Text

Forwards Proof & Review Tech Specs.Identification of Sections Which Do Not Accurately Reflect FSAR or as-built Plant Requested
	ML20138A458
Person / Time
Site:	Hope Creek
Issue date:	10/04/1985
From:	Butler W; Office of Nuclear Reactor Regulation
To:	Mittl R; Public Service Enterprise Group
References
	NUDOCS 8510080566
	Download: ML20138A458 (508)
	v • d • e

OCT 4 1985 Docket No.: 50-354 Mr. R. L. Ititti, General Manager

- fluclear Assurance and Regulation.

Public Service Electric & Gas Company P. O. Box 570, T22A Newark,llew Jersey 07101

Dear Mr. flitti:

SUBJECT:

HOPE CREEK TECHit! CAL $PECIFICATIONS The enclosed Hope Creek Technical Specifications are being forwarded to you at this tir:e for proof and review. You are requested to review this docurcent and identify any sections which do r.ot accurately reflect the Hope Crcok FSAR cr the "as-built" plant.

Please respor,d to this request by October 18, 1985. If you have any questions, you ray ccntact fir. David Wagner (301) 492-8525.

I Walter R. Butler, Chief Licensing Branch No. 2 Division of Licensirg

Enclosure:

As stated cc: See next page DISTRIBUTION Docket File / Attorney, OELD hRC PCR ACRS (16)

Local PDR JPa rtlow NSIC LGrir.es PPC System EJordan Lbe2 Feading SBrown EHyl ton DW4gner LtF4 - LBA2/CL DWagner:dh WButler 10/j/85 10/@85 l

0510000566 851004 PDR ADOCK 05000354 A PDR j

iv. R. L. ?:itti Public Service Electric C Gs.s Cc. Hcpe Creek Genero .iiig Statior.

cc:

Crecery Minor Susan C. Renis Richard Pttterc Division of Public Interest Acsococj Dale Bridenbaugh fiew Jersey State Departraent of I.fC Technical Associates the Public /.dvocate 1723 hamilton Avenue, Suite L Richard J. Hughes Justice Complet San Jose, California 95125 Cf,-850 Trenttr , f.ew Jersey 08625 Trcy C. Coi;ner, Jr. Esquire Office of Legal Counsel Cerrer 8 k'etterhahn Departrent of N6turel Rescurces ii47 Pennsylvania Avenue N.W. and Ervircr.raental Control bashir 9 ton, D.C. 20U06 89 Kings FigFway P.O. Box 1401 Dover, Delewore 19903 hict.u c Fryling, Jr. , Esquire Mr. K. F. Eurrones, Project Engineer Associate General Solic4'.or focttel Power Corporation Petlir k rv.ce L'ect.ric a Gas Companj 50 becle Street P. O. Box 570 T5E P. O. Box JW L Newark , New Jersey 07101 San francisco, California 9411!

Mr. J.11. Ashiy Resident Irsrtcter Senior Licensing Engineet U.S.N.R.C. c/c Put:11c Semice Electric o 6as to.

P. C. Lex 241 Bethesda Office Center. Suit 550 har.ccc(s Bridge, f.ew Jersey CE'01f. 4E20 East-West Highway Bethesca, L6tyitt.d 20P14 Eichara F. Engel Cr r t.ty / tterney General Mr. A. E. Gierd he Division cf Lev Mar.69er - Quality Assurance tol Envirocrental Pruett1cr. Secticn Public Servict Eltctric & Ces Co.

Richard J. hughes Justice Ccrplex P. O. Box A CN-112P Her:coch Bridge, New Jersey 08ny Trenton, hew ver su CCC25 Mr. Robert J. Touhey, Nr. Anthony J. Pietrofitta Acting Director General han69er DNEEC - Division of Power Production Engir eering Environmentel Cct, trol Atlantic Electric 89 Kings Highway 1199 B16ck horse Pike P. O. Box 1401 Pleasantville, New Jersey 08232 Dovcr, De16 ware 19903 Regional Administrator, Pegion 1 Mr. R. S. Salvesen U. S. Nuclear kegulatory Comission General Manager-Hope Creek Operation 631 P6rk Avenue Public Service Electric & Gas Co. King of Prussie, Pcr.nsylvania 19406 P.O. Box A Hancocks Eridce. New Jersey 08038 l

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' Public Scrvice Liectric & Gas Co. liope Creek Gcrerating Station cc:

fir. B. A. Prcston Public Service Electric & Gas Co.

Here Creek Site MC12Y l Licensirg Trailer 12LI

{ Foot of Button wood Rcad Her. cock's Bridge, New Jersey 0F03E 1

l's hebecca Green New Jersey Pu ccc of Radiation Protection 5t0 Scotch Road Trenton, flew Jersey 08628 4

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PUBLIC SERVICE ELECTRIC AND GAS COMPANY i

H0PE CREEK GENERATING STATION j TECHNICAL SPECIFICATIONS 1

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SECTION

1. 0 DEFINITIONS PAGE 1.1 ACTI0N..................................................... 1-1

1. 2 AVERAGE PLANAR EXPOSURE.................................... 1-1 1.3 AVERAGE PLANAR LINEAR HEAT GENERATION RATE................. 1-1 1.4 CNANNEL 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 DENSITY............ 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 1-3 TIME..

1.14 FRACTION OF LIMITING POWER 0ENSITY......................... 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 l 1.19 LIMITING CONTROL ROD PATTERN............................... 1-3 i

1.20 LINEAR HEAT GENERATION RATE................................ 1-4

1. 21 LOGIC SYSTEM FUNCTIONiit TEST. . . . . . . . . . . . . . . . . . . . . . . . . . 1-4 1.22 MAXIMUM FRACTION OF LIMITING POWER DENSITY................. 1-4 1.23 MEMBER (S) 0F THE PUBLIC.................................... 1-4

! 1.24 MINIMUM CRITICAL POWER RATI0............................... 1-4 c1 o.

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i DEFINITIONS I

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} SECTION i

i DEFINITIONS (Continued) PAGE 1.25 0FF-GAS RADWASTE TREATMENT SYSTEM.......................... 1-4 1.26 0FFSITE DOSE CALCULATION MANUAL............................

1-4 1.27 OPERABLE -

OPERABILITY..................................... 1-5 1.28 OPERATIONAL CONDITION -

CONDITION.......................... 1-5 1.29 PHYSICS TESTS.............................................. 1-5 1.30 PRESSURE BOUNDARY LEAKAGE.................................. 1-5 1.31 PRIMARY CONTAINMENT i

l INTEGRITY.............................. 1-5 1

1.32 PROCESS CONTROL PR0 GRAM.................................... 1-6

1.33 i

I PURGE-PURGING.............................................. 1-6 i

1.34 RATED THERMAL

! P0WER........................................ 1-6 i

1.35 REACTOR PROTECTION SYSTEM RESPONSE TIME.................... 1-6 1.36 REPORTABLE EVENT...................'........................ 1-6 1.37 ROD DENSITY................................................ 1-6 1.38 SECONDARY CONTAINMENT 3,

INTEGRITY............................ 1-7

1.39 SHUTDOWN MARGIN............................................ 1-7

1.40 SITE B0VNDARY.............................................. 1-7 1.41 SOLIDIFICATION............................................. 1-8 1.42 SOURCE CHECK...............................................

1-8 1.43 STAGGERED TEST BASIS....................................... 1-8 1.44 THERMAL l

P0WER.............................................. 1-8 1.45 TURBINE BYPASS SYSTEM RESPONSE TIME........................

1 1-8

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1. 4 6 UN I D ENT I F I E D L EA KAG E . . . . . . . . . . . . . . . . .1-8 .................

t 1.47 UNRESTRICTED 1

1 AREA.......................................... 1-8 I

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INDEX a 1.4 . i _ . .. ; ,,, , ; u s . j DEFINITIONS I

I SECTION .

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'{ l DEFINITIONS (Continued) PAGE 1.48 VENTILATION EXHAUST TREATMENT SYSTEM....................... 1-9 i

i 1.49 VENTING.................................................... 1-9 TA8LE 1.1, SURVEILLANCE FREQUENCY N0TATION...................... 1-10 TABLE 1.2, OPERATIONAL CONDITIONS............................... 1-11 i

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SAFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGS SECTION PAGE 2.1 SAFETY LIMITS

. THERMAL POWER, Low Pressure or Low Flow................... 2-1 i

q THERMAL POWER, High Pressure and High Flow................ 2-1 1

Reactor Coolant System Pressure........................... 2-1

! Reactor Vessel Water Leve1................................ 2-2 1

2.2 LIMITING SAFETY SYSTEM SETTINGS i

Reactor Protection System Instrumentation Setpoints....... 2-3 BASES l 2.1 SAFETY LIMITS THERMAL POWER, Low Pres sure u r 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 iv

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J LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE l 3/4.0 APPLICABILITY............................................. 3/4 0-1 i

j 3/4.1 REACTIVITY CONTROL SYSTEMS 4

3/4.1.1 SHUTDOWN MARGIN........................................ 3/4 1-1 3/4.1.2 REACTIVITY AN0MALIES................................... 3/4 1-2 1

3/4.1.3 CONTROL R005 Control Rod Operability................................ 3/4 1-3 i

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 J. Control Rod Scram Accumulators......................... 3/4 1-9 4

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 j 3/4.1.5 STANDBY LIQUID CONTROL SYSTEM.......................... 3/4 1-19 3/4.2 POWER OISTRIBUTION LIMITS 3/4.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE. . . . . . . . . . . . . 3/4 2-1 3/4 2.2 APRM SETP0lNTS......................................... 3/4 2-7 l 3/4.2.3 MINIMUM CRITICAL POWER RATI0........................... 3/4 2-8 3/4.2.4 LINEAR HEAT GENERATION RATE............................ 3/4 2-10 i

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LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE 3/4.3 INSTRUMENTATION 3/4.3.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION............ 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 3-32 3/4.3.4 RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION ATWS Recirculation Pump Trip System Instrumentation.. 3/4 3-41 End-of-Cycle Recirculation Pump Trip System Instrumentation...................................... 3/4 3-45 3/4.3.5 REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION...................................... 3/4 3-51 3/4.3.6 CONTROL ROD 8 LOCK INSTRUMENTATION.................... 3/4 3-56 l 3/4.3.7 MONITORING INSTRUMENTATION Radiation Monitoring Instrumentation................. 3/4 3-62 Seismic Monitoring Instrumentation................... 3/4 3-68 Meteorological Monitoring Instrumentation..........'.. 3/4 3-71 Remote Shutdown Monitorin Controls.................g Instrumentation and

............................ 3/4 3-74 Accident Monitoring Instrumentation.................. 3/4 3-84 Source Range Monitors................................ 3/4 3-88 Traversing In-Core Probe System...................... 3/4 3-89 Fire Detection Instrumentation....................... 3/4 3-90 Loose-Part Detection System.......................... 3/4 3-97 Radioactive Liquid Effluent Monitoring Instrumentation...................................... 3/4 3-98 Radioactive Gaseous Effluent Monitoring Instrumentation...................................... 3/4 3-103 3/4.3.8 TURBINE OVERSPEED PROTECTION SYSTEM.................. 3/4 3-110 3/4.3.9 FEE 0 WATER / MAIN TURBINE TRIP SYSTEM ACTUATION INSTRUMENTATION...................................... 3/4 3-112 g[ r C ' ' a

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j LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS

! SECTION PAGE i

3/4.4 REACTOR COOLANT SYSTEM '

i 3/4.4.1 RECIRCULATION SYSTEM Recirculation Loops.................................. 3/4 4-1 Jet Pumps............................................ 3/4 4-4 4 Recirculation Pumps.................................. 3/4'4-5 Idle Recirculation Loop Startup...................... 3/4 4-6 3/4.4.2 SAFETY / RELIEF VALVES Safety / Relief Valves................................. 3/4 4-7

, Safety / Relief Valves Low-Low Set Function............ 3/4 4-9

! 3/4 4.3 REACTOR COOLANT SYSTEM LEAKAGE 1,

Leakage Detection Systems............................ 3/4 4-10

! Operational Leakage.................................. 3/4 4-11 i

3/4.4.4 CHEMISTRY............................................ 3/4 4-15 i

3/4.4.5 SPECIFIC ACTIVITY.................................... 3/4 4-18 3/4.4.6 PRESSURE / TEMPERATURE LIMITS

Reactor Coolant System............................... 3/4 4-21 Reactor Steam 00me................................... 3/4 4-25

3/4.4.7 MAIN STEAM LINE ISOLATION VALVE 5..................... 3/4 4-26 3/4.4.8 STRUCTURAL INTEGRITY................................. 3/4 4-27 3/4.4.9

{ RESIDUAL HEAT REMOVAL l Hot Shutdown......................................... 3/4 4-28 l

Cold Shutdown........................................ 3/4 4-29 3/4.5 EMERGENCY CORE COOLING SYSTEMS l

3/4.5.1 ECCS - 0PERATING..................................... 3/4 5-1 l 3/4.5.2 ECCS - SHUTD0WN...................................... 3/4 5-6 3/4.5.3 SUPPRESSION CHAM 8ER.................................. 3/4 5-8 1

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LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS f

SECTION i

PAGE 3/4.6 CONTAINMENT SYSTEMS 3/4.6.1 PRIMARY CONTAINMENT Primary Containment Integrity. . . . . . . . . . . . . . . . . . . . . . . . 3/4 6-1

Primary Containment Leakage.......................... 3/4 6-2 i

Primary Containment Air Locks........................ 3/4 6-5 MSIV Sealing System.................................. 3/4 6-7 ,

Primary Containment Structural Integrity............. 3/4 6-8 Orywell 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 3/4.6.2 DEPRESSURIZATION SYSTEMS l

t Suppression Chamber.................................. 3/4 6-12 Suppression Pool Spray............................... 3/4 6-15 I

Suppression Pool Cooling.............................

3/4 6-16 3/4.6.3 PRIMARY CONTAINMENT ISOLATION VALVES. . . . . . . . . . . . . . . 3/4 . . 6-17 l 3/4.6.4 VACUUM RELIEF Suppression Chamber - Drywell Vacuum Breakers. . .. . . . . 3/4 6-43 Reactor Building - Suppression Chamber Vacuum j

8reakers........................................... 3/4 6-45 3/4.6.5 SECONDARY CONTAINMENT Secondary Containment Integri ty. . . . . . . . . . . . . . . . . . . . . . 3/4 6-47 Secondary Containment Automatic Isolation Dampers.... 3/4 6-49 Filtration, Recirculation and Ventilation System..... 3/4 6-51 3/4.6.6 PRIMARY CONTAINMENT ATMOSPHERE CONTROL Containment Hydrogen Recombiner Systems.............. 3/4 6-54 Drywell and Suppression Chamber Oxygen Concentration. 3/4 6-55 i

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INDEX i LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE

.; 3/4.7 PLANT SYSTEMS 3/4.7.1 SERVICE WATER SYSTEMS

! Safety Auxiliaries Cooling System.................... 3/4 7-1 l Station Service Water System......................... 3/4 7-3 4

i Ul timate Heat S i n k. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 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 7-11 1

1 3/4.7.5 SNUBBERS............................................. 3/4 7-13 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 Sprinkler Systems....................... 3/4 7-24 CO Systems.......................................... 3/4 7-26 2

Halon System......................................... 3/4 7-27 Fire Hose Stations................................... 3/4 7-28 3/4.7.8 FIRE RATED ASSEM8 LIES................................'. 3/4 7-31 3.4.7.9 MAIN TURBINE BYPASS SYSTEM........................... 3/4 7-33 3/4.8 ELECTRICAL POWER SYSTEMS

, 3/4 8.1 A.C. SOURCES A.C. Sources-Operating............................... 3/4 8-1 A.C. Sources-Shutdown................................ 3/4 8-11 '

l 3/4.8.2 0.C. SOURCES f

1 D.C. Sources-Operating............................... 3/4 8-12 l

D.C. Sources-Shutdown................................ 3/4 8-17 l

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l LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE ELECTRICAL POWER SYSTEMS (Continued) 3/4.8.3 ONSITE POWER DISTRIBUTION SYSTEMS Distribution - Operating............................. 3/4 8-18 Distribution - Shutdown.............................. 3/4 8-21 3/4.8.4 ELECTRICAL EQUIPMENT PROTECTIVE DEVICES !

Primary Containment Penetration Conductor Overcurrent Protective Devices................................. 3/4 8-24 Motor Operated Valve Thermal Overload Protection (Bypassed)......................................... 3/4 8-30 Motor Operated Valve Thermal Overload Protection (Not Bypassed)..................................... 3/4 8-35 Reactor Protection System Electric Power Monitoring.. 3/4 8-39 Class IE Isolation Breaker Overcurrent Protection Devices (Breaker Tripped by LOCA Signal)........... 3/4 8-40 Class IE Isolation Breaker Overcurrent Protection Devices (Primary and Backup Circuit Breakers)...... 3/4 8-43 (

Power Range Neutron Monitoring System Electric 1 Power Monitoring................................... 3/4 8-46 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 R00 P0SITION................................. 3/4 9-5 3/4.9.4 DECAY TIME........................................... 3/4 9-6 i

3/4.9.5 COMMUNICATIONS....................................... 3/4 9-7 3/4.9.6 REFUELING PLATF0RM................................... 3/4 9-8 3/4.9.7 CRANE TRAVEL - SPENT FUEL STORAGE P00L............... 3/4 9-10 I 3/4.9.8 WATER LEVEL - REACTOR VESSEL. . . . . . . . . . . . . . . . . . . . . . . . . 3/4 9-11 3/4.9.9 WATER LEVEL - SPENT FUEL STORAGE P00L................ 3/4 9 12 T/>

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LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS I

1 l l j S'iCTION PAGE

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,RjFUELINGOPERATIONS(Continued)

3/4.9.10 CONTROL R00 REMOVAL j Single Control Rod Remova1........................... 3/4 9-13 >

li Multiple Control Rod Remova1......................... 3/4 9-15

! 3/4.9.11 RESIDUAL HEAT REMOVAL AND COOLANT CIRCULATION 1

i High Water Level..................................... 3/4 9-17 Low Water Leve1...................................... 3/4 9-18 i 3/4.10 SPECIAL TEST EXCEPTIONS l

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l 3/4.10.1 PRIMARY CONTAINMENT INTEGRITY........................ 3/4 10-1 1 3/4.10.2 ROD SEQUENCE CONTROL SYSTEM.......................... 3/4 10-2 l

)1 3/4.10.3 SHUTDOWN MARGIN DEMONSTRATIONS....................... 3/4 10-3 i 3/4.10.4 RECIRCULATION L00PS.................................. 3/4 10-4 3/4.10.5 OXYGEN CONCENTRATION................................. 3/4 10-5 i

j 3/4.10.6 TRAINING STARTUPS.................................... 3/4 10-6 1

3/4.11 RADIOACTIVE EFFLUENTS

3/4.11.1 LIQUID EFFLUENTS

I j Concentration........................................... 3/4 11-1 L i Table 4.11.1.1.1-1 Radioactive Liquid Waste !

, Sampling and Analysis Program........................ 3/4 11-2 l 00se.................................................... 3/4 11-5 l

Liquid Radwaste Treatment System........................ 3/4 11-6 l Liquid Holdup Tanks..................................... 3/4 11-7 .

3/4.11.2 GASEOUS EFFLUENTS I J

Dose Rate............................................... 3/4 11-8 Table 4.11.2.1.2-1 Radioactive Gaseous Waste Sampling and Analysis Program........................ 3/4 11-9

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LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS 1 SECTION 1 PAGE ,

RADI0 ACTIVE EFFLUENTS (Continued)

! Dose - Noble Gases...................................... 3/4 11-12 ;

! Dose - Iodine-131, Iodine-133, Tritium, and

{ Radionuclides in Particulate Form..................... 3/4 11-13 Gaseous Radwaste Treatment.............................. 3/4 11-14 l Ventilation Exhust Treatment System. . . . . . . . . . . . . . . . . . . . 3/4 11-15 i Explosive Gas Mixture................................... 3/4 11-16 !

4 Main Condenser.......................................... 3/4 11-17

] Venting or Purging...................................... 3/4 11-18 I 4

1 3/4.11.3 SOLID RADI0 ACTIVE WASTE TREATMENT....................... 3/4 11-19 3/4.11.4 TOTAL 00SE.............................................. 3/4 11-20

! 3/4.12 RADIOLOGICAL ENVIRONMENTAL MONITORING l

3/4.12.1 MONITORING PR0 GRAM...................................... 3/4 12-1 Table 3.12.1-1 Radiological Environmental

, Monitoring Program................. 3/4 12-3 i

I Table 3.12.1-2 Reporting Levels For Radio-activity Concentrations In .

Environmental Samples.............. 3/4 12-9 i

i Table 4.12.1-1 Detection Capabilities For !

Environmental Sample Analysis...... 3/4 12-10 l l 3/4.12.2 LAND USE CENSUS......................................... 3/4 12 13

) 3/4.12.3 INTERLABORATORY COMPARISON PR0 GRAM...................... 3/4 12-14

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BASES SECTION PAGE 3/4.0 APPLICABILITY............................................ B 3/4 0-1 3/4.1 REACTIVITY CONTROL SYSTEMS 3/4.1.1 SHUTOOWN 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 NEAT GENERATION RATE.......................................... 8 3/4 2-1 3/4.2.2 APRM SETP0!NTS................................... B 3/4 2-2 3/4.2.3 MINIMUM CRITICAL POWER RATIO..................... 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 3/4.3.6 CONTROL ROD BLOCK INSTRUMENTATION.................................. B 3/4 3-4 3/4.3.7 MONITORING INSTRUMENTATION Radiation Monitoring Instrumentation............ B 3/4 3-4

- . ?33 HOPE CREEK xiii

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I INDEX l. ' ' '

';- El N,U?l BASES SECTION PAGE INSTRUMENTATION (Continued)

Seismic Monitoring Instrumentation.............. B 3/4 3-4 Meteorological Monitoring Instrumentation....... B 3/4 3-4 Remote Shutdown Monitoring Instrumentation and Controls.................................. B 3/4 3-5 Accident Monitoring Instrumentation............. B 3/4 3-5 Source Range Monitors........................... B 3/4 3-5 Traversing In-Core Probe System................. B 3/4 3-5 Fire Detection Instrumentation.................. B 3/4 3-6 Loose-Part Detection System..................... B 3/4 3-6 Radioactive Liquid Effluent Monitoring Instrumentation............................... B 3/4 3-6 Radioactive Gaseous Effluent Monitoring Instrumentation............................... B 3/4 3-7 3/4.3.8 TURBINE OVERSPEED PROTECTION SYSTEM............. B 3/4 3-7 3/4.3.9 FEEDWATER/ MAIN TURBINE TRIP SYSTEM ACTUATION INSTRUMENTATION............................... B 3/4 3-7 3/4.4 REACTOR COOLANT SYSTEM 3/4.4.1 RECIRCULATION SYSTEM............................ B 3/4 4-1 3/4.4.2 SAFETY / RELIEF VALVES............................ B 3/4 4-2 3/4.4.3 REACTOR COOLANT SYSTEM LEAKAGE Leakage Detection Systems....................... B 3/4 4-3 Operational Leakage............................. B 3/4 4-3 3/4.4.4 CHEMISTRY....................................... B 3/4 4-3 3/4.4.5 SFECIFIC ACTIVITY............................... B 3/4 4-4 3/4.4.6 PRESSURE / TEMPERATURE LIMITS..................... B 3/4 4-5 3/4.4.7 MAIN STEAM LINE ISOLATION VALVES................ B 3/4 4-6 3/4.4.8 STRUCTURAL INTEGRITY............................ B 3/4 4-6 3/4.4.9 RESIOUAL HEAT REM 0 VAL........................... B 3/4 4-6 stt S 0 l'I HOPE CREEK xiv

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fnh .V J. 'P.' ~ *:t ' ' ~ m m . . 1 INDEX -u- 'i i

~ ~ ~-----.' _ ,. f BASES I

SECTION PAGE i 3/4.5 EMERGENCY CORE COOLING SYSTEMS 3/4.5.1/2 ECCS - OPERATING 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-1 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 Sealing 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 Air Temperature.................. B 3/4 6-2 Drywell and Suppression Chamber Purge System..... B 3/4 6-2

3/4.6.2 DEPRESSURIZATION SYSTEMS......................... B 3/4 6-3 l

3/4.6.3 PRIMARY CONTAINMENT ISOLATION VALVES............. B 3/4 6-5 3/4.6.4 VACUUM RELIEF.................................... B 3/4 6-5 1 3/4.6.5 SECONDARY CONTAINMENT............................ B 3/4 6-5 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 3/4.7.3 FLOOD PROTECTION................................. B 3/4 7-1 3/4.7.4 REACTOR CORE ISOLATION COOLING SYSTEM. . . . . . . . . . . . B 3/4 7-1 i

3/4.7.S SNUBBERS........................................ B 3/4 7-2

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~ .. .. .' ,l BASES '-

SECTION PAGE PLANT SYSTEMS (Continued) 3/4.7.6 SEALED SOURCE CONTAMINATION..................... B 3/4 7-4 3/4.7.7 FIRE SUPPRESSION SYSTEMS........................ B 3/4 7-4 3/4.7.8 FIRE RATED ASSEMBLIES........................... B 3/4 7-5 3/4.7.9 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 R00 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 PLATF0RM.............................. B 3/4 9-2 3/4.9.7 CRANE TRAVEL-SPENT FUEL STORAGE P00L............ 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 3/4.9.11 RESIDUAL HEAT REMOVAL AND COOLANT CIRCULATION... B 3/4 9-2 3/4.10 SPECIAL TEST EXCEPTIONS 3/4.10.1 PRIMARY CONTAINMENT INTEGRITY................... B 3/4 10-1 3/4.10.2 ROD SEQUENCE CONTROL SYSTEM..................... B 3/4 10-1 I

3/4.10.3 SHUTDOWN MARGIN DEMONSTRATIONS.................. B 3/4 10-1 l SET l ;g_ l HOPE CREEK xvi

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INDEX ~ N-- _h BASES I

SECTION PAGE SPECIAL TEST EXCEPTIONS (Continued) 3/4.10.4 RECIRCULATION 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 3/4.11 RADIOACTIVE EFFLUENTS 3/4.11.1 LIQUID EFFLUENTS Concentration........................................ B 3/4 11-1 0ose................................................. B 3/4 11-1 Liquid Radwaste Treatment Syste'm..................... B 3/4 11-2 Liquid Holdup Tanks.................................. B 3/4 11-2 3/4.11.2 GASEOUS EFFLUENTS Dose Rate............................................ B 3/4 11-2 Dose - Noble Gases................................... B 3/4 11-3 Dose - Iodine-131, Iodine-133, Tritium, and Radionuclides in Particulate Form.................. B 3/4 11-3 Gaseous Radwaste Treatment System and Ventilation Exhaust Treatment Systems.............. B 3/4 11-4 Explosive Gas Mixture................................ B 3/4 11-4 Main Condenser....................................... B 3/4 11-5 Venting or Purging................................... B 3/4 11-5 3/4.11.3 SOLID RADI0 ACTIVE WASTE TREATMENT.................... B 3/4 11-5 3/4.11.4 TOTAL 00SE........................................... B 3/4 11-5 3/4.12 RADIOLOGICAL ENVIRONMENTAL MONITORING 3/4.12.1 MONITORING PR0 GRAM................................... B 3/4 12-1 3/4.12.2 LAND USE CENSUS..................................... B 3/4 12-1 3/4.12.3 INTERLABORATORY COMPARISON PROGRAM................... B 3/4 12-2

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DESIGN FEATURES I

l SECTION l PAGE 5.1 SITE Exclusion Area............................................. 5-1 Low Population Zone........................................ 5-1 Unrestricted Area and Site Boundary for Radioactive Gaseous and Liquid Effluents................... 5-1 5.2 CONTAINMENT Configuration.............................................. 5-1 Design Temperature and Pressure............................ 5-1 S eco nda ry Co nta i nme nt. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-1 5.3 REACTOR CORE Fuel Assemblies............................................ 5-5 Control Rod Assemblies..................................... 5-5 5.4 REACTOR COOLANT SYSTEM Design Pressure and Temperature............................ 5-5 Vo1ume..................................................... 5-5 5.5 METEOROLOGICAL TOWER L0 CATION.............................. 5-5 5.6 FUEL STORAGE Criticality................................................ 5-0 Drainage................................................... 5-6 Capacity................................................... 5-6 5.7 COMPONENT CYCLIC OR TRANSIENT LIMIT........................ 5-6 e

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J ADMINISTRATIVE CONTROLS SECTION PAGE 6.1 RESPONSIBILITY............................................ 6-1 6.2 ORGANIZATION.............................................. 6-1 6.2.1 0FFSITE.............................................. 6-1 6.2.2 UNIT STAFF........................................... 6-1.

6.2.3 SHIFT TECHNICAL ADVIS0R.............................. 6-6

6. 3 UNIT STAFF QUALIFICATIONS................................. 6-6

6. 4 TRAINING.................................................. 6-6 i

6.5 REVIEW AND AUDIT.......................................... 6-6 6.5.1 STATION OPERATIONS REVIEW COMMITTEE (50RC)........... 6-6 FUNCTION ............................................ 6-6 COMPOSITION ......................................... 6-7 ALTERNATES........................................... 6-7 MEETING FREQUENCY ................................... 6-7 QU0 RUM............................................... 6-7 RESPONSIBILITIES .................................... 6-7 REVIEW PR0 CESS....................................... 6-8 AUTHORITY............................................ 6-8 REC 0RDS.............................................. 6-9 6.5.2 NUCLEAR SAFETY REVIEW (NSR).......................... 6-9 FUNCTION ............................................ 6-9 COMPOSITION ......................................... 6-9 CONSULTANTS.......................................... 6-9 0FFSITE REVIEW GROUP (0SR)........................... 6-9 FUNCTION............................................. 6-9 HOPE CREEK xix OU t

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i ADMINISTRATIVE CONTROLS SECTION PAGE REVIEW............................................... 6-10 AUDITS............................................... 6-11 REC 0RDS.............................................. 6-12 ON-SITE SAFETY REVIEW GROUP (SRG).................... 6-12 RESP 0NSIBILITIES..................................... 6-12 NSR AUTHORITY........................................ 6-12 6.S.3 TECHNICAL REVIEW AND CONTR0L......................... 6-12 ACTIVITIES........................................... 6-12 PROCEDURE RELATED DOCUMENTS.......................... 6-13 4

NON-PROCEDURE RELATED DOCUMENTS...................... 6-14 REC 0RDS.............................................. 6-14 6.6 REPORTABLE EVENT ACTI0N................................... 6-14 6.7 SAFETY LIMIT VIOLATION.................................... 6-14 6.8 PROCEDURES AND PR0 GRAMS................................... 6-15 6.9 REPORTING REQUIREMENTS.................................... 6-16 6.9.1 ROUTINE REP 0RTS...................................... 6-16 STARTUP REP 0RT....................................... 6-16 ANNUAL REPORTS ...................................... 6-17 ANNUAL RADIOLOGICAL ENVIRONMENTAL OPERATING REPORT... 6-18 SEMIANNUAL RADIOLOGICAL ENVIRONMENTAL OPERATING REP 0RT............................................. 6-18 6.9.2 SPECIAL REP 0RTS...................................... 6-20 6.10 -RECORD RETENTION......................................... 6-20 6.11 RADIATION PROTECTION PR0 GRAM............................. 6-21 1 1

6.12 HIGH RADIATION AREA...................................... 6-22 HOPE CREEK xx gg on- , .

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I'i!ff i INDEX ADMINISTRATIVE CONTROLS SECTION PAGE 6.13 PROCESS CONTROL PROGRAM (PCP)............................ 6-23 6.14 0FFSITE DOSE CALCULATION MANUAL (00CM)................... 6-23 6.15 MAJOR CHANGES TO RADI0 ACTIVE LIQUID, GASEOUS, AND SOLID WASTE TREATMENT SYSTEMS............................ 6-24 SEF 3 0 ids HOPE CREEK xxi

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ADMINISTRATIVE CONTROLS LIST OF FIGURES FIGURE PAGE 6.2.1-1 0FFSITE ORGANIZATION................................. 6-3 6.2.2-1 UNIT ORGANIZATION................................... 6-4 LIST OF TABLES TABLE PAGE 6.2.2-1 MINIMUM SHIFT CREW COMPOSITION - SINGLE UNIT FACILITY............................................. 6-Sa gt i, r .9 HOPE CREEK xxii

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l SECTION 1.0 DEFINITIONS

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1.0 DEFINITIONS '

The following terms are defined so that uniform interpretation 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 shall be that part of a Specification which prescribes remedial measures required 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 l.

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 CALIBkATION may be performed by any series of sequential,' overlapping or total channel steps such that the entire channel is calibrated.

CHANNEL CHECK j 1.5 A CHANNEL CHECK shall be the qualitative assessment of channel behavior l

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

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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 OPERABILITY 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, nc HOPE CREEK 1-1 I

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. . - ~ . .- . . . ,o .,a DEFINITIONS 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 vessel. Normal movement of the SRMs, IRMs, TIPS, or special movable detectors is not considered a CORE ALTERATION. 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 1 shall be the average, weighted in proportion to the concentration of each radionuclide 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 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 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.

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___ j 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 open contacts of the recirculation pump circuit breaker from initial movement of the associated:

a. Turbine 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 B0UNDARY 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 ROD 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 i

value for APLHGR, LHGR, or MCPR.

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_ _ _ - _ ._ . . _. a DEFINITIONS LINEAR HEAT GENERATION RATE 1.20 LINEAR HEAT GENERATION RATE (LHGR) shall be the heat generation per unit length of 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 TEST shall be a test of all logic components, i.e., all relays and contacts, all trip units, solid state logic elements, etc, of a logic circuit, from sensor through and including the actuated device, to verify OPERABILITY. The LOGIC SYSTEM FUNCTIONAL TEST may be performed by any series of sequential, overlapping or total system steps such that the entire logic system 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.

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MEMBER (S) 0F THE PUBLIC 1.23 MEMBER (S) 0F ThE PUBLIC shall include all persons who are not occupationally associated with the plant. This category does not include employees of the utility, it contractors or vendors. Also excluded from this category are persons who enter the site to service equipment or to make deliveries.

This category does include persons who use portions of the site for 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 which exists in the core.

OFF-GAS RADWASTE TREATMENT SYSTEM 1.25 An OFF-GAS RADWASTE TREATMENT SYSTEM is any system designed and installed to reduce radioactive gaseous effluents by collecting reactor coolant sys-tem offgases from the main condenser evacuation system and providing for delay or holdup for the purpose of reducing the total radioactivity prior to release to the environment.

OFFSITE DOSE CALCULATION MANUAL 1.26 The OFFSITE DOSE CALCULATION MANUAL (00CM) 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.

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DEFINITIONS 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 instrumentation, controls, electrical power, cooling or seal water, lubrication or other auxiliary equipment that are required for the system, subsystem, train, component or device to perform its function (s) are also capable of performing their related support function (s).

OPERATIONAL CONDITION - CONDITION -

1.28 An OPERATIONAL CONDITION, i.e., CONDITION, shall be any one inclusive combination of mode 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 i 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-isclable 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 automatic isolation system, or

2. Closed by at least one manual valve, blind flange, or deactivated automatic valve secured in its closed position, except as provided in Table 3.6.3-1 of Specification 3.6.3.

b. All primary containment equipment hatches are closed and sealed.

c. Each primary containment air lock is in compliance with the requirements of Specification 3.6.1.3.

d. The primary containment leakage rates are within the limits of Specification 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 l penetration; e.g., welds, bellows or 0-rings, is OPERABLE.

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DEFINITIONS ,

PROCESS CONTROL PROGRAM 1.32 The PROCESS CONTROL PROGRAM (PCP) shall contain the provisions to assure that the SOLIDIFICATION or dewatering and packaging of radioactive wastes l results in a waste 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 receipt at the disposal site. With SOLIDIFICATION, the PCP shall identify the process parameters influencing SOLIDIFICATION such as pH, oil content,2H O content, solids content ratio of solidification agent to waste and/or necessary additives for'each type of anticipated waste, and the acceptable boundary conditions for the process i

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.

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t PURGE - PURGING 1.33 PURGE or PURGING shall be the controlled process of discharging air or gas 1

from a confinement to maintain temperature, pressure, humidity, concentra-tion or other operating condition, in such manner that replacement air or gas is required to purify the confinement.

RATED THERMAL POWER 1.34 RATED THERMAL POWER shall be a total reactor cor'e heat transfer rate to the reactor coolant of 3293 MWT.

I REACTOR PROTECTION SYSTEM RESPONSE TIME 1.35 REACTOR PROTECTION SYSTEM RESPONSE TIME shall be the time interval fro ~m when the monitored parameter exceeds its trip setpoint at the channel 4

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 i

1.36 A REPORTABLE EVENT shall be any of those conditions specified in Section 50.73 to 10 CFR Part 50.

, ROD DENSITY i

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% ROD DENSITY.

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DEFINITIONS SECONDARY CONTAINMENT INTEGRITY 1.38 SECONDARY CONTAINMENT INIEGRITY shall exist when:

a. All secondary 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 filtration, recirculation and ventilation system is in compliance with the requirements of Specification 3.6.5.3.

d. For double door arrangements, at least one door in each access to the secondary containmcnt is closed.

e. For single door arrangements, the door in each access to the secondary containment is closed, except for normal entry and exit.

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 SHUTOOWN MARGIN shall be the amount of reactivity by which the reactor is subcritical or would be subcritical assuming all control rods are fully inserted except for the single control rod of highest reactivity worth which is assumed to be fully withdrawn and the reactor 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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- -. l SOLIDIFICATION 1.41 SOLIDIFICATION shall be the immobilization of wet radioactive wastes such as evaporator bottoms, spent resins, sludges, and reverse osmosis concen-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).

l 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 1 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.

TURBINE BYPASS SYSTEM RESPONSE TIME

1.45 The TURBINE BYPASS SYSTEM RESPONSE TIME consists of two separate time inter-i vals: a) time from initial movement of the main turbine stop valve or con-trol valve until 8D% 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 ,

I steps such that the entire response time is measured.

UNIDENTIFIED LEAKAGE I

1.46 UNIDENTIFIED LEAKAGE shall be all leakage which is not IDENTIFIED LEAKAGE.

UNRESTRICTED AREA 1.47 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-tion of individuals from exposure to radiation and radioactive materials, or any area within the SITE BOUNDARY used for residential quarters or for industrial, commercial, institutional, and/or recreational purposes.

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- .. i DEFINITIONS VENTILATION EXHAUST TREATMENT SYSTEM 1.48 A VENTILATION EXHAUST TREATMENT SYSTEM shall be any system designed and installed to reduce gaseous radioiodine 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 systems are not considered to be VENTILATION EXHAUST TREATMENT S.YSTEM components.

VENTING 1.49 VENTING shall be the controlled process of discharging air or gas from a confinement to maintain temperature, pressure, humidity, concentration or other operating condition, in such a manner that replacement air or gas is not provided or required during VENTING. Vent, used in system names, does not imply a VENTING process.

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TABLE 1.1 SURVEILLANCE FREQUENCY NOTATION NOTATION FREQUENCY S At least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

D At least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

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.

P Prior to each radioactive release.

N. A. Not applicable.

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__- _ , , _ _ , , _ _ l OPERATIONAL CONDITIONS MODE SWITCH AVERAGE REACTOR CONDITIO_N POSITION COOLANT TEMPERATURE

1. POWER OPERATION Run Any temperature

2. STARTUP Startup/ Hot Standoy Any temperature

3. HOT SHUTDOWN Shutdown #'*** > 200*F

4. COLD SHUTDOWN Shutdown #'##'*** $ 200 F

5. REFUELING

Shutdown or Refuel **'# $ 140*F

The reactor mode switch may be placed in the Run or Startup/ Hot Standby position to test the switch interlock functions and related instrumentation 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.

1

1. 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 or withdrawn provided that the one-rod-out interlock is OPERABLE.

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2.1 SAFETY LIMITS THERMAL POWER, Low Pressure or Low Flow 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 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months 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 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months and comply with the requirements of Specification 6.7.1.

REACTOR COOLANT SYSTEM PRESSURE 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 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months and comply with the requirements of Specification 6.7.1.

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REACTOR VESSEL WATER LEVEL 2.1.4 The reactor vessel water level shall be above the top of the active irradiated fuel.

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.

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2.2 LIMITING SAFETY SYSTEM SETTINGS 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.

APPLICABILITY: As shown in Table 3.3.1-1.

ACTION:

4 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.

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n , REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS E

p ALLOWABLE FUNCTIONAL UNIT TRIP SETPOINT VALUES

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 1 20% of RATED THERMAL POWER

b. Flow Biased Simulated Thermal Power-Upscale

1) Flow Biased 5 0.66 W+51%, with 5 0.66 W+54%, with a maximum of a maximum of

2) High Flow Clamped i 113.5% of RATED $ 115.5% of RATED THERMAL POWER THERMAL POWER I c. Fixed Neutron Flux-Upscale 1 118% of RATED THERMAL POWER $ 120% of RATED THERMAL POWER

d. Inoperative NA NA

e. Downscale > 5% of RATED

~ > 3% of RATED THERMAL POWER - THERMAL POWER

3. Reactor Vessel Steam Dome Pressure - High i 1037 psig i 1057 psig 7 l

4. Reactor Vessel Water Level - Low, Level 3 > 12.5 inches above instrument > 11.0 inches at$,v) zero* instrument ero l

S. Main Steam Line Isolation Valve - Closure -< 8% closed < 12% closed 73 ! ,

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t 6. Main Steam Line Radiation - High - High 5 3.0 x full power background 13.6xfullpower; background .. ;

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n REACTOR PROTECTION SYSTEM INSTRUNENTATION SETPOINTS g (continued)

ALLOWABLE l FUNCTIONAL UNIT TRIP SETPOINT VALUES

7. Drywell Pressure - High 5 1.68 psig < 1.88 psig

8. Scram Discharge Volume Water Level - High

a. Float Switch Elevation 110' 10.5" Elevation 111' O.5" (80 inches above instrument (82 inches above zero*) instrument zero*)

b. Level Transmitter / Trip Unit 80 inches above instrument 88 inches above zero" instrument zero*

.i y 9. Turbine Stop Valve - Closure 5 5% closed

m 5 7% closed

10. Turbine Control Valve Fast Closure, Trip 011 Pressure - Low 1 530 psig 1 465 psig

11. Reactor Mode Switch Shutdown Position NA NA

12. Manual Scram NA NA T1 i.

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! AND LIMITING SAFETY SYSTEM SETTINGS l

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The BASES contained in succeeding pages sumarize

! the reasons for the Specifications in Section 2.0, but in accordance with 10 CFR 50.36 are not part of these Technical Specifications.

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2.1 SAFETY LIMITS BASES

2.0 INTRODUCTION

The fuel cladding, reactor pressure vessel and primary system piping are the principal barriers to the release of radioactive materials to the environs. Safety Limits are established to protect 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 10s 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 head will be greater than 28 x 103 lbs/hr. Full scale ATLAS test data taken at pressures 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 factors, this corresponds to a THERMAL POWER of more than 50% of RATED THERMAL POWER. Thus, a THERMAL POWER limit of 25% of RATED THERMAL POWER for reactor pressure below 785 psig is conservative.

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BASES 2.1.2 THERMAL POWER, High Pressure and High Flow The fuel cladding integrity Safety Limit is set such that no fuel damage is calculated to occur if the limit is not violated. Since the parameters which result in fuel damage are not directly observable during reactor operation, the thermal and hydraulic conditions resulting in a departure from nucleate boiling have been used to mark the beginning of the region where fuel damage .

could occur. Although it is recognized that a departure from nucleate boiling would not necessarily result in damage to SWR fuel rods, the critical power at which boiling transition is calculated to occur has been adopted as a convenient limit. However, the uncertainties in monitoring the core operating state and in the procedures used to calculate the critical power result in an uncertainty in the value of the critical power. Therefore, the fuel cladding integrity Safety Limit is defined as the CPR in the limiting fuel assembly for which more than 99.9% of the fuel rods in the core are expected to avoid boiling transition considering the power distribution within the core and all uncertain-ties.

The Safety Limit Analysis Basis, GETAB,MCPR is adetermined

, which is statisticalusing modelthe General that combinesElectric all ofThermal the uncertainties in operating parameters and the procedures used to calculate critical power. The probability of the occurrence of boiling transition is determined using the General Electric Critical Quality (X) Boiling Length (L),

(GEXL), correlation.

The GEXL correlation is valid over the range of conditions used in the tests of the data used to develop the correlation.

The required input to the statistical model are the uncertainties listed in Bases Table 82.1.2-1 and the nominal values of the core parameters listed in Bases Table 82.1.2-2.

The bases for the uncertainties in the core parameters are given in D

NEDO-20340 and the basis for the uncertainty in the GEXL correlation is given a

in NED0-10958-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 distribution having the greatest number of assemblies at the highest power levels. The worst distribution during any fuel cycle would not be as severe as the distribution used in the analysis.

a. " General Electric BWR Thermal Analysis Bases (GETAB) Data, Correlation and Design Application," NE00-10958-A.

b. General Electric " Process Computer Performance Evaluation Accuracy" NE00-20340 and Amendment 1, NE00-20340-1 dated June 1974 and December 1974, respectively.

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Bases Table 82.1.2-1 UNCERTAINTIES USED IN THE DETERMINATION OF THE FUEL CLADDING SAFETY LIMIT

Standard Deviation Quantity (% of Point)

Feedwater Flow 1.76 Feedwater Temperature 0.76 Reactor Pressure 0.5 Core Inlet Temperature 0.2 Core Total Flow 2.5 Channel Flow Area 3.0 Friction Factor Multiplier 10.0 Channel Friction Factor Multiplier 5.0 TIP Readings 6.3 R Factor 1.5 Critical Power 3.6 l

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.

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~~-J BASES 2.1.3 REACTOR COOLANT SYSTEM PRESSURE The Safety Limit for the reactor coolant system pressure has been selected such that it is at a pressure below which it can be shown that the integrity of the system is not endangered. The reactor pressure vessel is designed to Section III of the ASME Boiler and Pressure Vessel Code 1968 Edition, including 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 831.7 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 allowed by theSafety Limitcodes.

applicable is selected to be the lowest transient overpressure, 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 4

' the top of the active irradiated fuel to provide a point which can be monitored and also provide adequate margin for effective action.

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l 2.2.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS The Reactor Protection System instrumentation setpoints specified 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 but within its specified Allowable Value is acceptable on the basis that the difference between each Trip Setpoint and the Allowable Value is an allowance for instrument drift specifically allocated 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 show 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 l sequence and provides backup protection for the APRM.

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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 adequate 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 RWM. Of all the possible sources of reactivity input, uniform con-trol rod withdrawal is the most probable cause of significant power increase.

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LIMITING SAFETY SYSTEM SETTINGS BASES REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS (Continued)

Average Power Range Monitor (Continued)

Because the flux distribution associated with uniform 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 610.6 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 CMFLPD 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 i 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.

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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, icw 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.

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7. Drywell 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 tripped 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 l 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 approximately 35 gallons of water.

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LIMITING SAFETY SYSTEM SETTING ev~ r ? -

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.._h BASES REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS (Continued)

9. Turbine Stop Valve-Closure The turbine stop valve closure trip anticipates 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 011 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 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 valve fastvalves and in less than 30 milliseconds after the start of control 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 produce transients which 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

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l SECTIONS 3.0 and 4.0 LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS 1

1 i

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SEP 3 0199E

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3/4.0 APPLICABILITY .u a -- .- '

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LIMITING CONDITION FOR OPERATION 3.0.1 Compliance with the Limiting Conditions for Operation contained in the succeeding Specifications is required during the OPERATIONAL CONDITIONS or other conditions specified therein; except that upon failure to meet the Limiting Conditions 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 intirvals. If the Limiting Condition for Operation is restored prior to expiration of the specified time intervals, completion of the Action requirements is nct 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 an OPERATIONAL CONDITION in which the Specification does not apply by placing it, as applicable, in:

1. At least STARTUP within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months ,

2. At least HOT SHUTDOWN within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , and

3. At least COLD SHUTDOWN within the subsequent 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

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 applicabl'e 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 shell 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.

S U S 0 1995 HOPE CREEK 3/4 0-1

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APPLICABILITY * - '

SURVEILLANCE REQUIREMENTS 4.0.1 Surveillance Requirements shall be met during the OPERATIONAL CONDITIONS or other conditions specified for individual Limiting Conditions for Operation unless otherwise stated in an individual Surveillance Requirement.

4.0.2 Each Surveillance Requirement shall be performed within the specified 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 Surveillance 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 componen*.s 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) (1).

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 inspection and testing activities activities 1 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 days Yearly or annually At least once per 366 days HOPE CREEK 3/4 0-2 SEF 3 01995

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APPLICABILITY " ^ *'.' d l

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.

4 d. Performance of the above inservice 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.

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SEP 3 01985 HOPE CREEK 3/4 0-3 t

1 pqat o ryx- s, f. o . , l 3/4.1 REACTIVITY CONTROL SYSTEMS

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3/4.1.1 SHUTOOWN MARGIN l

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 SHUTOOWN MARGIN within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

4

b. In OPERATIONAL CONDITION 3 or 4, immediately verify all insertable control rods to be inserted and suspend all activities that could i

reduce the SHUTDOWN MARGIN. In OPERATIONAL CONDITION 4, establish SECONDARY CONTAINMENT INTEGRITY within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months .

c. In OPERATIONAL CONDITION 5, suspend CORE ALTERATIONS and other i

activities that could reduce the SHUTDOWN MARGIN and insert all insertable control rods within I hour. Establish SECONDARY CONTAIN-MENT INTEGRITY within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months .

SURVEILLANCE REQUIREMENTS 4.1.1 The SHUTOOWN 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 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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 i

the withdrawn worth of the immovable or untrippable control rod.

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HOPE CREEK 3/4 1-1 SEP 3 01985

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REACTIVITY CONTROL SYSTEMS --

1 3/4.1.2 REACTIVITY ANOMALIES !

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LIMITING CONDITION FOR OPERATION 3.1.2 The reactivity equivalence of the difference between the actual R0D 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 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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 SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

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.

HOPE CREEK 3/4 1-2

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REACTIVITY CONTROL SYSTEMS 3/4.1.3 CONTROL RODS CONTROL R00 OPERABILITY

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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 ** hydraulically by closing the drive water and exhaust water isolation valves.

Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

2. Restore the inoperable control rod, if withdrawn, to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

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.

i I

i *The inoperable control rod may then bc withdrawn to a position on further j withdrawn than its position when found to be inoperable.

l **May be rearmed intermittently, under administrative control, to permit testing associated with restoring the control rod to OPERABLE status.

b HOPE CREEK 3/4 1-3 1

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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 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

3. The provisions of Specification 3.0.4 are not applicable.

c. With more than 8 control rods inoperable, be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ,

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 OPERA 8LE status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

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 OPERA 8LE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months or be in at least NOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

SURVEILLANCE REQUIREMENTS 4.1.3.1.1 The scram discharge volume drain and vent valves shall be "

demonstrated OPERA 8LE by:

a. At least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 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.

l 4.1.3.1.2 When above the low power setpoint of the RWM and RSCS, all withdrawn control rods not required to have their directional control valves disarmed 1

, *These valves may be closed intermittently for testing under administrative

controls. -

- May be rearmed intermittently, under administrative control, to permit testing associated with restoring the control rod to OPERABLE status.

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REACTIVITY CONTROL SYSTEMS --

SURVEILLANCE REQUIREMENTS (Continued) 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 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 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 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.

,. 2 SEP 3 01985 i HOPE CREEK 3/4 1-5 l

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REACTIVITY CONTROL SYSTEMS CONTROL R0D MAXIMUM SCRAM INSERTION TIMES 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-energization of the scram 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 insertion times in excess of 7.0 seconds.

Otherwise, be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ,

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 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 t

once per 120 days of POWER OPERATION. -- :.

SEF S 01955 HOPE CREEK 3/4 1-6

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REACTIVITY CONTROL SYSTEMS l

l CONTROL ROD AVERAGE SCRAM INSERTION TIMES

! 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-energization 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 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

SURVEILLANCE REQUIREMENTS i

~

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.

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REACTIVITY CONTROL SYSTEMS FOUR CONTROL R0D GROUP SCRAM INSERTION TIMES 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 0.45 39 0.92 25 2.05 5 3.70 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 1

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 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

b. The provisions of Specification 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS 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.S.2. >. .

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HOPE CREEK 3/4 1-8

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T v-( {8Nu,f9,ry.uemna u..,...;, tu l REACTIVITY CONTROL SYSTEMS l CONTROL ROD SCRAM ACCUMULATORS 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 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months s:

a) Restore the inoperable accumulator to OPERABLE st'atus, or b) Declare the control rod associated with the inoperable accumulator inoperable.

Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

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 accu-mulator 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. If no control rod drive pump is operating: 1) If reactor pressure is

> 900 psig, restart at least one control rod drive pump within 20 minutes or place the reactor mode switch in the Shutdown position. 2) If reactor pressure is < 900 psig, 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 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

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 j

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 and 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 39g

REACTIVITY CONTROL SYSTEMS PRE <t rma< a -/ -

SURVEILLANCE REQUIREMENTS l 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 the 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 verifying an alarm setpoint of 940 + 30, -0 psig on decreasing pressure.

2. Measuring and recording the time for at least 10 minutes that each individual accumulator check valve maintains the associated accumulator pressure above the alarm setpoint, starting at nor-mal system operating pressure, with no control rod drive pump operating.

HOPE CREEK 3/4 1-10 gp<g01985

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REACTIVITY CONTROL SYSTEMS l f T-.," s f" ' ' ~ - . ,

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CONTROL ROD DRIVE COUPLING j LIMITING CONDITION FOR OPERATION L

3.1.3.6 All control rods shall be coupled to their drive mechanisms.

1 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 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months s:

< l. If permitted by the RWM and RSCS, insert the control rod to accomplish recoupling and verify recoupling by withdrawing the control rod, and:

I a) Observing any indicated response of the nuclear instrumentation, and b) Demonstrating that the control rod will not go to the overtravel position.

2. If recoupling is not accomplished on the first attempt or, if not permitted by the RWM 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 SHUT 00WN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , i

b. In OPERATIONAL CONDITION 5* with a withdrawn control rod not coupled to its associated drive mechanism, within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months 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 i

the associated directional control valves ** either:

a) Electrically, or a b) Hydraulically by closing the drive water and exhaust water isolation valves.

c. The provisions of Specification 3.0.4 are not applicable, i "At least each withdrawn control rod. Not applicable to control'rods removed 1

per Specification 3.9.10.1 or 3.9.10.2.

- May be rearmed intermittently, under administrative control, to permit l testing associated with restoring the control rod to OPERABLE status, i

HOPE CREEK 3/4 1-11 gr y 0 %

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REACTIVITY CONTROL SYSTEMS C~n2 6 . . w J I. . .'. . . . g .

- ,e s,,i l SURVEILLANCE REQUIREMENTS 1

i 4.1.3.6 Each affected control rod shall be demonstrated to be cou' pled to its drive mechanism by observing any indicated response of the nuclear instrumen-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 ALTFRATIONS 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, i

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REACTIVITY CONTROL SYSTEMS L Ed..

.df CONTROL ROD POSITION INDICATION LIMITING CONDITION FOR OPERATION 3.1.3.7 The control rod position indication system shall be OPERABLE.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 5*.

ACTION:

a. In OPERATIONAL CONDITION 1 or 2 with one or more control rod position indicators inoperable, within 1 hour:

1. Determine the position of the control rod by utilizing the RSCS substitute position display within preset power level, or:

a) Moving the control rod, by single notch movement, to a position with an OPERABLE position indicator, b) Returning the control rod, by single notch movement, to its original position, and c) Verifying no control rod drift alarm at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , or

2. Move the control rod to a position with an OPERABLE position indicator, or

3. When THERMAL POWER is:

a) Within the preset power level of the RSCS, declare the control rod inoperable.

b) Greater than the preset power level of the RSCS, declare the control rod inoperable, insert the control rod and 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 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

i

b. In OPERATIONAL CONDITION 5* 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.

l *At least each withdrawn control rod. Not applicable to control" rods removed per Specification 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 1-13 SEF 3 01W

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! REACTIVITY CONTROL SYSTEMS _

SURVEILLANCE REQUIREMENTS 4.1.3.7 The control rod position indication system shall be determined OPERABLE by verifying: ,

a. At least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months that the position of each control rod is indicated,

b. That the indicated control rod position changes during the movement I of the control rod drive when performing Surveillance Requirement 4.1.3.1.2, and

.1 c. That the control rod position indicator corresponds to the control i . rod position indicated by the " Full out" position indicator when performing Surveillance Requirement 4.1.3.6.b.

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CONTROL ROD ORIVE HOUSING SUPPORT 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 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

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.

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=~~_ l 3/4.1.4 CONTROL ROD PROGRAM CONTROLS R0D WORTH MINIMIZER LIMITING 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 other technically qualified member of the unit technical staff who is present at 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.

SURVEILLANCE REQUIREMENTS 4.1.4.1 The RWM shall be demonstrated OPERABLE:

a. In OPERATIONAL CONDITION 2 within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months prior to withdrawal of control rods for the purpose of making the reactor critical, and in OPERATIONAL CONDITION 1 within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months 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.

b. In OPERATIONAL CONDITION 2 within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months 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.

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 control rod.

d. By verifying that the control rod patterns and sequence input to the RWM computer are correctly loaded following any loading of the program into the computer. ,

a Entry into OPERATIONAL CONDITION 2 and withdrawal of selected control rods is permitted for the purpose of determining the OPERABILITY of the RWM prior to withdrawal of control rods for the purpose of bringing the reactor to criticality.

HOPE CREEK 3/4 1-16 3 g p,.

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ROD SEQUENCE CONTROL SYSTEM LIMITING CONDITION FOR OPERATION 3.1.4.2 The rod sequence coatrol system (RSCS) shall be OPERA 3LE.

APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2*#, when THERMAL POWER is less than or equal to 20% RATED THERMAL POWER, the minimum allowable low power setpoint.

ACTION:

a. With the RSCS inoperable, control rod movement shall not be permitted, except by a scram.

b. With an inoperable control rod (s), OPERABLE control rod movement may contir.ue by bypassing the inoperable control rod (s) in the RSCS provided that:

1. The position and bypassing of inoperable control rods is verified by a second licensed operator or other technically qualified member of the unit technical staff, and

2. There are not more than 3 inoperable control rods in any RSCS group.

SURVEILLANCE REQUIREMENTS 4.1.4.2 The RSCS shall be demonstrated OPERABLE by:

a. Performance of a system diagnostic function:

1. Within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months prior to each reactor startup, and

2. Prior tc movement of a control rod after rod inhibit mode automatic initiation when reducing THERMAL POWER.

b. Attempting to select and move an inhibited control 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 i when reducing THERMAL POWER.

See Special Test Exception 3.10.2 -

Entry into OPERATIONAL CONDITION 2 and withdrawal of selected control rods is permitted for the purpose of determining the OPERABILITY of the RSCS prior to withdrawal of control rods for the purpose of bringing the reactor to criticality.

HOPE CREEK 3/4 1-17 SU J l

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REACTIVITY CONTROL SYSTEMS ROD BLOCK MONITOR

[]}(( {' , . g , LIMITING CONDITION FOR OPERATION 3.1.4.3 Both rod block monitor (RBM) channels shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITION 1, when THERMAL POWER is greater than or equal to 30% of RATED THERMAL POWER. ACTION: .

a. With one RBM channel inoperable:

1. Verify that the reactor is not operating on a LIMITING CONTROL ROD PATTERN, and

2. Restore the inoperable RBM channel to OPERABLE status within 24 hours.

Otherwise, place the inoperable rod block monitor channel in the tripped condition within the next hour,

b. With both RBM channels inoperable, place at least one inoperable rod block monitor channel in the tripped condition within one hour.

SURVEILLANCE REQUIREMENTS 4.1.4.3 Each of the above required RBM channels shall be demonstrated OPERABLE by performance of a:

a. CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION at the frequencies and for the OPERATIONAL CONDITIONS specified in Table 4.3.6-1.

b. CHANNEL FUNCTIONAL TEST prior to control rod withdrawal when the reactor is operating on a LIMITING CONTROL R00 PATTERN.

HOPE CREEK 3/4 1-18

REACTIVITY CONTROL SYSTEMS - 3/4.1.5 STANDBY LIQUID CONTROL SYSTEM LIMITING CONDITION FOR OPERATION 3.1.5 The standby liquid control system shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, and 5* ACTION:

a. In OPERATIONAL CONDITION 1 or 2:

1. With one system 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 both system subsystems 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, insert all insertable control rods within one hour.

SURVEILLANCE REQUIREMENTS 4.1.5 The standby liquid control system shall be demonstrated OPERABLE:

a. At least once per 24 hours by verifying that;

1. The temperature of the sodium pentaborate solution in the storage tank is greater than or equal to 70*F.

2. The available volume of sodium pentaborate solution is within the limits of Figure 3.1.5-1.

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.

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b. At least once per 31 days by: -

1. Verifying the continuity of the explosive charge.

2. Determining that the available weight of sodium pentaborate 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 1255 psig is met.

d. At least once per 18 months during shutdown by:

1. Initiating one of the standby liquid control system subsystem, 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 and verifying that the relief valve does not actuate during recirculation to the test tank. 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 successfully fired. Both injection subsystems shall be tested in 36 months.

2. Demonstrating that the pump relief valve setpoint is less than or equal to 1400 psig.

3. ** Demonstrating that all heat traced piping between the storage tank and the injection pumps is unblocked 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 after the heaters are energized.

  "This test shall also be performed anytime water or boron is added to the solution or when the solution temperature drops below 70 F.
 **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 secuential, overlapping or total flow path steps such that the entire flow path is . included.

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                                                                 ~ ~ ~~~ -..% ,, j 3/4.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE LIMITING CONDITION FOR OPERATION                                         '

3.2.1 All AVERAGE PLANAR LINEAR HEAT GENERATION RATES (APLHGRs) for each ty of fuelinas shown a function Figures of AVERAGE 3.2.1-1, PLANAR 3.2.1-2, 3.2.1-3, EXPOSURE 3.2.1-4, and 3.2.1-5. shall not exceed the lim 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, 3.2.1-3, 3.2.1-4, or 3.2.1-5, 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, 3.2.1-3, 3.2.1-4 and 3.2.1-5:

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. i

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POWER DISTRIBUTION LIMITS '- OI J 3/4.2.2 APRM SETPOINTS LIMITING CONDITION FOR OPERATION 3.2.2 The APRM flow biased simulated thermal power-upscale scram trip setpoint (S) and flow biased neutron flux-upscale control rod block trip setpoint (SRB) shall be established according to the following relationships: TRIP SETPOINT ALLOWABLE VALUE S < (0.66W + 51%)T S < (0.66W + 54%)T Sj$(0.66W+42%)T g Sj1(0.66W+45%)T R where: 5 and S are in percent of RATED THERMAL POWER, W=LoohBrecirculation flow as a percentage of the loop recirculation flow which produces a rated core flow of (100) million lbs/hr, T = Lowest value of the ratio of FRACTION OF RATED THERMAL POWER (FRTP) divided by the CORE MAXIMUM FRACTION OF LIMITING POWER DENSITY (CHFLPD). T is applied only if less than or equal to 1.0. APPLICABILITY: OPERATIONAL CONDITION 1, when THERMAL POWER is greater than or equal to 25% of RATED THERMAL POWER. ACTION: With the APRM flow biased simulated thermal power-upscale scram trip setpoint and/or the flow biased neutron flux-upscale control rod block trip setpoint less conservative than the value shown in the Allowable Value column for S or S as above determined, initiate corrective action within 15 minutes andad$s,t5and/ ors g to be consistent with the Trip Setpoint values

within 6 hours or reduce THERMAL POWER to less than 25% of RATED THERMAL 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 flux-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 greater than the FRTP 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 provided that the j 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 2-7

                                                                             - ;v..

i . J . ,' ;Pa . .. ' r% 7 / 1 POWER DISTRIBUTION LIMITS -.

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l 3/4.2.3 MINIMUM CRITICAL POWER RATIO LIMITING CONDITION FOR OPERATION 3.2.3 The MINIMUM CRITICAL POWER RATIO (MCPR) shall be equal to or greater than the MCPR limit 1.20, times the K f of Figure 3.2.3-1 provided that the end-of-cycle recirculation pump trip cystem is OPERABLE per Specification 3.3.4.2. . APPLICABILITY: OPERATIONAL CONDITION 1, when THERMAL POWER is greater than or equal to 25% of RATED THERMAL POWER. ACTION: shown in Figure 3.2.3-1 initiate With MCPR corrective lesswithin action than15the MCPRand minutes limit times the X, MCPR to within the required restore limit within 2 hours or reduce THERMAL POWER to less than 25% of RATED THERMAL POWER within the next 4 hours. SURVEILLANCE REQUIREMENTS 4.2.3 MCPR shall be determined to be equal to or greater than the MCPR limit times the Kf shown in 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 R0D PATTERN for MCPR.

d. The provisions of Specification 4.0.4 are not applicable.

g . r '97) 1 HOPE CREEK 3/4 2-8

a y

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i l 1.3 AUTOMAT 4C FLOW CONTROL 1.1 MANUAL FLOW CONTROL SCOOP TURE SETPOINT CALISAATION POSillONED SO THAT FLOW MAXIMUM = 1823% 93 _ FLOW MAXIMUM = 197A% / ( FLOW MAXIMUM = 112.0% / FLOW MAXIMUM = ,117A% 0 30 40 08 et M 30 90 .100 Core Mour. % Of Resed Care new ' K FACTOR f , ,3g Figure 3.2.3-1 S(' ~ HOPE CREEK 3/4 2-9

N p% POWER DISTRIBUTION LIMITS '$8 . l#t [M -

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aijg{ 3/4.2.4 LINEAR HEAT GENERATION RATE -- ~ 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 I 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. Wittiin 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 R0D PATTERN for LHGR.

d. The provisions of Specification 4.0.4 are not applicable.

St.i 2 ' HOPE CREEK 3/4 2-10

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3/4.3 INSTRUMENTATION w,;jf 1

                                                                                <A*t 3/4.3.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION                               -

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 PROTECTION SYSTEM RESPONSE TIME as shown in Table 3.3.1-2. APPLICABILITY: As shown in Table 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 channe'Is 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.

i SURVEILLANCE REQUIREMENTS 4.3.1.1 Each reactor protection system instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, C9ANNEL 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 5YSTEM 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 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 3.3.1-1 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, except when this would cause the Trip Function to occur.

gy 2 e Y *- HOPE CREEK 3/4 3-1

x TABLE 3.3.1-1 REACTOR PROTECTION SYSTEM INSTRUMENTATION

   !2 m

W APPLICABLE MINIMUM OPERATIONAL OPERABLE CHANNELS FUNCTIONAL UNIT CONDITIONS PER TRIP SYSTEM (a) ACTION

1. Intermediate Range Monitors (b).

a. Neutron Flux - High 2 3 1 3,4(c) 5 2(d) 2

b. Inoperative 2 3 1 3, 4 2 5 2(d) 3 3 a

2. Average Power Range Monitor f '):

R a. Neutron Flux - Upscale, Setdown 2 2 1 3, 2 (c) 2(d) m

b. Flow Biased Simulated Thermal Power - Upscale 1 2 4

c. Fixed Neutron Flux - Upscale 1 2 4

d. Inoperative 1, 2 2 1 3,4(c) 5 2(d) 2 2

3 ---;

e. Downscale I I9) 2 4 lt .)

[$

3. Reactor Vessel Steam Dome

~"

I ', Pressure - High 1, 2 II) 2 1 3 y, 4. Reactor Vessel Water Level - Low, J m, level 3 1, 2 2 1 !

  .,                                                                                                                                                                 ~.   .

o 5. Main Steam Line Isolation Valve - , - . g Closure I I9) 4 4 . ..', p - s)

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TABLE 3.3.1-1 (Continued) o i m REACTOR PROTECTION SYSTEM INSTRUMENTATION 9 m W APPLICABLE MINIMUM OPERATIONAL OPERABLE CHANNELS FUNCTIONAL UNIT CONDITIONS PER TRIP SYSTEM (a) ACTION

6. Main Steam Line Radiation -

High 1, 2(I) 2 5

7. Drywell Pressure - High 1, 2(h) 2 1

8. Scram Discharge Volume Water Level - High

a. Float Switch 1, 2 I9) 2 1 S 2 3 R.

Y b. Level Transmitter / Trip Unit 1,2(g) 2 1 w 5 2 3

9. Turbine Stop Valve - Closure I II) 4(k) 6

10. Turbine Control Valve Fast Closure, Valve Trip System Oil Pressure - Low 1(3) 2(k) 6

I

11. Reactor Mode Switch Shutdown rs Position 1, 2 2 1 i !

3, 4 2 7 I . 5 2 3 j i

                  $ 12. Manual Scram                               1, 2                           2                1                             ,
                  '                                                  3, 4                           2               8                              i j                                                     5                           2               9                              ?

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                                                                         -New _ _

l .. j i TABLE 3.3.1-1 (Continued) f [],0 ~"' c n m - V ./ l _]--'- REACTOR PROTECTION SYSTEM INSTRUMENTATION ACTION 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 one 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. ACTION 5 - Be in STARTUP with the main steam line isolation valves closed within 6 hours or in at least HOT SHUTDOWN within 12 hours. ACTION 6 - Initiate a reduction in THERMAL POWER within 15 minutes and

reduce turbine first stage pressure to less than the automatic bypass setpoint 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 replacement of LPRM strings provided SRM instrumentation is OPERABLE per Specification 3.9.2. SEF S0:.P HOPE CREEK 3/4 3-4

                                                                  ' r. .~ e - -=

I _ TABLE 3.3.1-1 (Continued ) I'. ~ 4 Q h ' r d -

                                                                                ... , _ ~~ -~.[ ~ 'l REACTOR PROTECTION SYSTEM INSTRUMENTATION TABLE NOTATIONS (a) A channel may be placed in an inoperable status for up to 2 hours for required surveillance without placing the trip system in the tripped condition provided at least one OPERABLE channel in the 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) Unless adequate shutdown margin has been demonstrated per Specifica-tion 3.1.1, the " shorting links" shall be removed from the RPS circuitry prior to and during the time any control rod is withdrawn".

~'

(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, 6 IRMS and 2 SRMS. (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 less than or equal to 22% of turbine first stage pressure in psia, at valves wide open turbine throttle steam flow, equivalent to THERMAL POWER less than 30% of RATED THERMAL POWER. To allow for instrument accuracy, calibration, and drift, a setpoint of 19% of turbine first stage pressure in psig is used. (k) Also actuates the EOC-RPT system.

      *Not required for control rods removed per Specification 3.9.10.1 or 3.9.10.2.

3: l HOPE CREEK 3/4 3-5

TABLE 3.3.1-2 o

                         ??                                                            REACTOR PROTECTION SYSTEM RESPONSE TIMES 9

m 92 RESPONSE TIME FUNCTIONAL UNIT (Seconds)

1. Intermediate Range Monitors:

a. Neutron Flux - High NA

b. Inoperative NA

2. Average Power Range Monitor *:

a. Neutron Flux - Upscale, Setdown NA

b. Flow Biased Simulated Thermal Power - Upscale < 0.09**

c. Fixed Neutron Flux - Upscale 7 0.09

d. Inoperative HA

e. Downscale NA 50 3. Reactor Vessel Steam Dome Pressure - High < 0.55

                         **   4.                         Reactor Vessel Water Level - Low, Level 3                                7 1.05 i'   5.                         Main Steam Line Isolation Valve - Closure                                7 0.06

6. Main Steam Line Radiation - High NA

7. Drywe11' Pressure - High NA

8. Scram Discharge Volume Water Level - High NA

a. Float Switch NA

b. Level Transmitter / Trip Unit NA

9. Turbine Stop Valve - Closure < 0.06 __

10. Turbine Control Valve Fast Closure, I 7

Trip Oil Pressure - Low < 0.08# Ii f

11. Reactor Mode Switch Shutdown Position RA ( ;4

12. Manual Scram NA ! .' y- ,

j i-; >

Neutron detectors are exempt from response, time testing. Response time shall be measured i: 7 u) ns from the detector output or from the input of the first electronic component in-the channel.

                              **Not including simulated thermal power time constant, 6 1 0.6 seconds.

i i,.;

                                                                                                                                                               'l
                          ][,  # Measured from start of turbine control valve fast closure.                                                                     j
                                                                                                                                                              .)

3 e f

                                                                                                                                                   --.4

TABLE 4.3.1.1-1 o A REACTOR PROTECTION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS n E CHANNEL OPERATIONAL E CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH FUNCTIONAL UNIT CHECK TEST CALIBRATION (a) SURVEILLANCE REQUIRED

1. Intermediate Range Monitors:

a. Neutron Flux - High S/U(b) 5 S/U(c) ,W R 2 S W R 3,4,5

b. Inoperative NA W NA 2,3,4,5

2. Average Power Range Monitor (I):

a. Neutron Flux - 5/U(b) S, S/U(c),W SA 2 Upscale, Setdown S W SA 3,4,5

b. Flow Biased Simulated R' Thermal Power - Upscale 5,D I9) S/U(c) y

                                                                                                               ,     g(d)(e) SA,R(h),

y Y c. Fixed Neutron Flux -

                    "                                                                                   S/U(c) ,y Upscale                       5                            g(d) , 34             7

d. Inoperative NA W NA 1,2,3,4,5

e. Downscale S W SA 1

3. Reactor Vessel Steam Dome Pressure - High M S R 1, 2 J~7 t

4. Reactor Vessel Water Level - !;j Low, Level 3 S M R 1, 2 . 2

.3

5. Main Steam Line Isolation !/4 Valve - Closure NA M R 1 f,..,

                       $                       6. Main Steam Line Radiation -                                                                                                 3,'l es High                                S            M               R                    1, 2 9)                            ,~ . . .

1 i E 7. Drywell f -[yj l if Pressure - High 5 M R 1, 2

                                                                                                                                                                               .N.gi 1
                                                                                                                                                                            \

L _.

TABLE 4.3.1.1-1 (Ccntinued) x REACTOR PROTECTION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL OPERATIONAL 2 CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH y FUNCTIONAL UNIT CHECK TEST CALIBRATION SURVEILLANCE REQUIRED

8. Scram Discharge Volume Water Level - High

a. Float Switch NA Q R 1,2,S Id)

b. Level Transmitter / Trip Unit 5 M R 1,2,5(j)

9. Turbine Stop Valve - Closure NA M R 1

10. Turbine Control Valve Fast Closure Valve Trip System Oil Pressure - Low NA M R 1

11. Reactor Mode Switch w Shutdown Position NA R NA 1,2,3,4,5 A 12. Manual Scram NA M NA 1,2,3,4,5 Y

C" (a) Neutron detectors may be excluded from CHANNEL CALIBRATION. (b) The IRM and SRM channels shall be determined to overlap for at least 35 decades during each startup after entering OPERATIONAL CONDITION 2 and the IRM and APRM channels shail be determined to overlap ~ for at least 1 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 tiian 2% of RATEu THERMA '] _ POWER. Any APRM channel gain adjustment made in compliance with Specification 3.2.2 shall not be O included in determining the absolute difference. hg ,' (e) This calibration shall consist of the adjustment of the APRM flow biased channel to conform to a j g., calibrated flow signal. (f) The LPRMs shall be calibrated at least once per 1000 effective full power hours (EFPH) ,l ' }- using the TIP system. ' c; m (g) Verify measured core flow (total core flow) to be greater than or equal to established core flow at the.> Q existing recirculation loop flow (APRM % flow). ' ; 7. j w

(h) This calibration shall consist of verifying the 6 i 0.6 second simulated thermal power time constant. r 3 l (i) This function is not required to be OPERABLE when the reactor pressure vessel head is removed per >l

                                                    -.i       Specification 3.10.1.                                                                                     l .: 3' '

I4 (j) With any control rod withdrawn. Not applicable to control rods removed per Specification 3.9.10.1 l ; or 3.9.10.2. ~ '-

I pm e, z. , INSTRUMENTATION fdyg,( { ,), ,, t l 3/4.3.2 ISOLATION ACTUATION INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.2 The isolation 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 I

less conservative than the value shown in the Allowable Values column of Table 3.3.2-2, 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 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. i "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.

**The trip system need not be placed in the tripped condition if this would j cause the Trip Function to occur. When a trip system can be placed in the tripped condition without causing the Trip Function to occur, place the trip j

system with the most inoperable channels in the tripped condition; if both systems have the same number of inoperable channels, place either trip system in the tripped condition. I c. HOPE CREEK 3/4 3-9 ~~

                                                                                                                                 ? $0[

INSTRUMENTATION t fb, - fNY

                             ,                                                                          i SURVEILLANCE REQUIREMENTS I

l 4.3.2.1 Each isolation 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 4.3.2.1-1. 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. l l SEF ( HOPE CREEK 3/4 3-10

TABLE 3.3.2-1 5 g ISOLATION ACTUATION INSTRUMENTATION 2 VALVE ACTUA-E

TION GROUPS MINIMUM APPLICABLE OPERATEkdgY OPERABLECHANNEg) OPERATIONAL TRIP FUNCTION SIGNAL PER TRIP SYSTEM CONDITION ACTION i 1. PRIMARY CONTAINMENT ISOLATION

a. Reactor Vessel Water Level; 1) Low Low, Level 2 1,2,8,9, 2 1,2,3 20 12, 13, 14, 15, 17, 18 t 2) Low, Low Low, Level 1 10, 11, 15, 16 2 1,2,3 20; b. Drywell Pressure - High 1, 8, 9, 10, 2 1,2,3 20 11, 12, 13,
14, 15, 16 j

{ 17, 18 w

c. Reactor Building Exhaust 1, 8, 9, 12

                                .                   Radiation - High                           13, 14, 15,                    3               1,2,3            28 3

17, 18

d. Manual Initiation 1, 8, 9, 10 1 1,2,3 24 11, 12, 13, 14, 15, 16, 17, 18 -

m

 .l                                      2. SECONDARY CONTAINMENT ISOLATION                                                                                               "J
                                                                                                                                                                             - ' ;)

a. Reactor Vessel Water Level - 7 e i

Low Low, Level 2 19(c) 2 1, 2, 3 and

26 ' I "J

b ., Drywell Pressure - High 19(c) 2 1,2,3 26 , .; l ! c. Refueling Floor Exhaust i lI' l Radiation - High 19(C) 3 1, 2, 3 and

29 , -j .'

                                                                                                                                                                                ~
                                                                                                                                                                                  ~

i

d. Reactor Building Exhaust -

l Radiation - High 19(c) 3 1, 2, 3 and

28 r5

e. Manual Initiation 19(c) 1 1, 2, 3 and

26 1 l .b . ..

TABLE 3.3.2-1 (Continued) ISOLATI0N ACTUATION INSTRUMENTATION S VALVE ACTUA-E

TION GROUPS MINIMUM APPLICABLE OPERATEgY OPERABLECHANNEg) OPERATIONAL TRIP FUNCTION SIGNAL PER TRIP SYSTEM CONDITION ACTION

3. MAIN STEAM LINE ISOLATION

a. Reactor Vessel Water Level - 1 2 1,2,3 21 Low Low Low, Level 1

b. Main Steam Line Radiation - 1, 2(b) 2 1,2,3 21 High - High

c. Main Steam Line Pressure - 1 2 1 22 Low

d. Main Steam Line Flow - High 1 2/11ne 1, 2, 3 20

{ e. Condenser Vacuum - Low 1 2 1, 2**, 3** 21 w f. Main Steam Line Tunnel 1 2/line 1, 2, 3 21 y Temperature - High

g. Manual Initiation 1, 2, 17 2 1,2,3 25

4. REACTOR WATER CLEANUP SYSTEM ISOLATION

a. RWCU A Flow - High 7 1/ ValveI ') 1, 2, 3 23

b. RWCU a Flow - High, Timer 7 1/ Valve (e) 1, 2, 3 23 y'

c. RWCU Area Temperature - High 7 6/ Valvef ') 1, 2, 3 23 1,4

d. RWCU Area Ventilation a 7 6/ ValveI *) 1, 2, 3 23 : N Temperature High l _,

e, SLCS Initiation 7(I) 1/ ValveI *) 1, 2, 5# 23 ; -! '

f. Reactor Vessel Water 7 2/Valvc(') 1, 2, 3 23 f Level - Low Low, Level 2

g. Manual Initiation 7 1/ ValveI ') 1, 2, 3 25 -

                                                                                                    ;       2 ,

TABLE 3.3.2-1 (Continued) ISOLATION ACTUATION INSTRUMENTATION Q VALVE ACTUA-A TION GROUPS MINIMUM APPLICABLE OPERATEkdgY OPERABLE CHANNE OPERATIONAL TRIP FUNCTION SIGNAL PERTRIPSYSTEM(g) CONDITION ACTION

5. REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION

a. RCIC Steam Line a Pressure - High 6 1/ Valve (*) 1, 2, 3 23

b. RCIC Steam Line a Pressure - 6 1/ ValveI ') 1, 2, 3 23 High, Timer

c. RCIC Steam Supply 6 2/ Valve (*) 1, 2, 3 23 Pressure - Low R

d. RCIC Turbine Exhaust 6 2/ ValveI *) 1, 2, 3 23 Diaphragm Pressure - High w

h e. RCIC Pump Room 6 1/ Valve (*) 1, 2, 3 23 Temperature - High

f. RCIC Pump Room Ventilation Ducts 6 1/ Valve b) 1, 2, 3 23 a Temperature - High

g. RCIC Pipe Routing Area 6 1/ Valve (') 1, 2, 3 23 -

Temperature - High r,

h. RCIC Torus Compartment 6 3/ Valve (') 1, 2, 3 23 Temperature-High h'

i. Drywell Pressure - Higb(9) 6 2/ Valve (*) 1, 2, 3 23 h, .

j. Manual Initiation 6(h) 1/RCIC System 1, 2, 3 ' 25 f

.I

1. 7,i3 b

          "                                                                                                  .4 l_;;l

TABLE 3.3.2-1 (Continued) ISOLATION ACTUATION INSTRUMENTATION O VALVE ACTUA-lR TION GROUPS MINIMUM APPLICABLE

OPERABLE CHANNE OPERATIONAL TRIP FUNCTION OPERATEkdgY SIGNAL PERTRIPSYSTEM(g) CONDITION ACTION

6. HIGH PRESSURE COOLANT INJECTION SYSTEM ISOLATION

a. HPCI Steam Line a Pressure - 5 1/ ValveI ") 1, 2, 3 23 High

b. HPCI Steam Line a Pressure - 5 1/ ValveI *) 1, 2, 3 23 High, Timer

c. HPCI Steam Supply Pressure-Low 5 2/ ValveI *) 1, 2, 3 23 w d. HPCI Turbine Exhaust Diaphragm 5 2/ ValveI ') 1, 2, 3 23 i Pressure - High

   ,'         e.                                HPCI Pump Room                                  5           1/ ValveI ')    1, 2, 3          23

Temperature - High

f. HPCI Pump Room Ventilation 5 1/ ValveI *) 1, 2, 3 23 Ducts a Temperature - High

. g. HPCI Pipe Routing Area 5 1/ Valvef ') 1, 2, 3 23 Temperature - High i [~m 7

h. HPCI Torus Compartment 5 3/ Valvef ') 1, 2, 3 23 . [$

Temperature - High !

                                                                                                                                                                 ,j i,                            g Drywell Pressure - High(9)                      5           2/ ValveI ')    1, 2, 3          2)
                                                                                                                                                                        /

j. Manual Initiation S II) 1/HPCI system 1, 2, 3 25 k

 ,e.                                                                                                                                                               n y                                                                                             _ _ _ _ _ _               _ _ _ _ _ _ _ _ _ _ _ _ . _ . _ .

TABLE 3.3.2-1 (Continued) E A ISOLATION ACTUATION INSTRUMENTATION n E VALVE ACTUA-W TION GROUPS MINIMUM APPLICABLE OPERABLE CHANNE OPERATIONAL TRIP FUNCTION OPERATEDgj SIGNAL g PERTRIPSYSTEM(g) CONDITION ACTION

7. RHR SYSTEM SHUTDOWN COOLING MODE ISOLATION

a. Reactor Vessel Water Level - Low, Level 3 3 2/ ValveI ') 1, 2, 3 27

b. Reactor Vessel (RHR Cut-in Permissive) Pressure - High 3 2/ ValveI ') 1, 2, 3 27

c. Manual Initiation 3 1/ ValveI ') 1, 2, 3 25 R+

Y U 7' 1

                                                                                                                                                                                                               - .,1 s

f l . '3 ( db ~3 c' *(p

                                   .                                                                                                                                                                         "4

I. ,. ,

                                                                                ~ __

TrBLE 3.3.2-1 (Continued) I* ~ Yj

                                                              ~   ~

ISOLATION ACTUATION INSTRUMENTATION -- ACTION ACTION 20 - Be in at least HOT SHUTOOWN within 12 hours and in COLD SHUTOOWN within 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 SHUTDOWN within 12 hours and in COLD SHUTDOWN within the next 24 hours. ACTION 22 - Be in at least STARTUP within 6 hours. ACTION 23 - Close the affected 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 12 hours and in COLD SHUTDOWN within the following 24 hours. ACTION 25 - Restore the 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. ACTION 26 - Establish SECONDARY CONTAINMENT INTEGRITY with the Filtration, Recirculation and Ventilation System (FRVS) operating within one hour. ACTION 27 - Lock the affected system isolation valves closed within one hour and declare the affected system inoperable. ACTION 28 - Place the inoperable channel in the tripped condition or close the affected system isolation valves within one hour and declare the affected system inoperable. ACTION 29 - Place the inoperable channel in the tripped condition or establish SECONDARY CONTAINMENT INTEGRITY with the Filtration, Recirculation, and Ventilation System (FRYS) operating within one hour. NOTES When handling irradiated fuel in the secondary containment and during CORE ALTERATIONS and operations with a potential for draining the reactor vessel. When any turbine stop valve is greater than 90% open and/or when the key-locked bypass switch is in the Norm position.

 #   Refer to Specification 3.1.5 for applicability.

(a) A channel may be placed in an inoperable status for up to 2 hours for re- l quired surveillance without placing the trip system in the tripped condition provided at least one other OPERABLE channel in the same trip system is monitoring that parameter. (b) Also trips and isolates the mechanical vacuum pumps. (c) Also starts the Filtration, Recirculation and Ventilation System (FRVS). (d) Refer to Table 3.3.2-1 table notation for the listing of which valves in an actuation group are closed by a particular isolation signal. Refer to Tables 3.6.3-1 and 3.6.5.2-1 for the listings of all valves within an ' actuation group. l (e) Sensors arranged per valve group, not per trip system. (f) Closes only RWCU system isolation valve (s) HV-F001 and HV-F004. (g) Requires system steam supply pressure-low coincident with drywell pressure-high to close turbine exhaust vacuum breaker valves. (h) Manual isolation closes HV-F008 only, and only following manual or automatic initiation of the RCIC system. (i) Manual isolation closes HV-F003 and HV-F042 only, and only following manual or automatic initiation of the HPCI system. HOPE CREEK 3/4 3-16 SEF d' C H b

TABLE 3.3.2-1 (Continued) 5 g ISOLATION ACTUATION INSTRUMENTATION E TABLE NOTATION R This table notation identifies which valves, in an actuation group, are closed by a particular trip signal. If all valves in the group are closed by the trip signal, only the valve group number will be listed. If only certain valves in the group are closed by the trip signal, the valve group number will be listed followed by, , in parentheses, a listing of which valves are closed by the trip signal. TRIP FUNCTION VALVES CLOSED BY SIGNAL

1. PRIMARY CONTAINMENT ISOLATION

a. Reactor Vessel Water Level -

1) Low Low, Level 2 1 (HV-5834A, HV-5835A, HV-5836A, HV-5837A), 2, 8, 9, 12, 13, 14, 15 (HV-5154 HV-5155), 17, 18

2) Low Low Low, Level 1 10, 11, 15(HV-5126 A&B, HV-5152 A&B, HV-5147, HV-5148,

{ HV-5162), 16 Y b. Drywell Pressure - High 1 (HV-5834A, HV-5835A, HV-5836A, HV-5837A), 8, 9, 10, U 11, 12, 13, 14, 15, 16, 17, 18

c. Reactor Building Exhaust Radiation - High 1 (HV-5834A, HV-5835A, HV-5836A, HV-5837A), 8, 9, 12, 13, 14, 15, 17 (HV-5161), 18

d. Manual Initiation 1 (HV-5834A, HV-5835A, HV-5836A, HV-5837A),. Q 10, 11, 12, 13, 14, 15, 16, 17 (HV-5161), 18 f

_, 1

2. SECONDARY CONTAINMENT ISOLATION - .Y

.i

a. Reactor Vessel Water Level - .'

                                                                   ' Low Low, Level 2                                   19 tt                                                                                                      o         4       .

b. Drywell Pressure - High 19 i

 ,                                                                                                                                                                                     t C                          c.                                       Refueling Floor Exhaust Radiation - High           19                                                        -

d. Reactor Building Exhaust Radiation - High 19 Jlf

e. Manual Initiation 19

TABLE 3.3.2-1 (Continued) ISOLATION ACTUATION INSTRUMENTATION O TABLE NOTATION lR x TRIP FUNCTION VALVES CLOSE0 BY SIGNAL

3. MAIN STEAM LINE ISOLATION

a. Reactor Vessel Water Level - 1 (HV-F022A, B, C & D, HV-F028A, B, C & D, HV-F067A, B, Low Low Low, Level 1 C & D, HV-F016, HV-F019)

b. Main Steam Line Radiation - High, High 1 (as above), 2

c. Main Steam Line Presure - Low 1 (as above)

d. Main Steam Line Flow - High 1 (as above)

R

e. Condenser Vacuum - Low 1 (as above) w h f. Main Steam Line Tunnel 1 (as above)

Temperature - High

g. Manual Initiation 1 (as above), 2, 17 (SV-J004A-1, 2, 3, 4 & 5)

A. REACTOR WATER CLEANUP SYSTEM ISOLATION

a. RWCU A Flow - High 7

[M rp!

b. RWCU A Flow - High, Timer 7 '

l 6 . g

c. RWCU Area Temperature - High 7 -

l

.i

{ w."

                                                                                                                                       ; . 4 ,,

P d C. 3

       -x                                                                                                                                   %J
                                                                                                                                       -m.

TABLE 3.3.2-1 (Continued) ISOLATION ACTUATION INSTRUMENTATION O TABLE NOTATION

A x TRIP FUNCTION VALVES CLOSED BY SIGNAL

d. RWCU Area Ventilation 7 A Temperature - High

e. SLCS Initiation 7

f. Reactor Vessel Water Level - 7 Low Low, level 2

g. Manual Initiation 7 y 5. REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION Y a. RCIC Steam Line A Pressure - High 6 (HV-F007, HV-F076, HV-F008)

b. RCIC Steam Line A Pressure - High, Timer 6 (HV-F007, HV-F076, HV-F008)

c. RCIC Steam Supply Pressure - Low 6

d. RCIC Turbine Exhaust 6 (HV-F007, HV-F076, HV-F008)

~~

Diaphragm Pressure - High

                                                                                                           ' r3

e. RCIC Pump Room Temperature - High 6 (HV-F007, HV-F076, HV-F008) b[$,

e ,

                                                                                                          ' ' ~-

f. ;RCIC Pump Room Ventilation Ducts 6 (HV-F007, HV-F076, HV-F008)

              ,A Temperature - High                                                                   ) f I

O

g. RCIC Pipe Routing Area 6 (HV-F007, HV-F076, HV-F008) e

                                                                                                      .'2 j

Temperature - High I

  "                                                                                                 f       ,,, j

h. RCIC Torus Compartment Temperature - High 6 (HV-F007, HV-F076, HV-F008) 5

                                                                                                         ,.3         9 s ^2

TABLE 3.3.2-1 (Continued) ISOLATION ACTUATION INSTRUMENTATION 53 TABLE NOTATION A n TRIP FUNCTION VALVES CLOSED BY SIGNAL

i. Drywell Pressure - High 6 (HV-F062, HV-F084)

j. Manual Initiation 6 (HV-F008)

6. HIGH PRESSURE COOLANT INJECTION SYSTEM ISOLATION

a. HPCI Steam Line a Pressure - High 5 (HV-F002, HV-F100, HV-F003, HV-F042)

b. HPCI Steam Line a Pressure - High, Timer 5 (HV-F002, HV-F100, HV-F003, HV-F042)

R

 **             c. HPCI Steam Supply Pressure - Low                    5 Y

E! d. HPCI Turbine Exhaust 5 (HV-F002, HV-F100, HV-F003, HV-F042) Diaphragm Pressure - High

e. HPCI Pump Room Temperature - High 5 (HV-F002, HV-F100, HV-F003, HV-F042)

f. HPCI Pump Room Ventilation Ducts 5 (HV-F002, HV-F100, HV-F003, HV-F042) --

a Temperature - High ' i

g. ,

i

g. HPCI Pipe Routing Area 5 (HV-F002, HV-F100, HV-F003, HV-F042) , f 4', r Temperature - High i

-/.

h. hPCI Torus Compartment Temperature - High 5 (HV-F002, HV-F100, HV-F003, HV-F042)

                    *                                                                                         ,              2             -

en i. Drywell Pressure - High 5 (HV-F075, HV-F079) , "~! rn ': , [. j. Manual Initiation 5 (HV-F003, HV-F042) ~C

     .,                                                                                                                 t.7
        .                                                                                                               CI3
                                                                                                                        ~il
                                                                                                                        - 40

J TABLE 3.3.2-1 (Continued) o

            ??                                                   ISOLATION ACTUATION INSTRUMENTATION n

N? TABLE NOTATION W TRIP FUNCTION VALVES CLOSED BY SIGNAL

7. RHR SYSTEM SHUTDOWN COOLING M00E ISOLATION

, a. Reactor Vessel Water Level 3 (HV-F008, HV-F009, HV-F015A & B, HV-F022, HV-F023) i Low, Level 3

b. Reactor Vessel (RHR Cut-in 3 (HV-F008, HV-F009, HV-F015A & B, HV-F022, HV-F023)

Permissive) Pressure - High

c. Manual Initiation 3 (HV-F008, HV-F009, HV-F015A & B, HV-F022, HV-F023)

Ri N I:i c . y g "I i 1 i f 1

                                                                                                                                                                     .I I

(> p

.~

TABLE 3.3.2-2 ISOLATION ACTUATION INSTRUMENTATION SETPOINTS n ALLOWABLE

 %      TRIP FUNCTION                                    TRIP SETPOINT                        VALUE

1. PRIMARY CONTAINMENT ISOLATION

a. Reactor Vessel Water Level

1) Low Low, Level 2 > -38.0 inches * > -45.0 inches

2) Low Low Low, Level 1 5 -129.0 inches

i -136.0 inches

b. Drywell Pressure - High 31.68psig i1.88psig

c. Reactor Building Exhaust Radiation - High 5 1x10 3pCi/cc** 5 1.2x10 3pci/cc**

d. Manual Initiation NA NA

2. SECONDARY CONTAINMENT ISOLATION

a. Reactor Vessel Water Level -

Low Low, Level 2 _> -38.0 inches *

 ,                                                                                        _> -45.0 inches 1             b. Drywell Pressure - High             5 1.68 inches                    5 1.88 inches Y             c. Refueling Floor Exhaust M                   Radiation - High                    1 2x10 3pCi/cc**                 1 2.4x10 3pci/cc**

d. Reactor Building Exhaust Radiation - High 1 1x10 3pCi/cc** 1 1.2x10 3pCi/cc**

e. Manual Initiation NA NA

3. MAIN STEAM LINE ISOLATION

a. Reactor Vessel Water Level - *i' Low Low Low, Level 1 > -129.0 inches * > -136.0 inches !j,'

b. Main Steam Line 5 3.0 X full power 5 3.6 X full power !,; i Radiation - High, High background background , .

e , .,.t

c. Nain-SteamLine >

Pressure - Low > 756.0 psig > 736.0 psig 3

                                                                                                                  ,   )

w d. Main Steam Line i - Flow - High j. 7 5 108.7 psid $ 111.7 psid .- - e.~ .

                                                                                                              .'.,d
                                                                                                              ; =< j i      _1 1

TABLE 3.3.2-2 (Continued) ISOLATION ACTUATION INSTRUMENTATION SETPOINTS ALLOWABLE O TRIP FUNCTION TRIP SETPOINT VALUE R; MAIN STEAM LINE ISOLATION (Continued)

e. Condenser Vacuum - Low 2 8.5 inches Hg vacuum 2 7.6 inches Hg vacuum

f. Main Steam Line Tunnel Temperature - High 5 160 F 5 172 F

g. Manual Initiation NA NA

4. REACTOR WATER CLEANUP SYSTEM ISOLATION

a. RWCU a Flow - High < 60.0 gpm < 68.0 gpm

b. RWCU A Flow - High, Timer 45.0 seconds 5 t < 47.0 seconds 45.0 seconds 5 t 5 47.0 seconds

c. RWCU Area Temperature - High < 140*F or 135*F#*** < 152*F or 147*F#***

1 d. RWCU/ Area Ventilation a y Temperature - High 5 60*F < 70*F 0 e. SLCS Initiation NA NA

f. Reactor Vessel Water Level -

Low Low, Level 2 1 -38.0 inches

1 -45.0 inches

g. Manual Initiation NA NA

5. REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION

a. RCIC Steam Line A N Pressure - High < 218.0" H2 0** < 228.0" H2 0** 3' I

b. RCIC Steam Line A Pressure - 3.0 seconds < t < 13.0 seconds

                                                                                                 -   -              3.0 seconds < t < 13.0 pec M s
                                      ,High, Timer l

c. N RCIC Steam Supply Pressure - Low 1 64.5 psig 1 56.5 psig' l m:

d. RCIC Turbine Exhaust Diaphragm ! .J

    >                                  Pressure - High                            5 10.0 psig                       < 20.0 psig            ; ..'J yiI
   -O                                                                                                                                           ,

I

                                                                                                                                            . . . .J

      - .         . -           ~ - _ . .          . _ --.-. - - - - .-..----..- -                                            -   .- -..--.- -                  -- - ---..                  - -.

. t 1 TABLE 3.3.2-2 (Continued) , ISOLATION ACTUATION INSTRUNENTATION SETPOINTS ALLOWA8LE !8 TRIP SETPOINT VALUE lA TRIP FUNCTION - 4 2 m REACTOR CORE ISOLATION C0') LING SYSTEM ISOLATION (Continued) i

e. RCIC Pump Room Temperature - High $ 160*F $ 172*F

f. RCIC Pump Room Ventilation Duct A Temperature - High 5 80*F l 5 70*F t

g. RCIC Pipe Routing Area #

Temperature - High 5 160*F, 5 172*F L j h. RCIC Torus Compartment Temperature - High i 128'F, $ 140*F, r

i. Drywell Pressure - High 1 1.68 psig 5 1.88 psig i

NA i 3 J. Manual Initiation NA i 5

6. HIGH PRESSURE COOLANT INJECTION SYSTEM ISOLATION w

1 a. HPCI Steam A Pressure - High i 337.0 inches H20** 1 352.0 inches H2 0** . ) Y b. HPCI Steam a Pressure - High, 3.0 seconds 5 t 5 13.0 seconds 3.0 seconds i t 5 13.0 seconds

2 Timer i c. HPCI Steam Supply Pressure - Low 1 100.0 psig 1 90.0 psig I

d. HPCI Turbine Exhaust Diaphragm Pressure - High 5 10.0 psig 5 20.0 psig l t

! e. HPCI Pump Room Temperature - High 5 160*F $ 172*F i t HPCI Pump Room Ventilation [} i f. 5 80*F ! Ducts a Temperature - High 1 70*F l ', {! s

                                        ,HPCI Pipe Routing Area
!                            g.                                                                                                                    $ 172*F,,

l eTemperature - High 5 160*F,, 5 , j u, h. HPCI Torus Compartaent < 128'F

                                                                                                                                                   < 140*F
                                                                                                                                                                                          f g                               Temperature - High                                                                                                                                l
           ~~3

i. Drywell Pressure High $ 1.68 psig $ 1.88 psig .

l <

j. Manual Initiation NA NA frs g

                                                                                                                                                                                       * .s
                                                                                                                                                                                         ,y g
                                                                                                                                                                                     . *C              ,

4 i I i i

TABLE 3.3.2-2 (Continued) g ISOLATION ACTUATION INSTRUMENTATION SETPOINTS m n ALLOWABLE R TRIP FUNCTION TRIP SETPOINT VALUE E

7. RHR SYSTEM SHUTDOWN COOLING MODE ISOLATION

a. Reactor Vessel Water Level -

4 Low, Level 3 3 12.5 inches

1 11.0 inches

b. Reactor Vessel (RHR Cut-in Permissive) Pressure - High 5 82.0 psig 5,102.0 psig

c. Manual Initiation NA NA w "See Bases Figure B 3/4 3-1.

             )                                   ** Initial setpoint. Final setpoint to be determined during startup test program. -Any required change w                                      to this setpoint shall be submitted to the Commission within 90 days of test completion.

4 ***The higher setpoint valve is for the RWCU pump rooms and heat exchange rooms; the lower setpoint

valve is for the RWCU pipe chase.

                                                   #30 minute time delay.
                                                 ##15 minute time delay.

l n, I

                                                                                                                                                                                     !              ,3 :n

( = -, g

                                                                                                                                                                                            'n p                                                                                                                       ,
                                                                                                                                                                                          * "5 g-                                                                                                      e              ,o        f)                  <

i

~-)

1 :~

                   ~
                                                                                                                                                                                ! .~

l [~ ' )

J. f l

q *- .-

'j

i PO "' TABLE 3.3.2-3 f'**.=r3.

                                                                                  -         i.:J ; ]e ISOLATION SYSTEM INSTRUMENTATION RESPONSE TIME TRIP FUNCTION RESPONSE TIME (Seconds)#

1. PRIMARY CONTAINMENT ISOLATION

a. Reactor Vessel Water Level

1) Low Low, Level 2 g) ,

2) Low Low Low, Level 1 1 13 51.0

b. Drywell Pressure - High

c. Reactor Building Exhaust 5 13(a)

Radiation - High NA

d. Manual Initiation NA

2. SECONDARY CONTAINMENT ISOLATION

a. Reactor Vessel Water Level-Low, Low Level 2 < 13(,)

 . .         b. Drywell Pressure - High

c. Refueling Floor Exhaust Radiation - 513 1 13 Higb(b)

d. Reactor Building Exhaust 5 13(a)

Radiation - High(b)

e. Manual Initiation NA

3. MAIN STEAM LINE ISOLATION

a. Reactor Vessel Water Level - Low Low Low, level 1 < 13(a)

b. Main Steam Line Radiation - High High(a)(b)

c. Main Steam Line Pressure - Low 7 1.0*/< 13((a) ,

d. Main Steam Line Flow-High 7 1.0*/7 13(a),,

 ,,         e. Condenser Vacuum - Low 50.5*/513 a),,

NA f. Main Steam Line Tunnel Temperature - High NA

g. Manual Initiation NA

4. REACTOR WATER CLEANUP SYSTEM ISOLATION

a. RWCU a Flow - High

b. RWCU A Flow - High, Timer 5 13(*)##

NA

c. RWCU Area Temperature - High NA

d. RWCU Area Ventilation A Temperature - High NA

e. SLCS Initiation NA f.

Reactor Vessel Water Level - Low Low, Level 2 < 13(*)

g. Manual Initiation RA S.

REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION

a. RCIC Steam Line a Pressure - High b.

                                                                          < 13(a)###

RCIC Steam Line A Pressure - High, Timer RA

c. RCIC Steam Supply Pressure - Low $ 13(,)

d. RCIC Turbine Exhaust Diaphragm Pressure - High 1

NA l HOPE CREEK 3/4 3-26 ' TJ 3 ( '

l P

f. M.nC ,P W -~] ~.n ~o .. , -

                                                                                                                                                                              ,I t

i TABLE 3.3.2-3 (Continued) L __' _ j

                                                                                                                                                                        ,     l ISOLATION SYSTEM INSTRUMENTATION RESPONSE TIME 4

TRIP FUNCTION RESPONSE TIME (Seconds)#

'                                   REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION                                                         -

e. RCIC Pump Room Temperature - High NA J

f. RCIC Pump Room Ventilation Ducts a Temperature

. - High NA

g. RCIC Pipe Routing Area Temperature - High NA

h. RCIC Torus Compartment Temperature - High NA

i. Drywell Pressure - High g) {

j. 5 13 Manual Initiation NA

6. HIGH PRESSURE COOLANT INJECTION SYSTEM ISOLATION i

a. HPCI Steam Line a Pressure - High 1 13(,),g,

b. HPCI Steam Line A Pressure - High, Timer NA

~'

c. HPCI Steam Supply Pressure - Low $ 13(,)

1 d. HPCI Turbine Exhaust Diaphragm Pressure - High NA 3 e. HPCI Pump Room Temperature - High NA

f. HPCI Pump Room Ventilation Ducts A Temperature - High NA ,

!                                          g.          HPCI Pipe Routing Area Temperature - High                                  NA

h. HPCI Torus Compartment Temperature - High NA i 1. Drywell Pressure - High 1 13(,)

;                                          j.          Manual Initiation                                                          NA I                                   7. RHR SYSTEM SHUTDOWN COOLING MODE ISOLATION

a. Reactor Vessel Water Level - Low, Level 3

b. 113(*)

Reactor Vessel (RHR Cut-in Permissive) ! Pressure - High NA l c. Manual Initiation NA

)                                    (a) Isolation system instrumentation response time specified includes diesel generator starting and sequence loading delays.

