Text

Proposed Tech Spec Changes Reflecting Pending Issuance of Full Power OL
	ML20199B400
Person / Time
Site:	Hope Creek
Issue date:	06/13/1986
From:	; Public Service Enterprise Group
To:	;
Shared Package
ML20199B390	List: ML20199B386; ML20199B400;
References
	NUDOCS 8606170130
	Download: ML20199B400 (63)
	v • d • e

l ATTACHMENT I TECHNICAL SPECIFICATION 3.8.2.1 DC SOURCES - OPER ATING Action a. of Technical Specification 3/4.8.2.1 requires that with any 125v battery and/or all associated chargers inoperable, the inoperable channel must be restored to OPERABLE status within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or be in HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . This requirement is based on Regulatory Guide 1.93 Section c.5 which states that if the available onsite de supplies are one less than the LCO, power operation may continue for a period that should not exceed two hours. This limitation is based on the de power supply being in a condition where a subsequent single f ailure could render the entire power system inoperable and jeopardize plant safety. The attached change would revise action statements allowing one channel of the de power supply to be inoperable for up to 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months permitting a reasonable time to effect necessary repairs prior to requiring plant shutdown.

For HCGS the de power system consists of four independent de power channels, each provided with its own 125 volt battery supply and either one or two 100% capacity chargers. When one de power supply or-dc power distribution system is out of service three channels are still operable, and therefore, if a single failure is assumed in addition to the inoperable dc power supply or distribution system, a complete loss of de power will not occur. The required functions for operation, safe shutdown, and mitigation of the effects of an accident can be provided by one division of safety equipment from either electrical channels A and C or channels B and D. If the assumed single failure leaves the combination of,either A and C or B and D channels unavailable, the full capability of the remaining division is available.

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8606170130 860613 PDR ADOCK 05000354 P PDR E

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Therefore, postulating a single failure while one of the four. independent channels is inoperable will not result in a complete loss of the power system, and thus the restrictions

. discussed in Regulatory Guide 1.93~do not apply and a longer time to re-energize the channel is justified. Since each of the four de power channels, including the battery supply, is independent and is associated with the corresponding ac power channel, the requirement for availability of both the zu: and de systems is similar, and therefore, the requirement to re-energize the inoperable de channel should be the same as for the ac channel. The requirement to re-energize the de channels should be 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months , which is consistent with the requirement for the corresponding ac power system channel in Technical Specification 3/4.8.3.1.

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ELECTRICAL POWER SYSTEMS 3/4.8.2 0.C. SOURCES D.C. SOURCES - OPERATING LIMITING CONDITION FOR OPERATION 3.8.2.1 As a minimum, the following D.C. electrical power sottces 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 10D421;

4. 250 volt full capacity charger 10D423

b. Channel B, consisting of:

1. 125 volt battery 180411

2. 125 volt full capacity charger.1BD413 or 180414

3. 250 volt battery 10D431;

4. 250 volt full capacity charger 100433

c. Channel C, consisting of:

1. 125 volt battery 1CD411

2. 125 volt full capacity charger 1CD413 or 1CD414

3. 125 volt battery 1C0447

4. 125 volt full capacity charger 1CD444

d. Channel D, consisting of:

1. 125 volt battery 10D411

2. 125 volt full capacity charger 100413 or 100414

3. 125 volt battery 1D0447

4. 125 volt full capacity charger 100444 APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3.

ACTION:

'IONGl

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 withi ours or be in at least H0T SHUTDOWN within i the next 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 .

' llWSELT! :

cg. 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.

HOPE CREEK 3/4 8-12

INSERT POR PAGE 3/4 8- 12 With any one channel A and C 125v battery and/or all associated

- chargers or any one channel B and D 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 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 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 and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

he 9

b 9 5 9-a

I ATTACHMENT II TECHNICAL SPECIFICATION 4.6.5.3.b FILTRATION, RECIRCULATION AND VENTILATION SYSTEM ( FRVS)

AND 4. 7. 2. b CONTROL ROOM EMERGENCY FILTRATION SYSTEM (CREFS)

Surveillance Requirements 4.6.5.3.b and 4.7.2.b require, at least once per 31 days, flow to be initiated from the control room through the HEPA filters and charcoal adsorbers and verification that the subsystem operates for at least 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months with the heater and humidity control instrumentation OPERABLE. The attached change would revise the above two ref erenced surveillances to state "...at least 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months with the heaters on in order to reduce the buildup of moisture on the carbon adsorbers and HEPA filters."

The HCGS filtration systems are operated at least 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months each 31 days with the heaters on, not just with the heaters and the I humidity control instrumentation OPERABLE. This is performed in accordance with the requirements of Regulatory Guide 1.52- 1978,

" Design, Testing and Maintenance Criteria for Post Accident Engineered-Saf ety-Feature Atmosphere Cleanup System Air Filtration and Adsorption Units of Light-Water-Cooled Nuclear Power Plants." Section 4.d of Regulatory Guide 1.52 states that ,

"each ESF atmosphere cleanup train should be operated at least 10 l hours per month, with the heaters on (if so equipped), in order to reduce the buildup of moisture on the adsorbers and HEPA filters." Operating the system for 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months with the heaters and the humidity control instrumentation OPERABLE will not ensure the

heaters are on and therefore, will not ensure the buildup of

! moisture on the adsorbers and HEPA filters is reduced. Turning the heaters on will verify the operation of the humidity control instrumentation. Therefore, this change will remove confusion

' with respect to the heaters and humidity control instrumentation being OPERABLE and ensure compliance with Section 4.d of Regulatory Guide 1.52 by requiring the heaters to be on and not just OPERABLE.

CONTAINMENT SYSTEMS FILTRATION, RECIRCULATION AND VENTILATION SYSTEM (FRVS)

LIMITING CONDITION FOR OPERATION 3.6.5.3 Five FRVS recirculation units and two FRVS ventilation units shall be OPERABLE.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3 and *.

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 the next 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 .

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 reactor vessel. The provisions of Speci-fication 3.0.3. are not applicable.

SURVEILLANCE REQUIREMENTS 4.6.5.3 Each of the six FRVS recirculation and two ventilation units shall be demonstrated OPERABLE:

a. At least once per 14 days by verifying that the water seal bucket traps have a water seal and making up any ev40Scative losses by fil-ling the traps to the overflow.

b. At least once per 31 days by initiating, from the control room, flow through the HEPA filters and charcoal adsorbers and veri _fying that the ggI subsystem operates for at least 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months with the heater"-" '" "'

lity centrol instr = ntatica CPER^.SLE.i p r

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 6-51

PLANT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) through the HEPA filters and charcoal adsorbers and verifying that (l> N I i

the subsystem operates for at least 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months with the heaters M p

( heidity dentrol instr =entation OPERASLE.)f '

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 tssting acceptance criteria of less than 0.05% and uses the test procedure guidance in Regulatory Positions C.5.a, C.S.c and C.S.d of Regulatory Guide 1.52, Revision 2, March 1978, and the system 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 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; 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 hours0.00833 days 0.2 hours 0.00119 weeks 2.7396e-4 months 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 humidity of 70% in accordance with l ATSM D3803 with a 4 inch bed.

e. At least once per 18 months by: ,, ,

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1. Verifying that the pressure drop across the c6mbined HEPA filters and charcoal adsorber banks is less than 7.5 inches Water 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 mode actuation test signals, the subsystem automatically switches to the isolation mode of operation and the isolation dampers close within 5 l seconds:

HOPE CREEK 3/4 7-7

INSERT FOR PAGES 3/4 6-51 AND 3/4 7-7 on in order to reduce the buildup of moisture on the carbon adsorbers and HEPA filters.

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ATTACHMENT III

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INDEX The'HCGS Technical Specifications Index does not include references to the Tables and Figures contained within the document. The attached' change would include the Tables and

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Figures in the Index in order to enhance the Index and make the Technical Specifications.an easier document to use.

a ,+

INDEX SAFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGS SECTION PAGE 2.1 SAFETY LIMITS THERMAL POWER, Low Pressure or Low Flow................... 2-1 THERMAL POWER, High Pressure and High F1cw................ 2-1 Reactor Coolant System Pressure........................... 2-1 Reactor Vessel Water Level................................ 2-2 2.2 LIMITING SAFETY SYSTEM SETTINGS Reactor Protection System Instrumentation Setpoints....... 2-3

, L l sugar.11 BASES 2.1 SAFETY LIMITS THERMAL POWER , Low Pressure or Low Flow. . . . . . . . . . . . . . . . . . . B 2-1 THERMAL POWER, High Pressure and High Flow................

B 2-2

((Af/qEr 2Ll Reactor Coolant System Pressure........................... B 2-5 Reactor Vessel Water Level.................. ............. B 2-5 2.2 LIMITING SAFETY SYSTEM SETTINGS Reactor Protection System Instrumentation Setpoints........ B 2-6 l

HOPE CREEK iv l

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE 3/4.0 APPLICABILITY............................................. 3/4 0-1 3/4.1 REACTIVITY CONTROL SYSTEMS 3/4.1.1 SHUTDOWN MARGIN............................... ........ 3/4 1-1 3/4.1.2 REACTIVITY AN0MALIES................................... 3/4 1-2 3/4.1.3 CONTROL RODS Control Rod Operability................................ 3/4 1-3 Control Rod Maximum Scram Insertion Times.............. 3/4 1-6 Control Rod Average Scram Insertion Times.............. 3/4 1-7

.- Four Control Rod Group Scram Insertion Times........... 3/4 1-8 Control Rod Scram Accumulators......................... 3/4 1-9 Control Rod Drive Coupling............................. 3/4 1-11 -

Control Rod Position Indication........................ 3/4 1-13 Control Rod Drive Housing Support...................... 3/4 1-15 3/4.1.4 CONTROL R0D PROGRAM CONTROLS Rod Worth Minimizer.................................... 3/4 1-16 Rod Sequence Control System............................ 3/4 1-17 Rod Block Monitor...................................... 3/4 1-18 3/4 1-19 Larszrr- 31 3/4.1.5 STANDBY LIQUID CONTROL SYSTEM..........................

