44.44) psig.
APPLICABILITY: When PRIMARY CONTAINMENT INTEGRITY is required per Specification 3.6.1.1. ACTION: With: .
- a. The measured overall integrated primary containment leakage rate exceeding 0.75 L, or
- b. The measured combined leakage rate for all penetrations and all valves listed in Table 3.6.3-1, except for main steam line isolation valves
- and valves which are hydrostatically tested per Table 3.6.3-1, subject to Type B and C tests exceeding 0.60 L , or 3
- c. The measured leakage rate exceeding 11.5 scf per hour for any one main steam line isolation valves, or
- d. The measured combined leakage rato for all (ECCS and RCIC) containment isolation valves in hydrostatically tested ifnes which penetrate the primary containment exceeding (1 gpm times the total number of such valves) (3 gpm),
restore:
- a. The overall integrated leakage rate (s) to less than or cou.1 to 0.75 L,, and
- Exemption to Appendix "J" of 10 CFR 50.
HOPE CREEK 3/4 6-2
DfWT CONTAINMENT SYSTEMS LIMITING CONDITION FOR OPERATION (Continued) I28 3 33 ACTION (Continued)
- b. The combined leakage rate for all penetrations and all valves listed in Table 3.6.3-1, except for main steem line isolatien valve:* ' rad valves whien are hydrostatically tested per Table 3.6.3-1), subject to Type B and C tests to less than or equal to 0.60 L,, and
- c. The leakage rate to less than or equal to (11.5) (46) scf per hour for (any one) (all four) main steam line((a) through the) isolation valve (s), and
- d. The combined leakage rate for all (ECCS and RCIC) containment isolation valves in hydrostatically tested lines which pentrate the primary conttinment to less than or equal to (1 gpm times the total number of such valves) (3 gpm),
prior to increasing reactor coolant system temperature above 200*F. SURVEILLANCE REQUIREMENTS 4.6.1.2 The primary containment leakage rates shall be demonstrated at the following test schedule and shall be determined in conformance with the criteria specified in Appendix J of 10 CFR 50 using the methods and provisions of ANSI N45.4 - 1972:
- a. Three Type A Overall Integrated Containment Leakage Rate tests shall be conducted at 40 + 10 month intervals during shutdown at P,,
48.1 psig, during each 10 year service period. The third test of each set shall be conducted during the shutdown for the 10 year plant inservice inspection.
- b. If any periodic Type A test fails to meet 0.75 L,, the test schedule for subsequent Type A tests shall be reviewed and approved by the Commission. It two consecutive Type A tests fail te meet 0.75 L,, a Type A test shall be performed at least every 18 months until two consecutive Type A tests meet 0.75 L,, at which time the above test schedule may be resumed,
- c. The accuracy of each Type A test shall be verified by a supplemental test which:
- 1. Confirms the accuracy of the test by verifying that the difference between the supplemental data and the Type A test data is wishin O.25 L,.
- 2. Has duration sufficient to establish accurately the change in leakage rate between the Type A test and the supplemental test.
- 3. Requires the quantity of gas injected into the containment or bled from the centainment during the supplemental test to be l between 0.75 L, and 1.25 L,,
HOPE CREEK 3/4 6-3 i
CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) The formula to be used is: [L, + L,, - 0.25 L,] < Le # Elo * 'am
- 0.25 L,] where Lga supplement test result; L, a superimposed leakage; and L, a measured Type A leakage, d.
Type 8 and C tests shall be conducted with gas at P,, 48.1 psig*, at intervals no greater than 24 months except for tests involving:
- 1. Air locks,
- 2. Main steam line isolation valves.
- 3. Valves pressurized with fluid from a seal system,
- 4. (ECCS and RCIC) containment isolation valves in hydrostatically tested lines which penetrate the primary containment, and
- 5. Purge supply and exhaust isolation valves with resilient material seals,
- s. Air locks shall be tested and demonstrated OPERA 8LE per Surveillance Requirement 4.6.1.3.
- f. Main steam line isolation valves shall be leak tested at least once per 18 months,
- g. Leakage from isolation valves that are sealed with fluid from a seal syster may be excluded, subject to the provisions of Appendix J.
Section III.C.3, when determining the combined leakage rate provided the seal system and valves are pressurized to at least 1.10 P , (44.4) psig,andthesealsystemcapacityisadequatetomaintainsyltem pressure for at least 30 days,
- h. ECCS and RCIC containment isolation valves in hydrostatically tested lines which pentrate the primary containment shall be leak tested at least once per 18 months.
- 1. Purge supply and exhaust isolation valves with resilient material seals shall be tested and demonstrated OPERABLE per Surveillance Requirements 4.6.1.8.3 and 4.6.1.8.4.
- j. The provisions of Specification 4.0.2 are not applicable to 24 month and 40 1 10 month surveillance intervals.
"Unless a hydrostatic test is required per Table 3.6.3 1. HOPE CAEEK 3/4 6 4
CONTAINMENT SYSTEMS PRIMARY CONTAINMENT AIR LOCKS g,9 ,, , :. . q LIMITING CONDITION FOR OPERATION 3.6.1.3 Each primary containment air lock shall be OPERABLE with:
- a. Both doors closed except when the air lock is being used for normal transit entry and exit through the containment, then at least one air lock door shall be closed, and b.
An overall air lock leakage rate of less than or equal to 0.05 L, at 48.1 psig. P,, APPLICABILITY: OPERATIONAL CONDITIONS 1, 2* and 3. ACTION:
- a. With one primary containment air lock door inoperable:
- 1. Maintain at least the OPERABLE air lock door closed and either restore the inoperable air lock door to OPERABLE status within 24
, hours or lock the OPERABLE air lock door closed.
- 2. Operation may then continue until performance of the next required overall air lock leakage test provided that the OPERABLE air lock door is verified to be locked closed at least once per 31 days.
- 3. Othenvise, be in at least HOT SHUTOOWN within the next 12 hours and in COLD SHUT 00WN within the following 24 hours.
- 4. The provisions of Specification 3.0.4 are not applicable,
- b. With the primary containment air lock inoperable, except as a result of an inoperable air lock door, maintain at least one air lock door closed; restore the inoperable air lock to OPERABLE status within 24 hours or be in at least HOT SHUT 00VN within the next 12 hours and in COLD SHUT 00WN within the following 24 hours.
"See Special Test Exception 3.10.1. HOPE CREEK 3/4 6-5
CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS I% 4.6.1.3 Each primary containment air lock shall be demonstrated OPERABLE: a. Within 72 hours following each closing, excapt why the cir 1 c': is being usted for multipew wntries, then at least once per 72 hours, by verifying seal leakage rate less than or equal to 5 scf per hour when the gap between the door seals is pressurized to 10.0 psig. b. By conducting an overall air lock leakage test at P , 48.1 psig, and by verifying that the overall air lock leakage fate is within its limit:
- 1. At least once per 6 months', and
- 2. Prior to establishing PRIMARY CONTAINMENT INTEGRITY when maintenance has been performed on the air lock that could affect the airlock sealing capability.*
c. At least once per 6 months by verifying that only one door in each air lock can be opened at a time.** l l f The provisions of Specification 4.0.2 are not applicable.
- Exemption to Appendix J of 10 CFR 50.
**Except that the inner door need not be opened to verify interlock OPERABILITY when the primary containment is inerted, provided that the inner door interlock !
is tested within 8 hours after the primary containment has been de-inerted. I HOPE CREEK 3/4 6 6
CONTAINMENT SYSTEMS
~
MSIV SEALING SYSTEM ' LIMITING CONDITION FOR OPERATION M28 m 'l 3.6.1.4 Two independent MSIV sealing system (MSIVSS) subsystems shall be 1 OPFRA*LE APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. l ACTION: . With one MSIV sealing system subsystem inoperable, restore the inoperable ( subsystem to OPERABLE status within 30 days or be in at least HOT SHUTDOWN within i the next 12 hours and in COLD SHUTOOWN within the following 24 hours. , SURVEILLANCE REQUIREMENTS , 4.6.1.4 Each MSIV sealing system subsystem shall be demonstrated t OPERA 8LE: i
- a. At least once per 31 days by:
(
- 1. Starting the blower (s) from the control room and operating the , ,
blower (s) for at least 15 minutes.
- 2. Cycling each (air dilution valve) through at least one complete cycle T of full travel. [
- 3. Energizing the heaters and verifying (a temperature rise of greater !
than or equal to ( )*F within ( ) minutes) (current of ( ) amperes
*( )% per phase for each heater).
l
- b. During each COLD SHUTDOWN (, if not performed within the previous 92 days, by I cycling each bleeder valve and steam isolation valve through at least one [
complete cycle of full travel) (in accordance with Specification 4.0.5). ; t
- c. At least once per 18 months by: l
- 1. Performance of a functional test which includes simulated actuation [
of the subsystem throughout its operating sequence, and verifying
~
l that each interlock and timer operates as designed, each automatic
- valve actuates to its correct position and the blower starts. .
1 l 2. Verifying that the blower (s) develops at least the below required ! I vacuum at the rated capacity: l a) Inboard valves, (60)" H 0 at (100) scfm. i 2 b) Outboard valves, (50)" H 2 0 at (240) scfm.
- d. By verifying the (flow, pressure, temperature and level) (operating) instrumentation to be OPERABLE by performance of at
- 1. CHANNEL CHECK at least once per 24 hours,
- 2. CHANNEL FUNCTIONAL TEST at least once per 31 days, and l
- 3. CHANNEL CALIBRATION at least once per 18 months. ,
t HOPE CREEK 3/4 6 7 i
CONTAINMENT SYSTEMS PRIMARY CONTAINMENT STRUCTURAL INTEGRITY (Optional) JUlV 2a gg3 LIMITING CONDITION FOR OPERATION 3.6.1.5 The structural integrity of the primary containment shall be maintained at a level consistent with the acceptance criteria in Sp::-ificatinn , 4.6.1.5. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION: With the structural integrity of the primary containment not conforming to the above requirements, restore the structural integrity to within the limits within 24 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTOOWN within the following 24 hours. SURVEILLANCE REQUIREMENTS 4.6.1.5.1 The structural integrity of the exposed accessible interior and exterior surfaces of the primary containment, including the liner plate, shall be determined during the shutdown for each Type A containment leakage rate test by a visual inspection of those surfaces. This inspection shall be performed prior to the Type A containment leakage rate test to verify no apparent changes in appearance or other abnormal degradation. 4.6.1.5.2 Reports Any abnormal degradation of the primary containment structure detected during the above required inspections shall be reported to the Commission pursuant to Specification 6.9.1. This report shall include a description of the condition of the concrete, the inspection procedure, the tolerances on cracking, and the corrective actions taken. HOPE CREEK J/4 6 8
CONTAINMENT SYSTEMS ORYWELL AND SUPPRESSION CHAM 8ER INTERNAL PRESSURE E8 1985 I LIMITING CONDITION FOR OPERATION 3.6.1.6 Drywell and suppression chamber internal pressure shall be maintained I between -0.5 and 61.5 psig. APPLICA8ILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION: With the drywell and/or suppression chamber internal pressure outside of the specified limits, restore the internal pressure to within the limit within 1 hour or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTOOWN within the following 24 hours. SURVEILLANCE REQUIREMENTS 4.6.1.6 The drywell and suppression chamber internal pressure shall be determined to be within the limits at least once per 12 hours. HOPE CREEK 3/4 6 9
l CONTAINMENT SYSTEMS t JUN 28 yng ORYWELL AVERAGE AIR TEMPERATURE LIMITING CONDITION FOR OPERATION
~
- 3. 6.1. 7 Orywell average air temperature shall not exceed 135*F. %
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION: With the drywell average air temperature greater than 135'F, reduce the average air temperature to within the limit within 8 hours or be in at least HOT 24 SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the foll hours. SURVEILLANCE REQUIREMENTS 4.6.1.7 The drywell average air temperature shall be the volumetric average of the temperatures at the following locations and shall be determined to be within the limit at least once per 24 hours: Elevation Azimuth a. b. c. d. e. f. 'At least one reading from each elevation is required for a volumetric average calculation. , HOPE CREEK 3/4 6-10
CONTAINMENT SYSTEMS 1 DRYWELL AND SUPPRESSION CHAMBER PURGE SYSTEM LIMITING CONDITION FOR OPERATION MS
- 3. 6.1. 8 The drywell and suppression chamber purge supply and exhaust isolation valves shall be OPERABLE and sealed closed.*
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:
- a. With a drywell and suppression chamber purge supply and/or exhaust isola-tion valve (s) cpen or not sealed closed, close and/or seal the valves (s) or otherwise isolate the penetration within four hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.
- b. With a drywell and suppression chamber purge supply and/or exhaust isolation valve (s) with resilient material seals having a measured leakage rate
- exceeding the limi'., of Surveillance Requirements 4.6.1.8.2 and/or 4.6.1.8.3, restore the inoperable valve (s) to OPERABLE status within 24 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTOOWN within j
the following 24 hours. SURVEILLANCE REQUIREMENTS 4.6.1.8.1 Each drywall and suppression chamber purge supply and exhaust iso-lation valve shall be verified to be sealed closed at least once per 31 days. (4.6.1.8.2 At least once per 6 months on a STAGGERED TEST BASIS each sealed closed drywell and suppression chanber purge supply and exhaust isolation valve with resilient material seals shall be demonstrated OPERABLE by verifying that the measured leakage rate is less than or equal to 0.05 L, when pressurized to P, (48.1) psig.) (4.6.1.8.3 At least once per 92 days the drywell purge inboard valve isolation valve with resilient material seals shall be demonstrated OPERABLE by verifying that the measured leakage rate is less than or equal to 0.01 L, when pressurized to P, (48.1) psig.)
"The drywell purge inboard 26 inch valve may be opened in series with the ; 2 inch vent line bypass valve for containment pressure control during periods ,,
of power ascension or descension. HOPE CREEK 3/4 6-11
m CONTAINMENT SYSTEMS {
)[~5 h..
3/4.6.2 DEPRESSURIZATION SYSTEMS SUPPRESSION CHAMBER - JUN 2 8 f'one LIMITING CONDITION FOR OPERATION 3.6.2.1 The suppression chamber shall be OPERABLE with:
- a. The psol water:
3
- 1. Volume between 118,000 ft and 122,000 3ft , equivalent to a level between (22' 0") and (24'0"), and a
- 2. Maximum average temperature of 95'F during OPERATIONAL CONDITION 1 or 2, except that the maximum average temperature may be permitted to increase to:
a) 105*F during testing which adds heat to the suppression chamber. b) 110'F with THERMAL POWER less than or equal to 1% of RATED THERMAL POWER. c) 120*F with the main steam line isolation valves closed following a scram.
- b. A total leakage between the suppression chamber and drywell of less than the equivalent leakage through a 1-inch diameter orifice at a differential pressure of 1.44 psig.
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:
- a. With the suppression chamber water level outside the above limits, restore the water level to within the limits within 1 hour or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUT 00WN within the following 24 hours.
- b. In OPERATIONAL CONDITION 1 or 2 with the suppression chamber average water temperature greater than 95*F, restore the average temperature to less than or equal to 95*F within 24 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUT 00WN within the following 24 hours, except, as permitted above:
- 1. With the suppression chamber average water temperature greater than 105'F during testing which adds heat to the suppression chamber, stop all testing which adds heat to the suppression chamber and restore the average temperature to less than 95'F within 24 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.
- 2. With the suppression chamber average water temperature greater than:
a) 95'F for more than 24 hours and THERMAL POWER greater than , 1% of RATED THRMAL PCWER, be in at least HOT SHUTDOWN within 12 hours and in COLD SHUTDOWN within the next 24 hours, b) 110'F, place the reactor modo switch in the Shutdown posi-tion and operate at least one residual heat removal loop in the suppression pool cooling mode. HOPE CREEK 3/4 6-12
CONTAINMENT SYSTEMS ft w SL ni l
, LIMITING CONDITION FOR OPERATION (Continued) 0 IS85 ACTION: (Continued)
- 3. With the suppression chamber average water temperature greater than 120*F, depressurite the reactor pressure " m e! to Mcs than 20u p:ing within 12 hours.
- c. With one suppression 7001 water teaparature instrumentation enannel
' in any pair (s) of temperature instruinentation channels in the same sector inoperable, restore the inoperable channel (s) to OPERABLE status within 7 days or verify suppression chamber water temperature to be within the limits at least once per 12 hours.
- d. With both suppression pool water temperature instrumentation channels in any pair (s) of temperature instrumentation channels in the same sector inoperable, restore at least one inoperable water temperature instrumentation channel in each pair of temperature instrumentation channels in the same sector to OPERABLE status within 8 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.
- e. With the drywell-to-suppression chamber bypass leakage in excess of the limit, restore the bypass leakage to within the limit prior to increasing reactor coolant temperature above 200 F.
SURVEILLANCE REO.UIREMENTS 4.6.2.1 The. suppression chamber shall be demonstrated OPERABLE:
- a. By verifying the suppressio'n chamber water volume to be within the limits at least once per 24 hours.
- b. At least once per 24 hours in OPERATIONAL CONDITION 1 or 2 by verifying the suppression chamber average water temperature to be less than or equal'to 95*F, except:
- 1. At least once per 5 minutes during testing which adds heat to the suppression chamber, by verifying the suppression chambar average water temperature less than or equal to 105 F.
- 2. At least once per hour when suppression chamber average water temperature is greater than or equal to 95*F, by verifying:
I a) Suppression chamber average water temperature to be less than or equal to 110 F, and b) THERMAL POWER to be less than or equal to 1% of RATED THERMAL POWER after suppression chamber average water temperature has exceeded 95 F for more than 24 hours.
- 3. At least once per 30 minutes following a scram with suppression chamber average water temperature greater than or equal to 95 F, by verifying suppression chamber average water temperature less than or equal to 120 F.
HOPE CREEK 3/4 6-13
CONTAINMENT SYSTEMS g SURVEILLANCE REQUIREMENTS (Continued) 28 7985
- c. By an external visual examination of the suppression chamber after safety / relief valve operation with the suppression chamber average
, wate- tape *ature g-e.te~ ti..n n ::;ucl to 148F and resci.or coolant system pressure greater than 100 psig.
- d. At least once per 18 months by a visual inspection of the accessible interior and exterior of the suppression chamber.
- e. By verifying (at least) sixteen suppression pool water temperature instrumentation channels, at least one pair in each suppression pool sector, OPERABLE by performance of a:
- 1. CHANNEL CHECK at least once per 24 hours,
- 2. CHANNEL FUNCTIONAL TEST at least once per 31 days, and
- 3. CHANNEL CAg.IBRATION at least once per 18 months, with the water high temperature alarm setpoint for < 120*F. _
f. At least once per 18 months by conducting a drywell-to-suppression chamber bypass leak test at an initial differential pressure of " 1 psi and verifying that the differential pressure does not decrease by more than 0.20 inch of water per minute for a period of 10 minutes. If any drywell-to-suppression chamber bypass leak test fails to meet the specified limit, the test schedule for subsequent tests shall be reviewed and approved by the Commission. If two consecutive tests fail to meet the specified limit, a test shall be performed at least every 9 months until two consecutive tests meet the specified limit, at which time the 18 month test schedule may be resumed. i l I HOPE CREEK 3/4 6-14
'7 CONTAINMENT SYSTEMS IN l SUPPRESSION POOL SPRAY gg 1985 LIMITING CONDITION FOR OPERATION 3.6.2.2 The suppression pool spray mode of the residual heat removal (RHR) system shall be OPERABLE with two independent loops, each loop consisting of:
- a. One OPERABLE RHR pump, and
- b. An OPERABLE flow path capable of recirculating water from the suppression chamber through an RHRSW heat exchanger and the suppression pool spray sparger.
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:
- a. With one suppression pool spray loop inoperable, restore the inoper-able loop to OPERABLE status within 72 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.
- b. With both suppression pool spray loops inoperable, restore at least one loop to OPERABLE status within 8 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN
- within the following 24 hours.
SURVEILLANCE REQUIREMENTS 4.6.2.2 The suppression pool spray mode of the RHR system shall be demonstrated OPERABLE:
- a. At least once per 31 days by verifying that each valve, manual, power operated or automatic, in the flow path that is not locked, sealed 7
or otherwise secured in position, is in its correct position. l b. By verifying that each of the required RHR pumps develops a flow I of at least 500 gpm on recirculation flow (through the RHR heat exchanger) and suppression pool spray sparger when tested pursuant to Specification 4.0.5.
- c. At least once per 18 months by performance of a system functional test which includes manual actuation of the system and verifying that each automatic valve in the flow path is in its correct position.
- d. By performance of an air or smoke flow test of the drywell spray nozzles at least once per 5 years and verifying that each spray nozzle is unobstructed.
*Whenever both RHR subsystems are inoperable, if unable to attain COLD SHUTDOWN as required by this ACTION, maintain reactor coolant temperature as low as practical by use of alternate heat removal methods.
HOPE CREEK 3/4 6-15
4 s CONTAINMENT SYSTEMS JIl[l4.h SUPPRESSION POOL COOLING LIMITING CONDITION FOR OPERATION 3.6.2.3 system shall be OPERABLE with two independent loo
- a. One OPERABLE RHR pump, and b.
An OPERABLE flow path capable of recirculating water from the suppression chamber through an RHRSW heat exchanger. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION: a. With one suppression pool cooling loop inoperable, restore the HOT SHUTDOWN the following 24 hours, within the next 12 hours and in b. HOT SHUTOOWN within 12 hours and in COLD S 24 hours. SURVEILLANCE REQUIREMENTS 4.6.2.3 demonstrated OPERABLE:The suppression pool cooling mode of the RHR system shall b
- a. ,
At least once per 31 days by verifying that each valve, manual, power operated or automatic, in the flow path that is not locked, sealed or otherwise secured in position, is in its correct position. } b. By verifying that each of the required RHR pumps develops a flov of at least 10,000 gpm on recirculation flow through the RHR heat exchanger and4.0.5. Specification the suppression pool when tested pursuant to (
"Whenever both RHR subsystems are inoperable, if unable to attain COLD SHUT '
practical by use of alternate heat removal methods.as required by th l 1 HOPE CREEK 3/4 6-16
CONTAINMENT SYSTEMS *hi\ Vl > wdt/11 l 3/4.6.3 PRIMARY CONTAINMENT ISOLATION VALVES JUN 2 8 ;ggg LIMITING CONDITION FOR OPERATION 3.6.3 The primary containment isolation valves and the reactor instrumentatien
'it: arces: flev chack valvc; a;;u-n ... TaLie 3.6.3-1 shall be OPERABLE with isolation times less than or equal to those shown in Table 3.6.3-1.
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:
- a. With one or more of the primary containment isolation valves shown in Table 3.6.3-1 inoperable, maintain at least one isolation valve OPERABLE in each affected penetration that is open and within 4 hours either:
- 1. Restore the inoperable valve (s) to OPERABLE status, or
- 2. Isolate each affected penetration by use of at least one deactivated automatic valve secured in the isolated position,* or
- 3. Isolate each affected penetration by use of at least one closed manual valve or blind flange.*
Otherwise, be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours,
- b. With one or more of the reactor instrumentation line excess flow check valves shown in Table 3.6.3-1 inoperable, operation may continue and the provisions of Specifications 3.0.3 and 3.0.4 are not applicable provided that within 4 hours either:
- 1. The inoperable valve is returned to OPERABLE status, or
- 2. The instrument line is isolated and the associated instrument is declared inoperable.
Otherwise, be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.
^1 solation valves closed to satisfy these requirements may be reopened on an intermittent basis under administrative control.
P J HOPE CREEK 3/4 6-17
- l. Q ,5 f CONTAINNENT SYSTEMS hu .. ~
p e E 193E SURVEILLANCE REQUIREMENTS 4.6.3.1 Each primary containment isolation valve shown in Table 3.6.3-1 shall be demonstrated OPERABLE prior to returning the valve to service after mainte-nance, repair or replacement work is performed on the valve or its associated actuator, control or power circuit by cycling the valve through at least one complete cycle of full travel and verifying the specified isolation time. 4.6.3.2 Each primary containment automatic isolation valve shown in Table 3.6.3-1 shall be demonstrated OPERABLE during COLD SHUTDOWN or REFUELING at least once per 18 months by verifying that on a containment isolation test signal each automatic isolation valve actuates to its isolation position. 4.6.3.3 The isolation time of each primary containment power operated or I automatic valve shown in Table 3.6.3-1 shall be determined to be within its l r limit when tested pursuant to Specification 4.0.5. l - 4.6.3.4 Each reactor instrumentation line excess flow check valve shown in Table 3.6.3-1 shall be demonstrated OPERABLE at least once per 18 months by verifying that the valve checks flow at greater than a (10) psid differential pressure. 4.6.3.5 Each traversing in-core probe system explosive isolation valve shall be demonstrated OPERABLE:
- a. At least once per 31 days by verifying the continuity of the explosive charge.
- b. At least once per 18 months by removing the explosive squib from at least one explosive valve such that each explosive squib in each explosive valve will be tested at least once per 90 months, and initiating the explosive squib. The replacement charge for the exploded squib shall be from the same manufactured batch as the one j fired or from another batch which has been certified by having at least one of that batch successfully fired. No squib shall remain in use beyond the expiration of its shelf-life or operating life, as applicable.
f i HOPE CREEK 3/4 6-18 i
TABLE 3.6.3-1 E g PRIMARY CONTAINMENT ISOLATION VALVES S lE MAXIMUM VALVE FUNCTION AND NUMBER ISOLATION TIME (Seconds)
- a. Automatic Isolation Valves
- 1. Group 1 - Main Steam system (a) Main Steam Isolation Valves (MSIVs)
Inside: - Line A HV-F022A (AB-V028) 5 Line B HV-F0228 (AB-V029) 5 Line C HV-F022C (AB-V030) 5 s Line D llV-F0220 (AB-V031) 5 Outside: T 5 Line A HV-F028A (AB-V032) 5 Line B HV-F0288 (AB-V033) 5 Line C HV-F028C (AB-V034) 5 Line D HV-F0280 (AB-V035) 5 (b) Main Steam Line Drain Isolation Inside: ilV-F016 (AB-V039) 19 Outside: Line A IIV-F067A (AB-VP'3) 29 Line B HV-F0678 (AB-V060) 29 Line C HV-F067C (AB-V061) 29 Line D HV-F0670 (AB-V062) 19 HV-F019 (AB-V040) k a co M
- ih
.- rs ^
.Q
x TABLE 3.6.3-1 (Continued) m PRIMARY CONTAINMENT ISOLATION VALVES i [9 x MAXIMUi4 VALVE FUNCTION AND NUMBER ISOLATION TIME i (Seconds) (c) MSIV Sealing System Isolation Valves i Outside: i Line A HV-5834A (KP-V010) 29 Line B HV-5835A (KP-V009) 29 - Line C HV-5836A (KP-V008) 29 Line D HV-5837A (KP-V007) 29 i j 2. Group 2 - Reactor Recirculation Water Sample System y (a) Reactor Recirculation Water Sample Line Isolation Valves 1 w T Inside: BB-SV-4310 15
; g Outside: BB-SV-4311 15
- 3. Group 3 - Residual Heat Removal (RHR) System 1
(a) RilR Suppression Pool Cooling Water & System Test Isolation Valves
, Loop A: ilV-F024A (BC-V124) ' 180 ilV-F010A (BC-V125) 180 HV-F011A (BC-V126) locked closed Loop B: ilV-F0248 (BC-V028) 180 llV-F0108 (BC-V027) 180 HV-F011B (BC-V026) locked closed i l (b) RHR to Suppression Chamber Spray Header Isolation Valves Loop A: HV-F027A (BC-V112)
Loop B: 65 g ilV-F0278 (BC-V015) 65
.h, g
h %g
5 TABLE 3.6.3-1 (Centinu:d)
;g PRIMARY CONTAINMENT ISOLATION VALVES i
O m
? MAXIMUM ISOLATION TIME VALVE FUNCTION AND NUMBER (Seconds)
(c) RHR Shutdown Cooling Suction Isolation Valves Inside: HV-F009 (BC-V071) Outside: 60 IIV-F008 (BC-V164) 60 (d) RHR Head Spray Isolation Valves - ' Inside: ilV-F022 (BC-V021) Outside: 35 ilV-F023 (BC-V020) 54
, (e) RilR Shutdown Cooling Return Isolation Valves h . Loop A: ilV-F015A (BC-V110) 4 60 w
Loop B: HV-F015B (BC-V013) 60
- 4. Group 4 - Core Spray System (a) Core Spray Test to Suppression Pool Isolation Valves 1 Loop A: ilV-F015A (BE-V025)
Loop B: 72 ilV-F0158 (BE-V026) 72
- 5. Group 5 - liigh Pressure Coolant Injection (HPCI) System (a) HPCI Turbine Steam Supply Isolation Valves Inside: HV-F002 (F0-V001) 50 ilV-F100 (F0-V051)
! 29 Outside: ilV-F003 (F0-V002) 50 (b) IIPCI Pump suction Isolation Valve HV-F042 (BJ-V009) 96
- i
TABLE 3.6.3-1 (Continued) PRIMARY CONTAINMENT ISOLATION VALVES n 5 MAXIMUM W ISOLATION TIME VALVE FUNCTION AND NUMBER (Seconds) (c) HPCI Turbine Exhaust Isolation Valve to Vacuum Breaker Network HV-F075 (FD-V007) 22 (d) HPCI and RCIC Vacuum Network Isolation Valve v - HV-F079 (FD-V010) 21
- 6. Group 6 - Reactor Core Isolation Cooling (RCIC) System 5 (a) RCIC Turbine Steam Supply Isolation Valves m
a Inside: ilV-F007 (FC-V001) 20 HV-F076 (FC-V048) 29 Outside: ilV-F008 (FC-V002) 20 (b) RCIC Turbine Exhaust Isolation Valve to l Vacuum Breaker Network l IIV-F062 (FC-V006) 21 (c) HPCI and RCIC Vacuum Network Isolation Valve HV-F084 (FC-V007) 21
- 7. Group 7 - Reactor Water Cleanup (RWCU) System (a) RWCU Supply Isolation Valves Inside: HV-F001 (BG-V001) 35 Outside: HV-F004 (BG-V002)
~
35 co to Ncm j
TABLE 3.6.3-1 (Centinu:d) 5 A PRIMARY CONTAINMENT ISOLATION VALVES g p MAXIMUM ISOLATION TIME VALVE FUNCTION AND NUMBER (Seconds) -
- 8. Group 8 - Suppression Pool Cleanup (SPC) System (a) SPC Suction Isolation Valves HV-4680 (EE-V003) 39
~
HV-4681 (EE-V004) 39 (b) SPC Return Isolation Valves HV-4652 (EE-V002) 39 m HV-4679 (EE-V001) 39 1 o, 9. Group 9 - Drywell Sumps E w (a) Drywell Floor Drain Sump Discharge Isolation Valves Inside: HV-F003 (HB-V005) 21 Outside: HV-F004 (HB-V006) 21 (b) Drywell Equipment Drain Sump Discharge Isolation Valves Inside: HV-F019 (HB-V045) 21 Outside: HV-F020 (HB-V046) 21
- 10. Group 10 - Drywell Coolers (a) Chilled Water to Drywell Coolers Isolation Valves Inside:
Loop A: HV-953IB1 (GB-V081) 51 Loop B: HV-953183 (GB-V083) *- 51 gg n M
. h R :Q
+
TABLE 3.6.3-1 (Continued) m PRIMARY CONTAINMENT ISOLATION VALVES k W MAXDIUM VALVE FUNCTION AND NUMBER ISOLATION TIME ' (Seconds) Outside: Loop A: ilV-9531A1 (GB-V048) 51 Loop B: ilV-9531A3 (GB-V070) 51 (b) Chilled Water from Drywell Coolers Isolation Valves Inside: Loop A: HV-953182 (GB-V082) 51 Loop B: ilV-953184 (GB-V071) 51 w Outside: 1 Loop A: ilV-9531A2 (GB-V046) m 51 Loop B: ilV-9531A4 (GB-V071) 51
- 11. Group 11 - Recirculation Pump System (a) Recirculation Pump Seal Water Isolation Valves Loop A: ilV-3800A (BF-V098)
Loop B: 29 ilV-38008 (BF-V099) 29
- 12. Group 12 - Containment Atmosphere Control system (a) Drywell Purge Supply Isolation Valves IIV-4956 (GS-V009) (A) 9 HV-4979 (GS-V021) (A) 9 (b) Drywell Purge Exhaust Isolation Valves llV-4951 (GS-V025) flV-4950 (GS-V026) (A) 15 9
hLD m .~- C - IIV-4952 (GS-V024) (A) 9 co A
%q
o TABLE 3.6.3-1 (Continued)
- 7. PRIMARY CONTAINMENT ISOLATION VALVES k MAXIMUM E ISOLATION TIME VALVE FUNCTION AND NUMBER (Seconds)
(c) Suppression Chamber Purge Supply Isolation Valves HV-4980 (GS-V020) (A) 9 HV-4958 (GS-V022) (A) 9 (d) Suppression Chamber Purge Exhaust Isolation Valves HV-4963 (GS-V076) 15 HV-4962 (GS-V027) (A) 9 HV-4964 (GS-V028) (A) 9 (e) Nitrogen Purge Isolation Valves b
- HV-4974 (GS-V053) 29 HV-4978 (GS-V023) 9
- 13. Group 13 - Hydrogen /0xygen (H2/02) Analyzer System (a) Drywell H2/02 Analyzer Inlet Isolation Valves Loop A: HV-4955A (GS-V045) 29 HV-4983A (GS-V046) 29 HV-4984A (GS-V048) 29 HV-5019A (GS-V047) 29 Loop 8: HV-49558 (GS-V031) 29 HV-49838 (GS-V032) 29 HV-49848 (GS-V034) 29 HV-50198 (GS-V033) 29 gQ eo
= .h3
-an
n o TABLE 3.6.3-1 (Centinued) 55 PRIMARY CONTAINMENT ISOLATION VALVES 2 fM m x MAXIMUM VALVE FUNCTION ANO NUMBER ISOLATION TIME (Seconds) (b) Suppression Chamber H2/02 Analyzer Inlet Isolation Valves - Loop A: HV-4965A (GS-V050) 29 HV-4959A (GS-V049) 29 Loop B: HV-4965B (GS-V041) 29 HV-49598 (GS-V040) 29 (c) H2/02 Analyzer Return to Suppression Chamber q, Isolation Valves u ei Loop A: HV-4966A (GS-V051) f; 29 ilV-5022A (GS-V052) 29 Loop B: HV-4966B (GS-V042) 29 HV-5022B (GS-V0'43) 29 14. Group 14 - Containment Hydrogen Recombination (CHR) System (a) CHR Supply Isolation Valves Loop A: ilV-5050A (GS-V002) 28 ilV-5052A (GS-V003) 28 Loop B: HV-50508 (GS-V004) 28 HV-50528 (GS-V005) 28 (b) CllR Return Isolation Valves Loop A: HV-5053A (GS-V008) 39 g , HV-5054A (GS-V010) 39 g 5, . ,j ds ~,3 00
~ 'e_._
C- !
TABLE 3.6.3-1 (C:ntinued) E g PRIMARY CONTAllMENT ISOLATION VALVES O N MAXIMUM VALVE FUNCTION AND NUMBER ISOLATION TIME (Seconds) Loop 8: HV-50538 (GS-V006)
- 39 HV-50548 (GS-V007) 39 1
- 15. Group 15 - Primary Containment Instrument Gas System (PCIGS) ,
1 (a) PCIGS Drywell Header Isolation Valves Inside: Loop A: HV-5152A (KL-V028) 29 Loop B: HV-51528 (KL-V026) 29 . Outside: ' I T Loop A: HV-5126A (KL-V027) O 29 f Loop B: HV-5126B (KL-V025) 29 t (b) PCIGS Drywell Suction Isolation Valves 1 ! Inside: HV-5148 (KL-V001) 29 Outside: Loop A: HV-5147 (KL-V002) 29 Loop B: HV-5162 (KL-V049) 29 ' (c) PCIGS Suppression Chamber Supply Isolation Valves l 3 HV-5154 (KL-V018) 15
- HV-5155 (KL-V019) 15 1 -
h C 0
*e. a
o TABLE 3.6.3-1 (Continued) m PRIMARY CONTAINMENT ISOLATION VALVES E m E MAXIMUM VALVE FUNCTION AND NilMBER ISOLATION IIME (Seconds)
- 16. Group 16 - Reactor Auxiliaries Cooling System (RACS)
(a) RACS Supply Isolation Valves Inside: IIV-2554 (ED-V020) 28 Outside: IIV-2553 (ED-V019) " 28 (b) RACS Return Isolation Valves Inside: ilV-2556 (ED-V022) 28 1 Outside: ilV-2555 (ED-V021) 28 7 17. Group 17 - Traversing In-core Probe (TIP) System (a) TIP Probe Guide Tube Isolation Valves SV-J004A-1 (SE-V026) 15 SV-J004A-2 (SE-V027) 15 SV-J004A-3 (SE-V028) 15 SV-J004A-4 (SE-V029) 15 SV-J004A-5 (SE-V030) 15 (b) TIP Purge System Isolation Valve HV-5161 (SE-V004) 15
- 18. Group 18 - Reactor Coolant Pressure Boundary (RCPB)
Leakage Detection System (a) Drywell Leak Detection Radiation Monitoring System (DLD-RMS) Inlet Isolation Valves h CD llV-5018 (SK-V005) liv-4953 (SK-V006) 29 29 N
.1
5 TABLE 3.6.3-1 (Continued) A PRIMARY CONTAINMENT 1501ATION VALVES n s MAXIMUM W ISOLATION TIME VALVE FUNCTION AND NUMBER (Seconds) (b) DLD-RMS Return Isolation Valves HV-4957 (SK-V008) 29 HV-4981 (SK-V009) 29
- b. Manual Isolation Valves
- 1. Group 21 - Feedwater System (a) Feedwater Isolation Valves
$ HV-F0748 (AE-V002) m HV-F074A (AE-V006) U 2. Group 22 - High Pressure Coolant Injection (HPCI) System (a) Feedwater Discharge Valve HV-8278 (BJ-V059) (b) Core Spray Discharge Valve HV-F006 (8J-V001) (c) Turbine Exhaust Valve HV-F071 (FD-V006) (d) HPCI Minimum Return Line Valve HV-F012 (BJ-V016)
- 3. Group 23 - Reactor Core Isolation Cooling (RCIC) System (a) Feedwater Discharge Valve f F
LU HV-F013 (80-V005) "1-(b) RCIC Turbine Exhaust Valve ' HV-F059 (FC-V005) tf
TABLE 3.6.3-1 (Continued) '1 5 g PRIMARY CONTAlletENT ISOLATION VALVES n A MAXIMUM y ISOLATION TIME VALVE FUNCTION AND NUMBER (Seconds) (c) RCIC Pump Suction Isolation Valve HV-F031 (80-V003) (d) RCIC Minimum Return Line Isolation Valve SV-F019 (80-V007) (e) RCIC Vacuum Pump Discharge ilV-F060 (FC-V011)
- 4. Group 24 - Reactor Water Cleanup (RWCU) System (a) Heactor Return Valve HV-F0309 (AE-V021)
$ 5. Group 25 - Core Spray System (a) Core Spray injection Valves Loop A&C HV-V005A (BE-V007)
Loop B&O HV-F0058 (BE-V003) (b) Core Spray Suppression Pool Suction Valves Loop A HV-F001A (BE-V017) Loop B HV-F001B (BE-V019) Loop C llV-F001C (BE-V018) Loop D llV-F0010 (BE-V020) (c) Core Spray Minimum Flow Valves Loop A&C HV-F031A (BE-V035) Loop B&D HV-F0318 (BE-V036) (d) Core Spray Injection Line Bypass Valves HV-F039A (BE-V071) " HV-V0398 (BE-V072) ,
a TABLE 3.6.3-1 (Continued) m PRIMARY CONTAIWMENT ISOLATION VALVES 2 m MAXIMUM E ISOLATION TIME VALVE FUNCTION AND NUMBER (Seconds,
- 6. Group 26 - Residual Heat Removal System (a) Low Pressure coolant Injection Valves Loop AHV-V017A (BC-V113)
Loop BHV-V0178 (BC-V016) Loop CHV-V017C (BC-V101) Loop OHV-V0170 (BC-V004) (b) RflR Containment Spray Loop AHV-F021A (BC-V116) e, HV-F016A (BC-V115) a H Loop BHV-F0218 (BC-V019) HV-F0168 (BC-V018) (c) Rt:R Suppression Pool Suction Loop AllV-F004A (BC-V103) Loop BHV-F004B (BC-V006) Loop CilV-F004C (BC-V098) Loop OllV-F004D (BC-V001) (d) RHR Minimum Flow Isolation Valves Loop AHV-F007A (BC-V128) Loop BHV-F0078 (BE-V031) Loop CHV-F007C (BE-F131) Loop DilV-FC070 (BE-F034)
# es
~5 G
5 .- TABLE 3.6.3-1 (Continued) N ,, PRIMARY CONTAINMENT ISOLATION VALVES S m N MAXIMUM VALVE FUNCTION AND NUMBER ISOLATION TIME (Seconds) (e) Bypass Valves on LPCI Injection Lines HV-F146A (BC-V119) liv-F1468 (BC-V120) IIV-F146C (BC-V121) IIV-F1460 (BC-V122) (f) Bypass Valves on Shutdown Cooling Return Lines HV-F122A (BC-V117) w HV-F1228 (BC-F118) 1 o, 7. Group 27 - Standy Liquid Control w HV-F006A (BH-V028) HV-F0068 (BH-V054)
- 8. Group 28 - Containment Atmosphere Control System Supression Chamber Vacuum Relief HV-5031 (GS-V038)
IIV-5029 (GS-V080)
- 9. Group 69 - TIP System Explosive Shear Valves SE-V021 SE-XV-J004B1 SE-V022 SE-XV-J00182 SE-V023 SE-XV-J00483 SE-V024 SE-XV-J004B4 hO"C3 SE-V025 SE-XV-J004BS eo
5 TABLE 3.6.3-1 (Continued) A PRIMARY CONTAINMENT ISOLATION VALVES 2 m MAXIMUM W ISOLATION T.ME VALVE FUNCTION AND NUMBER (Seconds)
- 10. Group 29 - HPCI System Suppression Pool Level Instrumentation Isolation HV-4803 (BJ-VS00)
HV-4804 (BJ-VS01) HV-4865 (BJ-VS02) HV-4866 (BJ-VS03)
- 11. Group 30 - Post-Accident Sampling System Liquid Sampling a
w RC-SV-0643A RC-SV-06438 RC-SV-8903A
.RC-SV-8902B Gas Sampling
.- RC-SV-0730A RC-SV-0729A 2 RC-SV-0730B RC-SV-07298 RC-SV-0731A RC-SV-0707A RC-SV-07318 RC-SV-07078 RC-SV-0728A RC-SV-07288
~
- Es' B
=
9 x TABLE 3.6.3-1 (Continued) m PRIMARY CONTAINMENT ISOLATION VALVES 9 m m
- MAXIMUM ISOLATION TIME VALVE FUNCTION AND MIMBER (Seconds)
- c. Primary Containment
{ (Other Isolation Valves)
- 1. Group 31 - Feedwater System (a) Feedwater Isolation Valves P Inside Check Valves -
AE-V003 R a AE-V007
? 2. Group 32 - Standby Liquid Control System .
Inside Check Valve e BH-V-29 i
- 3. Group 33 - Primary Containment Atmosphere Control / System Containment Vacuum Breakers GS-PSV-5032 GS-PSV-5030
- 4. Group 34 - Service Air System i
KA-V038 KA-V039 d
- 5. Group 35 - Breathing Air System 2
= -n s
to %.g KG-V016
- KG-V034 -I 3 .
TABLE 3.6.3-1 (Continued) PRIMARY CONTAINMENT ISOLATION VALVES S E
- MAXIMUM VALVE FUNCTION AND NUMBER ISOLATION TIME (Seconds)
- 6. Group 36 - flP Purge System-Check Valve SE-V006
- 7. Group 37 - HPCI System HPCI Turbine Exhaust FD-V004
, 8. Group 38 - RCIC System RCIC Turbine Exhaust FC-V003 Vacuum Pump Discharge FC-V010
- 9. Group 39 - RifR System (a) Thermal Relief Valves Loop A BC-PSV-V025A Loop B BC-PSV-V0258 Loop C BC-PSV-V025C Loop D BC-PSV-V0250 (b) Jockey Pump Discharge Check Valves Loops A&C (BC-V206)
Loops B&D (BC-V260) (c) RHR Heat Exchanger Thermal Relief Valves C BC-PSV-4431A 00 BC-PSV-44310
+
2 TABLE 3.6.3-1 (Continued) m PRIMARY CONTAINMENT ISOLATION VALVES E y MAXIMUM ^ ISOLATION TIME VALVE FUNCTION AND NUMBER (Seconds) (d) RHR Shutdown Cooling Suction Thermal Relief Valve BC-PSV-4425 (e) LPCI Injection Line Check Valves HV-F041A (BC-V114) HV-F041B (BC-V017) HV-F041C (BC-V102) HV-F0410 (BC-V005) s"
- (f) Shutdown Cooling Return Line Check Valves P
g HV-F050A (BC-Vill) HV-F050B (BC-V014)
- 10. Group 40 - Core Spray System (a) Thermal Relief Valves Loop A&C BE-PSV-F012A Loop B&D BE-PSV-F0128 (b) Core Spray Injection Line Check Valves llV-F006A (BE-V006)
HV-F0068 (BE-V002) ci
- 11. Group 41 - Drywell Pressure Instrumentation BB-V563
[ o> Q g .-J BB-V564
- .13 B8-V565 U
'" M 88-V566 ~4
TABLE 3.6.3-1 (Continued) E y PRIMARY CONTAINMENT ISOLATION VALVES S N MAXIMUM
- ISOLATION TIME VALVE FUNCTION AND NUMBER (Seconds) i
- 12. Group 42 - Intergrated Leak Rate Testing System GP-V001 GP-V004 GP-V002 GP-V005 GP-V120 GP-V122
- 13. Group 43 - Suppression Chamber Pressure Instrumentation f GS-V044 l , GS-V087 s
- 14. Group 44 - Chilled Water System Thennal Relief Valves U G8-PSV-9522A G8-PSV-9523 G8-PSV-9523A J
G8-PSV-95238
- 15. Group 45 - Recirculation Pump Seal Purge Line Valves BB-V043 BB-V047
- d. Excess Flow Check Valves
- 1. Group 46 - Nuclear Boiler 88-XV-3649 '
AB-XV-3666A through D g A8-XV-3667A through D Q AB-XV-3668A through D
- e to y
5 AB-XV-3669A through D
- C3
1 TABLE 3.6.3-1 (Continued) ns PRIMARY CONTAINMENT ISOLATION VALVES O m N MAXIMUM ISOLATION TIME VALVE FUNCTION AND NUMBER . (Seconds)
- 2. Group 47 - Muclear Boiler Vessel Instrumentation 88-XV-3621 BB-XV-3688 -
88-XV-3691 A and 8 88-XV-3725 B8-XV-3726 A and B 88-XV-3727 A and B 88-XV-3728 A and 8 BB-XV-3729 A and 8 ta BB-XV-3730 A and 8 2 88-XV-3731 A and 8 on 88-XV-3732 A thru H g; BB-XV-3732 J thru N 88-XV-3732 P 88-XV-3732 R thru W B8-XV-3734 A thru O 88-XV-3737 A and 8 88-XV-3738 A and 8
- 3. Group 48 - Reactor Recirculation System BB-XV-3783 BB-XV-3785 BB-XV-3787 B8-XV-3789 88-XV-3801 A thru D 88-XV-3802 A thru D BB-XV-3803 A thru 0 BB-XV-3804 A thru 0 c_ EIOI c ::23 5 h
- " :::1 m
l i . TABLE 3.6.3-1 (Continued) x o PRIMARY CONTAlfetENT ISOLATION VALVES Q MAXIMUM - p ISOLATION TIfE
^ VALVE FUNCTION AND NlstBER (Seconds)
- 4. Group 49 - Reactor Recirculation System - Cont'd.
B8-XV-3820 , 88-XV-3821 ! ! 88-XV-3826 88-XV-3827 l ! 5. Group 50 - Reactor Water Cleanup BG-XV-3882 i 8G-XV-3884 A thru D I w s
- 6. Group 51 - Reactor Core Isolation Cooling Systen l
l T i l g FC-XV-4150 A thru D
- 7. Group 52 - Residual Heat Removal Systen l l
BC-XV-4411 A thru D i BC-XV-4429 A thru D ' i i 1 >
- 8. Group 53 - Core Spray System i
BE-XV-F018 A and 8 i
- 9. Group 54 - High Pressure Coolant Injection Systen FD-XV-4800 A thru D C
(b) May be opened on an intermittent basis under administrative control, h -- , l (c) Not subject to Type C leakage tests. (d) Excess flow check valve. J h
~
L i
,E
.Q I
;A >
l
CONTAINMENT SYSTEMS 3/4.6,4 VACUUM RELIEF SUPPRESSION CHAMBER - ORWELL VACUUM BREAKERS LIMITING CONDITION FOR OPERATION _ 3.6.4.1 All of suppression chamoer - drywell vacuum breakers shall be OPERABLE and closed. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:
- a. With one of the above vacuum breakers inoperable for opening but known to be closed, restore the inoperable vacuum breakers to OPERABLE status within 72 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SH9TDOWN within the following 24 hours.
- b. With one or more suppression chamber - drywell vacuum breaker open, close the open vacuum breaker (s) within 2 hours; or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the M following 24 hours.
- c. With one of the position indicator of any suppression chamber - '
drywell vacuum breaker inoperable:
- 1. Verify the other vacuum breaker in the pair to be closed within 2 hours and at least once per 15 days thereafter, and (2. Verify the vacuum breaker (s) with the inoperable position indicator to be closed by (conducting a test which demonstrates that the AP is maintained at greater than or equal to 0.5 psi for one hour without makeup within 24 hours and at least once per 15 days thereafter).)
Otherwise, be in at least HOT SHUT 00WN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours. 8 HOPE CREEK 3/4 6-40
CONTAINMENT SYSTEMS ~1 50 JUN 2 8 1985 SURVEILLANCE REQUIREMENTS 4.6.4.1 Each suppression chamber - drywell vacuum breaker shall be:
- a. erified closed at least once per 7 aays.
- b. Demonstrated GPERABLE. I 1.
At least once per 31 days and within 2 hours after any discharge of steam to the suppression chamber from the safety relief valves, by cycling each vacuum breaker through at least one complete cycle of full travel.
- 2. At least once per 31 days by verifying both position indicators OPERABLE by observing expected valve movement during the cycling test.
- 3. At least once per 18 months by; a) Verifying the opening setpoint, from the closed position, to be less than or equal to 0.25 psid, and b) Verifying both position indicators OPER BLE by performance of a CHANNEL CALIBRATION.
K0PE CREEK 3/4 6-41
I 4 CONTAINMENT SYSTEMS REACTOR BUILDING - SUPPRESSION CHAMBER VACUUM BREAKERS LIMITING CONDITION FOR OPERATION
- 3. .*.i Ali Reactor Building - suppression chamber vacuum breakers shall be OPERABLE and closed.
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:
- a. With one Reactor Building suppression chamber vacuum breaker inoperable for opening but known to be closed, restore the inoperable vacuum breaker to OPERABLE status within 72 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.
