Text

Amend 21 to License NPF-29,revising Tech Specs Re Names & Designation of Certain Plant Svc Water Valves,Record Retention Specs & Control Rod Scram Discharge Vol
	ML20215L243
Person / Time
Site:	Grand Gulf
Issue date:	10/17/1986
From:	Butler W; Office of Nuclear Reactor Regulation
To:	;
Shared Package
ML20215L247	List: ML20215L243; ML20215L248;
References
	TAC-60587, TAC-60588, TAC-60589, TAC-60590, TAC-60591, TAC-60592, TAC-61196, TAC-61782, NUDOCS 8610280544
	Download: ML20215L243 (67)
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UNITED STATES

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NUCLEAR REGULATORY COMMISSION y

y WASHINGTON, D. C. 20555

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MISSISSIPPI POWER & LIGHT COMPANY MIDDLE SOUTH ENERGY, INC.

SOUTH MISSISSIPPI ELECTRIC POWER ASSOCIATION DOCKET NO. 50-416 GRAND GULF NUCLEAR STATION, UNIT 1 AMENDMENT TO FACILITY OPERATING LICENSE Amendment No. 21 License No. NPF-29 1.

The Nuclear Regulatory Commission (the Commission) has found that

~

A.

The application for amendment by Mississippi Power & Light Company, Middle South Energy, Inc., and South Mississippi Electric Power Association, (the licensees) dated January 29, 1986 (as amended April 14, July 16 and August 26, 1986), June 13, 1986 (as amended August 26,1986), and July 25, 1986 (as amended August 11,1986),

complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Comission's rules and regulations set forth in 10 CFR Chapttr I; B.

The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Comission; C.

There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Comission's regulations; D.

The issuance of this amendment will not be inimical to the comon defense and security or to the health and safety of the public; and E.

The issuance of this amendment is in accordance with 10 CFR Part 51 of the Comission's regulations and all applicable requirements have been satisfied.

2.

Accordingly, Facility Operating License NPF-29 is amended as follows:

A.

Change paragraph 2.C.(33)(b) to read as follows:

(b) Training Durina low Power Testing (I.G.1, SER)

Prior to restart following the first refueling outage, MP&L shall complete the additional training and testing related to TMI Action Plan I.G.1 as described in Section 2.3 of the MP&L submittal dated April 3, 1986.

3.

The license is further amended by changes to the Technical Specifications as indicated in the attachment to this license amendment, and paragraph 2.C.(2) of Facility Operating License No. NPF-29 is hereby amended to read as follows:

8610280544 861017 PDR ADOCK 05000416 P

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, Technical Specifications The Technical Specifications contained in Appendix A and the Environmental Protection Plan contained in Appendix B, as revised through Amendment No.

21, are hereby incorporated into this license.

Mississippi Power & Light Company shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

4 The charges to the Technical Specifications on Pages 3/4 6-31, 3/4 6-39, 3/4 6-42., 3/4 6-44, 3/4 12-1 and 6-20 and amended License Condition 2.C.(33)(b) are effective upon issuance of this amendment and the remainder of the changes to the Technical Specifications are effective when equipment necessitating the changes is installed and made operable but not later than startup following the first refueling outage.

FOR THE NUCLEAR REGULATORY COMMISSION 5

Walter R. Butler, Director BWR Project Directorate No. 4 Division of BWR Licensing

Attachment:

Changes to the Technical Specifications Date of Issuance: October 17, 1986 h

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. Technical Specifications The Technical Specifications contained in Appendix A and the Environmental Protection Plan contained in Appendix B, as revised through Amendment No. 21, are hereby incorporated into this license.

Mississippi Power & Light Company shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

4.

The changes to the Technical Specifications on Pages 3/4 6-31, 3/4 6-39, 3/4 6-42, 3/4 6-44, 3/4 12-1 and 6-20 and amended License Condition 2.C.(33)(b) are effective upon issuance of this amendment and the remainder of the changes to the Technical Specifications are effective when equipment necessitating the changes is installed and made operable but not later than startup following the first refueling outage.

FOR THE NUCLEAR REGULATORY COMMISSION Walter R. Butler, Director BWR Project Directorate No. 4 Division of BWR Licensing

Attachment:

Changes to the Technical Specifications Date of Issuance: October 17, 1986 7

ATTACHMENT TO LICENSE AMENDMENT NO. 21 FACILITY OPERATING LICENSE NO. NPF-29 DOCKET NO. 50-416 Replace the following pages of the Appendix "A" Technical Specifications with the attached pages. The revised pages are identified by Amendment number and contain vertical lines indicating the area of change. Asterisk pages provided to maintain document completeness.*

Remove Insert vii vii*

viii viii xiii xiii*

xiv xiv 2-3 2-3*

2-4 2-4 2-4a 2-4a 3/4 1-3 3/4 1-3*

3/4 1-4 3/4 1-4 3/4 1-4a 3/4 1-5 3/4 1-5 3/4 1-6 3/4 1-6*

3/4 3-3 3/4 3-3 3/4 3-4 3/4 3-4*

3/4 3-7 3/4 3-7*

3/4 3-8 3/4 3-8 3/4 3-29 3/4 3-29 3/4 3-30 3/4 3-30*

3/4 3-35 3/4 3-35*

3/4 3-35a 3/4 3-35a*

3/4 3-36 3/4 3-36 3/4 5-3 3/4 5-3 3/4 5-4 3/4 5-4*

3/4 5-5 3/4 5-5 3/4 5-Sa 3/4 5-6 3/4 5-6*

3/4 6-31 3/4 6-31 3/4 6-32 3/4 6-32*

3/4 6-33 3/4 6-33*

3/4 6-34 3/4 6-34 3/4 6-39 3/4 6-39 3/4 6-40 3/4 6-40*

3/4 6-41 3/4 6-41*

3/4 6-42 3/4 6-42 3/4 6-43 3/4 6-43*

3/4 6-44 3/4 6-44 3/4 6-45 3/4 6-45*

3/4 6-46 3/4 6-46 3/4 6-47 3/4 6-47 l

. 3/4 6-48 3/4 6-48*

3/4 8-23 3/4 8-23 3/4 8-23a 3/4 8-23a*

3/4 8-24 3/4 8-24*

3/4 8-25 3/4 8-25*

3/4 8-26 3/4 8-26 3/4 8-29 3/4 8-29 3/4 8-30 3/4 8-30*

3/4 8-31 3/4 8-31 3/4 8-32 3/4 8-32 3/4 8-37 3/4 8-37 3/4 8-38 3/4 8-38*

3/4 8-41 3/4 8-41*

3/4 8-42 3/4 8-42 3/4 8-53 3/4 8-53 3/4 8-54 3/4 8-54*

3/4 12-1 3/4 12-1 3/4 12-2 3/4 12-2*

B 3/4 6-7 B 3/4 6-7 B 3/4 6-8 B 3/4 6-8 8 3/4 6-8a 6-19 6-19*

6-20 6-20

,y c

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INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREME'NTS SECTION PAGE 3/4.6 CONTAINMENT SYSTEMS 3/4.6.1 PRIMARY CONTAINMENT Primary Containment Integrity.............................

3/4 6-1 Containment Leakage........................................

3/4 6-2 Containment Air Locks...................

3/4 6-5 l

(

MSIV Leakage Control System................................

3/4 6-7

~

Feedwater Leakage Control System...........................

3/4 6-8 Containment Structural Integrity...........................

3/4 6-9 Containment Internal Pressure..............................

3/4 6-10 Containment Average Ai r Temperature........................

3/4 6-11 Containment Purge System...................................

3/4 6-12 3/4.6.2 DRYWELL ---

Drywell Integrity..........................................

3/4 6-13 Drywell Bypass Leakage.....................................

3/4 6-14 D rywe l l A i r Lo c k s..........................................

3/4 6-15 Drywell Structural Integrity...............................

3/4 6-i7 Drywell Internal Pressure....................

3/4 6-18 Drywell Average Air Temperature............................

3/4 6-19 Drywell Vent and Purge.....................................

3/4 6-20 3/4.6.3 DEPRESSURIZATION SYSTEMS L

Suppression Poo1...........................................

3/4 6-21 Containment Spray..........................................

3/4 6-25 Suppression Pool Cooling...................................

3/4 6-26 Suppression Pool Nakeup System.............................

3/4 6-27 3/4.6.4 CONTAINMENT AND DRYWELL ISOLATION VALVES...................

3/4 6-28 GRAND GULF-UNIT 1 vii

.n.

a.

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE CONTAINMENT SYSTEMS (Continued) 3/4.6.5

'dRYWELLVACUUMRELIEF......................................

3/A 6-46 3/4.6.6 SECONDARY CONTAINMENT Secondary Containment Integrity............................

3/4 6-48 Secondary Containment Automatic Isolation Dampers /

Va1ves.....................................................

3/4 6-49 Standby Gas Treatment System...............................

3/4 6-55 3/4.6.7 ATMOSPHERE CONTROL Containment Hydrogen Recombiner Systems....................

3/4 6-58 Containeent and Drywell Hydrogen Ignition System...........

3/4 6-59 Combustible Gas Control Purge System.......................

3/4 6-66 1

3/4.7 PLANT SYSTEMS 3/4.7.1 SERVICE WATER-SYSTEMS Standby Service Water System...............................

3/4 7-1 l

High Pressure Core Spray Service Water System..............

3/4 7-3 Ultimate Heat Sink.........................................

3/4 7-4 3/4.7.2 CONTROL ROOM EMERGENCY FILTRATION SYSTEM...................

3/4 7-5 3/4.7.3 REACTOR CORE ISOLATION COOLING SYSTEM......................

3/4 7-7 3/4.7.4 SNUBBERS...................................................

3/4 7-9 3/4.7.5 SEALED SOURCE CONTAMINATION................................

3/4 7-15 3/4.7.6 FIRE SUPPRESSION SYSTEMS Fire Suppression Water System.........

3/4 7-17.

Spray and/or Sprinkler Systems.............................

3/4 7-20 CDs Systems................................................

3/4 7-22 Halon Systems..............................................

3/4 7-24 Fire Hose Stations.........................................

3/4 7-25

. Yard Fire Hydrants and Hydrant Hose Houses.................

3/4 7-28 GRAND GULF-UNIT 1 viii Amendment No. 21 Effective Cate:

INDEX BASES SECTION PAGE j

INSTRUMENTATION (Continued) 3/4.3.7 MONITORING INSTRUMENTATION Radiation Monitoring Instrumentation...............

B 3/4 3-4 Seismic Monitoring Instrumentation.................

B 3/4 3-4 Meteorological Monitoring Instrumentation..........

B 3/4 3-4 Remote Shutdown System Instrumentation and Controls.........................................

B 3/4 3-4 Accident Monitoring Instrumentation................

B 3/4 3-4 Source flange Moni tors..............................

B 3/4 3-5 Traversing In-Co're Probe System....................

B 3/4 3-5

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Chlorine Detection System..........................

B 3/4 3-5 Fire Detection Instrumentation.....................

B 3/4 3-5 Loose-Part Detection System........................

B 3/4 3-6 Radioactive Liquid Effluent Monitoring Instrumentation..................................

B 3/4 3-6 Radioactive Gaseous Effluent Monitoring Instrumentation..................................

B 3/4 3-6 3/4.3.8 PLANT SYSTEMS ACTUATION INSTRUMENTATION............

B 3/4 3-6 3/4.3.9 TURBINE OVERSPEED PROTECTION.......................

B 3/4 3-7 3/4.3.10 NEUTRON FLUX MONITORING INSTRUMENTATION............

B 3/4 3-7 l

3/4.4 REACTOR COOLANT SYSTEM 3/4.4.1 RECIRCULATION SYSTEM...............................

B 3/4 4-1 3/4.4.2 SAFETY / RELIEF VALVES.........................,.....

B 3/4 4-2 3/4.4.3 REACTOR COOLANT SYSTEM LEAKAGE Leakage Detection Systems..........................

B 3/4 4-2 Operational Leakage................................

B 3/4 4-2 3/4.4.4 CHEMISTRY..........................................

B 3/4 4-3 3/4.4.5 SPECIFIC ACTIVITY..................................

,B 3/4 4-3 3/4.4.6 PRESSURE / TEMPERATURE LIMITS....>...................

B 3/4 4-4 3/4.4.7 MAIN STEAM LINE ISOLATION VALVES................... - B 3/4 4-5 3/4.4.8 STRUCTURAL INTEGRITY...............................

B 3/4 4-5 3/4.4.9 RESIDUAL HEAT REM 0 VAL..............................

B 3/4 4-5 GRAND GULF-UNIT 1 4

xiii Amendment No.16 l

INDEX BASES SECTION PAGE 3/4.5 EMERGENCY CORE COOLING SYSTEM 3/4.5.1/2 ECCS - OPERATING and SHUTD0WN......................

B 3/4 5-1 3/4.5.3 SUPPRESSION P00L...................................

B 3/4 5-2 3/4.6 CONTAINMENT SYSTEMS 3/4.6.1 PRIMARY CONTAINMENT Primary Containment Integrity......................

B 3/4 6-1

~

Containment Leakage................................

B 3/4 6-1 Containment Air Locks..............................

B 3/4 6-1 MSIV Leakage Centrol System........................

B 3/4 6-1 Feedwater Leakage Control System...................

B 3/4 6-2 Containment Structural Integrity...................

B 3/4 6-2 Containment Internal Pressure......................

B 3/4 6-2 Containment Average Air Temperature................

B 3/4 6-2 Containment Purge System...........................

B 3/4 6-2 3/4.6.2 DRWELL D rywe l l I nte g ri ty..................................