3-3/4.2 POWER DISTRIBUTION LIMITS .

(n49EErr 41 3/4.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE............. 3/4 2-1 3/4 2.2 APRM SETP0lNTS,......................................... 3/4 2-7 DxtsPJ- Est 3/4.2.3 MINIMUM CRITICAL POWER RATI0........................... 3/4 2-8 3/4.2.4 LINEAR HEAT GENERATION RATE................... ........ 3/4 2-12 HOPE CREEK v

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE 3/4.3 INSTRUMENTATION llN 61x 3/4.3.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION............ 3/4 3-1 fin 5Gta- H 3/4.3.2

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ISOLATION ACTUATION INSTRUMENTATION.................. 3/4 3-9

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3/4.3.3 EMERGENCY CORE COOLING SYSTEM ACTUATION

\lOTRT- 9 I 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 f W eT cl Instrumentation...................................... 3/4 3-45 REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION f msser

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il )3/4.3.5 INSTRUMENTATION...................................... 3/4 3-51

= , ..

1MFPr '

IM 3/4.3.6 CONTROL R0D BLOCK INSTRUMENTATION.................... 3/4 3-56 3/4.3.7 MONITORING INSTRUMENTATION !

l IIM5T 33I Radiation Monitoring Instrumentation................. 3/4 3 busegr #4l Seismic Monitoring Instrumentation................... 3/4 3-68 gg ,g MehrologicalMonitoringInstrumentation............ 3/4 3-71 Remote Shutdown Monitoring Instrumentation and

,g g , Controls............................................. 3/4 3-74 Acc,ident Monitoring Instrumentation.................. 3/4 3-84 (w.I=Er R l -

Source Range Monitors................................ 3/4 3-88 Traversing In-Core Probe System...... ............... 3/4 3-89 liuS=12r 16 i, Fire Detection Instrumentation.......................

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3/4 3-90 Loose-Part Detection System........................ . 3/4 3-98 Radioactive Liquid Effluent Monitorir.g Instrumentation......................................

C 3/4 3-99 llW.E W 19l Radioactive Gaseous Eff1sent Monitoring Instrumentation...................................... 3/4 3-104 II>rser 2oi =

3/4.3.8 TURBINE OVERSPEED PROTECTION SYSTEM.................. 3/4 3-111 3/4.3.9 FEEDWATER/ MAIN TURBINE TRIP SYSTEM ACTUATION jgg , INSTRUMENTATION...................................... 3/4 3-113 HOPE CREEK vi

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE 3/4.4 REACTOR COOLANT SYSTEM 3/4.4.1 RECIRCULATION SYSTEM

, Recirculation Loops.................................. 3/4 4-1

. IW59ET 22. =

' i Jet Pumps............................................ 3/4 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 Va1ves................................. 3/4 4-7' Safety / Relief Valves Low-Low Set Function............ 3/4 4-9 ,

3/4 4.3 REACTOR COOLANT SYSTEM LEAKAGE Leakage Detection Systems............................ 3/4 4-10 Operational Leakage.................................. 3/4 4-11

[lkVEPI23\ -

3 /4.4.4 CHEMISTRY............................................ 3/4 4-15 lurer an =

SPECIFIC ACTIVITY.................................... 3/4 4-18

/IGEr 17) 3/4.4.5 e 3/4.4.6 PRESSURE / TEMPERATURE LIMITS Reactor Coolant System............................... 3/4 4-21 Reactor Steam Dome................................... 3/4 4-25 3/4.4.7 MAIN STEAM LINE ISOLATION VALVES..................... 3/4 4-26 3/4.4.8 STRUCTURAL INTEGRITY................................. 3/4 4-27 3/4.4.9 RESIDUAL HEAT REMOVAL Hot Shutdown......................................... 3/4 4-28 Cold Shutdown. ........'.............................. 3/4 4-29 3/4.5 EMERGENCY CORE COOLING SYSTEMS 3/4.5.1 ECCS - 0PERATING..................................... 3/4 5-1 3/4.5.2 ECCS - SHUTD0WN....................... .............. 3/4 5-6 3/4.5.3 SUPPRESSION CHAMBER.................................. 3/4 5-8 HOPE CREEK -

vii

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE 3/4.6 CONTAINMENT SYSTEMS 3/4.6.1 PRIMRY CONTAINMENT' Primary Containment Integri ty. . . . . . . . . . . . . . . . . . . . . . . . 3/4 6-1 Primary Containment Leakage.......................... 3/4 6-2 Primary Containment Ai r Locks. . . . . . . . . . . . . . . . . . . . . . . . 3/4 6-5 MSIV Sealing System.................................. 3/4 6-7 Primary Containment Structural Integrity. . . . . . . . . . . . . 3/4 6-8 Drywell and Suppression Chamber Internal Pressure. . . . 3/4 6-9

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Drywell Average Ai r Tempera ture. . . . . . . . . . . . . . . . . . . . . . 3/4 6-10 Drywell and Suppression Chamber Purge System......... 3/4 6-11 3/4.6.2 DEPRESSURIZATION SYSTEMS Suppression Chamber.................................. 3/4 6-12 Suppression Pool Spray...............................

3/4 6-15 l Suppression Pool Cooling............................. 3/4 6-16 ~l 3/4.6.3 PRIMARY CONTAINMENT ISOLATION VALVES................. 3/4 6-17

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. hOTRTRl 3/4.6.4 VACUUM RELIEF Suppression Chamber - Drywell Vacuum Breakers. . . . . . . . 3/4 6-43 Reactor Building - Suppression Chamber Vacuum Breakers........................................... 3/4 6-45 3/4.6.5 SECONDARY CONTAINMENT Secondary Containment Integri ty. . . . . . . . . . . . . . . . . . . . . . 3/4 6-47 g 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 4

HOPE CREEK viii

INDEX 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 Station Service Water System......................... 3/4 7-3 Ultimate Heat Sink................................... 3/4 7-5 3/4.7.2 CONTROL ROOM EMERGENCY FILTRATION SYSTEM............. 3/4 7-6 3/4.7.3 FLG0D PROTECTION.'.................................... 3/4 7-9

/poEr 29 3/4.7.4 REACTOR CORE ISOLATION COOLING SYSTEM................ 3/4 7-11 3/4.7.5 SNUBBERS............................................. 3/4 7-13 -

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WEerdol 3/4 7-19 3/4.7.6 SEALED SOURCE CONTAMINATION..........................

3/4.7.7 FIRE SUPPRESSION SYSTEMS Fi re Suppression Water System. . . . . . . . . . . . . . . . . . . . . . . . 3/6 7-21 Spray and/or Sprinkler Systems....................... 3/4 7-24 CO Systems.......................................... 3/4 7-26 2

Hal on Sy s tem. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3/4 7- 27 i

Fire Hose Stations................................... 3/4 7-28 lNSERT 31 i =

3/4.7.8 FIRE RATED ASSEMBLIES................................ 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. Source s-dpe rati ng. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3/4 8-1 lW:ERT 32.,, =

A.C. Sources-SIutdown................................ 3/4 8-11 3/4.8.2 D.C. SOURCES D. C. Source s-0pe rati ng. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3/4 8-12 flMSERr 33,i =

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

HOPE CREEK ix

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE ELECTRICAL POWER SYSTEMS (Continued) 3/4.8.3 ONSITE POWER DISTRIBUTION SYSTEMS

Di s tri bu ti on - Ope ra t i ng., . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3/4 8- 18 Distribution - Shutdown.............................. 3/4 8-21 3/4.8.4 ELECTRICAL EQUIPMENT PROTECTIVE DEVICE ~

Primary Containment Penetration Conductor Overcurrent Protective 0evices................................. 3/4 8-24 IVSRT 34 =

Motor Operated Valve Thermal Overload Protection (Bypassed)......................................... 3/4 8-30

'liN5GRr M Motor Operated Valve Thermal Overload Protection (Not Bypassed)..................................... 3/4 8-38 l W. f R T 3 M Reabtor Protection System Electric Power Monitoring.. 3/4 8-40 Class 1E Isolation Breaker Overcurrent Protection i

i Devices (Breaker Tripped by LOCA Signal)........... 3/4 8-41 1 IGET 3~l i Power Range Neutron Monitoring System Electric Power Monitoring.................,..,................ 3/4 8-44 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 3/4.9.5 COMMUNICATIONS.................. .................... 3/4 9-7 3/4.9.6 REFUELING PLATF.0RM................................... 3/4 9-8 3/4.9.7 CRANE TRAVEL - SPENT FUEL STORAGE P00L............... 3/4 9-10 3//. 9.8 WATER LEVEL - REACTOR VESSEL......................... 3/4 9-11 3/4.9.9 WATER LEVEL - SPENT FUEL STORAGE P00L................ 3/4 9-12 It0PE CREEK x

INDEX BASES SECTION PAGE 3/4.0 AP P L I C AB I LI TY. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B 3/4 0- 1 3/4.1 REACTIVITY CONTROL SYSTEMS 3/4.1.1 SHUTDOWN MARGIN.................................. B 3/4 1-1 3/4.1.2 REACTIVITY AN0MALIES............................. B 3/4 1-1 3/4.1.3 CONTROL R005..................................... B 3/4 1-2 3/4.1.4 CONTROL R0D PROGRAM CONTR0LS..................... B 3/4 1-3 3/4.1.5 STANDBY LIQUID CONTROL SYSTEM.....,.............. ,

B 3/4 1-4

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3/4.2 POWER DISTRIBUTION LIMITS 3/4.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE....................:!..................... B 3/4 2-1 3/4.2.2 APRM SETP0INTS................................... B 3/4 2-2 lMEer 361 =

