NUREG-0887, Forwards Approved Changes to Tech Specs for Full Power License,Per 860618,0718 & 30 Requests.Certification That Changes Consistent W/Fsar,Ser & as-built Plant Requested by 860908

Forwards Approved Changes to Tech Specs for Full Power License,Per 860618,0718 & 30 Requests.Certification That Changes Consistent W/Fsar,Ser & as-built Plant Requested by 860908

ML20214L941
Person / Time
Site:	Perry
Issue date:	09/04/1986
From:	Butler W Office of Nuclear Reactor Regulation
To:	Edelman M CLEVELAND ELECTRIC ILLUMINATING CO.
References
RTR-NUREG-0887, RTR-NUREG-887 NUDOCS 8609100463
Download: ML20214L941 (102)

Text

,

r; p gp gh DISTRIBUTION N BGrimes NRC PDR JPartlow LPDR NThompson PD#4 Reading JStefano RBernero M0'Brien Woodhead, OGC ACRS(10)

EJordan DVassallo Docket No. 50-440 Mr. Murray R. Edelman, Sr. Vice President Nuclear Operations Group The Cleveland Electric Illuminating Company P.O. Box 5000 Cleveland, Ohio 44101

SUBJECT:

TRANSMITTAL OF APPROVED CHANGES TO THE TECHNICAL SPECIFICATIONS FOR THE FULL POWER LICENSE FOR THE PERRY NUCLEAR POWER PLANT, UNIT 1 The changes to the Technical Specifications for the full power license for Perry, Unit 1, requested in your letters, dated June 18, 1986, July 18, 1986 and July 30, 1986, have been approved by the NRC staff. A copy of the applicable pages of the Technical Specifications, reflecting the approved changes, is enclosed. Your staff is aware of the approved version of your proposed changes.

The staff's SER pertaining to the changes found acceptable will be documented in SER Supplement No. 10 (NUREG-0887), which we plan to issue concurrently with the Perry, Unit I full power license.

We request that you certify that the enclosed Technical Specification changes for Perry Unit 1, are consistent with the Final Safety Analysis Report, the NRC Safety Evaluation Report and the as-built plant. Your certification to this effect should be received by the Project Manager, John J. Stefano, no later than COB, Friday, September 8, 1986.

If there are any questions, please direct them to Mr. Stefano.

Sincerely, N aessedly alW R. Buder, Wedor 8609100463 860904 BWR Project Directorate No. 4 PDR ADOCK 05000440 P PDR- Division of BWR Licensing

Enclosure:

As stated cc w/ enclosure:

See next page

• Previously concurred:

• 1 PD#4/PM PD#4/PD d *JStefano *WRButler 09/02/86 09/03/86

q ,,

Mr. Murray R. Edelman Perry Nuclear Power Plant The Cleveland Electric Units 1 and 2 Illuminating Company cc:

Jay Silberg, Esq. Mr. James W. Harris, Director Shaw, Pittman, & Trowbridge Division of Power Generation 1800 M Street, N. W. Ohio Department of Industrial Washington, D. C. 20006 Relations 2323 West 5th Avenue Donald H. Hauser, Esq. Post Office Box 825 The Cleveland Electric Columbus, Ohio 43216 Illuminating Company P. O. Box 5000 The Honorable Lawrence Logan Cleveland, Ohio 44101 Mayor, Village of Perry 4203 Harper Street Resident Inspector's Office Perry, Ohio 44081 U. S. Nuclear Regulatory Commission Parmly at Center Road The Honorable Robert V. Orosz Perry, Ohio 44081 Mayor, Village of North Perry North Perry Village Hall Regional Administrator, Region III 4778 Lockwood Road U. S. Nuclear Regulatory Commission North Perry Village, Ohio 44081 799 Roosevelt Road Glen Ellyn, Illinois 60137 Attorney General Department of Attorney General Donald T. Ezzone, Esq. 30 East Broad Street Assistant Prosecuting Attorney Columbus, Ohio 43216 105 Main Street Lake County Administration Center Ohio Department of Health Painesville, Ohio 44077 Attn: Radiological Health Program Director Ms. Sue Hiatt P. O. Box 118 OCRE Interim kepresentative Columbus, Ohio 43216 8275 Munson Mentor, Ohio 44060 Planning Coordinator 361 East Broad Street Terry J. Lodge, Esq. P. O. Box 1735 618 N. Michigan Street Columbus, Ohio 43215 Suite 105 Toledo, Ohio 43624 Ohio Environmental Protection Agency Division of Planning John G. Cardinal, Esq. Environmental Assessment Section Prosecuting Attorney P. O. Box 1049 Ashtabula County Courthouse Columbus, Ohio 43216 Jefferson, Ohio 44047 Mr. Arthur Warren, Chairman Eileen M. Buzzelli Perry Township Board of Trustees The Cleveland Electric 4169 Main Street Illuminating Company Perry, Ohio 44081 P. O. Box 97 E-210 Perry, Ohio 44081

)

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 Scram Accumulators........................... 3/4 1-8 .

Control Rod Drive Coupling............................... 3/4 1-10 ,

Control Rod Position Indication.......................... 3/4 1-12 Control Rod Drive Housing Support........................ 3/4 1-14 3/4.1.4 CONTROL ROD PROGRAM CONTROLS Control Rod Withdrawa1................................... 3/4 1-15 Rod Pattern Control System............................... 3/4 1-16 3/4.1.5 STANDBY LIQUID CONTROL SYSTEM............................ 3/4 1-18 I

Figure 3.1.5-1 Sodium Pentaborate Solution Concentration / Volume Requirements........................ 3/4 1-20 3/4.2 POWER DISTRIBUTION LIMITS .

3/4.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE............... 3/4 2-1 .

Figure 3.2.1-1 Maximum Average Planar Linear Heat ,

Generation Rate (MAPLHGR) Versus Average Planar Exposure Initial Core Fuel Types BP85RB219........... 3/4 2-2 Figure 3.2.1-2 Maximum Average Planar Linear Heat Generation Rate"(M4PLHGR) Versus Average Planar Exposure Initial ,

Core Fuel Types BP85RB176........... 3/4 2-3  ;

PERRY - UNIT 1 v

LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE i ,

POWER DISTRIBUTION LIMITS (Continued)

Figure 3.2.1-3!MaximumAveragePlanarLinearHeat -

Generation Rate (MAPLHGR) Versus

Average Planar Exposure Initial

, Core Fuel Types P85R8071........... 3/4 2-4 Figure 3.2.1-4 MAPFAC ............................

f 3/4 2-5 Figure 3.2.1-5 'MAPFAC ............................

p 3/4 2-6 3/4 2.2 MINIMUM CRITICAL POWER RATI0............................ 3/4 2-7 i

Figure 3.2.2-1 MCPR ..............................

f 3/4 2-8 ,

~

Figure 3.2.2-2 .MCPR ..............................

p 3/4 2-9 3/4.2.3 LINEAR HEAT GENERATION RATE............................. 3/4 2-10 i

3/4.3 INSTRUMENTATION 3/4.3.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION............... 3/4 3-1 Table 3.3.1-1 'eactor R Protection System Instrumentation..................... 3/4 3-2 Table 3.3.1-2 Reactor Protection System Response Times...................... 3/4 3-6 Table 4.3.1.1-1lReactorProtectionSystem

Instrumentation Surveillance

' Requirements.............;........ 3/4 3-7 3/4.3.2 ISOLATIONACTUATIONINSTRUMENTATION..................... 3/4 3-9

• i Table 3.3.2-1 Isolation Actuation Instrumentation.....................

3/4 3-11 Table 3.3.2-2 Isolation Actuation i

Instrumentation Setpoints........... 3/4 3-17 i

Table 3.3.2-3 Isolation System Instrumen-tation Response Time................ 3/4 3-21 Table 4.3.2.1-li Isolation Actuation Instrumen-i tation Surveillance

' Requirements...................... 3/4 3-23 i

i PERRY - UNIT 1 l vi 1  !

4 i

LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE CONTAINMENT SYSTEMS (Continued)

Containment Spray....................................... 3/4 6-25

, Suppression Pool Cooling................................ 3/4 6-26 Suppression Pool Makeup System.......................... 3/4 6-27 3/4.6.4 CONTAINMENT ISOLATION VALVES............................ 3/4 6-28 Table 3.6.4-1 Containment Isolation Valves........ 3/4 6-30 3/4.6.5 VACUUM RELIEF Containment Vacuum Breakers.................:........... 3/4 6-40 Containment Humidity Control............................ 3/4 6-42

.i

. Figure 3.6.5.2-1 Containment Average Temperature vs

] Relative Humidity................ 3/4 6-43 Drywell Vacuum Breakers................................. 3/4 6-44 3/4.6.6 SECONDARY CONTAINMENT Secondary Containment Integrity......................... 3/4 6-45 Annulus Exhaust Gas Treatment System.................... 3/4 6-46 3/4.6.7 ATMOSPHERE CONTROL Containment Hydrogen Recombiner Systems........;........ 3/4 6-49 l Combustible Gas Mixing System........................... 3/4 6-50 l Containment and Drywell Hydrogen Ignition System........ 3/4 6-51 1

! 3/4.7 PLANT SYSTEMS 3/4.7.1 COOLING WATER SYSTEMS

! Emergency Service Water System (Loops A, B, C).......... 3/4 7-1 1

i Emergency Closed Cooling Water System................... 3/4 7-2 l

l 1

PERRY - UNIT 1 xiii

l BASES SECTION PAGE i

3/4.0 APPLICABILITY............................................ B 3/4 0-1 3/4.1 REACTIVITY CONTROL SYSTEMS -

3 3/4.1.1 SHUTDOWN MARG IN. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 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 R00 PROGRAM CONTR0LS. . . . . . . . . . . . . . . . . . . . . . . . . . B 3/4 1-3 3/4.1.5 STANDBY LIQUID CONTROL SYSTEM. . . . . . . . . . . . . . . . . . . . . . . . . B 3/4 1-4 3/4.2 POWER DISTRIBUTION LIMITS -

3/4.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION i RATE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B 3 /4 2- 1 i

i Bases Table B 3/4 2.1-1 Significant Input Para-meters to the Loss-Of-Cooling Accident Analysis................ B 3/4 2-3 3/4.2.2 MINIMUM CRITICAL POWER RATI0.......................... B 3/4 2-4 Bases Figure B 3/4 2.2-1 Power to Flow Operating Map.................... B 3/4 2-6 3/4.2.3 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 l 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 .

i 3/4.3.5 REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION.....................:................. B 3/4 3-4 1

3/4.3.6 CONTROL R00 BLOCK INSTRUMENTATION..................... B 3/4 3-4 4

d PERRY - UNIT 1 xviii

BASES SECTION PAGE CONTAINMENT SYSTEMS (Continued) 3/4.6.2 DRYWELL Drywell Integrity....................................... B 3/4 6-3 D rywel l Bypa s s Lea kage. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B 3/4 6-3 Drywell Air Lock........................................ B 3/4 6-3 Drywell Structural Integrity............................ B 3/4 6-4 Drywell Internal Pressure............................... B 3/4 6-4

. D'rywell Average Air Temperature......................... B 3/4 6-4 3/4.6.3 DEPRESSURIZATION SYSTEMS................................ B 3/4 6-4 3/4.6.4 CONTAINMENT ISOLATION VALVES............................ B 3/4 6-5 3/4.6.5 VACUUM RELIEF........................................... B 3/4 6-6 3/4.6.6 SECONDARY CONTAINMENT................................... B 3/4 6-6 3/4.6.7 ATMOSPHERE CONTR0L...................................... B 3/4 6-7 3/4.7 PLANT SYSTEMS 3/4.7.1 COOLING WATER SYSTEMS................................... B 3/4 7-1 3/4.7.2 CONTROL ROOM EMERGENCY RECIRCULATION SYSTEM............. B 3/4 7-1 3/4.7.3 REACTOR CORE ISOLATION COOLING SYSTEM. . . . . . . . . . . . . . . . . . . B 3/4 7-1 3/4.7.4 SNUBBERS................................................ B 3/4 7-2 3/4.7.5 SEALED SOURCE CONTAMINATION............................. B 3/4 7-3 3/4.7.6 MAIN TURBINE BYPASS SYSTEM.............................. B 3/4 7-4 .

3/4.7.7 FUEL HANDLING BUILDING...............,................... B 3/4 7-4 PERRY - UNIT 1 xxi

ADMINISTRATIVE CONTROLS SECTION PAGE 6.1 RESPONSIBILITY............................................... 6-1 6.2 ORGANIZATION................................'................. 6-1 -

6.2.1 Corporate............................................... 6-1 Figure 6.2.1-1 Corporate Organization............. 6-3 6.2.2 Unit Staff.............................................. 6-1 Figure 6.2.2-1 Unit Organization.................. 6-4 Table 6.2.2-1 Minimum Shift Crew Composition......................... 6-6 6.2.3 INDEPENDENT SAFETY ENGINEERING GROUP Function .............................................. 6-7.

Composition..................;......................... -

6-7

. Responsibilities....................................... 6-7 Records................................................ 6-7 6.2.4 SHIFT TECHNICAL ADVIS0R................................ 6-7 6.3 UNIT STAFF QUALIFICATIONS................................... 6-7 6.4 TRAINING.................................................... 6-8 6.5 REVIEW AND AUDIT 6.5.1 PLANT OPERATIONS REVIEW COMMITTEE (PORC) ,

Function .............................................. 6-8 Composition ........................................... 6-8 Alternates............................................. 6-8 Meeting Frequency ..................................... 6-8 Quorum.............................. .. .............. 6-9 -

Responsibilities ...................................... 6-9 Records............................:................... 6-10 PERRY - UNIT 1 xxv

.-_ .. __ - . _ __ . _ _ = _ - _. . - - _ - - .

DEFINITIONS j CORE ALTERATION .

i

1. 7 CORE ALTERATION shall be the addition, removal, relocation or movement of i 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, LPRMs, TIPS, or special movable detectors is not .

j considered a CORE ALTERATION. Suspension of CORE ALTERATIONS shall not preclude l

completion of the movement of a component to a safe conservative position.

i CORE MAXIMUM FRACTION OF LIMITING POWER DENSITY

1.8 The CORE MAXIMUM FRACTION OF LIMITING POWER DENSITY (CMFLPD) shall be the highest value of the FLPD which exists in the core.

! CRITICAL POWER RATIO j 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 i

per gram, which alone would produce the same thyroid dose as the quantity and i isotopic mixture of I-131, I-132, I-133, I-134, and I-135 actually present.

l The thyroid dose conversion factors used for this calculation shall be those 1 listed in Table III of TID-14844, " Calculation of Distance Factors for Power j and Test Reactor Sites."

DRYWELL INTEGRITY 1.11 DRYWELL INTEGRITY shall exist when: '

i l a. All drywell penetrations required to be closed during accident l conditions are either:  ;

1

1. Capable of being closed by an OPERABLE automatic isolation j system, or l' 2. Closed by at least one manual valve, blind flange, or deactivated automatic valve secured in its closed position.

b. The drywell equipment hatch is closed and sealed.

c. The drywell head is installed and sealed.

d. The drywell air lock is in compliance with the requirements of Specification 3.6.2.3. . .

e. The drywell leakage rates are within the limits of l Specification 3.6.2.2.

! PERRY - UNIT 1 1-2

TABLE 1.2 OPERATIONAL CONDITIONS MODE SWITCH AVERAGE REACTOR CONDITION ' POSITION COOLANT TEMPERATURE i

1. POWER OPERATION Run Any temperature

2. STARTUP Startup/ Hot Standby ** Any temperature

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

4. COLD SHUTDOWN Shutdown #'##'*** 1 200*F

5. REFUELING

• Sh'utdown or Refuel **'# 1 140*F

1. The reactor mode switch may be placed in the Run, Startup/ Hot Standby, or Refuel 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 an'd 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. , ,

PERRY - UNIT 1 1-11

TABLE 2.2.1-1

, REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS .

E q ALLOWABLE

, FUNCTIONAL UNIT TRIP SETPOINT VALUES

$ 1. Intermediate Range Monitor H a. Neutron Flux-High < 120/125 divisions < 122/125 divisions e Hf full scale if full scale

b. Inoperative NA NA l 2. Aserage Power Range Monitor:

a. Neutron Flux-High Setdown

< 15% of RATED < 20% of RATED THERMAL POWER THERMAL POWER

b. Flow Biased Simulated Thermal Power-High

1) Flow Biased 5 0.66 W+69%, with 5 0.66 W+67%, with a maximum of a maximum of

2) High Flow Clamped < 111.0% of' RATED < 113.0% of RATED THERMAL POWER THERMAL POWER

c. Neutron Flux-High < 118.0% of RATED < 120.0% of RATED m THERMAL POWER THERMAL POWER

, d. Inoperative NA NA

3. Reactor Vessel Steam Dome Pressure - High 1 1064.7 ps'ig i 1079.7 psig l .

4. Reactor Vessel Water Level - Low, Level 3 > 177.7 inches above > 177.1 inches above Top of active fuel

• Top of active fuel * .;

5. Reactor Vessel Water Level-High, Level 8 < 219.5 inches above < 220.1 inches above Top of active fuel

• Top of active fuel *

~'

6. - Main Steam Line Isolation Valve - Closure 5 8% closed 1 12% closed

7. Main Steam Line Radiation - High < 3.0 x full power < 3.6 x full power i Eackground Eackground l

l 8. Drywell Pressure - High 1 1.68 psig $ 1.88 psig l

"See Bases Figure B 3/4 3-1. ,

i

1 LIMITING SAFETY SYSTEM SETTINGS i

BASES REACTOR PROTECTION SYSTEM INSTRUMENTATION SETP0INTS (Continued)

Average Power Rance Monitor (Continued)

• I 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 sys-l tem and therefore the monitors respond directly and quickly to changes due to transient operation for the case of the Neutron Flux-High setpoint; i.e, for.a power increase, the THERMAL POWER of the fuel will be less than i that indicated by the neutron flux due to the time constants of the heat trans-for associated with the fuel. For the Flow Biased Simulated Thermal Power-High setpoint, a time constant of 6 t 0.6 seconds is introduced into the flow i

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 l Limits and yet allow operating margin that reduces the possibility of unneces-

! sary shutdown.