1 (b) Radiation detectors are exempt from response time testing. Response time

!                                          shall be measured from detector output or the input of the first j                                           electronic component in the channel.

Isolation system instrumentation response time for MSIVs only. No diesel i

generator delays assumed for MSIVs.

                                        ** Isolation system instrumentation response time for associated valves i

except MSIVs.

                                         # Isolation system instrumentation response time specified for the Trip j                                          Function actuating each valve group shall be added to isolation time i

i 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 3 to 13 seconds. 'N i r HOPE CREEK 3/4 3-27 5 ~ U E E-

e TABLE 4.3.2.1-1 ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS Q CHANNEL OPERATIONAL N

CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED

1. PRIMARY CONTAINMENT ISOLATION

a. Reactor Vessel Water Level -

1) Low Low, Level 2 S M R 1,2,3

2) Low Low Low, Level 1 S M R 1,2,3

b. Drywell Pressure - High NA M R 1, 2, 3

c. Reactor Building Exhaust Radiation - High S M g) R 1,2,3

d. Manual Initiation NA M NA 1,2,3

2. SECONDARY CONTAINMENT ISOLATION 5:' a. Reactor Vessel Water Level -

Low Low, level 2 S M R 1, 2, 3 and *

, Y b. Drywell Pressure - High NA M R 1,2,3 y c. Refueling Floor Exhaust Radiation - High S M R 1, 2, 3 and *

d. Reactor Building Exhaust Radiation - High S M R 1, 2, 3 and *

e. Manual Initiation NA M(,) NA 1, 2, 3 and * ,

3. MAIN STEAM LINE ISOLATION ,ij

a. Reactor Vessel Water Level - ! 2 Low Low Low, Level 1 S M R 1,2,3 !

b. Main Steam Line '

l ,' '

                                 , Radiation - High, High             S             M               R                1,2,3             !

f. j c gMain Steam Line , ,' , !

Pressure - Low NA M R 1 i

d. Main Steam Line i i Flow - High S M R 1,2,3 3 i 3; .2 9 -f CJ }

                                                                                                                                     **--s 8

w

t TABLE 4.3.2.1-1 (Continued) ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL OPERATIONAL E CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH y TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED MAIN STEAM LINE ISOLATION (Continued) 1 e. Condenser Vacuum - Low NA M R 1, 2**, 3**

f. Main Steam Line Tunnel I

Temperature - High NA M R 1,2,3

g. Manual Initiation NA MI ") NA 1,2,3 5

4. REACTOR WATER CLEANUP SYSTEM ISOLATION

a. RWCU a Flow - High S M R 1,2,3

b. RWCU A Flow - High, Timer NA M R 1, 2, 3

{ c. RWCU Area Temperature - High NA M R 1, 2, 3 w d. RWCU Area Ventilation A

   $                                         Temperature - High                      NA           M                      R                1,2,3

e. SLCS Initiation NA M(b) #

                                                                                                                ,        NA                1, 2, 5

f. Reactor Vessel Water Level - Low Low, Level 2 S M R 1,2,3; g. Manual Initiation MA MI ") NA 1,2,3 S. REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION .h .b9; a. RCIC Steam Line A 1.-l
Pressure - High NA' M R 1,2,3: ~' n

;                                     b .'  'RCIC Steam Line A                                                                                                         - 5 N Pressure - High, Timer l

NA M R 1, 2, 3 -

)                                     c. RCIC Steam Supply Pressure -                                                                                       ,         ;

s' Low NA M R 1,2,3 ,1 .'. r- d. RCIC Turbine Exhaust Diaphragm e d.5* l C' Pressure - High NA M R 1,2,3 .! [ j l . _ , . , _ ,

TABLE 4.3.2.1-1 (Continued) 5 ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS E CHANNEL OPERATIONAL

 'O                                                 CHANNEL     FUNCTIONAL       CHANNEL        CONDITIONS FOR WHICH TRIP FUNCTION                               CHECK          TEST       CALIBRATION     SURVEILLANCE REQUIRED REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION (Continued)

e. RCIC Pump Room Temperature - High NA M R 1,2,3

f. RCIC Pump Room Ventilation Ducts A Temperature - High NA M R 1,2,3

g. RCIC Pipe Routing Area Temperature - High NA M R 1,2,3

h. RCIC Torus Compartment Temperature -High NA M R 1,2,3 m i. Drywell Pressure - High S M R 1,2,3 A j. Manual Initiation NA R NA 1,2,3 Y

4 g 6. HIGH PRESSURE COOLANT INJECTION SYSTEM ISOLATION

a. HPCI Steam Line a Pressure - High NA M R 1,2,3

b. HPCI Steam Line a Pressure - High Timer NA M R 1,2,3

c. HPCI Steam Supply --

Pressure - Low NA M R 1,2,3 , _r

d. HPCI Turbine Exhaust '

Diaphragm Pressure - High NA M i;' I R 1,2,3

e. llPCI Pump Room }.-

                                                                                                             ,                          j' Temperature - High                 NA            M               R                1,2,3            .
    'S

f. HPCI Pump Room Ventilation

     ,].           Ducts a Temperature - High         NA            M               R                1,2,3            {[,

l' g. HPCI Pipe Routing Area 1 - g Temperature - High NA M R 1,2,3 ( > s.:

.x

TABLE 4.3.2.1-1 (Continued) g ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIP.EMENTS CHANNEL OPERATIONAL 9 CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH y TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED HIGH PRESSURE COOLANT INJECTION SYSTEM ISOLATION (Continued)

h. HPCI Torus Compartment Temperature - High NA M R 1,2,3

i. Drywell Pressure - High NA M R 1,2,3

j. Manual Initiation NA , R NA 1,2,3

7. RHR SYSTEM SHUTDOWN COOLING MODE ISOLATION

a. Reactor Vessel Water Level -

Low, Level 3 5 M R 1,2,3 R b. Reactor Vessel (RHR Cut-in

Permissive) Pressure - High NA M R 1,2,3

c. Manual Initiation NA M(a) NA 1,2,3

                           " When handling irradiated fuel in the secondary containment and during CCRE ALTERATIONS and operations with a potential for draining the reactor vessel.
                          ** When any turbine stop valve is greater than 90% open and/or when the key-locked bypass switch is in the Norm position.                                                                                                   .7
                           # Refer to Specification 3.1.5 for applicability.                                                                         F$

(a) Manual initiation switches shall be tested at least once per 18 months during shutdown. All other circ ii)rq associated with manual initiation shall receive a CHANNEL FUNCTIONAL TEST at least once per 31 days as >a r.t j of ci.rcuitry required to be tested for automatic system isolation. , I ~3 (b) Each I. rain or logic channel shall be tested at least every other 31 days. ;- a i L ]2 M, 5.- 1 a-C e m 11

                                                              & ~~             -

PV, - . .. . INSTRUMENTATION ' Yinus g; <n*m' "E"'. O b',8 i I 3/4.3.3 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION LIMITING CONDITION FOR OPERATION t 3.3.3 The emergency core cooling system (ECCS) actuation instrumentation channels shown in Table 3.3.3-1 shall be OPERABLE with their trip setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.3.3-2 and with EMERGENCY CORE COOLING SYSTEM RESPONSE TIME as shown in Tab 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. SURVEILLANCE REQUIREMENTS 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 i 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 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 ECCS trip system. i

                                                                       *P 4

SEE 3 0 IW HOPE CREEK 3/4 3-32

TABLE 3.3.3-1 5 A EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION - n A MINIMUM OPERABLE E CHANNELS PER APPLICABLE TRIP OPERATIONAL TRIP FUNCTION FUNCTION (a) CONDITIONS ACTION

1. CORE SPRAY SYSTEM

a. Reactor Vessel Water Level - Low Low Low, level 1 2(b)(e) 1, 2, 3, 4*, 5* 30

b. Drywell Pressure - High 2(b)(e) 1, 2, 3 30

c. Reactor Vessel Pressure - Low (Permissive) 4/ division (f) 1, 2, 3 31 1/ division (b)(g) 4*' 5* 32

d. Manual Initiation y, 2, 3, 4*, 5* 33 w 2. LOW PRESSURE COOLANT INJECTION MODE OF RHR SYSTEM 1

w a. Reactor Vessel Water Level - Low Low Low, level 1 2/ valve 1, 2, 3, 4*, 5* 30 J, b. Drywell Pressure - High 2/ valve 1,2,3 30 w c. Reactor Vessel Pressure - Low (Permissive) 1/ valve 1,2,3 31 4*, 5* 32

d. Manual Initiation 1/ subsystem 1, 2, 3, 4*, 5* 33 ;

3. HIGH PRESSURE COOLANT INJECTION SYSTEM

a. Reactor Vessel Water Level - Low Low Level 2 4 1,2,3 34 _

b. Drywell Pressure - High 1, 2, 3 34 7

c. Condensate Storage Tank Level - Low 4(c) 2 1,2,3 35

d. Suppression Pool Water Level - High 2(d) 1, 2, 3 35 6] ,

e. Reactor Vessel Water Level - High, Level 8 4 1, 2, 3 31 Manual Initiation 1/ system 1, 2, 3 33 S"J i'

                                       .{ .                                                                                            ,

CUf Lf f

                           =
                                                                                                                                                !    I, I   '

i ; ,3 ta I , . CD '

I

                                                                                                                                                  ==c ,'
                                                                                                                                               % ==.

TABLE 3.3.3-1 (Cent'd) EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION z MINIMUM OPERABLE CHANNELS PER APPLICABLE TRIP OPERATIONAL 2, TRIP FUNCTION FUNCTION (a) CONDITIONS ACTION h 4. AUTOMATIC DEPRESSURIZATION SYSTEM

a. Reactor Vessel Water level - Low Low Low, Level 1 4 1,2,3 30

b. Drywell Pressure - High 4 1,2,3 30

c. ADS Timer 2 1,2,3 31

d. Core Spray Pump Discharge Pressure - High (Permissive) 1/ pump 1, 2, 3 31

e. RHR LPCI Mode Pump Discharge Pressure - High (Permissive) 2/ pump 1,2,3 31

f. Reactor Vessel Water level - Low, level 3 (Permissive) 2 1,2,3 31

g. ADS Drywell Pressure Bypass Timer 4 1,2,3 31

h. ADS Manual Inhibit Switch 2 1,2,3 31

i. Manual Initiation 4 1,2,3 33 MINIMUM APPLICABLE m TOTAL N0 CHANNELS g 0F CHANNELS (e) TOCHANNEL TRIP {,)

OPERABLE (,) OPERATIONAL CONDITIONS ACTION w 5. LOSS OF POWER g 1. 4.16 kv Emergency Bus Under-voltage (Loss of Voltage) 4/ bus 2/ bus 3/ bus 1, 2, 3, 4**, 5** 36

2. 4.16 kv Emergency Bus Under-voltage (Degraded Voltage) 2/ source / 2/ source / 2/ source / 1, 2, 3, 4**, 5** 36 bus bus bus (a) A channel may be placed in an inoperable status for up to 2 hours for required surveillance without placing the trip system in the tripped condition provided at least one OPERABLE channel in 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. e I, (d) Provides a signal to trip HPCI pump turbine only. When the system is required to be OPERABLE per Specification 3.5.2. f?a

                #    Not riquired to be OPERABLE when reactor steam dome pressure is less than or equal to 200 psig.                                                                        y.
                **   Required 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.                                                   i                 ,

us (e) In divisions 1 and 2, the two sensors are associated with each pump and valve combination. In divisions ' . E 3 and 4, the two sensors are associated with each pump only. -l t eo (f) Division 1 and 2 only. (g) In divisions 1 and 2, manual initiation is associated with each pump and valve combination; in divisions l g* j 3 and 4, manual initiation is associated with each pump only. gq

                                                                                                                                                                 -- w

n M o, M e n"f !" (<. ?/ uuu: l TABLE 3.3.3-1 (Continued) L.... A* r

                                                                      - _ _ _ . _ . e EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION ACTION ACTION 30 -   With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per 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 inoperat' 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, restore the inoperable channel to OPERABLE status within 8 hours or declare the associated ECCS inoperable. ACTION 34 - 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 tr.ip system in the tripped condition within one hour" or declare the HPCI system inoperable.

b. For both trip systems, declare the HPCI system inope'rable.

ACTION 35 - With the number of OPERABLE channels 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

or declare the HPCI system inoperable.

ACTION 36 - 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. SEP301985 HOPE CREEK 3/4 3-35

TABLE 3.3.3-2 5 A EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION SETPOINTS S

  "'                                                                                                ALLOWABLE E   TRIP FUNCTION                                                        TRIP SETPOINT               VALUE

1. CORE SPRAY SYSTEM

a. Reactor Vessel Water Level - Low Low Low, Level 1 >-129 inches * >-136 inches

b. Drywell Pressure - High 31.68psig 31.88psig

c. Reactor Vessel Pressure - Low > 461 psig, decreasing > 441 psig, decreasing

d. Manual Initiation NA NA

2. LOW PRESSURE COOLANT INJECTION MODE OF RHR SYSTEM

a. Reactor Vessel Water Level - Low Low Low, Level 1 >-129 inches * >-136 inches

b. Drywell Pressure - High 31.68psig 31.88psig w c. Reactor Vessel Pressure - Low (Permissive) > 450 psig, decreasing > 440 psig, decreasing i d. Manual Initiation NA NA

3. HIGH PRESSURE COOLANT INJECTION SYSTEM i cn

a. Reactor Vessel Water Level - (Low Low, Level 2) >-38 inches * >-45 inches

b. Drywell Pressure - High 31.68psig 31.88psig

c. Condensate Storage Tank Level - Low > 3.6% > 2.76%

d. Suppression Pool Water Level - High 377.0 inches 378.5 inches

e. Reactor Vessel Water Level - High, Level 8 5 54 inches 5 61 inches

f. Manual Initiation NA NA b,

c. e 'a e ei

                 <                                                                                               o       o,            .

M S r' t

   .o                                                                                                                    :1-

. O

l TABLE 3.3.3-2 (Continued) l k m EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRtMENTATION SETPOINTS ALLOWABLE k TRIP FUNCTION TRIP SETPOINT VALUE

E 4. AUTOMATIC DEPRESSURIZATION SYSTEM i

a. Reactor Water Level - Low Low Low, level 1 >-129 inches * >-136 inches

b. Drywell Pressure - High 31.68psig 31.88psig

c. ADS Timer < 105 seconds < 117 seconds

.          d. Core Spray Pump Discharge Pressure - High         [145psig, increasing     i155psig,increasingand e.
                                                                                            > 125 psig, increasing RHR LPCI Mode Pump Discharge Pressure-High         > 125 psig, increasing   < 135 psig, increasing and
                                                                                            > 115 psig, increasing

f. Reactor Vessel Water Level-Low, Level 3 > 12.5 inches > 11.0 inches

g. ADS Drywell Pressure Bypass Timer 55.0 minutes

h. ADS Manual Inhibit Switch 55.5 minutes NA NA l

1. Manual Initiation NA NA

{ 5. LOSS OF POWER i Y a. 4.16 kv Emergency Bus Undervoltage a. 4.16 kv Basis - U (Loss of Voltage)** 2975 1 30 volts 2975 1 63 volts

;                                                            b. 120 v Basis -

85 1 0.85 volts 85 i 1.8 volts

c. -< 0.07 sec. time ~< 0.07 sec. time +

delay delay - - , !

b. 4.16 kw Emergency Bus Undervoltage a. 4.16 kw Basis - '

i l (Degraded Voltage)** 38151114 volts 38151140 volts

b. 120 v Basis -

10913.3 volts 10914.0 volts $

c. >18.4 sec. time > 18.4 sec. time i

             ,   ,                                               delay                      delay        ,

See Bases Figure B 3/4 3-1.

      ** This is an inverse time delay voltage relay. The voltages shown are the maximum that will not p     result in a trip. Some voltage conditions will result in decreased trip times.

i I

.J

I l l

                                                                                                 .-                      i Q n t y

see n n e,, ,

TABLE 3.3.3-3 # '*i l !Nfi EMERGENCY CORE COOLING SYSTEM RESPONSE TIMES i ECCS RESPONSE TIME (Seconds)

1. CORE SPRAY SYSTEM

                                                                           $ 27

2. LOW PRESSURE COOLANT INJECTION MODE OF RHR SYSTEM $ 40

3. AUTOMATIC DEPRESSURIZATION SYSTEM NA

4. HIGH PRESSURE COOLANT INJECTION SYSTEM $ 27

5. LOSS OF POWER NA 1

                                                                                      -i pf 3 01985 HOPE CREEK                               3/4 3-38

TABLE 4.3.3.1-1 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS Q CHANNEL OPERATIONAL A

CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED

1. CORE SPRAY SYSTEM

a. Reactor Vessel Water Level -

Low Low Low, Level 1 5 M R 1, 2, 3, 4*, 5*

b. Drywell Pressure - High 5 M R 1, 2, 3

c. Reactor Vessel Pressure - Low 5 M R 1, 2, 3, 4*, 5*

d. Manual Initiation NA R NA 1, 2, 3, 4*, 5*

2. LOW PRESSURE COOLANT INJECTION MODE OF RHR SYSTEM

a. Reactor Vessel Water Level -

' !:>                          Low Low Low, Level 1                         5         M                   R     1, 2, 3,  4*, 5*

b. Drywell Pressure - High 5 M R 1,2,3 Y c. Reactor Vessel Pressure - Low 5 M R 1, 2, 3, 4*, 5*

M (Permissive)

d. Manual Initiation NA R NA 1, 2, 3, 4* , 5*

3. HIGH PRESSURE COOLANT INJECTION SYSTEM

a. Reactor Vessel Water Level -

Low Low, Level 2 5 M R 1,2,3 E.:;p l ,

b. Drywell Pressure - High S M R 1, 2, 3 33 5

c. Condensate Storage Tank Level - f, ,i Low 5 M R 1,2,3 m5

d. Suppression Pool Water Level - r;s ;

High 5 M R 1,2,3 3

e. Reactor Vessel Water Level - ' I High, Level 8 5 M R 1, 2, 3 l i'.:j T' '!

Manual Initiation NA , 1,2,3

f. R NA

                                                                                                                                        .(
   -                                                                                                                                  t r?

o <m>.,

TABLE 4.3.3.1-1 (Continued) EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS O CHANNEL OPERATIONAL lE 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 5 M R 1,2,3

e. RHR LPCI Mode Pump Discharge Pressure - High 5 M R 1,2,3

f. Reactor Vessel Water Level - Low, 5:' Level 3 S M R 1,2,3

g. ADS Drywell Pressure Bypass Timer NA M Q 1,2,3 Y h. ADS Manual Inhibit Switch NA R NA 1,2,3

              ;E;         i.                  Manual Initiation                      NA         R                    NA      1, 2, 3 S. 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-y voltage (Degraded Voltage) S M R 1, 2, 3, 4 * * , 5* * :: 3 <

CT When the system is required to be OPERABLE per Specification 3.5.2.

                                                                                                                                                     -d Requited.0PERABLE when ESF equipment is required to be OPERABLE.                                                '        p3 Not required to be OPERABLE when reactor steam done pressure is less than or equal to 200 psig.                            ~
                     ##    Not required to be OPERABLE when reactor steam done pressure is less than or equal to 100 psig.                            -"
                                                                                                                                                   ' *d
                   ,                                                                                                                                  c.:,

y L '*

_\ h h k.?[ -. _ - QYa 3/4.3.4 RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION ATWS RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION : LIMITING CONDITION FOR OPERATION 3.3.4.1 The anticipated transient without scram recirculation pump trip (ATWS-RPT) system instrumentation channels shown in Table 3.3.4.1-1 shall be OPERABLE with their trip setpoints set consistent with values shown in the Trip Setpoint column of Table 3.3.4.1-2. 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, or if this action will initiate a pump trip, declare the trip system inoperable.

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 REQUIREMENTS 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 freque'ncles s,hown 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. u..'3C1W HOPE CREEK 3/4 3-41

A TABLE 3.3.4.1-1 A ATWS RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION W MINIMUM OPERABLE CHANNELS PER TRIP FUNCTION TRIP SYSTEM (8)

1. Reactor Vessel Water Level - 2 Low Low, Level 2

2. Reactor Vessel Pressure - High 2 Ra T

i 7 73 03l rp :

                                                                                                                                                    .I          l h
                                                                                                                                         '51                    f M                            i                                                                                          '       ~sp                      -

e o ,--

                                                                                                                                      ,                       4 (a) One channel may be placed in an inoperable status for up to 2 hours for required surveillance          '

R' I

h provided the other channel is OPERABLE. '

Ib 4 3

                                                                                                                                    - -~ !

5 TABLE 3.3.4.1-2 n j* ATWS RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION SETPOINTS W TRIP ALLOWA8LE SETPOINT VALUE TRIP FUNCTION

1. Reactor Vessel, Water level - > -38 inches * > -45 inches Low Low, Level 2

2. Reactor Vessel Pressure - High 5 1071 psig i 1086 psig R+

T 0

                                                                                                                                                                ~n
                                       ^See Bases Figure B3/4 3-1.                                                                                              jyj 7
                                                                                                                                                               $ ._/.

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     ~                                                                                                                                                           1.

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                                                                                                                                     -r ,

TABLE 4.3.4.1-1 ATWS RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS S N 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 5 M R R.

t w I'1

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                                                                                                                       'k b%

l l py o p e 'n ..~ . I stud b n ,; , INSTRUMENTATION _ _ , , , END-OF-CYCLE RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.4.2 The end-of-cycle recirculation pump trip (E0C-RPT) system instrumentation channels shown in Table 3.3.4.2-1 shall be OPERABLE with their trip setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.3.4.2-2 and with the END-OF-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 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 turbine control valve channel and one 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 i than 30% of RATED THERMAL POWER within the next 6 hours'.-

l l SEP 3 0 Ige! HOPE CREEK 3/4 3-45

c

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                                                                               . ...7,'

INSTRUMENTATION . I

                                                                   -mmm.m.

SURVEILLANCE REQUIREMENTS 4.3.4.2.1 Each end-of-cycle recirculation pump trip system instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations at the frequencies shown in

Table 4.3.4.2.1-1.

l 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 TIME of 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. 4.3.4.2.4 The time interval necessary for breaker arc suppression from energization of the recirculation pump circuit breaker trip coil shall be measured at least once per 60 months. SEP 3 019ec HOPE CREEK 3/4 3-46

5 5 TABLE 3.3.4.2-1 k END-OF-CYCLE RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION W MINIMUM OPERABLECHANNE(j) TRIP FUNCTION PER TRIP SYSTEM

1. Turbine Stop Valve - Closure 2(b)

2. Turbine Control Valve-Fast Closure 2(b)

R T (a)A trip system may be placed in an inoperable status for up to 2 hours for required surveillance provided t 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 22% of turbine first stage pressure in psia at valves wide open turbine throttle steam flow, equivalent

to THERMAL POWER less than 30% of RATED THERMAL POWER. To allow for instrument accuracy, calibration and drift, a setpoint of 19% of turbine first stage pressure in psig is used. M

                                                                                                                             .~a
                            .                                                                                                s .3

7 } 'a1 e , 7o .

J 51 NU - Ca '} o f e J

, TA3LE 3.3.4.2-2 E A . END-OF-CYCLE RECIRCULATION PUMP TRIP SETPOINTS O h ALLOWABLE TRIP FUNCTION TRIP SETPOINT VALUE

1. Turbine Stop Valve-Closure 5 5% closed 5 7% closed

2. Turbine Control Valve-Fast Closure 1 530 psig 1 465 psig R.

Y s

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TABLE 3.3.4.2-3 a

                   ;E                                                      END-0F-CYCLE RECIRCULATION PUMP TRIP SYSTEM RESPONSE TIME k                            TRIP FUNCTION                                                           RESPONSE TIME (Milleseconds) 9

1. Turbine Stop Valve-Closure 5 175

2. Turbine Control Valve-Fast Closure $ 175 Y

e i

T.I p.' f i t' s o p I.* e . . i 6

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TABLE 4.3.4.2.1-1 o A END-0F-CYCLE RECIRCULATION PUMP TRIP SYSTEM SURVEILLANCE REQUIREMENTS n A CHANNEL E FUNCTIONAL CHANNEL TRIP FUNCTION TEST CALIBRATION

1. Turbine Stop Valve-Closure M R

2. Turbine Control Valve-Fast Closure M R M.

Y 8 1,

1 C .) i C

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3/4.3.5 REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION LIMITING CONDITION FOR OPERATION l 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 150 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 i i i 4.3.5.1 Each RCIC system actuation instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL j FUNCTIONAL TEST and CHANNEL CALIBRATION operations at the frequencies shown f in Table 4.3.5.1-1. 4.3.5.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic operation of i all channels shall be performed at least once per 18 months. 4 SEP 3 0 guy HOPE CREEK 3/4 3-51

5 m TABLE 3.3.5-1 m REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION W MINIMUM OPERABLECHANNEL{,) FUNCTIONAL UNITS PER TRIP SYSTEM ACTION

a. Reactor Vessel Water Level - Low Low, Level 2 2 50

b. Reactor Vessel Water Level - High, Level 8 2 50

c. Condensate Storage Tank Water Level - Low 2(b) 51

d. Manual Initiation 1/ system (c) 52

                   $         (a) A channel may be placed in an inoperable status for up to 2 hours for required surveillance without w             placing the trip system in the tripped condition provided at least one other OPERABLE channel in the J,             same trip system is monitoring that parameter.

N (b) One trip system with one-out-of-two logic. (c) One trip system with one channel.

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TABLE 3.3.5-1 (Continued) ) REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION ACTION 50 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip System requirement:

a. For one trip system, place the inoperable channel (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, place at least one inoperable channel in the tripped condition within one hour or declare the RCIC system inoperable. ACTION 52 - 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. SEF30 w. HOPE CREEK 3/4 3-53

5 A TABLE 3.3.5-2 REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION SETPOINTS , x i ALLOWABLE FUNCTIONAL UNITS TRIP SETPOINT VALUE

a. Reactor Vessel Water Level - Low Low, level 2 > -38 inches

2 -45 inches

b. Reactor Vessel Water Level - High, level 8 5 54 inches

5 61 inches

c. Condensate Storage Tank Level - Low > 3.6% > 2.96%

d. Manual Initiation NA NA w "See Bases Figure B 3/4 3-1.

D Y T F."~I l F-

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5 A TABLE 4.3.5.1-1 n E REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS W

,                                                                          CHANNEL 1'

CHANNEL FUNCTIONAL CHANNEL FUNCTIONAL UNITS CHECK TEST CALIBRATION

a. Reactor Vessel Water Level -

Low Low, Level 2 S M R i

b. Reactor Vessel Water S M R i level - High, level 8 4; c. Condensate Storage Tank Level - Low NA M R
i d. Manual Initiation NA M(a) NA Y

w (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. . I

                                                                                                                                                   .e. T i

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                                                                            ,                ~f INSTRUMENTATION                                              . . ,

3/4.3.6 CONTROL R0D BLOCK INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.6. The control rod block instrumentation channels shown in Table 3.3.6-1 shall be OPERABLE with their trip setpoints set consistent with the values shown in the Trip Setpoint column of 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 syst. ems 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.

                                                                      ~ ,.

SEP 3 01985 l HOPE CREEK 3/4 3-56

TABLE 3.3.6-1 CONTROL R00 BLOCK INSTRUMENTATION km MINIMUM APPLICABLE OPERADLE CilANNELS OPERATIONAL Q TRIP FUNCTION PER TRIP FUNCTION CONDITIONS ACTION h 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. Itoperative 4 1,2,5 61

c. Downscale 4 1 61

d. N utron Flux - Upscale, Startup 4 2, 5 61

3. SOURCE RANGE MONITORS

a. Detector not full in(b) 3 2 61 w 2 5 61 A b. Upscale (c) 3 2 61 w 2 5 61 Inoperative (c) 3 h c.

3

d. Downscale(d)

4. INTERMEDIATE RANGE MONITORS

a. Detector not full in 6 2, 5 61

b. Upscale 6 2, 5 61

c. Inoperati 6 2, 5 61 m

d. Downscale{g) 6 2, 5 61 E'

5. SCRAM DISCHARGE VOLUME !,

a. Water Level-High 2 1, 2, 5** 62 g

6. REACTOR COOLANT SYSTEM RECIRCULATION FLOW ' '

i-

a. Upscale 2 1 62

b. Inoperative 2 1 62

c. Comparator 2 1 62 m 7. REACTOR MODE SWITCil SituT00WN POSITION 2 1

C 3, 4 63 _ g - 2

pgy Ue ,'8 x- d d' TABLE 3.3.6-1 (Continued) :.-- CONTROL ROD BLOCK INSTRUMENTATION ! ACTION ! ACTION 60 - Declare the RBM inoperable and take the ACTION regt> ired by Specification 3.1.4.3. ACTION 61 - With the number of OPERABLE Channels:

a. One less than required by the Minimum OPERABLE Channels per Trip Function requirement, restore the inoperable channel to 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.

The provisions of Specification 3.0.4 are not applicable. 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. The provisions of Specification 3.0.4 are not applicable. ACTION 63 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, initiate a rod block. NOTES With THERMAL POWER > 30% of RAT D 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.

b. This function shall be automatically bypassed if detectcr 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~ch'annels 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 3-58 E l

TABLE 3.3.6-2 CONTROL ROD BLOCK INSTRUMENTATION SETPOINTS

 $                TRIP FUNCTION                                              TRIP SETPOINT                    ALLOWABLE VALUE

1. R00 BLOCK MONITOR 2 a. Upscale < 0.66 W + 40% < 0.66 W + 43%

A b. Inoperative NA NA

c. Downscale > 5% of RATED THERMAL POWER > 3% of RATED THERMAL POWER

2. APRM

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 5

NA 5

b. Upscale < 1.0 x 10 cps < 1.6 x 10 cps

c. Inoperative NA NA

d. Downscale > 3 cps ** > 1.8 cps 1 4. INTERMEDIATE RANGE MONITORS w a. Detector not full in NA NA J, b. Upscale < 108/125 divisions of < 110/125 divisions of

Tull scale Tull scale

c. Inoperative NA NA

d. Downscale > 5/125 divisions of > 3/125 divisions of Tull scale Tull scale

5. SCRAM DISCHARGE VOLUME

a. Water Level-High < 109'1" (North Volume) < 109'3" (North Volume) 3108'11.5"(SouthVolume) 3109'1.5"(SouthVolume)

6. REACTOR COOLANT SYSTEM RECIRCULATION FLOW m p a. Upscale < 108% of rated flow < 111% of rated flow 33 b.

c. Inoperative Comparator NA

                                                                            < 10% flow deviation NA
                                                                                                              < in, tIow dpviation
                                                                                                                                                          'O m7
       ~

7. REACTOR MODE SWITCH SHUIDOWN POSITION NA NA W]

m, "The Average Power Range Monitor rod block function is varied as a function of recirculation loop flow d

                                                                                                                                                             'j (W). The trip setting of this function must be maintained in accordance w th Specification 3.2.2.                                       iW4
                  **May be reduced to 0.7 cps provided the signal-to-noise ratio is > 2.                                                                     253 ca

(:3

                                                                                                                                                           , *y3
                                                                                                                                                             =~~

TABLE 4.3.6-1 g CONTROL R00 BLOCK INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL OPERATIONAL 9 CHANNEL FUNCT10NAL CHANNEL CONDITIONS FOR WHICH y TRIP FUNCTION CHECK TEST CALIBRATION (a) SURVEILLANCE REQUIRED

1. R00 BLOCK MONITOR

a. Upscale NA S/U(b)(c) (c), 33 7,

b. Inoperative NA S/U NA 1*

c. Downscale NA S/U SA 1*

2. APRM

a. Flow Biased Neutron Flux -

Upscale NA S/UIU) M, SA 1

b. Inoperative NA S/U ,M NA 1,2,5

c. Downscale NA S/U M b^ 1

d. Neutron Flux - Upscale, Startup NA S/U(b)'M, SA 2, 5 g 3. SOURCE RANGE MONITORS

a. Detector not full in NA NA Y b. Upscale NA S/U(ID)

S/U b),W W SA 2, 2, 5 5 8 c. Inoperative NA S/U ,W NA 2, 5

d. Downscale NA -

S/U ,W SA 2, 5

4. INTERMEDIATE RANGE MONITORS

a. Detector not full in NA S/U(b) !LA. 2, 5

b. Upscale NA S/U(b),W,W SA 2, 5

c. Inoperative NA S/U ,W NA 2, 5

d. Downscale NA S/U ,W SA 2, 5

5. SCRAM DISCHARGE VOLUME

a. Water Level-High 6.

NA REACTOR COOLANT SYSTEM RECIRCULATION FLOW Q R 1, 2, 5** Q

                                                                                                                                                 ,        es   .

a. Upscale NA S/U(b) M S/UI ),M SA 1 N

b. Inoperative NA NA

 'j                                          c. Comparator                         NA            S/U( ),M SA 1

1 L.Q F. i g 7. REACTOR MODE SWITCH SHUTDOWN 5 u- POSITION NA R NA 3, 4 S 4

TABLE 4.3.6-1 (Continued) f),((,((3,[dljh[f f 1 CONTROL R0D BLOCK INSTRUMENTATION SURVEILLANCE htyU1HEMENT5 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 s. SEF 3 6 Msg HOPE CREEK 3/4 3-61

INSTRUMENTATION qa- ; r -- on-*/ p fi illdi Ct LSih uW t 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 inoperabic.

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. SEP 3 01985 HOPE CREEK 3/4 3-62

e TABLE 3.3.7.1-1 RADIATION MONITORING INSTRUMENTATION n h

MINIMUM CHANNELS APPLICABLE ALARM / TRIP INSTRUMENTATION OPERABLE CONDITIONS SETPOINT ACTION

1. Control Room 2/ intake 1,2,3,5 and * $ 2x10 s pC/cc** 71 Ventilation Radiation Monitor

2. Area Monitors Fe 1 # 1 5 mR/hr and 72 Storage Vault I i i 20 mR/hr ")

l

2) Spent Fuel 1 ## 1 5 mR/hr and 72 I

f $ Storage Pool 5 20 mR/hr *) , Y b. Control Room Direct 1 At all times 2.5 mR/hrI ") 72 O Radiation Monitor

3. Reactor Auxiliaries Cooling 1 At all times 9 x 10 5 pC/cc(a) 73 Radiation Monitor 6 x 10 5 pC/cc(a)

4. Safety Auxiliaries Cooling 1/ loop At all times 73 Radiation Monitor -3 (D

t.J

                                                                                                                                                                                   ~ r1 fM I

N' e {lf ag an

                                                                                                                                                                                   '7
                                                                                                                                                                                   <3 lGC I

2

;   W.

l

TABLE 3.3.7.1-1 (Continued) E RADIATION MONITORING INSTRUMENTATION A n E TABLE NOTATION N *When irradiated fuel is being handled in the secondary containment.

        ** Activates control room emergency filtration system.
         #With fuel in the new fuel storage vault.
        ##With fuel in the spent fuel storage pool.

3 (a) Alarm only. T i i Nh 1 LJ C:) 3 C.i 9 'I , l E Un .~2 . rvi ( S t. ' , l, M m ha 6 i g3 ,

   $                                                                                      *[! P

k l

r __ TABLE 3.3.7.4-2 (Continued) { Cpp .f , REMOTE SHUTDOWN SYSTEMS CONTROLS' I ' ' ' " " *

CACWS - REDUNDANT CONTROLS 1GJ-AK400 Local Control - Control Area Chiller AK400 1GJ-AK403 Local Control - Safety-Related Panel Room Chiller AK403 i 1GJ-AP400 Local Control - Control Area Chilled Water Circulating Pump AP400 1GJ-AP414 Local Control - Safety-Related Panel Room Chilled

Water Circulating Pump AP414 REACTOR RECIRCULATION SYSTEM -RSP 1BB-HV-F031B(3) Indication - Reactor Recirculation Pump BP201 Discharge Valve SAFETY / RELIEF VALVES - RSP 1AB-PSV-F013F Control - Main Steam Line B Safety / Relief Valve 1AB-PSV-F013H Control - Main Steam Line D Safety / Relief Valve 1AB-PSV-F013M . Control - Main Steam Line D Safety / Relief Valve SAFETY / RELIEF VALVES - REDUNDANT CONTROLS 1AB-PSV-F013A local Control - Main Steam Line A Safety /Pelief Valve 1AB-PSV-F013E Local Control - Main Steam Line C Safety / Relief Valve (1) The Remote Shutdown Panel (RSP) is Panel 10C399.

(2) Valve is signalled to open on RSP Takeover. (3) Valve is signalled to close on RSP Takeover. (4) Pump is signalled to run on RSP Takeover. (5) Operation of valve 1EG-HV-2496B is ganged to operation of valve IEG-HV-25228. (6) Operation of valve 1EG-HV-2496D is ganged to operation of valve 1EG-HV-25220. (7) Operation of valve 1EG-HV-2520B is ganged to operation of RHR Pump BP202. i w g. 4EF S 0 gr HOPE CREEK 3/4 3-81 l

e TABLE 4.3.7.4-1 1 y REMOTE SHUTDOWN MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS E , lE CHANNEL CHANNEL INSTRUMENT CHECK CALIBRATION

1. Reactor Vessel Pressure M R

2. Reactor Vessel Water Level M R

3. Safety / Relief Valve Position (Energization) M NA

4. Suppression Chamber Water Level M R

5. Suppression Chamber Water Temperature M R

6. RHR System Flow M R

7. Safety Auxiliaries Cooling System Flow M R Y

       $       Safety Auxiliaries Cooling System 8.

Temperature M R

9. RCIC System Flow M R -._ _

~,

10. RCIC Turbine Speed M R :a c', y

11. RCIC Turbine Bearing 011 Pressure Low - li;{

Indication M R p.,

12. RCICpighPressureTurbineBearing I ;??

TempgratureHighIndication M R *j e -

13. RCIC Low Pressure Turbine Bearing ,

ki Temperature High Indication M R 6 e.

                                                                                                                *h is C                                                                                                         ,,Q g                                                                                                        ~~

E u,

l TABLE 4.3.7.4-1 (Continued) REMOTE SHUTOOWN MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS E , E

CHANNEL CHANNEL

, INSTRUMENT CHECK CALIBRATION l

14. Condensate Storage Tank Level Low-Low Indication M R

15. Standby Diesel Generator IAG400 Breaker Indication M NA

16. Standby Diesel Generator IBG400 s Breaker Indication M NA

17. Standby Diesel Generator ICG400 Breaker Indication M NA R

18. Standby Diesel Generator IDG400

,                  T           Breaker Indication                               M              NA O
!                        19. Switchgear Room Cooler 1AVH401 1                              Status Indication                                M              NA 20    Switchgear Room Cooler IBVH401 Status Indication                                M              NA

21. Switchgear Room Cooler ICVH401 '

Status Indication y [ M NA 7J l j Ca 3 22. Switchgear Room Cooler IDVH401 k-j

!                              Status Indication                               M               NA                                     p,     ,

j 1 ' -

                      $,                                                                                                            i CO O                                                   .
                     .n                                                                                                            m u-        y i

l-INSTRUMENTATION t. Ci , ,

                                                                                          )
                                                                                             '[ l ACCIDENT MONITORING INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.7.5 The accident monitoring instrumentation channels shown in Table 3.3.7.5-1 shall be OPERABLE.

APPLICABILITY: As shown in Table 3.3.7.5-1. ACTION: With 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 operations at the frequencies shown in Table 4.3.7.5-1. > 1 0 ) HOPE CREEK 3/4 3-84 l

II TABLE 3.3.7.5-1 ACCIDENT MONITORING INSTRUMENTATION Q MINIMUM APPLICABLE A* REQUIRED NUMBER CHANNELS OPERATIONAL INSTRUMENT OF CHANNELS OPERABLE CONDITIONS ACTION

1. Reactor Vessel Pressure 2 1 1,2,3 80

2. Reactor Vessel Water Level 2 1 1,2,3 80

3. Suppression Chamber Water Level 2 1 1,2,3 80

4. Suppression Chamber Water Temperature

2 2 1,2,3 80(a)

5. Suppression Chamber Pressure 2 1 1,2,3 80

6. Drywell Pressure 2 1 1,2,3 80

7. Drywell Air Temperature 2 1 1,2,3 80 w 8. Primary Containment Hydrogen /0xygen Concentration 1 Analyzer and Monitor 2 1 1,2,3 80 w 9. Safety / Relief Valve Position Indicators 2/ valve ** 1/ valve ** 1,2,3 80 i E 10. Drywell Atmosphere Post-Accident Radiation Monitor 2 1 1,2,3 81

11. North Plant Vent Radiation Monitor # 1 1 1,2,3,4,5 81

12. South Plant Vent Radiation Monitor # 1 1 1,2,3,4,5 81

13. FRVS Vent Radiation Monitor # 1 1 1,2,3,4,5 81

                                                                            #High range noble gas monitors.                                                                                               y       I

Average bulk pool temperature. --

                                                                                                                                                                                                          -u
                                                                          ** Acoustic monitoring and tail pipe temperature.                                                                               C7 i

(a) Suppression chamber water temperature instrumentation must satisfy the availability requirements specified k,I inSpecjfication3.6.2.1. , p.c l.,*d n m rs7 l $ -- ca e2 l o L3

                                                            $~                                                                                                                                         =

l

F Table 3.3.7.5-1 (Continued) f k NTd/

                                                                              -u f DV m~            --

I ACCIDENT MONITORING INSTRUMENTATION - ACTION STATEMENTS 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 7 days or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

b. With the number of OPERABLE accident monitoring instrumenta' tion 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 and in COLD SHUTDOWN within the following 24 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. Prepare and submit a Special Report to the Commission pursuant to Specification 6.9.2 within 14 days following the event outlining the action t:2en, the cause of the inoperability and the plans and schedule for restoring the system to OPERABLE status.

The provisions of Specification 3.0.4 are not applicable. I SEP 3 0 Iger HOPE CREEK 3/4 3-86

TABLE 4.3.7.5-1 I k"' ACCIDENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS APPLICABLE Q CHANNEL CHANNEL OPERATIONAL m INSTRUMENT CHECK CALIBRATION CONDITIONS n

1. Reactor Vessel Pressure M R 1,2,3

2. Reactor Vessel Water Level M R 1,2,3

3. Suppression Chamber Water Level M R 1,2,3 -

4. Suppression Chamber Water Temperature M R 1,2,3

5. Suppression Chamber Pressure M R 1,2,3

6. Drywell Pressure M R 1,2,3

7. Drywell Air Temperature M R 1,2,3

8. Primary Contairment Hydrogen /0xygen Concentration ..

Analyzer and Monitor M Q* 1,2,3

         $    9. Safety / Relief Valve Position Indicators                    M                         R             1,2,3 Y    10. Drywell Atmosphere Post-Accident Radiation Monitor           M                         R**           1,2,3 0    11. North Plant Vent Radiation Monitor #                         M                         R             1,2,3,4,5

12. South Plant Vent Radiation Monitor # M R 1,2,3,4,5

13. FRVS Vent Radiation Monitor # M R 1,2,3,4,5 "Using sample gas containing:

a. Five volume percent oxygen balance nitrogen (oxygen analyzer channel). _

b. Five volume percent hydrogen, balance nitrogen (hydrogen analyzer channel). '

              ** CHANNEL 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 3]

C.3 installed or portable gamma source. y

              #High rang 6 noble gas monitors.                                                                                                                                        j.

I

           =m 1 f.P i 7; l

M 1* e . ' U . k- cm a

                                                                                                                                                                             "*'y

1 INSTRUMENTATION rtmp g N*f f ? pn 7" i udJr u um a.a out i SOURCE RANGE MONITORS i -- LIMITING CONDITION FOR OPERATION

3.3.7.6 At least the following source range monitor channels shall be OPERABLE:

a. In OPERATIONAL CONDITION 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.

c. Verifying, prior to withdrawal of control rods, that th6* 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 3-88

1 INSTRUMENTATION s ., .. I ;

              ,                                               11      b .f.I ,.. Jl h );' s TRAVERSING IN-CORE PROBE SYSTEM LIMITING CONDITION FOR OPERATION 3.3.7.7. The traversing in-core probe system shall be OPERABLE with:

a. Five movable detectors, drives and readout equipment to map the core, and

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 MFLPD.

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 LPRM calibration function.

 "Only the detector (s) in the required measurement location (s) are gequired to be OPERABLE.

HOPE CREEK 3/4 3-89 SEPS0 g$ l

INSTRUMENTATION p p,g .. ,3 . , . . . . y htsi u a ( ..a -- UU. / 1 FIRE DETECTION INSTRUMENTATION 1 LIMITING CONDITION FOR OPERATION 3.3.7.8 As a minimum, the fire detection instrumentation for each fire detection zone shown in Table 3.3.7.8-1 shall be OPERABLE. APPLICABILITY: 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 3.3.7.8-1 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.

2. One less than the Total Number of Instruments shown in Table 3.3.7.8-1 for Function B, or one-half or less of the Total Number of Instruments shown in Table 3.3.7.8-1 for Function A, or with any two or 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.

b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS 4.3.7.8.1 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, except for restorable spot. type heat detectors, which will be tested such that at least one detector on each signal-initiating circuit will be tested at least once per 6 months, such that all detectors are tested in 5 years. Fire detectors which are not accessible during unit operation shall be demonstrated OPERABLE by the perfor-mance of a CHANNEL FUNCTIONAL TEST during each COLD SHUTDOWN exceeding 24 hours unless performed in the previous 6 months. 4.3.7.8.2 The NFPA Standard 720 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. HOPE CREEK 3/4 3-90

TABLE 3.3.7.8-1 o A FIRE DETECTION INSTRUMENTATION n i A DETECTION PHOTO- IONIZA- , W ZONE - ELEV. ROOM OR AREA (FIRE ZONE / ROOM NO.) HEAT FLAME ELECTRIC TION (x/y) (x/y) (x/y) (x/y)

a. Reactor Building 4101 54' RHR Pump Room (4114) N/A N/A N/A 6/0 4102 54' RHR Pump /Ht. Exch. Room (4113) N/A N/A N/A 4/0
4103 54' RHR Pump Room (4107) N/A N/A N/A 6/0 4104 54' RHR Pump /Ht. Exch. Room (4109) N/A N/A N/A 4/0
4105 54' Core Spray Pump Room (4116) N/A 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 i 4108 54' Core Spray Pump Room (4104) N/A N/A N/A 5/0 4109 54' HPCI Pump & Turbine Room (4111) N/A N/A N/A 6/0

w 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 w 4112 54' Electric Equipment Room (4108) N/A N/A N/A 6/0 4

4102 77' RHR Heat Exchanger Room (4214) N/A N/A N/A 3/0 ! 4104 77' RHR Heat Exchanger Room (4208) N/A N/A N/A 3/0 i 4201 77' RACS Pump / Heat Exch. Area (4211, 4209). N/A N/A N/A 18/0 4201 77' Safeguard Instrument Room (4210) N/A N/A N/A 1/0 4201 77' Safeguard Instrument Room (4219) N/A N/A N/A 1/0 l 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)                                0/8     N/A         N/A                          7/0 4206         77'        CRD Pumps Room 2 Corridor (4202 & 4203)        N/A     N/A         N/A                          9/0                 i 4301         102'       SACS Heat Exch./ Pump Room (43'09)             N/A     N/A         N/A                          19/0       .7 j               4302      > 102'        MCC Area & Corridor (4310, 4301)               0/15    N/A         N/A                          12/0      ii]~3   i l              4303         102'       SACS Heat Exch./ Pump Room (4307)              N/A     N/A         N/A                  ,       18/0
;              4306      ' 102'        CRD Hydr. Control Area (4328)                  N/A     N/A         N/A                          5/0 f ."!I 4306         102'       Perq. & Equip. Access Area & Corridor          N/A     N/A         N/A                          5/0

c2 (4331, 4315) ;. C 8 j Q- 4306 102' CRD Removal & Repair Area (4326) N/A N/A N/A 2/0 I.

e, 4307 102' CRD Hydr. and Masi r Control Areas and F,: a Equip. Access Area (4317, 4320, 4322) N/A N/A N/A 11/0 L.J

k c'. -

CU

%)

me- ( 3

TABLE 3.3.7.8-1 (Continued) FIRE DETECTION INSTRUMENTATION 2, DETECTION PHOTO- 10NIZA-ZONE ELEV. ROOM OR AREA (FIRE ZONE / ROOM NO.) HEAT FLAME ELECTRIC TION RI

   *                                                                                 (x/y) (x/y)  (x/y)      (x/y)

a. Reactor Building (Cont'd) 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 4602 162' Equip Area 2 Corridor (4605, 4608) N/A N/A N/A 12/0

< 4602 162' Post-LOCA Recomb. Area (4604, 4602) N/A N/A N/A 4/0 R' 4602 162' MCC Area (4601, 4618) N/A N/A N/A 4/0-

4602 162' Standby Liquid Control Area (4606) N/A N/A N/A 2/0 Y 4701 178'-6" FRVS Recirc. Unit Room (4616) N/A N/A N/A 8/0 2 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' Neutron 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 8/0 (4625,4626,4627,4628) 4604 162' Standby Liquid Control Area (4606) N/A N/A N/A 5/0 4113 54/77 Torus Area Safe Shutdown Cable Trays 12/0 N/A N/A N/A

b. Auxiliary Building Control & D/G Areas -

5103 54' 250V DC Battery Rooms (5164) N/A N/A 1/0 1/0 $ 5103 5104 54' 1 54' 250V DC Battery Rooms (5128) RPS MG Set Area (5105) ~ N/A N/A N/A N/A 1/0 1/0 8 1/0 1/0 f's , w 5105 54' DSL Full Stor. Tanks Room (5107) 0/7 2/0 2/0 N/A r , 54' DSL Full Stor. Tanks Room (5108) 0/7 2/0 2/0 N/A ;y:, ' Q 5106 5107 54' DSL Full Stor. Tanks Room (5109) 0/7 2/0 2/0 N/A i F,j j

                                                                                                                        ,   a u,

e. 5108 54' DSL Full Stor. Tanks Room (5110) 0/7 2/0 2/0 N/A (* i f b.if.

u. .