3/4.2.3 MINIMUM CRITICAL POWER RATI0..................... B 3/4 2-4 3/4.2.4 LINEAR HEAT GENERATION RATE...................... B 3/4 2-5 3/4.3 INSTRUMENTATION 3/4.3.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION........ B 3/4 3-1 3/4.3.2 ISOLATION ACTUATION INSTRUMENTATION.............. B 3/4 3-2 3/4.3.3 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION.............'..................... B 3/4 3-2 3/4.3.4 RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION.................................. B 3/4 3-3 3/4.3.5 REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION........................ B 3/4 3-4 3/4.3.6 CONTROL R0D BLOCK INSTRUMENTATION.................................. B 3/4 3-4 3/4.3.7 MONITORING INSTRUMENTATION Radiation Monitoring Instrumentation............ B 3/4 3-4 HOPE CREEK xiii

INDEX BASES SECTION PAGE INSTRUMENTATION (Continued)

Seismic Monitoring Instrumentation.............. B 3/4 3-4 Meteorological Monitoring Instrumentation....... B 3/4 3-4 Remote Shutdown Monitoric.g 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

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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 FEE 0 WATER / MAIN TURBINE TRIP SYSTEM ACTUATION INSTRUMENTATION............................... B 3/4 3-7

[l N F) =-

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 SPECIFIC 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 RESIDUAL HEAT REM 0 VAL........................... B 3/4 4-6 lidEEr % e HOPE CREEK xiv L

INDEX DESIGN FEATURES SECTION PAGE 5.1 SITE Exclusion Area and Map Defining Unrestricted Area and Site Boundary for Radioactive Gaseous and Liquid Effluents...... 5-1 Low Population Zone........................................ 5-1 5.2 CONTAINMENT Configuration.............................................. 5-1 Design Temperature and Pressure............................ 5-1 Secondary Containment...................................... 5-1 lHWHII -

5.3 REACTOR CORE Fuel Assemblies............................................ 5-4 Control Rod Assemblies..................................... 5-4 ,

5.4 REACTOR COOLANT SYSTEM Design Pressure and Temperature............................ 5-4 Vo1ume..................................................... 5-4 5.5 METEOROLOGICAL TOWER LOCATI0N.............................. 5-4 5.6 FUEL STORAGE Criticality................................................ 5-5 Drainage................................................... 5-5 Capacity....... .,........................................ 5-5 5.7 COMPONENT CYCLIC OR TRANSIENT LIMIT........................ 5-5 -

=

lA) SERT 42]

HOPE CREEK xviii

- INDEX ADMINISTRATIVE CONTROLS SECTION PAGE 6.1 RESP 0NSIBI'ITY............................................

L 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 6.5 REVIEW AND AUDIT.......................................... 6-6 ,

s 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 AUTH0RITY............................................ 6-9 REC 0RDS.............................................. 6-9 6.5.2 NUCLEAR SAFETY REVIEW (NSR).......................... 6-9 FUNCTION ............................................ 6-9 COMPOSITION ......................................... 6-9 CONSULTANTS.......................................... 6-10 6-10 0FFSITE SAFET) REVIEW (0SR)..........................

FUNCTION............................................. 6-10 HOPE CREEK xix

e INDEX ADMINISTRATIVE CONTROLS l

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4 HOPE CREEK xxii

INSERT 1 TABLE 2.2.1-1, Reactor Protection System 2-4 Instrumentation Setpoints INSERT-2 TABLE B2.1.2-1, Uncertainties Used in the B 2-3 Determination of the Fuel Cladding Safety Limit TABLE B2.1.2-2, Nominal Values of Parameters B 2-4 Used in the Statistical Analysis of Fuel Cladding Integrity-Safety Limit INSERT 3 FIGURE 3.1.5-1,' Sodium Pentaborate Solution 3/4 1-21 Volume / Concentration Requirement INSERT 4 Maximum Average Planar Linear-Heat-Generation Rate (MAPLHGR) versus Average Planar Exposure FIGURE 3.2.1-1, Initial Core Fuel 3/4 2-2 Type P8CIBO71 FIGURE 3.2.1-2, Initial Core Fuel 3/4 2-3 Type P8CIB094 FIGURE 3.2.1-3, Initial Core Fuel 3/4 2-4 Type P8CIB163 FIGURE 3.2.1-4, Initial Core Fuel 3/4 2-5 Type P8CIB248 FIGURE 3.2.1-5, Initial Core Fuel 3/4 2-6 Type P8CIB278 INSERT 5 FIGURE 3.2.3-1, Minimum Critical Power Ratio 3/4 2-10 (MCPR) T* versus at Rated Flow

FIGURE 3.2.3-2, Kg Factor 3/4 2-11 INSERT 6 TABLE 3.3.1-1, Reactor Protection-System 3/4 3-2 Instrumentation TABLE 3.3.1-2, Reactor Protection System 3/4 3-6 Response Times FIGURE 4.3.1.1-1, Reactor Protection System 3/4 3-7 Surveillance Requirements INSERT 7 TABLE 3.3.2-1, Isolation Actuation Instrumentation 3/4 3-11

-TABLE 3.3.2-2, Isolation Actuation Instrumentation 3/4 3-22 Setpoints

-TABLE 3.3.2-3, Isolation System Instrumentation 3/4 3-26 Response Time TABLE 4.3.2.1-1, Isolation Actuation Instrumentation 3/4 3-28 a.

Surveillance Requirements INSERT 8 TABLE 3.3.3-1, Emergency Core Cooling System 3/4 3 Actuation Instrumentation TABLE 3.3.3-2, Emergency Core Cooling System 3/4 3-36 Actuation Instrumentation Setpoints TABLE 3.3.3-3, Emergency Core Cooling System 3/4 3-38 Response Times TABLE 4.3.3.1-1, Emergency Core Cooling System 3/4 3-39 l Actuation Instrumentation j Surveillance Requirements

INSERT 9 TABLE 3.3.4.1-1, ATWS Recirculation Pump Trip System 3/4 3-42 Instrumentation TABLE 3.3.4.1-2, ATWS Recirculation Pump Trip System 3/4 3-43 Instrumentation Setpoints TABLE 4.3.4.1-1, ATWS Recirculation Pump Trip 3/4 3-44 Actuation Instrumentation Surveillance Requirements INSERT 10 TABLE 3.3.4.2-1, End-of-Cycle Recirculation Pump 3/4 3-47 Trip System Instrumentation TABLE 3.3.4.2-2, End-of-Cycle Recirculation Pump 3/4 3-48 Trip Setpoints TABLE 3.3.4.2-3, End-of-Cycle Recirculation Pump 3/4 3-49 1

Trip System Response Time TABLE 4.3.4.2.1-1, End-of-Cycle Recirculation Pump 3/4 3-50 Trip System surveillance Requirements

~

' INSERT 11 TABLE 3.3.5-1, Reactor Core Isolation Cooling 3/4 3-52 System Actuation Instrumentation TABLE 3.3.5-2, Reactor Core Isolation Cooling 3/4 3-54 System Actuation Instrumentation Setpoints TABLE 4.3.5.1-1, Reactor Core Isolation Cooling 3/4 3-55 System Actuation Instrumentation surveillance Requirements INSERT 12 TABLE 3.3.6-1, Control Rod Block Instrumentation 3/4 3-57 4

- - 3 -- ,m e v v --- - , - , n.--,,c--- - - -,,e , e-,,,---- , - r ,,,- - , ,-,, ,e,-, . - , -- --.

TABLE 3.3.6-2, Control Rod Block Instrumentation 3/4 3-59 Setpoints TABLE 4.3.6-1, Control Rod Block Instrumentation 3/4 3-60 Surveillance Requirements INSERT 13 TABLE 3.3.7.1-1, Radiation Monitoring Instrumentation 3/4 3-63 TABLE 4.3.7.1-1, Radiation Monitoring Instrumentation 3/4 3-66 Surveillance Requirements INSERT 14

-TABLE 3.3.7.2-1, Seismic Monitoring Instrumentation 3/4 3-69 TABLE 4.3.7.2-1, Seismic Monitoring Instrumentation 3/4 3-70 Surveillance. Requirements INSERT 15 TABLE 3.3.7.3-1, Meteorological Monitoring .3/4 3-72 Instrumentation TABLE 4.3.7.3-1, Meteorological Monitoring 3/4 3-73 Instrumentation Surveillance Requirements INSERT 16 TABLE 3.3.7.4-1, Remote Shutdown Monitoring 3/4 3-75 Instrumentation TABLE 3.3.7.4-2, Remote Shutdown Systems Controls 3/4 3-77 TABLE 4.3.7.4-1, Remote Shutdown Monitoring 3/4 3-82 Instrumentation Surveillance Requirements INSERT 17 TABLE 3.3.7.5'-1, Accident Monitoring Instrumentation 3/4 3-85 TABLE 4.3.7.5-1, Accident Monitoring Instrumentation 3/4 3-87 Surveillance Requirements t

e INSERT 18 TABLE 3.3.7.8-1, Fire Detection Instrumentation 3/4 3-91 INSERT 19 TABLE 3.3.7.10-1, Radioactive Liquid Effluent 3/4 3-100 Monitoring Instrumentation TABLE 4.3.7.10-1, Radioactive Liquid Effluent 3/4 3-102 Monitoring Instrumentation Surveillance Requirements INSERT 20 TABLE 3.3.7.11-1, Radioactive Gaseous 3/4 3-105 Effluent Monitoring Instrumentation TABLE 4.3.7.11-1, Radioactive Gaseous Effluent 3/4 3-108 Monitoring Instrumentation Surveillance Requirements INSERT 21 TABLE 3.3.9-1, Feedwater/ Main Turbine Trip System 3/4 3-114 Actuation Instrumentation TABLE 3.3.9-2, Feedwater/ Main Turbine Trip System 3/4 3-115 Actuation Instrumentation Setpoints TABLE 4.3.9.1-1, Feedwater/ Main Turbine Trip System 3/4 3-116 Actuation Instrumentation Surveillance Requirement INSERT 22 FIGURE 3.4.1.1-1, Core Flow % Rated Thermal Power 3/4 4-3 Versus Core Flow INSERT 23 TABLE 3.4.3.1-1, Reactor Coolant System Pressure 3/4 4-13 Isolation Valves TABLE 3.4.3.2-2, Reactor Coolant System Interface 3/4 4-14 Valves Leakage Pressure Monitors