- b. With one Reactor Building - suppression chamber vacuum breaker open, verify the other vacuum breaker in the line to be closed within 2 hours; 4
restore the.open vacuum breaker to the closed position within 72 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.
- c. With the position indicator of any suppression chamber - drywell vacuum breaker inoperable, (restore the inoperable position indicator to OPERABLE status within 14 days or verify the vacuum breaker to be closed at least once per 24 hours by (an alternate means). Otherwise,)
(declare the vacuum breaker inoperable or) be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours. SURVEILLANCE REQUIREMENTS ( 4.6.4.2 Each Reactor Building - suppression chamber vacuum breaker shall be: ! a. Verified closed at least once per 7 days. l b. Demonstrated OPERABLE:
- 1. At least once per 31 days by:
a) Cycling vacuum breaker through at least one complete cycle of full travel. b) Verifying both position indicators OPERABLE by observing expected valve movement during the cycling test.
- 2. At least once per 18 months by:
a) Demonstrating that the force required to open each vacuum breaker l does not exceed the equivalent of 0.25 psid. , ! b) Visual inspection. c) Verifying both position indicators OPERABLE by performance of a l CHANNEL CALIBRATION. HOPE CREEK 3/4 6-42 l t - - - -
CONTAINMENT SYSTEMS ! 3/4.6.5 SECONDARY CONTAINMENT e&f
, h, d I i
SECONDARY CONTAINMENT INTEGRITY y 2 5 E5 LIMITING CONDITION FOR OPERATION l l 3.6.5.1 SECONDARY CONTAINMENT INTEGRITY shall be maintained. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3 and *. ACTION: l Without SECONDARY CONTAINMENT INTEGRITY:
- a. In OPERATIONAL CONDITION 1, 2 or 3, restore SECONDARY CONTAINMENT INTEGRITY within 4 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.
- b. In Operational Condition *
, suspend handling of irradiated fuel in 1 the secondary containment, CORE ALTERATIONS and operations with a potential for draining the reactor vessel.
~
The provisions of Specification 3.0.3 are not applicable. _ SURVEILLANCE REQUIREMENTS 4.6.5.1 SECONDARY CONTAINMENT INTEGRITY shall be demonstrated by:
- a. Verifying at least once per 24 hours that the pressure within the secondary containment is less than or equal to (0.25) inches of vacuum water gauge.
- b. Verifying at least once per 31 days that:
- 1. All secondary containment equipment hatches and blowout panels are closed and sealed.
- 2. At least one door in each access to the secondary containment is closed.
- 3. All secondary containment penetrations not capable of being closed by OPERABLE secondary containment automatic isolation dampers /
valves and required to be closed during accident conditions are closed by valves, blind flanges, or deactivated automatic dampers / valves secured in position.
- c. At least once per 18 months:
- 1. Verifying that four filtration units and one ventilation unit of the filtration recirculation and ventilation system will draw down the secondary containment to greater than or equal to 0.25 inches of vacuum water gauge in less than or equal to 168 seconds, and
- 2. Operating four filtration units and one ventilation unit of the filtration recirculation and ventilation system for four hours and maintaining greater than or equal to 0.25 inches of vacuum water gauge in the secondary containment at a flow rate not exceeding 3324 CFM.
*When irradiated fuel is being handled in the secondary containment and during CORE ALTERATIONS and operations with a potential for draining the reactor vessel.
HOPE CREEK 3/4 6-43
CONTAINMENT SYSTEMS SECONDARY CONTAINMENT AUTOMATIC ISOLATION DAMPERS y; 3 8 gg LIMITING CONDITION FOR OPERATION 3.6.5.2 The secondary containment ventilation system automatic isolation (dampers) (valves) shown in Table 3.6.5.2-1 shall be OPERABLE with isniation times ic;s thor, er equal to the i.iaes shown in s able 3.6.d.2-1. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3 and ". ACTION: With one or more of the secondary containment ventilation system automatic isolation dampers shown in Table 3.6.5.2-1 inoperable, maintain at least one isolation damper OPERABLE in each affected penetration that is open and within 8 hours either:
- a. Restore the inoperable dampers to OPERABLE status, or
- b. Isolate each affected penetration by use of at least one deactivated damper secured in the isolation position, or
- c. Isolate each affected penetration by use of at least one closed manual valve or blind flange.
Otherwise, in OPERATIONAL CONDITION 1, 2 or 3, be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours. Otherwise, in Operational Condition *
, suspend handling of irradiated fuel in the secondary containment, CORE ALTERATIONS and operations with a potential for draining the reactor vessel. The provisions of Specification 3.0.3 are not applicable.
SURVEILLANCE REQUIREMENTS 4.6.5.2 Each secondary containment ventilation system automatic isolation damper shown in Table 3.6.5.2-1 shall be demonstrated OPERABLE:
- a. Prior to returning the damper to service after maintenance, repair or replacement work is performed on the damper or its associated actuator, control or power circuit by cycling the damper through at least one complete cycle of full travel and verifying the specified isolation time.
l b. During COLD SHUTOOWN or REFUELING at least once per 18 months by verifying that on a containment isolation test signal each isolation damper actuates to its isolation position. l c. By verifying the isolation time to be within its limit when tested pursuant l to Specification 4.0.5. , i
*When irradiated fuel is being handled in the seco.idary containment and during CORE ALTERATIONS and operations with a potential for draining the reactor vessel.
HOPE CREEK 3/4 6-44
l i TABLE 3.6.5.2-1 l SECONDARY CONTAINMENT VENTILATION SYSTEM AUTOMATIC ISOLATION DAMPERS JUN 2 8 1985 MAXIMUM ISOLATION TIME (DAMPER)(VALVE) FUNCTION (Seconds)
- 1. Re ctor Building Ventilation Supply Damper HD-9370A 10
- 2. Reactor Building Ventilation Supply Damper HD-93703 10
- 3. Reactor Building Ventilation Exhaust Damper HD-9414A 10
- 4. Reactor Building Ventilation Exhaust Damper HD-94148 10
- 5. , Filtration, Recirculation and Ventilation 15 Bypass Damper HD-9395A
- 6. Filtration, Recirculation and Ventilation 15 Bypass Damper HD-93958 HOPE CREEK 3/4 6-45
CONTAINMENT SYSTEMS ! FILTRATION, RECIRCULATION AND VENTILATION SYSTEM (FRVS) JUN 2 8 IS63" LIMITING CONDITION FOR OPERATION 3.6.5.3 Six FRVS recirculation units and two FRVS ventilation units shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3 and *. , ACTION:
- a. With two FRVS recirculation units or one FRVS ventilation unit inoper-able, restore the inoperable unit to OPERABLE status within 7 days, or:
~
i
- 1. In OPERATIONAL CONDITION 1, 2 or 3, be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.
- 2. In Operational Condition *
, suspend handling of irradiated fuel in the secondary containment, CORE ALTERATIONS and operations with a potential for draining the reactor vessel. The provisions of Specification 3.0.3 are not applicable.
- b. With three FRVS recirculation or both ventilation units inoperable in Operational Condition *, suspend handling of irradiated fuel in the secondary containment, CORE ALTERATIONS or operations with a potential for draining the reactor vessel. The provisions of Speci-fication 3.0.3. are not applicable.
SURVEILLANCE REOUIREMENTS 4.6.5.3 Each of the six FRVS recirculation and two ventilation units shall be demonstrated OPERABLE:
- a. At least once per 31 days by initiating, from the control room, flow through the HEPA filters-and charcoal adsorbers and verifying that the subsystem operates for at least 10 hours with the heaters and humid-ity control instrumentation OPERABLE.
*When irraciated fuel is being handled in the secondary containment and during CORE ALTERATIONS and operations with a potential for draining the reactor vessel.
HOPE CREEK 3/4 6-46 l l
CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) J$ 2 6 $"-
- b. At least once per 18 months or (1) after any structural maintenance on the HEPA filter or charcoal adsorber housings, or (2) following painting, fire or chemical release in any ventilation zone communicating with the subsystem by:
- 1. Verifying that the subsystem satisfies the in place penetration and bypass leakage testing acceptance criteria of less than (*)%
and uses the test procedure guidance in Regulatory Positions C.5.a. C.5.c and C.5.d of Regulatory Guide 1.52, Revision 2, March 1978, and the system flow rates are 30,000 cfm i 10% for each FRVS recirculation unit, and 9,000 cfm i 10% for each FRVS ventilation unit.
- 2. Verifying within 31 days after removal that a laboratory analysis of a reprpsentative carbon sample obtained in accordance with Regulatory
- Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, meets the laboratory testing criteria of Regulatory Position C.6.a of Regulatory Guide 1.52, Revision 2, March 1978, for a methyl iodide penetration of less than (**)%; and m
- 3. Verifying a subsystem flow rate of 30,000 cfm i 10% for each
. FRVS recirculation unit and 9,000 cfm for each FRVS ventilatio,n unit during system operation when tested in accordance with ANSI N510-1975.
- c. After every 720 hours of charcoal adsorber operation by verifying within 31 days after remcval that a laboratory analysis of a repre-sentative carbon sample obtained in accordance with Regulatory Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, meets the laboratory testing criteria of Regulatory Position ~ C.6.a of Regulatory Guide 1.52, Revision 2, March 1978, for a methyl iodide penetration of less than (**)%.
4
- d. At least once per 18 months by:
- 1. Verifying that the pressure drop across the combined HEPA filters and charcoal adsorber banks is less than (8) inches Water Gauge in the recirculation filter train and less than, 5 inches Water Gauge in the ventilation unit while operating the filter train at a flow rate of 30,000 cfm i 10% for each FRVS recirculation unit and 9,000 cfm i 10% for each FRVS ventilation unit.
. 2. Verifying that the filter train starts and isolation dampers open on each of the following test signals: i
- a. Manual initiation from the control room, and
- b. Simulated automatic initiation signal.
, HOPE CREEK 3/4 6-47
CONTAINMENT SYSTEMS JUN 2 B 1985 SURVEILLANCE REQUIREMENTS (Continued)
- 3. Verifying that the heaters dissipate 100 1 5 kw for.each recirculation unit and 32 1 3 kw for each ventilation unit whu. tested in accordance with ANSI N510-1975. Also, verifing humidity control instruments operate to maintain less than or equel to 70% relative humidity.
- e. After eac; complete or partial replacement of a HEPA filter bank by verifying that the HEPA filter bank satisfies the inplace penetration and leakage testing acceptance criteria of less than (*)% in accordance with ANSI N510-1975 while operating the system at a flow rate of 30,000 cfm i 10% for each FRVS recirculation unit and 9,000 cfm 10%
for each FRVS ventilation unit.
- f. After each complete or partial replacement of a charcoal adsorber bank by verifying that the charcoal adsorber bank satisfies the inplace penetration and leakage testing acceptance criteria of less than (*)%
in accordance with ANSI N510-1975 for a hologenated hydrocarbon refrigerant test gas while operating the system at a flow rate of 30,000 cfm i 10% for each FRVS recirculation unit and 9,000 cfm 10% for each FRVS ventilation unit. l l l l t HOPE CREEK 3/4 6-48 l l [
CONTAINMENT SYSTEMS 3/4.6.6 PRIMARY CONTAINMENT ATMOSPHERE CONTROL DRYWELL AND SUPPRESSION CHAMBER HYOR0 GEN RECOMBINER SYSTEMS LIMITING CONDITION FOR OPERATION 3.6.6.1 Two independent drywell and suppression chamber hydrogen recombiner systems shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. ACTION: With one drywell and/or suppression chamber hydrogen recombiner system inoperable, restore the inoperable system to OPERABLE status within 30 days or be in at least HOT SHUTDOWN within the next 12 hours. SURVEILLANCE REQUIREMENTS _ 4.6.6.1 Each drywell and suppression chamber hydrogen recombiner system shall be demonstrated OPERABLE: a. At least once per 6' months by verifying during a recombiner system functional test that the minimum (heater sheath) temperature increases to greater than or equal to 1150*F within 120 minutes. Maintain > 1150*F for at least 2 hours.
- b. At least once per 18 months by:
- 1. Performing a CHANNEL CALIBRATION of all recombiner instrumenta-tion and control circuits.
- 2. Verifying the integrity of all heater electrical circuits by performing a resistance to ground test within 30 minutes follow-ing the above required functional test. The resistance to ground for any heater phase shall be greater than or equal to one megaohm.
- 3. Verifying through a visual examination that there is no evidence of abnormal conditions within the recombiner enclosure; i.e, loose wiring or structural connections, deposits of foreign materials, etc.
- c. By measuring the system leakage rate as a part of the overall inte-grated leakage rate test required by Specification 3.6.1.2.
=
HOPE CREEK 3/4 6-49
CONTAINMENT SYSTEMS ORYWELL AND SUPPRESSION CHAMBER OXYGEN CONCENTRATION LIMITING CONDITION FOR OPERATION 3.6.6.4 The drywell and suppression chamber atmosphere oxygen concentratinn shall be less than 4% by volume. APPLICABILITY: OPERATIONAL CONDITION 1*, during the time period:
- a. Within 24 hours after THERMAL POWER is greater than 15% of RATED THERMAL POWER, following startup, to
- b. Within 24 hours prior to reducing THERMAL POWER to less than 15% of RATED THERMAL POWER, preliminary to a scheduled reactor shutdown, s
ACTION: With the drywell and/or suppression chamber oxygen concentration exceeding the limit, restore the oxygen concentration to within the limit -s within 24 hours or be in at least STARTUP within the next 8 hours. SURVEILLANCE REQUIREMENTS 4.6.6.4 The drywell and suppression chamber oxygen concentration shall be verified to be within the limit within 24 hours after THERMAL POWER is greater than 15% of RATED THERMAL POWER and at least once per 7 days thereafter. i 5 ( , "See Special Test Exception 3.10.5. i e HOPE CREEK 3/4 6-50 l
3/4.7 PLANT SYSTEMS 3/4.7.1 SERVICE WATER SYSTEMS 8 1985 SAFETY AUXILIARY COOLING SYSTEM LIMITING CONDITION FOR OPERATION 3.7.1.1 At least the following independent safety auxiliary cooling water system (SACS) sub ystems. With each subsystem comprised of:
- a. Two OPERABLE SACS pumps, and
- b. An OPERABLE flow path capable of transferring water through the asso-ciated systems and components heat exchanger (s) that are required to be OPERABLE.
shall be OPERABLE:
- a. In OPERATIONAL CONDITION 1, 2 and 3, two subrystems.
- b. In OPERATIONAL CONDITION 4, 5, and ** the ,ubsystems associated with systems and components required OPERABLE ty Specification 3.4.9.1, 3.4.9.2, 3.5.2, 3.8.1.2, 3.9.11.1 and 3.9.11.2.
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3, 4, 5, and **. ACTION:
- a. In OPERATIONAL CONDITION 1, 2, or 3:
- 1. With one SACS pump or heat exchanger inoperable, restore the inoperable pump or heat exchanger to OPERABLE status within 72 hours or be in at least HOT SHUT 00WN within the next 12 hours and in COLD SHUT 00WN within the following 24 hours.
- 2. With two SACS pumps or heat exchangers in different flow paths inoperable, immediately initiate measures to place plant in at least HOT SHUT 00WN within the next 12 hours and in COLD SHUT 00WN*
within the following 24 hours,
- b. In OPERATIONAL CONDITION 3 or 4 with the SACS subsystem, which is associated with an RHR loop required OPERABLE by Specification 3.4.9.1 or 3.4.9.2, inoperable, declare the associated RHR loop inoperable and take the ACTION required by Specification 3.4.9.1 or 3.4.9.2, as applicable.
"Whenever both SACS subsystems are inoperable, if unable to attain COLD SHUTDOWN as required by this ACTION, maintain reactor coolant temperature as low as practical by use of alternate heat removal methods. **When handling irradiated fuel in the secondary containment.
HOPE CREEK 3/4 7-1
PLANT SYSTEMS s LIMITING CONDITION FOR OPERATION (Continued) M 2 8 1985 ACTION: (Continued) c. In OPERATIONAL CONDITION 4 or 5 with the RHRSW subsystem, which is associated with safe +.y rel= tad aquip.r:.7t requ;rsd CPERA~LE oy 5peci-fication 3.5.2, inoperable, declare the associated safety related equipment inoperable and take +he ACTION required by Specificacion 3.5.2.
- d. In OPERATIONAL CONDITION 5 with the SACS subsystem, which is associated with an RHR loop required OPERABLE by Specification 3.9.11.1 or 3.9.11.2, inoperable, declare the associated RHR system inoperable and take the ACTION required by Specification 3.9.11.1 or 3.9.11.2, as applicable.
SURVEILLANCE REQUIREMENTS 4.7.1.1 At least the above required safety auxiliaries cooling system subsystems shall be demonstrated OPERABLE: a. At least once per 31 days by verifying that each valve in the flow path in itsthat is not correct locked, sealed or otherwise secured in position, is position, b. At least once per 18 months during shutdown by verifying that each automatic valve servicing safety-related equipment actuates to its correcc position on a test signal. l l l l HOPE CREEK 3/4 7-2
PLANT SYSTEMS i i STATION SERVICE WATER SYSTEM JUN 2 8 1983 LIMITING CONDITION FOR OPERATION 3.7.1.2 At least the following independent station service water system loops, with each 1000 comorised of:
- a. Two OPERABLE station service water pumps, and b.
An OPERABLE flow path capable of taking suction from the Delaware River and transferring the water to the SACS heat exchangers, shall be OPERABLE:
- a. In OPERATIONAL CONDITION 1, 2 and 3, two loops.
- b. In OPERATIONAL CONDITION 4, 5 and *, one loop.
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3, 4, 5 and *. ACTION:
- a. In OPERATIONAL CONDITION 1, 2, or 3:
- 1. With one station service water pump inoperable, restore the inoperable pump to OPERABLE status within (30) days or be in a least HOT within SHUTOOWN the following within the next 12 hours and in COLD SHUTDOWN 24 hours.
2. With one station service water pump in each loop inoperable, restore at least one inoperable pump to OPERABLE status within 72 hours i or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours. 3. With one station service water system loop inoperable, immedi-ately initiate measures to place plant in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours. b. With only one station service water pump and its associated flowpath OPERABLE, restore at least two pumps with at least one flow path to OPERABLE status within 72 hours or:
- 1. In OPERATIONAL CONDITION 4 or 5, declare the associated SACS subsystem inoperable and take the ACTION required by Speci fication 3. 7.1.1.
- 2. In Operational Condition *, declare the associated SACS subsystem inoperable and take the ACTION required by ,
Specification 3.7.1.1. The provisions of Specification 3.0.3 are not applicable.
"When nanaling irradiated fuel in the secondary containment.
HOPE CREEK 3/4 7-3
PLANT SYSTEMS [?'
].
E8 1985 SURVEILLANCE REQUIREMENTS 4.7.1.2 At least the above required station service water system loops shall be demonstrated OPERABLE: a. At least once per 31 days by verifying that each valve, manual, power operated or automatic, serv':ing safety related equipment enat *.; not locked, sealed or otherwise secured in position, is in its correct position. b. At least once per 18 months during shutdown, by verifying that: 1. Each automatic valve servicing non-safety related equipment actuates to its isolation position on an isolation test signal. I 2. Each pump starts automatically to maintain service water pressure greater than or equal to (60) psig. A HOPE CREEK 3/4 7-4
PLANT SYSTEMS ULTIMATE HEAT SINK LIMITING CONDITION FOR OPERATION 3.7.1.3 The (ultimate heat sink) shall be OPERABLE with: a. A minimum river water level at or above elevation ( ) Mean Sea Level, USGS datum, and
- b. An average river water temperature of less than or equal to (90.5)*F.
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3, 4, 5 and *. ACTION: With the requirements of the above specification not satisfied:
- a. In OPERATIONAL CONDITIONS 1, 2 or 3, be in at least HOT SHUTDOWN within 12 hours and in COLD SHUTOOWN within the next 24 hours.
- b. In OPERATIONAL CONDITIONS 4 or 5, declare the SACS system and the station service water system inoperable and take the ACTION required by Specification 3.7.1.1 and 3.7.1.2.
- c. In Operational Condition *, declare the plant service water system inoperable and take the ACTION required by Specification 3.7.1.2.
The provisions of Specification 3.0.3 are not apnlicable. SURVEILLANCE REQUIREMENTS 4.7.1.3 The ultimate heat sink shall be determined OPERABLE at least once per 24 hours by verifying the average river water temperature and water level to be within their limits.
"When handling irradiated fuel in the secondary containment.
4 HOPE CREEK 3/4 7-5
i PLANT SYSTEMS 3/4.7.2 CONTROL ROOM EMERGENCY FILTRATION SYSTEM
#f 1963 r LIMITING CONDITION FOR OPERATION 3.7.2 Two independent control room emergency filtration system subsystems shall be OPERABLE. <
APPLICABILITY: All OPERATIONAL CONDITIONS and *. ACTION:
- a. In OPERATIONAL CONDITION 1, 2 or 3 with one control room emergency filtration subsystem inoperable, restore the inoperable subsystem to OPERABLE status within 7 days or be in at least HOT SHUTOOWN within the next 12 hours and in COLD SHUT 00WN within the following 24 hours. ;
s
- b. In OPERATIONAL CONDITION 4, 5 or *:
- 1. With one control room emergency filtration subsystem inoperable, l restore the inoperable subsystem to OPERABLE status within 7 days or initiate and maintain operation of the OPERABLE 3 subsystem in the (isolation) mode of operation.
- 2. With both control room emergency filtration subsystems inoperable, suspend CORE ALTERATIONS, handling of irradiated fuel in the secondary containment and operations with a potential for draining the reactor vessel,
- c. The provisions of Specification 3.0.3 are not applicable in Operational Condition *.
SURVEILLANCE REQUIREMENTS 4.7.2 Each control room emergency filtration subsystem shall be demonstrated OPERABLE:
- a. At least once per 12 hours by verifying that the control room air temperature is less than or equal to 85'F.
- b. At least once per 31 days on a STAGGERED TEST BASIS by initiating, from the control room, flow through the HEPA filters and charcoal adsorbers and verifying that the subsystem operates for at least i 10 hours with the heaters OPERABLE.
i
*When irraciated fuel is being handled in the secondary containment.
HOPE CREEK 3/4 7-6 w=te--e-, - - ,
,,w,, - - - .ww-w.y-ym.w_. -,-,-,,y*,ym-.--,y- ,,ww.,,-... --_m,- . - .- . - . - . .-,,-,--.,.mc. -a, ep----,--p-.
PLANT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) D
- c. At least once per 18 months or (1) after ar.y structural maintenance on the HEPA filter or charcoal adsorber housings, or (2) following painting, fire or chemical release in any ventilation zone communicating with the seMyste M"
- 1. Verifying that the subsystem satisfias the in place penetration and bypass leakage in testing acceptance criteria of less than 0.05% and uses the test procedure guidance in Regulatory Positions C.5.a, C.S.c and C.S.d of Regulatory Guide 1.52, Revision 2, March 1978, and the system flow rate is 4000 cfm i 10%.
2. Verifying within 31 days after removal that a laboratory analysis of a representative carbon sample obtained in accordance with Regulatory Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, meets the laboratory testing criteria of Regulatory Position C.6.a of Regulatory Guide 1.52, Revision 2, March 1978, for a methyl iodide penetration of less than 0.175%; and
- 3. Verifying a subsystem flow rate of 4000 cfm i 10% during subsystem operation when tested in accordance with ANSI N510-1975.
d. After every 720 hours of charcoal adsorcer operation by verifying within 31 days after removal that a laboratory analysis of a repre-sentative carbon sample obtained in accordance with Regulatory Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, meets the laboratory testing criteria of Regulatory Position C.6.a of Regulatory Guide 1.52, Revision 2, March 1978, for a methyl iodide penetration of less than 0.175%.
- e. At least once per 18 months by:
- 1. Verifying that the pressure drop across the combined HEPA filters and charcoal adsorber banks is less than 7.5 inches Water Gauge while operating the subsystem at a flow rate of 4000 cfm i 10%.
- 2. Verifying that on each of the below isolation mode actuation test signals, the subsystem automatically switches to the isolation mode of operation and the isolation dampers close within 5 seconds:
I a) (Chlorine detection), and b) (Ammonia detection), 4 i HOPE CREEK 3/4 7-7
I 3 PLANT SYSTEMS N 2 8 1.ong SURVEILLANCE REQUIREMENTS (Continued)
- 3. Verifying that on each of the below pressurization mode actntion test sig;u'.:,, ;.he suosystem automatically switches to the pressurization mode of operation and the control room is maintained at a positise pressure of 1/8 inch W.G. relative to the outside atmosphere during subsystem operation at a flow rate less than or equal to 4000 cfm:
a) Smoke detection and b) Air intake radiation monitors.
- 4. Verifying that the heaters dissipate 1311.3 Kw when tested in accordance with ANSI N510-1975.
f. After each complete or partial replacement of a HEPA filter bank by verifying that the HEPA filter bank satisfies the inplace penetration and bypass leakage testing acceptance criteria of less than (*)% in accordance with ANSI N510-1975 while operating the system at a flow rate of 4000 cfm 2 10%.
- g. After each complete or partial replacement of a charcoal adsorber bank by verifying that the charcoal adsorber bank satisfies the _inplace pene-tration and bypass leakage testing acceptance criteria of less than 0.05%
in accordance with ANSI N510-1975 for a halogenated hydrocarbon refrigerant test gas while operating the system at a flow rate of 4000 cfm i 10%. HOPE CREEK 3/4 7-8
PLANT SYSTEMS [ 3/4.7.3 FLOOD PROTECTION (OPTIONAL *) JUN 2 8 toes LIMITING CONDITION FOR OPERATION 3.7.3 Flood protection shall be provided for all safety related systems, components ano structures when the water level of the Delaware River exceeds 10.5 feet Mean Sea Level USGS datum at the Service Water Intake Structure. APPLICABILITY: At all times. ACTION: With the water level at the service water intake structure above elevation 10.5 feet Mean Sea Level USGS datum: a. Be in at least HOT SHUTDOWN'within the next 12 hours and in COLD SHUTDOWN within the following 24 hours, and b. Initiate and complete within 2 hours the closing of all water tight perimeter flood doors identified in Table 3.7.3-1. SURVEILLANCE REQUIREMENTS 4.7.3 The mined water to be level within theatlimit theby: service water intake structure shall be deter-
- a. Measurement at least once per 24 hours when the water level is below elevation ( ) Mean Sea Level USGS datum, and b.
Measurement at least once per 2 hours when the water level is equal to or above elevation 8.5 Mean Sea Level USGS datum. HOPE CREEK 3/4 7-9
TABLE 3.7.3-1 I PERIMETER FLOOD DOORS J(l% 2 8 gg INTAKE STRUCTURE DOORS Water tight door 1 Water tight door 2 Water tight door 3 Water tight door 4 Water cight door 5 Water tight door 6 Water tight door 7 Water tight door 8 POWER BLOCK DOORS and HATCH Doors & Hatch Location Hatch Exterior 45; K S-13 45.5; L 33408 44; M 33378 44; Md 6312 45.4; T 63238 45.4; U 5315A 29.9; X 5315C 29; X 4323A 13.6; U 4304 13.6; U 01A 13,6; Md 058 13.6; L 33158 Interior-102' 25; H 3329A 27; H 33318 35; H 3209A Interior 26; H 4 i i HOPE CREEK 3/4 7-10 L
ad PLANT SYSTEMS J[lN 2 8 g 3/4.7.4 REACTOR CORE ISOLATION COOLING SYSTEM LIMITING CONDITION FOR OPERATION 3.7.4 The reactor core isolation cooling (RCIC) system shall be OPERABLE with ar CaraAaLE 'h path capable o' at:te:.:_ tis::.11y taking suction from the suppression pool and transferring the water to the reactor pressure vessel. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, and 3 with reactor steam dome pressure greater than 150 psig. ACTION: With the RCIC system inoperable, operation may continue provided the HPCI system is OPERABLE; restore the RCIC system to OPERABLE status within 14 days or be in at least HOT SHUTDOWN within the next 12 hours and reduce reactor steam dome pressure to less than or equal to 150 psig within the following 24 hours. SURVEILLANCE REQUIREMENTS 4.7.4 The RCIC system shall be demonstrated OPERABLE:
- a. At least once per 31 days by:
- 1. Verifying by venting at the high point vents that the system piping from the pump discharge valve to the system isolation valve is filled with water.
- 2. Verifying that each valve, manual, power operated or automatic in the flow path that is not locked, sealed or otherwise secured in position, is in its correct position.
- 3. Verifying that the pump flow controller is in the correct position,
- b. When tested pursuant to Specification 4.0.5 by verifying that the RCIC pump develops a flow of greater than or equal to 600 gpm in the test flow path with a system head corresponding to reactor vessel operating pressure when steam is being supplied to the turbine at 1000 + 20, - 80 psig.*
"The provisions of Specification 4.0.4 are not applicable provided the surveillance is performed within 12 hours after reactor steam pressure is adequate to perform the test.
J HOPE CREEK 3/4 7-11
PLANT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) 8 $00
- c. At least once per 18 months by:
- 1. Performing a system functional test which includes simulated automatic art'.*ation and r3 start and verifying that each automatic valve in the flow path actuates to its :orrect position. Actual injection of coolant into the reactor vessel may be excluded.
- 2. Verifying that the system will develop a flow of greater than or equal to 600 gpm in the test flow path when steam is supplied to the turbine at a pressure of 150 + 15 - 10 psig.*
- 3. Verifying that the suction for the RCIC system is automatically transferred from the condensate storage tank to the suppression pool on a condensate storage tank water level-low signal.
"The provisions of Specification 4.0.4 are not applicable provided the "
surveillance is performed within 12 hours after reactor steam pressure is
- adequate to perform the tests. -
I HOPE CREEK 3/4 7-12
PLANT SYSTEMS j 3/4.7.5' SNUBBERS JUN 2 8 1085 LIMITING CONDITION FOR OPERATION 3.7.5 All snubbers shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1,2, and 3. OPERATIONAL CONDITIONS 4
...d 5 fcr snubbers located on systems required OPERABLE in those OPERATIONAL CONDITICNS.
ACTION: With one or more snubbers inoperable, within 72 hours replace or restore the inoperable snubber (s) to OPERABLE status and perform an engineering evaluation per Specification 4.7.5.g on the attached component or declare the attached system inoperable and follow the appropriate ACTION statement for that system. SURVEILLANCE REQUIREMENTS 4.7.5 Each snubber shall be demonstrated OPERABLE by performance of the following augmented inservice inspection program and the requirements of Specification 4.0.5.
- a. Inspection Types ,
As used in this specification, type of snubber shall mean snubbers of the same design and manufacturer, irrespective of capacity.
- b. Visual Inspections Snubbers are categorized as inaccessible or accessible during reactor operation. Each of these groups (inaccessible and accessible) may be inspected independently according to the schedule below. 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. If all snubbers of each type are found OPERABLE during the first inservice visual inspection, the second inservice visual inspection shall be performed at the first refueling outage. Otherwise, subsequent visual inspections shall be performed in accordance with the following schedule:
HOPE CREEK 3/4 7-13
PLANT SYSTEMS bdF JUN 2 8 1925 SURVEILLANC2 REQUIREMENTS (Continued) No. Inoperable Snubbers of Each Type per Subsequent Visual Inspection Period Inspection Period *# 0 10 s nths i 2S% 1 2 12 months 25% 2 montrs 1 25% 3,4 124 days 1 25% 5,6,7 62 days i 25% 8 or more 31 days i 25%
- c. Visual Inspection Acceotance Criteria Visual inspections shall verify (1) that there are no visible indications of damage or impaired 0FERABILITY, (2) attachments to the foundation or supporting structure are secure, and (3) fasteners for attachment of the snubber to the component and to the snubber anchorage are secure. Snubbers which appear inoperable as a result of visual inspections may be determined OPERABLE for the purpose of establishing the next visual inspection interval, providing that:
(1) the cause of the rejection is clearly established and remedied for that particular snubber and for other snubbers irrespective of type on that system that may be generically susceptible; and/or (2) the affected snubber is functionally tested in the as found condition and determined OPERABLE per Specifications 4.7.4.f. For those snubbers common to more than one system, the OPERABILITY of such snubbers shall be considered in assessing the surveillance schedule for each of the related systems.
- d. Transient Event Insoection An inspection shall be performed of all snubbers attached to sections of systems that have experienced unexpected, potentially damaging transients, as determined from a review of operational data or a visual inspection of the systems, within 72 hours for accessible systems and 6 months for inaccessible systems following this deter-mination. In addition to satisfying the visual inspection accectance criteria, freedom-of-motion of mechanical snubbers shall be verified using at least one of the following: (1) manually induced snutber movement; or (2) evaluation of in place snubber piston setting; or (3) stroking the mechanical snubber through its full range of travel.
*The inspection interval for each type of snubber shall not be lengthered more than one step at a time unless a generic problem has been identified and corrected; in that event the inspection interval may be lengthened one step the first time and two steps thereafter if no inoperable snubbers of that type are found. . #The provisions of Specification 4.0.2 are not applicable.
HOPE CREEK 3/4 7-14
PLANT SYSTEMS M SURVEILLANCE REQUIREMENTS (Continued)
- e. Functional Tests During the first refueling shutdown and at least once per 18 months '
thereafter during shutdown, a representative sample of snubbers shall be tested using one of the following sample plant for each Wa e' Or.ubbe r. The haarple plan shall be selected prior to the test period and cannot be changed during the test period. The NRC Regional Admir istrator shall be notified in writing of the sample plan selected prior to the test period or the sample plan used in the prior test period shall be implemented:
- 1) At least 10% of the total of each type of snubber shall be functionally tested either in place or in a bench test. For each snubber of a type that does not meet the functional test acceptance criteria of Specification 4.7.4.f., an additional 10% of that type of snubber shall be functionally tested until no more failures are found or until all snubbers of that type have been functionally tested; or
- 2) A representative sample of each type of snubber shall be '
functionally tested in accordance with Figure 4.7.4-1. "C" is the total number of snubbers of a type found not meeting the acceptance requirements of Specification 4.7.4.f. The cumulative number of snubbers of a type tested is denoted by "N". At the end of each day's testing, the new values of "N" and "C" (previous day's total plus current day's increments) shall be plotted on Figure 4.7.4-1. If at any time the point plotted falls on or above the " Reject" line all snubbers of that type shall be functionally tested. If at any time the point plotted falls on or below the
" Accept" line, testing of snubbers of that type may be terminated.
When the point plotted lies in the " Continue Testing" region, additional snubbers of that type shall be tested until the point falls in the " Accept" region or the " Reject" region, or all the snubbers of that type have been tested. Testing equipment failure during functional testing may invalicate that day's testing and allow that day's testing to resume anew at a late
- time, providing all snubbers tested with the failed equipment during the day of equipment failure are retested; or
- 3) An initial representative sample of 55 snubbers of each type shall be functionally tested. For each snubber type which does not meet the functional test acceptance criteria, another sample of at least one-half the size of the initial sample shall be tested until the total number tested is equal to the initial sample size multiplied by the factor, 1 + C/2, where "C" is the number of snubbers found which do not meet the functional test acceptanca criteria. The
' results from this sample plan shall be plotted using an " Accept" line which follows the equation N = 55(1 + C/2). Each snubber point should be plotted as soon as the snubber is tested. If the point plotted falls on or below the "A: cept" line, testing of that type of snubber may be terminated. If the point plotted falls L above the " Accept" line, testing must continue until the point falls on or below the " Accept" line or all the snuboers of that type have been tested. ' , HOPE CREEK 3/4 7-15
PLANT SYSTEMS .6 i .. i SultVEILLANCE REQUIREMENTS (Continued) 8 I98I The representative sample selected for the function test sample I plans shall be randomly selected from the snubbers of each type and reviewed before beginning the testing. The review shall ensure as far as practical th e ther :rc repre::ntM.L.. of the w ious configu-rations, operating snutbers of each type. environments, range of size, and capacity of ; Snubbers placed in Ute sarc locations as l snubbers which failed the previous functional test shall be ratested . at the time of the next functional test but shall not be included in the sample plan, and failure of this functional test shall not be the l sole cause for increasing the sample size under the sample plan. If during the functional testing, additional sampling is required due to ' failure of only one type of snubber, the functional testing results
- shall be reviewed at the time to determine if additional samples '
i should be limited to the type of snubber which has failed the functional testing.
- f. Functional Test Acceptance Criteria The snubber functional test shall verify that:
4
- 1) Activation (restraining action) is achieved within the specified 1
range in both tension and compression; i { 2) Snubber bleed, or release rate where required, is present in ' both tension and compression, within the specified range (hydraulle snubbers only);
- 3) For mechanical snubbers, the force required to initiate or main- '
tain motion of the snubber is within the specified range in both directions of travel; and
- 4) For snubbers specifically required not to displace under continuous load, the ability of the snubber to withstand load without displacement.
Testing methods may be used to measure parameters indirectly or parameters other than those specified if those results can be corre-lated to the specified parameters through established methods.
- g. Functional Test Failure Analysis !
4 An engineering evaluation shall be made of each failure to meet the functional test acceptance criteria to determine the cause of the failure. The results of this evaluation shall be used, if applicable, in selecting snubbers to be tested in an effort to determine the OPERABILITY of other snubbers irrespective of type which may be subject to the same failure mode. 1 l
- For the snubbers found inoperable, an engineering evaluation shall be performed on the components to which the inoperable snubbers are attached. The purpose of this engineering evaluation shall be to determine if the components to which the inoper-sble snubbers are 4
attached were adversely affected by the inoperability of the snubbers in oroer toservice. designed ensure that the component remains capable of meeting the . f HOPE CREEK 3/4 7-16
PLANT SYSTEMS
- N 28 1985 SURVEILLANCE REQUIREMENTS (Continued)
Ifanysnubberselectedforfunck)oka5testingeitherfailstolock up or fails to move, i.e., frozen-in-place, the cause will be evaluated and if caused by manufacturer or design deficiency all snubbers of the same type subject to the same defect shall be functionally tasted. This test;.ig r.qairs.t.e..L shall be inovpendent of the requirements stated in Specification 4.7.4.e. for snubbers not meeting the functional test acceptance criteria. ~ ;
- h. Functional Tetting of ' Repaired and Replaced Snubbers !
Snubbers which fail the visual inspection or the~ functional test acceptance criteria shall be repaired or replaced. Rep'lacement snubbers'and snubbers which have repsirs which might affect the functionalstast result shall be tested to meet the functional test criteria before installation in the unit. Mechanical snubbers shall have met the acceptance criteria subsequent to their most recent service, and uie fresdom-of motion test must have been performed within 12 months barare being installed in the unit. /
- i. Snubber Service life Replacement Procram ~
a The service life at all sn6bbers shall be monitored to ensure that the service life is not exceeded between surveillance inspections. The maximum expected service life for various seals, springs, and other critical parts shall be extended or shortened based on mont-tored test results and failure historyr" Critical parts shall be c replaced so that the maximum servico Iffe will not be exceeded - during a period when the snubber is required to be OPERABLE. The - parts repfacements shall be de _Jented and the documentation sball be retained in accordance witi, Specification 6.10.3. 9 s g 3
/
r g A. M l
* , n we v
HOPE CREEK 3/4 7-17 l __---,-r--,.. .a., -- --- -. ~. -
--.m- , - , , , , - _ _ _ - - . . - - , .n--_ , - . - - -.. - - , _ . . , , . , . , , , , . ,
-,-,-,m- -
ul) JWl 2 6 as SAMPLE PLAN 2) FOR SNUBBER FUNCTIONAL TEST Figure 4.7.5-1 HOPE CREEK 3/# ~
PLANT SYSTEMS 3/4.7.6 SEALE0 SOURCE CONTAMINATION O LCS$ LIMITING CONDITION FOR OPERATION 3.7.6 Each sealed source containing radioactive material either in exerss of l'10 microcuries of beta and/or gamma emitting material or 5 microcuries of alpha uitting material shall be free of greater than or equal to 0.005 microcuries of removable contamination. APPLICABILITY: At all times. ACTION:
- a. With a sealed source having removable contamination in excess of the above limit, withdraw the sealed source from use and either:
- 1. Decontaminate and repair the sealed source, or
- 2. Dispose of the sealed source in accordance with Commission Regulations.
- b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.
l SURVEILLANCE REQUIREMENTS 4.7.6.1 Test Requirements - Each sealed source shall be tested for leakage and/or contamination by:
- a. The licensee, or l
- b. Other persons specifically authorized by the Commission or an Agreement State.
The test method shall have a detection sensitivity of at least 0.005 microcuries per test sample. 4.7.6.2 Test Frecuencies - Each category of sealed sources, excluding startup sources and fission detectors previously subjected to core flux, shall be tested at the frequency described below.
- a. Sources in use - At least once per six months for all sealed sources containing racioactive material:
- 1. With a half-life greater than 30 days, excluding Hydrogen 3, and
- 2. In any form other than gas.
HOPE CREEK 3/4 7-19
l PLANT SYSTEMS JUN 2 81985 i SURVEILLANCE REQUIREMENTS,,(Cylntinued)
- b. Stored sources not in use - Each sealed source and fission detector thC1 ';e te:ted prior to usa or ;..ansier to anut.hu licensee unies.
tested within the previous six months. Sealed sources and fission detectc : transferred without a certii;eate indicating the last test date shall be tested prior to being placed in:o use.
- c. Startup sources and fission detectors - Each sealed startup source and fission detector shall be tested within 31 days prior to being subjected to core flux or installed in the core and following repair or maintenance to the source.
4.7.6.3 Reoorts - A report shall be prepared and submitted to the Commission on an annual basis if sealed source or fission detector leakage tests reveal the presence of greater than or equal to 0.005 microcuries of removable contamination. HOPE CREEK 3/4 7-20
PLANT SYSTEMS ORAFl 3/4.7.7 FIRE SUPPRESSION SYSTEMS 8 1985 FIRE SUPPRESSION WATER SYSTEM LIMITING CONDITION FOR OPERATION 3.7.7.1 The fire suppression water system shall be OPERABLE with:
- a. Two OPERABLE fire suppression pumps, one electric motor driven and one diesel engine driven, each with a capacity of 2500 gpm, with their discharge aligned to the fire suppression header,
- b. Separate fire water supplies, each with a minimum contained volume of 328,000 gallons, and
- c. An OPERABLE flow path capable of taking suction from either fire water storage tank and transferring the water through distribution piping with OPERABLE sectionalizing control or isolation valves to the yard hydrant curb valves, the last valve ahead of the water flow alarm device on each sprinkler or hose standpipe and the last valve ahead of the deluge valve on each deluge or spray system required to be OPERABLE per Specifications 3.7.7.2, 3.7.7.5, and 3.7.7.6.
APPLICABILITY: At all times. ACTION:
- a. With one pump and/or one water supply inoperable, restore the inoperable equipment to OPERABLE status within 7 days or provide an alternate backup pump or supply. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.
- b. With the fire suppression water system otherwise inoperable, establish a backup fire suppression water system within 24 hours.
SURVEILLANCE REQUIREMENTS 4.7.7.1.1 The fire suppression water system shall be demonstrated OPERABLE:
- a. At least once per 7 days by verifying the minimum contained water supply volume.
(b. At least once per 31 days (on a STAGGERED TEST BASIS) by starting (each) (the) electric motor driven fire suppression pump and operating it for at least 15 minutes on recirculation flow.)
- c. At least once per 31 days by verifying that each valve, manual, power '
operated or automatic, in the flow path is in its correct position. HOPE CREEK 3/4 7-21
PLANT SYSTEMS ORMT UUl28 y SURVEILLANCE REQUIREMENTS (Continued)
- d. At least once per 12 months by performance of a system flush.
- e. At least once per 12 months by cycling each testable valve in the flow nath through at least one comp; ate cy-la of full travel.
f. At least once per 18 months by performing a system functional test which includes simulated automatic actuation of the system througnout its operating sequence, and:
- 1. Verifying that each automatic valve in the flow path actuates to its correct position,
- 2. Verifying that each fire suppression pump develops at least 2500 gpm at a system head of 288 feet, 3.
Cycling each valve in the flow path that is not testable during plant and operation through at least one complete cycle of full travel, 4. Verifying that each fire suppression pump starts sequentially to maintain the fire suppression water system pressure greater' than or equal to 100 psig.
- g. At least once per 3 years by performing a flow test of the system in accordance with Chapter 5, Section 11 of the Fire Protection Handbook, 14th Edition, published by the National Fire Protection Association.
4.7.7.1.2 The diesel driven fire suppression pump shall be demonstrated OPERABLE:
- a. At least once per 31 days by:
- 1. Verifying the fuel day tank contains at least ( ) gallons of fuel.
- 2. Starting the diesel driven pump from ambient conditions and operating for greater than or equal to 30 minutes on recirculaticn flow.
- b. At least once per 52 days by verifying that a sample of diesel fuel from the fuel storage tank, obtained in accordance with ASTM-D270-75, is within the acceptable limits specified in Table 1 of ASTM 0975-77 when checked for viscosity, water and sediment.
- c. At least etce per 18 months by subjecting the diesel to an inspection in accordance with procedures prepared in conjunction with its manufacturer's recommendations for the class of service.
HOPE CREEK 3/4 7-22
D PLANT SYSTEMS
$ah,t.
JUN 2 8 gggg SURVEILLANCE REQUIREMENTS (Continued) 4.7.7.1.3 The diesel driven fire pump starting 24-volt battery bank and charger sb=11 ba des;nstrcted OPEkABLE.
- a. At least once per 7 days by verifying that:
1. The electrolyte level of each pilot cell is above the plates, 2. The pilot cell specific gravity, corrected to 77*F and full electrolyte level, is greater than or equal to 1.200, and 3. The overall battery voltage is greater than or equal to 24 volts. b. At least once per 92 days by verifying that the specific gravity is appropriate for continued service of the battery.
- c. At least once per 18 months by verifying that:
- 1. The batteries, cell plates and battery racks show no visual i
indication of physical damage or abnormal deterioration, and 2. Battery-to-battery and terminal connections are clean, tight, free of corrosion and coated with anti-corrosion material. HOPE CREEK 3/4 7-23 L m-
m-
+
4: PLANT SYSTEMS SPRAY AND/OR SPRINKLER SYSTEMS M 2 8 10 % LIMITING CONDITION FOR OPERATION 3.7.7.2 The following spray and sprinkler systems shall be OPERABLE: SYSTEM HAZARD AREA ELEVATION NO. Reactor Building Motor Control Center Area 4201 77' IPS15 Corridor 4301 - 102' IPS16 FRVS* Recirc. Charcoal Filter 132' 1P03 FRVS Recirc. Charcoal Filter 132' IPD4 FRVS Vent Unit Charcoal Filter 145' 1PDS FRVS Vent Unit Charcoal Filter 145' IP06 FRVS Recirc. Charcoal Filter 162' IPD7 FRVS Recirc. Charcoal Filter 162' 1PD8 FRVS Recire. Charcoal Filter 178'6" 1PD10 FRVS Recire. Charcoal Filter 178'6" 1PD11 Auxiliary Building Control and D/G Areas Cable Spreading Room 77' IPS4 Corridor 5207 77' IPS6
' Corridor 5237 77' IPS7 Electrical Access 5339 102' 1PS8 Control Equipment Mezzanine 117'6" 1D28 Electrical Access 5401 124' IPS9 Cable Chase 5203, 5323, 5331, 5405, 5419, 5531 77', 102', 124', IPS10 130', 137, 150' Cable Chase 5204, 5324, 5332, 5406, 5420, 5532 77', 102', 124', IPS11 130', 137, 150' Cable Chase 5205, 5325, 5333, 5407, 5421, 5533 77', 102', 124', 1P512 130', 137, 150' Cable Chase 5206, 5326, 5334, 5408, 5422, 5534 77', 102', 124', IPS13 130', 137, 150' Emergency Charcoal Filter 153' 101 Emergency Charcoal Filter 153' 1D2 Diesel Tank Room 5107 54' 1D22 Diesel Tank Room 5108 54' 1023 Diesel Tank Room 5109 54' 1024 Diesel Tank Room 5110 54' 1D25 Auxiliary Building Radiwaste and Service Areas Electrical Access Area 3204 77' 1956 Electrical Access Area 3405 134' IPS9 Intake Structure - Service Water Pump Room IPS1 - Service Water Pump Room 1952 HEV Chase 5535 150' 1P514
- Filtration, Recirculation and Ventilation systems HOPE CREEK 3/4 7-24
, PLANT SYSTEMS D4W.2DAPi y 2 ! SES SURVEILLANCE REQUIREMENTS (Continued)
APPLICABILITY: Whenever equipment protected by the spray and/or sprinkler systems is required to be OPERASLE. ACTION:
- a. With one or more of the above requirec' spray and/or sprinkler systems <
4 inoperable, within ene hour establish a continuous fire watch with backup fire 8uppression equipment for those areas in which redundant systems or c aponents could be damaged; for other areas, establish an hourly fire watch patrol.
- b. The provisions of Specification 3.0.3 and 3.0.4 are not applicable.
SURVEILLANCE REQUIREMENTS
~
4.7.7.2 Each of the above required spray and sprinkler systems shall be demonstrated OPERABLE:
- a. At least once per 31 days by verifying that each valve, manual, power operated or automatic, in the flow path is in its correct position.
- b. At least once per 12 months by cycling eacn testable valve in the flow path through at least one complete cycle of full travel.
- c. At least once per 18 months:
- 1. By performing a system functional test which includes simulated automatic actuation of the system, and:
a) Verifyir.g that the automatic valves in the flow path actuate to their correct positions on a test signal, and b) Cycling each valve in the flow path that is not testable during plant operation through at least one complete cycle of full travel. i 2. By a visual inspection of the dry pipe spray and sprinkler headers l to verify their integrity, and
- 3. By a visual inspection of each sprinkler or deluge nozzle's spray area to verify that the spray pattern is not obstructed.
- d. At least once per 3 years by performing an air flow test through each open head spray and sprinkler header and verifying each open head spray and sprinkler nozzle is unobstructed.
( HOPE CREEK 3/4 7-25
PLANT SYSTEMS g2 SYSTEMS JUN 2 8 1985 LIMITING CONDITION FOR OPERATION 3.7.7.3 The following low pressure and high pressure CO OPERABLE: 2 systems shall be Hazard Area Elevation System No. Auxiliary Building Control & D/G Areas
- a. Fuel Tank Rocm 5110
- b. 54' IC1 Fuel Tank Room 5109 54'
- c. Fuel Tank Room 5108 IC2
- d. 54' IC3 Fuel Tank Room 5107 54'
- e. IC4 Diesel Generator Room 5301 102'
- f. Diesel Generator Room 5306 ICS
- g. 102' ICS Diesel Generator Room 5305 102'
- h. IC7 Diesel Generator Room 5304 102'
- i. Control Equip. Room Mezzanine 5447 IC8
- j. 117'-6" IC10 C07 Hose Reel Systems (excluding systems IC12 Tn Radwaste & Service Areas)
APPLICABILITY: 4 Whenever equipment protected by the CO 2 systems is required to be OPERABLE. ACTION: a. With one or more of the above required CO, systems inoperable, within one hour establish a continuous fire watch with backup fire suppression equipment for those areas in which redundant systems or components could be damaged; for other areas, establish an hourly fire watch patrol. b. The provisions of Specification 3.0.3 and 3.0.4 are not applicable. SURVEILLANCE REQUIREMENTS 4.7.7.3.1~ Each of the above required C0 7systems shall be demonstrated OPERABLE at least once per 31 days by verifying that each valve, manual, power operated, or automatic, in the flow path is in its correct position. 4.7.7.3.2 Each of the above required low pressure CO 2 systems shall be
-demonstrated OPERABLE:
a. At least once per 7 days by verifying the CO, storage tank level to be greater than 55% and pressure to be greater than 275 psig, and
- b. At least once per 18 months by verifying: ,
1. The system, including associated ventilation system fire dampers and fire door release mechanisms, actuates, manually and , automatically, upon receipt of a simulated actuation signal, and ,
- 2. Flow from each nozzle during a " Puff Test."