I.._ i

-_               ._-_         - - -    - - - _ .           -        .   -   -  -      _ _ _ -   -.    - . _-                              ~                                          -.

l TABLE 3.3.7.8-1 (Continued) FIRE DETECTION INSTRUMENTATION Q DETECTION PHOTO- IONIZA-p ZONE ELEV. ROOM OR AREA (FIRE ZONE / ROOM NO.) HEAT FLAME ELECTRIC 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 N/A 5/0 6/0 l 5201 77' Cable Spreading Room (5202) N/A N/A 0/14 0/13 { 5202 77' H&V Equip. Room (5208) N/A N/A 2/0 3/0 l 5203 77' H&V Equip. Room (5209) N/A N/A 2/0 3/0 77' H&V Equip. Room (5210) 5204 N/A N/A 2/0 3/0 5205 77' H&V Equip. Room (5211) N/A N/A 2/0 3/0 3 5206 77' Corridor (5207) 0/7 N/A 1/0 2/0 i 5206 77' Corridor (5237) 0/12 N/A 4/0 4/0 5301 102' Control Equip. Room (5302) N/A N/A 12/0 12/0 l 5314 102' DSL Generator Room (5304) 0/7 2/0 1/0 N/A ' R 5315 102' DSL Generator Room (5305) 0/7 2/0 1/0 N/A

5316 102' 0/7 DSL Generator Room (5306) -

2/0 1/0 N/A

'y 5317 102' DSL Generator Room (5307) 0/7 2/0 1/0 N/A 3 5318 102' Elec Access Area (5301) N/A N/A 5/0 6/0 i

5318 102' Electrical Access Area (5339) 0/26 N/A 1/0 1/0 5401 117'6" Control Equip. Room Mezz. (5403) 0/14 N/A 11/0 11/0 1 5402 124' Class 1E Inverter Room (5447) N/A N/A N/A 1/0 j 5402 124' Class IE Inverter Room (5448) N/A N/A 1/0 2/0 t ] 5407 5403 124' 130' Corridor (5401) D/G Control Room (5410) 0/9 N/A N/A N/A 3/0 N/A 3/0 1/0

],

g

5403 130' Class IE Swgr. Room (5411) N/A N/A 1/0 2/0 r,3: 5404 130' D/G Control Room (5412) N/A N/A N/A 1/0 s"M <

. 5404 130' Class IE Swgr. Room (5413) N/A N/A 1/0 2/0

fm i

5405 130' D/G Control Room (5414) N/A N/A N/A 1/0 ' g 5405 ' 130' Class IE Swgr. Room (5415) N/A N/A 1/0 2/0 lD7 l 5406 N' 130' D/G Control Room (5416) N/A N/A N/A ' 1/0 . 5406 130' Class IE Swgr. Room (5417) N/A 1/0 i 5502 137' Control Room and Ready Room N/A. 2/0 .' h' i , j (5509, 5510, 5511) N/A

   '.* 5504               137'      Control Room Console N/A       N/A                            15/0 8/0 c.

c 5505 5506 137' 137' Control Room Vert. Board (Right) N/A N/A N/A N/A N/A N/A 4/0 lM I _. y 3s Control Room Vert. Board (Niddle) N/A N/A N/A 3/0 i

l l l TABLE 3.3.7.8-1 (Continued) FIRE DETECTION INSTRUMENTATION O DETECTION PHOTO- IONIZA-lE ZONE ELEV. ROOM OR AREA (FIRE ZONE / ROOM NO.) HEAT FLAME ELECTRIC TION (x/y) (x/y) (x/y) (x/y)

b. Auxiliary Buiiding Control & D/G Areas (Cont'd) 5507 137' Control Room Vert. Board (Left) N/A N/A N/A 4/0 5515 137' Elec. Access Area (5501) N/A N/A 2/0 3/0 5516 146' Battery Charger Room (5538) 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 N/A 1/0 1/0 5517 146' Battery Room (5541) N/A N/A N/A 1/0 5518 146' Battery Charger Room (5542) N/A N/A 1/0 1/0 5518 146' Battery Room (5543) N/A N/A N/A 1/0 5519 146' Battery Charger Room (5544) N/A N/A 1/0 1/0 5519 146' Battery Room (5545) N/A N/A N/A 1/0 R

5521 77', Elec. Cable Chase, Channel D (5203, 0/15 N/A 3/0 3/0 102', 5323,5331,5405,5419,5531) Y 124', 2 120', 137', 150' 5522 77', Elec. Cable Chase, Channel B 0/15 N/A 3/0 3/0 102', (5204, 5324, 5332, 5406, 5420, 5532) 124', y 120 , w 137', 9, 150' :.p, , 5523 77', Elec. Cable Chase, Channel C 0/15 N/A 3/0 3/0 i 3., 102', (5205, 5325, 5333, 5407, 5421, 5533) l

124',

1 120', ' I 137', 150' t -

5524 77', Elec. Cable Chase, Channel A 0/15 N/A 3/0 3/0 "o en 102', (5206, 5326, 5334, 5408, 5422, 5534)
124'

120' k 137', 150' l NA 150' H and V Chase (5535) 0/8 N/A N/A N/A

TABLE 3.3.7.8-1 (Continued) 5

                       ;M                                               FIRE DETECTION INSTRUMENTATION k     DETECTION                                                                               PHOTO-       IONIZA-p        ZONE       ELEV. ROOM OR AREA (FIRE ZONE / ROOM NO.)             HEAT      FLAME ELECTRIC       TION (x/y)    (x/y)  (x/y)         (x/y)

b. Auxiliary Building Control & D/G Areas (Cont'd) 5601 155'3" Control Area HVAC Equip. Room'(5602) N/A N/A 7/0 8/0 5602 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 9/0 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 N/A 1/0 N/A 5612 163'6" Inverter Room (5616) N/A N/A 1/0 N/A 5613 163'6" Inverter Room & Battery Room (5613, 5614) N/A N/A 2/0 N/A 5614 163'6" Inverter Room & Battery Room (5607, 5604) N/A N/A 2/0 N/A m 5615 163'6" HVAC Equip. Room (5620) N/A N/A 3/0 6/0

                    }       5701           178'    HVAC Equip. Room & DSL Area                      N/A       N/A   10/0          11/0 m                             HVAC Equip. Room (5703, 5704) a,     5409           130'    D/G Air Intake (5223, 5450)                      N/A       N/A   17/0          N/A u

c. Intake Structure 7115 93', Intake Struct. Unit 1 A & C Serv. Wtr. 0/2 N/A 7/0 2/0 122' Pumps (203, 204, 305, 306) 7116 93', Intake Struct. Unit 1 B & D Sere. Wtr. 0/2 N/A 7/0 2/0 122' Pumps (207, 208, 311, 312) ;

7115 114' Intake Struct. Travelling Screen Motor Area N/A N/A 3/0 2/0 yi C3 '

d. Charcoal Filter Units c>!

m1 ReactorBujlaing , f :C ', j

.s 1 132' FRVS Recirc. Charcoal Filter Compartment. ' , 1/0 N/A N/A N/A J ki 1 eg 132' FRVS Recirc. Charcoal Filter Compartment 1/0 N/A N/A N/A i p.d 145' FRVS Vent Unit Charcoal Filter Compartment .1/0 N/A N/A N/A Q o -

145' FRVS Vent Unit Charcoal Filter Compartment- 1/0 N/A N/A N/A

                     ~     -

162' FRVS Recirc. Charcoal Filter Compar'tment I/O N/A N/A N/A l [,'j 162' FRVS Recirc. Charcoal Filter Compartment 1/0 N/A N/A N/A i %! 178'6" FRVS Recirc. Charcoal Filter Compartment 1/0 N/A N/A H/A i % l 178'6" FRVS Recirc. Charcoal Filter Compartment 1/0 N/A N/A N/A +---

TABLE 3.3.7.8-1 (Continued) FIRE DETECTION INSTRUMENTATION 2 DETECTION PHOTO- IONIZA-A ZONE ELEV. ROOM OR AREA (FIRE ZCNE/ ROOM NO.) HEAT FLAME ELECTRIC TION Tx79) (x/y) (x/y) (x/y)

e. Auxiliary Building Control Area 153' Control Room Emerg. Char. Filter Units 1/0 N/A N/A N/A 153' Control Room Emerg. Char. Filter Units 1/0 N/A N/A N/A

f. Auxiliary Building Radwaste & Service Areas 3203 77' Electrical Access Area (3204) 0/19 N/A 4/0 4/0 3307 102' Electrical Access Area (3314) N/A N/A 1/0 2/0 3410 124' Electrical Access Area (3425) 0/5 N/A 2/0 2/0 3312 102' Hot Water Heater, Corridor & Janitor's N/A N/A 13/0 9/0 Room (3342, 3302, 3304)

R 3313 102' Men's Toilet Rm (3303) N/A N/A 3/0 2/0

3503 137' N/A N/A N/A 2/0 Remote Shutdown Panel Room (3576)

Y

                               (x/y):                               x is number of Function A (early warning fire detection and notification only) instruments.

y is number of Function B (actuation of fire suppression systems and early warning notification) instruments. TT

                                                                                                                                                                           -- 1
                                                                                                                                                                           % .)
                                                                                                                                                                             "2 R Pt2 y                                                                                                                                            r .=

co - . 5f C> D: u A

1 INSTRUMENTATION (( 7..,,,.,1 LOOSE-PART DETECTION SYSTEM LIMITING CONDITION FOR OPERATION 3.3.7.9 The loose part detection system shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. ACTION:

a. With one or more loose part detection system channels inoperable for more than 30 days, 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.

l

b. The provisions of Specification 3.0.3 and 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS 4.3.7.9 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 HOPE CREEK 3/4 3-97

_ . _ ~ INSTRUMENTATION g(( 'gt[.' t..*l prA# l 1 RADI0 ACTIVE LIQUID EFFLUENT MONITORING INSTRUMENTATION l LIMITING CONDITION FOR OPERATION 3.3.7.10 The radioactive liquid effluent monitoring instrumentation channels shown in Table 3.3.7.10-1 shall be OPERABLE with their Alarm / Trip Setpoints set to ensure that the limits of Specification 3.11.1.1 are not exceeded. 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 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 3.3.7.10-1. 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.

SURVEILLANCE REQUIREMENTS 4.3.7.10 Each radioactive liquid effluent monitoring instrumentation channel shall be demonstrated OPERABLE by performance of the CHANNEL CHECK, SOURCE CHECK, CHANNEL CALIBRATION, and CHANNEL FUNCTIONAL TEST at the frequencies I shown in Table 4.3.7.10-1. j i 00 ? ? %: HOPE CREEK 3/4 3-98

TABLE 3.3.7.10-1 5 A RADI0 ACTIVE LIQUID EFFLUENT M0'.ITORING INSTRUMENTATION O h MINIMUM CHANNELS INSTRUMENT OPERABLE ACTION

1. RADI0 ACTIVITY MONITORS PROVIDING ALARM AND AUTOMATIC TERMINATION OF RELEASE

a. Liquid Radwaste Discharge Line to the Cooling Tower Blowdown Line 1 110

2. RADI0 ACTIVITY MONITORS PROVIDING ALARM BUT NOT PROVIDING AUTOMATIC TERMINATION OF RELEASE m a. Cooling Tower Blowdown Effluent 1 111 A

w 3. FLOW RATE MEASUREMENT DEVICES

a. Liquid Radwaste Discharge Line to Cooling 1 112 Tower Blowdown Line

b. Cooling Tower Blowdown Weir 1 112

                                                                                                                         ?J
                                                      .                                                                  C.3

t. 3 6

T e Qo hbi m n r.i e

       ^
                                                                                                                        ..d C3 k                                                                                                                  l

                                                                                                                             ,            _ = -       --

i TABLE 3.3.7.10-1 (Continued) l- ' 1 --.-- TABLE NOTATION ACTION 110 - With the number of channels OPERABLE less than required by the Minimum Channels OPERABLE requirement, effluent releases via this pathway may continue for up to 30 days provided that prior to initiating a release: i 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 J and discharge line valving; l Otherwise, suspend release of radioactive effluents via this

    .,                                        pathway.

ACTION 111 - With the number of channels OPERABLE less than required by the Minimum Channels OPERA 8LE requirement, effluent releases via this pathway may continue for up to 30 days provided that, at least once per 12 hours, grab samples are collected and analyzed for

j gross radioactivity at a limit of detection of at least 10 7 microcuries/al. Otherwise, suspend release of radioactive effluents via this pathway.

ACTION 112 - With the number of channels OPERABLE less than required by the Minimum Channels OPERA 8LE requirement, effluent releases via i this pathway may continue for up to 30 days provided the flow

rate is estimated at least once per 4 hours during actual releases.

4 Pump performance curves generated in place may be used to estimate flow. J t

31 HOPE CREEK 3/4 3-100

TABLE 4.3.7.10-1

           !@                                            RADI0 ACTIVE LIQUID EFFLUENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS "m

CHANNEL A

CHANNEL SOURCE CHANNEL FUNCTIONAL INSTRUMENT CHECK CHECK CALIBRATION TEST

1. RADI0 ACTIVITY MONITORS PROVIDING ALARM AND AUTOMATIC TERMINATION OF RELEASE

a. Liquid Radwaste Discharge Line to the Cooling Tower Blowdown Line D P R(3) Q(1)

2. RADI0 ACTIVITY MONITORS PROVIDING ALARM BUT NOT PROVIDING AUTOMATIC TERMINATION OF RELEASE g a. Cooling Tower Blowdown Effluent D M R(3) Q(2)

Y 3. FLOW RATE MEASUREMENT DEVICES o

              ~                               a. Liquid Radwaste Discharge Line                    D(4)       N.A.           R                Q to Cooling Tower Blowdown Line

b. Cooling Tower Blowdown Weir D(4) N.A. R Q t i 6: 3 hh

                                                    *                                                                                         .           m

D F4 h

n c,~ c.)

o R3

                                                                                                                                                         ==
                                   ~

l' ~ - n -_, L fk.[.Y.* 0dab' d (suf f f TABLE 4.3.7.10-1 (Continued) J TABLE NOTATIONS (1) The CHANNEL FUNCTIONAL TEST shall also demonstrate that automatic i of this pathway following and control conditions 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.

(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 i

c. Instrument indicates a downscale failure. (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 range. the system over its intended range of energy and measurement For subsequent CHANNEL CALIBRATION, sources that have been related to the initial calibration or are NBS traceable shall be used. (4) CHANNEL of release.CHECK shall consist of verifying indication of flow during periods CHANNEL CHECK shall be made at least once per 24 hours on days on which continuous, periodic, or batch releases are made. HOPE CREEK 3/4 3-102 l __ - - - -

t-.. , QP ("? f 0 ~ -.y..

3 INSTRUMENTATION L

                                                                                        ' b[f / k$vf'J RADIOACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.7.11 The radioactive gaseous effluent monitoring instrumentation channels shown in Table 3.3.7.11-1 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 not exceeded. The Alarm / Trip Setpoints of these channels meeting Specification 3.11.2.1 shall be determined and adjusted in accordance with the methodology and parameters in the 00CH.

APPLICABILITY: As shown in Table 3.3.7.11-1. ACTION:

a. With a radioactive gaseous effluent monitoring instrumentation channel Alarm / Trip 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 3.3.7.11-1. 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.

l SURVEILLANCE REQUIREMENTS 4.3.7.11 Each radioactive gaseous effluent monitoring 'qstrumentation channel shall be demonstrated OPERABLE by performance of the CHA'NEL CHECK, SOURCE CHECK, CHANNEL CALIBRATION and CHANNEL FUNCTIONAL TEST at the frequencies shown in Table 4.3.7.11-1. i l N 3 L ,%. HOPE CREEK 3/4 3-103

TABLE 3.3.7.11-1 RADI0 ACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION 9 lQ MINIMUM CHANNELS

INSTRUMENT OPERABLE APPLICABILITY ACTION

1. MAIN CONDENSER OFFGAS TREATMENT SYSTEM EXPLOSIVE GAS MONITORING SYSTEM

a. Hydrogen Monitor 1 **

124

2. FILTRATION, RECIRCULATION AND VENTILATION MONITORING SYSTEM

a. Noble Gas Activity Monitor 1

123

b. Iodine Sampler 1

125 R
c. Particulate Sampler 1
125 Y

g d. Flow Rate Monitor 1

122

e. Sampler Flow Rate Monitor 1

122

3. SOUTH PLANT VENT MONITORING SYSTEM .T

a. Noble Gas Activity Monitor 1

123 Ff c..)

v1

b. Iodine Monitor 1

125 C*u We

c. Yarticulate Monitor 1

125 DI N'

Flow Rate Monitor

e

                                                                                                                       ;;q    .

d. 1 122 q.

e. Sampler Flow Rate Monitor 1

122 E!

m

~<

m " vs

e TABLE 3.3.7.11-1 (Continued) x y RADI0 ACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION O N

MINIMUM CHANNELS INSTRUMENT OPERABLE APPLICABILITY ACTION

4. NORTH PLANT VENT MONITORING SYSTEM

a. Noble Gas Activity Monitor 1

123

b. Iodine Monitor 1

125

c. Particulate Monitor 1

125

d. Flow Rate Monitor 1

122

e. Sampler Flow Rate Monitor 1

122

M. E w

                                                                                                                                         .va IC $

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F . _ _ _ - t f { {'?0'] [~yf TABLE 3.3.7.11-1 (Continued) L _d' a

                                                                                                -----...i 3

TABLE NOTATION At all times.

        ** During operation of the main condenser air ejector.

ACTION 122 - With the number of channels OPERABLE less than required by the Minimum Channels OPERABLE requirement, effluent releases via this pathway may continue for up to 30 days provided the flow rate is estimated at least once per 4 hours. Otherwise, suspend release of radioactive effluents via this pathway. ACTION 123 - With the number of channels OPERABLE less than required by the Minimum Channels OPERABLE requirement, effluent releases via this pathway may continue for up to 30 days provided grab samples are taken at least once per 12 hours and these samples are analyzed for gross activity within 24 hours. Otherwise, suspend release of radioactive effluents via this pathway. ACTION 124 - With the number of channels OPERABLE less than required by the Minimum Channels OPERABLE requirement, operation of main condenser offgas treatment system may continue for up to 30 days provided grab samples are collected at least once per 4 hours and analyzed within the following 4 hours. Otherwise, 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, effluent releases via this pathway may continue provided that within 8 hours samples are continuously collected with auxiliary sampling equipment as required in Table 4.11-2. i s

                                                                            *h I

i

                                                                                 $[l: O Iib!'

HOPE CREEK 3/4 3-106

t TABLE 4.3.7.11-1 RADI0 ACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS

E

CHANNEL MODES IN WHICH CHANNEL SOURCE CHANNEL FUNCTIONAL SURVEILLANCE INSTRUMENT CHECK CHECK CALIBRATION TEST REQUIRED

1. MAIN CONDENSER OFFGAS TREATMENT SYSTEM EXPLOSIVE GAS MONITORING SYSTEM

a. Hydrogen Monitor D N.A. Q(3) M **

1

2. FILTRATION, RECIRCULATION AND VENTILATION MONITORING SYSTEM

a. Noble Gas Activity Monitor D M R(2) Q(1) *

b. Iodine Sampler W N.A. N.A. N.A. *

{ T c. Particulate Sampler W N.A. N.A. N.A.

E$

d. Flow Rate Monitor 0 N.A. R Q

e. Sampler Flow Rate Monitor D N.A. R- Q

3. SOUTH PLANT VENT MONITORING SYSTEM ,

I T

a. Noble Gas Activity Monitor D M R(2) Q(1)

gr

o. ;

b. Io, dine Monitor 0 N.A. R(2) Q(1)

m;

                                                     .                                                                                                                     f>

c.PIrticulateMonitor '* D N.A. R(2) Q(1) I j.y , d. Flow Rate Monitor D N.A. R Q

j .' ]

w I .D ' E' e. Sampler Flow Rate Monitor D N.A. R Q

I N c.- C.3 c 9

;y

4

,                                                         TABLE 4.3.7.11-1 (Continued) g i

m RADI0 ACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS E E CHANNEL MODES IN WHICH CHANNEL SOURCE CHANNEL FUNCTIONAL SURVEILLANCE INSTRUMENT CHECK CHECK CALIBRATION TEST REQUIRED

4. NORTH PLANT VENT MONITORING SYSTEM

a. Noble Gas Actvity Monitor D M R(2) Q(1) *

b. Iodine Monitor D M R(2) Q(1) *

c. Particulate Monitor D M R(2) Q(1) l

d. Flow Rate Monitor D N.A. R Q R e. Sampler Flow Rate Monitor D N.A. R Q E.

4 D 7 CD f i

                                                                                                                                 !    Tl f Co  zu c>                                                                                                                ?;*%

( E e.- n 4 e l'j u"r !* I i $ -J l h

                                  -         -           _ .                  --                                                                =

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                                                                                                       , , ,, , , , 7                                       .

J$,U s, "" ~ TABLE 4.3.7.11-1 (Continued) -

                                                                                                                                           ,.:   s,.      >

TABLE NOTATION "~.--.- l

At all times. ,

        **    During operation of the main condenser air ejector.

(1) 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.

(2) 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 or are NBS traceable shall be used. (3) The CHANNEL CALIBRATION shall include the use of standard gas samples containing a nominal:

1. Zero volume percent hydrogen, balance nitrogen, and

2. 1.5 volume percent hydrogen, balance nitrogen.

1 r.

                                                                                                                                 $LF b 41985, HOPE CREEK                                          3/4 3-109
                               .-__ _ _ ,__                 _    , _ - . _ _    _            . _ . - - , - - _ _ _ __.         . - - - - ~

l 1 F-- INSTRUMENTATION p ., , , , ,

6 ,%p {c ,i . . . 4. .l. ~., . 3/4.3.8 TURBINE OVERSPEED PROTECTION SYSTEM ^% %i i 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, or one main stop valve per high pressure turbine steam lead inoperable and/or with one combined intermediate valve per low pressure turbine steam lead inoperable, restore the inoperable valve (s) to OPERA 8LE 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.

c. The provisions of Specification 3.0.4 are not applicable.

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) Six low pressure combined intermediate valves b) For the electrical overspeed trip system and the mechanical !

overspeed trip system; j 1) Four high pressure main stop valves, and

4) Six low pressure combined intermediate valves.

e LL- - !d HOPE CREEK 3/4 3-110

l INSTRUMENTATION i ... ,

                                                                                                      /[ l
                                                                                            -._,...t SURVEILLANCE REQUIREMENTS (Continued)

b. At least once per 31 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 b) For the electrical overspeed trip system and the mechanical overspeed trip system;

1) Four high pressure turbine control valves.

           . c. At least once per 18 months by performance of a CHANNEL CALIBRATION of the turbine overspeed protection instrumentation.

J

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.

i -i l HOPE CREEK 3/4 3-111

7"9 !" r m . .

                                                                                                                                                  . ,   f
                                                                                                                   ~                               '

i INSTRUMENTATION i f i r 3/4.3.9 FEEDWATER/ MAIN TURBINE TRIP SYSTEM ACTUATION INSTRUMENTATION ! LIMITING CONDITION FOR OPERATION - i 3.3.9 The feedwater/ main turbine trip system actuation instrumentation channels shown in Table 3.3.9-1 shall be OPERA 8LE with their trip setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.3.9-2. APPLICABILITY: As shown in Table 3.3.9-1.

ACTION

i

a. With a feedwater/ main turbine trip system actuation instrumentation

          ..                             channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.3.9-2, declare the channel inoperable and either place the inoperable channel in the tripped condition until
!                                        the channel is restored to OPERABLE status with its trip setpoint adjusted consistent with the Trip Setpoint value, or declare the associated system inoperable.

I b. With the number of OPERA 8LE channels one less than required by the l Minimum OPERABLE Channels requirement, restore the inoperable channel

+
                    ,                   to OPERABLE status within 7 days or be in at least STARTUP within the next 6 hours.

c. With the number of OPERABLE channels two less than required by the Minimum OPERABLE Channels requirement, restore at least one of the
_. inoperable channels to OPERABLE status within 72 hours or be in

, at least STARTUP within the next 6 hours. l SURVEILLANCE REQUIREMENTS 4.3.9.1 Each feedwater/ main turbine trip system actuation instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL j FUNCTIONAL TEST and CHANNEL CALIBRATION operations for the OPERATIONAL CONDITIONS and at the frequencies shown in Table 4.3.9.1-1. 4.3.9.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic operation of all channels shall be performed at least once per 18 months. l l O HOPE CREEK 3/4 3-112 l

                                                   - ~ . - _ - _ _ ~ _ _ _ _ . - _ - - - -

f. .

TABLE 3.3.9-1 FEEDWATER/ MAIN TURBINE TRIP SYSTEM ACTUATION INSTRUMENTATION n 5 E APPLICABLE MININMUM OPERATIONAL FUNCTIONAL UNIT OPERABLE CHANNELS CONDITIONS

1. Reactor Vessel Water Level-High, Level 8 3 1 i w 1

Y t C M 4 J C.3 0 .3

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g. '

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                                                                                                                                , ' v~% ,h N                                                                                                                                          ._J

i TABLE 3.3.9-2 x FEEDWATER/ MAIN TURBINE TRIP SYSTEM ACTUATION INSTRUMENTATION SETPOINTS Q ALLOWABLE g FUNCTIONAL UNIT TRIP SETPOINT VALUE n I 1. Reactor Vessel Water Level-High, Level 8 5 54.0 inches

1 55.5 inches "See Bases Figure B 3/4 3-1.

R. M+ n 22 C3 C-3 M i , f2o N' ' ET3 .

                                                                                                                                                       ." 1
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                                          ,'3                                                                                                       s >i I

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                                           ?,                                                                                                   !l

TABLE 4.3.9.1-1 5o m FEEDWATER/ MAIN TUR8INE TRIP SYSTEN ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS E R; CHANNEL OPERATIONAL CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH TRIP FUNCTIONAL CHECK CHECK TEST CALIBRATION SURVEILLANCE REQUIRE 0

1. Reactor Vessel Water Level-High, Level 8 S M R 1 M.

H, u L M b

&)

i N 1% l7y N'

_l

                                                                                                                                  ;               : i
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f- - { w e.' h 3/4.4 REACTOR COOLANT SYSTEM .t 3/4.4.1 RECIRCULATION SYSTEM l RECIRCULATION LOOPS I LIMITING CONDITION FOR OPERATION i l 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 Ifmit 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 and total core flow less than 45% of rated core flow and THERMAL POWER greater than the limit specified 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 required limits within 2 hours by increasing.cQre 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. l 1

  *See Special Test Exception 3.10.4.

i ** 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 Str ;i .. q7- \ _ _ -.

PR037gc,r,,.,,,/,/ a w. - l REACTOR COOLANT SYSTEM _-__ SURVEILLANCE REQUIREMENTS 4.4.1.1.1 At least once per 12 hours verify that total core flow is greater than or equal to 45% of rated core flow and/or that THERMAL POWER-is less than the limit specified in Figure 3.4.1.1-1. 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 to 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.

l SD b < w HOPE CREEK 3/4 4-2

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[ CORE Ft.0W, % RATED 8R e THERMAL POWER VERSUS CORE FLOW f *"*3 j 3 FIGURE 3.4.1.1-1 j M

REACTOR COOLANT SYSTEM J ?.Ynt n L JET' PUMPS *' d m. If @.I~"'

                                                                                , [~~- ep,n f p l/ 7
                                                                                             ~,

LIMITING CONDITION FOR OPERATION _ 3.4.1.2 All jet pumps shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. C ACTION: With one or more jet pumps inoperable, be in at least HOT SHUT 00WN 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 leas per 24 hours by determining recirculation loop flow, total core that no two of the following conditions occur when the recirculation pumps are operating in accordance with Specification 3.4.1.3.

a. The indicated recirculation loop flow differs by more than 10% from

              ,the established pump speed-loop flow characteristics.

b. The indicated total core flow differs by more than 10% from the established total core flow value derived from recirculation loop flow measurements.

c. The indicated dif fuser-to-lower plenum differential pressure of any individual jet pump differs from the established patterns by more than 10%.

SEF d i. ggs l l 3/4 4-4 HOPE CREEK

REACTOR COOLANT SYSTEM l [!"mor' .E

                                                                       , - ;9

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RECIRCULATION PUMPS N,

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LIMITING CONDITION FOR OPERATION

l 3.4.1.3 Recirculation pump speed shall 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.

SEF l '. , - HOPE CREEK 3/4 4-5

I REACTOR COOLANT SYSTEM IQnu,3

                                                                .n 4

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                                                                                *   .'   , ,; l IDLE RECIRCULATION LOOP STARTUP                                        ~ ~ ' '- " - - -        _3 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 coolant and the bottom head drain line coolant is less than or equal to 145*F and:

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. ACTION: With temperature differences and/or flow rates exceeding the above limits, suspend startup of any idle recirculation loop. SURVEILLANCE REQUIREMENTS 4.4.1.4 The temperature differentials and flow rate shall be determined to be within the limits within 15 minutes prior to startup of an idle recirculation loop. I

                                                                     .s y h

HOPE CREEK 3/4 4-6

REACTOR COOLANT SYSTEM P g; , ,. ~ ,,3 l 3/4.4.2 SAFETY / RELIEF VALVES

                                                                       ~.'U_ I f SAFETY / RELIEF VALVES LIMITING CONDITION FOR OPERATION 3.4.2.1 The safety valve fe        $

i ofatleast13oftgefollowingreactor coolant systcc safety /reliu . - shall be OPERABLE

with the specified code safety valvei Snction lift se. ;: **

4 safety-relief valves 9 1108 psig 11% 5 safety-relief valves 9 1120 psig 11% 5 safety-relief valves 9 1130 psig 11% APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:

a. With the safety valve function of two or more of the above listed fourteen safety / relief valves inoperable, be in at least HOT SHUTOOWN 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 (s) 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, restore the inoperable monitors 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.

i *SRVs which perform as ADS function must also satisfy the OPERABILITY requirements of Specification 3.5.1, ECCS-Operating.

  **The lift setting pressure shall correspond to ambient conditions of the valves at nominal operating temperatures and pressures.                    +e
  #SRVs which perform a low-low set function must also satisfy the OPERABILITY l    requirements of Specification 3.2.2, Safety / Relief Valves Low-Low Set i    Function.

HOPE CREEK 3/4 4-7 '

1 -. _ p' "'~ [ ( ~^ ' ' .tr 7 'V j REACTOR COOLANT SYSTEM

                                                                                                 ~ ' ' " ' "' '

l SURVEILLANCE REQUIREMENTS

4.4.2.1 The acoustic monitor for each safety / relief valve shall be demonstrated OPERABLE with the setpoint verified to be 30% of full open noise level **

by performance of a:

a. CHANNEL FUNCTIONAL TEST 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. SEi d ; ,335 HOPE CREEK 3/4 4-8

F ~ _. REACTOR COOLANT SYSTEM - , '~~~--r k ? " *':(^ -di. ( j J. l -

                                                                                     ..,l a

s s' s j SAFETY / RELIEF VALVES LOW-LOW SET FUNCTION ' '%I LIMITING CONDITION FOR OPERATION - 3.4.2.2 The relief valve function and the low-low set function of the following reactor coolant system safety / relief valves shall be OPERABLE with the following settings: Low-Low Set Function Setpoint* (psia) 12% Valve No. Open Close F013H 1017 905 F013P 1047 935 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 coolant 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 SHUTDOWN 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 both 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 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.

The lift setting pressure shall correspond to ambient conditions =of the valves at nominal operating temperatures and pressures.

SE; 'e t wst HOPE CREEK 3/4 4-9

REACTOR COOLANT SYSTEM t 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.

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 REQUIREMENTS 4.4.3.1 The reactor coolant system leakage detection systems shall be demonstrated OPERABLE by:

a. Drywell atmosphere noble gas monitoring system-performance of a CHANNEL CHECK at least once per 12 hours, a CHANNEL F'JNCTIONAL TEST at least once per 31 days and a CHANNEL CALIBRATION at least once per 18 months.

b. Di;,wil 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.

I l SEFSi HOPE CREEK 3/4 4-10

REACTOR COOLANT SYSTEM I.q D nr p r

                                                          .v L a C ,y .

I OPERATIONAL LEAKAGE I- I LIMITING CONDITION FOR OPERATION 3.4.3.2 Reactor coolant system leakage shall be limited f.s: -

a. No PRESSURE BOUNDARY LEAKAGE.

b. 5 gpm UNIDENTIFIED LEAKAGE.

c. 25 gpm IDENTIFIED LEAKAGE averaged over any 24-hour period.

d. 0.5 gpm leakage per nominal inch of valve size up to a maximum of 5 gpm from any reactor coolant system pressure isolation valve specified in Table 3.4.3.2-1, at full power temperature and pressure.

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 tr.e 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 isolation 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 one other closed manual or deactivated automatic or check

valves, or be in at least HOT SHUTDOWN 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 3.4.3.2-2 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.

 *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.

l l l HOPE CREEK 3/4 4-11 D 11 e &.

1 REACTOR COOLANT SYSTEM 3 p P...p f. fi - 6 c~ .,#' ' T'I {}{'f SURVEILLANCE REQUIREMENTS - '~ 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 drywell atmosphere noble gas monitoring system radioactivity at least once per 12 hours, (not a means of quantifying leakage), b. Monitoring the drywell floor and equipment drain sump monitoring system at least once per 12 hours, and c. Monitoring the drywell air coolers condensate flow monitoring system at least once per 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.

c. As outlined in the ASME Code, Section XI paragraph IWV-3427(b).

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.

SEP t HOPE CREEK 3/4 4-12

TABLE 3.4.3.2-1 o A REACTOR COOLANT SYSTEM PRESSURE ISOLATION VALVES E A IST ISOLATION 2ND ISOLATION VALVE (S) NUMBERS (S) VALVE (S) NUMBER (S) PRESSURE INDICATION SERVICE BE-V006 BE-V007 1-BE-PISH-N654A 'A' Core Spray / BE-V071 HPCI Injection BE-V002 BE-V003 1-BE-PISH-N654B 'B' Core Spray BE-V072 Injection BC-V114 BC-V113 1-BC-PISH-N653A 'A' LPCI Injection BC-V119 BC-V017 BC-V016 1-BC-PISH-N653B 'B' LPCI Injection BC-V120

                 $          BC-V102               BC-V101                       1-RC-PISH-N653C    'C' LPCI Injection a          BC-V121 0

BC-V004 BC-V005 1-BC-PISH-N653D 'D' LPCI Injection BC-V122 BC-V020 BC-V021 1-BC-PISH-N653B Head Spray N I BC-V111 BC-V110 1-BC-PISH-N653A 'A' Shutdown Cooli > g.%. BC-V117 Return to 'A' Reci c6for c *s BC-V014 BC-V013 1-BC-PISH-N6538 'B' Shutdown Cool- n BC-V118 Return to 'B' Re r i .m-BC-VQ71 BC-V164 1-BC-PISH-N657 Shutdows Cooling ilp)

                   ,                                                                               From 'B' Recirc I04p.,,1y 7                                                                                                     L:

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F TABLE 3.4.3.2-2 l 4a $?h,Qd{**,.t'lr

                                                                     ? 
                                                                               ';1
                                                                                   'I REACTOR COOLANT SYSTEM INTERFACE VALVES LEAKAGE PRESSURE MONITORS ALARM              ALARM SETPOINT          ALLOWABLE SERVICE    INSTRUMENT                          (psig)          VALUE (psig)

Core Spray 1-BE-PISH-N654A 475 $500 Core Spray 1-BE-PISH-N654B 475 1500 LPCI/RHR 1-BC-PISH-N653A 380 5410 LPCI/RHR 1-BC-PISH-N6538 380 1410 LPCI/RHR 1-BC-PISH-N653C 380 5410 LPCI/RHR 1-BC-PISH-N6530 380 5410 LPCI/RHR 1-BC-PISH-N657 130 5155 l

                                                              . . s.

l l HOPE CREEK 3/4 4-14 U U 1995

REACTOR COOLANT SYSTEM [ P), ..

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                                                                               ~n, l 3/4.4.4 CHEMISTRY                                                  x. ,~ N,         [

l l LIMITING CONDITION FOR OPERATION 3.4.4 The chemistry of the reactor coolant system shall be maintained within the limits specified in Table 3.4.4-1. APPLICABILITY: At all times. 4 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. Determina 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.

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i REACTOR COOLANT SYSTEM , hhh [ P .A' ."' .9.S'W uci 1 SURVEILLANCE REQUIREMENTS 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 startup, 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, 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 Table 3.4.4-1.

l l l SEF u o 19c,5 HOPE CREEK 3/4 4-16

2 TABLE 3.4.4-1 i n REACTOR COOLANT SYSTEM g CHEMISTRY LIMITS m m OPERATIONAL CONDITION CHLORIDES CONDUCTIVITY (puhos/cm @25*C)

                                                                                                                                   .P._H.

1

                                                                      $ 0.2 ppm
                                                                                                              $ 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                               $ 10.0          5.3 1 pH $ 8.6

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s I 3/4.4.5 SPECIFIC ACTIVITY ~~ I l LIMITING CONDITION FOR OPERATION 3.4.5 The specific activity of the primary coolant shall be limited to:

a. Less than or equal to 0.2 microcuries per gram DOSE EQUIVALENT I-131, and

b. Less than or equal to 100/E 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 coolart;

1. Greater thar. 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 exceecing 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 tima interval or for more than 800 hours cumulative 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 100/l microcuries per gram, be in at least Psi SHUTDOWN with the main steamline isolation valves close.1 within 12 hours.

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 ccolant is restored to 1 within its limit. A Special Report shall be prepare ( an.d submitted i to the Commission pursuant to Specification 6.9.2. This report shall '

contain the results of the specific activity ar.alyses 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 inform 4 tion. HOPE CREEK 3/4 4-18 SLP J o y

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c. In OPERATIONAL CONDITION 1 or 2, with:

1. THERMAL POWER changed by more than 15% of RATED THERMAL POWER in one hour *, or

2. The off gas level, at the SJAE, increased by more than 10,000 microcuries per second in one hour during 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 Item 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) Tne THERMAL POWER or off gas level change. SURVEILLANCE REQUIREMENTS 4.4.5 The specific activity of the reactor coolant shall be demorrstrated to be within the limits by performance of the sampling and analysis program of Table 4.4.5-1. m Not applicable during the startup test program. .. 0 *. * : .g HOPE CREEK 3/4 4-19

l l r TABLE 4.4.5-1 5 i ?$ PRIMARY COOLANT SPECIFIC ACTIVITY SAMPLE AND ANALYSIS PROGRAM n N? OPERATIONAL (ONDITIONS 92 TYPE OF MEASUREMENT SAMPLE AND ANALYSIS IN WHICH aAMPLE AND ANALYSIS FREQUENCY AND ANALYSIS REQUIRED

1. Gross Beta and Gamma Activity At least once per 72 hours 1, 2, 3 Determination

2. Isotopic Analysis for DOSE At least once per 31 days 1 EQUIVALENT I-131 Concentration

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#

whenever the specific u, activity exceeds a limit, 30 as required by ACTION b. s n'o b) At least one sample, between 1, 2 c' 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 I gas Sample Including Quantitative 7 Measurements for at least Xe-133, ----I ts Xe-135 and Kr-88 7 C./ ..< L ..

Sample tosbe taken after a minimum of 2 EFPD and 20 days of POWER OPERATION have elapsed since reactor was "v 1 last subcritical for 48 hours or longer. , r:ba

                             #Until the' specific activity of the primary coolant system is restored to within its limits.                   ,     . ,77 I:;,1 l i  .      3 l: 1 ,,

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__ j 3/4.4.6 PRESSURE / TEMPERATURE LIMITS REACTOR COOLANT SYSTEM - LIMITING CONDITION FOR OPERATION ; 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 B' for heatup by non-nuclear i 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 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 metal temperature shall be maintained greater than or equal to 79 F when reactor vessel head bolting studs are under tension.

APPLICABILITY: At all times. i 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. J SURVEILLANCE REQUIREMENTS 4.4.6.1.1 During system heatup, cooldown and inservice leak and hydrostatic l testing operations, the reactor coolant system temperature and pressure shall be determined to be within the above required heatup and cooldown limits and to I the right of the limit lines of Figure 3.4.6.1-1 curves A and A*,se and B', or

C and C' as applicable, at least once per 30 minutes.

i l i l SEPSctyp' HOPE CREEK 3/4 4-21

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                                                                    %..% _, ~ -                  f REACTOR COOLANT SYSTEM SURVEILLANCE REQUIREMENTS (Continued) 4.4.6.1.2 The reactor coolant system temperature 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 79 F:

a. In OPERATIONAL CONDITION 4 when reactor coolant system temperature is:

1. 5 99*F, at least once per 12 hours.

2. 1 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.

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SEr0 y ; HOPE CREEK 3/4 4-22

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                                                                               )             A= SYSTEM HYDROTEST LIMIT w1TH FUEL IN VESSEL
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l l LlMIT gg C- eeuCLE Am ICOME CRITICAL) 1300 - SMIFTite07 LeMITHsGy-3 s f LiedlT SASED ON G. E.CO. Swm LICEasssNG TOPICAL REP 0mTNEDO.21778 A A. r.c - Cone sELTomE AFTEn AN ASSUMED 20*F TEMP. 1 l SHIFT pnoM AN lastTIAL PLAft RT NOTOF 598F O 4 y ggD0 - VI M L j f l l CumVES ARE NOT LIMITING (SHOueN FOR MsFOMMATION 088LY) otscoNTlauiTY .: LiedlTS Il 3 / -

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p / CUnvES A. s. ANo C ant O PREDICTED TO APPLY AS THE LIMITS 80R 40 YEAm8 g (32 EFPYi op optaAvioN r i

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0 ' ' ' ' ' 0 900 m 300 400 800 eseNIMUM pt ACTOR VESSE L MET AL TEMPER ATURE (*F)

l MINIMUMREACTORPRESSUREVESSELMETALTEMPERATUREVS.REACTORVESIELPRESSURE Figure 3.4.6.1-1 SEF b c . HOPE CREEK 3/4 4-23

TABLE 4.4.6.1.3-1 i' 5 A REACTOR VESSEL MATERIAL SURVEILLANCE PROGRAM-WITHDRAWAL SCHEDULE o 4 A CAPSULE VESSEL LEAD WITH0RAWAL TIME Q NUMBER LOCATION FACTOR @ T (EFPY) 1 30" 1.20 6 2 120" 1.20 15 3 300* 1.20 EOL M. T n-7

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l' - REACTOR COOLANT SYSTEM L uIdj}[ihj[ggpy REACTOR STEAM DOME 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 REQUIREMENTS 3 4.4.6.2 The reactor steam dome pressure shall be verified to be less than 1020 psig at least once per 12 hours. m 0 Not applicable during anticipated transients. 4 SEP 3 6 sa3 HOPE CREEK 3/4 4-25

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itsi d.d b g ( [ l J 3/4.4.7 MAIN STEAM LINE ISOLATION VALVES LIMITING CONDITION FOR OPERATION - 3.4.7 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 equal to 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 SHUTOOWN 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 l 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. en y SL; t e HOPE CREEK 3/4 4-26

l REACTOR COOLANT SYSTEM PMFo++"m%4 b..? 8 3/4.4.8 STRUCTURAL INTEGRITY

4 LIMITING CONDITION FOR OPERATION -

l 3.4.8 The structural integrity of ASME Code Class 1, 2 and 3 components shall be maintained in accordance with Specification 4.4.8. APPLICABILITY: ERATIONAL CO MITICas 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 the affected component (s) prior to increasing the Reactor Coolant System temperature more than 50*F above the minimum temperature required by NDT considerations. j b.

 '                With the structural integrity of any ASME Code Class 2 component (s) not conforming to the above reqc~rements, restore the structural integrity of the affected component (s) to within its limit or isolate 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.

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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 4-27

REACTOR COOLANT SYSTEM 8 [akl1I+!"'

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3/4.4.9 RESIDUAL HEAT REMOVAL HOT SHUTOOWN l LIMITING CONDITION FOR OPERATION 3.4.9.1 Two# shutdown cooling mode loops of the residual heat removal (RHR) system shall be OPERABLE and, unless at least one recirculation pump is in operation, at least one shutdown cooling mode loop shall be in operation *'## with each loop consisting of: ,

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 or recirculation pump 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, one recirculation pump, 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 or at least one recirculation pump is 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.

1. The RHR shutdown cooling mode loop may be removed from operationsduring 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 4-28 Sie t ; g,,,

F - REACTOR COOLANT SYSTEM i uk $ V81T- :~ n ~ ., I J l - s. . .' (,3([ COLD SHUTDOWN LIMITING CONDITION FOR OPERATION 3.4.9.2 Two# shutdown cooling modo loops of the residual heat removal (RHR) system shall be OPERABLE and, unless at least one recirculation pump is in operation, at least one shutdown cooling mode loop shall be in operation *'## with each loop consisting of:

a. One OPERABLE RHR pump, and

b. One OPERABLE RHR heat exchanger.

APPLICABILITY: OPERATIONAL CONDITION 4. ACTION:

a. With les,s 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 or recirculation pump 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 motie loop of the residual heat removal system, recirculation pump 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 or at least one recirculation pump is 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.

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HOPE CREEK 3/4 4-29

3/4.5 EMERGENCY CORE COOLING SYSTEMS ,,, 3/4.5.1 ECCS - OPERATING ; _

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LIMITING CONDITION FOR OPERATION 3.5.1 The emergency core cooling systems shall be OPERABLE with:

a. The core spray system (CSS) consisting 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 coolant 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 five OPERABLE ADS valves.

APPLICABILITY: OPERATIONAL CONDITION 1, 2*, ** #, and 3*, **, ##. I n l The HPCI system is not required to be OPERABLE when reactor steam dome pressure is less than or equal to 200 psig, nn 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.

    "TwoLPCIsubsystemsoftheRHRsystemmaybeinoperablein[ha[theyare aligned in the shutdown cooling mode when the reactor vessel pressure is less than the RHR shutdown cooling permissive setpoint.

HOPE CREEK 3/4 5-1 ~*

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LIMITING CONDITION FOR OPERATION (Continued) ACTION:

a. For the Core Spray system:

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1. With one core spray subsystem inoperable, 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 SHUT 00WN 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 subsystem 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 SHUTDOWN 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 subsystems 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 i 24 hours. l l

4. With all four LPCI subsystems inoperable, be in at least HOT I SHUTDOWN within 12 hours and in COLD SHUTDOWN within the next 24 hours.* !

c. For the HPCI system, provided the Core Spray System, the LPCI system, the ADS and the RCIC system are OPERABLE:

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 5-2 O

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LIMITING CONDITION FOR OPERATION (Continued) ACTION: (Continued) .

1. With the HPCI system inoperable, restore the HPCI 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 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 SHUTDOWN within the next 12 hours and reduce reactor steam dome pressure to 5 100 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 $ 100 psig within the next 24 hours.

e. With a CSS and/or LPCI header AP instrumentation channel inoperable, restore the inoperable channel to OPERABLE status within 7 days or determine the ECCS header AP locally at least once per 12 hours; otherwise, declare the associated ECCS subsystem inop rable.

f. With a LPCI or CCS system discharge line " keep filled" alarm instru-mentation inoperable, perform Surveil. lance 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 usage factor for each affected safety injection nozzle shall be provided in this Special Report whenever its value exceeds 0.70.

I HOPE CREEK 3/4 5-3 l

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1 fC l h p ,n, EMERGENCY CORE COOLING SYSTEMS ~ udi'[f SURVEILLANCE REQUIREMENTS 4.5.1 The emergency core cooling systems shall be demonstrated OPERABLE by:

a. At least once per 31 days: 1 1

1. For the core spray system, the LPCI system, and the HPCI 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 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 corresponding to a reactor vessel pressure of 1105 psi above suppression pool pressure.

2. Each LPCI pump in each subsystem develops a flow of at least 10,000 gpm against a test line pressure corresponding 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 corresponding to a reactor vessel pressure of 1000 psig when steam is being supplied to the turbine at 1000,

                  +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 position 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.

SEF e g HOPE CREEK 3/4 5-4 (

          -             .             . _ _                                           =       . _ _      . _ _ _ - _ _                  -      - . -

t r EMERGENCY CORE COOLING SYSTEMS ' - I a lk& 4 SURVEILLANCE REQUIREMENTS (Continued) 1;

2. For the HPCI system, verifying that: ,
I

'                                 a)        The system develops a flow of at least 5600 gpm against a test line pressure corresponding to a reactor vessel pressure                                            {

of > 200 psig, when steam is being supplied to the turbine at 200 + 15, -0 psig.** 1 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, and LPCI system discharge line " keep filled" alarm instrunentation.

4. Performing a CHANNEL CALIBRATION of the CSS header AP instrumenta-tion and verifying the setpoint to be 1 the allowable value of 3.8 psid.

5. Performing a CHANNEL CALIBRATION of the LPCI header AP instrumen-tation and verifying the setpoint to be i the allowable value of 1.0 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 includes 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

! 2) There is a corresponding change in the measured steam flow. c) Performing a CHANNEL CALIBRATION of the Primary Containment Instrument Gas System low-low pressure alarm system and 4 verifying an alarm setpoint of 85 + 2 psig on decreasing pressure. 1

            **The provisions of Specification 4.0.4 are not applicable prov ded the surveillance is performed within 12 hours after reactor steam pressure is j

adequate to perform the test. HOPE CREEK 3/4 5-5 SEP ; c g

EMERGENCY CORE COOLING SYSTEMS 3/4 5.2 ECCS - SHUTDOWN f ((( - j LIMITING CONDITION FOR OPERA 110N 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 27%.

b. Low pressure coolant injection (LPCI) system subsystems each 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.

b. With both of the above required subsystems inoperable, suspend CORE ALTERATIONS and all operations with a potential for draining the reactor vessel. Restore at least one subsystem to OPERABLE status within 4 hours or establish SECONDARY CONTAINMENT INTEGRITY within the next 8 hours.

"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 removec', and water level is maintained within the limits of Specification 3.9.8 and 3.9.9. O C 194: HOPE CREEK 3/4 5-6

l m 1 EMERGENCY CORE COOLING SYSTEMS (!'g*"

                                                                   ~r~: ~"..w". .          .
                                                                                      ..., / CU'f[

j_ *.-r g SURVEILLANCE REQUIREMENTS 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. 1 I SFV 3 C Gb5 HOPE CREEK 3/4 5-7

l-- . . . . , _ EMERGENCY CORE COOLING SYSTEMS t- r , 3/4.5.3 SUPPRESSION CHAMBER ' Ihhi d ik. a _ _ _ _ 3 h 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 ft 3 , equivalent to an indicated level of 74.5".

b. In OPERATIONAL CONDITION 4 and 5' with a contained volume of at least 57,390 ft3 , equivalent to an indicated level of 5.0" 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 an indicated level of 27%, and

4. The core spray system is OPERABLE per Specification 3.5.2 with an OPERABLE flow path capable of taking suction from 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 that have a potential for draining the reactor vessel and lock the j reactor mode switch in the Shutdown position. Establish SECONDARY l CONTAINMENT INTEGRITY within 8 hours.

The suppression chamber is not required to be OPERABLE provided that the ,

reactor vessel head is removed, the cavity is flooded or being flooded from l the suppression pool, the spent fuel pool gates are removed when the cavity i is flooded, and the water level is maintained within the limits of l Specification 3.9.8 and 3.9.9. ' HOPE CREEK 3/4 5-8 SEP 3 0 g

EMERGENCY CORE COOLING SYSTEMS g,por o n 3 c; e,--- j I dUuf C d-J Ld bu(jI , SURVEILLANCE REQUIREMENTS i 4.5.3.1 The suppression chamber shall be determined OPERABLE by' verifying the water level to be greater than or equal to: a. 74.5" at least once per 24 hours in OPERATIONAL CONDITIONS 1, 2, and 3. b. 5.0" at least once per 12 hours in OPERATIONAL CONDITIONS 4 and 5*. 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 footnote conditions

to be satisfied.

l SEP 3 0 Egg. HOPE CREEK 3/4 5-9

f 3/4.6 CONTAINMENT SYSTEMS w.n . . s

                                                                                                                                                ~
                                                                                                                      ,,                                      f

{ Rdp;(r

h ,

                                                                                                               "~nus' I MQ  '

l . 3/4.6.1 PRIMARY CONTAINMENT _ i , PRIMARY CONTAINMENT INTEGRITY

q LIMITING CONDITION FOR OPERATION 3.6.1.1 PRIMARY CONTAINMENT INTEGRITY shall be 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 SHUTDOWN within the following 24 hours. 4 SURVEILLANCE REQUIREMENTS

4.6.1.1 PRIMARY CONTAINMENT INTEGRITY shall be demonstrated
a. After each closing of each penetration subject to Type B testing, except the primary containment air locks, if opened following Type A or B test, by leak rate testing the seals with 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 OPERABLE containment automatic isolation valves and required to be closed during 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 3.6.1.3.

! d. By verifying the suppression chamber is in compliance with the requirements of Specification 3.6.2.1.

                           *See Special Test Exception 3.10.1                                                .
                          **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. S E f 2 ,, & HOPE CREEK 3/4 6-1

l 7__ N"n v - - - - CONTAINMENT SYSTEMS L 0 6,* [ .". , _' 1,1 (.,gg .. i.,. PRIMARY' CONTAINMENT LEAKAGE -- I d. LIMITING CONDITION FOR OPERATION 3.6.1.2 Primary containment leakage rates shall be limited to:

a. , 0. 5 An overall percent integrated by weight of theleakage rate of containment air less per 24than or equal hours at P,, to L,48 1 psig.

b. for all Acombinedleakagerateoflessthanorequalto0.60L@eptformain penetrations and all valves listed in Table 3.6.3-1, ex 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 5 psig (seal system AP).

d. A combined leakage rate of less than or equal to 10 gpm for all containment isolation valves in hydrostatically tested lines in Table 3.6.3-1 which penetrate the primary containment, when tested at 1.10 Pa, 52.9 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

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 rate for all containment isolation valves in hydrostatically tested lines in Table 3.6.3-1 which penetrate the primary containment exceeding 10 gpm, restore:

a. The overall integrated leakage rate (s) to less than or equal to 0.75 L,, and

Exemption to Appendix "J" of 10 CFR 50.

                                                                             $ll a e p.)

HOPE CREEK 3/4 6-2

(~ D n o .' . - ^ CONTAINMENT SYSTEMS "C6 Eayew]i ] [ LIMITING CONDITION FOR OPERATION (Continued) ACTION (Continued) -

b. The 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 to less than or equal to 0.60 L,, and

c. The leakage rate to less than or equal to 11.5 scf per hour for any one main steam line through the isolatio.1 valve (s), and

d. The combined leakage rate for all containment isolation valves in hydrostatically tested lines in Table 3.6.3-1 which pentrate the primary containment to less than or equal to 10 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 ' a 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 a

for subsequent Type A tests shall be reviewed and approved by the Commission. It two consecutive Type A tests fail to 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 within 0.25 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 l bled from the containment during the supplemental test to be between 0.75 L, and 1.25 L,.

l HOPE CREEK 3/4 6-3 30 1993

m. CONTAINMENT SYSTEMS

                                                               %t1t' ' c g n,,
                                                                         .x g~ ~4          , , ,     l'lg
                                                                             .~ _. : _ l_

SURVEILLANCE REQUIREMENTS (Continued) The formula to be used is: [L g + L , - 0.25 L,) < L c +l am

o 0.25 L,] where Lc= supplement test result; L, E superimposed leakage; and L, a measured Type A leakage.

d. Type B 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. All containment. isolation valves in hydrostatically tested lines in Table 3.6.3-1 which penetrate the primary containment, and

5. Purge supply and exhaust isolation valves with resilient material seals.

e. Air locks shall be tested and demonstrated OPERABLE per Surveillance Requirement 4.6.1.3.

f. Main per 18steam months.line isolation valves shall be leak tested at least once

c. Leakage from isolation valves that are sealed with fluid from a seal system may be excluded, subject to the provisions of Appendix J, Section III.C.3, when determining the combined leakage rate provided i

the seal system and valves are pressurized to at least 1.10 P , 52.9 psig, and the seal system capacity is adequate to maintain syftem pressure for at least 30 days.

h. All containment isolation valves in hydrostatically tested lines in Table 3.6.3-1 which pentrate the primary containment sha'l 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 6.1.8.2 and 4.6.1.8.3.