INSERT 24 TABLE 3.4.4-1, Reactor Coolant System Chemistry Limits 3/4 -17 INSERT 25 TABLE 4.4.5-1, Primary. Coolant Specific Activity 3/4 4-20 Sample and Analysis Program INSERT 26 FIGURE 3.4.6.1-1, Minimum Reactor Pressure Vessel 3/4 4-23 Metal Temperature Versus Reactor Vessel Pressure TABLE 4.4.6.1.3-1, Reactor' Vessel Material . 3/4 4-24 Surveillance Program Withdrawal Schedule d

INSERT 27 TABLE 3.6.3-1, Primary Containment Isolation Valves 3/4 6-19 INSERT 28 TABLE 3.6.5.2-1, Secondary containment Ventilation 3/4 6-50 System Automatic Isolation Dampers Isolation Group No. 19 INSERT 29 TABLE 3.7.3-1, Perimeter Flood Doors 3/4 7-10 INSERT 30 FIGURE 4.7.5-1, Sample Plan 2) for Snubber Functional 3/4 7-18 Test INSERT 31 TABLE 3.7.7.5-1, Fire Hose Stations 3/4 7-29 INSERT 32 TABLE 4.8.1.1.2-1, Diesel Generator Test Schedule 3/4 8-10

INSERT 33 TABLE 4. 8. 2.1-1, Battery Surveillance Requirements 3/4 8-16 INSERT 34 TABLE 3.8.4.1-1, Primary Containment Penetration 3/4 8-26 Conductor Overccrrent Protective Devices INSERT 35 ,

TABLE 3.8.4.2-1, Motor Operated Valves-Thermal 3/4 8-31 Overload Protection (Eypassed)

INSERT 36 TABLE 3.8.4.3-1, Motor Operated Valves-Thermal 3/4 8-39 Overload Protection (Not Bypassed)

INSERT 37 TABLE 3.8.4.5-1, Class lE Isolation Breaker 3/4 8-42 Overcurrent Protective Devices (Breaker Tripped by a LOCA Signal) a INSERT 38 TABLE B3. 2.1-1, Significant Input Parameters 3/4 2-3 to the Loss-of-Coolant Acci ant Analysis INSERT 39 FIGURE-B3/4 3-1, Reactor Vessel Water Level B3/4 3-8 INSERT 40 TABLE B3/4.4.6-1, Reactor Vessel Toughness B3/4 4-7 FIGURE B3/4.4.6-1, Fast Neutron Fluence B3/4 4-8 (E>lMev) at (1/4)T as a Function of Service Life

INSERT 41 FIGURE 5.1.1-1, Exclusion Area and Unrestricted 5-2 Areas and Site Boundary for Radioactive Gaseous and Liquid Effluents FIGURE 5.1.2-1, Low Population Zone 5-3 INSERT 42 TABLE 5.7.1-1, Component Cyclic or Transient Limits 5-6 INSERT 43 FIGURE 6.2.1-1, Offsite Organization 6-3 FIGURE 6.2.2-1, Unit Organization 6-4 FIGURE 6.2.2-1, Minimum Shift Crew Composition 6-5 Single Unit Facility l

i l

I l

t 4

i l

l e

i.-

ATTACHMENT IV TECHNICAL SPECIFICATION 3.8.1.1 AC SOURCES - OPERATING Action e of Technical Specification 3.8.1.1 requires with two diesel generators inoperable, in addition to testing the remaining OPERABLE diesel generators, at least one of the inoperable diesel generators be restored to OPERABLE status within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or place the plant in shutdown. The attached change would revise the 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months time frame to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

HCGS has four separate and independent diesel generators, with diesel generators A and C comprising one train and diesel generators B and D comprising the other train. The Standard Technical Specification (STS) action for having one train inoperable requires the restoration to OPERABILITY be performed within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months and the STS action for having both trains inoperable requires the restoration of at least one train to OPERABILITY be performed within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months . In Action e of the referenced HCGS Technical Specification, the time required should be 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months instead of 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months to restore at least one of two inoperable diesel generators, provided the two inoperable diesel generators are in the same train (i.e. A and C or B and D) , to OPERABLE status to be consistent with the STS requirements. In addition, action f effectively precludes the situation where the loss of one diesel generator from each division is permitted to exist for up to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months by requiring that all required systems, subsystems, trains, components and devices that depend on the remaining diesel generators be demonstrated OPERABLE within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months otherwise place the plant in shutdown.

ELECTRICAL POWER SYSTEMS LIMITING CONDITION FOR OPERATION (Continued) g ACTION: (Continued) at least once per 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months thereafter. If a diesel generator became inoperable. due to any causes other than preplanned preventive main-tenance or testing, demonstrate the OPERABILITY of the remaining OPERABLE diesel generators separately for each diesel generator by performing Surveillance Requirement 4.8.1.1.2.a.4 and 4.8.1.1.2.a.5 within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .* Restore at least two offsite circuits and all fcur of the above required diesel generators to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months from time of the initial loss 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 and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . A successful test (s) of diesel generator OPERABILITY per Sur-veillance Requirement 4.8.1.1.2.a.4 and 4.8.1.1.2.a.5 performed under this ACTION statement for the OPERABLE diesel generators satisfies the diesel generator test requirements of ACTION Statement b.

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 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months unless the diesel generators are already operating; restore at least one of the above required offsite circuits to OPERABLE 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 . With only one off-site circuit restored to OPERABLE status, restore at least two offsite circuits ~to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months from time of initial loss 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 and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . A successful test (s) of diesel generator OPERABILITY 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 OPERABLE diesel generators satisfies the diesel generator test requirements of ACTION statement a.

l , e. With two diesel generators of the above required A.C. electrical power I IW 8 sources inoperable,4 demonstrate the OPERABILITY of the above required A.C. offsite sources by performing Surveillance Requirement 4.8.1.1.1.a within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and at least once per 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months thereafter and demonstrate j the OPERABILITY of the remaining diesel generators by performing Sur-i veillance Requirement 4.8.1.1.2.a.4 and 4.8.1.1.2.a.5 sep rately for l each diesel aenerator within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months .* Restore at least ne of the b inoperable diesel generators to OPERABLE status withi hours 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 and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . Restore both of the inoperable diesel generators to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months from time of initial I loss 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 and in l

This test is required to be completed regardless of when the inoperable diesel generator is restored to OPERABILITY. -

HOPE CREEK 3/4 8-2

INSERT FOR PAGE 3/4 8-2 provided they are diesel generators A and C or B and D (i.e.

Train A or Train B).

l 4

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ATTACHMENT V TECHNICAL SPECIFICATION 6.9.1.8 MONTHLY OPERATING REPORTS Technical Specification 6.9.1.8 requires routine reports of operating statistics and shutdown experience to be submitted on a monthly basis to the Director, Office of Management and Progam Anaylsis, U.S. Nuclear Regulatory Commission, Washington, DC 20555, with a copy to the Regional Administrator of the Regional Office no later than the 15th of each month following the calendar month covered by the report.

The attached change would require the reports to be sent to the U.S. Nuclear Regulatory Commission, Document Control Desk, Washington, DC 20555.

Since the Office of Management and Program Analysis has been disbanded, this change assares the reports reach their intended location in the NRC.

1 I

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ADMINISTRATIVE CONTROLS SEMIANUAL RADI0 ACTIVE EFFLUENT RELEASE REPORT (Continued)

The radioactive effluent release report to be submitted within 60 days after January 1, of each year shall also include an assessment of radiation doses to the likely most exposed MEMBER OF THE PUBLIC from reactor releases and other nearby uranium fuel cycl'e sources (including doses from primary effluent pathways and direct radiation) for the previous 12 consecutive months to show conformance with 40 CFR 190, Environmental Radiation Protection Standards for Nuclear Power Operation. Acceptable methods for calculating the dose contribution from liquid and gaseous effluents are given in Regulatory Guide 1.109, Rev. 1.

The radioactive effluents release shall include the following information for each class of solid waste (as defined by 10 CFR 61) shipped offsite during the report period:

a. Container volume,

b. Total curie quantity (specify whether determined by measurement or estimate),

c. Principal radionuclide (specify whether determined by measurement or estimate),

d. Type of waste (e.g., spent resin, compact dry waste, evaporator bottoms),

e. Type of container (e.g., LSA, Type A, Type B, Large Quantity), and

f. Solidification agent (e.g., cement, urea formaldehyde).

The radioactive effluent release reports shall include unplanned releases from the site to the UNRESTRICTED AREA of radioactive materials in gaseous and liquid effluents on a quarterly basis.

The radioactive effluent release reports shall include any changes to the i PROCESS CONTROL PROGRAM (PCP), OFFSITE 00SE CALCULATION MANUAL (00CM) or radioactive waste systems made during the reporting period.

MONTHLY OPERATING REPORTS

6. 9.1. 8 Routine reports of operating statistics and shutdown experience shall 7 be submitted on a monthly basis to thelDirectcr. Office of Mana;;;; cat and Pro-j i;;ra- ^nalyW U.S. Nuclear Regulatory Commission,tWashington, D.C. 20555, with facopytotheRegionalAdministratoroftheRegionalOfficenolaterthanthe /

15th of each month following the calendar month covered by the report. /

SPECIAL REPORTS h 6.9.2 Special reports shall be submitted to the Regional Administratcr of the Regional Office of the NRC within the time period specified for each report.