HOPE CREEK 3/4 7-26 4
PLANT SYSTEMS DP#T FIRE HOSE STATIONS JUN 2 8 g LIMITING CONDITION FOR OPcffMION 3.7.7.4 The fire hose stations shown in Tabla 3.7.7.4 1 en-l' *
. OPERABLE.
APPLICABILITY: Whenever equipment in the areas protected by the fire hose stations is required to be OPERABLE. ACTION: a. With one or more of the fire hose stations shown in Table 3.7.7.4-1 inoperable, provided gated wye (s) on the nearest OPERABLE hose station (s). One outlet of the wye shall be connected to the standard length of hose provided at the hose station. The second outlet of the wye shall be connected to a length of hose sufficient to provide coverage.for the area left unprotected by the inoperable hose station. Where it can be demonstrated that the physical routing of the fire hose woulc result in a recognizable hazard to operating technicians, plant equipment, or the hose itself, the fire hose shall be stored in a roll at the outlet of the OPERABLE hose station. Signs shall be mounted above the gated wye (s) to identify the proper hose to use. The above ACTION shall be accomplished within 1 hour if the inoperable fire hose is the primary means of fire suppression; otherwise route the additional hose within 24 hours. b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable. SURVEILLANCE REQUIREMENTS 4.7.7.4 Each of the fire hose stations shown in Table 3.7.7.4-1 shall be demonstrated OPERABLE:
- a. At least once per 31 days by a visual inspection of the fire hose stations accessible during plant operation to assure all required equipment is at the station.
- b. At least once per 18 months by:
- 1. Visual inspection of the fire hose stations not accessible during plant operation to assure all required equipment is at 1
the station.
- 2. Removing the hose for inspection and re-racking, and
- 3. Inspecting all gaskets and replacing any degraded gaskats in the couplings,
- c. At least once per 3 years by:
- 1. Partially opening each hose station valve to verify valve OPERABILITY and no flow blockage.
2. Conducting a hose hydrostatic test at a pressure of 150 psig or at least 50 psig above the maximum fire main operating pressure, whichever is greater. HOPE CREEK 3/4 7-27
7.D 1se
,j T'""
ei PLANT SYSTEMS diuf12 i YARD FIRE HYDRANTS AND HYDRANT HOSE HOUSES JUN 2 8 mag LIMITING CONDITION FOR OPERATION 3.7.7.5 The yard fire hydrants and associated hydrant hose houses shown in Table 3.7.7.E-1 chall bc OPER."2LE. APPLICARILITY: Whenever equipment fr. the acess protected by the yard fire hydrants is required to be OPERABLE. ACTION:
- a. With one or more of the yard fire hydrants or associated hydrant hose houses shown in Table 3.7.7.5-1 inoperable, within 1 hour have sufficient additional lengths of 2 1/2 inch diameter hose located in an adjacent OPERABLE hydrant hose house to provide service to the unprotected area (s) if the inoperable fire hydrant or associated hydrant hose house is the primary means of fire suppression; otherwise provide the additional hose within 24 hours.
- b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable. 3 SURVEILLANCE REQUIREMENTS -
4.7.7.6 Each of the yard fire hydrants and associated hydrant hose houses shown in Table 3.7.7.5-1 shall be demonstrated OPERABLE:
- a. At least once per 31 days by visual inspection _of the hydrant hose house to assure all required equipment is at the hose house.
- b. At least once per 6 months, during March, April or May and during September, October or November, by visually inspecting each yard fire hydrant and verifying that the hydrant barrel is dry and that the hydrant is not damaged.
- c. At least once per 12 months by:
4
- 1. Conducting a hose hydrostatic test at a pressure of 150 psig or at least 50 psig above the maximum fire main operating pressure, whichever is greater.
- 2. Replacement of all degraded gaskets in couplings.
i
- 3. Performing a flow check of each hydrant.
HOPE CREEK 3/4 7-30 I
i
, TABLE 3.7.7.5-1 I d YARD FIRE HYDRANTS AND ASSOCIATED HYDRANT HOSE HOUSES JUN 2 8 1933 LOCATION (*)
HYDRANT NUMBER
~
O e HOPE CREEK 3/4 7-31
PLANTSYSTEM.} 3/4.7.8 FIRE RATED ASSEMBLIES fI JUN 2 E G55 LIMITING CONDITION FOR OPERATION 1 'Q. All fire rated asserutd ies, insulucing walls, floor /cellings, cable tray enclosures and other fire barriers, separating safety related fire areas or sep-ating portio'is of redundant sy= tams i.nportant to safe shutdown within a fire area, and all sealing devices in fire rated assembly penetrations, including fire doors, fire windows, fire dampers, cable, piping and ventilation duct penetration seals and ventilation seals, shall be OPERABLE. APPLICABILITY: At all times. ACTION: a. With one or more of the above required fire rated assemblies and/or sealing devices inoperable, within one hour establish a continuous fire watch on at least one side of the affected assembly (s) and/or sealing device (s) or verify the OPERABILITY of fire detectors on at least one side of the inoperable assembly (s) and sealing device (s) and establish an hourly fire watch patrol. b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable. SURVEILLANCE REOUIREMENTS 4.7.8.1 Each of the above required fire rated assemblies and penetration sealing devices shall be verified OPERABLE at least once per 18 months by performing a visual inspection of:
- a. The exposed surfaces of each fire rated assembly.
- b. Each fire window, fire damper, and associated hardware.
- c. At least 10 percent of each type of sealed penetration. If apparent changes in appearance or abnormal degradations are found, a visual inspection of an additional 10 percent of each type of sealed penetration shall be made. This inspection process shall continue until a 10 percent sample with no apparent changes in appearance or
~
abr.ormal degradation is found. Samples shall be selected such that each penetration seal will be inspected at least once per 15 years. HOPE CREEK 3/4 7-32
s 0;h fi[?
$ PLANT SYSTEMS idit$1) i
$NEl 2 81385 SURVEILLANCE REQUIREMENTS (Continued) 4.7.8.2 Each of the above required fire doors shall be verified npERAE!.E by intpe: ting t a aaton.atic hoid-open, release and closing mechanism and latches at least once per 6 months, and by verifying:
- a. The OPERABILITY of the fire door supervision system for each electrically supervised fire door by performing a CHANNEL FUNCTIONAL TEST at least once per 31 days.
b. That each locked-closed fire door is closed at least once per 7 days.
- c. That doors with automatic hold-open and release mechanisms are free of obstructions at least once per 24 hours and performing a functional test of these mechanisms at least once per 18 months.
- d. That each unlocked fire door without electrical supervision is
, closed fire door at least once per 24 hours.
A HOPE CREEK 3/4 7-33
PLANT SYSTEMS J } 3/4.7.9 AREA TEMPERATURE MONITORING
-JUN 2 6 1985 LIMITING CONDITION FOR OPERATION
~ 3.7.9 The temperature of each area shown in Table 3.7.9-1 snall be maintained
.c thin the limits indicated in iaole 0.7.3-1.
APPLICABILITY: Whenever the equipment in an affected area is required to be OPERABLE. ACTION: With one or more areas exceeding the temperature limit (s) shown in Table 3.7.9-1:
- a. For more than eight hours, in lieu of any report required by Specification 6.9.1, prepare and submit a Special Report to the Commission pursuant to Specification 6.9.2 within the next 30 days providing a record of the amount by which and the cumulative time the temperature in the affected area exceeded its limit and an analysis to demonstrate the continued OPERABILITY of the affected equipment.
- b. By more than 30*F, in addition to the Special Report required above, within 4 hours either restore the area to within its temperature limit or declare the equipment in the affected area inoperable.
SURVEILLANCE REQUIREMENTS
- 4. 7. 9 The temperature in each of the areas shown in Table 3.7.9-1 shall be determined to be within its limit at least once per 12 hours.
HOPE CREEK 3/4 7-34
5 I h-I t-TABLE 3.7.9-1 JUN 2 8 1935 AREA TEMPERATURE MONITORING 4 AREA TEMPERATURE LIMIT ( F) a. b c. d.
- e. .
i 4 h A i r d i 4 l HOPE CREEK 3/4 7-35
PLANT SYSTEMS 3/4.7.10 MAIN TURBINE BYPASS SYSTEM gg 2 8 1985 LIMITING CONDITION FOR OPERATION 3.7.10 The main turbine bypass system shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITION 1. ACTION: With the main turbine bypass system inoperable, restore the system to OPERABLE status within 1 hour or reduce THERMAL POWER to less than or equal to 25% of RATED THERMAL POWER within the next 4 hours. SURVEILLANCE REOUIREMENTS ' 4.7.10 The main turbine bypass system shall be demonstrated OPERABLE at least once per:
- a. 7 days by cycling each turbine bypass valve through at least one complete cycle of full travel, and
- b. 18 months by:
- 1. Performing a system functional test which includes simulated automatic actuation and verifying that each automatic valve actuates to its correct position.
- 2. Demonstrating TURBINE BYPASS SYSTEM RESPONSE TIME meets the following requirements when measured from the initial movement of the main turbine stop or control valve:
a) 80% of turbine bypass system capacity shall be established in less than or equal to 0.3 second. b) Bypass valve opening shall start in less than or equal to 0.1 second. HOPE CREEK 3/4 7-36
3/4.8 ELECTRICAL POWER SYSTEMS 3/4.8.1 A.C. SOURCES N SS5 A.C. SOURCES - OPERATING LIM 101NG CONDITION FOR OPERATION 3.8.1.1 As a minimum, the following A.C. electrical power sources shall be OPERABLE: a. Two physically inQpendent circuits between the offsite transmission network and the onsite Class lE distribution system, and-
- b. Four separate and independent diesel generators, each with:
1. A separate day fuel tank containing a minimum of 200 gallons of fuel, 2. A separati fuel storage system consisting of two storage 3. tanks containing a minimum of 48,800 gallons of fuel, and A separate fuel transfer pump for each storage tank. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, and 3. * . ACTION:
' ~
a. With one diesel generator of the above required A.C. electrical powir sources inoperable, demonstrate the OPERABILITY of the remaining A.C. sources by performing Surveillance Requirements 4.8.1.1.la. and 4.8.1.1.2a.4., for one diesel generator at a time, within 24 hours and at least once per 7 days thereafter; restore the inoperable diesel generator to OPERABLE status within 92 days or be in at least HOT SHUTDOWN following 24 within hours.the next 12 hours and in COLD SHUTDOWN within the b. With two diesel generators of the above required A.C. electrical power sources inoperable, demonstrate the OPERABILITY of the remaining A.C. sources by performing Surveillance Requirements 4.8.1.1.la. and 4.8.1.1.2a.4., for one diesel generator at a time, within 1 hour and at least once per 8 hours thereafter; restore at least one of the inoper-able diesel generators to OPERABLE status within 72 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN i within the following 24 hours.
- c. With three diesel generators of the above required A.C. electrical A
power sources inoperable, demonstrate the OPERABILITY of the remaining A.C. sources by performing Surveillance Requirements 4.8.1.1.la. and 4.8.1.1.2a.4., for one diesel generator at a time, within 1 hour and at least once per 8 hours thereafter; restore at least one of the inop-erable diesel generators to OPERABLE status within 2 hours or be in i at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN ' within the following 24 hours.
- d. With one offsite circuit and one diesel generator of the above required A.C. electrical power sources inoperable, demonstrate the OPERABILITY of the remaining A.C. sources by performing Surveillance Requirements 4.8.1.1.la. and 4.8.1.1.2a.4. within 1 hour and at least once per HOPE CREEK 3/4 8-1
F
$ 1 mi i ELECTRICAL POWER SYSTEMS M28 E65 LIMITING CONDITION FOR CyRATION (C1ntinued)
ACTTON: (Coritinued) 8 hours thereafte . Resters at least two offsite circuits and at least three of the above required diesel generators to OPERABLE status within 72 hours from time of initial loss or be in at least HOT SHUTDOWN following 24 hours,within the next 12 hours and in COLD SHUTDOWN within the e. With two diesel generators of the above required A.C. electrical power sources inoperable, in addition to ACTION b. , above, verify within 2 hours that all required systems, subsystems, trains, components, and devices that depend on the remaining diesel generators as a source of emergency power are also OPERABLE; otherwise, be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours. f. With one offsite circuit of the above required A.C. electrical power sources inoperable, demonstrate the OPERABILITY of the remaining A.C. sources by performing Surveillance Requirements 4.8.1.1.la. and 4.8.1.2a.4, for one diesel generator at a time, within 1 hour and at least once per 8 hours thereafter; restore at least two offsite circuits to OPERABLE status within 72 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN.within the following 24 hours.
- g. With two of the above required offsite circuits inoperable, demonstrate the OPERABILITY of all of the above required diesel generators by performing Surveillance Requirement 4.8.1.1.2a.4., for one diesel generator at a time, within 1 hour and at least once per 8 hours there-after, unless the diesel generators are already operating; restore at least one of the inoperable offsite circuits to OPERABLE status within i
' 24 hours or be in at least HOT SHUTDOWN within the next 12 hours. With only one offsite circuit restored to OPERABLE status, restore at least two offsite circuits to OPERABLE status within 72 hours frcm time of l initial loss or be in at least HOT SHUTDOWN within the next 12 hours l and in COLD SHUTDOWN within the following 24 hours.
- h. With one offsite circuit and two diesel generators of the above required A.C. electrical power sources inoperable, demonstrate the OPERABILITY l
of the remaining A.C. sources by performi_ng Surveillance Requirements 4.8.1.1.la. and 4.8.1.1.2a.4. within 1 hour and at least once per 8 hours thereafter; restore at least one of the above required ! inoperable A.C. sources to OPERABLE status within 12 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN i within the following 24 hours. Restore at least two offsite circuits l and at least three of the above required diesel generators to OPERABLE l status within 72 hours from time of initial loss or be in at ! east HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours. l HOPE CREEK 3/4 8-2
~J1/ij g ELECTRICAL POWER SYSTEMS M 28 to85 SURVEILLANCE REQUIREMENTS
- 4. 8.1.1.1 Eacn of the above required independent circuits between the offsite transmission' network and the onsite Class 1E distribution system shall be:
- a. Determined OPERABLE at least once per 7 days by verifying correct breaker alignments and indicated power availability, and
- b. Demonstrated OPERABLE at least once per 18 months during shutdown by transferring, manually and automatically, unit power supply from the normal circuit to the alternate circuit.
4.8.1.1.2 Each of the above required diesel generators shall be demonstrated OPERABLE:
- a. In accordance with the frequency specified in Table 4.8.1.1.2-1 on a STAGGERED TEST BASIS by:
- 1. Verifying the fuel level in the day fuel tank.
- 2. Verifying the fuel level in the fuel storage tank.
- 3. Verifying the fuel transfer pump starts and transfers fuel from the storage system to the day and engine-mounted fuel tanks.
- 4. Verifying the diesel starts from ambient condition
- and accelerates to at least 514 rpm in less than or equal to 10 seconds. The generator voltage and frequency shall be 4160 420 volts and 60 1 1.2 Hz within 10 seconds after the start signal. The diesel generator shall be started '
for this test by using one of the following signals: a) Manual.** b) Simulated loss of offsite power by itself. c) Simulated loss of offsite power in conjunction with an ESF actuation test signal. d) An ESF actuation test signal by itself.
- 5. Verifying the diesel generator is synchronized, loaded to greater than or equal to 4430 kw in less than or equal to 60 seconds, and operates with this load for at least 60 minutes.
^fhe diesel generator start (10 sec) and subsequent loading (200 sec) from ambient conditions shall be performed at least once per 184 days in these surveillance tests. All other engine starts and loading for the purpose of this surveillance testing may be preceded by an engine prelube period and/or '
other warmup procedures recommended by the manufacturer so that mechanical stress and wear on the diesel engine is minimized.
**If diesel generator started manually from the control room, 10 seconds after the automatic prelube period.
HOPE CREEK 3/4 8-3
r 5 ELECTRICAL F0WER SYSTEMS
$'g
~
JUN 2 8 ;gg5 SURVEILLANCE REQUIREMENTS (Continued) G. Verify 1ng cne diesei generator is aligned to provide standby , power to the associatad emergency busses.
- 7. Verifying the paessure in all diesel generator air start receivers to be greater than or equal to 380 psig.
- 8. Verifying the lube oil pressure, temperature and differential pressure across the lube oil filters to be within manufac-turer's specifications.
- b. At least once per 31 days by visually examining a sample of lube' oil from the diesel engine to verify absence of water and by verifying a minimum of forty 55 gallon drums of lube oil are stored onsite.
- c. At least once per 31 days and after each operation of the diesel where the period of operation was greater than or equal to 1 hour by checking for and removing accumulated water from the day fuel tank.
- d. At least once per 92 days by removing accumulated water from the fuel storage tanks.
- e. At least once per 31 days by performing a functional test on the emergency load sequencer to verify operability.
- f. At least once per 92 days and from new fuel oil prior to addition to the storage tanks by obtaining a sample in accordance with ASTM-0270-1975 and by verifying that the sample meets the following minimum requirements and is tested within the specified time limits:
- 1. As soon as sample is taken or from new fuel prior to addition to the storage tank, as applicable, verify in accordance with the tests specified in ASTM-0975-77 that the sample has:
a) A water and sediment content of less than or equal to 0.05 volume percent. b) A kinematic vixcosity @ 40 C of greater than or equal tc 1.9 centistokes, but less than or equal to 4.1 centistokes. c) A specific gravity as specified by the manufacturer as API gravity @ 60*F of greater than or equal to 28 degrees but less than or~ equal to 42 degrees. ,
- 2. Within one week after obtaining the samole, verify an impurity level of less than 2 mg of insolubles per 100 ml. wnen tested in accordance with ASTM-02274-70.
HOPE CREEK 3/4 8-4
ELECTRICAL POWER SYSTEMS JUN 2 g . rJc3 SURVEILLANCE REOUIREMENTS (Continued) ....
- 3. Within tuc w:0 5 after obt:...i.e eie =ampie, verity tnat tne other properties specified in Table 1 of ASTM-D975-77 and Regulatory Guide 1.137, Position Z.a, are met when tested in accordance with ASTM-0975-77.
- g. At least once per two months by verifying the buried fuel oil trans-fer piping's cathodic protection system is operable and at least once per year by subjecting the cathodic protection system to a performance test.
- h. At least once per 18 months, during shutdown, by:
- 1. Subjecting the diesel to an inspection in accordance with procedures prepared in conjunction with its manufacturer's recommendations for this class of standby service.
- 2. Verifying the diesel generator capability to reject a load of greater than or equal to 991 kW for each diesel generator while maintaining voltage at 4160 420 volts and. frequency at 60 1.2 Hz engine speed < 75% of the difference between nominal speed and the overspeed trip setpoint or 15% above nominal, whichever is less.
- 3. Verifying the diesel generator capability to reject a load of 4430 kW without tripping. The generator voltage shall not exceed 4580 volts during and following the load rejection.
- 4. Simulating a loss of offsite power by itself, and:
a) Verifying deenergization of the emergency busses and load shedding from the emergency busses. b) Verifying the diesel generator starts on the auto-start signal, energizes the emergency busses with permanently connected loads within 10 seconds, energizes the auto-connected shutdown loads through the load sequencer and operates for greater than or equal to 5 minuter while its generator is loaded with the shutdown loads. After energization, the steady state voltage and frequency of the emergency busses shall be maintained at 4160 ! 420 volts and 60 1.2 Hz during this test.
- 5. Verifying that on an ECCS actuation test signal, without loss of offsite power, the diesel generator starts on the auto-start signal and operates on standby for greater than or equal to -
5 minutes. The generator voltage and frequency shall be 4160 420 volts and 60 1.2 Hz within 10 seconds after the auto-start signal; the steady state generator voltage and fre-quency shall be maintained within these limits during this test. HOPE CREEK 3/4 8-5
r ELECTRICAL POWER SYSTEMS 085 SURVEILLANCE REQUIREMENTS (Continued)
- 6. Verit 43 t5at m * :faulated % of 1..a Jiesel generator, with offsite power not available, the loads are shed from the emergency busses and that subsequent loading of the diesel generator is in accordance with design requirements.
- 7. Simulating a loss of offsite power in conjunction with an ECCS actuation test signal, and:
a) Verifying deenergization of the emergency busses and load shedding from the emergency busses. { b) Verifying the diesel generator starts on the auto-start signal, energizes the emergency busses with permanently connected loads within 10 seconds, energizes the auto-connected shutdown loads through the load sequencer and operates for greater than or equal to 5 minutes while its generator is loaded with the emergency loads. After energization, the steady state voltage and frequency of the emergency busses shall be maintained at 4160 420 volts and 60 i 1.2 Hz during this test.
- 8. Verifying that all automatic diesel generator trips, except engine overspeed and generator differential current are automatically bypassed upon loss of voltage on the emergency bus concurrent with an ECCS actuation signal.
- 9. Verifying the diesel generator operates for at least 24 hours.
During the first 2 hours of this test, the diesel generator shall be loaded to greater than or equal to 4873 kW and during the remaining 22 hours of this test, the diesel generator shall be loaded to 4430 kw. The generator voltage and frequency shall be 4160 420 volts and 60 1.2 Hz within 10 seconds after the start signal; the steady state generator voltage and frequency shall be maintained within these limits during this test. Within 5 minutes after completing this 24-hour test, perform Surveillance Requirement 4.8.1.1.2.h.4.b).*
- 10. Verifying that the auto-connected loads to each diesel generator do not exceed the 2000-hour rating of 4737 kW.
- 11. Verifying the diesel generator's capability to:
T If Surveillance Requirement 4.8.1.1.2.h.4.b is not satisfactorily completed, it is not necessary to repeat the preceding 24 hour test. Instead, the diesel generator may be operated at (continuous rating) kw for one hour or until operating temperature has stabilized. HOPE CREEK 3/4 8-6
ELECTRICAL POWER SYSTEMS JUU 2 8 g SURVEILLANCE REQUIREMENTS (Continued) a) Synchronize with the offsite power source while the generc. tor is loadeu oita its emergency loads upon a simulated restoration of offsite power, b) Transfer its loads to the offsite power source, and c) Be restored to its standby status. 12. Verifying that with the diesel generator operating in a test mode and connected to its bus, a simulated ECCS actuation signal overrides the test mode by (1) returning the diesel generator to standby operation, and (2) automatically energizes the emergency loads with offsite power. s (13. Verifying that with all diesel generator air start receivers pressurized to less than or equal to (250) psig and the compressors secured, the diesel generator starts at least 5 times from ambient conditions and accelerates to (900) rpm % 3% in less than or equal to (13) seconds.) 14. Verifying that the fuel transfer pump transfers fuel from each' fuel storage tank to the day and engine-mounted tanks of each diesel via the installed cross connection lines. 15. Verifying that the automatic load sequence timer is OPERABLE with designtheinterval. interval between each load block within 10% of its 16. Verifying that the following diesel generator lockout features prevent diesel generator starting only when required: a) Engine overspeed, generator differential, and low lube oil pressure (regular lockout relay, (1) 86R). b) Backup generator differential and generator overcurrent (backup lockout relay, (1) 868) c) Generator ground and lockout relays regular, backup and test, energized (breaker failure lockout relay, (1) 86F) 1. At least once per 10 years or after any modifications which could affect diesel generator interdependence by starting both diesel generators simultaneously, during shutdown, and verifying that both diesel generators accelerate to at least 514 rpm in less than or equal to 10 seconds. J. At least once per 10 years by: HOPE CREEK 3/4 8-7
i 5 ELECTRICAL POWER SYSTEMS JUll 2 8 tcy SURVEILLANCE REOUIREMENTS (Continued)
- 1. Draining eacn ruel oil storage tank, removing the accumulated sediment and cleaning the tank using a sodium hypochlorite solution, and
- 2. Performing a pressure test of those portions of the diesel fuel oil system designed to Section III, subsection ND of the ASME Code in accordance with ASME Code Section 11 Article IWD-5000.
4.8.1.1.3 Reports - All diesel generator failures, valid or non-valid, shall be reported to the Commission pursuant to Specification 6.9.1. Reports of diesel cenerator failures shall include the information recommended in Regulatory Position C.3.b of Regulatory Guide 1.108, Revision 1, August 1977. If the number of failures in the last 100 valid tests, on a per nuclear unit basis, is greater than or equal to 7, the report shall be supplemented to include the additional information recommended in Regulatory Position C.3.b of Regulatory Guide 1.108, Revision 1, August 1977. HOPE CREEK 3/4 8-8
5 3 TABLE 4.8.1.1.2-1 3'u'eb s u DIESEL GENERATOR TEST SCHEDULE 0 85 Number of Failuras fr. Last 100 Valid Tests Test Frequency
<1 At least once per 31 days 2
At least once per 14 days 3 At laast once per 7 days
>4 At least once per 3 days
- Criteria for determining number of failures and number of valid tests shall be in accordance with Regulatory Position C.2.e of Regulatory Guide 1.108, Revision 1, August 1977, where the last 100 tests are determined on a per nuclear unit basis. For the purposes of this test schedule, only valid tests conducted after the OL issuance date shall be included in the computation of the "last 100 valid tests." Entry into this test schedule shall be made at the 31 day test frequency. .
E 5 e e HOPE CREEK 3/4 8-9
ELECTRICAL POWER SYSTEMS
.lUN 2 a gg A.C. SOURCES - SHUTOOWN
$ LIMITING CONDITION FOR OPERATION ! 5.8.1.2 As a minimum, the following A.C. electrical power sources shall be OPERABLE: a. One circuit between the offsite transmission network and the onsite , Class 1E distribution system, and
- b. Two diesel generators each with:
i
- 1. A day fuel tank containing a minimum of 200 gallons of fuel.
4- 2. A fuel storage system consisting of two storage tanks containing a minimum of 48,000 gallons of fuel.
- 3. A separate fuel transfer pump for each storage tank.
APPLICABILITY: OPERATIONAL CONDITIONS 4, 5 and *. 1 ACTION:
- a. With less than the above required A.C. electrical power sources OPERABLE, suspend CORE ALTERATIONS, handling of irradiated fuel in the secondary containment, operations with a potential for draining the reactor vessel and crane operations over the spent fuel storage pool when fuel assemblies are stored therein. In addition, when in OPERATIONAL CONDITION 5 with the water level less than 22'-2" above the reactor pressure vessel flange, immediately initiate corrective action to restore the required power sources to OPERABLE status as s,
soon as practical.
- b. The provisions of Specification 3.0.3 are not applicable.
SURVEILLANCE REOUIREMENTS 4.8.1.2 At least the above required A.C. electrical power sources shall be demonstrated OPERABLE per Surveillance Requirements 4.8.1.1.1, 4.8.1.1.2, and 4.8.1.1.3, except for the requirement of 4.8.1.1.2.a.5.
*when nandling irradiated fuel in the secondary containment.
~ HOPE CREEK 3/4 8-10
m N Df I l' , e ELECTRICAL POWER SYSTEMS
- d 3/4.8.2 0.C. SOURCES .
0.C. SOURCES - OPERA _TTNG # MMITING CONDITION FOR OPERATION _ L 3.8.2.1 As a minimum, the following D.C. electrical power' sources shall be OPERABLE: _e
- a. Channel A, consisting of:
- 1. 125 volt battery 1A0411
- 2. 125 volt full cr.pacity charger 1AD413 or 1AD414
- 3. 250 volt battery 100421; 4,250 volt full capacity charger 10D423
- b. Channel B, consisting of:
- 1. 125 volt battery 180411
- 2. 125 volt full capacity charger 180413 or 180414
- 3. 250 volt battery 100431; 4,250 velt full capacity charger 100433
- c. Channel C, consisting of:
, 1. 125 volt battery ICD 411
- 2. 125 volt full capacity charger 1CD413 or 1CD414
- 3. 125 volt battery 1CD447
- 4. 125 volt full capacity charger 1CD444
- d. Channel D, consisting of: -
- 1. 125 volt battery 10D411 _
- 2. 125 volt full capacity charger 10D413 or 10D414
- 3. 125 volt battery 100447
- 4. 125 volt full capacity charger 10D444 APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. '
ACTION: - Withanybatteryand/orcijargeroftheaboverequiredD.C. electrical power sources inoperable,' restore the inoperable divisic'. battery to OPERABLE status within 2 hours or be in at least HOT SHUTDOWN wittiin tt le next 12 hours and in COLD SHUTDOWN within the following 24 hours. SURVEILLANCE REOUIREMENTS , [
~
4.8.2.1 Each of the above required batteries and chargers shall be d on .- strated OPERABLE: . .
- a. At least once per 7 days by verifying that:
- 1. The parameters in Table 4.8.2.1-1 meet the Category A limits, and HOPE CREEK 3/4 8-11
^
ELECTRICAL POWER SYSTEMS M 2 4 ty8E' SURVEILLANCE REQUIREMENTS (Continued)
- 2. Total battery terminal voltage for each 125-volt battery is
. greater than or equal to 129 volts on float charge and for each
~.50-vcit battery the ves.a...al vul cage is greater than or equal to 258 volts on float charge.
- b. At least once per 92 days and within 7 days after a battery discharge with battery terminal voltage below 105 volts for a 125-volt battery or 210 volts for a 250-volt battery, or battery overcharge with battery terminal voltage above 140 volts for a 125-volt battery or 280 volts for a 250-volt battery, by verifying that:
- 1. The parameters in Table 4.8.2.1-1 meet the Category B limits,
- 2. There is no visible corrosion at either terminals or connectors, and
~
- 3. The average electrolyte temperature of each sixth cell of connected cells is above 60*F.
- c. At least once per 18 months by verifying that:
- 1. The cells, cell plates and battery racks show no visual indication of physical damage or abnormal deterioration,
- 2. The cell-to-cell and terminal connections are clean, tight, free of corrosion and coated with anti-corrosion material,
- 3. The resistance of each cell-to-cell and terminal connection is-less than or equal to 150 x 10 8 ohms, and
- 4. The battery charger will supply the current listed below at a minimum of ( ) volts for at least (4) hours.
CHARGER CURRENT (AMPERES) l 1AD413, 1AD414 180413, 1BD414 1CD413, 1CD414 1CD444, 1DD414 i 100444-100423, 10D433 l d. At least once per 18 months, during shutdown, by verifying that either: ,
~
s. i HOPE CREEK 3/4 8-12 l L.
ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)
- 1. The battery capacity is adequate to supply and maintain in OPERA 3LE status Z of Liie actual emergency loaos for tne design duty cycle when the battery is subjected to a battery service test, or
- 2. The battery capacity is adequate to supply a dummy load of the following profile while maintaining the battery terminal voltage greater than or equal to 105 volts for the 125-volt battery and 210 volts for the 250-volt battery:
LOAD CYCLE (amps) Channel Battery 0-1 Min. 1-239 Min. 239-240 Min. A B C D Each 125/250-volt battery is rated at (1500) ampere-hours at an 8-hour discharge rate, based on a terminal voltage of (1.75) volts per-cell at (77)*F. Each 125-volt battery is rated at (250) ampere-hours at an 8-hour discharge rate, based on a terminal voltage of (1.75) volts per-cell at (77) F.
- e. At least once per 60 months.during shutdown by verifying that the battery capacity is at least 80% of the manufacturer's rating when subjected to a' performance discharge test. At this once per 60 month interval, this performance discharge test may be performed in lieu of the battery service test.
- f. At least once per 18 months during shutdown performance discharge tests of battery capacity shall be given to any battery that shows signs of-degradation or has reached 85% of the service life expected for the application. Degradation is indicated when the battery capacity drops more than 10% of~ rated capacity from its average on previous performance tests, or is below 90% of the manufacturer's rating.
i HOPE CREEK 3/4 8-13
i TABLE 4.8.2.1-1 l BATTERY SURVEILLANCE REQUIREMENTS ! JUN 2 81S85 CATEGORY A(1) CATEGORY B(2) Parameter Limits for each Limits for each Allowable (3) designated pilot connected cell value for each cell connected cell Electrolyte > Minimum level > Minimum level Level Indication mark, Above top of Indication mark, plates, and < \" above and < " above .and not. maximum level maxiiiium level overflowing indication mark indication mark s Float Voltage > 2.13 volts > 2.13 volts (C) > 2.07 volts Not more than
.020 below the * .
average of all
. . > (1.195) connected cells Specifig)
Gravity
> (1.200)(b) Average of all Average of all connected cells connected
> (1.205) >(1.195)(ggils (a) Corrected for electrolyte temperature and level.
( )0r battery charging current is less than 2 amperes when on float charge. (c)May be corrected for average electrolyte temperature. (1)For any Category A parameter (s) outside the limit (s) shown, the battery i may be considered OPERABLE provided that within 24 hours all the Category B measurements are taken and found to be within their allowable values, and previoed all Category A and B parameter (s) are restored to within limits within the next 6 days. (2)For any Category B parameter (s) outside the limit (s) shown, the battery may be considered OPERABLE provided that the Category B parameters are l within their allowable values and provided the Category S parameter (s) are restored to within limits within 7 days. (3)Any Category B parameter not within its allowable value indicates an inoperable battery.
- l
! HOPE CPEEK 3/4 8-14
ELECTRICAL POWER SYSTEMS
\
ff V dJ u ll I D.C. SOURCES - SHUTDOWN JUN 2 8 1985 LIMITING CONDITION FOR OPERATION 3.8.2.2 As a minimum, two of the following four divisions of the D.C. electrical power sources syster sh- be OPERABLE with:
- a. Channel A, consisting of:
- 1. 125 volt battery 1AD411
- 2. 125 volt full capacity charger 1AD413 or 1AD414
- 3. 250 volt battery 10D421; 4,250 volt full capacity charger 100423
- b. Channel B, consisting of:
- 1. 125 volt battery (IB).
- 2. 125 volt full capacity charger.
3. 250 volt battery 100431; 4,250 volt full capa' city charger 100433
- c. Channel C, consisting of:
- 1. 125 volt battery ICD 411
- 2. 125 volt full capacity charge ICD 413 or 1CD414
- 3. .125 volt battery 1CD447
- 4. 125 volt full capacity charge ICD 444
- d. Channel D, consisting of:
, 1. 125 volt battery 1DD411
- 2. 125 volt full capacity charge 1D0413 or 1DD414
- 3. 125 volt battery 100447-
- 4. 125 volt full capacity charge 100444 APPLICABILITY: OPERATIONAL CONDITIONS 4, 5 and *.
ACTION:
- a. With less than two channels of the above required D.C. electrical power sources OPERABLE, suspend CORE ALTERATIONS, handling of irradiated fuel in the secondary containment and operations with a potential for draining the reactor vessel.
- b. The provisions of Specification 3.0.3 are not applicable.
SURVEILLANCE REOUIREMENTS 4.8.2.1 At least the above required battery and charger shall be demonstrated OPERABLE per Surveillance Requirement 4.8.2.1. A I ! *When handling irradiated fuel in the secondary containment. i i HOPE CREEK 3/4 8-15
ELECTRICAL POWER SYSTEMS 3/4.8.3 ONSITE POWER DISTRIBUTION SYSTEMS JUN 2 8 1cas DISTRIBUTION - OPERATING LIMITING CONDITION FOR OPERATION 3.8.3.1 The following power distribution system channels shall be energized:
- a. A.C. power distribution:
- 1. Channel A, consisting of:
a) 4160 volt A.C. switchgear bus 10A401 b) 480 volt A.C. load centers 10B410 108450 c) 480 volt A.C. MCCs 108212 10B411 108451 10B553 d) 208/120 volt A.C. distribution panels 10Y401(source:103411) 10Y411(source:108451)' 10Y501(source:108553) e) 120 volt A.C. distribution panels 1AJ481 1YF401(source:1AJ481) 1AJ482
- 2. Channel B, consisting of:
a) 4160 volt A.C. switchgear bus 10A402 b) 480 volt A.C. load centers 108420 108460 c) -480 volt A.C. MCCs 108222 108421 10B461 108563 d) 208/120 volt A.C. distribution panels 10Y402(source:108421) 10Y412(source:108461) 10Y502(source:108563) e) 120 volt A.C. distribution panels 1BJ481 1YF402(source:1BJ481) 1BJ482
- 3. Channel C, consisting of:
a) 4160 volt A.C. switchgear bus 10A403 b) 480 volt A.C. load centers 108430 108470 c) 480 volt A.C. MCCs 108232 108431 . 108471 10B573 d) 208/120 volt A.C. distribution panels 10Y403(source:108431) 10Y413(source:108471) 10Y503(source:108573) HOPE CREEK 3/4 S-16 L
l l ELECTRICAL POWER SYSTEMS " LIMITING CONDITION FOR OPERATION (Continued) " O 1985 e) 120 volt A.C. distribution panels 1CJ481 1YF403(source:1CJ481) 1CJ482
- 4. Channel D, consisting of:
a) 4160 volt A.C. switchgear bus 10A404 b) 480 volt A.C. load centers 108440 108480 c) 480 volt A.C. MCCs 108242 108441 108481 10B583 d) 208/120 volt A.C. distribution panels 10Y404(source:108441) 10Y414(source:108481) 10Y504(source:108583)
- b. 0.C. power distribution:
- 1. Channel A, consisting of:
a) 125 volt D.C. switchgear 100410 b) 125 volt D.C. fuse box 1AD412 c) 125 volt D.C. distribution panel 1AD417 d) 250 volt D.C. switchgear 100450 e) 250 volt D.C. fuse box 100422 f) 250 volt D.C. MCC 10D251
- 2. Channel B, consisting of:
a) 125 volt D.C. switchgear 10D420 b) 125 volt D.C. fuse box 180412 c) 125 volt D.C. distribution panel 180417 d) 250 volt D.C. switchgear 100460 e) 250 volt D.C. fuse boxes 100432 f) 250 volt D.C. MCC 10D261
- 3. Channel C, consisting of:
a) 125 volt D.C. switchgear 10D430 10D436 b) 125 volt D.C. fuse box 1CD412 1CD448 c) 125 volt D.C. distribution panel 1C0417
- 4. Channel D, consisting of:
a) 125 volt D.C. switchgear 10D440 10D446 ' b) 125 volt D.C. fuse boxes 1D0412 10D448 c) 125 volt D.C. distribution panel 10D417 HOPE CREEK 3/4 8-17
a ELECTRICAL POWER SYSTEMS N 8 1985 LIMITING CONDITION FOR OPERATION (Continued) APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:
- a. With one of the above required A.C. distribution system channels not energized, re-energize the channel within 8 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN withir, the following 24 hours.
- b. With one of the above required D.C. distribution system divisions not energized, re energize the division within 2 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.
SURVEILLANCE REQUIREMENTS 4.8.3.1 Each of the above required power distribution system divisions shall be determined energized at least once per 7 days by verifying correct breaker alignment and voltage on the busses /MCCs/ panels. l l HOPE CREEK 3/4 8-18 i
a ELECTRICAL POWER SYSTEMS JUN 2 e ngg DISTRIBUTION - SHUTDOWN LIMITING CONDITION FOR OPERATION 3.8.3.2 As.a minimum, shall be energized with: 2 of the 4 channels of the power distribution system
- a. A.C. power distribution:
- 1. Channel A, consisting of:
a) 4160 volt A.C. switchgear bus 10A401 b) 480 volt A.C. load centers 10B410 108450 c) 480 volt A.C. MCCs 108212 10B411 10B451-108553 d) 208/120 volt A.C. distribution panels 10Y401(source:108411) 10Y411(source:10B451) e) 120 volt A.C. distribution panels 10Y501(source:108553) 1AJ481 1YF401(source:1AJ481) 1AJ482
- 2. Channel 8, consisting of:
a) 4160 volt A.C. switchgear bus 10A402 b) 480 volt A.C. load centers 108420 108460 c) 480 volt A.C. MCCs 108222 108421 10B461 108563 d) 208/120 volt A.C. distribution panels 10Y402(source:108421) 10Y412(source:108461) e) 120 volt A.C. distribution panels 10Y502(source:108563) 1BJ481 1YF402(source:1BJ481) 1BJ482
- 3. Channel C, consisting of:
a) 4160 volt A.C. switchgear bus 10A403 b) 480 volt A.C. load centers 108430 10B470 c) 480 volt A.C. MCCs 108232 108431 108471 ' 108573 d) 208/120 volt A.C. distribution panels 10Y403(source:108431) 10Y413(source:108471) 10Y503(source:10B573) HOPE CREEK 3/4 8-19
ELECTRICAL POWER SYSTEMS 0%7 dl:N 2 8 1995 LIMITING CONDITION FOR OPERATION (Continued) e) 120 volt A.C. distribution panels 1CJ481 1YF403(source:1CJ481) 1CJ482
- 4. Channel D, consisting of:
a) 4160 volt A.C. switchgear bus 10A404 b) 480 volt A.C. load centers 108440 108480 c) 480 volt A.C. MCCs 108242 108441 108481 108583 d) 208/120 volt A.C. distribution panels 10Y404(source:108441) a 10Y414(source:108481) 10Y504(source:108583)
- b. D.C. power distribution:
- 1. Channel A, consisting of: "
~~
a) 125 volt D.C. switchgear 100410 b) 125 volt D.C. fuse box 1A0412 - c) 125 volt D.C. distribution panel 1A0417
- 2. Channel 8, consisting of:
a) 125 volt D.C. switchgear 10D420 b) 125 volt D.C. fuse box 180412 c) 125 volt D.C. distribution panel 180417
- 3. Channel C, consisting of:
a) 125 volt D.C. switchgear 100430 10D436 i b) 125 volt D.C. fuse boxes ICD 412 1CD448 l c) 125 volt D.C. distribution panel 1CD417 l 4 Channel D, consisting of: l a) 125 volt D.C. switchgear 10D440 100446 b) 125 volt D.C. fuse box 100412 100448 c) 125 volt D.C. distribution panel 100417 l HOPE CREEK 3/4 8-20
i ELECTRICAL POWER SYSTEMS dify p g i LIMITING CONDITION FOR OPERATION (Continued) APPLICABILITY: OPERATIONAL CONDITIONS 4, 5 and *. ACTION:
- a. With less than.two channels of the above required A.C. distribution system energized, suspend CORE ALTERATIONS, handling of irradiated fuel in the secondary containment and operations with a potential for draining the reactor vessel.
- b. With less than two channels of the above required D.C. distribution system energized, suspend CORE ALTERATIONS, handling of irradiated fuel in the secondary containment and operations with a potential for draining the reactor vessel.
- c. The provisions of Specification 3.0.0 are not applicable.
SURVEILLANCE REOUIREMENTS 4.8.3.2 At least the above required power distribution system channels shall be determined energized at least once per 7 days by verifying correct breaker alignment and voltage on the busses /MCCs/ panels.
*When handling irradiated fuel in the secondary containment.
HOPE CREEK 3/4 8-21
b i ELECTRICAL POWER SYSTEMS 3/4.8.4 ELECTRICAL EQUIPMENT PROTECTIVE DEVICES JUN 2 8 1'c': A.C. FIRCiliTS INSTDE Pp Ary cnuTtT*fuEMT LIMITIN3 CONDITION FOR OPERATION 3.8.4.1 At least the following A.C. circuits inside primary containment shall be de-energized *:
- a. Circuit numbers ( _ , _ , _ and _ ) in panel ( ).
- b. Circuit numbers ( _ , _ , _ and _ ) in panel ( ).
APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION: With any of the above required circuits energized, trip the associated. circuit breaker (s) in the specified panel (s) within 1 hour. SURVEILLANCE REQUIREMENTS 4.8.4.1 Each of the above required A.C. circuits shall be determined to be de-energized at least once per 24 hours ** by verifying that the associated circuit breakers are in the tripped condition. l l l l
*Except curing entry into the drywell. **Except at least once per 31 days if locked, sealed or otherwise secured in the tripped condition.
l HOPE CREEK 3/4 8-22 L
ELECTRICAL POWER SYSTEMS BF! AFT PRIMARY CONTAINMENT PENETRATION CONDUCIOR OVERCURRENT PROTECTIVE DEVICES M5 LIMITING CONDITION FOR OPERATION 3.8.4.2 All primary containment penetration conductor overcurrent protective devices shown in Table 3.9.4.2-1 shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:
- a. With one or more of the primary containment penetration conductor i
overcurrent protective devices shown in Table 3.8.4.2-1 inoperable, declare the affected system or component inoperable and apply the appropriate ACTION statement for the affected system, and
- 1. For 4.16 kV circuit breakers, de-energize the 4.16 kV circuit (s) by tripping the associated redundant circuit breaker (s) within 72 hours and verify the redundant circuit breaker to be tripped at least once per 7 days thereafter.
- 2. For 480 volt circuit breakers, remove the inoperable circuit breaker (s) from service by (racking out the breaker) within 72 hours and verify the inoperable breaker (s) to be (racked out) at least once per 7 days thereafter.
Otherwise, be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours,
- b. The provisions of Specification'3.0.4 are not applicable to overcurrent devices in 4.16 kV circuits which have their redundant circuit breakers tripped or to 480 volt circuits which have the inoperable circuit breaker (racked out).
SURVEILLANCE REQUIREMENTS 4.8.4.2 Each of the primary containment penetration conductor overcurrent protective devices shown in Table 3.8.4.2-1 shall be demonstrated OPERABLE:
- a. At least once per 18 months:
- 1. By verifying that the medium voltage 4.16 kV circuit breakers are OPERABLE by selecting, on a rotating basis, at least 10% of the circuit breakers (of each voltage level) and performing:
a)~ A CHANNEL CALIBRATION of the associated protective relays, and b) An integrated system functional test which includes simulated autcmatic actuation of the system and verifying that each relay and associated circuit breakers and overcurrent control circuits function as designed. c) For.ea~ch circuit breaker found inoperable during these functional tests, an additional representative sample 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. HOPE CREEK 3/4 8-23
u sa ELECTRICAL POWER SYSTEMS EN 2 8 1065 \ SURVEILLANCE REQUIREMENTS (Continued)
- 2. By selecting and functionally testing a representative sample of at least 10% of each type 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 inject:ng 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 20% of the pickup value of the element and verifying that the circuit breaker trips instantaneously with no inten-tional time delay. Molded case circuit breaker testing shall also follow this precedure except that generally no more than two trip elements, time delay and instantaneous, will be involved. Circuit breakers found inoperable during functional testing shall be restored to OPERABLE status prior to resuming operation. For each circuit breaker found inoperable during these functional tests, an additional representative sample 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.
- 3. By selecting and functionally testing a representative sample of each type of fuse on a rotating basis. Each representative sample of fuses shall include at least 10% of all fuses of that type. The functional test shall consist of a non-destructive resistance measurement test which demonstrates that the fuse c meets its manufacturer's design criteria. Fuses found inoperable
- during these functional testing shall be replaced with OPERABLE j fuses prior to resuming operation. For each fuse found inoperable j during these functional tests, an additional representative sample of at least 10% of all fuses of that type shall be functionally tested until no more failures are found or all fuses of that I type have been functionally tested.
- b. At least once per 60 months by subjecting each circuit breaker to an
! inspection and preventive maintenance in accordance with procedures prepared in conjunction with its manufacturer's recommendations. l . L l l l HOPE CREEK 3/4 8-24
A TABLE 3.8.4.2-1 PRIMARY CONTAINMENT PENETRATION CONOUCTOR SSIN 8 8 ggg OVERCURRENT PROTECTIVE DEVICES
- 1. 4160-VOLT CIRCUIT BREAKERS CIRCUIT SYSTEMS GR BREAKER NO. LOCATION EQUIPMENT POWERED 1AN205 1AN205 1BN205 Reactor Recirculation Pump 1AP201 1BN205 Reactor Recirculation Pump 1BP201 1CN205 1CN205 10N205 Reactor Recirculation Pump 1AP201 1DN205 Reactor Recirculation Pump 1BP201
- 2. 480-VOLT MOLDED CASE CIRCUIT BREAKERS Primary and backup breakers have the same device numbers and are located in the same Motor Control Center cubicle.
CIRCUIT SYSTEMS OR BREAKER NO. LOCATION TYPES EQUIPMENT POWERED 52-411065 108411 IM HFB150 RHR Head Spray Valve TM HFB150 1BC-HV-F022 52-451061 10B451 IM HFB150 RHR Shutdown Cooling Inboard TM HFB150 Valve 1BC-HV-F009 52-212021 108212 IM HFB150 RWCV Suction Isolation Inboard TM HFB150 Valve 1BG-HV-F001 52-212101 108212 IM HFB150 Instrument Gas Supply Inboard TM HFB150 Valve 1XL-HV-5152A 1 52-212181 108212 IM HFB150 Steam Line Drain Inboard TM HFB150 Valve 1AB-HV-F016 52-212183 108212 IM HFB150 Instrument Gas Compressor TM HFB150 Inboard Valve 1XL-HV-5148 52-232161 108232 IM HFB150 Supply Header A Shutoff TM HFB150 Valve 1XL-HV-5124A 52-232102 108232 IM HFB150 Drywell Equip. Drain Sump TM HFB150 Valve 1HB-HV-F019 52-232103 108232 IM HFB150 HPCI Warmup Line Isolation TM HFB150 Valve 1FO-HV-F100 52-232181 108232 IM HFB150 Chilled Water Loop A Supply . TM HFB150 Isolation Valve 1GB-HV-953181 52-232182 10B232 IM HFB150 Chilled Water Loop A Return TM HFB150 Isolation Valve 1GB-HV-953182 52-232183 108232 IM HFB150 Chilled Water Loop B Supply TM HFB150 Isolation Valve 1GB-HV-953183 HOPE CREEK 3/4 8-25
, . _ . , - , - _ _ , . . . - _,y - . _ _ , _ , , _ _ . - ----_...._y._ . , -..__-__-._.._.______.._.-m
- m. ,, . . - . . ~ ._-._,
I h TABLE 3.8.4.2-1 (Continued) EdN28 PRIMARY CONTAINMENT PENETRATION CONDUCTOR S85 OVERCURRENT PROTECTIVE DEVICES 2. 480-VOLT MOLDED CASE CIRCUIT BREAKFR3 (Centinued) CIRCUIT BREAKER NO. SYSTEMS OR LOCATION TYPES EQUIPMENT POWERED 52-232193 108232 IM HFB150 Chilled Water Loop B Return TM HFB150 Isolation Valve 1GB-HV-953184 52-232203 10B232 IM HFB150 HPCI Pump Turbine Steam TM HFB150 Isolation Valve 1FO-HV-F002 52-242021 10B242 IM HFB150 Isolation Closure Signal 3 TM HFB150 Valve 1HB-HV-F003 52-242061 108242 IM HFB150 Supply Header 8 Shutoff TM HFB150 Valve 1XL-HV-51248 52-242101 108242 IM HFB150 Instrument Gas Header B . TM HFB150 Inboard Isolation Valve ' 1KL-HV-5152B 242102 108242 IM HFB150 RCIC Steam Supply Isolation' TM HFB150 Valve 1FC-HV-F007 52-242103 108242 IM HFB150 RCIC Isolation Valve Bypass TM HFB150 1FC-HV-F076 52-242172 108242 IM HFB150 Reactor Recire Pump Cooling TM HFB150 Isolation IED-HV-2554 52-242173 108242 IM HFB150 Reactor Recirc Pump Cooling TM HFB150 Isolation 1ED-HV-2556 52-252021 108252 IM HFB150 Drywell Cooler A Fan 1A1V212 TM HFB150 52-252022 108252 IM HFB150 Orywell Cooler B Fan 181V212 TM HFB150 52-252031 108252 IM HFB150 Orywell Cooler C Fan 1C1V212 TM HFB150 52-252032 108252 IM HFB150 Drywell Cooler 0 Fan 101V212 TM HFB150 52-252041 10B252 IM HFB150 Orywell Cooler E Fan 1E1V212 TM HFB150 52-252042 108252 IM HFB150 Orywell Cooler F Fan 1FIV212 .. TM HFB150 52-252051 108252 IM HFB150 Orywell Cooler G Fan 1G1V212 TM HFB150 52-252052 10B252 IM HFB150 Orywell Cooler H Fan 1HIV212 TM HFB150 HOPE CREEK 3/4 B-25
TABLE 3.8.4.2-1 (Continued) D L/;l/~ j PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES ,pjy 2 6
$85 2.