J. The provisions of Specification 4.0.2 are not applicable to ! Specifications 4.6.1.2.a, 4.6.1.2.b, 4.6.1.2.c, 4.6.1.2 4, and 4.6.1.2.e.

 "Unless a hydrostatic test is required per Table 3.6.3-1.

Sgp 3 HOPE CREEK 3/4 6-4 t

CONTAINMENT SYSTEMS Sfl0C 6 nN" sc vu, huel Oi ).C y,Lg g y y PRIMARY CONTAINMENT AIR LOCKS l __ l 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 P,, 48.1 psig.

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. Otherwise, be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN 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 SHUTOOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

"See Special Test Exception 3.10.1. SEP 3 01983 HOPE CREEK 3/4 6-5 1

r<-- a r ,, %g CONTAINMENT SYSTEMS b v, I C *i' ' .. 6:6e SURVEILLANCE REQUIREMENTS 4.6.1.3 Each primary containment air lock shall be demanstrated 0,PERABLE:

a. Within 72 hours following each closing, except when the air lock is being used for multiple entries, 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.**

The provisions of Specification 4.0.2 are not applicable.

Exemption to Appendix J of 10 CFR 50.
- Except that the inner dc,or 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.

SEP3 HOPE CREEK 3/4 6-6

~~

CONTAINMENT SYSTEMS - -. ' MSIV SEALING SYSTEM . - LIMITING CONDITION FOR OPERATION 3.6.1.4 Two independent MSIV sealing system (MSIVSS) subsystems shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION: With one MS1V sealing system subsystem inoperable, restore the inoperable subsystem 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. SURVEILLANCE REQUIREMEN15 4.6.1.4 Each MSIV sealing system subsystem shall be demonstrated OPERABLE:

a. At least once per 92 days by cycling each testable valve except the Main Steam Stop Valves (MSSVs) through at least one complete cycle of full travel.

b. During each COLD SHUT 00WN, if not performed within the previous 92 days, by cycling each valve including the Main Steam Stop Valves (MSSVs) not testable during operation through a least one complete cycle of full travel.

c. At least once per 18 months by performance of a functional test of the subsystem throughout its operating sequence, and verifying that each interlock operates as designed and each automatic valve actuates to its correct position.

d. By verifying the control instrumentation to be OPERABLE by performance of a:

1. CHANNEL CHECK at least once per 24 hours,

2. CHANNEL FUNCTIONAL TEST at least once per 92 days, and

, 3. CHANNEL CALIBRATION at least once per 18 months. P 3 0 sg; HOPE CREEK 3/4 6-7

l -- ._ CONTAINMENT SYSTEMS i .

                                                          ,                       -.          . 4
                                                                              ' ~

PRIMARY CONTAINMENT STRUCTURAL INTEGRITY - 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 Specification 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 SHUTDOWN within the following 24 hours. SURVEILLANCE REQUIREMENTS 1 4.6.1.5.1 The structural integrity of the exposed accessible interior and exterior surfaces of the primary containment 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 i the Commission pursuant to Specification 6.9.2. This report shall include a description of the condition of the containment, the inspection procedure, and the corrective actions taken. v HOPE CREEK 3/4 6-8

l - CONTAINMENT SYSTEMS

                                                        ,. I   -.
                                                                             - ..'7. ;I DRYWELL AND SUPPRESSION CHAMBER INTERNAL PRESSURE LIMITING CONDITION FOR OPERATION i

3.6.1.6 Drywell and suppression chamber internal pressure shall be maintained between -0.5 and +1.5 psig. APPLICABILITY: 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 SHUTDOWN within the following 24 hours. SURVEILLANCE REQUIREMENTS 4.6.1.6 The drywell and suppression chamber internal prcssure shall be determined to be within the limits at least once per 12 hours. l St.uc y HOPE CREEK 3/4 6-9 L

1 ll

~~

CONTAINMENT SYSTEMS , _ '9 f8... s_ s -

) DRYWELL AVERAGE AIR TEMPERATURE f LIMITING CONDITION FOR OPERATION i ! 3.6.1.7 Drywell average air temperature shall not exceed 135*F. i APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. 4 ACTION: 4 j With the drywell average air temperature greater than 135*F, reduce the j average air temperature to within the limit within 8 hours or be in at least t HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours. 4 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 Zone Approximate Azimuth

i a. 86'11"-112'8" 90*, 225*, 135*, 290*

j (under vessel)

b. 86'11"-111'10" 135*, 300*, 100*, 190*

!                  (outside of pedestal)

{ c. 110'10"-139'2" 55*, 2408, 155*, 315* l 1 d. 139'2"-168'0" 45*, 215*, 0*, 90*, 180*, 270*

e. 168'0"-192'7" 95*, 130*, 300*, 355*,

45*, 225* i i i

   *At least one reading from each elevation zone is required for a volumetric average calculation.

HOPE CREEK 3/4 6-10

rs

f, - + --. _ ,, ' ~ CONTAINMENT SYSTEMS .is. 1 [ $ *.s DRYWELL AND SUPPRESSION CHAMBER PURGE SYSTEM LIMITING CONDITION FOR OPERATION 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: i

a. With a drywell and suppression chamber purge supply and/or exhaust isola-tion valve (s) open 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 cMmber purge supply and/or exhaust isolation valve (s) with resilient material seals having a measured leakage rate -

exceeding the limit 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 SHUTDOWN within the following 24 hours. SURVEILLANCE REQUIREMENTS 4.6.1.8.1 Each drywell 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 chamber 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, per penetration 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 0.05 L, per penetration when pressurized to P, 48.1 psig. (

   *The drywell purge inboard 26 inch valve is not required to be sealed closed and may be opened in series with the 2 inch vent line bypass valve for                      l containment pressure control.                                                               !
                                                                                       '%5 HOPE CREEK                             3/4 6-11                                             )

t- -

CONTAINMENT SYSTEMS 4 . % ,' . ' " "1 1 --- - -i 8 3/4.6.2 DEPRESSURIZATION SYSTEMS SUPPRESSION CHAMBER LIMITING CONDITION FOR OPERATION 3.6.2.1 The suppression chamber shall be OPERABLE with:

a. The pool water:

1. Volume between 118,0003ft and 122,000 ft3 , equivalent to an indicated level between 74.5" and 78.5" 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.

3. Maximum average temperature of 95*F during OPERATIONAL CONDITION 3, except that the maximum average temperature may be permitted to increase to 120*F with the main steam line isolation valves closed following a scram.

I

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 SHUTDOWN within the following 24 hours.

b. 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 SHUTOOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours, except, as per-mitted 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 110*F, place the reactor mode switch in the Shutdown posi-tion and operate at least one residual heat removal loop in the suppression pool cooling mode.

b."OC y HOPE CREEK 3/4 6-12

j n . ,. , [ T CONTAINMENT SYSTEMS J-- M .-., 6hg [' LIMITING CONDITION FOR OPERATION (Continued) ACTION: (Continued)

3. With the suppression chamber average water temperature greater than 120*F, depressurize the reactor pressure vessel to less than 200 psig within 12 hours.

c. With one suppression pool water temperature monitoring channel inoperable, restore the inoperable channel (s) to OPERABLE status within 7 days or verify suppression pool temperature to be within the limits at least once per 12 hours,

d. With both suppression pool water temperature monitoring channels inoperable, restore at least one inoperable channel to OPERABLE status within 8 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTOOWN 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 REQUIREMENTS 4.6.2.1 The suppression chamber shall be demonstrated OPERABLE:

a. By verifying the suppression chamber water volume to be within the Ifmits 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 chamber 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:

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. c) At least once per 30 minutes in OPERATIONAL CONDITION 3 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. b 3/4 6-13 HOPE CREEK

< l r

                                                                                       "909ro ne" .               I CONTAINMENT SYSTEMS

ovwf L hf; c, j @ ';(( )

                                                                                                        ' - ~ '

SURVEILLANCE REQUIREMENTS (Continued)

c. By an external visual examination of the suppression chamber after safety / relief valve operation with the suppression cham 5er average l water temperature greater than or equal to 177'F and reactor 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 all temperature elements used by the suppression pool water temperature monitoring system OPERA 8LE 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 CALIBRATION 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 0.25 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 1

!                                      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.

1 1 l 4 i I 3* SU 3 0125 HOPE CREEK 3/4 6-14

CONTAINMENT SYSTEMS

(10 W'.c 37 .' ,, SUPPRESSION POOL SPRAY 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 RHR 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 7 days or be in at least HOT SHUTOOWN 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 SHUT 00WN within the next 12 hours and in COLD SHUTOOWN* 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 val.a, 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 flow 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.
 "Whenever both RHR subsystems are inoperable, if unable to attain COLD SHUTOOWN as required by this ACTION, maintain reactor coolant temperature as low as practical by use of alternate heat removal methods.

O U v 1939 HOPE CREEK 3/4 6-15

CONTAINMENT SYSTEMS

%_~

SUPPRESSION POOL COOLING p N ha ' a %' , .. .

                                                                       .aj g.,

LIMITING CONDITION FOR OPERATION 3.6.2.3 The suppression pool cooling mode of the residual heat removal 'tHR) 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 RHR heat exchanger.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:

a. With one suppression pool cooling loop inoperable, restore the inoperable 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 cooling loops inoperable, be in at least HOT SHUTDOWN within 12 hours and in COLD SHUTDOWN

within the next 24 hours.

SURVEILLANCE REQUIREMENTS 4.6.2.3 The suppression pool cooling 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 or otherwise secured in position, is in its correct position.

b. By verifying that each of the required RHR pumps develops a flow of at least 10,000 gpm on recirculation flow through the RHR heat exchanger and the suppression pool when tested pursuant to Specification 4.0.5.

 "Whenever both RHR subsystems are inoperable, if unable to attain COLD SHUTOOWN as required by this ACTION, maintain reactor coolant temperature as low as practical by use of alternate heat removal methods.

HOPE CREEK 3/4 6-16 SLT 3 019gg

i N CONTAINMENT SYSTEMS n <- De;7 * . . :.

                                                                    ' " *g      . .
                                                                               'N 3/4.6.3 PRIMAR CONTAINMENT ISOLATION VALVES h

LIMITING CONDITION FOR OPERATION 3.6.3 The primary containment isolation valves and the reactor instrumentation line excess flow check valves shown in Table 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.*

4. The provisions of Specification 3.0.4 are not applicable provided that within 4 hours the affected penetration is isolated in accordance with ACTION a.2. or a.3. above, and provided that the associated system, if applicable, is declared inoperable and the appropriate ACTION statements for that system are performed.

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 i

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.

                                                                      *v
 ^ Isolation valves closed to satisfy these requirements may be reopened on an intermittent basis under administrative control.

at*dv}$ HOPE CREEK 3/4 6-17

CONTAINMENT SYSTEMS ~ , . r f " C 4p r m.....

                                                                    % ,,,j W , %8 y SURVEILLANCE REQUIREMENTS                                                        I 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, contrnl 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 automatic valve shown in Table 3.6.3-1 shall be determined to be within its limit when tested pursuant to Specification 4.0.5. 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. 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 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.

l 3EF U 0 1995 HOPE CREEK 3/4 6-18 : t ;

TABLE 3.6.3-1

a g PRIMARY CONTAll#4ENT ISOLATION VALVES E '

MAXIMUM E

PENETRATION ISOLATION TIME

, VALVE FUNCTION AND NUMBER NUMBER (Seconds) NOTE (S) P&ID , a. Automatic Isolation Valves

1. Group 1 - Main Steam system (a) Main Steam Isolation Valves (MSIVs) M-41 Inside:

Line A HV-F022A (A8-V028) PIA 5 1 i Line B HV-F0228 (AB-V029) PIB 5 1 Line C HV-F022C (A8-V030) PIC 5 1

                                                  ,                                     Line D HV-F022D (AB-V031)                                        PID                       5                     1 s

Outside: T Line A HV-F028A (A8-V032) PIA 5 1 Io Line 8 HV-F0288 (A8-V033) PIB 5 1 l Line C HV-F028C (A8-V034) PIC 5 1 Line D HV-F0280 (A8-V035) PID 5 1 (b) Main Steam Line Drain Isolation M-41-1 , Inside: HV-F016 (AB-V039) P12 30 3 P% - f

                                                                                                                                                                                                                          'n J Outside:

Line A HV-F067A (AB-V059) P1A 45 1 k$ ;j

                                                                                                                                                                                                                         ~-7 Line 8 HV-F0678 (A8-V060)                                        PIB                       45                    1 Line C HV-F067C (A8-V061)                                        PIC                       45                    1               Kn N.                 Line D HV-F067D (AB-V062)                                        PID                       45 1             ;a ,
                                                                                                                                                                                                                               -{

HV-F019 (A8-V040) P12 30 3 f,, i i d 'b4 i A ~ D in , S j .E , t

                                                                                                                                                                                                                ' -- I                '

t TABLE 3.6.3-1 (Continued) PRIMARY CONTAINMENT ISOLATION VALVES Q MAXIMUM p PENETRATION ISOLATION TIME

VALVE FUNCTION AND NUMBER NUMBER (Seconds) NOTE (S) P&ID (c) MSIV Sealing System Isolation Valves M-72-1 Outside:

Line A HV-5834A (KP-V010) PIA 45 1 Line B HV-5835A (KP-V009) PIB 45 1 Line C HV-5836A (KP-V008) PIC 45 1 Line D HV-5837A (KP-V007) PID 45 1

2. Group 2 - Reactor Recirculation Water Sample System (a) Reactor Recirculation Water Sample Line Isolation Valves M-43-1

 ?                     Inside:    BB-SV-4310                            P17                 15                                      3 g                     Outside:   BB-SV-4311                            P17                 15                                      3

, 3. Group 3 - Residual Heat Removal (RHR) System (a) RHR Suppression Pool Cooling Water & System Test ; Isolation Valves M-51-1 Outside: 7 7 Loop A: HV-F024A (BC-V124) P212B 180 E$ 5 HV-F010A (BC-V125) P2128 180 Q 5 ,

               '       Outside:                                                                  I%

M' Loop B: HV-F024B (BC-V028) P212A 180 M ' 5 HV-F010B (BC-V027) P212A 180 ;1I 5 c' ilI

    ,]           (b) RHR to Suppression Chamber Spray Header Isolation Valves                      Q M-51-1
   ,;$                 Outside:                                                                 ,',,
   $                   Loop A:   HV-F027A (BC-V112)                     P214B               75         f                           3 Loop B:   HV-F0278 (BC-V015)                     P214A               75

3

i. .

TABLE 3.6.3-1 (Continued) E y PRIMARY CONTAINMENT ISOLATION VALVES n E MAXIMUM PENETRATION ISOLATION TIME E VALVE FUNCTION ANO NUMBER NUMBER i (Seconds) NOTE (S) P&ID (c) RHR Shutdown Cooling Suction Isolation Valves M-51-1 Inside: HV-F009 (BC-V071) P3 45 3 Outside: HV-F008 (BC-V164) P3 45 3 (d) RHR Head Spray Isolation Valves M-51-1 Inside: HV-F022 (BC-V021) P10 60 3 Outside: HV-F023 (BC-V020) P10 60 3 (e) RHR Shutdown Cooling Return Isolation Valves M-51-1 Outside: w Loop A: HV-F015A (BC-V110) P4B 45 3 i Loop B: HV-F015B (BC-V013) P4A 45 3 cn h 4. Group 4 - Core Spray Systen Outside: (a) Core Spray Test to Suppression Pool Isolation Valves M-52-1 Loop A: HV-F015A (BE-V025) P2178 80 5 Loop B: HV-F015B (BE-V026) P217A 80 5

5. Group 5 - High Pressure Coolant Injection (HPCI) System

~~

7

                                                                                                                             -2 (a) HPCI Turbine Steam Supply Isolation Valves
                                                                                                                            ,C]             M-55-1 Inside:    HV-F002 (FO-V001)                       P7                     NA         .          3 N'                HV-F100 (FD-V051)                       P7                     NA l~          3 i

lC Outside: HV-F003 (FO-V002) P7 NA ( *" }; 3 f,' (b) HPCI Pump Suction Isolation Valve l T:

                                                                                                                         *~ 1
                                                                                                                      ;                     M-55-1 r,~.,

IB

    "                                 Outside:

HV-F042 (BJ-V009) P202 c >' NA .. S

-a

TABLE 3.6.3-1 (Continued) PRIMARY CONTAINMENT ISOLATION VALVES n MAXIMUM Ni PENETRATION ISOLATION TIME E VALVE FUNCTION ANO NUMBER NUMBER (Seconds) NOTE (S) P&IO (c) HPCI Turbine Exhaust Isolation Valve to Vacuum Breaker Network M-55-1 Outside: HV-F075 (F0-V007) P201/P204 NA 5 (d) HPCI and RCIC Vacuum Network Isolation Valve M-55-1 Outside: HV-F079 (FD-V010) P204/P201 NA 3

6. Group 6 - Reactor Core Isolation Cooling (RCIC) System (a) RCIC Turbine Steam Supply Isolation Valves M-49-1

{ i Inside: HV-F007 (FC-V001) P11 NA 3 M HV-F076 (FC-V048) P11 NA 3 Outside: HV-F008 (FC-V002) P11 NA 3 (b) RCIC Turbine Exhaust Isolation Valve to Vacuum Breaker Network i 7 M-49-1 "T 7 Outside: h.$ HV-F062 (FC-V006) P207/P204 NA Cj, S

             ,(c) HPCI and RCIC Vacuum Network Isolation Valve                                  C7                M-49-1 M'      Outside:                                                                    ;. e'                  .

HV-F084 (FC-V007) P204/P207 NA i. 3 L-

.h'      7. Group 7 - Reactor Water Cleanup (RWCU) System                                   y 2              (a) RWCU Supply Isolation Valves                                                 .j                M-44-1 Inside: HV-F001 (BG-V001)                         P9              45

3 h Outside: HV-F004 (BG-V002) P9 45 1 3

t TABLE 3.6.3-1 (Continued) PRIMARY CONTAINMENT ISOLATION VALVES 9 MAXIMUM lE PENETRATION ISOLATION TIME

VALVE FUNCTION AND NUMBER HUMBER (Seconds) NOTE (S) P&ID

8. Group 8 - Torus Water Cleanup (TWC) System (a) TWC Suction Isolation Valves M-53-1 Outside:

HV-4680 (EE-V003) P223 45 5 HV-4681 (EE-V004) P223 45 5 (b) TWC Return Isolation Valves M-53-1 Outside: R HV-4652 (EE-V002) P222 45 5 HV-4679 (EE-V001) P222 45 5

E! 9. Group 9 - Drywell Sumps (a) Drywell Floor Drain Sump Discharge Isolation Valves M-61-1 Inside: HV-F003 (H8-V005) P25 30 - 3 Outside: HV-F004 (H8-V006) P25 30 m 3

                                                                                                                     .J (b) Drywell Equipment Drain Sump Discharge Isolation Valves                                []                                                                              M-61-1 n

Inside: HV-F019 (HB-V045) P26 30 ;e, 3 Outside: HV-F020 (HB-V046) P26 30 ;. , 3 Id. Mbroup 10 - Drywell Coolers ~I ' - ch (a) Chilled Water to Drywell Coolers Isolation Valves 4 M-87-1 Q n e Inside: l o Loop A: HV-9531B1 (G8-V081) P88 60 . . 3 Loop B: HV-953183 (GB-V083) P38A 60 3 Q m

_ _ _ _= TABLE 3.6.3-1 (Continued) PRIMARY CONTAINMENT ISOLATION VALVES n MAXIMUM h PENETRATION ISOLATION TIME

VALVE FUNCTION AND NUMBER NUMBER (Seconds) NOTE (S) P&ID Outside:

Loop A: HV-9531A1 (GB-V048) P88 60 3 Loop B: HV-9531A3 (G8-V070) P38A 60 3 (b) Chilled Water from Drywell Coolers Isolation Valves M-87-1 Inside: Loop A: HV-953182 (GC-V082) P8A 60 3 Loop B: HV-953184 (GB-V084) P388 60 3 Outside: Loop A: HV-9531A2 (GB-V046) P8A 60 3 R

Loop B: P380 60 3 HV-9531A4 (G8-V071)

11. Group 11 - Recirculation Pump System (a) Recirculation Pump Seal Water Isolation Valves M-43-1 Outside:

Loop A: HV-3800A (BF-V098) P19 45 3 Loop B: HV-38006 (BF-V099) P20 45 - 3

12. Group 12 - Containment Atmosphere Control System ,]

L3

                        , (a) Drywell Purge Supply Isolation' Valves                                         f: j M-57-1
                     . g-      Outside:                                                                 ;    ro HV-4956 (GS-V009)                                P22/220          15          .3         '3 , 9         -

m HV-4979 (GS-V021) P22/220 15 J 3, 9 (b) Drywell Purge Exhaust Isolation Valves M-57-1 cc e

                                                                                                            ' {!

g Outside: 3 HV-4951 (GS-V025) P23 15 s 3

           $                                                                     P23             15             ?        3, 9

, HV-4950 (GS-V026) P23 15 3, 9 HV-4952 (GS-V024)

TABLE 3.6.3-1 (Continued) PRIMARY CONTAINMENT ISOLATION VALVES

S MAXIMUM

PENETRATION ISOLATION TIME VALVE FUNCTION AND NUMBER NUMBER (Seconds) NOTE (S) P&ID (c) Suppression Chamber Purge Supply Isolation Valves M-57-1 Outside:

HV-4980 (GS-V020) P22/P220 15 3, 9 4 HV-4958 (GS-V022) P220/P22 15 3, 9 . (d) Suppression Chamber Purge Exhaust Isolation Valves M-57-1 Outside: HV-4963 (GS-V076) P219 15 3 HV-4962 (GS-V027) P219 15 3, 9 { HV-4964 (GS-V028) P219 15 3, 9 (e) Nitrogen Purge Isolation Valves M-57-1 Outside: HV-4974 (GS-V053) J7D/J202 45 3 HV-4978 (GS-V023) P22 15 3 l

13. Group 13 - Hydrogen /0xygen (H2/02) Analyzer System

                                                                                                                                           'N
                                                                                                                                              ]

t3 (a) Drywell H2/02 Analyzer Inlet Isolation Valves C3 M-57-1 m Outside: f?o Loop A: HV-4955A (GS-V045) J9E 45 3 I ' :7 HV-4983A (GS-V046) J9E 45 !. 1 3

                                               . g,                                                                                            -  e                                    .

HV-4984A (GS-V048) J10C 45 -: 3 HV-5019A (GS-V047) J10C 45 3 Outside: a

                                                                                                                                         YJ
    ,                                                             Loop B:   HV-4955B (GS-V031)                     J38              45     N            3
   'y  '

HV-49838 (GS-V032) J38 45 ' l 3 HV-49848 (GS-V034) J7D/J202 45 3 HV-50198 (GS-V033) J7D/J202 45 3

t TABLE 3.6.3-1 (Continued) 5

 ;    y                                          PRIMARY CONTAINMENT ISOLATION VALVES p,                                                                                                        MAXIMUM p                                                                           PENETRATION                ISOLATION TIME x       VALVE FUNCTION AND NUMBER                                             NUMBER                  _

(Seconds) NOTE (S) P&ID (b) Suppression Chamber H2/02 Analyzer Inlet Isolation Valves M-57-1 i I Outside: Loop A: HV-4%5A (GS-V050) J212 45 3 HV-4959A (GS-V049) J212 45 3 Outside: Loop 8: HV-49658 (GS-V041) J210 45 3 HV-49598 (GS-V040) J210 45 3 (c) H2/02 Analyzer Return to Suppression Chamber y Isolation Valves M-57-1 Outside: i Loop A: HV-4966A (GS-V051) J201 45 3

      $                                      HV-5022A (GS-V052)                       J201                        45                       3 Outside:

Loop B: HV-4%68 (GS-V042) J202/J70 45 3 HV-50228 (GS-V043) J202/J70 45

3

14. Group 14 - Containment Hydrogen Recombination (CHR) System [9 C1 (a) CHR Supply Isolation Valves '}

                                                                                                                            ...                  M-58-1 Outside:

Loop A: HV-5050A (GS-V002) P23 45 y 3

HV-5052A (GS-V003) P23 45 . 3 N' Outside: >

          ..                       Loop B:   HV-50508 (GS-V004)                       P22/P220                    45          -

3

          ';:                                HV-50528 (GS-V005)                       P22/P220                    45         _,           3 y              (b) CHR Return Isolation Valves                                                                      ,f                 M-58-1 3                         Outside:                                                                            !

, UF Loop A: HV-5053A MS-V008) P220/P22 45 3 HV-5054A toS-V010) P220/P22 45 3 l l

e TABLE 3.6.3-1 (Continued) PRIMARY CONTAINMENT ISOLATION VALVES Q MAXIMUM p PENETRATION ISOLATION TIME VALVE FUNCTION AND NUMBER NUMBER (Seconds) P&ID NOTE (S) Outside: Loop B: HV-5053B (GS-V006) P219 45 3 M-58-1 HV-50548 (GS-V007) P219 45 3

15. Group 15 - Primary Containment Instrument Gas System (PCIGS)

(a) PCIGS Drywell Header Isolation Valves M-59-1 Inside: Loop A: HV-5152A (KL-V028) P288 45 3 Loop B: HV-51528 (KL-V026) P28A 45 3

             ?                   Outside:

y Loop A: HV-5126A (KL-V027) P28B 45 3 Loop B: HV-51268 (KL-V025) P28A 45 3 (b) PCIGS Drywell Suction Isolation Valves M-59.-1 Inside: HV-5148 (KL-V001) P39 45 :y 7 3 ca Outside: Loop A: HV-5147 (KL-V002) P39 45 M 3 Loop B: r3 HV-5162 (KL-V049) P39 45 3 e # Kb) PCIGS Suppression Chamber Supply 7( ' . Isolation Valves !-8 M-59-1

                                                                                                                          ~ .. :
               %i                Outside:                                                                                 ca HV-5154 (KL-V018)                                  J211              15                  EJ          3 5                 HV-5155 (KL-V019)                                  J211              15                  -$'

3

1 i

f TABLE 3.6.3-1 (Continued) PRIMARY CONTAINMENT ISOLATION VALVES S MAXIMUM lE

PENETRATION ISOLATION TIME VALVE FUNCTION AND NUMBER NUMBER (Seconds) NOTE (S) P&ID

16. Group 16 - Reactor Auxiliaries Cooling System (RACS)

(a) RACS Supply Isolation Valves M-13-1 Inside: HV-2554 (ED-V020) P29 45 3 Outside: HV-2553 (ED-V019) P29 45 3 (b) RACS Return Isolation Valves M-13-1 Inside: HV-2556 (ED-V022) P30 45 3 Outside: HV-2555 (ED-V021) P30 45 3

17. Group 17 - Traversing In-core Probe (TIP) System

{ {* (a) TIP Probe Guide Tube Isolation Valves M-59-1 ' Outside: SV-J004A-1 (SE-V026) P34A 15 3 SV-J004A-2 (SE-V027) P34B 15 3 SV-J004A-3 (SE-V028) P34C 15 _ 3 SV-J004A-4 (SE-V029) P34D 15 3 SV-J004A-5 (SE-V030) P34E 15 $ c:s 3 (b) TIP Purge System Isolation Valve Outside: Q M-59-1 p;p t HV-5161 (SE-V004) P34G 15 m 3 18: roup 18 - Reactor Coolant Pressure Boundary (RCPB) ' ' Leakage Detection System !{.' ; (a) Drywell Leak Detection Radiation Monitoring System (DLD-RMS) g Inlet Isolation Valves l

my M-25-1 w Outside: o HV-5018 (SK-V005) J8C 45 3 HV-4953 (SK-V006) J8C 45 3

TABLE 3.6.3-1 (Continued) PRIMARY CONTAINMENT ISOLATION VALVES O MAXIMUM m PENETRATION

ISOLATION TIME VALVE FUNCTION AND NUMBER NUM2ER (Seconds) P&ID NOTE (S)

(b) DLD-RMS Return Isolation Valves M-25-1 Outside: HV-4957 (SK-V008) J5A 45 3 HV-4981 (SK-V009) J5A 45 3

b. Manual Isolation Valves

1. Group 21 - Feedwater System (a) Feedwater Isolation Valves M-41-1 R

Outside: Check Valves i HV-F074B (AE-V002) P2A 2 O HV-F074A (AE-V006) P2B 2

2. Group 22 - High Pressure Coolant Injection (HPCI) System (a) Core Spray Discharge Valve Outside: T HV-F006 (BJ-V001) PSB _"T7 4 M-55-1

2 (b) Turbine Exhaust Valve Outside:

M r HV-F071 (FD-V006) P201 Ro 5 M-55-1 tt ' ~'s * (c) HPCI Minimum Return Line Valve (.;f 0, Outside: [i,3 Q HV-F012 (BJ-V016) P203 -

                                                                                                                                     ,M'                                                    S M-55-1
                                             ~^

3. Group 23 - Reactor Core Isolation Cooling (RCIC) System !

m I "]i.s y (a) RCIC Torbine Exhaust Valve 4 Outside: " HV-F059 (FC-V005) P207 5 M-49-1

TABLE 3.6.3-1 (Continued) PRIMARY CONTAINMENT ISOLATION VALVES Q MAXIMUM N PENETRATION ISOLATION TIME VALVE FUNCTION AND Nt#EER NUMBER (Seconds) NOTE (S) P&ID Outside: (b) RCIC Pump Suction Isolation Valve HV-F031 (BD-V003) P208 5 M-49-1 Outside: (c) RCIC Minimum Return Line Isolation Valve SV-F019 (BD-V007) P209 5 M-49-1 Outside: (d) RCIC Vacuum Pump Discharge HV-F060 (FC-V011) P210 5 M-49-1

4. Group 25 - Core Spray System (a) Core Spray injection Valves -

M-52-1

          ?                     Outside:                          .

g Loop A&C HV-V005A (BE-V007) PSB 4 i Loop B&D HV-F005B (BE-V003) PSA 4 (b) Core Spray Suppression Pool Suction Valves - - - M-52-1 Outside: g I Loop A HV-F001A (BE-V017) P216D :: J 5 Loop B HV-F0018 (BE-V019) P216A @ 5 Loop C HV-F001C (BE-V018) P216C vs 5 Loop D HV-F001D (BE-V020) P2168 (y.3 5 (c) Core Spray Minimum Flow Valves Outside: l [$ M-52-1 N' Loop A&C HV-F031A (BE-V035) P217B L53 ' 5 - Loop B&D HV-F031B (BE-V036) P217A

5 c: s (d) Core Spray Injection Line Bypass Valves CJ M-52-1 o

Inside: HV-F039A (BE-V071) P5B l k 4

                                                                                                  ' 'i              4
            <.                  HV-F039B (BE-V072)                                  PSA q

! a

e TABLE 3.6.3-1 (Continued) PRIMARY CONTAINMENT ISOLATION VALVES

o MAXIMUM E PENETRATION ISOLATION TIME VALVE FUNCTION AND NUMBER NUMBER (Seconds) NOTE (S) P&ID

5. Group 26 - Residual Heat Removal System (a) Low Pree,ure Coolant Injection Valves M-51-1 Outside:

Loop A: HV-F017A (BC-V113) P6C 4 Loop B: HV-F0178 (BC-V016) P6B 4 Loop C: HV-F017C (BC-V101) P60 4 Loop D: HV-F0170 (BC-V004) P6A 4 (b) RHR Containment Spray M-51-1 Outside: R Loop A: HV-F021A (BC-V116) P24B 4 HV-F016A (BC-V115) P24B 4 i Loop B: HV-F0218 (BC-V019) P24A 4 $ HV-F016B (BC-V018) P24A 4 (c) RHR Suppression Pool Suction M-51-1 Outside:

g Loop A: HV-F004A (BC-V103) P211C . 5 Loop B: HV-F0048 (BC-V006) P211B E].s 5 Loop C: HV-F004C (BC-V098) P2110 C. 3 5 Loop D: HV-F0040 (BC-V001) P211A hM 5 j Co (d) RHR Minimum Flow Isolation Valves : :p M-51-1 Outside: t fJ Loop A: HV-F007A (BC-V128) P2128

p .] 5 N, Loop B: HV-F007B (BC-V031) ' '

P212A i 2. j r 5 Loop C: HV-F007C (BC-V131) P212B ... 5 Loop D: HV-F007D (BC-V034) P212A , t 5, 5

~$

3

l - e l TABLE 3.6.3-1 (Continued) PRIMARY CONTAINMENT ISOLATION VALVES n MAXIMUM . := PENETRATION ISOLATION TIME ( VALVE FUNCTION AND NUpBER

             %                                                                                           NUMBER           (Seconds)                         NOTE (S)           P&ID (e) Bypass Valves on LPCI Injection Lines                                                                                     M-51-1 l                                                         Inside:

HV-F146A (BC-V119) P6C 4 4 ' HV-F1468 (BC-V120) P68 4 HV-F146C (BC-V121) P6D 4 , HV-F1460 (BC-V122) P6A 4 (f) Bypass Valves on Shutdown Cooling Return Lines M-51-1 Inside: HV-F122A (BC-V117) P48 3

HV-F1228 (BC-V118) P4A 3 i (g) RHR Suppression Pool Return Valves M-51-1 2

w Outside: D HV-F011A (BC-V126) P2128 5 m HV-F011B (BC-V026) P212A 5 i w j 6. Group 27 - Standby Liquid Cnntrol M-48-1 ) Outside: HV-F006A (BH-V028) P18 3 HV-F0068 (BH-V054) P18 3 j 7. Grcup 28 - Containment Atmosphere Control System Supression Chamber Vacuum Relief Outside: 3 M-57-1

}                                                       HV-5031 (GS-V038)

HV-5029 (GS-V080) P220/P22 P219 f3.$ 3 { , p 3 8.' N(iroup 69 - TIP System ' - j m Explosive Shear Valves M-59-1 4 nt Outside: 4 SE-XV-J00481 SE-V021 P34A 8 I E, SE-XV-J00482 SE-V022 P348 l 8 y, SE-XV-J004B3 SE-V023 P34C 8 j If SE-XV-J00484 SE-V024 P340 8 j SE-XV-J004B5 SE-V025 P34E . _ . 8 i

I TABLE 3.6.3-1 (Continued)

 ,                                                                                    PRIMARY CONTAINMENT ISOLATION VALVES 9                                                                                                                                 MAXIMUM IN                                                                                                              PENETRATION    ISOLATION TIME VALVE FUNCTION AND NUMBER                                                                                NOMBER          (Seconds)   NOTE (S)  P&ID

9. Group 29 - HPCI System Suppression Pool Level Instrumentation Isolation M-55-1 Outside:

HV-4803 (BJ-V500) J209 7 liv-4804 (BJ-V501) P228 7 HV-4865 (BJ-V502) J217 7 HV-4866 (BJ-V503) J219 7

10. Group 30 - Post-Accident Sampling System R Liquid Sampling M-38-0

Outside:

      ?                                             RC-SV-0643A                                                           P227                            3 O                                             RC-SV-0643B                                                           P227                            3 RC-SV-8903A                                                           J50                             3 RC-SV-8903B                                                           J50              -

3 i Gas Sampling Outside: k C3 M-38-0 RC-SV-9730A RC-SV-0730B J7E J7E M 3 3 g RC-SV-0731A J10E 3 RC-SV-0731B J10E kj 3 RC-SV-0728A J206 ,*. ; 3 RC-SV-0728B J206 h1 i 3 N RC-SV-0729A J221 MI '3 - RC-SV-0729B J221 c3 3 v., RC-SV-0707A J220 C) 3 Pri RC-SV-07078 J220 k 3

          $                                                                                                                              -- - j

e TABLE 3.6.3-1 (Continued) k"' PRIMARY CONTAINMENT ISOLATION VALVES l Q MAXIMUM N s PENETRATION ISOLATION TIME VALVE FUNCTION AND NUMBER NUMBER (Seconds) NOTE (S) P&ID

c. Primary Containment (Other Isolation Valves)

1. Group 31 - Feedwater System (a) Feedwater Isolation Valves M-41-1 Inside Check Valves AE-V003 P2A 2 AE-V007 P2B 2

2. Group 32 - Standby Liquid Control System T

y Inside Check Valve M-48-1 BH-V029 P18 3

3. Group 33 - Primary Containment Atmosphere Control / System Containment Vacuum Breakers [, M-57-1 Outside: o GS-PSV-5032 P220/P22 L C) 3 GS-PSV-5030 P219 3 "

3 f?S 4. Group 34 - Service Air System P3 M-15-0 n- ' i Outside KA-V038 P27 LJ , i.'. 3

             ,Q            Inside         KA-V039                                        P27               i;           3 co                                                                                               .3 l

o

5. Group 35 - Breathing Air System '

M-15-1 T. c>i l $ Inside KG-V016 P31

~#

3 Outside KG-V034 P31 3 1

TABLE 3.6.3-1 (Continued) PRIMARY CONTAINMENT ISOLATION VALVES 9 MAXIMUM E

PENETRATION ISOLATION TIME VALVE FUNCTION ANO NUMBER NUMBER (Seconds) NOTE (S) P&ID

6. Group 36 - TIP Purge System

               .                                              Inside:

Check Valve: SE-V006 P34G 3 M-59-1

7. Group 37 - HPCI System Outside:

HPCI Turbine Exhaust: FD-V004 P201 5 M-55-1

8. Group 38 - RCIC System Outside:

RCIC Turbine Exhaust: FC-V003 P207 5 M-49-1 R Vacuum Pump Discharge: FC-V010 P210 5 M-49-1 i 9. Group 39 - RHR System M (a) Thermal Relief Valves M-51-1 Outside: Loop A: BC-PSV-F025A P212B 6 Loop B: BC-PSV-F0258 P212A qq, 6 Loop C: BC-PSV-F025C P2128 A'3 6 Loop D: BC-PSV-F0250 P212A c3 6 mg (b) Jockey Pump Discharge Check Valves @ M-51-1 Outside: 73 Loops A & C: (BC-V206) P2128 r 5 Loops B & D: (BC-V260) P212A 5 (c) RHR Heat Exchanger Thermal Relief Valves '4 M-51-1 Outside: CJ

                            ~n BC-PSV-4431A BC-PSV-4431B P2138 P213A W

6 6 ce

TABLE 3.6.3-1 (Continued) PRIMARY CONTAINMENT ISOLATION VALVES MAXIMUM M

PENETRATION ISOLATION TIME VALVE FUNCTION AND NUMBER NUMBER (Seconds) NOTE (S) P&ID (d) RHR Shutdown Cooling Suction Thermal Relief Valve Inside: M-51-1 BC-PSV-4425 P3 3 (e) LPCI Injection Line Check Valves Inside: M-51-1 HV-F041A (BC-V114) P6C 4 HV-F0418 (BC-V017) P68 4 HV-F041C (BC-V102) P60 4 HV-F041D (BC-V005) P6A 4 R (f) Shutdown Cooling Return Line Check Valves
Inside: M-51-1

  ?                     HV-F050A    (BC-Vill)                             P4B g                     HV-F0508    (BC-V014)                             P4A 3

3

10. Group 40 - Core Spray System (a) Thermal Relief Valves Outside:

Loop A&C: BE-PSV-F012A [

                                                                                             = :,

M-52-1 P217B C .~2 6 Loop B&D: BE-PSV-F0128 P217A kj 6 (b) Core Spray Injection Line Check Valves Outside: M-52-1 e HV-F006A (BE-V006) PSB Ej y3 4

              -        HV-F006B M-                 (BE-V002)                             PSA               ry3     '4              -

11. Group 41 - Drywell Pressure Instrumentation

                                                                                           -e Outside:                                                            ea               M-42-1 C3
   $n                  BB-V563 BB-V564 J6A
                                                                                          -M         7 re J80                         7 BB-V565                                           J7A                    -

7 7.. BB-V566 J100 7

TABLE 3.6.3-1 (Continued) a g PRIMARY CONTAINMENT ISOLATION VALVES S MAXIMUM IE

PENETRATION ISOLATION TIME VALVE FUNCTION AND NUMBER NUMBER (Seconds) P&ID NOTE (S)

12. Group 42 - Intergrated Leak Rate Testing System M-60-1 Inside GP-V001 J36D 3 Outside GP-V002 J36D 3 Inside GP-V120 J36C 3 Outside GP-V122 J36C 3 Outside GP-V004 J209 3 Outside GP-V005 J209 , 3

13. Group 43 - Suppression Chamber Pressure Instrumentation M-57-1 Outside R* GS-V044 J207 7 GS-V087 J208 7

O 14. Group 44 - Chilled Water System Thermal Relief Valves M-87-1 Inside GB-PSV-9522A D88 3 GB-PSV-95228 P38A 3 GB-PSV-9523A P8A 3 GB-PSV-95238 P38B $ (;.3 3

15. Group 45 - Recirculation Pump Ses1 Purge Line Check Valves Inside fe]

c M-43-1 BB-V043 P19 3 BB-V047 P20 if

                                                                                                                                 ..}.,

3

d. Exhefs Flow Check Valves jr .j ' '

~~

1. Group 46 - Nuclear Boiler M-41-1 c3 m Outside C:3 T

Z BB-XV-3649 AB-XV-3666A J5C J25A )

.].

AB-XV-36668 d J26A -------- 1 AB-XV-36660 J27A AB-XV-3666D J28A

TABLE 3.6.3-1 (Continued)

PRIMARY CONTAINMENT ISOLATION VALVES Q MAXIMUM p PENETRATION ISOLATION TIME x VALVE FUNCTION AND NUMBER NUMBER (Seconds) NOTE (S) P&lD Outside M-41-1 AB-XV-3667A J22A AB-XV-36678 J22C AB-XV-3667C J21A AB-XV-3667D J210 3 AB-XV-3668A J228 l AB-XV-3668B J22D AB-XV-3668C J21E AB-XV-36680 J21F: AB-XV-36694 J25C AB-XV-36698 J26C y AB-XV-3669C J270

AB-XV-36690 J280

2. Group 47 - Nuclear Boiler Vessel Instrumentation M-42-1 Outside BB-XV-3621 J3A l BB-XV-3725 J2C BB-XV-3726A J1350 BB-XV-3726B J1353 BB-XV-3727A BB-XV-3727B J44 J41 6]

c, BB-XV-3728A J1351 %i BB-XV-37288 J1354 Ao BB-XV-3729A J51 33 N' BB-XV-37298 J42 8

                                                                                                                        ,, t BB-XV-3730A                                       Jr:2                          -

2 BB-XV-3730B J43 [ *^ .I i BB-XV-3731A J1352 i

          ~n                          BB-XV-3731B J1355                     ,!]

SS ,

BB-XV-3732A J37A ~i '

BB-XV-3732B J11A *E ik BB-XV-3732C J24E '

.w

e TABLE 3.6.3-1 (Continued) 5 g PRIMARY CONTAINMENT ISOLATION VALVES k MAXIMUM PENETRATION ISOLATION TIME VALVE FUNCTION AND NUMBER NUMBER (Seconds) P&ID NOTE (S) Outside M-42-1 BB-XV-3732D J118 BB-XV-3732E J37C BB-XV-3732F J40C BB-XV-3732G J37D BB-XV-3732H J40E BB-XV-3732J J37E BB-XV-3732K J11E BB-XV-3732L J14A BB-XV-3732M J40F BB-XV-3732N J148 R

BB-XV-3732P J128 BB-XV-3732R J14C T BB-XV-37325 J12C l$ BB-XV-3732T J14D BB-XV-3732U J400 BB-XV-3732V J14E BB-XV-3732W J12E ---

BB-XV-3734A BB-XV-37348 J50 J47

'm'

7 BB-XV-3734C J14F BB-XV-3734D J12F h3 vi BB-XV-3737A J38A gyn BB-XV-37378 J16C ,,

BB-XV-3738A J13D .Cj l P BB-XV-37388 J38B 5: ( N ' '

                                                                                                                                        .71 t          3. Group 48 - Reactor Recirculation System                                                                                j *'                                     M-42-1 1

iC3 T Outside BB-XV-3783 J32B , kl N BB-XV-3785 J32C

   'j i

BB-XV-3787 J30C a BB-XV-3789 J308 g BB-XV-3801A J18B 1 l

s TABLE 3.6.3-1 (Continued)

PRIMARY CONTAINMENT ISOLATION VALVES 2 MAXIMUM Ri PENETRATION ISOLATION TIME

VALVE FUNCTION AND NUMBER NUMBER (Seconds) NOTE (S) P&ID Outside M-42-1 BB-XV-38018 J28B BB-XV-3801C J16E BB-XV-3801D J36E BB-XV-3802A J18F I BB-XV-38028 J28F BB-XV-3802C J16F BB-XV-38020 J36F BB-XV-3803A J29F

BB-XV-3803B J24A l BB-XV-3803C J38C i l 5: ' BB-XV-38030 J34D

BB-XV-3604A l J290 l T BB-XV-3804B J24B l $; BB-XV-3804C J38F BB-XV-3804D J34E

4. Group 49 - Reactor Recirculation System - Cont'd. -

__ M-43-1 Outside BB-XV-3820 J32E CD BB-XV-3821 J32F b4 BB-XV-3826 J348 pa BB-XV-3827 J23C ,

5. Group 50 - Reactor Water Cleanup pc}

I M-44-1

- y

ple -

Outside ': g BG-XV-3882 J24C ya ! en BG-XV-3884A J190 , 2.' BG-XV-38848 J34A j ;f - l $ BG-XV-3884C J19E _ _~', 3 BG-XV-3884D J34C-9

t HBLE3.6.3-1(Continued) PRIMARY CONTAINMENT ISOLATION VALVES n

=

El MAXIMUM

PENETRATION ISOLATION TIME VALVE FUNCTION AND NUMBER NUMBER (Seconds) NOTE (S) P&ID

6. Group 51 - Reactor Core Isolation Cooling System M-49-1 Outside FC-XV-4150A J20A FC-XV-41508 J408 FC-XV-4150C J208 FC-XV-41500 J40A

7. Group 52 - Residual Heat Removal System M-51-1 Outside R! BC-XV-4411A

J33A BC-XV-44118 J238 i BC-XV-4411C J35A

 $                                                 BC-XV-4411D                                                J36B BC-XV-4429A                                                 J330 BC-XV-44298                                                 J23A BC-XV-4429C                                                 J35C i

BC-XV-44290 J36A T~ _ 7

8. Group 53 - Core Spray System

[$y M-52-1 - Outside c .:. i

                                                                                                                                                          ~51    8 BE-XV-F018A                                                J19C BE-XV-F0188                                                J30F f?' 8 f
                                          '                                                                                                              :,i

9.

rGroup 54 - High Pressure Coolant Injection System L: > ,\

                                                                                                                                                       ;       ,        M-55-l' Outside FD-XV-4800A                                                J19A I

FD-XV-4800B J29A l

                                                                                                                                                      -If FD-XV-4800C                                                J19B                   I ~*s.. .C
  ;5                                              FD-XV-48000                                                J298                   f - _J iil e

nnn y TABLE 3.6.3-1 bd h l [T[)V e~~ . .. -< PRIMARY CONTAINMENT ISOLATION VALVES ' ' ~ ~ ~ ------ A NOTES NOTATION I l

1. Main Steam Isolation Valves are sealed with a seal system that main-tains a positive pressure of 5 PSIG above reactor pressure. Leakage is in-leakage and is not added to 0.60 La allowable leakage.

2. Feedwater Isolation Valves are sealed with a water seal from the HPCI and RCIC system. Isolation valves are gas type C tested to evaluate disc / seat leakage condition. Leakage is not added to 0.60 La allowable leakage. The water seal boundary valves are tested with water at Pa, 48.1 psig, to ensure seal boundary will prevent by pass leakage.

Seal boundary liquid leakage will be added to the Type C, water test leakage. . . 3. Containment Isolation Valve, Type C gas test at Pa, 48.1 psig. Leak-age added to 0.60La allowable leakage.

4. ECCS Isolation Valve, Type C gas test. Leakage test to determine valve leakage condition. Leakage is not added to 0.60La allowable leakage.

5. Containment Irolation Valve, Type C water test at Pa, 48.1 psig a P.

Leakage added to 10 gpm allowable leakage.

6. Containment isolation is discharge nozzle or relief valve, leakage tested during Type A test.

7. Drywell and suppression chamber pressure and level instrument root .

_, valves, leakage tested during Type A.

8. Explosive shear valves (SE-V021 through SE-V025) not Type C tested.

9. Surveillances to be performed per Specification 4.6.1.8.1.

10. All valve I.D. numbers are preceded by a numeral 1 which represents an Unit 1 valve.

3: 8 HOPE CREEK 3/4 6-42

r d CONTAINMENT SYSTEMS h*. +C2 '?' D .p l 3/4.6.4 VACUUM RELIEF SUPPRESSION CHAM 8ER - ORYWELL VACUUM BREAKERS LIMITING CONDITION FOR OPERATION 3.6.4.1 All suppression chamber - 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 te 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 or more suppression chamber - drywell vacuum breaker (s) 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 following 24 hours.

c. With one of the position indicators of any suppression chamber -

drywell vacuum breaker inoperable:

1. Verify the other position indicator in the pair to be OPERABLE within 2 hours and at least once per 14 days thereafter, or

2. Verify the vacuum breaker (s) with the inoperable position indicator to be closed by conducting a test whith;d::monstrates 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 14 days thereafter.

Otherwise, be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours. l

                                                                      -   3-SEF 3 0 3995 HOPE CREEK                             3/4 6-43

r U g h

                                                         <                l O~O
                                                                       .m,.    , -N,!

CONTAINMENT SYSTEMS -- j SURVEILLANCE REQUIREMENTS 4.6.4.1 Each suppression chamber - drywell vacuum breaker shall Ee:

a. Verified closed at least once per 7 days,

b. Demonstrated OPERABLE:

1. At least once per 31 days and within 2 hours after any discharge of steam to the suppression chamber frnm 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 OPERABLE by performance of a CHANNEL CALIBRATION.

l l I HOPE CREEK 3/4 6-44 AECF : I ass l .,

l l p',~.=. 1

                                                                                               , . c u.
                                                                                                         ! ;.' ..~

j%. , '7 p* n ,f f CONTAINMENT SYSTEMS ~

                                                                                                                ~~....,}

REACTOR BUILDING - SUPPRESSION CHAMBER VACUUM BREAKERS LIMITING CONDITION FOR OPERATION \ 3.6.4.2 Both reactor building - suppression chamber vacuum breaker assemblies consisting of a vacuum breaker valve and a butterfly isolation valve shall be OPERABLE and closed. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:

a. With one valve of a reactor building - suppression chamber vacuum breaker assembly inoperable for opening but known to be closed, restore the inoperable vacuum breaker assembly valve 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 valve of a reactor building - suppression chamber vacuum breaker assembly open, verify the other vacuum breaker assembly valve in the line to be closed within 2 hours; restore the open vacuum breaker assembly valve to the closed position within 72 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTOOWN within the following 24 hours.

c. With the position indicator of any reactor building - suppression

' chamber vacuum breaker assembly valve inoperable, restore the inoper-able position indicator to OPERABLE status within 14 days or verify the affected vacuum breaker assembly valve to be closed at least once per 24 hours by a visual inspection. Othemise, declare the vacuum

breaker assembly valve inoperable or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours. SURVEILLANCE REQUIREMENTS 4.6.4.22 Both reactor butiding - suppression chamber vacuum breaker assemblies shall be:

a. Verified closed at least once per 7 days.

b. Demonstrated OPERABLE:

1. At least once per 31 days by:

l i a) Cycling each vacuum breaker assembly valve through at least one complete cycle of full travel. b) Verifying the position indicators on each assembly valve OPERABLE by observing expected valve movement during the cycling test. i

2. At least once per 18 months by: '

l a) Der.onstrating that the force required to open each vacuum breaker valve does not exceed the equivalent of 0.25 psid. b) Visual inspection. HOPE CREEK 3/4 6-45 N '

CONTAINMENT SYSTEMS j

                                                        ]ggnp p. .       , m SURVEILLANCE REQUIREMENTS (Continued)

W . s ,; - l,'8 ' g

c) Verifying the position indicators on each assembly valve OPERABLE by performance of a CHANNEL CALIBRATION. d) Verifying the instrument actuation system for the inboard isola-tion valve auto open control system OPERABLE by performance of a CHANNEL CALIBRATION. SEP 3 0 ;9g5 HOPE CREEK 3/4 6-46

F CONTAINMENT SYSTEMS h h' f h* 3/4.6.5 SECONDARY CONTAINMENT I SECONDARY CONTAINMENT INTEGRITY LIMITING CONDITION FOR OPERATION 3.6.5.1 SECONDARY CONTAINMENT INTEGRITY shall be maintained. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3 and *. ACTION: 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 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 reactor building ven-tilation system (RBVS) exhaust flowrate exceeds the supply flowrate, and that the reactor building is at a negative pressure.

b. Verifying at least once per 31 days that:

1. All secondary containment equipment hatches and blowout panels are closed and sealed. -

2. a. For double door arrangements, at least one door in each access to the secondary containment is closed.

b. For single door arrangements, the door in each access to the secondary containment is closed except for routine entry and exit.