HOPE CREEK 6-20 l

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ATTACHMENT VI TECHNICAL SPECIFICATION TABLE 2.2.I-1 TABLE 3. 3. l- 1, TABLE 3. 3.1-2, TABLE 4.3.1. l.- 1 AND SECTION 3.10.7 The above listed Technical-Specifications contain typographical /

editorial errors. The attached changes would correct these errors.

t E TABLE 2.2.1-1 A

n REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS M

p% .' ALLOWABLE

FUNCTIONAL UNIT TRIP SETPOINT VALUES

] 1. Intermediate Range Monflor, Neutron Flux-High 5 120/125 divisions 5 122/125 divisions of full scale of full scale j 2. Average Power Range Monitoir:

a. Neutron Flux-Upscale, Setdown 5 15% of RATED THERMAL POWER 5 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 5 113.5% of RATED j < 5 115.5% of RATED THERMAL POWER THERMAL POWER

'? *

c.' ' Fixed Neutron Flux-Upscale -< 118% of RATED THERMAL POWER -< 120% of RATED THERMAL POWER l d. . Inoperative NA NA I e. Downscale > 4% of RATED > 3% of RATED

- THERMAL POWER THERMAL POWER i

3. Reactor. Vessel Steam Dome Pressure - High 5 1037 psig .

5 1057 psig

4. Reactor Vessel Water Level - Low, Level 3 > 11.0 inches above

-> 12.5 inches above instrument zero* instrument zero

5. Main Steam Line Isolation Valve - Closure 1 8% closed 5 12% closed I 6. MainSteamLineRadiation.-High(High , 5 3.0 x full power background

' 5 3.6 x full power background l *See Bases Figure B 3/4 3-1.

l

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O ) .lu O

O' . O O TABLE 3.3.1-1 (Continued) 5 .

7, REACTOR PROTECTION SYSTEM INSTRUMENTATION n

E' APPLICABLE MINIMUM OPERATIONAL OPERABLE CHANNELS FUNCTIONAL UNIT , CONDITIONS PER TRIP SYSTEM (a) ACTION

6. Main Steam Line Radiation -

Highf "' 1, 2 5#) 2 5

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

2 1

8. ~ Scram Discharge Volume Water Level - High- .

a. Float Switch 1,2(9) 2 1 5 2 3 R.

Y . b. Level Transmitter / Trip Unit 1, 2 2 1 w S I9) 2 3

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

10. Turbine Control Valve Fast Closure, Valve Trip System 011 Pressure - Low 1(3) 2(k) 6

11. Reactor Mode Switch Shutdown Position 1, 2 2 1 3, 4 2 7 5 2 3

12. Manual Scram 1, 2 .

2 1 3, 4 2 - S 5 2 9 e

S l

n t _ _ _ _ _

V t

TABLE 3.3.1-2 5

A REACTOR PROTECTION SYSTEM RESPONSE TIMES E -

g -

x ,

, FUNCTIONAL UNIT ' RESPONSE TIME

,l (Seconds)

1. Intermediate Range Mohitors:

a. . Neutron Flux - High, NA b.'; Inoperative { NA

2. Average Power Range ManI(or*:

a. A Neutron Flux -_Upscile, Setdown NA

b. 4 Flow Biased Simulated Thermal Power - Upscale

c. - Fixed Neutron Flux - Upscale < 0.09**

I 0.09 d.' Inoperative' -

-?' -

RA

e. 3 Downscale

~

j NA R*

3. ~ Reactor Vessel Steam, Dome Pressure - High < 0.55

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

6. 7 0.06 Main Steam Line Radiation - High / RA

, 7. Drywell Pressure - High NA y HIGH 8. Scram Discharge Volume Water Level - High NA

a. Float Switch -

NA

b. Level Transmitter / Trip Unit NA

9. Turbine Stop Valve - Closure

10. Turbine Control Valve Fast Closure, -< 0.06 c Trip Oil Pressure - Low < 0.08# .

11. Reactor Mode Switch Shutdown Position RA

'12. Manual Scram ~ ,

, NA

" Neutron detectors are exempt from response time testing. Response time shall be measured from the detector output or from the input of the first electronic component in the channel.

' **Not-including simulated thermal power time constant, 610.6 seconds.

Mea,sured from start of turbine control valve fast closure. . -

O

. . _ .t f e ns _ _ _

W TABLE 4.3.1.1-1 5

A REACTOR PROTECTION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS k '

CHANNEL OPERATIONAL

W CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH FUNCTIONAL UNIT CHECK TEST CALIBRATION (,) 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 MonitorII):

a. Neutron Flux - 5/U(b) 5, 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 y(d)(e) SA,R(h) y a

Y c. Fixed Neutron Flux -

Uoscale S S/U(c),y y(d), SA 1

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

e. Downscale -

S W SA 1

3. Reactor Vessel Steam Dome Pressure - High S M R 1, 2

4. Reactor Vessel Water Level -

Low, Level 3 S M R 1, 2

5. Main Steam Line Isolation Valve - Closure NA M R 1

6. Main Steam Line Radiation -

l j H GH ,

High j S M R 1,2(I)

7. Drywell Pressure - High 5 M R 1, 2

e Q

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SPECIAL TEST EXCEPTIONS .

V 3/4.10.7 SPECIAL INSTRUMENTATION - INITIAL CORE LOADING .

l s

f LIMITING CONDITION FOR OPERATION 3.10.7 Duringinitialcore[loadingwithintheStartupTestProgramthepro-visions of Specification 3 89.2 may be suspended provided that at least two source range monitor (SRM) channels with detectors inserted to the normal operating level are OPERABLE with: .

a. One of th'e required SRM channels continuously indicating

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,8*

c. The RPS " shorting. links" shall be removed prior to and during fuel loading, -

d. The reactor mode switch is OPERABLE and locked in the REFUEL position. .

APPLICABILITY: OPERATIONAL CONDITION 5 -

7 j ACTION .

J With the requirements of the above specification not satisfied, immediately ,

suspend all operations involving CORE ALTERATIONS and insert all insertable control rods.

n* ,

SURVEILLANCE REQUIREMENTS - 4.10.7 Each of the above required SRM channels shall be demonstrated O'PERABLE

by: , r, .- * *

.d, p -yp"d%', Q, 4-' '

-Q .

_ ,0 . a. 'Within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months prior.to and at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months during CORE ~ '

T ,^ $ 7 ,,

ALTERATIONS: 'VQW5F JW4 ' 0:"a"

'.. C ,

, .y.,;..

c' c4 y $ . .fb.. +

s. w auMM. -

' E.

. : }4

. .. 1.

.c a s ,

h '," .2 '

T h.} y,j. ' &%2kl. .M3? Q4 MQ 1;.f.: ; @

PerformanceofaCHANNELCHECK** ,

Dove requir

' /2.' Confirming that the t;

. j.d; .:

c. c m.j,r;v. /.l,"'g9:_.fr normaloperating.levelandlocatedinth.equadrantsrequired.

by Specification'3.10.7. #.% , ' s ?. ~t

- . . f -- .

, , )*: . ..'U}Tl l

[i.7) ,

, '* &,Q ".':.rQpg i.N

g. h*1 ' ..

5ms,!:-.j 4 Q.J l; .. g .'.. , - '

\ ,

x, % r, y' ; - ,,y .

.2 .

4 -- *Up to 16 fuel bundles may be loaded'without a visual indicatin~n f count.6 oi '

%.p,,:,, . - -7

% ,. : vW~':. +: .

. . 8.. m .. m;; ;, . * ? .

rate.n ,,- . c+ l y.

.- m ' 9% w+& *dit'

.. s em ~ " h'.<*,/

. , k h' ..

.n--

- The use of special movable etectors during CORE ALTERATIONS in p ace of L 'y* "

'~']

g . .? th normal SRM nuclear detectors is permissible as long as these special '

7 de ctors are connected to the, nomal SRM circuits. - -

- - Check may be performed by use of movable* neutron source. -

. HOPE CREEK..

3/4 10-7 . - - , .

. , . e-

ATTACHMENT VII TECHNICAL SPECIFICATION 3.9.2 INSTRUMENTATION Technical Specification 3.9.2 requires at least 2 source range monitors (SRM) be OPERABLE and inserted to the normal operating level with certain provisions satisfied. There is a ##

footnote which requires that 3 SRM channels be OPERABLE for critical shutdown margin demonstrations. This footnote permits an SRM detector to be retracted provided a channel indication of at least 100 cps is maintained and THERMAL POWER is less than 1% of R ATED THERMAL POWER. The attached change would delete "...and THERMAL POWER is less than 1% of RATED THERMAL POWER" from the ## footnote.

The ## footnote requiring 3 SRM channels to be OPERABLE for critical shutdown margin demonstrations is a HGCS specific requirement due to differences in the accelerated power ascension test program (PAT). The only real requirement for being permitted to retract a single SRM detector is provided a channel indication of at least 100 cps is maintained. The requirement to be less than 1% of RATED THERM AL POWER was intentionally included as an additional conservatism. However, this requirement is unnecessarily restrictive and may lead to unwarranted and unnecessary decreased operational flexibility during the PAT while not providing any additional safety margin.

l

REFUELING OPERATIONS 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 operat'ing 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 OPERA 8LE by:

a. At least once per 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months s:

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

are connected to the normal SRM circuits.Not required for control rods jjSeeSpecialTestException3.10.7.Three SRM channels shall be OPERABLE/ for c tions. An SRM detector may be retracted provided a channel indication of at least 100 cps is maintainedler.d-TiiE=?L POWER-is-less-than-1%-of4ATEG TflE (POWEH Y

HOPE CREEK 3/4 9-3

l ATTACHMENT VII TECHNICAL SPECIFICATION 4.4.6.1.4 PRESSUU.E/ TEMPERATURE LIMITS REACTOR COOLANT SYSTEM Surveillance Requirement 4.4.6.1.4 requires that the reactor vessel flange and head flange temperature be verified greater j than or equal to 79'F.

A. In OPERATIONAL CONDITION 4 when reactor coolant system temperature is:

1. 1 109 ' F , at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

2. i 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 The attached change would revise the 79'F to 70'F and change the 109

F and 89'F to 100

F a nd 8 0

F , respectively.