B 3/4 6-3 Drywell Bypass Leakage.............................

B 3/4 6-3 D rywel l Ai r Loc ks..................................

B 3/4 6-3 Drywel l Structural Integrity.......................

B 3/4 6-4 Drywell Internal Pressure..........................

B 3/4 6-4 Drywell Average Ai r Temperature....................

B 3/4 6-4 D rywe l l Ve nt a nd Pu rg e.............................

B 3/4 6-4 3/4.6.3 DEPRESSURIZATION SYSTEMS...........................

B 3/4 6-4 3/4.6.4 CONTAINMENT AND DRYWELL ISOLATION VALVES...........

B 3/4 6-7 3/4.6.5 DRYWELL VACUUM RELIEF..............................

B 3/4 6-7 l 3/4.6.6 SECONDARY CONTAINMENT..............................

B 3/4 6-8 3/4.6.7 ATMOSPHERE CONTR0L.................................

B 3/4 6-9 GRAND GULF-UNIT 1 xiv Amendment No. 21 Effective Date:

SAFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGS 2.2 LIMITING SAFETY SYSTEM SETTINGS REACTOR PROIECTION SYSTEM INSTRUMENTATION SETPOINTS 2.2.1 The reactor protection system instrumentation setpoints shall be set consistent with the Trip Setpoint values shown in Table 2.2.1-1.

APPLICABILITY: As shown in Table 3.3.1-1.

ACTION:

With a reactor protection system instrumentation setpoint less conservative than the value shown in the Allowable Values column of Table 2.2.1-1, declare the channel inoperable and apply the-applicable ACTION statement requirement of Specification 3.3.1 until the channel is restored to OPERABLE status with its setpoint adjusted consistent with the Trip Setpoint value.

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REACTOR PROTECTION SYSTEM INSTRUMENTATION SETFOINTS 5

g ALLOWABLE I

FUNCTIONAL UNIT TRIP SETPOINT VALUES Cy 1.

Intermediate Range Monitor, Neutron tiux-High 5 120/125 divisions 5 122/125 divisions g

of full scale of full scale

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2.

Average Power Range Monitor:

a.

Neutron Flux-High, Setdown 5 15% of RATED

~ 5 20% of RATED THERMAL POWER THERMAL POWER b.

Flow Biased Simulated Thermal Power-High

1) During two recirculation loop operation:

a) Flow Biased 5 0.66 W+64%, with 5 0.66 W+67%, with a maximum of a maximum of b) High Flow Clamped 5 111.0% of RATED 5 113.0% of RATED THERMAL POWER THERMAL POWER I

_2) During single recirculation loop operation:

a) Flow Biased

< 0.66 W+40%

< 0.66 W+43%

b) High Flow Clamped

- Not Required

- Not Required OPERABLE OPERABLE c.

Neutron Flux-High

-< 118% of RATED

< 120% of RATED THERMAL POWER

- THERMAL POWER d.

Inoperative NA NA 3.

Reactor Vessel Steam Dome Pressure - High 5 1064.7 psig 5 1079.7 psig 4.

Reactor Vessel Water Level - Low, Level 3

> 11.4 inches above

> 10.8 inches above instrument zero*

instrument zero*

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Reactor Vessel Water Level-High, Level 8

-< 53.5 inches above

< 54.1 inches above 3

{[m instrument zero*

- instrument zero*

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_ TABLE 2.2.1-1 (Continued)

REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS FUNCTIONAL UNIT iALLOWABLE o

TRIP SETPOINT VALUES C

T 6.

Main Steam Line Isolation Valve - Closure 5 6% closed 5 7%, closed 3

7.

Main Steam Line Radiation - High 5 3.0 x full power 5 3.6 x full power l

background background g

8.

Drywell Pressure - High 5 1.23'psig 5 1.43 psig 9.

Scram Discharge Volume Water Level - High 2

a.

Transmitter / Trip Unit

< 60% of full scale

< 63% of full scale b.

Float Switch i 64"

~< 65'

10. Turbine Stop Valve - Closure 1 40 psig**

1 37 psig y

11. Turbine Control Valve Fast Closure, g

Trip 011 Pressure - Low 1 44.3 psig**

142 psig

12. Reactor Mode Switch Shutdown Position NA NA

13. Manual Scram NA NA i

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

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

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REACTIVITY CONTROL SYSTEMS 3/4.1.3 CONTROL RODS CONTROL R0D OPERABILITY LIMITING' CONDITION FOR OPERATION 3.1.3.1 All control rods shall be OPERABLE.

APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2.

ACTION:

With one control rod inoperable due to being immovable, as a result of a.

excessive friction or mechanical interference, or known to be untrippable:

1.

Within one hour:

a)

Verify that the inoperable control rod, if withdrawn, is separated from all other inoperable control rods by at least two control cells in all directions.

b)

Disarm the, associated directional control valves ** either:

1)

Elettrically, or 2)

Hydraulically by closing the drive water and exhaust water isolation valves.

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

2.

Comply with Surveillance Requirement 4.1.1.c within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

3.

Comply with Surveillance Requirement 4.1.3.1.2.b.

4.

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

b.

With one or more control rods trippable but inoperable for causes other i

than addressed in ACTION a, above:

1.

If the inoperable control rod (s) is withdrawn, within one hour verify:

a) l That the inoperable withdrawn control rod (s) is separated from all other inoperable withdrawn control rods by at least two control cells in all directions, and b)

The insertion capability of the inoperable witndrawn control l

rod (s) by inserting the control rod (s) at least one notch by drive water pressure within the normal operating range *.

Otherwise, insert the inoperable withdrawn control rod (s) and disarm the associated directional control valves ** either:

l a)

Electrically, or b)

Hydraulically by closing the drive water and exhaust water isolation valves.

"The inoperable control rod may then be withdrawn to a position no further withdrawn than its position when found to be inoperable.

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

GRAND GULF-UNIT I 3/4 1-3

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i REACTIVITY CONTROL SYSTEMS LIMITING CONDITION FOR OPERATION (Continued)

ACTION (Continued) i 2.

If the inoperable control rod (s) is inserted, within one hour j

disarm the associated directional control valves ** either:

a)

Electrically, or b)

Nedraulically by closing the drive water and exhaust water isolation valves.

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

3.

The provisions of Specifjcation 3.0.4 are not applicable.

With more than 8 control rods inoperable, be in at least NOT SHUTDOWN c.

within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

With one scram discharge volume vent valve and/or one scram discharge d.

volume drain valve inoperable and open, restore the inoperable valve (s) to OPERABLE status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or be in at least HOT SHUTDOWN within the naxt 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

With two scram discharge volume ver.t valves and/or two scram discharge e.

volume drain valves inoperable and open, restore one valve in the vent line and one valve in the drain Ifne to OPERABLE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months and restore all valves to OPERABLE status within the next 16 hours1.851852e-4 days 0.00444 hours 2.645503e-5 weeks 6.088e-6 months or close at least one vent valve and one drain valve and be in a least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

f.

With any scram discharge volume vent valve (s) and/or any scram discharge i

volume drair, valve (s) inoperable and closed except when required by ACTION statement e. above, restore all valves to OPERABLE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

SURVEILLANCE REQUIREMENTS 4.1.3.1.1 The scram discharge volume drain and vent valves shall be demonstrated OPERABLE by:

At least once per 31 days verifying each valve to be open,* and a.

b.

At least once per 92 days cycling each valve through at least one complete cycle of full travel.

These valves may be closed intermittently for testing under administrative controls.

]

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

4 GRAND GULF-UNIT 1 3/4 1-4 Amendment No. 21 Effective Date:

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REACTIVITY CONTROL SYSTEMS LIMITING CONDITION FOR OPERATION (Continued) 4.1.3.1.2 When above the low power setpoint of the RPCS, all withdrawn control rods net. required to have their directional control valves disarmed electrically or hydraulically shall be demonstrated OPERABLE by moving each control rod at least one notch:

At least once per 7 days, and a.

b.

At least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months when any control rod is immovable as a result of excessive friction or mechanical interference.

4.1.3.1.3 All control rods shall be demonstrated OPERABLE by performance of Surveillance Requirements 4.1.3.2, 4.1.3.3, 4.1.3.4 and 4.1.3.5.

-h GRAND GULF-UNIT 1 3/4 1-4a gndgen,tgo,21 l g

REACTIVITY CONTROL SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) 4.1.3.1.4 The scram discharge volume shall be determined OPERABLE by demonstrating:

a.*

The scram discharge volume drain and vent valves OPERABLE, when l

control rods are scram tested from a normal control rod configuration of less than or equal to 50% R0D DENSITY at least once per 18 months, by verifying that the drain and vent valves:

1.

Close within 30 seconds after receipt of a signal for control rods to scram, and 2.

Open when the scram signal is reset.

b.

Proper level sensor response by performance of a CHANNEL FUNCTIONAL TEST of the scram discharge volume scram and control rod block level instrumentation at least once per 31 days.

~ _ _

I l

The provisions of Specification 4.0.4 are not applicable provided this l

surveillance is performed at least once per 18 months, i

GRAND GULF-UNIT 1 3/4 1-5 Amendment No. 21 l

Effective Date:

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REACTIVITY CONTROL SYSTEMS CONTROL ROD MAXIMUM SCRAM INSERTION TIMES LIMITING CONDITION FOR OPERATION 3.1.3.2 The.5aximum scram insertion time of each control rod from the fully withdraw; position, based on de-energization of the scram pilot valve solenoids as time zero, shall not exceed the following limits:

Maximum Insertion Times to Notch Position (Seconds)

Reactor Vessel Dome Pressure (psig)*

43 29 13 950 G

M M

1050 0.32 0.86 1.57 APPLICABILITY: OPERATIONAL CONDITIONS 1 cr.d 2.

h ACTION:

a.

With the maximum scram insertion time of one or more control rods

~

exceeding the maximum scram insertion time limits of Specification 3.1.3.2 as determined by Surveillance Requirement 4.1.3.2.a or b, operation may continue provided that:

~

1.

For all " slow" control rods, i.e., those which exceed the limits of l

Specification 3.1.3.2, the individual scram insertion time.s do not I

exceed the following limits:

Maximum Insertion Times to Notch Position (Seconds)

Reactor Vessel Dome Pressure (psia)*

43 29 13 950 D

M M

1050 0.39 1.14 2.22 2.

For " fast" control rods, i.e., those which satisfy the limits of Specification 3.1.3.2, the average scram insertion times do not exceed the following limits:

Maximum Average Insertion Times to Notch Position-(Seconds)

Reactor Vessel Dome Pressure (psia)*

43 29 13 950 U

G W

1050 0.31 0.84 1.53 3.

The sum of " fast" control rods with individual scram insertion times in excess of the limits of ACTION a.2 and of " slow" control rods does not exceed 7.

4.

No " slow" control rod, " fast" control rod with individual scram insertion time in excess of the limits of ACTION a.2, or other-wise inoperable control rod occupy adjacent locations in any direction, including the diagonal, to another such control rod.

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

"For intermediate reactor vessel dome pressure, the scram time criteria is determined by linear interpolation at each~ notch position.

GRAND GULF-UNIT 1 3/4 1-6 M*O

Q i

TABLE 3.3.1-1 (Continued) oCg REACTOR PROTECTION SYSTEM INSTRIMENTATION E

T APPLICABLE MINIMUM g

OPERATIONAL OPERABLE CHANNELS y

FUNCTIONAL UNIT CONDITIONS PER TRIP SYSTEM (a)

ACTION 9.

Scram Discharge Volume Water Level - High 6

a.

Transmitter / Trip Unit 1, 2, 2

1 I9)

S 2

3 b.

Float Switch 1, 2, 2

1 l

IU) 2 3

S

10. Turbine Stop Valve - Closure 1(h) 4 6

l t

[

11. Turbine Control Valve Fast Closure, Valve Trip System 011 Pressure - Low 1(h) 2 6

I I

12.

Reactor Mode Switch Shutdown 1

Position 1, 2 2

1 t

3. 4 2

7 1

E 2

3

13. Manual Scram 1, 2 2

1 3, 4 2

8 5

2 9

51

~

ai Oaa D;-

M l

t

INSTRUMENTATION TABLE 3.3.1-1 (Continued)

REACTOR PROTECTION SYSTEM INSTRUMENTATION ACTION ACTION 1 Be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

ACTION 2 Verify all insertable control rods to be inserted in the core and lock the reactor mode switch in the SHUTDOWN position within one hour.

ACTION 3 Suspend all operations involving CORE ALTERATIONS *, and insert f

all insertable control rods within one hour.

~

. ACTION 4 Be in at least STARTUP within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

ACTION 5 Be in STARTUP with the main steam line isolation valves closed within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months or in at least HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

ACTION 6 Initiate a reduction in THERMAL POWER within 15 minutes and reduce turbine first stage pressure to less than the automatic bypass setpoint within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

ACTION 7 Verify all insertable control rods to be inserted within one hour.

l ACTION 8 Lock the reactor mode switch in the SHUTDOWN position within one hour.

ACTION 9 Suspend all operations involving CORE ALTERATIONS *, and insert all insertable control rods and lock the reactor mode switch in the SHUTDOWN position within one hour.

"Except movement of IRM, SRM or special movable detectors, or replacement of LPRM strings provided SRM instrumentation is OPERABLE per Specification 3.9.2.

4 GRAND GULF-UNIT 1 3/4 3-4 I

S R

I ABLE 4.11.1-1 REACTOR PROIECTION SYST[M INSTRIMENTATION SURVEllt ANCE RfqIIIRINENTS q

CllANNIL OPERAil04AL e

CHANNEL Ilir Il0NAL CHANNEL CONDl110NS FOR WilCR 55 FUNCilONAL (INii

_CHfCK IESI CAllHRAIION(d}

Si!RVllll ANCE RIQtflRED M

1.