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 / l valves secured in position.

c. At least once per 18 months:

1. Verifying that four filtration recirculation and ventilation system (FRVS) recirculation units and one ventilation unit of the filtration recirculation and ventilation system will draw l down the secondary containment to greater than or eqtf&l7o 0.25 inc.hes of vacuum water gauge in less than or equal to 375 seconds, and i

 *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 6-47 - W 3 0199g

l l CONTAINMENT SYSTEMS IUus e (U{ff' ...

                                                                        . t  .j SURVEILLANCE REQUIREMENTS (Continued)

2. Operating four filtration recirculation and ventilation system (FRVS) recirculation 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.

O E l l HOPE CREEK 3/4 6-48 SEP s c w

t PRD W &iYu m' w 'y CONTAINMENT SYSTEMS SECONDARY CONTAINMENT AUTOMATIC ISOLATION DAMPERS 4 LIMITING CONDITION FOR OPERATION 3.6.5.2 The secondary containment ventilation system (RBVS) automatic ! isolation dampers shown in Table 3.6.5.2-1 shall be OPERABLE with isolation , times less than or equal to the times shown in Table 3.6.5.2-1. l l 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 l 8 hours either: l 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.

1 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.

b. During COLD SHUTDOWN 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. ,

i . c. By verifying the isolation time to be within its linit when Jested pursuant to Specification 4.0.5.

                    "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 6-49 N30g

TABLE 3.6.5.2-1 PR00F & E BV ?,2PY , SECONDARY CONTAINMENT VENTILATION SYSTEM AUTOMATIC ISOLhTIDN DAMPERS MAXIMUM ISOLATION TIME ' DAMPER FUNCTION (Seconds)

1. Reactor Building Ventilation Supply Damper HD-9370A 10

2. Reactor Building Ventilation Supply Damper HD-93708 10

3. Reactor Building Ventilation Exhaust Damper HD-9414A 10

4. Reactor Building Ventilat" ion Exhaust Damper HD-9414B 10 I

sa

                                                                         t l                                                                              b 6 995 HOPE CREEK                            3/4 6-50

                                                                                        }    . ._

Dy~7 buu m L *. I N --_ . CONTAINMENT SYSTEMS * -

                                                                                                                        ...p~..*

I FILTRAT' ION, RECIRCULATION AND VENTILATION SYSTEM (FRVS) LIMITING CONDITION FOR OPERATION ' 3.6.5.3 OPERABLE. Five FRVS recirculation units and two FRVS ventilation units shall be ] APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3 and *. i ACTION: a. With one of the above required FRVS recirculation units or one of the ' above required FRVS ventilation units inoperable, restore the inoper-able unit to OPERABLE status within 7 days, or: 1. In OPERATIONAL CONDITION 1, 2 or 3, be in at least HOT SHUTDOWN within

                                        '24      the next 12 hours and in COLD SHUTDOWN within the following 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 units or both ventilation units inoper-able in Operational Condition *, suspend handling of irradiated fuel in the secondary containment, CORE ALTERATIONS or operations with a potential for draining the re ctor vessel. The provisibns of Speci-fication 3.0.3. are not applicible. SURVEILLANCE REQUIREMENTS 4.6.5.3 demonstrated Each of the six OPERABLE: FRVS recirculation and two ventilation units shall be a. At least once per 14 days by verifying that the water seal bucket traps have a water seal and making up any evaporative losses by fil-ling the traps 4.o the overflow. b. 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 irradiated fuel is being handled in the secondary containment and during CORE ALTERATIONS and operations with a potential for draining the reactor vessel.

9,cy 3 0 M HOPE CREEK 3/4 6-51

                                                                             .s wy I w

h._d 4 6-s.ad CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

c. 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 testing acceptance criteria of less than 0.05% and uses the test procedure guidance in Regulatory Positions C.S.a, C.S.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 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, Revisica 2, March 1978, by showing a methyl iodide penetration of less than 0.175% when tested at a temperature of 30*C and at a relative humidity of 70%

in accordance with ASTM D3803 with a 4 inch bed; and

3. Verifying a subsystem flow rate of 30,000 cfm i 10% for each FRVS recirculation unit and 9,000 cfm 110% for each FRVS ventilation unit during system operation when tested in accordance with ANSI N510-1980.

d. After every 720 hours of charcoal adsorber operation by verifying within 31 days after removal that a laboratory a.nalysis 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, by showing a methyl iodide penetration of less than 0.175% when tested at a temperature of 30 C and at a relative humidity of 70% in accordance with ASTM D3803 with a 4 inch bed.

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 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:

a. Manual initiation from the control room, and D 3 0 ?Mg HOPE CREEK 3/4 6-52

                                                                                     = - - -

CONTAINMENT SYSTEMS h[ h Fy"Ey/ Fv' su- .. .- ; yf SURVEILLANCE REQUIREMENTS (Continued)

b. Simulated automatic initiation signal.

3. Verifying that the heaters dissipate 100 1 5 kw for each recirculation unit and 32 1 3 kw for each ventilation unit when tested in accordance with ANSI N510-1975. Also, verifing humidity control instruments operate to maintain less than or equal to 70% relative humidity.

f. After each complete or partial replacement of a HEPA filter bank by verifying that the HEPA filter bank satisfies the inplace penetration testing acceptance criteria of less than 0.05% in accordance with Regulatory Position C.S.a and C.S.c of Regulatory Guide 1.52, Revi-sion 2 March 1978, 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.

g. After each complete or partial replacement of a charcoal adsorber bank by verifying that the charcoal adsorber bank satisfies the inplace penetration testing acceptance criteria of less than 0.05% in accor-dance with Regulatory Position C.S.a and C.S.d of Regulatory Guide 1.52, Revision 2, March 1978, for a halogenated hydrocarbon refrig-erant 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 i 10% for each FRVS ventilation unit.

l l 4 $8 t fb { e' + l ouRggg HOPE CREEK 3/4 6-53 l i

CONTAINMENT SYSTEMS IN kn, ~~% .

                                                                                    - - a. a yap ,s        .

3/4.6.6 PRIMARY CONTAINMENT ATMOSPHERE CONTROL ~ --- __ _,i CONTAINMENT HYDROGEN RECOMBINER SYSTEMS LIMITING CONDITION FOR OPERATION ' 3.6.6.1 Two independent containment hydrogen recombiner systems shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. ACTION: With one containment hydrogen recombiner system inoperable, restore the inoper-able 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 containment 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 reaction chamber gas temperature increases to greater than or equal to 1150*F within 120 minutes and is maintained > 1150'F for at least 2 hours.

b. At least once per 18 months by:

1. Performing a CHANNEL CALIBRATION of all recombiner control panel instrumentation 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. I i at i e HOPE CREEK 3/4 6-54

CONTAINMENT SYSTEMS *L h[h]'gJ DRYWELL AND SUPPRESSION CHAMBER OXYGEN CONCENTRATION LIMITING CONDITION FOR OPERATION ' 3.6.6.2 t The drywell and suppression chamber atmosphere oxygen concentration 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. ACTION: With the drywell and/or suppression chamber oxygen concentration exceeding the limit, restore the oxygen concentration to within the limit within 24 hours or be in at least STARTUP within the next 8 hours. SURVEILLANCE REQUIREMENTS 4.6.6.2 The drywell and suppression chamber oxygen concentration shall l I 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.

  "See Special Test Exception 3.10.5.

HOPE CREEK 3/4 6-55 ' bI Sb

l l- \ 3/4.7 PLANT SYSTEMS ' 3/4.7.1 SERVICE WATER SYSTEMS I l b'[ SAFETY AUXILIARIES COOLING SYSTEM LIMITING CONDITION FOR OPERATION - 3.7.1.1 At least the following independent safety auxiliaries cooling system (SACS) subsystems, with each subsystem comprised of: i i i

a. Two OPERABLE SACS pumps, and

b. An OPERABLE flow path consisting of a closed loop through the SACS heat exchanger (s) and SACS pumps and to associated safety related equipment shall be OPERABLE:

2

a. In OPERATIONAL CONDITION 1, 2 and 3, two subsystems.

b. In OPERATIONAL CONDITION 4, 5, and ** the subsystems associated with l

systems and components required OPERA 8LE by 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 SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

2. With one SACS subsystem otherwise inoperable, realign the affected diesel generators to the OPERABLE SACS subsystem within 2 hours, and restore the inoperable subsystem to OPERABLE status with at least one OPERABLE pump and heat exchanger within 72 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD 'l SHUTDOWN within the following 24 hours. 3. With one SACS pump or heat exchanger in each subsystem inoperable, immediately initiate measures to place the unit in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours. 4. j With both SACS subsystems otherwise inoperable, immediately initiate measures to place the unit in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTOOWN* in the following 24 hours. t

       *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 Sfp ; g

i l-PLANT SYSTEMS n g i % ,- . .7Clj*p+

                                                                                 ,,; k.
                                                                                      ~

I LIMITING CONDITION FOR OPERATION (Continued) i l ACTION: (Continued)

b. In OPERATIONAL CONDITION 3 or 4 with the SACS subsystem, which is assuciated 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.

c. In OPERATIONAL CONDITION 4 or 5 with the SACS subsystem, which is associated with safety related equipment required OPERABLE by Speci-fication 3.5.2, inoperable, declare the associated safety related equipment inoperable and take the ACTION required by Specification 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,

e. In OPERATIONAL CONDITION 4, 5, or **, with one SACS subsystem, which is associated with safety related equipment required OPERABLE by Specification 3.8.1.2, inoperable, realign the associated diesel generators within 2 hours to the OPERABLE SACS subsystem, or declare the associated diesel generators inoperable and take the ACTION re-quired by Specification 3.8.1.2. The provisions of Specifica-tion 3.0.3 are not applicable. .

f. In OPERATIONAL CONDITION 4, 5, or **, with only one SACS pump and heat exchanger and its associated flowpath OPERABLE, restore at least two pumps and two heat exchangers and associated flowpaths to OPERABLE status within 72 hours' or, declare the associated safety related equipment inoperable and take the associated ACTION requirements.

SURVEILLANCE REQUIREMENTS 1 i 1 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 j path that is not locked, sealed or otherwise secured in position, is 1

in its correct position.

b. At least once per 18 months during shutdown by verifying that: 1) Each automatic valve servicing safety-related equipment actuates to its correct position on the appropriate test signal (s), and 2) Each pump starts automatically when its associated diesel generator starts.

HOPE CREEK 3/4 7-2 N

PLANT SYSTEMS rs h[ ,9;qr w.. .< STATION SERVICE WATER SYSTEM ' %,N LIMITING CONDITION FOR OPERATION 3.7.1.2 At least the following independent station service water system loops, with each loop comprised of:

a. Two OPERABLE station service water pumps, and

b. An OPERABLE flow path capable of taking suction from the Delaware River (ultimate heat sink) 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 C0'4DITION .., 2, or 3:

1. With one station service water pump inoperable, restore the in-operable pump to OPERAL'LE 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 one station service water pump in each loop inons."able, restore at least one inoperable pump to OPERABLE status witt in 72 hours or be in at least HOT SHUTDOWN within the next 12 hours and M COLD SHUTDOWN within the following 24 hours.

3. With one station service water system loop otherwise inoperable, restore the inoperable station service water system loop to j OPERABLE status with at least one OPERABLE pump 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 only one station service water pump and its associated flowpath l OPERABLE, restore at least two pumps with at least one flow path to OPERABLE status within 72 hours cr:

1. In OPERATIONAL CONDITION 4 or 5, declare the associated SACS subsystem inoperable and take the ACTION required by Specification 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 handling irradiated fuel in the secondary containment.

HOPE CREEK 3/4 7-3 E' d 01985

fN. ((*".... PLANT SYSTEMS ' i

                                                     )                          n 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, servicing safety related equipment that is 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.

2. Each pump starts automatically when its associated diesel genera-tor starts.

e SEP3c g, HOPE CREEK 3/4 7-4 t - _ . _ _ . _. . -_ - - . - - -

l I . PLANT SYSTEMS

                                                      'F          -~

l r .- L i eQr mg [

~-

ULTIMATE HEAT SINK - g LIMITING CONDITION FOR OPERATION 3.7.1.3 The ultimate heat sink (Delaware River) shall be OPERABLE with:

a. A minimum river water level at or above elevation 76'O Mean Sea Level, PSE&G datum (-13.0' 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 SHUTDOWN 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 applicable. SURVEILLANCE REQUIREMENTS l 4.7.1.3 The ultimate heat sink shall be determined OPERABLE:

a. By verifying the river water level to be greater than or equal to the minimum limit at least once per 24 hours.

b. By verifying river water temperature to be within its limit:

I

1) at least once per 24 hours when the river water temperature is less than or equal to 85*F.

2) at least once per 6 hours when the river water tempesature is greater than 85*F.

l

 *When handling irradiated fuel in the secondary containment.

SEP 3 0. 95 HOPE CREEK 3/4 7-5

PLANT SYSTEMS Jhvu'ICsa r4 Q--U 3/4.7.2 CONTROL ROOM EMERGENCY FILTRATION SYSTEM LIMITING CONDITION FOR OPERATION 3.7.2 Two independent control room emergency filtration system subsystems shall be OPERABLE with each subsystem consisting of: a) One control room supply unit, b) One filter train, and c) One control room return air fan. 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 SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

b. In OPERATIONAL CONDITI0h 4, 5 or *:

1. With one control room emergency filtration subsystem inoperabla, restore the inoperable subsystem to OPERABLE status within 7 days or initiate and maintain operation of the OPERABLE subsystem in the pressurization / recirculation 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 reacto: 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: i

a. At least once per 12 hours by verifying that the control room air I temperature is less than or equal to 85*F #.

b. At least once per 31 days on a STAGGERED TEST BASIS by initiating, i from the control room, flow through the HEPA filters ant charcoal l

 *When irradiated fuel is being handled in the secondary containment.

This does not require starting the non-running control emergency filtration subsystem. HOPE CREEK 3/4 7-6 SEP 3 0 g

I-

u. ..~. u m'!

s v l PLANT SYSTEMS i SURVEILLANCE REQUIREMENTS (Continued) adsorbers and verifying that the subsystem operates for at least 10 hours with the heaters and humidity control instrumentation OPERABLE.

c. 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 in testing acceptance criteria of less than 0.05% and uses the test procedure guidance in Regulatory Positions C.S.a. C.S.c and C.S.d of Regulatory Guide 1.52, Revision 2, March 1978, and the system filter train 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 cr'iteria of Regulatory Position C.6.a of Regulatory Guide 1.52, Revision 2, March 1978, by showing a methyl iodide penetration of less than 0.175% when tested at a temperature of 30'C and at a relative humidity of 70%

in accordance with ASTM D3803; and

3. Verifying a subsystem filter train flow rate of 4000 cfm i 10%

during subsystem operation when tested in accordance with ANSI N510-1980.

d. After every 720 hours of charcoal adsorber 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, by showing a methyl iodide penetration of less than 0.175% when tested at a temperature of 30*C and at a relative h aidity of 70% in accordance with ATSM D3803.

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 Vater Gauge while operating the filter train subsystem at a flow rate of 4000 cfm i 10%.

2. Verifying with the control room hand switch in the recirculation mode that on each of the below recirculation mofe actuation test signals, the subsystem automatically switches to the isolation mode of operation and the isolation dampers close within 5 seconds:

l HOPE CREEK 3/4 7-7 , I'U S( 995

PLANT SfSTEMS D* T'C." t.; [ *. " L ^ *',I 3 no w . l

                                                                                                                ..9 . . . .                                ,

__ l SURVEILLANCE REQUIREMENTS (Continued) i l a) High Drywell Pressure b) Reactor Vessel Water Level Low Low Low, Level I c) Control room ventilation radiation monitors high.

3. Verifying with the control room hand switch in the outside air mode that on each of the below pressurization mode actuation test signals, the subsystem automatically switches to the pressurization mode of operation and the control room is maintained at a positive pressure of 1/8 inch W.G. relative to the outside atmcsphere during subsystem operation at an outdoor flow rate less than or equal to 1000 cfm:

a) High Drywell Pressure b) Reactor Vessel Water Level Low Low Low, Level 1 c) Control room ventilation radiation monitors high. 1

4. Verifying that the heaters dissipate 13 1 1.3 Kw when tested in accordance with ANSI N510-1980 and verifying humidity control instruments operate to maintain less than or equal to 70% humidity.

f. After each complete or partial replacement of a HEPA filter bank by verifying that the HEPA filter bank satisfies the inplace penetration testing acceptance criteria of less than 0.05% in accordance with Regulatory Positions C.S.a and C.5.c of Regulatory Guide 1.52, Revision 2, March 1978, while operating the system at a flow rate of 4000 cfm i 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 testing acceptance criteria of less than 0.05% in accordance with Regulatory Positions C.5.a and C.5.d of Regulatory Guide 1.52, Revision 2, 1

March 1978, for a halogenated hydrocarbon refrigerant test gas while operating the system at a flow rate of 4000 cfm i 10%. b I HOPE CREEK 3/4 7-8 i

q o r-p' e ,u , ;- , '" I l

A-{jy f '.ne' "4 i -3 ' PLANT SYSTEMS e J _) 3/4.7.3 FLOOD PROTECTION LIMITING CONDITION FOR OPERATION 3.7.3 Flood protection shall be provided for all safety related systems, components and structures when the water level of the Delaware River exceeds 10.5 feet Mean Sea Level USGS datum (99.5 feet PSE&G 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 water level at the service water intake structure shall be deter-mined to be within the limit by:

a. Measurement at least once per 24 hours when the water level is below elevation 8.5 Mean Sea Level USGS datum, and

b. Measurement at least once per 4 hours when severe storm warnings from the National Weather Service which may impact Artificial Island are in effect.

c. Measurement at least once per 2 hours when the water level is equal to or above elevation 8.5 Hean Sea Level USGS datum.

i SEP 3 0 9 35 l HOPE CREEK 3/4 7-9

l%* [ ,'y _

                                                                        ~          ~~

l TABLE 3.7.3-1 ' - y,

PERIMETER FLOOD DOORS - J INTAKE STRUCTURE 000RS Water tight door 1 Water tight door 2 Water tight door 3 Water tight door 4 Water tight door 5 Water tight door 6 Water tight door 7 Water tight door 8 POWER BLOCK 000RS and HATCH Doors & Hatch Location Hatch Exterior 45; K S-13 45.5; L 3340B " 44; M 3337B 44; Md 6312 45.4; T 6323B 45.4; U 5315A 29.9; X 5315C 29; X 4323A 13.6; U 4304 13.6; U 3301A 13.6; Md 3305B 13.6; L . 33158 Interior-102' 25; H 3329A 27; H 33318 " 35; H 3209A Interior 26; H 1

                                                                 *v SEP 3o79gg t

HOPE CREEK 3/4 7-10

                                                                               ..          .        ~.    .

PLANT SYSTEMS ' " ' * ' YhUJI L es. I . .$ aus 1 3/4.7.4 REACTOR CORE ISOLATION COOLING SYSTEM - - - - - - -- f LIMITING CONDITION FOR OPERATION 3.7.4 The reactor core isolation cooling (RCIC) system shall be OPERABLE with an OPERABLE flow path capable of automatically 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 SHUTOOWN 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 i adequate to perform the test.

NT ; ', HOPE CREEK 3/4 7-11 D

l-PLANT SYSTEMS n- ^

r o r ew ro. - . - -

f .i. I' U is_ ?.h,i Lsn' [ i_.- __ SURVEILLANCE REQUIREMENTS (Continued)

c. At least once per 18 months by:

1. Performing a system functional test which includes simulated automatic actuation and restart # 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. -

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 - O 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.
    #Automatic restart on a low water level signal which is subsequent to a high j      water level trip.

i .l l l l ' l HOPE CREEK 3/4 7-12 EU6

PLANT SYSTEMS DDS'IC E C .P a=~a

                                                                                                         &/      l t         L lw s ...,  .g i   ,

3/4.7.5 SNUBBERS LIMITING CONDITION FOR OPERATION 3.7.5 All snubbers shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1,2, and 3. OPERATIONAL CONDITIONS 4 and 5 for snubbers located on systems required OPERABLE in those OPERATIONAL CONDITIONS. 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 pert)rmance. of the following augmented inservice inspection program and the r'quirements 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 0C g

PLANT SYSTEMS h ) h;h 3 ([jfy SURVEILLANCE REQUIREMENTS (Continued) ! No. Inoperable Snubbers

of Each Type per Subsequent-Visual 3 Inspection Period Inspection Period *#

j 0 18 months i 25% ; 1 12 months i 25% 2 6 months i 25% j 3,4 124 days i 25% l 5,6,7 62 days i 25% 8 or more 31 days i 25% ,

c. Visual Inspection Acceptance Criteria I Visual inspections shall verify (1) that there are no visible i indications of damage or impaired OPERABILITY, (2) attachments to l the foundation or supporting structure are secure, and (3) fasteners

for attachment of the snubber to the component and to the snubber i anchorage are secure. Snubbers which appear inoperable as a result of visual inspections may be determined OPERABLE for the purpose of i estabi khing the next visual inspection period, providing that:

(1) the u use of the rejection is clearly established and remedied for that particular snubber and for other snubbers irrespective of l type on that system that may be generically st.sceptible; and/or (2) the j 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 Inspection ! An inspection shall be performed of all snubbers attached to sections ! of systems that have experienced unexpected, potentially damaging l transients, as determined from a review of operational data or a ! visual inspection of the systems, within 72 hours for accessible 1 syctems and 6 months for inaccessible systems following this deter-mination. In addition to satisfying the visual inspection acceptance { criteria, freedom-of-motion of mechanical snubbers shall be verified i using at least one of the following: (1) manually induced snubber movement, or (2) evaluation of in place snubber piston setting. l 1

       *The inspection interval for each type of snubber shall not be lengthened

, more than one step at a time unless a generic probltm has been identified and corrected; in that event the inspection interval may be lengthened one step j the first time and two steps thereafter if no inope'able snubbers of that j type are found. **

       #The provisions of Specification 4.0.2 are not applicable.

I i HOPE CREEK 3/4 7-14

U0g

l l PLANT SYSTEMS 8 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 plans for each type of snubber. The sample plan shall be selected prior to the test period and cannot be changed during the test period. The NRC Regional Admin-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 4.7.5.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. Testing equipment failure during functional testing may invalidate that day's testing and allow that day's testing to resume anew at a later time, providing all snubbers tested with the failed equipment during the day of equipment failure are re-tested; or

2) A representative sample of each type of snubber shall be functionally tested in accordance with Figure 4.7.5-1. "C" is the total number of snubbers of a type found not meeting the acceptance requirements of Specification 4.7.5.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 4.7.5-1. 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 invalidate that day's testing and allow that day's testing to resume anew at a later time, providing l all snubberr 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 l 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 acceptance 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 HOPE CREEK 3/4 7-15 SEF 3 01995

~~-

PLANT SYSTEMS { hh [if,. 6 h e, Tt 3 f.ma > we ( 1 SURVEILLANCE REQUIREMENTS (Continued) point plotted falls on or below the " Accept" line, testing of that type of snubber may be terminated. If the point plotted falls above the " Accept" line, testing must continue until the point falls on or below the " Accept" line or all the snubbers of that type have been tested. Testing equipment failure during func-tional testing may invalidate that day's testing and allow that day's testing to resume anew at a later time, providing all snubbers tested with the failed equipment during the day of equipment failure are retested. The representative sample selected for the function test sample 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 that they are representative of the various configu-rations, operating environments, range of size, and capacity of snubbers of each type. Snubbers placed in the same locations as snubbers which failed the previous functional test shall be retested 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 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 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:

1) Activation (restraining action) is achieved within the specified range in both tension and compression;

2) Snubber bleed, or release rate where required, is present in j both tension and compression, within the specified range (hydraulic snubbers oniv);

j

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 i

4) For snubbers specifically required not t 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 *

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 HOPE CREEK 3/4 7-16 0 0 gge J t

( . PLANT SYSTEMS 8 h b.... Y.s

                                                                        --   WV uus :      ,

SURVEILLANCE REQUIREMENTS (Continued) OPERABILITY of other snubbers irrespective of type which may be subject to the same failure mode. ' 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 inoperable snubbers are attached were adversely affected by the inoperability of the snubbers in order to ensure that the component remains capable of meeting the designed service. If any snubber selected for functional testing either fails to lock 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 tested. This testing requirement shall be independent of the requirements stated in Specification 4.7.5.e. for snubbers not meeting the functional test acceptance criteria.

h. Functional Testing of Repaired and Replaced Snubbers Snubbers which fail the visual inspection or the functional test acceptance criteria shall be repaired or replaced. Replacement snubbers and snubbers which have repairs which might affect the functional test 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 the freedom of-motion test must have been performed within 12 months before being installed in the unit.

i. Snubber Service Life Replacement Program The service life of all snubbers 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 moni-tored test results and failure history. Critical parts shall be replaced so that the maximum service life will not be exceeded during a period when the snubber is required to be OPERABLE. The parts replacements shall be documented and the documentation shall be retained in accordance with Specification 6.10.3. SEP3o HOPE CREEK 3/4 7-17

l

                                                                           ... l PllS a a !. i.. a i.r.i n i-c          --

j , THis PADIO'il PENDiN3 HECEIPT OF_

          ; ! N F 2 J i-.               . __
                                 Ni T'li APPUCAi9T

_y i SAMPLE PLAN 2) FOR SNUBBER FUNCTIONAL TEST ** Figure 4.7.5-1 1 SEP 3 0 p - HOPE CREEK 3/4 7-18

I PLANT SYSTEMS P

                                                                               ~m
                                                                     ~-'

3/4.7.6 SEALED SOURCE CONTAMINATION L - . . ; g LIMITING CONDITION FOR OPERATION 3.7.6 Each sealed source containing radioactive material either in excess of 100 microcuries of beta and/or gamma emitting material or 5 microcuries of alpha emitting 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.

SURVEILLANCE REQUIREMENTS 4.7.6.1 Test Requirements - Each sealed source shall be tested for leakage and/or contamination by:

a. The licensee, or

! 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 Frequencies - 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 radioactive material:; 1. With a half-life greater than 30 days, excluding Hydrogen 3, and
2. In any form other than gas.

                                                                                 ** J 0 19a HOPE CREEK                              3/4 7-19

F ~ ~ . _ . _ PLANT SYSTEMS i_

                                                              ;(((C ?  ' -
                                                                    *6-.t.         ,g ,
                                                                                       .,,   l

_ j SURVEILLANCE REQUIREMENTS (Continued)

b. Stored sources not in use - Each sealed source and fission detector shall be tested prior to use or transfer to another licensee unless tested within the previous six months. Sealed sources and fission detectors transferred without a certificate indicating the last test date shall be tested prior to being placed into 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 Reports - 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. l a01185 HOPE CREEK 3/4 7-20

d ( N. a PLANT SYSTEMS .

                                                                                  ,        - -l 3/4.7.7 FIRE SUPPRESSION SYSTEMS                       %..,_,,                   ff     .
                                                                                  ~

l 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. Two 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 or both of the fire water storage tank (s) 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, 3.7.7.4, and
 ;               3.7.7.5.

APPLICABILITY: At all times. ACTION: I

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 i

supply volume. . b. At least once per 31 days by starting the electric motor driven fire suppression pump and operating it for at least 15 minutes. c. At least once per 31 days by verifying that each valve ^, Nanual, power operated or automatic, in the flow path is in its correct position. S U J e 19ar, l HOPE CREEK 3/4 7 21

I r")y o e, . , . 7 ~ PLANT SYSTEMS ; I i' d I . i

                                                                                                                     - - - - .     .I SURVEILLANCE REQUIREMENTS (Continued)

^

d. At least once per 12 months by performance of a system flush, i

e. At least once per 12 months by cycling each testable valve in the flow path through at least one complete cycle of full travel,

f. At least once per 18 months by performing a system functional test j

which includes simulated automatic actuation of the system,throughout 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 275 feet, 1 3. Cycling each valve in the flow path that is not testable during I plant operation through at least one complete cycle of full travel, i and; 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 t

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: i a. At least once per 31 days by: ~l 1. Verifying the fuel storage tank contains at least 135 gallons of fuel. I

2. Starting the diesel driven pump from ambient conditions and operating for greater than or equal to 30 minutes, t

! b. At least once per 92 days by verifying that a sample of diesel fuel from the fuel storage tank, obtained in accordance with ASTM-0270-75, 1 is within the acceptable limits specified in Table 1 of ASTM D975-77 l when checked for viscosity, water and sediment,

c. At least once per 18 months by subjecting the diesel to an inspection in accordance with procedures prepared in conjunction with its
manufacturer's recomendations for the class of service.

SEs~" b l HOPE CREEK 3/4 7-22 %

                                                                                                             =-         ..     .    ._

PLANT SYSTEMS g, , ,7 s...: s. .. . .

                                                                                                                 ~ ~ ~ ~ ' ' ~

h SURVEILLANCE REQUIREMENTS (Continued) 4.7.7.1.3 The diesel driven fire pump starting 24-volt battery bank and charger shall be demonstrated OPERABLE:

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 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.

O Y hh HOPE CREEK 3/4 7-23

PLANT SYSTEMS SPRAY AND/OR SPRINKLER SYSTEMS ; p- .'. . . . 1

i. , '

LIMITING CONDITION FOR OPERATION 3.7.7.2 The following spray and sprinkler systems shall be OPERA.BLE: HAZARD AREA SYSTEM ELEVATION NO. Reactor Buildino Motor Control Center Area 4201 77' Corridor 4301 1P515

       -                                                      102'                     IPS16 FRVS* Rectrc. Charcoal Filter                    132' FRVS   Recire. Charcoal Filter                                            IPD3
       -                                                      132'                     1PD4 FRVS   Vent Unit Charcoal Filter                 145' FRVS Vent Unit Charcoal Filter                                            IPDS
      -                                                       145'                     IPD6 FRVS Recire. Charcoal Filter                     162' FRVS Recire. Charcoal Filter                                              IPD7
      -                                                      162'                      1P08 FRVS Recire. Charcoal Filter                    178'6" FRVS Recirc. Charcoal Filter                                               1P010
                                                    ,        178'6"                   IPD11 Auxiliary Buildino Control and D/G Areas Cable Spreading Room Corridor 5207                                    77'                      IPS4 Corridor 5237                                    77'                     IPS6
     -                                                       77'                     IPS7 Electrical Access 5339                           102' Control Equipment Mezzanine                                              IPS8 Electrical Access 5401                           117'6"                  1028
    -                                                       124'                     IPS9 Elec. Cable Chase 5203, 5323, 5331, 5405, 5419, 5531                                      77', 102', 124',         IPS10
    -                                                       130', 137, 150' Elec. Cable Chase 5204, 5324, 5332, 5406, 5420, 5532                                       77', 102', 124',        IPS11
   -                                                        130', 137, 150' Elec. Cable Chase 5205, 5325, 5333, 5407, 5421, 5533                                       77', 102', 124',        IPS12
   -                                                        130', 137, 150' Elec. Cable Chase 5206, 5326, 5334, 5408,        77', 102', 124',

5422, 5534 IPS13 Emergency Charcoal Filter 130', 137, 150' Emergency Charcoal Filter 153' 101

  -                                                         153'                    102 Diesel Tank Room 5107                           54' 04csel Tank Room 5108                                                    1022
 -                                                         54'                      1023 Diesel Tank Room 5109                            54' Diesel Tank Room 5110                                                     1024

54' 1025 Auxiliary Building Radwaste and Service Areas Electrical Access Area 3204 77' Electrical Access Area 3425 1P56 124' 1P59 Intake Structure * *
Service Water Pump Room Service Water Pump Room IPS1 H and V Chase 5535 IPS2 0 150' IPS14
Filtration, Recirculation and Ventilation system.

HOPE CREEK 3/4 7-24 SEPS,

l PLANT SYSTEMS r. - , . ,, Y. .a . ' ' T .' SURVEILLANCE REQUIREMENTS (Continued) ~ l APPLICABILITY: Whenever equipment protected by the spray and/or sprinkler i systems is required to be OPERABLE. ACTION:

a. With one or more of the above required spray and/or sprinkler 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 4.7.7.2 Each of the above required spray and sprinkler systems shall be demonstrated OPERABLE: l l 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 each 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) Verifying'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.

1 i 2. By a visual inspection of the dry pipe spray and sprinkler headers t 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.

i d. At least once per 3 years by performing an air flow tast,through each ! deluge sprinkler header and verifying each open head deluge sprinkler

is unobstructed.

l i l SEP 3 01985 HOPE CREEK 3/4 7-25

i V __ PLANT SYSTEMS i " a ' '- 1 i 6, .s u , ,

                                                                                                                                                             "t C0 SYSTEMS
  -2                                                                                                 -
                                                                                                                                                 --        ,'J i

LIMITING CONDITION FOR OPERATION 3.7.7.3 The following low pressure CO systems shall be OPERABLE: 2 Hazard Area Elevation System No. Auxiliary Building Control & D/G Areas

a. Fuel Tank Room 5110 54' 1C1

b. Fuel Tank Room 5109 54' IC2 .

i c. Fuel Tank Room 5108 54' IC3 i d. Fuel Tank Room 5107 54' IC4 l e. Diesel Generator Room 5301 102' IC5 I , f. Diesel Generator Room 5306 102' IC6

g. Diesel Generator Room 5305 102' 107

! h. Diesel Generator Room 5304 102' 1C8

1. Control Equip Room Mezzanine 5447 117'-6" 1C10 APPLICABILITY: 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 i l 4.7.7.3.1 Each of the above required C0 systems shall be demonstrated OPERABLE at least once per 31 days by vefifying 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 C0 systems shall be i 2 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 At least once per 18 months by verifying: b.

1. The system, including associated ventilation system fire dampers and fire door release mechanisms, actuates, manualTy and automatically, upon receipt of a simulated actuation signal, and l

2. Flow from each accessible nozzle during a " Puff Test."

) HOPE CREEK 3/4 7-26 l MP30'

PLANT SYSTEMS l- _ HALON SYSTEM l ' t . . . .' l l l I --- LIMITING CONDITION FOR OPERATION J ' ' _]

3.7.7.4 The Control Room Console Pit Halon system shall be OPERABLE with the J storage tanks having at least 95% of full charge level. i APPLICA8ILITY: Whenever equipment protected by the Halon system is required to be OPERABLE. ACTION:

a. With the above required Halon system inoperable, within one hour establish a continuous fire watch with backup fire suppression l 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 Specifications 3.0.3 and 3.0.4 are not applicable.

1

SURVEILLANCE REQUIREMENTS i

4.7.7.4 The above required Halon system shall be demonstrated OPERABLE: q a. At least once per 6 months by verifying Halon storage tank level,

b. At least once per 18 months by performance of a flow test through accessible headers and nozzles to assure no blockage.

l l i l i 1 i i i

                                                                                                 *v i

i l l HOPE CREEK 3/4 7-27 Sif J 01966 L

PLANT SYSTEMS -

^'

FIRE HOSE STATIONS LIMITING CONDITION FOR OPERATION 3.7.7.5 The fire hose stations shown in Table 3.7.7.5-1 shall be 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 3.7.7.5-1 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 lef t unprotected by the inoperable hose station.

Where it can be demonstrated that the physical routing of the fire hose would 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, j b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable. SURVEILLANCE REQUIREMENTS l 4.7.7.5 Each of the fire hose stations shown in Table 3.7.7.5-1 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 i

during plant operation to assure all required equipment is at I the station.

2. Removing the hose for inspection and re-racking, and

3. Inspecting all gaskets and replacing any degraded gaskets 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 b1nckage.

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 7-28 St# 3 01985

! l

1

.I f%

~"

l TABLE 3.7.7.5-1 I ." ~ - - 8*~ . ,

FIRE HOSE STATIONS j% I. ;

                                                                                                                         *~.:

LOCATION HOSE RACK j: ELEVATION COLUMN IDENTIFIC"ATION

^ l

a. Reactor Building 54' W-14R 1AHR200 i 54' W-23R 1BHR200 54' P-23R ICHR200 54' P-14R IDHR200 i 77' W-14R 1EHR200 77' W-24.2 IFHR200 i

77' N-24.2 1GHR200 77' V-14R 1HHR200 t 77' R-23R 1BHR202 ! 77' V-18.9 1CHR202 i

!                     77'                       P-18.9                                       IDHR202                                    l 1                     77'                       R-14R                                        1EHR202                                    (

l 102' W-14R

IJHR200 ;

102' W-24.2 IKHR200 102' N-23R ILHR200 102' Q-15R IMHR200 ,

102' U-14R INHR200 ; 102' U-22R 1PHR200 102' N-14R 12HR200 l 102' Q-21R 1AHR201

!                    132'                       U-20R                                        IQHR200 1                    132'     -

Q-20R 1RHR200 132' R-14R 1YHR200 3 145' P-17R IBHR201

 !                   145'                       U-20R                                        ISHR200                                    i 1                    145'                       Q-15R                                        ITHR200                                    !

1 162' Q-15R IUHR200 i 162' U-20R IVHR200 l l 178' Q-15R 1AHR202 i 201' N-19R 1CHR201 201' U 20R IWHR200 i 201' Q-15R IXHR200

b. Auxiliary Building Control & 0/G Areas 1 54' Vd-29 1AHR400 l l 54' S-29 IBHR400 l i 54' V 25 1CHR400 j 54' 5-25 10HR400 j 54' N 25 77' Vd 29 IEHJt4g0 IFHR4 1 77' V 25 1GHR400 77' N 25 1HHR400 l

i i SkF 3 0198"t HOPE CREEK 3/4 7-29

! l_ ---t . ~ . _ TABLE 3.7.7.5-1 (Continued) !i I# ' l , 3- . . _ 1 HOSE RACK ELEVATION COLUMN IDENTIFICATION

b. Auxiliary Building Control & 0/G Areas (continued) '

77' S-25 ILHR400 , 77' T-29 1MHR400 102' N-25 1AHR401 102' V-25 18HR401 1 102' S-25 10HR401 l 102' T-30 ISHR401 l 102' Vd-28.1 IQHR400 124' N-25 1RHR400 l i 124' R-25 1HHR401 130' W-29 ISHR400 130' T-29 1CHR401 _ 130' X-25 1GHR401 130' U-29 1THR401 1 137' R-24.2 ITHR400 i 146' W-29 IJHR401 J 146' U-29 10HR401 1 146' S-29 IVHR400 ' 150' X-25 10HR400 . 155'-3" N-25 1YHR400

!            163'                    V-29                                            IWHR400 i

163' T-29 1XHR400 ! 163' U-29 IKHR401 l 163' V-26 IPHR401 ,

178' S-29 1RHR401 >

j 178' V-29 IQHR401 ; j c. Auxiliary Building Radwaste & Service Areas I 54' Md-21.4 1FHR400 < 54' L-15.8 OAHR300 77' Md-21.4 IJHR400

102' Md-21.4 1NHR400 l 102' Mc-19 IPHR400 j 102' l L-15.8 0QHC300 i 137' Mc-29 OMHC301 l 137' K-21.4 OGHC301 i

j d. Intake Structure j 100' -- 1AHR500 } 100' -- 18HR500

o.

1 w am ! j HOPE CREEK 3/4 7-30 '

PLANT SYSTEMS ' f 3/4.7.8 FIRE RATED ASSEMBlics ;

                                                              '{*~~'                  ~~     . l
                                                                                        ,, 3   j LIMITING CONDITION FOR OPERATIOP 3.7.8 All fire rated assemblies, including walls, floor / ceilings, cable tray                 .

enclosures and other fire barriers, separating safety related fire areas or separating portions of redundant systems important to safe shutdown within a , fire area, and all sealir.g 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. l 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: <

1. Verify the OPERABILITY of fire detectors on both sides of the affected penetration and establish a daily fire watch patrol, or

2. Verify the OPERABILITY of fire detectors on at least one side of the t.ffected penetration and establish an hourly fire watch patrol, or l

3. Establish a continuous fire watch on at least one side of the I affacted penetration.

b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS I 4.7.8.1 Each of the above required fire rated assembifes and penetration I 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 shaII be made. This inspection process shall continue until a 10 percent sample with no apparent changes in appearance or abnormal degradation is found. Samples shall be selected such ,

that each penetration seal wili be inspected at least once per ' 15 years. l l t SEP 3 0199c HOPE CREEK 3/4 7-31 ! I

PLANT SYSTEMS j __ f .. U l

                                                          .                         ------~~.                            l l

SURVEILLANCE REOUIREMENTS (Continued) 2 - 4.7.8.2 Each of the above required fire doors shall be verified OPERABLE by i inspecting the closing mechanisms and latches at least once per 6 months, and i 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.                                                                                                         r

c. That each unlocked fire door without electrical supervision is
closed at least once per 24 hours.
f i

i i I i F

4 I J 1 I . 1 ) 1 i j H 1915 i j HOPE CREEK 3/4 7-32 l

l l l i PLANT SYSTEMS h -- - l 1 PIlu,*vra,1f,;,; . j 3/4.7.9 MAIN TURBINE BYPASS SYSTEM l LIMITING CONDITION FOR OPERATION - l \ l l 3.7.9 The main turbine bypass system shall be OPERABLE. l l APPLICABILITY: OPERATIONAL CONDITION 1. ! ACTION: With the main turbine bypass system inoperable, restore the system to UFERIELE 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 REQUIREMENTS i i 4.7.9 The main turbine bypass system shall be demonstrated OPERABLE at least once per:

a. 31 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: 4 a) 80% of turbine bypass system capacity shall be established in less than or equal to 0.3 second.

I b) Bypass valve opening shall start in less than or equal to i 0.1 second. ! i E { j l t t

                                                                                                                      .. 4 0'%

l l HOPE CREEK 3/4 7-33 1

i r - 3/4.8 ELECTRICAL POWER SYSTEMS g a r. . - - [. 3/4.8.1 A.C. SOURCES j _

                                                                      '4  ~ e.t   J A.C. SOURCES - OPERATING LIMITING CONDITION FOR OPERATION

3. 8.1.1 As a minimum, the following A.C. electrical power source's shall be OPERABLE:

a. Two physically independent circuits between the offsite transmission network and the onsite Class 1E distribution system, and

b. Four separate and independent diesel generators, each with:

1. A separate fuel oil day tank containing a minimum of 200 gallons of fuel,

2. A separate fuel storage system consisting of two storage tanks containing a minimum of 48,800 gallons of fuel, and

3. A separate fuel transfer pump for each storage tank.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, and 3. ACTION:

a. 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 Requirement 4.8.1.1.1.a within I hour and at least once per 8 hours thereafter. If any diesel l generator has not been successfully tested within the past 24 hours, demonstrate its OPERABILITY by performing Surveillance Require-ment 4.8.1.1.2.a.4 and 4.8.1.1.2.a.5 for each such diesel generator separately within 24 hours. Restore the inoperable offsite circuit to OPERABLE status within 72 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUT 00WN within the following 24 hours. .

b. With one diesel generator of the above required A.C. electrical power sources inoperable, demonstrate the OPERABILITY of the above required A.C. offsite sources by performing Surveillance Requirement 4.8.1.1.1.a within 1 hour and at least once per 8 hours thereafter. If the diesel generator became inoperable due to any cause other than preplanned preventive maintenance or testing, demonstrate the OPERABILITY of the remaining diesel generators by performing Surveillance Require-ment 4.8.1.1.2.a.4 and 4.8.1.1.2.a.5 separately for each diesel generator within 24 hours *; restore the inoperable diesel generator to OPERABLE status within 72 hours or be in at least HOT SHUTOOWN within the next 12 hours and in COLD SHUTOOWN within the following 24 hours.

c. With one offsite circuit of the above required A.C. sources 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 Requirement 4.8.1.1.1.a wit,hin I hour and

    *This test is required to be completed regardless of when the inoperable diesel generator is restored to OPERABILITY. The provisions of Specification 3.0.2 are not applicable.

HOPE CREEK 3/4 8 1 }$ 'i W.

l

[ l

E

~-

n .e. e - - - ELECTRICAL POWER SYSTEMS '7" f *Nd u f C ..,',, , LIMITING CONDITION FOR OPERATION (Continued) ~""'*-------- I se ACTION: (Continued) at least once 8 hours thereafter. If a diesel generator became inoper-able due to any causes other than preplanned preventive mai~ntenance or testing, demonstrate the OPERABILITY of the remaining OPERABLE diesel generators separately for each diesel generator by performing Surveil-lance Requirement 4.8.1.1.2.a.4 and 4.8.1.1.2.a.5 within 24 hours. E Restore at least two offsite circuits and all four of the above re-quired diesel generators to OPERA 8LE status within 72 hours from time _ of the initial loss or be in at least HOT SHUTOOWN within the next ' 12 hours and in COLD SHUTOOWN within the following 24 hours. '

d. With both of the above required offsite circuits inoperable, demon-strate the OPERABILITY of all of the above required diesel generators by performing Surveillance Requirement 4.8.1.1.2.a.4 and 4.8.1.1.2.a.5 separately for each diesel generator within 8 hours unless the diesel generators are already operating; restore at least one of the above required offsite circuits to OPERA 8LE status within 24 hours or be in at least HOT SHUTOOWN within the next 12 hours. With only one off-site circuit restored to OPERA 8LE status, restore at least two offsite circuits to OPERABLE status within 72 hours from time of initial loss or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours. A successful test (s) of diesel generator OPERA 8ILITY per Surveillance Requirement 4.8.1.1.2.a.4 and 4.8.1.1.2.a.5 performed under this ACTION statement for the OPERA 8LE diesel generators satisfies the diesel generator test requirements ,

of ACTION statement a. j e With two diesel generators of the above required A.C. electrical power sources inoperable, demonstrate the OPERASILITY of the above required A.C. offsite sources by performing Surveillance Requirement 4.8.1.1.1.a within 1 hour and at least once per 8 hours thereaf ter and demonstrate the OPERABILITY of the remaining diesel generators by performing Sur-veillance Requirement 4.8.1.1.2.a.4 and 4.8.1.1.2.a.5 separately for , each diesel generator within 8 hours." Restore at least one of the inoperable diesel generators to OPERA 8LE status within 2 hours or be , in at least HOT SHUT 00WN within the next 12 hours and in COLD SHUTDOWN ' within the following 24 hours. Restore both of the inoperable diesel 4 generators to OPERA 8LE status within 72 hours from time of initial loss or be in at least HOT SHUTOOWN within the next 12 hours and in

COLD SHUT 00WN within the following 24 hours.

f. 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 SHUT-DOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours. * "This test is required to be completed regardless of when the inoperable diesel g generator is restored to OPERABILITY. The provisions of Specification 3.0.2 are not applicable. HOPE CREEK 3/4 8-2 0%

l ELECTRICAL POWER SYSTEMS i $00f [~'f.'ir_ {ll'.F(( LIMITING CONDITICN FOR OPERATION (Continued) ' l ACTION: (Continued)

g. With one offsite circuit and two diesel generators of the above re-quired A.C. electrical power sources inoperable, demonstrate the OPERABILITY of the remaining A.C. sources by performing Surveillance Requirement 4.8.1.1.1.a within 1 hour and at least once per 8 hours thereafter and demonstrate the OPERA 81LITY of the remaining diesel generators by performing Surveillance Requirements 4.8.1.1.2.a.4 and 4.8.1.1.2.a.5 separately for each diesel generator within 8 hours.

Restore at least one of the above required inoperable A.C. sources to OPERABLE status within 2 hours or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours, j Restore the inoperable offsite circuit and both of the inoperable diesel generators to OPERABLE status within 72 hours from time of initial loss or be in at least HOT SHUTDOWN within 12 hours and in COLD SHUTDOWN within the following 24 hours. l i l 1 i "This test is required to be completed regardless of when the inoperable diesel generator is restored to OPERABILITY. The provisions of Specification 3.0.2 are not applicable. HOPE CREEK 3/4 8-3 , ug

l - l l m .~. . .. ; _ ( "' . 4 - ELECTRICAL POWER SYSTEMS Il5VW" ' I

                                                                                                                                                               = . . . . . .
                                                                                                                                                                                   . . . _ _               j SURVEILLANCE REQUIREMENTS 4.8.1.1.1 Each of the above required independent circuits between' the offsite transmission network and the onsite Class IE 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 sonths 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 1

OPERA 8LE: I a. In accordance with the frequency specified in Table 4.8.1.1.2-1 on a STAGGERED TEST BASIS by: l

1. Verifying the fuel level in the fuel oil day tank.

2. Verifying the fuel level in the fuel oil storage tank.

3. Verifying the fuel transfer pump starts and transfers fuel from the storage system to the fuel oil day tank.

4. Verifying the diesel starts from ambient conditions

and accel-i erates to at least 514 rpm in less than or equal to 10 seconds a

after receipt of the start signal. The genes. tar voltage and ; frequency shall be 4160 t 420 volts and 60 1 1.2 Hz within '

 .                                                                                                        10 seconds after receipt of the start signal. The diesel I

generator shall be started for this test by using one of the following signals: a) Manual.** I b) Simulated loss of offsite power by itself, c) Simulated loss of offsite power in conjunction with an ESF i actuation test signal. d) An ESF actuation test signal by itself. I 5. Verifying the diesel generator is synchronized, loaded to greater than or equal to 4430 kw in less than or equal to 130 seconds, and operates with this load for at least 60 minutes.

          "The diesel generator start (10 sec) and subsequent loading (130 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.
       **!f diesel generator started manually from the control room, 10 seconds after the automatic prelube period.

I trr ,. HOPE CREEK 3/4 8-4 *

p. ;

yy,p p. ~.. ELECTRICAL POWER SYSTEMS i

                                                                     ' " ' ' {'      _l SURVEILLANCE REQUIREMENTS (Continued)

6. Verifying the diesel generator is aligned to provide standby power to the associated emergency busses.

7. Verifying the pressure 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 I hour by checking for and removing accumulated water from the fuel oil day tank,

d. At least once per 92 days by removing accumulated water from the fuel oil 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 viscosity 9 40'C of greater than or equal to 1.9 centistokes, but less than or equal to 4.1 centistokes or a Saybolt Second Universal (ssu) viscosity at 100'F of greater than or equal to 32 ssu but less than or equal to 45 ssu. c) A specific gravity as specified by the manufacturer as API gravity 9 60'F of greater than or equal to 28 Jegrees but less than or equal to 42 degrees.

2. Within one week after obtaining the sample, verify ar impurity level of less than 2 mg of insolubles per 100 ml. when tested in accordance with ASTM-02274-70.

HOPE CREEK 3/4 8-5 'P5 i

                                                                    .--9..        , _

ELECTRICAL POWER SYSTEMS ! rL 0 0" b SURVEILLANCE REQUIREMENTS (Continued)

3. Within two weeks after obtaining the sample, verify that the other properties specified in Table 1 of ASTM-0975-77 and 3

Regulatory Guide 1.137, Position 2.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 1 420 volts and frequency at 60 1 3.0 Hz.

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. , $1mulating a loss of offsite power by itself, and:

a) Verifying loss of power is detected and 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 after receipt of the start signal, energizes the autoconnected shutdown loads through the load sequencer and operates for greater than or equal to 5 minutes while its generator is loaded with the shutdown loads. After energization, the steady state voltage and frequency of the energency busses shall be maintained at 4160 2 420 volts and 60 2 1.2 Hz during this test.

   *The diesel generator start (10 sec) and subsequent loading (130 see) from              l 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 other warmup procedures recommended by the manufacturer so that mechanical stress and wear on the diesel engine is minimized.                 ' '~
   #For any start of a diesel generator, the diesel must be operated with a load in accordance with the manufacturer's recommendations, t                                                                                           i 1

i HOPE CREEK 3/4 8-6 i

__ . - ~ - _ _ _ _ _ _ ._ l 1 i

i ELECTRICAL POWER SYSTEMS U.v . .

                                                                                                     ,s
                                                                                                             . .    . . .   ...i
                                                                                                                                 'I SURVEILLANCE REQUIREMENTS (Continued)

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 1 420 volts and 60 1 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.
,                                           6.         Simulating a loss of offsite power in conjunction with an ECCS actuation test signal, and:

a) Verifying loss of power is detected and deenergization of the emergency busses and load shedding from the emergency j busses. I b) Verifying the diesel generator starts

on the auto-start I

 !                                                             signal, energizes the emergency busses with permanently connected loads within 10 seconds after receipt of the start signal, energizes the autoconnected 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 frenuency of the emergency busses shall be main-tained at 4160 1 420 volts and 60 1 1.2 Hz during this test.

l 7. Verifying that all automatic diesel generator trips, except engine overspeed, generator differential current, generation i overcurrent, bus differential current and low lube oil pressure are automatically bypassed upon loss of voltage on the emergency bu. concurrent with an ECCS actuation signal.