The 79'F is the minimum temperature for the closure studs.

However, as stated in FSAR Section 5.3.2.1.1, Temperature Limits for Boltings, a sufficient number of studs can be tensioned at 70'F to seal the closure flange 0-rings for the purpose of raising the reactor water level above the closure flanges in order to assist in warming them. The flanges and adjacent shell l are required to be warmed to minimum temperatures of 79'F before l

being stressed by the fully intended bolt preload. This chango would provide the flexibility to tension a sufficient number of studs thereby allowing the reactor vessel water level to assist in warming the closure flanges, while still ensuring that the minimum temperature for the closure studs is maintained. This change would provide for considerably f aster warming which minimizes soak time and enhances overall schedule.

1 i

t

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 based on the greater of the following criteria:

a. The actual shift in reference temperature for plate material from heat SK3238-1 and weld metal 510-01205 as determined by Charpy impact test, or ,

b. The predicted shif t in reference temperatures for plate material from heat SK3025-1 as determined by Regulatory Guide 1.99, " Radiation Damage to Reactor Vessel Materials."

4.4.6.1.4 The reactor vessel flange and head flange temperature shall be b verified to be greater than or equal toQF:

a

a. In OPERATIONAL CONDITION 4 when reactor coolant system temperature is:

Y h 1. $ N F, at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

h 2. 1\ W 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.

I l

HOPE CREEK 3/4 4-22 .

ATTACHMENT IX TECHNICAL SPECIFICATION TABLE 3.3.3- 1 TABLE 3.3.7.1- 1, TABLE 3. 3.7. 5- 1, TABLE 4. 3.7. 5- 1, AND SECTIONS 3.4.3.1 and 3.11.3 The above referenced Technical Specifications contained various deferrals to OPERABILITY requirements to permit completion of preoperational tests after initial fuel load but prior to exceeding 5% of RATED THERMAL POWER. The attached changes would delete these deferrals.

The deferrals to OPERABILITY requirements should be deleted because they are no longer applicable, i.e., initial criticality and 5% of RATED THERMAL POWER will have already been achieved. With the issuance of a full power operating license, HCGS will be authorized to exceed 5% of RATED THERMAL POWER and hence the aforementioned tests and power levels will have already been performed and those systems declared OPERABLE.

.. ~

"4' g i i$ _

TABLE 3.3.3-1 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION 5

MINIMUM OPERABLE

" '~

' CHANNELS PER APPLICABLE

,k. . ,

TRIP gg) OPERATIONAL CONDITIONS ACTION g TRIP FUNCTION . ,

FUNCTION

1. ' CORE SPRAY SYSTEM '".

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

D)I')

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

c. Reactor Vessel Pressure - Low (Permissive) 4/ division (f) 1,2,3 31 s .

4*' 5* 32 Core Spray Pump Discharge Flow - Low (Bypass) 1/ subsystem 1, 2, 3, 4*, 5* 37

, . d.

- e. Core Spray Pump. Start Time Delay - Normal Power g 1/ subsystem 1, 2, 3, 4*, 5* 31 1, 2, 3, 4*, 5* 31

- f. . Core Spray Pump Start Time Delay - Emergency Power 1/ subsystem g.

~

' Manual Init,iation ' 1/ division (D)(9) 1, 2, 3, 4*, 5* 33

2. LOWPRESSUREC00LANbINJECTIONMODEOFRHRSYSTEM Reactor Vessel)ater Level - Low Low Low, Level 1 2/ valve 1, 2, 3, 4*, 5* 30

$ a.

b. Drywell' Pressure - High 2/ valve 1,2,3 30

, 1,2,3 31

c. Reactor Vessel Pressure - Low (Permissive) 1/ valve a

w - ,

- 4*, 5* 32

d. LPCI Pump Discharge Flow - Low (Bypass) # 1/ pump (9) 1, 2, 3, 4*, 5* 37

e. LPCI Pump Start Time Delay - Normal Powe F 1/ pump 1, 2, 3, 4*, 5* 31

f. Manual Initiation 1/ subsystem , 1, 2, 3, 4 * , 5

33

3. HIGH PRESSURE iANTINJECTIONSYSTEM

a. Reactor Vessel Water Level - Low Low Level 2 4 1,2,3 34 Drywell Pressure - High 4 1, 2, 3 34

b. g 1, 2, 3 35

- c. Condensate Storage Tank Level - Low -

2(c) 1, 2, 3 35

d. ,rSuppression, Pool Water Level - High 2(d)

e. Reactor Vessel Water level - High, Level 8 4 1,2,3 31

. f. HPCI Pump Discharge Flow - Low (Bypass M 1 -

1,2,3 - 37 1/ system 1, 2, 3 33

g. Manual Initiation

- 4. AUTOMATIC DEPRESSURIZATION SYSTEMN Reactor Vessel Water Level - Low Low Low, Level 1 4 1,2,3 30

a. 30

b. Drywell Pressure - High 4 1,2,3 2 1,2,3 31

c. ADS Timer 31 Core Spray Pump Discharge Pressure - High (Permis ive) 1/ pump 1, 2, 3

d. '

- _ nt

1 TABLE 3.3.3-1 (Cont'd)

EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION MINIMUM OPERABLE

[5 ,

CHANNELS PER APPLICABLE n TRIP g TRIP FUNCTION FUNCTION (3)

OPERATIONAL CONDITIONS ACTION N* 4. AUTOMATIC DEPRESSURIZATION SYSTEM

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 l . 1,2,3 31

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

i. Manual Initiation 4 1,2,3 33 MINIMUM APPLICABLE TOTAL NO CHANNELS OF CHANNELS TO (h) th OPERABLE TRIPCHANNELS ) CONDITIONS (h) OPERATIONAL ACTION

5. LOSS OF POWER

1. 4.16 kv Emergency Bus'Under-R voltage (Loss of. Voltage) 4/ bus 2/ bus 3/ bus 1, 2, 3, 4**, 5** 36

2. 4.16 kv Emergency Bus Under-57 voltage (Degraded, Voltage) 2/ source / 2/ source / 2/ source / 1, 2, 3, 4**, 5** 36 g bus bus bus (a) A channel may be placed in an inoperable status for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months 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 valve only.

(d) Provides a signal,to trip HPCI pump turbine only. .

,(e) In divisions 1 and 2,.the two sensors are associated with each pump and valve combination. In divisions 3 and 4, the two sensors are associated with each pump only.

(f) Division 1 and 2.only.

(g) In divisions 1 and 2, manual initiation is associated with each pump and valve combination; in divisions

-3 and 4, manual initiation is associated with each pump only.

(h) Each voltage detector is a channel.

(i) Start time delay is applicable to LPCI Pump C and D only.

.A ** . When the system is required to be OPERABLE per Specification 3.5.2. . -

Reautred when ESF eouineent is reouired to be OPERABLE.

I ^^^ ei. . w u'. a ;.. M ^^C"CC prI;r te i;';iti:1 criti: 1ity. l Not required to be OPERABLE when reactor steam dome pressure is less than or equal to 200 psig.

1. Not required to be OPERABLE when reactor steam dome pressure is less than or equal to 100 psig.

. 8 O ,t ,

t A s

(

TABLE 3.3.7.5-1 5 -

g _ .

ACCIDENT MONITORING INSTRUMENTATION

,, e -

_ ./ - .

APPLICABLE

= MINIMUM

/ ' '

REQUIRED NUM8ER CHANNELS OPERATIONAL h INSTRUMENT -

0F CHANNELS OPERABLE CONDITIONS ACTION

_f'

1. Reactor Vessel Pressuit' ' -

2 1 1,2,3 80

2. Reactor Vessel Water i.evel ' ,

~

2 -1 1,2,3 80

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

4. Suppression Chamber, Water Temperature

2 2 1,2,3 80(*)

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

6. Drywell- Pressure ~I 2 1 1,2,3 80

7. Drywell" Iir iesperature 2 1 1,2,3 80

8. Primary Containment. Hydrogen /0xygen Concentration Analyzer and Monitor. 2 1 1,2,3 80 1 9. Safety / Relief Valve Position Indicators 2/ valve ** 1/ valve ** 1,2,3 80

10. Drywell Atmosphere Post-Accident Radiation Monitor 2 1 1,2,3 81

[ ,

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

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

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

~ 14. PrimaryCoginmentIsolationValvePosition Indication ,.

2/ valve 1/ valve 1,2,3 82

High range noble gas monitors. -

Average bulk pool temperature. ,

- Acoustic monitoring and tail pipe temperature. .

(a) Suppression chamber water temperature instrumentation must satisfy the availabil.ity requirements specified in Specification 3.6.2.1.

(b)One channel consists of the open limit switch, and the other channel consists of the closed limit switch. '

J !!R ; . 4 red! te M 0^ "4 LE i,-ter te e needir.ii 5". e' "AT[", TllC""4L "04E".

A

~

\s t -

, A '. -

, (; TABLE 4.3.7.5-1 8

m ACCIDENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS APPLICABLE

[

= ,

- CHANNEL CHANNEL OPERATIONAL CONDITIONS

~

CHECK CALIBRATION h D NSTRUMENT 1,2,3 M R

1. Reactor _ Vessel . Pressure

2. Reactor Vessel Water Level M R 1,2,3 Suppression Chamber Water' Level M R 1,2,3

~3. .

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

Suppression Chamber Pressure M R 1,2,3 5.

M R 1,2,3

'6. Drywell Pressure .

~

Drywell Air Temperature M R 1,2,3 7.

8. Primary Containment Hydrogen /0xygen Concentration Analyzer and Monitor,, M Q* 1,2,3 Safety /ReliefValvePosN. ion' Indicators M R 1,2,3 9.

1 10. Drywell Atmosphere Post-Accident Radiation Monitor M R** 1,2,3 1,2,3

{

11. North Plant Vent Radiation Monito'r#

12/ South Plant Vent Radiatio'n Monitor #

M M

R R 1,2,3

~

M R 1,2,3

< 13.. FRVS' Vent Radiat' ion Monitor #.