3. Reactor Vessel Steam Dome Pressure-Hiah

! High pressure in the nuclear system could cause a rupture to the nuclear 1 system process barrier resulting in the release of fission products. A pres-I sure 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 set-ting 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 trips are bypassed. For a load rejection or turbine trip under these conditions, the

~

l

transient analysis indicated an adequate margin to the thermal hydraulic limit.

l .

I l

l PERRY - UNIT 1 B 2-7 I

,m.+._m- - , , . ,-.-r,-_ _ - - , . . -

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

8. Drywell Pressure-High -

1 j High pressure in the drywell could indicate a break in the primary pressure i boundary systems. The reactor is tripped in order to minimize the possibility i of fuel damage and reduce the amount of energy being added to the coolant and 1 to the primary containment. The trip setting was selected as low as possible without causing spurious trips.

a

9. 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-l 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 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 24 gallons of water.

! 10. . Turbine Stop Valve-Closure i

I The turbine stop valve closure trip anticipates the pressure, neutron flux, 4 and heat flux increases that would result from closure of the stop valves. With l a trip setting of 5% of valve closure from full open, the resultant increase in i heat flux is such that adequate thermal margins are maintained during the worst l case transient. As indicated in Table 3.3.1-1, this function is automatically

, bypassed below the turbine first stage pressure value equivalent to thermal j power less than 40% of RATED THERMAL POWER.

I i

) The automatic bypass setpoint is temperature dependent due to the subcooling l changes that affect the turbine first stage pressure - reactor power relation-4 ship. For RATED THERMAL POWER operation with feedwater temperature greater than or equal to 420*F, an allowable setpoint of <26.9% of control valve wide

! open turbine first stage pressure is provided for the bypass function. This setpoint is also applicable to operation at less than RATED THERMAL POWER with the correspondingly lower feedwater temperature. The allowable setpoint is reduced to <22.5%,

stage pressiire for NATED THERMAE POWER operation with a feedwater tempe l between 370*F and 420*F; 370*F and'320'F, and 320*F and 250*F, respectively, i Similarly, the reduced setpoint is applicable to operation at less than RATED l THERMAL POWER with the correspondingly lower feedwater temperature.

11. Turbine Control Valve Fast Closure Trip Oil Pressure-Low The turbine control valve fast closure tH p anticipates the pressure, ,

i neutron flux, and heat flux increase that could result from fast closure of the '

1 l

l PERRY - UNIT 1 B 2-9

LIMITING SAFETY SYSTEM SETTING BASES REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS (Continued) 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 sole'-

noid valves and in less than 20 milliseconds after the start of control valve fast closure. This is achieved by the action of the fast acting solenoid valver, 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 tran-sient analyses are discussed in Section 15.2.2 of the Final Safety Analysis Report. As with the Turbine Stop Valve-Closure, this function is also bypassed below 40% of RATED THERMAL POWER. The basis for the setpoint is id9ntical to that described for the Turbine Stop Valve-Closure.

12. Reactor Mode Switch Shutdown Position The reactor mode switch Shutdown position provides additional manual reactor trip capability.

13. Manual Scram The Manual Scram provides manual reactor trip capability. The manual scram function is composed of four push button switches in a one-out-of-two taken twice logic.

8 .

PERRY - UNIT 1 , B 2-10

POWER DISTRIBUTION LIMITS 3/4.2 POWER DISTRIBUTION LIMITS 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 type of fuel as a function of AVERAGE PLANAR EXPOSURE shall not exceed the limits shown in Figures 3.2.1-1, 3.2.1-2, and 3.2.1-3, as multiplied by the smaller of either the flow dependent MAPLHGR factor (MAPFAC f

) of Figure 3.2.1-4 or the power dependent MAPLHGR factor (MAPFAC p

) of Figure 3.2.1-5.

APPLICABILITY: OPERATIONAL CONDITION 1, when THERMAL POWER is greater than or equal to 25% of RATED THERMAL POWER.

ACTION:

With an APLHGR exceeding the limits of Figure 3.2.1-1, 3.2.1-2, or 3.2.1-3, as multiplied by the smaller of either the flow dependent MAPLHGR factor (MAPFAC )

f of Fig-ofFigure3.2.1-4orthepowerdependentMAPLHGRfactor(MAPFAC@s)toreAPLHGR ure 3;2.1-5, initiate corrective action within 15 minutes and r to within the required limits within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or reduce THERMAL POWER to less than 25% of RATED THERMAL POWER within the next 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.

I i

SURVEILLANCE REQUIREMENTS l l l

4.2.1 All APLHGRs shall be verified to be equal to or less than the above limits:  :

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

b. Within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after completion of a THERMAL POWER increase of at least 15% of RATED THERMAL POWER in one hour, and 2

. c. Initially and at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> when the reactor is operating with a LIMITING CONTROL ROD PATTERN for APLHGR. t

~

d. The provisions of Specification 4.0.4 are not applicable. ,

l i

PERRY - UNIT 1 3/4 2-1

a 5

i

= 13.8 21 h{ 12.5 12 2 12.3 - -

BP8 SRB 219

.12. 8 -

Iamti 11 g U9 11.2 "z

E9 11.8 ---

.g g{ 16.6

+ mw 10.5 -

? N6

,- 18.8 -

- =

m.

U*, 9. 5 - 99 a

9 . 8 --

8 $800 10000 15000 20000 25000 30000 35000 48080 AVERAGE PLAMAR EXPOSUBE (NWd/t)

/ MAXIMUM AVERAGE PLANAR LINEAR HEAT

/ GENERATION RATE (MAPLHGR) VERSUS

/ AVERAGE PLANAR EXPOSURE INITIAL CORE FUEL TYPES BP8 SRB 219 Figure 3.2.1-1 O

3 4

13 0 12.9 12.9 12 6 b

~

E 12.5 BP8 SRB 176 Et U 12.8 12.2- 11,7 E~d 12.0 I 11.5 Iz wo 11.8 10.8 w

D ww 10.5 .2 gg

. 18.8 5

a *' 9.5 9.6

I 9.0 -

0 5008 18888 15000 28000 25000 30000 35000 40000 AVERAGE PLANAR EXPOSURE.(mwd /t)

. MAXIMUM AVERAGE PLANAR LINEAR HEAT GENERATION RATE (MAPLHGR) VERSUS AVERAGE PLANAR EXPOSURE INITIAL CORE FUEL TYPES BP8 SRB 176

, 'N. Figure 3.2.1-2 '.

A

=

4

= 13.0 -- =- -

M 12.5 h{

E a P88HB071 e,5 12.8 - - -

5* 11.5 11.5 11.5 11.5 ew ^

}h

.g 11.4- 11.O 11.8 - - - -

o!E 5 10 4 y h

<wh 18,5 ---- -

• xo g e- 16.8 -

9,7"-

Eg j -

9.5 ---- -- - -

9.0 -- -- -

9.8 0 5000~ 10000 15000 20000 25000 30000 35000 40000 AVEHAGE PLANAR.EXPOSUBE (mwd /t)

~

MAXIMUM AVERAGE PLANAR LINEAR HEAT GENERATION RATE (MAPLHGR) VERSUS AVERAGE PLANAR EXPOSURE INITIAL CORE FUEL TYPES P8 SRB 071 Figure 3.2.1-3

+Jg. --

i 1.0 e ar d

E s

. V R E tH 0.9

/

0

< f x

• k f

y 0 .8 f

/ .

2 r N E o

p a.

f O f N 4 0.7 / ,s 4 ar sm 2r x '

g F 1 s 4 _

' ' ' ,MAPFACf = MIN (1.0, 0.4574 g  :

g + 0.006758F) .

J -

4 0.6 f

I f

0.5 ,

0.4 0 20 40 60 80 100 120 CORE FLOW (% RATED), F FLOW DEPENDENT MAPLHGR FACTOR (MAPFACf )

Figure 3.2.1-4 PERRY - UNIT 1 3/4 2-5

1.1 1.0 .,

r K

f f

A '

n a

f ur 0 0.9 /

f ar N

4 m r

/

2 .r

. i % '

w v -' '

O.8 ,"  !

g  ?' For 40%

50% MAPFACp = 0.6 + 0.002 (P-40) , i t 0.5 0.4 i 0 20 40 60 80 100 120 CORE THERMAL POWER (E RATED), P POWER DEPENDENT MAPLHGR FACTOR (MAPFACp ) - Figure 3.2.1-S l l l PERRY - UNIT 1 , 3/4 2-6 . . l POWER DISTRIBUTION LIMITS 3/4.2.2 MINIMUM CRITICAL POWER RATIO LIMITING CONDITION FOR OPERATION 1 3.2.2 The MINIMUM CRITICAL POWER RATIO.(MCPR) shall be equal to or greater than both MCPR and MCPR p limits at indicated core flow, THERMAL POWER AT* and f core average exposure compared to End of Cycle Exposure (EOCE)** as shown in' Figures 3.2.2-1 and 3.2.2-2. APPLICABILITY: OPERATIONAL CONDITION 1, when THERMAL POWER is greater than or equal to 25% of RATED THERMAL POWER. ACTION: With MCPR less than the applicable MCPR limit shown in Figures 3.2.2-1 and 3.2.2-2, initiate corrective action within 15 minutes and restore MCPR to within the required limit within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or reduce THERMAL POWER to less than 25% of RATED THERMAL POWER within the next 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. SURVEILLANCE REQUIREMENTS 4.2.2 MCPR shall be determined to be equal to or greater than the MCPR limit determined from Figures 3.2.2-1 and 3.2.2-2:

a. At least once per 24' hours,

b. Within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> afte'r completion of a THERMAL POWER increase of at least 15% of RATED THERMAL POWER in one hour, and

c. Initially and at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> when the reactor is operating with a LIMITING CONTROL ROD PATTERN for MCPR.

d. The provisions of Specification 4.0.4 are not applicable.

l

• This AT refers to the planned reduction of rated feedwater temperature from nominal rated feedwater temperature (420*F), such as prolonged removal of feedwater heater (s) from ser'vice.

• • End of Cycle Exposure (EOCE)! i s defined as 1)'the core average exposures at which there is no longer sufficient reactivity to achieve RATED THERMAL POWER with rated core flow, all control rods withdrawn, all feedwater heaters in service and equiltibrium Xenon, or 2) as specified by the fuel vendor.

1 J I PERRY - UNIT 1 3/4 2-7 1.7-1.6 6, ' L MCPRf = MAX (1.18, 1.8134-0.006948F) i / / .- ' t, < .- ~ i s' L, g -Af ~ I 1.5 'i,g . i!i lL f T ' IL ,o s - . . g k i 1.4 ' 4 H , -6, o i 9 s i l t ' h ' k )  % 1 ( 'k i 1.3 nt . s s, L L I h 'k FL ._ T. l k i nL i i 1.2 L t l 4 t I l 1 1.1 t i h 1.0 ' 0 20 40 60 80 100 120 CORE FLOW (% RATED), F ' MCPR . . f Figure 3.2.2-1 PERRY - UNIT 1 3/4 2-8 l l , I l 1 THERMAL POWER 25% sP s40% , CORE FLOW > 50% i r / 1 / i ll llll $II II l # . tj / il iiI ii ii I iit ii i I t j i . A I 4 i ,wr . . 64 4 .N e THERMAL POWER 25% sP s40% l \'l , . CORE FLOW 550% l 2.0 1m V / . i* 3 r i .. t, & x , . .# . x i . 1 i , 4 i ! e i 1.8

• i

.N i A , ,,, ,, , y 4 . ... , ,. i % A-A' , ll 1.6 , a' ' ' ' , , . . .. .. . . . . . . AN i THERMAL POWER 40%

70% i i i # #. i# 4 i!, . ii ii x MA* Core average exposure > EOCE and t XY w t t tl t t t ee' t t t i 100* F <aT s 170* F and Core flow s 105%. 'lNQQ 1 iXYu l*' - , + l . wx,, , I. C-C'N wx .i IB B' All core average exposures and ~ t 4

• 4 NN'

l 1.2 N S-B' (50* F <aT s 100* F and core flow s 100%) or (AT s 100* F and core flow > 100% and s 105%). rl lC-C' All core average exposures and + '-- (AT s 50' F and core flow s 100%) or ll ll (AT = 0* F and core flow > 100% and 5105%). i;i, O 20 40 60 80 - 100 120 CORE THERMAL POWER (% RATED), P MCPR P. . Figure 3.2.2-2 PERRY - UNIT 1 3/4 2-9 U " - l POWER DISTRIBUTION LIMIT 3/4.2.3 LINEAR HEAT GENERATION RATE LIMITING CONDITION FOR OPERATION 3.2.3 The LINEAR HEAT GENERATION RATE (LHG'R) 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 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or reduce THERMAL POWER to less than 25% of RATED THERMAL POWER within the next 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. SURVEILLANCE REQUIREMENTS 4.2.3 LHGR's shall be determined to be equal to or less than the limit:

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

b. Within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after completion of a THERMAL POWER increase of at least 15% of RATED THERMAL POWER in one hour, and

c. Initially and at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> when the reactor is operating on a LIMITING CONTROL ROD PATTERN for LHGR.

d. The provisions of Specification 4.0.4 are not applicable.

• e PERRY - UNIT 1 3/4 2-10

TABLE 3.3.1-1 (Continued) REACTOR PROTECTION SYSTEM INSTRUMENTATION TABLE NOTATIONS (a) A channel may be placed in an inoperable status for up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> 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) Unless adequate shutdown margin has been demonstrated per Specifica-tion 3.1.1 and the."one-rod-out" Refuel position interlock has been demonstrated OPERABLE per Specification 3.9.1, the shorting links shall be removed from the RPS circuitry prior to and during the time any control rod is withdrawn.* (c) 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. (d) This function is not required to be OPERABLE when the reacto'r pressure vessel head is removed per Specification 3.10.1. (e) This function shall be automatically bypassed when the reactor mode switch is not in the Run position. , (f) This function is n'ot required to be OPERABLE when DRYWELL INTEGRITY is i not required. (g) With any control rod withdrawn. Not applicable to control rods removed per Specification 3.9.10.1 or 3.9.10.2. (h) This function is automatically bypassed when turbine first stage pressure is less than the value of turbine first stage pressure corresponding to 40%** of RATED THERMAL POWER.

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

• • The initial setpoint shall be < 25.4% of the. calibrated span on increasing turbine first stage pressure for AT (see 3/4.2.2 for definition) = 0* F;

< 21% for 0* F< AT < 50' F; < 18% for 50' F < AT < 100* F and < 15% for 100* F< AT < 170* F7 The alTowable value shall be < 26.9%, < Y2.5%, < 19.5%, and < 16.5% respectively. - PERRY - UNIT 1 3/4 3-5 0 TABLE 4.3.1.1-1 (Continued)

E REACTOR PROTECTION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS .

4 E CHANNEL OPERATIONAL CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH E FUNCTIONAL UNIT CHECK TEST CALIBRATION SURVEILLANCE REQUIRED ] 10. 11. Turbine Stop Valve - Closure Turbine Control Valve Fast NA M R 1 l Closure Valve Trip System 011 l Pressure - Low NA M R 1

12. Reactor Mode Switch i Shutdown Position NA R NA 1,2,3,4,5

13. Manual Scram NA M NA 1,2,3,4,5 (a) Neutron detectors may be excluded from CHA*lNEL CALIBRATION.

(b) The IRM and SRM channels shall be determined to overlap for at least 1/2 decades during each startup after entering OPERATIONAL CONDITION 2 and the IRM and APRM channels shall be determined to overlap for i R at least 1/2 decades during each controlled shutdown, if not performed within the previous 7 days.

• (c) Within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to startup, if not performed within the previous 7 days.

T = (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 THERMAL POWER. Adjust the APRM channel if the absolute difference is greater than 2% 07 RATED THERMAL POWER. (e)* This galibration shall consist of the adjustment of the APRM flow biased channel to conform to a i calibrated flow signal. (f) The LPRMs shall be calibrated at least once per 1000 MWD /T using the TIP system. j (g) Calibrate trip unit setpoint at least once per 31 days. l (h) Verify measured core flow (total core flow) to be greater than or equal to established core flow at the i existing loop flow (APRM % flow). (i) This calibration shall consist of verifying the 6

• 0.6 second simulated thermal power time constant.

(j) This function is not required to be OPERABLE when the reactor pressure vessel head is removed per Specification 3.10.1. (k) With any control rod withdrawn. Not applicable to control rods removed per Specification 3.9.10.1 or 3.9.10.2. (1) This function is not required to be OPERABLE when Drywell Integrity is not required. , (m) The CHANNEL CALIBRATION shall exclude the flow reference transmitters, these transmitters shall be calibrated at least once per 18 months. l TABLE 3.3.2-1 (Continued) , h ISOLATION ACTUATION INSTRUMENTATION Q , VALVE GROUPS MINIMUM APPLICABLE l c- OPERATED BY OPERABLE CHANNELS OPERATIONAL

g TRIP FUNCTION- SIGNAL PER TRIP SYSTEM (a) CONDITION ACTION H 5. REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION

a. RCIC Steam Line Flow - High 9' 1 1,2,3 27

b. .RCIC Steam Supply Pressure -

. Low 9 1 1,2,3 27 I

c. RCIC Turbine Exhaust Diaphragm Pressure - High 9(I) 2 1,2,3 27

! d. RCIC Equipment Room Ambient l Temperature - High 9 1 1,2,3 27 l w e. RCIC Equipment Room A ) Temperature - High 9 1 1,2,3 27 Y f. Main Steam Line Tunnel - 0 Ambient Temperature - High 9 1 1,2,3 27 . g. Main Steam Line Tunnel f A Temperature - High 9 1 1,2,3 27 i h. Nain Steam Line Tunnel , i Temperature Timer 9 1 1,2,3 27 l RHR Equipment Room Ambient ' i.[ Temperature - High 9 1/ Area 1,2,3 27 )

j. RHR Equipment Room A Temperature - High 9 1/ Area 1,2,3 27 1 k. RCIC' Steam'Line Flow High Timer 9 .

1 1,2,3 27

1. Drywell Pressure - High 9(h) 1 1,2,3 27

m. ' Manual Initiation 9(k) 1 1,2,3 26 i

j - 1 TABLE 3.3.3-1 (Continued) 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 inoperable, declare the associated system inoperable.

ACTION 31 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, declare the associated ADS trip system or ECCS inoperable. ACTION 32 - With the number of OPERABLE channels less than 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 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> or declare the associated ADS valve or 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 trip system in the tripped condition within one hour

• or declare the HPCS system inoperable.

b. For both trip systems, declare the HPCS system inoperable.