Intermediate Range Monitors:

a.

Neutron Iluu - High 5/U,5,(b) 5/U, W R

2 5

W R

3,4,5 j

b.

Inoperative NA W

NA 2,3,4,5 2.

Avarage Power Range Monitor:IU a.

Neutron Fluu - High, S/U.S.(b) 5/U, W SA 2

Seldown 5

W SA 3, 5 l

J b.

Flow Blased Simulated i

)

Thermal Power - High

5. D(h)

W W(d)(e), SA, R(i)

I to IN, SA 1

c.

Heutron Flux - High 5

W W

Y 4

N d.

Inoperative NA W

NA 1, 2, 3, 5 1

3.

Reactor Vessel Steam Dome R g)

1. 2, ;)

g Pressure - High 5

M 4.

Reactor Vessel Water level -

Low, Level 3 5

M R(g) 1, 2 5.

Reactor vessel Water Level -

g R g)

High, level 8 5

M I

6.

Main Steam Line isolation Valve - Closure NA M

R I

+

7 Main Steam Line Radiation -

l High 5

M R

I. 2(j) 8.

Drywell Pressure - l?igh 5

M R(9' l. 2" '

I l

l

I

]t TABLE 4.3.1.1-1 (Continued)

REACTOR PROTECTION SYSTEN INSTRUNENTATION SURVEILLANCE REQUIRENENTS I

a i

h CHANNEL OPERATIONAL i

o CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH g

FUNCTIONAL UNIT CHECK TEST CALIBRATION SURVEILLANCE REQUIRE 0 3

9.

Scras Discharge Volume Water 3

Level - High

-1 a.

Transmitter / Trip Unit S

M RI8)

III 1, 2, 5 t

b.

Float Switch N6 M

R 1, 2, SII) 10.

Turbine Stop Valve - Closure S

M R(9) 1 I

11. Turbine Control Valve Fast closure Valve Trip Systes 011 Pressure - Low S

M RI8) 1 12.

Reactor Mode Switch Shutdown Position NA R

NA '

1,2,3,4,5

13. Manual Scram NA M

NA 1,2,3,4,5 m

i 1

l 4"

(a) Neutron detectors may be excluded from CHANNEL CALIBRATION.

(b)

The IRM and SRM channels shall be determined to overlap for at least 1/2 decade during each startup after entering OPERATIONAL CONDITION 2 and the IRM and APRM channels shall be deter-sined to overlap for at least 1/2 secade during each controlled shutdown, if.not performed 3

within the previous 7 days.

(c) [ DELETED]

1 (d) i This calibration shall consist of the adjustment of the APRM channel to confore to the power values calculated by a heat balatce during OPERATIONAL CONDITION 1 when THERMAL POWER > 25% of RATED j

THERMAL POWER.

Adjust the APRM channel if the absolute difference is greater tiian 2K of RATED i

THERMAL POWER.

i (e) This calibration shall consist of the adjustment of the APRM flow biased channel to confore to a l

calibra.ted flow signal.

Og (f) The LPRMs shall be calibrated at least once per 1000 PRdD/T using the TIP system.

j l

g*,

(g)

Calibrate trip unit at least once per 31 days, j

,g (h)

Verify ueasured drive flow to be less than or equal to established drive flow at the existing flow con-l

7,*

trol valve position.

(1) This calibration shall consist of verifying the 611 second simulated thermal power time constant.

l lii' g (j)

Not applicable when the reactor pressure vessel head is. unbolted or removed per Specification 3.10.1.

j

%m (k)

Not applicable when DRYWELL INTEGRITY is not required.

j (1) Applicable with any control rod withdrawn. Not applicable to control rods removed per Specifica-tion 3.9.10.1 or 3.9.10.2.

l

~

i i

1

9" TABLE 3.3.3-1 (Continued) l EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION ag MININUM OPERABLE APPLICA8LE g

CHANNELS PER OPERATIONAL:

l TRIP FUNCTION TRIP FUNCTION (,)

CONDITIONS ACTION

.c h

C.

DIVISION 3 TRIP SYSTEM 1.

HPCS SYSTEM a.

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

33 l,

Drywell Pressure - High N 4(b) 1, 2, 3 33 N

b.

ReactorVesselWaterLevel-High, Level l8 2j) 1, 2, 3, 4*, 5*

31 j

c.

g 3

)

i d.

Condensate Storage Tank Level-Low 2(d) 1, 2, 3, 4*, 5*

34 e.

Suppression Pool Water Level-High 2

1, 2, 3, 4*, 5*

34

)

f.

Manual InitiationN

,1 1, 2, 3, 4*, 5*

32 f

D.

LOSS OF POWER 1.

Division 1 and 2 a.

4.16 kv. Bus Undervoltage 4

1, 2, 3, 4**, 5**

30 (Loss of Voltage) i R

b.

4.16 kV Bus Undervoltage 4

1, 2, 3, 4**, 5**

30 (BOP Load Shed) y c.

4.16 kV Bus Undervoltage 4

1, 2, 3, 4**, 5**

30 g,

(Degraded Voltage) 2.

Division 3 a.

4.16 kV Bus Undervoltage 4

1, 2, 3, 4", 5**

30 (Loss of Voltage) l, b.

4.16 kV Bus Undervoltage 4

1, 2, 3, 4**, 5**

30 4

(Degraded Voltage)

I (a) A channel may be placed in an inoperable status for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months during periods of required surveillance l

without placing the trip system in the tripped condition provided at least one other OPERABLE

channel in the same trip system is monitoring that parameter.

1 (b) Also. actuates the associated division diesel generator.

dr.,

(c) Provides signal to close HPCS pump discharge valve only.

1 Rg (d) Provides signal to HPCS pump suction valves only.

i

'1{

Applicable when the system is required to be OPERA 8LE per Specification 3.5.2 or 3.5.3.

j

%g Required when applicable ESF equipment is required to be OPERABLE.

Not required to be OPERA 8LE when reactor steam done pressure is less than or equal to 135 psig.

%F N

The injection function of Drywell Pressure - High and Manual Initiation are not required to be l

j

." g OPERA 8LE with indicated reactor vessel water level on the wide range instrument greater than Level 8 setpoint coincident with the reactor pressure less than 600 psig.

l

\\

INSTRUMENTATION TABLE 3.3.3-1 (Continued)

EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION

~~

ACTION

' With the number of OPERABLE channels less than reau' ' by the AGION 30 -

Minimum OPERABLE Channels per Trip Function requirer..:

With one channel inoperable, place the inoperatle channel a.

in the tripped condition within one hour

or ceclare the associated system (s) inoperable.

b.

-With more than one channel inoperable, declare the associated sys;em(s) inoperabic.

ACTION 31 -

With the number of OPERABLE channels less than required by the-Minimum OPERABLE Channels per Nip Function requirement, declare the associated ADS tr : system or ECCS inoperable.

ACTION 32 -

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 6. hours or declare the associated ADS trip cystem or ECCS inoperable.

j ACTION 33 -

With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, piace the inoperable channel (s) in tne tripped condition within one hour

or declare the NPCS system inoperable.

ACTION 34 -

With the number of OPERABLE channelt less than required by the Minimum OPERABLE Channels per Trip Fanction requirement, place at least one ir.sperable channel in the tripped condition within one hour

or declere the HPCS system inoperable.

ACTION 35 -

With.the number of DPERABLE channels less than required by the i

Minimum OPERABLE Channels per Trip Function requirement, place i

the inoperable channel (s) in the tripped condition within one l

hour

or declare the associated system (s) inoperable.

1 "The provisions of Specification,3.0.4 are no applicable.

GRAND GULF-UNIT 1 3/4 3-30 V andment No. 20 l E:tective Date:

7

~

o TARLE 4.3.3.1-1 (Continued)

EMERGENCY CORE COOLING 3YSTER ACTUATION INSTRUMENIATION SURVEILLAr#CE REQUI i

i E

CHANNEL OPERATIONAL CH'ilNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH E

TRIP FlpICTION CHECK TEST CALIBRATION SURVEILLANCE _RE_ QUIRED l

h B.

DIVISION 2 TRIP SYSTEM (Continued) 2.

AtIT0pWLTIC DEPRESSURIZATION SYSTEM TRIP SYSTEM "8"#

a.

Reactor Vessel Water Level -

Low Low Iow, Level 1 S

M R(a) 1, 2, 3 b.

Drywell Pr

.ure-High S

M I

,R *I 1, 2, 3 c.

ADS Initiation Timer NA M

Q 1, 2, 3 l

d.

Reactor Vessel Water Level -

Low, Level 3 S

M R(a) 4 in i

e.

LPCI Pump 8 and C Discharge 1, 2, 3 1

Pressure-High S

M(b)

Rg,)

1, 2, 3 u.

de f.

Manual Initiation NA R

NA 1, 2, 3 g.

ADS Bypass Timer (High Drywell Pressura)

NA M

Q 1, 2, 3 l

h.

Manual Inhibit NA R

NA 1, 2, 3 1

{

C.

DIVISION 3 TRIP SYSTEM i

1..HPCS SYSTEM i

Reactor Vessel Water level -

Low Low, Level 2 S

M

! ")

I 1, 2, 3, 4*, 5*

i b.

Drywell Pressure-High##

S M

R(a) 1, 2, 3 I

c.

Reactor Vessel Water S

M IR "I 1, 2, 3, 4*, 5*

l Level-High, level 8 Q

d.

Condensate Storage Tant Os Level - Low S

M R,I 1, 2, 3, 4*, 5*

I j

39 e.

Suppression Pool Water 75 Level - High 5

M RII IbI 1, 2, 3, 4*, 5*

f.

Manual Initiation ##

NA R

NA 1, 2, 3, 4*, 5*

EE

\\

.?N I

l

e r

+

o TABLE 4.3.3.1-1 (Continued)

)

EMERGENCY CORE COOLING SYSTUI ACIllATIUN INSTRUMINIAIION SURV[lll A E

CHANNIL OPERATIONAL CllANNEL FilNCil0NAL CilANNE L CONDITIONS FOR milch E

TRIP FUNCTION CIIECK IEST cal'"0ATION SIIRVEILLANCE pr"'llRID D.

LOSS OF POWER 1.

Olvision 1 and 2 a.

4.16 kV Bus Undervoltana NA IH 'I R

1, 2, 3, 4**, 5**

(Loss of Voltage) b.

4.16 kV Bus l'ndervoltage NA g

M,)

R 1, 2, 3, 4**, 5**

(BOP Load Shed)

I c.

4.16 kV Bus Undervoltage NA M 'I R

1, ?, 3, 4**, 5**

(Degraded Voltage) w 2.

Division 3 a

a.

4.16 kV Bus lindervoltage NA NA R

1, 2, 3, 4 * *, 5*

w (Loss of Vo age) w E'

b.

4.16 kV Bus Undervoltage NA NA '

R 1, 2, 3, 4**, 5**

(Degraded Voltage) b n

EIu lii'!

.Yh T

TABLE 4.3.3.1-1 (Continued)

EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS NOTATION 4

Not required to be OPERABLE when reactor steam dome pressure is less than or equal to 135 psig.

The injection function of Drywell Pressure - High and Manual Initiation l

are not required to be OPERABLE with indicated reactor vessel water level on the wide range instrument greater than Level 8 setpoint coincident with the reactor pres-

.k sure less than 600 psig.

~

Applicable when the system is required to be OPERABLE per Specification 3.5.2 or 3.5.3.

Required when ESF equipment is required to be OPERABLE.

(a) Calibrate trip unit at least once per 31 days.

(b) Manual initiation switches shall be tested at least once per 18 months during shutdown. All other circuitry associated with manual initiation shall receive a CHANNEL FUNCTIONAL TEST at least once per 31 days as a part of circuitry required to be tested for automatic system actuation.

(c) DELETED (d) DELETED (e) Functional Tiiting of Time Delay Not Required i

i l

l l

GRAND GULF-UNIT 1 3/4 3-36 Amendment No. 21 Effective Date:

EMERGENCY CORE COOLING SYSTEMS LIMITING CONDITION FOR OPERATION (Continued)

ACTION:

(Continued)

For ECCS divisions 1 and 2, provided that ECCS division 3 is e.

OPERABLE and divisions 1 and 2 are otherwise OPERABLE:

1.

With one of the above required ADS valves inoperable, restore the inoperable ADS valve to OPERABLE status within 14 days or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and reduce reactor steam dome pressure to 1 135 psig within the next 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

b With two or more of the above reouired ADS valves inoperable, 2.

be in at least HOT SHUTDOWN withi'n 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and reduce reactor

~

steam dome pressure to 1 135 psig within the next 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

f.

With an ECCS discharge line " keep filled" pressure alarm instrumentation channel inoperable, perform Surveillance Requirement 4.5.1.a.1 at least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

g.

With an ECCS header delta P instrumentation channel inoperable, restore the inoperable channel to OPERABLE status with 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or determine ECCS header delta P locally at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ; otherwise declare the associated ECCS inoperable.

h.

In the event an ECCS system is actuated and injects water into the Reactor Coolant System, a Special Report shall be prepared and sub-mitted to the Commission pursuant to Specification 6.9.2 within 90 days describing the circumstances of the actuation and the total accumulated actuation cycles to date. The current value of the useage factor for each affected safety injection nozzle shall be provided in this Special Report whenever its value exceeds 0.70.

i.

With an ADS accumulator low pressure alarm system instrumentation channel (s) inoperable, determine the associated ADS accumulator pressure locally at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ; restore the inoperable channel (s) to OPERABLE status within 7 days; otherwise declare the associated ADS valves inoperable.