14.. Primary Containment Isolation Valve Position 1,2,3 e R Indicatio -

M "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

, installed or portable gamma source. .

High range noble gas monitors. .

E 2 %t 7:gir:d u 5: 0"E"""'_E pri:r t: :::::dir.g 5% :f ""TED TlE "."1 "Oi!E".

g

l l

n RADI0 ACTIVE EFFLUENTS 3/4.11.3 SOLID RADI0 ACTIVE WASTE TREATMENT l

LIMITING CONDITION FOR OPERATION .

i 1

3.11.3 Radioactive wastes shall be SOLIDIFIED or dewatered in accordance with 1 the PROCESS CONTROL PROGRAM to meet shipping and transportation requirements during transit, and disposal site requirements when received at the disposal site.

APPLICABILITY: At all times. .

ACTION: -

a. With SOLIDIFICATION or dewatering not meeting disposal site and shipping and transportation requirements, suspend shipment of the inadequately processed wastes and correct the PROCESS CONTROL PROGRAM, the procedures and/or the solid waste system as necessary to prevent recurrence.

b. WithSOLIDIFICATIONordewateringilotperformedinaccordancewith the PROCESS CONTROL PROGRAM, (1) demonstrate by test or analysis --

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

prevent recurrence. .

c. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS .

4.11.3.1 The PROCESS CONTROL PROGRAM shall be followed t 'o verify that the pro-perties_of the packaged waste meet the minimum stability requirements of 10 CFR Part 61 and other requirements for transportat, ion to the disposal site.and re-ceipt at the, disposal site. ?*

,- o c , ~ , d ,> .- ,

m .

' ' 4.113.2 "The PROCESS CONTROL' Pit 0 GRAM shall knclude sufficidnE q'uality_ control and assurance methods to assure the solidified waste product.from any process ~

(either in-house or contracted vendor) meets the requirements for transporta-tion and receipt at the disposal s,ite. " ' " ' * - "' '

.i n,: e . .

.' t .t i ... .

on y a ,n . : . . , . -

m .

. i 8 .. .

. . .. . , .. .b '

.. .u '

4 3 4f** I *

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i' ,

t gq f*

'1% (, '

, d

, *~';

3*,, e ,'y i ,. ,

n. , .

' % , 1 k ' ' 's ,

c. 'i p: ~

.*r.

~. , . n s. a i, n : . ~

2 :

0 - '

?

^

j t .-

' y

,9y rua u u ==e w= u wwe --w=uts .

HOPE CREEK 3/4 11-19

ATTACHMENT X TECHNICAL SPECIFICATION TABLE 3.6.3- 1 PRIMARY CONTAINMENT ISOLATION VALVES Technical Specification Table 3.6.3-1, Item D.1, Excess Flow Check Valves Group 46 - Nuclear Boiler, requires leak testing of excess flow check valves. The attached change would add the notation which deletes the requirement to leak test excess flow check valve BB-XV-3649.

The reactor vessel head seal leak detection line (penetration JSC) excess flow check valve (BB-XV-3649) is not subject to OPERABILITY testing because this valve will not be exposed to primary system pressure except under the unlikely conditions of a seal f ailure where it could be partially pressurized to reactor pressure. In addition, any leakage path is restricted at the source. This change was recently approved in the Limerick Unit 1 Technical Specifications.

l l

l I

I

(

r

2

( TABLE 3.6.3-1 (Continued) 5 PRIMARY CONTAINMENT ISOLATION VALVES

g MAXIMUM

[= , :

g. g PENETRATION ISOLATION TIME P&ID VALVE FUNCTION AND NUpeER ; NUMBER (Seconds) NOTE (S)

12. Group 42 - Intergrated Leak Rate Testing System M-60-1

' 'Inside C GP-V001 J360 NA 3 Outside" GP-V002 J36D 'NA 3 Inside. GP-V120' J36C NA 3 Outside GP-V122 J36C NA 3 Outside ~GP-V004 J209 NA 3 Outside GP-V005 J209' NA 3

13. Group 43 - Suppression Chamber Pressure Instrumentation M-57-1 Outside '

M GS-V044 J207 NA 6 GS-V087 J208 NA 6

[.

U 14. Group 44 - Chilled Water System Thermal Relief Valves M-87-1 Inside G8-PSV-9522A .

P88 NA 3 G8-PSV-95228 P38A NA 3 G8-PSV-9523A' P8A NA 3 G8-PSV-95238 P388 NA 3

15. Group 45 - Recirculation Pump Seal Purge Line Check Valves -

M-43-1 Inside ~ '

BB-V043' ' ~ P19 NA 3 88-V047 P20 NA 3 D . Excess Flow Check Valves 1. Group 46 - Nuclear Boiler . M-41-1 Outside BB-XV-3649 J5C NA 6 10 A8-XV-3666A J25A NA .

AB-XV-36668 J26A NA 6 AB-XV-3666C . J27A NA 6 A8-XV-3666D - J28A NA 6

' 5i _ __ _

TABLE 3.6.3-1 PRIMARY CONTAINMENT ISOLATION VALVES -

NOTES NOTATION

1. Main Steam Isolation Valves are sealed with a seal system that maintains a positive pressure of 5 psig above reactor pressure. Leakage is in-leakage and is not added to 0.60 La allowable leakage.*

2. Containment Isolation Valves are sealed with a water seal from the HPCI and/or RCIC system to form the long-term seal boundary of the feedwater lines. The valves are tested with water at 1.10 Pa, 52.9 psig, to ensure the seal boundary will prevent by pass leakage. Sea'l boundary liquid "

leakage will be' limited to 10 gpm.

3. Containment Isolation Valve, Type C gas test at Pa, 48.1 psig. Leakage added to 0.60La allowable le.akage.

4. Containment Isolation Valvo, Type C water test at Pa, 48.1 psig A P.

Leakage added to 10 gpm allowable leakage.

5. Containment boundary is' discharge nozzle of relief valve, leakage tested --.--

during Type A test.* c

6. Drywell and suppression enamber pressure and level instrument root valves and excess flow check valves, leakage tested during Type A.* .

7. Explosive shear valves (SE-V021 through SE-V025) not Type C tested.*

8. Surveillances to be performed per Specification 3.6.1.8. .

9. All valve I.D. numbers are preceded by a numeral 1 which represents an Unit 1 valve.

[ marl =

t 9

I.

.

Exemption to Appendix J of 10 CFR Part 50.

~

HOPE CREEK r

3/4 6-42

~

kf '

INSERT FOR PAGE 3/4 6-42 10 . The reactor vessel head seal leak detection line (pentration JSC) excess flow check valve (BB-XV-3649) is not subject to OPERABILITY testing. This valve will not be exposed to primary system pressure except under the unlikely conditions of a seal failure where it could be partially pressurized to reactor pressure. Any leakage path is restricted at the source; therefore, this valve need not be OPERABILITY tested.

ATIACHMENT XI TECHNICAL SPECIFICATION TABLE 3.6.3- 1 PRIMARY CONTAINMENT ISOLATION VALVES Technical Specification Table 3.6.3- 1, Item B.5(g), Remote Manual Isolation Valves Group 26-RHR Suppression Pool Return valves, classifies two RHR suppression pool return valves as remote manual isolation valves. The attached change would delete the two valves from the reiaote manual valve listing and add them to Item C.9, Other Primary Containment Isolation Valves Group 39-RHR System as Subitem (g).

RHR suppression pool return valves are not remote manual isolation valves but are manual valves. Therefore, these valves should be listed as other isolation valves. This change is purely editorial in that it lists the referenced valves under the proper category and type.

___W

.- - ~. ::t . r .

y 'c'

', y ' .c -iyy '"., -

3

(( ,,

- y % , 'V gJ}. . :. c. , f , ,- ,

< (w;,m,js , . y ; . p ;7 _

p j$g:g-y7 a-4 .s 3

.eJ'

.9 TABLE 3.6.3-1 (Continued) ,

l':g; g i *ypf 7

, o. W Z g . s. < PRIMARY CONTAINMENT ISOLATION VALVES

.m- n .Q y 3r. h ,.,t p ,Q.twNNy4 q,,'w; f;<;- w w 6 m y.

3 ~. - ..

. _ dt -

MAXIMUM :'

y' $nt.o Ul' i '.,i ? M G 4 Q fi d % i.g y sp p g ,. n 9;. PENETRATION ISOLATION TIME

, ' F VALVE FUNCTIOS ANO: NUMBER 4 etc. M b i< " >

y.

NUMBER (Seconds) NOTE (S) P&ID

%e..' (e) . Byp' ass: V51v'se ;on LPCI Injection Lines M-51-1

7. V' '

' Inside: "

r HV-F14GAj.(BC-V119),,,

P6C NA 3

~ *- '

1 ,, ' 3HV-F1463',j(BC'V120). % P6B NA 3

,r 1 ? -.HV-F146C..(BCtV121) .s: P60 , NA 3 l ' ;W -

P6A

- - . -HV-F1460,';'(BC-V122)

- u , .

. ....' , , NA 3 Y .'

. 'l(f) ; Bypass on Shutdown Cooling Return Lines M-51-1 4 Inside: Valveb.

em HV-F122A (BC-V117) , P48. NA 3

~ ,

HV.-F1228.". (BC-V118), 9 ., P4A NA 3 w :,y:u. . y (g)'

,~

s n uSupp

"",,. w.- :ed:fc..q Peel .; Retera Ya!ver f .t SI-1

'/ e.] y ;"h* ff h ' Of N) h g}lf '

p2123 Np, (_

'i'f

?

w ..

} llV F0110'^ (SC-V025) * ' P212? "A~ '

~ s: ,.

'6h;,.Grou[27,-Standby'LiquidControl M-48-1 if ' .

t0utside: 7 " ~'

-?

c.