ACTION 35 - With the number of OPERABLE chanfels less than required by the Minimum OPERABLE Channels per TMp Function requirement, place l at least one inoperable channel in the tripped condition within one hour *, or align the HPCS system to take suction from the suppression poo1*, or declare the HPCS system inoperable. ACTION 36 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 i one hour

• or declare the HPCS system inoperable. ,

! ACTION 37 - With the number of OPERABLE channels less than the Total Number of Channels, declare the associated emergency diesel generator inoperable and take the ACTION required by Specification 3.8.1.1 or 3.8.1.2, as appropriate. ACTION 38 - With the number of OPERABLE channels less than the Total Number of Channels, place the inoperable channel in the tripped condi-tion within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> *; operation may then continue until perform-ance of the.next required CHANNEL FUNCTIONAL TEST. ACTION 39 With the number of OPERABLE channels less than required by the ! Minimum OPERABLE Channels per Trip 1 unction requirement, place - the inoperable channel in the tripped condition within one hour. Restore the inoperable channel to OPERABLE status within 7 days or declare the associated system inoperable.

• The provisions of Specification 3.0.4 are not applicable.

PERRY - UNIT 1 3/4 3-31 TABLE 3.3.4.2-1 . END-OF-CYCLE RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION B c MINIMUM l35 OPERABLECHANNE(j) !j TRIP FUNCTION PER TRIP SYSTEM

1. Turbine Stop Valve - Closure 2(b)

2. Turbine Control Valve - Fast Closure 2(b) e (a)A trip system may be placed in an inoperable status for up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> for required surveillance to provided that the other trip system is OPERABLE.

32 (b)This function is automatically bypassed when turbine first stage pressure is less than the to value of turbine first stage pressure corresponding to 40%* of RATED THERHAL POWER. t s.

• The initial setpoint shall be < 25.4% of the calibrated span on increasing turbine first stage pressure

< AT < 100* forFAT and(see15%3/4.2.2 for 100* forF< definition) AT < 170* = F. 0* F;The T10wable a value shalT be <<- 21% 2679%,for<0*22.5%, F< AT < 50* F; < 18% for 50* 5 19.5%, 9nd 5 16.5% respectively. v* l INSTRUMENTATION 3/4.3.5 REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.5 The reactor core isolation cooling (RCIC) system actuation instrumenta-tion channels shown in Table 3.3.5-1 shall be OPERABLE with their trip set-points 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 REQUPREMENTS j 4.3.5.1 Each RCIC system actuation instrumentation channel shall be demon- ) strated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL

TEST and CHANNEL CALIBRATION operations at the frequencies shown in Table l 4.3.5.1-1.

4.3.5.2 LOGICSYSTEMFUNCTIONALTESTSandsimulatedautokaticoperationof all channels shall be performed at.least once per 18 months. 1 PERRV - UNIT 1 3/4 3-50 l TABLE 3.3.6-2 ~ g CONTROL R00 BLOCK INSTRUMENTATION SETPOINTS j TRIP FUNCTION TRIP SETPOINT ALLOWABLE VALUE

1. R00 PATTERN CONTROL SYSTEM E a. Low Power Setpoint 20 + 15, - 0% of RATED THERMAL POWER ** 20 + 15, - 0% of RATED THERMAL POWER **

Z b. RWL - High Power Setpoint 70 + 0, - 15% of RATED THERMAL POWER ** 70 + 0, - 15% of RATED THERMAL POWER **

2. APRM '

i

a. Flow Biased Neutron Flux - Upscale

~ 1) Flow Biased < 0.66 W+58%*, with a maximum of < 0.66 W+61%*, with a maximum of

2) High Flow Clamped i 108.0% of RATED THERMAL POWER 7 110% of RATED THERMAL POWER -

b. Inoperative NA NA i c. Downscale -> 4% of RATED THERMAL POWER -> 3% of RATED THERMAL POWER l d. Neutron Flux - Upscale j Startup 1 12% of RATED THERMAL POWER 1 14% of RATED THERMAL POWER

! 3. SOURCE RANGE MONITORS -

w a. Detector not full in NA NA

A b. Upscale < 1 x 105 cps < 1.6 x 105 cps i w c. Inoperative NA NA j d. Downscale > 0.7 cps, > 0.5 cps,

4. INTERMEDIATE RANGE MONITORS 1 a. Detector not full in NA NA

b. Upsegle < 108/125 division of full scale < 110/125 division of full scale j c. Inoperative NA NA

! d. Downscale > 5/125 division of full scale > 3/125 division of full scale

, 5. SCRAM DISCHARGE VOLUME

~ , a. Water Level - High < 16.6 inches *** < 17.48 inches ***

• l - (624' 3.3" elevation) - (624' 4.17" elevation) l 6. REACTOR COOLANT SYSTEM RECIRCULATION FLOW

a. Upscale i 111% of rated flow 1 114% of rated flow l

7. REACTOR MODE SWITCH SHUTDOWN POSITION NA NA

• The Average Power Range Monitor rod block function'is varied as a function of recirculation loop flow (W).

• • The actual setpoints are the corresponding values of the turbine first stage pressure for these power levels.

• • • Level zero is 622' 10.69" elevation; level transmitter readout.

1. Provided signal to noise ratio > 2. -

l ~ TABLE 4.3.6-1 CONTROL R00 BLOCK INSTRUMENTATION SURVEILLANCE REQUIREMENTS , .= E CHANNEL OPERATIONAL lE CHANNEL FUNCTIONAL CHANNEL CONDITIONS IN WHICH e TRIP FUNCTION CHECK TEST CALIBRATION (a) SURVEILLANCE REQUIRED E 1. ROD PATTERN CONTROL SYSTEM

a. Low Power Setpoint NA S/U(b) M

, SA 1, 2 i

b. RWL - High Power Setpoint NA S/U(b) M

, SA 1

2. APRM

a. Flow Biased Neutron Flux - Upscale

1) Flow Biased NA S/U(b) W SA(c) y

2) High Flow Clamped NA S/U(b), SA(c) y

b. Inoperative NA S/U(b),W NA 1,2,5

c. Downscale NA S/U(b),W 34 7

d. Neutron Flux - Upscale, Startup NA S/U(b),9

,W SA 2, 5 j 3. SOURCE RANGE MONITORS iT a. Detector not full in NA S/U(b) NA 2, 5 $ b. Upscale NA S/U(b),W SA 2, 5

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

'd. Downscale NA S/U(b),W ,W SA 2, 5

4. INTERMEDIATE RANGE MONITORS

a. Detector not full in NA S/U(b) NA 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 NA M R 1, 2, 5*

6. REACTOR COOLANT SYSTEM RECIRCULATION FLOW ,

a. Upscale NA S/U(b) M

, SA(c) y

7. REACTOR MODE SWITCH SHUTDOWN POSITION NA R NA 3, 4

TABLE 4.3.6-1 (Continued) CONTROL ROD BLOCK INSTRUMENTATION SURVEILLANCE REQUIREMENTS NOTES:

a. Neutron detectors may be excluded from CHANNEL CALIBRATION. ,

L. Within 7 days prior to startup.

c. The CHANNEL CALIBRATION shall exclude the flow reference transmitters, these transmitters shall be calibrated at least once per 18 months.

• 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. Calibrate trip unit setpoint at least once per 31 days.

9 f

• O e

PERRY - UNIT 1 3/4 3-60 TABLE 3.3.7.1-1 (Continued) RIDIATION MONITORING INSTRUMENTATION ACTION ACTION 70 - With the required monitor inoperable, obtain and analyze at . least one grab sample of the monitored parameter at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. In addition, with the Unit 1 Vent noble gas monitor inoperable, restore the inoperable noble gas monitor to OPERABLE status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or place the inoperable noble gas. monitor in the tripped condition. . ACTION 71 - With the required monitor inoperable, release via this pathway may continue provided grab samples are taken at least once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> and these samples are analyzed for gross activity within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. - ACTION 72 - With the required monitor inoperable, assure a portable con-tinuous noble gas monitor or the Control Room Area Radiation Monitor is OPERABLE in the control room within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Re-store the inoperable monitor to OPERABLE status within 7 days, otherwise, initiate and maintain operation of the control room emergency filtration system in the isolation mode of operation - within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. ACTION 73. - With the number of channels OPERABLE less than required by Minimum Channels OPERABLE requirement, release via this pathway - l 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 ence per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> and analyzed within the following 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />; Otherwise, be in at least NOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

ACTION 74 - With the required monitor inoperable, assure a portable area radiation monitor with the same alarm setpoint is OPERABLE in the vicinity of the installed monitor during any fuel movement. If no fuel movement is being made, perform area surveys of the monitored area with portable monitoring instrumentation at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. ACTION 75 - 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 <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. e i PERRY - UNIT 1 3/4 3-64 TABLE 3.3.7.5-1 h ACCIDENT M0hITORING INSTRUMENTATION 5! MINIMUM APPLICABLE 5 H REQUIRED NUMBER CHANNELS OPERATIONAL INSTRUMENT OF CHANNELS OPERABLE CONDITIONS ACTION w

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

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

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

4. Suppression Pool Water Temperature 16, 2/ sector 8, 1/ sector 1,2,3 80

5. Primary Containment Pressure 2 1 1,2,3 80

6. Primary Containment Air Temperature 2 1 1,2,3 80

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

8. Drywell Air Temperature 2 1 1,2,3 80

9. Primary Containment and Drywell Hydrogen Concentration Analyzer and Monitor 2 1 1,2,3 80 R 10. Safety / Relief Valve Position Indicators ** 2/ valve 1/ valve 1,2,3 80

• 11. Primary Containment /Drywell Area Gross Gamma y Radiation Monitors 2* 1* 1,2,3 81 g 12. Offgas Ventilation Exhaust Monitor, 1 1 1,2,3 81

13. Turbine Building / Heater Bay Ventilation Exhaust

! Monitor # 1 1 1,2,3 81

14. Unit 1 Vent Monitor, 1 1 1,2,3 81

15. Unit 2* Vent Monitor, 1 . 1 1,2,3 81 i 16. Neutron Flux

a. Average Power Range 2 1 1,2,3 80 l b. Intermediate Range 2 1 1,2,3 80

c. Source Range *,, 2 1

~ 1,2,3 80

17. Primary Containment Isolation Valve Position 2/ valve 1/ valve 1,2,3 82 l

"Each for primary containment and drywell. One channel consists of a pressure switch on the SRV discharge pipe, the other channel consists of a temperature sensor on the SRV discharge pipe. One channel consists of the open limit switch, and the other channel consists of the closed limit switch for each automatic containment isolation valve in Table 3.6.4-1,a. . High and intermediate range D19 system noble gas monitors. Table 3.3.7.5-1 (Continued) ACCIDENT MONITORING INSTRUMENTATIONS 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~0PERABLE status within 7 days or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

b. With the number of OPERABLE accident monitoring instrumentation channels less than the Minimum Channals OPERABLE requirements of Table 3.3.7.5-1, restore the inoperable channel (s) to OPERABLE status within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN with the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

ACTION 81 - With the number of OPERABLE Channels less than required by the Minimum Channcis OPERABLE requirement, either restore the inoperable Channel (s) to OPERABLE stttus within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, or:

a. Initiate the preplanned alternate method of monitoring the appropriate parameter (s), and

b. Prepare and sub'mit a Special Report to the Commission pursuant to Specification 6.9.2 within 14 days following the event outlining the action taken, the cause of the inoperability and the plans and schedule for restoring the system to OPERABLE status.

ACTION 82 - With the number of OPERABLE accident monitoring instrumentation channels less than the Minimum Channels OPERABLE requirements of Table 3.3.7.5-1, verify the valve (s) position by use of alter-nate indication methods; restore the inoperable channel (s) to OPERABLE status at the next time the valve'is required to be demonstrated OPERABLE pursuant to Specification 4.0.5. e PERRY - UNIT 1 3/4 3-79 TABLE 4.3.7.5-1 , h ACCIDENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS 4 . APPLICABLE , c. CHANNEL CHANNEL OPERATIONAL g INSTRUMENT CHECK CALIBRATION CONDITIONS H

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

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

3. Suppression Pool Water Level M R 1,2,3

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

5. Primary Containment Pressure M R 1,2,3

6. Primary Containment Air Temperature M R 1,2,3

7. Drywell Pressure M R 1,2,3

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

9. Primary Containment and Drywell Hydrogen Concentration Analyzer and Monitor NA Q* 1,2,3 l

10. Safety / Relief Valve Position Indicators M R 1,2,3 R 11. Primary Containment /Drywell Area

• Gross Gamma Radiation Monitors M R** 1,2,3 i

12. Offgas Ventilation Exhaust Monitor # M R 1,2,3 o 13. Turbine Building / Heater Bay Ventilation

• Exhaust. Monitor # M R 1,2,3

14. Unit 1 Vent Monitor # M R 1,2,3

15. Unit 2 Vent Monitor # M R 1,2,3

16. Neutron Flux

a. Average Power Range M R 1,2,3

, b. Intermediate Range M R 1,2,3

c. Source Range M R 1,2,3

17. Primary Containment Isolation Valve Position M R 1,2,3

• Using sample gas containing:

a. One volume percent hydrogen, balance nitrogen. -

b. Four volume percent hydrogen, balance nitrogen.

• • The 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.

1. High and intermediate range D19 system noble gas monitors.

i TABLE 3.3.7.10-1 o RADI0 ACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION c- MINIMUM CHANNELS ( INSTRUMENT OPERABLE APPLICABILITY ACTION

1. OFFGAS VENT RADIATION MONITOR

a. Noble Gas Activity Monitor 1

• 121

b. Iodine Sampler 1

• 122

c. Particulate Sampler 1

• 122

d. Effluent System Flow Rate Monitor 1 123

{ e. Sampler Flow Rate Monitor 1 123

2. UNIT l' VENT RADIATION MONITOR

a. Noble Gas Activity Monitor 1 1,2,3 125 -

4, 5 121

b. Iodine Sampler 1 122

c. Particulate Sampler 1 122

d. Effluent System Flow Rate Monitor 1 123

e. Sampler Flow Rate Monitor 1 123 t

l TABLE 4.3.7.10-1 (Continued) RADIOACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS TABLE NOTATION At all times. During main condenser offgas treatment system operation. (1) The CHANNEL FUNCTIONAL TEST shall also demonstrate that control room alarm annuciation occurs if any of the following conditions exists: , 1. Instrument indicates measured levels above the alarm setpoint.

2. Instrument indicates a downscale failure.

3. Instrument controls not set in operate mode.

(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 par-ticipate in measurement assurance activities with NBS. These standards 'shall permit calibrating the system over its intended energy and measure-ment range. For subsequent CHANNEL CALIBRATION, sources that have been related to the initial calibration shall be used. (3) The CHANNEL CALIBRATION shall include the use of standard gas samples containing a nominal:

1. One volume percent hydrogen, balance nitrogen, and

2. Four volume percent hydrogen, balance nitrogen.

(4) The iodine cartridges and particulate filters will be changed at least once per 7 days. Performance of this CHANNEL CHECK does not render the system inoperable, and the applicable ACTION stater.ents need not be entered. o e e PERRY - UNIT ~1 3/4 3-95 - - -.- w - - - - - , , - . - - . . + - , , - - - - . .-----.---,,.,--~-.--,-,,.w.,,---, . - , . . - - -<-.,,,----------,---,,:---,.---------- - l INSTRUMENTATION j 3/4.3.8 TURBINE OVERSPEED PROTECTION SYSTEM . i i l l LIMITING CONDITION FOR OPERATION ' i i 3.3.8 At least one turbine overspeed protection system shall be OPERABLE. . l APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. , ACTION:

a. With one turbine control valve or one turbine stop valve per high pressure turbine steam line inoperable, and/or with one turbine .

intercept or intermediate stop valve per low pressure turbine steam . line inoperable, restore the inoperable valve (s) to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or close at least one valve in the affected steam - line or isolate the turbine from the steam supply within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. ,

b. With the above required turbine overspeed protection system otherwise inoperable, within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> 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 turbine intercept valves, and

2) Four high pressure turbine control valves.

b) For the electrical overspeed trip system and the mechanical. i overspeed trip system; .

1) Four high pressure turbin'e stop valves, and l 2) Six low pressure turbine intermediate stop valves, and *

3) Four high pressure turbine control valves.

. PERRY - UNIT 1 3/4 3-96 , TABLE 3.3.9-2 h PLANT SYSTEMS ACTUATION INSTRUMENTATION SETPOINTS 5! , , ALLOWABLE e TRIP FUNCTION TRIP SETPOINT VALUE 5

1. CONTAINMENT SPRAY SYSTEM

e I a. Drywell Pressure - High < 1.68 psig < 1.88 psig

) b. Containment Pressure - High i 8.35 psig 7 8.85 psig ! c. ' Reactor Vessel Water Level - Low, Level 1 -I 16.5 inches

• I 14.3 inches 1 d. Timers -

i (1) System A and B 10.85 1 0.3 minutes 10.85 1 0.6 minutes (2) System B 35 1 2 seconds 35 i 3 seconds

e. Manual Initiation NA NA

2. FEE 0 WATER SYSTEM / MAIN TURBINE TRIP SYSTEM R a. Reactor Vessel Water Level - High, Level 8 5 219.5 inches * $ 220.1 inches y 3. SUPPRESSION P00L MAKEUP SYSTEM i E$.

H a. Drywell Pressure - High 5 1.68 psig 5 1.88 psig

• b. Reactor Vessel Water Level - Low, Level 1 > 16.5 inches * > 14.3 inches

c. Suppression Pool Water Level - Low I 591' 6.9" elevation 5 591' 5.64" elevation

d. Suppression Pool Makup Timer 7 29.4 minutes 7 30.0 minutes

e. SPMU Manual Initiation HA NA "See Bases Figure B 3/4 3-1.

l REACTOR COOLANT SYSTEM , JET PUMPS LIMITING CONDITION FOR OPERATION 3.4.1.2 All jet pumps shall be OPERARLE. , APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. ACTION: With one or more jet pumps inoperable, be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. SURVEILLANCE REQUIREMENTS 4.4.1.2 Each of the above required jet pumps shall be demonstrated OPERABLE prior to THERMAL POWER exceeding 25% of RATED THERMAL POWER and at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> by determining recirculation loop flow, total core flow and diffuser-to-1cwer plenum differential pressure for each jet pump and verifying that no two of the following conditions occur when the recirculation loops are operating at.the same flow control valve position.

a. The indicated recirculation loop flow differs by more than 10% from the established flow control valve position-loop flow characteristics.

b. The indicated total core flow differs by enre than 10% from the established total core flow value derived from recirculation loop l flow measurements.

c. The indicated diffuser-to-lower plenum differential pressure of any individual jet pump differs from established patterns by more than 10%.