Whenever two or more RHR subsystems are inoperable, if unable to attain COLD SHUTDOWN as required by this ACTION, maintain reactor coolant temperature as low as practical by,use of alternate heat removal methods.

GRAND GULF-UNIT 1 3/4 5-3 Amendment No.

21 Effective Date:

>=, ew v.

EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE REQUIREMENTS ECCS division 1, 2 and 3 shall be demonstrated OPERABLE by:

4.5.1 At least once per 31 days for the LPCS, LPCI and HPCS systems:

a.

1.

Verifying by venting at the high point vents that the system piping from the pump discharge valve to the system isolation valve is filled with water.

2.

Performance of a CHANNEL FUNCTIONAL TEST of the:

a)

Discharge line " keep filled" pressure alarm instrumentation, and b)

Header delta P instrumentation.

~

3.

Verifing that each va'ive, manual, power operated or automatic, in the flow path,that is not locked, sealed, or otherwise secured in position, is in its correct position.

b.

Verifing that, when tested pursuant to Specification 4.0.5, each:

1.

LPCS pump develops a flow of at least 7115 gpm with a total developed head of greater than or equal to 290 psid.

2.

LPCI pump develops a flow of at least 7450 gpm with a total developed head of greater than or equal to 125 psid.

3.

HPCS pump develops a flow of at least 7115 gpm with a total developed head of greater than or equal to 445 psid.

For the LPCS, LPCI and HPCS systems, at least once per 18 months:

c.

1.

Performing a system functional test which includes siinulated automatic actuation of the system throughout its emergency operating sequence and verifying that each automatic valve in the flow path actuates to its correct position. - Actual injec-tion of coolant into the reactor vessel may be excluded from

~

this test.

2.

Performing a CHANNEL CALIBRATION of the:

a)

Discharge line high pressure and " keep filled" low pressure alarm instrumentation and verifying tht.

1)

High pressure setpoint of th':

e (a) LPCS system to be 5 575 psig.

(b) LPCI subsystems to be 5 475 psig.

i GRAND GULF-UNIT 1 3/4 5-4 h"

4 EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) i 2)

Low pressure setpoint of the:

(a) LPCI A and B subsystem loop to be 1 38 psig.

(b) LPCI C subsystem loop and LPCS system to be > 22 psig.

(c) HPCS system to be 1 18 psig.

b)

Header delta P instrumentation and verifying the setpoint of the HPCS system and LPCS system and LPCI subsystems to

(

be 1.210.1 psid change from the normal indicated AP.

~

1 3.

Verifying that'the suction for the HPCS system is automatically transferred from the condensate storage tank to the suppression pool on g condensate storage tank low water level signal and on i

a suppression pool high water level signal.

4.

Verifying that the time required for each LPCI and LPCS injec-tion valve to travel from fully closed to fully open is

< 29 seconds when tested pursuant to Specification 4.0.5.

d.

For the ADS at least once per 18 months by:

1.

Performing a. system functional test which includes simulated automatic actuation of the system throughout its emergency i

operating sequence, but excluding actual valve actuation.

2.

Manually opening each ADS valve when the reactor steam dome pressure is greater than or equal to 100 psig* and observing that either:

a)

The control valve or bypass valve position responds accordingly, or b)

There is a corresponding change in the measured steam flow.

3.

Performing an extrapolated pressure decay test on the ADS air system to demonstrate system pressure will be maintainea for 7 days at a value > 110 psig without makeup air available.

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

GRAND GULF-UNIT 1 3/4 5-5 Amendment No. 21 l

Effective Date:

EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) 4.-

Performing a CHANNEL CALIBRATION of the accumulator low pres-sure alarm channels and verifying an alarm setpoint of

> 150 psig on decreasing pressure.

For the ADS at least once per 31 days by performing a CHANNEL e.

FUNCTIONAL TEST of the accumulator low pressure alarm channels.

T l

GRAND GULF-UNIT 1 3/4 5-Sa AmendmentNo.21l Effective Date:

EMERGENCY CORE COOLING SYSTEMS 3/4 5.2 ECCS - SHUTDOWN LIMITING CONDITION FOR OPERATION 3.5.2 At reast two of the following shall be OPERABLE:

The low pressure. core spray (LPCS) system with a flow path capable a.

of taking suction from the suppression pool and transferring the water through the spray sparger to the reactor vessel.

b.

Low pressure coolant injection (LPCI) subsystem "A" of the RHR system with a flow path capable of taking suction from the suppression pool upon being manually realigned and transferring the water to the reactor vessel.

Low pressure coolant injection (LPCI) subsystem "B" of the RHR system c.

with a flow path capable of taking suction from the suppression pool upon being manually realigned and transferring the water to 'he reactor vessel.

d.

Low pressure coolant injection (LPCI) subsystem "C" of the RHR system with a flow path capable of taking suction from the suppression pool upon being manually realigned and transferring the water to the reactor vessel.

The high pressure core spray (HPCS) system with a flow path capable e.

of taking suction from one of the following water sources and trans-ferring the water through the spray sparger to the reactor vessel:

1.

From the suppression pool, or 2.

When the suppression pool level is less than the limit or is drained, from the condensate storage tank containing at least 170,000 available gallons of water, equivalent to a level of 18 feet.

APPLICABILITY: OPERATIONAL CONDITION 4 and 5*.

ACTION:

With one of the above required subsystems / systems inoperable, restore a.

at least two subsystems / systems to OPERABLE status within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months or suspend all operations that have a potential for draining the reactor vessel.

b.

With both of the above required subsystems / systems inoperable, suspend CORE ALTERATIONS and all operations that have a potential for draining the reactor vessel.

Restore at least one subsystem / system to OPERABLE l

status within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months or establish SECONDARY CONTAINMENT INTEGRITY within the next 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months .

"The ECCS is not required to be OPERABLE provided that the reactor vessel head is removed, the cavity is flooded, the upper containment fuel pool gates are removed, the spent fuel pool gates are removed, and water level is maintained within the limits of Specifications 3.9.8 and 3.9.9.

i GRAND GULF-UNIT 1 3/4 5-6

1 TABLE 3.6.4-1 (Continued)

CONTAINMENT AND DRYWELL ISOLATION VALVES MAXIMUM SYSTEM AND PENETRATION ISOLATION TIME VALVE NUMBER NUMBER VALVE GROUP (a)

(Seconds)

Containment (Continued)

Main St'am Line B21-F019-A 19(0) 1 20 e

Drains Main Steam Line B21-F016-B 19(I) 20 Drains RHR Heat Exchanger E12-F028A-A 20(I) 5 90 "A" to CTMT SPR Sparger INL RHR Heat Exchanger E12-F037A-A 20(I) 3 74 "A" to CTMT Pool RHR Heat Exchanger E12-F028B-B 21(I) 5 90 "B" to CTMT SPR Sparger INL RHR Heat Exchanger E12-F0378-8 21(I) 3 74 "B" to CTMT Pool RHR "A" Test Line E12-F024A-A 23(0)(d) 5 90 to Supp. Pool RHR "A" Test Line E12-F011A-A 23(0)(d) 5 36 to Supp. Pool RHR "C" Test Line E12-F021-B 24(0)(d) 5 144 to Supp. Pool HPCS Test Line E22-F023-C 27(0)(d) 68 75 RCIC Pump Suction E51-F031-A 28(0)(d) 4 56 RCIC Turbine E51-F077-A 29(0)(c) 9 26 Exhaust LPCS Test Line E21-F012-A 32(0)(d) 5 144 Cont. Purge and M41-F011-(A) 34(0) 7 4

Vent Air Supply Cont. Purge and M41-F012-(B) 34(I) 7 4

Vent Air Supply Cont. Purge and M41-F034-(B) 35(I) 7 4

Vent Air Exh.

Cont. Purge and M41-F035-(A) 35(0) 7 4

Vent Air Exh.

Drywell Chilled P72-F123-B 36(I) 6A 33 l

Water Return Drywell Chilled P72-F122-A 36(0) 6A 33 l

Water Return Drywell Chilled P72-F121-A 37(0) 6A 33 l

Water Supply Chilled Water P71-F150-(A) 38(0) 6A 12 Supply GRAND GULF-UNIT 1 3/4 6-31 Amendment No. 21 l

TABLE 3.6.4-1 (Continued)

CONTAINMENT AND DRYWELL ISOLATION VALVES MAXIMUM SYSTEM AND P8NETRATION ISOLATION TIME VALVE NUMBER NUMBER VALVEGROUP(*)

(Seconds)

Containment(Continued)

Chilled Water P71-F148-(A) 39(0) 6A 12 Return Ch111ed Water P71-F149-(B) 39(I) 6A 12 Return Service Air PS2-F105-(A) 41(0) 6A 6

Supply Inst. Air Supply P53-F001-(A) 42(0) 6A 6

(

RWCU to Main G33-F034-A 43(0) 8 35 Condenser RWCU to Main G33-F028-B.

43(I) 8 35 Condenser RWCU Backwash to G36-F106-(B) 49(I) 6A 11 C/U Phase Sep. Tank

~

RWCW Backwash to G36-F101-(A) 49(0) 6A 11 C/U Phase Sep. Tank Drywell & Cont.

P45-F067-(B) 50(I) 6A 7

Equip. Drain Sump Disch.

(

Drywell & Cont.

P45-F068-(A)

50(0) 6A 7

Equip. Drain Sump Disch.

Drywell & Cont.

P45-F061-(B) 51(I) 6A 7

Floor Drain Sump Disch.

Drywell & Cont.

P45-F062-(A) 51(0) 6A 7

Floor Drain Sump Disch.

~

Condensate Supply P11-F075-(A) 56(0) 6A 10

~

FPC & CU to Upper G41-F028-A 57(0) 6A 51 Cont. Pool Upper Cont. Pool G41-F029-A 58(0) 6A 51 to Fuel Pool Drain Tank Upper Cont. Pool G41-F044-8 58(I) 6A

, 40 to Fuel Pool Drain Tank Aux. Bldg. Fir.

P45-F273-A 60(0) 6A 32 and Equip. Drn.

Tks. to Supp. Pool Aux. Bldg. Fir.

P45-F274-8 60(0) 6A 32 and Equip. Drn.

Tks. to Supp. Pool GRAND GULF-UNIT 1 3/4 6-32

TABLE 3.6.4-1 (Continued)

CONTAINMENT AND DRYWELL ISOLATION VALVES MAXIMUM

. SYSTEM AND PENETRATION ISOLATION TIME VALVE NUMBER NUMBER VALVE GROUP (,)

(Seconds) '

Containment (Continued)

Comb. Gas Control E61-F009-(A) 65(0) 7 4

f.ont. Purge (Outside Air Supply)

Comb. Gas Control E61-F010-(B) 65(I) 7 4

Cont. Purge (Outside Air Supply)

Purge Filter Train E61-F056-(B) 66(I) 7 4

Isolation Purge Filter Train E61-F057-(A) 66(0) 7 4

Isolation RHR "B" Test Line E12-F024B-B 67(0)(d) 5 90 To Suppr. Pool RHR "B" Test Line E12-F011B-B 67(0)(d) 5 36 To Suppr. Pool Refueling Water P11-F130-(A) 69(0)(c) 6A 8

Transf. Pump Suction Retueling Water P11-F131-(B) 69(0)(c) 6A 8

Transf. Pump Suction Instr. Air to ADS P53-F003-A 70(0) 6A 4

RCIC Turbine Exh.

E51-F078-B 75(0) 9 10 Vacuum Breaker RWCU to Feedwater G33-F040-B 83(I) 8 35 RWCU to Feedwater G33-F039-A 83(0) 8 35 Chemical Waste P45-F098-(B) 84(I) 6A 8

Sump Discharge Chemical Waste P45-F099-(A) 84(0) 6A 8

Sump Discharge Supp. Pool Clean-P60-F009-A 85(0) 6A 8

up Return Supp. Pool Clean-P60-F010-8 85(0) 6A 8

up Return Domin. Water P21-F017-A 86(0)

~6A 19 I.

Supply to Cont.

Demin. Water P21-F018-B 86(I) 6A IF Supply to Cont.

RWCU Pump Suction G33-F001-B 87(I) 8 35 GRAND GULF-UNIT 1 3/4 6-33

,,, _ _ _ ~ ~,. _. _. _ _ _ _ _.. _. _.,.,,. _. _ _ _ _ _ _ _ _ _ _. _ _ _ _ _....

_, _.. _ _, _., _ _ _, _ _ _ _ _ _ _. _ _ _ _ _ _,... _ _ _ ~_

TABLE 3.6.4-1 (Continued)

CONTAINMENT AND DRYWELL ISOLATION VALVES MAXIMUM SYSTEM AND PENETRATION ISOLATION TIME VALVE NUMBER NUMBER VALVE GROUP (a)

(Seconds)

Containment (Continued)

RWCU Pump Suction G33-F252-A 87(I) 8 35 RWCU Pump Suction G33-F004-A 87(0) 8 35 RWCU Pump Disch.

G33-F053-B 88(I) 8 35 RWCU Pump Disch.

G33-F054-A 88(0) 8 35 b.

Drywell Instrument Air PS3-F007-8 335(0) 6A 7

Drywell Chilled P72-F125-A 331(I) 6A 32 l

Water Return Drywell Chilled P72-F126-8 331(0) 6A 32 l

h Water Return Drywell Chilled P72-F124-8 332(0) 6A 32 l

Water Return RWCU Pump Suction G33-F250-A 337(I) 8 35 RWCU Pump Suction G33-F251-8 337(0) 8 35 Combustible Gas

~E61-F0038-8 338(0) 5 84 Con.