. 480-VOLT MOLDED CASE CIRCUIT BREAKERS (Contim.'ad) CIRCUIT 5YSTEMS OR BREAKER NO. LOCATION TYPES EQUIPMENT POWERED 52-252063 108252 IM HFB150 Drywell Equip Drain Sump Pump TM HFB150 1AP267 52-252064 10B252 IM HFB150 Drywell Equip Drain Sump Pump TM HFB150 1CP267 52-252073 108252 IM HFB150 Feedwater Inlet A Shutoff TM HFB150 1AE-HV-F011A 52-262021 10B262 IM HFB150 Drywell Cooler A Fan 1A2V212 TM HFB150 52-262022 108262 IM HFB150 Drywell Cooler B Fan 182V212 TM HFB150 52-262031 108262 IM HFB150 Drywell Cooler C Fan 1C2V212 TM HFB150 52-262032 108262 IM HFB150 Drywell Cooler D Fan ID2V212 TM HFB150 52-262041 10B262 IM HFB150 Drywell Cooler E Fan 1E2V212 TM HFB150 52-262042 108262 IM HFB150 Drywell Cooler F Fan 1F2V212 TM HFB150 52-262051 10B262 IM HFB150 Drywell Cooler G Fan 1G2V212 TM HFB150 52-262052 10B262 IM HFB150 Orywell Cooler H Fan 1H2V212 TM HFB150 52-262063 108262 IM HFB150 Drywell Equip Drain Sump Pump TM HFB150 1BP267 52-262064 108262 IM HFB150 Drywell Equip Drain Sumo Pump TM HFB150 1DP267 52-253012 108253 IM HFB150 Recirc Pump Motor Hoist 1AH201 TM HFB150 Disconnect Switch 1AS204 l 52-253021 108253 IM HFB150 Recirc Pump 1BP201 Suction l TM HFB150 Valve 1BB-HV-F0238 , 52-253031 108253 IM HFB150 Recire Pump 1BP201 Discharge TM HFB150 Valve 1BB-HV-F0318 52-253053 10B253 IM HFB150 Reactor Vessel Head Vent TM HFB150 Inboard Isolation 1BB-HV-F001 HOPE CREEK 3/4 8-27
TABLE 3.8.4.2-1 (Continued) g PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES 2. 480-VOLT' MOLDED CASE CIDCllIT BREAKERS 'ContinuetG CIRCUIT SYSTEMS OR BREAKER NO. LOCATION TYPES EQUIPMENT POWERED 52-253064 108253 IM HFB150 Reactor Vessel Head Vent to TM HFB150 Steam Line 1BB-HV-F005 52-263011 108263 IM HFB150 Reactor Vessel Head Vent TM HFB150 Outboard Isolation 1BB-HV-F002 52-263012 108263 IM HFB150 Recirc Pump Motor Hoist 1BH201 TM HFB150 Disconnect Switch 18S204 52-263042 108263 IM HFB150 Main Steam Relief Valve Hoist TM HFB150 10H202 Disconnect Switch 10S207 52-263054 108263 IM HFB150 RWCU Recirc Loop A 1BG-HV-F100 TM HFB150 52-263081 108263 IM HFB150 RPV Bottom Drain Valve TM HFB150 IBG-HV-F101 52-263082 10B263 IN HFB150 RWCU Suction Valve IBG-HV-F102 TM HFB150 52-263083 108263 IM HFB150 RWCU Suction from Recirc Loop TM HFB150 B Valve 1BG-HV-F106 52-264053 108264 IM HFB150 Recirc Pump Discharge Valve TM HFB150 1BB-HV-F031A 52-264062 108264 IM HFB150 Feedwater Inlet Shutoff TM HFB150 Valve 1AE-HV-F0118 52-264071 108264 IM HFB150 Reactor Recire Pump 1AP201 TM HFB150 Space Heater 1AS220 52-264072 108264 IM HFB150 Reactor Recirc Pumo 1BP201 TM HFB150 Space Heater 18S220 52-264083 108264 IM HFB150 Recire Pump A Suction Valve TM HFB150 1BB-HV-F023A HOPE CREEK 3/4 8-28
ELECTRICAL POWER SYSTEMS JUN 2 8 gg MOTOR OPERATED VALVES THERMAL OVERLOAD PROTECTION (Bypassed) LIMITING CONDITION FOR OPERATTOM 3.8.4.3 The thermal overload protection of each valve shown in Table 3.8.4.3-1 shall be bypassed continuously or only under accident conditions, as applicable, by an OPERABLE bypass device integral with the motor starter. APPLICABILITY: Whenever the motor operated valve is required to be OPERABLE. ACTION:
- With the thermal overload protection for one or more of the above required valves not bypassed continuously or only under accident conditions, as t applicable, by an OPERABLE integral bypass device, continuously bypass the thermal overload within 8 hours or declare the affected valve (s) inoperable and apply the appropriate ACTION statement (s) for the affected system (s).
SURVEILLANCE REQUIREMENTS 4.8.4.3.1 The thermal overload protection for the above required valves shall be verified to be bypassed continuously or only under accident conditions, as applicable, by an OPERABLE integral bypass device by verifying that the i thermal overload protection is bypassed for those thermal overloads which are continuously bypassed and temporarily placed in force only when the valve motors are undergoing periodic or maintenance testing or the performance of a CHANNEL
-FUNCTIONAL TEST of the bypass circuitry for those thermal overloads which are normally in force during plant operation and are bypassed only under accident conditions:
, a. At least once per 18 months for those thermal overloads which are continuously bypassed and temporarily placed in force only when the valve motors are undergoing' periodic or maintenance testing or at least once per 92 days for those thermal overloads which are normally in force during plant operation and are bypassed only under accident conditions.
- b. Following maintenance on the motor starter.
~4.8.4 3 2 The thermal overload protection for the above required valves which are continuously bypassed and temporarily placed in force only when the valve ,
motor is undergoing periodic or maintenance testing shall be verified to be bypassed following periodic or maintenance testing during which the thermal overload protection was temporarily placed in force. 1 HOPE CREEK 3/4 8-29
--m- - -m-- - -,-g , --=-
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b/I TABLE 3 B 4 3-1 ll/i OU?l 2 8 1995 MOTOR OPERATED VALVES THERMAL OVERLOAD PROTECTION aypass DEVICC Continuous or
. VALVE NUMBER Accident Conditions SYSTEM (S) AFFECTED 1AB-HV-F016 Continuous Main Steam 1AB-HV-F019 Continuous Main Steam 1AB-HV-F067A Continuous Main Steam 1AB-HV-F067B Continuous Main Steam 1AB-HV-F067C Continuous Main Steam 1AB-HV-F0670 Continuous Main Steam 1AP-HV-F011 Accident Condensate Storage & Transfer 1BC-HV-F097A Accident Residual Heat Removal 1BC-HV-F007B Accident Residual Heat Removal IBC-HV-F007C Accident Residual Heat Removal 1BC-HV-F007D Accident Residual Heat Removal 1BC-HV-F008 Continuous Residual Heat Removal 1BC-HV-F009 Continuous Residual Heat Removal 1BC-HV-F010A Continuous Residual Heat Removal 1BC-HV-F010B Continuous Residual Heat Removal 1BC-HV-F011A Continuous Residual Heat Removal 18C-HV-F011B Continuous Residual Heat Removal 18C-HV-F015A Continuous Residual Heat Removal 1BC-HV-F015B Continuous Residual Heat Removal 1BC-HV-F017A Accident Residual Heat Removal IBC-HV-F017B Accident Residual Heat Removal 1BC-HV-F017C Accident Residual Heat Removal IBC-HV-F0170 Accident Residual Heat Removal 1BC-HV-F022 Continuous Residual Heat Removal 1BC-HV-F023 Continuous Residual Heat Removal I
1BC-HV-F024A Continuous Residual Heat Removal IBC-HV-F0248 Continuous Residual Heat Removal 1BC-HV-F026A Continuous Residual Heat Removal
- 1BC-HV-F0268 Continuous Residual Heat Removal i 1BC-HV-F027A Continuous Residual Heat Removal i 1BC-HV-F0278 Continuous Residual Heat Removal 1BC-HV-F040 Continuous Residual Heat Removal 1BC-HV-F048A Accident Residual Heat Removal 1BC-HV-F0488 Accident Residual Heat Removal 18C-HV-F049 Continuous Residual Heat Removal 1BC-HV-F052A Continuous Residual Heat Removal 1BC-HV-F0528 Continuous Residual Heat Removal
! 1BC-HV-4428 Continuous Residual Heat Renoval i 1BD-HV-F010 Continuous Reactor Core Isolation Cooling , 1BD-HV-F012 Accident Reactor Core Isolation Cooling i 1BD-HV-F013 Accident Reactor Core Isolation Cooling 1BD-HV-F022 Continuous Reactor Core Isolation Cooling j 180-HV-F031 Accident Reactor Core Isolation Cooling HOPE CREEK 3/4 8-30 1 i__ - - . . - - - .
TABLE 3.8.4.3-1 (Continued) 5 28 fone w MOTOR OPERATED VALVES THERMAL OVERLOAD PROTECTION BYPASS DEVICE Continuous or VALVE NUMBER Accident Conditions SJSTEM(S)AFFECTED 180-HV-F046 Accident 18E-HV-F004A Accident Reactor Core Isolation Cooling IBE-HV-F004B Reactor Core Spray Accident Reactor Core Spray 1BE-HV-F005A Accident 1BE-HV-F005B Reactor Core Spray Accident Reactor Core Spray 1BE-HV-F015A Continuous 1BE-HV-F015B Reactor Core Spray Continuous Reactor Core Spray 1BE-HV-F031A Accident 1BE-HV-F031B Reactor Core Spray Accident Reactor Core Spray 1BG-HV-F001 Continuous 1BG-HV-F004 Reactor Water Cleanup Continuous Reactor Water Cleanup 1BJ-HV-F004 Accident 1BJ-HV-8278 High Pressure Coolant Injection Accident High Pressure Coolant Injection IBJ-HV-F006 Accident IBJ-HV-F007 High Pressure Coolant Injection Accident High Pressure Coolant Injection 1BJ-HV-F008 Continuous 1BJ-HV-F012 High Pressure Coolant Injection Accident High Pressure Coolant Injection 1BJ-HV-F042 Accident 1BJ-HV-F059 High Pressure Coolant Injection Accident High Pressure Coolant Injection 1EA-HV-2198A Continuous 1EA-HV-2198B Station Service Water Continuous Station Service Water 1EA-HV-2198C Continuous 1EA-HV-21980 Station Service Water Continuous Station Service Water 1EA-HV-2355A Continuous 1EA-HV-2355B Station Service Water Continuous Station Service Water 1EA-HV-2371A Continuous 1EA-HV-2371B Station Service Water Continuous Station Service Water 1ED-HV-2553 Continuous 1EA-HV-2554 Reactor Auxiliaries Cooling Continuous Reactor Auxiliaries Cooling 1ED-HV-2555 Continuous 1EA-HV-2556 Reactor Auxiliaries Cooling Continuous Reactor Auxiliaries Cooling 1EE-HV-4652 Continuous 1EE-HV-4680 Torus Water Clean Continuous Torus Water Clean IEE-HV-4681 Continuous IEE-HV-4679 Torus Water Clean Continuous Torus Water Clean 1EG-HV-2317A Continuous 1EG-HV-2317B Safety Auxiliaries Cooling Continuous Safety Auxiliaries Cooling 1EG-HV-2321A Continuous 1EG-HV-2321B Safety Auxiliaries Cooling Continuous Safety Auxiliaries cooling 1EG-HV-2453A Continuous Safety Auxiliaries Cooling 1EG-HV-2453B Continuous 1EG-HV-7922A Safety Auxiliaries Cooling Continuous Safety Auxiliaries Cooling 1EG-HV-7922B Continuous Safety Auxiliaries Cooling HOPE CREEK 3/4 8-31
TABLE 3.8.4.3-1 (Continued) 0%7 J{jy g g MOTOR OPERATED VALVES THERMAL OVERLOAD PROTECTION BYPASS DFVICE Continuous or VALVE NUMBER Accident Conditions SYSTEM (S) AFFECTED 1FC-HV-F007 Continuous RCIC 1FC-HV-F008 Continuous RCIC 1FC-HV-F045 Continuous RCIC 1FC-HV-F062 Continuous RCIC 1FC-HV-F076 Continuous RCIC 1FC-HV-F084 Continuous RCIC 1FD-HV-4922 Continuous HPCI 1FD-HV-F001 Accident HPCI 1FD-HV-F002 scontinuous HPCI 1FD-HV-F003 Continuous HPCI 1FD-HV-F075 Continuous HPCI 1FD-HV-F079 Continuous HPCI 1FD-HV-F100 Continuous HPCI 1GB-HV-9531A1 Continuous ~' 1GB-HV-9531A2 Chilled Water Continuous Chilled Water .1GB-HV-9531A3 Continuous 1GB-HV-9531A4 Chilled Water - Continuous Chilled Water 1GB-HV-953181 Continuous 1GB-HV-953182 Chilled Water Continuous Chilled Water 1GB-HV-953183 Continuous 1GB-HV-9531B4 Chilled Water Continuous Chilled Water 1GB-HV-9532-1 Continuous 1GB-HV-9532-2 Chilled Water Continuous " Chilled Water 1GS-HV-4951 Continuous 1GS-HV-4955A Containment Atmosphere Control Continuous Containment Atmosphere Control 1GS-HV-4955B Continuous Containment Atmosphere Control 1GS-HV-4959A Continuous Containment Atmosphere Control 1GS-HV-4959B Continuous Containment Atmosphere Control 1GS-HV-4963 Continuous Containment Atmosphere Control 1GS-HV-4965A Continuous Containment Atmosphere Control 1GS-HV-4965B Continuous Containment Atmosphere Control 1GS-HV-4966A Continuous Containment Atmosphere Control 1GS-HV-4966B Continuous Containment Atmosphere Control 1GS-HV-4983A Continuous Containment Atmosphere Control 1GS-HV-4983B Continuous Containment Atmosphere Control 1GS-HV-4984A Continuous Containment Atmosphere Control 1GS-HV-4984B Continuous 1GS-HV-4974 Containment Atmosphere Control Continuous Containment Atmosphere Control 1GS-HV-5019A Continuous Containment Atmosphere Control - 1GS-HV-5019B Continuous Containment Atmosphere Control 1GS-HV-5022A Continuous Containment Atmosphere Control 1GS-HV-5022B Continuous Containment Atmosphere Control 1GS-HV-5052A Continuous Containment Atmosphere Control HOPE CREEK 3/4 8-32
TABLE 3.8.4.3-1 (Continued) JUN 36 ggg MOTOR OPERATED VALVES THERMAL OVERLOAD PROTECTION BYPASS DEVICE Continuous or VALVE NUMBER Accident Conditions SYSTEM (S) AFFECTED 1GS-HV-5052B Continuous 1GS-HV-5053A Containment Atmosphere Control Continuous Containment Atmosphere Control 1GS-HV-5053B Continuous 1GS-HV-5054A Containment Atmosphere Control Continuous Containment Atmosphere Control 1GS-HV-5054B Continuous 1GS-HV-5050A Containment Atmosphere Control Continuous Containment Atacsphere Control 1GS-HV-5050B Continuous 1GS-HV-5055A Containment Atmosphere Control Continuous Containment Atmosphere Control 1GS-HV-5055B Continuous 1GS-HV-5057A Containment Atmosphere Control Continuous Containment Atmosphere Control 1GS-HV-50578 Continuous 1HB-HV-F003 Containment Atmosphere Control Continuous Liquid Radwaste 1HB-HV-F004 Continuous Liquid Radwaste 1HB-HV-F019 Continuous Liquid Radwaste 1HB-HV-F020 Continuous' Liquid Radwaste 1KL-HV-5152A Continuous Primary Containment Instrument Gas 1KL-HV-5152B Continuous Primary Containment Instrument Gas 1XL-HV-5124A Continuous Primary Containment Instrument Gas 1KL-HV-5124B Continuous Primary Containment Instrument Gas 1KL-HV-5126A Continuous Primary Containment Instrument Gas 1KL-HV-5126B Continuous Primary Containment Instrument Gas
'1KL-HV-5147 Continuous Primary Containment Instrument Gas 1KL-HV-5148 Continuous Primary Containment Instrument Gas 1XL-HV-5162 Continuous Primary Containment Instrument Gas 1KL-HV-5172A Continuous Primary Containment Instrument Gas 1XL-HV-51728 Continuous Primary Containment Instrument Gas 1KP-HV-5834A Continuous Main Steam 1KP-HV-5835A Continuous Main Steam 1KP-HV-5836A Continuous ,
Main Steam 1XP-HV-5837A Continuous Main Steam ISK-HV-4953 Continuous ISK-HV-4957 Plant Leak Detection
~ Continuous Plant Leak Detection ISK-HV-4981 Continuous 1SK-HV-5018 Plant Leak Detection Continuous Plant Leak Detection HOPE CREEK 3/4 8-33
! ELECTRICAL POWER SYSTEMS 4 MOTOR OPERATED VALVES THERMAL OVERLOAD PROTECTION (Not Bypassed) M28 r t LIMITING CONDITION FOR OPERATION 3.8.4.4 The thermal overload protection of each valve shown in Table 3.8.4.4-1 shall be OPERABLE. i APPLICABILITY: Whenever the motor operated valve is required to be OPERABLE. ACTION: With the thermal overload protection for one or more of the above required i valves inoperable, continuously bypass the inoperable thermal overload within 8 hours; restore.-the inoperable thermal overload to OPERABLE status within 30 days or declare the affected valve (s) inoperable and apply the appropriate ACTION statement (s) for the affected system (s). i SURVEILLANCE REOUIREMENTS 4.8.4.4 The thermal overload protection for the above required valves shall be demonstrated OPERABLE at least once per 18 months and following maintenance on the motor starter by the performance of a CHANNEL CALIBRATION of a j representative sample of at least 25% of all thermal overloads for the above
- required valves.
i i i l-I \ 1 1 l HOPE CREEK 3/4 S-34 i-
5] TABLE 3.8.4.4-1 00N 28 ogg f MOTOR OPERATED VALVES THERMAL OVERLOAD PROTECTION 9YPASS DEVICE None or During VALVE NUMBER Manual Operation SYSTEM (S) AFFECTED 1AB-HV-3631A Manual Main Steam 1AB-HV-36318 Manual Main Steam 1AB-HV-3631C Mancal Main Steam 1AB-HV-36310 Manual Main Steam 1AB-HV-F071 Manual Main Steam 1AE-HV-F032A Manual Feedwater 1AE-HV-F0328 Manual Feedwater 1AE-HV-F039 Manual Feedwater 1AN-HV-2600 Manual Demineralized Water 0AP-HV-2072 Manual Condensate Storage & Transfer 1AP-HV-2073 Manual Condensate Storage & Transfer . 1BC-HV-F003A None Residual Heat Removal IBC-HV-F003B None Residual Heat Removal 1BC-HV-F004A Manual Residual Heat Removal 1BC-HV-F0048 Manual Residual Heat Removal 1BC-HV-F004C Manual Residual Heat Removal 1BC-HV-F0040 Manual Residual Heat Removal IBC-HV-F006A Manual Residual Heat Removal 1BC-HV-F006B Manual Residual Heat Removal 1BC-HV-F016A Manual Residual Heat Removal 1BC-HV-F016B Manual Residual Heat Removal 1BC-HV-F021A Manual Residual Heat Removal 1BC-HV-F0218 Manual Residual Heat Removal ~ IBC-HV-F047A Manual Residual Heat Removal 1BC-HV-F0478 Manual Residual Heat Removal 1BC-HV-F075 Manual Residual Heat Removal 1BC-HV-F103A Manual Residual Heat Removal 1BC-HV-F103B Manual Residual Heat Removal 1BC-HV-F104A Manual Residual Heat Removal 1BC-HV-F1048 Manual Residual Heat Removal 18C-HV-4420A Manual Residual Heat Removal 1BC-HV-4420B Manual Residual Heat Removal IBC-HV-4421 Manual Residual Heat Removal 1BC-HV-4439 Manual Residual Heat Removal 18E-HV-F001A Manual Reactor Core Spray 1BE-HV-F0018 Manual Reactor Core Spray 19E-HV-F001C Manual Reactor Core Spray 1BE-HV-F0010 Manual Reactor Core Spray IBF-HV-3800A Manual Control Rod Drive , 1BF-HV-38008 Manual Control Rod Drive IBF-HV-4005 Manual Control Rod Drive IBG-HV-F034 Manual Reactor Water Cleanup 1BG-HV-F035 Manual Reactor Water Cleanup 1BG-HV-3980 Manual Reactor Water Cleanup 1BH-HV-F006A Manual Standby Liquid Control HOPE CREEK 3/4 8-35
TABLE 3.8.4.4-1 (Continued) 4 /,. ,.b MOTOR OPERATED VALVES THERMAL OVERLOAD PROTECTION 'kMl28 $py BYPASS DEVICE None or During . VALVE NUMBER Manual Operation SYSTEM (S) AFICCTED 1BH-HV-F006B Manual Standby Liquid Control 1BJ-HV-4803 Manual High Pressure Coolant Injection 1BJ-HV-4804 Manual High Pressure Coolant Injection IBJ-HV-4865 Manual High Pressure Coolant Injection 1BJ-HV-4866 Manual High Pressure Coolant Injection OBN-HV-2069 Manual Refueling Water 1EA-HV-2197A Manual Station Service Water 1EA-HV-2197B Manual Station Service Water 1EA-HV-2197C Manual Station Service Water 1EA-HV-2197D Manual Station Service Water 1EA-HV-2203 Manual Station Service Water 1EA-HV-2204 Manual Station Service Water 1EA-HV-2207 Manual Station Service Water 1EA-HV-2234 Manual Station Service Water 1EA-HV-2236 Manual Station Service Water 1EA-HV-2238 Manual Station Service Water 1EA-HV-2225A Manual Station Service Water 1EA-HV-2225B Manual Station Service Water 1EA-HV-2225C Manual Station Service Water 1EA-HV-22250 Manual Station Service Water 1EA-HV-2346 Manual Station Service Water 1EA-HV-2356A Manual Station Service Water 1EA-HV-23568 Manual Station Service Water 1EA-HV-2357A Manual Station Service Water 1EA-HV-23578 Manual Station Service Water 1EA-HV-F073 Manual Station Service Water 1EC-HV-4647 Manual Fuel Pool Cooling 1EC-HV-4648 Manual Fuel Pool Cooling IEC-HV-4689A Manual Fuel Pool Cooling 1EC-HV-46898 Manual Fuel Pool Cooling 1ED-HV-2598 Manual Reactor Aux. Cooling 1ED-HV-2599 Manual Reactor Aux. Cooling 1EG-HV-2314A Manual Safety Auxiliaries Cooling 1EG-HV-23148 Manual Safety Auxiliaries Cooling 1EG-HV-2320A Manual Safety Auxiliaries Cooling 1EG-HV-2320B Manual Safety Auxiliaries Cooling 1EG-HV-2446 Manual Safety Auxiliaries Cooling IEG-HV-2447 Manual Safety Auxiliaries Cooling 1EG-HV-2452A Manual Safety Auxiliaries Cooling IEG-HV-2452B Manual Safety Auxiliaries cooling 1EG-HV-2491A Manual Safety Auxiliaries tooling 1EG-HV-24918 Manual Safety Auxiliaries Cooling 1EG-HV-2494A Manual Safety Auxiliaries Cooling HOPE CREEK 3/4 8-36
TABLE 3.8.4.4-1 (Continued) MOTOR OPERATE 0 VALVES THERMAL OVERLOAD PROTECTION 5 85 BYPASS DEVICE None or During VALVE NUMBER Manual Operatian SYSTEM (S) AFFECTED 1EG-HV-24948 Manual Safety Auxiliaries Cooling 1EG-HV-2496A Manual Safety Auxiliaries Cooling 1EC-HV-24968 Manual Safety Auxiliaries. Cooling 1EG-HV-2496C Manual Safety Auxiliaries Cooling IEG-HV-24960 Manual Safety Auxiliaries Cooling 1EG-HV-2512A Manual Safety Auxiliaries Cooling 1EG-HV-2512B Manual Safety Auxiliarias Cooling 1EG-HV-7921A Manual Safety Auxiliaries Cooling 1EG-HV-79218 Manual Safety Auxiliaries Cooling '- 1FC-HV-4282 Manual RCIC 1FC-HV-F060 Manual RCIC 1FC-HV-F059 Manual RCIC 1FO-HV-F071' Manual HPCI 1GH-HV-5543 Manual Radwaste Area Vent l 1GS-HV-5741A None Containment Atm Cont. 1GS-HV-57418 None Containment Atm Cont. 1HB-HV-5262 Manual Liquid Radwaste 1HB-HV-5275 Manual Liquid Radwaste 1HC-HV-5551 Manual Solid Radwaste 1KA-HV-7626- Manual Service Compressed Air 1KA-HV-7629 Manual Service Compressed Air 1KC-HV-3408M None Fire Protection 1KL-HV-5160A Manual Primary Containment Instrument
' Gas 1XL-HV-51608 Manual Primary Containment Instrument Gas 1XP-HV-5829A Manual Main Steam 1KP-HV-58298 Manual Main Steam
, 1KP-HV-58348 Manual Main Steam
- 1KP-HV-5835B Manual Main Steam il^
1KP-HV-5836B Manual Main Steam 1XP-HV-5837B Manual Main Steam
- s. $-
# 0 h
HOPE CREEK 3/4 8-37 '
a ELECTRICAL POWER SYSTEMS REACTOR PROTECTION SYSTEM ELECTRICAL POWER MONITORING M 2 8 1983 MMITING_CONDITTONFOROPERATION 3.8.4.4 Two RPS electric power monitoring channels for each inservice RPS MG set or alternate power supply shall be OPERABLE. APPLICABILITY: ~At all times. ACTION:
- a. With one RPS electric power monitoring channel for an inservice RPS MG set or alternate power supply inoperable, restore the inoperable power monitoring channel to OPERABLE status within 72 hours or remove the associated RPS MG set or alternate power supply from service.
- b. With both RPS electric power monitoring channels for an inservice RPS MG set or alternate power supply inoperable, restore at least one electric power monitoring channel to OPERABLE status within 30 minutes or remove the associated RPS MG set or alternate power supply from service.
SURVEILLANCE REQUIREMENTS 4.8.4.4 The above specified RPS electric power monitoring channels shall be determined OPERABLE:
- a. At least once per.6 months by performance of a CHANNEL FUNCTIONAL TEST, and
- b. At least once per 18 months by demonstrating the OPERABILITY of j~
over-voltage, under-voltage, and under-frequency protective instrumentation by performance of a C.IANNEL CALIBRATION including simulated autcmatic actuation of the protective relays, tripping l logic and output circuit breakers and verifying the following setpoints.. -
- 1. Over-voltage 1 (132) VAC,.
- 2. Under-voltage 3 (108) VAC,
- 3. Under-frequency 1 (57) Hz. ,.
l i l HOPE CREEK 3/4 8-38
r. 3/4.9 REFUELING OPERATIONS 3/4.9.1 REACTOR MODE SWITCH - ' i ~ LIMITING CONDITION FOR OPERATION JUN 2 8 1985 l 3.9.1 Refuel The reactor mode switch shall be OPERABLE and locked in the Shutdown or position. When the reactor made-switch is locked in the Refuel position:
- a. A control rod shall not be withdrawn unless the Refuel position' one-rod-out interlock is OPERABLE.
- b. CORE ALTERATIONS shall not be performed using equipment associated with a Refuel position interlock unless at least the following associ-ated Refuel position interlocks are OPERABLE for such equipment.
- 1. All rods in. ' . ,
- 2. Refuel pigtform position.
- 3. Refuel platform hoists fuel-loaded. '.
- 4. Fuel grapple position.
- 5. Service platform hoist fuel-loaded.
APPLICABILITY: OPERATIONAL CONDITION 5* # .
. ACTION: ,
a. With the reactor mode switch not locked in the Shutdown or Rdfdel position as specified, suspend CORE ALTERATIONS and lock the reactor ; mode switch in the Shutdown or Refuel position. ' I
- b. With the one-rod-out interlock inoperable, lock the reactor mode switch in the Shutdown position..
- c. With any of the above required Refue1~ position equipment interlocks inoperable, suspend CORE ALTERATIONS with, equipment associated with the inoperable Refuel position equipment interlock.
- See Special Test Exceptions 3.10.1 and 3.10.3.
# The reactor shall be maintained in OPERATIONAL CONDITION 5 wisenever fuel is in the reactor vessel with the vessel head closure' colts loss than fully tensioned or with the head removed.
M
/
t HOPE CREEK 3/4 9-1
--,,----w,--.,- - - - - ,- -, - , - - , - -- -- - - - .- ~ - - - .-. - - - - ~ . - - - - -
-w , ,,,, , n. - - . -
REFUELING OPERATIONS
)
SURVEILLANCE REQUIREMENTS ,,,,,,
'985
- 4. 9.1.1 The reactor mode switch shall be verified to be locked in the Shutdown or Refuel position as specified:
- a. Within 2 hours prior to:
- 1. Beginning CORE ALTERATIONS, and
- 2. Resuming CORE ALTERATIONS when the reactor mode switch has been unlocked.
- b. At least once per 12 hours.
4.9.1.2 Each of the above required reactor mode switch Refuel position interlocks
- shall be demonstrated OPERABLE by performance of a CHANNEL FUNCTIONAL TEST within 24 hours prior to the start of and at least once per-7 days during control rod withdrawal or CORE ALTERATIONS, as applicable.
4.9.1.3 .Each of the above required reactor mode switch Refuel position interlocks
- that is affected shall be demonstrated OPERABLE by performance of a CHANNEL FUNCTIONAL TEST prior to resuming control rod withdrawal or CORE ALTERATIONS, as applicable, following repair, maintenance or replacement of any component that could affect the Refuel position interlock.
The reactor mode switch may be placed in the Run or Startup/ Hot Standby position to test the switch interlock functions provided that all control rods are verified to remain fully inserted by a second licensed operator or other technically qualified member of the unit technical staff. l l l l HOPE CREEK 3/4 9-2 t
REFUELING OPERATIONS i 3/4.9.2 INSTRUMENTATION S&lN S g g LIMITING CONDITION FOR OPERATION 3.9.2' At least 2 source range monitor * (SRM) channels shall be OPERABLE and inserted to the normal operating level with:
- a. Continuous visual indication in the control room, b.
At least one refueling with audible indication in the control room and on the floor,
- c. One of the required SRM detectors located in the quadrant where CORE ALTERATIONS are being performed and the other required SRM detector located in an adjacent quadrant, and d.
The " shorting links" removed from the RPS cipcuitry prior to and i ' during the time any control rod is withdrawn and shutdown margin demonstrations are in progress. APPLICABILITY: OPERATIONAL CONDITION 5. ACTION: With the requirements of the above specification not satisfied, immediately suspend all operations involving CORE ALTERATIONS ** and insert all insertable control rods. SURVEILLANCE REQUIREMENTS 4.9.2 Each of the above required SRM channels shall be demonstrated OPERABLE by:
- a. At least once per 12 hours:
- 1. Performance of a CHANNEL CHECK,
- 2. Verifying the detectors are inserted to the normal operating level, and
- 3. During CORE ALTERATIONS, verifying that the detector of an OPERABLE SRM channel is located in the core quadrant where CORE ALTERATIONS are being performed and another is located in an adjacent quadrant.
"The use of special movable detectors during CORE ALTERATIONS in place of the normal SRM nuclear detectors is permissible as long as these special detectors e are connected to the normal SRM circuits. **Except movement of IRM, SRM or special movable detectors.
Not required for control rods removed per Specification 3.9.10.1 and 3.9.10.2. HOPE CREEK 3/4 9-3
REFUELING OPERATIONS , SURVEILLANCE REQUIREMENTS (Continued) N 28 FP-
- b. Performance of a CHANNEL FUNCTIONAL TEST:
- 1. WiLisin 24 siours prior to the start or CORE ALTERATIONS, and
- 2. At'least once per 7 days.
- c. Verifying that the channel. count rate is at least 3 cps:*
- 1. Prior to control rod withdrawal,
- 2. Prior to and at least once per 12 hours during CORE ALTERATIONS, and
- 3. At least once per 24 hours.
- d. Verifying, within 8 hours prior to and at least once per 12 hours during, that the RPS circuitry " shorting links" have been removed during:
- 1. The time any control rod is withdrawn, or
- 2. Shutdown margin demonstrations.
- Provided signal-to-noise is ,> L ,
Otherwise, 3 cps. HOPE CREEK 3/4 9-4
REFUELING OPERATIONS 3/4.9.3 CONTROL ROD POSITION JUN 28 uns LIMITING CONDITION FOR OPERATION 3.9.3 All control rods shall be inserted.* APPLICABILITY: OPERATIONAL CONDITION 5, during CORE ALTERATIONS.** ACTION: With all control rods not inserted, suspend all other CORE ALTERATIONS, except that one control rod may be withdrawn under control of the reactor mode switch Refuel position one-rod-out interlock. SURVEILLANCE REQUIREMENTS 4.9.3 All control rods shall be verified to be inserted, except as above specified:
- a. Within 2 hours prior to:
- 1. The start of CORE ALTERATIONS.
- 2. The withdrawal of one control rod under the control of the reactor mode switch Refuel position one-rod-out interlock.
- b. At least once per 12 hours.
- Except control rods removed per Specification 3.9.10.1 or 3.9.10.2.
C*See Special Test Exception 3.10.3. l HOPE CREEK 3/4 9-5
REFUELING OPERATIONS I,l!)i,I L 31$
=
3/4.9.4 DECAY TIME JUN 2 81985 LIMITING CONDITION FOR OPERATION 3 9.4 The reactor shall be suber:tical for at leasu 24 hours. APPLICABILITY: OPERATIONAL CONDITION 5, during movenent of irradiated fuel in the reactor pressure vessel. ACTION: With the reactor subcritical for less than 24 hours, suspend all operations involving movement of irradiated fuel in the reactor pressure vessel. SURVEILLANCE REQUIREMENTS 4.9.4 The reactor shall be determined to have been subcritical for at least 24 hours by verification of the date and time of subcriticality prior to movement of irradiated fuel in the reactor pressure vessel. i l l l l HOPE CREEK 3/4 9-6
REFUELING OPERATIONS j 3/4.9.5 COMMUNICATIONS ' JUN 2 81c25 LIMITING CONDITION FOR OPERATION 3.9.5 Direct refueling communication floor personnel. shall be maintained between the control room and APPLICABILITY: OPERATIONAL CONDITION 5, during CORE ALTERATIONS.*. ACTION: When-direct communication between the control room and refueling floor personnel cannot be maintained, immediately suspend CORE ALTERATIONS.* s SURVEILLANCE REQUIREMENTS 4.9.5 Direct communication between the control room and refueling floor personnel shall be demonstrated within one hour prior to the start of and at least once per 12 hours during CORE ALTERATIONS.*
*Except movement of incore instrumentation and control rods with their normal drive system.
HOPE CREEK 3/4 9-7
g 3 P-= REFUELING OPERATIONS Ul d j 3/4.9.6 REFUELING PLATFORM wD EE LIMITING CONDITION FOR OPERATION 3.9.G The refueliny platform snail be OPEfmDLE and used for handling fuel assemblies or control rods within the reactor pressure vessel. APPLICABILITY: During handling of fuel assemblies or control rods within the reactor pressure vessel. ACTION: With the requirements for refueling platform OPERABILITY not satisfied, suspend use of any inoperable refueling platform equipment from operations involving the handling of control rods and fuel assemblies >tthin the reactor pressure vessel after placing the load in a safe condition. SURVEILLANCE REOUIREMENTS 4.9.6 Each refueling platform crane or hoist used for handling of control rods or fuel assemblies within the reactor pressure vessel shall be demonstrated OPERABLE within 7 days prior to the start of such operations with that crane or hoist by:
- a. Demonstrating operation of the overload cutoff on the main hoist when the load exceeds 1200 1 50 pounds.
- b. Demonstrating operation of the overload cutoff on the frame mounted and monorail hoists when the load exceeds 1000 1 50 pounds.
l l c. Demonstrating operation of the uptravel mechanical stop on the frame i mounted and monorail hoists when uptravel brings the top of (active) fuel assembly to (8) feet below the (normal fuel storage pool) water level.
- d. Demonstrating operation of the downtravel mechanical cutoff on the main hoist when grapple hook down travel reaches 4 inches below fuel assembly handle.
- e. Demonstrating operation of the slack cable cutoff on the main hoist when the load is less than 50 10 pounds.
- f. Demonstrating operation of the loaded interlock on the main hcist when the load exceeds 485 ! 50 pounds.
- g. Demonstrating operation of the r=dundant loaded interlock on the main hoist when the load exceeds 550 .: 50 pounds.
HOPE CREEK 3/4 9-8
g REFUELING OPERATIONS 3/4.9.7 CRANE TRAVEL-SPENT FUEL STORAGE POOL t'^e JUN 2 8 LIMITING CONDITION FOR OPERATION 3.9.7 Loads in excess of (1103) pounds shall be prohibited from travel over fuel assemblies in the spent fuel storage pool racks. APPLICABILITY: With fuel assemblies in the spent fuel storage pool racks. ACTION: With the requirements of the above specification not satisfied, place the crane load in a safe condition. The provisions of Specification 3.0.3 are not . applicable. SURVEILLANCE REQUIREMENTS 4.9.7 Crane interlocks and physical stops which prevent crane travel with loads in excess of (1100) pounds over fuel assemblies in the spent fuel storage pool racks shall be demonstrated OPERABLE within 7 days prior to and at least once per 7 days during crane operation. HOPE CREEK 3/4 9-9 i I
REFUELING OPERATIONS
- =
AJ 3/4.9.8 WATER LEVEL - REACTOR VESSEL JUN 2 E 1 LIMITING CONDITION FOR OPERATION 3.9.8 At least 27 feet 2 inches of water shall be maintained over the top of the reactor pressure vessel flange. APPLICABILITY: During handling of fuel assemblies or control rods within the reactor pressure vessel while in OPERATIONAL CONDITION 5 when the fuel assemblies being handled are irradiated or the fuel assemblies seated within the reactor vessel are irradiated. ACTION: ' With the requirements of the above specification not satisfied, suspend all operations involving handling of fuel assemblies or control rods within the reactor pressure vessel after placing all fuel assemblies and control rods in a safe condition. l SURVEILLANCE REOUIREMENTS 4.9.8 The reactor vessel water level shall be determined to be at least its minimum required depth within 2 hours prior to the start of and at least once per 24 hours during handling of fuel assemblies or control rods within the ( reactor pressure vessel. HOPE CREEK 3/4 9-10
- f REFUELING OPERATIONS b3 3/4.9.9 WATER LEVEL - SPENT FUEL STORAGE POOL 'JtjN 2 81985 LIMITING CONDITION FOR OPERATION 3.9.9 At least 23 feet of water shall be maintained over the top of irradiated fuei assemblies seated in tne spent fuel storage pool racks.
APPLICABILITY: Whenever irradiated fued assemblies are in the spent fuel storage pool. ACTION: With the requirements of the above specification not satisfied, suspend all movement of fuel assemblies and crane operations with loads in the spent fuel storage pool area after placing the fuel assemblies and crane load in a safe condition. The provisions of Specification 3.0.3 are not applicable. SURVEILLANCE REQUIREMENTS 4.9.9 The water level in the spent fuel storage pool shall be determined to be at least at its minimum required depth at least once per 7 days. HOPE CREEK 3/4 9-11
REFUELING OPERATIONS V} 3/4.9.10 CONTROL ROD REMOVAL SINGLE CONTROL ROD REMOVAL LIMITING CONDITION FOR OPERATION 3.9.10.1 One control rod and/or the associated control rod drive mechanism may be removed from the core and/or reactor pressure vessel provided that at least the following requirements are satisfied until a control rod and associ-ated control rod drive mechanism are reinstalled and the control rod is fully inserted in the core.
- a. The reactor mode switch is OPERABLE and locked in the Shutdown position or in the Refuel position per Table 1.2 and Specification 3.9.1.
- b. The source range monitors (SRM) are OPERABLE per Specification 3.9.2.
- c. The SHUTDOWN MARGIN requirements of Specification 3.1.1 are satisfied, except that the control rod selected to be removed;
- 1. May be assumed to be the highest worth control rod required to be assumed to be fully withdrawn by the SHUTDOWN MARGIN test, and
- 2. Need not be assumed to be immovable or untrippable.
- d. All other control rods in a five-by-five array centered on the control rod being removed are inserted and electrically or hydraulically disarmed or the four fuel assemblies surrounding the control rod or control rod drive mechanism to be removed from the core and/or reactor vessel are removed from the core cell.
- e. All other control rods are inserted.
APPLICABILITY: OPERATIONAL CONDITIONS 4 and 5. ACTION: With the requirements of the above specification not satisfied, suspend removal of the control rod and/or associated control rod drive mechanism from the core and/or reactor pressure vessel and initiate action to satisfy the above requirements. HOPE CREEK 3/4 9-12
REFUELING OPERATIONS Jt;N 2 8 1985 SURVEILLANCE REQUIREMENTS 4.9.10.1 Within 4 hours prior to the start c# remc W of a contial red and/cr tne associatea cuntrol rod drive mechanism from the core and/or reactor pressure vessel and at least once per 24 hours thereafter until a control rod and associ-ated in thecontrol core, rod drive verify mecnanism are reinstalled and the control rod is inserted that:
- a. The reactor mode switch is OPERABLE per Surveillance Requirement 4.3.1.1 or 4.9.1.2, as applicable, and locked in the Shutdown position or in the Refuel position with the "one rod out" Refuel position interlock OPERABLE per Specification 3.9.1.
- b. The SRM channels are OPERABLE per Specification 3.9.2.
- c. The SHUTOOWN MfRGIN requirements of Specification 3.1.1 are satisfied per Specification 3.9.10.1.c.
- d. All other control rods in a five-by-five array centered on the control rod being removed are inserted and electrically or hydraulically " -
disarmed or the four fuel assemblies surrounding the control roa or control rod drive mechanism to be removed from the core and/or reactor vessel are removed from the core cell.
- e. All other control rods are inserted.
HOPE CREEK 3/4 9-13
Jfull{3 f5 4 REFUELING OPERATIONS JUN 2 e MULTIPLE CONTROL ROD REMOVAL LIMIllNG CONUITION FOR OPERATION 3.9.10.2 Any number of control rods and/or control rod drive mechanisms may be removed from the core and/or reactor pressure vessel provided that at least the following requirements are satisfied until all control rods and control rod drive mechanisms are reinstalled and all control rods are inserted in the Core,
- a. The reactor mode switch is OPERABLE and locked in the Shutdown position or in the Refuel position per Specification 3.9.1, except that the Refuel position "one-rod-out" interlock may be bypassed, as required, for those control rods and/or control rod drive mechanisms to be removed, after the fuel assemblies have been removed as specified below.
- b. The source range monitors (SRM) are OPERABLE per Specification 3.9.2.
- c. The SHUTDOWN MARGIN requirements of Specification 3.1.1 are satisfied.
- d. All other control rods are either inserted or have the surrounding four fuel assemblies removed from the core cell.
- e. The four fuel assemblies surrounding each control rod or control rod drive mechanism to be removed from the core and/or reactor vessel are removed from the core cell.
APPLICABILITY: OPERATIONAL CONDITION 5. ACTION: With the requirements of the above specification not satisfied, suspend removal of control rods and/or control rod drive mechanisms from the core and/or reactor pressure vessel and initiate action to satisfy the above requirements. l .- i \ e e t l HOPE CREEK 3/4 9-14 l
$ REFUELING OPERATIONS j JUN 2 8 Eco SURVEILLANCE REQUIREMENTS 4.9.10.2.1 Within 4 hours crior to tha st et nf ema"=1 of contcol rods and/ .
control rod drive mechanisms from the core and/or reactor pressure vessel and at least once per 24 hours thereafter until all control rods and control rod drive mechanisms are reinstalled and all control rods are inserted in the core, verify that:
- a. The reactor made switch is OPERABLE per Surveillance Requirement 4.3.1.1 or 4.9.1.2, as applicable, and locked in the Shutdown position or in the Refuel position per Specification 3.9.1.
- b. The SRM channels are OPERABLE per Specification 3.9.2.
- c. The SHUTDOWN MARGIN requirements of Specification 3.1.1 are satisfied.
- d. All other control rods are either inserted or have the surrounding four fuel assemblies removed from the core cell.
- e. The four fuel assemblies surrounding each control rod and/or control rod drive mechanism to be removed from the core and/or reactor vessel are removed from the core cell.
4.9.10.2.2 Following replacement of all control rods and/or control rod drive mechanisms removed in accordance with this specification, perform a functional test of the "one-rod-out" Refuel position interlock, if this function had been bypassed. e OI I 1 1 HOPE CREEK 3/4 9-15 mm - - , -,. - -+%- * .
-4 .------ --yg --. -w-w-i.*r
REFUELING OPERATIONS 3/4.9.11 RESIOUAL HEAT REMOVAL AND COOLANT CIRCULATION HIGH WATER LEVEL LIMITING CONDITION FOR OPERATION 3.9.11.1 At least one shutdown cooling mode loop of the residual heat removal (RHR) system shall be OPERABLE and in operation
- with at least:
- a. One OPERABLE RHR pump, and
- b. One OPERABLE RHR heat exchanger.
APPLICABILITY: OPERATIONAL CONDITION 5, when irradiated fuel is in the reactor vessel and the water level is greater than or equal to 22 feet 2 inches above the top of the reactor pressure vessel flange. ACTION:
- a. With no RHR shutdown cooling mode loop OPERABLE, within one hour and at least once per 24 hours thereafter, demonstrate the operability of at least one alternate method capable of decay heat removal. Otherwise, suspend all operations involving an increase in the reactor decay heat load and establish SECONDARY CONTAINMENT INTEGRITY within 4 hours.
- b. With no RHR shutdown cooling mode loop in operation, within one hour establish reactor coolant circulation by an alternate method and monitor reactor coolant temperature at least once per hour.
SURVEILLANCE RE0VIREMENTS 4.9.11.1 At least one shutdown cooling mode loop of the residual heat removal system or alternate method shall be verified to be in operation and circulating reactor coolant at least once per 12 hours. The shutdown cooling pump may be removed from operation for up to 2 hours > per 8-hour period. HOPE CREEK 3/4 9-16
REFUELING OPERATIONS LOW WATER LEVEL d LD E l /@{ LIMITING CONDITION FOR OPERATION 3.9.11.2 Two shutdown cooling mode loops of the residual heat removal (RHR) system shall be OPERABLE and at least one loop shall be in operation,* with each loop consisting of at least:
- a. One OPERABLE RHR pump, and
- b. One OPERABLE RHR heat exchanger.
APPLICABILITY: OPERATIONAL CONDITION 5, when irradiated fuel is in the reactor vessel and the water level is less than 22 feet 2 inches above the top of the reactor pressure vessel flange. ACTION:
- a. With less than the above required shutdown cooling mode loops of the RHR system OPERABLE, within one hour and at least once per 24 hours there-
' after, demonstrate the operability of at least one alternate method =
capable of decay heat removal for each inoperable RHR shutdown cooling mode loop.
- b. With no RHR shutdown cooling mode loop in operation, within one hour establish reactor coolant circulation by an alternate method and monitor reactor coolant temperature at least once per hour.
SURVEILLANCE REOUIREMENTS 4.9.11.2 At least one shutdown cooling mode loop of the residual heat removal system or alternate method shall be verified to be in operation and circulating reactor coolant at least once per 12 hours.
"The shutdown cooling pump may be removed from operation for up to 2 hours per 8-hour period.
HOPE CREEK 3/4 9-17
3/4.10 SPECIAL TEST EXCEPTIONS 3/4.10.1 PRIMARY CONTAINMENT INTEGRITY JUN 2 81985 LIMIT 1NG CONDITION FOR OPENTTON 3.10.1 The provisions of Specifications 3.6.1.1, 3.6.1.3 and 3.9.1 and Table 1.2 may be suspended to permit the reactor pressure vessel closure head and the drywell head to be removed and the primary containment air lock doors to be open when the reactor mode switch is in the Startup position during low power PHYSICS TESTS with THERMAL POWER less than 1% of RATED THERMAL POWER and reactor coolant temperature less than 200 F. APPLICABILITY: OPERATIONAL CONDITION 2, during low power PHYSICS TESTS. ACTION: With THERMAL POWER greater than or equal to 1% of RATED THERMAL POWER or with the reactor coolant temperature greater than or equal to 200 F, immediately place the reactor mode switch in the Shutdown position. SURVEILLANCE REQUIREMENTS 4.10.1 The THERMAL POWER and reactor coolant temperature shall be verified to be within the limits at least once per hour during low power PHYSICS TESTS. HOPE CREEK 3/4 10-1
I SPECIAL TEST EXCEPTIONS 3/4.10.2 ROD SEOUENCE CONTROL SYSTEM ! LIMITING CONDITION FOR OPERATION 3.10.2 The sequence constraints imposed on control rod groups by the rod sequence control system (RSCS) per Specification 3.1.4.2 may be suspended by means of bypass switches for the following tests provided that the rod worth minimizer is OPERABLE per Specification 3.1.4.1:
- a. Shutdown margin demonstrations, Specification 4.1.1.
- b. Control rod scram, Specification 4.1.3.2.
- c. Control rod friction measurements.
- d. Startup Test Program with the THERMAL POWER less than 20% of RATED THERMAL POWER.
APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. ACTION: With the requirements of the above specification not satisfied, verify that the RSCS is OPERABLE per Specification 3.1.4.2. 1 SURVEILLANCE REQUIREMENTS
- 4.10.2 When the sequence constraints imposed by the RSCS are bypassed, verify:
l a. Within 8 hours pria- to bypassing any sequence constraints and at least once per 12 hours anile any set ance constraint is bypassed:
- 1. That the rod worth minimizer is OPERABLE per Specification 3.1.4.1,
- 2. That movement of the control rods frcm 75% ROD DENSITY to the RSCS low power setpoint is limited to the approved control rod withdrawal sequence during scram and friction tests.