I l PERRY - UNIT 1 3/4 4-4 REACTOR COOLANT SYSTEM RECIRCULATION LOOP FLOW . , LIMITING CONDITION FOR OPERATION 3.4.1.3 Recirculation loop flow mismatch shall be maintained within:

a. 5% of rated recirculation flow with core flow greater than or equal to 70% of rated core flow.

b. 10% of rated recirculation flow with core flow less than 70% of rated core flow.

APPLICABILITY: OPERATIONAL CONDITIONS 1* and 2*. ACTION: With recirculation loop flows different by more than the specified limits, either:

a. Restore the recirculation loop flows to within the cpecified limit within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, or

b. Declare the recirculation loop with the lower flow not in operation

. and take the ACTION required by Specification 3.4.1.1. SURVEILLANCE REQUIREMENTS 4.4.1.3 Recirculation loop flow mismatch shall be verified to be within the limits at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. "See Special Test Exception 3.10.4. O 6 e PERRY - UNIT 1 3/4 4-5 REACTOR COOLANT SYSTEM 3/4.4.3 REACTOR COOLANT SYSTEM LEAKAGE , LEAKAGE DETECTION SYSTEMS, 4 LIMITING CONDITION FOR OPERATION 3.4.3.1 The following reactor coolant system leakage detection systems shall' be OPERABLE:

a. The drywell atmosphere particulate or gaseous radioactivity monitoring system,

b. The drywell floor drain sump and equipment drain sump flow monitoring system, and

c. The upper drywell air coolers condensate flow rate monitoring system.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. ACTION: With only two of the required leakage detection systems OPERABLE, operation may continue for.up to: '

a. 30 days when the required gaseous and particulate radioactive monitoring system is inoperable provided grab samples of the drywell atmosphere are obtained and analyzed at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, or l b. 30 days when the drywell floor-drain sump or equipment drain sump

, flow monitoring system is inoperable, or

c. 30 days when the upper drywell air coolers condensate flow rate monitoring system is inoperable.

Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. SURVEILLANCE REQUIREMENTS 4.4.3.1 The reactor coolant system leakage detection systems shall be demon-strated OPERABLE by:.

a. Drywell atmosphere particulate or gaseous monitoring systems-performance of a CHANNEL CHECK at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, a CHANNEL FUNCTIONAL TEST at least once per 31 days and a CHANNEL CALIBRATION at least once per 18 months.

b. Drywell floor drain and equipment drain sump 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. ,

c. Upper drywell air coolers condensate flow rate monitoring system-performance of a CHANNEL FUNCTIONAL TEST at least once per 31 days 4

and a CHANNEL CALIBRATION at least once per 18 months. 1 PERRY - UNIT 1 3/4 4-9 . . . - , - . - . _ . . - _ . _ . _ - _ . _ - - - . _ - . _ . _ . ~ _ . _ . , _ _ _ - - _ , , . _ . _ . . . . , . - _ , , . _ - . . _ . _ . - . . _ _ , . . - _ . _ . _ _ _ _ _ _ . _ , . . _ . , _ _ , _ _ _ . _ _ , ,%- -, 7l REACTOR COOLANT SYSTEM COLD SHUTDOWN-LIMITING' CONDITION'FOR OPERATION 3.4.9.2 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 operat. ion **## with each loop consisting of at least:

a. One OPERABLE RHR pump, and

b. Two OPERABLE RHR heat exchangers.

APPLICABILITY: OPERATIONAL CONDITION 4 when heat losses to the ambient are not sufficient"" to maintain OPERATIONAL CONDITION 4. ACTION:

a. With less th'an the above required RHR shutdown cooling mode loops OPERABLE, within one hour and at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 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.

c. The provisic,ns of Specification 3.0.4 are not applicable. O SURVEILLANCE REQUIREMENTS 4.4.9.2 At least one shutdown cooling mode 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 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

l t l

1. 0ne RHR shutdown cooling mode loop may be inoperable for up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> for surveillance testing provided the other loop is OPERABLE and in operation.

NThe shutdown cooling mode loop may be removed from operation d'u*ing hydrostatic testing. . ,

• The shutdown cooling pump may be removed from operation for up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> per 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> period provided the other loop is OPERABLE.

• • Ambient losses must be such that no increase in reactor vessel water tempera-ture will occur (even though COLD SHUTDOWN conditions are being maintained).

PERRY - UNIT 1 3/4 4-27 EMERGENCY CORE COOLING SYSTEMS t SURVEILLANCE REQUIREMENTS (Continued)  : For the ADS by: e.

1. At least once per 31 days, performing a CHANNEL FUNCTIONAL TEST of the safety related instrument air system 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, or ,

3) The safety relief valve discharge pressure switch indicates the valve is open.

, c) Performing a CHANNEL CALIBRATION of the safAty related instrument air system low pressure alarm sA tem and verifying an alarm setpoint of > 155 psig on decreasing j pressure.

• The provisions of Specification 4.0.4 are not applicable provided the surveillance is performed within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after reactor steam pressure is adequate to perform the test.

e 3 PERRY - UNIT 1 3/4 5-5 l l 1 I 3/4.6.1 PRIMARY CONTAINMENT $ PRIMARY CONTAINMENT INTEGRITY - SHUTDOWN LIMITING CONDITION FOR OPERATION 3.6.1.1.2 PRIMARY CONTAINMENT INTEGRITY

• shall be maintained.

APPLICABILITY:  ! . When irradiated fuel is being handled in the primary containment, and during CORE ALTERATIONS, and operations with a potential for drainine the reactor vessel. Under these conditions, the requirements of PRIMAR" iMTAINMENT INTEGRITY do not apply to normal operation of the inclined fet.i transfer system.  ; - ACTION: Without PRIMARY CONTAINMENT INTEGRITY, suspend handling of irradiated fuel in the primary containment, CORE ALTERATIONS, and operations with a potential for draining the reactor vessel. t SURVEILLANCE REQUIREMENTS 4.6.1.1.2 PRIMARY CONTAINMENT INTEGRITY shall be demonstrated:

a. At least once per 31 days by verifying that all primary containment penetrations not capable of bety closed by OPERABLE primary contain-ment automatic isolation valves and required to be closed during j

accident conditions are closed by valves, blind flanges, or deacti-vated automatic valves secured in position, except as provided in Table 3.6.4-1 of Specification 3.6.4.

b. By verifying each primary containment air lock is in compliance with the requirements of Specification 3.6.1.3.

l l i "The primary containment leakage rates in accordance with Specification 3.6.1.2 are not applicable. PERRY - UNIT 1 3/4 6-2 CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) , I

1. ' Confirms the accuracy of the test by verifying that the differ- l ence between the supplemental data and the Type A test data is within 0.25 L,. The formula to be used is:

[L, + L,, - 0.25 L,] 1 Lc I El o +l . am + 0.25 L,] where L c supplemental test result; L, = superimposed leakage; L,,=

measured Type A leakage.

! 2. Has duration sufficient to establish accurately the change in leakage rate between the Type A test and the supplemental test. l 3. Requires the quantity of gas injected into the primary contain-i ment or bled from the primary containment during the supple-mental test to be between 0.75 L, and 1.25 L,.

d. Type B and C tests shall be conducted with gas at P , 11.31 psig*,

atintervalsnogreaterthan24monthsexceptfort$stsinvolving:

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 per Table 3.6.4-1 which penetrate the primary containment, and

5. Purge supply and exhaust isolation valves with resilient materyalseals. ,

e. Air locks shall be tested and demonstrated OPERABLE per Surveillance Requirement 4.6.1.3.

f. Main steam line isolation valves shall be leak tested at least once per 18 months.

g. Leakage from isolation valves that are sealed with fluid from a seal system may be excluded, subject to the provisions of Appendix J of 10 CFR 50 Section III.C.3, when determining the combined leakage rate

! provided the seal system and valves are pressurized to at least 1.10 P ! maintain,12.44psig,andthesealsystemcapacityisadequateto system pressure for at least 30 days.

h. All containment isolation valves in hydrostatically tested lines per j Table 3.6.4-1 which penetrate the primary containment shall be leak l tested at least once per 18 months.

i. Purge supply and exhaust isolation valves with resilient material

seals shall be tested and demonstrated OPERABLE per Surveillance

. Requirements 4.6.1.8.3. and 4.6.1.8.4. ,

j. The provisions of Specification 4.0.2 are not applicable to .

Specifications 4.6.1.2.a, 4.6.1.2.b, 4.6.1.2.c, and 4.6.1.2.d. t r "Unless a hydrostatic test is required per Table 3.6.4-1.

PERRY - UNIT 1 3/4 6-5

CONTAINMENT SYSTEMS PRIMARY CONTAINMENT AIR LOCKS , LIMITING CONDITION FOR OPERATION 3.6.1.3 Each primary containment air lock shall be OPERABLE with: I 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 2.5 scf per hour at P,, 11.31 psig.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3, and #. ACTION:

a. With one primary containment air lock door in one or both air locks inoperable:

l

1. Maintain at least the OPERABLE air lock door closed

• and either restore the inoperable air lock door to OPERABLE status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 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 j 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 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

8 4. Otherwise, in OPERATIGNAL CONDITION #, suspend all operation involving handling of irradiated fuel in the primary containment, CORE ALTERATIONS, and operations with a potential for draining the reactor vessel.

5. The provisions of Specification 3.0.4 are not applicable.

b. With a primary containment air lock inoperable in OPERATIONAL CONDITIONS 1, 2, or 3, except as a result of an inoperable air lock door, maintain at i least one air lock door closed; restore the inoperable air lock to OPER-ABLE status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

l

c. With a primary containment air lock inoperable, in OPERATIONAL CONDITION #,

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 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or suspend all operations involving handling of irradiated fuel in the primary containment, CORE ALTERATIONS, and operations with a ! potential for draining the reactor vessel. \ i i #When handling irradiated fuel in the primary containment, during CORE j ALTERATIONS, and operations with a potential for draining the reactor vessel. ! *Except during entry to repair an inoperable inner door, for a cumulative time not to exceed 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> per year. PERRY - UNIT 1 3/4 6-6 i n - CONTAINMENT SYSTEMS. 3/4.6.2 DRYWELL .. DRYWELL INTEGRITY LIMITING CONDITION FOR OPERATION 3.6.2.1 DRYWELL INTEGRITY shall be maintained. , l APPLICABILITY: OPERATIONAL CONDITIONS 1, 2* and 3. ACTION: Without DRYWELL INTEGRITY, restore DRYWELL INTEGRITY within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. SURVEILLANCE REQUIREMENTS ~ 4.6.2.1 DRYWELL INTEGRITY shall be demonstrated: .

a. At least once per 31 days by verifying that all drywell penetrations ** not capable of being closed by OPERABLE drywell automatic isolation valves and required to be closed during accident conditions are closed by valves blind flanges, or deactivated automaticvalvessecuredinposition.

b. By verifying the drywell air lock is in compliance with the require-ments of Specification 3.6.2.3.

c. By verifying the suppression pool is in compliance with the requiro-ments of Specification 3.6.3.1.

d. By verifying the drywell bypass leakage is in compliance with the requirements of Specification 3.6.2.2.

• See Special Test Exception 3.10.1.

• • Except valves, blind flanges, and deactivated automatic valves which are located inside the drywell or containment, and are locked, sealed or other-wise secured in the closed position. These penetrations shall be verified closed during each COLD SHUTDOWN except such verification need not be performed more often than once per 92 days.-

PERRY

• UNIT 1 3/4 6-15

~ l CONTAINMENT SYSTEMS . DRYWELL AIR LOCK LI ITING CONDITION FOR OPERATION - 3.6.2.3 The drywell air lock shall be OPERABLE with: - I

a. Both doors closed except when the air lock is being used for normal transit entry and exit through the drywell,3 hen at least one air lock door shall be closed, and

b. An overall air lock leakage rate of less than or equal to 2.5 scf per hour' at 2.5 psig.

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

a. With one drywell air lock door inoperable:

1. Maintain at least the OPERABLE air lock door closed ** and either i

restore the inoperable air lock door to OPERABLE status within i 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or lock the OPERABLE air lock door closed.

2. Operation may then continue provided that the OPERABLE air lock door j is verified to be locked closed ** at least once per 31 days.

3. Otherwise, be in at least HOT SHUTDOWN within the next 12 hourg and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

4. The provisions of Specification 3.0.4 are not applicable.

b. With the dr>vell 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 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or be in at least i

HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. l l i e 1 l *See Special Test Exception 3.10.1. I **Except during entry to repair an inoperable-inner door for a cumulative time i not to exceed 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> per year. PERRY - UNIT 1 3/4 6-17 ~ CONTAINMENT SYSTEMS 3/4.6.4 CONTAINMENT ISOLATION VALVES I LIMITING CONDITION FOR OPERATION 1 3.6.4 The containment isolation valves shown in Table 3.6.4-1 shall be OPER-ABLE with isolation times less than or equal to those shown in Table.3.6.4-1 . l APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3, and **. ACTION:

a. With one or more of the containment isolation valves shown in Table 3.6.4-1 inoperable, maintain at least one isolation valve OPERABLE in each affected penetration that is open and within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> either:

1. Restore the inoperable valve (s) to OPERABLE status, or l

l 2. Isolate each affected penetration by use of at least one deactivated 4 automatic valve secured in the isolated position,* or I i 3. Isolate each affected penetration by use of at least one closed i manual valve or blind flange.* i The provisions of Specification 3.0.4 are not applicable provided that 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 stateme$s for that system are performed. 4 Otherwise, in OPERATIONAL CONDITION 1, 2 or 3, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. . Otherwise, in Operational Condition **, suspend all operations involving 2 CORE ALTERATIONS, handling of irradiated fuel in the primary containment 4 and with a potential for draining the reactor vessel. The provisions of Specification 3.0.3 are not applicable. " Isolation valves closed to satisfy these requirements may be reopened on an intermittent basis under administrative controls.

• • When handling irradiated fuel in the primary containment and during CORE ALTERATIONS and operations with a potential for draining the reacte-vessel. ,

PERRY - UNIT 1 3/4 6-28 Table 3.6.4-1 Containment Isolation Valves , 3

=

a. CONTAINMENT AUTOMATIC ISOLATION VALVES j 7 Valve Penetration Valve Maximum Secondary Test t

c Number Number Group (c) Isolation Time Containment Pressure I

• (Seconds) Bypass Path (Psig) e (Yes/No)

IB21-F016 P423 6 20 Yes 11.31

IB21-F019 P423 6 20 Yes 11.31 1821-F022A P124 6 5(g) No 11.31

! 1821-F022B P416 6 5(g) No 11.31' 1821-F022C P122 6 5(g) No 11.31 l 1821-F0220 P415 6 5(g) No 11.31 IB21-F028A P124 6 5(g) No 11.31 _ _ IB21-F0288 - P416 6 # 5(g) No 11.31 1821-F028C P122 6 5(g) No 11.31 IB21-F0280 P415 6 5(g) No 11.31 R 1B21-F067A P124 6 22.5* .No 11.31

• = 1821-F0678 P416 6 22.5* No 11.31 i  ? 1821-F067C P122 6 22.5* No 11.31 l g 1821-F0670 P415 6 22.5* No 11.31 l

' 1D17-F071A' P201 1 3 Yes 11.31 1D17-F071B P201 1 3 Yes 11.31 1D17-F079A. P201 1 3 Yes 11.31 1' 1017-F0798 P201 1 3 Yes 11.31 . 1017-F081A P317 1 3 Yes 11.31 1017-F081B P317 1 3 Yes 11.31 , ID17-F089A P317 1 3 Yes - 11.31 i 1D17-F089B P317 1 3 Yes 11.31 1 l 1E12-F008 P421 4 33 No(h) 77,31 1E12-F009 P421 4 33 No 11.31 ! 1E12-F011A P105 2 60* No . (b) i 1E12-F011B P407 2 60* (b) I 1E12-F021 P408 2 90 No(h) 11.31 - i 1E12-F023 P123 4 90* No(h) No 11.31 i 1E12-F024A P105 2 90 No (b) 1E12-F024B P407 2 90 No (b) 1E12-F037A P113 4 180* No 11.31 j 1E12-F037B P412 4 180* No 11.31 1 i . l

b. CONTAINMENT MANUAL ISOLATION VALVES (Continued) ,

h Valve - Penetration Valve Naximum Secondary Test 5 Number Number Group (c) Isolation Time Containment Pressure (Seconds) Bypass Path (Psig) . I c = (Yes/No) ! U IN27-F751 P106, P107, NA NA Yes 11.31 " P115, P429 C P305 NA 3 No 11.31

IP53-F030 C ')) P305 NA 3 No 11.31 1 IP53-F035 1P53-F040C ' ') P312 NA - 3 No 11.31 C

1P53-F045 ') P312 NA 3 No 11.31 1P53-F536 / F570 P305 NA NA Yes 11.31 1P53-F541 / F571 P312 NA NA Yes 11.31 R 1P54-F726(k) P406 NA NA Yes 11.31

• IP54-F727(k) P406 NA NA Yes 11.31 1P57-F015A P304 NA 15* No 11.31 1P57-F0158 P116 NA 15* . No 11.31 l IP87-F037f*f P401 NA 3 Yes (b) 1P87-F065 C 'F) P318 NA 3 Yes (a) i IP87-F071(*)

P318 NA 3 Yes (a) i IP87-F074 P318 NA 3 Yes (a)

1P87-F077 C ') P318 NA 3 Yes (a)

P413 NA 3 Yes 11.31 ' IP87-F049((*)) P413 NA 3 Yes 11.31 1P87-F055(**) IP87-F04S P413 NA 3 Yes 11.31 1P87-F052(*) P413 NA 3 Yes 11.31 . IP87-F083(') P106, P107 NA 3 Yes . 11.31

P115, P429

) IP87-F264(*) P106, P107 NA 3 Yes 11.31

P115, P429 -

i - _ . ? , 1 . 4 , Table 3.6.4-1 Containment Isolation Valves

• E NOTES: a. Isolation valve for instrument line which penetrates the containment, conforms to the requirements '

E of Regulatory Guide 1.11. The In-service Inspection (ISI) program will provide assurance of the e operability and integrity of the isolation provisions. Type "C" testing wil'1 not be performed on - e the instrument line isolation valves. The instrument lines will be within the boundaries of the 5 " Type "A" test, open to the media (containment atmosphere or suppression pool water) to which they " will be exposed under postulated accident conditions. Three exceptions to the above are penetrations P401, P318, and P425. Isolation valves for these three penetrations include the H2 analyzer and Post Accident Sampling System valves. These valves are normally closed post-LOCA, opened only inter-mittently, and will receive Type C tests.

b. Hydrostatic leak test at > 1.10Pa.