P18 NA 3

+ .' t -HV-F006A'!(BH-V028)Tl' HV-F006B'(BH-V054)

.s ; , .o o Il P18 NA 3 17.( ' Group [28% Codtdihnt 'Atmo' sphere Control System w >;, ...

.;Supression Chamber Vacuum Relief .

M-57-1 d ~ Outsider:'. ~r < 1 HV-5031- (GS-V038)y P220 NA 3 N HV-5029'(GS-V080) ;r- P219 NA 3

. ~8.' - ' Groudi69 Z TIP. System

' Explosive Shear Valves M-59-1 Outside: .

'SE-XV-J00481 (SE-V021)

. P34A NA 7

. ; SE-XV-J00482 (SE-V022) ' '

P348 NA 7

' ISE-XV-J004B3 P34C NA 7

SE-XV'J00484?(SE-V023) s c,e . (SE-V024) P340

NA 7

~

i J,SE-XV-J00485;(SE-V025) . P34E NA 7 4 g \ g - 4: 4 ( ggg,y a u

, A .4 A2, ;.. v.~

~

,m" L '; - ' kkfg V ,, R [' .

[' , . y: ng V 97g . , .

j . g. .q~,. ~s y,.

g. -f TABLE 3.6.3-1 (Continued)

Q q j 't; . . O g e- t'MmM'. o

'A .i..

yy..'; V w,,,w.,y~e n .

PRIMARY CONTAINMENT ISOLATION VALVES "y $'

~

V ;

,, lrjeq 1. p n ' '

MAXIMUM Q. e "N .x m PENETRATION. ISOLATION TIME

MALVE FUNCTION AN0 ' NUMBER "' *; * NUMBER

' ~ (Seconds) NOTE (S) P&ID v; p,;.

" en (d) ' RHR'Shistdown Cooling' Suction Thermal Relief Valve M-51-1 Inside:L ',

-.BC-PSV-4425 u!.'

. 'P3 NA 3

~ . .

-(e) :LPCI-Injection:Line Check Valves M-51-1

.. ;; d ;Insidei.;j; 4

f'"

Y

~HV-F041A i BC-V114) T P6C NA 3

~

'^'VHV-F041B

.'HV-F041C F(BC-V102)'

W ((BCaV017) P68 .

P6D NA NA 3

3

'C HV-F041D N (BC-V005) P6A NA 3

t. A y - -

1 '

4

'- (f) ,Shutdowri Coeling Return Line Check Valves M-51-1

, - . -3 : O @ Inside: 1."', 4 W -

J, m C ~'f .4HV-F050A.((BC-Vill) HV-F050B l (BC-V014), -

P48 NA 3

- P4A NA 3

, = :, . o.

fgj p g 10. Group 40 - Core Spray System ,

~

(a) Thermal Relief Valves-M-52-1

,*,0utside:

/J Loop!A&Ci>

' Loop:B&D:'?BE-PSV-F012A P2178 NA 5

. BE-PSV-F0128 P217A NA 5

' .N- ~

'(b)UCore Spray)Irijection Line Check Valves M-52-1

Inside: e

,~

~ ' HV-F006A "'(BE-V006) D ' N.* P58 NA 3

.'HV-F0068.." (BE-V002) s PSA NA 3

.f%

<re ,+ c

11. Group 41.- Drywell: Pressure Instrumentation '

M-42-1 c "

4 s.Outside:- " -

> 1 ', BB-V563 ,.- '

'~ ' J6A NA 6

'BB-V564' " -

'J80 NA 6 1 BB-V565 ,. ' :,' J7A NA 6 BB-V566. ,' J10D NA 6

_1,

.n.

INSERT FOR PAGE 3/4 6-36 (g) RHR Suppression Pool Return Valves M-51-1 Outside:

HV-F0llA (BC-V126) P212B NA 4 HV-FollB (BC-V026) P212A NA 4 l

l l

l

l 1

ATTACHMENT XII TECHNICAL SPECIFICATION 4.6.5.3.e.3, FILTRATION, RECIRCULATION AND VENTILATION SYSTEM (FRVS) AND 4.7.2.e.4, CONTROL ROOM EMERGENCY FILTRATION SYSTEM ( CREFS)

Technical Specification 4.6.5.3.e.3 requires that the heaters dissipate 100 + 5 kw for each recirculation unit and that the humidity control instruments operate to maintain less than or equal to 70% relative humidity while Technical Specification 4.7.2.e.4 requires that the heaters dissipate 13 1 1..3 kw and that the humidity control instruments operate to maintain less than or equal to 70% relative humidity. The attached change would increase the heater dissipation for the FRVS system from 100 1 5 kw to 100 1 10 kw and clarify the method of verifying the humidity control instruments are operable by using a channel calibration for the FRVS and CREFS.

The requirement of ANSI N510- 1980 for testing heater dissipation is the rating of the heaters i 10 % . The rating of the FRVS heaters is 100 kw and the tolerance should, therefore, be + 10% of 100 kw, which is 10 kw , not 5 kw. The actual method of verifying operability of the humidity control instrumentation for the FRVS and CREFS is the performance of a channel calibration. This change will clarify the fact that this type of surveillance is the actual method of satisfying Technical Specification 4.6.5.e.3 and 4.7.2.e.4.

O CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

b. Simulated automatic initiation signal.

3. Verifying that the heaters dissipate 100 i w for each recirculation unit and 32 1 3 kw for each ventilation unit when tested in accordance with ANSI N510-1980.Fl *Med/erifying humidity ': entre: ' u t r=:nt;; n__.

, stJc; rate te :mta:miless than or equal to 70% relative humidityg maiso\ f. After each complete or partial replacement of a HEPA filter bank by verify-ing 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 while operating,and C.S.catofa Regulatory the system Guidecfm flow rate of 30,000 1.52, Revision i 10% for each2 March 1978, FRVS recirculation unit and 9,000 cfm i 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 penetra-tion testing acceptance criteria of less than 0.05% in accordance with Regulatory Position C.5.a and C.S.d of Regulatory Guide 1.52, Revision 2, March 1978, for a halogenated hydrocarbon refrigerant test gas while operating the system at a flow rate of 30,000 cfm i 10% for each FRVS recirculation unit and 9,000 cfm i 10% for each FRVS ventilation unit.

WouGH THE CARBCN AD$ORBER$l BY TGPJDRHAOCE O V A CstA n n E L.

C/lLIPRATCd (F THE HuMIDlTV (C$JT820L iMSTRLMiGWATK'Al .

HOPE CREEK 3/4 6-53

PLANT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) 7 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 bblow 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 at least 1/8 inch water gauge relative to adjacent areas during subsystem operation at a flow rate less than or equal to 1000 cfm:

a) High Drywell Pressure b) Reactor Vessel Water Level Low Low Low, Level I c) Control room ventilation radiation monitors high.

4. Verifying that the heaters dissipate 13 1.3 Kw when tested y 6 in accordance with ANSI N510-1980 and verifying humidity lcontrcU awann

imetrrenteeperatetemaintain',pessthanorequalto70% 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.5.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 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.S.a and C.S.d of Regulatory Guide 1.52, Revision 2, March 1978, for a halogenated hydrocarbon refrigerant test gas while operating the system at a flow rate of 4000 cfm 10%.

M UGH THs CAL'Bosj AD$cR5EP4 BY TERFCONAMC6 CF A CMAeJML CALL 6RATlcA3 CF TW HttMtDITY CC+JTROL NSTRL&1GOTATiCA).

A t

I i

HOPE CREEK 3/4 7-8

r; ATTACHMENT XIII TECHNICAL SPECIFICATION TABLE 3.3.7.1- 1 RADI ATION MONITORING INSTRUMENTATION Table 3.3.7.1-1, Radiation Monitoring Instrumentation, Action 74 states that with the offgas pre-treatment radiation monitor inoperable, that release (s) into the pathway may continue for up to 30 days provided:

a. The offgas system is not bypassed, and

b. The offgas post-treatment monitor is OPERABLE, and

c. Grab samples are taken at least once per 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months and analyzed within the following 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months ; Otherwise, be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

The attached change would delete provision b above, that the offgas post-treatment monitor be OPERABLE.

The holdup lines through the offgas holdup tanks are such that the offgas post-treatment monitor will not detect Kr-85 releases for one day and will not detect Xe- 133 releases for 14 days. The post-treatment monitor's indication is, therefore, not meaningful for real-time monitoring. In addition, everything that passes through the of fgas post-treatment monitor passes through the downstream North Plant Vent Monitor, which is required to be OPERABLE in Technical Specification Table 4.11. 2.1. 2- 1. Also, the grab samples taken are an adequate indication of the radiation in line.

1

?

q

f TABLE 3.3.7.1-1 (Continued)

RADIATION MONITORING INSTRUMENTATION l ACTION ACTION 71 -

a. With one of the required monitors inoperable, place the inoperable channel in the tripped condition within one hour; restore the inoperable channel to OPERABLE status within 7 days, or, within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , initiate and maintain operation of the control room emergency filtration system in the pressurization. mode of operation.

b. With both of the required monitors inoperable, initiate and maintain operation of the control room emergency filtration system in the pressurization mode of operation within one hour.

ACTION 72 - With the required monitor inoperable, perform area surveys of the monitored area with portable monitoring instrumentation at least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

ACTION 73 -

With the required monitor inoperable, obtain and analyze at least one sample of the monitored parameter at least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .*

ACTION 74 - With the number of channels OPERABLE less than required by Minimum Channels OPERABLE requirement, release (s) via this y pathway may continue for up to 30 days provided:

a. The offgas system is not bypassed, and Y

' b. The Offg:: :::t-tr:ct ::nt =0 niter i C"E".^aEE. ; d!

Grab samples are taken at least once per 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months and b./. analyzed within the following 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months ; Otherwise, be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , i

l

Radiation level readings may be taken at the Local Radiation Processor (LRP) at least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months in lieu of obtaining and analyzing grab samples at least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months prior to 120 days after initial fuel load.

HOPE CREEK 3/4 3-65

ML20199B400

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