- b. Conformance with this specification and test procedures by a second ,
licensed operator or other technically qualified member of the unit technical staff. ( = l t HOPE CREEK 3/4 10-2
SPECIAL TEST EXCEPTIONS 3/4.10.3 SHUTDOWN MARGIN DEMONSTRATIONS 3N 2 81985 LIMITING CONDITTON FOR OPERATIO.*.* 3.10.3 The provisions of Specification 3.9.1, Specification 3.9.3 and Table 1.2 may be suspended to permit the reactor mode switch to be in the Startup position and to allow more than one control rud to be withdrawn for shutdown margin demonstration, provided that at least the following requirements are satisfied.
- a. The source range monitors are OPERABLE with the RPS circuitry " shorting links" removed per Specification 3.9.2.
- b. The rod worth tirinimizer is OPERABLE per Specification 3.1.4.1 and is programmed for the shutdown margin demonstration, or conformance with the shutdown margin demonstration procedure is verified by a second licensed operator or other technically qualified member of the unit technical staff. ,
- c. The " rod-out-notch override" control shall not be used during out-of-sequence movement of the control rods. '
- d. No other CORE ALTERATIONS are in progress.
APPLICABILITY: OPERATIONAL CONDITION 5, during shutdown margin demonstrations. ACTION: With the requirements of the above specification not satisfied, immediately place the reactor mode switch in the Shutdown or Refuel position. SURVEILLANCE REQUIREMENTS 4.10.3 Within 30 minutes prior to and at least once per 12 hours during the performance of a shutdown margin demonstration, verify that;
- a. The source range monitors are OPERABLE per Specification 3.9.2,
- b. The rod worth minimizer is OPERABLE with the required program per Specification 3.1.4.1 or a second licensed operator or other techni-cally qualified member of the unit technical staff is present and .
verifies compliance with the shutdown demonstration procedures, and
- c. No other CORE ALTERATIONS are in progress. I HOPE CREEK 3/4 10-3
SPECIAL TEST EXCEPTIONS ' [1]}1l-l11 u'1 3/4.10.4 RECIRCULATION LOOPS
~ JRD( 2 8 102C LIMITING CONDITION FOR OPERATION 3.10.4 The requirements of Specifications 3.4.1.1 and 3.4.1.3 that recirculation loops be in operation with matched pump speed may be suspended for up to 24 hours for the performance of:
- a. PHYSICS TESTS, provided that THERMAL POWER does not exceed'5% of RATED THERMAL POWER, or
- b. The Startup Test Program.
APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2, during PHYSICS TESTS and the Startup Test Program. ACTION:
- a. With the above specified time limit exceeded, insert all control rods.
- b. With the above specified. THERMAL POWER limit exceeded during PHYSICS TESTS, immediately place the reactor mode switch in the Shutdown position.
SURVEILLANCE REOUIREMENTS 4.10.4.1 The time during which the above specified requirement has been suspended shall be verified to be less than 24 hours at least once per hour during PHYSICS TESTS and the Startup Test Program. 4.10.4.2 THERMAL POWER shall be determined to be less than 5% of RATED THERMAL POWER at least once per hour during PHYSICS TESTS. HOP 5 CREEK 3/4 10-4
SPECIAL TEST EXCEPTIONS DMFT 3/4.10.5 OXYGEN CONCENTRATION LIMITING CONDITION FOR OPERATION 3.10.5 The provisions of Specification 3.6.6.4 may be suspended during the performance of the Startup Test Program until 6 months after initial criticality. APPLICABILITY: OPERATIONAL CONDITION 1. ACTION With the requirements of the above specification not satisfied, be in at least STARTUP within 6 hours. SURVEILLANCE REQUIREMENTS 4.10.5 The number of months since initial criticality shall be verified to be less than or equal to 6 months at least once per 31 days,during the Startup Test Program. HOPE CREEK 3/4 10-5
SPECIAL TEST EXCEPTIONS ;# $ 3/4.10.6 TRAINING STARTUPS JW 2 81985 LIMITING CONDITION FOR OPERATION 3.10.6 The provisions of Specification 3.5.1 may be suspended to permit one RHR subsystem to be aligned in the shutdown cooling mode during training startups provided that the reactor vessel is not pressurized THERMAL POWER is less than or equal to 1% of RATED THERMAL POWER and reactor coolant temperature is less than 200 F. APPLICABILITY: OPERATIONAL CONDITION 2, during training startups. ACTION: With the requirements of the above specification not satisfied, immediately place the reactor mode switch in the Shutdown position. SURVEILLANCE REQUIREMENTS 4.10.6 The reactor vessel shall be verified to be unpressurized and the THERMAL POWER and reactor coolant temperature shall be verified to be within the limits at least once per hour during training startups. t
. HOPE CREEK 3/4 10-6
,, ?
9 i I 3/4.11 RADIOACTIVE EFFLUENTS Aj h 3/4.11.1 LIQUID EFFLUENTS Jty 2 3 gpg CONCENTRATION LIMITING CONDITION FOR OPERATION 3.11.1.1 The concentration c.' radioactive material releaseo in liquid effluents to UNRESTRICTED AREAS (see Figure 5.1.3-1) shall be limited to the concentra-tions specified in 10 CFR Part 20, Appendix B, Table II, Column 2 for radio-nuclides other than dissolved or entrained noble gases. For dissolved or entrained noble gases, the concentration shall be limited to 2 x 10 4 microcuries/ml total activity. APPLICABILITY: At all times. ACTION: With the concentration of radioactive material released in liquid effluents to UNRESTRICTED ~ AREAS exceeding the above limits, immediately restore the concentration to within the above limits. 4 SURVEILLANCE REQUIREMENTS 4.11.1.1.1 Radioactive liquid wastes shall be sampled and analyzed according to the sampling and analysis program of Table 4.11.1.1.1-1. ( 4.11.1.1.2 The results of the radioactivity analyses shall be used in accordance with the methodology and parameters in the ODCM to assure that the concentrations at the point of release are maintained within the limits of Specification 3.11.1.1. t 9 HOPE CREEK 3/4 11-1 .
TABLE 4.11.1.1.1-1 Jd RADIOACTIVE LIOUID WASTE SAMPLING AND ANALYSIS PROGRA Lower Limit Minimum Liquid Release Sampling Analysis Type of Activity ofDetect{on Typ. Frequency Frequency (L'0) Analysis (pCi/ml) A. Batch Wgste P P Release Each Batch Each Batch Principa 5x10
-7 Sample Emitters} Gamma Tanks (3)
I-131 1x10
-6 P M Dissolved and 1x10
-5 One Batch /M Entrained Gases (Gamma Emitters)
. _ . . . . ._ P M H-3 1x10
-5 Each Batch Composite d
,7 Gross Alpha 1x10 P Q Sr-89, Sr-90 5x10
- Each Batch Composite d Fe-55 1x10
-6 B. Continuogs M 5x10
-7 Releases d Principa} Gamma
, Composite Emitters General Service NA Water System -6 (GSW) (If I-131 1x10 ! Contaminated) W -5 M Dissolved and 1x10 Grab Sample Entrained Gases (Gamma Emi.tters) H-3 1x10
-5 NA Composi e d Gross Alpha 1x10' Q Sr-89, Sr-90 5x10' l
NA Camposite d Fe-55 1x10
-6 l
l HOPE CREEK 3/4 11-2 i
s TABLE 4.11.1.1.1-1 (Continued) . l TABLE NOTATION AN 2 8 ;ggg a The LLD is defined, for purposes of these specifications, as the smallest concentration of radioactive material in a sample that will yield a net count, above system background, that will be detected with 95% necbability witt, voly 5% probauiiity of falsely concluding that a blank observation represents a "real" signal. For a particular measurement system, which may include radiochemical separation: 4' $ D LLD = E V 2.22 x 108 Y exp (-Mt) Where: LLD is the "a prior 3" lower limit of detection as defined above, as microcur.ies-per unit mass or volume, s is the standard deviation of the background counting rate or of t.e counting rate of a blank sample as appropriate, as courts per % minute, E is the counting efficiency, as counts per disintegration, ' V is the sample size in units of mass or volume, 2.22 x 108 is the number of disintegrations per minute per microcurie, Y is the fractional radiochemical yield, when applicable, A is t'he radioactive decay constant for the particular radionuclide (sec 1), and' at for plant effluents is the elapsed time between the midpoint of sample collection and~ time of counting (sec). Typical values of E, V, Y, and at should be used in the calculation. It should be recognized that the LLD is defined as'an a_ priori (before the fact) limit representing the capability of a measurement system and not as an a posteriori (after the fact) limit for a particular measurement. b A batch release is the discharge of liquid wastes of a discrete volume. Prior to sampling for analyses, each batch shall be isolated, and then thoroughly mixed by a method described in the ODCM to assure representative sampling. . HOPE CREEK 3/4 11-3
r TABLE 4.11.1.1.1-1 (Continued) w I a TABLE NOTATION 28 1965 c The principal gamma emitters for which the LLO specification applies exclusively are: Mn-54, Fe-59, Co-58, Co-60, Zn-65, Mo-99, Cs-134, Cs-137, and Ce-141. Ce-144 shall also be measured, but with an LLD of 5 x 10 8 This does not mean that only these nuclides are to be considered. Other pe-s i. hat are it:..ti f *Me, tsgt.t;ier with tnose of tne above nuclides, shall also be analyzed and reported in the Semiannual Radioactive Ef fli'ent Release Report pursuant to Cpecification 6.9.1.d. d A composite sample is one in which the quantity of liquid samples is proportional to the quantity of liquid waste discharged and in which the method of sampling employed results in a specimen that is representative of the liquids released.
'A continuous release is the discharge of liquid wastes of a nondiscrete volume; e.g. , from a volume of a sjstem that has an input flow during the continuous release. ,
fTo be.repie'seiftative of the quantities and concentrations of radioactive , materials in liquid effluents, samples shall be collected continuously in proportion to the rate of flow of the effluent stream. Prior to analyses, all samples taken for the composite shall be thoroughly mixed in order for the composite sample to be representative of the effluent release. i HOPE CREEK 3/4 11-4
RADIOACTIVE EFFLUENTS DOSE JUN 2 8 7985 LIMITING CONDITION FOR OPERATION 3.11.1.2 The do:,e or dose commitment to a MEMBER OF THE PUBLIC ~ from radio-active materials in liquid effluents released, from each reactor unit, to UNRESTRICTED AREAS (see Figure 5.1.3-1) shall be limited:
- a. During any calendar quarter to less than or equal to 1.5 mrems to the total body and to less than or equal to 5 mrems to any organ, and
- b. During any calendar year to less than or equal to 3 mrems to the total body and to less than or equal to 10 mrems to any organ.
APPLICABILITY: At all times. ACTION: a. Wiih the~ calculated dose from the release of radioactive materials in liquid effluents exceeding any of the above limits, prepare and submit to the Commission within 30 days, pursuant to Specifica-tion 6.9.2, a Special Report that identifies the cause(s) for exceeding the limit (s) and defines the corrective actions that have been taken to reduce the releases and the proposed corrective actions to be taken to assure that subsequent releases will be in compliance with the above limits.
- b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.
SURVEILLANCE REOUIREMENTS 4.11.1.2 Cumulative dose contributions from liquid effluents for the current calendar quarter and the current calendar year shall be determined in accordance with the methodology and parameters in the ODCM at least once per 31 days. HOPE CREEK 3/4 11-5
4
. RADIOACTIVE EFFLUENTS .
LXQUID WASTE TREATMENT w '- I' LIMITING CONDITION FOR OPERATION 3.11.1.3 ine siquid c.Uwaste treatment system shall be OPERABLE and appropriate portions of the system shall be used to reduce the radicactive materials in liquid wasces pitr i.o their discharge when the projected doses due to the liquid effluent, from each reactor unit, to UNRESTRICTED AREAS (see Figure 5.1.3-1) would exceed 0.06 mrem to the total body or 0.2 mrem to any organ in any 31-day period. , APPLICABILITY: At all times. ' ACTION: 7
- a. With radioactive liquid waste being discharged and in excess of the j above limits and any portion of the liquid radwaste treatment system ;
not.in operation, prepare and submit to the Commission within 30 days pursuant to Specification 6.9.2 a Specihl Report that includes the following information:
- 1. Explanation of why liquid radwaste was being discharged without complete treatment, identification of any inoperable equipment or subsystems, and the reason for the inoperability, '
- 2. Action (s) taken to restore the inoperable equipment to OPERABLE status, and '
l
- 3. Summary description of I: tion (s) taken to prevent a recurrence. ~ ,
- b. TheprovisionsofSpecificatfons3.0.3and3.0.4arenotapplicable.
SURVEILLANCE REQUIREMENTS 4.11.1.3.1 Doses due to liquid releases from each reactor unit to UNR STRICTED AREAS shall be projected at least once per 31 days in accordance with the , methodology and paranieters in th'e ODCM.
+ -
4.11.1.3.2 The installed liquid.radvaste treatment system shall be demonstrated OPERABLE by meeting Specifications 3.11.1.1 and 3.11.1.2.
. r 4
e
/ a
~
\' .
HOPE CREEK 3/4 11-6 ' s. I
= RADIOACTIVE EFFLUENTS LIQUID HOLOUP TANKS '" LIMITING CONDITION FOR OPERATION 3.11.1.4 The ,.:ntity of rad' ac. .e ...aterial contained in any outsioe temporary tank shall be limited to less than or equal to 10 curies, excluding tritium and dissolved or entrained ..uble gases. APPLICABILITY: At all times. ACTION:
- a. With the quantity of radioactive material in any of the above tanks exceeding the above limit, immediately suspend all additions of radioactive material to the tank, within 48 hours reduce the tank contents to within the limit, and describe the events leading to this condition in the next Semiannual Radioactive Effluent Release Report, pursuant to Specification 6.9.1.7.
- b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.
SURVEILLANCE REQUIREMENTS 4.11.1.4 The quantity of radioactive material contained in each of the above tanks shall be determined to be within the above limit by analyzing a repre-sentative sample of the tank's contents at least once per 7 days when radio-active materials are being added to the tank. HOPE CREEK 3/4 11-7
RADIOACTIVE EFFLUENTS Mh AJ 2'a l 3/4.11.2 GASEOUS EFFLUENTS DOSE RATE JUN 2 8 ;385 LIMITING CONDITION FOR OPERATION 3.11.2.1 The dose rate due to radioactive materials released in gaseous effluents from the site to areas at and beyond the SITE BOUNDARY (see Figure 5.1.3-1) shall be limited to the following:
- a. For noble gases: Less than or equal to 500 mrems/yr to the total body and less than or equal to 3000 mrems/yr to the skin, and
- b. For iodine-131, iodine-133, tritium, and for all radionuclides in particulate form with half-lives greater than 8 days: Less than or equal to 1500 mrems/yr to any organ.
APPLICABILITY:- At-ell times. ACTION: With the dose rate (s) exceeding the above limits, immediately restore the release rate to within the above limit (s). SURVEILLANCE REQUIREMENTS 4.11.2.1.1 The dose rate due to noble gases in gaseous effluents shall be determined to be within the above limits in accordance with the methodology and parameters in the ODCM. 4.11.2.1.2 The dose rate due to iodine-131', iodine-133, tritium, and all radio-nuclides in particulate form with half-lives greater than 8 days in gaseous effluents shall be determined to be within the above limits in accordance with the methodology and parameters in the ODCM b:, ataining representative samples and perfcrming analyses in accordance with ).ta ;ampling and analysis program specified in Table 4.11.2.1.2-1. HOPE CREEK 3/4 11-8
-____=________________________-_____________________
TABLE 4.11.2.1.2-1 RADI0 ACTIVE GASE0US WASTE SAMPLING AND ANALYSIS PROGRAM n
,y Minimum Lower Limit of p Sampling Analysis Type of Detection (LLD),
Gaseous Release Type Frequency Frequency Activity Analysis (mci /ml) A. Containment PURGE Eac PURGE (3) Each PURGE (3) Princip 1 Gamma Emitters (2) 1x10 Grab Sample M H-3 (oxide) 1x10 B. North Plant Vent M I )'I4) M(3) Principal Gamma Emitters (2) 1x10'4 South Plant Vent Grab Sample H-3 (oxide) 1x to
-6 C. All Release Types Continuous (5) y(6) I-131 1x10
-12 ds listed in A Charcoal and B above. Sample Continuous (5) y(6) Principal Gamma Emitters (2) 1x10
-11 Particulate Sample Continuous (5) M Gross Alpha 1x',0
-11 R
Composite Particulate _, Sample b Continuous (b) Q Sr-89, Sr-90 1x10
~11 Composite Particulate Sample Continuous Ib) Noble Gas Noble Gases 1x10
-6 Monitor Gross Beta or Gamma 1
/
l b "r;%U
. E , ;;;,
2 %
,j.
m
TABLE 4.11.2.1.2-1 (Continued) {I A{ a TABLE NOTATION gg (1)The LLD is defined, for purposes of these specifications, as.the smallest concentration of radioactive material in a sample that will yield a net count, above system background, that will be detected with 95% probability
? P c.'ly ".S. prcb:bilitj f C::b .:.a.:cNding that a blank ubservation represents a "real" signal.
For a pt.rticular measurement system, which may include radiochemical separation: 4* 8 b LLD = E V 2.22 x 108 Y exp (-Mt) Where: LLD is the "a priori" lower limit of detection as defined above, as microcuries per unit mass or volume, s is th standard deviation of the background counting rate or of tMe counting rate of a blank sample as appropriate, as counts per minute, E is the counting efficiency, as counts per disintegration, V is the sample size in units of mass or volume, 2.22 x 108 is the number of disintegrations per minute per microcurie, Y is the fractional radiochemical yield, when applicable, A is the radioactive decay constant for the particular radionuclide l (sec 1), and l l at for plant effluents is the elapsed time between the midpoint of ! sample collection and time of counting (sec). Typical values of E, V, Y, and at should be used in the calculation. 1 It should be recogni:ed that the LLD is defined as an a priori (before the i fact) limit representing the capability of a measurement system and not as l an a posteriori (after the fact) limit for a particular measurement. I l HOPE CREEK 3/4 13-10 L
I TABLE 4.11.2.1.2-1 (Continued) TABLE NOTATIONS J[JN 2 8 to85 (2)The principal are the gamma following emitters for which the LLD specification applies exclusively radionuclides: Kr-87, Kr-88, Xe-133, Xe-133m, Xe-135, and Xe-138 in noble gas releases and Mn-54, Fe-59, Co-58, Co-60, Zn-65, Mo-99, 1-131, Cs-134, Cs-137, Ce-141 and Ce-144 in iodine and particulate releases. This list does not me e that erly the c n'clidos are b be uns:A md. Other gamma peaks that are identifiable, together with those of the above nuclides, shall also be analyzed and reported in the Scriannital Radioactive Effluent Release Report pursuant to Specification 6.9.1.8. (3) Sampling and analysis shall also be performed following shutdown, startup, or a THERMAL POWER change exceeding 15% of RATED THERMAL POWER within a 1-hour period. This requirement does not apply if (1) analysis shows that the DOSE EQUIVALENT I-131 concentration in the primary coolant has not increased more than a factor of 3; and (2) the noble gas monitor shows that effluent activity has not increased more than a factor of 3. (4) Tritium grab samples shall be taken at least once per 7 days from the ventilation exhaust from the spent fuel pool area, whenever spent fuel is in the spent fuel pool. (5)The ratio of the sample flow rate to the sampled stream flow rate shall be known for the time period covered by each dose or dose rate calculation made in accordance with Specifications 3.11.2.1, 3.11.2.2, and 3.11.2.3. (6) Samples shall be changed at least once per 7 days and analyses shall be completed within 48 hours after changing, or after removal from sampler. Sampling shall also be performed at least once per 24 hours for at least 7 days following each shutdown, startup or THERMAL POWER change exceeding 15% of RATED THERMAL POWER in 1 hour and analyses shall be completed within 48 hours of changing. When samples collected for 24 hours are analyzed, the corresponding LLDs may be increased by a factor of 10. This requirement does not apply if (1) analysis shows that the DOSE EQUIVALENT I-131 concentration in the primary coolant has not increased more than a factor of 3; and (2) the noble gas monitor shows that effluent activity has not increased more than a factor of 3. HOPE CREEK 3/4 11-11
RADIOACTIVE EFFLUENTS . DOSE - NOBLE GASES JUN 2 8 1985 LIMITING CONDITION FOR OPERATION 3.11.z.2 ine air dose due to noble gases released in gaseous effluents, from each reactor unit, to areas at and beyond the SITE B0UNDARY (see Figure 5.1.3-1) shall be limited to the following:
- a. During any calendar quartt a: Less than or equal to 5 mrads for gamma radiation and less than or equal to 10 mrads for beta radiation and,
- b. During any calendar year: Less than or equal to 10 mrads for gamma radiation and less than or equal to 20 mrads for beta radiation.
APPLICABILITY: At all times. ACTION
- a. With the calculated air dose from radioactive noble gases in gaseous effluents exceeding any of the above limits, prepare and submit to the Commission within 30 days, pursuant to Specification 6.9.2, a l Special Report that identifies the cause(s) for exceeding the limit (s) and defines the corrective actions that have been taken to reduce the releases and the proposed corrective actions to be taken to assure that subsequent releases will be in compliance with the i
above limits,
- b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.
SURVEILLANCE REQUIREMENTS I 4.11.2.2 Cumulative dose contributions for the current calendar quarter and l current calendar year for noble gases shall be determined in accordance with j the methodology and parameters in the ODCM at least once per 31 days. l' l HOPE CREEK 3/4 11-12
RADIOACTIVE EFFLUENTS h
.UIU ia
']
MN28 1985 DOSE - IODINE-131, IODINE-133, TRITIUM, AND RADIONUCLIDES IN PARTICULATE FORM LIMITING CONDITION FOR OPERATION 3.11.2.s The dose to a MEMBER OF THE PUBLIC from iodine-131, iodine-133, tritium, and all radionuclides in particulate form with half-lives creater than 8 cays in gaseous effiuents released, from each reactor unit., to areas at and beyond the SITE BOUNDARY (see Figure 5.1.3-1) shall be limited to the following:
- a. During any calendar quarter: Less than or equal to 7.5 mrems to any organ and,
- b. During any calendar year: Less than or equal to 15 mrems to any organ.
APPLICABILITY: At all times. ACTION: ,- -
- a. With the calculated dose from the release of iodine-131, iodine-133, tritium, and radionuclides in particulate form with half lives greater than 8 days, in gaseous effluents exceeding any of the above limits, prepare and submit to the Commission within 30 days, pursuant to Specification 6.9.2, a Special Report that identifies the cause(s) for exceeding the limit and defines the corrective actions that have been taken to reduce the releases and the proposed corrective actions to be taken to assure that subsequent releases will be in compliance with the above limits.
- b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.
SURVEILLANCE REQUIREMENTS 4.11.2.3 Cumulative dose contributions for the current calendar quarter and current calendar year for iodine-131, iodine-133, tritium, and radionuclides in particulate form with half-lives greater than 3 days shall be determined in accordance with the methodology and parameters in the ODCM at least once per 31 days. t HOPE CREEK 3/4 11-13
RADI0 ACTIVE EFFLUENTS GASEOUS RADWASTE TREATMENT JUN 2 8 1985 LIMITING CONDITION FOR OPERATION 5.11.2.4 The GASEOUS RanWAdit TREAIMENT SYSTEM shall be in operation. nFPLI t3ILITY: Whenever the main condenser steam jet air ejector system is in operation. ACTION:
- a. With gaseous radwaste from the main condenser air ejector system being discharged without treatment for more than 7 days, prepare and submit _to the Commission within 30 days, pursuant to Specifica-tion 6.9.2, a Special Report that includes the following information:
- 1. Identification of the inoperable equipment or subsystems and
...-the reason for the inoperability,
- 2. Action (s) taken to restore the inoperable equipment to OPERABLE status, and
- 3. Summary description of action (s) taken to prevent a recurrence.
- b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.
SURVEILLANCE REQUIREMENTS l 4.11.2.4 The readings of the relevant instruments shall be checked every l 12 hours whenthe main condenser air ejector is in use to ensure that the ! gaseous radwaste treatment system is functioning. l l-HOPE CREEK 3/4 11-14 L
l RADI0 ACTIVE EFFLUENTS s u'l VENTILATION EXHAUST TREATMENT SYSTEM M 28 1985 LIMITING CONDITION FOR OPERATION 3.11.2.5 The VENTILATION EXHAUST TREATMENT SYSTEM shall be OPERABLE and appropriate portions of this system shall be used to reduce release of radio-activity when the projected doses in 31 days due to gaseous e, fluent releases from each unit to areas at and beyond the SITE BOUNDARY (see Figure 5.1.3-1) would exceed:
- a. 0.2 mrad to air from gamma radiation, or
- b. 0.4 mrad to air from beta radiation, or
- c. 0.3 mrem to any organ of a MEMBER OF THE PUBLIC APPLICABILITY: At all times.
ACTION:
- a. With radioactive gaseous waste being discharged without treatment ~3 and in excess of the above limits, prepare and submit to the Commission within 30 days pursuant to Specification 6.9.2 a Special Report that includes the following information: '
- 1. Identification of any inoperable equipment or subsystems, and the reason for the inoperability,
- 2. Action (s) taken to restore the inoperable equipment to OPERABLE status, and
- 3. Summary description of action (s) taken to prevent a recurrence.
, b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicaole. SURVEILLANCE REQUIREMENTS 4.11.2.5.1 Doses due to gaseous releases from the each unit to areas at and beyond the SITE BOUNDARY shall be projected at least once per 31 days in .: . accordance with the methodology and parameters in the ODCM, when the . VENTILATION EXHAUST TREATMENT SYSTEM is not being fully utilized. 4.11.2.5.2 The installed VENTILATION EXHAUST TREATMENT SYSTEM shall be con-sidered OPERABLE by meeting Specifications 3.11.2.1 and 3.11.2.2 and 3.11.2.3. , HOPE CREEK 3/4 11-15
2 RADI0 ACTIVE EFFLUENTS EXPLOSIVE GAS MIXTURE JUfi 2 8 ;ggg LIMITING CONDITION FOR OPERATION 3.11.4.6 The concentration of hydrogen in the main condenser offgas treatment system shall be limited to less than or equal to 4% by volume. t- APPLICABILITY: At all times. ACTION: i. . a. With the concentration of hydrogen in the main condenser offgas treatment system exceeding the limit, restore the concentration to within the limit within 48 hours.
- b. With continuous monitors inoperable, utilize grab sampling procedures for a period not to exceed 30 days.
- c. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.
SURVEILLANCE REQUIREMENTS 4.11.2.6 The concentration of hydrogen in the main condenser offgas treatment system shall be determined to be within the above limits by continuously moni-i toring the waste gases in the main condenser offgas treatment system whenever I the main condenser evacuation system is in operation with the hydrogen monitors required OPERABLE by Table 3.3.7.3-1 of Specification 3.3.7.3. I i l l HOPE CREEK 3/4 11-16 l L
RADI0 ACTIVE EFFLUENTS MAIN CONDENSER JUN 2 8 7ggg LIMITING CONDITION FOR OPERATION 3.11.2.7 The radioactivity rate of noble gases measured at the main condenser air ejector disall be iimited to less than or equal to 100 millicuries /sec per MWt (after 30 minute decay). APPLICABILITY: At all times. ACTION: With the radioactivity rate of noble gases at the main condenser air ejector exceeding 100 millicuries /sec per MWt (after 30 minute decay), restore the gross radioactivity rate to within its limit within 72 hours or be in at least HOT STANDBY within the next 12 hours. SURVEILLANCE REQUIREMENTS 4.11.2.7.1 The radioactivity rate of noble gases at the outlet of the. rain condenser air ejector shall be continuously monitored in accordance with i Specification 3.3.7.12. 4 4.11.2.7.2 The radioactivity rate of noble gases from the main condenser air ejector shall be determined to be within the limits of Specification 3.11.2.7 at the following frequencies by performing an isotopic analysis of a repre-sentative sample of gases taken near the discharge prior to dilution and/or discharge of the main condenser air ejector:
- a. At least or.:e per 31 days.
t r b. Within 4 hours following an increase, as indicated by the Offgas l Radioactivity Monitor, of greater than 50%, after factoring out l increases due to changes in THERMAL POWER level, in the nominal I steady-state fission gas release from the primary coolant. l l l H3PE CREEK 3/4 11-17
RADI0 ACTIVE EFFLUENTS VENTING OR PURGING JUN 2 8 gggg LIMITING CONDITION FOR OPERATION i 3.11.2.8 VENTING or PURGING of the Mark I containment drywell shall be through the reactor building ventilation system. APPLICABILITY: Whenever the containment is vented or purged. ACTION:
- a. With the requirements of the above specification not satisfied, suspend all VENTING and PURGING of the drywell.
- b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.
SURVEILLANCE-REQUIREMENTS 4.11.2.8.1 The containment shall be determined to be aligned for VENTING or PURGING through the reactor building ventilation system within 4 hours prior to start of and at least once per 12 hours during VENTING or PURGING of the drywell. i i i HOPE CREEK 3/4 11-18
RADIOACTIVE EFFLUENTS 3/4.11.3 SOLID RADIOACTIVE WASTE TREATMENT JUN 2 8 G85 LIMITING CONDITION FOR OPERATION 3.11.3 Radioactive wastes shall be SOLIDIFIED or dewatered in accordance with the PROCEfS CCNTROL ro0 GRAM to mect chipping and Lr:. sport;'.icn requireme..L: during transit, and disposal site requirements when received at the disposal site. APPLICABILITY: At all times. ACTION:
- a. With SOLIDIFICATION or dewatering not meeting disposal site and shipping and transportation requirements, suspend shipment of the inadequately processed wastes and correct the PROCESS CONTROL PROGRAM, the procedures and/or the solid waste system as necessary to prevent recurrence.
- b. With SOLIDIFICATION or dewatering not performed in accordance with the PROCESS CONTROL PROGRAM, test the improperly processed waste in each~c~ontainer to ensure that it meets the requirements for trans-portation to the disposal site and for receipt at the disposal site and take appropriate administrative action to prevent recurrence.
- c. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.
SURVEILLANCE REQUIREMENTS 4.11.3 SOLIDIFICATION of at least one representative test specimen from at least every tenth batch of each type of wet radioactive waste (e.g. , filter sludges, spent resins, evaporator bottoms, boric acid solutions, and sodium sulfate solutions) shall be verified in_accordance with the PROCESS CONTROL PROGRAM:
- a. If any test specimen fails to verify SOLIDIFICATION, the SOLIDIFICA-TION of the batch under test shall be suspended until such time as additional test specimens can be obtained, alternative SOLIDIFICATION parameters can be determined in accordance with the PROCESS CONTROL PROGRAM, and a subsequent test verifies SOLIDIFICATION. SOLIDIFICA-TION of the batch may then be resumed using the alternative SOLIDIFI-CATION parameters determined by the PROCESS CONTROL PROGRAM;
- b. If the initial test specimen from a batch of waste fails to verify SOLIDIFICATION, the PROCESS CONTROL PROGRAM shall provide for the collection and testing of representative test specimens from each consecutive batch of the same type of wet waste until at least three consecutive initial test specimens demonstrate SOLIDIFICATION. The PROCESS CONTROL PROGRAM shall be modified as required, as provided in Specification 6.13, to assure SOLIDIFICATION of subsequent batches of waste; and
- c. With the installed equipment incapable of meeting Specification 3.11.3 or declared inoperable, restore the equipment to OPERABLE status or provide for contract capability to process wastes as necessary to satisfy all applicable transportation and disposal requirements.
HOPE CREEK 3/4 11-19
RADIOACTIVE EFFLUENTS 3/4.11.4 TOTAL DOSE JUN 2 8 1985 LIMITING CONDITION FOR OPERATION 3 11.4 Tne anru71 (c:lendar yacr) dcce or Jose commiiment to any menoErt ut ' THE PUBLIC due to releases of radioactivity and to radiation from uranium fuel cycle sources shall be limited to 12ss than or equal tu 25 mrems to the total body or any organ, except the thyroid, which shall be limited to less than or equal to 75 mrems. APPLICABILITY: At all times. ACTION:
- a. With the calculated doses from the release of radioactive materials in liquid or gaseous effluents exceeding twice the limits of Specifi-
, cation 3.11.1.2a., 3.11.1.2b., 3.11.2.2a., 3.11.2.2b., 3.11.2.3a., or 3.11.2.3b., calculations should be made including direct radiation contributions from the units including outside storage tanks, etc. t'o' determine whether the above limits of Specification 3.11.4 have been exceeded. If such is the case, prepare and submit to the Com-mission within 30 days, pursuant to Specification 6.9.2, a Special Report that defines the corrective action to be taken to reduce sub-sequent releases to prevent recurrence of exceeding the above limits and includes the schedule for achieving conformance with the above limits. This Special Report, as defined in 10 CFR 20.405c, shall include an analysis that estimates the radiation exposure (dose) to a MEMBER OF THE PUBLIC from uranium fuel cycle sources, including all effluent pathways and direct radiation, for the calendar year that includes the release (s) covered by this report. It shall also de-scribe levels of radiation and concentrations of radioactive material involved, and the cause of the exposure levels or concentrations. If the estimated dose (s) exceeds the above limits, and if the release condition resulting in violation of 40 CFR Part 190 has not already ! been corrected, the Special Report shall include a request for a vari-I ance in accordance with the provisions of 40 CFR Part 190. Submittal l of the report is considered a timely request, and a variance is i granted until staff action on the request is complete. l b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable. i
-SURVEILLANCE REQUIREMENTS 4.11.4.1 Cumulative dose contributions from liquid and gaseous effluents shall be determined in accordance with Specificatiuns 4.11.1.2, 4.11.2.2, and 4.11.2.3,
, and in accordance with the methodology and parameters in the ODCM. 4.11.4.2 Cumulative dose contributions from direct raciation from the units including outside storage tanks, etc. shall be determined in accordance with
- the methodology and parameters in the 00CM. This requirement is applicable only under conditions set forth in Specification 3.11.4, ACTION a.
HOPE CREEK 3/4 11-20
3/4.12 RADIOLOGICAL ENVIRONMENTAL MONITORING 3/4.12.1 MONITORING PROGRAM M 2 8 1985 LIMITING CONDITION FOR OPERATION 3.12.1 The rdological envircnmental me-itu. :.g pogr:.r. :.Mll be cond-.sd as specified in Table 3.12.1-1. APPLICABILITY: At all times. ACTION:
- a. With the radiological environmental monitoring program not being conducted as specified in Table 3.12.1-1, prepare and submit to the Commission, in the Annual Radiological Environmental Operating Report required by Specification 6.9.1.7, a description of the reasons for not conducting the program as required and the plans for preventing a recurrence,
- b. With"t'helevel of radioactivity as the result of plant effluents in an environmental sampling medium at a specified location exceeding the reporting levels of Table 3.12.1-2 when averaged over any calendar quarter, prepare and submit to the Commission witnin 30 days, pursuant to Specification 6.9.2, a Special Report that identifies the cause(s) for exceeding the limit (s) and defines the corrective actions to be taken to reduce radioactive effluents so that the potential annual dose
- to A MEMBER OF THE PUBLIC is less than the calendar year limits of Specifications 3.11.1.2, 3.11.2.2, and 3.11.2.3. When more than one of the radionuclides in Table 3.12.1-2 are detected in the sampling medium, this report shall be submitted if:
concentration (1) , concentration (2) reporting level (1) reporting level (2)
+ ***> 1.0 When radionuclides other than those in Table 3.12-2 are detected and are the result of plant effluents, this report shall be submitted if the potential annual dose
- to A MEMBER OF THE PUBLIC from all radio-nuclides is equal to or greater than the calendar year limits of Specifications 3.11.1.2, 3.11.2.2, and 3.11.2.3. This report is not required if the measured level of radioactivity was not the result of plant effluents; however, in such an event, the condition shall be reported and described in the Annual Radiological Environmental i Operating Report pursuant to Specification 6.9.1.6.
- c. With milk or fresh leafy vegetable samples unavailable from one or more of the sample locations required by Table 3.12.1-1, identify specific locations for obtaining replacement samples and add them to l the radiological environmental monitoring program within 30 days. [
- The methodology used to estimate the potential annual dose to a MEMBER OF THE PUBLIC shall be indicated in this report.
HOPE CREEK 3/4 12-1
RADIOLOGICAL ENVIRONMENTAL MONITORING JUN 2 8 sqq
~
LIMITING CONDITION FOR OPERATION (Continued) ACTION: (Continued) The specific locations from which samples were unavailable may then be daleted frn? +ha monitoria; program. ?.rcuant to Sp:.i r:co-tion 6.9.1.8, identify the cause of the unavailability of samples and identify the new location (s) for obtaining replacement sa.aple, in the next Semiannual Radioactive Effluent Release Report pursuant to Speci-fication 6.9.1.8 and also include in the report a revised figure (s) and table for the ODCM reflecting the new location (s).
- d. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.
SURVEILLANCE REQUIREMENTS 4.12.1 The radiological environmental monitoriag samples shall be collected pursuant to Tabl'e 3.12.1-1 from the specific locations given in the table and figure (s) in the 00CM, and shall be analyzed pu suant to the requirements of Table 3.12.1-1 and the detection capabilities required by Table 4.12.1-1. Y t i i HOPE CREEK 3/4 12-2
TABLE 3.12.1-1 m RADIOLOGICAL ENVIRONMENTAL MONITORING PROGRAM
- 9 El Number of
^
Representative , Exposure Pathway Samples and Sampling and Type and Frequency and/or Sample Sample Locations (7) Collection Frequency of Ana'ysis i
- 1. DIRECT RADIATION I } Forty-three routine monitoring Quarte'rly Gamma dose quarterly.
stations (DR1-DR40) either i 4 with two or more dosimeters placed as follows: An inner ring of stations, one in each meteorological sector in the general area of the SITE BOUNDARY (DR1-DR16); An outer ring of stations, one in each meteorological secte- ' u in the 6- to 8-km range from 2 the site (DR17-DR32); and
" The balance of the stations 1 (DR33-DR40) to be placed in special interest areas such as population centers, nearby residences, schools, and in one or two areas to serve as control stations.
1
*The number, media, frequency, and location of samples may vary from site to site. This table presents an acceptable minista program for a site at which each entry is applicable. Local site charactaristics must be examined to determine if pathways not covered by this table may significantly contri.ute to an individual's dose and should be included in the sample program. The code letters in parenthsses, e.g.,
DR1, Al, provide one way of defining sample locations in this specification that can be used to identify the specific locations in the map (s) and table in the ODCM. c
'g E
m a m
TABLE 3.12.1-1 (Continued) 5 g RADIOLOGICAL ENVIRONMENTAL MONITORING PROGRAM S h Number of , Representative .- Exposure Pathway Samples and Sampling and Type and Frequency and/or Sample Sample Locations 3) Collection Frequency of Analysis
- 2. AIRBORNE i
Radioiodine and Samples from 5 locations (Al-AS). Continuous sampler Radioiodine Cannister: Particulates operation with sample I-131 Enalysis weekly. Three samples (Al-A3) from close collection weekly, or to the 3 SITE BOUNDARY locations, more frequently if in different sectors, of the required by dust Particulate Sampler: highest calculated annual average loading. Gross teta radioactivity groundlevel D/Q. analysisfollogg filter change; w One sample (A4) from the vicinity Gamma isotopic analysis I4) of a community having the highest of composite (by 2 calculated annual average ground- location) quarterly. level D/Q. One sample (A5) from a control location, as for example 15-30 km distant and in winddirection.gheleastprevalent
- 3. WATERBORNE
- a. Surface Ib) One sample upstream (Wal). Gamma isotopic analysis I)
One sample downstream (Wa2). Compositesampg)over 1-month period monthly. Composite for tritita analysis monthly. '
- b. Ground Samples from one or two sources Monthly Gamma isocopic(4) and tritium (Wbl, Wb nly if likely to be analysis raonthly if ground affected water flow reversal is noted.
D
!E' G
2
TABLE 3.12.1-1 (Continued) Q RADIOLOGICAL ENVIRONMENTAL MONITORING PROGRAM e Q X Number of Representative ,. Exposure Pathway Samples and Sampling and and/or Sample Sample Locations (7) Type and Frequency Collection Frequency of Analysis
- c. Drinking One sample of each of one to Composite sample I-131 analysis on each three (Wcl-Wc3) of the nearest over 2& week period (6) composite when the dose '
water supplies that could be when I-131 analysis calculated for the consump-affected by its discharge. is performed, monthly composite otherwise tion of the water is gater than 1 mrem per year. Com-One sample from a control location (Wc4). positeforgrossbetaag gamma isotopic analyses monthly. Composite for tritium analysis quarterly.
- d. Sediment One sample from 10wnstream area Semiannually Gamma isotopic analysis I4) from (Wdl) semiannually.
m shoreline One sample from upstream area 2 (Wd2) _. One sample frmo cross stream asaa '? (Wd3) m
- 4. INGESTION
- a. Milk Samples from milking animals in Semimonthly when Gamma isotopicI4) and I-131 three locations (Ial-Ia3) within animals are on analysis -semimonthly when 5 km distance having the highest. pasture, monthly at animals are on pasture; dose potential. If there are other times monthly at other times.
none, then, I sample from milking animals in each of three areas between 5 to 8 km distant where doses are calculatef8h be greater than 1 mrem per yr. One sample from milking animals at a control location (Ia4) :g: @ 15 30 km distant and in the M - least prevalent wind direction. y m
TABLE 3.12.1-1.(Continued)
'@ RADIOLOGICAL ENVIRONMENTA'l MONITORING PROGRAM 9
A Number of Representative .- Exposure Pathway Samples and Sampling and Type and Frequency and/or Sample Sample Locations (3) Collection Frequency of Analysis
- b. Fish and One sample of each commercially Sample,in season, or' Gamma isotopic analysis I4)
Inverte- and recreationally important semianhually if they on edible portions. brates species in vicinity of plant' are not seasonal discharge area (Ibl-Ib). ,. One sample of same species in areas not influenced by plant discharge (Ib10-Ib).
- c. Food One sample of each principal At time of harvest I) Gamma isetopic analysis O)
Products class of food products from any on edible portion. area that is irrigated by water w in which liquid plant wastes 1 have been discharged (Icl-Ic).
';* Samples of three different kinds Monthly when Gamma isotopicI4) and I-131 of broad leaf vegetation grown available analysis, nearest each of two different offsite locations of highest predicted annual average ground-level D/Q if milk sampling is not performed (Ic10-Ic13).
I sample of each of the similar Monthly when Gamma isotopic (4) and I-131 broad leaf vegetation grown available analyais. ' 15-30 km distant in the least prevalent wind direction if milk sampling is not performed (Ic20-Ic23). n # a ca b
~
TABLE 3.12.1-1 (Continued) 1 TABLE NOTATIONS J[Ly p g (1) Specific parameters of distance and direction sector from the centerline of one reactor, and additional description where pertinent, shall be pro-vided for each and every sample location in Table 3.12.1-1 in a table and figure (s) in the ODCM. Refer to NUREG-0133, " Preparation of Radiological Effluent Technical Specification; #cr N"cla ~ Power Planta ," 0 -t N r O , and to Radiological Assessment Branch Technical Position, Revision 1, November 1979. Deviations are perm tted from the required sampling schedule if specimens are unobtainable due to hazardous conditions, sea-sonal unavailability, malfunction of automatic sampling equipment and other legitimate reasons. If specimens are unobtainable due to sampling equipment malfunction, every effort shall be made to complete corrective action prior to the end of the next sampling period. All deviations from the sampling schedule shall be documented in the Annual Radiological Environmental Operating Report pursuant to Specification 6.9.1.6. It is recognized that, at times, it may not be possible or practicable to con-tinue to obtain samples of the media of choice at the most desired loca-tion or time. In these instances suitable specific alternative media and locations may be chosen for the particular pathway in question and appro-priate, substitutions made within 30 days in the Radiological Environmental Monitoring Program given in the ODCM. Pursuant to Specification 6.14, submit in the next Semiannual Radioactive Effluent Release Report documen-tation for a change in the ODCM including a revised figure (s) and table for the ODCM reflecting the new location (s) with supporting information identifying the cause of the unavailability of samples for that pathway and justifying the selection of the new location (s) for obtaining samples. (2)0ne or more instruments, such as a pressurized ion chamber, for measuring and recording dose rate continuously may be used in place of, or in addi-tion to, integrating dosimeters. For the purposes of this table, a thermo-luminescent dosimeter (TLD) is considered to be one phosphor; two or more phosphors in a packet are considered as two or more dosimeters. Film badges shall not be used as dosimeters for measuring direct radiation. The frequency of analysis or readout for TLD systems will depend upon the characteristics of the specific system used and should be selected to obtain optimum dose information with minimal fading. (3)Airbrne particulate sample filters shall be analyzed for gross beta radio-activity 24 hours or more after sampling to allow for radon and thoron daughter decay. If gross beta activity in air particulate samples is greater than 10 times the yearly mean of control samples, gamma isotopic analysis shall be performed on the individual samples. (4) Gamma isotopic analysis means the identification and quantification of gamma-emitting radionuclides that may be attributable to the effluents from the facility. (5)The " upstream sample" shall be taken at a distance beyond significant influence of the discharge. The " downstream" sample shall be taken in an area beyond but near the mixing zone. " Upstream" samples in an estuary must be taken far enough upstream to be beyond the plant influence. Salt water shall be sampled only when the receiving water is utilized for recreational activities. HOPE CREEK 3/4 12-7
TABLE 3.12.1-1 (Continued) j) TABLE NOTATION JUN 2 8 m (6)A composite sample is one in which the quantity (aliquot) of liquid sampled is proportional to the quantity of flowing liquid and in which the method of sampling employed results in a specimen that is representative of the liquid flow. In this program composite sample aliquots shall be collected at .; .;
.r.k. sal., tr.at are very short (e.g. , hourly) reiative to the com-positing period (e.g., monthly) in order to assure obtaining a representa-tive sample.
(7) Groundwater samples shall be taken when this source is tapped for drinking or irrigation purposes in areas where the hydraulic gradient or recharge properties are suitable for contamination. (8)The dose shall be calculated for the maximum organ and age group, using the methodology and parameters in the ODCM. (9)If harvest occurs more than once a year, sampling shall be performed during each discrete harvest. If harvest occurs continuously, sampling shall be monthly.. . Attention shall be paid to including samples of tuberous and root food products. HOPE CREEK 3/4 12-3 L
I TABLE 3.12.1-2 REPORTING LEVELS FOR RADI0 ACTIVITY CONCENTRATIONS IN ENVIRONMENTAL SAMPL25 S REPORTING LEVELS m rc Water Airborne Particulate Fish' Milk Food Products Analysis (pCi/t) or Gases (pC1/m3 ) (pCi/kg, wet) (pCi/1) (pCi/kg, wet) H-3 30,000 ; 1 Mn-54 1,000 30,000 l Fe-59 400 10,000 Co-58 1,000 30,000 Co-60 300 10,000 { Zn-65 300 20,000 y Z r-Nb-95 400 e I-131 20 0.9 3 100 Cs-134 30 10 1,000 60 1,000 i Cs-137 50 20 2,000 70 2,000 Ba-La-140 200 300 e: e C. E ao "A N m u, -)
- q TABLE 4.12.1-1 DETECTION CAPA8ILITIES FOR ENVIRONMENTAL SAMPLE ANALYSIS (l)(2) k LOWER LIMIT OF DETECTION (LLD)(3)
N Water Airborne Particulate Fish
- Milk Food Products Sediment Analysis (pCi/2) or Gas (pCi/m3) (pCi/kg, wet) ',(pCi/1)
(pCi/kg, wet) (pCi/kg, dry) gross beta 4 0.01 11- 3 3000 Mn-54 15 130 fe-59 30 260 Co-58,60 15 130 { Zn-65 30 260 Z r-Nb-95 15 af. I-131 15 0.07 1 60 Cs-134 15 0.05 130 15 60 150 Cs-137 18 0.06 150 18 80 18C Ba-La-140 15 15 d c::3
% pt3 p
3 y
g TABLE 4.12.1-1 (Continued) yj TABLE NOTATIONS JUN 2 8 1985 (1)This list does not mean that only these nuclides are to be considered. Other peaks that are identifiable, together with those of the above nuclides, shall also be analyzed and reported in the Annual Radiological Envirnnmental 0,nerr.tinc Repe-t ,nursua-+ to speci fice < ,; ". 9. ., c, (2) Required detection capabilitias for thermoluminescent dosimeters used for environmental measurements shall be in accordane with the recommenda-tions of Regulatory Guide 4.13. (3)The LLD is defined, for purposes of these specifications, as the smallest concentration of radioactive material in a sample that will yield a net count, above system background, that will be detected with 95% probability with only 5% probability of falsely concluding that a blank observation represents a "real" signal. For a particular measurement system, which may include radiochemical separation: 4.66 s b LLD = E - V - 2.22 - Y - exp(-Aat) Where: LLD is the "a priori" lower limit of detection as defined above, as picocuries per unit mass or volume, h is the standard deviation of the background counting rate or of s tne counting rate of a blank sample as appropriate, as counts per minute. E is the counting efficiency, as counts per disintegration, V is the sample size in units of mass or volume, 2.22 is the number of disintegrations per minute per picoeurie, Y is the fractional radiochemical yield, when applicable. A is the radioactive decay constant for the particular radionuclide (sec 1), and at for environmental samples is the elapsed time between sample collection, or end of the sample collection period, and time of counting (sec) Typical valves of E, V, Y, and at should be used in the calculation. HOPE CREEK 3/4 12-11
TABLE 4.12.1-1 (Continued) {Q1l}, id'h TABLE NOTATIONS JUN 2 81985 It should be recognized that the LLD is defined as an a priori (before the fact) limit representing the capability of a measurement system and not as an a posteriori (after the fact) limit for a particular measurement. Analycas shall be performed f r s ::h a mannor th ' ti.e stcteJ LLDs wili be i, achieved under routine conditions. Occasionally background fluctuations, unavoidable small sample sizes, the presence of intec.'cring nuclides, or other uncontrollable circumstances may render these LLDs unachievab'.e. In such cases, the contributing factors shall be identified and described in the Annual Radiological Environmental Operating Report pursuant to Specification 6.9.1.6. i i HOPE CREEK 3/4 12-12
RADIOLOGICAL ENVIRONMENTAL MONITORING 3/4.12.2 LAND USE CENSUS JUN 2 81985 LIMITING CONDITION FOR OPERATION 1 12.2 a land us2 cen:u: shell 52 ;. ndated ai,J shali Idant.;fy wi m n a distance of 8 km (5 miles) the location in each of the 16 meteorological
< actors of the nearest milk ani;;:al, the naarest residence and the nearest garden
- of greater than 50 m2 (500 ft 3) producing broad leaf vegetation.
APPLICABILITY: At all times. ACTION:
- a. With a land use census identifying a location (s) that yicids a calcu-lated dose or dose commitment greater than the values currently being calculated in Specification 4.11.2.3, identify the new location (s) in the next Semiannual Radioactive Effluent Release Report, pursuant to Specifica_ tion 6.9.1.7.
- b. With a land use census identifying a location (s) that yields a calculated dose or dose commitment (via the same exposure pathway) 20% greater than at a location from which samples are currently being obtained in accordance with Specification 3.12.1, add the new location (s) to the radiological environmental monitoring program within 30 days. The sampling location (s), excluding the control station location, having the lowest calculated dose or dose commitment (s), via the same exposure pathway, may be deleted from this monitoring program after October 31 of the year in which this land use census was conducted. Pursuant to Specification 6.9.1.8, identify the new location (s) in the next Semiannual Radioactive Effluent Release Report and also include in the report a revised figure (s) and table for the 00CM reflecting the new location (s),
- c. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.