8. 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 ! *The diesel generator start (10 sec) and subsequent loading (130 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 I 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. SEP :. c . HOPE CREEK 3/4 8-7

ELECTRICAL POWER SYSTEMS p",*1,'1 T g ? ;" '

                                                                                       ~~'-"""t

[l a: 'a SURVEILLANCE REQUIREMENTS (Continued) shall be 4160 1 420 volts and 60 t 1.2 Hz within 10 seconds after the start signal; the steady state generator voltage and frequency shall be maintained within these limits Buring this test. Within 5 minutes after completing this 24-hour test, perform Surveillance Requirement 4.8.1.1.2.h.4.b).**

9. Verifying that the auto-connected loads to each diesel generator do not exceed the continuous rating of 4737 kW.

10. Verifying the diesel generator's capability to:

a) Synchronize with the offsite power source while the generator is loaded with 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, d) Diesel generator circuit breaker is open.

11. 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.

4

12. Verifying that the fuel oil transfer pump transfers fuel oil i from each fuel storage tank to the day tank of each diesel via j the installed cross connection lines.

l

13. Verifying that the automatic load sequence timer is OPERABLE with the interval between each load block within i 10% of its design interval.

14. 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)

   **If Surveillance Requirement 4.8.1.1.2.h.4.b is not satisfactority completed, it is not necessary to repeat the preceding 24 hour test. Instead, the diesel generator may be operated at 4430 kw for one hour or until operating temperature has stabilized, i

1 HOPE CREEK 3/4 8-8

ELECTRICAL POWER SYSTEMS {']ij f, V'I (, , {V SURVEILLANCE REQUIREMENTS (Continued)

1. At least once per 10 years or after any modifications which could affect diesel generator interdependence by starting all diesel generators simultaneously, during shutdown, and verifying that all diesel generators accelerate to at least 514 rpm in less than or equal to 10 seconds.

j. At least once per 10 years by:

1. Draining each fuel 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 6.9.2. Reports of diesel generator 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. r' 1 l HOPE CREEK 3/4 8-9 s Ek6

                                                                                           . g r. ,

TABLE 4.8.1.1.2-1 I- ' I d DIESEL GENERATOR TEST SCHEDULE Number of Failures in Number of Failures in Last 20 Valid Tests

Last 100 Valid Tests
Test Frequency 31 54 Once per 31 days 1 2** 15 Once per 7 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, but determined on a per diesel generator basis.

For the purposes of determining the required test frequency, the previous test failure count may be reduced to zero if a complete diesel overhaul to like new condition is completed, provided that the overhaul including appropriate post-maintenance operation and testing, is specifically approved by the manufacturer and if acceptable reliability has been demonstrated. The reliability criterion shall be the successful completion of 14 consecutive tests,in a single series. Ten of these tests shall be in accordance with the routine Surveillance Require-ment 4.S.1.1.2.a.4 and 4.8.1.1.2.a.5, four tests, in accordance with the 184-day testing reruirement of Surveillance Requirement 4.8.1.1.2.a.4 and 4.8.1.1.2.a.5.

  , If. this criterion is not satisfied during the first series of tests, any alter-nate criterion to be used to transvalue the failure count to zero requires NRC approval.
 **The associated test frequency shall be maintained until seven consecutive failure free demands have been performed and the number of failures in the last 20 valid demands has been reduced to one.                                                                    l l

1

( HOPE CREEK 3/4 8-10 l

ELECTRICAL POWER SYSTEMS _,,,..., n. .; p n . .j

                                                          . . .s. . t .. ..       . .       a3 A.C. SOURCES - SHUTDOWN LIMITING CONDITION FOR OPERATION 3.8.1.2 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:

1. A separate fuel oil day tank containing a minimum of 200 gallons of fuel.

2. A fuel storage system consisting of two storage tanks containing a minimum of 48,800 gallons of fuel.

3. A separate fuel transfer pump for each storage tank.

APPLICABILITY: OPERATIONAL CONDITIONS 4, 5 and *. 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 soon as practical.

b. The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 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. f

   *When handling irradiated fuel in the secondary containment.                                      '

Cfi 5 0 jen HOPE CREEK 3/4 8-11 "

ELECTRICAL POWER SYSTEMS a~an- a t- -

c. .'. nu c..... ...i

(_._... _ 3/4.8.2 D.C. SOURCES D.C. SOURCES - OPERATING LIMITING CONDITION FOR OPERATION 3.8.2.1 As a minimum, the following D.C. electrical power sources shall be OPERABLE:

a. Channel A, consisting of:

1. 125 volt battery 1AD411

2. 125 volt full capacity charger 1AD413 or 1AD414

3. 250 volt battery 100421;

4. 250 volt full capacity charger 100423

b. Channel B, consisting of:

1. 125 volt battery 180411

2. 125 volt full capacity charger 180413 or 180414

3. 250 volt battery 10D431;

4. 250 volt full capacity charger 10D433

c. Channel C, consisting of:

1. 125 volt battery 1CD411

2. 125 volt full capacity charger ICD 413 or ICD 414

3. 125 volt battery ICD 447

4. 125 volt full capacity charger ICD 444

d. Channel D, consisting of:

1. 125 volt battery 10D411

2. 125 volt full capacity charger 100413 or 200414

3. 125 volt battery 100447

4. 125 volt full capacity charger 100444 APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3.

ACTION:

a. With any 125v battery and/or all associated chargers of the above required D.C. electrical power sources inoperable, restore the inoperable channel to OPERABLE status 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. With any 250v battery and/or charger of the above required DC electrical power sources inoperable, declare the associated HPCI or RCIC system inoperable and take the appropriate ACTION required by the applicable Specification. ,

                                                                                      ' N 0 f)3; HOPE CREEK                               3/4 8-12

                                                                                ^
                                                                                                   - - - ~ ~

nmne n n .. . . m . . l ELECTRICAL POWER SYSTEMS bi*NI f i SURVEILLANCE REQUIREMENTS 4.8.2.1 Each of the above required batteries and chargers shall be demon-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

2. Total battery terminal voltage for each 125-volt battery is greater than or equal to 129 volts on float charge and for each 250-volt battery the terminal voltage 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:

l

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 6 ohms, and

4. The battery charger will supply the current listed below at the voltage listed below for at least 4 hours.

CURRENT CHARGER Minimum Voltage (AMPERES) 1A0413, 1A0414 125 200 180413, 18D414 1CD413, 1CD414 1CD444, 10D414 ., 100444, 10D413 100423, 100433 250 50 HOPE CREEK 3/4 8-13 Q? l, g L,,

y e. g. ,; . w~, ELECTRICAL POWER SYSTEMS s ; * ' SURVEILLANCE REQUIREMENTS (Continued)

d. At least once per 18 months, during shutdown, by verifying that either: '

1. The battery capacity is adequate to supply and maintain in OPERABLE status all of the actual emergency loads for the 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 design profile whfie 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 Profile 125 Volt Battery Duration in Amperes Sequence (Minutes) 1AD411 451.1 1 330.4 1 273.0 8 270.4 50 298.1 180 18D411 443.3 1 326.5 1 267.2 8 267.9 30 267.2 20 289.6 180 ICD 411 419.2 1 359.2 1 272.2 58 299.2 180 100411 416.3 1 356.3 1 269.3 58 294.3 180 125 Volt Battery 1C0447 68 60 77 180 100447 73 80

                                                                      ^66 180 250 Volt Battery 100421                                758.1                                 1 42.6                                 7 HOPE CREEK                           3/4 8-14 E; 3 6 g

UV IJAC'O * " {-.. b a f'ys ELECTRICAL POWER SYSTEMS J SURVEILLANCE REQUIREMENTS (Continued) Load Profile (Continued)

Duration in 250 Volt Battery Amperes Sequence (Minutes) 10D421 (Continued) 307.9 1 42.6 41 348.9 1 42.6 7

                                                      . 307.9                                       1 42.6                                    41 348.9                                       1 42.6                                      7 307.9                                       1 42.6                                    41 387.9                                       1 83.6                                    89 10D431                                            197.9                                      1 25.3                                      5 66.3                                       1 25.3                                    17 74.7                                       1 33.7                                   125 33.7                                    60 56.3                                      1 33.7                                    29

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 j signs of degradation or has reached 85% of the service life expected l 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.

HOPE CREEK 3/4 8-15 00 lit 6

                                                                              , - v, a* -,e 5 r ,- - !

l l1 l' t,1 ' TABLE 4.8.2.1-1 BATTERY SURVEILLANCE REQUIREMENTS 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 Above top of Level Indication mark, Indication mark, plates, and < %" above and < %" above and not maximum level maximum level overflowing indication mark (d) indicatior, mark (d) Float Voltage 1 2.13 volts 1 2.13 volts (c) > 2.07 volts Not more than

                                                                                            .020 below the average of all 1 1.195                connected cells Specifig)                  1 1.200(b)                       Average of all         Average of all Gravity                                                     connected cells        connectg) cells
                                                                     > 1.205                1 1.195 (a) Corrected for electrolyte temperature and level.

(b)0r battery charging current is less than 2 ampares when on float charge. (c)May be corrected for average electrolyte temperature. (d) Electrolyte level may exceed 1/4" above maximum level indication mark if an equalizing charge is in progress or an equalizing charge has been completed within the previous 72 hours. (1)For any Category A parameter (s) outside the limit (s) shown, the battery may be considered OPERABLE provided that within 24 hours all the Category 8 measurements are taken and found to be within their allowable values, and provided all Category A and B parameter (s) are restored to within limits within the next 6 days. (2)For any Category 8 parameter (s) outside the limit (s) shown, the battery may be considered OPERABLE provided that the Category B parameters are within their allowable values and provided the Category B parageter(s) are restored to within limits within 7 days. l (3)Any Category B parameter not within its allowable value indicates an inoperable battery. HOPE CREEK 3/4 8-16 'd b 0I g

i i . ELECTRICAL POWER SYSTEMS r n- e a - -

                                                                                                                                                      ! pg]

D.C. SOURCES - SHUTOOWN ... . - ~=

LIMITING CONDITION FOR OPERATION 3.8.2.2 As a minimum, two of the following four channels of the D.C. i electrical power sources system shall be OPERABLE with: l

a. Channel A, consisting of: I

1. 125 volt battery 1AD411 I i 2. 125 volt full capacity charger # 1AD413 or IA0414

) 3. 250 volt battery 100421; j 4. 250 volt full capacity charger 100423 l b. Channel B, consisting of: j 1. 125 volt battery 180411

2. 125 volt full capacity charger # 18D413 or 180414,

3. 250 volt battery 100431; i 4. 250 volt full capacity charger 100433

c. Channel C, consisting of:

1. 125 volt battery ICD 411

2. 125 volt full capacity charger # ICD 413 or ICD 414 l 3. 125 volt battery ICD 447 i

4. 125 volt full capacity charger ICD 444

d. Channel D, consisting of:

1. 125 volt battery 100411 j 2. 125 volt full capacity charger # 100413 or 200414 4

3. 125 volt battery 100447

4. 125 volt full capacity charger 10D444 APPLICA8ILITY: OPERATIONAL CONDITIONS 4, 5 and *.

]i ACTION: . l a. With less than two channels of the above required D.C. electrical power sources OPERA 8LE, suspend CORE ALTERATIONS, handling of

'                                            irradiated fuel in the secondary containment and operations with a potential for draining the reactor vessel.

I b. The provisions of Specification 3.0.3 are not applicable. SURVEILLANCE REQUIREMENTS l 4.8.2.1 At least the above required battery and charger shall be demonstrated , OPERABLE per Surveillance Requirement 4.8.2.1. i L ; 1

                                *When handling irradiated fuel in the secondary containment.                                     **

, #0nly one full capacity charger per battery is required for the channel to be OPERABLE. i HOPE CREEK 3/4 8-17 M l l

ELECTRICAL POWER SYSTEMS 3/4.8.3 ONSITE POWER DISTRIBUTION SYSTEMS , DISTRIBUTION - OPERATING l 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 108410 108450 c) 480 volt A.C. MCCs 108212 108411 10B451 108553 d) 208/120 volt A.C. distribution panels 10Y401(source:108411) 10Y411(source:108451) 10Y501(source:10B553) 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 i 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 10B232 108431 - 108471 108573 d) 208/120 volt A.C. distribution panels 10Y403(source:108431) 10Y413(source:108471) 10Y503(source:108573) HOPE CREEK 3/4 8-18 g

                                                       --- - - . - .             ,,,g       \

ELECTRICAL POWER SYSTEMS LIMITING CONDITION FOR OPERATION (Continued) e) 120 volt A.C. distribution panels 1CJ481 1YF403(source:1CJ481) ICJ482

4. Channel D, consisting of:

a) 4160 volt A.C. switchgear bus 10A404 b) 480 volt A.C. load centers 10B440 108480 c) 480 volt A.C. MCCs 108242 108441 10B481 108583 d) 208/120 volt A.C. distribution panels 10Y404(source:108441) 10Y414(source:108481) 10Y504(source:108583) e) 120 volt A.C distribution panels IDJ481 1YF404(source:1DJ481) 1DJ482

b. D.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 100251

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 100430 100436 b) 125 volt D.C. fuse box 1C0412 1C0448 c) 125 volt D.C. distribution panel ICD 417

4. Channel D, consisting of:

a) 125 volt D.C. switchgear 100440 100446 .

b) 125 volt D.C. fuse boxes 100412 100448 c) 125 volt D.C. distribution panel 10D417 08 t 0 0 79e,r HOPE CREEK 3/4 8-19

3 ~ e, 8 ~ ,

                                                                                                                        .. l ELECTRICAL POWER SYSTEMS
                                                                           ' ""                              ')     8 '
                                                                         - - - - -                                            l 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 within the following 24 hours.

b. With one of the above required 125 volt D.C. distribution system channels 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.

c. With any one of the above required 250 volt D.C. distribution systems not energized, declare the associated HPCI or RCIC system inoperable and apply the appropriate ACTION required by the applicable Specifications.

SURVEILLANCE REQUIREMENTS 4.8.3.1 Each of the above required power distribution system channels shall , be determined energized at least once per 7 days by verifying correct breaker / switch alignment and voltage on the busses /MCCs/ panels. l HOPE CREEK 3/4 8-20

1 1

                                                                                                                                        .._t 7 7. ,. .. -
                                                                                                     . .,                          i n ;gg
                                                                                                              - ' ~ "

ELECTRICAL POWER SYSTEMS DISTRIBUTION - SHUTDOWN LIMITING CONDITION FOR OPERATION 3.8.3.2 As a minimum, 2 of the 4 channels of the power distribution system shall be energized with:

a. A.C. power distribution:

1. Channel A, consisting of:

a) 4160 volt A.C. switchgear bus 10A401 i b) 480 volt A.C. load centers 108410 i 108450 c) 480 volt A.C. MCCs 108212 108411 108451 108553 d) 208/120 volt A.C. distribution panels 10Y401(source:108411)

                                                                                          ,            10Y411(source:108451) 10Y501(source:108553) e)    120 volt A.C. distribution panels                                          1AJ481 1YF401(source:IAJ481) 1AJ482

2. Channel B, consisting of:

a) 4160 volt A.C. switchgear bus 10A402 b) 480 volt A.C. load centers 108420 108460 1 c) 480 volt A.C. MCCs 108222 108421 108461 108563 d) 208/120 volt A.C. distribution panels 10Y402(source:108421) 4 10Y412(source:108461) 10Y502(source:108563) e) 120 volt A.C. distribution panels 1BJ481 1YF402(source:1BJ481) IBJ482

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 10B431 108471 -- 108573 d) 208/120 volt A.C. distribution panels 10Y403(source:108431) 10Y413(source:108471) 10Y503(source:108573) HOPE CREEK 3/4 8-21 50g _ ~ _ _ . - - _ ._ J

+-

ELECTRICAL POWER SYSTEMS I"*** "II J LIMITING CONDITION FOR OPERATION (Continued) 4 e) 120 volt A.C. distribution panels 1CJ481 1YF403(source:1CJ481) ICJ482 l

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) e) 120 volt A.C. distribution panels IDJ481 1YF404(source:1DJ481) 1DJ482

b. D.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

2. Channel B, consisting of:

d a) 125 volt D.C. switchgear 100420 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 100436 i

b) 125 volt D.C. fuse boxes ICD 412 1CD448 c) 125 volt D.C. distribution panel 1C0417

4. Channel D, consisting of:

a) 125 voit D.C. switchgear 100440 100446 b) 125 volt D.C. fuse box 100412 i 1D0448 c) 125 volt D.C. distribution panel 100417 i b ( l%[ HOPE CREEK 3/4 8-22 1___ . - _ _ _ _ - .

I ELECTRICAL POWER SYSTEMS 'l'6 -

                                                                                    .. Y
                                                                              .. '.._    _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 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS ' 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 / switch alignment and voltage on the busses /MCCs/ panels.

 "When handling irradiated fuel in the secondary containment.

HOPE CREEK 3/4 8-23 l

y- _ _ . i

                                                             & . ] $.
                                                                         .I. '. s
                                                                                       " "' ? h   ,

[ *,,, b, ELECTRICAL POWER SYSTEMS - PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES LIMITING CONDITION FOR OPERATION 3.8.4.1 All primary containment penetration conductor overcurrent protective devices shown in Table 3.8.4.1-1 shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:

a. With one or more of the primary containment penetration conductor overcurrent protective devices shown in Table 3.8.4.1-1 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 disconnecting the breaker within 72 hours and verify the inoperable breaker (s) to be disconnected 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 disconnected.

j SURVEILLANCE REQUIREMENTS 4.8.4.1 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 25% of the circuit breakers and performing:

l a) A CHANNEL CALIBRATION of the associated protective relays, and i b) An integrated system functional test which includes simulated automatic actuation of the system and verifying that each relay and associated circuit breakers and overcurrent l control circuits function as designed, c) For each circuit breaker found inoperable during these functional tests, an additional representative sample of at least 25% of all the circuit breakers of^tMe 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 8-24 'U.i 5 0 g;

ELECTRICAL POWER SYSTEMS l ,Ca r, e .

                                                                                                                     .,.....           . , ' _N s
                                                                                                                                                  .. k SURVEILLANCE REQUIREMENTS (Continued) l

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 injecting a current with a value between 150% and 300% of the pickup of the long time delay trip element and a value between 150% and 300% of the pickup of the short time delay trip element, and verifying that the circuit breaker operates within the time delay bandwidth for that current specified by the manufacturer. The instantaneous element shall be tested by injecting a current equal to 120% of the pickup value of the

  !                    element and verifying that the circuit breaker trips instantan-eously with no intentional time delay. Molded case circuit breaker testing shall also follow this precedure except that a

generally no more than two trip elements, time delay and instan-

  ;                    taneous, 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 represen-tative 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 i                     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 i i I HOPE CREEK 3/4 8-25 Sir auEWS

i l -{. '~* ~~ - v ~.. TABLE 3.8.4.1-1 - - - - - PRIMARY CONTAINMENT PENETRATION CONDUCTOR

OVERCURRENT PROTECTIVE DEVICES t: 1. 4160-VOLT CIRCUIT BREAKERS ,

CIRCUIT SYSTEMS OR I BREAKER NO. LOCATION EQUIPMENT POWERED 1AN205 1AN205 Reactor Recirculation Pump 1AP201 IBN205 IBN205 Reactor Recirculation Pump 1BP201 1CN205 1CN205 Reactor Recirculation Pump 1AP201 10N205 10N205 Reactor Recirculation Pump IBP201

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 HF8150 18C-HV-F022 52-451061 108451 IM HFB150 RHR Shutdown Cooling Inboard

,                                                                   TM HFB150          Valve 13C-HV-F009 52-212021                108212                    IM HF8150         RWCU Suction Isolation Inboard TM HF8150          Valve 18G-HV-F001 52-212101                108212                    IM HFB150         Instrument Gas Supply Inboard TM HF8150          Valve 1KL-HV-5152A 52-212181                108212                   IM HF8150          Steam Line Drain Inboard i                                                                    TM HF8150          Valve 1AB-HV-F016 52-212183                 108212                   IM HFB150          Instrument Gas Compressor TM HF8150          Inboard Valve 1KL-HV-5148 52-232061                 108232                   IM HFB150          Supply Header A Shutoff TM HF8150          Valve 1KL-HV-5124A 52-232103                 108232                   IM HF8150          Drywell Equip. Drain Sump

] TM HFB150 Valve 1HB-HV-F019 { 52-232104 108232 IM HFB150 HPCI Warmup Line Isolation TM HF8150 Valve 1FD-HV-F100 i 52-232181 108232 IM HFB150 Chilled Water Loop A Supply TM HFB150 Isolation valve 1GB-HV-953181 52-232182 108232 IM HFB150 Chilled Water Loop A Return TM HFB150 Isolation Valve 1GB-HV-953182 52-232183 108232 IM HFB150 Chilled Water Loop B Supply i TM HFB150 Isolation Valve 1GB-HV-953183 HOPE CREEK 3/4 8-26 tEF 3 C 3

                                                         ;q,e p r.

tl TABLE 3.8.4.1-1 (Continued) - - -- - - .3 PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES

2. 480-VOLT MOLDED CASE CIRCUIT BREAKERS (Continued) ,

CIRCUIT SYSTEMS OR BREAKER NO. LOCATION TYPES EQUIPMENT POWERED 52-232193 108232 IM HF8150 Chilled Water Loop B Return TM HFB150 Isolation Valve IGB-HV-953184 52-232203 108232 IM HF8150 HPCI Pump Turbine Steam TM HFB150 Isolation Valve 1FD-HV-F002 52-242021 108242 IM HF8150 Isolation Closure Signal TM HFB150 Valve 1HB-HV-F003 52-242061 108242 IM HF8150 Supply Header B Shutoff TM HF8150 Valve 1KL-HV-51248 52-242101 108242 IM HFB150 Instrument Gas Header B TM HFB150 Inboard Isolation Valve 1KL-HV-51528 52-242102 108242 IM HFB150 RCIC Steam Supply Isolation TM HFB150 Valve IFC-HV-F007 52-242103 108242 IM HFB150 RCIC Isolation Valve Bypass TM HF8150 IFC-HV-F076 52-242172 108242 IM HF8150 Reactor Recirc Pump Cooling TM HF8150 Isolation 1ED-HV-2554 52-242173 108242 IM HF8150 Reactor Recirc Pump Cooling TM HFB150 Isolation IED-HV-2556 52-252021 10B252 IM HFB150 Drywell Cooler A Fan 1A1V212 TM HF8150 52-252022 108252 IM HF8150 Drywell Cooler B Fan IB1V212 TM HF8150 52-252031 10B252 IM HFB150 Drywell Cooler C Fan IC1V212 TM HF8150 52-252032 108252 IM HF8150 Drywell Cooler D Fan 101V212 TM HF8150 52-252041 108252 IM HFB150 Drywell Cooler E Fan IE1V212 TM HF8150 52-252042 108252 IM HFB150 Drywell Cooler F Fan 1F1V212 TM HFB150 52-252051 108252 IM HF8150 Drywell Coolet t Fan 1G1V212 TM HF8150 52-252052 108252 IM HFB150 Drywell Cooler H Fan 1HIV212 TM HF8150 SEF 3 0 p~er HOPE CREEK 3/4 8-27

j - -

                                                                                                                                 ' r. . .. :                         ;NI TABLE 3.8.4.1-1 (Continued)

I PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES

2. 480-VOLT MOLDED CASE CIRCUIT BREAKERS (Continued) ,

1 CIRCUIT SYSTEMS OR BREAKER NO. LOCATION TYPES EQUIPMENT POWERED l 52-252063 108252 IM HFB150 Drywell Equip Drain Sump Pump TM HFB150 1AP267 52-252064 108252 IM HFB150 Drywell Equip Drain Sump Pump j TM HFB150 1CP267 Feedwater Inlet A Shutoff 4 52-252073 108252 IM HFB150 j TM HFB150 1AE-HV-F011A L ) 52-262021 108262 IM HFB150 Orywell Cooler A Fan 1A2V212

 !                                                                                TM HFB150 52-262022                10B262                     IM HFB150                   Drywell Cooler B Fan 182V212

TM HFB150 52-262031 10B262 IM HFB150 Drywell Cooler C Fan IC2V212 i TM HFB150

;                              52-262032                10B262                     IM HFB150                   Drywell Cooler 0 Fan ID2V212 i                                                                                  TM HFB150
!                              52-262041                108262                     IM HFB150                   Orywell Cooler E Fan 1E2V212                              l l                                                                                  TM HFB150

! 52-262042 108262 IM HFB150 Orywell Coo.ler F Fan 1F2V212 TM HFB150 l 52-262051 108262 IM HFB150 Drywell Cooler G Fan 1G2V212 TM HFB150 ! 52-262052 10B262 IM HFB150 Drywell Cooler H Fan 1H2V212 TM HFB150 l

!                              52-262063                10B262                     IN HFB150                   Drywell Equip Drain Sump Pump                             l TM HFB150                    IBP267                                                    !

52-262064 108262 IM HFB150 Drywell Equip Drain Sump Pump j TM HFB150 10P267 i } 52-253012 108253 IM HFB150 Recirc Pump Motor Hoist 1AH201 I i TM HFB150 Disconnect Switch 1A5204

;                             52-253021                 10B253                     IM HFB150                   Recire Pump 1BP201 Suction 1

TM HFB150 Valve IBB-HV-F023B 1 ! 52-253031 108253 IM HFB150 Recirc Pump 1BP201 Discharge l TM HFB150 Valve IBB-HV-703'1B : ! 52-253053 108253 IM HFB150 Reactor Vessel Head Vent l l TM HFB150 Inboard Isolation 1BB-HV-F001 i l i HOPE CREEK 3/4 6-28 00 %

         .    . _ _ .                                       --          _ _ _ _ _ _ _ . .          ~ - - - - _ - _                               - .- - _ - _                                      _ - _ -                         . _ - - _ _ _ _ .

l --- - ~ ~ . ._ l{,, * ' i..7/ _f

                                                                                                                                                                                               ~~               ^

I TABLE 3.8.4.1-1 (Continued) PRIMARY CONTAINMENT PENETRATION CONDUCTOR l OVERCURRENT PROTECTIVE DEVICES

2. 480-VOLT MOLDE0 CASE CIRCUIT BREAKERS (Continued) ,

CIRCUIT SYSTEMS OR BREAKER NO. LOCATION TYPES EQUIPMENT POWERED

52-253064 108253 IM HFB150 Reactor Vessel Head Vent to 1 TM HFB150 Steam Line IBB-HV-F005 52-263011 108263 IM HFB150 Reactor Vessel Head Vent j TM HFB150 Outboard Isolation 1BB-HV-F002 52-263012 108263 IM HFB150 Recirc Pump Motor Holst IBH201 l

TM HFB150 Disconnect Switch 185204 52-263042 108263 IM HFB150 Main Steam Relief Valve Hoist TM HFB150 10H202 Disconnect Switch 105207 52-263054 108263 IM HFB150 RWCU Recirc Loop A IBG-HV-F100 TM HFB150 4 52-263081 108263 IM HFB150 RPV Bottom Drain Valve TM HFB150 IBG-HV-F101 l 52-263082 108263 IM 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 i 52-264053 108264 IM HFB150 Recirc Pump Discharge Valve

 ,                                                                                                                   TM HFB150                   IBB-HV-F031A 52-264062                                                               108264                    IM HFB150                   Feedwater Inlet Shutoff TM HFB150                   Valve IAE-HV-F011B 52-264071                                                               108264                    IM HFB150                   Reactor Recirc Pump 1AP201 i                                                                                                                    TM HFB150                   Space Heater IA5220 j                   52-264072                                                               108264                    IM HFB150                   Reactor Recirc Pump IBP201

TM HFB150 Space Heater 185220 52-264083 108264 IM HFB150 Recirc Pump A Suction Valve TM HFB150 IBB-HV-F023A l

I i HOPE CREEK 3,4 g.gg

'G%

i

9. - - ..- . __

                                                                               .v-              ,,,,,,,,

l ELECTRICAL POWER SYSTEMS '- -

                                                                                                   --       f MOTOR OPERATED VALVES THERMAL OVERLOAD PROTECTION (Bypassed)

LIMITING CONDITION FOR OPERATION 3.8.4.2 The thermal overload protection of each valve shown in Table 3.8.4.2-1 shall be bypassed continuously or only under accident conditions, as applicable, by an OPERABLE bypass device with the motor starter circuit. 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 applicable, by an OPERABLE 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 4.8.4.2.1 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 bypass device by verifying that the thermal over-load protection is bypassed for those thermal overloads which are continuously bypassed and temporarily placed in force only when the valve motors are under-going 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.

4.8.4.2.2 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. . ,. L.. '. ( li.. HOPE CREEK 3/4 8-30

                                                                  ,    _ - ~       j i  ,
                                                                              '}./ '

l --- - ~~ TABLE 3.8.4.2-1 ' MOTOR OPERATED VALVES THERMAL OVERLOAD PROTECTION BYPASS DEVICE 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-F007A Accident Residual Heat Removal IBC-HV-F0078 Accident Residual Heat Removal 1BC-HV-F007C Accident Residual Heat Removal 1BC-HV-F0070 Accident Residual Heat Removal 1BC-HV-F008 Continuous Residual Heat Removal IBC-HV-F009 Continuous Residual Heat Removal IBC-HV-F010A Continuous Residual Heat Removal 18C-HV-F010B Continuous Residual Heat Removal IBC-HV-F011A Continuous Residual Heat Removal IBC-HV-F011B Continuous Residual Heat Removal IBC-HV-F015A Continuous Residual Heat Removal 1BC-HV-F015B Continuous Residual Heat Removal 1BC-HV-F017A Accident Residual Heat Removal 1BC-HV-F0178 Accident Residual Heat Removal IBC-HV-F017C Accident Residual Heat Removal 1BC-HV-F0170 Accident Residual Heat Removal IBC-HV-F022 Continuous Residual Heat Removal 1BC HV-F023 Continuous Residual Heat Removal IBC-HV-F024A Continuous Residual Heat Removal 1BC-HV-F0248 Continuous Residual Heat Removal IBC-HV-F026A Continuous Residual Heat Removal 1BC-HV-F026B Continuous Residual Heat Removal IBC-HV-F027A Continuous Residual Heat Removal 18C-HV-F027B Continuous Residual Heat Removal 1BC-HV-F040 Continuous Residual Heat Removal 1BC-HV-F048A Accident Residual Heat Removal IBC-HV-F0488 Accident Residual Heat Removal 1BC-HV-F049 Continuous Residual Heat Removal IBC-HV-F052A Continuous Residual Heat Removal IBC-HV-F0528 Continuous Residual Heat Removal IBC-HV-4428 Continuous Residual Heat Removal IBD-HV-F010 Continuous Reactor Core Isolation Cooling IBD-HV-F012 Accident Reactor Core Isolation Cooling 1BD-HV-F013 Accident Reactor Core 1sqJation Cooling IBD-HV-F022 Continuous Reactor Core Isolation Cooling IBD-HV-F031 Accident Reactor Core Isolation Cooling hii 3 0 Iggr HOPE CREEK 3/4 8-31

i..,..'. .. t TABLE 3.8.4.2-1 (Continued) MOTOR OPERATED VALVES THERMAL OVERLOAD PROTECTION BYPASS DEVICE , Continuous or VALVE NUMBER Accident Conditions SYSTEM (S) AFFECTED 1BD-HV-F046 Accident Reactor Core Isolation Cooling 1BE-HV-F004A Accident Reactor Core Spray IBE-HV-F0048 Accident Reactor Core Spray 1BE-HV-F005A Accident Reactor Core Spray IBE-HV-F005B Accident Reactor Core Spray IBE-HV-F015A Continuous Reactor Core Spray IBE-HV-F0158 Continuous Reactor Core Spray IBE-HV-F031A Accident Reactor Core Spray IBE-HV-F031B Accident Reactor Core Spray IBG-HV-F001 Continuous Reactor Water Cleanup 1BG-HV-F004 Continuous Reactor Water Cleanup 1BJ-HV-F004 Accident High Pressure Coolant Injection IBJ-HV-8278 Accident High Pressure Coolant Injection 1BJ-HV-F006 Accident High Pressure Coolant Injection IBJ-HV-F007 Accident High Pressure Coolant Injection IBJ-FV-F008 Continuous High Pressure Coolant Injection IBJ-HV-F012 Accident High Pressure Coolant Injection IBJ-HV-F042 Accident High Pressure Coolant Injection IBJ-HV-F059 Accident High Pressure Coolant Injection 1EA-HV-2198A Continuous Station Service Water 1EA-HV-21988 Continuous Station Service Water IEA-HV-2198C Continuous Station Service Water IEA-HV-21980 Continuous Station Service Water IEA-HV-2355A Continuous Station Service Water 1EA-HV-23558 Continuous Station Service Water IEA-HV-2371A Continuous Station Service Water 1EA-HV-23718 Continuous Station Service Water 1ED-HV-2553 Continuous Reactor Auxiliaries Cooling IEA-HV-2554 Continuous Reactor Auxiliaries Cooling IED-HV-2555 Continuous Reactor Auxiliaries Cooling IEA-HV-2556 Continuous Reactor Auxiliaries Cooling IEE-HV-4652 Continuous Torus Water Cleanup IEE-HV-4680 Continuous Torus Water Cleanup IEE-HV-4681 Continuous Torus Water Cleanup 1EE-HV-4679 Continuous Torus Water Cleanup IEG-HV-2317A Continuous Safety Auxiliaries Cooling IEG-HV-23178 Continuous Safety Auxiliaries Cooling IEG-HV-2321A Continuous Safety Auxiliaries Cooling IEG-HV-23218 Continuous Safety Auxiliaries Cooling IEG-HV-2453A Continuous Safety Auxiliaries Cooling IEG-HV-24538 Continuous Safety Auxiliari,es Cooling 1EG-HV-7922A Continuous Safety Auxiliaries Cooling 1EG-HV-79228 Continuous Safety Auxiliaries Cooling HOPE CREEK 3/4 8-32 M h 0 ;$is

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                                                                                   .I I    e
                                                                     ' ~~

TABLE 3.8.4.2-1 (Continued) MOTOR OPERATED VALVES THERMAL OVERLOAD PROTECTION BYPASS DEVICE , Continuous or VALVE NUMBER Accident Conditions SYSTEM (S) AFFECTED 1FC-HV-F007 Continuous Reactor Core Isolation Cooling IFC-HV-F008 Continuous Reactor Core Isolation Cooling IFC-HV-F045 Continuous Reactor Core Isolation Cooling IFC-HV-F062 Continuous Reactor Core Isolation Cooling 1FC-HV-F076 Continuous Reactor Core Isolation Cooling IFC-HV-F084 Continuous Reactor Core Isolation Cooling 1FD-HV-4922 Continuous High Pressure Coolant Injection 1FO-HV-F001 Accident High Pressure Coolant Injection IFD-HV-F002 Continuous High Pressure Coolant Injection 1FD-HV-F003 Continuous High Pressure Coolant Injection 1FD-HV-F075 Continuous High Pressure Coolant Injection 1FO-HV-F079 Continuous High Pressure Coolant Injection 1FO-HV-F100 Continuous High Pressure Coolant Injection 1GB-HV-9531A1 Continuous Chilled Water 1GB-HV-9531A2 continuous Chilled Water IGB-HV-9531A3 Continuous Chilled Water 1GB-HV-9531A4 Continuous Chilled Water 1GB-HV-953181 Continuous Chilled Water 1GB-HV-953182 Continuous Chilled Water 1GB-HV-953183 Continuous Chilled Water 1GB-HV-953184 Continuous Chilled Water 1GB-HV-9532-1 Continuous Chilled Water 1GB-HV-9532-2 Continuous Chilled Water 1GS-HV-4951 Continuous Containment Atmosphere Control 1GS-HV-4955A Continuous Containment Atmosphere Control 1GS-HV-4955B Continuous Containment Atmosphere Control 1GS-HV-4959A Continuous Containment Atmosphere Control 1GS-HV-49598 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-49838 Continuous Containment Atmosphere Control 1GS-HV-4984A Continuous Containment Atmosphere Control 1GS-HV-49848 Cr tinuous Containment Atmosphere Control 1GS-HV-4974 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 l 5 (, y l HOPE CREEK 3/4 8-33

                                                                                                      }'~~           -
                                                                                                                                   ...                         1

[s* O Y m t *.s I o' TABLE 3.8.4.2-1 (Continued)

                                                                                                                                               . a at MOTOR OPERATED VALVES THERMAL OVERLOAD PROTECTION                                                                         l l

BYPASS DEVICE , Continuous or VALVE NUMBER Accident Conditions SYSTEH(S) AFFECTED i 1GS-HV-5052B Continuous Containment Atmosphere Control 1GS-HV-5053A Continuous Containment Atmosphere Control 1GS-HV-50538 Continuous Containment Atmosphere Control 1GS-HV-5054A Continuous Containment Atmosphere Control 1GS-HV-50548 Continuous Containment Atmosphere Control 1GS-HV-5050A Continuous Containment Atmosphere Control.

!                  IGS-HV-50508                   Continuous                                     Containment Atmosphere Control 1GS-HV-5055A                   Continuous                                     Containment Atmosphere Control 1GS-HV-5055B                   Continuous                                     Containment Atmosphere Control 1GS-HV-5057A                   Continuous                                     Containment Atmosphere Control l                  1GS-HV-50578                   Continuous                                     Containment Atmosphere Control j                   1HB-HV-F003                    Continuous                                     Liquid Radwaste IHB-HV-F004                    Continuous                                     Liquid Radwaste 1HB-HV-F019                    Continuous                                     Liquid Radwaste 1HB-HV-F020                    Continuous                                     Liquid Radwaste IKL-HV-5152A                   Continuous                                     Primary Containment Instrument ql Gas i                   1XL-HV-51528                  Continuous                                      Primary Containment Instrument Gas

. 1KL-HV-5124A Continuous Primary Containment Instrument I Gas IKL-HV-51248 Continuous Primary Containment Instrument Gas . p 1KL-HV-5126A Continuous Primary Containment Instrument Gas 1KL-HV-5126B Continuous Primary Containment Instrument Gas IKL-HV-5147 Continuous Primary Containment Instrument Gas IKL-HV-5148 Continuous Primary Containment Instrument Gas IKL-HV-5162 Continuous Primary Containment Instrument Gas IKL-HV-5172A Continuous Primary Containment Instrument i Gas l IKL-HV-51728 Continuous Primary Containment Instrument Gas IKP-HV-5834A Continuous Main Steam ! IKP-HV-5835A Continuous Main Steam IKP-HV-5836A { Continuous Main Steam

1XP-HV-5837A Continuous Main Steam . !

I ISK-HV-4953 Continuous Plant Leak Detection l 1SK-HV-4957 Continuous Plant Leak Detection t ISK-HV-4981 Continuous Plant Leak Detection ISK-HV-5018 Continuous Plant Leak Detection HOPE CREEK 3/4 8-34 SEPsc k-~ '.

                                                                                       ,.             *.                    t l , , o .n L . .'..        ..e  wti ELECTRICAL POWER SYSTEMS MOTOR OPERATED VALVES THERMAL OVERLOAD PROTECTION (Not Bypassed)

LIMITING CONDITION FOR OPERATION - 3.8.4.3 The thermal overload protection of each valve shown in Table 3.8.4.3-1 shall be OPERABLE. APPLICABILITY: Whenever the motor operated valve is required to be OPERABLE. ACTION: i With the thermal overload protection for one or more of the above required 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). SURVEILLANCE REQUIREMENTS I I 4.8.4.3 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
!    representative sample of at least 25% of all thermal overloads for the above l   required valves.

l i l ) . i HOPE CREEK 3/4 8-35 CE

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TABLE 3.8.4.3-1 _ _ - - - --- MOTOR OPERATED VALVES THERMAL OVERLOAD PROTECTION BYPASS DEVICE ' None or During VALVE NUMBER Manual Operation SYSTEM (S) AFFECTED 1AB-HV-3631A Manual Main Steam 1AB-HV-3631B Manual Main Steam 1AB-HV-3631C Manual Main Steam 1AB-HV-3631D 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 0AP-HV-2073 Manual Condensate Storage & Transfer 1BC-HV-F003A None Residual Heat Removal 1BC-HV-F003B None Residual Heat Removal 1BC-HV-F004A Manual Residual Heat Removal 1BC-HV-F004B Manual Residual Heat Removal 18C-HV-F004C Manual Residual Heat Removal 1BC-HV-F004D Manual Residual Heat Removal 18C-HV-F006A Manual Residual Heat Remo.a1 1BC-HV-F006B Manual Residual Heat Removal 1BC-HV-F016A Manual Residual Heat Removal IBC-HV-F016B Manual Residual Heat Removal 1BC-HV-F021A Manual Residual Heat Removal 1BC-HV-F0218 Manual Residual Heat Removal 1BC-HV-F047A Manual Residual Heat Removal IBC-HV-F047B 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 IBC-HV-4420A Manual Residual Heat Removal IBC-HV-44208 Manual Residual Heat Removal 1BC-HV-4421 Manual Residual Heat Removal IBC-HV-4439 Manual Residual Heat Removal 1BE-HV-F001A Manual Reactor Core Spray 1BE-HV-F0018 Manual Reactor Core Spray 1BE-HV-F001C Manual Reactor Core Spray IBE-HV-F0010 Manual Reactor Core Spray IBF-HV-3800A Manual Control Rod Drive IBF-HV-38008 Manual Control Rod Drive IBF-HV-4005 Manual Control Rod Drive IBG-HV-F034 Manual Reactor Water Cleanup IBG-HV-F035 Manual Reactor Water Cleanup IBG-HV-3980 Manual Reactor Water Cleanup 1BH-HV-F006A Manual Standby Liquid Contrcl a LF S 0 198c HOPE CREEK 3/4 8-36

I

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                                                                        .     % :",,Ia,rn. u1 TABLE 3.8.4.3-1 (Continued)                   --

MOTOR OPERATED VALVES THERMAL OVERLOAD PROTECTION BYPASS DEVICE None or During VALVE NUMBER Manual Operation SYSTEM (S) AFFECTED 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 IBJ-HV-4866 Manual High Pressure Coolant Injection OBN-HV-2069 Manual Refueling Water Transfer IEA-HV-2197A Manual Station Service Water IEA-HV-21978 Manual Station Service Water 1EA-HV-2197C Manual Station Service Water 1EA-HV-21970 Manual Station Service Water 1EA-HV-2203 Manual Station Service Water 1EA-HV-2204 Manual Station Service Water IEA-HV-2207 Manual Station Service Water 1EA-HV-2234 Manual Station Service Water 1EA-HV-2236 Manual Station Service Water IEA-HV-2238 Manual Station Service Water 1EA-HV-2225A Manual Station Service Water 1EA-HV-22258 Manual Station Service Water 1EA-HV-2225C Manual Station Service Water 1EA-HV-2225D Manual Station Service Water 1EA-HV-2346 Manual Station Service Water 1EA-HV-2356A Manual Station Service Water IEA-HV-2356B 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 IEC-HV-46898 Manual Fuel Pool Cooling IED-HV-2598 Manual Reactor Auxiliaries Cooling IED-HV-2599 Manual Reactor Auxiliaries Cooling IEG-HV-2314A Manual Safety Auxiliaries Cooling 1EG-HV-2314B Manual Safety Auxiliaries Cooling 1EG-HV-2320A Manual Safety Auxiliaries Cooling 1EG-HV-2320B Manual Safety Auxiliaries Cooling IEG-HV-2446 Manual Safety Auxiliaries Cooling 1EG-HV-2447 Manual Safety Auxiliaries Cooling 1EG-HV-2452A Manual Safety Auxiliaries Cooling j 1EG-HV-2452B Manual Safety Auxiliaries Cooling 1EG-HV-2491A Manual SafetyAuxiliar(psCooling ; 1EG-HV-2491B Manual Safety Auxiliaries Cooling IEG-HV-2494A Manual Safety Auxiliaries Cooling i i HOPE CREEK 3/4 8-37 0 b I3hi

                                                                                  ...                ~~--~~--

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T yn l TABLE 3.8.4.3-1 (Continued) ~ -- .j MOTOR OPERATED VALVES THERMAL OVERLOAD PROTECTION BYPASS DEVICE '

None or During VALVE NUMBER Manual Operation SYSTEM (S) AFFECTED 1EG-HV-2494B Manual Safety Auxiliaries Cooling 1EG-HV-2496A Manual Safety Auxiliaries Cooling IEG-HV-24968 Manual Safety Auxiliaries Cooling IEG-HV-2496C Manual Safety Auxiliaries Cooling IEG-HV-24960 . Manual Safety Auxiliaries Cooling IEG-HV-2512A Manual Safety Auxiliaries Cooling IEG-HV-2512B Manual Safety Auxiliaries Cooling 1EG-HV-7921A Manual Safety Auxiliaries Cooling IEG-HV-7921B Manual Safety Auxiliaries Cooling IFC-HV-4282 Manual Reactor Core Isolation Cooling 1FC-HV-F060 Manual Reactor Core Isolation Cooling l IFC-HV-F059 Manual Reactor Core Isolation Cooling IFD-HV-F071 Manual High Pressure Coolant Injection 1GH-HV-5543 Manual Radwaste Area Vent 1GS-HV-5741A None Containment Atmosphere Control 1GS-HV-57418 None Containment Atmosphere Control 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 1KL-HV-5160B Manual Primary Containment Instrument Gas 1KP-HV-5829A Manual Main Steam 1KP-HV-5829B Manual Main Steam 1KP-HV-58348 Manual Main Steam 1XP-HV-5835B Manual Main Steam 1KP-HV-5836B Manual Main Steam 1KP-HV-5837B Manual Main Steam

                                                                                    *v                                    j

c. i

                                                                                                  ;t1E HOPE CREEK                        3/4 8-38
                                             .    . - - - - , - -         .-               -       - ~ - - - -       ,

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ELECTRICAL POWER SYSTEMS ^ * ~ -- ._ _j "g . REACTOR PROTECTION SYSTEM ELECTRICAL POWER MONITORING LIMITING CONDITION FOR OPERATION 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 OPERAELE 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 over-voltage, under voltage, and under-frequency protective instrumentation by performance of a CHANNEL CALIBRATION including simulated automatic actuation of the protective relays, tripping logic and output circuit breakers and verifying the following setpoints.

1. Over-voltage 5 132 VAC, (Bus A), 132 VAC (Bus B)

2. Under-voltage 2 108 VAC, (Bus A), 108 VAC (Bus B)

3. Under-frequency 2 57 Hz. (Bus A and Bus B) l HOPE CREEK 3/4 C-39 l

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                                                                  - - ~               'j ELECTRICAL POWER SYSTEMS CLASS 1E ISOLATION BREAKER OVERCURRENT PROTECTIVE DEVICES '

LIMITING CONDITION FOR OPERATION 3.8.4.5 All Class 1E isolation breaker (tripped by a LOCA signal) overcut rent protective devices shown in Table 3.8.4.5-1 shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:

a. With one or more of the overcurrent protective devices shown in Table 3.8.4.5-1 inoperable, declare the affected isolation breaker inoper-able and remove the inoperable circuit breaker (s) from service within 72 hours and verify the inoperable breaker (s) to be disconnected at least once per 7 days thereafter.

b. The provisions of Specification 3.0.4 are not applicable to over-current devices in 480 volt circuits which have the inoperable cir-cuit breaker disconnected.

SURVEILLANCE REQUIREMENTS 4.8.4.5 Each of the Class 1E isolation breaker overcurrent protective devices shown in Table 3.8.4.5-1 shall be demonstrated OPERABLE:

a. At least once per 18 months:

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 s. elected on a rotating basis. Testing of these circuit breakers shall consist of injecting a current with a value equal to between 150% and 300% of the pickup of the short time delay, and verifying that the circuit breaker operates within the time delay band width for that current specified by the manufacturer. The instantaneous element shall be tested by injecting a current equal to 120% of the pickup value of the element and verifying that the circuit breaker trips instantaneously with no intentional time delay. Molded case circuit breaker testing shall also follow this procedure except that generally no more than two trip elements, time delay and instantaneous, will be involved. For circuit breakers equipped with solid state trip devices, the func-tional testing may be performed with use of portable instruments de-signed to verify the time current characteristics and pickup calibra-tion of the trip elements. Circuit breakers found inoperable during j 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 inoperat4e.t.ype shall also be functionally tested until no more failures are found or all circuit breakers of that 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 l prepared in conjunction with its manufacturer's recommendations. HOPE CREEK 3/4 8-40 'Er901995

l TABLE 3.8.4.5-1 . " ' v 'N >

                                                                                       . ..       .-  .a CLASS 1E ISOLATION BREAKER                                        I'" I f f' OVERCURRENT PROTECTIVE DEVICES (BREAKER TRIPPED BY A LOCA SIGNAL)                   -

480 VAC POWER CIRCUIT BREAKERS

1. TYPE AKR-5A-30 Class 1E Circuit Class 1E Breaker No. Bus Non-Class IE Load Description 52-41011 108410 Reactor Auxiliaries Cooling System Pump 1AP209 52-41014 108410 Radwaste and Service Area MCC 108313 52-41024 108410 Reactor Building Supply Air Handling Unit IBVH300 52-42011 108420 Reactor Auxiliaries Cooling System Pump 1BP209 52-42014 108420 Radwaste and Service Area MCC 10B323 52-42024 108420 Reactor Building Exhaust Fan 1BV301 52-43024 10B430 Reactor Building Supply Air Handling Unit ICVH300 52-43014 108430 Control Rod Drive Pump 1AP207 j 52-44014 108440 Control Rod Drive Pump 1BP207 52-44024 108440 Reactor Building Supply Air Handling Unit 1AVH300 52-44034 108440 Radwaste Area Supply Fan OBV316 l

52-45011 108450 Reactor Area MCC 10B252 l 52-45014 108450 Radwaste Area Exhaust Fan OAV305 . , i 52-45024 108450 Emergency Instrument Air Compressor 10K100 la , - HOPE CREEK 3/4 8-41

l . , ,

                                                                                     -- ~          __,

TABLE 3.8.4.5-1 (Continued) e j_ r*" - 480 VAC POWER CIRCUIT BREAKERS

1. Type AKR-5A-30 (Continued) .

Class 1E Circuit Class 1E Breaker No. Bus Non-Class 1E Load Description 52-45034 108450 Reactor Building Exhaust Fan ICV 301 52-46011 108460 Reactor Area MCC 108262 52-46014 108460 Radwaste Area Exhaust Fan OBV305 52-47011 108470 Reactor Area MCC 10B272 52-47014 10B470 Radwaste Area Exhaust Fan OCV305 52-47024 10B470 Radwaste Area Supply Fan 0AV316 52-47031 108470 Technical Support Center MCC 00B474 52-48011 108480 Reactor Area MCC 108282 52-48024 108480 Reactor Building Exhaust Fan 1AV301 480 VAC MOLDED CASE CIRCUIT BREAKERS

1. Type HFB150 Class IE Circuit Class 1E Breaker No. Bus Non-Class 1E Load Description 52-441043 108441 NSSS Computer Inverter 100485 52-451023 108451 Public Address System Inverter 100496 52-471023 108471 Security System Inverter 0A0495

                                                                       -e HOPE CREEK                          3/4 8-42

                                                                                                                            i b' _ s . . u ., , l   *
                                                                                          ~~

ELECTRICAL POWER SYSTEMS ~ _l

 ;    CLASS IE ISOLATION BREAKER OVERCURRENT PROTECTIVE DEVICES LIMITING CONDITION FOR OPERATION 3.8.4.6 All Class 1E isolation breaker primary and backup overcurrent protective devices shown in Table 3.8.4.6-1 shall be OPERABLE.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION:

a. With one or more of the overcurrent protective devices shown in Table 3.8.4.6-1 inoperable, declare the affected system or component inoperable and apply the appropriate ACTION statement for the affected system, and remove the inoperable circuit breaker (s) from service within 72 hours and verify the inoperable breaker (s) to be discon-nected at least once per 7 days thereafter.

Otherwise, be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTOOWN within the following 24 hours,

b. The provisions of Specification 3.0.4 are not applicable to over-current devices in 480 volt circuits which have the inoperable cir-cuit breaker disconnected.