Combustible Gas E61-F003A-A 339(0) 5 84 Con.

Combustible Gas E61-F005A-A 340(0) 5 84 Con.

Combustible Gas E61-F0058-8 340(0) 5 84 Con.

Combustible Gas E61-F007-(A) 341(0) 5 9

Con.

Combustible Gas E61-F020-(8) 341(0) 5 18 Con.

Drywell Air Purge M41-F015-(A) 345(I) 7 4

Supply Drywell Air Purge M41-F013-(8) 345(0) 7 4

Supply Drywell Air Purge M41-F016-(A) 347(I) 7 4

Exhaust Drywell Air Purge M41-F017-(8) 347(0) 7 4

Exhaust Equipment Drains P45-F009-(A) 348(I) 6A 6

Equipment Drains P45-F010-(8) 348(0) 6A 6

Floor Drains P45-F003-(A) 349(I) 6A 6

Floor Drains P45-F004-(8) 349(0) 6A 6

. Service Air P52-F195-8 363(0) 6A 16 I

Chemical Sump P45-F096-A 364(I) 6A 9

Disch.

Chemical Sump P45-F097-8 364(0) 6A 9

Disch.

RWCU to Heat G33-F253-8 366(0) 8 35 Exch.

Reactor Water 833-F019-8 465(I) 10 36 Sample Line Reactor Water 833-F020-A 465(0) 10 36 Sample Line GRAND GULF-UNIT 1 3/4 6-34 Amendment No. 21 l

Effective Date:

TABLE 3.6.4-1 (Continued)

CONTAINMENT AND DRYWELL ISOLATION VALVES '

SYSTEM AND PENETRATION VALVE NUMBER NUMBER Containment (Continued)

RHR Pump "A" Test E12-F227 23(0)(')

Line to Suppr.

Pool RHR Pump "A" Test E12-F262 23(0)(')

Line to Suppr.

Pool RHR Pump "A" Test E12-F228 23(0)(*)

Line to Suppr.

Pool RHR "A" Test Line E12-F290A-A 23(0)(d) to Supp. Pool RHR Pump "A" Test E12-F338 23(0)(c)

Line to Suppr.

Pool RHR Pump "A" Test E12-F339 23(0)(c)

Line to Suppr.

Pool RHR Pump "A" Test E12-F260 23(0)(')

Line to Suppr.

Pool RHR Pump "C" Test E12-F280 24(0)(d.l Line to Suppr.

Pool RHR Pump "C" Test E12-F281 24(0)(d)

Line to Suppr.

Pool HPCS Suction E22-F014 25(0)(d)

HPCS Discharge E22-F005-(C) 26(I)

HPCS Discharge E22-F218 26(I) i HPCS Discharge E22-F201 26(I)(d)

HPCS Test Line E22-F035 27(0) 27(0)('))

i HPCS Test Line E22-F302 27(0)(')

HPCS Test Line E22-F301 30(0)(d LPCS Pump Suction E21-F031 LPCS Discharge E21-F006-(A) 31(I)

LPCS Discharge E21-F200 31(I)

LPCS Discharge E21-F207 31(I) d) 32(0)((d)

LPCS Test Line E21-F217 LPCS Test Line E21-F218 32(0)

CRD Pump C11-F122 33(I)

Discharge DCW Supply P72-F165 37(I) l Plant Chilled P71-F151 38(1)

Water Supply Service Air PS2-F122 41(I)

Supply I

l GRAND GULF-UNIT 1 3/4 6-39 Amendment No. 21 l

i-

T TABLE 3.6.4-1 (Centinued)

CONTAINMENT AND DRYWELL ISOLATION VALVES SYSTEM AND

' PENETRATION VALVE NUMBER NUMBER

_ Containment (Continued)

Instr. Air Supply P53-F002 42(I)

CCW Supply P42-F035 44(I)

RCIC Disch.

E51-F251 46(0)(c)

Min. Flow RCIC Disch.

E51-F252 46(0)(C)

Min. Flow RHR H at Ex. "B" E12-F055B 48(0)(d)

Relief Vent Header RHR Heat Ex. "B" E12-F103B 48(0)(d)

Relief Vent Header RHR Heat Ex. "B" E12-F1048 48(3)(d)

Relief Vent Header Refueling Wtr.

G41-F053 54(0)

Stg. Tk to Upper Ctat. Pool Refueling Wtr.

G41-F201 i

Stg. Tk. to 54(I)

Upper Ctat. Pool

(

Condensate Supply P11-F004 56(I)

FPC & CU to Upper G41-F040 57(I)

Cont. Pool Stby. Liquid C41-F151 61(1)

Control Sys.

Mix. Tk.

(future use)

Stby. Liquid C41-F150 61(0)

Control Sys.

Mix. Tk.

~

(future use)

RHR Pump "B" Test E12-F276 67(0)(*)

Line RHR Pump "B" Test E12-F277 67(0)(')

Line RHR Pump "B" Test E12-F212 67(0)(')

Line RHR Pump "B" Test 'E12-F213 67(0)(')

Line RilR Pump "B" Test E12-F249 67(0)(')

Line RHR Pump "B" Test E12-F250 67(0)I')

Line RHR Pump "B" Test E12-F334 67(0)(c) i Line t

GRAND GULF-UNIT 1 3/4 6-40

,#- - - -e-----

--m-,_,_

.,o,

-,.m_

w. -

m

-,,----r-

t TABLE 3.6.4-1 (Continued)

CONTAINMENT AND DRYWELL ISOLATION VALVES SYSTEM AND PENETRATION VALVE NUMBER NUMBER Containment (Continued)

RHR Pump "B" Test E12-F335 67(0)(c)

Line RHR "B" Test Line E12-F2908-B 67(0)(d)

To Suppr. Pool Inst. Air to ADS P53-F006 70(I) (d)

LPCS Relief Valve E21-F018 71A(0)

Vent Header

(

RHR Pump "C" E12-F025C 71B(0)(d)

Relief Valve Vent Header RHR Shutdown E12-F036 73(0)

Vent Header RHR Shutdown E12-F005 76B(0)

Suction Relief Valve Disch, RHR Heat Ex. "A" E12-F055A 77(0)(d)

Relief Vent Header RHR Heat Ex. "A" - E12-F103A 77(0)(d)

Relief Vent Header RHR Heat Ex. "A" E12-F104A 77(0)(d)

Relief Vent Header 89(I)((c) c SSW "A" Supply P41-F169A

)

SSW "B" Supply P41-F169B 92(I)

Ctmt. Leak Rate M61-F015 110A(I)

Test Inst.

Ctmt. Leak Rate M61-F014 110A(0)

Test Inst.

Ctmt. Leak Rate M61-F019 1100I)

Test Inst.

Ctmt. Leak Rate M61-F018 110C(0)

Test Inst.

Ctat. Leak Rate M61-F017 110F(I)

Test Inst.

Ctat. Leak Rate M61-F016 110F(0)

Test Inst.

b.

Drywell LPCI "A" E12-F041A 313(I)

LPCI "B" E12-F041B 314(I)

LPCI "B" E12-F236 314(0)

CRD to Recirc.

833-F013A 326(I)

Pump A Seals GRAND GULF-UNIT 1 3/4 6-41

TABLE 3.6.4-1 (Continued)

CONTAINMENT AND ORYWELL ISOLATION VALVES SYSTEM AND PENETRATION VALVE NUMBER NUMBER Drwell (Continued)

CR0 to itecire.

833-F017A 326(0)

Pump A Seals Instrument Air PS3-F008 335(I)

Standby Liquid C41-F007 328(I)

Control Standby Liquid C41-F006 328(0)

Control Cont. Cooling P42-F115 329(I)

Water Supply Drywell Chilled P72-F147 332(I) l Water Supply Condensate Flush 833-F204 333(I)

Conn.

Condensate Flush 833-F205 333(0)

Conn.

Combustible Gas E01-F002A 339(0)

Control Combustible Gas E61-F0028 338(0)

Control.

Combustible Gas E61-F004A 340(0)

Control Combustible Gas

~E61-F0048 340(0)

Control Upper Containment G41-F265 342(0)

Pool Drain CR0 to Recirc.

833-F0138 346(I)

Pump B Seals CR0 to Rectrc.

833-F0178 346(0)

Pump B Seals Service Air PS2-F196 363(!)

Cont. Leak Rate M61-F021 438A(I)

Test Inst.

Cont. Leak Rate M61-F020 438A(0)

Sys.

BLIND FLANGES Cont. Leak Rate NA 40(I)(0)

Sys.

Cont. Leak Rate NA 82(I)(0)

Sys.

Containment NA 343(I)(0)

Leak Rate System GRAND GULF-UNIT 1 3/4 6-42 Amendment No. 21 guyer e

TABLE 3.6.4-1 (Continued)

CONTAINMENT AND DRYWELL ISOLATION VALVES l

SYSTEM AND PENETRATION VALVE NUMBER NUMBER 4.

Test Connections (9) a.

Containment Main Steam T/C 821-F025A 5(0)

Main Steam T/C B21-F025B 6(0)

Main Steam T/C 821-F025C 7(0)

Main Steam T/C B21-F025D 8(0)

Feedwater T/C B21-F030A 9(0)

Feedwater T/C 821-F063A 9(0) g Feedwater T/C 821-F063B 10(0)

Feedwater T/C B21-F0308 10(0)

RHR Shutdown Cool. E12-F002 14(0)

Suction T/C RCIC Steam Line

~ E51-F072 17(0)

T/C RHR to Head E12-F342 18(0)

Spray T/C RHR to Head E12-F061 18(0)

Spray T/C LPCI "C" T/C E12-F056C 22(0)

RHR "A" Pump E12-F322 23(0)(c)

Test Line T/C RHR "A" Pump E12-F336 23(0)(c)

Test Line T/C RHR "A" Pump E12-F349 23(0)(C)

Test Line T/C RHR "A" Pump E12-F303 23(0)(c)

Test Line T/C RHR "A" Pump -

E12-F310 23(0)(c)

Test Line T/C RHR "A" Pump E12-F348 23(0)(c)

Test Line T/C RHR"C" Pump E12-F311 24(0)(c)

~

Test Line T/C RHR"C" Pump E12-F304 2.4(0)(c)

Test Line T/C HPCS Discharge T/C' E22-F021 26(0)

HPCS Test Line T/C E22-F303 27(0)(g)

.27(0)fc e

HPCS Test Line T/C E22-F304 RCIC Turbine E51-F258 29(0)

Exhaust T/C RCIC Turbine E51-F257 29(0)(c)

Exhaust T/C LPCS T/C E21-F013 31(0)(c)

LPCS Test Line E21-F222 32(0)

T/C LPCS Test Line E21-F221 32(0)gg)

T/C GRAND GULF-UNIT 1 3/4 6-43 Amendment No. 4 Etlective Datet7 NOV 85*

TA8LE 3.6.4-1 (Continued)

CONTAINMENT AND ORYWELL ISOLATION VALVES SYSTEM AND PEMETRATION VALVE NUMBER NUMBER Contai'nment (Continued)

CR0 T/C C11-F128 33(0)

Cont. Purge M41-F042 34(0)

Supply T/C Cont. Purge M41-F051 35(0)

Exhaust T/C DCW Supply T/C P72-F167 37(0) l Plant Chilled P71-F232 38(0)

Water T/C Plant Chilled P71-F246 39(0)

Water T/C Ctat. Leak Rate M61-F009 40(I)

T/C Service Air T/C PS2-f258 41(0)

Inst. Air T/C P53-F036 42(0)

RWCU T/C G33-F070 43(0)

CCW Supply T/C P42-F161 44(0)

CCW Return T/C P42-F162 45(I)

Condensate Supply P11-F095 56(0)

T/C FPC & CU To G41-F340 57(!)

Upper Cont. Pool T/C Aux. Bldg. Fir.

P45-F275 60(0)

& Equip. Drain Tk. to Suppr.

Pool T/C Aux Bldg. Fir.

P45-F290 60(0)

& Equip. Drain Tk to Suppr.

Pool T/C Stby. Liquid C41-F152 61(0)

Control Sys.

Mix. Tk. T/C (future use)

Combustible Gas E61-F017 65(0)

Control T/C Purge Radiation M41-F054 66(0)

Detector T/C RHR "8" Test Line E12-F321 67(0)(C)

T/C RHR "8" Test Line E12-F351 67(0)(C)

T/C RHR "8" Test Line E12-F331 67(0)(c)

T/C GRAND GULF-UNIT 1 3/4 6-44 Amendment No.21 1

h WG e

TABLE 3.6.4-1 (Continued)

CONTAINMENT AND DRYWELL ISOLATION VALVES SYSTEM AND PENETRATION VALVE NUMBER NUMBER Containment (Continued)

RHR "B" Test Line E12-F350 67(0)(C) 1/C RHR "B" Test Line E12-F312 67(0)(C)

T/C RHR "B" Test Line E12-F305 67(0)(c)

T/C Refueling Water P11-F425 69(0)(c) h Transf. Pump Suction T/C o

Refueling Water P11-F132 69(0)(c)

Transf. Pump Suction T/C s'

Inst. Air to ADS P53-F043 70(0)

T/C Cont. Leak Rate M61-F010 82(I)

T/C RWCU To Feedwater G33-F055 83(0)

~

T/C Suppr. Pool P60-F011 85(0)

Cleanup T/C Suppr. Pool P60-F034 85(0)

Cleanup T/C RWCU Pump Suction G33-F002 87(0)

T/C RWCU Pump G33-F061 88(0)

Discharge T/C SSW T/C P/1-F163A 89(0)((c)

C SSW T/C~

P41-F163B 92(0) )

b.