SURVEILLANCE REQUIREMENTS 4.12.2 The land use census shall be conducted during the growing season at least once per 12 months using that information that will provide the best results, such as by a door-to-door survey, visual survey, aerial survey, or by consulting local agriculture authorities. The results of the land use census shall be included in the Annual Radiological Environmental Operating Report pursuant to Specification 6.3.1.6. " Broad leaf vegetation sampling of at least three different kinds of vegetation may be performed at the SITE BOLNDARY in each of two different direction sectors with the highest predicted 0/Qs in lieu of the garden census. Specifications for broad leaf vegetation samplir.g in Table 3.12.1-1, Part 4.c., shall be followed, including analysis of control samples. HOPE CREEK 3/4 12-13
. n- . - < -
s , RADIOLOGICAL ENVIPOP MENTAL MbNITORING , 3/4.12.3 INTERL480RATORY COMPARISON PROGRAM' JUN 2 8 1985 LIMITING CONDITION FOR OPERATION 3.14.3 Analyses shall be performeif on radioactive materials supplied as part of an Interlaboratory Comparison ~ Program that has been =pproved by the Commission.
- APPLICABILITY: At all times. .
ACTION: <
- a. With analyses not being perforied as required above, report the corrective actions taken to prevent a recurrence to the Commission in the Annual Radiological Environmental Operating Repor; pur;uant to Specification 6.9.1.6.
- b. T,heprovi}ionsofSpecifications3.0.3and3.0.4 are not applicable.
! SURVEILLANCE REQUIREME'NTS 4
4.12.3 The Inter).atoratory Ccmparison Program shall be described in the 00CM. A summary of the r'esults obtained as part of the above required Inter-laboratory Comparisen Program shall be included in the Annual Radiological Environmental Opersting Report pursuant to Specification 6.9.1.6. o
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'l HOPE CREEK , et 3/4 II*14
.___-_-.____--..-_____--.-_---_a _a
DMFT JM 2 8 1985 BASES FOR
" ~ ^ ~
SECTIONS 3.0 AND 4.0 LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS e
4 i I JUN 2 8 1935 E NOTE The Su'mmary statements contained in this section provide the bases for the specifications in Section 3.0 and 4.0 but in accordance with 10 CFR 50.36 are not a part of these Technical Specifications. I t' i
? - ~i . - . - . - _ . . .-,2 ., - . --. . , - . -_ ._, . -_~-. .---,-e,,--. .--,4
mob hiM'h 3/4.0 APPLICABILITY BASES JUN 2 8 SS5 The vecifications of this section provide the general requirements applicable to each of the Limiting Conditions for Operation and Surveillance Requirements within Section 3/4. 3.0.1 This specification states the applicability of each specification in terms of defined OPERATIONAL CONDITION or other specified applicability condition and is provided to delineate specifically when each specification is applicable. 3.0.2 This specification defines those conditions necessary to constitute compliance with the terms of an individual Limiting Condition for Operation and associated ACTION requirement. 3.0.3 This specification delineates the measures to be taken for circum-stances not directly provided for in the ACTION statements and whose occurrence would violate the intent of the specification. For example, Specification 3.7.2 calls for two control room emergency filtration subsystems to be OPERABLE and provides explicit ACTION requirements if one subsystem is inoperable. Under the requirements of Specification 3.0.3, if both of the required subsystems are inoperable, within one hour measures must be initiated to place the unit in at least STARTUP within the next 6 hours, in at least HOT SHUTDOWN within the following 6 hours and in COLD SHUTDOWN within the subsequent 24 hours. As a further example, Specification 3.6.6.1 requires two primary containment hydrogen recombiner systems to be OPERABLE and provides explicit ACTION require-ments if one recombiner system is inoperable. Under the requirements of Specification 3.0.3, if both of the required systems are inoperable, within one hour measures must be initiated to place the unit in at least STARTUP within the next 6 hours and in at least HOT SHUTDOWN within the following 6 hours. 3.0.4 This specification provides that entry into an OPERATIONAL CONDITION me t be made with (a) the full complement of required systems, equipment or components OPERABLE and (b) all other parameters as specified in the Limiting Conditions for Operation being met without regard for allowable deviations and out of service provisions contained in the ACTION statements. The intent of this provision is to ensure that unit operation is not initiated with either required equipment or systems inoperable or other limits
~
being exceeded. Exceptions to this provision have been provided for a limited number of specifications when startup with inoperable equipment would not affect plant safety. These exceptions are stated in the ACTION statements of the appropriate specifications. HOPE CREEK B 3/4 0-1
1 rxr*** s u+ .
- M1MI APPLICABILITY JUN 28 5ES BASES 4.0.1 This specification orovides that <"-vaillance ?ctivitic: nect::;ry to ensure tne Limiting Conditions for Operation are met and will be performea.
during the OPERATIONAL CONDITIONS or other conditions for which the Limiting Conditions ror Operation are applicable. Provisions for additioral surveillance. activities to be performed without regard to the applicable OPERATIONAL CONDI-TIONS or other conditions are provided in the individual Surveillance Require-ments. Surveillance Requirements for Special Test Exceptions need only be performed when the Special Test Exception is being utilized as an exception to an individual specification. 4.0.2 The provisions of this specification provide allowable tolerances for performing surveillagce activities beyond those specified in the nominal surveillance interval. These tolerances are necessary to provide operational flexibility, because of scheduling and performance considerations. The phrase "at least" associated with a surveillance frequency does not negate this allowable tolerance; instead, it permits the more frequent performance of sur-veillance activities. ~' The tolerance values, taken either individually or consecutively over 3 , test intervals, are sufficiently restrictive to ensure that the reliability as:ociated with the surveillance activity is not significantly degraded beyond that obtained from the nominal specified interval. 4.0.3 The provisions of this specification set forth the criteria for determination of compliance with the OPERABILITY requirements of the Limiting Conditions for Operation. Under this criteria, equipment, systems or components are assumed to be OPERABLE if the associated surveillance activities have been satisfactorily performed within the specified time interval. Nothing in this provision is to be construed as defining equipment, systems or components OPERABLE, when such items are found or known to be inoperable although still meeting the Surveillance Requirements. l l t l l l l HOPE CREEK 3 3/4 0-2 l L
APPLICABILITY
- hs BASES k' WN 2 8 1985 4.0.4 This specification ensures that surveillance activities a:sociated -
with t. '.iriting Conditioces for Operation have been performed within the specified time interval prior to entry into an applicable OPERATIONAL CONDITION or other specified applicability cundition. The intent of this provision is to ensure that surveillance activities have been satisfactorily demcnstrated on a current basis as required to meet the OPERABILITY requirements of the Limiting Condition for Operation. Under the terms of this specification, for example, during initial plant startup or following extended plant outage, the applicable surveillance activ-ities must be performed within the stated surveillance interval prior to placing or returning the system or equipment into OPERABLE status. 4.0.5 This. specification ensures that inservice inspection of ASME Code Class 1, 2 and 3 components and inservice testing of ASME Code Class 1, 2 and 3 pumps and valves will be performed in accordance with a periodically updated version as of Section required XI of50, by 10 CFR theSection ASME Boiler and Pressure Vessel Code and Addenda 50.55a. Relief from any of the above require-ments has been provided in writing by the Commission and is not a part of these Technical Specifications. This specification includes a clarification of the frequencies of perform-ing the inservice inspection and testing activities required by Section XI of the ASME Boiler a,nd Pressure Vessel Code and applicable Addenda. This clarifi-cation is provided to ensure consistency in surveillance intervals throughout these Technical Specifications and to remove any ambiguities relative to the frequencies for performing the required inservice inspection and testing activ-ities. Under the terms of this specification, the more restrictive requirements of the Technical Specifications take precedence over the ASME Boiler and Pressure Vessel Code and applicable Addenda. For example, the requirements of Specifi-cation 4.0.4 to perform surveillance activities prior to entry into an OPERATIONAL CONDITION or other specified applicability condition takes precedence over the ASME Boiler and Pressure Vessel Code provision which allows pumps to be tested up to one week after return to normal operation. And for example, the Technical Specification definition of OPERABLE does not grant a grace period before a device that is not capable of performing its specified function is declared inoperable and takes precedence over the ASME Boiler and Pressure Vessel provi-sion which allows a valve to be incapable of performing its specified function for up to 24 hours before being declared inoperable. HOPE CREEK B 3/4 0-3
l l 3/4.1 REACTIVITY CONTROL SYSTEMS i
@ 26 35 l BASES ' '4.1.1 90T00Wr! MARGIN A s"fficient SHUTDOWN MARGIN ensures that if tne reactor can be made subcritical from all operating conditions, 2) the reactivity transients associated with postulated accident conditions are controllable within acceptable limits, and 3) the reactor will be maintained sufficiently subcritical to preclude inadvertent criticality in the shutdown condition.
Since core reactivity values will vary through core life as a function of fuel depletion and poison burnup, the demonstration of SHUTDOWN MARGIN will be performed in the cold, xenon-free condition and shall show the core to be subcritical by at least R + 0.38% delta K or R + 0.28% delta K, as appro-priate. The value of R in units of % delta K is the difference between the calculated value.of-maximum core reactivity during the operating cycle and the calculated beginning-of-life core reactivity. The value of R must be positive or zero and must be determined for each fuel loading cycle. Two different values are supplied in the Limiting Condition for Operation to provide for the different methods of demonstration of the SHUTDOWN MARGIN. The highest worth rod may be determined analytically or by test. The SHUTDOWN MARGIN is demonstrated by (an insequence) control rod withdrawal at the beginning of life fuel cycle conditions, and, if necessary, at any future time in the cycle if the first demonstration indicates that the required margin could be reduced as a function of exposure. Observation of subcriticality in this condition assures subcriticality with the most reactive control rod fully withdrawn. This reactivity characteristic has been a basic assumption in the analysis of plant performance and can be best demonstrated at the time of fuel loading, but the margin must also be determined anytime a control rod is incapable of insertion. 3/4.1.2 REACTIVITY ANOMALIES Since the SHUTDOWN MARGIN requirement for the reactor is small, a careful check on actual conditions to the predicted conditions is necessary, and the changes in reactivity can be inferred from these comparisons of rod patterns. Since the comparisons are easily done, frequent checks are not an imposition on normal operations. A 1% change is larger than is expected for normal operation so a change of this magnitude should be thoroughly evaluated. A change as large as 1% would not exceed the design conditions of the reactor and is on the safe side of the postulated transients. HOPE CREEK B 3/4 1-1
l 1 REACTIVITY CONTROL SYSTEMS l BASES M N ID 3/4.1.3 CONTROL RODS The specificaHes of this section enema *h?t (?) 'ha minimum SHUTDOWN MARGIN is maintained, (2) the control rod insertion times are consistent with those used in the arrident analysis, and (3) limit the potential effects of the rod drop accident. The ACTION statements permit variations from the basic requirements but at the same time impose more restrictive criteria for continued operation. A limitation on inoperable rods is set such that the resultant effect on total rod worth and scram shape will be kept to a minimum. The requirements for the various scram time measurements ensure that any indication of systematic problems with rod drives will be investigated on a timely basis. Damage within the control rod drive mechanism could be a generic problem, therefore with a control rod immovable because of excessive friction or mechanical interference, operation of the reactor is limited to a time period which is reasonable to determine the cause of the inoperability and at the same time preventroperation with a large number of inoperable control rods. Control rods that are inoperable for other reasons are permitted to be taken out of service provided that those in the nonfully-inserted position are consistent with the SHUTDOWN MARGIN requirements. The number of control rods permitted to be inoperable could be more than the eight allowed by the specification, but the occurrence of eight inoperable rods could be indicative of a generic problem and the reactor must be shutdown for investigation and resolution of the problem. The control rod system is designed to bring the reactor subcritical at a rate fast enough to prevent the MCPR from becoming less than 1.06 during the limiting power transient analyzed in Section 15.4 of the FSAR. This analysis shows that the negative reactivity rates resulting from the scram with the average response of all the drives as given in the specifications, provide the required protection and MCPR remains greater than 1.06. The occurrence of scram times longer then those specified should be viewed as an indication of a systematic problem with the rod drives and therefore the surveillance interval is reduced in order to prevent operation of the reactor for long periods of time with a potentially serious problem. The scram discharge volume is required to be OPERABLE so that it will be available when needed to accept discharge water from the control rods during a reactor scram and will isolate the reactor coulant system from the containment when required. Control rods with inoperable accumulators are declared inoperable and Specification 3.1.3.1 then applies. This prevents a pattern of inoperaole accumulators that would result in less reactivity insertion on a scram than has been analyzed even that.gh control rods with inoperable accumulators may still be inserted with normal drive water pressure. Operacility of the accumulator ensures that there is a means available to insert the control rocs even under the most unfavorable depressuri:ation of the reactor. HOPE CREEK 2 3/4 1-2
REACTIVITY CONTROL SYSTEMS JUN 2 81955 BASES CONTROL RODS (Continued) Control rod coucling integrity is carW to cr.:ure :apli:nce ith u. analysis of the rod drop accident in the FSAR. The overtravel position feature provides the only positive means of determin N that a rod is properly coupl.d and therefore this check must be performed prior to achievir.g criticality after completing CORE ALTERATIONS that could have affected the control rod coupling integrity. The subsequent check is performed as a backup to the initial demon-stration. In order to ensure that the control rod patterns can be followed and there-fore that other parameters are within their limits, the control rod position indication system must be OPERABLE. The control rod housing support restricts the outward movement of a control rod to less than (3) inches in the event of a housing failure. The amount of rod reactiv.ity 'which could be added by this small amount of rod withdrawal is less than a normal withdrawal increment and will not contribute to any damage to the primary coolant system. The support is not required when there is no pressure to act as a driving force to rapidly eject a drive housing. The required surveillance intervals are adequate to determine that the rods are OPERABLE and not so frequent as to cause excessive wear on the system components. 3/4.1.4 CONTROL ROD PROGRAM CONTROLS Control rod withdrawal and insertion sequences are established to assure that the maximum insequence individual control rod or control rod segments which are withdrawn at any time during the fuel cycle could not be worth enough to result in a peak fuel enthalpy greater than 280 cal /gm in the event of a control rod drop accident. The specified sequences are characterized by homogeneous, scattered patterns of control rod withdrawal. When THERMAL POWER is greater than 20% of RATED THERMAL POWER, there is no possible rod worth which, if dropped at the design rate of the velocity limiter, could result in a peak enthalpy of 280 cal /gm. Thus requiring the RSCS and RWM to be OPERABLE when THERMAL POWER is less than or ecual to 20% of RATED THERMAL POWER provides adequate control. The RSCS and RWM provide automatic supervision to assure that out-of-sequence rods will not be withdrawn or inserted. The analysis of the rod drop accident is presented in Section 15.4.9 of the FSAR and the. techniques of the analysis are presented in a topical report, Reference 1, and two supplements, References 2 and 3. The RBM is designed to automatically prevent fuel damage in the event of erroneous rod withdrawal from locations of high power density during high power operation. Two channels are provided. Tripping one of the channels will block erroneous rod withdrawal soon enough to prevent fuel damage. This system backs up the written sequence used by the operator for withdrawal of control rods. HOPE CREEK 8 3/4 1-3
X REACTIVITY CONTROL SYSTEMS a BASES JUN 2 81985 E4.1.5 STANDBY LIO,UID CONTROL SYST_EM_ The standby liquid control system provides a backup capability for bringing the reactor from full power to a cold, Xenon-free shutdown, assuming that the withdrawn control rods remain fixed in the rated power pattern. To meet this objective it is necessary to inject a quantity of boron which produces a concen-tration of (660) ppm in the reactor core and other piping systems connected to the reactor vessel. To allow for potential leakage and improper mixing this con-centration is increased by 25%. The required concentration is achieved by having a minimum available quantity of 4750 gallons of sodium pentaborate solution con-taining a minimum of 5750 lbs of sodium pentaborate. This quantity of solution is a net amount which is above the pump section, thus allowing for the portion which cannot be injected 3 The pumping rate of 41.2 gpm provides a negative reactivity insertion rate over the permissible pentaborate solution volume range, which adequately compensates for the positive reactivity effects due to tempera-ture and xe'non during shutdown. The temperature requirement is necessary to ensure that the sodium pentaborate remains in solution. m With redundant pumps and explosive injection valves and with a highly . reliable control rod scram system, operation of the reactor is permitted to . continue for short periods of time with the system inoperable or for longer periods of time with one of the redundant components inoperable. Surveillance requirements are established on a frequency that assures a high reliability of the system. Once the solution is established, boron con-centration will not vary unless more boron or water is added, thus a check on the temperature and volume once each 24 hours assures that the solution is available for use. Replacement of the explosive charges in the valves at regular intervals will assure that these valves will not fail because of deterioration of the charges.
- 1. C. J. Paone, R. C. Stirn an'd J. A. Woolley, " Rod Drop Accident Analysis for Large BWR's", G. E. Topical Report NEDO-10527, March 1972
- 2. C. J. Paone, R. C. Stirn and R. M. Young, Supplement 1 to NE00-10527, July 1972 ..
- 3. J. M. Haun, C. J. Paone and R. C. Stirn, Addendum 2, " Exposed Cores",
Supplement 2 to NED0-10527, January 1973 HOPE CREEK B 3/4 1-4
3/4.2 POWER DISTRIBUTION LIMITS BASES JUN 2 8 W The spet.ifications of this section assure that the peak cladding temperature following the postulated design basis loss-of-coolant accident will not exceed the 2200*F limit specified in 10 CFR 50.46. 3/4.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE The peak cladding temperature (PCT) following a postulated loss of-coolant accident is primarily a function of the average heat generation rate of all the rods of a fuel assembly at any axial location and is dependent only secondarily on the rod to rod power distribution within an assembly. The peak clad temperature is calculated assuming a LHGR for the highest powered rod which is equal to or less than the design LHGR corrected for densification. This LHGR times (1.02) is used in the heatup code along with the exposure dependent steady state gap conductance'and rod-to-rod local peaking factor. The Technical Specification AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR) is this LHGR of the highest
. powered rod divided by its local peaking factor. The limiting value for APLHGR is shown in Figures (3.2.1-1. 3.2.1-2 and 3.2.1-3).
The calculational procedure used to establish the APLHGR shown on Figures (3.2.1-1, 3.2.1-2 and 3.2.1-3) is based on a loss-of-coolant accident analysis. The analysis was performed using General Electric (GE) calculational models which are consistent with the requirements of Appendix K to 10 CFR 50. A complete discussion of each code employed in the analysis is presented in Reference 1. Differences in this analysis compared to previous analyses can be broken down as follows.
- a. Input Chances
- 1. Corrected Vaporization Calculation - Coefficients in the vaporization correlation used in the REFLOOD code were corrected.
- 2. Incorporated more accurate bypass areas - The bypass areas in the top guide were recalculated using a more accurate technique.
- 3. Corrected guide tube thermal resistance.
- 4. Correct heat capacity of reactor internals heat nodes. ;
HOPE CREEK B 3/4 2-1 l
POWER DISTRIBUTION LIMITS JUN 2 8 1985 BASES AVERAGE 6 NAR LihdAR HhaT GENERATION RAlt (Continued)
- b. Model Change
- 1. Core CCFL pressure differential - 1 psi - Incorporate the assumption that flow from the bypass to lower plenum must overcome a 1 psi pressure drop in core.
- 2. Incoporate NRC pressure transfer assumption - The assumption used in the SAFE-REFLOOD pressure transfer when the pressure is increasing
[ was changed. l l A few of the changes affect the accident calculation irrespective of CCFL. These changeFare listed below,
- a. Input Change
- 1. Break Areas - The DBA break area was calculated more accurately.
- b. Model Chance
- 1. Improved Radiation and Conduction Calculation - Incorporation of CHASTE 05 for heatup calculation.
A list of the significant plant input parameters to the loss-of-coolant accident analysis is presented in Bases Table B 3.2.1-1. 3/4.2.2 APRM SETPOINTS , The fuel cladding integrity Safety Limits of Specification 2.1 were based on a power distribution which would yield the design LHGR at RATED THERMAL POWER. The flow biased simulated thermal power-upscale scram setting and flow biased neutron flux-upscale control rod block functions of the APRM instruments must be adjusted to ensure that the MCPR does not become less than 1.06 or that
> 1% plastic strain does not occur in the degraded situation. The scram settings and rod block settings are adjusted in accordance with the formula in this specification when the combination of THERMAL POWER and MFLPD indicates a higher peaked power distribution to ensure that an LHGR transient would not be increased in the degraded condition.
HOPE CREEK B 3/4 2-2
,tt Bases Table B 3.2.1-1 SIGNIFICANT INPUT PARAMETERS TO THE- JUN 2 8 55 LOSS-OF-COOLANT ACCIDENT ANALYSIS Plant Parameters:
Core THERMAL POWER .................... 3435 Mwt* which corresponds to 105% of rated steam flow Vessel Steam Output ................... 14.86 x 108 lbm/hr which corresponds to 105% of rated steam flow Vessel Steam Dome Pressure............. 1055 psia Design Basis Recirculation Line Break. Area for: a.Large Breaks 4.1 ft2
- b. Small Breaks' O.09 ft2 ,
Fuel Parameters: PEAK TECHNICAL INITIAL SPECIFICATION DESIGN MINIMUM LINEAR HEAT AXIAL CRITICAL FUEL BUNDLE GENERATION RATE PEAKING POWER FUEL TYPE GEOMETRY (kw/ft) FACTOR RATIO Initial Core 8x8 13.4 1. 4 1.18 A more detailed listing of input of each model and its source is presented in Section II of Reference 1 and subsection 6.3.3 of the FSAR.
- This power level meets the Appendix X requirement of 102%. The core heatup calculation assumes a bundle power consistent with operation of the highest powered rod at 102% of its Technical Specification LINEAR HEAT GENERATION RATE limit.
A HOPE CREEK B 3/4 2-3
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POWER OISTRIBUTION LIMITS BASES JUN 2 8 $85 3/4.2.3 MINIM,U,M CRITICAL POWER RATIO The required operating limit MCPRs'at steady state operating conditions as specified in Spe.::fication 3.2.3 are derived from the established fuel cladding integrity Safety Limit MCPR of (1.06), and an analysis of abnormal operational transients. For any abnormal operating transient analysis evalua-tion with the initial condition operating limit, it is required thatof the reactor being at the steady state the resulting MCPR does not decrease below the Safety setting Limit given in MCPR at any time Specification 2.2. during the transient assuming instrument trip To assure that the fuel cladding integrity Safety Limit is not exceeded 4 during any anticipated abnormal operational transient, the most limiting tran-sients have been analyzed to determine which result in the largest reduction in CRITICAL POWER RATIO (CPR). The type of transients evaluated were loss of flow, incre'ase in pressure and power, positive reactivity insertion, and coolant temperature decrease. MCPR. The limiting transient yields the largest delta When added to the Safety Limit MCPR of 1.06, the required minimum operating limit MCPR of Specification 3.2.3 is obtained (and presented in Figure 3.2.3-1). The evaluation of a given transient begins with the system initial parameters shown in FSAR Table 15.0-3 that are input to a GE-core dynamic behavior transient computer progr g The code used to evaluate pressurization events is described in NEDO-24154 events is described in NEDO-10802(2) and the program used in non pressurization The outputs of this program along with the initial MCPR form the input for further analyses of the thermally limiting bundlewithtgsinglechanneltransientthermalhydraulicTASCcodedescribed in NEDE-25149 The principal result of this evaluation is the. reduction in MCPR caused by the transient. The purpose of the fK factor of Figure 3.2.3-1 is to define operating limits at other than rated core flow conditions. At less than 100% of rated flow the required MCPR is the product of the MCPR and the K, factor. The K factors assure that the Safety Limit MCPR will not be violated during a flowf increase transient resulting from a motor generator speed control failure. The K 7 factors may be applied to both manual and automatic flow control modes. The K, factors values shown in Figure 3.2.3-1 were developed generically and are ap#licable to all BWR/2, BWR/3 and BWR/4 reactors. The K, factors were derived using the flow control line corresponding to RATED THERMAL PCWER at rated core flow. For the manual flow control mode, the Kf factors were calculated such that for the maximum flow rate, as limited by the pump scoop tube set point and the corresponding THERMAL POWER along the rated flow control line, the limiting bundle's relative power was adjusted until the MCPR changes with different core flows. The ratio of the MCPR calculated at a given point of core flow, diviced by the operating limit MCPR, determines the K . 7 HOPE CREEK B 3/4 2-4 L
POWER DISTRIBUTION LIMITS BASES MINIMUM CRITICAL POWER RATIO (Continued) For operation in the automatic flow control mode, the same procedure was employed except the initial power di t:ibution was established s'uch chat ti,e MCPR was equal to the operating limit MCPR at RATED THERMAL POWER and rated thermal flow. The K, factors shown in Figure 3.2.3-1 are conservative for the General Electric plant operation because the operating limit MCPRs of Specification 3.2.3 are greater than the original 1.20 operating limit MCPR used for the generic derivation of K . f At THERMAL POWER levels less than or equal to (25)% of RATED THERMAL POWER, the reactor will be oper'ating at minimum recirculation pump speed and the moderator voi.d. content will be very small. For all designated control rod patterns which may be employed at this point, operating plant experience indi-cates that the resulting MCPR value is in excess of requirements by a considerable margin. During initial start-up testing of the plant, a MCPR evaluation will be made at 25% of RATED THERMAL POWER level with minimum recircuiation pump speed. The MCPR margin will thus be demonstrated such that future MCPR evaluation below this power level will be shown to be unnecessary. The daily requirement for calculating MCPR when THERMAL POWER is greater than or equal to 25% of RATED THERMAL POWER is sufficient since power distribution shifts are very slow when there have not been significant power or control rod changes. The require-ment for calculating MCPR when a limiting control rod pattern is approached ensures that MCPR will be known following a change in THERMAL POWER or power shape, regardless of magnitude, that could place operation at a thermal limit. 3/4.2.4 LINEAR HEAT GENERATION RATE This specification dssures that the Linear Heat Generation Rate (LHGR) in any rod is less than the design linear heat generation even if fuel pellet densification is postulated.
References:
- 1. General Electric Company Analytical Model for Loss-of-Coolant Analysis in Accordance with 10 CF2 50, Appendix K, NEDE-20566, November 1975.
- 2. R. B. Linford, Analytical Methods of Plant Transient Evaluations for the GE BWR, NE00-10802, February 1973.
- 3. Qualification of the One Dimensional Core Transient Model for Boiling Water Reactors, NE00-24154, October 1978.
4 TASC 01-A Computer Program for the Transient Analysis of a Single Channel, Technical Description, NEDE-25149, January 1980. HOPE CREEK B 3/4 2-5
nD ua 3/4.3 INSTRUMENTATION 3 28 1985 : BASES 3/4.3.1 REAtf0R PROTECTION SYSTEM INSTRUMENTATION The reactor protection system automatically initiates a reactor scram to:
- a. Preserve the integrity of the fuel cladding.
- b. Preserve the integrity of the reactor coolant system.
- c. Minimize the energy which must be adsorbed following a loss of-coolant accident, and
- d. Prevent inadvertent criticality.
This spect'fication provides the limiting conditions for operation necessary to preserve the ability of the system to perform its intended function even during periods when instrument channels may be out of service because of main-tenance. When necessary, one channel may be made inoperable for brief intervals to conduct required surveillance. The reactor protection system is made up of two independent trip systems. There are usually four channels to monitor each parameter with two channels in each trip system. The outputs of the channels in a trip system are combined in a logic so that either channel will trip that trip system. The tripping of both trip systems will produce a reactor scram. The system meets the intent of IEEE-279 for nuclear power plant protection systems. The bases for the trip settings of the RPS are discussed in the bases for Specification 2.2.1. The measurement of response time at the specified frequencies provides assurance that the protective functions associated with each channel are com-pleted within the time limit assumed in the safety analyses. No credit was taken 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 measurement, provided such tests demonstrate the total channel response time as defined. Sensor response time verification may be demonstrated by either (1) inplace, onsite or offsite test measurements, or l (2) utilizing replacement sensors with certified response times. i HOPE CREEK B 3/4 3 1
dI INSTRUMENTATION JUN 28 W BASES 3/4.3.2 ISOLATION ACTUATION INSTRUMENTATION This specification ensures the effectiveness of the instrumaatation used to mitigate the consequences of accidents by prescribing the OPERABILIT trip setpoints and response times for isolation of the reactor systems. When necessary, one channel may be inoperable for brief intervals to conduct required surveillance. Some of the trip settings may have tolerances explicitly stated where both the high and low values are critical and may have a substantial effect on safety. The set-points of other instrumentation, where only the high or low end of the setting have a direct bearing on safety, are established at a level away from the normal operating range to prevent inadvertent actuation of the systems involved. Except for the MSIVs, the safety analysis does not address individual sensor response times or the response times of the logic systems to which the sensors are connected.- For-0.C. operated valves, a 3 second delay is assumed before the valve starts to move. For A.C. operated valves, it is assumed that the A.C. power supply is lost and is restored by startup of the emergency diesel generators. In this event, a time of 13 seconds is assumed before the valve starts to move. In addition to the pipe break, the failure of the D.C. operated valve is assumed; thus the signal delay (sensor response) is concurrent with the 13 second diesel startup. The safety analysis considers an allowable inventory loss in each case which in turn determines the valve speed in conjunc-tion with the 13 second delay. It follows that checking the valve speeds and tne 13 seccnd time for emergency power establishment will estaD ish the 1 response time for the isolation functions. , Operation with a trip set less conservative than its Trip Setpoint but within its specified Allowable Value is acceptable on the basis that the difference between each Trip Setpoint and the Allowable Value is equal to or less than the drift allowance assumed for each trip in the safety analyses. 3/4.3.3 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION The emergency core cooling system actuation instrumentation is provided to initiate actions to mitigate the consequences of accidents that are beyond i the ability of the operator to control. This specification provides the OPERABILITY requirements, trip setpoints and response times that will ensure effectiveness of the systems to provide the design protection. Although the instruments are listed by system, in some cases the same instrument may be used i to send the actuation signal to more than one system at the same time. Operation with a trip set less conservative than its Trip Setpoint out within its specified Allowable Value is acceptable on the basis that the difference between each Trip Setpoint and the Allowable Value is equal to or less than the drift allowance assumed for each trip in the safety analyses. HOPE CREEK B 3/4 3-2 I
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)g =I di 6h INSTRUMENTATION dljN 2 B E BASES 3/4.3.4 RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION The anticipated transient without scram (ATWS) recirculation pump trip system p.avides a means of limiting the consequences of the unlikely occurrence of a failure to scram during an anticipated transient. The response of the plant to this postulated event falls within the envelope of study events in General Electric Company Topical Report NEDO-10349, dated March 1971, NEDO-24222, dated December 1979, and Section 15.8 of the FSAR.
The end-of-cycle recirculation pump trip (EOC-RPT) system is a part of the Reactor Protection System and is an essential safety supplement to the reactor trip. The purpose of the EOC-RPT is to recover the loss of thermal margin which occurs at the end-of-cycle. The physical phenomenon involved is that the void reactivity feedback due to a pressurization transient can add positive reactivity to the reactor. system at a faster rate than the control rods add negative scram reactivity.- ' Each EOC-RPT system trips both recirculation pumps, reducing coolant flow in order to reduce the void collapse in the core during two of the most limiting pressurization events. The two events for which the EOC-RPT protective feature will function are closure of the turbine stop valves and fast closure of the turbine control valves. A fast closure sensor from each of two turbine control valves provides input to the EOC-RPT system; a fast closure sensor from each of the other two turbine control valves provides input to the second EOC-RPT system. Similarly, a (position switch) for each of two turbine stop valves provides input to one E0C-RPT system; a (position switch) from each of the other two stop valves provides input to the other EOC-RPT system. For each EOC-RPT system, the sensor relay > contacts are arranged to form a 2 out-of-2 logic for the fast closure of turbine I control valves and a 2-out-of-2 logic for the turbine stop valves. The operation of either logic will actuate the EOC-RPT system and trip both recirculation pumps. Each EOC-RPT system may be manually bypassed by use of a keyswitch which is administratively controlled. The manual bypasses and the automatic Operating Bypass at less than 30% of RATED THERMAL POWER are annunciated in the control room. The EOC-RPT system response time is the (time assumed in the analysis between initiation of valve motion and complete suppression of the electric l arc, i.e., 190 ms. Included in this time are: the response time of the sensor, the time allotted for breaker are suppression, and the response time of the system logic. Operation with a trip set less conservative than its Trip Setpoint but within its specified Allowable Value is acceptable on the basis that the difference between each Trip Setpoint and the Allowable value is equal to or less than the drift allowance assumed for each trip in the safety analyses. HOPE CREEK B 3/4 3-3
INSTRUMENTATION BASES 26 N 3/4.3.5 REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION The reactor core isolation cooling system actuation instrumentation is provided to initiate action M acsura adequit; : ore coc!ing :.. Lhe etc..t cf reactor isolation from its primary heat sink and the loss of feedwater flow to the reactor vessel without prowiding actuation of any of the eu rgerc" core cooling equipment. Operation with a trip set less conservative than its Trip Setpoint but within its specified Allowable Value is acceptable on the basis that the difference between each Trip Setpoint and the Allowable Value is equal to or less than the drift allowance assumed for each trip in the safety analyses. 3/4.3.6- CONTROL RCD BLOCK INSTRUMENTATION The control rod block functions are provided consistent with the requirements of the specifications in Section 3/4.1.4, Control Rod Program Controls and Section 3/4.2 Power Distribution Limits. The trip logic is arranged so .that a4 rip in any one of the inputs will result in.a control rod block. -- Operation with a trip set less conservative than its Trip Setpoint but within its specified Allowable Value is acceptable on the basis that the difference between each Trip Setpoint and the Allowable Value is equal to or less than the drift allowance assumed for each trip in the safety analyses. 3/4.3.7 MONITORING INSTRUMENTATION 3/4.3.7.1 RADIATION MONITORING INSTRUMENTATION The OPERABILITY of the radiation monitoring instrumentation ensures that; (1) the radiation levels are continually measured in the areas served by the individual channels, and (2) the alarm or automatic action is initiated when the radiation level trip setpoint is exceeded; and (3) sufficient information is available on selected plant parameters to monitor and assess these variables following an accident. This capability is consistent with 10 CFR Part 50, Appendix A, General Design Criteria 19, 41, 60, 61, 63 and 64. ! 3.4.3.7.2 SEISMIC MONITORING INSTRUMENTATION
! The OPERABILITY of the seismic monitoring instrumentation ensures that sufficient capability is available to promptly determine the magnitude of a seismic event and evaluate the response of those features important to safety.
l This capability is required to permit comparison of the measured response to that used in the design basis for the unit. This instrumentation is consistent with the recommendations of Regulatory Guide 1.12 " Instrumentation for Earthquakes," April 1974. l 3/4.3.7.3 METEOROLOGICAL MONITORING INSTRUMENTATION ! The OPERABILITY of the meteorological monitoring instrumentation ensures L that sufficient meteorological data is available for estimating potential radia-tion doses to the public as a result of routine or accidental release of ! radioactive materials to the atmosphere. This capability is required to evaluate the need for initiating protective measures to protect the health and safety of the public. This instrumentation is consistent with the recommenda-tions of Regulatory Guide 1.23 "Onsite Meteorological Programs," February,1972. HOPE CREEK B 3/4 3-4
INSTRUMENTATION BASES M MONITORING INSTRUMENTATION (Continued) 3 /4 ', . . 4 RC4TC SHUTDOWN nuivITORinG ltMRUMENTATION The OPE.1ADILITY of the remote shutdown monitoring instrumentation ensures that sufficient capability is available to permit shutdown and maintenance of HOT SHUT 00WN of the unit from locations outside of the control room. This capabil-ity is required in the event control room habitability is lost and is consistent with General Design Criteria 19 of 10 CFR 50. 3/4.3.7.5 ACCIDENT MONITORING INSTRUMENTATION The OPERABILITY of the accident monitoring instrumentation ensures that sufficient information is available on selected plant. parameters to monitor and assess important variables following an accident. This capability is consistent with the recommendations of Regulatory Guide 1.97, " Instrumentation for Light Water Cooled Nuclear Power Plants to Assess Plant Conditions During and Following an Accident," December 1980 and NUREG-0737, " Clarification of TMI Action Plan Requirements," November 1980. --, '3I4.3.7.6 SOURCE RANGE MONITORS ' The source range monitors provide the operator with information of the status of the neutron level in the core at very low power levels during startup and shutdown. At these power levels, reactivity additions shall not be made without this flux level information available to the operator. When the inter-mediate range monitors are on scale, adequate information is available without the SRMs and they can be retracted. 3/4.3.7.7 TRAVERSING IN-CORE PROBE SYSTEM The OPERABILITY of the traversing in-core probe system with the specified minimum complement of equipment ensures that the measurements obtained from use of this equipment accurately represent the spatial neutron flux distribution of the reactor core. 3/4.3.7.8 CHLORINE (AND AMMONIA) DETECTION SYSTEM (Optional) The OPERABILITY of the chlorine (and ammonia) detection system ensures that an accidental chlorine (and/or ammonia) release will be detected promptly and the necessary protective actions will be automatically initiated to provide protection for control room personnel. Upon detection of a high concentration of chlorine (and/or ammonia), the control room emergency ventilation system will automatically be placed in the (isolation) made of operation to provide the required protection. (The detection systems required by this specification are consistent with the recommendations of Regulatory Guide 1.95 " Protection of Nuclear Power Plant Control Room Operators against an Accidental Chlorine Release", (February 1975) (Revision 1, January, 1977).) HOPE CREEK B 3/4 3-5
% .-=
L [ "i INSTRUMENTATION g 2 5 'rs BASES MONITORING INSTRUMENTATION (Continued) 3/4.3.7.9 CHLORIDE INTRlFION MONIT0DS (0,t lc.ia!) The chloride intrusion monitors provide adequate warnina of any leakage - in the condenser or hotwell so that actions can be taken to mitigate the con-sequences of such intrusion in the reactor coolant system. With only a minimum number of instruments available increased sampling frequency provides adequate information for the same purpose. 3/4.3.7.10 FIRE DETECTION INSTRUMENTATION OPERABILITY of the detection instrumentation ensures that both adequate warning capability is available for prompt detection of fires and that fire suppression systems, that are actuated by fire detectors, will discharge extin-guishing agent in a timely manner. Prompt detection and suppression of fires will reduce the potential for damage to safety related equipment and is an integral element'in~the overall facility fire protection program. Fire detectors that are used to actuate fire suppression systems represent a more critically important component of a plant's fire protection program than detectors that are installed solely for early fire warning and notification. Consequently, the minimum number of OPERABLE fire detectors must be greater. The loss of detection capability for fire suppression systems, actuated by fire detectors, represents a significant degradation of fire protection for any area. As a result, the establishment of a fire watch patrol must be initi-ated at an earlier stage than would be warranted for the loss of detectors that provide only early fire warning. The establishment of frequent fire patrols in the affected areas is required to provide detection capability until the inoperable instrumentation is restored to OPERABILITY. 3/4.3.7.11 LOOSE-PART DETECTION SYSTEM The OPERABILITY of the loose part detection system ensures that sufficient capability is available to detect loose metallic parts in the primary system and avoid or mitigate damage to primary system components. The allowable out of-service times and surveillance requirements are consistent with the recem-mendations of Regulatory Guide 1.133, " Loose-Part Detection Program for the Primary System of Light-Water-Cooled Reactors," May 1981. 3/4.3.7.12 RADIOACTIVE GASEOUS !FFLUENT MONITORING INSTRUMENTATION The radioactive gaseous effluent aonitoring instrumentation is provided to monitor and control, as applicable, the releases of radioactive materials in gaseous effluents during actual or potential releases of gaseous effluents. Tne alarm / trip setpoints for these instruments shall be calculated and adjusted in accordance with the methodology and parameters in the 00CM utilizing the system design flow rates as specified in the ODCM. This conservative method is used be-cause the Fermi 2 design does not include flow rate measurement devices. This HOPE CREEK B 3/4 3-6
INSTRUMENTATION Jim 2 S TE BASES will ensure the alarm / trip will occur prior to exceeding the limits of 10 CFR Part 20. This instrumentation also includes provisions for monitoring and con-tre"(q th wcca.traticns .,7 ;ote.r.*dir axplosive gas mixtures in the main condenser offgas treatment system. The OPERABILITY and use of this instrumen-ta+ ion is consistent with the requirements of General Design Criteria 60, 63, and 64 of A.ppendix A to 10 CFR Part.50. 3/4.3.7.13 RADIOACTIVE LIQUID EFFLUENT MONITORING INSTRUMENTATION The radioactive liquid effluent monitoring instrumentation is provided to monitor and control, as applicable, the releases of radioactive materials in liquid effluents during actual or potential releases of liquid effluents. The alarm / trip setpoints for these instruments shall be calculated and adjusted in accordance with the methodology and parameters in the ODCM to ensure that the alarm / trip will occur prior to exceeding the limits of 10 CFR Part 20. The OPERABILITY.a_nd.use_of this instrumentation is consistent with the requirements of General tesign Criteria 60, 63, and 64 of Appendix A to 10 CFR Part 50. 3/4.3.8 TURBINE OVERSPEED PROTECTION SYSTEM This specification is provided to ensure that the turbine overspeed protection system instrumentation and the turbine speed control valves are OPERABLE and will protect the turbine from excessive overspeed. Protection from turbine excessive overspeed is required since excessive overspeed of the turbine could generate potentially damaging missiles which could impact and damage safety related components, equipment or structures. 3/4.3.9 FEEDWATER/ MAIN TURBINE TRIP SYSTEM ACTUATION INSTRUMENTATION The feedwater/ main turbine trip system actuation instrumentation is pro-vided to initiate action of the feedwater system / main turbine trip system in the event of high reactor vessel level due to failure of feedwater controller under-maximum climate. l 1 HOPE CREEK B 3/4 3-7
. . _ . _ . _ . . _ . _ _ . _ _ - i
) i JUN 2 8 re5 Bases Figure B 3/4 3-1 REACTOR VES3EL WATER LEVEL HOPE CREEK B 3/4 3-8
3/4.4 REACTOR COOLANT SYSTEM JUN 2 6 15E BASES 3/4.4.1 RECIRCULATION SYSTEM Operation with one reactor core coolant recirculation loop inoperable is
;.t.Mbit:d until an eve.lu:tlca cf tha 4.'fors.ance of the ECC5 uuring one loup operation has been performed, evaluated and determined to be acceptable.
An inoperable jet pump.is not, in itself, a sufficient reason to declare a recirculation loop inoperable, but it does, in case of a design-basis-accident, increase the blowdown area and reduce the capability of reflooding the core; thus, the requirement for shutdown of the facility with a jet pump inoperable. Jet pump failure can be detected by monitoring jet pump performance on a prescribed schedule for significant degradation. Recirculation pump speed mismatch limits are in compliance with the ECCS LOCA analysis design criteria. The limits will ensure an adequate core flow coastdown from either recirculation loop following a LOCA.
~
In orde7 to' prevent undue stress on the vessel nozzles and bottom head region, the recirculation loop temperatures shall be within 50*F of each other prior to startup of an idle loop. The loop temperature must also be within 50*F of the reactor pressure vessel coolant temperature to prevent thermal shock to the recirculation pump and recirculation nozzles. Since the coolant in the bottom of the vessel is at a lower temperature than the coolant in the upper
., regions of the core, undue stress on the vessel would result if the temperature difference was greater than 145*F.
The objective of GE BWR plant and fuel design is to provide stable operation with margin over the normal operating domain. However, at the high power / low flow corner of the operating domain, a small probability of limit cycle neutron flux oscillations exists depending on combinations of operating conditions (e.g., rodpattern,.powershape). To provide assurance that neutron flux limit cycle oscillations are detected and suppressed, APRM and LPRM neutron flux noise levels should be monitored while operating in this region. Stability tests at operating BWRs were reviewed to determine a generic region of the power / flow map in which surveillance of neutron flux noise levels should be performed. 'A conservation decay ratio of 0.6 was chosen as the bases for determining the generic region for surveillance to account for the plant to plant variability of decay ratio with core and fuel designs. This generic region has been determined to correspond to a core flow of less than or equal to 45%, of rated-core flow and a THERMAL POWER greater than that specified in Figure:3.4.1.1-1. Plant specific calculations can be performed to determine an applicable region for monitoring neutron flux noise levels. In this case the degree of conservatism can ,be reduced since plant to plant variability would be eliminated. In this case, adequate margin will be assured by monitoring the region which has a decay ratio gr' eater tnan or equal to 0.8. HOPE CREEK B 3/4 4-1
REACTOR COOLANT SYSTEM BASES JUN 2 8 G Neutron flux noise limits are also established to ensure early detection of limit cycle neutron flux oscillations. BWR cores typically operate with neutron flux noise caused by random boiling and flow noise. . Typical neutron flux noise levels of 1-12% of rated power (peak-to peak) have been reDorted for the range of low to a1yn recirculation loop flow during both single and dual recirculation loop operation. Neutron flux noise levels which significantly bound these values are c.onsidered in the thermal / mechanical design of GE BWR fuel and are found to be of negligible consequence. In addition, stability tests at operating BWRs have demonstrated that when stability related neutron flux limit cycle oscillations occur they result in peak-to peak neutron flux limit cycles of 5-10 times the typical values. Therefore, actions taken to reduce neutron flux noise levels exceeding three (3) times the typical value are suf-ficient to ensure early detection of limit cycle neutron flux oscillations. Typically, neutron flux noise levels show a gradual increase in absolute magnitude as core flow i,s increased (constant control rod pattern) with two reactor recirculation lodps in operation. Therefore, the baseline neutron flux noise level obtained at a specific core flow can be applied over a range of core flows. To' maintain a reasonable variation between the low flow and high flow end of the flow range, the range over which a specific baseline is applied should not exceed 20% of rated core flow with two recirculation loops in operation. Data % from tests and operating plants indicate that a range of 20% of rated core flow will result in approximately a 50% increase in neutron flux noise level during operation with two recirculation loops. Baseline data should be taken near the maximum rod line at which the majority of operation will occur. However, base-line date taken at lower rod lines (i.e., lower power) will result in a conser-vative value since the neutron flux noise level is proportional to the power level at a given core flow. 3/4.4.2 SAFETY / RELIEF VALVES The safety valve function of the safety / relief valves operates'to prevent the reactor coolant system from being pressurized above the Safety Limit of 1375 psig in accordance with the ASME Code. A total of 13 OPERABLE safety / relief l valves is required to limit reactor pressure to within ASME III allowable values for the worst case upset transient. l Demonstration of the safety / relief valve lift settings will occur only l during shutdown. The safety / relief valves will be removed and either set pres-sure tested or replaced with spares which have been previously set pressure tested and stored in accordance with manufacturers recommendations in the speci-fied frequency. , HOPE CREEK B 3/4 4-2 L
REACTOR COOLANT SYSTEM BASES 3/4.4.3 REACTOR COOLANT SYSTEM LEAKAGE y 2 B TE 3/4.4.3.1 LEAKAGE DETECTION SYSTEMS The RCS leakage @ tcetio. P tc.c required by this specification are provided to monitor and detect leakage from the reactor coolant pressure boundary. These detection systems are consistent with the recommendations of Regulatory Guide 1.45, " Reactor Coolant Pressure Boundary Leakage Detection Systems", May 1973. 3/4.4.3.2 OPERATIONAL LEAKAGE The allowable leakage rates from the reactor coolant system have been based on the predicted and experimentally observed behavior of cracks in pipes. The normally expected background leakage due to equipment design and the detection capability of the instrumentation for determining system leakage was also con-sidered. The evidence obtained from experiments suggests that for leakage somewhat greater than that specified for UNIDENTIFIED LEAKAGE the probability is small that the imperfection or crack associated with such leakage would grow rapidly. Hoseve'r, in all cases, if the leakage rates exceed the values specified or the leakage is located and known to be PRESSURE BOUNDARY LEAKAGE, the reactor will be shutdown to allow further investigation and corrective action. The Surveillance Requirements for RCS pressure isolation valves provide added assurance of valve integrity thereby reducing the probability of gross valve failure and consequent intersystem LOCA. Leakage from the RCS pressure isolation valves is IDENTIFIED LEAKAGE and will be considered as a portion of the allowed limit. 3/4.4.4 CHEMISTRY The water chemistry limits of the reactor coolant system are established to prevent damage to the reactor materials in contact with the coolant. Chloride limits are specified to prevent stress corrosion cracking of the stainless steel. The effect of chloride is not as great when the oxygen concentration in the coolant is low, thus the 0.2 ppm limit on chlorides is permitted during POWER OPERATION. During shutdown and refueling operations, the temperature necessary for stress corrosion to occur is not present so a 0.5 ppm concentration of chlorides is not considered harmful during these periods. Conductivity measurements are required on a continuous basis since changes in this parameter are an indication of abnormal conditions. When the conductivity is within limits, the pH, chlorides and other impurities affecting conductivity must also be within their acceptable limits. With the conductivity meter inoperable, additional samples must be analyzed to ensure that the chlorides are not exceeding the limits. The surveillance requirements provide adequate assurance that concentrations in excess of the limits will be detected in sufficient time to take corr ective action. HOPE CREEK B 3/4 4-3
REACTOR COOLANT SYSTEM h BASES M 3/4.4.5 SPECIFIC ACTIVITY The li..it-thns ca the specific activity of tne primary coolant ensure that the 2 hour thyroid and whole body doses resulting from a main steam line failure outside the u tainment during steady state operation will not exceed small fractions of the dose guidelines of 10 CFR 100. The values for the limits on specific activity represent interim limits based upon a parametric evaluation by the NRC of typical site locations. These values are conservative in that specific site parameters, such as site boundary location and meteorological conditions, were not considered in this evaluation. The ACTION statement permitting POWER OPERATION to continue for limited time periods with the primary coolant's specific activity greater than 0.2 microcuries per gram DOSE EQUIVALENT I-131, but less than or equal to 4.0 micro-curies per gram DOSE EQUIVALENT I-131, accommodates possible iodine spiking phenomenon which.may occur following changes in THERMAL POWER. Operation with specific activity levels exceeding 0.2 microcuries per gram DOSE EQUIVALENT I-131 but less than or equal to 4.0 microcuries per gram DOSE EQUIVALENT I-131 must be restricted to no more than 800 hours per year, approximately 10 percent of the unit's yearly operating time, since these activity levels increase the 2 hour thyroid postulated steamdose lineatrupture. the site boundary by a factor of up to 20 following a The reporting of cumulative operating time over 500 hours in any 6 month consecutive period with greater than 0.2 micro-curies per gram DOSE EQUIVALENT I-131 will allow sufficient time for Commission evaluation of the circumstances prior to reaching the 800 hour limit. Infor: nation obtained on iodine spiking will be used to assess the parameters associated with spiking phenomena. A reduction in frequency of isotopi analysis the data obtained. following power changes may be permissible if justified by Closing the main steam line isolation valves prevents the release of activity to the environs should a steam line rupture occur outside containment. 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. HOPE CREEK B 3/4 4-4
REACTOR COOLANT SYSTEM BASES 3/4.4.6 PRESSURE / TEMPERATURE LIMITS g 2 8 $85 All components in the reactor coolant system are designed to withstand the effects of cyclic loads due to system temperature and pressure chaaces. The.c cyclic loar.:;, ca i. t.had s' y normal load transients, reactor trips, and startup and shutdown operations. The various categories of load cycles used for design purposes are provided in Section (4.9) of the FSAR. During startup and shutdown, the rates of temperature and pressure changes are limited so that the maximum specified heatup and cooldown rates are consistent with the design assumptions and satisfy the stress limits for cyclic operation. The operating limit curves of Figure 3.4.6.1-1 are derived from the fracture toughness requirements of 10 CFR 50 Appendix G and ASME Code Section III, Appen-dix G. The curves are based on the RTNDT and stress intensity factor information for the reactor vessel components. Fracture toughness limits and the basis for compliance are more fully discussed in FSAR Chapter 5, Paragraph 5.3.1.5, " Frac-ture Toughness.". RT The reactor vessel materials have been tested to determine their initial NDT. The results of these tests are shown in Table B 3/4.4.6-1. Reactor operation and resultant fast neutron, E greater than 1 MeV, irradiation will cause an increase in the RT Therefore, an adjusted reference temperature, NDT. based upon the fluence, phosphorus content and copper content of the material in question, can be predicted using Bases Figure B 3/4.4.6-1 and the recommenda-tions of Regulatory Guide 1.99, Revision 1, " Effects of Residual Elements on Predicted Radiation Damage to Reactor Vessel Materials." The pressure / tempera-ture limit curve, Figure 3.4.6.1-1, curves A', 8' and C', includes predicted adjustments for this shif t in RT f r the end of life fluence, as well as NDT adjustments for possible errors in the pressure and temperature sensing instruments. The actual shift in RT NDT f the vessel material will be established period-ically during operation by removing and eval m ting, in accordance with ASTM E185-73 and 10 CFR 50, Appendix H, irradiated reactor vessel material specimens installed near the inside wall of the reactor vessel in the core area. The irradiated specimens can be used with confidence in predicting reactor vessel material transition temperature shift. The operating limit curves of Figure 3.4.6.1-1 shall be adjusted, as required, on the basis of the specimen data and recommendations of Regulatory Guide 1.99, Revision 1. HOPE CREEK 8 3/4 4-5
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g REACTOR COOLANT SYSTEM , ,
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BASES I g ic M PRESSURE / TEMPERATURE LIMITS (Continued) > f The pressure-temperature limit linee shown# i n figures 3.4.6.1-1, t'irv.--t . C, and C', ..a r, ano A', tor reactor c 'i.icality and for inservice leak and hydrostatic testing have been providet to assure. compliance with the minimum temperature requin ea.ents of Apoandix G to 10 CFR Part S0 for reactor criticality l and for inservice leak and hydrostatic testing. The number of reactor vessel irradiation surnillance capsules and the j frequencies for removing and testing the specimens in these capsules are pro-vided in Table 4.4.6.1.3-1 to assure compliance vith the requirements of Appen- j 4 dix H to 10 CFR Part 50. , 3/4.4.7 MAIN STEAM LINE ISOLATION VALVES Double isolation valves are provided on eabh of the main steam lines to minimize the-potential leakage paths from the containment in case of a line break. OnTy^ one valve in each~ iine is required to maintain the integrity of the containment, however, single failure considerations require that two valves be OPERABLE. The surveillance requirements are based on the operating history of this type valve. The maximum closure time has been selected to # contain fission products and to ensure the core is not uncovered followir.g i line breaks. The minimum closure time is consistent with the assumptions - in the safety analyses to prevent pressure surges. 3/4.4.8 STRUCTURAL INTEGRITY
+
The inspection programs for ASME Code Class 1, 2 a.go 3 components ensure - that the structural integrity of these components will be maintained at an - acceptable' level throughout the life of the plant.