. c. See Specification 3.3.2, Table 3.3.2-1, for isolation signal (s) associated with each valve , groups 1-9. Valve groups 10-13, 16 and 17 are as follows: e ' Valve Group 10 - MSIV Leakage Control System Valve Group 11 - Reactor Recirculation System Valve Group 12 - Combustible Gas Control System w Valve Group 13 - Drywell Vacuum Relief System . 1 Valve Group 16 - HPCS m Valve Group 17 - LPCS $ d. Test connection valve. . e. Remote manually controlled valve. .

f. Check valve.

g. See Section 3/4.4.7, " Main Steam Line Isolation Valves." .

h. During Type C testing, valve stem and bonnet are checked for leaks as potential secondary 4 containment bypass leakage paths.  !

1. Notrequiredtobe'5PERABLEinOPERATIONALCONDITION**.

j. Not required to be OPERABLE in OPERATIONAL CONDITIONS 1, 2 and 3. ,

- i l k. These valves may be opened as necessary to supply fire mains in OPERATIONAL CONDITION **.

• l .

• Standard closure time, based upon nominal pipe diameter, is approximately 12 inches / min for gate valves and approximately 4 inches / min for globe valves.

• • When handling irradiated fuel in the primary containment,'during CORE ALTERATIONS and operations with a potential for draining the reactor vessel.

3/4.6.5 VACUUM RELIEF CONTAINMENT VACUUM BREAKERS . LIMITING CONDITION FOR OPERATION 3.6.5.1 All containment vacuum breakers shall' be OPERABLE and the vacuum breakers shall ,be closed. j APPLICABILITY: Whenever PRIMARY CONTAINMENT INTEGRITY is~ required per 5pecifications 3.6.1.1.1 and 3.6.1.1.2. ACTION:

a. With one containment vacuum breaker inoperable for opening but known to be

closed, operation may continue and the provisions of Specification 3.0.4

are not epplicable,

b. With two containment vacuum breakers inoperable and/or with one or two

, containment vacuum breakers open, within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> close the motor operated isolation valve (s). Restore at least 3 vacuum breakers to OPERABLE and

l closed status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in at least NOT SHUTDOWN within

the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, i

c. With more than two containment vacuum breakers inoperable and/or open, be l in at least HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the

next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, and:

1. Maintain an unobstructed opening (s) in the containment that equals or exceeds the flow area provided by two open vacuum breakers, or

2. Deactivate the containment spray by closing at least one valve in each containment spray supply header and deenergizing the power

) supply to its motor operator. 3

d. With the position indicator of any containment vacuum breaker inoperable, i restore the inoperable position indicator to OPERABLE status within 14 days

or verify the vacuum breaker to be closed at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> by i

local indication. Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. l } f PERRY - UNIT 1 3/4 6-40 l ~ SUREVILLANCE REQUIREMENTS ~ 4.6.5.1 Each containaent vacuum breaker shall be:

a. Verified closed at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, l

4 b. Demonstrated OPERABLE: j ,

1. At least once per 31 days by:

a) Cycling the vacuum breaker and isolation valve through at least one complete cycle of full travel. b) Verifying the position indicator OPERABLE by observing expected valve movement during the cycling test.

2. At least once per 18 months by:

a) Verifying the pressure differential required to begin to open the vacuum breaker, from the closed position, to be 1 0.1 psid and to be fully open to be 1 0.2 psid (out-side containment to containment), and b) Verifying the position indicator OPERABLE by performance

of a CHANNEL CALIBRATION . -

3. By verifying the OPERABILITY of the vacuum breaker isolation

valve differential pressure actuation instrumentation with the t

opening setpoint of greater than or equal to 0.0 psid and less than or equal to 0.112 psid (containment to outside containment) by performance of a: a) CHANNEL CHECK at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, b) CHANNEL FUNCTIONAL TEST at least once per 31 days, and j c) CHANNEL CALIBRATION at least once per.18 months. l e l 1 3/4 6-41 PERRY - UNIT 1 l , CONTAINMENT HUMIDITY CONTROL I ' LIMITING CONDITION FOR OPERATION , 3.6.5.2 Containment average temperature and relative humidity shall be main-l tained above the curve shown in Figure 3.6.5.2-1. I APPLICABILITY: Whenever PRIMARY CONTAINMENT INTEGRITY is required for Specifications 3.6.1.1.1 and 3.6.1.1.2. ACTION: With the containment average temperature / relative humidity not within the limits j for acceptable operation as shown in Figure 3.6.5.2-1: { a. In OPERATIONAL CONDITION 1, 2 or 3, restore the average temperature / relative humidity to within the limits for acceptable operation as

shown in Figure 3.6.5.2-1 within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> or be in at least H0T SHUTDOWN l within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following l 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

I

b. At all other times, either: ,

~

1. Maintain an unobstructed opening (s) in the containment that

! equals or exceeds the flow area provided by two open vacuum i breakers, or.

2. Deactivate the cnntainment spray by closing at least one valve in each containment spray supply header and deenergizing the power supply to its motor operator.

I I SURVEILLANCE REQUIREMENTS i i , 4.6.5.2 Containment average temperature / relative humidity shall be verified to be within the limits for acceptable operation curve shown in Figure 3.6.5.2-1 at least once every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. , e e l PERRY - UNIT 1 3/4 6-42 t t i 4 100 . , . . , , i i i + - i . . .____ i 90  :  ; , ,; __ - , i i i . . .._. . i >  : . _ . ._ .. __ . . . .. a. . ..__ -__. . -. . -- -- - - 80  ;  ;  :. i i 70 ~ a 60 . st ~ ACCEPTABLE , , .i . OPERATION 2:', 50 , .. . , ! 13 ie ii - E i ii ! = 40  ::  ; . o i z . , i . . i sm o t 6 . . . . , . s-- , 3 , , , , e + i . 30 , ... ,. .- .a  : 'i l g l s #" ' s i E 20 ' l . ' - UNACCEPTABLE ::::  ! I - OPERATION 10 .L_ i

i ,

i ' - --- --. i i _-_ _ i O 60 70 80 90 100 110 120 , Temperature ( F) i l l l CONTAINMENTAVERAGETEMPERATUREVSRfLATIVEHUMIDITY Figure 3.6.5.2-1 { PERRY - UNIT 1 3/4 6-43 -,.,~----_--..w,- .---_,.,#- , , - - , 1 CONTAINMENT SYSTEMS i DRYWELL VACUUM BREAKERS . LIMITING CONDITION FOR OPERATION - 3.6.5.3 All drywell vacuum breakers shall be OPERABLE and closed. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. , ACTION: l

a. With one drywell vacuum breaker inoperable for opening but known to be closed, restore the inoperable vacuum breaker to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

b. With one drywell vacuum breaker open, restore the open vacuum breaker to the closed position within I hour or be in at least HOT SHUT-DOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTOOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. i

c. With the position indicator of an OPERABLE drywell vacuum breaker inoper-able, verify the vacuum breaker to be closed at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> by local indication. Otherwise, declare the vacuum breaker inoperable.

SURVEILLANCE REQUIREMENTS . 4.6.5.3 Each drywell vacuum breaker shall be:

a. Verified closed at least once per 7 days.

b. Demonstrated OPERABLE:

1. At least once per 31 days by a) Cycling the vacuum breaker and associated isolation valve through ati least one complete cycle of full travel, b) the position indicators OPERABLE by observing Verifying;alvemovementduringthecyclingtest.

expected v

2. At least once per 18 months by:

a) Verifying 'the pressure differential required to open the vacuum breaker, from the closed position, to be less than or equal to 0.5 psid (containment to drywell), and b) Verifying the position indicators OPERABLE by performance of a CHANNEL CALIBRATION.

3. By verifying the OPERABILITY of the vacuum breaker isolation valve differential pressure actuation instrumentation with the opening setpoint < -0.810 inch water gauge dp by performance of a:

a) CHANNEL FUkCTIONAL TEST at least once per 31 days, and ~ b) CHANNEL CALIBRATION at least once per 18 months. I PERRY - UNIT 1  ! 3/4 6-44 l l j . CONTAINMENT SYSTEMS 3/4.6.6 SECONDARY CONTAINMENT I SECONDARY CONTAINMENT INTEGRITY LIMITING CONDITION FOR OPERATION 3.6.6.1 SECONDARY CONTAINMENT INTEGRITY shall be maintained. - - l APPLICA8ILITY: OPERATIONAL CONDITIONS 1, 2, 3 and *. ACTION: - Without SECONDARY CONTAINMENT INTEGRITY: 1

a. In OPERATIONAL CONDITION 1, 2 or 3, restore SECONDARY CONTAINMENT INTEGRITY within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

b. In Operational Condition *, suspend handling of irradiated fuel in the primary 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 i

4.6.6.1 SECONDARY CONTAINMENT INTEGRITY shall be demonstrated by

i

a. Verifying at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> that the pressure within the-secondary containment is less than or equal to 0.40 inches of vacuum water gauge.

i

b. Verifying at least once per 31 days that:

~ i

1. The primary containment equipment hatch is closed and sealed and the shield blocks are installed adjacent to the shield

building.

. 2. The door in each access to the secondary containment is closed, except for routine entry and exit. l 3. All penetrations terminating in the annulus not capable of being l closed by OPERABLE automatic isolation valves and required to be 4 closed during accident conditions are closed by valves, blind ! flanges, or deactivated automatic valves secured in position. . *When irradiated fuel is being handled in the primary containment and during l CORE ALTERATIONS and operations with a potential for draining the reactor ( vessel. .

PERRY - UNIT 1 3/4 6-45 i

i i CONTAINMENTSYSTEM{ ANNULUS EXHAUST GAS TREATMENT SYSTEM LIMITING CONDITION FOR OPERATION 3.6.6.2 Two independent annulus exhaust gas treatment subsystems shall be OPERABLE. . ,

APPLICABILITY

OPERATIONAL CONDITIONS 1, 2, 3 and *.

i ACTION:

a. With one annulus exhaust gas treatment subsystem inoperable, restore the inoperable subsystem 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 <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following j 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

2. In Operational Condition * , suspend handling of irradiated fuel

'. in the primary 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 both annulus exhaust gas treatment subsystems inoperable in Operational Condition *, suspend handling of irradiated fuel in the , primary containment, CORE ALTERATIONS and operations with a potential i for draining the reactor vessel. The provisions of Specification i 3.0.3 are not applicable. SURVEILLANCE REQUIREMENTS i 4.6.6.2 Each annulus exhaust gas treatment subsystem shall be demonstrated

OPERABLE

l l

a. At least once per 31 days by initiating, from the control room, flow through the HEPA filters and charcoal adsorbers and verifying that the subsystem operates for at least 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> with the heaters OPERABLE.

l ~ ~

• When irradiated fuel is being handled in the primary containment and during CORE ALTERATIONS and operations with a potential for draining the reactor vessel.

I l PERRY - UNIT 1 3/4 6-46 ( CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) j b.. At least once per 18 months or (1) after any structural maintenance

on the HEPA filter or charcoal adsorber housings, or (2) following

! painting, fire or chemical release in any ventilation zone communicating with the subsystem by: .

1. Verifying that the subsystem satisfies the in place penetration testing acceptance criteria of less than 0.05% and uses the test t

procedure guidance in Regulatory Positions C.5.a. C.S.c and C.5.d of Regulatory Guide 1.52, Revision 2, March 1978, while operating the system at,a flow rate of 2000 scfm i 10%. 2

2. Verifying within 31 days after removal that a laboratory analysis i 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 j 70% in accordance with ASTM D3803; and

3. Verifying a subsystem. flow rate of 2000 scfm i 10% during system 4

operation when tested in accordan.ce with ANSI N510-1980. The installed air flow monitor can be used to determine flow in lieu of the pitot traverse.

c. After every 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> 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 j of Regulatory Guide 1.52, Revision 2, March 1978, by showing a methyl j 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; f d. At least once per 18 months by:

! 1. Performing a system functional test which includes simulated l automatic actuation of the system throughout its emergency l operating sequence for the LOCA.

2. Verifying that the pressure drop across the combined HEPA filters i and charcoal adsorber banks is less than 6.0 inches water gauge

while operating the filter train at a flow rate of 2000 scfm

!

• 15.

3. Verifying that the filter train starts and isolation dampers

! open on each of the following test signals: I a. Manual initiation from the*corttrol room, and

b. Simulated automatic initation signal.

f I

4. Verifying that the heaters dissipate 20 kw i 10% when tested in accordance with ANSI N510-1980.

PERRY - UNIT 1 3/4 6-47 l CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS (Continue *) s- - .

e. After each comp *sete 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.S.c of Regulatory Guide Ic52 Revi-sion 2, March 1978, while operating the system at a flow rate of 2000 scfm t 10%.

f. 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 accord-ance with Regulatory Positions C.S.a and C.5.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 2000 scfm i 10%.

l l 1 PERRY - UNIT 1 3/4 6-48 . o . CONTAINMENT SYSTEMS 3/4.6.7 ATMOSPHERE CONTROL CONTAINMENT HYDROGEN RECOMBINER SYSTEMS  : i I LIMITING CONDITION FOR OPERATION , 3.6.7.1 Two independent containment hydrogen recombiner subsystems s' hall be' i 0PERABLE. - 1 APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. ACTION: With one containment hydrogen recombiner subsystem inoperable, restore the inoperable subsystem to OPERABLE status within 30 days or be in at least HOT

SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

I l SURVEILLANCE REQUIREMENTS ' 4.6.7.1 Each containment hydrogen recombiner subsystem shall be demonstrated j OPERABLE:

a. At least once per 6 months by verifying during a recombiner subsysi.em i functional test that the minimum heater sheath temperature increases to greater than or equal to 700*F within 90 minutes. Maintain > 700*F for at least 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />..

b. At least once per 18 months by:

1. Performing a CHANNEL CALIBRATION of all control complex recombiner j operating instrumentation and control circuits.

2. Verifying the integrity of all heater electrical circuits by

! performing a resistance to ground test within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> following i the below required functional test. The resi.tance to ground

for any heater phase shall be greater than or equal to 10,000 ohms.

3. Verifying during a recombiner subsystem functional test that the heater sheath temperature increases to greater than or equal l ~

to 1225'F within 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> and is maintained between 1225'F and 1450*F for at least 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. t

4. Verifying through a visual examination that there is no evidence of abnormal conditions within the recombiner enclosure; i.e, loose wiring or structural connections, deposits of foreign materials, etc.

. PERRY - UNIT 1 3/4 6-49 l l l- . - - - - - - - _ - - . - _ - _ _ - . _ _ . - . - . , _ _ . - - .__-.-.-_-_:-._-, . - _ _ e- . t CONTAINMENT SYSTEMS  ! i COMBUSTIBLE GAS MIXING SYSTEM f LIMITING CONDITION FOR OPERATION 3.6.7.2 Two independent combustible gas mixing subsystems shall be OPERABLE with each subsystem consisting of one combustible gas purge compressor. APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. ACTION: With one combustible gas mixing subsystem inoperable, restore the inoperable subsystem to OPERABLE status within 30 days or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. . SURVEILLANCE REQUIREMENTS 4.6.7.2 Each combustible gas mixing subsystem shall be demonstrated OPERABLE: -

a. At least once per 92' days by:

1. Starting the subsystem from the control room, and

2. Verifying that the subsystem operates for at least 15. minutes.

b. At least once per 18 months by verifying a subsystem flow rate of at least 500 scfm.

e o e PERRY - UNIT 1 3/4 6-50 . o . CONTAINMENT SYSTEMS

• i CONTAINMENT AND DRYWELL HYDROGEN IGNITION SYSTEM LIMITING CONDITION FOR OPERATION i 3.6.7.3 The containment and drywell hydrogen ignition system shall be operable consisting of two independent containment and drywell hydrogen ignition sub-systems each consisting of three circuits with no more than two igniter assen- ,

blies inoperable per circuit and no more than five igniter assemblies inoperable per subsystem, and no adjacent igniter assemblies inoperable. , APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2. ACTION:

a. With one containment and drywell hydrogen ignition subsystem and/or circuit inoperable, restore the inoperable subsystem and/or circuit to OPERABLE status within 30 days or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. ,

With any adjacent igniter assembly inoperable, restore all igniter 4 - b. i assemblies adjacent to an inoperable igniter assembly to OPERABLE ' status within 30 days or be in at least HOT SHUTDOWN within the next i 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. I SURVEILLANCE REQUIREMENTS 4.6.7.3 The containment and drywell hydrogen ignition system shall be demonstrated OPERABLE:

a. At least once per 6 months by energizing all the igniter assemblies and performing a current voltage measurement of each. circuit.

1. If more than 3 igniter assemblies on either subsystem are deter-mined to be inoperable, Surveillance Requirement 4.6.7.3.a shall be performed.at least once per 92 days until this condition no i longer exists.