Drywell LPCI "A" T/C E12-F056A 313(0)

LPCI "B" T/C E12-F056B 314(0) j Instrument Air T/C P53-F493 335(0)

SLCS T/C C41-F026 328(0) 1 Service Air T/C PS2-F476 363(0)

RWCU T/C G33-F120 356(I)

Reactor Sample B33-F021 465(0) i T/C l

i GRAND GULF-UNIT 1 3/4 6-45 1

i

l CONTAINMENT SYSTEMS 3/4.6.5 DRYWELL VACUUM RELIEF l

LIMITING CONDITION FOR OPERATION 3.6.5 Bott) 'drywell post-LOCA vacuum relief subsystems and both drywell purge vacuum relief subsystems shall be OPERABLE with associated vacuum breakers and isolation valves closed.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3.

ACTION:

With one of the drywell post-LOCA vacuum relief subsystems and/or one of a.

the drywell purge vacuum relief subsystems inoperable for opening but known to be closed, restore the inoperable subsystem (s) to OPERABLE status within 30 days or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in C0'D SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , b.

With two of the post-LOCA vacuum relief subsystems inoperable for opening but known to be closed, provided that both of the drywell purge vacuum relief subsystems are OPERABLE, restore the inoperable subsystems to OPERABLE status within 30 days or be in a least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , With two of the post-LOCA vacuum relief subsystems and one of the drywell c.

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

d.

With one of the drywell isolation vacuum breakers open, restore the open vacuum breaker to the closed position within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the follow-ing 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

With the position indicator of an OPERABLE drywell vacuum breaker or e.

associated isolation valve of the drywell vacuum relief subsystems 3

inoperable, verify the vacuum breaker or isolation valve to be closed at least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months by local indication. Otherwise be in a least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTOOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

SURVEILLANCE REQUIREMENTS 4.6.5 Each post-LOCA and purge system vacuum breaker and associated isolation valve shall be:

a.

Verified closed at least cnce per 7 days.

GRAND GULF-UNIT 1 3/4 6-46 AmendmentNo.21l Effective Date:

1 CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) b.

Demonstrated OPERABLE:

1.

-At feast on'ce per 31 days by:

a)

Cycling the vacuum breaker and associated isolation valve through at least one complete cycle of full travel.

b)

Verifying the position indicators OPERABLE by observing expected vacuum breaker and associated isolation valve movements during the cycling test.

2.

At least once per 18 months by:

h o

a)

Verifying the pressure differential required to open the vacuum breaker, from the closed position, to be less than or equal to 1.0 psid, and,-

b)

Verifying the position indicators of the vacuum breaker and associated isolation valve OPERA 8LE by performance of CHANNEL CALIBRATIONS.

(

3.

By verifying the OPERA 8ILITY of the isolation valve differential pressure actuation instrumentation with the opening setpoint of 0.0 to 1.0 psid for the drywell purge subsystems and -1.0 to 0.0 psid for the post-LOCA vacuum relief subsystems (Drywell minus Containment) by performance of a:

(

a)

CHANNEL CHECK at least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , b)

CHANNEL FUNCTIONAL TEST at least once per 31 days, and c)

CHANNEL CALIBRATION at least once per 18 months.

GRAND GULF-UNIT 1 3/4 6-47 Amendment No.21 Effective Date:

CONTAINMENT SYSTEMS 3/4.6.6 SECONDARY CONTAINMENT SECONDARY CONTAINMENT INTEGRITY LIMITING CONDITIUN FOR OPERATION SEC0h0ARYCONTAINMENTINTEGRITYshallbemaintained.

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

ACTION:

Without SECONDARY CONTAINMENT INTEGRITY:

In OPERATIONAL CONDITION 1, 2 or 3, restore SECONDARY CONTAINMENT a.

INTEGRITY within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months or be in at least NOT SHUTOOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTOOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

b.

In Operational Conditi,on

, suspend handling of irradiated fuel in the primary or secondary containment, CORE ALTERATIONS and operations with a potential for draining the reactor vessel.

Specification 3.0.3 are not appifcable.

The provisions of SURVEILLANCE REQUIREMENTS 4.6.6.1 SECONDARY CONTAINMENT INTEGRITY shall beemonstrated-by:

d Verifying at least once per 31 days that:

a.

1.

All Auxiliary Building and Enclosure Building equipment hatches and blowout panels are closed and sealed.

2.

The door in each access to the Auxiliary Building and Enclosure Building is closed, except for routine entry and exit.

3.

All Auxiliary Building and Enclosure Building penetrations not capable of being closed by OPERABLE secondary containment automatic isolation dampers / valves and required to be closed during accident conditions are closed by valves, blind flanges, rupture discs or deactivated automatic dampers / valves secured in position.

i b.

At least once per 18 months:

1.

Verifying that one standby gas treatment subsystem will draw down the secondary containment to greater than or equal to 0.25 inches of vacuum water gauge in~1ess than or equal to 120 seconds, and 2.

Operating one standby gas treatment subsystem for one hour and maintaining greater than or equal to 0.266 inches of vacuum water gauge in the secondary containment at a flow rate not exceeding 4000 CFM.

When irradf ated fuel is being handled in the primary or secondary containment and during CORE ALTERATIONS and operations with a potential for draining the reactor vessel.

GRAND GULF-UNIT 1 3/4 6-48

TABLE 3.8.4.1-1 (Continued)

PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES 480 VAC Circuit Breakers (Continued) c.

Molded Case, Type NZM TRIP

RESPONSE

BREAKER SETPOINT TIME SYSTEM / COMPONENT NUMBER (Amperes)

(Seconds)

AFFECTED 52-1112-20 90 0.100 RWCU FILTER DEMIN HOLDING PUMP (N1G36C001A-N) 52-1112-21 800 0.100 480 V RECEPTACLE 52-1112-22 5

O.100 MOV-STM TUNNEL COOLER INLET (N1P72F150A-N) l 52-1112-24 32 0.100 MOV CLEANUP LINE RECIRC LOOP A (Q1G33F100-N) 52-1112-27

- 24 0.100 RESIN TANK AGITATOR (N1G360020-N) 52-1112-28 38 0.100 MOV RWCU HEAT EXCHANGER BYPASS (N1G33F104-N) 52-1112-31 38 0.100 MOV RWCU HEAT EXCHANGER BYPASS (N1G33F044-N) 52-1112-36 500 0.100 REAC. RECIRC. PUMP SPACE HEATER (TBIB33C001A) 52-111* 37 800 0.100 480 V RECEPTACLE 52-1112-38 44 0.100 REAC WATER SAMPLE STA FILTER TRAIN FAN (N1M41-D006-N) 52-1112-41 6

0.100 REAC RECIRC SAMPLE PANEL ISOL MOV (N1833F129) 52-1113-07 125 0.100 CNTMT FLOOR DRAIN SUMP PUMP (N1P45C0198-N)

GRAND GULF-UNIT 1 3/4 8-23 Amendment No. 21 l

Effective Date:

TABLE 3.8.4.1-1 (Continued)

PRIMARY CONTAINMENT PENETRATION CC.wCUCTOR OVERCURRENT PROTECTIVE DEVICES c.

480 VAC Circuit Breakers (Continued)

Molded Case, Type NZM TRIP

RESPONSE

BREAKER SETPOINT TIME SYSTEM / COMP 0NENT NUMBER (Amperes)

(Seconds)

AFFECTED 52-1113-21 60 0.100 DRYWELL EQUIP DRAIN SUMP PUMP (M1P45C0028-N) 52-1113-30 28 0.100 MOV RWCU HX OUTL ISOL VLV (N1G33F254-N) 1 l

S 1

3 f

c GRAND GULF-UNIT 1 3/4 8-23a Amendment No. 6 l Effective Date:

.--.._.v,

-.s.

--m,

TABLE 3.8.4.1-1 (Continued)

PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES 480 VAC Circuit Breakers (Continued) c.

Molde'd Case,' Type NZM TRIP

RESPONSE

BREAKER SETPOINT TIME SYSTEM / COMPONENT NUMBER (Amperes)

(Seconds)

AFFECTED 52-1113-44 800 0.100 480 V RECEPTACLE 52-1113-47 500 0.100 SPARE 52-1151-06 240 0.100 CNTMT COOLING FILTER TRAIN FAN (N1M410002A-N)

^

52-1151-07 17.5 0.100 REAC. RECIRC HPU OIL PUMP FAN (N18330003A3-N) 52-1151-10 600 0.100 REAC. RECIRC. HPU OIL PUMP (N18330003Al-N) 52-1151-12.

75 0.100 MOV - RECIRC PUMP SUCTION (Q1833F023A-N) 52-1151-19 75 0.100 MOV RECIRC PUMP DISCHARGE (Q1833F067A-N)

~

52-1151-20 600 0.100 REAC. RECIRC. HPU OIL PUMP (N18330003A2-N)

~

52-1151-21 17.5 0.100 REAC. RECIRC. HPU l

OIL PUMP FAN l

(N18330003A4-N) 52-1151-22 60 0.100 ORYWELL CHEMICAL WASTE SUMP PUMP (N1P45C029-M) 52-1151-27 60 0.100 DRYWELL EQPT. OR.

SUMP PUMP l

(N1P4,5C002A-N) l 52-1151-28 125 0.100 CNTMT FLOOR OR.

SUMP PUMP (N1P45C019A-N) l GRANO GULF-UNIT 1 3/4 8-24 I

TABLE 3.8.4.1-1 (Continued)

PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES c.

480 VAC Circuit Breakers (Continued)

I Molded' Case, Type NIM TRIP

RESPONSE

BREAKER SETPOINT TIME SYSTEM / COMPONENT NUMBER (Amperes)

(Seconds)

AFFECTED 52-1222-04 800 0.100 CNTMT CLR FAN COIL UNIT FAN (N1M4180018-N)

N 52-1222-05 240 0.100 CNTMT COOLING SYS CHAR TRAIN FAN (N1M4100028-N)

~

52-1222-09 1200 0.100 LIGHTING XFMR 1X104 (N1R185204-E) 52-1222-11 800 0.100 480 V RECEPTACLES l

52-1222-18 500 0.100 REAC. RECIRC. PUMP

~

SPACE NEATER (T81833C0018) 52-1222-19 75 0.100

~ MOV - RWCU RETURN 70 REACTOR (N1G33F042-N) 52-1222-20 32 0.100 M0V - VESSEL ORAIN LINE RECIRC.

(Q1G33F101-N) 52-1222-21

75 0.100 MOV - CLEANUP LINE

~

SUCT. IN ORYWELL (Q1G33F102-N) 52-1222-22 32 0.100 MOV - CLEANUP LINE

. RECIRC LOOP 8 (Q1G33F106-N)

~

52-1251-01 175 0.100 STEAM TUNNEL CLR.

INSIDE CNTMT (N1M41C0048-N) 52-1251-07 60 0.100 CNTMT CHEM WASTE SUMP PUMP (N1P45CO27A-N)

GRAND GULF-UNIT 1 3/4 8-25 l

TABLE 3.8.4.1-1 (Continued)

_ PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES 480 VAC Circuit Breakers (Continued) c.

Molded Case, Type NZM TRIP

RESPONSE

BREAKER SETPOINT TIME SYSTEM / COMPONENT NUMBER (Amperes)

(Seconds)

AFFECTED 52-1251-13 800 0.100 CNTMT CLR FAN COIL UNIT FAN (N1M418001C-N) 52-1251-15 32 0.100 MOV - RWCS HX INL o

ISOL VLV (NIG33F256-N)

~

52-1251-18 38 0.100 MOV - REGEN HEAT EXCHANGER BYPASS (Q1G33F107-N) 52-1251-19 38 0.100 MOV - RWCU DRAIN FLOW ORIFICE BYP (N1GMF031-N) 52-1251-20 320 0.100 CNTMT EQUIP ORAIN PUMP (N1P45C0048-M) 52-1251-22 32 0.100 MOV - RWCU TO FLT "S" ISOL VLV (N1G33F255-N) 52-1251-26 1200 0.100 LIGHTING XFMR IX112 (NIR185112-0)

'S 52-1251-28 5

0.100 MOV - STM TUNIEL COOLER INLET (N1P72F1508-N) l 52-1252-23 60 0.100 ORYWELL FLOOR ORAIN SUMP PUMP (N1P45C0018-N) 52-1252-27 500 0.100 FUEL TRANSFER SYS MN CONSOLE (N1F11E015-MC) 52-1411-01 38 0.100 M]V - VESSEL HEAD VENTILATION (Q1821F002-N)

GRAND GULF-UNIT 1 3/4 8-26 Amendment No. 21 l Effective Date: I

TABLE 3.8.4.1-1 (Continued)

PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES c.

480 VAC Circuit Breakers (Continued)

Molded Case,* Type NZM TRIP

RESPONSE

BREAKER SETPOINT TIME SYSTEM / COMPONENT NUMBER (Amperes)

(Seconds)

AFFECTED 52-1511-54 24 0.100 Spare 52-1521-02 6

0.100 MOV COMBUSTIBLE GAS CONTROL SYS (Q1E61F003A-A) 52-1521-03 6

O.100 MOV COMBUSTIBLE GAS CONTROL SYS (Q1E61F005A-A) 52-1521-07 10 0.100 MOV SUPPR. POOL MAKE-UP VALVE (Q1E30F002A-A) 52-1521-14 600 0.100 SCL SYSTEM PUMP (Q1C41C001A-A) 52-1521-15 5

0.100 STORAGE TANK OUTLET VALVE (Q1C41F001A-A) 52-1521-28 12.5 0.100 MOV INST LINE ISOL VALVE (Q1M71F595-A) 52-1521-44 10 0.100 MOV - SUPPR POOL MAKE-UP VALVE (Q1E30F001A-A) 52-1531-24 12.5 0.100 MOV - DRYWELL COOLER ISOLATION (Q1P72F125-A) l 52-1531-25 8

0.100 MOV - REACTOR WATER SAMPLE.

(Q1833F020-A)

GRAND GULF-UNIT 1 3/4 8-29 Amendment No. 21 l

Effective Date:

TABLE 3.8.4.1-1 (Continued)

PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICE 5 480 VAC Circuit Breakers (Continued) c.