% c Components of the reactor coolant system were designed to provide access '
to permit inservice inspections in accordance with Section XI of the ASME Boiler J. and Pressure Vessel Code 1977 Edition ard Addenda through Summer 1978. The inservice inspection program for ASME Code Class 1, 2 and 3 components will be performed in accordance with Section XI of the ASME Boiler and Pressure Vessel Code and applicable addenda as required by 10 CFR Part 50.55a(g) excert where specific written relief'has been granted by the NRC pursuant to 10 CFR C Part 50.55a(g)(6)(1). > 3/4.4.9 RESIOUAL HEAT REMOVAL A single shutdown cooling mode loop prevides sufficient heat removal capability for removing core decay heat and mixihg to assure accurate tempera-ture indication, however, single failure considerations require that two loops be OPERABLE or that alternate metnods capable of decay heat removal be demonstrated and that ar alternate method of coolant mixing be in operation. . HOPE CREEK B 3/4 4-6
BASES TABLE B 3/4.4.6-1 x REACTOR VESSEL TOUGHNESS O m liEAT/ SLAB HIGHEST PREDICTED UNIRRADIATED MAX. E0L g BELTLINE WELD SEAM I.D. OR UPPER SHELF m RT A RT COMPONENT OR MAT't TYPE ilEAT/ LOT CU(%) P(%) NDT( F) NOT(*F) RT (FT-LBS) NOT(*F) Plate SA-533 GR B CL.1 SK3025-1 .15 .012 +1h 20 '6 +39 Weld Long. seams for 055040/ . 08- .010 -3Q 17 135 -13 shells 4&S and girth 1125-02000 weld between 4&S NOTE:
- These values are given only for the benefit of calculating the end-of-life (EOL) RT H0T' HEAT / SLAB HIGHEST REFERENCE NON-BELTLINE MI'L TYPE OR OR COMPONENT gMPERATURE WELD SEAM I.D. IIEAT/ LOT NDT (*F) m _
R Shell Ring Connected to SA 533, GR.8, C1.1 All Heats +19 3- Vessel Flange y Bottom Head Dome SA 533, GR.B, C1.1 All Heats +30 N Bottom liead Torus SA 533, GR.R, C1.1 All Heats +30 LPCI Nozzles SA 508, C1.2 All Heats -20 Top Head Torus SA 533, GR.8, C1.1 All lleats +19 Top Head Flange SA 508, C1.2 All 11 eats +10 Vessel Flange SA 508, C1.2 All lleats +10 feedwater Nozzle SA 508, C1.2 All lleats -20 Weld Metal All RPV Welds All lleats O Closure Studs SA 540, GR.8, 24 All Heats Meet 45 ft-lbs & 25 mils lateral expansion at +10*F The design of the llope Creek vessel results in these nozzles experiencing a predict'ed EOL f1tence at 1/4T of the vessel thickness of 1.6 x 10 " h/cm2 . Therefore, these nozzles are predicted to have an EOL RT NDT f -6 F. C N fj M
~. 3
JUN 2 81985 1 s - m
't Service Life (Years *)
Fast Neutron Fluence (E 1 Mev) at k T As a Function of Service Life
- Bases Ficure B 3/4.4.6-1
- At-(90,)% of RATED THERMAL POWER and (90)% availability
- HG?E CREEK' B 3/4 4-8 n ainn i i mi i iii- --
3/4.5 EMERGENCY CORE COOLING SYSTEM BASES 3/4.5.1 and 3/4.5.2 ECCS - OPERATING and SHUTDOWN The core spray system (CSS), together with the LPCI mode of the RHR system, is provided to assure that the core is adequately cooled following a loss-of- . coolant accident and provides adequate core cooling capacity for all break sizes up to and including the double-ended reactor recirculation line break, and for smaller breaks following depressurization by the ADS. The CSS is a primary source of emergency core cooling after the reactor vessel is depressurized and a source for flooding of the core in case of accidental draining. The surveillance requirements provide adequate assurance that the CSS will be OPERABLE when required. Although all active components are testable and full flow can be demonstrated by recirculation through a test loop during reactor operation, a complete functional test requires reactor shutdown. The pump discharge piping is maintained full to prevent water hammer damage to piping and to start cooling at the earliest moment. The low pressure coolant injection (LPCI) made of the RHR system is provided to assure that the core is adequately cooled following a loss-of-coolant' accident.. Four subsystems, each with one pump, provide adequate core flooding for all break sizes up to and including the double-ended reactor recirculation line break, and for small breaks following depressurization by the A05. The surveillance requirements provide adequate assurance that the LPCI system will be OPERABLE when required. Although all active components are testable and full flow can be demonstrated by recirculation through a test loop during reactor operation, a complete functional test requires reactor shutdown. The pump discharge piping is maintained full to prevent water i hammer damage to piping and to start cooling at the earliest moment. . The high pressure coolant injection (HPCI) system is provided to assure that the reactor core is adequately cooled to limit fuel clad temperature in the event of a small break in the reactor coolant system and loss of coolant which does not result in rapid depressurization of the reactor vessel. The HPCI system permits the reactor to be shut down while maintaining sufficient reactor vessel water level inventory until the vessel is depressurized. The HCPI system continues to operate until reactor vessel pressure is below the pressure at which CSS operation or LPCI mode of the RHR system operation maintains core cooling. ene capa4tby oi *heL System iS Selected to proVice Ine required Core Coollng. The HPCI pump is designed to deliver greater than or equal to 5600 gpm at differential pressures between 1279 and 368 psid. Initially, water.from the condensate storage tank is used'instead of injecting water from the suppression pool into the reactor, but no credit is taken in the safety analyses for the condensate storage tank water. HOPE CREEK B 3/4 5-1
EMERGENCY CORE COOLING SYSTEM BASES ECCS-OPERATING and SHUTDOWN (Continued) With the HPCI system inoperable, adequate core cooling is assured by the OPEPABILUY M the r#4ndant ard diV2rdfi!I " tr.'at#~ @pressuriZath 4 UO ta. and both the CS and LPCI systems. In addition, the reactor core isolation cooling (RCIN system, (a system for which r.: credit is taken in the safety analysis), will automatically provide makeup at reactor operating pressures on a reactor low water level condition. The HPCI out-of-service period of 14 days is based on the demonstrated OPERABILITY of redundant and diversified low pressure core cooling systems and the RCIC system. The surveillance requirements provide adequate assurance that the HPCI system will be OPERABLE when required. Although all active components are testable and full flow can be demonstrated by recirculation through a test loop during reactor operation, a complete functional test with reactor vessel injection requires reactor shutdown. The pump discharge piping is maintained full to prevent water hammer damage and to provide cooling at the earliest moment. ,- - - Upon failure of the HPCI system to function properly after a small break loss-of-coolant accident, the automatic depressurization system (ADS) automa-tically causes selected safety-relief valves to open, depressurizing the reactor so that flow from the low pressure core cooling systems can enter the core in time to limit fuel cladding temperature to less than 2200*F. ADS is conserva-tively required to be OPERABLE whenever reactor vessel pressure exceeds (100) psig. This pressure is substantially below that for which the low pressure core cooling systems can provide adequate core cooling for events requiring ADS. ADS automatically controls five selected safety-relief valves although the safety analysis only takes credit for four valves. It is therefore appropriate to permit one valve to be out-of-service for up to 14 days without materially reducing system reliability. 3/4.5.3 SUPPRESSION CHAMBER I The suppression chamber is required to be OPERABLE as part of the ECCS to ensure that a sufficient supply of water is available to the HPCI, CS and LPCI systems in the event of a LOCA. This limit on suppression chamber minimum water volume ensures that sufficient water is available to permit recirculation cooling flow to the core. The OPERABILITY of the suppression chamber in l OPERATIONAL CONDITIONS 1, 2 or 3 is also required by Specification 3.6.2.1. l Repair work might require making the suppression chamber inoperable. This l specification will permit those repairs to be made and at the same time give assurance that the irradiated fuel has an adequate cooling water supply when the suppression chamber must be made inoperable, including draining, in ! OPERATIONAL CONDITION .1 or 5. In OPERATIONAL CONDITION 4 and 5 the suppression chamber minimum required water volume is reduced because the reactor coolant is maintained at or below 200 F. Since pressure suppression is not required below 212 F, the minimum water volume is based on NPSH, recirculation volume and vortex prevention plus l a 2'-4" safety margin for conservatism. l HOPE CREEK B 3/4 5-2 l
DRAFT 3/4.6 CONTAINMENT SYSTEMS 3m 2 8 h.. BASES 3/4.6.1 PRIMARY CONTAINMENT 2/4.6.1.1 TMNAV C0idiAINHENT INTEGRI ff PRIMARY CONTAINMENT INTEGRITY ensures that tne release of radioactive mate-rials from the containment atmosphere will be restricted to those leakage paths and associated leak rates assumed in the accident analyses. This restriction, in conjunction with the leakage rate. limitation, will limit the site boundary radiation doses to within the limits of 10 CFR Part 100 during accident conditions. 3/4.6.1.2 PRIMARY CONTAINMENT LEAKAGE The limitations on primary containment leakage rates ensure that the total containment leakage volume will not exceed the value assumed in the accident analyses at the peak accident pressure of 48,1 psig, P,. As an added conserva-tism, the measured-overall integrated leakage rate is further limited to less than or eqtial to 0.75 L during performance of the periodic tests to account for possible degradation of,the containment leakage barriers between leakage tests. Operating experience with the main steam line isolation valves has indicated that degradation has occasionally occurred in the leak tightness of the valves; therefore the special requirement for testing these valves. The surveillance testing for measuring leakage rates is consistent with the requirements of Appendix "J" of 10 CFR Part 50 with the exception of exemptions granted for main steam isolation valve leak testing and testing the airlocks after each opening. 3/4.6.1.3 PRIMARY CONTAINMENT AIR LOCKS The limitations on closure and leak rate for the primary containment air locks are required to meet the restrictions on PRIMARY CONTAINMENT INTEGRITY and the primary containment leakage rate given in Specifications 3.6.1.1 and 3.6.1.2. The specification makes allowances for the fact that there may be long periods of time when the air locks will be in a closed and secured position during reactor operation. Only one closed door in each air lock i is required to maintain the integrity of the containment. 3/4.6.1.4 MSIV SEALING SYSTEM Calculated doses resulting from the maximum leakage allowance for the main
- steamline isolation valves in the postulated LOCA situations would be a small
! fraction of the 10.CFR 100 guidelines, provided the main steam line system from the isolation valves up tc and including the turbine condanscr rcmains intact. Operating experience has indicated that degradation has occasionally occurred in the leak tightness of the MSIV's such that the specified leakage requirements have not always been maintained continuously. The requirement.for the sealing system will reduce the untreated leakage from the MSIVs when isolation of the primary system and containment is required. HOPE CREEK B 3/4 6-1
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CONTAINMENT SYSTEMS JLRt .85 BASES 3/4.6.1.5 DRYWELL ANy_ SUPPRESSION CHAMBER INTERNAL PRESSURE ine limitations on drywell and suppression chamber internal pressure ensure that the containment peak pressure of 48.1 psig does not exceed the design pressure of 62 psig during LOCA conditions or that the external pressure differential does not exceed the design maximum external pressure differential of 3 psid. The limit of -0.5 to +1.5 psig for initial positive containment pressure will limit the total pressure to 48.1 psig which is less than the design pressure and is consistent with the safety analysis. 3/4.6.1.7 DRYWELL AVERAGE AIR TEMPERATURE The limitation on drywell average air temperature ensures that the containment peak air temperature does not exceed the design temperature of 340 F during LOCA conditions and is consistent with the safety analysis. 3/4.6.1.8 'DRYWELL AND SUPPRESSION CHAMBER PURGE SYSTEM The 26-inch and 24-inch drywell and suppression chamber purge supply and -i exhaust isolation valves are required to be sealed closed during plant operation
. since these valves have not been demonstrated capable of closing during a LOC.A or steam line break accident. Maintaining these valves sealed closed during plant operations ensures that excessive quantities of radioactive materials will not be released via the containment purge system. To provide assurance that the 26-inch and the 24-inch valves cannot be inadvertently opened, they are sealed closed in accordance with Standard Review Plan 6.2.4, which includes mechanical devices to seal or lock the valve closed or prevent power from being supplied to the valve operator.
A HOPE CREEK B 3/4 6-2
CONTAINMENT SYSTEMS gN28 N BASES ORYWELL AND SUPPRESSION CHAMBER PURGE SYSTEM (Continued) Tha use of t.M drywell and s::pression ch=ber purge li. e= .i. p.assur e control is restricted with the following exception, the inboard 26-inch valve on the drywell purge outlet vent line when used in conjunction with '.: e. 2-inch purge outlet vent line bypass valve since the 2-inch valves will close during a LOCA or steam line break accident and therefore the site boundary dose guidelines of 10 CFR Part 100 would not be exceeded in the event of an accidtnt during purging operations. In addition due to the limited flow rate through-the 2-inch bypass valve, the inboard 26-inch valve is also capable of closing under these conditions. The design of the 2-inch purge supply and exhaust isolation valves meets the requirements of Branch Technical Position CSB 6-4, " Containment Purging During Normal Plant Operations." Leakage integrity tests with a maximum allowable leakage rate for purge supply and exhaust isolation valves will provide early indication of resilie,t material seaTde' gradation and will allow the opportunity for repair before gross leakage failure develops. The 0.60 L leakage limit shall not be exceeded when the leakage rates determined by the l$akage integrity tests of these valves are added to the previously determined total for all valves and penetrations subject to Type B and C tests. 3/4.6.1.9 PRIMARY CONTAINMENT PENETRATION PRESSURIZATION SYSTEM (Optional) The OPERABILITY of the primary containment penetration pressurization system is required to meet the restrictions on overall containment leak rate assumed in the accident analyses. (The Surveillance Requirements for determining OPERABILITY are consistent with Appendix "J" of 10 CFR 50.) 3/4.6.2. DEPRESSURIZATION SYSTEMS The specifications of this section ensure that the primary containment pressure will not exceed the design pressure of (59) psig during primary system blowdown from full operating pressure. The suppression chamber wate_r provides the heat sink for the reactor coolant system energy release following a postulated rupture of the system. The suppression chamber water volume must absorb the associated decay and structural sensible neat released during reactor coolant system blowcown from 1025 psig. Since all of the gases in the drywell are purged into the suppression chamber air space during a loss of coolant accident, the pressure of the liquid must not exceed 62 psig, the suppression chamber maximum internal design pressure. The design volume of the suppression chamber, water and air, was obtained by considering that the total volume of reactor coolant and to be considered is discharged to the sucoression chamber and that the drywell volume is purged to the suppression chamber. , Using the minimum or maximum water volumes given in this specification, containment pressure during the design basis accident is approximately 48.1 psig HOPE CREEK B 3/4 6-3
assume B
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&e J CONTAINMENT SYSTEMS JUN 28 1S25 BASES DEPRESSURIZATION SYSTEMS (Continued) whi:h h below the de*i';n prescu'*a of E2 ,si]. 'hvinum water *'ci.m.. cf 122,000 fta results in a downcomer submergence of 3.33 ft and the minimum volume of 118,000 ft3 results in a submergence vprnximtely 3.0 ft. The majority of the Bodega tests were run with a submerged length of four feet and with complete condensation. Thus, with respect to the downcomer submergence, this specification is adequate. The maximum temperature at the end of the blowdown tested during the Humboldt Bay and Bodega Bay tests was 170 F and this is con-servatively taken to be the limit for complete condensation of the reactor coolant, although condensation would occur for temperatures above 170 F.
Should it be necessary to make the suppression chamber inoperable, this shall only be done as specified in Specification 3.5.3. Under full power operating conditions, blowdown from an initial suppression chamber water temperature of 95 F results in a water temperature of approx-imately 135'F'immediately following blowdown which is below the 200 F used for complete condensation via mitered T quencher devices. At this tempera-ture and atmospheric pressure, the available NPSH exceeds that required by both the RHR and core spray pumps, thus there is no dependency on containment over-pressure during the accident injection phase. If both RHR loops are used for containment cooling, there is no dependency on containment overpressure for post-LOCA operations. Experimental data indicates that excessive steam condensing loads can be avoided if the peak local temperature of the suppression pool is maintaineo below 200 F during any period of relief valve operation. Specifications have been placed on the envelope of reactor operating conditions so that the reactor can be depressurized in a timely manner to avoid the regime of potentially high suppression chamber loadings. Because of the large volume and thermal capacity of the suppression pool, the volume and temperature normally changes very slowly and monitoring these parameters daily is sufficient to establish any temperature trends. By requiring the suppression pool temperature to be frequently recorded during periods of significant heat addition, the temperature trends will be closely followed so that appropriate action can be taken. The requirement for an external visual examination following any event where potentially high loadings could occur pro-vides assurance that no significant damage was encountered. Particular atten-tion should be focused on structural discontinuities in the vicinity of the relief valve discharge since these are expected to be the points of highest stress. In addition to the limits on temperature of the suppression chamber pool water, operating procedures define the action to be taken in the event a safety-relief valve inadvertantly opens or sticks open. As a minimum this action shall . include: (1) usa cf all svailabic mcons to cle:c the v lvc, (2) initiate :uppres-sion pool water cooling, (3) initiate reactor shutdown, and (4) if other safety- . relief valves are used to depressurize the reactor, their discharge shall be separated from that of the stuck-open safety relief valve to assure mixing and uniformity of energy insertion to the pool. HOPE CREEK B 3/4 6-4
i I CONTAINMENT SYSTEMS Nb C:a2 "
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BASES M 3/4.6.3 PRIMARY CONTAINMENT ISOLATION VALVES Th. '"'EP.A :* :TY cf the primary containment isolation vaives ensures that the containment atmosphere will be isolated from the outside environment in the event of a release cf radioactive material to the containment atmosphere or pressurization of the containment (and is consistent with the requirements of GDC 54 through 57 of Appendix A of 10 CFR 50). Containment isolation within the time limits specified for those isolation valves designed to close auto-matically ensures that the release of radioactive material to the environment will be' consistent with the assumptions used in the analyses for a LOCA. 3/4.6.4 VACUUM RELIEF Vacuum relief breakers are provided to equalize the pressure between the suppression chamber and drywell and between the Reactor Building and suppres-sion chamber....This-system will maintain the structural integrity of the primary containment' under conditions of large differential pressures. The vacuum breakers between the suppression chamber and the drywell must not be inoperable in the open position since this would allow bypassing of the suppression pool in case of an accident. 3/4.6.5 SECONDARY CONTAINMENT Secondary containment is designed to minimize any ground level release of radioactive material which may result from an accident. The Reactor Building and associated structures provide secondary containment during normal operation when the drywell is sealed and in service. At other times the drywell may be open and, when required, secondary containment integrity is specified. Establishing and maintaining a 0.25 inch water gage vacuum in the reactor building with the filtration recirculation and ventilation system (FRVS) once per 18 months, along with the surveillance of the doors, hatches, dampers and valves, is adequate to ensure that there are no violations of the integrity of the secondary containment. The OPERABILITY of the FRVS ensures that sufficient iodine removal capa-bility will be available in the event of a LOCA. The reduction in containment iodine inventory reduces the resulting site boundary radiation doses associated with containment leakage. The operation of this system and resultant iodine removal capacity are consistent with the assumptions used in the LOCA analyses. Continuous operation of the system with the heaters and humidity control instru-ments OPERABLE for 10 hours during each 31 day period is sufficient to reduce the builduo of moisture on the adsorbers and HEPA filters. HOPE CREEK B 3/4 6-5
l CONTAINMENT SYSTEMS i
.R#( 2 8 1985 l BASES 3/4.6.6 PRIMARY CONTAINMENT ATMOSPHERE CONTROL The OPERABILITY of the systems required for the detection and control of hydragan gas ensures that these sysieras wi'l be available to maintain the hydrogen concentration within the primary containment below its flammable limit during post-LOCA conditions. Either containment hydrogen recombiner is capable of controlling the expected hydrogen generation associated with (1) zirconium-water reactions, (2) radiolytic decomposition of water and (3) corrosion of metals within containment. The hydrogen control system is consistent with the recommendations of Regulatory Guide 1.7, " Control of Combustible Gas Concen-trations in Containment Following a LOCA" (March 1971.)
HOPE CREEK B 3/4 6-6
QQ \\ . 3/4.'7 PLANT SYSTEMS Ud BASES UM 3/4.7.1 SERVICE WATER SYSTEMS The OPERABILITY of the station service water and the safety auxiliaries cooling systems ensures that sufficient cooling capacity is available for con-tinued comration of safety-related equist.cnt during .~,u..:a1 oiid accioent cond1-tions. The redundant cooling capacity of these systems, assuming a single failure,.is consistent with the assumptiens used in the acc! dent conditions within acceptable limits. 3/4.7.2 CONTROL ROOM EMERGENCY FILTRATION SYSTEM-The OPERABILITY of the control room emergency filtration system ensures that 1) the ambient air temperature does not exceed the allowable temperature for continuous duty rating for the equipment and instrumentation cooled by this system and 2) the control room will remain habitable for operations personnel during and following all-design basis accident conditions. Continuous operation of the system with the heaters and humidity control instruments OPERABLE for 10 hours during each 31 day period is sufficient to reduce the buildup of
~
moisture on ~tte 'adiorbers and HEPA filters. The OPERABILITY of this system in conjunction with control room design provisions is based on limiting the radia-tion exposure to personnel occupying the control room to 5 rem or less whole body, or its equivalent. This limitation is consistent with the requirements ,, , of General Design Criteria 19 of Appendix "A",10 CFR Part 50. i 3/4.7.3. FLOOO PROTECTION (Optional)
.The requirement for flood protection ensures that facility protective actions will be taken and operation will be terminated in the event of flood conditions. The limit of elevation 10.5 Mean Sea Level is based on the maximum elevation at which facility flood control measures provide protection to safety
- related equipment.
- 3/4.7.4' REACTOR CORE ISOLATION COOLING SYSTEM The reactor core isolation cooling (RCIC) system is provided to assure adequate core cooling in the event of reactor isolation from its primary heat sink and the loss of feedwater flow to the reactor vessel without requiring actuation of any of the Emergency Core Cooling System equipment. The RCIC system is conservatively required to be OPERABLE whenever reactor pressure exceeds 150 psig. This pressure is substantially below that for which the
, RCIC system can provide adequate core cooling for events requiring the RCIC system. The RCIC system specifications are applicable during OPERATIONAL CONDITIONS 1, 2 and 3 when reactor vessel pressure exceeds 150 psig because RCIC is the primary non-ECCS source of emergency core cooling when the reactor is predburized. ~
- With the RCIC system inoperable, adequate core cooling is assured by the OPERABILITY of the HPCI system and justifies the specified 14 day out-of-service period.
i HOPE CREEK B 3/4 7-1
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l PLANT SYSTEMS n9' I
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)
BASES JUN 2 8 EE5 REACTOR CORE ISOLATION COOLING SYSTEM (Continued) The surveillance requirements provide adequate assurance that RCIC will
.,e CPC.';A6t.E when requirea. Although a 1 active components are testable and full flow can be demonstrated by recirculation during reactor operation, a ci. ylete functiunal test requires reactos snutdown. The pump discharge piping is maintained full to prevent water hammer damage and to start cooling at the earliest possible moment.
3/4.7.5 SNUBBERS All snubbers are required OPERABLE to ensure that the structural integrity of the reactor coolant system and all other safety related systems is maintained during and following a seismic or other event initiating dynamic loads. Snub-bers excluded from this inspection program are those installed on nonsafety-related systems and then only if their failure or failure of the system on which they are installed would have no adverse effect on any safety related system. Snubbers are classified and grouped by design and manufacturer but not by size. For example, mechanical snubbers utilizing the same design features of the 2-kip,10-kip, and 100-kip capacity manufactured by Company "A" are of the same type. The same design mechanical snubbers manufactured by Company "B" for the purposes of this Technical Specification would be of a different type, as would hydraulic snubbers from either manufacturer. A list of individual snubbers with detailed information of snubber location and size and of system affected shall be available at the plant in accordance with Section 50.71(c) of 10 CFR Part 50. The accessibility of each snubber shall be determined and approved by the Plant Operations Review Committee. The determination shall be based upon the existing radiation levels and the expected time to perform a visual inspection in each snubber location as well as other factors associated with accessibility during plant operations (e.g., temperature, atmosphere, location, etc.), and the recommendations of Regulatory Guide 8.8 and 8.10. The addition or deletion of any snubber shall be made in accordance with Section 50.59 of 10 CFR Part 50. The visual inspection frequency is based upon maintaining a constant level of snubber protection to each safety-related system. Therefore, the required inspection interval varies inversely with the observed snubber failures on a given system and is determined by'the number of inoperable snubbers found during an inspection of each system. In order to establish the inspection frequency for each type of snubber on a safety-related system, it was assumed that the frequency of snubber failurr.s and initiating events is constant with time and that the failure of any snNbber on that system could cause the system to be onnrotected and to result in failure during an assumed initiatino event. Inspections performed before that interval has elapsed may be used as a new HOPE CREEK B 3/4 7-2
f PLANT SYSTEMS , 5 i JUN 2 8 Es BASES SNUBBERS (Continued) reference point to determine the next inspection. However, the results of such u . j ., inspos. ions performed before the original required time interval has elasped (nominal time less 25%) may not be used to lengthen the required inspec-tion interval. Any inspection whose results required a shorter inspection interval will override the previous schedule. The acceptance criteria are to be used in the visual inspection to determine OPERABILITY of the snubbers. To. provide assurance of snubber functional reliability one of three functional testing methods is used with the stated acceptance criteria:
- 1. Functionally test 10% of a type of snubber with an additional 10%
tested for each functional testing failure, or
' ~
. 2. Purictiona11y test a sample size and determine sample acceptance or rejection using Figure 4.7.4-1, or
- 3. Functionally test a representative sample size and determine sample acceptance or rejection using the stated equation.
Figure 4.7.4-1 was developed using "Wald's Sequential Probability Ratio Plan" as described in Quality Control and Industrial Statistics" by Acheson J. Duncan. Permanent or other exemptions from the surveillance program for individual snubbers may be granted by the Commission if a justifiable basis for exemption is presented and, if applicable, snubber life destructive testing was performed to qualify the snubbers for the applicable design conditions at either the com-pletion of their fabrication or at a subsequent date. Snubbers so exempted shall be listed in the list of individual snubbers indicating the extent of the exemptions. The service life of a snubber is evaluated via manufacturer input and information through consideration of the snubber service conditions and asso-ciated installation and maintenance records (i.e., newly installed snubber, seal replaced, spring replaced, in high radiation area, in high temperature area, etc.). The requirement to monitor the snubber service life is included to ensure that the snubbers periodically undergo a performance evaluation in view of their age and operating conditions. These records will provide statis-tical bases for future consideration of snubber service life. HOPE CREEK B 3/4 7-3
PLANT SYSTEMS p M. BASES 3/4.7.6 SEALED SOURCE CONTAMINATION ED The limitations on removable contamination for sources requiring leak
' ;tir.g, ;.)cluain9 alpha eiiiitter=, is ba=ted en 20 CFR )v. 4) 11mi cs ior
. plutonium. This limitation will ensure that leakage from byproduct, source,
/.d spccial ntelear material sou ces w'll not exceed allowable intake values.
Sealed sources are classified into three groups according to their use, with surveillance requirements commensurate with the probability of damage to a i source in that group. Those sources which are frequently handled are required to be tested more often than those which are not. Sealed sources which are continuously enclosed within a shielded mechanism, i.e., sealed sources within radiation monitoring devices, are considered to be stored and need not be tested unless they are removed from the shielded mechanism. 3/4 7.7 FIRE SUPPRESSION SYSTEMS The OPER. ABILITY of the fire suppression systems ensures that adequate fire suppressiori capability is availaole to confine and extinguish fires occurring l in any portion of the facility where safety related equipment is located. The fire suppression system consists of the water system, spray and/or sprinkler systems, CO2 systems, and fire hose stations. The collective capability of the fire suppression systems is adequate to minimize potential. damage to safety related equipment and is a major element in the facility fire protection program. In the event that portions of the fire suppression systems are inoperable, alternate backup fire fighting equipment is required to be made available in the affected areas until the inoperable equipment is restored to service. When the inoperable fire fighting equipment is intended for use as a backup means of fire suppression, a longer period of time is allowed to provide an alternate , means of fire fighting than if the inoperable equipment is the primary means of fire suppression. The surveillance requirements provide assurances that the minimum ! OPERABILITY requirements of the fire suppression systems are met. In the event the fire suppression water system becomes inoperable, immediate corrective measures must be taken since this system provides the major fire suppression capability of the plant. 3/4.7.8 FIRE RATED ASSEMBLIES The OPERABILITY of the fire barriers and barrier penetrations ensure that fire damage will be limited. These design features minimize the possibility of } a single fire involving more than one fire area prior to detection and extinguish-ment. The fire barriers, fire barrier penetrations for conduits, cable trays and piping, fire windows, fire dampers, and fire doors are periodically inspectec , to. verify their OPERABILITY. HOPE CREEK B 3/4 7-4
a PLANT SYSTEMS EJI k8
- BASES M E 6 192 ~
3/4.7.9 AREA TEMPERATURE MONITORING (Optional) The area temperature limitations ensure +. hat sa M y-relatad equip 9 eat wi!!
..os u' e suuaected to temperatures in excess of their environraental qualification temperatures. Exposure to excessive temperatures may daarade equipment and can cause loss of its OPERABILITY. The temperature limits include allowance for an instrument error of ( )"F.
3/4.7.10 MAIN TUR8INE BYPASS SYSTEM The main turbine bypass system is required to be OPERABLE consistent with the assumptions of the (feedwater controller failure) analysis for FSAR Chapter 15. HOPE CREEK B 3/4 7-5
3/4.8 ELECTRICAL POWER SYSTEMS JUN 2 E E5 BASES 3/4.8.1, 3/4.8.2 and 3/4.8.3
~
A.C. SOURCES, D.C. SOURCFS and ONSITE POWER GISThlt:UTION SlSitiMS The OFEP. ABILITY of the A.C. anc D.C. power sources and associated distribution systems during operation ensures that sufficient power will be available to supply the safety related equipment required for (1) the safe shutdown of the facility and (2) the mitigation and control of accident conditions within the facility. The minimum specified independent and redundant A.C. and D.C. power sources and distribution systems satisfy the requirements of General Design Criteria 17 of Appendix "A" to 10 CFR 50. The ACTION requirements specified for the levels of degradation of the power sources provide restriction upon continued facility operation commensurate with the level of degrad1 tion. The OPERABILITY of the power sources are con-sistent witti.the initial condition assumptions of the safety analyses and are based upon maintaining at least one of the onsite A.C. and the corresponding D.C. power sources and associated distribution systems OPERABLE during accident conditions coincident with an assumed loss of offsite power and single failure . of the other onsite A.C. or D.C. source. The A.C. and D.C. source allowable out-of-service times are based on Regulatory Guide 1.93, " Availability of Electrical Power Sources", December 1974. When one diesel generator is inoperable, there is an additional ACTION requirement to verify that all required systems, susbsystems, train's, components dnd devices, that depend on the remaining OPERABLE diesel generator is a source of emergency power, are also OPERABLE. This requirement is intended to provide assurance that a loss of offsite power event will not result in a complete loss of safety function of critical systems during the period one of the diesel generators i:; inoperable. The term verify as used in this context means to administratively check by examining logs or other information to determine if certain components are out-of-service for maintenance or other reasons. It does not mean to perform the surveillance requirements needed to demonstrate the OPERABILITY of the component. The OPERABILITY of the minimum specified A.C. and D.C. power sources and associated distribution systems during shutdown and refueling ensures that (1) the facility can be maintained in the shutdown or refueling condition for extended time periods and (2) sufficient instrumentation and control capability is available for monitoring and maintaining the unit status. The surveillance requirements for demonstrating the OPERABILITY of the diesel generators are in accordance witn the recommendations of Regulatory Guide 1.9, " Selection of Diesel Generator Set Capacity for Standby Power Supplies", March 10, 1971, Regulatory Guide 1.108, " Periodic Testing of U1esel , Generator Units Used as Onsite Electric Power Systems at Nuclear Power Plants", Revision 1, August 1977 and Regulatory Guide 1.137" Fuel-Oil Systems for Standby Diesel Generators", Revision 1, October 1979. HOPE CREEK B 3/4 8-1
ELECTRICAL POWER SYSTEMS D[d g I-JUN 2 81885 BASES A.C. A RCE3, D.C. 50udCES and DNSITE POWER DISlRIBUTION SYSTEMS (Continued) The surveillance requirements for demonstrating the OPERABILITY of the unit batteries are in accordance with the recommendations of Regulatory Guide 1.129 " Maintenance Testing and Replacement of Large Lead Storage Batteries for Nuclear Power Plants", February 1978 and IEEE Std 450-1980, "IEEE Recommended Practice for Maintenance, Testing, and Replacement of Large Lead Storage Batteries for Generating Stations and Substations." Verifying average electrolyte temperature above the minimum for which the battery was sized, total battery terminal voltage on float charge, connection resistance values and the performance of battery service and discharge tests ensures the effectiveness of the charging system, the ability to handle high discharge rates and-compares the battery capacity at that time with the rated capacity.
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Table 4.8.2.11 specifies the normal limits for each designated pilot cell and each connected cell for electrolyte level, float voltage and specific gravity. The limits for the designated pilot cells float voltage and specific gravity, greater than 2.13 volts and .015 below the manufacturer's full charge specific gravity or a battery charger current that had stabilized at a low value, is characteristic of a charged cell with adequate capacity. The normal limits for each connected cell for float voltage and specific gravity, greater than 2.13 volts and not more than .020 below the manufacturer's full charge specific gravity with an average specific gravity of all the connected cells not more than .010 below the manufacturer's full charge specific gravity, ensures the OPERABILITY and capability of the battery. Operation with a battery cell's parameter outside the normal limit but within the allowable value specified in Table 4.8.2.1-1 is permitted for up to 7 days. During this 7 day period: (1) the allowable values for electrolyte level ensures no physical damage to the plates with an adequate electron transfer capability; (2) the allowable value for the average specific gravity of all the cells, not more than .020 below the manufacturer's recommended full charge specific gravity ensures that the decrease in rating will be less than the safety margin provided in sizing; (3) the allowable value for an individual cell's specific gravity, ensures that an individual cell's specific gravity will not be more than .040 below the manufacturer's full charge specific gravity and that the overall capability of the battery will be maintained within an acceptable limit; and (4) the allowable value for an individual cell's float voltage, greater than 2.07 volts, ensures the battery's capability to perform its desian function. HOPE CREEK B 3/4 8-2
ELECTRICAL POWER SYSTE'.45
@ 2S E BASES 3/4.8.4 ELECTRICAL EQUIPMEN_T, PROTECTIVE DEVICES Primary containment electrical penetrations and penetration conductors are protected by either de-energizing circuits not required during reactor operation or demonstrating the OPERABILITY of primary and backup overcurrent protection circuit breakers by periodic surveillance.
The surveillance requirements applicable to lower voltage circuit breakers and fuses provides assurance of breaker and fuse reliability by testing at least one representative sample of each manufacturers brand of circuit breaker and/or fuse. Each manufacturer's molded case and metal case circuit breakers and/or fuses are grouped into representative samples which are than tested on a rotating basis to ensure that all breakers and/or fuses are tested. If a wide variety exists within any manufacturer's brand of circuit breakers and/or fuses, it is necessary to..div.ide-that manufacturer's breakers and/or fuses into groups and treat each group as a separate type of breaker or fuses for surveillance purposes. The OPERABILITY or bypassing of the motor operated valves thermal overload protection continuously or during accident conditions by integral bypass de-vices ensures that the thermal overload protection during accident conditions will not prevent safety related valves from performing their function. The Surveillance Requirements for demonstrating the OPERABILITY or bypassing of the thermal overload protection continuously or during accident conditions are in accordance with Regulatory Guide 1.106 " Thermal Overload Protection for Elec-tric Motors on Motor Operated Valves", Revision 1, March 1977. 9 HOPE CREEK B 3/4 8-3
3/4.9 REFUELING OPERATIONS . JUN 2 e y BASES o/*. 9.1 REACTOR MODE SWITCH Locking the OPERABLE reactor mode switch in the Shutdown or Refuel position, as specified, ensures that the restrictions on control rod withdrawal and refueling platform movement during the refueling operations are properly activated. These conditions reinforce the refueling procedures and reduce the probability of inadvertent criticality, damage to reactor internals or fuel assemblies, and exposure of personnel to excessive radioactivity. 3/4.9.2 INSTRUMENTATION The OPERABILITY of at least two source range monitors ensures that redundant monitoring capability is availaole to detect changes in the reactivity condition of the core.' 3/4.9.3 CONTROL R00 POSITION The requirement that all control rods be inserted during other CORE ALTERATIONS rod. ensures that fuel will not be loaded into a cell without a control 3/4.9.4 DECAY TIME The minimum requirement for reactor subcriticality prior to fuel movement ensures that sufficient time has elapsed to allow the radioactive decay of the short li'ved fission products. This decay time is consistent with the assump-tions used in the accident analyses. 3/4.9.5 COMMUNICATIONS The requirement for communications capability ensures that refueling station personnel can be promptly informed of significant changes in the facility status or core reactivity condition during movement of fuel within the reactor pressure vessel. HOPE CREEK B 3/4 9-1
REFUELING OPERATIONS BASES M 2 8 1984 3/4.9.6 REFUELING PLATFORM The OPERABILITY requirements ensure that (D the raNaling platfere will u
'e used ror hanosing control rods and fuel assemblies within the reactor pressure vessel, (2) each crane and hoist has sufficient load capacity for handling fuel asseablies and control rods, and (3) the core internals and pressure vessel are protected from excessive lifting force in the event they are inadvertently engaged during lifting operations.