SURVEILLANCE REQUIREMENTS

!    4.8.4.6 Each of the Class IE isolation breaker overcurrent protective devices shown in Table 3.8.4.6-1 shall be demonstrated OPERABLE per Surveillance l   Requirements 4.8.4.5.

i l i

                                                                                                         ' p "sI HOPE CREEK                                        3/4 8-43

TABLE 3.8.4.6-1 , CLASS 1E ISOLATION BREAKER

                                                                           ,' ' - -~ .~

OVERCURRENT PROTECTIVE DEVICES (PRIMARY AND BACKUP CIRCUIT BREAKERS) . 480 VAC Molded Case Circuit Breakers Type HF8150 Class 1E Circuit Breaker No. Location Trip Type

System Equipment Powered 52-212043 108212 TM 208/120 VAC Distribution TM Panel 10Y201 52-222043 10B222 TM 208/120 VAC Distribution TM Panel 10Y202 52-232043 108232 TM 208/120 VAC Distribution TM Panel 10Y203 52-242043 108242 TM 208/120 VAC Distribution TM Panel 10Y204 52-232021 108232 IM Steam Header Downstream Orain 52-232101 108232 TM Isolation Valve 1AB-HV-F071 52-232131 108232 IM MSIV Outboard Seal Gas Supply 52-232102 108232 TM Valve 1KP-HV-5829B 52-232132 108232 IM Main Steam Line A MSIV Outboard 52-232191 108232 TM Seal Gas Supply Valve 1KP-HV-58348 52-232133 108232 IM Main Steam Line 8 MSIV Outboard 52-232192 108232 TM Seal Gas Supply Valve 1KP-HV-58358 52-232141 108232 IM Main Steam Line C MSIV Outboard 52-232194 108232 TM Seal Gas Supply Valve 1KP-HV-5836B 52-232143 108232 IM Main Steam Line D MSIV Outboard 52-232195 108232 TM Seal Gas Supply Valve 1KP-HV-58378 52-242111 108242 IM MSIV Inboard Seal Gas Supply 52-242023 10B242 TM Valve 1KP-HV-5829A

  *IM denotes instantaneous magentic TM denotes thermal magnetic I

SH : s 19cr j HOPE CREEK 3/4 8-44 L

l TABLE 3.8.4.6-1 (Continued) " _[ g- . - ,

-t

t. /'i

              -480 VAC Molded Case Circuit Breakers                                                     N          % ,_

Type HFB150 (Continued) l , Class IE Circuit Breaker No. Location Trip Type

System Equipment Powered 52-242132 10B242 IM Main Steam Line A MSIV Inboard 52-242024 108242 TM Seal Gas Supply Valve 1KP-HV-5834A 52-242133 108242 IM Main Steam Line 8 MSIV Inboard 52-242064 108242 TM Seal Gas Supply Valve IKP-HV-5835A 52-242141 108242 IM Main Steam Line C MSIV Inboard 52-242113 108242 TM Seal Gas Supply Valve 1KP-HV-5836A 52-242143 10B242 IM Main Steam Line D MSIV Inboard 52-242114 108242 TM Seal Gas Supply Valve 1KP-HV-5837A 52-242161 108242 IM RWCU Discharge To Feedwater 52-242214 108242 TM Valve IAE-HV-F039

52-232054 10B232 IM Feedwater Line Cross Tie Isolation i

52-232171 108232 TM Valve 1AE-HV-4144 l

                                                                                                        -F
                                                                                                                       ~
                 *IM denotes instantaneous magnetic TM denotes thermal magnetic HOPE CREEK                                     3/4 8-45

l l g9r r ' . .' . ELECTRICAL POWER SYSTEM - %. _ h'0f{ POWER RANGE NEUTRON MONITORING SYSTEM ELECTRICAL POWER MONITORING LIMITING CONDITION FOR OPERATION . 3.8.4.7 The power range neutron monitoring system (NMS) electric power monitoring channels for each inservice power range NHS power supply shall be OPERABLE. APPLICABILITY: At all times. ACTION:

a. With one power range NMS electric power monitoring channel for an inservice power range NMS power supply inoperable, restore the in-operable power monitoring channel to OPERABLE status within 72 hours or deenergize the associated power range NHS power supply feeder circuit.

b. With both power range NMS electric power monitoring channels for an j inservice power range NHS power supply inoperable, restore at least one electric power monitoring channel to OPERABLE status within 30 minutes or deenergize the associated power range NHS power supply feeder circuit.

SURVEILLANCE REQUIREMENTS 4.8.4.7 The above specified power range NHS electric power monitoring channels shall be determined OPERABLE: l a. At least once per 6 months by performance of a CHANNEL FUNCTIONAL i TEST, and

1

b. At least once per 18 months by demonstrating the OPERABILITY of over-voltage, under-voltage, and under-frequency protective instrumentation by performance of a CHANNEL CALIBRATION including simulated automatic actuation of the protective relays, tripping i logic and output circuit breakers and verifying the following i setpoints, j 1. Over-voltage 1 132 VAC (BUS A), 132 VAC (BUS B)

2. Under-voltage > 108 VAC (BUS A),108 VAC (BUS B)

3. Under-frequency > 57 Hz. -0, +2% - .-

PLS r. e HOPE CREEK 3/4 8-46

M v .. .. 3/4.9 REFUELING OPERATIONS Q_I ' ' I hi 3/4.9.1 REACTOR MODE SWITCH LIMITING CONDITION FOR OPERATION I ! 3.9.1 The reactor mode switch shall be OPERABLE and locked in the Shutdown or Refuel position. When the reactor mode 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 platform position.

3. Refuel platform hoists fuel-loaded.

4. Service platform hoist fuel-loaded.

APPLICABILITY: OPERATIONAL CONDITION 5* # . ACTION:

a. With the reactor mode switch not locked in the Shutdown or Refuel position as specified, suspend CORE ALTERATIONS and lock the reactor mode switch in the Shutdown or Refuel position.

b. With the one-rod-out interlock inoperable, lock the reactor mode switch in the Shutdown position.

I c. With any of the above required Refuel position equipment interlocks I 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 whenever fuel is in the reactor vessel with the vessel head closure bolts less than fully tensioned or with the head removed.
                                                                                             ~

I l l , ', HOPE CREEK 3/4 9-1

     - _ _ . . _ . - -                              _          ___ - _ _           __ _ _  _   _         ~ _   , _ - ,      -

REFUELING OPERATIONS PHUJI 6' .1 l."iiio ru.t' ~ ~''" r)re SURVEILLANCE REQUIREMENTS

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 OPERA 8LE 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 i

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.

1 l l l SEe 3 c gg,,, HOPE CREEK 3/4 9 2

l I REFUELING OPERATIONS Y! '

u. t. . . . . 1. Ly(f 3/4.9.2 INSTRUMENTATION 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. Annunciation and continuous visual indication in the control room,

b. 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

c. Unless adequate shutdown margin has been demonstrated per Specifica-tion 3.1.1,the"shortinglinks"removedfromtheRP)circuitryprior to and during the time any control rod is withdrawn 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 gare connected to the normal SRM circuits.

Not required for control rods removed per Specification 3.9.10,.1,and 3.9.10.2. HOPE CREEK 3/4 9-3 !

qqa-e., . I REFUELING OPERATIONS M3 *

                                                                            -- --        i & b.,( j SURVEILLANCE REQUIREMENTS (Continued)

b. Performance of a CHANNEL FUNCTIONAL TEST: ,

1. Within 24 hours prior to the start of CORE ALTERATIONS, and

2. At least once per 7 days.

c. Verifying that the channel count rate is at least 0.7 cps:a

1. Prior to control rod withdrawal, l 2. Prior to and at least once per 12 hours during CORE ALTERATIONS, j and i

3. At least once per 24 hours.

l

d. Unless adequate shutdown margin has been demonstrated per Specification 3.1.1, verifying that the RPS circuitry " shorting links" have been removed, within 8 hours prior to and at least once per 12 hours during the time any control rod is withdrawn.**

      "Provided signal-to-noise is > 2. Otherwise, 3 cps.
     **Not required for control rods removed per Specification 3.9.10.1 or 3.9.10.2.

HOPE CREEK 3/4 9 4 '14 fpp

{ g , l ~, '7 ~ ~~~ - m iu. . j REFUELING OPERATIONS w: j[,jjf * **H Leu s's

                                                                                                                                                                                                              ;          l 3/4.9.3 CONTROL ROD POSITION i

LIMITING CONDITION FOR OPERATION 4 3.9.3 All control rods shall be inserted.* I

 ,             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. I l SURVEILLANCE REQUIREMENTS i, 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.

i l l

             " Except control rods removed per Specification 3.9.10.1 or 3.9.10.2.

l **See Special Test Exception 3.10.3. J, l )

~ # o i 1...

a HOPE CREEK 3/4 9-5 1

p. ..

l REFUELING OPERATIONS YA0J( ( *'** e s a. .! s, ,/ > '-~~ ., j , 3/4.9.4 DECAY TIME LIMITING CONDITION FOR OPERATION

I 3.9.4 The reactor shall be subcritical for at least 24 hours.
APPLICABILITY: OPERATIONAL CONDITION 5, during movement 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. 4 I I I SURVEILLANCE REQUIREMENTS i 4 J 1 1 t

   4.9.4 The reactor shall be determined to have been suberitical 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.

l l HOPE CREEK 3/4 9-6 )

( , ;-- ' REFUELING OPERATIONS

                                                                                                                                                                               ** ' " 3 '     ...      . ,e )

J ] 3/4.9.5 COMMUNICATIONS i LIMITING CONDITION FOR OPERATION 3.9.5 Direct communication shall be maintained between the control room and ) refueling floor personnel. l APPLICABILITY: OPERATIONAL CONDITION 5, during CORE ALTERATIONS. ACTION: 4 1 When direct communication between the control room and refueling floor i personnel cannot be maintained, immediately suspend CORE ALTERATIONS. 1 1 i I { SURVEILLANCE REQUIREMENTS l

                  4.9.5 Direct communication between the control room and refueling floor                                                                                                                               !

I personnel shall be demonstrated within one hour prior to the start of and j at least once per 12 hours during CORE ALTERATIONS. l 4 e i f I l t 1 1 b# 4 /t l ! HOPE CREEK 3/4 9-7 l

l REFUELING OPERATIONS l (h ' ' ' 2, 3/4.9.6 REFUELING PLATFORM LIMITING CONDITION FOR OPERATION I 1 3.9.6 The refueling platform shall be OPERABLE and used for handling fuel 1 assemblies or control rods within the reactor pressure vessel.

;                 APPLICABILITY:       During handling of fuel assemblies or control rods within the
;                 reactor pressure vessel.

i ACTION: l With the requirements for refueling platform OPERABILITY not satisfied, suspend i use of any inoperable refueling platform equipment from operations involving l the handling of control rods and fuel assemblies within the reactor pressure vessel after placing the load in a safe condition. ' i ; I SURVEILLANCE REQUIREMENTS 4.9.6.1 The refueling platform main hoist used for handling of control rods l j or fuel assemblies within the reactor pressure vessel shall be demonstrated 1 J OPERABLE within 7 days prior to the start of such operations by: ' l I

a. Demonstrating operation of the overload cutoff on the main hoist when l the load exceeds 1200 + 0, -50 pounds.

b. Demonstrating operation of the main hoist uptravel ' stops when uptravel brings the grapple to 8 feet below the platform tracks.

c. Demonstrating operation of the slack cable cutoff on the main hoist when the load is less than 50 t 10 pounds.

i d. Demonstrating operation of the loaded rod block interlock on the main j hoist when the load exceeds 485 t 50 pounds. 1 i e. Demonstrating operation of the redundant loaded interlock on the main ! { hoist when the load exceeds 550 t 50 pounds. l 1 l i 1

                                                                                                   ~ ,.

I HOPE CREEK 3/4 9 8

i W- ... _ t' ~ l i Yt\ Ntir h .' ~-ti' "b.s

                                                                                                                                                                                                                                                                                                     *        % t!

REFUELING OPERATIONS SURVEILLANCE REQUIREMENTS (Continued) l i 4.9.6.2 The refueling platform frame-mounted auxiliary hoist used for handling of control rods within the reactor pressure vessel shall be demonstrated OPERABLE l within 7 days prior to the use of such equipment by: l a. Demonstrating operation of the overload cutoff on the frame mounted l hoist when the load exceeds 500 1 50 pounds.

b. Demonstrating operation of the uptravel mechanical stop on.the frame mounted hoist when uptravel brings the top of active fuel to 8 feet below the platform tracks.

c. Demonstrating operation of the control rod block interlock on the frame mounted hoist when the load exceeds 400 1 50 pounds.

4.9.6.3 The refueling platform monorafi mounted auxiliary hoist used for handling of control rods within the reactor pressure vessel shall be demon-strated OPERABLE within 7 days prior to the use of such equipment by:

a. Demonstrating operation of the overload cutoff on the monorail hoist when the load exceeds 500 1 50 pounds,

b. 9emonstrating operation of the uptravel mechanical stop on the mono-rail hoist when uptravel brings the top of active fuel to 8 feet below the platform tracks.

c. Demonstrating operation of the control rod block interlock on the

                                      ..                                                                                               monorail hoist when the load exceeds 400 1 50 pounds.
                                                                                                                                                                                                                                                                                                        ' 0 9.s-1 h0PE CREEK                                      3/4 9 9

8 l l j ~ ~ ~~_ _,; . _ l _ l, REFUELING OPERATIONS I (~ . . ' ., . .' w

                                                                                    .     .P j          3/4.9.7 CRANE TRAVEL-SPENT FUEL STORAGE POOL i
 ]        LIMITING CONDITION FOR OPERATION                                        -

i 3.9.7 Loads in excess of 1200 pounds shall be prohibited from travel over ! fuel assemblies in the spent fuel storage pool racks unless handled by a single failure proof handling system. APPLICABILITY: With fuel assemblies in the spent fuel storage pool racks. ACTION: i With the requirements of the above specification not satisfied, place the crane [ J load in a safe condition. The provisions of Specification 3.0.3 are not i applicable. , I j . l r SURVEILLANCE REQUIREMENTS i l l j 4.9.7.1 Crane interlocks and physical stops which prevent crane travel with loads in excess of 1200 pounds over fuel assemblies in the spent fuel storage pool ; i racks shall be demonstrated OPERA 8LE within 7 days prior to and at least once j per 7 days during crane operation.

 !       4.9.7.2 The single failure proof load paths of the polar crane shall be i

visually inspected and verified OPERA 8LE within 7 days prior to and at least ] once per 7 days during crane operation. I ? i I

'I j                                                                                                  l
                                                                             =v                    (

i

!                                                                                                  s i

i HOPE CREEK 3/4 9-10 : i

P i--- - . . _ _ P A m

                                                                    #'9 p l       REFUELING OPERATIONS I eague b , $'$h* hhh'g#

i [ 3/4.9.8 WATER LEVEL - REACTOR VESSEL

 !       LIMITING CONDITION FOR OPERATION i

1 3.9.8 At least 22 feet 2 inches of water shall be maintained over the top l of the reactor pressure vessel flange. 1

!        APPLICABILITY:   During handling of fuel assemblies or control rods within the

{ reactor pressure vessel while in OPERATIONAL CONDITION 5 when the fuel assemblies i being handled are irradiated or the fuel assembifes seated within the reactor

 !       vessel are irradiated.

I i ACTION: i

 !       With the requirements of the above specification not satisfied, suspend all I

operations involving handling of fuel assemblies or control rods within the

!        reactor pressure vessel after placing all fuel assemblies and control rods in I

1 a safe condition. i l 4

     .. SURVEILLANCE REQUIREMENTS i

4.9.0 The reactor vessel water level shall be determined to be at least its i minimum required depth within 2 hours prior to the start of and at least once l per 24 hours during handling of fuel assemblies or control rods within the reactor pressure vessel. ] 1 }

9=

l i l l l

                                                                                          ) '. ,,

HOPE CREEK 3/4 9-11 ~

                                                                                 ~ .~ a .          ,

i REFUELING OPERATIONS VgN U ((i,,g * {. I' j 3/4.9.9 WATER LEVEL - SPENT FUEL STORAGE POOL { LIMITING CONDITION FOR OPERATION i 3.9.9 At least 23 feet of water shall be maintained over the top of irradiated ,

fuel assemblies seated in the spent fuel storage pool racks. l l APPLICABILITY: Whenever irradiated fuel assemblies are in the spent fuel storage
pool. !

!      ACTION:
!                                                                                                     i j       With the requirements of the above specification not satisfied, suspend all                   I j       movement of fuel assemblies and crane operations with loads in the spent fuel i

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. t i 1 i i SURVEILLANCE RE00!REMENTS i : l

!      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.

) 1 I i ; i i d 1 1b:. j HOPE CREEK 3/4 9-12 i

t

REFUELING OPERATIONS hyf h (.. . . . .. ,,.,,. .; 3/4.9.10 CONTROL R00 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 OPERA 8LE 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.

f. All fuel loading operations shall be suspended.

APPLI; ABILITY: OPERATIONAL CONDITIONS 4 and 5. j ACTION: i j With the requirements of the above specification not satisfied, suspend removal i of the control rod and/or associated control rod drive mechanism from the core i and/or reactor pressure vessel and initiate action to satisfy the above requirements. i 2 L IBM HOPE CREEK 3/4 9-13

i t .- REFUELING OPERATIONS Yhjf'? *

                                                                                                                                                                                                                                                     'L / a'ij (ll.. !                '

l SURVEILLANCE REQUIREMENTS 4.9.10.1 Within 4 hours prior to the start of removal of a control rod and/or the associated control 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 control rod drive mechanism are reinstalled and the control rod is inserted l in the core, verify that: 1 l

a. The reactor mode switch is OPERA 8LE 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 l t

OPERA 8LE per Specification 3.9.1. I

b. The SRM channels are OPERA 8LE per Specification 3.9.2.

c. The SHUTOOWN MARGIN 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 rod or i 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.

f. All fuel loading operations are suspended.

i 5 j j l } i 1 l , i ) a w 4 f)b' HOPE CREEK 3/4 9-14

l

                                                                                    .. ~~-

REFUELING OPERATIONS ,~. . ~ ~

                                                                                       ,'"..., L',-,~      i MULTIPLE CONTROL ROD REMOVAL 4    '

i LIMITING CONDITION FOR OPERATION i 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 i the following requirements are satisfied untti all control rods and control : rod drive mechanisms are reinstalled and all control rods are inserted in the Core. ' I

a. The reactor mode switch is OPERA 8LE and locked in the Shutdown position l 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 i below. I

b. The source range monitors SRM are OPERA 8LE 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 I four fuel assemblies removed from the core cell, i

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. l

f. All fuel loading operations shall be suspended.

APPLICA81LITY: OPERATIONAL CONDITION 5. ! ACTION: ! i 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. : i f i

98 l

su s t s HOPE CREEK 3/4 9-15

i f REFUELING OPERATIONS hf h f ~'[ ' , + ,

                                                                                                            %[                     *
                                                                                                                                         ~j j                                                         SURVEILLANCE REQUIREMENTS i

I l' 4.9.10.2.1 Within 4 hours prior to the start of removal of control rods and/or control rod drive mechanisms from the core and/or reactor pressure vessel and i at least once per 24 hours thereafter until all control rods and control rod l drive mechanisms are reinstalled and all control rods are inserted in the core, I verify 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 per Specification 3.9.1.

b. The SRM channels are OPERA 8LE 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,

f. All fuel loading operations are suspended.

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.

W HOPE CREEK 3/4 9-16

REFUELING OPERATIONS l In ; )" . . ,, t,,g g 3/4.9.11 RESIDUAL 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:

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 nr 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 REQUIREMENTS 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. A The shutdown cooling pump may be removed from operation for up.tg.2 hours per 8-hour period. Si , ' l HOPE CREEK 3/4 9-17

REFUELING OPERATIONS fg I h , [, LOW WATER LEVEL 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:

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 1 system OPERABLE, within one hour and at least once per 24 hours there-after, demonstrate the OPERABILITY of at least one alternate method 1

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. -

1 j SURVEILLANCE REQUIREMENTS t 4.9.11.2 At least one shutdown cooling mode loop of the residual heat removal j system or alternate method shall be verified to be in operation and circulating .i reactor coolant at least once per 12 hours. l i i 1 l "The shutdown cooling pump may be removed from operation for up to 2 hours per 8-hour period. ., l SEF5(ey; 3 HOPE CREEK 3/4 9-18

3/4.10 SPECIAL TEST EXCEPTIONS pe 8 r

T'w i w Lgf 3/4.10.1 PRIMARY CONTAINMENT INTEGRITY LIMITING CONDITION FOR OPERATION 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. l 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 j place the reactor mode switch in the Shutdown position. I I SURVEILLANCE REQUIREMENTS i

!      4.10.1 The THERMAL POWER and reactor coolant temperature shall be verified to i       be within the limits at least once per hour during low power PHYSICS TESTS.

i I S EF L. 0 y . HOPE CREEK 3/4 10-1 - l

i - . L. PEF 8E..,6..t.ZR l

~"'

SPECIAL TEST EXCEPTIONS 3/4.10.2 ROD SEQUENCE 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 I and 2. ACTION: With the requirements of the above specification not satisfied, verify that the RSCS is OPERABLE per Specification 3.1.4.2. SURVEILLANCE REQUIREMENTS 4.10.2 When the sequence constraints imposed by the RSCS are bypassed, verify:

a. Within 8 hours prior to bypassing any sequence constraints and at least once per 12 hours while any sequence constraint is bypassed:

1. That the rod worth minimizer is OPERABLE per Specification 3.1.4.1,

2. That movement of the control rods from 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 %y a second licensed operator or other technically qualified member of the unit technical staff. )

HOPE CREEK 3/4 10-2 SEP 3 013"c-

kl?.R0 : SPECIAL TEST EXCEPTIONS bus *] 1 3/4.10.3 SHUTOOWN MARGIN DEMONSTRATIONS LIMITING CONDITION FOR OPERATION 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 rod 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 minimizer 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.

t

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 i 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.

1 : i l Sir 3 C jy'c ' l HOPE CREEK 3/4 10-3

b 7* . 'I SPECIAL TEST EXCEPTIONS

N h~ '[# F" f

3/4.10.4 RECIRCULATION LOOPS

                                                                           ~
                                                                                          \

l LIMITING CONDITION FOR OPERATION l 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 su.spended 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, i:nmediately place the reactor mode switch in the Shutdown position.

SURVEILLANCE REQUIREMENTS 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. SEP 3019e5 HOPE CREEK 3/4 10-4

s fnft.': :

                                                             ~vt . . . . . . , .,4 SPECIAL TEST EXCEPTIONS                                          '

p " g 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

~.

r. d$W . . , , SPECIAL T'EST EXCEPTIONS 3/4.10.6 TRAINING STARTUPS , 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. 4 g. SEF 3 0 g HOPE CREEK 3/4 10-6

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3/4.11 RADIOACTIVE EFFLUENTS fg{1,l. }

    '3/4.11.1 LIQUID EFFLUENTS CONCENTRATION I

LIMITING CONDITION FOR OPERATION 3.11.1.1 The concentration of radioactive material released 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. 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. i i j SEF S 0 995 HOPE CREEK 3/4 11-1

l

                                                                                                 ~ N l%~ ..Yi
                                                                                                      $f ? Gk, ; .

W- - ; ' - ' I TABLE 4.11.1.1.1-1 RADIOACTIVE LIQUID WASTE SAMPLING AND ANALYSIS PROGRAM l 1

                                                                                                        - Lower Limit Minimum                                             ofDetectjon Liquid Release            Sampling       Analysis                   Type of Activity                (LLD)

Type Frequency Frequency Analysis (pCi/ml) A. Batch Wgste P P

                                                                                                                  -7 Release             Each Batch     Each Batch                  Principa               5x10 Sample                                                         Emitters} Gama Tanks (3)

I-131 1x10

                                                                                                                  -6 P                     M                 Dissolved and          1x10
                                                                                                                  -5 One Batch /M                                Entrained Gases                   ,

(Gama Emitters) P Q H-3 1x10 Each Batch Composite d 7 Gross Alpha 1x10 P Sr-89, Sr-90 ~8 Q d 5x10 Each Batch Composite Fe-55 1x10

                                                                                                                 -6 B.                                                                                                  -7
  -                 Continuogs                                     M d      Principa} Gama           5x10 Releases                           Composite                 Emitters Station Service        NA Water System                                                                                 -6 (GSW) (If                                                    I-131                    1x10 Contaminated)          W                                                                     -5 M              Dissolved and            1x10 Grab Sample                               Entrained Gases (Gama Emitters) i H-3
                                                                                                                 -5 1x10 NA          Composi e d               Gross Alpha              1x10
                                                                                                                 ~7 I

Q Sr-89, Sr-90 5x10 NA Composite d Fe-55 ^

1x10 -6 l SEF S 01585 HOPE CREEK 3/4 11-2

d N:t M~/

                                                                                   ~ .
                                                                                             ,.[ ,/

i TABLE 4.11.1.1.1-1 (Continued) /t TABLE NOTATION

          *The LLD is defined, for purposes of these specifications, as the, smallest concentration of radioactive material in a sample that will yield a net i

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: 1 4.66 s b 2.22 x 10s . y . exp (-Aat) E V Where: LLD is the "a priori" lower limit of detection as defined above, as microcuries per unit mass or volume, ss is the standard deviation of the background counting rate or of tfie counting rate of a blank sample as appropriate, as counts per minute, j E is the counting efficiency, as counts per disintegration, V is the sample size in units of mass or volume,

 ; ..          2.22 x 10s 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 (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. 'l 1 SEF 3 0199: HOPE CREEK 3/4 11-3 4

may e .. ~ TABLE 4.11.1.1.1-1 (Continued - IN[.I $,}'ste TABLE NOTATION %--

c The principal gamma emitters for which the LLD 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 6f 5 x 10 8 This 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 Semiannual Radioactive Effluent Release Report pursuant to Specification 6.9.1.8. 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 system that has an input flow during the continuous release.

i e .

                                                                                            ~ .-

bia 3 zu mg5 HOPE CREEK 3/4 11-4

RADIOACTIVE EFFLUENTS I h((.y. , 8 DOSE "%u nyff I LIMITING CONDITION FOR OPERATION

3.11.1.2 The dose 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 Ifmited:

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. With the calculated dose from the release of radioactive materials in liquid effluents exceeding any of the above limits, prepare and j 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 j compliance with the above limits. b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable. SURVEILLANCE REQUIREMENTS 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. I

W*

S E ? = 995 HOPE CREEK 3/4 11-5 \

l RADI0 ACTIVE EFFLUENTS %> LIQUID WASTE TREATMENT 007

                                                                        ^"' C' p.
                                                                               ?   *%y Tpf/
                                                                              %, _ - -~/..,           y LIMITING CONDITION FOR OPERATION                                          .

3.11.1.3 The liquid radwaste treatment system shall be OPERABLE and appropriate portions of the system shall be used to reduce the radioactive materials in liquid wastes prior to 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:

a. With radioactive liquid waste being discharged and in excess of the 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 Special Report that includes the following information:

1. Explanation of why liquid radwaste was being discharged without treatment, identification of any inoperable equipment or sub-systems, 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 4.11.1.3.1 Doses due to liquid releases from each reactor unit to UNRESTRICTED AREAS shall be projected at least once per 31 days in accordance with the methodology and parameters in the ODCM. 4.11.1.3.2 The installed liquid radwaste treatment system shall be demonstrated OPERABLE by meeting Specifications 3.11.1.1 and 3.11.1.2. 5:.* c v 1985 i l l HOPE CREEK 3/4 11-6 l

RADIOACTIVE EFFLUENTS 8

                                                                    ,P R $ 1 a ,3., , N LIQUID HOLDUP TANKS NI LIMITING CONDITION FOR OPERATION 3.11.1.4 The quantity of radioactive material contained in any outside temporary tank shall be limited to less than or equal to 10 curies, excluding tritium and dissolved or entrained noble 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 I

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 SE:I'N

RADI0 ACTIVE EFFLUENTS 3/4.11.2 GASEOUS EFFLUENTS py**n!!"*k:/

                                                                                   ~'
                                                                                        'U !

D'.'!)*r

DOSE RATE

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 1

equal to 1500 mrems/yr to any organ. APPLICABILITY: At all 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. 1 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 by obtaining representative samples and performing analyses in accordance with the sampling and analysis program specified in Table 4.11.2.1.2-1. LLr : .

es HOPE CREEK 3/4 11-8

_ TABLE 4.11.2.1.2-1 RADI0 ACTIVE GASEOUS WASTE SAMPLING AND ANALYSIS PROGRAM n

                =                                                   Minimum                                          Lower Limit of h                                 Sampling          Analysis               Type of                   Detection (LLD)*

Gaseous delease Type Frequency Frequency Activity Analysis (pCi/ml) A. Containment PURGE Eac PURGEIC) Each PURGE (c) Principal Gamma Emitters (b) 1x10

                                                                                                                            -4 Grab Sample                                                                -6 M         H-3 (oxide)                       1x10 B. North Plant Vent      M(c),(d)                  g(c)      Principal Gamma Emitters ID)

South Plant Vent Grab Sample H-3 (oxide) 1x10_f 1x10 C. All Release Types ContinuousI ') W II) I-131 1x10

                                                                                                                            -12 as listed in A                           Charcoal and B above.                             Sample U                                ContinuousI ')            W(I)      Principal Gamma EmittersID)       1x10
                                                                                                                            -11

[ Particulate w Sample ContinuousI ') Q Gross Alpha 1x10

                                                                                                                           -II Composite Particulate Sample ContinuousI ')          Q           Sr-89, Sr-90                     1x10
                                                                                                                           -11 Composite                                                                f i                                                                    Particulate Sample ye3 g
                                ,               ContinuousI ') Noble Gas             Noble Gases                      1x10
                                                                                                                           -6             f Monitor          Gross Beta or Gamma                       ,               g El]
                                                                                                                                               . i
                                                                                                                                            &d      '

K: 6 c, l,ef3 o I

r. q

h b t I

N l~ - myj r-f* 4 J f g, v ~ [.' ' { . ' p r .p, j ' r ., I TABLE 4.11.2.1.2-1 (Continued) N TABLE NOTATION (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% 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* 8 LLD = b E V 2.22 x 108 Y exp (-Aat) Where: LLD is the "a priori" lower limit of detection as defined above, as microcuries per unit mass or volume, - s h is the standard deviation of the background counting rate or of 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 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 (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 tne capability of a measurement system and not as an a posteriori (after the fact) limit for a particular measurement. m , k HOPE CREEK 3/4 11-10

I L%.

                                                             / fhl)E f f
                                                                   " '                                              /
                                                                                - . . ! ; - **, "* f .'1,W        j TABLE 4.11.2.1.2-1 (Continuea;      m%                                weg 1

TABLE NOTATIONS (b)The principal gamma emitters for which the LLD specification applies exclusively are the following 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, Tn-65, Mo-99, I-131, Cs-134, Cs-137, Ce-141 and Ce-144 in iodine and particulate releases. This list does not mean that only these nuclides are to be considered. Other gamma peaks that are identifiable, together with those of the above nuclides, shall also be analyzed and reported in the Semiannual Radioactive Effluent Release Report pursuant to Specification 6.9.1.8. (c) 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. (d) 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. (e)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. (f) 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 l effluent activity has not increased more than a factor of 3. l 1 O l& HOPE CREEK 3/4 11-11

s nfs n . .,. . RADIOACTIVE EFFLUENTS Q. ~[~ %.,7 i Q"lEw. , s DOSE - NOBLE GASES LIMITING CONDITION FOR OPERATION 3.11.2.2 The air dose due to noble gases released in gaseous effluents, 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 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 I effluents exceeding any of the above limits, prepare and submit to i the Commission within 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 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 4.11.2.2 Cumulative dose contributions for the current calendar quarter and current calendar year for noble gases shall be determined in accordance with the methodology and parameters in the 00CM at least once per 31 days.

t

9*

I Si.e b 0 g 5 HOPE CREEK 3/4 11-12

RADIOACTIVE EFFLUENTS PR02FS'. g'c 8 th W[ DOSE - IODINE-131, IODINE-133, TRITIUM, AND RADIONUCLIDES IN PARTICULATE FORM LIMITING CONDITION FOR OPERATION 3.11.2.3 The dose to a MEMBER OF THE PUBLIC from iodine-131, iodine-133, tritium, and all radionuclides in particulate form with half-lives greater than 8 days in gaseous effluents 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:

organ and, Less than or equal to 7.5 mrems to any

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 8 days shall be determined in accordance with the methodology and parameters in the ODCM at least once per 31 days. 1 HOPE CREEK 3/4 11-13

~.

RADIOACTIVE EFFLUENTS L, 'I "M "Md, t' ' ' ' 't GASEOUS RADWASTE TREATMENT (~ UF / LIMITING CONDITION FOR OPERATION 3.11.2.4 The GASEOUS RA0 WASTE TREATMENT SYSTEM shall be in operation. APPLICABILITY: 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 4.11.2.4 The readings of the relevant instruments shall be checked every 12 hours when the main condenser air ejector is in use to ensure that the gaseous radwaste treatment system is functioning, l SEP 3 0 g HOPE CREEK 3/4 11-14

RADIOACTIVE EFFLUENTS kOf P. Cm .7 I VENTILATION EXHAUST TREATMENT SYSTEM I "HbL h' [ 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 effluent 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.

i ACTION:

l

a. With radioactive gaseous waste being discharged without treatment 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 applicable.

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 l accordance with the methodology and parameters in the 00CM, 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-i sidered OPERABLE by meeting Specifications 3.11.2.1 and 3.11.2.2 Thd 3.11.2.3. EEF 3 ) w l HOPE CREEK 3/4 11-15 l \

RADI0 ACTIVE EFFLUENTS %.

                                                                                               ~ - -

EXPLOSIVE GAS MIXTURE f'fflilY X,'-.h"2'F1r g c.3 {y LIMITING CONDITION FOR OPERATION . 3.11.2.6 The concentration of hydrogen in the main condenser offgas treatment system shall be limited to less than or equal to 4% by volume. APPLICABILITY: At all times. ACTION:

a. With the concentration of hydrogen in the main condenser offgas treatment system exceeding the limit, restore the concentration to t

 !                      within the limit within 48 hours,

b. With continuous monitors inoperable, utilize grab sampling procedures.

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-toring the waste gases in the main condenser offgas treatment system whenever

   -  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.

l l O g. l l TCP

                                                                                                     ~   O '

l sau HOPE CREEK 3/4 11-16

                                                                      -a-RADIOACTIVE EFFLUENTS                                                        1 1

MAIN CONDENSER L k hhh d LIMITING CONDITION FOR OPERATION 3.11.2.7 The radioactivity rate of noble gases measured at the main condenser air ejector shall be limited to less than or equal to 330 millicuries /sec g after 30 minute decay. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2* and 3*. ACTION: With the radioactivity rate of noble gases at the main condenser air ejector exceeding 330 millicuries /sec after 30 minute decay, restore the radioactivity rate to within its limit within 72 hours or b.e 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 main condenser air ejector shall be continuously monitored in accordance with Specification 3.3.7.11. 4.11.2.7.2 The radioactivity rate of noble gases from the main condenser air ejector (recombiner package) 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 representative sample of gases taken near the discharge of the main condenser air ejector:

a. At least once per 31 days.

b. Within 4 hours following an increase, as indicated by the Offgas Radioactivity Monitor, of greater than 50%, after factoring out increases due to changes in THERMAL POWER level, in the nominal steady-state fission gas release from the primary coolant.

c. The provisions of Specification 4.0.4 are not applicable.

l 1

          *When the main condenser air ejector is in operation.

HOPE CREEK 3/4 11-17 MI

                                                                                                      . - - - __         -A e                                            !

RADIOACTIVE EFFLUENTS DCd* *!" N- - s .,.

                                                                 '8uGb         C. h f ie e' ag(["                             l VENTING OR PURGING LIMITING CONDITION FOR OPERATION                                                  .

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 .

                                                                                   ~v
                                                                                                   ~~~             '

t e,gg HOPE CREEK 3/4 11-18 l _

r -- RADI0 ACTIVE EFFLUENTS w hj

                                                                                                   )) ('7/_
                                                                                                              ?

l 3/4.11.3 SOLID RADIOACTIVE WASTE TREATMENT LIMITING CONDITION FOR OPERATION 3.11.3 Radioactive wastes shall be SOLIDIFIED or dewatered in accordance with the PROCESS CONTROL PROGRAM to meet shipping and transportation requirements during transit, and disposal sita 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, (1) demonstrate by test or analysis l

that the improperly processed waste in each container meets the requirements for transportation to the disposal site and for receipt at the disposal site and (2) take appropriate administrative action to i prevent recurrence.

c. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS 4.11.3 The PROCESS CONTROL PROGRAM shall be used to verify that the properties of the packaged waste meet the minimum stability requirements of 10 CFR Part 61 and other requirements for transportation to the disposal site and rec ('Dt at the disposal site. I i SEF 3 013er l HOPE CREEK 3/4 11-19 1

_ - _ - - - - . - . - - ~ _ . . - . _ - - . . _ - _ - - . _ _ - _ _ - - - . 4 l 7 e r ~ ~- . , , l RADIOACTIVE EFFLUENTS -_ M ah bd 7 3/4.11.4 TOTAL DOSE i LIMITING CONDITION FOR OPERATION l l '

3.11.4 The annual (calendar year) dose or dose commitment to any MEMBER OF THE PUBLIC due to releases of radioactivity and to radiation from uranium fuel cycle sources shall be limited to less than or equal to 25 mrems to the total body or any organ, except the thyroid, which shall be limited to less than or equal to 75 areas.

4 j APPLICA8ILITY: At all times. 1 ACTION: 1 ! a. With the calculated doses from the release of radioactive materials

in liquid or gaseous effluents exceeding twice the limits of Specifi-l 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 '

j contributions from the units including outside storage tanks, etc. to determine whether the above limits of Specification 3.11.4 have i 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- ~

i sequent releases to prevent recurrence of exceeding the above limits and includes the schedule for achieving conformance with the above i limits. This Special Report, as defined in 10 CFR 20.405c, shall t

!                                                 include an analysis that estimates the radiation exposure (dose) to a MEMBER OF THE PUBLIC from uranium fuel cycle sources, including all

! .. effluent pathways ar.J direct radiation, for the calendar year that j includes the release (s) covered by this report. It shall also de-j 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-1                                                ance in accordance with the provisions of 40 CFR Part 190.                                                 Submittal I

of the report is considered a timely request, and a variance is ] granted until staff action on the request is complete.

b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

} !' SURVEILLANCE REQUIREMENTS l' 4.11.4.1 Cumulative dose contributions from liquid and gaseous effluents shall be determined in accordance with Specifications 4.11.1.2, 4.11.2.7,, and 4.11.2.3, and in accordance with the methodology and parameters in the 00CM. ! 4.11.4.2 Cumulative dose contributions from direct radiation from the units l including outside storage tanks, etc. shall be determined in accordance with j the methodology and parameters in the ODCM. This requirement is applicable i only under conditions set forth in Specification 3.11.4, ACTION a. HOPE CREEK 3/4 11-20 SEP 3 01g i

l_*'-- - . - . . . 3/4.12 RADIOLOGICAL ENVIRONMENTAL MONITORING 1 I[1 k h -. * n e-JFL y r , , 3/4.12.1 MONITORING PROGRAM -. i LIMITING CONDITION FOR OPERATION 3.12.1 The radiological environmental monitoring program shall be conducted 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 the level 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 whea averaged over any calendar quarter, 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 (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) + ***> 1.0 reporting level (1) reporting level (2) 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 1 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 Ang, add them to 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.

Ti . HOPE CREEK 3/4 12-1 l

l r - - . . . . _ PROOFe dv ~ . 1 RADIOLOGICAL ENVIRONMENTAL MONITORING _I.(([*" ** -%-

                                                                                                        '8 y

f LIMITING CONDITION FOR OPERATION (Continued) ACTION: (Continued) , The specific locations from which samples were unavailable may then be deleted from the monitoring program. Pursuant to Specifica-tion 6.9.1.8, identify the cause of the unavailability of samples and identify the new iccation(s) for obtaining replacement samples in the next Semiannual Radioactive Effluent Release Report pursuant to Speci-fication 6.0.1.8 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 monitoring samples shall be collected pursuant to Table 3.12.1-1 from the specific locations given in the table and figure (s) in the ODCM, and shall be analyzed pursuant to the requirements of Table 3.12.1-1 and the detection capabilities required by Table 4.12.1-1. 5 a y b6e OV jff HOPE CREEK 3/4 12-2

f TABLE 3.12.1-1 m RADIOLOGICAL ENVIRONMENTAL MONITORING PROGRAM

l

. E m

E Number of Representative Exposure Pathway Samples and Sampling and Type and Frequency and/or Sample gy) i Sample Locations Collection Frequency of Analysis: 1. DIRECT RADIATIONI2) Forty-three routine monitoring Quarterly Gamma dose quarterly.
stations either with two or j more dosimeters placed as i follows

An inner ring of stations, one j in each meteorological sector , in the general area of the SITE BOUNDARY; I R , An outer ring of stations, one i M in each land based meteorological

   <!,                                            sector in the 6- to 8-km range from the site; and The balance of the stations to be placed in special I                                                  interest areas such as popula-

! tion centers, nearby residences, 1 schools, and in one or two E - areas to serve as control I i stations. Ay F.j

) ff vgi

                                                                                                                                                                                 'y.
                       *The number, media, frequency, and location of samples may vary from site to site. This table presents an                                         '

acceptable minimum program for a site at which each entry is applicable. Local site characteristics : .j must be examined to determine if pathways not covered by this table may significantly contribute to an

r individual's dose and should be included in the sample program. f h, at ,

6 [ S l ,N,, %. i

*%d

l l l TABLE 3.12.1-1 (Continued) 5 g RADIOLOGICAL ENVIRONMENTAL MONITORING PROGRAM O h Number of Representative Exposure Pathway Samples and gy) Sampling and Type and Frequency and/or Sample Sample Locations Collection Frequency of Analysis

2. AIRBORNE Radioiodine and Samples from 5 locations. Continuous sampler Radiciodine Cannister:

Particulates operation with sample I-131 analysis weekly. Three samples from close to the collection weekly, or SITE BOUNDARY locations, in more frequently if different sectors, of the highest required by dust Particulate Sampler: calculated annual average ground- loading. Gross beta radioactivity level D/Q. analysisfollogg y filter change; a g One sample from the vicinity of a Gamma isotopic anal.ysis I4) community having the highest cal- of composite (by culated annual average groundlevel location) quarterly. D/Q. One sample from a control location, as for example 15-30 km distant and in the least prevalent wind c direction a CB

3. WATERBORNE !S;Q

a. Surface Ib) One sample upstream. Grab sample saonthly. Gamma isotopic analysis I4) q One sample downstream.

One sample crosstream. monthly. Composite for ,;l ; '

tritium analysis monthly. '

                                                                                                                                                                     ,l y            b. Ground               Samples from one or two sources       Monthly               Gamma isotopicI4) and tritius                       . l l2                                                      only if likely to be  affected I) .                         analysis monthly if ground     l 8

j i o water flow reversal is noted.l ...,

                                                                                                                                                                    - ,l

I !

J 1

TABLE 3.12.1-1 (Continued) RADIOLOGICAL ENVIRONMENTAL MONITORING PROGRAM E N Number of

Representative Exposure Pathway Samples and Sampling and Type and Frequency and/or Sample _ Sample Locations (7) Collection Frequency of Analysis

c. Drinking One sample of each of one to Composite sample I-131 analysis on each three the nearest water sup- over 2-week period (6) composite when the dose plies that could be affected when I-131 analysis calculated for the consump-by its discharge. is performed, monthly tion of the water is g ater composite otherwise than 1 mrem per year. Com-One sample from a control positeforgrossbetaag location. gamma isotopic analyses monthly. Composite for tritium analysis quarterly.

                                    $           d. Sediment      One sample from downstream area               Semiannually           Gamma isotopic analysis f4) g                   from       One sample from upstream area                                        semiannually.

3

                                    '?,                 shoreline  One sample from cross stream area u

4. INGESTION

a. Milk Samples from allking animals in Semimonthly when Gamma isotopic monthlyI4) and three locations within 5 km animals are on I-131 analysis semimonthly distance having the highest dose pasture, monthly at when animals are on pasture; other times potential. If there are none, monthly at other times. -

then, 1 sample from milking animals in each of three areas .]3 2 between 5 to 8 km distant where !e r doses are calculatef8) be greater ' ',4 q than 1 arem per yr. ,

                                        .,                                                                                                                                  '. 3 I'                        One sample from milking animals                                                                              !J at a control location 15-30 km                                                                                  ,

distant, j h] h $s

.l

TABLE 3.12.1-1 (Continued) 5

g RADIOLOGICAL ENVIRONMENTAL MONITORING PROGRAM 2

m p Number of Representative Exposure Pathway Samples and Sampling and Type and Frequency and/or Sample Sample Locations g Collection Frequency of Analysis

b. Fish and One sample of each commercially Sample in season, or Gamma isotopic analysis (*)

Inverte- and recreationally important semiannually if they on edible portions. brates species in vicinity of plant are not seasonal discharge area. One sample of same species in areas not influenced by plant discharge.

c. Food One sample of each principal At time of harvest (9) Gamma isotopic analysis (*)

R

Products class of food products from any on edible portion.

g area that is irrigated by water a in which liquid plant wastes . have been discharged. Samples of three different kinds Monthly when Gamma isotopic I *) 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 saw.pling is not , performed. ., t _s s

                             >          1 sample of each of the similar         Monthly when           Gamma isotopic (*) and I-1 31E . .

1 broad leaf vegetation grown available analysis. , ',., 15-30 km distant if milk

sampling is not performed. !

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                                                                                                                                               4 CO                                                                                                                                      ~,"

O . , 0 * {a G3 y "k I w.y

i - i

                                                                  , " t) r e p . _ " ~~ '- 7 TABLE 3.12.1-1(Continued)fN               W L' rii k s,l ["' "'3*/ [

TABLE NOTATIONS ' -l - (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 irt a table and i figure (s) in the 00CM. Refer to NUREG-0133, " Preparation of Radiological Effluent Technical Specifications for Nuclear Power Plants," October 1978, and to Radiological Assessment Branch Technical Position, Revision 1, November 1979. Deviations are permitted 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 l 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 en 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. l (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 3 U '- W

7,.--....__ non.,- TABLE 3.12.1-1 (Continued) ; b'- -

                                                                               ~ ~ ~ ~

TABLE NOTATION (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 time intervals that are very short relative to the compositing period in order to assure obtaining a representative 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)lf 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 12-8 SEPao g

TABLE 3.12.1-2 5 g REPORTING LEVELS FOR RADI0 ACTIVITY CONCENTRATIONS IN ENVIRONMENTAL SAMPLES y REPORTING LEVELS W Water Airborne Particulate Fish Milk food Products Analysis (pCi/1) or Gases (pCi/m3 ) (pCi/kg, wet) (pC1/1) (pCi/kg, wet) H-3 30,000 Mn-54 1,000 30,000 Fe-59 400 10,000 Co-58 1,000 30,000 Co-60 300 10,000 R

Zn-65 300 20,000 0

4 Zr-Nb-95 400 1-131 2 0.9 3 100 Cs-134 30 10 1,000 60 1,000 Cs-137 50 20 2,000 70 2,000 D*Ti Ba-La-140 200 300 :-$ h

              ,                                                                                                     c.,

1 I

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                                                                                                                      .I
                                                                                                               }     };

J

TABLE 4.12.1-1 II)(2) A DETECTION CAPABILITIES FOR ENVIRONMENTAL SAMPLE ANALYSIS A LOWER LIMIT OF DETECTION (LLD)(3) %' Food Products Sediment Water Airborne Particulate Fish Milk (pCi/kg, wet) (pCi/1) (pCi/kg, wet) (pCi/kg. dry) Analysis (pCi/1) or Gas (pCi/m3 ) gross beta 4 0.01 H-3 3000 15 130 Mn-54 30 260 Fe-59 130 Co-58,60 15 R* 30 260 Zn-65 "o t

   ,'.,   Zr-Nb-95                15 o

1 60 I-131 1 0.07 130 15 60 150 Cs-134 15 0.05 150 18 80 180 Cs-137 18 0.06 - - - - - 15 ,,, Ba-La-140 15 c/

                              )                                                                                                         r 4                                                                                e E *'

[ , 2 s I r .

                                                                                                                              , .         j Q                                                                                                                         .

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n _ __ _ _ _ _ _ _ . _ - O-- - -- '

i m [ _ l . [ t[ QQip TABLE 4.12.1-1 (Continued) " ' - - -.! TABLE NOTATIONS (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 Environmental Operating Report pursuant to Specification 6.9.1.6. (2) Required detection capabilities 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' $ D 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, sbis the standard deviation of the background counting rate or of 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 picocurie, Y is the fractional radiochemical yield, when applicable, A is the radioactive decay constant for the particular radionuclide (sec 3), 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. SU S V iM ! HOPE CREEK 3/4 12-11 l

l r TABLE 4.12.1-1 (Continuec )n%e,- ,1, -,

                                                             ' f e.svg t ",         ^'Ym-       /

TABLE NOTATIONS l-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 (af ter the fact) limit for a particular measurement. Analyses shall b; performed in such a manner that the stated LL0s will be achieved under routine conditions. Occasionally background fluctuations, unavoidable small sample sizes, the presence of interfering nuclides, or other uncontrollable circumstances may render these LLDs unachievable. 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 HOPE CREEK 3/4 12-12 05 i

N. ~ ..

                                                                                                                                      .w .

l RADIOLOGICAL ENVIRONMENTAL MONITORING f*y* E h p ;, *

                                                                                                                                                                      ,.         1 j                                          3/4.12.2 LAND USE CENSUS                                                                                                        '

a i , 1 LIMITING CONDITION FOR OPERATION 3.12.2 A land use census shall be conducted and shall identify within a i distance of 8 km (5 miles) the location in each of the 16 meteorological i sectors of the nearest milk animal, the nearest residerice and the nearest '

!                                        garden

of greater than 50 m2 (500 ft 8) producing broad leaf vegetation, i

 !                                      APPLICABILITY: At all times.

l ACTION: i j a. With a land use census identifying a location (s) that yields a calcu-1 i lated dose or dose commitment greater than the values currently being calculated in Specification 4.11.2.3, identify the new location (s) in i { the next Semiannual Radioactive Effluent Release Report, pursuant to i Specification 6.9.1.7.

l b. With a land use census identifying a location (s) that yields a j I 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 j new location (s) to the radiological environmental monitoring program within 30 days. The sampling location (s), excluding the [ j control station location, having the lowest calculated dose or dose commitment (s), via the same exposure pathway, may be deleted from l this monitoring program after October 31 of the year in which this land use census was conducted. Pursuant to Specification 6.9.1.8, i identify the new location (s) in the next Semiannual Radioactive Effluent Release Report and also include in the report a revised 1 figure (s) and table for the 00CM reflecting the new location (s). 4 1 c. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable, t ] SURVEILLANCE REQUIREMENTS i i 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 j by consulting local agriculture authorities. The results of the land use census shall be included in the Annual Radiological Environmental Operating

4 Report pursuant to Specification 6.9.1.6. l 4 g. f *8 road leaf vegetation sampling of at least three different kinds of vegetation j may be performed at the SITE BOUNDARY in each of two different direction sectors

with the highest predicted D/Qs in lieu of the garden census. Specifications j for broad leaf vegetation sampling in Table 3.12.1-1 Part 4.c., shall be

,                                         followed, including analysis of control samples.                                                                                           ,

HOPE CREEK 3/4 12-13 E 5 ?

l "'o'r RADIOLOGICAL ENVIRONMENTAL MONITORING f#'"dwI[ ' 3/4.12.3 INTERLABORATORY COMPARISON PROGRAM W _ * * *%_,; .. LIMITING CONDITION FOR OPERATION 3.12.3 Analyses shall be performed on radioactive materials supplied as part of an Interlaboratory Comparison Program that has been approved by the Commission. APPLICABILITY: At all times. ACTION: ! a. With analyses not being performed as required above, report the corrective actions taken to prevent a recurrence to the Commission in the Annual Radiological Environmental Operating Report pursuant to Specification 6.9.1.6.

b. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS 4.12.3 The Interlaboratory Comparison Program shall be described in the 00CM. A summary of the results obtained as part of the above required Inter-laboratory Comparison Program shall be included in the Annual Radiological Environmental Operating Report pursuant to Specification 6.9.1.6.

                                                                                          *9 S E.>         ,

HOPE CREEK 3/4 12-14

o _ _ . . _ .... .-._ _ . .m. & __ 2 ___.__m.._4_.w a _ _ _..m.. . _ . . uw_ .-- -_, ____ .m_.u_m_a._ .-.. 2 __ _ . _ . . . i

                                                                                                                                                  %n ,                   .

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3 i 4 i BASES FOR 3 SECTIONS 3.0 AND 4.0 i LIMITING CONDITIONS FOR OPERATION I AND

,                                                                                 SURVEILLANCE REQUIREMENTS b  o e                                                                                                                                                  e f

I i i 4 i l - w t i i 5 "10 i n i I.

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                                                                                                      ~ ~ . -. _            _. ._

_ I i i NOTE The Summary statements contained in this section provide the bases 4 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 i h e.h y - - -w- --- - = 2 - , ,w--s-w---- --- ,,-w---

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. D 3/4.0 APPLICABILITY ~

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BASES The specifications 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 containment hydrogen re-combiner systems to be OPERABLE and provides explicit ACTION requirements 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 must 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 1 safety. These exceptions are stated in the ACTION statements of the appropriate t l specifications. HOPE CREEK B 3/4 0-1

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ML20138A458

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Dear Mr. flitti:

SUBJECT:

Enclosure:

2.0 INTRODUCTION

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ML20138A458

Text

Dear Mr. flitti:

SUBJECT:

Enclosure:

2.0 INTRODUCTION

Navigation menu

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