I ! 2. If more than 1 igniter assembly on each subsystem are determined 1 to be inoperable, determine if the inoperable igniter assemblies j are adjacent.

b. At least once per 18 months by energizing each igniter assembly and verifying by* current measurement sufficient current / voltage draw to '

develop 1700 F temperature for those igniter assemblies in high radi-4 ation areas and verifying a surface temperature of at least 1700*F - for each of the remaining igniters. l PERRY - UNIT 1 3/4 6-51 i PLANT SYSTEMS l 3/4.7.3 REACTOR CORE ISOLATION COOLING SYSTEM

LIMITING CONDITION'FOR OPERATION i 3.7.3 The reactor core isolation cooling (RCIC) system shall be OPERABLE with i an OPERABLE flow path capable of automatically taking suction from the sup -

! pression pool and trans' ferring the water to the reactor pressure vessel. 4 ! APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3* with reactor steam dome j pressure greater than 150 psig. f ACTION: i

With'the RCIC system inoperable, operation may continue provided the HPCS *

! system is OPERABLE; restore the RCIC system to OPERABLE status within 14 days or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and 5 reduce reactor steam dome pressure to less than or equal to 150 psig ! within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. ) SURVEILLANCE REQUIREMENTS ! 4.7.3 The RCIC system shall be demonstrated OPERABLE:

a. At least once per 31 days by

Verifying by venting at the high point vents that the system

1.

i piping from the pump discharge valve to the system isolation O valve is filled with water. . ! 2. Verifying that each valve, manual, power operated or automatic 1 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 j position. _ . j b. When tested pursuant to Specification 4.0.5 by verifying that the i RCIC pump develops a flow of greater than or equal to 700 gpm in the i test flow path with a system head corresponding to reactor vessel operating pressure when steam is being supp* lied to the turbine at ] 1020 + 25 - 100 psig (steam dome pressure). I \ { *The provisions of Specification 4.0.4 are not applicable provided the l surveillance is perfomed within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after r.eactor steam pressure is l adequate to perform the test. I j . i i ! PERRY - UNIT 1 3/4 7-6 1, -,--,~~m-.,-,_ _ _ -.v,~-n, nn n en_, _ nn--~-,n__--_--_,,, , - , _,__ --.n __ (

PLANT SYSTEMS ,

! 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-4 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 l criteria of Specification 4.7.4.f., an additional 5% of that type 4 of snubber shall be functionally tested until no more failures are i found or until all snubbers of that type have been functionally tested; or j 2) A representative sample of each type of snubber shall be

functionally tested in accordance with Figure 4.7.4-1. "C" is the total number of snubbers of a type found not meeting the acceptance requirements of Specification 4.7.4.f. The cumulative number of snubbers of a type tested is denoted by "N'!. At the

! end of each day's testing, the new values of "N" and "C" (previous l' day's total plus current day's increments) shall be plotted on Figure 4.7.4-1. If at any time the point plotted falls on or above i the " Reject" line all snubbers of that type shall be functionally 4 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, J , additional snubbers of that type shall be tested until the point falls in the " Accept" region or the " Reject" region, or all the j snubbers of that type have been tested. Testing equipment failure during functional testing may invalidate that day s testing and l allow that day's testing to resume anew at a later time, providing l all snubbers tested with the failed equipment during the day of

. equipment failure are retested; or

3) An initial representative sample of 55 snubbers of each type shall be functionally tested. For each snubber type which does not meet the functional test acceptance criteria, another sample of at least one-half the size of the initial sample shall be tested until the total number tested is equal to the initial sample size multiplied by the factor,1 + C/2, where "C'! is the number of snubbers found which do not meet the functional test 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 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 aust continue until the point falls on or below the " Accept"'line or all the snubbers of that type have been tested. ,

PERRY - UNIT 1 3/4 7-10 PLANT SYSTEMS 3/4.7.6 MAIN TURBINE BYPASS SYSTEM i LIMITING CONDITION FOR OPERATION 3.7.6 The main turbine bypass system shall be OPERABLE. - APPLICABILITY: OPERATIONAL CONDITION 1 when THERMAL POWER is greater than. or equal to 25% of RATED THERMAL POWER. ACTION: With the main turbine bypass system inoperable, restore the system to UFINABLE status within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or reduce THERMAL POWER to less than 25% of RATED THERMAL POWER within the next 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. SURVEILLANCE REQUIREMENTS 4.7.6 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 ore complete cycle of full travel, and

b. 18 months by: 3

1. Performing a system functicnal test which includes simulated automatic actuation and verifying that each automatic valve actuates to its correct position.

2. Demonstrating TURBINE BYPASS SYSTEM RESPONSE TIME meets the following requirements when measured from the initial movement of the main turbine stop or control valve:

a) 80% of turbine bypass system capacity shall be established in less than or equal to 0.3 seconds. b) Bypass valve opening shall start in less than or equal to 0.1 seconds. i l l l ! PERRY - UNIT 1 3/4 7-16 I .. -. - _ _ _ _ - __ . ___ . . - - _._ __- - - __ - -_-_ . . ELECTRICAL POWER SYSTEMS SURVEILI.ANCE REQUIREMENTS (Continued) i . i

7. ' Verifying the pressure in at least one air start receiver for  !

i each diesel generator to be greater than or equal to 210 psig. '

b. 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 day tank.

c. At least once per 92 days by checking for and removing accumulated l water from the fuel oil storage tanks. '

d. At least once per 92 days and from new fuel oil prior to its addi- ,

tion to the storage tanks by verifying that a sample obtained in ' accordance with ASTM-D270-1975 meets the following minimum require- t ments in accordance with the tests specified in ASTM-0975-1977: '

1) A water and sediment content of less than or equal to 0.05 volume percent; l 1

2) , A saybolt universal viscosity at 100*F of greater than or equal ' .

i to 32.6 sus, but less than or equal to 40.1 sus; j

3) An API gravity as specified by the manufacturer at 60*F of greater than or equal to 26. degrees, but less than or equal _to 36 degrees; 4 9

4) An impurity level of less than 2 mg of insolubles per 100 m1 when tested in accordance with ASTM-D2274-70; analysis shall be l

completed within 7 days after obtaining the sample but may be

sampled and analyzed after the addition of new fuel oil; and

5) The othe'r properties specified in Table 1 of ASTM-D975-1977

• and Regulatory Guide 1.137, Revision 1, October 1979, Position '

, 2.a., when tested in accordance with ASTM-D975-1977; analysis l shall be c.ompleted within 14 days after obtaining the sample but may be sampled and analyzed after the addition of new fuel '. oil. ' i

e. At least once per 18 months *, during shutdown, by: ,

1. ' Subjecting the diesel to an inspection in accordance with  ;

instructions 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 1400 kw (LPCS pump) for diesel generator Div 1, greater than or equal to 725 kw (RHR B pump or RHR C pump) ,

• For any start of a diesel, the diesel must be loaded in accordance with the manufacturer's recommendations. +

PERRY - UNIT 1 3/4 8-5 -- __ . _ _ _ _ _ , _ . - _ - . ___ _ _ - , . ?

ELECTRICAL POWER SYSTEMS .

3/4.8.2 D.C. SOURCES D.C. SOURCES - OPERATING LIMITING CONDITION FOR OPERATION l 3.8.2.1 As a minimum, the following D.C. electrical power sources sh'all be OPERABLE: .

a. Division 1, consisting of:

1. 125 volt battery 1R42-5002 or 2R42-S002.

2. 125 volt full capacity charger 1R42-S006 or OR42-S007.

b. Division 2, consisting of:

1. 125 volt battery 1R42-5003 or 2R42-5003.

2. 125 volt full capacity charger 1R42-5008 or OR42-5009.

c. Division 3, consisting of:

1. 125 volt battery 1E22-S005 or 2E22-S005.

2. 125 volt full capacity charger 1E22-5006 or OR42-S011.

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

a. With the Unit 1 and Unit 2 Division 1 batteries and/or.both chargers of the above required Division 1 D.C. electrical power sources inoperable, restore an inoperable Division 1 battery and charger to

' OPERABLE status within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or be in at leas; HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

b. With the Unit 1 and Unit 2 Division 2 batteries and/or both chargers of the above required Division 2 D.C. electrical power sources inoperable, restore an inoperable Division 2 battery and charger to OPERABLE status within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

c. With the Unit 1 and Unit 2 Division 3 batteries and/or both chargers of the above required Division 3 0.C. electrical power sources inoperable, declare the HPCS system inoperable and take the ACTION ,

required by Specification 3.5.1. - SURVEILLANCE REQUIREMENTS 4.8.2.1 Each of the above required 125 volt batteries and chargers shall  ! be demonstrated OPERABLE: .

a. At least once per 7 days by verifying that: l

1. i The parameters in Table 4.8.2.1-1 meet the Category A limits, j and

2. Total battery terminal voltage is greater than or equal to 129 volts on float charge.

PERRY - UNIT 1 3/4 8-12 ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

b. At least once per 92 days and within 7 days after a battery discharge with battery terminal _ voltage below 110 volts, or battery overcharge with battery terminal voltage above 145 volts, by verifying that:

1. The parameters in Table 4.8.2.1-1 meet the Category B limits,

2. There is no visible cerrosion at either terminals or connectors, or the connection resistance of each cell-to-cell and terminal connection is less than or equal to 50 x 10 s ohms for Div 1 and Div 2 batteries and 100 x 10.s ohms for the Div 3 battery.

3. The average electrolyte tecperature of 10 connected cells is above 72*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 50 x 10 8 ohms for Div 1 and Div 2 batteries and 100 x 10 s ohms for the Div 3 battery.

4. The battery chargers 1R42-5006, -5008, OR42-S007, and -S009 will each supply at ,least 400 amperes at a minimum of 125 volts for at least 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />,s, and

5. The battery cha'rgers IE22-5006 and OR42-5011 will each supply atleast50 amp;eresataminimumof125voltsforatleast 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. ,

i

d. Atleastonceper18jmonths,duringshutdown,byverifyingthat either:  ;

i

1. The battery capacity is adequate to supply and maintain in OPERABLE statusiall of the actual emergency loads for the designdutycyc)ewhenthebatteryissubjectedtoabattery service test, or i

2. The battery capacity is adequate to supply a dummy load of the followingprofi)ewhilemaintatoingthebatteryterminal voltage greater than or equal to 105 volts.

i i PERRY - UNIT 1 3/4 8-13 ELECTRICAL POWER SYSTEMS l l D.C. SOURCES - SHUTDOWN  ! LIMITING CONDITION FOR OPERATION 3.8.2.2 As a minimum, Division 1 or Division 2, and, when the HPCS system is required to be OPERABLE, Division 3, of the D.C. electrical power sources shall be OPERABLE with:

a. Division 1 consisting of:

1. 125 volt battery 1R42-S002.

2. 125 volt full capacity charger 1R42-S006 or OR42-5007.

b. Division 2 consisting of: ~

1. 125 volt battery 1R42-5003.

2. 125 volt full capacity charger 1R42-S008 or OR42-S009.

c. Division 3 consisting of:

1. 125 volt battery 1E22-S005.

2. 125 volt full capacity charger 1E22-S006 or OR42-5011.

APPLICABILITY: OPERATIONAL CONDITIONS 4, 5 and *. ACTION:

a. With the Unit 1 and Unit 2 Division 1 batteries and/or both chargers of the above required Division 1 D.C. electrical power sources and the Unit 1 and Unit 2 Division 2 batteries and/or both chargers of the above required Division 2 D.C. electrical power sources inoperable, suspend CORE AliERATIONS, handling of irradiated fuel in the fuel handling building or primary containment and operations with a poten-tial for draining the reactor vessel.

b. With the Unit 1 and Unit 2 Division 3 batteries and/or both chargers of the above required D.C. electrical power sources inoperable, declare the HPCS system inoperable and take the ACTION required by Specification 3.5.2 and 3.5.3.

c. The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.8.2.2 Each of the above required battery and charger shall be demonstrated OPERABLE per Surveillance Requirement 4.8.2.1.

• When handling irradiated fuel in the Fuel Handling Building or primary containment.

PERRY - UNIT 1 3/4 8-16 ELECTRICAL POWER SYSTEMS CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTI , LIMITING CONDITION FOR OPERATION 3.8.4.1 shown in Table 3.8.4.1-1 shall be OPERABLE.All containment penetrat d APPLICABILITY: OPERAT.IONAL CONDITIONS 1, 2 and 3. , ACTION: a. With one or more of the containment penetration conductor overcurrent protective devices shown in Table 3.8.4.1-1 inoperable, declare the affected system for or component the affected systeminoperable and: and apply the appropriate ACTION statement 1. For 13.8 kV circuit breakers, de-energize the 13.8 kV circuit (s) by tripping the associated redundant circuit breaker (s) within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and7verify per days the redundant circuit breaker to be tripped at least once thereafter. 2. For 120-volt circuit breakers remove the inoperable circuit - breaker (s) from service by rac, king out* the breaker within.72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and7verify per daysthe inoperable breaker (s) to be racked out* at least once thereafter. Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, b. The provisions of Specification 3.0.4 are not applicable to overcurrent devices in 13.8 kV circuits which have their redundant circuit breakers tripped or to 120-volt circuits which have the inoperable circuit breaker racked out.* SURVEILLANCE REQUIREMENTS 4.8.4.1 devices shown in Table 3.8.4.1-1 shall be demonstrated OPERAB

a. At least once per 18 months:

1. By verifying that the medium voltage 13.8 kV circuit breakers are OPERABLE by selecting, on a rotating basis, at least 10% of the circuit breakers and performing: a) b) A CHANNEL CALIBRATION of the associated protective relays, An integrated system functional test which includes simulated 1 automatic actuation of the system and verifying that each relay and associated circuit breakers and overcurrent con-trol circuits function as designed, and " control. Racking out may be accomplished by tripping the' breaker under administrative PERRY - UNIT 1 3/4 8-21 I ---,m--,- - - - , - - - - - - ,--- ---.-----.,,,------<,-,-J- - - - - , , - - - - - - - - TABLE 3.8.4.1-1 CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES 13.8 KV LOAD OVERCURRENT PROTECTION Primary Secondary 1833-C001A L1106 1R22-5012 1833-C0018 L1205 1R22-S013 120V LOAD OR CIRCUIT 1821-B760XB 1R25-5043-CB20 NA* 1821-B756XB 1R25-5043-CB18 NA* 1821-8758XB 1R25-SO43-CB19 NA* 1821-B754XB . 1R25-SO43-CB17 NA* IB21-B752XB 1R25-5047-CB11 NA* 1833-B1X (Sp. Htr.) 1R25-SO93-CB7 NA* 1833-B3X (Sp. Htr.) 1R25-SO93-CB8 NA* 1833-B5X (Sp. Htr.) 1R25-5097-CBS NA* 1833-87X (Sp. Htr.) 1R25-5097-CB6 NA* 1833-89X (Sp. Htr.) 1R25-SO93-CB9 NA* 1833-B11X (Sp. Htr.) 1R25-SO93-CB10 NA* IB33-B13X (Sp. Htr.) 1R25-SO97-CB7 NA* 1833-B15X (Sp. Htr.) 1R25-5097-CB8 NA* 1Cll-C1X NA* 1H13-P653-CB1 1C41-89XB (Sp. Htr) 1R25-SO43-CB21 NA* 1E51-B3XB 1R25-SO43-CB24 NA* 1E51-B1XB 1R25-SO43-CB23 NA* 1F42-B3X (Sp. Htr.) 1R25-5097-CB3 .NA*

• Protected by fuse.

PERRY - UNIT 1 3/4 8-23 TABLE 3.8.4.1-1 (Continued) 120V LOAD OR CIRCUIT OVERCURRENT PROTECTION Primary Secondary 1G41-81X 1R25-5077-CB1 NA* 1R25-B516X OR25-5054-CB7 NA* 1R25-B517X OR25-S054-CB13 NA* 1R25-8245X 1R25-5057-CB12 NA* IP56-B1060X 1R25-5053-CB34 NA* ~1P57-83XB IR25-5043-CB15 NA* 1R25-8522X 1R25'-S153-CB13 NA* 1R25-B515X 1R25-S053-CB25 NA* IM16-B7XB 1R25-5047-CB1 NA* 1M16-89XB IR25-SO47-CB3 NA* 1M16-B17XB 1R25-SO47-CBS NA* 1M16-B19XB IR25-SO47-CB6 NA* 1E12-83XB 1R25-5047-CB7 NA* 1E12-87XB 1R25-5047-CB8 NA* 1E12-B11XB 1R25-SO47-CB9 NA* 1E12-815XB 1R25-5047-CB10 NA*

• Protected by fuse.

PERRY - UNIT 1 3/4 8-24 ELECTRICAL POWER SYSTEMS-REACTOR PROTECTION SYSTEM ELECTRIC POWER MONITORING 4 LIMITING CONDITION FOR OPERATION t i 3.8.4.2 Two RPS electric power monitoring assemblies for each inservice RPS MG~ l set or alternate power supply shall be OPERABLE. APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3, 4*, and 5. . ACTION:

a. With one RPS electric power monitoring assembly for an inservice RPS MG set or alternate power supply inoperable, restore the inoperable power monitoring assembly to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or remove the associated RPS MG set or alternate power supply from service.

b. With both RPS electric power monitoring assemblies for an inservice RPS MG set or alternate power supply inoperable, restore at least one electric ,

power monitoring assembly to OPERABLE status within 30 minutes or remove the associated RPS MG set or alternate power supply from service. j SURVEILLANCE REQUIREMENTS 4.8.4.2 The above specified RPS electric power monitoring assemblies shall be determined OPERABLE:

a. By performance of a CHANNEL FUNCTIONAL TEST each time the unit is in COLD SHUTDOWN for a period of more then 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, unless performed within the previous 6 months, and

b. At least once per 18 months by demonstrating the OPERABILITY of over-voltage, under-voltage and under-frequency protective instru-mentation 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 $ 132 VAC, .

2. Under-voltage > 108 VAC, and

3. Under-frequency > 57 Hz.

"Must be demonstrated OPERABLE prior to control red withdrawal. I i . l l PERRY - UNIT 1 3/4 8-25 REFUELING OPERATIONS 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 at least:

a. One OPERABLE RHR pump, and

b. Two OPERABLE RHR heat exchangers.

APPLICABILITY: OPERATIONAL CONDITION 5, when irradiated fuel is in the reactor vessel and the water level is greater than or equal to 22 feet 10 inches above the top of the reactor pressure vessel flange and heat losses to the ambient

• are not sufficient to maintain' 0PERATIONAL CONDITION 5.

ACTION: With no RHR shutdown cooling mode' loop 0PERABLE, within one hour and at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> thereafter, demonstrate the operability of at least one alter-nate method capable of decay heat removal. Otherwise, suspend all operations involving an increase in the reactor decay heat load and establish PRIMARY CONTAINMENT INTEGRITY w'ithin 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. . SURVEILLANCE REQUIREMENTS l 4.9.11.1 At least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> verify at least one RHR shutdown cooling mode loop is capable of taking suction from the reactor vessel and discharging back to the reactor vessel through an RHR heat exchanger with available cooling water. , 1 l l

• Ambient losses must be such that no increase in reactor vessel water temper-ature will occur (even though, REFUELING conditions are being maintained).

l I PERRY - UNIT 1 3/4 9-16 l l l REFUELING OPERATIONS l l l 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 at least:

a. One OPERABLE RHR pump, and

b. Two OPERABLE RHR heat exchangers.