3/4.9.7 CRANE TRAVEL - SPENT FUEL STORAGE POOL The restriction on movement of loads in excess of the nominal weight of a fuel assembly over other fuel assemblies in the storage pool ensures that in the event this load is dropped (1) the activity release will be limited to that contained in a single fuel assembly, and (2) any possible distortion of fuel in the storage racks will not result in a critical array. This assumption is consistent with the activity release assumed in the safety analyses. 3/4.9.8 and 3/4.9.9~ WATER LEVEL - REACTOR VESSEL and WATER LEVEL - SPENT FUEL STORAGE POOL The restrictions on minimum water level ensure that sufficient water depth is available to remove (99)% of the assumed (10)% iodine gap activity released from the rupture of an irradiated fuel assembly. This minimum water depth is consistent with the assumptions of the accident analysis. 3/4.9.10 CONTROL R00 REMOVAL These specifications ensure that maintenance or repair of control rods or control rod drives will be performed under conditions that limit the probability of inadvertent criticality. The requirements for simultaneous removal of more than one control rod are more stringent since the SHUTDOWN MARGIN specification provides for the core to remain subcritical with only one control rod fully withdrawn. 3/4.9.11 RESIDUAL HEAT REMOVAL AND COOLANT CIRCULATION The requirement-that at least one residual heat removal loop be OPERABLE or that an alternate method capable of decay heat removal be demonstrated and that an alternate method of coolant mixing be in operation ensures that (1) suf-ficient cooling capacity is available to remove decay heat and maintain the water in the reactor pressure vessel below 140 F as required during REFUELING, and (2) sufficient coolant circulation wculd be available through the reacter core to assure accurate temperature indication and to distribute and prevent stratification of the poison in the event it becomes necessary to actuate the standby liquid control system. The requirement to have two shutdown cooling made loops OPERABLE when there is less than (23) feet of water above the reactor vessel flange ensures that a singic fcilurs of the operating loop will act result in a ccmplete loss of rasid-ual heat removal capability. With the reactor vessel head removed and (23) feet of water above the reactor vessel flange, a large heat sink is available for core cooling. Thus, in the event a failure of the operating RHR loop, adequate time is provided to initiate alternate methods capable of decay heat removal or emergency procedures to cool the core. HOPE CREEK B 3/4 9-2
pt 3/4.10 SPECIAL TEST EXCEPTIONS BASES 8 1S85 3/4.10.1 PRIM,ARYCONTAINMENTINTEGRTH The requirement for PRIMARY CONTAINMENT INTEGRITY is not applicable duri g the period when open vessel tests are being performed during the low power PHYSICS TESTS. 3/4.10.2 ROD SEQUENCE CONTROL SYSTEM In order to perform the tests required in the technical specifications it is necessary to bypass the sequence restraints on control rod movement. The additional surveillance requirments ensure that the specifications on heat generation rates and shutdown margin requirements are not exceeded during the period when these tests are being performed and that individual rod worths do not exceed the values assumed in the safety analysis. 3/4.10.3 SHUkDOWNMARGINDEMONSTRATIONS Performance of shutdown margin demonstrations with the vessel head removed requires additional restrictions in order to ensure that criticality does not occur. These additional restrictions are specified in this LCO. 3/4.10.4 RECIRCULATION LOOPS This special test exception permits reactor criticality under no flow conditions and is required to perform certain startup and PHYSICS TESTS while at low THERMAL POWER levels. 3/4.10.5 OXYGEN CONCENTRATION Relief from the oxygen concentration specifications is necessary in order to provide access to the primary containment during the initial startup and testing phase of operation. Without this access the startup and test program could be restricted and delayed. 3/4.10.6 TRAINING STARTUPS This special test exception permits training startups to be performed with the reactor vessel depressurized at low THERMAL POWER and temperature while controlling RCS' temperature with one RHR subsystem aligned in the shutdown cooling mode in order to minimize contaminated water discharge to the radioactive waste disposal system. HOPE CREEK B 3/4 10-1
3/4.11 RADIOACTIVE EFFLUENTS BASES M 2 8 1985 3/4.11.1 LIOUID EFFLUENTS 3/4.11.1.1 CONCENTRATION This specification is provided to ensure that the concentration of ra ficactive material. relcued in liquid waste effluents to UNRESTRICTED AREAS will be less than the concentration levels specified in 10 CFR Part 20, Appen-dix B, Table II, Column 2. This limitation provides additional assurance that the levels of radioactive materials in bodies of water in UNRESTRICTED AREAS will result in exposures within (1) the Section II.A design objectives of Appen-dix I, 10 CFR Part 50, to a MEMBER OF THE PUBLIC and (2) the limits of 10 CFR Part 20.106(e) to the population. The concentration limit for dissolved or entrained noble gases is based upon the assumption that Xe-135 is the control-ling radioisotope and its MPC in air (submersion) was converted to an equivalent concentration in water using the methods described in International Commission on Radiological Protection (ICRP) Publication 2. The regulre'd detection capabilities for radioactive materials in liquid waste samples are tabulated in terms of the lower limits of detection (LLDs). Detailed discussion of the LLD, and other detection limits can be found in Currie, L. A., " Lower Limit of Detection: Definition and Elaboration of a Proposed Position for Radiological Effluent and Environmental Measurements," NUREG/CR-4007 (September 1984), and in the HASL Procedures Manual, HASL-300 (revised annually). 3/4.11.1.2 DOSE This specification is provided to implement the requirements of Sections II. A, III. A, and IV. A of Appendix I,10 CFR Part 50. The Limiting Condition for Operation implements the guides set forth in Section II.A of Appendix I. The ACTION statements provide the required operating flexibility and at the same time implement the guides set forth in Section IV.A of Appen-dix I to assure that the releases of radioactive material in liquid effluents to UNRESTRICTED AREAS will be kept "as low as is reasonably achievable." Also, for fresh water sites with drinking water supplies that can be potentially affected by plant operations, there is reasonable assurance that the operation of the facility will not result in radionuclide concentrations in the finished drinking water that are in excess of the requirements of 40 CFR Part 141. The dose calculation methodology and parameters in the ODCM implement the require-ments in Section III.A of Appendix I that conformance with the guides of Appendix I be shown by calculational procedures based on models and data, such that the actual exposure of a MEMBER OF THE PUBLIC through appropriate pathways is unlikely to be substantially underestimated. The equations specified in the ODCM for calculating the doses due to the actual release rates of radioactive materials in liquid effluents are consistent with the methodology provided in Rogniatnry nois 1.109, " calculation of a nnua! Deses te Man fre- Deutine . Releases of Reactor Effluents for the Purpose of Evaluating Compliance with 10 CFR Part 50, Appendix I," Revision 1, October 1977 and Regulatory Guide 1.113, " Estimating Aquatic Dispersion of Effluents from Accidental and Routine Reactor Releases for the Purpose of Implementing Appendix I," April 1977. HOPE CREEK 8 3/4 11-1
RADIOACTIVE EFFLUENTS BASES JUN 2 8 1985 3/4.11.1.3 LIQUID RA0 WASTE TREATMENT SYSTEM The OPERABILITY of the liquid radwam +"atmant syst.cm onwrc- that. '.:t system will be available for use whenever liquid effluents require treatment prior to their release to the environment. The requirement that the appropriate portions of this system be used, when specified, provides assurance that the releases of radioactive materials in liquid effluents will be kept "as low as is reasonably achievable._" This specification implements the requirements of General Design Criterion 60 of Appendix A to 10 CFR Part 50 and the design objective given in Section II.D of Appendix I to 10 CFR Part 50. The specified limits governing the use of appropriate portions of the liquid radwaste treatment system were specified as a suitable fraction of the dose design objectives set forth in Section II. A of Appendix I,10 CFR Part 50, for liquid effluents. 3/4.11.1.4 LIQUID HOLDUP TANKS The tanks listed in this specification include all those outdoor radwaste
~
tanks that are not surrounded by liners, dikes, or walls capable of holding the tank contents and that do not have tank overflows and surrounding area drains connected to the Liquid Radwaste Treatment System. Restricting the quantity of radioactive material contained in the specified tanks provides assurance that in the event of an uncontrolled release of the tanks' contents, the resulting concentrations would be less than the limits of 10 CFR Part 20, Appendix B, Table II, Column 2, at the nearest potable water supply and the nearest surface water supply in an UNRESTRICTED AREA. 3/4.11.2 GASEOUS EFFLUENTS 3/4.11.2.1 00SE RATE This specification is provided to ensure that the dose at any time at and beyond the SITE BOUNDARY from gaseous effluents from all units on the site will be within the annual dose limits of 10 CFR Part 20 to UNRESTRICTED AREAS. The annual dose limits are the doses associated with the concentrations of 10 CFR Part 20, Appendix B, Table II, Column 1. These limits provide reasonable assurance that radioactive material discharged in gaseous effluents will not result in the exposure of a MEMBER OF THE PUBLIC in an UNRESTRICTED AREA, either within or outside the SITE BOUNDARY, to annual average concentrations exceeding the limits specified in Appendix B, Table II of 10 CFR Part 20 (10 CFR Part 20.106(b)). For MEMBERS OF THE PUBLIC who may at times be within the SITE BOUNDARY, the occupancy of that MEMBER OF THE PUBLIC will usually be sufficiently low to compensate for any increase in the atmospheric diffusion 1 factor above that for the SITE BOUNDARY. Examples of calculations for such MEMBERS OF THE PUBLIC, with the appropriate occupancy factors, shall be given in the ODCM. The specified release rate limits restrict, at all times, the corresponding gamma and beta dose rates above background to a MEMBER OF THE PUBLIC at or beyond tne SITE BOUNDARY to less than or equal to 500 mrems/ year to the total body or to less than or equal to 3000 mrems/ year to the skin. HOPE CREEK B 3/4 11-2
RADI0 ACTIVE EFFLUENTS { n . , BASES JUN 2 S 1985 DOSE RATE (Continued) These release rata limits alco restrict, at '11 ti m tha corrtsp W ing thyroid dose rate above background to a child via the inhalation pathway to less than or equal to 1500 mrems/ year. The required detection capabilities for radioactive materials in gaseous waste samples are tabulated in terms of the lower limits of detection (LLDs). Detailed discussion of the LLD, and other detection limits can be found in Currie, L. A. , " Lower Limit of Detection: Definition and Elaboration of a Proposed Position for Radiological Effluent and Environmental Measurements," NUREG/CR-4007 (September 1984), and in the HASL Procedures Manual, HASL-300 (revised annually). ' 3/4.11.2.2 00SE - NOBLE. GASES This specification is provided to implement the requirements of Sections II.8, III.A, and IV.A of Appendix I, 10 CFR Part 50. The Limiting Condition for Operation implements the guides set forth in Section II.B of Appendix I. The ACTION statements provide the required operating flexibility --- and at the same time implement the guides set forth in Section IV.A of Appendix I to assure that the releases of radioactive material in gaseous effluents to UNRESTRICTED AREAS will be kept "as low as is reasonably achievable." The Su'r-veillance Reciuirements implement the requirements in Section III. A of Appendix I that conformance with the guides of Appendix I be shown by calculational proce-dures based on models and data such that the actual exposure of a MEMBER OF THE PUBLIC through appropriate pathways is unlikely to be substantially under-estimated. The dose calculation methodology and parameters established in the ODCM for calculating the doses due to the actual release rates of radioactive noble gases in gaseous effluents are consistent with the methodology provided in Regulatory Guide 1.109, " Calculation of Annual Doses to Man from Routine Releases of Reactor Effluents for the Purpose of Evaluating Compliance with 10 CFR Part 50, Appendix I," Revision 1, October 1977 and Regulatory Guide 1.111, " Methods for Estimating Atmospheric Transport and Dispersion of Gaseous Effluents in Routine Releases from Light-Water Cooled Reactors," Revision 1, July 1977. The ODCM equations provided for determining the air doses at and beyond the SITE BOUNDARY are based upon the historical average atmospheric conditions. 3/4.11.2.3 DOSE - 10 DINE-131, IODINE-133, TRITIUM, AND RADICNUCLIOES IN PARTICULATE FORM This specification is provided to implement the requirements of Sections II.C, III.A and IV.A of Appendix I, 10 CFR Part 50. The Limiting Conditions for Operation are the guides set forth in Section II.C of Appendix I. The ACTION statements provide the required operating flexibility and at the same L;me lmplement tiie guides set forth 16 Sec.tico IV.A vf Appendia I to assure that the releases of radioactive materials in gaseous effluents to UNRESTRICTED AREAS will be kept "as low as is reasonably achiesable." The 00CM calculational methods speci#ied in the Surveillance Requirements implement HOPE CREEK B 3/4 11-3
O 1Y RA010ACTEVE EFFLUENTS U mI BASES JUN 2 9 "-35 00SE - 100lNE-131, 10 DINE-133, TRITIUM, AND RADIONUCLIDES IN PARTICULATE FORM (Continued) the requirements in Section III.A of Appendix I that conformance with the guides of Appendix I be shown by calculational p, edares based on models and data, such that the actual exposure of a MEMBER OF THE PUBLIC through appropriate pathways is unlikely to be substantially underestimated. The 00CM calculational methodology and parameters for calculating the doses due to the actual release rates of the subject materials are consistent with the methodology provided in Regulatory Guide 1.109, " Calculation of Annual Doses to Man from Routine Releases of Reactor Effluents for the Purpose of Evaluating Compliance with 10 CFR Part 50, Appendix I," Revision 1, October 1977 and Regulatory Guide 1.111, " Methods for Estimating Atmospheric Transport and Dispersion of Gaseous Effluents in Routine Releases from Light-Water-Cooled Reactors," Revision 1, July 1977. These equations also provide for determining the actual doses based upon the historical average atmospheric _ conditions. The release rate specifications for iodine-131, iodine-133,- tritium, and radionuclides in particulate form with half lives greater than 8 days are dependent upon the existing radionuclide pathways to man, in the areas at and beyond the SITE BOUNDARY. The pathways that were examined in the development of these' calculations were: (1) individual innala-tion of airborne radionuclides, (2) deposition of radionuclides onto green leafy vegetation with subsequent consumption by man, (3) deposition onto grassy areas where milk animals and meat producing animals graze with consumption of the milk and meat by man, and (4) deposition on the ground with subsequent exposure of man. 3/4.11.2.4 AND 3/4.11.2.5 GASEOUS RADWASTE TREATMENT AND VENTILATION EXHAUST TREATMENT The OPERABILITY of the GASEOUS RADWASTE TREATMENT SYSTEM and the VENTILA-TION EXHAUST TREATMENT SYSTEM ensures that the system will be available for use whenever gaseous effluents require treatment prior to release to the anvironment. The requirement that the appropriate portions of these systems be used, when specified, provides reasonable assurance that the releases of radioactive mate-rials in gaseous effluents will be kept "as low as is reasonably achievable." This specification implements the requirements of General Design Criterion 60 1 of Appendix A to 10 CFR Part 50, and the design objectives given in Section II.D l of Appendix I to 10 CFR Part 50. The specified limits governing the use of ! appropriate portions of the systems wera specified as a suitable fraction of I the dose design objectives set forth in Sections II.B and II.C of Appendix I, 10 CFR Part 50, for gaseous effluents, i 3/4.11.2.6 EXPLOSIVE GAS MIXTURE Tiiin spm.ifisation is p,ovided to ensure that the concentr: tion .cf poten- ,
, tially explosive gas mixtures contained in the GASEOUS RADWASTE TREATMENT SYSTEM
! main condenser offgas system is maintained below the flammability lim #ts of hydrogen and oxygen. Automatic control features are included in the system to prevent the hydrogen and oxygen concentration from reaching these flammability limits. These automatic control features include isolation of the source of i HOPE CREEK B 3/4 11-4 i
l s ( RADIOACTIVE EFFLUENTS . BASES JUN 2 8 tog EXPLOSIVE GAS MIXTURE (Continued) hydrcgen and/uc vaygen, outcraatic divers son to recombiners or injection of dilutants to reduce the concentration below the flammability limits. Maintain-ing the concent..ation af hydrogen below the flammability limit provides assur-ance that the releases of radioactive materials will be controlled in conform-ance with the requirements of General Design Criterion 60 of Appendix A to 10 CFR Part 50. 3/4.11.2.7 MAIN CONDENSER Restricting the gross radioactivity rate of noble gases from the main condenser provides reasonable assurance that the total body exposure to an individual at the exclusion area boundary will not exceed a small fraction of the limits of 10 CFR Part 100 in the event this effluent is inadvertently discharged directly_to the environment without treatment. This specification implements -the requirements of General Design Criteria 60 and 64 of Appendix A to 10 CFR Part 50. 3/4.11.2.8 MARK I CONTAINMENT This specification provides reasonable assurance that releases from drywell purging operations will not exceed the annual dose limits of 10 CFR Part 20 for UNRESTRICTED AREAS. 3/4.11.3 SOLID RADIOACTIVE WASTE TREATMENT This specification implements the requirements of General Design Criterion 60 of Appendix A to 10 CFR Part 50. The process parameters included in establishing the PROCESS CONTROL PROGRAM may include, but are not limited to waste type, waste pH, waste / liquid / solidification agent / catalyst ratios, waste oil content, waste principal chemical constituents, and mixing and curing times. 3/4.11.4 TOTAL DOSE This specification is provided to meet the dose limitations of 40 CFR Part 190 that have been incorporated into 10 CFR Part 20 by 46 FR 18525. The specification requires the preparation and submittal of a Special Report whenever the calculated doses from plant generated radioactive effluents and direct radiation exceed 25 mrems to the total body or any organ, except the thyroid, which shall be limited to less than or equal to 75 mrems. For sites containing up to 4 reactors, it is highly unlikely that tne resultant dose to a MEMBER OF THE PUBLIC will exceed the dose limits of 40 CFR Part 190 if the individual reactors remain within twice the dose design objectives of Annendix I, and if direct radiation dncec from the "eactnr unite inc1ndinn outside storage tanks,etc. are kept small. The Special Report will describe a course of action that should result in the limitation of the annual dose to a MEMBER OF THE PUBLIC to within the 40 CFR Part 190 limits. For tne purposes of the Special Report, it may be assumed that the dose commitment to the MEMBER OF HOPE CREEK B 3/4 11-5
9 RADIOACTIVE EFFLUENTS DME: JUN 2 8 gogg 8ASES TOTAL DOSE (Continued) THE PUBLIC from uther uranium fuei cycle sources is negligible, with the excep-tion that dose contributions from other nuclear fuel cycle facilities at the same site or within a radius of 8 km must be' considered. If the dose to any MEMBER OF THE PUBLIC is estimated to exceed the requirements of 40 CFR Part 190, the Special Report with a request for a variance (provided the release condi-tions resulting in violation of 40 CFR Part 190 have not already been corrected), in accordance with the provisions of 40 CFR Part 190.11 and 10 CFR Part 20.405c, is considered to be a timely request and fulfills the requirements of 40 CFR Part 190 until NRC staff action is completed. The variance only relates to the limits of 40 CFR Part 190, and does not apply in any way to the other require-ments for dose limitation of 10 CFR Part 20, as addressed in Specifica-tions 3.11.1.1 and 3.11.2.1. An individual is not considered a MEMBER OF THE PUBLIC during any period in which he/she is engaged in carrying out any opera-tion that 1s part of the nuclear fuel cycle. I 4 i A I t HOPE CREEK B 3/4 11-6
3/4.12 RADIOLOGICAL ENVIRONMENTAL MONITORING BASES 3/4.12.1 MONITORING PROGRAM s The r-d' W -ica! envircnment.1 r...:r1;.s ,.,ugram required by tnis specification provides representative measurements of radiation and of radio-active materi als in those exposure pathways and for thase radionuclides that lead to the highest potential radiation exposures of HEMBERS OF THE PUBLIC resulting from the station operation. This monitoring pragram' implements Section IV.8.2 of Appendix I to 10 CFR Part 50 and thereby supplements the radiological effluent monitoring progrin by verifying that the n:easurable concentrations of radioactive materials and levels of radiation are not higher than expected on the basis of the effluent measurements and the modeling of the environmental exposure pathways. Guidance for this monitoring program is' provided by the Radiological Assessment Branch Technical Position on Env, tron-mental Monitoring, Revision 1, November 1979. The initially specified mcnitor-ing program will be effective for at least the first 3 years of commercial operation. Followi_ng this period, program changes may be initiated based on operational- experience. The required detection capabilities for environmental sample analyses are tabulated in terms of,the lower limits of detection (LLDs). The LLDs required by Table 4.12.1-1 are considered optimum for routine environmental measurements in industrial laceratories. It should be recognized that the LLD is defined as an a priori (before the fact) limit representing the capa-bility of a measurement system and not as an a_ posteriori (after the fact) limit for a particular measurement. Detailed discussion of the LLD, and other detection limits, can be found in Currie, L. A. , " Lower Limit of Detection: Definition and Elaboration of a Proposed Position for Radiological Effluent and Enviro'nmental Neasurements," NUREG/CR-4007 (September 1984), and in the HASL Procedures Manutl, HASL-300 (revised annually). ' 3/4.12.2 LAND USE CENSUS This specification is provided to ensure that changes in the use of areas at and beyond the SITE BOUNDARY are identified and that modifications to the radiological environmental monitoring program are made if required by the results of this census. The best information from the docr-to-door survey, from aerial survey, from visual survey or from consulting with local agricul-tural authorities shall be used. This census satisfies the requirements of Section IV.B.3 of Appendix I to 10 CFR Part 50. Restricting the census to gar-dens of greater than 50 m2 provides assurance that significant exposure pathways via leafy vegetables will be identified and monitored since a garden of this i size is the minimum required to produce the quantity (26 kg/ year) of leafy, vege-tables assumed in Regulatory Guide 1.109 for consumotion by a child. To dotar- , mine this minimum garden size, the following assumptions were made: (1) 20% of the garden was used for growing broad laaf vegetation (i.e., similar to lettuce and cabbage), and (2) a vegetation yield of 2 kg/m2 , HOPE CREEK B 3/4'12-1
3/4.12 RADIOLOGICAL ENVIRONMENTAL MONITORING DRE UUN 2 E ng3 BASES 3/4.12.3 INTERLABORATORY COMPARISON PROGRAM The requirament for rsrtici; 'for in :n approsed Interlabora c 3 Cumpo.; cr. Program is provided to ensure that independent checks on the precision and accu-racy of the measurements of radioactive material in environmental ampic matrices are performed as part of the quality assu ance program for enviren-mental monitoring in order to demonstrate that the results are valid for the purposes of Section IV.B.2 of Appendix I to 10 CFR Part 50. s HOPE CREEK B 3/4 12-2
1 DPE JUN 2 8 1985 SECTION 5.0 DESIGN FEATURES e
5.0 DESIGN FEATURES 5.1 SITE
'JUN 2 8 g EXCLUSION AREA 3.1.1 The exclusion area snalI be as shown in Figure 5.1.1-1.
LOW POPULATION ZONE 5.1.2 The low population zone shall be as shown in Figure 5.1.2-1. 5.2 CONTAINMENT CONFIGURATION 5.2.1 The pr.imary. containment is a steel structure composed of a spherical lower portion, a cylindrical middle portion, and a hemispherical top head which form a drywell. The drywell is attached to the suppression chamber through a series of downcomer vents. The suppression chamber is a steel pressure vessel in the shape of a torus. The drywell has a minimum free air volume of 169,000 cubic feet. The suppression chamber has an air volume of 133,500 cubic feet and a water region of 118,000 cubic feet. DESIGN TEMPERATURE AND PRESSURE 5.2.2 The primary containment is designed and shall be maintained for:
- a. Maximum internal pressure 62 psig.
- b. Maximum internal temperature: drywell 340'F.
suppression pool 310*F.
- c. Maximum external differential pressure 3 psid.
SECONDARY CONTAINMENT 5.2.3 The secondary containment consists of the Reactor Building, the Reactor Building recirculation fan room, the equipment access structure and a portion of the main steam tunnel and has a minimum free volume of 4,000,000 cubic feet. HOPE CREEK 5-1
9 1 a4 JUN 2 8 x This figure shall consist of a map of the site area and provide at a minimum, the
. information described in Section (2.1.2) of the FSAR and meteoro1gical tower location.
t O
?
EXCLUSION AREA ' FIGURE 5.1.1-1 HOPE CREEK 5-2
- - - - -- , . . - . . . . . _ , . - , , , , - . _ - . . , . - ~ _ _ _ - , , - _ , , . . , - - _ . - . - , , c
JUN 2 81985 This figure shall consist of a map of the site area showing the Low Population Zone boundary. Features such as towns, roads and recreational areas shall be indicated in
. ~s'ufficient detail to allow identification of significant shifts in population distribution within the LPZ.
LOW POPULATION ZONE FIGURE 5.1.2-1 HOPE CREEK 5-3
DESIGN FEATURES 5.3 REACTOR CORE gge FUEL ASSEMBLIES 5.3.1 The reaciut core shall concain 'io* tuel assemblies with each fuel assembly containing 62 fuel rods and two water rods clad with Zircaloy-2. Each Tuel red shall have a nominal active fuel length of 150 inches. The initial core loading shall have a maximum average enrichment of 1.90 weight percent U-235. Reload fuel shall be similar in physical design to the initial core loading and shall have a maximum average enrichment of 3.20 weight percent U-235. CONTROL R00 ASSEMBLIES 5.3.2 The reactor core shall contain (185) control rod assemblies, each consisting of a cruciform array of stainless steel tubes containing 143 inches of bor.on carbide, B 4C, powder surrounded by a cruciform shaped stainless steel sheath.
- 5. 4 REACTOR COOLANT SYSTEM DESIGN PRESSURE AND TEMPERATURE 5.4.1 The reactor coolant system is designed and shall be maintained:
- a. In accordance with the code requirements specified in Section (5.2) of the FSAR, with allowance for normal degradation pursuant to the applicable Surveillance Requirements,
- b. For a pressure of:
- 1. 1250 psig on the suction side of the recirculation pump.
- 2. (1650) psig from the recirculation pump discharge to the outlet side of the discharge shutoff valve.
- 3. (1550) psig from the discharge shutoff valve to the jet pumps.
- c. For a temperature of 575 F.
VOL'JME 5.4.2 The total water and steam volume of the reactor vessel and recirculation system is approximately 21,970 cubic feet at a nominal steam dome saturation temperature of 547 F.
)
HOPE CREEK 5-4
DESIGN FEATURES 5.5 METEOROLOGICAL TOWER LOCATION JUN 2 81535 5.5.1 The meteorological tower shall be located as shown on Figure 5.1.1-1. 5.6 FUEL STORAGE CRITICALITY 5.6.1 The spent fuel storage racks are designed and shall be maintained with:
- a. A k,ff equivalent to less than or equal to 0.95 when flooded with unborated water, including all calculational uncertainties and biases as described in Section 9.1.2 of the FSAR.
- b. A nominal 6.308 inch center-to-center distance between fuel assemblies placed in the storage racks.
- 5. 6.1. 2 Tile.tyf f for new fuel for the first core loading stored dry in the spent fuel storage racks shall not exceed 0.98 when aqueous foam moderation is assumed.
DRAINAGE 5.6.2 The spent fuel storage pool is designed and shall be maintained to prevent inadvertent draining of the pool below elevation 199' 4". CAPACITY 5.6.3 The~ spent fuel storage pool is designed and shall be maintained with a storage capacity limited to no more than 1108 fuel assemblies. 5.7 COMPONENT CYCLIC OR TRANSIENT LIMIT 5.7.1 The components identified in Table 5.7.1-1 are designed and shall be maintained within the cyclic or transient limits of Table 5.7.1-1. HOPE CREEK 5-5
x 8 71 h TABLE 5.7.1-1
'/1 COMPONENT CYCLIC OR TRANSIENT, LIMIT 3 s_
CYCLIC OR - DESIGN CYCLE C0llPONENT TRANSIENT LIMIT ; OR TRANSIENT Reactor 120 heatup and cooldown cycles 70 F to 546*F to 70 F 80 step change cycles Loss of all feedwater heaters 180 reactor trip cycles 100% to 0% of RATED THERMAL POWER 130 hydrostatic pressure and Pressurized to > 930 aad leak tests $1250 psig CD g W v oo m
0UE Jim 2 81365 s SECTION 6.0 ADMINISTRATIVE CONTROLS S l l l
6.0 ADMINISTRATIVE CONTROLS JUN 2 8 % 6.1 RESPONSIBILITY 6.1.1 The General Manager - Hope Creek Operations shall be responsible for overall unit operation and shall delegate in writing the suecastinn to tMe responsloiiity during his absence. 6.1.2 Tne Shift Supervisor or during his absence from the control room, a designated individual shall be responsible for the control room command function. A management directive to this effect, signed by the Vice President - Nuclear shall be reissued to all station personnel on an annual basis. 6.2 ORGANIZATION OFFSITE 6.2.1 The offsite organization for unit management and technical support shall be as shown on Figure 6.2.1-1. UNIT STAFF ~ 6.2.2 The unit organization shall be as shown on Figure 6.2.2-1 and:
- a. Ea:h on duty shift shall be composed of at least the minimum shift crew composition shown in Table 6.2.2-1;
- b. At least one licensed Operator shall be in the control room when fuel is in the reactor. In addition, while the unit is in OPERATIONAL CONDITION 1, 2 or 3, at least one licensed Senior Operator shall be in the control room;
- c. A Health Physics Technician
- shall be on site when fuel is in the reactor;
- d. ALL CORE Ali2 RATIONS shall be observed and directly supervised by either a liccased Senior Operator or licensed Senior Operator Limited to Fuel Hant' ling who has no other concurrent responsibilities during this operation;
- e. A site fire brigade of at least five members shall be maintained on site at all times *. The fire brigade shall not include the Shift Supervisor, the Shift Technical Advisor, nor the two other members of the minimum shift crew necessary for safe shutdown of the unit and any personnel required for other essential functions during a fire emergency; and
- The Health Physics Technician and fire brigade composition may be less than the minimum requirements for a period of time not to exceed 2 hours, in order to accommodate unexpected absence, provided immediate action is taken to fill the required positions.
HOPE CREEK 6-1
i N R M* bfkb3 ) ADMINISTRATIVE CONTROLS DUN 2 UNIT STAFF (continued)
- f. Administrative procedures shall be developed and implemented to limit the work;ng hout s of unit staff wno perform safety related functions e.g., licensed Senior Operators, licensed Operators, health physi-cists, auxiliaiy operators, and key maintenance per sonnel.
The amount of overtime worked by unit staff members performing safety-related functions shall be limited in accordance with the NRC Policy Statement on working hours (Generic Letter No. 82-12). i
~
l - . i l HOPE CREEK 6-2
Pii!.ti JUN 2 8 '.2c 5
,_,Th,is. figure shall show the organizational structure and lines of responsibility for the offsite groups that provide technical and management support for the unit. The organizational arrangement for performing and monitoring quality assurance activities shall also be indicated.
-f .
FIGURE 6.2.1-1 0FFSITE ORGANIZATION HOPE CREEK 6-3
Jk JtRI 2 8 t)c.5 This figure shall show the organizational structure and lines of responsibility for the unit staff. Positions to be staffed by licensed personnel shall be indicated. The organizational arrangement for performing and moni-toring quality assurance activities shall also be indicated. i l l i FIGURE 6.2.2-1 UNIT ORGANIZATION HOPE CREEK 6-4
TABLE 6.2.2-1 MINIMUM SHIFT CREW COMPOSITION SINGLE UNIT FACILITY POSITION NUMBER OF INDIVIDUALS REQUIRED TO FILL POSITION CONDITION 1, 2, or 3 CONDITION 4 or 5
- SS 1 1 SR0 1 None R0 2 1 A0 2 1 STA 1 None L
TABLE NOTATION
~ ^
SS - Shift ' Supe'rvEsor with a Senior Operator license on Unit (1). SR0 - Individual with a Senior Operator license on Unit (1). R0 - Individual with an Operator license on Unit (1). AO - Auxiliary Operator STA - Shift Technical Advisor Except for the Shift Supervisor, the shift crew composition may be one less than the minimum requirements of Table 6.2.2-1 for a period of time not to exceed 2 hours in order to accommodate unexpected absence of on-duty shift crew members provided immediate action is taken to restore the shift crew composition to within the minimum requirements of Table 6.2.2-1. .This provision does not permit any shift crew position to be unmanned upon shift change due to an oncoming shift crewman being late or absent. During any absence of the Shift Supervisor from the control room while the unit is in OPERATIONAL CONDITION 1, 2 or 3, an individual (other than the Shift Technical Advisor) with a valid Senior Operator license shall be designated to assume the control room command function. During any absence of the Shift Supervisor from the control room while the unit is in OPERATIONAL CONDITION 4 or 5, an individual with a valid Senior Operator license or Operator license shall be designated to assume the control room command function. 4 HOPE CREEK 6-5 I
- , , - - - - ---n- ,..-.n,~,,,,..,-_--._----nnn. . - . - - . - - ,n.-n-. . - , , , , -- . - , . - . - , . --,,, , ,n
ADMINISTRATIVE CONTROLS M( ~~ 6.2.3 INDEPENDENT SAFETY ENGINEERING GROUP (ISEG) FUNCTION JUN 2 81c85 , 6.2.3.1 The ISEG shall function to examine unit operating characteristics, i NRC issuances, industry advisories, Licensee Event Reports, and other sources of unit design and operating experience information, including units of simi- : lar design, which may indicate areas for improving unit safety. The ISEG shall make dets! led -e.ch.mandstions for revisea pruccoures, equipment modifications, maintenance activities, operations activities, or other means of improving unit safety to (a high l a el corporate official in a technically oriented position who is not in the management chain for power production). COMPOSITION 6.2.3.2 The ISEG shall be composed of at least five, dedicated, full-time i engineers located onsite. Each shall have a bachelor's degree in engineering l or related science and at least 2 years professional level experience in his field, at least 1 year of which experience shall be in the nuclear field. RESPONSIBILITIES l 6.2.3.3 The ISEG shallsbe responsible for maintaining surveillance of unit activities to. provide independent verification
- that these activities are per-formed correctly and that human errors are reduced as much as practical.
RECORDS l 6.2.3.4 Records of activities performed by the ISEG shall be prepared, main-tained, and forwarded each calendar month to (a high level corporate official in a technically oriented position who is not in the management chain for power production). l 6.2.4 SHIFT TECHNICAL ADVISOR l 6.2.4.1 The Shift Technical Advisor shall provide advisory technical support to j the Shift Supervisor in the areas of thermal hydraulics, reactor engineering, and plant analysis with regard to safe operation of the unit. The Shift Technical ( Advisor shall have a bachelor's degree or equivalent in a scientific or engineer-ing discipline and shall have received specific training in the response and anal-ysis of the unit for transients and accidents, and in unit design and layout, including the capabilities of instrumentation and controls in the control room. 6.3 UNIT STAFF QUALIFICATIONS Minimum qualifications for memoers of the unit staff snall be specified by use of en overall qualification statement referencing (an ANSI Standard acceptable to the NRC staff) or alternately by specifying individual position qualifica-tions. Generally, the first method is preferable; however, the second method is adaptacle to those unit staffs requiring special qualification statements because of a unioue orcanizational structure. 6.3.1 Each memcer of the unit staff shall meet or exceed the minimum qualifica-tions of (an ANSI Standard acceptable to the NRC Staff) for comparable positions,
- l. except for the (Radiation Protection Manager) who shall meet or exceed the qualifications of Regulatory Guide 1.8, September 1975. The licensed Operators and Senior Operators shall also meet or exceed the minimum qualifications of the supplemental requirements specified in Sections A and C of Enclosure 1 of the March 28, 1980 NRC letter to all licensees.
"Not respons1Dle for sign-off function.
HOPE CREEK G-5 l --- - - - - . - - - _ - .- . _ - . -- .-
l N$kI
. nN h ADMINISTRATIVE CONTROLS
,, ,,, 2 8 1995 6.4 TRAINING 6.4.1 A retraining and replacement training program for the unit staff shall be maintained under the direction of the (position title), shall meet or exceed the requirements and recommendations of Section ( ) of (an ANSI Standard accept-able to the NEC st.af f) anu Appendix A of 10 CFR Part SS and the supplemental requirements specified in Sections A and C of Enclosure 1 of.the March 28, 1980 flP.C letter to all licensees, and shall include familiarization with relevant l industry operational experience.
6.5 REVIEW AND AUDIT The method by which independent review and audit of unit operations is accomplished may take one of several forms. The licensee may either assign this function to an organizational unit separate and independent from the group having responsibility for unit operation or may utilize a standing committee composed of individuals from within and outside the licensee's organization. Irrespective of the. method used, the licensee shall specify the details of each functional . element-provided for the independent review and audit process as illustrated in the following example soecifications. 6.5.1 (UNIT REVIEW GROUP (URG)) FUNCTION 6.5.1.1 The (URG) shall function to advise the (Plant Superintendent) on all matters related to nuclear safety. COMPOSITION
- 6. 5.1. 2 The (URG) shall be composed of the:
Chairman: (Plant Superintendent) Member: (Operations Supervisor) Member: (Technical Supervisor) Member: (Maintenance Supervisor) Member: (Plant Instrument and Control Engineer) Member: (Plant Nuclear Engineer) Member: (Health Physicist) ALTERNATES 6.5.1.3 All alternate members shall be appointec in writing by the (URG) Chairman to serve on a temporary basis; however, nc more than two alternates shall participate as voting members in (URG) activities at any one time. MEETING FREQUENCY 6.5.1.4 The (URG) shall meet at least once per calendar month and as convened by the (URG) Chairman or his designated alternate. QUORUM 6.5.1.5 The quorum of the (URG) necessary for the performance of the (URG) responsibility and authority provisions of these Technical Specifications shall consist of the Chairman or his designated alternate and four members including alternates. HOPE CREEK 6-7 t
ODbb ~ unru 1 ADMINISTRATIVE CONTROLS
.!!W 2 8 ESS ,
RESPONSIBILITIES l 6.5.2.6 The (URG) shall be responsible for:
- a. Review of (2) all proposed proce'dures required by Specification 6.8 ar.d :hcnges thereto, (2) all piopc==u picgram r& quired by 5peci fica-tion 6.8 and changes thereto, and (3) any other proposed procedures or chanca: thereto as determined by tht: (Plar.t Superintendent) to affect nuclear safety;
- b. Review of all proposed tests and experiments that affect nuclear safety;
- c. Review of all proposed changes to Appendix A Technical Specifications;
- d. Review of all proposed changes or modifications to unit systems or equipment that affect nuclear safety;
- e. Investigation of all violations of the Technical Specifications, including the preparation and forwarding of reports covering evaluation and recommendations to prevent recurrence, to the (Vice President -
Nuc. lear Operations) and to the (Company Nuclear Review and Audit Group);
- f. R'eview~of events requiring 24-hour written notification to the Commission;
- g. Review of unit operations to detect potential hazards to nuclear safety;
- h. Performance of special reviews, investigations, or analyses and reports thereon as requested by the (Plant Superintendent) or the (Company Nuclear Review ano Audit Group);
- i. Review of the Security Plan and implementing procedures and submittal of recommended changes to the (Company Nuclear Review and Audit Group); and J. Review of the Emergency Plan and implementing procedures and submittal -
of the recommended changes to the (Company Nuclear Review and Audit Group).
- 6. 5.1. 7 The (URG) shall:
- a. Recommend in writing to the (Plant Superintendent) approval or disapproval of items considered under Specification 6.5.1.6.a. through
- d. prior to their implementation.
- b. Render determinations in writing with regard to whether or not each item considered under Specification 6.5.1.6.a. through e. constitutes an unreviewed safety question.
- c. Provide written notification within 24 hours to the (Vice President -
Nuclear Operations) and the (Company Nuclear Review and Audit Group) of disagreement between the (URG) and the (Plant Superintendent); however, the (Plant Superintendent) shall have responsibility for resolution of such disagreements pursuant to Specification 6.1.1. HOPE CREEK 6-8
JUN 2 81S85 ADMINISTRATIVE CONTROLS RECORDS 6.5.1.8 The (URG) shall maintain written minutes of each (URG) meeting that, at a minimum, document the results of all (URG) activities perfcrmed under tha r:sponsibilit.y provisions of these Technical Specifications. Copies shall be provided to the (Vice President - Nuclear Operations) and the (Company Nuclear Review and Audit Group). 6.5.2 (COMPANY NUCLEAR REVIEW AND AUDIT GROUP (CNRAG)) FUNCTION 6.5.2.1 The (CNRAG) shall function to provide independent review and audit of designated activities in the areas of:
- a. Nuclear power plant operations,
- b. Nuclear engineering,
- c. Chemistry and radiochemistry,
- d. Metallurgy,
- e. Instrumentation and control,
- f. Radiological safety,
- g. Mechanical and electrical engineering,
- h. Quality assurance practices, and
- i. (Other appropriate fields associated with the unique characteristics of the nuclear power plant).
The (CNRAG) shall report to and advise the (Vice President - Nuclear Operations) on those areas of responsibility in Specifications 6.5.2.7 and 6.5.2.8. COMPOSITION 6.5.2.2 The (CNRAG) shall be composed of the: , Director: (Position Title) Member: (Position Title) Member: (Position Title) Member: (Position Title) Member: (Position Title) ALTERNATES 6.5.2.3 All alternate members shall be appointed in writing by the (CNRAG) Director to serve on a temporary basis; however, no more than two alternates shall participate as voting members in (CNRAG) activities at any one time. HOPE CREEK 6-9
r ADMINISTRATIVE CONTROLS JUN 2 81Sc5 CONSULTANTS 6.5.2.4 Consultants shall be utilized as determined by the (CNRAG) Director to provide expert advice to the (CNRAG). MEETING FREQUENCY 6.5.2.5 The (CNRAG) shall meet at least once per calendar quarter during the initial year of unit operation following fuel loading and at least once per 6 months thereafter.
-QUORUM 6.5.2.6 The quorum of the (CNRAG) necessary for the performance of the (CNRAG) review and audit functions of these Technical Specifications shall consist of the Director or his designated alternate and at least (four) (CNRAG) members including alternates. No more than a minority of the quorum shall have line responsibility.for. operation of the unit.
REVIEW 6.5.2.7 The (CNRAG) shall review:
- a. The safety evaluations for (1) changes to procedures, equipment, or systems; and (2) tests or experiments completed under the provision of 10 CFR 50.59 to verify that such actions did not constitute an unreviewed safety question;
- b. Proposed changes to procedures, equipment, or systems which involve an unreviewed safety question as defined in 10 CFR 50.59;
- c. Proposed tests or experiments which involve an unreviewed safety question as defined in 10 CFR 50.59;
- d. Proposed changes to Technical Specifications or this Operating License;
- e. Violations of codes, regulations, orders, Technical Specifications, license requirements, or of internal procedures or instructions having nuclear safety significance;
- f. Significant operating abnormalities or deviations from normal and expected performance of unit equipment that affect nuclear safety; l
- g. Events requiring 24-hour written notification to the Commission;
- h. All recognized indications of an unanticipated deficiency in some aspect of design or operation of structures, systems, or components that could affect nuclear safety; and
- i. Reports and meeting minutes of the (URG).
HOPE CREEK 6-10
p in ADMINISTRATIVECONTROLS JUN 2 81985 AUDITS 6.5.2.8 Audits of unit activities shall be performed under the ennnizance nf tim (CNRAG). These auults shall encompass:
- a. The conformance of unit operation to provisions contained within the Technical Specifications and applicable license conditions at least once per 12 months;
- b. The performance, training and qualifications of the entire unit staff at least once per 12 months;
- c. The results of actions taken to correct deficiencies occurring in unit equipment, structures, systems, or method of operation that affect nuclear safety, at least once per 6 months;
- d. The. performance of activities required by the Operational Quality Assurance Program to meet the criteria of Appendix B, 10 CFR Part 50, at least once per 24 months;
- e. The fire protection programmatic controls including the implementing procedures at least once per 24 months by qualified licensee QA personnel;
- f. The fire protection equipment and program implementation at least once per 12 months utilizing either a qualified offsite licensee fire protection engineer (s) or an outside independent fire protection consultant. An outside independent fire protection consultant shall be utilized at least every third year; and
- g. Any other area of unit operation considered appropriate by the (CNRAG) or the (Vice President - Nuclear Operations).
PECORDS 6.5.2.9 Records of (CNRAG) activities shall be prepared, approved, and distributed as indicated below;
- a. Minutes of each (CNRAG) meeting shall be prepared, approved, and forwarded to the (Vice President - Nuclear Operaticns) within 14 days following each meeting.
- b. Reports of reviews encompassed by Specification 6.5.2.7 shall be prepared, approved, and forwarded to the (Vice President - Nuclear Operations) within 14 days following completion of the' review.
- c. Audit reports encompassed by Specification 6.5.2.8 shall be forwarded to the (Vice President - Nuclear Operations) and to the management positions responsible for the areas audited within 30 days after i completion of the audit by the auditing organization.
HOPE CREEK 6-11
m 3 [," k 1 I ADMINISTRATIVE CONTROLS OM 6.6 REPORTABLE OCCURRENCE ACTION 6.6.1 The following actions shall be taken for REPORTABLE OCCURRENCES:
- o. ~ine Commission shall be notified and a report submitted pursuant to the requirements of Specification 6.9, and
- b. Each REPORTABLE OCCURRENCE requiring 24-hour notification to the Commission shall be reviewed by the (URG), and the results of this review shall be submitted to the (CNRAG) and the (Vice President -
Nuclear Operations). 6.7 SAFETY LIMIT VIOLATION 6.7.1 The following actions shall be taken in the event a Safety Limit is violated: ,
- a. The.NRC Operations Center shall be notified by telephone as soon as p'ossible and in all cases within 1 hour. The (Vice President - Nuclear Operations) and the (CNRAG) shall be notified within 24 hours.
- b. A Safety Limit Violation Report shall be prepared. The report shall
, be reviewed by the (URG). This report shall describe (1) applicable circumstances preceding the violation, (2) effects of the violation' upon unit components, systems, or structures, and (3) corrective action taken to prevent recurrence.
- c. The Safety Limit Violation Report shall be submitted to the Commission, the (CNRAG), and the (Vice President - Nuclear Operations) within 14 days of the violation.
- d. Critical operation of the unit shall not be resumed until authorized by the Commission.
I HOPE CREEK 6-12 . l
\
JUN 2 81985 ADMINISTRATIVE CONTROLS 6.8 PROCEDURES AND PROGRAMS 6.8.1 Written procedures shall be established, implemented, and maintained covering the activities referenced below:
- a. The applicable procedures recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978.
- b. The applicable procedures required to implement the requirements of NUREG-0737.
- c. Refueling operations.
- d. Surveillance and test activities of safety-related equipment.
- e. Security Plan implementation.
- f. Emergency Plan implementation.
- g. Fire Protection Program implementation.
6.8.2 Each' procedure of Specification 6.8.1, and changes thereto, shall be reviewed by the (URG) and shall be approved by the (Plant Superintendent) prior to implementation and reviewed periodically as set forth in administrative pro-cedures. 6.8.3 Temporary changes to procedures of Specification 6.8.1 may be made provided:
- a. The intent of the original procedure is not altered;
- b. The change is approved by two members of the unit management staff, at least one of whom holds a Senior Operator license on the unit affected; and
- c. The change is documented, reviewed by the (URG), and approved by the (Plant Superintendent) within 14 days of implementation.
6.8.4 The following programs shall be established, implemented, and maintained:
- a. Primary Coolant Sources Outside Containment A program to reduce leakage from those portions of systems outside containment that could contain highly radioactive fluids during a serious transient or accident to as icw as practical levels. The systems include the (HPCI, CS, RHR, RCIC, hydrogen recombiner, process sampling, containment and standby gas treatment) systems.
The program shall include the following:
- 1. Preventive maintenance and periodic visual inspection requirements, and
- 2. Integrated leak test requirements for each system at refueling cycle intervals or less.
[ HOPE CREEK 6-13
s C ADMINISTRATIVE CONTROLS .uw 2 8 g PROCEDURES AND PROGRAMS (Continued)
- b. In-Plant Radiation Monitoring A program which will ensure the capability to accurately determine the airborre iodine concentracion it. vital areas under accident conditions. This program shall inciude the following:
- 1. Training of personnel,
- 2. Procedures for monitoring, and
- 3. Provisions for maintenance of sampling and analysis equipment.
- c. Post-accident Sampling A prograa.which will ensure the capability to obtain and analyze reactor coolant, radioactive iodines and particulates in plant gaseous efflu-ents, and containment atmosphere samples under accident conditions.
The program shall include the following:
- 1. Training of personnel,
- 2. Procedures for sampling and analysis, and
- 3. Provisions for maintenance of sampling and analyiis equipment.
6.9 REPORTING REQUIREMENTS ROUTINE REPORTS AND REPORTABLE OCCURRENCES 6.9.1 In addition to the applicable reporting requirements of Title 10, Code of Federal Regulations, the~following reports shall be submitted to the Regional Administrator of the. Regional Office of the NRC unless otherwise noted. STARTUP REPORT 6.9.1.1 A summary report of plant startup and power escalation testing shall be submitted following (1) receipt of an Operating License, (2) amendment to the license involving a planned increase in power level, (3) installation of fuel that has a different design or has been manufactured by a different fuel supplier, and (4) modifications that may have significantly altered the nuclear, thermal, or hydraulic performance of the unit. 6.9.1.2 The startup report shall address each of the tests identified in the Final Safety Analysis Report and shall include a description of the measured values of the operating conditions or characteristics obtained during the test program and a comparison of these values with design predictions and specifica-tions. Any corrective actions that were required to obtain satisfactory operation shall also be described. Any additional specific details required in license conditions based on other commitments shall be included in this report. HOPE CREEK 6-14
ADMINISTRATIVE CONTROLS JUN 2 8 ' 1985 STARTUP REPOE (Continued)
- 6. 9.1. 3 Startup reports shall be submitted within (1) 90 days following comple-tion of the startup test program, (2) 90 days following resumption or commence-ment of commercial power operation, or (3) 9 months following initial criticality, whichever is earliest. If the startup report does not cover all three events
! (i.e., initial criticality, completion of startup test prog m , and *ammption or commencement of commercial operation) supplementary reports shall be submitted at least every 3 months until all three events have been complated. ANNUAL REPORTS
- 6.9.1.4 Annual reports covering the activities of the unit as described below
- for the previous calendar year shall be submitted prior to March 1 of each year.
The initial report shall be submitted prior to March 1 of the year following initial criticality.
- 6. 9.1. 5 Reports required on an annual basis shall include:
- a. A tabulation on an annual basis of the number of station, utility, and other personnel (including contractors) receiving exposures greater than 100 mrem /yr and their associated man-rem exposure according to wor.k and -job functions ** (e.g. , reactor operations and surveillance, in'ervice s inspection, routine maintenance, special maintenance
[ describe maintenance], waste processing, and refueling). The dose assignments to various duty functions may be estimated based on pocket dosimeter, thermoluminescent dosimeter (TLD), or film badge measure- , , ments. Small exposures totalling less than 20% of the individual total dose need not be accounted for. In the aggregate, at least 80% of the total whole-body dose received from external sources should be assigned to specific major work functions; (b. Documentation of all challenges to (safety valves or) safety / relief valves; and) (c. Any other unit unique reports required on an annual basis). MONTHLY OPERATING REPORTS 6.9.1.6 Routine reports of operating statistics and shutdown experience (, including documentation of all challenges to the the main steam system (safety valves or) safety / relief valves,) shall be submitted on a monthly basis to the Director, Office of Resource Management, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555, with a copy to the Regional Administrator of the Regional Office of the NRC no later than the 15th of each month following the calendar month covered by the report. REPORTABLE OCCURRENCES 6.9.1.7 The REPORTABLE OCCURRENCES of Specifications 6.9.1.8 and 6.9.1.9, including corrective actions and measures to prevent recurrence, shall be reported to the NRC. Supplemental reports may be required to fully describe final resolution of occurrence. In case of corrected or supplemental reports, a Licensee Event Report shall be completed and reference shall be made to the original report date. A A single submittal may be made for a multiple unit station. The submittal should combine those sections that are common to all units at the station.
==
This tabulation supplements the requirements of S20.407 of 10 CFR Part 20. HOPE CREEK 6-15
ADMINISTRATIVE CONTROLS .Q 2 6 L:qg PROMPT NOTIFICATION WITH WRITTEN FOLLOWUP i 6.9.1.8 The types of events listed below shall be reported within 24 hours by t:' Wna u.d con.*irm;d by tclagraph, ma!19.w.., or facsimde tr ansiniss ion to the Regional Administrator of the Regional Office of the NRC, or his designee no bter than the first working day follotag the event, with a written followup report within 14 days. The written followup report shall include, as a minimum, j a completed copy of a Licensee Event Report form. Information provided on the Licensee Event Report form shall be supplemented, as needed, by additional nar-1 I rative material to provide complete explanation of the circumstances surrounding the event,
- a. Failure of the reactor protection system or other systems subject to Limiting Safety System Settings to initiate the required protective function by the time a monitored parameter reaches the setpoint 3 specified as the Limiting Safety System Setting in the Technical Specif.ications or failure to complete the required protective function.
, b. Operation of the unit ot* affected systems when any parameter or
] operation subject to a Limiting Condition for Operation is less con-servative than the least conservative aspect of the Limiting Condi-tion for Operation established in the Technical Specifications.
- c. Abnormal degradation discovered in fuel cladding, reactor coolant pressure boundary, or primary containment.
- d. Reactivity anomalies involving disagreement with the predicted value of reactivity balance under steady-state conditions during power operation greater than or equal to 1% delta k/k; a calculateo reac-tivity balance indicating a SHUTDOWN MARGIN less conservative than
- l. ;specified in the Technical Specifications; short-term reactivity ,
increases that correspond to a reactor period of less than 5 seconds l or, if subcritical, an unplanned reactivity insertion of more than l- 0.5% delta k/k; or occurrence of any unplanned criticality. i i e. Failure or malfunction of one or more components which prevents or
- could prevent, by itself, the fulfillment of the functional require-l ments of system (s) used to cope with accicents analy
- ed in the Safety l Analysis Report.
- f. Personnel error or procedural inadequacy which prevents or could
? prevent, by itself, the fulfillment of the functional requirements of systems required to cope with accidents analyzed in the Safety l Analysis Report.
f g. Conditions arising frcm natural or man-made events that, as a direct result of the event, require unit shutdown, operation of safety
, systems, or other protective measures required by Technical Specifications.
1 ( HOPE CREEK 6-16
ADMINISTRATIVE CONTROLS
~ PROMPT NOTIFICATION WITH WRITTEN FOLLOWUP (Continued)
- h. Errors discovered in the transient or accident analyses or in the me thd: used for such analysas a= descriu' wd in une Safety Analysis Report or in the bases for the Technical Specifications that have or could have permitted reactor cperation in a manner less conservative than assumed in the analyses.
i. Performance of structures, systems, or components that requires remedial action or corrective measures to prevent operation in a manner less conservative than assumed in the accident analyses in the Safety Analysis Report or Technical Specifications bases; or discovery during unit life of conditions not specifically considered in the Safety Analysis Report or Technical Specifications that require remedial action or corrective measures to prevent the existence or development of an unsafe condition.
~
-j. Pailure[fmainsteamline(safetyor) safety /reliefvalves.
THIRTY OAY WRITTEN REPORTS
- 6. 9.1. 9 The types of events listed below shall be the subject of written reports to the Regional Administrator of the Regional Office of the NRC within 30 days of occu'rrence of the event. The written report shall include, as a minimum, a completed copy of a Licensee Event Report form.' Information provided on the Licensee Event Report form shall be supplemented, as needed, by additional narrative material to provide complete explanation of the circum-stances surrounding the event.
'a. Reactor protection system or engineered safety featu'res instrumenta-tion settings which are found to be less conservative than those established by the Technical Specifications but which do not prevent the fulfillment of_the functional requirements of affected systems.
- b. Conditions leading to operation in a degraded mode permitted by a Limiting Condition for Operation or plant shutdown required by a Limiting Condition for Operation,
- c. Observed inadequacies in the implementation of administrative or procedural controls which threaten to cause reduction of degree of redundancy provided in reactor protection systems or engineered safety features systems.
- d. Abnormal degradation of systems other than those specified in Specification 6.9.1.8c. designed to contain radioactive material resulting from the fission process. -
HOPE CREEK 6-17
L. 4 u P-ADMINISTRATIVE CONTROLS JJN 2 8 19E5 SPECIAL REPORTS Special reports may be required covering inspection, test, and maintenance a;'. f '. i t i e = . These special reports ara det.esariined on an liioiviuuai casis for each unit and their preparation and submittal are designated in the Technical Occifications. 6.9.2 Special reports shall be submitted to the Regional Administrator of the Regional Office of the NRC within the time period specified for each report. 6.10 RECORD RETENTION 6.10.1 In addition to the applicable record retention requirements of Title 10, Code of Federal Regulations, the following records shall be retained for atleasttheminimumperjodindicated. 6.10.2 The .folicwing records shall be retained for at least 5 years:
- a. Records and logs of unit operation covering time interval at each power level. ,
- b. Records and logs of principal maintenance activities, inspections, repair, and replacement of principal items of equipment related to '
nuclear safety.
- c. All REPORTABLE OCCURRENCES submitted to the Commission.
- d. Records of surveillance activities, inspections, and calibrations required by these Technical Specifications.
- e. Records of changes made to the procedures required by Specification
- 6. 8.1.
- f. Records of radioactive snipments.
- g. Records of sealed source and fission detector leak tests and results.
- h. Records of annual physical inventory of all sealed source material of record.
6.10.3 The following records shall be retained for the duration of the unit Operating License:
- a. Records and drawing changes reflecting unit design modifications made to systems and equipment described in the Final Safety Analysis Report.
- b. Records of new and irradiated fuel inventory, fuel transfers, and assembly burnup histories.
- c. Records of radiation exposure for all individuals entering radiation control areas.
HOPE CREEK 6-18
c ADMINISTRATIVE CONTROLS M 2 8 1985 RECORD RETENTION (Continued)
- d. Records of gaseous and liquid radioactive material released to the anvirons.
- e. Records of transient or operational cycles for those unit components identified in Table 5.7.1-1.
- f. Records of reactor tests and experiments,
- g. Records of training and qualification for current members of the unit staff.
- h. Records of inservice inspections performed pursuant to these Technical Specifications.
- 1. Records of quality assurance activities required by the Operational Quality Assurance Manual.
- j. Records of reviews performed for changes made to procedures or equip-ment'o'r reviews of tests and experiments pursuant to 10 CFR 50.59.
- k. Records of meetings of the (URG) and the (CNRAG).
- 1. Records of the service lives of all hydraulic and mechanical snubbers listed on Table (s) 3.7.5-1 (and 3.7.5-2) including the date at which the service life commences and associated installation and maintenance records.
6.11 RADIATION PROTECTION PROGRAM 6.11.1 Procedures for personnel radiation protection shall be prepared con-sistent with the requirements of 10 CFR Part 20 and shall be approved, main-tained, and adhered to for all operations involving personnel radiation exposure. 6.12 HIGH RADIATION AREA (Optional) 6.12.1 In lieu of the " control device" or " alarm signal" required by paragraph 20.203(c)(2) of 10 CFR Part 20, each high radiation area in which the intensity of radiation is greater than 100 mrem /hr but less than 1000 mrem /hr shall be i barricaded and conspicuously posted as a-high radiation area and entrance thereto shall be controlled by requiring issuance of a Radiation Work Permit (RWP)*. Any individual or group of individuals permitted to enter such areas shall be provided with or accompanied by one or more of the following:
- a. A radiation monitoring device which continuously indicates the l radiation dose rate in the area.
A Health physics personnel or personnel escorted by health physics personnel shall be exempt from the RWP issuance requirement during the performance of their assigned radiation protection duties, provided they are otherwise ! following plant radiation protection procedures for entry into high radiation l areas. HOPE CREEK 6-19 l
[I nn C DM ( ADMINISTRATIVE CONTROLS HIGH RADIATION AREA (Optional) (Continued)
- 6. A radiat*on munitornig devit.e whkn continuousiy incegrates the radiation dose rate in the area and alarms when a preset integrated dose is received. Entry in:.0 such areas with this monitoring device may ac made after the. dose rate levels in the area have been established and personnel have been made knowledgeable of them,
- c. A health physics qualified individual (i.e., qualified in radiation protection procedures) with a radiation dose rate monitoring device who is responsible for providing positive control over the activi-ties within the area and shall perform periodic radiation surveil-lance at the frequency specified by the Health Physicist in the RWP.
6.12.2 In addition to the requirements of Specification 6.12.1, areas accessible tn. personnel with radiation levels such that a major portion of the body could~ receive in I hour a dose greater than 1000 mrem shall be provided with locked doors to prevent unauthori::ed entry, and the keys shall be main-tained under the acministrative centrol of the Shift Foreman on duty and/or the health physics supervision. Ocors shall remain locked except during periods of access by personnel under an approved RWP which shall specify the dose rate levels in the immediate work area and the maximum allowable stay time for individuals in that area. For individual areas accessible to personnel with radiation levels such that a major portion of the body could receive in 1 hour a dose in excess of 1000 mrem
- that are located within large areas, such as the containment, where no enclosure exists for purposes of lccking, and no enclosure can be reasonably constructed around the individual areas, then that area shall be roped off, conspicuously posted, and a flashing light shall be activated as a warning device. In lieu of the stay time specification of the RWP, continuous surveillance direct or remote (such as use of closed circuit TV cameras), may be made by personnel qualified in radiation protection pro-cedures to 7rovide positive exposure control over the activities within the area.
Measurement made at la inches from source of radioactivity. HOPE CPEEK 6-20}}