Molded Cise, Type NZM TRIP

RESPONSE

BREAKER SETPOINT TIME SYSTEH/ COMPONENT NUMBER (Amperes)

(Seconds)

AFFECTED 52-1531-36 320 0.100 MOV - LPCI A INJECTION ISOL (Q1E12F042A-A) 52-1531-44 125 0.100 MOV - RHR A o

UPPER CMT POOL SPRAY (Q1E12F037A-A) 52-1531-49 32 0.100 MOV - DRYWELL CHEM WASTE ISOL (Q1P45F096-A) 52-1531-50 105 0.100 MOV - RHR A CONTAINMENT SPRAY (Q1E12F028A-A) 52-1541-32 32 0.100 MOV - COMB GAS CONT COMP A OUT (Q1P41F168A-A) 52-1542-05 320 0.100 DRWELL COOLER FAN COIL UNIT (N1M518001A-A) 52-1542-06 320 0.100 DRWELL COOLER FAN COIL UNIT (N1M5B002A-A) 52-1542-07 320 0.100 DRWELL COOLER FAN COIL UNIT (N1M51B003A-A) 52-1542-08 320 0.100 DRWELL COOLER FAN COIL UNIT (N1M518004A-A) 52-1542-09 320 0.100 DRWELL COOLER FAN COIL UNIT (N1M51B005A-A)

GRAND GULF-UNIT 1 3/4 8-30

~c

TABLE 3.8.4.1-1 (Continued)

PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES c.

480 VAC Circuit Breakers (Continued)

Molded Case,. Type NZM TRIP

RESPONSE

BREAKER SETPOINT TIME SYSTEM / COMPONENT NUMBER (Amperes)

(Seconds)

AFFECTED 52-1542-10 320 0.100 DRWELL COOLER FAN COIL UNIT (N1M518006A-A) h 52-1542-14 5

0.100 MOV - DRWELL COOLER INLET

-(N1P72F145-A) l

^

52-1542-15 5

0.100 MOV - DRWELL COOLER INLET (N1P72F116-A) l 52-1542-16 5

0.100 MOV - DRWELL COOLER INLET (N1P72F139-A) l 52-1542-17 5

0.100 MOV - DRWELL COOLER INLET (N1P72F111-A) l 52-1542-18 5

0.100 MOV - DRWELL COOLER INLET (N1P72F101-A) l 52-1542-19 5

0.100 MOV - DRWELL COOLER INLET (N1P72F134-A) l 52-1542-21 800

0.100 SLCS OPERATING r

HEATER (NIC410002) 52-1542-22 24 0.100 DRWL PURGE COMP AUX OIL PUMP (Q1E610001A-A) 52-1542 500 0.100 REFUELING PLATFORM ASSY (Q1F15E003-A) 52-1542-26 175 0.100 DRWELL RECIRC FAN (N1M51C001-A) 1

(

GRAND GULF-UNIT 1 3/4 8-31 Amendment No. 21 l

Effective date:

TABLE 3.8.4.1-1 (Continued)

PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVER URRENT PROTECTIVE DEVICES c.

480 VAC Circuit Breakers (Continued)

Molded Case, Type NZM TRIP

RESPONSE

BREAKER SETPOINT TIME SYSTEM / COMPONENT NUMBER (Amperes)

(Seconds)

AFFECTED 52-1542-29 1200 0.100 STBY LIQ CONTROL SYS MIXING HEATER (Q1C410003) 52-1611-10 12.5 0.100 MOV - DRWELL COLL TK OUTLET ISOLATION (Q1G41F044-8) 52-1611-15 12.5 O.100 MOV - DCW CTMT l

STM TNL CLR ISOL (Q1P72F123-B) l 52-1611-16 50 0.100 MOV-RHR RX HD SPR INBD ISOL (Q1E12F394-B) 52-1611-25 12.5 0.100 MOV - DRWELL CLG WTR ISOL (Q1P42F117-B) 52-1611-31 12.5 0.100 MOV - DRWELL CLG WTR INL ISOL (Q1P42F114-B) 52-1611-32 32 0.100 MOV - CTMT 3

CLG WTR ISOLATION (Q1P42F068-B) 52-1611-42 12.5 0.100 MOV DCW STEAM l

TUNNEL CLR ISOL (Q1P72F124-B) l

~

52-1611-43 12.5 0.100 MOV DCW STEAM l

TUNNEL CLR ISOL (Q1P72F126-8) l 52-1611-44 38 0.100 MOV - SERVICE AIR ORWELL ISOLATION (Q1PS2F195-B)

GRAND GULF-UNIT.1 3/4 8-32 Amendment No. 21l Effective Date:

TABLE 3.8.4.1-1 (Continued)

PRIMARY CONTAINM NT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES c.

480 VAC Circuit Breakers (Continued)

Molded Case, Type NZM TRIP

RESPONSE

BREAKER SETPOINT TIME SYSTEM / COMPONENT NUMBER (Amperes)

(Seconds)

AFFECTED 52-1642-10 320 0.100 DRYWELL COOLER FAN COIL UNIT (N1M5180068-B) 52-1642-14 12.5 0.100 MOV - DRYWELL COOLER INLET (N1P72F146-B) l 52-1642-15 12.5^

0.100 MOV - DRYWELL COOLER INLET (N1P72F117-B) l 52-1642-16 12.5 0.100 MOV - DRYWELL COOLER INLET (N1P72F140-B) l 52-1642-17 12.5 0.100 MOV - DRYWELL COOLER INLET (NIP 72F112-B) l 52-1642-18 12.5 0.100 MOV - DRYWELL COOLER INLET l

(N1P72F102-B) l 52-1642-19 12.5 0.100 MOV - DRYWELL COOLER INLET (NIP 72F135-B) l 52-1642-21 24 0.100 DRWL PURGE COMP AUX OIL PUMP (Q1E61C0018-B) 52-1642-29 175 0.100 DRWL RECIRC FAN (N1M5100028) i GRAND GULF-UNIT 1 3/4 8-37 Amendment No. 21 l

Effective Date:

TABLE 3.8.4.1-1 (Continued)

PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES (d) 125 VOC Circuit Breakers GE Type THED TIME 0.C.

RESPONSE

BREAKER PICKUP TIME SYSTEM / COMPONENT NUMBER (Amperes)

(Seconds)

AFFECTI:

72-11A-23 30

5. 0 AUTOMATIC DEPRESSURIZATION SYSTEM VALVES 72-11A-28 15 5.0 REMOTE SHUTDOWN PANEL / AUTOMATIC DEPRESSURIZATION SYSTEM VALVES 72-11A-30 15 5.0 REACTOR PROTECTION SYSTEM / BACKUP SCRAM VALVE 72-11A-33 15 5.0 CONTAINMENT &

DRYWELL ISOLATION SYSTEM ANNUNCIATION 72-11A-38 15 5.0 RESIDUAL HEAT REMOVAL SYSTEM VALVES 72-11B-14 50 5.0 RESIOUAL HEAT REMOVAL SYSTEM 72-11B-28 15 5.0 REMOTE SHUTDOWN PANEL / ADS VALVES q(

72-118-30 15 5.0 REACTOR PROTECTION SYSTEM /

BACKUP SCRAM VALVE 72-118-34 30 5.0 AUTOMATIC DEPRESSURIZATION,

SYSTEM VALVES 72-118-37 15 5.0 CONTAINMENT &

DRYWELL ISOLATION SYSTEM GRAND GULF-UNIT 1 3/4 8-38

TABLE 3.8.4.1-1 (Continued)

PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES (e) 208/120 VAC Circuit Breakers (Continued)

GE Type THQB TIME 0.C.

RESPONSE

BREAKER PICKUP TIME SYSTEM / COMPONENT NUMBER (Amperes)

(Seconds)

AFFECTED 52-1P151-23 15 4.0 CTMT. CLG. SYSTEM CHARCOAL FLTR.

TRAIN HEATER (N1M41D002A-N) 52-IP151-24 15 4.0 MOTOR SPACE HEATER FOR REACTOR RECIRC.

SYS.

(N1833D003A3-N) 52-IP151-25 15 4.0 MAIN STEAM PIPING AREA DRWL. COOLER SERVICE WATER CONT.

TRANSMITTER (TT-N041) 52-1P151-26 15 4.0 MOTOR SPACE HEATER FOR REACTOR RECIRC.

SYSTEM (N18330003A4-N) 52-1P151-37 15*

4.0 DRWL. PERSONNEL LOCK (120'-10" ELEV) 52-1P151-38 15*

4.0 CTMT. PERSONNEL LOCK (LOWER) -

52-1P222-17 15 4.0 CTMT. CLG. SYSTEM CHARCOAL FLTR.

l TRAIN HTR.

(N1M41D0028-N) 52-1P222-24 15 4.0 CTMT. & DRWL.

PERSONNEL

AIR LOCK MONITORING SYSTEM IN CONT.

ROOM GRAND GULF-UNIT 1 3/4 8-41 e.

l f

TABLE 3.8.4.1-1 (Continued)

PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES (e) 208/120 VAC Circuit Breakers (Continued)

GE Type THQB TIME.O.C.

RESPONSE

BREAKER PICKUP TIME SYSTEM / COMPONENT NUMBER (Amperes)

(Seconds)

AFFECTED 52-1P222-27 15 4.0 DRWL. COOLERS SERVICE WATER CONT.

TRANSMITTER (TT - N044)

~

~ 52-1P251-13

'15 4.0 PUMP VALVE SOLENOID CONT. CKT. &

TEMPERATURE FOR REACTOR WATER CLEAN UP SYS, 52-1P252-37 15*

4.0 CONTAINMENT EQUIP.

HATCH (Q1M23Y007-1) 52-1P252-3B 15*

4.0 CONTAINMENT EQUIP.

HATCH (QlM23Y007-2) 52-IP411-19 15 4.0 DRYWELL CHILLED l

WATER SYS. CONTROL VALVE INDICATION (IP72ZLR018)

{

52-1P412-22 15 4.0 MOTOR SPACE HEATER FOR REACTOR RECIRC.

SYSTEM (N18330003B1-N) 52-1P412-23 20 4.0 UTILITY POWER FOR REMOTE SIGNAL CONDITIONING PANEL 52-1P412-24 15 4.0 MOTOR SPACE HEATER FOR REACTOR RECIRC.

SYSTEM (N18330003B2-N) 52-1P412-25 20 4.0 UTILITY POWER FOR REMOTE SIGNAL CONDITIONING PANEL GRAND GULF-UNIT 1 3/4 8-42 Amendment No.21 l Effective Date:

TABLE 3.8.4.2-1 (Continued)

MOTOR OPERATED VALVES THERMAL OVERLOAD PROTECTION BYPASS DEVICE (CON-TINUOUS) (ACCIDENT SYSTEM (S)

VALVE NUMBER CONDITIONS) (MO)

AFFECTED Q1P72F121 Continuous Drywell CW System Q1P72F122 Continuous Drywell CW System Q1P72F125 Continuous Drywell CW System Q1P72F123 Continuous Drywell CW System Q1P72F124 Continuous Drywell CW System Q1P72F126 Continuous Drywell CW System Q1P44F042 Continuous Plant SW System

-(

Q1P44F054 Continuous Plant SW System Q1P44F067 Continuous Plant SW System Q1P45F096 Continuous Floor & Eqmt. Drain System Q1945F097 Continuous Floor & Eqmt. Drain System Q1P52F195 Continuous Service Air System Q1P53F003 Continuous Instrument Air System Q1P53F007 Continuous Instrument Air System Q1T48F005 Continuous SGTS Q1T48F006 Continuous SGTS Q1T48F024 Continuous SGTS Q1T48F026 Continuous SGTS Q1T48F023 Continuous.

SGTS Q1T48F025 Continuous SGTS

(

Q1P45F273 Continuous Floor & Eqmt. Drain System Q1P45F274 Continuous Floor & Eqmt. Drain System

~

GRAND GULF-UNIT 1 3/4 8-53 Amendment No. 21 l

Effective Date:

ELECTRICAL POWER SYSTEMS REACTOR PROTECTION SYSTEM ELECTRIC POWER MONITORING LIMITING CONDI. TION FOR OPERATION 3.8.4.3 Two RPS electric power monitoring assemblies for each inservice RPS MG set or alternate power supply shall be OPERABLE.

APPLICABILITY: At all times.

ACTION:

a.

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

With both RPS electric power monitoring assemblies for an inservice RPS MG set or alternate pcwer su;iply 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.

SURVEILLANCE REQUIREMENTS 4.8.4.3 The above specified RPS electric power monitoring assemblies.shall be determined OPERABLE:

By performance of a CHANNEL FUNCTIONAL TEST at ieast once per 6 months.

a.

b.

At least once per 18 months by demonstrating the OPERABILITY of over- '

voltage, under-voltage and under-frequency protective instrumentation by performance of a CHANNEL CALIBRATION including simulated automatic g

actuation of the protective relays, tripping logic and output circuit breakers and verifying the following setpoints:

1.

Over-voltage Bus A

< 132.9 VAC Bus B 5133.0VAC 2.