APPLICABILITY: OPERATIONAL CONDITION 5, when irradiated fuel is in the reactor vessel and the water level is less than 22 feet 10 inches above the top of the reactor pressure vessel flange and heat losses to the ambient are not suffi-cient** to maintain OPERATIONAL CONDITION 5. ACTION:

a. With less than the above required shutdown cooling mode loops of the RHR system OPERABLE, within one hour and at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> thereafter, demonstrate the operabil.ity of at least one alternate method capable of decay heat removal for each inoperable RHR shutdown cooling mode loop.

b. With no RHR shutdown cooling mode loop in operation, within one hour establish reactor coolant circulation by an alternate method and monitor reactor coolant temperature at least once per hour.

. c. The provisions of Specification 3.0.4 are not applicable. SURVEILLANCE REQUIREMENTS 4.9.11.2 At least one shutdown cooling mode loop of the residual heat removal system or alternate method shall be verified to be in operation and circulating reactor coolant at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, i j "The shutdown cooling pump may be removed from operation for up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> per 8-hour period.

• • Ambient losses must be such that no increase in reactor vessel water i

temperature will occur (even though REFUELING conditions are being maintained). . PERRY - UNIT 1 3/4 9-17 e 0 3/4.10 SPECIAL TEST EXCEPTIONS 3/4.10.1 PRIMARY CONTAINMENT INTEGRITY /DRYWELL INTEGRITY LIMITING CONDITION FOR OPERATION 3.10.1 The provisions of Specifications 3.6.1.1.1, 3.6.1.2, 3.6.1.3, 3.6.2.1, . 3.6.2.3, 3.6.5.1, 3.6.5.2, 3.9.1 and 3.9.3 and Table 1.2 may be suspended to permit the reactor pressure vessel closure head and the drywell head to be removed and the drywell air lock door to be open when the reactor mode switch is in the Startup position during low power PHYSICS TESTS with THERMAL POWER less than 1% of RATED THERMAL POWER and reactor coolant temperature less than 200*F. APPLICABILITY: OPERATIONAL CONDITIONS 2 and 5, during low power PHYSICS TESTS or shutdown margin demonstrations. ACTION: With THERMAL' POWER greater than or equal to 1% of RATED THERMAL POWER or with the reactor coolant temperature greater than or equal to 200*F, immediately place the reactor mode switch in the Shutdown position. SURVEILLANCE REQUIREMENTS 4.10.1 The THERMAL POWER and reactor coolant temperature'shall be verified to be within the limits at least once per hour during low power PHYSICS TESTS or shutdown margin demonstrations. e O PERRY - UNIT 1 3/4 10-1 i 3/4.11 RADI0 ACTIVE EFFLUENTS ~ 3/4.11.1 LIQUID EFFLUENTS CONCENTRATION LIMITING CONDITION FOR OPERATION 3.11.1.1 The concentration of radioactive material released in liquid effluents to UNRESTRICTED AREAS (see Figure 5.1.1-1) shall be limited to the concentrations specified in 10 CFR Part 20, Appendix B, Table II, Column 2 for radionuclides 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 ifmits, immediately restore the concentration to.within the above limits. SURVEILLANCE REQUIREMENTS 4.11.1.1.1 The radioactivity content of each batch of radioactive liquid waste shall be determined prior to release by sampling and analysis in accord-

ance with Table 4.11.1.1.1-1. The results of pre-release analyses shall be used with the calculational methods in the ODCM to assure that the concentration at the point of release is maintained within the limits of Specification 3.11.1.1.

4.11.'1.1.2 Post release analyses of samples composited from batch re' eases 1 shall be performed in accordance with Table 4.11.1.1.1-1. The results of the ~ l radioactivity analysis 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. 4.11.1.1.3 Continuous releases of radioactive liquid effluents shall be sampled and analyzed in accordance with Table 4.11.1.1.1-1. 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. 1 l l l PERRY - UNIT 1 3/4 11-1 RADI0 ACTIVE EFFLUENTS 3/4.11.3 SOLID RADWASTE 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 site requirements when received at the disposal site. APPLICABILITY: At all times. ACTION:

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

recurrence. - . b. With the SOLIDIFICATION or dewatering not performed in accordance with the PROCESS CONTROL PROGRAM, (1) test the improperly processed waste in each container to ensure that it meets burial ground and shipping requirements and (2) take appropriate administrative action to prevent recurrence. -

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

SURVEILLANCE REQUIREMENTS 4.11.3.1 If the SOLIDIFICATION method is used, the PROCESS CONTROL PROGRAM shall be used to verify the SOLIDIFICATION of at least one representative test specimen from.at least every tenth batch of each type of wet radioactive waste (e.g., filter sludges, spent resins, evaporator bottoms, and sodium sulfate solutions),

a. If any test specimen fails to verify SOLIDIFICATION, the SOLIDIFICA-TION of the batch under test shall be suspended until such time as additonal test specimens can be obtained, alternative SOLIDIFICATION parameters can be determined in accordance with the PROCESS CONTROL PROGRAM, and a subsequent test verifies SOLIDIFICATION. SOLIDIFICATION of the batch may then be resumed using the alternative SOLIDIFICATION parameters determined by the PROCESS CONTROL PROGRAM.

1 PERRY - UNIT 1 3/4 11-18 -_= - 1 TABLE 3.12.1-1 (Continued) RADIOLOGICAL ENVIRONMENTAL MONITORING PROGRAM TABLE NOTATIONS i Sample locations are given on the figure and the table in the ODCM. 4 (1) Specific parameters of distance and direction sector from the centerlin'e of one reactor, and additional description where pertinent, shall be provided for each and every sample location in Table 3.12-1 in a table and figure (s) in the ODCM. Refer to NUREG-0133, " Preparation of Radio-logical 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 circumstances such as hazardous conditions, seasonal unavailability, and malfunction of automatic sampling equipment. If specimens are unobtainable due to sampling equipment malfunction, effort shall be made to complete correc-tive 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 recogn b.ed that, at times, it may not be possible or practicable to continue to obtain samples of the media of choice at the most desired l location or time. In these instances suitable specific alternative media and locations may be chosen for tha particular pathway in question and appropriate substitutions made within 30 days in the Radiological Environ-mental Monitoring Program given in the 00CM. Pursuant to Specification 6.14, submit in the next Semiannual Radioactive Effluent Release Report documen-tation for a change in the ODCM, including a revised figure (s) and table for the ODCM reflecting the new location (s) with supporting information identifying the cause of the unavailability of samples for that pathway and justifying the selection of the new location (s) for obtaining samples. (2) One or more instruments, such as a pressurized ion chamber, for measuring-and recording dose rate continuously may be used in place of, or in addition to, integrating dosimeters. For the purposes of this table, a 4 thermoluminescent 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 l obtain optimum dose information with minimal fading.) (3) Airborne particulate sample filters shall be analyzed for gross beta radioactivity 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or more after sampling to allow for radon and thoron daughter decay. If gross beta activity in air particulate samples is greater than 10 times the yearly mean of control samples, gamma isotopic analysis shall be performed on the individual samples. 1 PERRY - UNIT 1 3/4 12-7 t -- 3/4.2 POWER DISTRIBUTION LIMITS BASES l 1 The specifications of this section assure that the peak cladding temper- ( the postulated design basis' loss-of-coolant accident will not ature exceedfollowing*F the 2200 limit specified in 10 CFR 50.46.  ! 3/4.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE The peak cladding temperature (PCT) following a postulated loss-of-coolant accident is primarily a function of the average heat generation rate of all the rods of a fuel assembly at any axial location and is dependent only secondarily on the rod to rod power distribution within an assembly. The peak clad temperature is calculated assuming a LHGR for the highest powered rod which is equal to or less than the design LHGR corrected for densification. This LHGR times 1.02 is used in the heatup code along with the exposure dependent steady state gap conductance and rod-to-rod local peaking factor. The Technical Specification AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR) is this LHGR of the highest powered rod divided by its local peaking factor. The MAPLHGR limits of Figures 3.2.1-1, 3.2.1-2, and 3.2.1-3 are multiplied by the smaller of either the flow dependent MAPLHGR factor (MAPFAC f ) or the power dependent MAPLHGR factor (MAPFAC p ). corresponding to existing core flow and power state to assure the adherence to fuel mechanical design bases during the most limiting transient. MAPFAC f 's are determined using the three-dimensional BWR simulator code to analyze slow flow runout transients. MAPFAC'saregeneratedusingthesamg p j data base as the MCPR p to protect the core from plant transients other than , core flow increases. The calculational procedure used to establish the APLHGR limits is based on a loss-of-coolant accident analysis. The analysis was performed using l General Electric (GE) calculational models which are consistent with the ! requirements of Appendix K to 10 CFR 50. A complete discussion of each code ( employed in the analysis is presented in Reference 1. Differences in this analysis compared to previous analyses can be broken down as follows.

a. Input Changes

1. Corrected Vaporization Calculation - Coefficients in the vaporization correlation used in the REFLOOD code were corrected.

2. Incorporated more accurate bypass areas - The bypass areas in the top guide were recalculated using a more accurate technique.

3. Corrected guide tube thermal resistance.'

4. Correct heat capacity of reactor internals heat nodes.

PERRY - UNIT 1 B 3/4 2-1 POWER DISTRIBUTION LIMITS BASES . l l AVERAGE PLANAR LINEAR HEAT GENERATION RATE (Continued) 1

b. Model Change

1. Core CCFL pressure differential - 1 psi - Incorporate the issumption  !

that flow from the bypass to lower plenum must overcome a 1 psi l pressure drop in. core.

2. Incorporate NRC pressure transfer assumption - The assumption used in the SAFE-REFLOOD pressure transfer when the pressure is increasing was changed.

A few of the changes affect the accident calculation irrespective of CCFL. These changes are listed below.

a. Input Change

1. Break Areas - The DBA break area was calculat:d more accurately.

b. Model Change .

1. Improved Radiation and Conduction Calculation - Incorporation of CHASTE 05 for heatup calculation.

A list of the significant plant input parameters to the loss-of-coolant accident analysis is presented in Bases Table B 3.2.1-1.

• I 1

4

• e PERRY - UNIT 1 B 3/4 2-2

Bases Table B 3.2.1-1 SIGNIFICANT INPUT PARAMETERS TO THE LOSS-OF-COOLANT ACCIDENT ANALYSIS Plant Parameters; Core THERMAL POWER .................... 3729 Mwt* which corresponds to 105% of rated steam flow Vessel Steam Output ................... 16.2 x 10s 1bm/hr~which corresponds to 105% of rated steam flow Vessel Steam Dome Pressure............. 1060 psia Design Basis Recirculation Line Break Area for:

a. Large Breaks 2.7 ft2,

b. Small Breaks 0.09 ft2 Fuel Parameters:

PEAK TECHNICAL INITIAL SPECIFICATION DESIGN MINIMUM LINEAR HEAT AXIAL CRITICAL FUEL BUNDLE GENERATION RATE PEAKING POWER FUEL TYPE GEOMETRY (kW/ft) FACTOR RATIO Initial Core ~ P8 x 8R 13.4 1. 4 MCPR f A more detailed listing of input of each model and its source is presented in Section II of Reference 1 and subsection 6.3 of the FSAR.

• This power level meets the Appendix K requirement of 102%. The core

, heatup calculation assumes a bundle power consistent with operation of the highest powered rod at 102% of its Technical Specification LINEAR HEAT GENERATION RATE limit. PERRY - UNIT 1 B 3/4 2-3 - - - , , - --w- ,, - - ,-- , --r--, - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - POWER DISTRIBUTION LIMITS BASES 3/4.2.2 MINIMUM CRITICAL POWER RATIO The required operating limit MCPRs at steady state operating conditions as specified in Specification 3.2.2 are derived from the established fuel 4 cladding integrity Safety Limit MCPR of 1.06, and an analysis of abnormal operational transients. For any abnormal operating transient analysis evalua-tion with the initial condition of the reactor being at the steady state operating limit, it is required that the resulting MCPR does not decrease below the Safety Limit MCPR at any time during the transient assuming instrument trip setting given in Specification 2.2. To assure that the fuel cladding integrity Safety Limit is not exceeded during any anticipated abnormal operational transient, the most limiting tran-sients have been analyzed to determine which result in the largest reduction in CRITICAL POWER RATIO (CPR). The type of transients evaluated were loss of flow, increase in pressure and power, positive reactivity insertion, and coolant temperature decrease. The limiting transient yields the largest delta CPR. When added to the Safety Limit MCPR, the required operating limit MCPR of Specification 3.2.2 is obtained. The power-flow map of Figure B 3/4 2.2-1 defines the analytical basis for generation of the MCPR operating limits. The evaluation of a given transient begins with the system initial parameters shown in FSAR Table 15.0-1, 15.E.3-1 and 15.E.3-2 that are input to a GE-core dynamic behavior transient computer program. The code used to eval-uate pressurization events is described in NEDO-24154(3) and the program used in non pressurization events is described in NEDO-10802(2) The outputs of . this program along with the initial MCPR form the input for further analyses of the thermally limiting bundle with the single channel transient thermal hydraulic TASC code described in NEDE-25149(4) . The principal result of this evaluation is the reduction in MCPR caused by the transient. The purpose of the MCPR f and MCPR p is to define operating limits at other than rated core flow and power conditions. At less than 100% of rated flow and power the required MCPR is the largar value of the MCPR and MCPR at the f p existing core flow and power state. The MCPR s are established to protect the f core from inadvertent core flow increases such that the 99.9% MCPR limit requirement can be assured. Figure 3.2.2-2 also reflects the required MCPR values resulting from the analysis performed to justify operation with the feedwater temperature ranging from 420*F to 320*F at 100% RATED THERMAL POWER steady state conditions, and also begond the end of cycle with the feedwater temperature ranging from 420*F and 250 F. The MCPR f s were calculated such that for the maximum core flow rate and the corresponding THERMAL POWER along a conservative steep generic power flow control line, the limiting bundle's relative power was adjusted until the MCPR was slightly above the Safety Limit. Using this relative bundle power, the MCPRs were calculated at different points along this conser.vative steep power flow control line corresponding to different core flows. The calculated MCPR ' at a given point of core flow is defined as MCPR . f PERRY - UNIT 1 B 3/4 2-4 POWER DISTRIBUTION LIMITS - BASES MINIMUM CRITICAL POWER RATIO (Continued) The MCPR p s are established to protect the core from plant transients other than core flow increases, including the localized event such as rod withdrawal error. The MCPR p s were calculated based upon the most limiting transient at the given core power level. For core power less than or equal to 40% of RATED THERMAL POWER, where the EOC-RPT and the reactor scrams on turbine stop valve closure and turbine control valve fast closure are bypassed, separate sets of MRPR p limits are provided for high and low core flows to account for the sig-nificant sensitivity to initial core flows. For core power above 40% of RATED THERMAL POWER, bounding power dependent MCPR limits were developed. At THERMAL POWER levels less than or equal to 25% of RATED THERMAL POWER, the reactor will be operating at minimum recirculation pump speed and the moderator void content will be very small. For all designated control rod patterns which may be employed at this point, operating plant experience indi-cates that the resulting MCPR value is in excess of requirements by a considerable margin. Durin be made at 25%g initial start-up testing of the plant, a MCPR evaluation will of RATED THERMAL POWER level with minimum recirculation pump. speed. The MCPR margin will thus be demonstrated such that future MCPR evaluation below this power level will be shown to be unnecessary. The daily requirement for calculating MCPR when THERMAL POWER is greater than or equal to 25% of RATED THERMAL POWER is sufficient since power distribution shifts are very slow when there have not been significant power or control rod changes. The require-ment for calculating MCPR when a limiting control rod pattern is approached ensures that MCPR will be known following a change in THERMAL POWER or power shape, regardless of magnitude, that could place operation at a thermal limit. 3/4.2.3 LINEAR HEAT GENERATION RATE This specification assures that the Linear Heat Generation Rate (LHGR) in any rod is less than the design linear heat generation even if. fuel pellet i densification is postulated. .

References:

1. General Electric Company Analytical Model for Loss-of-Coolant Analysis in Accordance with 10 CFR 50, Appendix K, NEDE-20566, November 1975. -

2. 'R. B. Linford, Analytical Methods of Plant Transient Evaluations for the GE BWR, NEDO-10802, February 1973.

~ ~

3. Qualification of the One Dimensional Core Transient Model For Boiling Water Reactors, NED0-24154, October 1978.

4. TASC 01-A Computer Program For The T-ransient Analysis of a Single

Channel, Technical Description, NEDE-25149, January 1980.

PERRY - UNIT 1 B 3/4 2-5

i I 1 I I 1 8 .

l l l l l o A. NATURAL CIRCULATION

8. LOW REClRC PUMP SPEED VALVE MINIMUM POSITION l E

o 110 -

C. LOW RECIRC PUMP SPEED VALVE MAXIMUM POSITION

"< D. RATED REClRC PUMP SPEED VALVE MINIMUM POSITION

, s E. LOWEST FLOW AT RATED POWER E F G 100 F. RATED POWER FLOW _

l c:

z G. HIGHEST FLOW AT RATED POWER l

-4 H 90 = f .

1. • • p s/ -

l C

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170 Ag

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-- =- -;

60- ----------1 / -- - - - - - . - - - - . _ - . _ _ _ _ _. ___.r ___ _ _

=

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0 20 30 40 50 60 70 80 90 100 110 120 10 PERCENT CORE FLOW POWER-FLOW OPERATING MAP BASES FIGURE B 3/4 2.2-1 a

i INSTRUMENTATION BASES MONITORING INSTRUMENTATION (Continued) i 3/4.3.7.4 REMOTE SHUTDOWN INSTRUMENTATION AND CONTROLS i i

The OPERABILITY of the remote shutdown monitoring instrumentati6n and - t controls ensures that sufficient capability is available to permit shutdown and maintenance of HOT SHUTDOWN of the unit from locations outside of the control room. This capability is required in the event control room habitability is lost and is consistent with General Design Criteria 19 of 10 CFR 50. -

3/4.3.7.5 ACCIDENT MONITORING INSTRUMENTATION  ;

The OPERABILITY of the accident monitoring instrumentation ensures that suffi-cient information is available on selected plant parameters to monitor and assess important variables following an accident. This capability is consistent with i the recommendations of Regulatory Guide 1.97, " Instrumentation for Light Water , 1 Cooled Nuclear Power Plants to Assess Plant Conditions During and Followi'ng an -

!' Accident," December 1975 and NUREG-0737, " Clarification of TMI Action Plan Require- -

ments," November 1980. The CHANNEL CHECK for the Primary Containment Isolation Valve Position consists of the verification that indication of valve position (open or closed) can be determined by the valve position lights in the control room. The CHANNEL CALIBRATION for the Primary Containment Isolation Valve Position consists of the Posi, tion Indicator Test (PIT), which is conducted in accordance with Specification 4.0.5.

3/4.3.7.6 SOURCE RANGE MONITORS The source range monitors provide the operator with information of the status of the neutron level in the core at very low power levels during startup and shutdown. At these power levels, reactivity additions shall not be made without this flux level information available to the operator. When the inter-- l mediate range monitors are on scale, adequate information is available without-l the SRMs and they can be retracted.

I The SRMs are required OPERABLE in OPERATIONAL CONDITION 2 to provide for rod block capability, and are. required OPERABLE in OPERABLE CONDITIONS 3 and 4 to provide monitoring capability which provides diversity of protection to the mode switch interlocks.  ;

3/4.3.7.7 TRAVERSING IN-CORE PROBE SYSTEM .

The OPERABILITY of the traversing in-core probe system with the specified minimum complement of equipment ensures that the measurements obtained from use of this equipment accurately represent the spatial gamma flux distribution l of the reactor core.

The TIP system OPERABILITY is demonstrated by normalizing all probes .

(i.e., detectors) prior to performing an LPRM cali.bration function. Monitoring core thermal limits may involve utilizing individual detectors to monitor ,

selected areas of the reactor core, thus all detectors may not be required to i OPERABLE. The OPERABILITY of individual detectors to be used for monitoring is.

demonstrated by comparing the detector (s) output with data obtained during the' previous LPRM calibrations.

I PERRY - UNIT 1 B 3/4 3-5

I CONTAINMENT SYSTEMS  !

i i BASES -

DEPRESSURIZATION SYSTEMS (Continued)

In addition to the limits on temperature of the suppression pool water, operating procedures define the action to be taken in the event a safety-relief valve inadvertently opens or sticks open. As a minimum this action shall include: (1) use of all available means to close the valve, (2) initiate suppression pool water cooling', and (3) if other safety-relief valves are used to depressurize the reactor, their discharge shall be separated from that of the stuck-open safety relief valve, where possible, to assure mixing and uniformity of energy insertion,to the pool.

The containment spray sys' tem consists of two 100% capacity loops, each with three spray rings located'at different elevations about the inside circum-ference of the containment. RHR pump A supplies one loop and RHR pump B sup-plies the other. RHR pump C cannot supply the spray system. Dispersion of the flow of water is effected by 345 nozzles in each loop, enhancing the condensa-tion of water vapor in the containment volume and preventing overpressurization.

l Heat rejection is through the RHR heat exchangers. The turbulence caused by,the I spray system aids in mixing the containment air volume to maintain a homogeneous

~

mixture for H2 control.

The suppression pool cooling ~ function is a mode of the RHR system and functions as part of the containment heat removal system. The purpose of the system is to ensure containment integrity following a LOCA by preventing exces-l sive containment pressures and temperatures. The suppression pool cooling mode is designed to limit the long term bulk temperature of the pool to 185*F con-sidering all of the post-LOCA energy additions. The suppression pool cooling trains, being an integral part of the RHR system, are redundant, safety-related component systems that are initiated following the recovery of the reactor vessel water level by ECCS flows from the RHR system. Heat rejection to the emergency service water is accomplished in the RHR heat exchangers.

The suppression pool make up system provides water from the upper containmentpooltothesupprelssionpoolbygravityflowthroughtwo100%

capacity dump lines following a LOCA. The quantity of water provided is sufficient to account for all conceivable post-accident entrapment volumes, ensuring the long term energy ' sink capabilities of the suppression pool and maintaining the water coverage over the uppermost drywell vents. During refueling, there will be admin:istrative control to ensure the make-up dump valves will not be opened.  ;

3/4.6.4 CONTAINMENT ISOLATION' VALVES The OPERABILITY of the containment isolation valves ensures that the containment atmosphere will be isolated from the outside environment in the event of a release of radioactive material to the~ containment atmosphere or pressurization of the containment and is consistent with the requirements of GDC 54 through 57 of Appendix A to 10 CFR 50. Containment isolation within the time limits specified for those isolation. valves designed to close auto-matica11y ensures that the release of radioactive material to the environment will be consistent with the assumptions used in the analyses for a LOCA.

l PERRY - UNIT 1 8 3/4 6-5

CONTAINMENT SYSTEMS

^

BASES 3/4.6.5 VACUUM RELIEF 3/4.6.5.1 CONTAINMENT VACUUM RELIEF AND 3/4.6.5.2 CONTAINMENT HUMIDITY CONTROL Vacuum breakers are provided on the containment to prevent an excessive' vacuum from developing inside containment during an inadvertent or improper operation of the containment spray. Four vacuum breakers and their associated isolation valves are provided. Any two vacuum breakers provide 100% vacuum relief.

The containment vacuum relief system is designed to prevent an excessive vacuum from being created inside the containment following in advertent initiation of the containment spray system. By maintaining. temperature /

relative humidity within the limits for acceptable operation shown on Fig-ure 3.6.5.2-1, the maximum containment vacuum created by actuation of both

containment spray loops will be limited to approximately -0.7 psig.

3/4.6.5.3 DRYWELL VACUUM BREAKERS

. Drywell vacuum breakers are provided on the drywell to prevent drywell flooding due to differential pressure across the drywell and to equalize pres-sure between the drywell and containment.

Two drywell vacuum breakers and their associated isolation valves are provided. Any one vacuum breaker can provide full vacuum relief capability.

3/4.6.6 SECONDARY CONTAINMENT I Secondary containment is designed to minimize any ground level release of

, radioactive material which may result from an accident. The Shield Building provides secondary containment during normal operation when the containment is sealed and in service. At other times, the containment may be open and, when required, secondary containment integrity is specified. .

i l Establishing and maintaining a vacuum in the annulus with the annulus exhaust gas treatment s, stem, along with the surveillance of the doors, hatches, and valves, is adequate to ensure that there are no violations of the integrity of the secondary containment.

The OPERABILITY of the annulus exhaust gas treatment systems ensures that sufficient iodine removal capability will be available in the event of a LOCA.

The reduction in containment iodine inventory reduces the resulting site l

I PERRY - UNIT 1 B 3/4 6-6

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3/4.10 SPECIAL TEST EXCEPTIONS BASES .

3/4.10.1 PRIMARY CONTAINMENT INTEGRITY /DRYWELL INTEGRITY The requirements for PRIMARY CONTAINMENT INTEGRITY and DRYWELL INTEGRITY -

are not applicable during the period when open vessel tests are being performed during the low power PHYSICS TESTS.

3/4.10.2 ROD PATTERN CONTROL SYSTEM In order to perform the tests required in the technical specifications it is necessary to bypass the sequence restraints on control rod movement. The additional surveillance requirements ensure that the specifications on heat generation rates and shutdown margin requirements are not exceeded during the period when these tests are being performed and that individual rod worths do not exceed the values assumed in the safety analysis.

3/4.10.3 SHUTDOWN MARGIN DEMONSTRATIONS Performance of shutdown margin demonstrations with the vessel head removed requires additional restrictions in order to ensure that criticality is properly.

monitored.and controlled. These additional restrictions are specified in this -

LCO.

3/4.10.4 RECIRCULATION LOOPS .

This special test exception permits reactor criticality under no flow conditions and is required to perform certain startup and PHYSICS iESTS while at low THERMAL POWER levels.

3/4.10.5 TRAINING STARTUPS This special test exception permits training startups to be performed with reactor vessel depressurized at low THERMAL POWER and temperature while controlling RCS temperature with one RHR subsystem aligned in the shutdown cooling mode in order to minimize contaminated water discharge to the radioactive waste disposal system.

• e 1

• PERRY - UNIT 1 B 3/4 10-1

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UNIT ORGANIZATION i

t

ADMINISTRATIVE CONTROLS 6.4 TRAINING 6.4.1 A retraining and replacement training program for the unit staff shall be maintained under the direction of the Perry Training Section General Super- '

visor, and shall meet or exceed the requirements and recommendations of Sec-tion 5.5 of ANSI N18.1-1971 and Appendix A of 10 CFR Part 55 and the supplemen- i tal requirements specified in Sections A and C of Enclosure 1 of the March 28, 1980 NRC letter to all licensees, and shall include familiarization with ,

relevant industry operational experience. l

6.5 REVIEW AND AUDIT 6.5.1 PLANT OPERATIONS REVIEW COPHITTEE (PORC)

FUNCTION 6.5.1.1 The PORC shall function to advise the Managers, Perry Plant Departments, on all matters related to nuclear safety.

COMPOSITION

6. 5.1. 2 The PORC shall be composed of the:

Chairman: Manager, Perry Plant Operations Department Vice-Chairman / Member: Manager, Perry Plant Technical Department Vice-Chairman / Member: Technical Superintendent, Perry Plant Technical Department Vice-Chairman / Member: Principal Nuclear Operations Engineer Member: General Supervisor, Operations Section Member: General Supervising Engineer, Technical Section Member: General Supervisor, Maintenance Section Member: Reactor Engineer Member: General Supervising Engineer, Radiation Protection Section Member: Plant Health Physicist Member: General Supervising Engineer, Instrumentation and Control Section Member 4 General Supervising Engineer, Licensing and Compliance Section Member: General Supervising Engineer, Outage Planning Section

~

ALTERNATES

, 6.5.1.3 All alternate members shall be appointed in writing by the PORC Chairman to serve on a temporary basis; however, no more than three alternates shall participate as voting members in PORC activities at any one time.

MEETING FREQUENCY 6.5.1.4 The PORC shall meet at least once per calendar month and as convened by the PORC Chairman or his designated alternate.

PERRY - UNIT 1 6-8

_- _ _ =m . . _ - _ - - -

ADMINISTRATIVE CONTROLS QUORUM

6. 5.1. 5 The quorum of the PORC necessary for the performance of the PORC responsibility and authority provisions of these Technical Specifications shall consist of the Chairman or his designated alternate and at least six members including alternates.

RESPONSIBILITIES 6.5.1.6 The PORC shall be responsible for:

a. Review of all Administrative Procedures; l

b. Review of the safety evaluations for (1) proposed procedures / j instructions, (2) changes to procedures / instructions, equipment, <

systems or facilities, and (3) tests or experiments performed under the provisions of 10 CFR 50.59 to verify that such actions do not '

constitute an unreviewed safety question;

c. Review of proposed procedures / instructions and changes to procedures /

instructions, equipment, systems or facilities which involve an unreviewed safety question as defined in 10 CFR 50.59;

d. Review of proposed tests or experiments which involve an unreviewed safety question as defined in 10 CFR 50.59;

e. Review of proposed changes to Technical Specifications or the Operating License;

f. Investigation of all violations of the Technical Specifications including the preparation and forwarding of reports covering evalua-tion and recomendations to prevent recurrence to the Vice President -

Nuclear Group and to the Nuclear Safety Review Committee;

g. Review of all REPORTABLE EVENTS;

h. Review of the plant Security Plan and Security Contingency Instruc-tions and submittal of recommended changes to the Nuclear Safety Review Committee; i 1. Review of the Emergency Plan and implementing instructions and sub-mittal of recomended changes to the Nuclear Safety Review Committee; j.

Review of changes to the PROCESS CONTROL PROGRAM, the OFFSITE DOSE

CALCULATION MANUAL, and Radwaste Treatment Systems;

k. Review of any accidental, unplanned or uncontrolled radioactive release including the preparation of reports covering evaluation, recommendations, and disposition of the corrective action to prevent recurrence and the forwarding of these reports to the Managers, Perry

, Plant Departments, the Nuclear Safety Review Committee and the Vice President - Nuclear Group;

1. Review of Unit operations to detect potential hazards to nuclear safety;

m. Investigations or analysis of special subjects as requested by the Chairman of the Nuclear Safety Review Committee; and

n. Review of the Fire Protection Program and implementing procedures and submittal of recommended changes to the Nuclear Safety Review Committee.

PERRY - UNIT 1 6-9

ADMINISTRATIVE CONTROLS SEMIANNUAL RADIOACTIVE EFFLUENT RELEASE REPORT (Continued)

The Semiannual Radioactive Effluent Release Reports shall include any changes made during the reporting period to the PROCESS CONTROL PROGRAM (PCP) and to the OFFSITE DOSE CALCULATION MANUAL (ODCM), pursuant to Specifications 6.13 and 6.14, respectively, as well as any major change to Liquid, Gaseous, or Solid Radwaste:

Treatment Systems pursuant to Specification 6.15. It shall also include a list-ing of new locations for dose calculations and/or environmental monitoring iden-tified by the Land Use Census pursuant to Specification 3.12.2.

The Semiannual Radioactive Effluent Release Reports shall also include the:

following: an explanation as to why the inoperability of liquid or gaseous effluent monitoring instrumentation was not corrected within the time specified in Specification 3.3.7.9 or 3.3.7.10, respectively; and description of the even.ts leading to liquid holdup tanks exceeding the limits of Specification 3.11.1.4. ,

MONTHLY OPERATING REPORTS  ;

6.9.1.8 Routine reports of operating statistics a'nd shutdown experience shall be submitted on a monthly basis to the Director, Office of Resource Management,.

U.S. Nuclear Regulatory Commission, Washington, D.C. 20555, with a copy to the .

Regional Administrator of the Regional Office no later than the 15th of each month following the calendar month covered by the report.

SPECIAL REPORTS 6.9.2 Special reports shall be submitted to the Regional Administrator of the -

Regional Office within the time period specified for each report.

6.9.3 Safety / relief valve failures will be reported to the Regional Administrator of the Regional Office of the NRC via the Licensee Event Report system within 30 days.

6.9.4 Violations of the requirements of the fire protection program described ,

in the Final Safety Analysis Report which would have adversely affected the ,

ability to achieve and maintain safe shutdown in the event of a fire shall be reported to the Regional Administrator of the Regional Office of the NRC via '

the Licensee Event Report system within 30 days. ,

6.10 RECORD RETENTION

! 6.10.1 In addition to the applicable record retention requirements of Title 10, Code of Federal Regulations, the following records shall be retained for at least the minimum period indicated.

6.10.2 The following records shall be retained for at least 5 years:

a. Records and logs of unit operation covering time interval at each power level. ,

b. Records and logs of principal maintenance activities, inspections, repair, and replacement of principal items of equipment related to nuclear safety.

PERRY - UNIT 1 6-21

ADMINISTRATIVE CONTROLS RECORD RETENTION (Continued) -

c. AllREPORTABLEEVENTb.

I

d. Records of surveillance activities, inspections, and calibrations required by these Technical Specifications.

e. Records of changes made to the procedures required by Specification 6.8.1.

f. Records of radioactive shipments.

g. Recordsofsealed'so;urceandfissiondetectorleaktestsandresults.

h. Records of annual physical inventory of all sealed source material of record.

l 6.10.3 The following recordss ' hall be retained for the duration of the unit Operating License:  ; ,,

a. Records and drawingc 'hanges reflecting unit design modifications made to systems and equipment described in the Final Safety Analysis Report.

b. Records of new and irradiated fuel inventory, fuel transfsrs, and assembly burnup histories.

c. Records of radiation exposure for all individuals entering radiation control areas.  ;

d. Records of' gaseous a'nd liquid radioactive material released to the environs.  ;

e. Records of transient'or operational cycles for those unit components identified in Table 5.7.1-1.

f. Records of reactor tests and experiments. -

g. Records of training and qualification for current members of the unit-8 staff.

h. RecordsofinservicelinspectionsperformedpursuanttotheseTechnical

( Specifications. j i

1. Records of quality assurance activities required by the Operational Quality Assurance Manual,

j. Records of reviews performed for changes made to procedures or equip-ment or reviews of tests and experimenti pursuant to 10 CFR 50.59.

k. Records of meetings of the PORC and the NSRC.

l PERRY - UNIT 1 6-22 1

ADMINISTRATIVE CONTROLS RECORD RETENTION (Continued) -

1. Records of the service lives of all liydraulic and mechanical snubbers including the date at which the service life commences and associated installation and maintenance records,

m. Records of analyses required by the radiological environmental moni- .

toring program that would permit evaluation of the accuracy of the analysis at a later date. This would include procedures effective at the specified times and QA records showing that these procedures were followed.

%\

6.11 RADIATION PROTECTION PROGRAM 6.11.1 Procedures for personnel radiation protection shall be prepared consist-ent with the requirements of 10 CFR Part 20 and shall be approved, maintained, and adhered to for all operations involving personnel radiation exposure.

l 6.12 HIGH RADIATION AREA 6.12.1 In lieu of the " control device" or " alarm signal" required by paragraph 20.203(c)(2) of 10 CFR Part 20, each high radiation area in which the intensity of radiation is greater than 100 mrem /hr** but less than 1000 mrem /hr** shall be barricaded and conspicuously posted.as a high radiation area and entrance thereto shall be controlled by requiring issuance of a Radiation Work Permit (RWP)*. Any individual or group of individuals permitted to enter such areas shall be provided with or accompanied by one or morp of the following:

l

a. A radiation monitoring device which continuously indicates the radiation dose rate in the area.

b. A radiation monitoring device which continuously integrates the radiation dose rate in the area and alarms when a preset integrated dose is received. Entry into such areas with this monitoring device may be made after the dose rate levels in the area have been established and personnel have been made knowledgeable of them.

c. A health physics qualified individual i.e., qualified in accordance l with ANSI N18.1-1971, with a radiation' dose rate monitoring device who is responsible for providing positive control over the activi-ties within the area and shall perform periodic radiation surveil-lance at the frequency specified by the Plant Health Physicist.

• Health physics personnel or personnel escorted by health physics personnel shall be exempt from the RWP issuance requirement during the performance of their assigned radiation protection duties, provided they are otherwise follow-ing plant radiation protection procedures for entry into high radiation areas. i

• • Measurement made at 18 inches from source of radioactivity.

l PERRY - UNIT 1 6-23

.