Under-voltage Bus A

> 115.0 VAC Bus B

[115.9VA l

3.

Under-frequency Bus A

> 57 Hz l

Bus B

[57.Hz l

l GRAND GULF-UNIT 1 3/4 8-54 l

c

3/4.12 RADIOLOGICAL ENVIRONMENTAL MONITORING 3/4.12.1 MONITORING PROGRAM LIMITING CONDITION FOR OPERATION 3.12.1 The radiological environmental monitoring program shall be conducted as specified in Table 3.12.1-1.

APPLICABILITY: At all times.

ACTION:

With the radiological environmental monitoring program not being a.

conducted as specified in Table 3.12.1-1, prepare and submit to the Commission, in the Annual Radiological Environmental Operating 1

Report per Specification 6.9.1.7, a description of the reasons for not conducting the program as required and the plans for preventing a recurrence.

b.

With the level of radioactivity as the result of plant effluent in

(

an environmental sampling medium at a specified location exceeding the reporting levels of Table 3.12.1-2 when averaged over any calendar quarter, prepare and submit to the Commission within 30 days pursuant to Specification 6.9.2 a Special Report that identifies the cause(s) for exceeding the limit (s) and defines the corrective actions to be taken to reduce radioactive effluents so that the potential annual dose to a MEMBER OF THE PUBLIC is less than the calendar year limits of Specifications 3.11.1.2, 3.11.2.2 and 3.11.2.3.

When more than one of the radionuclides in Table 3.12.1-2 are detected in the sampling medium, this report shall be submitted if:

concentration (1) reporting level (1)

concentration (2) reporting level (2) * *'11.0 When radionuclides other than those in Table 3.12.1-2 are detected and are the result of plant effluents, this report shall be submitted if the potential annual dose to a MEMBER OF THE PUBLIC is equal to or greater than the calendar year limits of Specifications 3.11.1.2, 3.11.2.2 and 3.11.2.3.

This report is not required if the measured level of radioactivity was not the result of plant effluents; however, in such an event, the condition shall be reported and described in the Annual Radiological Environmental Operating Report.

If milk or broad leaf vegetation sampling is relocated from one or c.

more of the sample locations required by Table 3.12.1-1, identify new locations for obtaining replacement samples and add them to the radiological environmental monitoring program within 30 days.

In addition, report the cause(s) of the unavailability of samples and the new locations for obtaining replacement samples in the next Semi-annual Radioactive Effluent Release Report.

Include in this report the revised 0 M figure (s) and table (s) reflecting the new locations.

The specific 1 cations from which samples were unavailable may then be deleted fr the radiological environmental monitoring program and j

the table (s).En the ODCM, provided the locations from which the replace-i ment samples were obtained are added to the table (s) as replacement l

ice.ations.

d.

The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

t GRAND GULF-UNIT 1 3/4 12-1 Amendment No. 21 l

Q w+ r-

RADIOLOGICAL ENVIRONMENTAL MONITORING SURVEILLANCE REQUIREMENTS 4.12.1 The radiological environmental monitoring samples shall be collected

~

pursuant to Table 3.12.1-1 from the locations given in the table and figures in the ODCM and shall be analyzed pursuant to the requirements of Tables 3.12.1-1 and 4.12.1-1.

l I

e GRAND GULF-UNIT 1 3/4 12-2

CONTAINMENT SYSTEMS BASES 3/4.6.4 CONTAINMENT AND DRYWELL ISOLATION VALVES The JPERABILITY of the containment isolation valves ensures that the con-tainment atmosphere will be isolated from the outside environment in the event of a release of radioactive material to the containment atmosphere or pressuri-zation of the containment and is consistent with the requirements of GDC 54 through 57 of Appendix A to 10 CFR Part 50. Containment isolation within the time limits specified for those isolation valves designed to close automatically ensures that the release of radioactive material to the environment will be consistent with the assumptions used in the analyses for a LOCA.

The operability of the drywell isolation valves ensures that the drywell

~

atmosphere will be directed to the suppression pool for the full spectrum of

(

pipe breaks inside the drywell. Since the allowable value of drywell leakage l

is so large, individual drywell penetration leakage is not measured. By checking valve operability on any penetration which could contribute a large fraction of the design leakage, the total leakage is maintained at less than the design value.

Table 3.6.4-1 lists the Containment and Drywell Isolation Valves in four sections. Section 1 contains the Automatic Isolation Valves which are those valves that receive an automatic isolation signal from Table 3.3.2-1 instrumen-tation and are located on the Containment or Drywell penetrations. The valves included in Section 2 are Manual Isolation Valves which receive a remote manual signal from a handswitch and are located on the Containment or Drywell Penetrations.

Some of the valves in Section 2 may receive automatic signals, but not automatic isolation signals from instrumentation in Table 3.3.2-1.

The valves included in Section 3 are those which do not receive isolation signals from instrumentation listed in Table 3.3.2-1 and do not utilize a remote manual handswitch. Section 3 includes check valves, local manual operated valves and power operated valves that do not utilize a handswitch. Section 4 of Table 3.6.4-1 contains test connection valves.

1 The maximum isolation times for containment and drywell automatic isolation valves are the times used in the FSAR accident analysis for valves with analyt-ical closing times. For automatic isolation valves not having analytical closing times, closing times are derived by applying margins to previous valve closing test data obtained by using ASME Section XI criteria. Maximum closing times for these valves was determined by using a factor of two times the allow-able (from previous test closure to next test closure) ASME Section XI margin and adding this to the previous test closure time.

3/4.6.5 DRYWELL VACUUM RELIEF ~

i The safety-related functions of the four drywell vacuum relief subsystems are drywell isolation, proper operation of the drywell purge compressors, and OPERABILITY in a large-break LOCA to control weir wall overflow drag and impact loads. The drywell isolation and drywell purge OPERABILITY functions are dis-cussed in Bases 3/4.6.4 and 3/4.6.7, respectively. Drywell vacuum relief is j

not required for hydrogen dilution or to protect drywell structural integrity in a design-basis accident.

GRAND GULF-UNIT 1 B 3/4 6-7 Amendment No. 21 Effective Date:

j CONTAINMENT SYSTEMS BASES DRYWELL VACUUM RELIEF (Continued)

To provide drywell vacuum relief, containment air is drawn through subsys-tems associated with three 10-inch lines penetrating the drywell. Two drywell post-LOCA vacuus relief subsystems are in a parallel arrangement connected to one of the three 10-inch vacuum relief lines penetrating the drywell. Each dry-well post-LOCA vacuum relief subsystem consists of a motor-operated isolation valve in series with a check valve. OPERABILITY of either drywell post-LOCA vacuum relief subsystem assures OPERABILITY of the associated 10-inch vacuum relief line penetrating the drywell. Each of the two remaining 10-inch vacuum relief lines penetrating the drywell contains a drywell purge vacuum relief subsystem. Each drywell purge vacuum relief subsystem consists of a series arrangement of a motor-operated isolation valve and two check valves.

Vacuum relief initiates at a differential pressure across the check valves of less than or equal to 1 psi.

Rapid weir wall overflow in a large-break LOCA could cause drag and impact loadings to essential equipment and systems in the drywell above the weir wall.

Drywell negative pressure analysis for rapid weir wall overflow in a large-break LOCA assumes a vacuum breaker capability of A//K = 0.38 fts thus re-quiring a minimum of two 10-inch drywell vacuum relief paths.

OPERABILITY requirements for the four drywell vacuum reifef subsystems in relationship to continued plant operation are based on maintaining at least two of the three 10-inch drywell vacuum relief paths OPERABLE.-Nowever, to ensure that essential equipment is returned to service in a timely manner, continued plant operation is ifmited with only one 10-inch drywell vacuum relief line out of service. Plant operation is further limited when two of the three 10-inch lines are out of service to ensure prompt response to restore equipment to service or to place the plant in a condition where the equipment is not required.

Plant operation is also limited with a drywell isolation vacuum breaker in the open position to help ensure that design drywell bypass leak-age is not potentially exceeded. Position indication is required to be OPERABLE on all drywell vacuum breakers and motor-operated isolation valves to help identify potential drywell bypass leakage paths.

Surveillance requirements and intervals were chosen to reflect the impor-tance associated with the drywell vacuum relief function and are based on good engineering judgement using previous accepted testing methods.

3/4.6.6 SECONDARY CONTAINMENT Secondary containment is designed to minimize any ground level release of radioactive material which may result from an accident. The Auxiliary Building and Enclosure Building provide secondary containment during normal operation when the containment is sealed and in service. When the reactor is in COLD SHUTDOWN or REFUELING, the containment may be open and the Auxiliary Building and Enclosure Building then become the only containment.

The maximum isolation times for secondary containment automatic isolation dampers / valves are the times used in the FSAR accident analysis for dampers /

valves with analytical closing times. For. automatic isolation valves not having GRAND GULF-UNIT 1 B 3/4 6-8 AmendmentNo.21l Effective Date:

n-

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CONTAINMENT SYSTEMS BASES SECONDARY CONTAINMENT (Continued) analytical closing times, closing times are derived by applying margins to previous valve closing test data obtained by using ASME Section XI criteria.

Maximum closing times for these valves was determined by using a factor of two times the allowable (from previous test closure to next test closure) ASME Section XI margin and adding this to the previous test closure time.

Establishing and maintaining a vacuum in the Auxiliary Building and Enclosure Building with the standby gas treatment system once per 18 months, along with the surveillance of the doors, latches, dampers, valves, blind flanges, and rupture discs is adequate to ensure that there are no violations of the integrity of the secondary containment.

The OPERABILITY of the standby 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 boundary radiation doses associated with containment leakage. The operation of this system and resultant iodine removal capacity are consistent with the assumptions used in the LOCA analyses.

Continuous operation of the system with the heaters OPERABLE for 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months over a 31-day period is sufficient to reduce the buildup of moisture on the adsorbers and HEPA filters.

1

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GRAND GULF-UNIT 1 B 3/4 6-8a AmendmentNo.21l Effective Date:

ADMINISTRATIVE CONTROLS SEMIANNUAL RADI0 ACTIVE EFFLUENT RELEASE REPORT (Continued)

Principal radionuclide (specify whether determined by measurement or c.

estimate),

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

i bottoms),

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

f.

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

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

The radioactive effluent release reports shall include any changes to the b,

PROCESS CONTROL PROGRAM (PCP), OFFSITE DOSE CALCULATION MANUAL (ODCM) or radio-active waste systems made during the reporting period.

MONTHLY OPERATING REPORTS

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6.9.1.10 Routine reports of operating statistics and shutdown experience, including documentation of all challenges to main steam system safety / relief valves, shall be submitted on a monthly basis to the Director, Office of Management and Program Analysis, 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 l

6.9.2 Special reports shall be submitted to the Regional Administrator of the Regional Office within the time period specified for each report.

6.10 RECORD RETENTION 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.

6.10.1 The following records shall be retained for at least five years:

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

power level.

b.

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

l c.

All REPORTABLE EVENTS.

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l GRAND GULF-UNIT I 6-19

-,,_,,,,-,--y-y---

r-,-----,--,,-.-.

ADMINISTRATIVE CONTROLS 6.10 RECORD RETENTION (Continued)

RecoEds of surveillance activities, inspections and calibrations d.

required by these Technical Specifications.

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

6.8.1.

f.

Records of radioactive shipments.

g.

Records of sealed source and fission detector leak tests and results.

h.

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

6.10.2 The following records shall be retained for the duration of the Unit Operating License:

Recordsanddrawingchange$reflectingunitdesignmodificationsmade a.

to systems and equipment described in the Final Safety Analysis Report.

b.

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

~

Records of radiation exposure for all individuals entering radiation c.

control areas.

d.

Records of gaseous and liquid radioactive material released to the environs.

Records of transient or operational cycles for those unit components e.

identified in Table 5.7.1-1.

f.

Records of reactor tests and experiments.

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

staff.

h.

Records of in-service inspections performed pursuant to these Technical Specifications.

i.

Records of Quality Assurance activities required by the Operational Quality Assurance Manual not listed in Section 6.10.1.

l j.

Records of reviews performed for changes made to procedures or equipment or reviews of tests and experiments pursuant to 10 CFR 50.59.

k.

Records of meetings of the PSRC and the SRC.

1.

Records of the service lives of all hydraulic and mechanical snubbers including the date at which the service life commences and associated installation and maintenance records, Records of analyses required by the radiological environmental m.

monitoring program.

GRAND GULF-UNIT 1 6-20 Amendment No.21 l

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v t e Letter Sequence Other
TAC:60587, (Approved, Closed) TAC:60588, (Approved, Closed) TAC:60589, (Approved, Closed) TAC:60590, (Approved, Closed) TAC:60591, (Approved, Closed) TAC:60592, (Approved, Closed) TAC:61196, (Approved, Closed) TAC:61782, (Approved, Closed)
Initiation Request, Request, Request, Request, Request, Request, Request, Request, Request Acceptance... Administration Questions Answers Results Approval, Approval Other: AECM-81-281, Responds to NRC Providing Addl Guidance for NUREG-0737,Item I.G.1 Re Training During Low Power Testing, as Applied to BWR-OL Applicants.Simulated Loss of Ac Power Test Program Will Be Submitted for NRC Approval, AECM-86-0042, Forwards Station Blackout Evaluati Ept..., for Approval.Rept Provides Justification for Not Performing Simulated Station Blackout Test,Per TMI Item I.G.1.Test Not Recommended Per Generic Ltr 83-24.Fee Paid, ML20003E750, ML20137P712, ML20199L109, ML20203D679, ML20203J963, ML20207G520, ML20212P470, ML20215L243
MONTHYEAR1986-04-03 [Table View]

ML20215L243

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